MISO staff last week floated initial ideas on how the RTO could better synchronize the separate studies supporting its annual transmission planning and generator interconnection queue processes.
The RTO took up the issue after multiple renewable developers complained that their generation projects were unfairly being required to finance multimillion-dollar network interconnection upgrades that should rightly be handled in the transmission planning process. They argued MISO was relying on network upgrades to plan the system. (See MISO Begins Bid to Merge Tx, Queue Planning.)
During a Planning Advisory Committee conference call Wednesday, MISO North Region Economic Planning Manager Neil Shah said one idea would adjust the Transmission Expansion Plan (MTEP) model development timeline to allow for more coordination, analysis and stakeholder input.
Shah said MISO could reserve a window of time in the MTEP cycle to review transmission needs found across multiple planning processes, including reliability and economic benefits, and in interconnection queue studies. From there, the RTO could identify “focus areas with common issues” or transmission needs in “electrical proximity for further investigation and cost-effective solution development,” he said.
MISO would have to decide how to select project needs unearthed in interconnection studies for testing for wider economic benefits under MTEP, Shah said. The RTO might settle on testing all new 230- or 345-kV upgrades that emerge from the first phase of the queue’s three-part definitive planning phase, he said.
Shah added that MISO may need to instate a timing cutoff for upgrades identified in the interconnection queue to be evaluated as potential market efficiency projects. An early December cutoff makes sense, he said, because that falls close to the time that MISO opens the window for economic project submissions for the next year’s MTEP cycle. He said a cutoff would ensure that interconnection upgrades are evaluated on a “fresh set of models and assumptions” from the latest MTEP cycle. He said MISO would accept other stakeholder ideas through May 28.
“These are some initial ideas. Definitely we’d like to hear from stakeholders for more ideas to explore,” he said.
Stakeholders on a Planning Subcommittee conference call Thursday asked MISO to provide a spreadsheet of its modeling and assumptions across all planning processes so they could more easily detect inconsistencies that contribute to apparent discrepancies in transmission needs. MISO has also been asking stakeholders what changes it could make to methodologies and assumptions across separate planning studies to achieve more comparable treatment of transmission projects.
MISO Senior Manager of Expansion Planning Edin Habibovic said such a list runs the risk of being too long and confusing. Director of Planning Jeff Webb said the RTO “might try to hone in on the salient points.”
Clean Grid Alliance’s Rhonda Peters said MISO has been seeing more 345-kV upgrades found in generator interconnection studies assigned to interconnection customers. She said the problem may lie in dramatically different contingency mitigation requirements in local planning criteria between different transmission owners. She asked for a review of TOs’ local planning criteria.
Webb said MISO would likely arrive at “negotiated reasons” as to why the different planning processes can’t be treated exactly the same.
MISO said all of its study processes — reliability and economic planning, transmission service requests, generation interconnection, generation deliverability and generation retirements — have “a uniquely defined purpose.”
FERC last week partly accepted NYISO’s March 12 compliance filing on buyer-side market power mitigation (BSM) rules, denying a waiver as unnecessary and rejecting the ISO’s arguments on Tariff language.
The commission ordered the ISO to submit a compliance filing within 45 days of the May 12 order on the rules for special-case resources (SCRs), a type of demand response resource (EL16-92-002, ER17-996). (See FERC Narrows NYISO Mitigation Exemptions.)
The commission in February narrowed the resources exempt from NYISO’s BSM rules in southeastern New York, ordering the ISO to subject storage and demand response to a minimum offer floor in its capacity market.
FERC ruled in February that new special-case resources in southeastern New York are subject to NYISO’s buyer-side mitigation rules. | NYISO
On April 1, NYISO’s Market Monitoring Unit and the Independent Power Producers of New York (IPPNY) filed protests. The MMU asserted that the “State Program Language” exempting certain resources administered under New York programs should not be considered part of the currently effective Services Tariff, while IPPNY contended that the commission “fully addressed and expressly rejected” said language in a March 2015 order and reaffirmed that decision in its February order.
“Despite NYISO’s claims to the contrary, the commission never accepted, and indeed expressly rejected, the State Program Language at issue,” FERC said.
NYISO also requested in its filing a conditional waiver to authorize the ISO’s past implementation of the February 2017 order from the period between that order — which established a blanket exemption for SCRs — and the February order that in part granted rehearing of the 2017 order.
“That waiver is unnecessary because in the February 2017 order, the commission directed NYISO to exempt SCRs from NYISO’s buyer-side market power mitigation rules effective as of the date of that order,” the commission ruled.
PJM’s transmission owners gave their long-awaited response to the push to open end-of-life (EOL) projects to competition and regional planning Friday, saying they support the RTO’s proposal to increase its oversight of the process.
The TOs made their case during a fractious special meeting of the Markets and Reliability Committee in which both sides of the debate accused RTO staff of treating them unfairly.
For months, stakeholders seeking to make PJM responsible for EOL planning have bemoaned the TOs’ refusal to engage in negotiations. On May 7, however, the TOs gave notice that they are supporting the PJM proposal and considering a Federal Power Act Section 205 filing to revise the Tariff to reflect it.
While conceding to load-side stakeholders in agreeing to increased PJM oversight of the EOL process, the TOs are trying to retain as much control as possible over the billion-dollar business of planning and building EOL projects.
