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October 31, 2024

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Clements Outlines Further Steps to Ease Interconnection Woes

BOSTON — Order 2023 is just the first step in addressing the interconnection backlogs in New England and across the country, FERC Commissioner Allison Clements said at Raab Associates’ New England Electricity Restructuring Roundtable on Dec. 8. 

“It would be silly and naive to think that we would fix the interconnection queue just by taking a first step,” Clements said. She outlined several next steps that were detailed in her concurrence on Order 2023. 

The commissioner said addressing transmission planning issues will be key to reducing backlogs. FERC has been working on a final rule on transmission planning, which has generated significant interest from environmental, industry and labor groups. (See FERC Gets Growing Calls to Finish Transmission Rule in 2024.)

“Fundamentally, we’re not going to fix the interconnection queue process if the transmission system planning process doesn’t anticipate and doesn’t recognize what’s in the queue,” Clements said. 

Clements highlighted the potential of a default cost-sharing mechanism for large transmission projects that would prevent disagreements between states from hindering progress. 

“If the states can agree on a cost-allocation approach, great. But what happens if they can’t?” Clements asked. “There’s a lot of support for a default mechanism so that the infrastructure that comes out of this robust planning process can then get cost-allocated and we don’t worry about a single-state veto or free-ridership concerns.”  

Regarding state clean energy solicitations, Clements told attendees that “resource planning processes across states should be aligned with the interconnection queue … if you can’t get your state-solicited resources online, then we have an immense problem.” 

New Technologies

Clements also spoke about the potential of grid-enhancing technologies (GETs), calling them the “cheapest, nearest term, shortest payback investments that we can make related to getting more efficiency out of our existing system.”

She added she’s considering which GETs should be included in a final rule on transmission planning.

Hudson Gilmer, CEO of the grid monitoring and analytics company LineVision, said the adoption of dynamic line ratings has accelerated across the country, in part because of the pressures of load growth and the availability of federal funding from the Department of Energy’s Grid Resilience and Innovation Partnerships Program.

Hudson Gilmer, LineVision | © RTO Insider LLC

However, Gilmer said the Northeast has lagged in its adoption of GETs. 

“The U.S. is behind the rest of the world … and let’s be honest, New England is behind the rest of the country,” Gilmer said. He added that GET adoption “can be accelerated by incentives that level the playing field with more capital-intensive traditional grid upgrades.” 

Sarah Jackson of the multiday battery storage company Form Energy highlighted the potential benefits of long-duration storage to New England, detailed in a white paper published by the company in September. (See Form Energy Wants to Bring Long-duration Storage to New England.) 

Jackson said the lack of recognition in ISO-NE’s capacity market of the reliability benefits of multiday battery storage is one of the factors holding back the technology in New England.  

“This is a place where the markets have not caught up to the technology,” Jackson said. She added that state procurements of long-duration storage could help speed up its commercial development in New England.  

“We don’t have the luxury of waiting for the technology to mature, we need this energy storage yesterday,” Jackson said. 

Gas Decarbonization

Two days prior to the Roundtable, the Massachusetts Department of Public Utilities (DPU) released a major ruling following a multiyear investigation into the Future of Natural Gas in the state (DPU 20-80-B). 

The release of the ruling came as a surprise to many stakeholders in the state and generally was applauded by environmental groups for its emphasis on weaning the state off gas. (See Massachusetts Moves to Limit New Gas Infrastructure.) 

“The focus is on setting a regulatory framework that is flexible, protects consumers, promotes equity, and provides for fair consideration of current technologies and commercial applications,” DPU Chair Jamie Van Nostrand told the Roundtable. 

Massachusetts DPU Chair Jamie Van Nostrand | © RTO Insider LLC

Van Nostrand said the order is intended to bring the state’s gas industry and heating sector into compliance with the state’s statutory emissions targets, including the sector-specific sublimits established in the state’s Clean Energy and Climate Plan for 2025 and 2030. 

“We’re either serious about addressing climate change in Massachusetts, or we’re not. We’re either serious about meeting the sector sub-limits for greenhouse gas emissions, or we’re not,” Van Nostrand said. 

Despite the state’s climate goals, the gas utilities have continued to operate as if it is “business as usual,” Van Nostrand said. “We’re still seeing 1 to 1.5% annual growth in gas load.” 

