PJM MRC/MC Briefs: Jan. 27, 2021

Markets and Reliability Committee

Black Start Packages Rejected

PJM is back to the drawing board as two different solution packages aimed at addressing the disputed black start unit issue were rejected by stakeholders at last week’s Markets and Reliability Committee meeting.

The RTO’s option 1 package, which emerged as the main motion with 83% support at the Dec. 3 Operating Committee meeting, failed with a sector-weighted vote of 2.48 (49.6%) at the MRC. Dominion Energy’s package, which served as the alternate at the OC meeting with 82% support, failed with a sector-weighted vote of 2.47 (49.4%) at the MRC.

Stakeholders were asked to endorse the proposals addressing black start unit testing, involuntary termination, substitution rules, capital recovery factor (CRF) and minimum tank suction level (MTSL), and corresponding revisions to the tariff, Manual 12: Balancing Operations, Manual 14D: Generator Operational Requirements and Manual 15: Cost Development Guidelines.

PJM — Tasley, a single-unit 33 MW industrial gas turbine that began commercial operation in 1972 in Tasley, Va., is a black start-capable unit. | *Calpine*

The black start issue has been lingering for months since the problem statement was endorsed at the May OC meeting, leading to heated discussions among PJM members and generation owners fighting back against calls for retroactively applying CRF to existing black start units. (See Gen Owners Balk at Change to PJM Black Start Rates.)

The CRF issue emerged as the most contentious portion of the black start unit discussions, with stakeholders voting to amend the issue charge at the OC in December to align with language in the problem statement. (See Vote on PJM Black Start Compensation Deferred.)

PJM Monitor Joe Bowring | © *RTO Insider*

Proposed issue charge language said, “Current black start units receiving the capital cost recovery rate (Schedule 6A) and units already awarded in recent black start [requests for proposals] will continue with the commitment period and capital recovery factor rates as documented in the current Open Access Transmission Tariff.”

The issue over the language emerged when stakeholders discovered the issue charge, which is officially voted on for endorsement as codified in Manual 34, did not include a footnote contained in the problem statement, leaving the application of CRF rates up to interpretation in the proposed black start packages.

PJM — Adrien Ford, ODEC | © *RTO Insider*

The Independent Market Monitor’s package, which ultimately received only 7% support at the December OC meeting, called for updated CRF rates to apply to new and existing black start units. Updated commitment periods would have also applied to new and existing black start units.

Monitor Joe Bowring said the CRF table was originally created in 2007 as part of the Reliability Pricing Model capacity market design and includes assumptions that are no longer correct. Bowring said the CRF values are significantly higher than they should be under the lower corporate tax rate from changes in the 2017 tax law, leading to overcompensation for units.

The addition of the updated black start issue charge language at the December OC led to last-minute modifications to the Monitor’s package and PJM’s primary package, both of which failed to be endorsed.

The next steps for the black start issue are yet to be determined and will be discussed at the Feb. 11 OC meeting.

Adrien Ford of Old Dominion Electric Cooperative said the packages failed to correct the error of the CRF table not being updated in the tariff with the 2017 tax law.

Susan Bruce of the PJM Industrial Customer Coalition said she appreciated that black start is a “pretty muddy issue” and that there are aspects of the issue that “cut both ways.” Bruce said her biggest concerns with the black start packages are the changes to the capital recovery and commitment periods.

“It’s a complex issue for many of the reasons highlighted, but what’s before us doesn’t solve the issue,” she said.

Alternative Black Start Package

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), reviewed a proposal as a first read on behalf of the Delaware Division of the Public Advocate as a compromise alternative to the PJM and Dominion packages that failed.

Poulos said the changes to the black start issue charge at the December OC meeting stifled the voices of minority interests related to the CRF issue.

“It completely materially changed the black start discussion and eliminated certain aspects of that discussion,” Poulos said.

PJM — Greg Poulos, CAPS | © *RTO Insider*

The advocate package uses much of the same language from the failed proposals, keeping intact aspects of testing, unit substitution and termination and the MTSL. The changes include the addition of the Monitor’s language regarding CRF, applying rates to both new and existing black start units.

It also uses the language from the primary PJM package, with a five-, 10-, 15- and 20-year capital recovery period based on unit age at the time of it entering black start service.

“The advocates at this point could not support the two current proposals that are up, and that’s why I’ve tried to find an alternative proposal,” Poulos said.

Bowring said he continues to believe that exempting existing resources with the change in the black start issue charge was “inappropriate” and that the CRF issue should ultimately be decided at FERC.

“We don’t think there are any rights to windfalls built in to the CRF process,” Bowring said. “That’s exactly what’s been occurring for existing units back to the time of the tax law change.”

PJM — Marji Philips, LS Power | © *RTO Insider*

Marji Philips, LS Power vice president of wholesale market policy, said she objected to the term “windfall” being used regarding CRF. Philips said PJM conducted a competitive procurement process with the black start service for units currently in operation, and prevailing interest rates were considered and accepted by all interested parties.

Philips said she does not have a problem with updated CRF rates applying to new black start units, but she said applying rates to existing units is “retroactive ratemaking.” She said the advocate proposal is not fair and doesn’t recognize long-term contract law.

“These projects were built based on an assumption, and it was competitively chosen,” Philips said.

Alex Stern, director of RTO strategy for PSEG Services, made a motion for the advocate package to be sent back to the OC for further discussion, saying it was “ripe for a motion to remand.” Stern said he appreciated Poulos bringing forward a new proposal that doesn’t fall within the issue charge, but he believed that the OC “needs to go back to the drawing board” to discuss the issue.

PJM — Alex Stern, PSEG | © *RTO Insider*

“I think everybody now has to go back and roll up their sleeves and try to work together to figure out what’s in the best interest of all,” Stern said.

Ford said she didn’t see why the MRC would direct the advocate proposal back to the OC for discussion, as stakeholders on the committee “very clearly rejected” the idea of applying CRF to existing black start units.

“I think it’s appropriately before the MRC, and that’s where it should stay,” Ford said.

Stern’s motion to remand failed with a sector-weighted vote of 2.2 (44%).

Mike Bryson of PJM said that if there was a procedure to get the advocate package back to the OC to discuss, it would be the best outcome to flesh out ideas or possible compromises. Bryson said PJM is still concerned about addressing CRF on existing black start units and that the RTO has a “significant commitment to these units,” and changing existing structures would be “problematic.”

“We’re going to have to fix this CRF issue one way or another,” Bryson said.

MOPR Revisions Endorsed

Stakeholders unanimously endorsed revisions to Manual 18: PJM Capacity Market that conform to the FERC-ordered rule changes in the minimum offer price rule (MOPR) and forward-looking net energy and ancillary services (E&AS) offset calculation. The revisions were also unanimously endorsed earlier this month at the Market Implementation Committee meeting Jan. 12. (See “MOPR Changes Endorsed,” PJM MIC Briefs: Jan. 12, 2021.)

Jeff Bastian, PJM senior consultant in market operations, reviewed the updates to Manual 18, including recent changes to the redline language resulting from stakeholder discussions.