With the TOs lined up behind PJM’s proposal, LS Power announced Friday that it was withdrawing its proposal and joining with the “joint stakeholder” package by a group including American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC), state consumer advocates, the Public Power Association of New Jersey and the PJM Industrial Customer Coalition.
The maneuvers by the TOs and LS Power mean that only two proposals will be brought to sector-weighted votes at the May 28 MRC meeting.
Project status as of Dec. 31, 2019 | PJM
PJM officials said at the April 30 MRC meeting that the package with the most support that meets the two-thirds threshold will be brought back to special meetings to draft governing document language. The package receiving the greatest support would become the main motion for a vote of the Members Committee on June 18.
On Friday, however, PJM Director of Stakeholder Affairs Dave Anders said it was unclear the May 28 vote on the joint stakeholder proposal would include their proposed Operating Agreement language. He said the procedure would be clarified in the agenda for the meeting.
Under the Consolidated Transmission Owners Agreement (CTOA), the TOs are required to provide stakeholders 30 days to comment before filing proposed Tariff changes. (Comments may be submitted to Comments_for_Transmission_Owners@pjm.com.)
The June 8 comment deadline gives the TOs more than a week to file their proposal with FERC before the MC votes.
“This [Section] 205 notification changes the game fairly significantly relating to the timing of voting on OA changes,” said Sharon Segner of LS Power. “Time is of the essence.”
Both the stakeholder and PJM proposals would require TOs to share how they make EOL determinations and potentially open at least some replacement projects to competition under the Regional Transmission Expansion Plan (RTEP).
The joint stakeholder proposal would require TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would become a new category of regionally planned projects.
LS Power’s proposal was identical except for requiring at least eight years’ notice for facilities of 230 kV and above. Segner said Friday that her company decided to address the issue in future manual changes because the joint stakeholders’ OA changes referred to “at least six years’” notice.
PJM’s package requires TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions.
The RTO said it would implement its plan through changes to Manual 14B: PJM Region Transmission Planning Process. The stakeholders questioned whether it would have authority to enforce the new rules if they were in the manual alone and have proposed changes to the OA, which they outlined during the nearly three-and-a-half-hour meeting Friday.
The TOs’ representative, Chad Heitmeyer, director of RTO policy for American Electric Power, said their proposed changes to Tariff Attachment M-3 go beyond FERC requirements to provide increased transparency on “certain asset management projects, including EOL projects.” The TOs said the revision would continue to “honor [TOs’] responsibility over end-of-useful-life replacement projects.”
He said the only significant difference between the TOs’ proposal and PJM’s is the TOs’ belief that the new rules require changes to Tariff Attachment M-3. “The Tariff is the most appropriate governing document to effectuate the delineation of responsibilities between PJM and the PJM TOs,” Heitmeyer said.
However, the TOs also said that under their proposal, the nonbinding five-year forecast of EOL candidates would be confidential and shared with PJM only. The stakeholders want the list to be made public. Dave Souder, senior director of system planning, said at the April 30 MRC meeting that PJM hadn’t decided whether the list would be made public or not.
On Friday, Souder said PJM would determine which EOL projects “overlap” with RTEP violations and would be included in a competitive window seeking regional solutions. EOL projects for which PJM did not find overlaps would not be disclosed, Souder said.
ODEC’s Mark Ringhausen said PJM’s approach represented a “complete lack of transparency.”
The TOs have been under increasing pressure from both stakeholders and FERC as spending on EOL and other supplemental projects controlled by the TOs has overtaken baseline upgrades planned by PJM. FERC opened Section 206 investigations of PJM, RTOs, TOs Defend Competition Exemptions.)
Baseline and supplemental projects since 2005 (adjusted by peak load) | PJM
Last week, the joint stakeholders sent a letter to the PJM Board of Managers highlighting the “the mounting evidence that the majority of transmission planning in the PJM footprint is not occurring on a regional basis.” The letter came as PJM reported that TOs’ supplemental projects totaled almost $3.4 billion in 2019, more than double the less than $1.5 billion in regionally planned baseline projects. It marked the fifth year out of the last six in which supplemental projects exceeded baseline projects. (See related story, Stakeholders Urge PJM: Plan ‘Grid of the Future’.)
Segner said she was concerned by the potential Section 205 filing because it “essentially moved a number of [FERC] Form 715 projects potentially into the supplemental bucket” exempt from competition. Last August, FERC ordered PJM to open Form 715 transmission projects to competitive bidding, with regional cost-sharing for those projects involving high-voltage lines. (See FERC Opens Local Tx Projects to Competition, Cost Sharing.)
“I don’t think PJM can file this because it violates the Operating Agreement,” she said.
Attorney Don Kaplan, representing the TOs, said the Tariff changes were not intended to have any impact on handling of Form 715 projects.
Process Dispute
Friday’s meeting opened with both load-side stakeholders and TO representatives criticizing PJM staff for mismanaging the agenda.
Load-side stakeholders accused staff of ignoring their requests to post the proposed OA language changes with meeting materials and include discussion of them on the agenda.
The OA language had been public since April 23, when it was posted for the April 30 MRC meeting. But it wasn’t until Thursday — after emails from multiple stakeholders — that it was posted with the materials for Friday’s meeting, said ODEC’s Adrien Ford, a former PJM staffer.
PJM facilitator Jim Gluck, who chaired the meeting, said the failure to post the language earlier was an “administrative oversight.”
