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November 18, 2024

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PJM Operating Committee Briefs: April 14, 2022

Reliability Products and Services Assessment Endorsed

PJM Operating Committee members last week unanimously approved an initial recommendation to evaluate the need to procure additional reliability-based generation as more intermittent resources are integrated into the RTO’s grid.

Chris Pilong, director of operations planning, and Alex Scheirer, a PJM senior client manager, reviewed the proposed “initial direction” regarding reliability products and services — the outcome of discussions in the Resource Adequacy Senior Task Force (RASTF).

Members began looking at a list of generator “reliability attributes” in January, Pilong said, examining PJM’s renewable integration studies and papers to determine the recommendations for addressing the potential for new reliability services and the next steps in the stakeholder process at the RASTF and other committees and task forces.

Pilong said stakeholders will discuss reactive capability and supply issues in the Reactive Power Compensation Task Force to ensure PJM is able to “utilize, measure and compensate the full reactive capability of synchronous and non-synchronous generators independent of their power output.” The issue also calls for discussions on the ability of all resources to follow voltage schedules and demonstrate performance.

On the issue of regulation service, Pilong said, stakeholders recommend reviewing existing regulation market signals and considering future system needs as part of the regulation market redesign issue charge approved by the Market Implementation Committee last year. (See “RTO to Propose Review of Regulation Market,” PJM MIC Briefs: Nov. 3, 2021.)

Members recommended that the Energy Price Formation Senior Task Force consider how to value flexibility of generation within the existing or modified ancillary services, Pilong said, while another recommendation has the RASTF exploring how to value fuel assurance for all resources that can be relied upon for “unexpected system conditions.”

Pilong said PJM and stakeholders may evaluate methods for data submission and review the existing penalty structure if data reporting requirements in PJM manuals are not followed regarding energy assurance. He said a potential problem statement and issue charge could be brought to the OC in the future to examine manual language changes.

“As we’re seeing the renewable penetration grow, we think we need to tighten those rules up a little bit more,” Pilong said.

Regarding black start resources, stakeholders recommended continuing to monitor activities at the OC special sessions on fuel requirements for black start resources and the discussions at the RASTF on black start flexibility, fuel and energy assurances.

Members also recommended the RASTF consider specific unit performance requirements to handle the increasing number of extreme weather events in the region.

Dynamic Rating Issue Endorsed

Stakeholders unanimously approved an issue charge and endorsed a proposed solution as part of the “quick fix” process regarding facilitation of the integration of dynamic line ratings (DLRs) into PJM operations.

Chris Callaghan, PJM senior business solution engineer, reviewed the problem statement and issue charge addressing interim manual revisions on DLR integration. PPL is tentatively scheduled to go live in June with a DLR system on some of its transmission lines.

PJM wanted to “enable the operational implementation of dynamic ratings” through temporary manual revisions, Callaghan said, which will be in place pending submission of the RTO’s FERC Order 881 compliance filing set to be completed by the end of the month.

In December, FERC ordered transmission providers to end the use of static line ratings in evaluating near-term transmission service and required transmission providers to employ ambient-adjusted ratings for short-term transmission requests of 10 days or less for all lines that are impacted by air temperature. (See FERC Orders End to Static Tx Line Ratings.)

The solution included new language in Manual 1: Control Center and Data Exchange Requirements, Manual 3: Transmission Operations and Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA) that develops new guidance and requirements related to the operational and technical implementation of dynamic rating systems.

The committee also unanimously endorsed a separate issue charge for the creation of a new task force to explore other issues related to the implementation of DLR in PJM. Callaghan reviewed the problem statement and issue charge related to the new task force reporting to the OC.

Key work activities of the task force include discussions on any impacts of DLR to the auction revenue rights and financial transmission rights markets, any impacts to the seasonal ratings used in the PJM planning processes and any other considerations regarding the notice of an intent to implement DLR in the RTO.

Out-of-scope items in the issue charge include modifications to the Operating Agreement, tariff or manuals that “infringe upon the terms of the Consolidated Transmission Owners Agreement,” including requiring transmission owners to install or implement DLR on lines.

The task force is set to begin by August or after the completion of PJM’s Order 881 compliance filing.

EKPC UFLS Requirements Endorsed

Stakeholders unanimously endorsed a quick-fix solution to appropriately document East Kentucky Power Cooperative’s under frequency load shedding (UFLS) requirements in PJM.

Denise Foster Cronin of the EKPC reviewed a problem statement and issue charge addressing the documentation of UFLS and the changes to the Operating Agreement.

The purpose of the UFLS requirement is to avoid an uncontrolled loss of load situation, Foster Cronin said, and the requirement establishes a total percentage of load shed that must be achieved when system frequency drops to a certain level to maintain the system.

All electric distributors must comply with the UFLS requirement established by their respective NERC region. When EKPC integrated into PJM in 2013, the cooperative was in the SERC region of the ERO.

Before EKPC’s integration, PJM’s OA documented a UFLS requirement for entities in the PJM’s Mid-Atlantic, West and South regions. But the OA was not changed with EKPC’s 2013 integration to incorporate the cooperative’s applicable UFLS requirement, and it wasn’t included in any of the regions.

In 2018, EKPC was added to PJM West when the RTO worked with stakeholders to clarify the region definitions in its governing documents. However, other entities included in PJM West are in the ERO’s ReliabilityFirst region, while EKPC remained in SERC, which has slightly different UFLS requirements.

Foster Cronin said a recent review of the region revisions showed “potential confusion” in EKPC’s appropriate UFLS requirement and needed to be corrected. She said the oversight did not create a reliability problem for the cooperative.

“We really wish for these changes to ensure there’s no confusion as to what is the appropriate under frequency load shedding requirements applicable for us,” Foster Cronin said.

The MRC will vote on the solution and corresponding OA revisions at its April 27 meeting.

Manual 1 Revisions Endorsed

The committee unanimously endorsed changes to Manual 1 as a part of the periodic review.

Bilge Derin, PJM senior engineer, reviewed the changes to Manual 1: Control Center and Data Exchange Requirements, saying the changes partially resulted from revisions in NERC standards CIP-012, COM-001 and EOP-008.

Minor changes were made throughout the manual, Derin said, including removing revision numbers from where NERC standards are referenced and replacing the term “member” with “PJM member” where applicable to keep the term uniform throughout the manuals.

In Section 2.5.6: Recovery Procedures, PJM clarified the loss of control center functionality procedures and documentation relating to EOP-008 and TO/TOP Matrix.

In Section 3.2.1.1: PJMNet Communications System, the language was clarified to ensure PJM is responsible for protecting all real-time assessment and real-time monitoring data through the PJMNet private network as the data is “in transit” between the PJM control centers and its routers. The RTO must also make sure all data is encrypted.

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Report: US Must Double Nuclear Power to Hit 2050 Climate Goals

Decarbonizing the U.S. economy by 2050 will require doubling the country’s nuclear energy generation by deploying 100 GW of advanced reactors while also building a domestic supply chain for the high-assay low-enriched uranium (HALEU) needed to fuel those plants, according to two new reports from the Nuclear Innovation Alliance (NIA).

Released Tuesday, “Fission Vision” acknowledges NIA’s 100-GW target may seem daunting, “but nuclear energy has been constructed this quickly in the United States before. Over 100 GW of light water reactors were constructed in the United States between 1960 and 1990,” the report says. “Application of modern manufacturing and construction practices can help us meet or exceed historic nuclear energy deployment rates and enable the doubling of domestic nuclear energy production by 2050.”

But the second report, focused on HALEU, cautions, “The main challenge of developing a mature commercial HALEU fuel cycle is that high assurance of long-term HALEU demand is needed to justify significant capital investments by fuel cycle companies, while high assurance of near- and midterm HALEU availability is needed to support the business case for the deployment of advanced reactors. Federal policy and investment to jumpstart HALEU fuel cycle activities could help provide these initial market signals and catalyze development of a mature and sustainable commercial market.”

