Stakeholders last week challenged PJM over use of a “quick fix process” to deal with incorrect capital recovery factor (CRF) values in the Tariff that resulted from federal tax code changes.
At Tuesday’s Market Implementation Committee meeting, Jeff Bastian, PJM senior consultant in market operations, provided a first read of the problem statement and issue charge addressing the value of CRFs used to calculate the avoidable project investment rate (APIR), a component of the net avoidable cost rate (ACR) of a resource.
The net ACR sets a resource’s market seller offer cap as well as the minimum offer price rule (MOPR) floor price, depending on which is applicable to the resource. Attachment DD of the Tariff includes tables of CRF values that resources can use to calculate either figure. The tables were established in 2007 as part of the Tariff.
The Independent Market Monitor notified PJM in a letter Dec. 4 that the CRF values do not reflect current federal tax law. The Monitor said the tables should have been updated in 2018 and must be changed before the next capacity market auction takes place in May. (See PJM Sets BRA for May 2021.)
PJM issued a statement Dec. 7 to members saying it understood the Monitor’s concerns but also appreciated the need for stakeholder input before making Tariff changes. Stakeholders were updated on the issue at the Markets and Reliability Committee meeting on Dec. 17. (See “Capital Recovery Factors,” PJM MRC/MC Briefs: Dec. 17, 2020.)
The RTO has proposed to address the CRF issue as part of a quick fix process in which the MIC simultaneously approves the issue charge and the proposed Tariff revisions at the meeting Feb. 10. It is proposing to update the values of the CRF table in Attachment DD to reflect the tax rates and depreciation provisions of current federal tax law.
Table in Attachment DD of the Tariff of CRF values for resources to calculate the market seller offer cap or the MOPR floor offer price | PJM
The proposed CRF values would become effective with the 2023/24 Base Residual Auction (BRA) scheduled for December, Bastian said. PJM had concerns that seeking an earlier effective date could lead to further delays of the already postponed 2022/23 BRA, with deadlines related to that auction looming this month.
Bastian said PJM is proposing to review CRF values on a schedule consistent with the quadrennial review of key auction parameters.
Paul Sotkiewicz of E-Cubed Policy Associates offered an objection to using the quick fix process to deal with the CRF issue. Sotkiewicz said he didn’t see a need for a “fast-track solution” since PJM is not looking to use the new values in the 2022/23 BRA.
He added that the CRF value calculations lack transparency and that PJM is going from one stated set of values to another “under the guise of changing tax laws.” He said the RTO should provide the formulas and all the inputs used in determining the values.
“I think we need to have a more thoughtful and considered discussion between the members, PJM and the IMM just to provide clarity and transparency,” Sotkiewicz said.
Erik Heinle of the D.C. Office of the People’s Counsel said he shared Sotkiewicz’s concerns about fast-tracking the CRF issue and that the concerns were “very reasonable.”
Heinle also expressed concerned about such a delayed response to a tax law that was passed three years ago, calling it a “collective failure” among PJM and stakeholders.
“I feel like we’re a little bit behind the ball of where the tax code is,” he said.
Bastian said Heinle made “fair points” and added that the CRF value update would have been caught earlier had it been part of the quadrennial review.
Monitor Joe Bowring said the table changes should be fast-tracked — and that the process doesn’t actually require a stakeholder process at all.
“The Tariff is wrong; we’ve known it’s wrong for quite some time, and there’s no reason to leave it wrong,” Bowring said.
He also disagreed with the notion that leaving the table wrong will reduce confusion in the 2022/23 BRA, which he said should also use the updated values. He added that not making the change is likely to increase uncertainty of the outcome of the BRA and could lead to challenges at FERC because the Tariff is “demonstrably wrong.”
MOPR Changes Endorsed
Members unanimously endorsed manual revisions to conform with recent FERC-ordered rule changes in the minimum offer price rule (MOPR) and forward-looking net energy and ancillary services (E&AS) offset calculation.