Ford wasn’t so sure. “There were multiple emails. That’s a lot of flubs,” Ford said. “This really feels like we’re not being treated equitably.”
“The intent is to treat all stakeholders equitably,” Gluck said.
“The outcome is much different from the intent,” AMP’s Ed Tatum responded.
After about 30 minutes of arguments, Gluck agreed to amend the agenda to provide time for the stakeholders’ presentation.
That prompted a protest from PPL’s Amber Thomas, who said stakeholders were not given notice that the OA language would be discussed during the meeting.
“There’s a lot of confusion about how this agenda was developed,” she said. “This all feels very messy and very confusing. … Some of you talked about [how] the stakeholder process is broken. This is another example.”
“I want to acknowledge that this is getting very tense,” responded PJM’s Anders, who promised staff “will certainly do a debrief on this internally.”
OA Page-turn
AMP General Counsel Lisa McAlister, who presented a page-turn of the proposed OA changes, said the stakeholders’ goal is to “put end-of-life planning on a par with reliability planning.”
Responding to questions about proposed revisions to the definition of supplemental projects, attorney Mike Engleman, representing LS Power, said, “To be frank, the intent was to not allow supplemental projects to be used to … prematurely replace facilities to avoid” the EOL notification requirement.
Supplemental projects by voltage (2015-2019) | PJM
AEP’s Heitmeyer presented the TOs’ proposal. “After reviewing PJM’s package, it was evident we were in alignment,” he said.
The PJM and stakeholder packages were developed in a series of lengthy meetings since December.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said he was “frustrated” by the TOs’ late introduction of their proposal and their threat to file it unilaterally with FERC.
“I would say this kind of ends the CBIR [consensus-based issue resolution] process at the Planning Committee,” he said.
“I don’t think the TOs consider what we’ve done here to be counter to the CBIR process,” said Alex Stern of Public Service Electric and Gas. “All we’re doing is facilitating what PJM has laid out.”
Tatum pressed PJM officials for their reaction to the TOs’ proposal, but Souder refused to take a position, saying only that the RTO is “very supportive of the stakeholder process.”
The PJM Planning Committee last week approved an initiative to develop rules for “if and how” storage should be considered in the Regional Transmission Expansion Plan (RTEP) process.
The storage as a transmission asset (SATA) issue charge was approved May 12 by an acclamation vote with one objection and no abstentions after some stakeholders expressed misgivings about the potential that storage could be a transmission asset at times and a market participant at others.
PJM is looking to develop “transparent rules” by the end of the year for how it would evaluate storage’s performance and cost and whether it could be an alternative to traditional transmission reinforcements. Proponents say storage could be dispatched by the RTO to address thermal, voltage or stability violations or to relieve transmission constraints.
During a first read of the problem statement and issue charge April 14, some PC members raised issues with PJM’s proposal, questioning its scope and timing. (See Stakeholders not Sold on PJM SATA Plan.)
During last week’s second read, PJM’s Jeff Goldberg said staff made several changes to reflect stakeholder and internal feedback. “While PJM’s approach to SATA hasn’t changed, some sections were entirely rewritten to incorporate comments and give clarity to PJM’s goal,” Goldberg said.
To address stakeholders’ concerns that the concept of SATA is an unsettled issue, staff added a paragraph to the problem statement citing two FERC decisions regarding proposed SATA systems in CAISO. The first was a 2010 decision approving transmission incentives for a project by Western Grid Development (EL10-19); the second was a 2008 denial for a project proposed by Nevada Hydro (ER06-278).
Primus Power energy pods | Primus Power
Wording was also added to the problem statement to clarify that PJM has not decided “whether or not storage assets should be included” in the RTEP.
Goldberg said Phase 1 of the process will be focused on identifying gaps in existing transmission planning rules for evaluating storage. Because PJM is the NERC-registered transmission planner and must be comply with reliability standards, Phase 1 also will identify any operations impacts that need to be addressed in Phase 2.
Issues regarding SATA implementation, such as telemetry requirements, are out of scope for Phase 1.
The RTO acknowledged the potential for SATA’s dual use.
“PJM recognizes that the evaluation of the cost-effectiveness of a given storage solution to a transmission reliability or market efficiency need could be impacted by the question of whether and how the unit would participate in the market,” the issue charge says. “Nevertheless, this issue is derivative of the primary question, to be answered in this Phase I, as to the feasibility of evaluat[ing] energy storage purely as a transmission asset.”
“We’re taking a measured approach,” Goldberg said.
Carl Johnson of the PJM Public Power Coalition said he appreciated the “significant changes” the RTO put into the problem statement and issue charge to address stakeholder concerns.
“I’m not enthusiastic about having this conversation because I’m not enthusiastic about the possibility of looking at dual use,” Johnson said. “But I understand where PJM is, which you may see these things approved somewhere on the system through a process that isn’t the RTEP and you’ll have to figure out how to incorporate those.”
John Brodbeck of EDP Renewables also said he wasn’t enthusiastic about bringing up the issue of SATA. He said he would have liked more clarity on how projects would be paid for and who could bid on a project.
“I’d like to make sure that there’s an Order 1000 process; that if we’re going to do storage as a transmission asset, we make sure that in order to build this, things are made available to everyone in the marketplace,” Brodbeck said.
PC Chair Dave Souder said making sure projects were open to competition would be part of the interest identification in Phase 1, so it wouldn’t be out of scope.
