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April 17, 2022November 28, 2023

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.”

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.

Renewables 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.

April 17, 2022

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.

April 17, 2022December 15, 2023

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.

April 17, 2022January 31, 2024

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.jpg

MISO’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.”

To 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

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SPP’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.

April 15, 2022

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.”

April 15, 2022June 14, 2023

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).

NYPSC 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.”

NYPSC 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 | 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.

NYPSC 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.

NYPSC 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.”

April 15, 2022

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.

April 14, 2022April 22, 2024

SPP to Phase Out WEIS as New Market Offerings Expand

SPP said Wednesday it plans to eventually close its Western Energy Imbalance Service (WEIS) after current members join either its expanded RTO West or its Markets+ program, now under development, that will offer a bundle of RTO-like services.

“We don’t intend to have three different offerings in the West,” Kara Fornstrom, SPP director of state regulatory policy and a staff member working on Markets+ design, said in a briefing for the Western Interstate Energy Board.

The webinar gave Western utility regulators the chance to ask questions about the Markets+ program. Fornstrom made her comments while answering a question from Colorado Public Utilities Commission Chair Eric Blank.

“I just realized this a few days ago, that the WEIS market, the energy imbalance market, is at some point in the future going to sunset as entities join the RTO and the Markets+ day-ahead,” Blank said.

“I was just surprised that WEIS is going away,” he added.

Blank asked if Markets+ would also “sunset” or would be a “permanent option.”

Fornstrom said most of the WEIS’s current members “will have moved already to the RTO expansion … before Markets+ launches, so the WEIS will have shrunk before we get to Markets+, and the remaining entities in WEIS that we have today have expressed their interest … to go to Markets+ rather than just the [WEIS’s] real-time service.

The move is “based on [WEIS members’] interest level on adding the [Markets+] day-ahead service,” she said.

Markets+ will be a “long-term durable solution” in the West, Fornstrom said.

Later, Joe Fina, a stakeholder member of the Markets+ design team and assistant general counsel at the Snohomish County Public Utility District, said: “The WEIS will be replaced by Markets+.”

And SPP spokeswoman Meghan Sever said in an email to RTO Insider that it is “SPP’s intention to only provide one market offering in the West in order to provide maximum benefits for Western utilities. Current WEIS participants will have the option to join the RTO or participate in Markets+. Until then, SPP remains fully committed to continue providing Western reliability coordination and operating the WEIS market.”

Toe-to-toe with CAISO

SPP launched the WEIS, a real-time interstate trading market, in January 2021, making it the first RTO with energy markets in both the Eastern and Western interconnections. It intended for the WEIS to compete with CAISO’s larger and well-established Western Energy Imbalance Market (WEIM).

SPP has had some success competing with CAISO. In January, three Colorado utilities that had planned to join the WEIM instead decided to join the WEIS. Public Service Company of Colorado, Platte River Power Authority and Black Hills Colorado Electric followed Colorado Springs Utilities in switching allegiance from CAISO to SPP. (See Colorado Utilities Choose WEIS over WEIM.)

The WEIS, however, has gained fewer members than the WEIM, which was launched in 2014.

CAISO’s imbalance market has attracted 22 current or planned participants, including major utilities such as Arizona Public Service and NV Energy, while the huge Bonneville Power Administration is scheduled to go live next month. The WEIM has produced $1.93 billion in economic benefits for its members in the past eight years and is expected to cross the $2 billion mark with its next quarterly report. (See Western EIM Nears $2B in Total Benefits.)

With the addition of the Colorado utilities, WEIS has 14 current or future members including Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, Guzman Energy and the Western Area Power Administration’s Upper Great Plains West and Rocky Mountain regions and its Colorado River Storage Projects.

CAISO has been working to develop an extended day-ahead market (EDAM) as an additional offering to the WEIM, a real-time interstate market that was the first of its kind. CAISO also provides reliability coordination services through its RC West to most of the Western Interconnection.