Bastian reviewed updates to Manual 18: PJM Capacity Market, including two 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 locational marginal pricing.
Table showing the fuel pricing point used for the purpose of establishing the net E&AS offset for each zone | PJM
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.
Bowring said the redline language in Manual 18 did not appear to be consistent with PJM’s statement on the financial accounting statements and added more confusion than clarity on the issue. The FERC order was “a bit ambiguous” about the accounting issue, and it’s unclear how financing could be used in the definition of the life of the asset that hasn’t been financed by a third party (ER20-2046). (See FERC Rejects PJM Stakeholder EOL Proposal.)
Bastian said PJM believes the language is consistent with the FERC order.
“What we’re trying to clarify is that the financial documents are the primary source of evidence, but there are other forms that can be provided,” he said.
The manual revisions now go to the MRC for endorsement at its meeting on Jan. 27.
PRD Credits Disposition
Stakeholders unanimously endorsed a proposed solution package addressing the disposition of price-responsive demand (PRD) credits. In a follow-up non-binding poll, the package received 91% support over maintaining the status quo.
Pete Langbein, manager of demand side response operations, reviewed the Baltimore Gas and Electric proposal addressing the PRD credits disposition issue.
PJM’s settlement rules call for revenues associated with PRD to be credited to the load-serving entity 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. PRD providers represent retail customers that have the capability to reduce load in response to prices. (See “PRD Credits Disposition,” PJM MRC/MC Briefs: Dec. 17, 2020.)
Langbein said an increasing share of PJM’s load is responsive to changing wholesale prices because of the implementation of dynamic and time-differentiated retail rates and utility investment in advanced metering infrastructure. Several EDCs cleared PRD as a capacity resource for the first time for the 2020/21 delivery year.
“At the end of the day, this is all about having the PRD provider actually receive the PRD bill credit,” he said.
PJM plans to submit a filing to FERC by early March and have a response by early May. The RTO intends to settle the issue before it receives PRD registrations. Langbein said the changes will simplify how those registrations are done.
PJM stakeholders last week heard another first read of the RTO’s proposals for mitigating and avoiding critical infrastructure designations under NERC rules, with some members questioning the stakeholder processes that led to the language in them.
Mike Herman of PJM presented a proposal on avoidance at last week’s Planning Committee meeting. PJM had postponed a vote on the proposal at the committee’s December meeting, saying it needed more time to consider language changes in response to a PJM PC/TEAC Briefs: Dec. 1, 2020.)
The commission rejected rehearing requests of its approval in March of planning procedures for transmission projects that mitigate the risk associated with critical infrastructure, as defined by NERC Critical Infrastructure Protection standard CIP-014. Such projects would also allow transmission owners’ existing infrastructure to avoid being designated by NERC as critical.
Herman went through a summary of the proposed changes to Manual 14B and Manual 14F that came out of the Critical Infrastructure Stakeholder Oversight (CISO) special sessions beginning in November 2019. He said that based upon stakeholder feedback, PJM made “slight tweaks” to the redline language.
The changes to Manual 14B include the addition of a new subsection describing the process related to maintaining reliability. It also added “avoidance” to the list of transmission planning activities. PJM also plans to add text to Manual 14F detailing the process by which it may modify a proposal submitted through the competitive planning process. It would also add resilience to the list of reliability criteria evaluated in a proposal window in both manuals.
Sharon Segner, vice president of LS Power, said the Manual 14F language in appears to create resilience criteria without specifically defining it. Segner said the proposal seems like an “end run around” to creating resilience criteria without making changes to PJM’s Operating Agreement, which she said FERC had directed in November.
“The rehearing order from FERC was very explicit that the planning criteria needs to be in the Operating Agreement,” Segner said. “You’re calling this resilience analysis, but at the end of the day, it’s creating standards, and that needs to be in the OA.”
Segner also said she was concerned about the stakeholder process regarding discussion of the package and PJM putting it on the agenda as a first read, when a PC special session scheduled for the week before and designed to examine the proposal language more closely was canceled. Segner said LS Power had materials and edits of the proposal language that she was planning to present at the meeting.