The committee will hold monthly special sessions beginning around June to work on the initiative. Proposed changes to manuals or other governing documents are expected to be completed by the end of the year.
Indiana regulators are collecting information from both sides of the argument over whether Duke Energy is prudently handling the self-commitments of its coal units in the state.
The Indiana Utility Regulatory Commission opened a docket in March to investigate Duke’s self-scheduling practices after the company applied to increase its fuel adjustment charge, the amount billed to ratepayers based on fluctuating fuel prices. The IURC has scheduled a Sept. 21 hearing in the matter (38707).
The Sierra Club and Citizens Action Coalition of Indiana (CAC) have said there are “serious issues related to Duke’s commitment decisions,” pointing to the company’s coal-fired Cayuga Generating Facility, Gibson Generating Station and Edwardsport Integrated Gasification Combined Cycle plant.
In testimony to the commission, Sierra Club attorney Kathryn Watson said the organization isn’t sure if Duke is meeting its responsibility of providing electricity to retail customers at “the lowest fuel cost reasonably possible because those costs may include periods of unreasonable commitment for its Cayuga, Gibson and Edwardsport coal-burning plants into the MISO energy markets.”
Jennifer Washburn, an attorney with CAC, also said Duke may be purchasing and storing “excessive amounts of coal” for some units.
Devi Glick, a senior associate at Synapse Energy Economics who testified on behalf of Sierra Club, said Duke’s own analysis showed that Edwardsport could have earned $3 million if it ran on natural gas alone, compared with the $3.1 million in losses the company had projected based on the plant running on a synthetic gas-and-coal combination from Sept. 1 to Nov. 30, 2019.
Glick herself estimated that over the same three-month period, Duke’s operational losses totaled $3.3 million at Edwardsport and $3.56 million at Cayuga.
“Duke should be electing to operate its units on a forward-looking basis only if it expects to make money, and the company should keep the units offline if they are projected to operate at a loss,” Glick told the IURC. “While there are reasons why inflexible units with longer start-up and shutdown times, such as coal-fired units, may choose to self-commit, the company’s process for deciding how and when to self-commit should result in reasonable decisions that do not bring or keep units online when they are projected to lose money over a multiday, weeklong or longer time horizon.
“Based on my review of the company’s internal commitment-decision process … I see no indication that the company’s internal processes are aligned with, or guaranteed to serve, the best interest of ratepayers,” Glick added.
Shannon Fisk, managing attorney for the Earthjustice coal program who represents the CAC, said that while there potentially may be “a day here and there” where coal units operate uneconomically for other reasons, it shouldn’t be nearly as often as occurs with Duke.
“They’re incurring substantial losses running Edwardsport on coal, when the more logical approach is to shut the thing down, which would be cheaper for customers or, at worst, run it on gas,” he told RTO Insider.
Duke: Must-run Statuses Justified
Duke spokesperson Angeline Protogere said the utility’s goal is “always economic operation of our plants for customers.”
“Each business day, we do an economic review of a number of factors as we make a decision for each unit,” Protogere said in an email to RTO Insider.
In April 29 testimony, Duke Managing Director of Trading and Dispatch John Swez said the company commits its generating units “on an economic basis, except as required for unit testing, operational requirements or other infrequent reasons.”
“Units are dispatched on an economic basis between their minimum and maximum capability when not required to run at a specific output as would be necessary for unit testing, an operational requirement or other reasons. Utilizing a commitment status offer of must-run in the MISO energy markets does not necessarily mean that a generating unit was not economically committed,” Swez said.
He said must-run designations are sometimes necessary for facility testing, to ensure that a unit meets its minimum run-time to prevent wear or avoid damage from freezing temperatures. He also said the designation is needed because of the Indiana Municipal Power Agency’s nearly 25% ownership interest in the 625-MW Gibson Unit 5 and the Cayuga station’s arrangement that one unit remain at or above 300 MW to supply steam to nearby industrial customer International Paper.
“Used properly, as we do, the use of a must-run offer reduces the overall cost to supply energy to our customers by reducing the additional costs and risk associated with the unnecessary and uneconomic cycling of longer lead-time generating units,” Swez said.
But Fisk questioned “whether the proceeds from International Paper justify the costs to ratepayers” to keep the unit always switched on.
“The issue we’ve queued up in the commission is whether this is beneficial to customers. It’s clear that sometimes they’re dispatching the unit uneconomically,” Fisk said.
Swez said the minimum run-time of a unit at the Gibson station is 72 hours, and a restart of Edwardsport’s gasification systems can take up to 14 days. He also noted that MISO’s day-ahead market “was never designed to forecast economic commitments beyond the next day.”
Beyond that, Duke makes purchases of lower-cost energy from the MISO markets, Swez said, noting that the company last year purchased a little more than 30% of energy served to customers from the RTO. “The MISO energy markets are a resource that is used to the customers’ advantage when power prices are below the cost of the company’s generation cost,” he said.
Protogere also noted that a unit under must-run designation in MISO is only required to be online for its minimum load.
“It’s still MISO … that directs dispatch of a unit anywhere between a unit’s minimum and maximum capability,” she said. “If there is lower-cost power available, we make every attempt to turn down/off our units and purchase from the market. We manage our units as economically as possible for our customers. The ability to self-commit a generating unit is critical to avoid start-up expenses and operational risks incurred by cycling a unit offline and then back online during short periods.”
Duke Vice President of Midwest Generation Cecil Gurganus also defended his company’s practice of maintaining a coal pile at Edwardsport even though the plant can run on natural gas.