The ISO, however, is limited by its one-state governance from becoming a Western RTO.

SPP also offers RC services in the West and is administrator for the Western Power Pool’s Western Resource Adequacy Program (WRAP). Once fully implemented, the WRAP will help Western balancing authorities respond to potential generation shortages during critical hours as the region addresses the retirement of thermal resources and its growing reliance on variable renewable resources. (See NWPP Rebrands as Western Power Pool.)

Unlike CAISO, SPP can offer full RTO membership to Western entities. It intends to expand its RTO footprint and develop a Western market system that is fully integrated with its existing market system.

The Markets+ program is aimed at utilities that do not want to join an RTO but need a range of services normally provided by an RTO, including day-ahead and real-time unit commitment and dispatch. SPP says Markets+ will provide easy transmission service across the footprint and set the stage for the reliable integration of renewable energy’s growth.

SPP presented the Markets+ model to interested participants during a virtual meeting in December and plans to hold in-person forums throughout the West. The RTO is gathering information from interested parties, including WRAP participants, as part of an extensive process leading up to the program’s launch. Wednesday’s WIEB briefing on program governance and other matters was part of that process.

April 14, 2022January 3, 2024

US Interstate Highways: A NIMBY-free Corridor for Grid Expansion?

An exhaustively researched report examining the use of the U.S. interstate highway system as a ready-made corridor for expansion of the nation’s high-voltage transmission system, as well as a broadband internet access, concludes it can be done relatively quickly and at a lower cost than siting new transmission corridors.

Prepared for the Minnesota Department of Transportation by Seattle-based NGI Consulting and The Ray, an Atlanta nonprofit, the 81-page analysis offers national conclusions. It argues that “NextGen Highways” ought to include buried HVDC transmission lines co-located with fiber-optic cables.

The recommendation to open interstate rights of way (ROWs) is in line with policy changes issued in 2021 by the U.S. Department of Transportation giving state DOTs the option to allow utilities to site energy infrastructure, including pipelines and even renewable energy projects, within interstate ROWs.

The release of the massive study also comes a year after the Biden administration announced the availability of $5 billion in loan guarantees to encourage the expansion of the grid, noting that decarbonizing transportation will require the grid to double or even triple in size.

The transportation sector accounted for 29% of carbon emission in 2019, more than power generation did, according to EPA, making transportation decarbonization a priority issue.

The report argues that state departments of transportation should:

- - “site and build fiber in a way that allows for buried HVDC transmission to be co-located at a later date;
  - “develop and invest in their relationship with utilities, public utilities commissions and other state agencies with transmission siting jurisdiction; [and]
  - “determine the amount of operational funding required to support the co-location of electric and communications infrastructure in their ROW.”

The report’s recommendation of underground HVDC power lines is no accident. HVDC power lines can move power long distances without line losses and without inducing currents in nearby conducting materials. And unlike AC lines, HVDC lines can connect systems operating at different AC frequencies. Yet few HVDC lines have been built in the U.S., according to the report.

“Unlike the U.S. Interstate Highway System, the U.S. power grid is composed of many discrete regions. Modeling study after modeling study has shown that connecting these regions is critical to cost-effective grid decarbonization,” the report states. “It is also critical for grid reliability and resiliency.

“Despite the importance of connecting the electric grid regions using interregional transmission lines, project after project has failed in the U.S. Since 2014, the U.S. has not built a single gigawatt of interregional transmission capacity. Meanwhile, China, Europe, South America and India have collectively built nearly 350 GW of interregional transmission capacity.

“Most recently, the construction of the New England Clean Energy Connect transmission line was stopped indefinitely by a public referendum in November 2021. This was an incredible result given that the New England Clean Energy Connect had already received the required regulatory approvals and was in the process of being built.”

One of the most important conclusions of the study is that decarbonizing the grid itself — moving clean power to where it is needed, particularly for charging electric vehicles — will be less costly using HVDC transmission lines.