Nikki Bruno, vice president of clean technologies at Eversource Energy, one of the major gas and electric utilities in the state, said she is “really excited about the guidance in the order.” 

Bruno highlighted Eversource’s ongoing networked geothermal pilot project in Framingham, Mass. (See Networked Geothermal Breaks Ground in Framingham.) 

The pilot project “positions Massachusetts as a state leader in this technology, and we’re looking forward to more,” Bruno said. “It doesn’t matter that it’s not gas, we want to do right by the customer.” 

Zeyneb Magavi, co-executive director of HEET, a climate nonprofit that’s been working with Eversource on the project, said geothermal networks could be a significant tool in decarbonizing dense environmental justice neighborhoods.

“The hardest places for us to decarbonize today are often the ideal places for geothermal networks,” Magavi said. 

Looking ahead, several speakers at the Roundtable spoke about the need to address state laws that require utilities to provide gas to existing customers who request it. Under these laws, individual gas customers could prevent the decommissioning of parts of the gas network.  

“I do think we need to revisit that obligation to serve, to make it clear that customers are still going to be provided the essential utility service of heat, but it may be provided in some way other than gas,” Van Nostrand said. 

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CAISO Discusses Year-ahead Requirements for RA Program

CAISO staff and stakeholders on Dec. 6 again dove into the details of the ISO’s resource adequacy construct, including increasing visibility, creating year-ahead requirements and refining the existing capacity procurement mechanism (CPM).

The ISO’s Resource Adequacy Modeling and Program Design Working Group is getting into the weeds of how to plan for RA in different time horizons, including the year-ahead, two- to four-year and five- to 10-year time frames. During its third meeting, the group focused on the year ahead.

Aditya Jayam Prabhakar, CAISO lead resource assessment and planning analyst, presented a proposed assessment of RA showings, designed to determine if load-serving entities have procured enough resources for the ISO to meet the one-in-10-year standard. Staff discussed potential modeling inputs for determining sufficiency, questioning what resources should be included in the assessment.

“As the world is changing and you have a lot more variable energy resources, probabilistic modeling of risks is necessary,” Prabhakar said. “Ensuring reliability is the responsibility of the ISO, and that’s what we’re trying to assess here.”

CAISO proposed a variety of inputs to be put into a stochastic production cost model that would run simulations and determine surplus and deficit megawatts, including information on when a shortfall is occurring and for how many megawatt-hours. They include the California Energy Commission’s one-in-two load forecast, 500 load profiles, 500 wind and solar profiles, hydro and imports modeling, and outage draws.

There was some disagreement surrounding the resources the ISO chose to include in the modeling. In particular, some stakeholders thought strategic reserves and other emergency resources should be included.

“I’m curious about the decision to exclude the strategic reliability reserve and the reliability demand response resources from this assessment,” said Doug Boccignone, principal with Flynn Resource Consultants. “We’re treating these as hidden resources that we are not acknowledging exist, but we know we will rely on them and have relied on them in the past, and that just seems like we’re now creating a standard that is much higher than a one-in-10.”

Prabhakar answered that the intent of the RA program is to ensure operation under normal conditions and to avoid emergency events.

“Accounting for resources that are only accessible for us under emergency conditions, I think in our opinion, defeats that purpose because that essentially means that we’re planning to get into emergency conditions,” Prabhakar said.

Still, Boccignone suggested including extreme load events and the resources they expect will be available to meet those loads in the stochastic modeling so they can ensure they’ve “got it covered” in the event of bad conditions. He was also concerned with how this modeling could affect the decision to backstop should the ISO choose not to include emergency resources in modeling.

“If you weren’t considering those resources when you’re deciding to CPM something, that would be a mistake. If you know you can count on them, they’re going to be there; there’s no point in CPMing,” he said.

However, Nuo Tang of Middle River Power pointed out that emergency reserve type resources are generally used only after the RA program exceeds a 0.1 loss-of-load expectation, and therefore shouldn’t be included for the purposes of reaching 0.1.

Kallie Wells, senior consulting with Gridwell Consulting, also questioned if energy-only resources that can be used to charge batteries should be included in modeling.

“I think it makes as a good question as to whether or not there is a way to maybe include them only so that they can charge the batteries,” Wells said. “Then the batteries are able to discharge up to the amount that they’ve been shown for, but not necessarily include those resources to also be discharged to the grid.” Not including them could impact storage resource availability, she added.

