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November 16, 2024

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‘Therapy Session’: SPP REAL Team Reviews Draft LOLE Study

DFW AIRPORT, Texas — Texas Public Utility Commissioner Will McAdams promised SPP’s REAL Team a “therapy session” in forming a consensus position around its schedule and priorities for 2024.

“Save most of your intellectual bandwidth for after lunch, because that’s where we’re going to need some discussion and dialogue,” the REAL (Resource and Energy Adequacy Leadership) Team’s chair said during its Nov. 28 meeting, alluding to a discussion of SPP staff’s draft loss-of-load expectation (LOLE) study.

“I think that schedule of priorities will be heavily impacted by the discussion around LOLE, because it shows us what our system needs are in the very near future,” McAdams said.

“This conversation is going to be the first of many,” said SPP’s Casey Cathey, senior director of grid asset utilization. “This particular area is a very, very important topic for the region. It’s not just the loss-of-load expectation study, but specifically establishing a separate winter planning reserve margin.”

Casey Cathey, SPP | © RTO Insider LLC

SPP conducts a LOLE analysis every two years to determine the capacity needed to meet reliability targets. It follows the industry threshold of one day in 10 years (equivalent to 0.1 days/year). The study also establishes the RTO’s planning reserve margin (PRM), currently 15%.

According to the draft 2023 study, maintaining a one-day-in-10 LOLE will require a summer PRM of 16.9% and a winter PRM of 45.2%, with 44% of the year’s LOLE allocated to the summer and 56% to the winter. Staff included full incremental cold weather and planned and maintenance outages in its modeling.

Staff extended its historical wind, solar and load profile assumptions, looking back 43 years instead of nine in looking at 2026 and 2029 planning years. The study forecasts 2026 summer and winter non-coincident peaks of just over 58 GW and almost 48 GW, respectively.

Responding to McAdams’ call for a more defined policy around outages, Cathey said planned outages should be included in the PRM. He noted that modeling planned outages associated with seasonal years or seasons of risk would increase the PRM.

“You’re making that assumption that you’re planning for that,” Cathey said. “We have to make some assumptions here and determine what are going to be the net effects as we’re creating the outage policy.”

“I just don’t want this to be an exercise where we’re going to assume that the planning outages are basically being swept over to the spring and fall season, so we don’t have to worry about [them],” the Advanced Power Alliance’s Steve Gaw said. “I don’t want the model to avoid the problem that we’re trying to fix. We need to have an appropriate level of planned outages that are taking place in the wintertime.”

Cathey promised to bring back to the team an evidence-based value proposition. “How do we appropriately assess the improvements in correlated outages for extreme events?” he asked rhetorically. “Maybe that helps better isolate where we’re going with this this grid and ultimately, a recommendation for next year.”

The Supply Adequacy Working Group (SAWG) is working on summer and winter PRM recommendations as part of the final study, due to be released in March or April. The PRM recommendation revision requests will go to the REAL Team and, in July, the quarterly governance meetings.

The daylong “therapy session” concluded with SPP Director Steve Wright telling McAdams his service to the group has been “remarkable.” McAdams has said he will resign from the Texas commission, leaving the REAL Team chairmanship as well. (See McAdams Says He Will Resign from Texas PUC.)

“Just the time and effort you put into this, you came so incredibly prepared for these meetings, and that set a very high bar for all of us who are participating here,” Wright said.

“We would not be where we are on these very important issues for this region without your leadership. You will very much be missed,” echoed SPP Engineering Vice President David Kelley.

In a manner reminiscent of his military background, McAdams brusquely cut off further plaudits.

“All right, that’s the meeting.”

FERC Rejects Winter Requirement

FERC added to the REAL Team’s workload Nov. 30 when it rejected SPP’s proposed winter resource adequacy requirement for its footprint. However, the commission said the RTO can address FERC’s concerns and resubmit the proposal (ER23-2781).

The commission said the proposal does not contain any requirement that a load-responsible entity’s (LRE) resources are expected to be available. It said SPP has not demonstrated it is reasonable to permit LREs to rely on resources that are not expected to be available in the winter season to satisfy their resource adequacy requirements.

SPP’s Market Monitoring Unit, as it had throughout the stakeholder process, opposed the tariff revision at FERC. It has pointed out the absence of language requiring a reasonable expectation of availability for resources. It also said an LRE could offer a resource to meet its winter obligation while planning to conduct a maintenance outage.

FERC said that in any future filing, the grid operator should take “appropriate steps” to ensure that resources included in LREs’ adequacy workbooks for the winter are expected to be available “just as in the [summer].”

“This would provide a more accurate reflection of the system’s capacity to meet winter demands and reinforce the need for LREs to maintain an adequate amount of available capacity,” the commission said.

Acknowledging recent extreme winter events in the Midwest, FERC encouraged SPP to consider expedited proceedings for any future filing.

“Delays could result in insufficient preparation for these increased demands, potentially compromising the reliability of the power grid and the safety of the consumers who depend on it,” it said.

SPP’s board and its stakeholders and state regulators approved the winter obligation in July. The Members Committee, which provides advisory votes to the board, approved the proposal in a 10-9 vote, with four abstentions. (See “Board, RSC Endorse Winter Obligation,” SPP Board/Members Committee Briefs: July 24-25, 2023.)

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SPP’s MPEC Approves Markets+ Governance Plan

SPP met a major milestone in its Western efforts Dec. 7 when the Markets+ Participants Executive Committee (MPEC) approved the day-ahead market’s proposed governing document, a key step as the grid operator moves quickly to file a tariff with FERC in early 2024.

The MPEC voted 73% in favor of the document, the product of a half-year of work by the committee to be incorporated into the tariff. Stakeholders approved a large portion of the Markets+ draft tariff language last month at an in-person meeting in Tempe, Ariz. (See Stakeholders Approve Bulk of SPP’s Markets+ Tariff.)