The first change is a previously unmapped region of the Ohio Valley Electric Corp. (OVEC) zone, which is now mapped to the Columbia-Appalachia TCO fuel pricing point for the purpose of establishing the net E&AS offset for the zone. The OVEC zone was also mapped to the AEP-Dayton Hub for determining the forward hourly LMP.

The second change includes new language in section 5.4.5.5(A) that clarifies that a seller’s financial accounting statements should serve as the primary form of evidence for use of an asset life more than 20 years.

Bastian highlighted two additional conforming changes made after the MIC endorsement. Language changes include the use of an average equivalent availability factor for PJM nuclear resources to account for refueling outages in the calculation of the forward net E&AS offset for existing nuclear units.

An additional change eliminated a requirement that a resource submit a sell offer at the resource-specific value under certain circumstances. Bastian said the update was related to the recent FERC filing regarding tariff revisions that account for when the default offer price floor exceeds the market seller offer cap (MSOC) under PJM’s MOPR (EL16-49-004, et al.). (See FERC Partially Accepts PJM MOPR Offer Floor Filing.)

Chen Lu, PJM senior counsel, provided a summary of the FERC order that largely accepted the RTO’s compliance filing, submitted Nov. 13, with the exception of one provision regarding the MSOC.

PJM included the Attachment DD language directed by the commission but also proposed an additional sentence to the tariff, which stated, “In the event the resource-specific MOPR floor offer price is greater than the applicable market seller offer cap, the capacity market seller of such capacity resource may only submit an offer for such resource equal to the resource-specific MOPR floor offer price into the relevant RPM auction.”

The commission rejected the additional sentence on the grounds that it exceeded its October compliance order, directing PJM to submit a new compliance filing within 15 days removing the sentence from the tariff. Lu said PJM will file an additional compliance filing by Feb. 3 to remove the rejected sentence from Attachment DD in accordance with FERC order.

PJM maintains that the additional compliance filing allows them to run the long-delayed capacity auctions for the 2022/2023 delivery year, Lu said, with the auctions set to commence on May 19.

“We believe we have the greenlight to run the next auction,” Lu said. “And we are prepared, ready and intend to commence the next auction.”

Stability Limits Endorsed

Members endorsed a proposed capacity constraint solution package and corresponding Operating Agreement and tariff revisions regarding stability limits capacity constraints. The package was endorsed with a sector-weighted vote of 4.05 (81%).

The proposal addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts. (See “Stability Limits Review,” PJM MIC Briefs: Dec. 2, 2020.)

The problem statement and issue charge were initially brought forward for endorsement at the August 2019 MIC meeting. (See “Modeling Units with Stability Limitations,” PJM MIC Briefs: Aug. 7, 2019.)

Lisa Morelli, director of market design for PJM, said the packages were developed to create consistent treatment of generator stability limitations.

Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.

The capacity constraint proposal was put forward by PJM and the Monitor and endorsed by the MIC with 64% support. It addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts.

Joe Ciabattoni, PJM manager of interregional market operations, said the units would be dispatched in economic merit order up to the stated stability limitation. If a unit chooses not to remedy a stability limitation identified during the planning process, Ciabattoni said, its operating restrictions — as documented in its interconnection service agreement — would be invoked prior to those for other units.

The package also included a measure for transparency, with PJM posting data on the frequency, location and number of affected units while maintaining confidentiality rules.

Lost opportunity cost (LOC) credits would not be paid for any reduction required to honor the stability limit. Similarly, LOC is not paid for economic megawatts of a resource that cannot produce because of a ramp limitation.

Paul Sotkiewicz of E-Cubed Policy Associates reviewed the alternate opportunity cost solution package that was ultimately not voted on. The proposal, presented by J-POWER, was fundamentally the same as the PJM-IMM package except for providing compensation for LOCs.

Sotkiewicz said if a generator is requested to take an outage when it can still run, the unit is in essence being asked to “not reveal our true capabilities” to the market of what could actually be generated. He said it creates a “slippery slope” going forward to misrepresent a unit’s true capabilities.

“I think the mechanical changes to the market are excellent, and I applaud PJM and the Market Monitor for that,” Sotkiewicz said. “But we do believe we should be paid lost opportunity costs.”

Catherine Tyler, Monitoring Analytics | © *RTO Insider*

Catherine Tyler of Monitoring Analytics said LOC was not included in the PJM-IMM proposal because generators could endanger a unit’s stability and risk damage by pursuing opportunities for LOCs. Tyler said the costs to repair potential damages to a unit would outweigh the LOC.

“There’s not a benefit of receiving the higher LMP if you’re going to break your unit to do it,” Tyler said.

A final vote on the package will be held at the Feb. 24 Members Committee meeting. Ciabationi said conforming manual revisions will be brought through the OC and MIC for endorsement following FERC approval of the proposal.

Manual 14C Revisions Endorsed

Stakeholders endorsed revisions to Manual 14C: Generation and Transmission Interconnection Facility Construction as part of the biennial cover-to-cover review after voting to delay the revisions last month over concerns regarding some of the proposed language. (See “Manual 14C Delayed,” PJM MRC/MC Briefs: Dec. 17, 2020.) The revisions were endorsed by acclamation vote with one objection and one abstention.

Mark Sims, PJM’s manager of infrastructure coordination, said the committee proposed minor changes to Manual 14C, including an update of the latest Tariff provisions clarifying the filing process for title transfers and associated title documentation in Section 5. New sections on cost-tracking for baseline projects and another for supplemental cost-tracking were also proposed.

Poulos made the request to delay the endorsement by one month to work with PJM on some language suggestions after expressing concerns about some of the language. Poulos specifically referenced sections 6.1.2 and 6.2.1 dealing with tracking of supplemental projects.

Sims said PJM coordinated with Poulos to address the language concerns, and Poulos presented the friendly amendments to make the language consistent with Manual 14B.

In Manual 14B, the transmission owners must update PJM on the status of state regulatory approval in the quarterly updates. But in Manual 14C, Poulos said the burden is on PJM to “request” the status of state regulatory approvals.

Poulos said PJM currently does not wait for state approval of supplemental projects, and with the manual change, it was less likely that the RTO will even be aware of the state procedural process.

The friendly amendment said the Manual 14C sections will be consistent with language in Manual 14B and will include “any relevant regulatory siting authority approval necessary for the project and the status of such approval.”

“My goal is to make the language consistent between the two manuals and ensure that PJM is updated on what the approval process is for each of these projects,” Poulos said.

Robert Taylor of Exelon asked if PJM was comfortable with the friendly amendment.

Sims said the language was consistent and added value in clarification. Sims said PJM was also intent on not making the procedures for requesting documentation overly burdensome for stakeholders or PJM staff and that the “relevant” documents would be enough for PJM engineers to adequately do their work.

Real-time Values Market Rules

Members endorsed a solution package addressing real-time values (RTV) market rules and corresponding revisions to Manual 11: Energy & Ancillary Services Market Operations and the tariff and Operating Agreement. The package was endorsed with a sector-weighted vote of 4.9 (98%).

Laura Walter, senior lead economist for PJM, said the original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources could not meet their unit-specific parameter limits or exceptions. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.

