Search
`
November 4, 2024

Posted on

PJM PC/TEAC Briefs: Dec. 5, 2023

Planning Committee

PJM 2024 Load Forecast Sees Jump from EVs, Data Centers, Heat Pumps

PJM’s preliminary load forecast for 2024 sees higher growth for both summer and winter, driven by electric vehicles, data centers and state incentives for heat pumps.  

The 15-year annualized growth rate increased to 1.6%, doubling the 0.8% growth rate in the 2023 forecast, with the difference between the two forecasts accelerating in later years, said Molly Mooney, who presented the forecast to the Planning Committee on Dec. 5.  

The 2027 preliminary forecast is 4.4% higher than the 2023 forecast (6,600 MW) while the 2038 preliminary figures are 13.9% higher (22,400 MW). 

The main drivers behind rising summer loads are EVs and data centers, which respectively contributed 3,700 MW and 4,000 MW in load growth over the 2023 forecast, without which Mooney said summer loads would remain largely flat. Solar generation reduced summer loads by 200 MW and energy efficiency provided a 750 MW reduction.  

The 15-year outlook for winter loads increased to a 1.9% annualized growth rate over the 0.9% in the 2023 forecast.  

The main policy change affecting the winter load forecast is New Jersey’s Executive Order 316, which has a goal of electrifying 400,000 homes and 20,000 commercial buildings by 2030. (See “Transitioning Commercial Buildings,” NJ Advances Multifaceted Building Decarbonization Strategy.) 

Mooney said this is the second year that PJM conducted the study using hourly forecasting rather than the daily peak methodology previously used. The commercial and residential data used in the study is based on 2013-2022 census figures. 

This was the first year that S&P Global was contracted to provide estimates of plug-in EV data. The company forecasted that there would be around 7.5 million such vehicles in PJM’s footprint by 2030. The Met-Ed territory is expected to see the largest number of medium and heavy duty EVs, owing to the large number of warehouses and shipping corridors in its region. 

Transmission Expansion Advisory Committee

Second Read of $5 Billion in RTEP Projects

PJM reviewed its proposed $5 billion package of transmission projects in the third window of the 2022 Regional Transmission Expansion Plan (RTEP), which is primarily aimed at addressing data center load growth in northern Virginia and generation retirements. (See PJM Recommends $5B in RTEP Transmission Projects.) 

PJM’s Sami Abdulsalam said the proposal is the most efficient, cost-effective and resilient set of solutions of the 80-plus project combinations staff analyzed. The package would construct new 500-kV lines from northern Virginia out to the Peach Bottom substation to the northeast, the 502 Junction substation to the northwest and the Morrisville substation to the south.  

PJM’s Sami Abdulsalam | © RTO Insider LLC

When considering the 72 proposals PJM received during the competitive process, Abdulsalam said staff prioritized cost, maximizing use of existing rights-of-way and scalability. 

PJM Senior Vice President of Planning Ken Seiler said the concerns members of the public have raised during previous TEAC meetings and letters to the Board of Managers have been noted. Many of the objections centered around siting issues, which he said will be the focus of the routing process transmission owners would go through after possible board approval. 

“This is a pretty significant body of work and we’ve received a lot of pushback and a number of letters from residents … we’ve heard from you,” Seiler said. 

PJM included with its meeting materials an FAQ detailing its role in selecting the proposals in the window. 

First Window of 2023 RTEP Set for Board Consideration in February

Abdulsalam presented a first read of three projects being added to PJM’s recommended transmission expansion in the first window of its 2023 RTEP, which is set to go before the Board of Managers for approval in February. 

The window includes a $42.05 million project to address an overload of APS’ Belmont 765/345-kV transformer by replacing the equipment with a new transformer bank; a $10.22 million rebuild of Commonwealth Edison’s 138-kV Haumesser Road-West DeKalb Tap line; and a $7.75 million proposal to add three 345-kV circuit breakers to ComEd’s Cherry Valley substation. 

