FERC on Friday approved PJM’s proposed rules on how the RTO will evaluate voluntary cost commitment proposals on competitive transmission projects (ER19-2915).
The Operating Agreement changes, which resulted from stakeholder-drafted motions at the Markets and Reliability Committee, require PJM to evaluate projects submitted in competitive proposal windows on multiple criteria, including “cost effectiveness.” (See PJM TOs Wary of Cost Containment Rules.)
The revisions clarify that PJM may not require developers to submit cost containments and that those that are voluntarily proposed are binding.
PJM would evaluate “the quality and effectiveness” of provisions that limit project construction costs, total return on equity (ROE) including incentive adders or capital structure.
Annual revenue requirement under partial and full cost caps | PJM
The RTO will submit to the Transmission Expansion Advisory Committee (TEAC) an analysis comparing the risks to be borne by ratepayers as a result of developers’ binding cost commitments or non-binding cost estimates.
In approving the rules, the commission rejected the objections of transmission owners, which argued the revisions did not provide enough details on how PJM will conduct its comparative analysis.
“We find that PJM’s filing is just and reasonable because it may assist PJM in its selection of the more efficient or cost-effective transmission solution and provides additional transparency of PJM’s evaluation of competing proposals,” the commission said. It noted that PJM is developing implementation details for the comparative analysis in Manual 14F.
“The proposed revisions provide reasonable flexibility both for developers to decide how to craft their voluntary cost commitment proposals and for PJM to evaluate and select the more efficient or cost-effective transmission solution. Moreover, the proposal provides for transparency, allowing stakeholders the opportunity to review any particular analysis conducted by PJM and raise any concerns via the TEAC process.”
FERC disagreed with arguments that the filing infringed on the rights of PJM transmission owners and nonincumbent transmission developers to exclusively make Federal Power Act Section 205 filings concerning transmission rates, revenue requirements and cost recovery.
It also rejected contentions that PJM will be determining whether the rate design elements under a proposal will result in just and reasonable rates. “PJM is proposing for the commission to determine, in reviewing the nonconforming DEA [designated entity agreement between PJM and a selected developer] with the cost commitment provision, whether any rate design component included in that provision is just and reasonable.”
FERC on Thursday denied NYC Energy’s (NYCE) request for a limited waiver of NYISO interconnection rules for its 80-MW energy storage facility proposed to be situated on a barge moored at the Brooklyn Navy Yard.
Manhattan as seen from the Brooklyn Navy Yard.
NYCE sought waiver of a Tariff provision that requires a project to withdraw from the ISO’s interconnection queue if it fails to comply with certain interconnection procedure requirements (ER20-629).
NYCE explained that its project is a modification of a previously permitted combined cycle gas/oil-fired generating facility and that the ISO also completed a materiality review of the project regarding a change in technology in August 2019. Further, the developer said it notified NYISO of its intention to enter the 2019 class year of the interconnection queue, and the ISO acknowledged the request on Aug. 16, 2019.
In addition, NYCE said it delivered an executed facilities study agreement (FSA) to NYISO on Sept. 11, 2019, along with all other required materials, including a $100,000 FSA study deposit.
But the company noted that when it submitted the FSA, it learned that NYISO had concluded that a previous finding of no adverse environmental impacts under state law applied only to the original project, not to the newer battery project, meaning the latter did not satisfy regulatory milestones required for the queue.
NYCE withdrew its effort to join the 2019 class year but sought a Tariff waiver in order to hold a position in the queue. NYISO supported NYCE’s waiver request, saying that absent a waiver from the commission, the ISO could not accept the two-part deposit for NYCE’s project after Sept. 16, 2019.
The ISO further said it did not dispute NYCE’s assertion that no adverse harm will result to other projects if the waiver request is granted because NYCE’s project no longer sought to participate in the 2019 class year.
The commission rejected NYCE’s arguments, saying “the record reveals no reason why NYCE could not have satisfied the regulatory milestone in accordance” with NYISO’s Tariff provisions, and the company “has not adequately explained why it assumed that prior regulatory reviews for a different generating facility would satisfy the regulatory milestone in the [Tariff].”
“Specifically, although we find no evidence of ill intent by NYCE, we find that NYCE has not demonstrated that it acted in good faith,” said the order confirmed by Chairman Neil Chatterjee and Commissioner Bernard L. McNamee.
The commission also found that NYCE failed to demonstrate that its waiver request was limited in scope.
It said “a waiver is not limited in scope if the party requesting waiver does not provide a compelling reason why it should be afforded special treatment compared to others. Here, NYCE seeks to shield itself from the consequences of its choices.”
Commissioner Richard Glick dissented in a separate statement.
“First, I see nothing in the record — or today’s order — indicating that NYCE did not act in good faith,” Glick said. “After all, it does not strike me as totally unreasonable to assume that, if an oil/natural-gas fired unit can pass environmental muster, then a non-emitting battery storage facility is likely to clear that bar as well.”
Glick argued that the waiver request is limited in scope insofar as it applies only to this facility and only to this single failure to comply with the applicable deadlines, and that the request remedies a concrete problem.
“Finally, I agree with NYISO that granting the waiver would not have undesirable consequences, such as harming third parties,” Glick said. “I also understand why NYCE sought to rely on its previous environmental determinations rather than fork over an additional quarter-million dollars in collateral … [which] does not, in my view, indicate that it acted in bad faith.”
Members of NERC’s Standards Committee are working to balance workload changes forced by the COVID-19 pandemic with the obligation to maintain transparency.