More urgent still, the Department of Energy is funding two advanced reactor demonstration projects, and according to NIA, their main source of HALEU is a Russian state-owned company called TENEX.

Speaking at a Tuesday webinar, NIA Executive Director Judi Greenwald said that “a whole-of-society effort” would be needed “to create the technical, policy, social and commercial conditions” to deploy advanced nuclear “at scale and at pace.” She called on DOE to launch an Advanced Nuclear Energy Earthshot, similar to its hydrogen and long-duration storage Earthshots, “to integrate DOE’s efforts with the broader innovation and commercialization ecosystem that includes private companies, universities and other entities.”

The Earthshot initiatives are specifically aimed at bringing down the costs of emerging technologies. For example, the Hydrogen Shot is targeting a price of $1/kg for green hydrogen within a decade — an 80% drop from its current price of about $5/kg. However, setting out a similar cost-reduction goal for nuclear would be difficult, Greenwald said, because of the range of applications for different-sized reactors.

The HALEU report, on the other hand, drills into the details of near-, mid- and long-term market development, looking at the role of the federal government either to ensure demand as a guaranteed offtaker of HALEU, or to help build out the processing plants and other facilities via a cost-sharing program with commercial suppliers. For example, the report estimates that early development of advanced reactors will need upward of 20 MT of HALEU at a price of $15,000/kg.

Thus, a federal offtake program for 10 MT/year could cost about $1.5 billion, not including costs for transportation or storage, the report says.

On Time and on Budget

Its lack of specificity notwithstanding, Greenwald said that “Fission Vision” is intended as a high-level rallying point for industry and government, underlining the integral role that NIA says nuclear must play in U.S. clean energy goals. President Biden has called for the country to decarbonize the electric grid by 2035 and achieve net-zero greenhouse gas emissions economywide by 2050.

As variable renewables increase on the grid, nuclear will be a critical source of firm, clean, dispatchable power, Greenwald said. “Climate solutions have to match the scope of the challenge,” she said. “Meeting our climate goals requires us to think bigger and consider the role advanced nuclear energy can play at scale.”

Further, “nuclear plants closed or not built are almost always right now replaced with fossil fuels,” said Josh Freed, senior vice president for climate and energy at Third Way, a D.C. think tank. “That’s bad for the economy; it’s bad for security; it’s bad for public health; and it’s bad for climate.”

Specific objectives in “Fission Vision” include:

  • ensuring projects are built on time and on budget by rebuilding the domestic supply chain and providing incentives to attract private investment;
  • tackling the complex social and environmental justice issues involved in nuclear regulation, siting and permitting, and the storing of spent nuclear fuel; and
  • integrating nuclear into clean energy planning and policies via “sensible and technology-inclusive” initiatives and a range of projects combining nuclear with renewables and storage, as well as repowering fossil fuel sites with advanced nuclear.

Freed also added another objective to the mix: developing a domestic advanced nuclear sector to promote U.S. competitiveness and leadership in global markets, where it currently lags behind Russia and China, as noted by the World Nuclear Association. Advanced nuclear plants built in the U.S. and exported overseas will be “a crucial tool to strengthen energy security for our allies abroad and reduce our dependence on energy supplies from authoritarian regimes,” he said.

The Nuclear Narrative

Freed and other speakers on the Tuesday webinar said that the narrative on nuclear has changed in recent years, with former opponents and skeptics now at least open to taking a second look. Russia’s invasion of Ukraine has similarly shifted the discussion in Europe, said Adam DeMella, global government affairs leader for GE Hitachi Nuclear Energy.

“Events in Ukraine have accelerated the energy transition, but they continue to push the importance of energy security to the fore,” DeMella said. “The U.S. has a key role to play here, but we have to get it right. If we don’t get it right, someone else will fill that void.”

A fundamental part of the new narrative is that nuclear technology itself is evolving. The advanced or next-generation nuclear reactors now in development use a higher-grade fuel, allowing for smaller, safer facilities that can use water, molten salt, gas or liquid metal for cooling and produce less waste. They can also more quickly adjust their output to match demand and provide both electricity and heat for industrial uses, such as the production of green hydrogen.

HALEU is the higher-grade fuel required for advanced reactors. It has concentrations of uranium-235 — the isotope needed for sustained nuclear reactions — at close to 20%. The uranium used in existing light water reactors has uranium-235 concentrations of about 5%, while weapons-grade uranium has concentrations of more than 90%.

Jessica Lovering, executive director of the nonprofit Good Energy Collective, laid out “the progressive case for advanced nuclear” her organization is trying to build. The success of the DOE demonstration projects and those that follow will depend on “genuine community support and buy-in,” she said. “And this will set an example for other communities that might be interested in hosting.”

Issues like permitting and siting for projects and nuclear waste storage are “heavy lifts” that will require coordination across public and private sectors, Lovering said. But she argued that advanced nuclear technologies, “particularly small modular reactors and microreactors, offer some opportunities for more equitable deployment of nuclear. They’re not a silver bullet, but they do facilitate more community ownership and control over energy production,” she said, particularly pointing to emerging economies that may not have the demand or infrastructure for a large reactor.

DeMella agreed that successful demonstration of small modular reactors will be key. He called for increased funding for the Nuclear Regulatory Commission to ensure adequate staff and expertise for the licensing of new plants. For example, DOE’s two demonstration projects are both slated to be online by 2028, and the licensing process for new reactors at the NRC can take up to five years, according to the U.S. Energy Information Administration.

Beyond licensing, he said, the industry will also need to simplify reactor designs and develop new excavation methods to cut project costs.

Bridge to the Future

Developing a HALEU supply chain in the U.S. presents yet another challenge.

Led by Sen. John Barrasso (R-Wyo.), ranking member of the Senate Energy and Natural Resources Committee, Republicans in March introduced a bill (S. 3978) that would ban the import of Russian uranium, with a companion bipartisan bill introduced in the House of Representatives.

Barrasso has also introduced a second bill (S. 4066) that would mandate that DOE prioritize securing a domestic supply chain for HALEU by using its own nuclear stocks to produce the fuel. One of DOE’s advanced nuclear demonstration projects — the 345-MW Natrium project being developed by TerraPower and GE Hitachi — is to be built in Wyoming.

The NIA report says that at present, only one facility in the U.S. ― the Centrus American Centrifuge Demonstration project in Piketon, Ohio ― is licensed to produce HALEU and only in limited amounts, about 1 MT/year. The report estimates that an initial group of advanced reactors, including the DOE demonstration projects, will require 20 MT of HALEU.

Building out additional new processing facilities would provide the foundation the country needs for mid- and long-term advanced reactor development, but according to NIA Project Manager Patrick White, “it’s not clear at this moment if they could be brought online quickly enough to meet the near-term demand.”

Drawing on DOE’s National Nuclear Security Administration’s stockpile would be “challenging programmatically,” the HALEU report says. With existing facilities, this option could produce a stopgap amount ― 5 to 10 MT — of HALEU per year, and while possible, the U.S. would need to balance HALEU production with other national security considerations. Significant federal investment would also be needed but “would not result in robust new HALEU production infrastructure possibilities,” the report says.

“Determining the best path forward on near-term HALEU absent supply from Russia requires us to examine the capabilities of different enrichment and fuel cycle providers to bring new capacity online, the timing and material needs for advanced reactor developers, and the ability of DOE to allocate … federal uranium supplies to HALEU production,” White said in an email to NetZero Insider.

DeMella also sees trade-offs ahead. Industry and government will need to cooperate to “figure out what’s ready to deploy in the near term, and work on those things in the near term, and then continue to work on the improvements that come in the next generation and the generation beyond,” he said. “Because if we don’t have a bridge to the future, we don’t ever get to the future.”