The three proposals join several projects in the first window aimed at addressing reliability issues identified in the Public Service Enterprise Group, PECO Energy, Dayton Light and Power, American Electric Power (and Ohio Valley Electric Corp. zones. 

Abdulsalam presented a second read of the existing projects, which amount to around $42.4 million. The proposals include: 

    • Replacing 230-kV and 345-kV fixed shunt reactors with higher rated variable reactors for $29.6 million to resolve high voltage issues around PSEG’s Waldwick substation; 
    • Replacing an over-duty 345-kV circuit breaker at AEP’s Olive substation for $1 million; 
    • Replacing breakers, switches and other equipment owned by AEP and OVEC at the Kyger Creek station for $1.16 million; and 
    • Reconductoring 8.8 miles of DPL’s Silver Run-Cedar Creek double-circuit 230-kV line and replacing infrastructure at both substations for a total of $8.7 million. 
Posted on

SCOTUS Won’t Take up Texas Appeal of ROFR Law

The U.S. Supreme Court on Dec. 11 declined to take up an appeal of a lower court’s ruling that a Texas law giving incumbent transmission companies the right of first refusal (ROFR) to build new transmission lines was unconstitutional.

The Texas Public Utility Commission, with then-Chair Peter Lake as the lead petitioner, requested a writ of certiorari last December after the 5th U.S. Circuit Court of Appeals’ decision earlier in 2022. (See Texas Petitions SCOTUS to Review ROFR Ruling.)

The appeals court found for NextEra Energy in its challenge to a 2019 Texas law (Senate Bill 1938) that set up a ROFR within state lines. It ruled the legislation violated the U.S. Constitution’s dormant Commerce Clause, and it remanded the case back to the U.S. District Court for Western Texas. (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.)

The Supreme Court gave no reason for not taking up the appeal, as is typical. It included the rejection (22-601) among dozens of other appeals it will not take up this term.

The high court says it receives about 10,000 requests for certiorari each year. Only about 100 of those are granted, allowing petitioners to make oral arguments before the justices on why the lower court was wrong.

U.S. Solicitor General Elizabeth Prelogar in October recommended the Supreme Court not to take up the ROFR case. She said the petition is not a “suitable vehicle” for reviewing the constitutionality of ROFR laws.

“The 5th Circuit got it right that the Texas law was unconstitutional,” Paul Cicio, chair of the Electricity Transmission Competition Coalition, said in an email to RTO Insider. “Blocking new entrants from competing on transmission projects isn’t just unconstitutional; it’s anti-consumer, anti-free-market policy that costs consumers billions of dollars in higher electricity rates.”

The coalition said FERC should see the denial as a “clear signal in support of transmission competition.” It said FERC has an opportunity to take action now in a pending complaint under Section 206 of the Federal Power Act against MISO to ensure the grid operator no longer applies ROFR laws when conducting transmission planning (EL22-78). (See Big Savings for Tx Competition Claimed as FERC Considers a New ROFR.)

Most recently, an Iowa court struck down that state’s ROFR law, saying the procedure used to pass the bill was unconstitutional. (See related story, Iowa ROFR Law Overturned, Throwing Multiple MISO LRTP Projects into Uncertainty.)

NextEra Energy Capital Holdings, NextEra Energy Transmission (NEET), NextEra Energy Transmission Midwest, Lone Star Transmission, NextEra Energy Transmission Southwest, Southwestern Public Service, Entergy Texas, Oncor, LSP Transmission Holdings II and East Texas Electric Cooperative were also named as respondents in the petition.

NextEra subsidiaries were involved in two projects in Texas’ non-ERCOT footprint that ran afoul of the ROFR law. NEET Midwest won a competitive bid in 2018 for a $130 million, 500-kV project in East Texas. MISO said last year that planned capacity in the region had negated much of the project’s economic benefits. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)

NEET Southwest also applied to the Texas PUC in 2018 to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s East Texas footprint. That application was withdrawn in 2020 after SB 1938 became law (48071).