Closing the Gap Between 90-100% Showings

The year-ahead time frame considers both shown capacity and forecast eligible capacity. Currently, the framework requires LSEs to provide 90% showings from May to September for system RA requirements, with the remaining 10% not shown because of the wide range of varying local regulatory authority requirements, leaving room for assumptions. As a result, CAISO questioned how to close the gap between 90 and 100% showings, assuming the remaining 10% could be RA-eligible resources held back for substitution or non-RA resources.

Kyle Navis, senior analyst with the California Public Utilities Commission’s Public Advocates Office, questioned if CAISO could request a nonbinding showing of the 90% requirement in the year-ahead showing process.

“If LSEs at the time of the showing are contracted to a compliance position that is above 90%, would they be able to show those additional resources without that additional capacity being bound by rules to acknowledge that there may be some movement in the market until the month-ahead showing process?” Navis said. “It seems like it would maybe close the assumption gap a little bit so that it’s not just ISO staff trying to come up with your best guess.”

Prabhakar answered that, if the process is effective, no one will have to make guesses on what resources will be available.

“If we have an approach where we can get 100% shown capacity for each month, and we don’t have to make any assumptions — that’s the idea of this entire process: We want to limit the number of assumptions that are made.”

The group will discuss the two– to four-year time frame during its next meeting, tentatively scheduled for Jan. 16.

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MISO Board Approves $9B MTEP 23; Members Deliberate on New Expedited Review Rules

ORLANDO, Fla. — MISO board members last week greenlit the $9 billion, 572-project 2023 Transmission Expansion Plan (MTEP 23), which contained the most expedited project reviews the RTO has ever conducted.

MISO directors unanimously approved the 2023 collection of transmission projects at a Dec. 7 board meeting. MTEP 23 more than doubles the spending of last year’s package and triples that of MTEP 21.

Executive Director of Transmission Planning Laura Rauch has said MISO expects bigger MTEP projects to continue in future cycles. She said MISO will perform economic screens on projects that may have regional potential on a case-by-case basis and will conduct alternatives analysis on large, complex projects.

Regarding MTEP 23, Rauch said the RTO is “confident” it landed on an appropriate alternative for the largest MISO South project to help relieve the strained Amite South load pocket in southeast Louisiana.

“Facilities that propose new lines or are larger in cost and potential impact on the system are prioritized for analysis. Roughly 75% of MTEP 23 projects didn’t meet criteria for alternative solution analysis, as they address needs with no cost-effective alternatives,” Rauch said during a November System Planning Committee meeting of the MISO Board of Directors that was held in preparation for last week’s vote.

Just three of MISO’s 11 member sectors voted to support the MTEP 23 package of projects. (See 3 MISO Sectors Vote to Recommend MTEP 23, Majority Silent.)

Since MTEP 03, $35 billion in transmission investment has gone into service in MISO, with $23 billion planned or under construction. The $23 billion includes the $10 billon first portfolio of long-range transmission plan projects approved last year.

MISO members, meanwhile, mused about how the process behind expedited project reviews under the MTEP cycle might change.

The RTO has said the growing number of expedited project review requests it studied under its MTEP 23 planning cycle means it should rethink its expedited review process for transmission projects that can’t wait until the usual December MTEP approval to begin construction. (See “MISO: Expedited Review Process Needs Revamp,” MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)

MTEP 23 Investment breakdown | MISO

MISO said it fielded more than 30 expedited project review requests — double the number it received in 2022 — predominantly because of new load interconnections.

Some members said the increasing number and growing sizes of projects requested for expedited treatment cause concern.

“The size, the magnitude of the projects are becoming a bigger deal,” Clean Grid Alliance’s Beth Soholt said. She said MISO might consider increased transparency around project requests and its review.

ITC’s Brian Drumm said MISO could raise its minimum $1 million threshold for projects to be vetted when they’re built out of the usual MTEP cycle. He said the dollar limit has been in place for years and hasn’t been adjusted for inflation. A higher threshold would scale back the projects that require expedited review and mean the RTO isn’t spending time reviewing insignificant projects, Drumm said.

LS Power’s Brenda Prokop said MISO might consider more proactively planning transmission for new load so fewer expedited reviews are needed.