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Mass. Commission Readies Proposal for State Clean Heat Standard

The Massachusetts Commission on Clean Heat signaled Thursday its intention to recommend that regulators consider adopting a clean heat standard (CHS) for the state’s buildings sector.

“We propose to request that the Department of Environmental Protection develop the design for meeting [building emission] caps via regulation, including the consideration of a [CHS] for projects that transition from an emitting heating resource to a non-emitting heating resource, including weatherization and transition to heat pumps,” said Judy Chang, undersecretary of Energy and Climate Solutions at the Executive Office of Energy and Environmental Affairs (EEA).

Chang presented several potential commission recommendations for buildings as part of a draft 2025/2030 Clean Energy and Climate Plan (CECP) due to the state legislature July 1. The 22-member commission, which Chang chairs, will develop clean building sector policy recommendations throughout this year that will inform the CECP and other efforts to achieve net-zero emissions by 2050.

“We’re analyzing the potential for a CHS to help achieve the [greenhouse gas] emission reductions that we need and the potential implications for the costs and how to spread those costs,” Chang said.

To support building decarbonization, the commission is creating a mechanism for building owners to report clean heat metrics, such as energy use intensity and GHG emissions, she said. The mechanism, she added, will be the first step in standardizing how different building sizes and types report emissions.

The commission also wants to align state programs with clean heat goals.

That effort could include what Chang called “sweeping” changes that adjust how utilities invest in infrastructure and shift the purpose of the Mass Save program from energy savings to GHG emissions savings.

In December 2020, the administration released an interim 2030 CECP, but passage of the 2021 Next Generation Roadmap requires both a 2025 and 2030 plan. EEA must develop the 2025/2030 CECP with increasing economy-wide limits for reaching net-zero emissions in 2050 and sector-specific sublimits.

The draft CECP is based on policies and programs that are under development and underway and take into consideration the public comments submitted on the interim CECP over the last year, Chang said.

To reach state emission targets, the draft CECP proposes emission sublimits for residential building heating of a 27% reduction by 2025 and a 44% reduction by 2030. Proposed sublimits for the commercial and industrial heating sector are 20% by 2025 and 47% by 2030.

Key factors in the draft for achieving building sector sublimits include weatherizing one-third of buildings, installing heat pumps in one-third of homes, electrifying commercial buildings and providing gap funding for clean heat solutions.

Comments on the draft CECP are due April 30.

Transportation

While decarbonizing Massachusetts’ building sector will be “challenging,” Chang said, the primary driver for “deep decarbonization” in the CECP through 2030 is electrification of vehicles.

The state has already issued California’s Advanced Clean Trucks regulation and will move forward with the Advanced Clean Cars II (ACCII) regulation when the California Air Resources Board finalizes it. Under the clean trucks regulation, commercial vehicle sales must transition to zero-emission technologies at increasing rates, with 75% of medium-duty truck sales being zero-emission by 2035.

In a recent updated draft of the ACCII regulation, the board proposed increasing early year target percentages for zero-emission new car sales on the path to 100% in 2035. (See New Draft of Advanced Clean Cars II Would Speed ZEV Sales.)

Other policy recommendations that would be new to the CECP focus on school buses, vehicles for hire and delivery trucks, according to Chang.

Massachusetts already launched an electric school bus program earlier this year to help school districts compete for federal funding, and the draft CECP proposes launching a vehicle-for-hire program for high-visibility, high-mileage drivers.

The program will “help educate the public about the comfort and the value of EVs,” Chang said.

A separate program proposal for delivery trucks would provide incentives for electrifying high-mileage vans and trucks.

“The rise of e-commerce makes delivery trucks a growing source of emissions, particularly near our ports and more broadly in our residential communities,” Chang said. Funding for the three programs, she added, is included in a $9.7 billion transportation bond bill currently before the Massachusetts legislature. (See Mass. Transportation Bond Bill Seeks to Unlock $4B in IIJA Funds.)

Through the draft CECP proposals, the state expects to have 200,000 registered passenger EVs by 2025 and 900,000 by 2030. In addition, 50,000 medium- and heavy-duty zero-emission vehicles would be in use by 2030.

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SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022

Counterflow Optimization Still an Issue Without a Solution

DALLAS — SPP stakeholders last week rejected a working group’s recommendation to stick with the status quo when it comes to adding counterflow optimization to the congestion-hedging process — three months after agreeing with staff to leave the market construct untouched.

The Market Working Group brought the recommendation to the Markets and Operations Policy Committee after more than a year’s worth of meetings and educational sessions and drafting a policy paper. However, it fell just short of the committee’s two-thirds approval threshold at 65.6%.

The measure will still go before the Board of Directors on April 26 for its consideration.

“If the board basically directs us to keep working on this, that’s what we’ll have to do,” SPP COO Lanny Nickell said during the April 11 discussion. “MOPC doesn’t have an official position because we didn’t approve the status quo motion. It simply sends a signal to the board that keeping the status quo is not a popular option.”

“Hopefully, it’ll be back to MOPC in July,” MOPC Chair Denise Buffington, of Evergy, told the Strategic Planning Committee on Wednesday. “A lot of work went into that.”

The proposal to add counterflow optimization — limited to excess auction revenue — to SPP’s market mechanism that hedges load against congestion charges has been an issue with no solution since its approval by the board in 2019. The Holistic Integrated Tariff Team’s (HITT) direction, which would essentially keep system transmission flows between two points balanced, was meant to address concerns about how congestion rights instruments are awarded and the current process’s efficiency. (See SPP SPC Takes on Congestion Hedging Issues.)

Staff and the MWG have been unable to reach consensus on the recommendation. The MWG voted in 2020 to keep the current market construct. Although they acknowledged that counterflow optimization would benefit load-serving entities, staff have also recommended keeping the current construct, noting some market participants want to review the transmission service process for efficiencies.

The RTO’s Marketing Monitoring Unit has said the proposal doesn’t give participants a say in the amount of counterflow they receive and there is no way for them to avoid being affected by optimization even when they opt-out. It says auction participants will adapt to the market changes, which will affect auction revenue.

The SPC in January agreed with staff and stakeholders to put the issue on hold and allow for a “cooling-off” period. (See “Counterflow Optimization on Hold,” SPP Lays Out its Western Expansion Strategic Plan.)

“We’ve been talking about this for four or five years,” Southwestern Public Service’s (SPS) Bill Grant said. “What we’ve run into is that a lot of companies are currently happy with their total end results on hedging, mainly because of the annual uplift that takes place once a year. That’s why there’s reluctance to make a change.”

Steve Gaw Matt Caves 2022-04-13 (RTO Insider LLC) Alt FI.jpg

APA’s Steve Gaw (left) makes a point as Western Farmers’ Matt Caves waits his turn. | © RTO Insider LLC

The Advanced Power Alliance’s Steve Gaw said the congestion-hedging problem is not fixed and will hinder stakeholders’ efforts to export power from wind-rich regions.

“This remains a substantial obstacle for accomplishing that. Until that is fixed, we’ll continue to have this wall as far as the opportunities exist for this transaction in SPP,” he said.

“This is bad policy of doing nothing, which lead to those exports not happening,” American Electric Power’s Jim Jacoby said. “Everyone complains about all the wind congestion happening in SPP. We need some way to export this stuff.”

A study by SPP found that market participants’ hedging positions will change in coming years thanks to new topology, HITT initiatives and the changing generation mix. The study indicated a net positive value for all LSEs with counterflow optimization.

“At the risk of sounding like Yogi Berra,” Golden Spread Electric Cooperative’s Mike Wise said, referring to the baseball Hall of Famer known for his misuse of the English language, “we are where we are, although we’re not where we are going to be.