The proposal now advances to the Interim Markets+ Independent Panel (IMIP), which is expected to vote on it Dec. 19.

Markets+ rules require the MPEC to pass any measures with a supermajority of 67% of voting members. The bulk of the votes against the governance plan came from representatives of the “Independents” sector dissatisfied with the proposed voting structure for their group once the market goes live.

The document spells out governance structure and functions for Markets+, including the makeup and roles of the SPP Board of Directors, permanent MIP, MPEC, Markets+ State Committee and other standing committees; the MIP election process; meeting policies; the voting process for market policies; and process for appealing decisions. It also covers the establishment of working groups and task forces, the role of SPP staff in relation to the market, and attendance and proxy voting policies.

The Dec. 7 vote was preceded by the MPEC’s approval of a handful of amendments to the governing document, including:

    • An SPP staff proposal that market participants be assigned to geographical regions to enable the MIP to understand the geographical breakdown of MPEC votes for “informational” before voting on issues advanced to the panel by the committee.
    • An SPP staff proposal that members of the Markets+ Nominating and Governance Committee (MNGC) be subject to term limits and that the market retain the option to assign MNGC representatives to geographic regions on a rotating basis.
    • A Bonneville Power Administration proposal to require that a proceeding to remove a MIP member be supported by a minimum of 35% of the sector-weighted representation on the MPEC, compared with 20% in the original plan.
    • A proposal by Western Resource Advocates (WRA) to remove the option for the MPEC to add to the slate of MIP nominees proposed by the MNGC. MPEC members largely agreed with WRA that retaining the option would undermine the role of the nominating committee.

‘Mom or Dad’

The MPEC downgraded to a future “action item” an amendment proposed by the MSC that would’ve permitted a majority of the MSC to appeal an action or inaction by the MIP to SPP’s board after some committee members expressed concern the rule change would allow the MSC to do an end-run around the MIP, the board most directly responsible for overseeing the Western market.

Ed Garvey, a consultant advising the MSC, said the amendment was intended to address the fact that the governance plan would allow only MIP members the ability to appeal a MIP decision to the SPP board.

Garvey said MSC members had concluded that as a body, they should be able to appeal issues to the SPP board “when they’re acting in their umbrella capacity as sort of the public interest representatives and commissioners on the region-wide basis.”

“The MIP is the final governance for Markets+; the MIP is the one looking out for Markets+,” Joe Taylor, senior director of Western markets at Xcel Energy-Colorado, said in opposing the amendment. “I hate to be condescending, but it’s almost like you don’t like the answer you got from mom, so you’re going to dad.”

“If an issue is really important to the region from the MSC’s perspective, they wanted to be able to take it to the ultimate authority,” Garvey responded. “Not necessarily dad, or mom, but certainly the ultimate authority for the responsibility for Markets+.”

Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition (NIPPC), said he was inclined to support some version of the amendment.

“From my part of the market, I kind of view the regulators as mom or dad — pick your parent — so that kind of power dynamic didn’t enter into my mind because, in my view, the states do have an important role in voicing a regulator’s view.”

In moving the amendment to become an action item, the MPEC committed to working with the MSC to determine whether the latter wanted to proceed with the proposal and, if so, what the next steps should be.

The MPEC also approved a handful of other action items, perhaps the most significant of which will deal with how Markets+ governance will function as planning activities around the market move from the current Phase 1 to Phase 2 after the tariff is filed early next year.

During the MPEC meetings held Dec. 6-7, SPP General Counsel Paul Suskie clarified for participants that the governance structure being considered will not actually take effect until Markets+ goes live, likely in the latter half of 2026.

“So then what that leaves is the gap between the end of Phase 1 and the market go-live,” meaning participants will need to determine how they’ll manage their deliberations in the interim as they work through implementation issues, Suskie said.

“Now just my personal opinion, not SPP’s, that it would just seem that the governance we have in place today would make sense to continue until go-live, unless this group chose to change it,” he said.

‘Pretty Fundamental Issue’

Tensions arose during the meeting over NIPPC’s proposed amendment to alter the future voting structure for the MPEC’s “Independents” member sector, which consists of IPPs, power marketers and “Market Stakeholders” such as public interest organizations and consumer advocates.

Under the governance rules adopted by the committee Dec. 7, voting by the MPEC’s “Investor-Owned Utilities” and “Public Power” member sectors will be weighted based on those participants’ load share. Voting among the Independents will be structured to ensure that participants contributing generation to the market receive two-thirds of the sector vote, while those without generation receive one-third.

NIPPC’s amendment sought to continue the status quo practice of each Independent member receiving a single vote within the sector. Gray said his sector was concerned the future depth of the Markets+ market cannot be predicted, and if only one IPP joined the market at go-live, it would represent 22% of the vote for the entire MPEC.

“And that seemed inappropriate for any entity, IPP, or otherwise,” Gray said.

Gray also noted the two-thirds/one-third voting structure had not been previously “presented or debated or negotiated within the groups that were active on governance.”

Over the course of the two-day MPEC meeting, NIPPC altered the proposed amendment to include a September 2025 deadline to review the “one member, one vote” structure in light of the expected depth of IPP participation ahead of the market commencing operation.

NIPPC’s amendment failed with 63% of the MPEC approving, short of the 67% threshold.

In the wake of the vote on the amendment, Gray said NIPPC would consider casting a “no” vote on the entire governance proposal, as did Lisa Hickey of the Interwest Energy Alliance and Scott Miller of the Western Power Trading Forum.

“I think for the majority of our sector [the amendment vote] comes across as more of an intervention in the vote-weighting within the sector from folks likely outside of the sector,” Gray said. He added that the move represented “a pretty fundamental issue for the perception in our sector” of how fair Markets+ can be in respecting the internal independence of the sectors.