“We must acknowledge the reliability and resiliency value in fuel inventory maintained at coal plants, relative to natural gas. Even having contracted firm transportation agreements with natural gas suppliers is no guarantee of service when the commodity is curtailed,” he said.
Gurganus said Edwardsport’s fuel flexibility allows it to be available when other resources may not be. He also said the plant’s permitting dictates it run on coal as a primary fuel source and natural gas as a secondary fuel.
But Fisk said Edwardsport is approved to run on either fuel.
“Duke has substantial over-inventories of coal,” Fisk said, adding that utility-wide, it appears that Duke keeps about 60-plus days of inventory at units in addition to up to 1.4 million tons of coal in off-site storage. He said Duke should rethink coal-supply contracts and set aside any possible loyalties to keeping coal mines afloat. Duke officials pointed out in testimony that the plants use locally sourced Indiana coal.
“It should not be on Indiana ratepayers to keep a struggling coal mine is business,” he said. “A more prudent approach would be to ask: How can we stop buying more coal?”
While Fisk said his organization has yet to evaluate a MISO multiday market, he argued it wouldn’t change much about Duke’s commitment behavior.
“The argument here isn’t whether Duke on a daily basis is turning the unit on and off. The argument is: Duke has analysis over the coming weeks that the unit will be uneconomic, and it’s committing it anyways. If their own projection is showing the unit won’t make money, then it should be taken offline,” he said.
MISO’s Perspective
MISO itself continues to maintain that uneconomic coal must-run designations are uncommon.
The RTO said that from early 2017 to late 2019, self-committed coal units economically dispatched above their economic minimum level represented about 76% of its total coal-fired generation. MISO said it economically committed and dispatched another 12%.
“Added together, that means 88% of the region’s coal-fired energy in the last three years was economically dispatched in some manner,” MISO said.
But Fisk said that uneconomic commitments even 12% of the time represents “still quite a bit of money lost.”
“Commissions should be carefully evaluating how to shrink that number,” Fisk said.
MISO also points out that self-commitment is “used by all types of resources, not just coal.” During March, coal represented just 2 out of the 12 TWh in self-committed and uneconomically dispatched generation, the RTO said.
It also reported that coal self-commitments are on the decline. In 2009, 64% of its total energy was from self-committed coal resources. By 2019, that share fell to 36%.
Despite the drop, MISO states Minnesota and Missouri have also opened similar investigations into utilities’ coal plant self-scheduling.
Fisk acknowledged that coal self-commitments are on the decline even as they garner more attention. He said increasingly economic renewable resources have likely contributed to the emphasis on the issue.
“Certainly, the rise of renewables has contributed to lower-cost generation. The question is whether these utilities have properly adjusted to this new reality. It doesn’t appear that Duke has attempted this transition,” he said.
SPP’s Market Monitoring Unit last week released the final version of its 2019 State of the Market report and a study conducted for state regulators working on improving issues across the MISO seam.
The Monitor said SPP’s energy prices were the lowest since its Integrated Marketplace went live in 2014. Day-ahead prices averaged about $22/MWh and real-time prices about $21/MWh, both down from $25/MWh in 2018.
The flow for the coordinated transaction scheduling process across the SPP-MISO seam | Market Monitoring Unit
The report also lists several new market-improvement recommendations, including strengthening price formation during emergencies and scarcity events, incentivizing capacity performance, and updating and improving outage coordination methodology.
The MMU will discuss the report with stakeholders during a May 26 webinar.
The second report analyzes coordinated transaction scheduling (CTS) as part of the MMU’s work for the SPP Regional State Committee and the Organization of MISO States’ Liaison Committee.
The study estimated that the RTOs are incurring $9.4 million to $11.2 million in economic inefficiency losses because they lack a CTS product. The MMU looked at cost and benefit information from other markets’ CTS products and estimated the potential increase in flow across the SPP and MISO seam.
The MMU said several roadblocks are hampering efficiency gains, such as transmission fees and non-energy market charges for CTS transactions, ramp-rate restriction on net scheduled interchange, and price forecasting accuracy, volatility and uncertainty.
Potomac Economics, MISO’s Independent Market Monitor, has also filed a study report with the regulatory committee that evaluates the market-to-market (M2M) coordination processes. The M2M process allows the RTOs to manage together congestion on transmission constraints that affect both SPP and MISO.
The IMM study says that “even modest improvements” in the M2M process can lead to large changes in congestion costs and efficiency savings. The RTOs’ congestion costs during the one-year study period exceeded $150 million.
WEIS Market Participants Prep for Tests
David Kelley, SPP’s director of seams and market design, told participants in the RTO’s nascent Western Energy Imbalance Service (WEIS) market to “buckle up” with market trials just weeks away.
“Ensure your systems are working,” Kelley told members of the Western Markets Executive Committee during a webinar Friday. “You will start to get flooded with a lot of information around market trials. It’s about to be a wild ride.”
In July, WEIS market participants will conduct connectivity testing to ensure their systems can “talk” with SPP’s. Structured and unstructured testing will be held from August through Nov. 20.
The WEIS market, with eight participants signed up, is scheduled to go live in February 2021. Kelley said the implementation project is in yellow status only while it waits on a second release of its markets software.
SPP, MISO Begin Year 5 of M2M Process
SPP and MISO began their fifth year of M2M operations across their seam by continuing the trend set during the first four years, with SPP again benefiting from settlements in its favor.