The PJM package requires that market participants repeatedly failing to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. A market participant would be required to enter a forced outage ticket into PJM’s Generator Availability Data System (eGADS) for the period of increased notification, start-up time and/or minimum downtime.

For the timeline of an RTV submittal, Walter said, the package would require that the requested period not exceed one market day. She said that when an RTV is requested, it would be available for that one day, then the entire schedule would revert to the previous day’s values.

Siva Josyula, Monitoring Analytics | © *RTO Insider*

The package also calls for adding RTVs to the tariff. Currently, RTVs are mentioned only in the manual, Walter said.

Siva Josyula of Monitoring Analytics reiterated the Monitor’s concern that the changes proposed in the PJM package undermine the parameter-limited scheduling (PLS) rules used in RTVs. The PLS rules are part of the capacity performance rules requiring units to operate to defined parameters, he said.

The package will be voted on at the February MC meeting.

PRD Credits Disposition

Stakeholders unanimously endorsed through an acclamation vote the proposed solution package addressing the disposition of price-responsive demand (PRD) credits.

PJM’s Pete Langbein went over the corresponding revisions to Manual 11: Energy & Ancillary Services Market Operations, Manual 18: PJM Capacity Market, OA tariff and Reliability Assurance Agreement. Langbein said no changes were made to the package after it was presented for a first read at the December MRC meeting. (See “PRD Credits Disposition,” PJM MRC/MC Briefs: Dec. 17, 2020.)

PJM’s settlement rules call for revenues associated with PRD to be credited to the load-serving entity (LSE) for an area and do not address the roles of electric distribution companies (EDCs) or curtailment service providers (CSPs), meaning some LSEs are paid for PRD service supplied by EDCs and CSPs.

Langbein said the LSE was removed from emergency/pre-emergency demand response process several years ago.

The solution package calls for the PRD provider to receive the PRD bill credit and that any member that is a PRD provider is treated the same with no need to differentiate between a PRD provider and an LSE.

The package now heads to the MC for a vote in February.

Members Committee

Manual 34 Changes

Proposed revisions to Manual 34: PJM Stakeholder Process were unanimously endorsed at last week’s Members Committee meeting.

PJM — Gary Greiner, PSEG | © *RTO Insider*

The change provides clarifying language to affirm that the preference over the status quo 50% requirement is binding. (See “Manual 34 Revisions,” PJM MRC/MC Briefs: Nov. 19, 2020.) Gary Greiner, director of market policy for PSEG, sponsored the revisions that came out of discussions at the Stakeholder Process Forum.

Members proposed incorporating an additional threshold for moving a proposal to a senior standing committee. The language change says a proposal must pass a simple majority voting threshold and be preferred over the status quo by more than a simple majority. Current rules that do not require a majority prefer the alternative over the status quo.

“In the way of enhancements, we determined that we were going to ask the preference question for all proposals before we knew the level of support that they garner,” Greiner said.

February 2, 2021October 30, 2023

Overheard at Conn. LCV Environmental Summit

The Connecticut League of Conservation Voters held its annual environmental summit last week with hundreds tuning into discussions on the Transportation and Climate Initiative and the controversial plan to build a natural gas power plant in southeastern Connecticut.

Here is some of what we heard from elected officials, state regulators and environmental activists.

Lamont, Dykes Target Planned Power Plant

Gov. Ned Lamont (D) did not pull his punches in expressing his opposition to NTE Energy’s proposed 650-MW gas-fired Killingly Energy Center.

“I don’t want to build Killingly; I’m not interested in building Killingly, and I’m not sure the market will say that we need Killingly,” Lamont said. “The question is, what can I do about this?”

The plant received siting approval and is going through the permitting process. The project is “a lot of the way down the road” according to Lamont. He said playing “some games” with permits could slow things down, but the market itself could dictate the plant’s future.

“Look, electric usage is flat to down. … I’m not quite sure where the market is going to come out on this,” he said.

Lamont did concede that there is a “slight benefit” that Killingly could provide “relatively cleaner” energy as opposed to a coal-fired power plant, but “I’m not positive you’re going to see Killingly built at all.”

When asked if the lawmakers can do anything to stop the Killingly, House Speaker Matthew Ritter (D) said, “probably not.”

“The reason I say that is because I haven’t even been approached about that yet, which leads me to believe that there are people who would be concerned about the legality of [legislation],” Ritter said. “People can certainly research it, but my instinct is that this one is now at the administrative level. We need to make sure we’re very clear about what we’re committed to doing, how we’re going to meet our [clean energy and decarbonization] goals.”

Katie Dykes, commissioner for state’s Department of Energy and Environmental Protection, said she hears from people “every day about their concerns about this gas plant.” Dykes added that outside of the established permitting process, “we have to change the system … if we want to achieve our broader transformation and decarbonization goals, and we’re doing that by working” to change ISO-NE.

Dykes referenced Lamont and the four other New England governors, who released a joint statement in October calling for reforms to the RTO, saying it is frustrating their efforts to reduce economy-wide greenhouse gas emissions. A subsequent vision statement listed changes the states seek to ISO-NE market designs, transmission planning process and governance. (See States Demand ‘Central Role’ in ISO-NE Market Design.)

Online public technical forums are underway in all three areas. (See ISO-NE, NEPOOL to Kick off State Technical Forums.)

“It’s really important. This is a generational opportunity,” Dykes said. “We have to transform our grid and make sure that we can get the clean energy resources that we need to achieve our goals.”

Dykes added, “with every concern that I’ve heard from folks about this power plant, it’s redoubling our efforts to make this system-wide change if we want to prevent future projects like this from coming forward or much older, much dirtier plants from operating longer than is necessary.”

Focus on TCI-P

Charles Rothenberger, climate and energy attorney for Save the Sound, sought to counter misinformation he said is being spread about the memorandum of understanding Connecticut, Massachusetts, Rhode Island and D.C. signed in December to launch the Transportation and Climate Initiative Program (TCI-P), which aims to cut GHG emissions from vehicles by 26% from 2022 to 2032. (See NE States, DC Sign MOU to Cut Transportation Pollution.)

From top left: Katie Dykes, Connecticut DEEP; Connecticut Gov. Ned Lamont; and Lori Brown, Connecticut League of Conservation Voters | Connecticut League of Conservation Voters

TCI-P is a cap-and-invest program that will require large gasoline and diesel fuel suppliers to purchase allowances for the pollution and later to auction them, which officials said will generate $300 million for yearly investments in less polluting transportation. Each year, the total number of emission allowances would decline.

Rothenberger said the challenge of needing to rapidly decrease emissions “at a much quicker and steeper pace to meet medium- and long-term mitigation targets” will not be successful without a focus on transportation.

In Connecticut and throughout the region, transportation is the largest source of GHG emissions, accounting for approximately 38% of the total.

Rothenberger said there is “a lot of work to be done” to develop the rules that will govern the regulatory structure.

He said the hope is that Connecticut lawmakers will pass legislation this year and that the regulatory rulemaking and early reporting period can both be in place by January 2022 as a trial run for the tracking and accounting of emissions from the regulated fuel sources. The first formal compliance period begins in January 2023.

Rothenberger added that there is already “inaccurate and false information” about TCI-P making the rounds.