A particular focus at the committee’s conference call this week — replacing its scheduled in-person meeting in accordance with NERC’s Business Continuity Plan — was the work of the organization’s standard drafting teams (SDTs). Charles Yeung, chair of the Standards Committee Project Management and Oversight Subcommittee, told members the teams have seen little impact so far from ending face-to-face meetings. However, he warned that conference calls and online meetings could make discussing technical issues very difficult.
Linda Lynch, a member of the drafting team for Project 2017-01, involving frequency response and frequency bias shedding, presented her team’s approach to the problem in hopes that others might find it useful. Rather than try to address complicated technical subjects during full conference calls, team members have found it more useful to schedule smaller meetings of two or three people on an ad hoc basis. These small groups allow difficult issues to be worked out and presented to the larger group for a decision.
Committee members agreed that this approach could help work progress more quickly, but some expressed concern that they had not known about these small group meetings until this week’s call. They worried that these informal meetings could unintentionally shut entities out of an essential step in the standard drafting process.
“If, because of the pandemic, industry starts not having as much visibility [into] these standard projects, then it could be problematic, just from a perception standpoint,” said Sean Bodkin, NERC compliance policy manager for Dominion Energy.
In response, Lynch emphasized that the small group meetings were intended only to facilitate work on highly technical matters that are hard to resolve at the SDTs’ official meetings. Soo Jin Kim, NERC’s manager of standards development, insisted that the organization intends to ensure that industry operators do not see any significant loss of input into the standards development process.
“I will assure you, and I’ll reaffirm with all the developers, [that] there are no votes taking place, there’s nothing necessarily put forward to ballot … If there [are] any concerns, the small groups are also presenting their information to the larger team to discuss,” Kim said.
Approvals
The committee approved action on the following projects:
Modifications to reliability standard MOD-032-1: Accept the standard authorization request (SAR) as developed by the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group; authorize posting of the SAR for a 30-day informal comment period; and authorize solicitation for nominees for a SAR drafting team.
Transmission-connected resources: Accept the SAR proposing modifications to reliability standards MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-2 and PRC-024-3 to apply to nonsynchronous energy sources; authorize posting of the SAR for a 30-day informal comment period; and authorize solicitation for nominees for a SAR drafting team.
Modifications to CIP-012 requiring entities to protect cyber communication links between control centers: Accept the SAR developed in response to FERCOrder866; authorize posting of the SAR for a 30-day informal comment period; and solicit nominees for a drafting team.
Data request on cybersecurity supply chain risks: Accept the SAR developed in response to a resolution adopted by NERC’s board of trustees at its February meeting; authorize posting of the SAR for a 30-day informal comment period; and solicit nominees for a drafting team.
The last two items were passed in modified form. While the original proposals would have assigned each SAR to an existing standard drafting team — Project 2019-02 for the CIP-012 SAR and Project 2019-03 for the cybersecurity data request — the committee voted to create new teams for both projects.
In the case of CIP-012, Bodkin said he feels the team for Project 2019-02 — working on expanding options for entities to manage bulk electric system cyber information — already has enough on its plate with addressing industry feedback on its proposals. (See CIP Teams Compromise on Cloud Risk Assessment.) Regarding the cybersecurity data request, Venona Greaff of Occidental Chemical Corporation said industry feedback indicated that “this is not a supply chain issue, but a remote connectivity issue,” and that the SAR would therefore be better addressed by a new team rather than the supply chain-focused 2019-03.
Nominating Criteria Debate Remains Unsettled
The committee also approved a proposal to change its criteria for drafting team membership, despite objections that the planned revision did not do enough to provide needed clarity in the nominating process.
The review of the team membership criteria was ordered at the committee’s December meeting, following an unsuccessful motion by Bodkin to remove a regional entity official from the SAR drafting team responsible for cold weather standards (Project 2019-06) on the basis that only industry members should serve on drafting teams. (See NERC Worries Standards Committee ‘Close to a Line’.) Bodkin had led a push the previous month to remove two members from a different team because they were consultants. (See “Consultants Removed from SDT Nominee List,” NERC Standards Committee Briefs: Nov. 20, 2019.)
These actions led to concern on the part of committee members that criteria for drafting team membership were unclear. At the time, Howard Gugel, NERC vice president of engineering and standards, warned that if the nominating process was not considered transparent, the Electric Reliability Organization could have trouble winning recertification by the American National Standards Institute.
In response, the Standards Committee Process Subcommittee — chaired by Bodkin — was assigned to review the nominating criteria. The resulting document, presented at this week’s conference call, contained no changes to the criteria themselves. However, the subcommittee did change the “Purpose” section of the document to indicate more clearly that it related to eligibility for appointment to an SDT and replaced a reference to the Standards Development Process Participant Conduct Policy with the NERC Participant Conduct Policy.
Kent Feliks of American Electric Power Company, who chaired the group that revised the document, explained to the committee that their goal was to give the Standards Committee the greatest possible latitude to select drafting team members, which was why their changes were relatively limited. However, Gugel warned that the underlying issues had yet to be resolved.
“While I think these changes are fine, I still think there’s an elephant in the room that needs to be addressed. And whether you assign it to this team or create some other team, there still needs to be some way for drafting team selection to occur without bias, or without the appearance of bias,” Gugel said.
FERC on Thursday proposed a new approach to awarding transmission incentives and a doubling of the adder for participating in an RTO.
The Notice of Proposed Rulemaking would shift from awarding benefits based on the risks and challenges of a project to one focused on economic and reliability benefits (RM20-10).