All three organizations followed through on their threats to vote against the governance plan. Other “no” votes included Advanced Power Alliance, American Clean Power Association, Clean Energy Buyers Association, Natural Resources Defense Council, Northwest Energy Coalition, Pattern Energy, Sierra Club and Western Resource Advocates.

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NJ Advances Multifaceted Building Decarbonization Strategy

New Jersey is launching a $15 million grant program to help commercial building owners retrofit heating or cooling systems as part of an ongoing series of initiatives to cut natural gas use and pursue building electrification. 

The New Jersey Board of Public Utilities (BPU) also voted Dec. 6 to hire a contractor to help carry out an executive order to study how to support the natural gas sector as the state ramps up electrification. 

Gov. Phil Murphy’s (D) order, EO 317, requires the BPU to consider how to mitigate the impact on the gas industry and its workforce as the state works toward the goal of a 50% reduction in greenhouse gas emissions below 2006 levels by 2030. 

The BPU vote followed an unrelated Nov. 30 hearing of the Assembly Environment and Solid Waste Committee at which the lack of consensus on how to cut building emissions was on full display. Utility, business and union interests vigorously backed a bill, A577, that would enable the use of renewable natural gas, while environmentalists — who fiercely oppose the bill — argued in part that it would weaken the state’s move to electricity. 

Backing the hiring of the consultant, BPU President Christine Guhl-Sadovy said the move was part of a plan to consider all sides of the issue. The board agreed to contract with one of two companies that responded to a request for proposals the BPU put out March 6. The BPU did not release the name of the consultant, and a spokesperson said they will release details of the order when the state Treasury has approved it. 

“We are looking forward to continuing stakeholder engagement throughout this proceeding, once the consultant gets on board,” Guhl-Sadovy said after the vote. “I look forward to the public’s engagement.” 

Transitioning Commercial Buildings

Murphy signed EO 317 the same day he signed an executive order, EO 315, setting a state goal to have 100% of the state’s electricity generated through clean energy sources by 2035, moving that goal up from 2050. At the same time, Murphy signed an order, EO 316, seeking to “advance the electrification of commercial and residential buildings,” with a goal of electrifying 400,000 additional dwelling units and 20,000 additional commercial spaces or public facilities by December 2030. (See NJ Governor Sets Out Accelerated Emissions Targets.) 

In line with that effort, the New Jersey Economic Development Authority (EDA) on Nov. 16 approved a pilot program, called NJ Cool, to allocate $15 million in funds from the 2023 Regional Greenhouse Gas Initiative (RGGI) auction to provide grants for building decarbonization. 

The funds will pay to “retrofit projects in existing commercial buildings that result in a reduction of operating greenhouse gas emissions,” EDA CEO Tim Sullivan said in a memo to the EDA board. 

The pilot initially will award grants in Newark, Edison and Atlantic City, one each in the northern, central and southern regions of the state, all of which “have significant numbers of commercial buildings” that could be eligible and “are municipalities with high commercial energy usage,” the memo said. 

The EDA board also gave Sullivan authority to increase program funding to $30 million if RGGI funds are available and demand for the grants exceeds the initial $15 million. 

The authority expects to begin accepting applications for the grants in 2024. 

Building emissions are New Jersey’s second largest source of emissions, and 80% of the buildings that exist today will still exist in 2050, according to Sullivan. The state’s 2019 Energy Master Plan recommended at least 90% of residential and commercial buildings be converted from gas to electric appliances by 2050, he said. 

“Cost is a major barrier when upgrading homes and businesses to reduce carbon emissions and transition to low GWP commercial refrigeration systems or chillers,” his memo said, referring to global warming potential (GWP) refrigeration systems. 

Grants awarded under the program will cover up 50% of a project, to a maximum of $1 million and a minimum of $50,000 per project. Eligible projects must switch 75% or more of building space heating loads from existing fossil fuel-based combustion systems to low- or zero-emissions systems, or replace GWP with low-GWP alternatives. 

Threat or Opportunity?

At the Assembly Environment and Solid Waste Committee hearing, more than two dozen speakers addressed the merits of A577, even though committee Chairman James J. Kennedy (D) said at the outset the body would not vote on it that day. The bill, introduced in January 2022, secured the backing of the Assembly Telecommunications and Utilities Committee a year ago but otherwise has not moved in either the Assembly or Senate. 

“To get the pure clean energy by the year 2050, we have to have a matrix of energy sources,” said Assemblyman Robert J. Karabinchak (D), a bill sponsor. “This bill will allow the biogas methane, potentially hydrogen, to be mixed by our gas providers today into their infrastructure.” 

The bill’s definition of “renewable natural gas” includes “biogas that is upgraded to meet natural gas pipeline quality standards such that it may blend with, or substitute for, geologic natural gas,” as well as hydrogen or methane gas. 

The bill directs the BPU to establish a program to implement the use of renewable natural gas in the state and give gas utilities a customer rate recovery mechanism to recoup the costs of the program. It requires the creation of guidelines for the “procurement of renewable natural gas and investments in renewable natural gas infrastructure in order to enable that procurement.”  

Business groups said the state needs to have a diverse set of clean energy options to cut emissions, and renewable natural gas would create jobs and investment. Supporters of the bill included the New Jersey Chamber of Commerce, New Jersey Business and Industry Association, the New Jersey Utilities Association and the Chemistry Council of New Jersey, which represents manufacturers in the chemistry sector. Also supporting the bill were unions for pipefitters, plumbers and steamfitters. 

Speakers noted that President Joe Biden on Oct. 13 announced that he had picked Mid-Atlantic Clean Hydrogen Hub (MACH2) — which will serve Pennsylvania, Delaware and New Jersey — as one of seven regional clean hydrogen hubs that together will receive $7 billion in funding.

“This bill would send a message that New Jersey is open for business investments in these energy sectors, which include renewable natural gas and hydrogen,” said Erick Ford, president of the New Jersey Energy Coalition, which promotes clean energy use and represents sectors include business, health care and labor groups. 