The RTO piled up $2.77 million in M2M settlements in March, raising its 61-month total to $76.35 million, staff told the Seams Steering Committee on Wednesday. M2M settlements have accrued to SPP for 45 months since the two RTOs began the process in March 2015.
SPP has piled up $76.35 million in market-to-market settlements from MISO since March 2015. | SPP
Temporary and permanent flowgates on the RTOs’ seam were binding for 681 hours during March. Temporary flowgates accounted for 429 of the binding hours.
PJM officials have revised some of their proposed rules for applying the minimum offer price rule (MOPR) to state default service procurements in response to stakeholder feedback.
At the Market Implementation Committee meeting Wednesday, PJM attorney Chen Lu outlined a revised definition of an “entity providing default retail service.” The new definition defines the term as any entity “providing default retail service, including but not limited to a load aggregator or power marketer that enters into a contract or similar obligation with an electric distribution company to provide default electric services for retail customers who do not participate in the selection of a competitive retail provider that has been granted the authority.”
Exemption Criteria
Lu also provided a revised “state subsidy definition” exempting “bilateral transactions” used to fulfill default retail service obligations from the MOPR if the state default procurement auction meets certain criteria:
being subject to independent oversight by a consultant or manager who certifies that the auction was conducted through a nondiscriminatory and competitive bidding process;
does not impose conditions based on the ownership, location, affiliation or resource type — except for meeting state renewable portfolio standard requirements;
does not require bilateral transactions to be sourced from any specific resource or resource type to satisfy retail supply obligations; and
costs can be avoided by retail customers who elect to obtain supply from a competitive retail supplier.
Wednesday’s two-and-a-half hour discussion picked up on talks at the MIC’s special session May 6 over straw proposals attempting to address Paragraph 386 of FERC’s April 16 rehearing order of its Dec. 19 order expanding the MOPR. That paragraph said that state procurement auctions are a form of a state subsidy because they provide a payment or other financial benefit to capacity resources that are part of a state-sponsored or state-mandated process. PJM must make a compliance filing in response to the April order by June 1.
Jason Barker of Exelon said Wednesday he was “concerned” by the new language and requested PJM consider how the selected wording would impact businesses participating in the provider of last resort (POLR) auctions. He said focusing the exemption on the existence of bilateral contracts could have major implications on most capacity auctions because some POLR auction suppliers also own generation.
“You could have the potential impact of tens of thousands of megawatts of potential supply into those auctions,” Barker said. “We would certainly ask you to sharpen the pencils on that point.”
Lu said the new language was proposed as another alternative after hearing stakeholder concerns at the May 6 special session and that the RTO has not finalized its decision on the issue.
NRC Chairman Kristine L. Svinicki tours Energy Harbor’s Beaver Valley nuclear plant. Energy Harbor announced April 30 that it was awarded 18 tranches in the recent Pennsylvania provider of last resort (POLR) auction. | NRC
Consultant Roy Shanker said he liked the new wording, calling it a “simple solution” that seemed to address concerns voiced by Sam Randazzo, chairman of the Public Utilities Commission of Ohio, at the May 6 meeting. Shanker said a simple way to look at the new language was that if the auction is asking for more than megawatts or megawatt-hours, then it’s discriminatory.
“This is an efficient way to send the right signal about who you are trying to exempt,” Shanker said.
Gary Greiner, director of market policy for Public Service Enterprise Group, said he was taken aback early on in Wednesday’s discussion as to what constitutes a “bilateral transaction.” In the commercial world, “bilateral” means direct one-to-one transactions between two parties, he said.
The issue, Greiner said, is that a generation-owning entity typically engages in multiple POLR contracts and other supply arrangements, and that anything that happens within a portfolio could be considered a bilateral transaction. He said there’s nothing that doesn’t come through a bilateral transaction that is fulfilling an obligation in a default service program. Theoretically, he said, just about anything could be exempt.
“It’s impossible to paint the megawatts that are being used to fulfill the state retail service obligations,” Greiner said. “It’s just all baked in there.”
Marji Philips, LS Power’s vice president of wholesale market policy, said she viewed the new language as clearer than what PJM initially proposed. Philips said if stakeholders take the FERC order to its literal conclusion, then no generation owner could do any hedging in the PJM market, whether it’s with public power or a load-serving entity.
Philips said what PJM could do as a workaround is having the ability to track capacity obligations for transparency.
“What PJM is proposing is a good solution to what is a financial market that FERC has told them they have some obligation to oversee,” Philips said. “I think it really tries to solve a very difficult conundrum.”
Sticking to the Order
But Philips and David “Scarp” Scarpignato took issue with PJM’s plan to introduce in its June 1 compliance filing a new term, “re-entry capacity resource with state subsidy,” for resources that return to the capacity market after failing to offer into a BRA.
MIC Chair Lisa Morelli said such resources would have a MOPR floor price of net CONE, like new-entry resources. However, PJM is proposing to treat them like existing resources regarding the penalty for accepting a subsidy after electing the competitive exemption. It would require them to forfeit capacity revenues for the delivery year but not subject them to the asset life ban applied to new resources that violate the competitive exemption.
Because FERC was “silent” on this particular issue, Morelli said, PJM decided banning such existing resources from the capacity market for their lifespan “seemed a bit harsh.”