FERC, which gained authority to issue incentives in the Energy Policy Act of 2005, implemented its policy in Order 679 in 2006. Last March, it opened a docket to reconsider its policy (PL19-3). (See Stakeholders Spar in FERC Tx Incentives Docket.)
| Burns & McDonnell
Thursday’s NOPR would eliminate Order 679’s “nexus test,” which requires applicants to show a connection between the requested incentives and the risks and challenges of the project.
“By shifting our focus to incentives based on how a transmission project benefits consumers rather than risks and challenges of building it, I think what this NOPR does is better align our policies with the law,” Chairman Neil Chatterjee said in a news conference Thursday.
The NOPR would:
Double the incentive for joining and remaining a member of an RTO, ISO “or other Commission-approved transmission organization” to 100 basis points from 50. The incentive would be available whether or not participation is voluntary.
Provide 50 basis points to projects that meet a pre-construction benefit-to-cost ratio in the top 25% of projects examined over a sample period, with another 50 basis points for projects that meet a post-construction b/c ratio in the top 10% of projects over the same period.
Award up to 50 basis points to projects that show reliability benefits through quantitative or qualitative analysis.
Award 100 basis points for transmission technologies that “enhance reliability, efficiency and capacity as well as improve the operation of new or existing transmission facilities.”
Replace the current limits on incentives to the base return on equity zone of reasonableness with a 250-basis-point cap on total ROE incentives. It also seeks comment on whether transmission providers should be allowed to replace the zone-of-reasonableness restrictions on previously granted incentives with the hard 250-bp cap.
Eliminate incentives for transmission facilities built by stand-alone transmission companies or “transcos.”
Retain existing incentives for abandoned plant recovery, construction work in progress and hypothetical capital structures.
Partial Dissent
Commissioner Richard Glick dissented in part, saying the NOPR “focuses narrowly on the transmission needs of today and will do little to help the country build the transmission grid of the future.
“I am concerned that [FERC’s proposal] altogether ignores transmission projects needed to meet public policy goals, such as state carbon reduction targets, which are the country’s most pressing transmission need,” he said, adding that the commission proposed the 250-bp cap “without any evidence to suggest that transmission owner rates would be just and reasonable” with the adder.
Glick said the increase in the RTO incentive ignores Congress’ direction that the incentive is supposed to be for joining an RTO, not remaining in one. “Even worse, the NOPR proposes to double the size of this incentive from 50 basis points to 100 basis points — even though there is nothing in the record to suggest that any transmission owner would leave an RTO if not for that handout,” he said in a statement. “Simply put, the commission wants to double the cost to consumers of an ‘incentive’ that does not incentivize anything.”
Chatterjee insisted he shares Glick’s belief that increased transmission is essential to decarbonization efforts, differing only on how to accomplish the goal. He also defended the increased RTO adder, saying RTOs/ISOs provide annual benefits exceeding $10 billion. “Those benefits continue to increase as the RTOs/ISOs evolve. Nationwide, the cost of this incentive is a fraction of these benefits. But I also think there [are] increasing challenges to TO participation in the RTOs and ISOs.”
The commission also issued a final rule clarifying its filing instructions for form FERC-730, which must be filed annually by utilities receiving transmission incentives (RM20–11). The clarification was requested by the Office of Management and Budget (OMB) to comply with the Administrative Procedure Act and the Paperwork Reduction Act of 1995 (PRA).
Comments on the NOPR are due 90 days after publication in the Federal Register.
FERC Chairman Neil Chatterjee said Thursday the agency is relaxing some filing deadlines and deferring some enforcement activities in response to the COVID-19 coronavirus pandemic, but that commission staff are working remotely to continue responding to industry filings.
“This commission will not be in the business of second guessing the good faith actions that companies take to keep the lights on,” Chatterjee said at a news conference via phone after the commission canceled its March open meeting. “I’m committed to ensuring that the industry can focus on continuity, safety and stability — not regulatory or enforcement matters that are not mission-critical during this crisis.”
It has issued a notice extending the deadlines for certain filings that are due on or before May 1, 2020 (AD20-11). Included in the extension are filings required by entities’ tariffs or rate schedules and non-statutory filings required by the commission such as compliance filings, responses to deficiency letters and rulemaking comments. Deadlines for certain forms required by the commission also have been relaxed, except for FERC Form 6, the annual report of oil pipelines. The notice also indicates that entities may seek extensions for other deadlines and waivers of commission orders, regulations, tariffs and rate schedules.
FERC’s Office of Enforcement is postponing all previously scheduled audit site visits and investigative testimony. The office also will consider extensions and waivers of compliance filings, forms and electronic quarterly reports.
Technical conferences scheduled through May 2020 will be postponed or conducted via conference call or WebEx. Schedules will be posted to the FERC.gov calendar.
Chief Administrative Law Judge (ALJ) Carmen Cintron has postponed a hearing scheduled to start April 7 and will make case-specific calls on other hearings as their start dates approach. ALJ settlement conferences will continue via conference call.
Chatterjee has tapped Caroline Wozniak, senior policy adviser in the Office of Energy Market Regulation, as the commission’s point of contact for all industry inquiries on the impact of its COVID-19 response. Questions can be sent to PandemicLiaison@ferc.gov.
Chatterjee said the commission is working with the Department of Energy, Department of Homeland Security and the Centers for Disease Control and Prevention to address coronavirus impacts affecting energy infrastructure. It also is working with NERC’s Electricity Information Sharing and Analysis Center to provide recommendations to industry to help with business continuity planning.
The steps announced Thursday followed a joint pledge by FERC and NERC Wednesday to use “regulatory discretion” to address the difficulties registered entities may have with complying with reliability standards. (See FERC, NERC Relax Compliance in Light of COVID-19.)