Dave Souder, director of operations planning for PJM, said that if Segner felt the issue required OA language, the RTO would take that into consideration and see if more stakeholder discussion is needed. PJM’s Aaron Berner noted that the OA does not define all the aspects of reliability criteria and that the information is normally detailed in the manuals.
Alex Stern, director of RTO strategy for PSEG Services, disagreed with Segner’s interpretation of FERC’s directive. The commission said, according to Stern, that TOs have not transferred the authority to plan CIP-014 mitigation projects to PJM and that it should not be in the OA for that reason.
But Stern also said he would like to see LS Power’s proposed OA language so that it can be reviewed in advance and considered. “I wouldn’t mind seeing this Operating Agreement language so that we have some time to process it within the stakeholder process,” he said.
Erik Heinle of the D.C. Office of the People’s Counsel said he was confused with the process going forward on the PJM proposal, with the first read being held at the PC. Heinle noted another CISO special session scheduled for Friday and asked if a second “first read” would be held at the committee’s February meeting if there were additional changes or edits to the manual language.
“I just hoped we weren’t getting too far ahead of ourselves with the first read,” Heinle said.
Souder said PJM’s intention is to move forward with the second read and endorsement at the PC’s February meeting. The RTO will take stakeholder feedback on the need for a second first read into consideration, he said.
“We want to make sure whatever product is coming out of the Planning Committee is ready as we bring it to the” Markets and Reliability Committee, Souder said.
After the presentation on avoidance, Herman discussed the mitigation issue with a package of proposals coming out of the CISO. He said OA language is currently under development by PJM for the mitigation portion of the package.
Herman pointed out some of the changes to the language since it was last reviewed at the November PC meeting. (See “Critical Infrastructure Stakeholder Update,” PJM PC/TEAC Briefs: Nov. 4, 2020.)
The major change was the addition of a definition for substation contingency resilience planning criteria: “analyses performed to ensure system resilience based on a study of select substation contingencies, which are based upon TPL-001-4 Extreme Contingency Analysis. The analysis evaluates the loss of load and potential cascade events which may result from power flow analysis. Due to the sensitive nature of the analysis, identified substations and results require confidentiality consistent with established processes and good utility practice.”
“A lot of the meat of this package hinges upon this definition,” Herman said.
Heinle asked if the definition will be included in the final OA language.
Herman said the definition would have to be included for documentation.
Flow chart for “Substation Contingency Resilience Planning” within mitigation efforts for the PJM proposal on future CIP-014 facilities | PJM
Heinle said he would like to see the avoidance and mitigation issues tied more closely together. He said he is concerned that the two “interrelated issues” are going on different rails, with avoidance language in the manual and mitigation language in the OA, which could lead to issues at FERC in the future.
“You can’t really have avoidance and not have a mitigation option as well,” Heinle said. “And you can’t really have mitigation if you don’t first try to avoid the issue.”
On Monday, Segner told RTO Insider that LS Power had provided PJM its proposed OA language and that it will be available for review before Friday’s special CISO session.
TO/TOP Matrix
Mark Kuras, chairman of the Transmission Owners/Transmission Operator (TO/TOP) Matrix Subcommittee, presented proposed changes to version 15 of the TO/TOP Matrix.
The matrix is an index between the PJM manuals and governing documents and NERC reliability standards that are applicable to the RTO as the TOP. It includes a column of “tasks” required by PJM under the documents. Kuras said version 15 of the matrix adds references for reliability standards, including TOP-001-5.
Proposed changes incorporated in version 15 of the TO/TOP Matrix | PJM
Some of the revised tasks include:
COM-001-3 R4.3, which was revised from a comment received from ReliabilityFirst;
TOP-001-5 R9, which added time frames for reporting com equipment outages; and
VAR-001-5 with changes for new eDART voltage schedule reporting.