Environmental groups vigorously opposed the bill, with one speaker saying renewable natural gas is an “Orwellian name for a product that is neither renewable nor natural” and would divert funds away from “real clean energy projects.” 

“Hydrogen is drawing growing interest as a way of delivering clean energy without harmful climate pollution,” said Mary Barber, New Jersey director for Environmental Defense Fund. “But hydrogen actually comes with safety, climate and other environmental challenges including the propensity to leak, raising serious questions over its ability to deliver the benefits. 

“This bill would allow utilities to charge customers for hydrogen and bio-methane mixing into the natural gas distribution systems that come into our homes and buildings without adequate oversight, creating safety and climate risks,” she said.   

The Division of Rate Counsel also opposed the bill. In a Nov. 29 letter to the committee, division Director Brian O. Lipman said renewable natural gas is more expensive than natural gas and it’s “unclear” if it is any more beneficial to the environment. 

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Overheard at the ISO-NE Consumer Liaison Group Meeting

BOSTON — A year removed from the takeover of the ISO-NE Consumer Liaison Group (CLG) Coordinating Committee by a group of climate activists, the CLG’s return to Boston brought an intense focus on the need to rapidly cut emissions while centering the needs of frontline communities. (See Climate Activists Take Over Small Piece of ISO-NE.)

The “Community Welcome,” a new feature of CLG meetings, was provided by the Rev. Mariama White-Hammond, Boston’s chief of environment, energy and open space.

Rev. Mariama White-Hammond, Boston’s chief of environment, energy and open space | © RTO Insider LLC

“Let’s be honest: Five years ago, I’m not sure I would have been the person here speaking,” White-Hammond told attendees while starting her address.

White-Hammond highlighted the importance of environmental justice in the planning and siting of new energy infrastructure.

“We have to be honest about the fact that for many years, we have put the most polluting facilities in black and brown communities and in poor and working-class communities,” White-Hammond said. “The question is: How can we build an energy system that repairs those harms while also recognizing that the consensus is clear … that climate change is happening because of our use of fossil fuels.”

Speaking to the climate advocates at the meeting, White-Hammond emphasized that electrification of heating and transportation will require a significant amount of new electricity infrastructure, including substations and transmission lines.

Turning to policymakers and other stakeholders, White-Hammond called for greater imagination in planning and siting to avoid replicating the mistakes and injustices of the past.

When considering the needs for new infrastructure, White-Hammond said energy efficiency and demand reductions should come first, followed by building up infrastructure in areas that have not historically been asked to host energy infrastructure, or are driving the need for the infrastructure. Only as a final resort should major projects be sited in vulnerable communities that already host a disproportionate share of infrastructure, White-Hammond said.

In these cases, the community benefits of hosting the infrastructure must well exceed any detrimental impacts, she added. These local benefits could include increased access to renewable energy, lower electricity costs and improved grid resilience.

Reliability, Affordability and Sustainability

Matt Christiansen, general counsel for FERC, stressed the importance of maintaining grid reliability and affordability, then took a series of public questions that focused largely on FERC’s ability to speed up the retirement of fossil fuels.

Judith Black, a climate activist and member of 350 Mass, pushed back against Christiansen’s framing, arguing sustainability should be included among FERC’s top priorities.

“There’s a scientific consensus that we are at the edge of our extinction, and just saying reliability and affordability is like putting on huge blinders,” Black said. “Sustainability has got to be a third prong of this work.”

Christiansen said while FERC must remain fuel neutral, the commission will play an essential role in ensuring the grid can manage the increasing number of distributed weather-dependent renewables.

“Wind and solar are probably going to be the predominant part of our resource mix before too long,” Christiansen said. “The best thing anyone can do if you’re an advocate of those resources is making sure that the infrastructure and the market rules are in place so that those resources can contribute to a reliable grid that people can afford.”

Climate advocates also pushed representatives of ISO-NE to do more to expedite fossil fuel retirements and emissions reductions, to which representatives of the RTO also stressed their resource neutrality. However, ISO-NE CEO Gordon van Welie said the RTO is open to implementing a carbon pricing mechanism in the RTO’s markets if all six New England states can reach an agreement.

“We’ve talked a lot internally about how we could implement carbon pricing,” van Welie said. “In my view, this is the quickest way to accelerate the clean energy transition.”

Also, van Welie highlighted the role that active demand response could play in reducing emissions associated with the daily peak load but said this “needs to be activated at the retail level” and therefore would be the jurisdiction of the states.

With peak loads on the grid expected to rise dramatically in the coming decades, “we have to really scale up demand response in this region,” van Welie said.

Several audience members echoed the need for accelerated demand response efforts but contended ISO-NE could play a larger role in engaging the public to reduce demand during times of peak load.

“I think I can speak for more than just some of the people in this room when I say we would rather turn everything in our apartments off than see a coal plant get called on for the peak,” said Rebecca Beaulieu of 350 New Hampshire.

In response, Anne George of ISO-NE said the RTO calls for conservation only during last-resort efforts to prevent forced outages, and that sending out frequent conservation requests would dull their effects when they are needed most.

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Overheard at GridWise Alliance’s gridCONNEXT 2023

WASHINGTON — The energy transition will require new sources of power as more of the economy is electrified and new investments in information technology are made to help balance the increased loads, speakers said at the GridWise Alliance’s gridCONNEXT conference Dec. 5. 

Rep. Bob Latta (R-Ohio) said he always asks how much more power the grid will need in the future when industry representatives come before the House Energy and Commerce Committee on which he sits. Responses vary, Latta said, but he contended that more supply — and particularly baseload resources — are needed to keep vital industries like steel manufacturing running. 

“The question always becomes is if you’re going to have to have more power, how do you get there?” Latta said. 

Latta co-chairs the bipartisan Grid Innovation Caucus with Rep. Marilyn Strickland (D-Wash.), and while they might have different visions on the future of the grid, some common ideas help them work across the aisle.