“It’s important that legislators know the actual facts and have the relevant information about how the program works, and its benefits,” he said.

One of the “absolutely not true” elements circulating is that TCI-P a Trojan horse for raising the gas tax.

“There is no tax, gas or otherwise, in sight,” Rothenberger said. “It’s a cap on emissions, and individuals, wholesalers, primary fuel suppliers that are bringing fuel into the state and participating jurisdictions will need to purchase auctioned emissions allowances. It’s shifting the cost of pollution on to the suppliers of the pollution producing fuels.”

Rothenberger said it is possible that fuel suppliers “may pass some portion of those costs on to consumers, which is “clearly their decision.”

“But there’s no state tax component to this whatsoever, and the program has modeled the most conservative scenario in which 100% of the compliance costs would be passed on to consumers by the fuel suppliers that indicates there may be at most a 5-cent increase in gas prices at the pump,” Rothenberger said.

Ritter said that although he has discussed TCI-P with Gov. Lamont, “rank-and-file legislators” might only have “an inkling” about the program. “So, there’s a real education gap, including for me,” he said. He added that lawmakers need to understand better “what Connecticut’s commitments are” and not construe it as a gas tax.

“It’s a silly notion, but you have to explain this to people and get the education out because I don’t think the average legislator is familiar,” Ritter said. “The good news is … we have a lot of time to get there and explain it, and I’m confident that when we explain what it does, how we’re working with our neighboring states … we will be able to make a compelling case.”

Ritter Speaks

Ritter, a six-term legislator serving his first term as speaker, said that although the COVID-19 pandemic will prevent a regular legislative session in 2021, advocates need to continue to reach out to legislators to signal their support or opposition to potential bills. He said virtual lawmaking is a slower process, and as committees prioritize bills, some items could be pushed off to the 2022 session.

“Every week since January we’ve had a member in our caucus positive with COVID,” Ritter said. “If we are in session and somebody tests positive, or staff tests positive, at any given time, we could be on a 14-day hiatus from the state capitol building. So, keep that in mind, no voting at all. If that happens in late April or early May, it takes up a lot of session days. You’ve got to think about the worst-case scenarios.”

February 2, 2021

Texas Utility Plans to Join CAISO EIM

El Paso Electric, a utility that serves more than 400,000 customers in the Rio Grande Valley of Texas and New Mexico, said Monday it plans to join CAISO’s Western Energy Imbalance Market in 2023.

The move would expand the EIM’s footprint to Texas for the first time. It also ups the competition between CAISO and SPP’s Western Energy Imbalance Service (WEIS), which launched operations Monday. (See related story, SPP Successfully Launches Western Market.)

“The EIM will allow EPE to leverage our interconnection to the electrical grid with neighboring markets to reduce cost and balance our energy generation with the real-time power needs of our customers, as well as integrate greater amounts of renewable energy,” EPE CEO Kelly Tomblin said in a joint statement with CAISO.

Public Service Company of New Mexico, whose territory borders EPE’s to the north, plans to go live in the EIM early this year.

An iconic sign sits atop El Paso Electric’s Rio Grande Power Plant in Sunland Park, NM. | *El Paso Electric*

SPP has been trying to attract utilities in more politically conservative states that do not want to get too cozy with liberal California and its 100% clean-energy agenda.

But the EIM’s oversight — its Governing Body members come from other states — and its economic benefits have been attractive to entities across the West, including in more conservative interior states.

In the fourth quarter of 2020, the EIM provided participants with $69 million in benefits, bringing its total savings for members to $1.18 billion since it began in 2014.

The initial eight members of SPP’s WEIS are Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, the Wyoming Municipal Power Agency, and the Western Area Power Administration’s Upper Great Plains West, Rocky Mountain region and Colorado River Storage Projects.

The EIM’s current members include Arizona Public Service and Arizona’s Salt River Project; Idaho Power Company; NV Energy; and PacifiCorp’s vast service territory in Oregon, Washington, Utah, Wyoming, Idaho and Northern California.

Five entities plan to go live in the EIM in the first half of 2021: PSC, the Los Angeles Department of Water and Power, NorthWestern Energy, Turlock Irrigation District and the Balancing Authority of Northern California Phase 2. Six more utilities are scheduled to join the EIM in 2022, including Avista and the Bonneville Power Administration, covering most of the Pacific Northwest, and Xcel Energy, which serves much of Colorado.

EPE was the first entity to announce plans to join the EIM in 2023.

A privately held group, Infrastructure Investments Fund (IIF), bought EPE last year for $4.3 billion, after winning approval for the deal from the Nuclear Regulatory Commission. EPE owns a nearly 16% stake in the Palo Verde power plant in Arizona, the nation’s largest nuclear generating station. (SeeFERC OKs El Paso Electric Mitigation.)

Its decision to join the EIM was based on the projected economic benefits and a desire to pursue “a clean, green energy future,” Tomblin said in the statement.

CAISO CEO Elliot Mainzer said he was pleased EPE chose to join the EIM.

“El Paso’s entry … will improve efficiencies for their customers while strengthening and expanding the geographical scope of our market,” Mainzer said. “We look forward to providing them with outstanding customer service as they join the family of Western EIM entities.”

February 2, 2021

CAISO Advances Summer Readiness Plan

CAISO introduced a straw proposal Wednesday that aims to attract supply this summer and head off shortfalls like those that led to rolling blackouts in August and energy emergencies in September.

Propelled by those concerns, the ISO is moving ahead on its “market enhancements for summer 2021 readiness” stakeholder initiative at an unusually fast pace. It began advancing the measure in earnest in early January and scheduled it to be adopted by the Board of Governors in late March, with implementation scheduled for June 1.

The proposal took the form of a slide presentation only, not a written proposal as would normally be the case, because of time constraints. It is part of a series of fast-tracked measures being pursued by the ISO and the California Public Utilities Commission in anticipation of summer heat waves and capacity deficiencies as the state transitions from fossil fuels to renewables.

It and other measures are intended to address issues identified in a root-cause analysis of the summer shortages submitted to Gov. Gavin Newsom by CAISO, the CPUC and the state Energy Commission at Newsom’s request. It identified a variety of problems including transmission constraints, questionable exports from the ISO during tight supply conditions and market practices that undermined supply. (See Summer Readiness Sought by CAISO, CPUC.)

“This initiative’s goal is to prepare the CAISO’s operations and market ahead of this summer,” James Friedrich, market design policy specialist, said in his presentation. The “initiative is part of several measures to better access available supply, protect grid reliability and avoid rotating power outages during extreme heat waves. In addition to reliability, the CAISO has the responsibility to ensure its markets are operated efficiently, including mitigating market power and ensuring rational price formation.”

CAISO Summer Readiness Plan — | *Shutterstock*

The proposal deals with import incentives during tight load conditions, scarcity pricing enhancements and coordination with the interstate Western Energy Imbalance Market (EIM), among other changes. (See Western EIM Questions Performance in Shortfalls.)

For example, it proposes reviewing the performance of the ISO’s resource sufficiency evaluation (RSE) as part of its EIM participation. The re-evaluation would address defects identified in prior workshops such as accounting for resources that are derated as part of the capacity test and eliminating the double counting of mirror resources.