“I’m torn, because our organization doesn’t want to make any changes. We’re comfortable with our hedging position,” Wise said. “From the perspective of SPP, it’s looking at the bigger picture. We are probably going to see a different set of circumstances going forward. It will likely be that many of us who enjoy the current paradigm won’t enjoy it in the future.”

Staff Reducing Interconnection Queue’s Backlog

Staff told MOPC that they are on track to eliminate the backlog in SPP’s interconnection queue in two years, having reduced the current queue’s number of active interconnection requests from 651, totaling 119.9 GW, to 481, totaling 90.3 GW, as of March.

GI Queue (SPP) Content.jpgRenewables and storage dominate SPP’s reduced GI queue. | SPP

SPP’s Juliano Freitas said the new three-phase interconnection study process, approved by FERC in 2019, kickstarted the mitigation effort. (See FERC OKs New SPP Interconnection Process.)

Since then, staff have also received stakeholder approval to reduce the number of models required per study, combine 16 study groups into five and incorporate more realistic generation dispatch assumptions. They have also eliminated a special studies backlog, redesigned vendor contracts to streamline the process, and accelerated procedures to reduce wait times and clear a path for the consolidated planning process.

At the same time, SPP has been able to add 24.9 GW of generation over the last five years and execute 121 generator interconnection agreements (GIAs).

Freitas said that historically, 60 to 65% of interconnection requests are withdrawn, but the three-phase study process has helped filter out those requests that will not result in a GIA.

“Restudies add time to the process,” he said. “That’s why I’m confident we will mitigate the backlog.”

SPS’ Jarred Cooley was among several MOPC members complimenting SPP’s progress, but he also said SPS was concerned with the fuel-dispatch changes that he said should have been brought to the committee as a policy issue.

“No analysis was done to warn the TWG [Transmission Working Group] of how these changes will impact the SPP region,” Cooley said.

Arash Ghodsian, a former MISO staffer who is now senior director of transmission and policy at EDF Renewables, said, “No one anticipated the size of the queues to grow like this. This is a change that’s needed.”

Tx Planning Changes Pass

The committee endorsed working groups’ recommendations to re-baseline the 2022 Integrated Transmission Planning (ITP) assessment and to modify the 2022 20-year assessment’s scope.

The TWG and the Economic Studies Working Group (ESWG) said approving several waivers and revising the 2022 ITP would allow staff to perform a reliability-only assessment this year and full assessments for the 2023 and 2024 ITPs.

MOPC unanimously endorsed the proposal, with one abstention, after having asked the groups in January to bring a more fully developed plan to the April meeting. ESWG Chair Alan Myers, with ITC Holdings, said all ITP assessments are on track and that a 345-kV, 150-mile double-circuit project’s re-evaluation in West Texas will be completed by the June MOPC meeting. (See SPP Markets and Operations Policy Committee Briefs: Jan. 10-11, 2022.)

The two working groups also recommended the 20-year assessment’s scope be modified to include more aggressive emissions-reduction futures that include a 93 to 95% reduction target in 2042 from 2017 levels. Staff identified a software limitation that would not allow the target to be met without modifying the scope.

Oklahoma Gas & Electric’s Usha Turner noted that one model showed emissions rising because it was unable to account for energy storage, resulting in additional thermal resources being dispatched.

“Modeling storage has been tricky the last few years,” Myers said.

The ESWG and TWG’s request passed with 99% approval.

The committee also:

  • endorsed the annual 2022 SPP Transmission Expansion Plan (STEP) report. Staff have issued 94 notifications to construct (NTCs) valued at $894 million since the last STEP report, a period covering January 2021 through March 2022. Twelve upgrades valued at $38 million have been withdrawn, and 38 upgrades, valued at $162 million, have been completed. SPP is currently tracking $2.77 billion of upgrades.
  • approved suspension of a 115-kV project related to an industrial load in Nebraska while staff conduct a restudy to determine appropriate changes to the NTC, its possible withdrawal or whether an alternative project can be found. A $6.3 million increase to relocate a 345/115-kV substation helped push the project’s costs from $43.4 million to $53.8 million, a 24% increase beyond the baseline’s 20% plus-minus threshold. Staff said they were optimistic they can reach Nebraska Public Power District’s request to complete the restudy by July and avoid further cost increases.

MOPC Honors Retiring Bill Grant

SPP staff and stakeholders paid tribute to SPS’ Grant, who is retiring June 1 after 40 years with SPS parent company Xcel Energy. He has spent 16 of those years serving on MOPC and other stakeholder groups.

“I don’t know how you did it,” SPP’s Nickell told Grant, one of the RTO’s more vocal and colorful stakeholders who was involved in half a dozen groups last year. “I will always appreciate Bill’s candor, his straightforwardness. … He would call just to tell me how things would work. He would try to help me understand and how I could make things better at SPP.

“I always appreciated your willingness to improve our processes, once we addressed your concerns,” Nickell said to knowing smiles in the room. Members then gave Grant a standing ovation.

“One thing I’ll miss is the relationships,” he said, appearing to choke up with emotion. “Don’t take them for granted.”

Grant is retiring as vice president of rates and regulatory affairs to Jasper, Texas. He plans to do some consulting but also take advantage of two nearby lakes and enjoy spending time with his 11 grandchildren. Asked if he enjoys fishing, Grant said he has bought a triton boat. He also has a fully stocked pond on his property.

Cooley, SPS’ director of strategic planning, has replaced Grant on MOPC.

Order 2222 Compliance Work ‘Highly Complex’

Michael Desselle, SPP’s chief compliance and administrative officer, told stakeholders it could cost as much as $1 million and take as many as 18 months to implement compliance measures with FERC Order 2222. The 2020 order directed RTOs and ISOs to open their markets to distributed energy resource aggregations. (See FERC Opens RTO Markets to DER Aggregation.)

Desselle said the “highly complex effort” to change tools, process and procedures, involving 10 different sections of the RTO’s tariff, could be completed by the third quarter of 2025. That assumes FERC approves SPP’s compliance filing by the end of the year.

“All we can do is estimate what it takes for us … to get [changes] in place, for our system alone,” Desselle said.

SPP has estimated it will take almost 16,000 hours to complete the process, he said, “but only if the staff has nothing else to work on.”

Surplus Interconnection Service Change Remanded

The committee remanded back to the MWG and Operating Reliability Working Group a revision request (RR451) that would create pooled surplus interconnection service for existing generators with multiple interconnection agreements and a shared point of interconnection. The measure fell percentage points short of MOPC’s two-thirds approval.

Members pushed back over whether staff could reliably manage the process during a discussion that devolved into the intricacies of Robert’s Rules of Order. The measure passed three stakeholder group ballots with only one opposing vote and nine abstentions, primarily over cost concerns.

SPP estimates it will cost $20,000 to $60,000 to implement RR451’s changes and almost $200,000 annually to administer the GI service, which was mandated by FERC Order 845.

The tariff currently allows surplus service to be associated with only one existing generator’s interconnection service. Staff said allowing generators to pool their GIAs and offer the service could enable more cost-effective surplus generation to enter the market.

MOPC did approve RR465 by an 83.3-16.7 margin after it was pulled from the consent agenda. It allows transmission facilities constructed to facilitate generator interconnections to be treated on a consistent cost basis with other transmission facilities if the transmission owner self-funds the work.

Some grid operators have already implemented similar measures that give TOs the option to provide the initial funding for upgrades and the ability to earn a return on the facilities. A recent PJM proposal was modeled on a FERC-approved order in MISO following a 2018 ruling by the D.C. Circuit Court of Appeals. (See MISO Gauging Aftershocks of TO Self-fund Order.)

“If this goes forward, we will be involved in litigation because other cases are outstanding,” APA’s Gaw warned.

The unanimously approved consent agenda include eight other RRs, removal of a remedial action scheme on the SPS system, and approval of a re-evaluated OG&E-sponsored upgrade to add a new 345/161-kV substation and transformer.