“We don’t snap our fingers and suddenly put in a bunch of charging stations and change how we are providing energy to people,” Strickland said. “We have to make sure that the infrastructure that we have is reliable, that we understand that this is as much about transmission and distribution as anything else, and making sure that we have adequate resources to make these investments.” 

Transportation is one of the sectors poised for greater electrification, and while the government offers plenty of subsidies for EVs, charging infrastructure is holding things back, Strickland said. 

“Automobile dealers have told us that the United States ranks at the bottom when it comes to EV sales,” she said. “And that’s not because people hate electric vehicle charging stations; we don’t have the infrastructure that makes someone feel as though they can trust how long the charge will last, or that is easily accessible to as many people as possible.” 

Taking Risks

The conversations in D.C. and other policymaking circles must eventually get past arguments about whether the energy transition is a good idea, said Gene Rodrigues, assistant secretary for electricity at the U.S. Department of Energy.  

“We need to get away from those people who are saying this is a terrible idea and those people saying this is a wonderful idea,” Rodrigues said. “But we need to get to a culture where people are trying to figure out how to make it work.” 

Rep. Kathy Castor (D-Fla.) | © RTO Insider LLC

Rodrigues said cultural changes around the issue could take a decade. Rep. Kathy Castor (D-Fla.) noted that congressional Republicans have tried to repeal parts of the Investment Reduction Act and Infrastructure Investment and Jobs Act, which are heavily funding the clean energy transition. 

“We simply don’t have time for that,” Castor said. “Notwithstanding the attempts by the oil and gas industry to take us backwards, the clean energy transition is happening swiftly.” 

As the share of energy demand served by electricity grows, so will consumers’ bills, and that is going to require an educational effort from the industry, Exelon Senior Director of Federal Policy Suzanna Mora-Schrader said. 

“The affordability piece of this is huge,” she said. “And part of that is not only about us being able to spend money, whether it’s federal dollars, or investment dollars from our rate base, it’s about making customers understand that more and more of their life is a function of electricity. And so, you’ve got to start driving people into understanding share of wallet as opposed to the increase in the bill.” 

Part of the transition is going to require utilities taking some risk, something Mora-Schrader said she learned about in previous jobs in less risk-averse industries. 

“If you want to do fast, we’re going to have to take some chances,” she added. “And that’s something for utilities to hear and that’s something for our regulators to hear.” 

Some of the investments utilities make will have less certainty than others, but they will still need to make them even if the risk cannot be eliminated, Mora-Schrader said. 

Maryland Public Service Commissioner Bonnie Suchman pushed back on the notion that regulators will have to embrace more risk. 

“I have to recognize reliability,” said Suchman. “We have got to keep the lights on; we have to keep them on now. Recognizing that we have to do [transition-related activities] in five and 10 years, that’s really important.” 

But on top of reliability, regulators need to ensure the grid is resilient against extreme weather and that affordability is not lost in the shuffle either, she added. 

“A third of Maryland’s residential customers are considered low- or moderate-income. We cannot leave them behind as we continue to deploy these various assets,” Suchman said. 

Sharing the Opportunity

One way to ensure the grid is resilient and affordable throughout the energy transition is to make demand more flexible through advanced meters, price signals and participation in markets as FERC Order 2222 contemplates. 

“We’re actually seeing transformers failing because of three people plugging in their EV at the same time,” said Mike Phillips, CEO of Sense, a home energy monitor company. “We’re seeing that happen in real time. And there’s two solutions: You either replace all the transformers that can handle these EV loads, or you see that this is happening and you start to make these things intelligent and responsive.” 

While some consumption is inflexible, ensuring a car has a full charge for the next day’s commute or the water heater is ready for the morning are not, and both can be controlled given the right technology and policy, he said. 

Either utilities or an independent distribution system operator (DSO) will have to coordinate all that activity at the distribution level, ensuring that nodes — or neighborhood circuits — can operate reliably with the new demand, said Curtis Tongue, chief strategy officer at OhmConnect.  

“All the devices within that node are able to do their optimization, and the single demand signal is output from that node,” he said. “And then there’s the node-to-node kind of optimization that the DSO or some market operator will be working with,” which would require an interface between the DSO and transmission system operator. 

Getting a dynamic system at the edge of the grid to tap into distributed resources can ensure that the utilities do not have to spend so much money that the transition becomes unaffordable, said Chris Irwin, DOE’s transactive energy program manager. 

“We cannot accomplish electrification of all loads without a monumental investment in grid infrastructure,” Irwin said. “If the utility is the sole investor in that control surface, we will suffer because of a high price tag. So, as we lift ourselves up, as we lift up grid infrastructure, we must contact those distributed energy resources; we must share the opportunity that exists.” 

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Grain Belt Express Asks FERC to Overrule MISO on In-service Date

Invenergy asked FERC on Nov. 7 to order MISO to allow it to energize part of its Grain Belt Express project in 2028 despite delays in upgrades needed in Ameren’s territory (EL24-35).

The approximately 800-mile, 600-kV high-voltage direct current transmission line will have the capacity to deliver up to 5,000 MW of renewable generation from Western Kansas to the Midwest and PJM.

Grain Belt Express (GBX) asked the commission to add a limited operation provision to Attachment GGG of MISO’s Open Access Transmission, Energy and Operating Reserve Markets Tariff.

Invenergy said it will be able to put Phase I of its project into operation in 2028 because it has obtained siting permits in all four states on its route and has nearly completed right-of-way acquisition.

However, on Sept. 15, MISO informed GBX that it was delaying the in-service date from Dec. 1, 2027, to Dec. 1, 2030, because two network upgrades Ameren will build require regulatory permits, extending the time for their completion.