Posted on

NY Reliability Council Approves 22% IRM for 2024/25

ALBANY, N.Y. — After four rounds of voting, the New York State Reliability Council Executive Committee agreed Dec. 8 to set the installed reserve margin (IRM) for the state’s 2024/25 capability year at 22%, up from 20% for the previous year. (See New York PSC Approves 20% Installed Reserve Margin.)

The IRM represents the additional supply capacity NYISO mandates load-serving entities maintain as a precaution against unexpected outages or demand surges.

Following a yearlong examination, the NYSRC’s Installed Capacity Subcommittee (ICS), in collaboration with NYISO, published a technical study report, which originally found that an IRM under base conditions of 23.1% would satisfy the resource adequacy criteria without violating a loss of load expectation (LOLE) of no greater than 0.1 events-days/year in the next capability year, extending from May 1, 2024, through April 30, 2025.

NYSRC Report

The ICS’ report studied how several sensitivities, including new topology changes, transmission security limit (TSL) floor inputs and increases in renewable generation, might impact the final base case modeling and the final IRM necessary to meet the state’s future requirements.

For instance, the ICS noted that a reduction in emergency assistance import limits increased the IRM by 2.24% and expected updates in the performance of special case resources raised the IRM by 0.14%. Conversely, the ICS observed that expected increases in the amount of behind-the-meter solar caused the IRM to decrease by 0.5%.

The report also documented the observation that using a 23.1% IRM while incorporating higher TSL floors in the locational capacity requirement (LCR) setting process, which is administered the ISO under its tariff, results in a system with a LOLE of 0.069, below the minimum reliability requirement of 0.1.

TSL floors are used in the LCR calculations, conducted by NYISO in its process, as the lower limit beyond which LCRs cannot fall below, resulting in minimum capacity margins that a locality, such as Zone J (New York City), Zone K (Long Island) or Zone G (Lower Hudson Valley), must maintain to ensure grid stability under standard N-1-1 system conditions.

Additional analysis using TSL floors in the LCR study, where the statewide LOLE is readjusted to 0.1, caused “noticeably better” results and produced an IRM of 21.5%.

This adjustment also yielded preliminary LCRs of 81.7% for Zone J, 105.3% for Zone K and 81% for Zone G, which contrasts with the final base case IRM results for these zones that were 72.73%, 103.21% and 84.58%, respectively.

Both NYISO and the NYSRC agree that more analysis, modeling and discussion are needed before the NYSRC Policy 5 IRM and the ISO’s TSL/LCR processes can be merged to ensure no unexpected consequences result from any process change. The NYSRC said at the meeting that this is a priority effort for 2024 and beyond.

The committee members approved the report’s base case, data parameters and sensitivities at last month’s EC meeting after extensive stakeholder development and feedback. (See “IRM Modeling Updates Approved,” NY Reliability Council OKs Interconnection Standards for Large IBRs.)

Comments

The NYSRC, responsible for establishing the IRM, determines the annual ICR that generators must maintain throughout the next capability year. The ICS’ report highlighted the disagreements among the EC about how New York should address its future reliability challenges.

Consolidated Edison’s Mayer Sasson, former chair of the EC, urged members to carefully consider the report’s findings before voting, saying, “make sure to interpret the TSL correctly before we set the IRM.”

Mark Younger, president of Hudson Energy Economics, also urged caution, saying, “while 21.5% results in a LOLE event value of 0.1, don’t kid yourself that it is reliable, since that is absolutely inconsistent with NYISO’s STAR [short-term assessment of reliability] reports and CRP [comprehensive reliability plan].” (See NYISO’s 10-Year Forecast: Challenges Ahead, but No Immediate Needs.)

On the other side, Roger Clayton, chair of the NYSRC’s Reliability Rules Subcommittee, while not explicitly endorsing an IRM of 21.5% appeared supportive, saying, “from a reliability point of view and thinking about nothing else, 21.5% is reliable according to the analysis that has been performed.”