Most commission employees are on telework status until further notice and headquarters will remain closed to outside visitors unless they are cleared by the Office of the Executive Director.
Although the commission canceled Thursday’s open meeting, it said it would issue all the orders listed on the meeting agenda through notational voting.
Chatterjee said the commission’s telework capabilities should enable it to continue to perform its duties.
“I think that one of the reasons we wanted to hold this teleconference and vote on all of the orders that were on the [agenda] notationally today was to demonstrate that the commission is fully functioning,” he said.
Commissioner Richard Glick suggested in a statement that the commission should delay issuing nonessential orders because it has no authority to waive the 30-day deadline for parties to seek rehearing on commission orders. “To the extent commission action is not statutorily required or needed in the short-term, I believe we should refrain from acting to allow parties who are otherwise dealing with the pandemic to avoid putting resources toward seeking rehearing of a commission order,” he said.
Chatterjee said that would be unfair to parties who have been waiting for commission action.
“The industry continues to work to provide Americans with energy. The commission has to continue to respond to their filings. Many of the commission’s actions are increasing regulatory certainty to stakeholders. We’re not imposing additional burdens. … The energy bar should largely be able to telework as is most of the commission.
“Of course, we’ll be flexible and evaluate all of our actions on a case-by-case basis,” he added. “But I think FERC pausing action right now would not be good for the economy. The last thing industry needs right now is delays.”
Jordan Cove, Danly
Among the items on which the commission acted Thursday was voting 2-1 to approve the Jordan Cove LNG export facility, with Glick dissenting (CP17-495, CP17-494). A vote on the project was postponed at the last minute at the commission’s February meeting. (See In Rare Surprise, FERC Declines to Act on Jordan Cove.)
Chatterjee said he was deferring to General Counsel James Danly on when he would be sworn in as FERC’s fourth commissioner. Danly was confirmed by the Senate on March 12. (See Senate Confirms Danly to FERC.)
“Until he makes that announcement, he is still general counsel,” Chatterjee said, declining to say who would be Danly’s replacement as the commission’s top lawyer.
Chatterjee rejected complaints by Democrats on the Senate Energy and Natural Resources Committee earlier this month that the commission had become politicized. Democrats were incensed that Republicans advanced Danly without taking action on their candidate for a Democratic opening on the five-member commission. (See Danly Re-advances, but not Without Drama.)
Danly, Chatterjee and Commissioner Bernard McNamee will form a 3-1 majority, with Glick the lone Democrat.
“The overwhelming majority of the work we do is by consensus. It shouldn’t matter what political party there is,” Chatterjee said. “I do not recall similar criticism of the commission when it was 3-0 Democrat for a considerable period of time.”
When ERCOT this week instituted mandatory work-from-home requirements for staff that do not need to be in the office to handle their job responsibilities, spokesperson Leslie Sopko quickly encountered one of the major distractions of working from home: children.
“They followed me everywhere,” she said Wednesday — with a laugh — of her daughters, 7 and 4. The oldest was home from school, the youngest from daycare.
Sopko spoke from the safety of her back porch, where, armed with her laptop and cell phone, she said she could see her trees and the setting sun. It had been a day packed with responding to media inquiries and joining conference calls determining the next steps to respond to the coronavirus disease (COVID-19).
Besides ensuring employees and contractors have the proper tools and resources to do their jobs, either at ERCOT facilities or from home, the grid operator has been using a wide array of communication channels to reach staff. An internal newsletter is constantly updated with new information stressing caution and offering tips on working from home, social distancing and well-being. CEO Bill Magness has sent several well-received messages of encouragement and comfort.
“We’re definitely taking as many precautionary steps as we can to keep our staff healthy and safe,” Sopko said. “We’ve been very consistent with our communications … We have received positive feedback that they do feel informed. We know we provide a critical function, and we’re dedicated to maintaining the grid’s reliability.”
On Tuesday, ERCOT issued “Pandemic Plan Preparations for Coronavirus (COVID-19),” which listed the steps it has taken to protect employees and ensure it continues to manage the grid. The plan also included a link to a redacted version of its pandemic preparedness plan.
The ISO has closed its facilities to most outside visitors since March 3, instituting travel restrictions for staff and canceling in-person meetings. Staff that need to be on-site must be on a pre-determined list and undergo temperature screenings when reporting for work. Even then, they are expected to maintain social distancing as much as possible.
Sopko said she is not aware of any confirmed cases of the virus among staff.
She said it is too early to see any change in the ISO’s load patterns, as school and business closures have only recently begun. On Thursday, Texas Gov. Greg Abbott issued an executive order that will close schools, restaurants, bars and gyms as COVID-19 continues to spread.
“We need some time to trend the data,” Sopko said of potential changes in ERCOT’s load patterns. “We need things to settle into the new normal, if you will.”
The grid operator will announce any changes to the summer peak load forecast when it releases the summer’s final resource adequacy assessment in May.
SPP Protects Operations Staff
SPP is taking similar proactive measures, “strongly encouraging” staff to work from home if they are able and scrubbing in-person meetings through April. The RTO has closed its gates and doors to all but mail and other deliveries, as well as maintenance work — and only if visitors have been screened by security.
“Pretty much everyone is working from home,” said David Kelley, director of seams and market design, during a conference call Thursday with the Western Markets Executive Committee.
Spokesperson Derek Wingfield said the RTO’s emergency management team meets daily, “constantly monitoring and assessing” the situation. He said the current requirements could be extended if necessary.
To protect SPP’s operations and dispatch staff, all but essential traffic between the operations center and the corporate building has been prohibited, Wingfield said. The ISO has also shifted some of its operations staff to its backup operations center, 17 miles from the corporate center.