GBX said it asked MISO to incorporate into its transmission construction agreement (TCA) an option for limited operations “comparable to the limited service options included in the commission’s pro forma large generator interconnection agreement (LGIA) for generator interconnections, and which some RTOs have explicitly expanded to merchant transmission.”

GBX said MISO rejected its proposal because it is not a provision in its current tariff. The RTO told GBX it would add the proposal to a list of issues to be discussed with stakeholders but that “it would not be something pursued in the near term as it is working through other pending initiatives, including completion of its Order No. 2023 compliance requirements … activities that can be expected to extend throughout 2024 and likely 2025 as well.”

GBX said that meant “by the time it finishes its pending initiatives, starts stakeholder proceedings, develops a tariff proposal, and then files it with and obtains commission acceptance, it will likely be close to or past GBX’s planned 2028 operations date.”

“As such, MISO’s promise to look into this at a later date may not result simply in a delay, but in practical terms, a denial of limited operation. It is important that GBX have certainty as it is lining up customer commitments and moving forward on obtaining financing, and that the potential for limited operation prior to 2030 be managed now.”

GBX said it will also ask FERC to modify the TCA, which MISO is expected to file unexecuted this month.

MISO did not immediately respond to a request for comment.

Limited Operation

Phase I of GBX will interconnect its Kansas converter station with a converter station in Monroe County, Mo. A 40-mile AC tie-line will connect that station to the MISO system along an Ameren Missouri 345-kV AC transmission line connecting the McCredie substation and the Montgomery substation and interconnecting with the Associated Electric Cooperative Inc. system at the McCredie 345-kV substation.

GBX said MISO should modify the TCA to allow limited operation of the project without the Ameren upgrades for whatever lower amount of capacity could be connected and injected prior to the upgrades’ completion.

It cited FERC’s pro forma LGIA, which says that, if upgrades are not expected to be completed prior to the commercial operating date of a generating facility, the transmission owner will perform studies to determine the extent to which a customer may operate prior to the completion of those upgrades.

GBX said it has commissioned studies “which, on a preliminary basis, are indicating that there should be some potential for operating at less than full capacity prior to the completion of the two Ameren lines.”

Invenergy said FERC’s “policy of providing a limited operation option to generator interconnection customers applies equally to MHVDC connection customers.”

It said PJM has merged its procedures for all types of new service requests, including merchant transmission interconnection, and explicitly permits limited operation of merchant transmission facilities if there is a gap period between the completion of the transmission and network upgrades.

“MISO’s rejection of GBX’s request for limited operation while it awaits completion of network upgrades for three years after the GBX facilities are completed is unreasonable given the urgent need for transmission in the U.S. and the harm to GBX,” it said.

It said the delay would require it to carry the financing cost of its projects for an additional three years before beginning service to paying customers.

It asked FERC for an expedited order by March 15, 2024.

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RSTC Sends DER Proposal Back to Working Group

At their quarterly meeting Dec. 6, members of NERC’s Reliability and Security Technical Committee rejected a proposal to endorse a standard authorization request (SAR) to update reliability standard EOP-005-3 (System restoration from black start resources) to better account for distributed energy resources.

NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group developed the SAR based on a recommendation in the ERO’s October 2022 Reliability Standards Review white paper, which the working group also developed. The group’s intended changes to EOP-005-3 would require transmission operators to consider the automatic responses of DERs when designing their system restoration processes.

But during the discussion of the SAR, several RSTC members said they were reluctant to endorse what they considered a lower-priority project, despite understanding the need to ensure DERs are accurately modeled in system planning. Southern Co.’s Todd Lucas reminded attendees that NERC’s Standards Committee “has got their hands full with … existing projects” and suggested that instead of “just [piling] more things in the hopper,” the RSTC could wait to send the SAR through.

“I’m questioning, does this one rise to the level of adding it into that hopper, or should we just take an opportunity to reprioritize and see where it falls out?” Lucas said. “Is it something we want to push forward now, or is it something that would be more effective if we pursued it later?”

After the motion to endorse the SAR failed — with 48% of the committee voting against, 41% voting for and 10% abstaining — RSTC Chair Rich Hydzik suggested that SPIDER rework the SAR and present it at the committee’s next meeting in March. Robert Reinmuller of Hydro One said it is important for the SAR to return to the committee as soon as possible.

“We don’t look good when we say, ‘Well, two years ago we thought this was important, and now we’re just going to ignore it for a little while,’” Reinmuller said. “Everybody knows today that as we add more DERs … and have more uncoordinated responses, and you don’t understand what a DER does or doesn’t do … the risk will continue to increase. So I think [this] document is very useful to create that clear visibility for every [generator operator] or every owner of assets that is connecting and operating DERs.”

PRC-006 SAR Approved for Comment Period

The EOP-005 SAR was the only one up for endorsement at the meeting; however, the committee did agree to post another SAR developed by SPIDER for a public comment period.

The SAR, also developed following the Reliability Standards Review paper, proposes to revise PRC-006-5 (Automatic underfrequency load shedding) to correct a potential danger to the grid from DERs tripping because of underfrequency load shedding (UFLS). This behavior could “impact the ability of the UFLS program to properly arrest a frequency decline,” SPIDER said.

SPIDER’s proposal noted that a minority of the group’s members felt it “should not be seeking posting or comment” on the SAR because other projects constituted a higher priority for the RSTC, but the committee approved its posting for a 45-day comment period.

The RSTC also approved several reference documents and security guidelines at the meeting:

    • 6-GHz communication interference white paper — discussing the potential for communication in the 6-GHz radio spectrum to interfere with the energy industry;
    • Product security sourcing guide and reference guide — helping asset owners identify and address potential cybersecurity vulnerabilities when purchasing grid control products;
    • Electric vehicle technical reference document — presenting a model for understanding the impact to the grid of charging EVs; and
    • Reliability guideline: fuel assurance and fuel-related reliability risk analysis for the bulk power system — providing information to help utilities ensure their fuel supplies are sufficient to ensure reliability.