Scarp said the new definition appeared to be an attempt to “improve upon” the order.
“This is kind of pushing the envelope on whether you’re complying with the order or not,” he said. “I’m worried you’re going to unintentionally cause a delay in getting a final order out of FERC. You’re risking FERC coming back and ordering a third compliance filing.”
Morelli said failing to address the issue would be unfair to resources that had accepted subsidies under rules in effect before the December FERC order expanding the MOPR. “We’re not trying to get cute with the language, but it’s a very real issue,” she said.
Philips said PJM’s proposal “so clearly contradicts what the order says.”
“As Scarp noted, we have plenty of time to change the rules. As it is, the auction is on a very tight schedule,” she continued. “I would encourage PJM to stick to the issues and not reinterpret what it thinks is right.”
The New York Public Service Commission on Thursday voted unanimously to undertake a study to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals (20-E-0197).
“In my view, this is a timely, critical and thoughtful plan to start to modernize our grid … to meet our future needs, including the need to deliver the new clean energy called for by the state’s agenda,” PSC Chair John Rhodes said.
The study was mandated by a budget amendment passed last month that created a new siting agency for renewable energy projects. The New York State Energy Research and Development Authority will collaborate with the Department of Environmental Conservation and the Department of Public Service (DPS) to develop build-ready sites for renewable energy projects. (See NY Renewable Supporters Push for New Siting Agency.)
2019 NYCA energy production by zone | NYISO
Under the new order, transmission investments that the commission determines must be “completed expeditiously” are referred to the New York Power Authority for development and construction. Other projects are to be selected for implementation through NYISO’s public policy planning process.
“I look most importantly to the New York ISO, who has been a leader in appropriate tactical studies as it relates to the grid, especially with the reliability and resiliency aspects, and the studies that they are currently undertaking,” Commissioner Diane Burman said. “I do look to them as an important component of really critical evaluation and analysis that will be helpful.”
Commissioner John Howard said that in “the process of turning legislative goals into policy … we should be as cautious with other people’s pocketbooks as possible. This rebuilding of the grid could be enormously expensive … there’s always the temptation to gold-plate the system.”
Extended Run for NY-Sun
The commission also authorized an additional $573 million in funding to support the state’s goal to procure 6 GW in distributed solar generation by 2025 and extend the NY-Sun program to 2025, as petitioned by NYSERDA in November (19-E-0735).
DPS staff determined that the state is on track to achieve the original goal of 3 GW by 2023, with more than 2,410 MW in service in New York and more than 1,200 MW currently in development.
The NY-Sun initiative was part of the Clean Energy Fund created by the commission in 2016, which established utility collections from ratepayers to support the overall $960 million funding requirement.
Burman was the sole vote against the program extension, as she was in last month’s authorization for NYSERDA to solicit up to 2,500 MW of offshore wind energy this year. (See NYPSC Greenlights 2,500-MW Offshore Wind RFP.)
NY statewide solar distribution showing 2,410 MW as of March 31, 2020 | New York DPS
“I am really concerned about not only extending the program through 2025, which means the [ratepayer] collections continue, but also allocating additional funding — albeit it may be from reallocating uncommitted funds — and also then teeing up that we may be looking at new funding in a clean energy review,” Burman said.
Rather than indicate in the order that the PSC expects NYSERDA to report back on the impacts of the COVID-19 pandemic on the distributed solar industry, she said the commission should be asking the agency to report on that now.
“Doing this now really concerns me because, as we’ve seen, even from last session, what we saw as a need to move quickly on something didn’t necessarily mean that NYSERDA did,” Burman said.
Following the commission’s offshore authorization last month, NYSERDA said in a statement that it would not be rushing to put out a request for proposals amid the pandemic.
“My concern is that we have large-scale renewables solicitations on pause; we have the offshore wind solicitation on pause; we have a number of things that are on pause; and so the only thing not on pause is the movement of funding and the extension of programs that have ratepayer dollars attached to them,” Burman said.
Commissioner Tracey Edwards joined the call for accountability.
“I’m concerned that what we have in here that benefits the low- and moderate-income communities actually happens,” Edwards said.
She asked DPS staff to talk to NYSERDA about making the annual clean energy review into a quarterly review.
“I think it’s just critical,” she said. “Low-income communities get the brunt of environmental injustices right now, so if there are programs that are going to be put in place, we need to make sure that they are in fact working.”
The Federal Communications Commission voted Wednesday to make part of the 900-MHz spectrum available for companies in the utility, transportation, manufacturing and petrochemical sectors to develop “critical wireless broadband technologies and services.”
The 900-MHz band is currently reserved for narrowband land mobile radio communications by those industries. According to a press release, the FCC’s decision would make 6 MHz available for broadband licenses on a county-by-county basis, while the remaining 4 MHz would remain reserved for narrowband operations.
As part of the action, the commission will partially lift the 900-MHz application freeze so that existing licensees may relocate their operations as part of a transition plan. Utilities will be exempt from mandatory relocation. It will also modify the Association of American Railroads’ 900-MHz license, which gives it full use of the spectrum in areas surrounding rail lines in the contiguous U.S. Under the new rules, the AAR will be limited to the 4 MHz of narrowband frequencies.
FCC Chairman Ajit Pai | FCC
Opening up the 900-MHz band for broadband use is expected to provide a range of benefits to utilities and other users that will not have to use noisy commercial spectrums. Potential uses of the new spectrum by the electric industry described by commissioners include cybersecurity applications, real-time damage notifications and more efficient routing of energy.