Kuras said stakeholders will be requested to provide a recommendation to the Transmission Owners Agreement Administrative Committee (TOA-AC) to approve the draft TO/TOP Matrix at the February PC meeting, and the endorsed changes will then head back to the TOA-AC for final approval. He said PJM would like to have the new matrix in place by April.
Texas regulators last week denied complaints by two ERCOT market participants and rejected an administrative law judge’s preliminary decision related to the ISO’s price-correction practices (50871).
DC Energy Texas and Monterey TX, both qualified scheduling entities in ERCOT, alleged last year that the ISO improperly charged them for point-to-point obligations in the day-ahead market at prices exceeding their not-to-exceed bid prices. The ALJ in October ruled ERCOT violated its Protocols when it issued resettlement statements and found that DC Energy and Monterey were entitled to a remedy.
Texas’ Public Utility Commission disagreed. After hearing arguments from both sides during its open meeting on Thursday, it granted ERCOT’s motion for a summary decision.
Monterey’s legal counsel, Valerie Green, argued that maximum prices are the only way market participants can limit their liability in auctions and that they are a fundamental component of the bid. She said DC Energy had committed to pay less than $261/MWh but wound up ultimately being charged more than $44,000/MWh for the same contract path.
ERCOT Senior Corporate Counsel Erika Kane responded that the grid operator followed its Protocols in making the price corrections and that all market participants are aware of the process.
“Just because ERCOT has done it this one way, that doesn’t mean it’s necessarily correct in the Protocols,” Green countered.
The ISO has been forced to make a number of price corrections in recent years because of software or human errors. Most recently, the Board of Directors in October approved price corrections for 25 operating days during 2020. (See “Board Approves 2 Sets of Price Corrections,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)
“I think DAM price corrections is a very apt phrase here,” Commissioner Arthur D’Andrea said.
Texas PUC Chair DeAnn Walker | Texas PUC
PUC Chair DeAnn Walker noted ERCOT had attempted to revise its process for price corrections with a nodal protocol revision request but failed to successfully complete the stakeholder process.
“We may have to address it here because the industry can’t do it out there,” she said. “I really have a problem with this being uplifted to ratepayers who had nothing to do with this. … Every ratepayer in ERCOT is going to have to pay for this mistake, and I don’t think that’s the right answer.”
D’Andrea and Commissioner Shelly Botkin agreed with Walker, with D’Andrea saying the case “raises questions [that] need to be answered at the commission.”
“Efforts to resolve this issue at ERCOT have stalled out,” Botkin said. “It may be time for us to make some policy decisions about how to do these things. Nobody likes price corrections.”
No Approval for Entergy, ETEC Swap
The commissioners decided not to sign off for the time being on a request by Entergy Texas and East Texas Electric Cooperative (ETEC) for approval of two mutually dependent transactions until they can gather more information from the parties (50790).
The utilities want to transfer ETEC’s ownership of the Hardin County Peaking Facility to Entergy in exchange for a minority interest in the latter’s new Montgomery County Power Station that equates to 75 MW of capacity. Montgomery County, a 993-MW natural-gas facility, was energized on Jan. 1.
Entergy’s Montgomery County Power Station | Entergy Texas
If approved, Entergy would pay a little over $36 million for the 11-year-old Hardin facility, which consists of two 75-MW combustion turbines. ETEC would nearly double that by paying $71.1 million for its minority share in Entergy’s unit.
“We have a company giving up ownership in a very efficient, new project to get a less efficient, older project,” Walker said. “I can see what’s in East Texas’ best interest, but I’m not sure how it’s [beneficial] to Entergy.”
The commissioners also expressed their unease with what they said were “side deals” between some of the parties involved. The joint applicants, PUC staff, the Office of Public Utility Counsel and Texas Industrial Energy Consumers filed an unopposed settlement agreement last year.
“This looks more like a straightforward transfer of money,” D’Andrea said. “It’s hard to know. Ultimately, money is flowing from Entergy to ETEC. Entergy has a rebuttal that says, ‘No, this is mutually beneficial exchange.’