Two proposed enhancements seek to improve market incentives during times of tight supply. One would improve day-ahead market scheduling incentives, and a second would improve real-time incentives.

Another part of the straw proposal involves increasing the real-time market’s prices under certain conditions, including when the ISO issues a day-ahead market alert, or a warning or emergency in real time. The proposal would scale prices to the $2,000/MWh threshold established by FERC in Order 831. The order required ISOs and RTOs to raise the hard caps on supply bids from $1,000 to $2,000; offers over $1,000 require suppliers to justify their costs.

CAISO’s Market Surveillance Committee said in September that the ISO needs to consider implementing scarcity pricing to obtain energy during heat waves and supply shortages. (See CAISO Adds Scarcity Pricing to Policy ‘Roadmap’.)

Making sure storage resources are charged in strained conditions is another component of the straw proposal. Hundreds of megawatts of additional storage are scheduled to come online by this summer. A lack of storage for renewable resources last summer led to shortages when solar ramped down in the evening but demand from air conditioning remained high.

Comments on the straw proposal are due this Wednesday, with a final proposal expected by the end of the month.

February 2, 2021

Decommissioning Fund for Comanche Peak Tops $1.3B

The Texas Public Utility Commission last week approved a change to the decommissioning funds for Vistra Energy’s Comanche Peak Nuclear Power Plant.

During its Jan. 29 open meeting, the PUC signed off on an order that allows Vistra’s Luminant subsidiary to continue its annual decommissioning funding amount of $20.1 million for the plant’s two units. However, the order adjusts the funds’ allocation to 72.3% from 57.1% for Unit 1 and to 27.7% from 42.9% for Unit 2 (50945).

The net after-tax value of the units’ trusts total more than $1.3 billion, with nearly $624 million allocated for Unit 1 and $692.5 million for Unit 2. The plant said external and internal analyses indicates it will cost $1.729 billion to decommission and completely dismantle the facility in 2019 dollars, assuming a 10% contingency.

The commission said Comanche Peak “demonstrated that the funds in its nuclear decommissioning trusts are being invested prudently” and are following its investment guidelines.

Comanche Peak Decommissioning Fund — Comanche Peak Nuclear Power Plant | *The Nuclear Decommissioning Collaborative*

Unit 1, which began operating in 1990, is licensed until February 2030. The license for Unit 2, which opened three years later, expires in 2023.

While numerous nuclear plants have received extensions of their original 40-year licenses, others have been shut down as uneconomic, and five reactors totaling 5.1 GW of capacity — Indian Point 3 in New York, and Byron (two units) and Dresden (two units) in Illinois — are scheduled to close this year.

“Given Comanche Peak is one of the youngest plants in the country, significant decisions on license renewal are a few years away, but the plant is currently well positioned, and we have no plans to close it prematurely,” a Vistra spokesman told the Houston Chronicle in 2019.

Other Action

In other actions, the PUC approved a financing order that allows Entergy Texas to issue $539.9 million in transition bonds to recover hurricane-related costs (37247).

It also denied the city of Seymour’s request to overturn an administrative law judge’s December ruling allowing four people to intervene in its request for a declaratory order confirming that Tri-County Electric Cooperative has no grandfathered corridor rights for retail service within its city limits (49726).

Also last week, the commission announced it had promoted agency veteran Connie Corona to the new position of deputy executive director. She was previously the PUC’s chief program officer, guiding the market analysis, customer protection, infrastructure, rate regulation and legal divisions.

“Connie is a walking encyclopedia of industry knowledge who makes everyone around her more focused, productive and effective,” Executive Director Thomas Gleeson said. “We are truly fortunate to have her in such a critical role on our team.”

February 2, 2021

SPP Successfully Launches Western Market

SPP successfully launched its Western real-time balancing market at midnight Sunday, making it the first RTO with power markets in both the Western and Eastern Interconnections.

The RTO has said its Western Energy Imbalance Services (WEIS) market will lower wholesale electricity costs, increase price transparency and mitigate congestion for its participants. The market joins the reliability coordinator services SPP has been offering 12 entities in seven states since 2019; the grid operator will expand its RC function in April. (See SPP Expands its Western RC Footprint.)

“This will be a historic moment for SPP to launch this market … on time, and under budget,” CEO Barbara Sugg told stakeholders last week.

SPP Western Market — SPP celebrated its WEIS market launch Monday. | *SPP*

The WEIS market centrally dispatches energy from the region’s participating resources every five minutes. It is contract-based and does not require its participants to be SPP members. However, most of its participants have since indicated they are committed to evaluating becoming RTO members. (See Western Utilities Eye RTO Membership in SPP.)

WEIS market participants include:

Basin Electric Power Cooperative
Deseret Power Electric Cooperative
Municipal Energy Agency of Nebraska
Tri-State Generation and Transmission Association
Western Area Power Administration (WAPA)
Wyoming Municipal Power Agency

WAPA’s agreement includes the firm loads and resources of Pick-Sloan Missouri Basin Program–Eastern Division in the Upper Great Plains Western Area balancing authority footprint, the Loveland Area Projects and Salt Lake City Area Integrated Projects in the Western Area Colorado Missouri balancing authority footprint.

“Our electricity markets have played a big role in lowering costs, integrating renewables and enhancing reliability in the East, and we’re excited to see a new part of the country begin to see similar benefits,” Sugg said in a statement. “I’m hopeful this is just the beginning of valuable partnerships between SPP and western utilities that will help them and the customers they serve meet their financial, reliability and renewable-energy goals.”

SPP has long eyed expansion into the Western Interconnection. It explored a relationship with the Mountain West Transmission Group several years ago, but the effort was scuttled by Xcel Energy’s decision to join CAISO’s Energy Imbalance Market.

The RTO became the Western Interconnection Unscheduled Flow Mitigation Plan’s administrator in 2018 and it has been hired by the Northwest Power Pool to develop its regional resource adequacy program. (See NWPP Program Taking Shape for Q3 Launch.)

February 2, 2021

FERC Awaiting RTO Responses on Order 2222

The upcoming RTO stakeholder processes on Order 2222 are “where the rubber meets the road” for distributed energy resources’ participation in the markets, FERC Commissioner Neil Chatterjee told an Energy Bar Association webinar Wednesday.

Chatterjee was the FERC chair in September when the commission issued Order 2222, which directed RTOs to open their capacity, energy and ancillary service markets to aggregated DERs. (See FERC Opens RTO Markets to DER Aggregation.)

The order requires RTOs to allow DER aggregators to register as market participants under models that accommodate their physical and operational characteristics. FERC defines DERs as any resource located on the distribution system, a distribution subsystem or behind a customer meter, including energy and thermal storage, intermittent and distributed generation, energy efficiency and electric vehicles.

Chatterjee said the RTO compliance processes would be “interesting to watch” because, like Order 841, “we baked into the order a fair amount of flexibility on certain issues.” Compliance filings are due July 19. (See related story, MISO to Seek Extension on Order 2222 Plan.)