Timothy Lynch, senior director of transmission services at Avangrid, concurred, saying, “21.5% is a reasonable step at this time, given ratepayer pressures and so forth.” He added, “There’s a lot of changes in the study year-over-year, and I think some of that needs to play out to see what the future brings.”

Similarly, Michael Mager, a partner at Couch White who represents Multiple Intervenors, a group of large industrial, commercial and institutional energy consumers, was comfortable with 21.5% despite it being the highest IRM adopted, saying, “it meets the LOLE requirements … and moves in the right direction that we should be going, but in a more moderate step than the base case result.”

Curt Dahl, director of engineering at PSEG Long Island and chair of the NYSRC’s Extreme Weather Working Group, although partial to lower IRM values, advocated for a balanced approach, saying, “I always have a range of [IRM values] in my mind.”

EC Chair Chris Wentlent, a member of the Municipal & Electric Cooperative Sector, approached the IRM vote from a policy and environmental perspective, saying, “our reliability picture is getting more complicated going forward, not less complicated,” referring to how last year’s Winter Storm Elliott significantly impacted Northeastern state grids and unexpected costs and risks to energy consumers and triggered emergency operating procedures.

“Based on everything, I see a 22% as a reasonable outcome, because, in my opinion, this balances the cost issues, some of the [emergency operating procedures] issues, and other future risks we need to pay attention to,” he added.

In an email to RTO Insider, Richard Bratton, director of market and regulatory policy at the Independent Power Producers of New York, said “the IRM is a careful balance between maintaining system reliability and protecting ratepayer costs. Less than a year after Winter Storm Elliott, the NYSRC voted to significantly decrease the IRM from the number produced by the NYISO through its analysis. IPPNY is continually committed to advocating for system reliability through competitive markets.”

Posted on

BOEM Backs 10 Fewer Turbines for Sunrise Wind

The Bureau of Ocean Energy Management on Dec. 11 issued its final environmental impact statement for Sunrise Wind, endorsing an 11% reduction in the number of wind turbines for technical and environmental reasons.

The move sets the stage for Sunrise to be the seventh major offshore wind project approved in federal waters — BOEM typically follows its final EIS with a Record of Decision several weeks later, and all of the previous six were greenlit.

BOEM said Dec. 11 it plans to issue the Record of Decision in early 2024.

Securing a positive Record of Decision is the final major regulatory hurdle for Sunrise, but a different obstacle remains unresolved: paying for construction of the project, which would send 924 GW to the New York grid.

Ørsted has said it cannot proceed with the project under the financial terms negotiated with the state because the cost of construction has increased so much since the deal was struck. But the state refused to grant increased compensation. (See NY Rejects Inflation Adjustment for Renewable Projects.)

Ørsted now is focused on salvaging Sunrise by rebidding at more favorable terms. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) The state extended this option Nov. 30. (See New York Issues Expedited Renewable Energy Solicitations.)

The most recent Record of Decision by BOEM was an approval for Empire Wind 1 and 2 in late November. (See BOEM Approves Empire Wind.) The two offshore wind farms would send 2 GW of electricity to New York, but they, too, are under significant financial pressure. The developers of Empire Wind have said they cannot start construction without more money.

Nonetheless, the announcement of the final EIS for Sunrise was welcomed as good news for a fledgling U.S. industry that has been struggling in 2023.

Oceantic Network, a trade association, said in a news release: “Advancement of the Sunrise Wind project further strengthens confidence in the U.S. permitting system as the administration is nearing its halfway point in reviewing 16 projects and conducting seven new lease auctions by the end of 2024, approving 8 GW of power generation for construction. Adhering to this commitment is critical to drawing new and securing old investments in U.S. supply chain, and the network applauds BOEM’s consistent efforts to reach this goal.”

The plan Sunrise Wind submitted to BOEM called for up to 94 wind turbine generators across 86,823 acres of OCS-A 0482, 27 nautical miles east of New York’s Long Island and 17 nautical miles south of Martha’s Vineyard in Massachusetts.