“As seen in Europe and now in New York state, buried HVDC transmission is being used to build the interregional transmission required to cost-effectively and reliably decarbonize the electric grid,” the report said.

And in one of the dozens of supplemental documents attached to the report, the analysts explain in more detail that “many of the richest wind and solar resources are located far from the urban load centers where most of the country’s energy is consumed. The nation’s transmission infrastructure must at least double to accommodate the exponential growth of wind and solar that will accompany decarbonization.

“Without the addition of significant multiregional transmission, system planners will need to overbuild local renewable resources in order to manage weather patterns and meet demand, resulting in extreme curtailment of local wind and solar resources, even if high levels of storage capacity are available, dramatically increasing costs.”

Additionally, the expected development of solid-state converters to replace conventional transformers will allow for the development of medium- and high-voltage charging stations, the report postulates, further arguing that the buildout of HVDC converter stations will create “economic development zones … logical locations to site fleet and over-the-road EV charging infrastructure and data centers.”

While the study makes national recommendations, its analysis initially focuses on state DOTs because they control highway corridors and ROWs.

Most states, including Minnesota, have not permitted overhead transmission lines to run along highways because of the possibility of vehicular accidents. Many states limit transmission line intrusions to crossing over highways, the report found.

Wisconsin is one of the few states that does allow transmission lines to parallel highways inside the ROW and, according to the report, has permitted the construction of an overhead line to run inside an ROW after state lawmakers approved the practice in 2003.

That legislation requires utilities and grid companies building new transmission to first consider existing utility corridors and then highway and railroad corridors and even recreational trails before seeking to establish new utility corridors. The Wisconsin Department of Transportation (WisDOT) then amended its policies to reflect the new law, as did the state Public Service Commission (PSCW).

“In 2009, as a result of Act 89, WisDOT’s updated utility accommodation policy, and the development of new transmission infrastructure, WisDOT and PSCW entered into a cooperative agreement ‘to ensure that whenever practical, WisDOT and PSCW shall utilize existing transportation or transmission corridors instead of creating new corridors for electric transmission facilities.’ …

“The legislation, policy and agreements described [here] have fostered a collaborative and trusting relationship between Wisconsin utilities and WisDOT and have resulted in the efficient, cost-effective and successful siting of over 800 miles of transmission infrastructure in and along interstate and highway ROW in Wisconsin,” the report notes, adding that “Wisconsin has the playbook for siting transmission in DOT ROW.”

The Great Plains Institute, based in Minneapolis; Satterfield Consulting in Madison, Wis.; 5 Lakes Energy of Lansing, Mich.; and consultant Tracy Warren in D.C. assisted with the research and release of the report.

In a statement, Morgan Putnam, founder of NGI Consulting, announced the release of the report and what the team expects to do next.

“Given the positive findings from this study, we will be launching a NextGen Highways Coalition later this year. The coalition will facilitate conversations between state DOTs, transmission developers and governors to support the co-location of buried fiber and transmission in highway and interstate ROW.”

April 14, 2022December 7, 2023

SERC Urges Industry Effort on Facility Ratings

A new report released Wednesday by SERC aims to help “registered entities … reduce the risk of facility ratings challenges, resulting in a more reliable and secure” bulk power system.

The report, “Facility Ratings Themes and Lessons Learned,” was inspired by the “hundreds of individual instances” of violations of NERC reliability standard FAC-008-5 (Facility ratings) and its predecessors that SERC has logged since 2017. SERC based its analysis on data from those violations, as well as information “gathered through [its] various voluntary outreach and training activities.”

Improper facility ratings are a frequent source of compliance issues in SERC and other regions: FERC last year approved a $570,000 penalty leveled by ReliabilityFirst against American Electric Power over misratings at nearly 600 facilities. (See AEP to Pay $570K in NERC Penalties.) WECC also lodged a $265,000 settlement with Public Service Company of New Mexico over facility ratings issues last year, and SERC settled with the Tennessee Valley Authority for the same reason in March. (See FERC OKs $265,000 PNM Penalty.)