“It allows a little more distance,” Wingfield said.
Whether any staff had contracted the virus, he was unable to say with any certainty, pointing to the beginning of the allergy season.
SPP said RTOs could see “new and evolving patterns of energy use” as the coronavirus continues to spread. However, it has not yet seen a “discernable difference” in load within its footprint.
“SPP continues to closely monitor the situation as it develops, and we are confident in our ability to reliably manage the operation of the bulk electric system,” spokesperson Meghan Sever said in an email.
Memphis Light, Gas and Water is mulling whether to defect from the Tennessee Valley Authority to acquire power from MISO or another wholesale supplier.
A decision could come as early as this spring.
MLGW spokesperson Angelika Taylor confirmed that the utility is weighing an exit from TVA for another supplier for economic reasons.
“We are doing an integrated resource plan to determine the optimal electricity-producing resource mix to provide MLGW customers and our community with reliable, low-cost power as we consider whether or not to discontinue being a wholesale customer of TVA,” Taylor said in an email to RTO Insider.
The municipal utility’s IRP is scheduled to be completed by May, though Taylor warned that the spread of COVID-19 could delay that schedule. The city’s elected officials are expected to decide on the plan sometime this year.
Their decision could allow MISO to add another state to its 13-state footprint. As a rule, MISO does not reveal the names of utilities and companies that approach it for membership until its board of directors vote on approval during one of its public meetings.
MLGW’s move makes sense to environmental nonprofit Friends of the Earth (FOE), which for two years has urged the utility to pursue an alternative to TVA.
FOE commissioned The Brattle Group to prepare an analysis, released in September, that finds MLGW could save anywhere from $240 to $333 million per year by 2024 if it accesses lower-cost power across the Mississippi River and builds at least 350 MW or more of its own renewable generation.
“Certainly in our analysis, and the work that The Brattle Group has done for us, MISO is right at the top” as an alternative supplier option, said FOE attorney Herman Morris, Jr., also a former MLGW CEO.
MLGW has a few options as it crafts its IRP: Attempt to join MISO or another wholesale power supplier, produce its own power or undertake a combination of the two. The utility doesn’t currently generate any of its own power.
Another less probable option would involve sales from the embattled and unfinished Bellefonte Nuclear Power Plant in Alabama. Former Chattanooga developer Franklin L. Haney is trying to finalize the purchase of the plant from TVA, which contends he lacks the proper permitting. The dispute will likely head to trial this year.
‘Really Significant’ Savings
“From at least the Friends of the Earth perspective, all alternatives are preferable for the potential for new green and renewable sources as well as reliability and lower cost,” Morris told RTO Insider. “It’s certainly my personal view that MISO is a more than viable option … They serve a lot of capacity, and they’re reliable, greener and a whole lot cheaper than TVA. My sense is we’ll probably see some combination of self-generation and purchases of power from across the river, somewhere, somehow.”
Morris said TVA’s wholesale power costs about 7.5-8 cents/kWh versus the 4-4.5 cents/kWh that MISO offers.
“It’s simply hard to overcome the math in these things. That’s not just significant, that’s really significant. You can go a long way with savings of $300 million a year,” Morris said.
| TVA
Some of MLGW’s savings from switching suppliers could be spent on the construction of its own renewable generation and to defray the cost of connection to the MISO system, Morris said.
“Interest rates are so low, especially now. It just can be done,” he said.
“As large as [MISO] is, there’s a river between us. There’s not a great understanding by people on our side of the river of who MISO is,” Morris said. “[FOE] is not trying to promote MISO so much as we’re trying to educate the community as to what its options are. What we want to see is a fact-driven discussion: Is it possible to get a wholesale supplier less expensive than TVA? Is it possible to create a greener portfolio? We want to put these in front of community leaders and have them make a decision.”
TVA’s current generation portfolio consists of 37% nuclear, 24% coal, 20% natural gas, 9% hydro, 7% energy efficiency and 3% wind and solar generation, with a total capacity of about 35 GW. Peak load can reach 32 GW, and MLGW accounts for about 10% of TVA load. TVA sometimes purchases power from MISO.
“When you’ve got a fleet of old coal plants, many of which are supplied by Kentucky and West Virginia coal fields in the valley, and you’ve got 50-plus-year-old nuclear generation, you can’t turn that on a dime. You can’t say, ‘we’re going to be this next year,’” Morris said.
Majority in Favor
Last year, TVA’s board of directors approved an integrated resource plan that adds 14 GW of new solar generation, 5.3 GW of energy storage and up to 2.2 GW of energy efficiency savings by 2038. The plan also includes between 2 and 17 GW of new natural gas generation. TVA also has plans to retire its Paradise and Bull Run coal plants in 2020 and 2023, respectively.
Morris points out that about a third of Memphis residents live at or below the poverty line. “It’s important for people at the bottom economic rung that we are prudent and judicious in selecting our supplier. We believe that by having a more economical source of wholesale power, we can save this community close to a million dollars a day.”
He said there’s popular support in Memphis for getting cheaper and cleaner energy, especially considering that TVA generation and transmission costs comprise about 80% of customers’ residential electric bills.
“Right now, if you’re in the TVA valley, TVA sells you 100% of your power. And that’s it. It’s an all-requirements contract. And that’s probably made them a little less energetic — no pun intended — and more willing to ride these coal and nuclear plants to the bitter end,” Morris said. He also questioned the societal cost of TVA’s coal ash and spent nuclear rods.
The reduction in load from a MLGW exit could make it easier for TVA to consider speeding up retirement of some of its aging, inefficient plants, Morris added.