The committee’s next meeting will be held in person at the Westin Gaslamp Quarter hotel in San Diego on March 13-14.

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FERC Orders Settlement Procedures on NY Utilities’ Tx ROE Filing

FERC has ordered two New York utilities into hearing and settlement judge procedures over their proposed return on equity (ROE) on transmission investments to support the state’s renewable energy goals (ER23-1816, ER23-1817).

The commission’s Dec. 4 order accepts for filing Rate Schedule 19 formula rate protocols and templates for Avangrid’s New York State Electric & Gas (NYSEG) and Rochester Gas and Electric (RG&E) effective July 3, 2023, subject to refund.

In response to a protest by the New York Association of Public Power (NYAPP), FERC called for hearing and settlement proceedings on the utilities’ proposed 10.87% “ceiling base” ROE — a fixed value in the formula rate that would be subject to a lower ROE authorized by the New York Public Service Commission.

NYAPP said FERC should adopt the ROE and capital structure approved by the New York commission in the most recent retail case for NYSEG — 9.2% for 2024, with a capital structure of 52% equity and 48% debt and customer deposits.

FERC agreed that the 10.87% ROE had not been shown to be just and reasonable. “We find that applicants’ proposed ceiling base ROEs raise issues of material fact that cannot be resolved based on the record before us and that are more appropriately addressed in the hearing and settlement judge procedures ordered below,” it said.

Schedule 19 and the Cost Sharing and Recovery Agreement (CSRA) — a voluntary participant funding agreement among the six New York state-regulated public utility transmission owners — are intended to provide a cost recovery and allocation framework for local transmission upgrades needed to meet the state’s Climate Leadership and Community Protection Act and the Accelerated Renewable Energy Growth and Community Benefit Act.

Historically, local transmission upgrades have been funded via bundled, local transmission and distribution rates. Under the CSRA, the costs are instead shared statewide and recovered on a volumetric load-ratio share basis from load-serving entities.

FERC’s order requires the settlement judge to file a report on the status of the settlement discussions in 60 days after the judge’s appointment.

While FERC sided with NYAPP on the ROE issue, it rejected the group’s contention that the formula rate misallocates administrative and general expenses.

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‘Missing Pathway’ Advancing Through Approval Steps in West

The proposed Cross-Tie transmission project — a 214-mile line across Utah and Nevada that’s seen as a missing link in the Western transmission system — is moving through the federal approval process with a targeted in-service date in 2027. 

TransCanyon LLC has proposed the 500-kV HVAC line connecting PacifiCorp’s Clover substation in Utah with NV Energy’s Robinson Summit substation in Nevada.  

The U.S. Bureau of Land Management, the lead federal agency for the project, released a draft environmental impact statement for the proposal last month. BLM expects to decide in 2024 whether to grant the developer’s right-of-way request. 

TransCanyon is a joint venture between Berkshire Hathaway Energy’s BHE U.S. Transmission and Pinnacle West Capital, the parent company of Arizona Public Service (APS). 

The 1,500-MW Cross-Tie transmission project will cost an estimated $750 million and is expected to begin service in 2027, according to TransCanyon’s website. TransCanyon plans to develop, own and operate the transmission facilities. 

Delivering Renewables

TransCanyon called Cross-Tie a “missing pathway” in the Western transmission system that would enhance resilience and reliability and boost the delivery of renewable energy. 

At its eastern end, Cross-Tie would connect to the southern tip of PacifiCorp’s 416-mile Gateway South transmission line, which runs across Wyoming, Colorado and Utah. 

At Cross-Tie’s western end is the Robinson Summit substation, the northeastern vertex of NV Energy’s planned transmission triangle around Nevada. The triangle consists of the proposed Greenlink North and Greenlink West lines and the existing One Nevada Line. 

TransCanyon said that Cross-Tie, in concert with PacifiCorp’s Energy Gateway projects, the Greenlink projects and the Harry Allen-to-Eldorado project in southern Nevada, would provide needed transmission capacity between the Intermountain West and the Desert Southwest. 

“This additional transmission capacity would facilitate access between the significant existing and planned renewable resources, primarily wind in Wyoming and wind or solar resources in central Utah and eastern Nevada, to the diverse utility load profiles in the Desert Southwest/California,” TransCanyon said in a development plan submitted to the BLM. 

In addition, Cross-Tie might reduce solar curtailments and battery storage needs in California and the Desert Southwest, the plan said. 

During a virtual public meeting hosted by BLM on Dec. 5, one attendee asked whether any contracts are in place that would guarantee Cross-Tie will deliver renewable energy. 

TransCanyon representative Roger Yensen said the developer plans to complete the environmental review process with BLM before entering into contracts. 

But given its strategic location, Yensen said, “we anticipate there will be a significant portion of energy that will be carried on the Cross-Tie [project] that will be from renewable resources.” 

In October, the U.S. Department of Energy announced it would become an anchor off-taker for three interstate transmission projects, including Cross-Tie. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) Yensen said negotiations with DOE are underway. 

TransCanyon isn’t currently planning to connect Cross-Tie to the Intermountain Power Plant in Utah, even though the transmission project’s path runs near the facility. But that could be considered in the future, according to the development plan. 

Alternative Routes

In its environmental review of Cross-Tie, BLM is examining the developer’s proposed transmission path as well as several alternatives that would add four miles to about 150 miles to the route. BLM staff said the transmission project will cost roughly $3.5 million per mile. 

One alternative route addresses concerns from the town of Leamington, Utah, about the project’s impacts on scenic views. 

“Why would any project be proposed that destroys the view the residents of Leamington have enjoyed and cherished for over 150 years when a viable alternative is readily available?” Leamington’s mayor said in a written comment submitted for the virtual meeting. 

Other alternatives were designed to reduce impacts to cultural resources, environmentally sensitive areas or the U.S. Department of Defense’s Utah Test and Training Range. BLM has not yet selected a preferred alternative. 