      • RR419: provides a market power framework for storage resources operating as transmission assets, requiring they follow SPP directions at all times while allowing for technical issues.
      • RR455: requires a generation interconnection customer to correct all reliability problems found in the electromagnetic transient study before injecting power into the transmission system.
      • RR482: updates the ITP manual to reduce redundant stakeholder review of capacity additions for inclusion in the economic models.
      • RR485: modifies the ITP manual to be consistent with current IRS regulations that define a wind unit’s production tax credits (PTCs) as based on the construction start date. The change also allows for PTCs to be awarded to solar facilities, in accordance with IRS specifications.
      • RR486: updates the Integrated Marketplace protocols by removing outdated network and commercial model timelines and condensing about 17 pages of Network and Commercial Model Update Timelines tables to one page.
      • RR487: clarifies the Integrated Marketplace protocols over when an outage commitment status necessitates an outage scheduling tool (CROW) submission and when a CROW submission necessitates an outage commitment status.
      • RR488: adds two functions necessary to settle the real-time combined interest resource adjustment amount — the real-time ramp capability nonperformance amount, and the real-time ramp capability nonperformance distribution amount.
      • RR490: adds a new tariff section on transmission line ratings, detailing their development and usage, to comply with FERC Order 881.
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FERC Approves PJM-NJ Transmission Agreement

FERC gave final approval Thursday to the State Agreement Approach (SAA) sought by the New Jersey Board of Public Utilities and PJM that gives the greenlight for the state and RTO to build transmission to deliver 7.5 GW of planned offshore wind (ER22-902).

The commission concluded that the agreement would require all costs of the transmission to be borne by New Jersey customers, rejecting claims by PJM transmission owners that they could potentially be liable in the future. It said that the SAA protects the TOs because any such cost allocation would have to be approved by FERC.

The order gives final approval to a process that is already far advanced and that the BPU expects will conclude in the fall, either with its adoption of one or more proposed transmission enhancements or a rejection of all the submissions based on price, risk, environmental impact and other factors. The BPU had asked FERC to rule on the application by Friday.

Tying OSW to the Grid

The SAA sets up a framework by which PJM and New Jersey are granted permission to create a planning, selection and execution system for transmission improvements — in this case to respond to the expected surge in power from offshore wind projects — for which solely New Jersey customers would foot the bill. In a filing with FERC, PJM said it expects the resulting infrastructure to be in service for 30 to 40 years.

Thirteen developers submitted 80 proposals under the SAA solicitation process opened by the BPU in April 2021 and closed in September. (See PJM, NJ Staff Brief Stakeholders on State Agreement Approach). The BPU on April 12 held the final of four public hearings, in which the developers outlined their proposals and the board heard public and stakeholder comment on several issues, including grid integration concerns, the permitting and environmental issues of the proposals, and how to control the cost of the projects to ratepayers. (See related story, NJ Seeks Efficiency, Savings in OSW Transmission Process.)

Under the proposal, New Jersey would commit to paying 100% of the cost of the transmission but could seek to allocate some costs to other generation projects that use the additional capacity. The projects would be funded by a tariff authorized by FERC that would amortize the cost of the projects over their life. PJM would then allocate the costs to the utilities serving the state, who would in turn charge the cost as a transmission fee in ratepayer bills.

The state is seeking to generate 7.5 GW from offshore wind by 2035, about half of which the BPU awarded in two solicitations, with another three expected, the first of them in January. Each of the projects awarded so far — Ocean Wind 1 and 2, developed by Ørsted; and Atlantic Shores, by a joint venture between EDF Renewables North America and Shell New Energies US — included a plan to build accompanying transmission infrastructure. (See NJ Awards Two Offshore Wind Projects.)

However, the SAA offers the potential to create a network of infrastructure that could serve several projects. Developers testified in public hearings that such a system could result in lower costs to taxpayers and, in reducing the number of cables and amount of infrastructure needed, reduce the environmental impact and disruption in towns where the cables run ashore.

Future Beneficiaries

While the New Jersey Division of Rate Counsel, clean energy advocates and two offshore wind infrastructure developers filed statements of support for the SAA proposal, the Ohio Public Utilities Commission’s Federal Energy Advocate (FEA) and some PJM TOs opposed the plan, expressing concern at different elements of the cost-sharing provision. They argued that the SAA’s cost allocation rules were too broad or vague and could result in other states being charged, based on a claim that the transmission projects would provide “incremental reliability benefits to non-sponsoring states.”

The FEA said the rules are especially too broad in case one of the projects developed under the SAA is expanded to provide transmission service to neighboring states. It argued that costs should only be allocated if the future user voluntary agreed to participate in the expansion of the projects, and not simply because they receive its benefits.

PJM transmission owners also expressed concern about the cost allocation provisions.

But FERC concluded that the proposal’s language clearly states that the “BPU would be committing New Jersey customers for the cost of any SAA projects that [the] BPU elects to sponsor.”

The commission said that while it is true that the SAA leaves open the possibility that future users outside New Jersey could be charged, the agreement means that “approval by the commission of a subsequent cost allocation filing is necessary to implement such an allocation.” The BPU and PJM’s answers in response to the FEA and TOs’ concerns, “and the SAA agreement itself explain that no costs will be allocated to customers outside of New Jersey unless and until the commission accepts a future cost allocation filing as just and reasonable,” FERC said.

The section of the agreement that allows non-New Jersey users to be allocated costs “merely contemplates that future users of the SAA project could be asked to pay their fair share of costs … [that] will be defined in a future filing with the commission,” FERC said.

The commission also said that the FEA and TOs’ concerns about future cost allocations were “premature.”

“Any cost allocation to ‘future users’ is contingent on the commission reviewing and accepting a future cost allocation filing, and until any such filing is received, the SAA agreement allocating costs stands in place.”

Disagreement Between FERC’s Republicans

In a dissenting opinion, Commissioner James Danly said the language of the SAA agreement clearly states that “‘PJM shall allocate to any future user of a SAA project … a pro rata share of the total costs,’” which could be non-New Jersey users.

“The cost-sharing provision settles the single most important cost allocation detail: whether anyone besides the ratepayers in New Jersey can have the costs of a state ‘public policy’ project foisted upon them,” he wrote. “The answer to that question is ‘yes,’ the costs of a state’s pet project can be passed on to other states’ ratepayers.”

He said that the issue is important because “many in the industry have been concerned that certain states might seek to shift or socialize the costs of the transmission projects that will be required to achieve their bold (some might say ‘brash’) renewable portfolio goals to the ratepayers in other states. Now, the filed rate allows that very result.”

But fellow Republican Commissioner Mark Christie disagreed with Danly, concurring with the majority that the order makes no presumption about future cost allocations.

“The only proposal on the table now is New Jersey’s State Agreement Approach agreement, which does not allocate any costs to customers, wholesale or retail, in states other than New Jersey,” Christie wrote. “Moreover … today’s order makes clear that while the order does not attempt to answer any questions about whether any future cost allocations are just and reasonable, it does answer that such proposed allocation must be consistent with the State Agreement Approach.”

Offshore Infrastructure Options

In launching the solicitation for proposals, BPU and PJM set out a rough guiding framework of suggested elements and infrastructure improvements. They included four onshore locations on the existing grid — one in North Jersey, two in the center of the state and one in the south — that are suitable interconnection points. (See Fierce Competition in Plans to Upgrade NJ Grid.)

The board also identified several “power corridors” through which lines could run onshore from the coast to the connecting sites, and five suggested routes for cables running underwater to the shore. Finally, the BPU suggested an “offshore transmission backbone” running parallel to the coast, to which the turbines would connect and on which several substations would be sited.