MISO will hold more discussions on how it might overhaul its expedited review process in public stakeholder meetings next year.

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FERC Gets Growing Calls to Finish Transmission Rule in 2024

A growing chorus of stakeholders is hoping to see a final transmission planning rule from FERC sometime in the New Year, with a set of letters sent to the commission last week.

A group of nongovernmental organizations including Advanced Energy United, American Clean Power Association, Earthjustice, Environmental Defense Fund and Sierra Club said finalizing the transmission planning rule was important to ensuring the incentives from the Inflation Reduction Act actually get used and increasing the resilience of the grid to extreme weather.

“The electric industry is undergoing a major transformation driven by consumer, utility and corporate preferences, state public policies and the cost-competitiveness of renewable energy,” said the letter sent to FERC Dec. 8. “The commission’s transmission planning and cost allocation standards must be up to the challenge of enabling this transition while ensuring the continued provision of reliable and affordable electricity at just and reasonable rates.”

Another letter largely signed by power companies and labor including Ameren Transmission, Consolidated Edison, Exelon, the Blue-Green Alliance and the IBEW International also urged FERC to act.

“We support the commission’s proposal for regional, long-term, scenario-based transmission planning and urge the commission to issue, as soon as practicable, a final rule that will facilitate needed transmission investment,” the letter said. “The commission should ensure that the final rule is sufficiently robust to achieve the commission’s goal of ensuring just and reasonable rates and ‘remedy[ing] deficiencies in the commission’s existing regional transmission planning and cost allocation requirements.’”

FERC still has one more meeting this year, but it is unlikely to move the final transmission rule, as it has yet to issue a substantive order on rehearing for Order 2023, in addition all the other work before its staff, said consultant Rob Gramlich at a press event Dec. 8 hosted by Americans for a Clean Energy Grid.

“The chairman and his staff have been saying, ‘we want this to be durable, legally, you know, we’ve got to dot every I and cross every T and make sure,’” Gramlich said. “You know, most rules like this do get challenged and, so, they’re planning for that. And … that’s all competing against time. We don’t have time. It feels to me like 18 months is enough. It’s time to get the order out.”

The last time FERC issued major transmission reforms was Order 1000 in 2011, and that was meant to be an iterative process, said ACEG Executive Director Christina Hayes. A major issue driving the change then was state policies, especially renewable portfolio standards.

“I think it’s a matter of kind of evolving the process and evolving the analysis, where things right now are very focused on the silos — economic reliability, and policy silos — and kind of breaking free of those and recognizing that renewable requirements are being driven by customers, by utilities, who are getting out ahead of their states,” she added.

Gramlich said Congress also could move forward on transmission proposals, including a bipartisan permitting reform effort led by Sens. Joe Manchin (D-W.Va.) and John Barrasso (R-Wyo.).

While transmission largely is a priority for Democrats in this Congress, it was not always that way. The Energy Policy Act of 2005, with its reforms on transmission, came out of a Republican Congress and was signed by a Republican president. There’s reason to believe the party might get on board with transmission reforms this time.

“Everybody cares about reliability,” Gramlich said. “Everybody will soon be aware of massive load growth that’s happening for the first time in over two decades. And that’s a reason to build transmission. So, there’s a lot of nonclimate reasons if climate isn’t your priority.”

Even once all the policies are put in place, the industry and regulators will have a massive job working to expand the grid. Princeton University has said the grid needs to expand by 60% by 2030 and triple by 2050, but that does not even take into account the amount of industrial reshoring and other sources of demand growth, Hayes said.

“I think we can do it,” Gramlich said. “And we know that because we did do it 10 years ago. If you look at, like, 2013: the MISO MVPs come online, the SPP Priority Projects, ERCOT CREZ (Competitive Renewable Energy Zones), the Tehachapi buildout — all in one year. That happened to be in the same year when there was another period of time when everybody was talking about big transmission … and we got a lot done. And then … we kind of like just lost our momentum for a variety of reasons.”

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Board OKs MISO Budget Increase for 2024

ORLANDO, Fla. — MISO’s base operating budget will increase 15% in 2024, mostly because of the grid operator adding about 70 staff positions so it can keep up with the pace of change and emerging issues in the footprint.

MISO’s Board of Directors approved the nearly $400 million budget for 2024 at a Dec. 7 meeting, continuing a trend of budget increases year-over-year.