He estimates it would take at least five years for MLGW to make the transition from a non-generator to a modest generator for some of its load. He also noted that an exit from TVA would involve negotiations.
“There might be some legal issues to parse through, but we think the philosophy of the industry — and FERC — is strongly supportive of communities getting the best-cost supplier they can find.”
FOE this month conducted a poll that found 57% of Memphis residents would like to see MLGW leave TVA, with 20% opposed to such a move.
“The most important thing for this community is to identify a cheaper, more economical and greener source of wholesale power, and MISO is all of those things,” Morris said. “There is a robust voice from environmentally-conscious citizens in our community. I think whatever the outcome is, it will have to involve some element of renewable, clean, green supply.”
Marketed as an eco-friendly alternative to car ownership, Indianapolis’ BlueIndy electric vehicle rideshare service will cut the engine and go out of business this spring.
After four years of providing shared EVs, French owner Bolloré Logistics will end BlueIndy’s operations May 21, leaving city leadership to decide whether to purchase the company’s assets.
BlueIndy said it “did not reach the level of activity required to be economically viable,” reporting that it attracted about 11,000 members who took about 180,000 rides over the ride-sharing service’s existence.
Complicating matters, BlueIndy indefinitely suspended the service beginning this week in response to the spreading COVID-19 pandemic in Indianapolis.
“We thank you for your understanding and hope to be able to restore service as soon as the situation permits. Let us remain united and responsible,” BlueIndy’s homepage read.
It remains to be seen whether customers will ever again have the chance to drive a BlueIndy car.
Wrong Market?
BlueIndy had bestowed the Indiana capitol with the distinction of the largest network of public charging stations of any U.S. city. However, critics from the start said the service only makes sense in a higher-density city with a smaller geography — not Indianapolis’ nearly 880,000 inhabitants spread over 372 square miles. Bolloré Logistics spun off a Los Angeles version of the service — BlueLA — in partnership with the Los Angeles Department of Transportation. The sister rideshare remains open though operations there are also suspended due to COVID-19.
“Indianapolis drivers have been slow to adopt alternative transportation options and car ownership remains extremely high,” BlueIndy explained in a late 2019 press release.
Now Indianapolis is weighing whether it should purchase the approximately 90 EV charging stations scattered on public rights-of-way throughout the city. BlueIndy originally anticipated owning as many as 500 cars and up to 200 stations in the city.
“Leading up to [May 21], we will be having conversations with neighbors, corporate partners and personal mobility advocates to explore whether financially sustainable options exist that would allow us to put the existing infrastructure to use — either with another ride sharing program or as charging stations for electric vehicles,” City of Indianapolis Deputy Chief of Staff Taylor Schaffer said in an email to RTO Insider.
Schaffer said Indianapolis’ 15-year contract with Bolloré Logistics stipulates the city can notify the company it would like to purchase the infrastructure at any point within 90 days of the contract’s end.
BlueIndy promotional photos | BlueIndy
“This means the city has until mid-August to decide whether to purchase the infrastructure or not,” Schaffer said.
Schaffer did not comment on a possible purchase price for the assets, though the city has previously said it has the option to appraise and negotiate a fair market value.
BlueIndy got off to a rocky start in 2016 when the Indianapolis City-County Council contended that Bolloré Logistics’ process for placing stations lacked transparency. (See BlueIndy EV Sharing Program Seeks Rebound.) As a result of negotiations, BlueIndy paid the city an annual $45,000 franchise fee meant to cover the loss of parking meter payments due to the curbside stations.
The project was slated to cost a total of $50 million, with the company investing $41 million, the city contributing $6 million and Indianapolis Power & Light Co. ratepayers covering the remaining $3 million.
In 2017, BlueIndy showed a $22.5-million deficit. The company has not released recent financial standings.
Indianapolis’ former Republican Mayor Greg Ballard called the service a “clean, affordable transit option to help connect visitors and residents with all that Indy has to offer” when the collaboration was announced in 2015.
It’s unclear how much BlueIndy was affected by IndyGo’s new rapid transit electric busline, which opened its first route last year along many of BlueIndy’s curbside electric charging stations.
Multiple requests to interview remaining BlueIndy employees went unanswered. BlueIndy Managing Director James Delgado appeared to stop tweeting about the service in early 2019.
“We believe that the continued reliance and predominant use of traditional personal vehicles is not sustainable long term in a growing urban environment and the need for additional mobility options to complement operators in Indianapolis including BlueIndy, IndyGo and the Pacers Bikeshare is significant,” BlueIndy said last year.
The Business Issues Committee on Wednesday approved additional Tariff language for the energy storage resource (ESR) participation model to address issues identified during software development for the ESR project.
The language spells out details regarding day-ahead margin assurance payments (DAMAP); the method for setting feasible day-ahead and real-time schedules; generator offer caps, mitigation and reference levels; and installed capacity (ICAP) supplier bidding requirements.
The revisions to MST Section 25 Attachment J clarify which of the two energy contribution formulas will apply to ESR schedule changes.
A portion of the attachment that applies to fast-start units also will be revised to specify that those units that increase their minimum generation bids in real-time will not be eligible for DAMAP, consistent with Tariff rules that apply to increasing incremental energy bids or start-up bids in real-time.
The ISO also is revising MST 4.4.2.1 to support the market software used to ensure feasible real-time schedules for ESRs.