In addition to the virtual public meeting, BLM held four in-person meetings on Cross-Tie in late November. 

The deadline to comment on the draft environmental impact statement is Jan. 2. 

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MISO Champions Queue Crackdown as Stakeholders Blast MW Cap on Project Entries

ORLANDO, Fla. — Several MISO stakeholders took exception to the RTO’s proposal before FERC to cap the volume of interconnection requests it accepts annually. 

MISO made two filings with FERC last month to establish an annual megawatt cap on projects, enforce stricter proof of land use, enact automatic and escalating monetary penalties for withdrawals, and increase milestone fees for its generator interconnection queue (ER24-340 and ER24-341). (See MISO’s More Stringent Interconnection Queue Rules Go Before FERC.)  

DTE Energy said a queue cycle cap would be “unprecedented” and argued it won’t address “the root cause of MISO’s inability to timely process interconnection requests.”  

DTE said it’s not the number of projects overall, but the percentage of speculative projects in the queue that’s the problem. Developers have resorted to “over-saturating the interconnection queue with projects as an insurance strategy to secure a position” because of long wait times in the queue, DTE argued. DTE supported the other aspects of MISO’s queue rule changes.  

MISO has said there are only so many potential generation projects it can simultaneously consider in interconnection studies while still achieving accurate results. (See MISO Relaxes Proposal on Stricter Queue Ruleset.) 

But the Coalition of Midwest Power Producers argued MISO wants to impose a megawatt cap “without articulating how a lower volume will ensure accelerated queue processing.” The coalition said MISO didn’t detail “unique processes or additional computing power to resolve the volume and study pace issues that have been the albatross of the MISO queue process.”  

NextEra Energy agreed MISO didn’t provide evidence to show a cap will “remedy or mitigate the factors leading to its unwieldy, inefficient and untimely interconnection queue.” It said the cap will stymie competition and create barriers to entry for smaller generation developers.  

Ameren said it thought the cap “is a blunt tool that is not fully thought out and may result in unjust outcomes.”  

Xcel Energy, on the other hand, said MISO has sufficiently explained a megawatt cap is key to alleviating the overstuffed queue. Entergy agreed the sheer size of the interconnection queue is interfering with “realistic” study results and not giving developers a clear picture of whether they should proceed with generation projects.  

The Organization of MISO States also threw its support behind the cap, saying a “backstop mechanism is needed — at least temporarily — to ensure MISO can produce realistic network upgrade studies based on a smaller, more manageable queue size.”  

“MISO’s queue is oversaturated with projects that are vying to identify the cheapest locations to interconnect, causing MISO to choose to effectively shut down its interconnection queue,” OMS told FERC.  

MISO’s current generator interconnection queue contains more than 1,300 projects at nearly 230 GW — nearly double MISO’s summertime peak demand.  

“It is not reasonable to expect MISO to continue to try and work through this level of requests in its queue process,” Xcel said.  

In a joint protest, the American Clean Power Association, the American Council on Renewable Energy, the Solar Energy Industries Association and Clean Grid Alliance argued that limiting projects annually is diametrically opposed to the rapid transition of clean energy resources. They said it’s only natural MISO’s queue has expanded rapidly in recent years.  

“If accepted, the cap proposal would create perverse incentives that will create havoc, increase uncertainty and discriminate against the very clean-energy resources that the region needs,” the clean energy groups contended.  

Alliant Energy argued MISO’s proposal to cap queue cycles is an odd choice when the grid operator has been telling stakeholders new capacity additions are crucial. Alliant referenced OMS’ most recent resource adequacy survey showing the footprint runs the risk of a 9-GW capacity shortfall by 2028.

MISO Leadership Hopeful for ‘More Confident, Less Speculative’ Projects

At MISO Board Week in Orlando, Executive Director of Resource Planning Scott Wright said even though there are some complaints, stakeholders’ comments reveal “a broad consensus that the staggering queue line was unsustainable.”  

Scott Wright, MISO | © RTO Insider LLC

Wright said an annual megawatt cap on projects, an automatic penalty scheduled for withdrawal and increased milestone fees will encourage a “more confident, less speculative” class of projects to enter the queue.  

“Many of the projects in the queue are highly speculative despite our past rule changes to use a ‘first-ready, first-served’ approach,” he said. Wright also said MISO’s existing withdrawal process are too “low-consequence.”   

Wright added that the “staggering” number of queue projects is developers’ “rational” response to more favorable economic conditions for renewable energy development. He said it’s natural MISO found itself having to tighten requirements, so its historically “high-quality” queue isn’t compromised. 

Wright said since the last Board Week in September, members have announced more retirement plans, with Michigan adopting a clean energy pledge by 2040. 

MISO predicts it will add about 250 GW in installed capacity over the next 20 years, but it will only amount to a 38-GW increase to MISOS’s current 172 GW in accredited capacity.  

50 GW in Greenlit and Unfinished Projects Haven’t Budged

Wright added that the prospective projects in the queue still face inflation and supply chain headwinds. MISO’s large number of approved but unbuilt generation projects hasn’t budged since the summer. (See MISO: Reliability Risk Upped by 49 GW in Approved but Unbuilt Generation.)  

Today, 50 GW across 316 projects are awaiting construction, with 50% of those developers saying wait times will average 650 days until commercial operation. Most of the on-hold projects are solar generation, accounting for 32 GW.  

By year’s end, Wright said that amount could grow to nearly 60 in approved but unbuilt generation projects.  

Vice President of System Planning Aubrey Johnson said nationally, 260 GW in generation projects have signed interconnection agreements in the organized markets and yet remain unconstructed. Johnson said that side of the issue deserves more awareness in conversations about the country’s interconnection woes, when usually, inadequate transmission planning is emphasized.  

“This is something that needs national attention. It’s something that we call attention to at every turn,” Johnson said.