MISO is proposing a $370 million 2024 operating budget, which contains a nearly 15% increase in base operating spending over 2023. It also is eyeing approximately $27.3 million in capital spending.

MISO has said it struggles to keep up with its current workload under existing staff levels and the hires will help it accomplish projects under intended timelines.

MISO will up its $0.44/MWh tariff rate for members to $0.47/MWh next year.

The grid operator is poised to end the year with base expenses about 1.8% over budget, or $4.3 million. MISO said the cost overruns are mostly due to a $5 million cost overrun in salaries and benefits this year, due to hiring more staff, market pressures, and more overtime and on-call work.

MISO CFO Melissa Brown said MISO has returned to a more normal 3% employee vacancy rate after experiencing a 6% vacancy rate at the beginning of the year. She said the COVID pandemic was a “very strong lesson in how labor market dynamics can substantially impact [MISO].”

Brown said MISO is trying its best to get expenses down before year’s end, but the salary component is somewhat out of MISO’s control.

“Quite honestly, we’re talking about $50,000 line items right now, asking, ‘Do we really need to do that?’” Brown asked during a Nov. 30 meeting of the Audit and Finance Committee leading up to Board Week.

Brown said anticipating future budgets, especially on the five-year horizon into 2028, is becoming more challenging as the resource transition ensues and stubbornly high inflation sticks around.

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MISO Expecting Quiet Winter

ORLANDO, Fla. — MISO leadership predicted adequate supply paired with a temperate winter at the final Board Week of the year.

“Under normal conditions, we should be flush this year. If everything goes as planned, you won’t hear much from me come March,” Executive Director of Market Operations J.T. Smith told the Markets Committee of the MISO Board of Directors Dec. 5. “We have El Niño out there, keeping the Pacific Ocean waters warm. While we’re expecting this winter is going to be mild, we’re preparing for a significant drop in temperatures. … Winter Storms Uri and Elliott are great examples of how cold can blast into the footprint.”

MISO has said its winter demand could top 106 GW, with about 121 GW of supply available under normal grid and generation outage conditions. However, the RTO hasn’t ruled out the possibility of an emergency sometime in January. (See MISO: Possibility of Winter Emergency in January.) MISO’s record winter power demand, 109 GW, occurred Jan. 6, 2017.

Smith said it isn’t surprising NERC’s 2023-24 Winter Reliability Assessment highlighted fuel supply issues throughout the footprint and MISO South’s risk of high outages from inadequate weatherization if a deep freeze strikes southern states. Smith said MISO South generators rarely experience sub-zero temperatures, so they don’t prepare as if they’re an everyday occurrence.

“There is a risk that cold extends into the South, and that could be an issue,” he acknowledged.

Smith also said MISO members have access to healthy stores of natural gas and coal stockpiles heading into winter.

MISO’s 2023/24 generator winterization survey showed that 97% of MISO units responding to the survey have undergone winter preparations, 97% have recently reviewed NERC’s winter readiness guidelines and 96% have a severe cold weather checklist. The response rate of the survey was 92% of MISO generators. MISO said the reported level of preparedness generally is better than last year’s. The RTO uses its winter preparedness survey to inform its real-time market operations.

MISO also is preparing draft emergency trading rules for neighbors Louisville Gas & Electric/Kentucky Utilities and East Kentucky Power Cooperative, Smith said.

MISO’s Independent Market Monitor recommended MISO draw up emergency supply agreements with its non-RTO neighbors after MISO flowed a few gigawatts of power exports to utilities in the Southeast during winter storms last Christmas.

Monitor David Patton said he concurred with MISO’s take on the upcoming winter. However, he said an extreme winter event could drive forced generation outages to 29 GW and have MISO nearly draining its reserves. He qualified that MISO’s wind fleet usually performs well during winter weather events, so MISO experiencing a near-zero margin is unlikely, even if utilities’ gas scheduling becomes a problem.

“We should be OK this winter,” Patton concluded, though he added, “Thinking through fuel security is going to become a lot more important in the future.”

Smith also said MISO thankfully experienced a “wholly unremarkable” fall, with normal load, coal and fuel prices remaining inexpensive at about $2/MMBtu and no hurricane activity affecting the southern footprint.

MISO’s fall peak arrived early in the season on Sept. 5 when late summer heat drove 115 GW in load.

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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.