The ISO’s real-time dispatch software will account for the energy level of all ESRs to prevent infeasible dispatch of both self-managed and ISO-managed resources. The ISO’s original Order 841 compliance filing stated that the software will reduce the ESR’s upper operating limit (UOL) or increase its lower operating limit (LOL) as needed to produce a feasible schedule. But during the software development, the ISO realized such adjustments are unnecessary and may be inefficient. (See FERC Partially Accepts NYISO Storage Compliance.)
Under the change, the software will determine feasible real-time schedules based on an ESR’s actual telemetered energy storage level.
The offer price capping logic in MST 23.7.2 will be revised so that offers to withdraw energy are capped at the lowest of the energy offer, the price allowed by the current capping logic or the price needed to account for the unit’s round-trip efficiency. The ISO said the change will prevent performance issues with security-constrained unit commitment (SCUC), real-time commitment (RTC) and real-time dispatch (RTD).
The current price capping logic will continue to be applied if a unit’s energy offer does not cross zero and will be applied to all energy segments that are greater than zero.
Revisions to MST 23.4.2.2 will allow adjustments to the mitigation of an ESR’s incremental energy curve if needed to account for the ESR’s round-trip efficiency.
Revisions to Section 23.1.4.3 will exempt ESRs from requiring a new unit reference level, specifying that they should be calculated using cost-based reference levels. “New unit reference levels are based on historical LBMPs and would not be representative of ESRs’ costs or operating parameters such as round-trip efficiency,” the ISO said in a presentation.
The ISO had proposed that ESR ICAP suppliers have a day-ahead market (DAM) bid/schedule/notify (B/S/N) obligation equal to the ICAP equivalent of unforced capacity (UCAP) sold, like other ICAP suppliers.
After making its Order 841 compliance filings in December 2018 and May 2019, the ISO realized that when an ESR uses the ISO-managed energy level bidding parameter and enters the DAM with an energy level insufficient to satisfy its obligation, the ESR could submit bids to inject energy that appear to satisfy the B/S/N commitment, but that would not provide the ISO with all the promised energy.
NYISO is proposing that all ESR ICAP suppliers must B/S/N the full range of the ESR, including both the ISO- and self-managed energy level bidding parameters.
The ISO said the language is needed to “harmonize” the physical and operating characteristics of ESRs with the purpose of the existing B/S/N requirements: to either make the energy backing the ICAP supplier’s capacity available or notify the ISO that the capacity is unavailable so the NYISO can respond to maintain reliability. “Without the proposed requirement for an ESR, an ESR could meet its Tariff obligation and yet not make that energy available, which is inconsistent with the purpose of the requirement,” the ISO said.
Failing to reflect an ESR’s anticipated charging in the DAM “could cause reliability issues in real-time by not having enough resources committed from the DAM to meet actual load, reserves, and the ESRs’ charging,” the ISO said.
The ISO will bring the Tariff modifications to the March Management Committee meeting and hopes to make them effective with its other Order 841 compliance changes, no later than Sept. 30.
BIC OKs BTM:NG Revisions to Load Forecasting Manual
The BIC also approved the first revisions since 2013 to the Load Forecasting Manual, reflecting the impact of behind-the-meter net generation (BTM:NG) in the installed capacity market forecast. A BTM:NG is a BTM generator that has excess capability after serving its host load at the same location.
If a BTM:NG resource does not require power to serve load from the hour of the NYISO or locality peak, the load of the resource will not be included in the actual and weather-adjusted load in the transmission district (TD).
If the resource does require power, its load will be deducted from the TD’s actual load and weather-adjusted load.
The forecast load of a BTM:NG resource will be based on a weather adjustment of its actual load, a projection of the load’s losses and a growth rate “consistent with” that of the transmission district in which it is located, the ISO said.
“This is a little different than other loads … We normalize [transmission district loads] as a whole. But we recognize that BTM:NG might have load characteristics much different than the average load in the area,” explained engineer Arthur Maniaci, the ISO’s principal forecaster.
The ISO said the changes will reflect the specific weather response of each resource and is consistent with the Tariff and ICAP Manual, using the top 20 hours of each resource from within the top 40 New York Control Area hours during summer. It also mirrors current NYISO demand response processes.
The changes were developed by the Load Forecasting Task Force in 2018 and 2019 and modified after feedback from the ICAP Working Group last year.
Working During the Coronavirus Pandemic
Several stakeholders had questions about the impact of the coronavirus pandemic on ISO operations.
Mark Seibert, manager of the Member Relations team, said the ISO will provide a secondary call-in number for meetings because of heavy loads on remote meeting services that resulted in some stakeholders getting busy signals in attempting to listen to the BIC meeting.
NYISO’s Member Relations team: (from left) Selina Dean, Leigh Bullock, Kirk Dixon, team manager Mark Seibert, Debbie Eckels and Jennifer Davies. | NYISO
He also said that ISO staff who interact with stakeholders were directed to forward their work phones to their cell phones to remain accessible while working from home. Stakeholders should contact Seibert or Debbie Eckels in the Member Relations team if they have difficulty reaching an ISO official, he said.
Mike DeSocio, director of market design, said ISO employees are able to access the grid operator’s software systems remotely to allow continuity of operations. “Folks are able to get into the systems they need to get into and perform the work they need to perform, so we don’t expect any issues there,” he said.
PJM on Wednesday submitted proposed Tariff changes to comply with FERC’s controversial December order requiring expansion of the minimum offer price rule (MOPR) to new state-subsidized resources.
“These issues have been the subject of rigorous review and consideration of varying stakeholder interests within the time limitations allotted by the commission for the submission of this compliance filing,” PJM said, noting that RTO officials also have communicated with state regulators and the Organization of PJM States Inc. (OPSI).