At SERC’s Board of Directors and Members meeting last month in Savannah, Ga., the regional entity’s vice president of operations, Tim Ponseti, said the frequency of facility ratings violations was becoming a source of concern for the ERO Enterprise and prompted the report. (See SERC Board of Directors/Members Briefs: March 30, 2022.) With the growing risk of extreme weather from climate change, as well as the ongoing adoption of new generation resources, the RE felt it was necessary to address the reasons behind the issues.

“Facility ratings have a far- and wide-reaching impact [on] daily operations: real-time analysis, next-day planning, long-term planning, modeling … and the list goes on,” Ponseti said. “All these areas are making critically important decisions, and at their fundamental basis is a reliance on an assumption of accurate facility ratings.”

Utilities Lack Awareness of Own Systems

The report identified three major themes associated with the majority of the FAC-008 violations encountered by SERC in the last five years. Each theme was considered the primary cause of about a third of the infringements studied. While the document identified “potential mitigation strategies” for each issue, SERC emphasized that these should not be considered binding requirements or directives for industry.

The first theme, accounting for 28% of violations, was lack of awareness, which SERC defined as the absence of “an accurate physical accounting or understanding of the current-carrying equipment” within a utility’s system. Failure to develop and implement a facility ratings program also falls under this category.

When this occurs, entities tend to rely on rating information provided by equipment manufacturers, nameplate ratings or outdated field inspection reports. Without frequent inspections, inaccurate ratings may “go undetected for a long duration.”

SERC suggested addressing this issue by enhancing the engagement and oversight of senior management, urging leaders to “set a positive ‘tone at the top’ by creating a culture … that treats facility ratings as a program — like safety — and not like a one-time project with a finite start and end date.” This approach includes establishing a level of engagement with the entity’s RE and with NERC; the report noted that the ERO Enterprise has performed “a significant amount of outreach” to industry regarding facility ratings and that keeping up with these efforts could help utilities build awareness of potential deficiencies in their programs.

Periodic field validations are an essential component of a facility ratings program that is too often neglected, SERC said. As equipment is replaced in the field during restoration from extreme weather events, entities must ensure that they are not simply reusing the same ratings, which may not apply to the new items. Physical walk-downs can also help to spot equipment that an entity may have lost track of after a merger or acquisition.

Asset, Data and Change-management Challenges

Another theme identified in the report, and comprising 34% of violations, is inadequate asset and data management. Asset management is defined as the identification, management and tracking of physical facility ratings assets, while data management is the collection, validating and storage of ratings-connected data.

Managing assets and data can be challenging, because physical assets can range in size from very large to extremely small and may also be located in places that are physically difficult to inspect; data are often stored by the same departments that use them, for which storage is not necessarily a priority. This means that when data are needed during an audit or review, a utility may face delays tracking them down.

Mitigation strategies for asset and data management include periodic field verification programs, as well as effective data capture and verification strategies and spreadsheets or databases to store information properly. Entities must also include contractors in their strategies and make sure they are also trained in the proper data management schemes.

The third theme is inadequate change management, which SERC said enables “facility and equipment rating changes to be captured, coordinated and implemented throughout the entity in a timely manner.” Failure to properly track changes to an entity’s equipment can create an inaccurate assessment of its system, leading to breakdowns at critical moments.

SERC described a case when a generator owner and transmission owner installed a new transformer at a facility, replacing a transformer that had been the most limiting element there. The new component had a higher rating and was therefore no longer a limiting element; however, the utility failed to account for this by updating its facility rating. In another case, a transformer was shared between two units. The utility retired one of the units and reconfigured the high-voltage bus, but nobody thought to adjust the facility ratings.

The report’s authors recommended implementing a strong change-management process that provides “clear roles and responsibilities,” as well as a quality assurance review process for each change. The process should be communicated to personnel through regular training and verified through field inspections, they said.