“We have to make a public interest finding, and I’m not sure I’m ready to do that,” he said.
The PUC did approve on an interim basis Entergy’s request to update the power plant’s generation cost-recovery rider to reflect the sale of its partial interest. The commissioners agreed to abate the proceeding until either the transaction closes or the utility tells the commissioner it won’t close (51381).
The commission signed off on two other orders involving Entergy. It approved Entergy’s request to establish regulatory accounting treatment for a mark-to-market tax accounting method (51095) and to establish the tax effects of the method’s regulatory accounting treatment (50540) in its existing purchase power agreements.
In other actions, the PUC:
Approved East Texas Electric Cooperative’s request to change its wholesale transmission service rates, setting its recoverable annual cost-of-service revenue requirement at $244,902 (50295).
Allowed Texas-New Mexico Power Co. to upgrade its advanced meter technology for 170,000 meters after its service provider announced it would no longer support the third-generation network (51387).
Granted good-cause waivers of rate-filing requirements to Cross Texas Transmission (51534) and Electric Transmission Texas (51583).
Close COVID-19 Call for D’Andrea
Chair DeAnn Walker was the only commissioner in the room for the PUC’s meeting on Thursday. | Texas PUC
Walker was the only commissioner present in the hearing room for the open meeting, though both D’Andrea and Botkin called in from self-isolation.
D’Andrea quarantined himself “out of an abundance of caution” after being told a family member had symptoms similar to those of COVID-19.
The family member has since tested negative for COVID-19.
FERC last week accepted Tri-State Generation and Transmission Association’s Tariff modifications to its large generator and small generation interconnection procedures (LGIP, SGIP) and its proposed queue reform, effective Jan. 13 (ER21-410).
The commission directed Tri-State to make a compliance filing aligning its reform proposal with the requirements of Order 845. FERC ruled in December that Tri-State was in partial compliance with the order, designed to increase the GI process’ transparency and speed. (See “Tri-State Order 845 Compliance Lacking,” SPP FERC Order Briefs.)
In October, the commission rejected Tri-State’s proposal to transition to a clustered first-ready, first-served interconnection process, saying the approach would help address the G&T’s queue backlog, but that the proposed revisions were not consistent with or superior to the pro forma LGIP.
This time, FERC said in its Jan. 12 order that Tri-State had “sufficiently justified” its proposal. The commission said a transition from a serial first-come, first-served approach to a clustered first-ready, first-served approach “should allow ready projects to proceed on a more accelerated basis while allowing less-developed projects access to early information.”
Tri-State’s headquarters in Westminster, Colo. | Tri-State G&T
Tri-State said it worked with stakeholders to implement FERC’s guidance in its October order. It said that with only a few exceptions, its proposal was identical to queue-reform provisions the commission previously accepted for Tri-State’s neighbors Public Service Company of New Mexico, Public Service Company of Colorado and PacifiCorp.
The association’s proposal established two distinct study processes: an informational interconnection study and a definitive interconnection study. Tri-State said the informational study will decrease the likelihood that early-stage projects will enter the definitive process to assess their viability, while also improving the chances that viable projects will enter the process.
FERC found unpersuasive Invenergy’s argument that interconnection customers’ ability to sink outside of Tri-State’s system negates its justification for improving the queue process’ efficiency.
The commission determined that Tri-State’s proposal to allocate network upgrade costs using a distribution factor analysis is consistent with or superior to the pro forma LGIP. It noted the analysis was developed in consultation with stakeholders and that Tri-State had shown the proposal will allocate upgrade costs to the interconnection customers responsible for triggering the upgrades.
Commissioners Richard Glick and Allison Clements concurred with the decision but expressed separately their concern whether Tri-State’s revised 60-day timeline to meet the transitional procedure’s commercial readiness requirements provide “sufficient time for interconnection customers to meet the requirements.”
They noted that two of the three readiness requirements involve interconnection customers finding a buyer of either resource supply or the entire project within 60 days of the order.