The SAA proposal asked the commission to approve a variety of issues, among them to enable the BPU to assign transmission capability created by SAA projects to OSW generators selected by the BPU’s solicitation process. The application also sought approval for the BPU to allow OSW generators to be studied through PJM’s interconnection queue and grant incremental rights, if eligible, associated with any incremental transmission capability created by SAA projects. (See PJM, NJ Seek FERC OK for OSW Tx Process.)

The SAA, according to FERC, is “a supplementary transmission planning and cost allocation mechanism in PJM’s Operating Agreement through which one or more state governmental entities authorized by their respective states, individually or jointly, may agree to be responsible for the allocation of all costs of a proposed transmission expansion or enhancement that addresses state public policy requirements identified or accepted by the state(s).”

PJM proposed the SAA to comply with Order 1000’s requirement for procedures to address transmission needs driven by public policy requirements in the regional transmission planning process.

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Virginia AG, SCC Staff Question Costs on Dominion’s OSW Project

Dominion Energy’s (NYSE:D) proposed offshore wind project in Virginia has run into some stiff headwinds as it seeks state regulators’ approval.

In testimony filed with the Virginia State Corporation Commission (SCC), commission staff and the state attorney general’s Division of Consumer Counsel questioned the cost of the 2.6-GW Coastal Virginia Offshore Wind (CVOW) project and called for ratepayer protections (PUR-2021-00142). A consultant for Synapse Energy Economics also questioned Dominion’s ability to bring the project in on budget, citing its lack of experience with offshore wind.

The filings were made as the SCC prepares for hearings on the project beginning May 16. In November, Dominion announced that the projected cost had increased by more than 20% to $9.8 billion, citing “commodity and general cost pressures.” (See Dominion’s OSW Project to Cost $9.8B, up from $8B.)

Based on testimony by consultant Scott Norwood, the Consumer Counsel filing says that the project is not needed to serve the company’s system capacity requirements through at least 2035; that the capital costs are about twice or three times the cost of solar resources; and that the company is overstating the forecasted economic benefits.

The filing acknowledged that the legislature’s Virginia Clean Economy Act of 2020 (VCEA) “declared that utility-owned offshore wind electric generation facilities are … in the public interest” and directs the commission “to give due consideration to economic development and social cost of carbon benefits of the project.”

But given the high fixed cost of CVOW and the “significant risks” to customers, if it is approved, Norwood recommended that the SCC hold Dominion strictly to the $9.8 billion cost figure; that the SCC hold the company to minimum standards on capital, operations and maintenance costs, and operating performance; and that the agency have “the company publicly commit to in-service dates.” Moreover, the company should “be required to file periodic status reports … that address the performance and cost of the project through the construction period and for at least the first year of commercial operations.”

If Dominion finds that an in-service date is going to be delayed by more than six months or that it will overrun the $9.8 billion estimated cost by 5% or more, the filing says, the SCC “should require that the company make an immediate filing with the commission that provides notice of the delay or cost increase, provides an explanation of the reasons for the delay or cost increase, and which reopens the question of prudence” of the project as a whole.

Presumption of Prudence in Jeopardy

Katya Kuleshova, of the SCC’s Division of Public Utility Regulation, testified that levelized cost of energy (LCOE) sensitivity analyses show scenarios in which the project’s cost exceeds 1.4 times the cost of a conventional simple cycle combustion turbine — which would eliminate the project’s “presumption of reasonableness and prudence” under the VCEA.

Kuleshova said staff also were concerned that the project’s energy production is expected to be at its highest during shoulder months and at its lowest during summer afternoons, when it is needed the most.

“In the absence of the statutory presumption of prudence, staff does not take a position on the prudence of the project,” she said, recommending the commission order a performance guarantee and cost overrun protections to mitigate risks to ratepayers.

In an email to RTO Insider on Thursday, a spokesperson for Virginia Attorney General Jason Miyares said that his office cannot comment on “pending litigation.”

Dominion responded to the filings with a statement saying, “Offshore wind’s zero fuel cost and transformational economic development and jobs benefits are needed now more than ever.”

Company spokesperson Jeremy Slayton also noted that none of the parties intervening in the docket had opposed the project’s approval. “We are pleased all parties to the case have focused on ways to have the best possible project, and none have opposed it,” Slayton said.

Testifying for activist group Clean Virginia, Maximilian Chang, principal associate with Synapse Energy Economics, recommended that the SCC “conduct an assessment to evaluate if the current utility-owned model for the CVOW is the most appropriate mechanism for the second 2,600 MW of offshore wind for Virginia, as outlined in the Virginia Clean Economic Act legislation. As part of this assessment, the commission may consider other forms of offshore wind procurement, including but not limited to power purchase agreements and/or offshore renewable energy credits.”

The problem, in Chang’s view, is that outside of CVOW, Dominion’s project team appears to have limited direct offshore wind project experience that would show its ability to complete the project on time and within budget. Like the consumer counsel, he recommended that the SCC impose a capital cost cap for the project, but he also suggested that the cap exclude the $500 million the company is requesting for financial hedges and contingency. If the project’s capital costs increase beyond $9.8 billion, Chang said, the commission should set clear guidance that Dominion could be on the hook for overruns. The utility should also be required to submit regular progress reports, and to hire an independent monitor, he said.

In addition to 176 14.7-MW wind turbines, the project includes 3 miles of submarine transmission; a new Harpers Switching Station, located on the grounds of Naval Air Station Oceana; three new overhead 230-kV transmission lines between the new Harpers station and the existing Fentress Substation; the expansion of the Fentress station; a partial rebuild of Line 271; and a rebuild of Line 2240. Dominion estimated a cost of $774 million for transmission and $374 million for substation work, for a total of $1.15 billion.

Dominion requested a final order by Aug. 5, which would allow onshore construction to begin in the third quarter of 2023, followed by offshore construction in the second quarter of 2024, with construction finished in mid-2025. Commissioning of the turbines would begin in August 2025 and continue through the end of 2026.

Economic Impact

The company says the project will create approximately 900 jobs and have $143 million in economic impact annually during construction, increasing to approximately 1,100 and almost $210 million annually during its operation.

Norwood said Dominion’s cost-benefit analysis is flawed because it compared total production costs of the system in a scenario with the project, to costs of the system under an alternate scenario that assumes the company would not replace CVOW’s capacity and energy with other renewable resources. The utility’s modeling created “illusory benefits” for the CVOW project, he said.

Norwood also criticized Dominion for failing to include sensitivity analyses to assess the impact of uncertainty in forecasted commodity prices, carbon emissions prices or PJM energy prices. “For example, the commodities price forecasts used for all CBA scenarios assumes that Virginia remains as a member of the Regional Greenhouse Gas Initiative and that federal CO2 legislation becomes effective in 2026,” he said.

The commission will hear public testimony via phone May 16 and hold an evidentiary hearing in Richmond beginning May 17. Both hearings will be webcast. Those wanting to speak as a public witness must register by May 12.

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Now, the Hard Part: MISO, SPP Tackle JTIQ Cost Allocation

SPP and MISO began gathering stakeholder feedback Friday on ways they can pass the hat for the projected $1.65 billion in transmission projects that resulted from their joint targeted interconnection queue (JTIQ) study.

RTO officials began their meeting by acknowledging uncertainties over how much additional generation could be connected as a result of the new transmission, comprising seven projects that are projected to resolve 48 reliability constraints and deliver about $724 million in adjusted production costs savings to MISO and $247 million to SPP.

Andy Witmeier 2022-03-31 (RTO Insider LLC) FI.jpgMISO’s Andy Witmeier speaks at the Gulf Coast Power Association’s MISO South/SPP Conference in March. | © RTO Insider LLC

While MISO’s model estimated a total of 28 GW (10.5 GW in SPP and 17.5 GW in MISO), SPP’s model estimated almost twice as much benefit, a total of 53 GW (11.1 GW in SPP and 41.9 GW in MISO).