“PJM has heard and thoroughly considered the views of all stakeholders and representatives of states and, through this compliance filing, has attempted to balance all of the competing views on these various issues into a proposal … which is designed to meet the commission’s Dec. 19 order’s directives while also ensuring orderly and timely capacity auctions going forward.”
In addition to extending the MOPR to new state-subsidized resources, the rules would continue the existing MOPR on new combustion turbine and combined cycle natural gas resources.
“Where certain elements of the commission’s Dec. 19 order required additional details to support the design and application of the modified MOPR, PJM has used its best efforts to add these additional detailed elements to comply with the overarching goal of the Dec. 19 order,” the RTO said. “To provide market certainty, PJM will await commission action on this filing before implementing the modified MOPR in the next Base Residual Auction (BRA).”
Schedule
PJM asked the commission to allow at least 35 days for comments on its filing (no sooner than April 22). “Such an extension is appropriate given the volume of this filing and current circumstances,” the RTO said. “This will afford market participants sufficient time to review and comment on the proposed changes, which is necessary given the relative importance of this filing to PJM’s capacity market.”
It proposed “an orderly, but compressed” auction schedule following commission action on the compliance filing, saying it would complete all pre-auction activities and open the BRA for the 2022/23 delivery year within six-and-a-half months after the commission’s acceptance of the compliance filing. (See PJM Proposes Auction for 6 Months After FERC Ruling.)
Proposed capacity auction schedule | PJM
“Capacity market sellers should know before they make concrete auction preparations, for example, the specific definition of a state subsidy, the details of available exemptions, the net CONE [cost of new entry] and ACR [avoidable-cost rate] screening values for the various resource categories, and the parameters of an acceptable unit-specific exception showing — just to name a few,” it said.
Exemptions
Exempted from the MOPR would be existing resources participating in state renewable portfolio standard (RPS) programs; existing demand response, energy efficiency and storage resources; and existing self-supply resources. Federal subsidies would not trigger the MOPR.
FERC’s order also provided for exemptions for resources that forego state subsidies and those that can prove through the resource-specific exception that their costs are lower than MOPR reference values.
“While FERC’s order combined exemptions for demand resource, energy efficiency resources and capacity storage resources, PJM proposes to separate out capacity storage resources as a separate categorical exemption given the distinctions with demand resources and energy efficiency resources,” the RTO said.
It said it will offer “non-binding guidance” for capacity market sellers as to whether their resources qualify as subsidized.
MOPR eligibility flow chart | PJM
“PJM and the Market Monitor will work together to develop a non-exhaustive list of programs, based on information provided by capacity market sellers, that they consider to be a state subsidy and post this list in a guidance document. Given the myriad state and local programs that may exist throughout the PJM region and the fact that such programs may change over time, it would not be practical to include a list of specific state subsidies in the Tariff,” it said.
“Instead, PJM will develop and maintain, in collaboration with the Market Monitor, a list of specific state subsidies to provide guidance on many of the most common programs that may be applicable to capacity resources. Importantly, however, it is ultimately the capacity market seller’s responsibility to ensure that they correctly certify whether its capacity resource is subject to a state subsidy, irrespective of any guidance provided by PJM and the Market Monitor.”
It said such certifications should be subject to fraud and misrepresentation rules modeled on the provisions the commission previously approved regarding to capacity market sellers seeking a categorical exemption from the MOPR (ER13-535).
Legal Challenges Expected
FERC approved the expanded MOPR on a 2-1 vote, saying it was needed to combat price suppression from growing state subsidies, such as those for nuclear plants in Illinois, New Jersey and Ohio. Commissioner Richard Glick dissented, calling the order an attack on decarbonization efforts that would add billions in increased capacity costs.
Dozens of stakeholders filed requests for rehearing or clarification of the order, with some observers predicting the issue will end up in front of the Supreme Court. (See PJM MOPR Rehearing Requests Pourinto FERC.)
Todd Snitchler, CEO of the Electric Power Supply Association (EPSA), whose members own and operate more than 50,000 MW of capacity in PJM, praised the filing. “Since December, there has been a productive and extensive public conversation among all stakeholders about how competitive electricity markets can best serve the interests of consumers and the power grid,” he said. “PJM has worked diligently under a compressed timeline to conduct a thorough stakeholder process and develop a MOPR implementation plan while ensuring that perspectives from all relevant groups were considered and incorporated into its compliance filing. … Now, FERC must act expeditiously in order for PJM to move forward and hold its long-delayed Base Residual Auction as soon as possible.”
The American Wind Energy Association also gave an upbeat review.
“PJM’s proposal provides the flexibility necessary for renewable resources to demonstrate that they are among the lowest cost and most reliable sources of capacity available today,” said Amy Farrell, AWEA’s senior vice president of government and public affairs. “We appreciate PJM’s efforts to develop sensible responses to the unsustainable policies that FERC mandated for the region’s competitive market. AWEA and our members will continue working constructively with PJM to restart the capacity market and find practical solutions that recognize the value of renewable energy and protect the ability of states to control the fuel mix within their borders.”
Katherine Gensler, vice president of regulatory affairs for the Solar Energy Industries Association, said that although the organization “objects to the underlying policies presented in the current MOPR construct, PJM took a positive step in proposing how to comply with FERC’s December order. PJM’s submission will allow renewable generators to properly identify a project-specific bid price for bidding into the capacity market auctions. This process provides renewable generators a better opportunity to compete on a level playing field with other capacity providers and to help meet states’ clean energy goals.
“We request that FERC act swiftly to restore PJM’s annual capacity auctions in a timely manner. Our member companies are ready to see market certainty return to PJM and to put this multi-year debacle to a close.”