After reviewing comments and technical data, BOEM developed a preferred alternative — 84 wind turbines — for reasons of geotechnical feasibility and impact on the marine environment.

The actual potential effects of Sunrise are identified in the EIS as a range of positive and negative possibilities. These effects are similar to those predicted in the EIS documents BOEM prepared for other projects stretching between Cape Cod, Mass., and Cape May, N.J.: Sunrise could have major negative impacts on the endangered North Atlantic right whale, commercial and recreational fishing, search-and-rescue operations, scientific research and the view from land.

Posted on

BOEM to Auction Wind Energy Areas in Central Atlantic

Federal regulators Dec. 11 announced a planned auction of wind energy leases off the Delaware and Virginia coasts in 2024. 

The announcement excluded a wind energy area off the Maryland coast that is seen as problematic due to other activities in the area but included a pledge to help that state work toward its ambitious offshore wind goals. 

When the Bureau of Ocean Energy Management announced the Central Atlantic wind energy areas in July, it said the smallest of the three — area B-1 — might not be suitable for wind turbines due to the extensive military and space activities nearby. (See Potential Military/NASA Conflict with OSW Seen in Wind Energy Area.) 

On Dec. 11, BOEM said B-1 is not viable for wind energy development at this time, due to the expensive mitigation that would be needed. But BOEM is not giving up on B-1 — it might be offered in a second potential lease sale as soon as 2025, the Department of the Interior said. 

And BOEM said another potential area off the Maryland Coast of similar size and energy generating capacity has been identified and will be further analyzed. 

In its announcement Monday, BOEM emphasized a commitment to developing other potential wind energy areas that could feed clean energy to Maryland, which has an 8.5-GW offshore wind goal. 

In statements quoted in a BOEM news release, Maryland’s governor and U.S. senators welcomed BOEM’s commitment to identify other options. 

“I am pleased that we have reached an agreement on offshore wind leasing in the Central Atlantic that ensures Maryland can continue to make progress toward meeting our wind energy deployment goals, while protecting key national security and navigational safety priorities in these waters,” Sen. Chris Van Hollen (D) said. 

The senator’s comment points to the crowded and strategic nature of the ocean east of the nation’s capital. The shoreline is dotted with multiple military bases, squadrons of supersonic jet fighters, a NASA launch site and a bombing/gunnery range, raising questions about the risks of a phalanx of towering wind turbines spinning nearby. 

However, offshore wind is a signature initiative for the Biden administration, which has set a goal of 30 GW installed by 2030, and the various agencies are looking for solutions. 

In Monday’s news release, the Department of Defense presented the issue as one of national security — but one of energy security rather than planes, ships and missiles. 

“The Department has been an active participant in the Bureau of Ocean Energy Management’s efforts to find the best locations for offshore development in the Central Atlantic and we look forward to the continued collaboration on this critical issue,” said Radha Iyengar Plumb, deputy undersecretary of defense for acquisition and sustainment. 

NASA Administrator Bill Nelson added: “Developing new wind energy areas will provide clean energy for millions of homes and businesses while boosting American innovation. The time to address the climate crisis is now — and NASA will continue its work to improve life on Earth.” 

Lease Area A-2 totals 101,443 acres east of Delaware Bay. Lease Area C-1 consists of 176,505 acres east of the mouth of Chesapeake Bay. 

BOEM on Dec. 12 will publish a proposed sale notice in the Federal Register, kicking off a 60-day public comment period. 

Posted on

Counterflow: Holiday Happy Talk

It’s the time of the season for some happy talk. Real happy talk.

Let me start with a rock concert almost 40 years ago. For you kids, this was Live Aid, a 16-hour concert split between London and Philadelphia.

Steve Huntoon | Steve Huntoon

It was the greatest assemblage of rock royalty in history. By far. Thank you, Bob Geldof, for this miracle.