Andy Witmeier, director of resource utilization for MISO, said the discrepancies may have resulted from how SPP’s model dispatched MISO generation to serve MISO load and the impacts on loop flow.

To simplify the cost allocation, the RTOs said they settled on using each RTO’s model for its own generation: 11.1 GW in SPP and 17.5 GW in MISO, for a total of 28.6 GW.

“MISO knows how they dispatch their generation … and similar for SPP,” Witmeier said. “Let’s just use the SPP number based on how they’re serving their own load with their generation to try … and remove some ambiguities.”

Cost allocation (MISO) Content.jpgTo simplify cost allocation discussions, MISO and SPP said they will use SPP’s model for SPP’s generation and MISO’s for MISO: 11.1 GW of generation in SPP and 17.5 GW in MISO for a total of 28.6 GW. | MISO

In an example offered by the RTOs, generator interconnection requests with a 5% or greater DFAX (solution-based distribution factor) impact on the JTIQ portfolio could pay a charge of $35,000/MW. So, a 270-MW generator with a 10% DFAX impact would pay $945,000 (27 MW x $35,000).

Rafik Halim of National Grid Renewables asked the RTOs to share the details of their modeling. “There needs to be a study that’s transparent” before decisions are made, he said.

Stakeholder-driven Methodology Sought

Neil Robertson 2022-03-30 (RTO Insider LLC) FI.jpgSPP’s Neil Robertson at the Gulf Coast Power Association’s MISO South/SPP Conference in New Orleans. | © RTO Insider LLC

Neil Robertson, SPP’s coordinator of system planning, emphasized that the per-megawatt charge and DFAX threshold were used to illustrate the concept and not a firm proposal, saying the RTOs seek a “stakeholder-interactive approach” to developing the methodology.

“SPP and MISO did not intend to come up with a fully developed methodology and then simply ask for stakeholder input,” he said. “We want to take stakeholder input on key concepts and use them as building blocks to build out this methodology.”

“We are not naive enough to think we have all the answers,” added David Kelley, director of seams and tariff services for SPP.

The actual cost multiplier will be designed to collect all of the costs of the portfolio “while, at the same time, fully utilizing the capacity, not underselling or overselling the capacity that we are creating,” Robertson said. Whatever the methodology, “prior to executing a GIA [generator interconnection agreement], you would know what the JTIQ charge would be, just like you would know any of the other upgrades involved in the generation interconnection process.”

Robertson said RTO officials are seeking a balance between a subscription-based model and one in which load would initially pay for the projects and generation would reimburse as it interconnects. Such a balance could involve the requirement of a “critical mass” of generator agreements: for example, 50% of total JTIQ portfolio funding agreed to by GI customers in signed GIAs. Funding for the other 50% could come from local transmission owners or be regionally funded and later reimbursed as additional generators sign up.

Steve Gaw of the Advanced Power Alliance, which represents wind, solar, and energy storage companies, expressed concern that the critical mass approach could delay interconnections of projects already in an open study.

Robertson acknowledged that while the model could mitigate risk to “any particular segment of the stakeholder base,” it could also “increase the uncertainty” for some generators.

Brenda Prokop of LS Power said she agreed with the concept of a critical mass. “I think it’s pretty necessary to set some kind of threshold for proceeding with projects.”

But she said MISO and SPP should not “assume that the JTIQ projects would be reserved for local TOs and eligible to be funded by them” because not all of the projects would be in states that permit TOs a right of first refusal (ROFR). The projects would be built in Minnesota, North Dakota and South Dakota, which all have ROFR laws, as well as in Nebraska and Kansas.

Antoine Lucas, SPP’s vice president of engineering, closed the meeting by acknowledging that the two RTOs had forgone the “certainty” of their existing cost allocation processes in seeking an “ad hoc” methodology for JTIQ.

“But we felt like it was worth it to have the flexibility to be able to craft a mechanism customized to fit the specific projects and specific circumstances that we would see from the JTIQ,” he said.

Next Steps

The seven projects have a projected cost of $1.65 billion, but the JTIQ cost allocation likely won’t apply to two of the projects, which MISO has included in its tranche of long-range transmission projects. (See MISO, SPP Finalize JTIQ Results with MISO Tx Duplicates.)

MISO and SPP hope to submit their cost allocation formula to FERC by the end of this year, with RTO approvals of the JTIQ projects by the second quarter of 2023.

Additional joint stakeholder meetings are tentatively scheduled for 10 a.m. to 12 p.m. CT on May 20, June 27 and July 29. Comments may be sent to GI-AFS@misoenergy.org and interregionalrelations@spp.org.

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NACFE: Electric Vans Have Arrived

The North American Council for Freight Efficiency (NACFE) makes the case in a report released this week that electric versions of vans and step vans used by delivery companies and small businesses are not only competitive with gasoline and diesel vehicles but are “a perfect fit” for the market segment.

The conclusion is based on data collected from three battery electric vans and step vans operated last fall by companies participating in real-world testing of the vehicles, as well as interviews with their staffs of participating, including the vehicles’ drivers and maintenance crews. Members of the NACFE team also interviewed vehicle manufacturers.

The number of small commercial vehicles is expected to grow. NACFE estimates that there are about 4.2 million vans and step vans used commercially in the U.S. and Canada. Many of the vans are involved in deliveries of products purchased through e-commerce sales, which amounted to $218.5 billion in 2021.

Citing statistics from the Bureau of Transportation, NACFE noted that the tonnage delivered in the top 50 delivery routes is expected to increase from 2.4 million tons in 2022 to 3 million tons in 2030.

Data collection from the vehicles participating in the real-world testing was done electronically and appears to have been rigorous.

“All three vehicles were instrumented with a Geotab telematics device. The vehicle operations were continuously digitally tracked, and their metrics updated daily via a public website with the ability to view results by day or over a span of days. Metrics such as daily range, speed profiles, state of charge, charging events, amount of regenerative braking energy recovery and number of deliveries were shown in near real time. Information on weather conditions also was observed,” the report said.

Drivers were enthusiastic about their experience, the report states, because of the ease of operation and the considerably less noise and vibration that left them less fatigued at the end of a shift.

Interviews with maintenance crews found them to be positive, with far less to do, as the engines, transmissions and related emission controls had been replaced with an electric drive and battery pack.

The vehicle battery packs were designed to be charged at 240 V overnight, meaning even a fleet would not pose an extra heavy load on utilities.

Despite the positive results, the report points out that there will be challenges as the delivery industry switches over as predicted, gradually replacing their existing vehicles with electrics in pilot programs.

Total cost of ownership is one way fleet managers approach the problem, the report said.

“Fleets utilizing vans and step vans, especially in the parcel and package delivery space, currently expect the equipment to last 15 to 20 years and accumulate 300,000 to 400,000 miles in that time span.

“Although manufacturers believe battery life can meet design lives of five, seven and 10 years depending on the OEM choices, long-term performance of electrified vehicles in this market segment still needs to be validated by fleets,” the report cautions.

On the plus side, maintenance costs are expected to be considerably less than with conventional engines and transmissions that required steady preventive maintenance. One performance aspect on the side of the electrics is the cost of fuel.

A NACFE analysis based on the price of gasoline at $2.98/gallon and the delivered cost of electricity at the national average rate of 11.2 cents/kWh and 250 days of operation delivered an estimated annual fuel cost for the gasoline-fueled vehicle at $10,065 and $1,958 for the electric version.

“We expect that this work [the real-world testing] will encourage fleets to explore the deployment of commercial battery electric vehicles (CBEVs) in their operations where they make sense, for manufacturers to improve their products for quicker return on investment and for others to better support the efforts of the trucking industry to progress the use of CBEVs,” the report explained.

“NACFE considers this market segment to be 100% electrifiable,” the report concludes, “which would result in the avoidance of nearly 43.5 MT CO2e annually.”