“This window of time could prove to be challenging because Tri-State and its members have been wrapped up in Tri-State’s jurisdictional change for more than a year, with several related proceedings still pending before the Commission,” they wrote. “It is possible Tri-State’s window for readiness demonstration may not fully accommodate the current situation created by Tri-State’s pursuit of commission jurisdiction.”
Tri-State applied for FERC jurisdiction in 2019, saying that it would allow the company to advance member flexibility for more self-supply and local renewable energy development. The commission approved and affirmed the request last year. (See FERC Affirms its Jurisdiction over Tri-State G&T.)
How many committees, working groups, task forces and strike teams are too many?
SPP is about to find out as it balances staff and stakeholder time spent on analysis and studies with the need to adapt to a business environment that won’t stand still.
“The industry we’re a part of is changing so dramatically and quickly that solutions that looked good when you take a snapshot in time … don’t fit as well if it takes two years to implement,” SPP Board Chair Larry Altenbaumer told the Strategic Planning Committee last week.
“We have to deal with ongoing change,” Altenbaumer, also the SPC chair, said during a conference call Jan. 13. “That’s a key consideration when it relates to these kinds of activities.”
Still, the situation has resulted in stakeholders being involved in as many as seven different teams, in addition to their day jobs.
“Richard, I don’t know how you do it,” SPP COO Lanny Nickell said, addressing American Electric Power’s Richard Ross.
“If you don’t look to the future, at some point, you’re never going to get out of the mess you’re in,” Ross responded.
Having wrapped up the Holistic Integrated Tariff Team’s (HITT) year-long study of the footprint’s many challenges, which begat initiatives on energy storage, transmission-cost allocation and congestion hedging, among others, SPP has now embarked on an in-depth evaluation of its transmission planning and applicable cost-allocation processes.
The Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT) is comprised of 16 stakeholder representatives from the board, Members Committee, SPC, Markets and Operations Policy Committee and the Regional State Committee. The team reports to the board and plans to provide updates during the April and July governance meetings. A high-level review of its work is expected to be shared in October. (See “SPC Takes Look at Tx Planning,” SPP Briefs: Week of Aug. 31, 2020).
The Strategic and Creative Re-engineering of Integrated Planning Team’s six sub-teams | SPP
Director Mark Crisson, who chairs the SCRIPT, has divided its members, many of whom are involved in other stakeholder groups, into sub-teams focused on six key areas: consolidation, services, decision quality, transfers (exports/imports), optimization and cost-sharing. Each representative was assigned to two sub-teams, which are scheduled to meet twice a month through at least March. The SCRIPT itself will meet monthly.
“It’s a pretty busy schedule and our teams are busy with many other things,” Crisson said, noting the SCRIPT will meet Feb. 2 to decide whether all the meetings are necessary. “We have to consider the burnout factor here. We’re asking people to do an awful lot by October and evaluate where we are.”
“It’s a lot of meetings and a lot of different ideas,” SCRIPT member Bill Grant of Southwestern Public Service said. “We are tackling a broad spectrum of issues here in a very tight timeframe. I’m concerned whether we get into the details. I hope we can meet [the very aggressive schedule], especially with all the other initiatives going on.”
“The quality of this is so much more important than hitting the deadline,” SPP CEO Barbara Sugg said. “We’ve really got to focus on the quality. This is solving many of the challenges we have.”
Altenbaumer said he hopes the SCRIPT’s members will be able to get their arms around “everything that’s been addressed come October.”
Otherwise, he said, “it opens up a whole stream of things that need to be done. My hopes are the team working on this will come up with a game plan to help us address that moving forward.”
Nexant to Take Crack at Congestion Hedging
SPP has hired the Nexant consulting and software firm to perform a root-cause analysis of discrepancies in the grid operator’s congestion-hedging rules and policy, an issue stakeholders have been unable to reach consensus on.
The analysis will determine the reasons behind the difference between the total value of an entity’s congestion hedge and its day-ahead market position. Nexant is expected to recommend a solution to the SPC that incorporates new or existing measures — or any combination thereof.