In no particular order: Elton John, George Michael,[1] Queen, Dire Straits, Sting, David Bowie, and Bob Dylan with Keith Richards and Ron Wood (introduced by Jack Nicholson).[2]

Eric Clapton, Phil Collins, The Beach Boys, The Who (also introduced by Jack Nicholson),[3] Led Zeppelin and Mick Jagger.

Tina Turner, the Pretenders, Madonna, Tom Petty and the Heartbreakers, Hall & Oates, the Cars.

U2, Paul McCartney,[4] REO Speedwagon,[5] Crosby, Stills & Nash, Boomtown Rats[6] and Black Sabbath.

The Hooters (introduced by Chevy Chase and Joe Piscopo),[7] the Four Tops, Joan Baez, Elvis Costello, Rick Springfield and Neil Young.

Bryan Adams, George Thorogood & The Destroyers, Simple Minds, Santana, Ashford & Simpson with Teddy Pendergrass, Kenny Loggins and Run-D.M.C.

And the all-star Band Aid closing London with “Do They Know It’s Christmas?”[8] OMG. And the all-star U.S.A. For Africa closing Philly with “We Are the World.”[9] OMG 2.

Yeah, that’s what I’m talking about. Just plug Live Aid and your favorite rock star into YouTube and turn it up to 11.[10] Or get the 4-disc DVD set (which sadly came out 20 years late and left out 6 hours of performances).[11]

How much would tickets go for these days? Maybe even more than Taylor Swift’s!

Global Famine

The theme of Live Aid was “Feed the World.”

Here’s a graph showing global famine mortality over the decades.[12]

Annual deaths per 10,000 from famine | Our World in Data (CC-BY-SA)

Did Live Aid help, or more generally, did the human sentiment leading up to and highlighted by Live Aid help? I’d like to think so. Not to diminish in any way the importance of the Green Revolution and Norman Borlaug’s role in it.[13]

Here are three more charts we should toast this season.

Global Life Expectancy

Global average life expectancy has basically doubled over the last 100 years. A miracle.[14]

Average life expectancy | Our World in Data (CC-BY-SA)

Global Average Income

How about global average income from 1960 to date?[15]

Global average income | Macrotrends.net

In current U.S. dollars, global gross domestic product (GDP) per capita increased from $457 in 1960 to $12,647 in 2022. That is incredible.

Electricity Access

And apropos of our industry, global access to electricity has gone from 73.4% in 1998 to 91.4% in 2021 — little more than 20 years — as the chart at the top of this story illustrates.[16]

Holiday Cheer

It’s understandable to be concerned with the state of the world these days, but let’s take some comfort in these points of light. We’ll get through this.

I wish you and yours the happiest of holidays.

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

[1] Elton John and George Michael together are here, https://www.youtube.com/watch?v=ECN_wgw55lc.

[2] https://www.youtube.com/watch?v=u0Lx3supRTQ. Dylan at first says he doesn’t know where they are. Then Dylan breaks a string and Ronnie hands him his guitar. How cool is that?

[3] https://www.youtube.com/watch?v=PMxwPOoZm_c

[4] With a little help from his friends, https://www.youtube.com/watch?v=CSoYvI9t3ug

[5] The Beach Boys sing background vocals on “Roll with the Changes,” https://www.youtube.com/watch?v=YsvXe0vKmxA. How cool is that?

[6] I just learned that their song “I Don’t Like Mondays” is traced to a school shooting in 1979 where the 16-year old perpetrator had given “not liking Mondays” as her reason. https://www.economist.com/business/2023/12/07/why-monday-is-the-most-misunderstood-day

[7] https://www.youtube.com/watch?v=-GiS6yMxGlA (video posted in 2020).

[8] https://www.youtube.com/watch?v=Gifrd7ljNL4

[9] https://www.youtube.com/watch?v=00OeznNG4hM. Led by Lionel Ritchie and Harry Belafonte. Patti LaBelle hits the high notes. The spectacular studio version with even more rock royalty is here, https://www.youtube.com/watch?v=9AjkUyX0rVw.