“As recently as five years ago, I would have questioned the feasibility of electrifying North American van and step van fleets,” said Mike Roeth, NACFE executive director. “The transition to cost parity happened quicker than most of us expected, and I am surprised to announce today that the electric market has arrived.”

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NYPSC OKs 2 Huge Clean Energy Projects for New York City

The New York Public Service Commission on Thursday voted 5-2 to approve separate 25-year state contracts to buy electric power from the 1,300-MW Clean Path New York (CPNY) and the 1,250-MW Champlain Hudson Power Express (CHPE) projects that will bring solar, wind and hydropower from upstate and Canada into New York City (15-E-0302).

Rory Christian (NYDPS) Content.jpgNYPSC Chair Rory Christian | NYDPS

The two transmission projects, Tier 4 renewable resources under the state’s Clean Energy Standard, are projected to cut New York City (Zone J) fossil-fired generation by 51% and to bring up to $5.8 billion in social benefits, including greenhouse gas (GHG) reductions and air quality improvements and $8.2 billion in economic development across the state that will benefit disadvantaged communities.

“New York City relies heavily on aging fossil fuel generation — simply put, if we can’t deliver renewable energy to New York City we can’t reduce emissions from that fossil fuel fleet,” said PSC Chair Rory Christian. “Based on the over 30 proposals received, these options are the best available.”

The projects, he said, support the goals set by the Climate Leadership and Community Protection Act and align with the New York State Constitution supporting each person’s right to “clean air, water and a healthful environment.”

Diane X Burman (NYDPS) Content.jpgNYPSC Commissioner Diane X. Burman | NYDPS

CPNY, developed by the New York Power Authority (NYPA) and Forward Power, a joint venture of Invenergy and energyRe, will be tied to 23 generation facilities and bring upstate solar and onshore wind into the city from its origin point in Delaware County with a start date of June 30, 2027. The constant rate contract over 25 years pays $129.75/MWh for 7,870,865 MWh/year for a total contract price of approximately $25.5 billion.

The CHPE, developed by Transmission Developers and Hydro-Québec’s U.S.-based subsidiary HQUS, will run from the state’s border with Canada to Queens, with portions of the line running underneath the Hudson River. Its contract begins Dec. 15, 2025, and increases by 2.5% per year. Starting at $97.50/MWh for 10,402,500 MWh/year, the 25-year total contract price is approximately $34.6 billion.

The actual program payments will be calculated at those strike prices minus reference energy and capacity pay prices as defined in each contract, with the renewable energy credit (REC) payments dependent on future energy and capacity commodity prices, said Marco Padula, an economist at the state’s Department of Public Services. “The petition presents ratepayer impacts that are projected as the net REC costs over time under a range of projected energy and capacity price forecasts.”

City Lights

New York City filed a notice in November stating its intent to enter into a 25-year contract with the New York State Energy Research and Development Authority (NYSERDA) to procure Tier 4 RECs, which, when combined with the city’s load share-based allocation of offshore wind RECs, would be equivalent to its entire load, said Robert Rosenthal, general counsel for the DPS.

Robert Rosenthal (NYDPS) Content.jpgRobert Rosenthal, NYDPS | NYDPS

The city is taking a lead to reduce GHG emissions by backing up its policies with a significant financial commitment, providing a model for other branches of state and municipal governments to follow, Rosenthal said.

On April 9, the state Office of General Services (OGS) filed a letter of intent stating that it would also be entering into a contract with NYSERDA for Tier 4 RECs associated with energy used by all state agencies located in the city.

“DPS sees this all-of-government approach as a significant development that will meaningfully reduce utility ratepayer impact of implementing the CLCPA, and it will strongly encourage other branches of government to make commitments under Tier 4 similar to those made by New York City and OGS,” Rosenthal said.

The city’s efforts are encouraging signs that future investments will not solely be borne by ratepayers but spread out equitably through a more expansive all-of-government approach, Christian said.

David Valesky (NYDPS) Content.jpgNYPSC Commissioner David Valesky | NYDPS

“Many comments received, including those from the Real Estate Board of New York, highlighted the growing demand for RECs through voluntary corporate and consumer action as another potential source for savings,” he said. “It is likely that many building owners will procure Tier 4 RECs, potentially a very significant quantity of RECs, for compliance with various local laws, such as local law 97 in New York City,” Christian said. (See NY Stakeholders, Residents Split on HVDC Tx Projects.)

Commissioner David Valesky quoted from the comments filed by the largest property owners in the city who “are eager to explore participating in this voluntary market to determine how purchasing these RECs can enhance our corporate goals and local law 97 compliance strategies.”

Regarding voluntary participation versus mandates, “the reality of local law 97 cannot be understated and is significant to say the least, so I think these are important commitments,” Valesky said. “They’re meaningful commitments in terms of reducing the impact of these projects on ratepayers across the state.”

Ratepayer Concerns

The commission had to vote on the projects based on the record, which shows the known cost to ratepayers “are unacceptably high,” said Commissioner Diane X. Burman, who voted against the order.

Commissioner John B. Howard also voted no, concerned that the projects received little publicity and discussion west of the Hudson River.

John B Howard (NYDPS) Content.jpgNYPSC Commissioner John B. Howard | NYDPS

“In fact, of those entities who commented from central and western New York, they were by and large opposed to this order,” Howard said. “While this petition received extensive press coverage from the New York City-based media, nary a word was written about it in the upstate media, so in any discussions I had with individuals upstate, they had little or no awareness of the impacts to customers in their region.”

He urged the commission to more aggressively seek the opinions of those customers who will pay most of the bills, since electricity customers outside of the city will pay 60% of the Tier 4 cost for the contracts.

“Even today, we have heard over and over again that the vast majority of benefits to this proposal accrue to New York City because customers pay for Tier 4 on a pure kWh basis,” Howard said. “Combined with a relatively lower cost retail electric cost outside of New York City, particularly upstate, the percentage of increase on customers’ bills will be higher upstate.”

The contracts, he said, will have a “disproportionate impact” on large customers and “we cannot sacrifice upstate New York economic competitiveness as we decarbonize our economy.”

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CAISO Sets 98% Renewables Record

CAISO said Thursday it set a record for renewables on its grid earlier this month when nearly all the ISO’s electricity came briefly from clean, renewable resources.

The peak of 97.6% happened at 3:39 p.m. PT on April 3 and broke the previous record of 96.4% set a week earlier on March 27. Even higher numbers are possible this month, the ISO said.

CAISO has been adding more renewable energy to its grid in support of the state’s goal of achieving 100% clean power for retail customers by 2045.  

“When we see renewable energy peaks like this, we are getting to re-imagine what the grid will look like for generations to come,” CAISO Board of Governors Chair Ashutosh Bhagwat said in a news release. “These moments help crystallize the vision of the modern, efficient and sustainable grid of the future.”

CAISO’s installed renewable energy mix consists of about 57% solar, 30% wind and smaller amounts of geothermal energy, small-hydro resources and biofuels. About 32% of California’s energy mix came from renewable power in 2020, the most recent year for which figures are available, according to the state Energy Commission.

The ISO also set a new solar peak of 13.6 GW early in the afternoon of April 8 and an all-time wind peak of 6.2 GW shortly before 3 p.m. March 4.

“Renewable peaks typically occur in the spring due to mild temperatures and the sun angle allowing for an extended window of strong solar production,” the news release said. “ISO analysis forecasts a potential for more renewable records in April.”

SPP reached a similar milestone last month when it became the first multistate grid operator to temporarily serve more than 90% of its demand with renewable energy. (See SPP Stuns with 90.2% Renewable Penetration Mark.)

SPP’s footprint includes high-wind regions of the Dakotas, Kansas, Missouri, Nebraska, Oklahoma and Texas, and its resource mix includes about 31 GW of installed wind capacity.