Industry reactions to the change have been largely positive, with John Hughes, director of network engineering for Ameren, saying the decision “paved the way for [Ameren] to deploy a smarter, stronger and more secure communications network with far greater bandwidth.” The Enterprise Wireless Alliance, which proposed the rule change alongside Anterix in 2014, also applauded the move, saying that businesses and critical infrastructure entities “deserve access to spectrum capable of providing broadband solutions to their industrial tasks.”
“The order we adopt today strikes a balance between the goals of expanding access to broadband wireless communications services and maintaining access to sufficient spectrum for existing narrowband services,” FCC Chairman Ajit Pai said in a separate statement. “Our plan today not only will serve the existing users of the band, but also will rely on their unique expertise to make the transition to broadband possible.”
Recent FCC decisions affecting the electric industry include last month’s vote to open a portion of the 6-GHz band for unlicensed use. That decision was intended to improve rural connectivity and free up more space for use by consumer Wi-Fi devices. But utilities objected to the move, fearing disruption to their communications in the spectrum. (See Utilities Alarmed as FCC Opens 6 GHz Band to Wi-Fi.)
NERC’s Member Representatives Committee and Board of Trustees met via conference call on Thursday after in-person meetings in D.C. were canceled because of the COVID-19 pandemic.
Interviews Planned for Potential Canadian Trustees
The Nominating Committee has prepared a slate of six candidates to replace former Trustee David Goulding, who retired in January, and plans to hold interviews next month. The interviewing panel will include board Chair Roy Thilly, Vice Chair Kenneth W. DeFontes Jr., MRC Chair Jennifer Sterling, MRC Vice Chair Paul Choudhury and Trustee Colleen Sidford.
Along with Goulding’s replacement, the committee is also searching for a trustee to fill the seat of Jan Schori, who will retire at the end of 2020. As Goulding’s retirement leaves the board with only one Canadian trustee, and it is required to have at least two, the team decided to speed up the search for a successor who can be seated as soon as possible. (See “Search Begins for New Board Members,” NERC MRC Briefs: Feb. 5, 2020.)
For Schori’s replacement, the committee has engaged executive search firm Russell Reynolds and hopes to schedule interviews in early November. The interviews will be conducted in person if possible, but the committee is also exploring the option of remote interviews. Next month’s interviews are already set to be conducted electronically.
Align Expenditure Moves to FERC for Approval
The board agreed to request a $3.8 million budget variance from FERC to account for delays in NERC’s Align software project, intended to improve and standardize compliance monitoring and reporting processes across the ERO Enterprise.
Align was scheduled to be released in September 2019 but was delayed several times in order to include additional security features in the initial release. The delays caused the cost of the project to rise beyond its original estimate by up to $2 million, NERC interim CFO Andy Sharp said during the MRC conference call in April. (See Align Tool Set for 2021 Rollout.) The board also approved this expenditure at Thursday’s meeting.
The budget variance will be partially covered by a projected $1 million surplus from NERC’s operating contingency reserves for this year, but the majority will be financed by $2.8 million in debt. The organization will pursue a 60-month term rather than the typical 36 months, as the current low interest rates mean overall servicing costs will be the same or lower than previous projections of debt service for this year.
“I had asked the question earlier … as to whether we should really be thinking about doing financings for any of this, and the answer that came back was ‘yes,’” said Bill Gallagher, special projects chief for the Vermont Public Power Supply Authority. “I’ve always been looking at NERC to be debt-free, but I guess in this particular set of circumstances, it probably makes sense” to approve the debt.
Other Approvals
The board approved action on the following reliability standards:
Adopt reliability standard CIP-002-6, governing bulk electric system cyber system categorization, and retire CIP-002-5.1a per the recommendations of the CIP Version 5 Transition Advisory Group.
Withdraw proposed reliability standard VAR-001-6, covering voltage and reactive control. The decision would leave currently effective standard VAR-001-5 in place.
Board members also approved revisions to the current pro forma delegation agreements between NERC and the regional entities, which are set to expire at the end of the year. The revisions would include:
eliminating maps of RE boundaries in favor of textual descriptions, which the organization feels would allow more precision in assigning registered entities to specific REs;
clarifying requirements regarding the nomination of independent board members;
removing outdated language in light of the dissolutions of the SPP RE and Florida Reliability Coordinating Council;
prohibiting stakeholders from leading RE board compliance committees;
allowing REs greater flexibility regarding the use of funds collected through penalties; and
clarifying that delegation agreements may be terminated earlier than the end of the five-year term as long as written notice is provided of at least one year.
COVID-19 Prompts Further Meeting Changes
With future developments in the pandemic still uncertain, the board has decided that its next meeting, as well as the MRC’s, will be carried out via conference call again. The meetings were previously scheduled to take place Aug. 19-20 in Vancouver, Canada.
Chair Thilly said the board has deferred a decision on its final meeting of 2020, planned for Nov. 4-5 in Atlanta, while it monitors the progress of the COVID-19 response and recovery. The leadership is considering several options for the meeting that include going forward as planned, holding an online session again, or restricting in-person meetings to board and MRC members only, with others listening in via conference call.
“Whether that will be possible to establish [while maintaining] social distancing, or whether any meeting will be possible at that time, is simply unknown. But we will try to make that decision in a timely way so that people can prepare,” Thilly said.