[10] There are a few videos missing from YouTube, like Bryan Adams’ songs, but at least one is on Facebook, https://www.facebook.com/RockandRollNation1/videos/bryan-adams-cuts-like-a-knife-broadcast-of-live-aid-from-mtvjuly-13-1985/2218823795025652/.

[11] https://www.amazon.com/Live-Aid-4-Disc-Set/dp/B0002Z9HT8/ref=sr_1_1?crid=YHCBG819DNNL&keywords=live+aid+concert+dvd+1985&qid=1702070340&sprefix=live+aid+d%2Caps%2C154&sr=8-1

[12] https://ourworldindata.org/famines. https://sites.tufts.edu/wpf/files/2021/05/1_Famine_mortality_decade.pdf. Deaths from hunger and malnutrition continue, but the Global Hunger Index, which measures this, has declined from 28.0 in 2020 to 18.3 in 2023. https://www.globalhungerindex.org/

[13] https://www.nobelprize.org/prizes/peace/1970/borlaug/biographical/

[14] https://upload.wikimedia.org/wikipedia/commons/9/9a/Life_expectancy_by_world_region%2C_from_1770_to_2018.svg

[15] https://www.macrotrends.net/countries/WLD/world/gdp-per-capita.

[16] https://ourworldindata.org/energy-access

Posted on

Stakeholders Give SPP Services High Marks

SPP stakeholder satisfaction remained high this year, staff told the RTO’s Board of Directors and Members Committee last week during their annual review of organization metrics and feedback.

Mike Ross, senior vice president of external affairs and stakeholder relations, said during the board’s Dec. 5 meeting that all of SPP’s service ratings increased from 2022 by an average score of 0.33, with generator interconnection (GI) seeing the largest improvement (2.59 to 3.01 on a four-point scale, with three points for meeting expectations and four for exceeding them).

Stakeholders rated SPP’s services for GI, stakeholder process, Integrated Marketplace and settlements, operations and reliability, support services, training and transmission planning. Scores were up in all categories and averaged 3.49, with support services part of the survey for the first time.

Staff received a 3.70 score.

SPP distributed 3,220 surveys to its stakeholders, including those in the Western Interconnection. They returned 289 surveys, the most since 2016. However, the 9% response rate was the lowest in recent history.

Staff will distribute the survey results to departments and managers as part of the evaluation process. They will work with Consolidated Planning Process Task Force members to address GI and transmission planning, the two lowest-rated services, Ross said. SPP says it expects to complete a backlog of interconnection requests, dating back to the previous decade, by the end of 2024.

Stakeholder comments on the two services included “accelerated GI study times are also acknowledged and appreciated” and “quit holding GI customer concerns above all others.”

Staff also said audit, tax and advisory services firm KPMG awarded an unqualified audit opinion to SPP’s market operations and transmission service settlements for the 14th straight year. In 2022, the grid operator settled about $49 billion for the Integrated Marketplace and an additional $5.5 billion for transmission.

6 WG Chairs Approved

The board approved the Corporate Governance Committee’s (CGC) nominations for several stakeholder group chairs, who will begin two-year terms, effective Jan. 1.

    • Operating Reliability Working Group: Ron Gunderson, Nebraska Power Public District (NPPD).
    • Regional Tariff Working Group: Robert Pick, NPPD.
    • Seams Advisory Group: Jim Jacoby, American Electric Power.
    • Security Advisory Group: Phil Clark, Arkansas Electric Cooperative Corp.
    • Supply Adequacy Working Group: Colton Kennedy, Omaha Public Power District.
    • Transmission Working Group: Derek Brown, Evergy.

All six are incumbents.

Directors also approved the CGC’s recommendation to revise the Project Cost Working Group’s (PCWG) scope. The PCWG now will review transmission service projects where the cost is 100% directly assigned to one or more transmission customers that are not the transmission owner. The scope previously identified only regionally funded projects as being reviewed.

Posted on

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. 

Posted on

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.

Posted on

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.