FERC Order 2222 — Clockwise from top left: Kristin Swenson, MISO; Mike Blackwell, MISO; FERC Commissioner Neil Chatterjee; Lorenzo Kristov, independent consultant; ; James Pigeon, NYISO and Karin Herzfeld, FERC. | *Energy Bar Association*

“For example, we provided some flexibility for each region to determine the locational requirements for DERs to participate in an aggregation,” said Chatterjee, the webinar’s keynote speaker. “As another example, we require each RTO to establish rules that address the requirements related to metering and the hardware and software necessary for DER aggregations to participate, recognizing that there’s always a push and pull between technical needs and the potential burdens on new market participants that they create.”

Chatterjee noted a projection that there will be almost 19 million EVs on U.S. roads by the end of the decade. “But the truth is those EVs will be off the road more than they are on the road,” he said. As charging infrastructure develops, he said, EVs will be “virtually able to work in concert to provide grid-level services.”

“That’s an easy way to think about the potential of Order 2222, but the true beauty of the rule is that it’s technology-neutral,” Chatterjee added. “So as new technologies emerge, our market rules will be able to accommodate them.”

Chatterjee said that when he visited the National Renewable Energy Lab in Colorado in October, he learned the scientists had been tracking Order 2222. “They viewed it as a catalyst for the work they’re doing on new technologies for the clean energy transition,” Chatterjee said. “It was deeply gratifying to know that our work at the commission was driving such significant change.”

Panel Discussion

Following Chatterjee’s keynote, a panel discussed approaches among RTOs for Order 2222 compliance, market impacts of DER proliferation, jurisdictional issues relating to DER adoption, and the impact of DERs on grid reliability and resilience.

“It’s striking to me the brilliance of how this [order] is written,” said Tricia DeBleeckere, planning director in the Minnesota Public Utilities Commission’s regulatory analysis division. “Whatever outcome or however this order plays out, it’s going to get what FERC’s intention is, which is a path for DERs to a market, whatever that market might be.”

Lorenzo Kristov, an independent consultant and former principal at CAISO, emphasized that the coordination between DER aggregators, utilities and RTOs is “really going to be crucial to both having efficient competition and also increasing participation in the wholesale market by DERs.”

FERC attorney Karin Herzfeld said the commission needed to recognize the interests state and local regulatory authorities have in Order 2222, which “actually requires the RTOs and ISOs to coordinate with all of these entities.”

“I think that the role provided to distribution utilities and their view of the aggregations is going to be huge,” Herzfeld said. “That’ll be a big thing that the stakeholder processes will be wrestling with in the near future.”

Chatterjee, whose term ends in June, said it would be an “understatement” to say he was proud of Order 2222.

“To me, the beauty of Order 2222 is its simplicity,” Chatterjee said. “Don’t get me wrong. I fully understand that the details underpinning the rule, and the compliance work that stakeholders are engaged in right now with the RTOs, is hugely complex.”

Chatterjee said at the core of the order is a “rather simple and elegant premise.”

“We should eliminate any hurdles facing DER aggregations in our markets, so they can line up and compete with traditional resources to provide all the energy and ancillary services and capacity that they have to offer.”

January 31, 2021December 7, 2023

Study: No Silver Bullet for Fossil-Climate Legal Tension

Customers were at the center of a panel discussion last week that highlighted what can happen when new state climate laws conflict with those currently governing fossil fuels.

While people are working to address those policy conflicts, Dale Bryk, senior fellow for energy and the environment at Regional Plan Association, said “we’re not doing as well as we could” because the issues states face in implementing their climate ambitions are “very complicated.”

A case study published in Energy Law Journal casts light on policies under New York’s Climate Leadership and Community Protection Act (CLCPA) that are inconsistent with other state polices that support residential customer access to natural gas.

“If you make mistakes in this area, and you get it wrong, someone’s heat will go off,” Bryke said. “People are conservative in thinking about it and really want to get it right.”

Bryk is former New York deputy secretary for energy and environment. She joined the discussion about the case study, “Harmonizing States’ Energy Utility Regulation Frameworks and Climate Laws,” during a webinar Friday hosted by the Institute for Policy Integrity and Environmental Defense Fund.

The study by Justin Gundlach and Elizabeth B. Stein explained New York’s current gas market dilemma as stemming from two separate laws: CLCPA, which makes little room for fossil gas in the future energy system, and New York Public Service Law, which establishes reliable natural gas service as being in the public interest. The study said there are similar policy equations in California, Colorado and New Jersey.

By putting the example of the natural gas sector in New York under the microscope, the study demonstrated how a just transition to net-zero emissions is not a certainty under the state’s laws as written. The study said that a just transition should be among the principles that guide reform.

The movement of gas customers to electrification to meet CLCPA goals could leave remaining customers with higher bills to pay, as the gas utilities’ pool of customers diminishes, the study said. Furthermore, those customers who cannot transition likely are the most vulnerable community members.

Rory Christian, principal at Concentric Consulting Group, said that as markets advance electrification, low-income families need to be protected.

“You have many low-income homeowners, affordable housing developers and rental tenants which lack the financial means, the resources or capability to make this conversion, so we need to align those incentives in a just and equitable manner to ensure that those with the greatest need can take advantage of this opportunity and be a part of the transition,” he said.

Christian said that a key factor in an equitable transition is addressing how utility rates are set under current regulations.

“Understanding that the current rate regime is based to develop and maintain the system as it is, we need to reconsider how rates are deployed and how they’re developed to ensure that customers who have to transition and will transition do not experience unexpected spikes in costs as a result,” he said.

The pathway to long-term success, he added, means looking at all existing laws and regulations to “minimize the potential for creating a wider economic divide between the haves and have-nots as the pace of electrification quickens.”

Gas utilities, however, are regulated in a way that ensures they are structured to sell gas.

Utilities are driven to expand their customer base and build large infrastructure, Bryk said, adding that they make money based on the rules that government sets for them.

“If we want utilities to be in a different business, if we want them to be in the business of providing heat at least costs over the long term, and we want them to be in the business of designing a just and equitable transition … then we need to set the rules … that will drive them to do that,” she said.

Government, she added, is giving utilities conflicting signals.

“Let’s stop doing that,” she said.

Fuel Neutrality

The case study suggested that fuel neutrality should be another principle that guides legal and regulatory reform related to climate ambitions.

“Codifying into statute or regulation clear preferences or biased parameters that favor a given technology or fuel … can burden future policymakers … with obligations that they may eventually find to be incompatible with the best means of achieving long-term policy objectives,” the study said.

In addition, neutrality ensures incumbent fuels and technologies remain open to competition.

The gas system example in New York shows the challenges electric heat pumps or building management systems are having competing with gas service. The study said that newer services and technologies, such as heat pumps, are not a part of utilities’ networked systems and they would force new policy to be inclusive of non-utility providers.

This change, the study said, “could strain traditional notions of the commission’s jurisdiction and role.”

Safe Transition

A third principle for reform raised in the study made clear the nature of states’ challenges in cleaning up human activity.

The study said that a safe transition must be achieved that balances protecting people from the consequences of human-made climate change and protecting people in the process of social transformation.

“In the long term, this means recognizing that until the transition is substantially complete, we will have to continue maintaining, repairing and/or replacing infrastructure components that pose an imminent risk to physical safety, even though we are also likely to be shutting down other components simultaneously,” the study said.

Consequently, policymakers will have to support values that are contradictory and adopt rules that depart from how infrastructure is governed currently.

January 31, 2021December 7, 2023

ERCOT Technical Advisory Committee Briefs: Jan. 27, 2021

Its work complete, the ERCOT task force working on the real-time co-optimization of energy and ancillary services is living on borrowed time.

Staff told the Technical Advisory Committee on Wednesday that when the group next meets in February, it will be asked to sunset the Real-time Co-optimization Task Force (RTCTF) and instead focus on the Passport Program and its “three-and-a-half-year trek.”

“This is our first time out of the gate,” said ERCOT’s Matt Mereness, who chaired the RTCTF, in referencing the work that lies ahead. “We could probably have a one-day meeting on some of these topics.”

In the task force’s stead, Mereness said staff are proposing that the TAC develop a Passport Program implementation working group or task force in the coming months. He suggested that policy and analysis items from the RTCTF’s work be parceled out to some of the committee’s subcommittees this year, when business requirements and designs will be developed.

ERCOT’s Board of Directors in December approved nearly three dozen revision requests by the task force and a separate group developing policies and principles for energy storage resources (ESRs). (See “Passport Program to Take off in 2021,” ERCOT Board of Directors Briefs: Dec. 8, 2020.)

That work is now being taken up by the Passport Program, which faces a 2024 deadline to combine real-time co-optimization’s and ESRs’ implementation with that of ERCOT’s energy management system (EMS) upgrade. Storage and distribution generation functionality will be added before 2024, with Passport “tying up any loose ends.”

The program will expand ERCOT’s real-time market to clear energy and ancillary services every five minutes, bringing the grid operators in line with most others. The day-ahead market, which is already co-optimized, will allow virtual ancillary service offers, while the operating reserve demand curve’s price adders will be replaced by converting it into demand curves for each service, reflected in real-time energy and ancillary service prices.

ESRs will be modeled and dispatched as a single device that charges as load and discharges as a generator. Devices within the distribution system will still be dispatched with improved mapping techniques.

Passport has a total budget of $85.5 million. The bulk of that is attributed to real-time co-optimization ($51.6 million) and the EMS upgrade ($27.1 million).

“We have limited resources and funding beyond the [Passport] projects,” Mereness said, noting staff have already been reviewing protocol changes to ensure their impact analyses don’t affect the program. “The ones that did had a small impact, small enough and discrete enough that we didn’t want to stop what’s in flight.”

He said additional budget details will be shared with ERCOT’s Board of Directors during its Feb. 9 meeting.

Staff Loosens Transmission Outage Restrictions

Healthier reserve margins have allowed staff to loosen some restrictions around planned transmission outages during ERCOT’s summer months (May 15 to Sept. 15).

Outages will still be prohibited from noon through 9 p.m. on 345-kV lines, with 138-kV and 69-kV lines barred from planned outages during that same time should they affect generation dispatch. However, planned 345-kV bus outages and transformer outages will be allowed, and 138-kV outages will be limited to seven continuous days and restoration times of less than six hours.

No outages will be allowed that alter system topology either before or after a contingency. Transmission owners will still have the same list of potential exceptions as the previous two years.

The grid operator goes into this summer with a reserve margin of 15.5%, almost double the 8.6% margin it took into summer 2019. Last year’s reserve margin was 12.6%. (See Solar Power Boosts ERCOT’s Reserve Margins.)

“Even with higher reserve margins, we think it makes sense to leave some restrictions in place for planned outages,” said Dan Woodfin, ERCOT’s senior director of system operations. “This will allow the TOs to do some work during the summer that was maybe not allowed during the last two.”

Lange, Blakey to Lead TAC

The TAC approved nominations to leadership positions for 2021, choosing South Texas Electric Cooperative’s Clif Lange as its chair and Just Energy’s Eric Blakey as its vice chair. Because Lange was not able to participate in last week’s meeting, Blakey wound up chairing.

“It’s such an honor to even be a member of this group. We very much appreciate your support,” Blakey said upon assuming his virtual position. “Last year was very challenging, but I hope there are fewer challenges this year so we can get together.”

The committee also confirmed the leadership for its subcommittees: incumbents Martha Henson (Oncor Electric Delivery) and Melissa Trevino (Occidental Chemical) for the Protocol Revision Subcommittee; Jim Lee (American Electric Power) and John Schatz (Luminant) for the Retail Market Subcommittee; Chase Smith (Southern Power) and Katie Rich (Golden Spread Electric Cooperative) for the Reliability and Operations Subcommittee; and Resmi Surendran (Shell Energy) and Ivan Velasquez (Oncor) for the Wholesale Market Subcommittee.

Members OK Another SCT Directive

The TAC endorsed another in a series of directives tied to Southern Cross Transmission, a proposed HVDC line in East Texas that would ship more than 2 GW of energy between the Texas grid and Southeastern markets. (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

Staff recommended that any DC tie facility with an initial energization date or that is replaced after Jan. 1 have at least a 0.95 power factor leading/lagging reactive power capability for voltage support. A Nodal Protocol revision request (NPRR) will need to be drafted to codify the endorsement.

The Southern Cross DC tie’s imports and exports will cause reactive losses on the ERCOT system because its facilities are not currently planned to have any reactive capability to support system voltage. According to a staff report, thermal limits will be reached before voltage limits during summer peak imports. The same report indicated the system has enough margin to support up to 1,289 MW of export before voltage limits are reached.

“We’re still trying to work through all the angles of this concept,” said Cratylus Advisors principal Mark Bruce, speaking for the Southern Cross developers. “Southern Cross is not necessarily opposed. There are ways to get there. … We’ll be interested in the specific NPRR language.”

Virtual Meetings Likely to Last into May

ERCOT’s Kristi Hobbs told stakeholders that they should expect to continue holding virtual meetings through at least May, continuing a practice that has been in place since last March when the COVID-19 pandemic exploded. Staff have been encouraged to work from home and discouraged from traveling, while outside visitors have been restricted from the grid operator’s facilities.

“We continue to monitor the case trends [and] all the government guidelines, as well as how things are progressing with vaccine opportunities,” she said. “We want to see how the vaccine rollout goes and the success of that vaccine.”

Hobbs promised to return to the TAC in April for another update, following another checkpoint with staff in late March.

RUC Hours Consistent with 2019

ERCOT’s reliability unit commitment (RUC) usage for 2020 remained comparable to 2019, staff told the committee, with 224 instructed resource-hours resulting in 220.1 effective RUC resource-hours. The prior year’s numbers were 228 and 201.7, respectively.

All the resource-hours were for local thermal congestion or voltage concerns, with 83% of the total stemming from damage caused by Hurricane Hanna and associated congestion in the Rio Grande Valley.

Staff also told the committee the Board of Directors will be told in February that the system administration fee is forecast to be adequate for 2022. The fee has remained at 55.5 cents/MWh since 2019.

Market participants had asked for more advance notice of any future administration fee increases during the 2016-2017 budget process. Staff deliver that forecast during the Finance and Audit Committee’s first meeting of the calendar year.

‘Significant’ Price Corrections Defined

The committee unanimously approved its combination ballot by a 30-0 margin. The ballot included the Southern Cross directive, 11 NPRRs, three revisions to the Planning Guide (PGRRs), and single changes to the Resource Registration Glossary (RRGRR) and the Settlement Metering Operating Guide (SMOGRR).

Among the endorsed changes was NPRR1024, drafted in response to the recent spate of price corrections in the day-ahead and real-time markets. (See “Board Approves 2 Sets of Price Corrections,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)

Staff promised the board in October that they would work with stakeholders to reduce price-correction requests by better defining “significance,” the only threshold for determining which market errors require board-approved corrections. NPRR1024 defines “significance” as:

- - the absolute value change to any single day-ahead market (DAM) settlement point price at a resource node or day-ahead market-clearing price for capacity (MCPC) is greater than 5 cents/MWh;
  - requiring ERCOT to change more than 10 DAM settlement point prices and day-ahead MCPCs; or
  - the absolute value change to any DAM settlement point price at a load zone or hub is greater than 2 cents/MWh.

Members voted separately on another Protocol change when Morgan Stanley’s Clayton Greer indicated he would vote against NPRR994. The measure, which passed 29-1, clarifies which transmission improvement projects associated with the interconnecting new generation resources should be classified as “neutral” projects, including new substations, and delineates which interconnection facilities are considered before ERCOT performs an economic analysis.

“I don’t think it’s in compliance with the spirit of the original order that established the gen interconnect process at ERCOT,” explained Greer, who also opposed the measure at the subcommittee level. “The process as it has been up until five years ago was run in compliance, but it has moved away from that. … It would restrict a generator’s ability to get their energy out to market.”

The rest of the combo ballot included:

- - NPRR1034: creates a new protocol section (Frequency-Based Limits on DC Tie Imports or Exports) that enables ERCOT to establish import or export limits on DC ties and avoid the risk of unacceptable frequency deviation during an unexpected loss of one or more DC ties during the import/export. Staff will be able to curtail DC tie schedules on a last-in-first-out basis to address this risk.
  - NPRR1040: establishes compliance metrics for ancillary service supply responsibility.
  - NPRR1044: requires generation resources and ESRs to develop and implement subsynchronous resonance mitigation plans to address vulnerabilities in the event of six or fewer concurrent transmission outages, an increase from the current threshold of four or fewer.
  - NPRR1048: changes certain required system-adequacy reports to being aggregated “by forecast zone” instead of being aggregated “by load zone.” Forecast zones have the same boundaries as the 2003 congestion management zones: North, South, West and Houston.
  - NPRR1049: removes the requirement to obtain board approval to add, delete or change a DC tie load zone and also removes the 48-month waiting period before such actions can go into effect.
  - NPRR1050: changes the summer projected commercial operations date deadline from the start of the summer peak load season to July 1.
  - NPRR1051: removes the administrative price floor of -$251/MWh from all day-ahead settlement point prices.
  - NPRR1052: ensures that energy storage systems registered as settlement-only generators will continue to have their injections and withdrawals settled at load zone pricing until nodal pricing for injections and withdrawals is approved and implemented.
  - NPRR1053: establishes an exemption from ancillary service supply compliance requirements for any qualified scheduling entity (QSE) representing an ESR whose ability to charge is restricted during a Level 3 energy emergency alert event. The change also clarifies that the compliance exemption does not impact the QSE’s financial responsibility because of the AS insufficiency.
  - NPRR1054: removes all references to Oklaunion Exemption from the protocols and adjusts the affected sections’ remaining language accordingly. The coal-fired Oklaunion plant was retired in October.
  - PGRR085: adds a requirement for resource entities, interconnecting entities (IEs) and TOs to provide reports benchmarking the power system computer-aided design (PSCAD) model against actual hardware testing and to provide parameter verification documentation confirming model settings match those implemented in the field.
  - PGRR086: clarifies that resource entities and IEs must provide dynamic model data and model-quality tests to complete a full interconnection study application.
  - PGRR087: clarifies that remedial action schemes should not be relied upon to resolve planning criteria violations.
  - RRGRR027: clarifies that resource entities and IEs must provide dynamic model data and model-quality tests to complete a full interconnection study application. PSCAD models should be required before the applicable quarterly stability assessment deadline.
  - SMOGRR024: makes modifications to accommodate telemetered auxiliary load and allows a site to comply with NPRR1020.

January 31, 2021November 6, 2023

MISO Closes Loophole for Late-stage Interconnection Projects

MISO interconnection customers with signed agreements will no longer be able to abandon generation projects without assuming additional financial risk, thanks to FERC’s approval of a new rule.

The commission on Thursday approved a tariff revision that gives MISO the ability to use payments submitted by interconnection customers under generator interconnection agreements (GIAs) to lessen the burden on other interconnection projects, should the latter customers cancel projects after signing the agreements (ER21-525).

MISO said the change has a “narrow and specific goal:” closing a “loophole” that had allowed developers to pull the plug on all-but-certain generation projects without risking additional capital.

Now, instead of transmission owners returning a GIA’s unused payments to interconnection customers terminating generation projects, the funds will go to MISO. The grid operator will determine whether the funds are needed to cover any negative impacts on other projects that entered the interconnection queue at the same time.

The new rule goes into effect Feb. 1, in time for the next round of GIA execution.

MISO said that it previously had no way to compensate the remaining projects for unexpected network upgrade costs incurred when another project canceled its executed agreement.

“These customers have the option to terminate their interconnection after a GIA, and MISO has no milestone fees at that point to mitigate the harm,” MISO counsel Jackson Evans explained to stakeholders last fall during a Planning Advisory Committee meeting.

Under the RTO’s existing milestone-forfeiture process, developers make milestone payments when they enter the interconnection queue. It can then use those funds at earlier points in the process to mitigate the financial harm imposed on the queue’s remaining projects when others are withdrawn. Those rules no longer apply when a project reaches GIA execution, and the milestones become the initial payment to transmission owners.

The grid operator said it wanted to remove any “financial incentive” an interconnection customer might have by waiting until after an executed GIA to withdraw a project.

“The harm caused from one interconnection customer’s utilization of the post-GIA termination loophole also has the potential to impact the larger queue through additional withdrawals,” MISO explained in its filing. “The unmitigated reallocation of costs from one GIA termination could turn a financially viable project into a non-viable project, which may cause a second GIA termination, which may cause further terminations, resulting in cascading terminations and restudies.”

MISO said its plan had the support of “almost all stakeholders.”

The grid operator said it had found recent examples of harm caused by post-GIA project terminations. Using its 2016 and 2017 cycles of project entrants, it said one of three post-GIA withdrawals in the 2016 cycle had a nearly $5.5 million net financial impact on remaining interconnection customers, and one of six withdrawals in the 2017 cycle had an almost $10.5 million impact on other developers. The other withdrawals had no financial impacts.

MISO said FERC has “previously recognized that when an interconnection customer utilizes the post-GIA termination loophole, it has the potential to cause harm to MISO’s administration of the queue.”