The timeline for Nexant’s analysis of congestion hedging | SPP
“We’re looking at creating a clean slate,” said director Graham Edwards, who headed a strike team looking for a path forward on hedging issues.
“Why Nexant? They perform the analysis that is out there to solve this issue,” he said. “They’re the ones that are experts in this particular area of congestion hedging. They’re working with other RTOs and ISOs. They’re familiar with our rules.”
The SPC took up the cause when the Market Working Group was unable to coalesce around 11 different proposals after the HITT recommended adding counterflow optimization (CFO), limited to excess auction revenues, to the RTO’s hedging market mechanism. (See SPP SPC Takes on Congestion Hedging Issues.)
Nexant will work with the MWG and is expected to present its final recommendation to the SPC in July.
“Hopefully, we’ll be successful in drawing conclusions we can all gather around,” Altenbaumer said.
Separately, staff has begun a 2025 future study “to show the strategic importance of having [CFO] in SPP’s congestion-hedging markets.” The study will consider incremental long-term transmission congestion rights’ use in the markets, the NRIS/ERIS Deliverability Task Force’s white paper policy, and the effects of auction revenue rights awards.
SPC Welcomes New Members
The SPC began its first meeting of the year with several personnel changes, including Crisson stepping into the vice-chair’s role. Crisson replaces Golden Spread Electric Cooperative’s Mike Wise, who remains on the committee.
The new members are EDP Renewables’ David Mindham, Evergy’s Kevin Noblet and Oklahoma Municipal Power Authority’s Melie Vincent.
SPP staff last week unveiled a proposed mitigation plan to reduce the four-year backlog in the RTO’s generation interconnection queue, a result of legacy study processes that can take as long as 485 days to complete — and longer if restudies are required.
David Kelley, SPP’s director of seams and tariff services, told the Markets and Operations Policy Committee that staff are currently working on their first cluster of GI requests from 2017 and are soon scheduled to tackle a second set.
“That’s just indicative of where we are,” he said during the Jan. 11-12 virtual meeting.
SPP’s current generation-interconnection process timeline | SPP
“The three-stage process was not designed to get us out of the backlog we’re in,” he said. “We had a four-year backlog when we implemented the three-stage process, and we have it today. We still think the process will take too long to get to that point where we clear the backlog.”
Staff said the problem is that the queue has been formed by interconnection customers with different business purposes: some with a definitive proposal, and others that are simply speculating. Low financial commitments keep speculative customers in the queue, and the uncertainty triggers restudies that extend timelines.
“Left alone, the three-phase process will take too long to eliminate the DISIS backlog,” SPP’s Juliano Freitas said, referring to the definitive interconnection system impact study the RTO uses to cluster GI requests.
The three-stage process involves a thermal and voltage analysis, stability analysis and facilities study. It eliminates feasibility and preliminary queues, changes the amount and timing of security deposits, publishes study models earlier in the process, and allows penalty-free withdrawals when costs increase above certain thresholds.
Juliano Freitas, SPP | SPP
Under the mitigation plan, Freitas said staff will remove the redundant facility study report for SPP and transmission owners and begin the first phase of a DISIS study in parallel with the preceding cluster’s second phase. Staff will also provide better cost estimates for each phase’s first decision point and implement a nonrefundable payment on the TOs’ interconnection facilities cost estimates for the first two decision points.
Freitas said these steps will save about 205 days for each DISIS cycle, beginning with the first 2018 cluster. Assuming a restudy for each cluster, including the two 2017 DISIS groups, he projected SPP would catch up by the end of 2024.
“I like the concept,” Southwestern Public Service’s Bill Grant said. “These queues are so saturated and don’t reflect the actual results of the queue studies.”
Stakeholder discussions have revealed “vastly differing views” as to what success looks like, staff said. Much of the developer community believes the three-phase process should be allowed to work before pursuing additional major overhauls of the GI process, they said, while a number of load-serving members have expressed significant concern with increased generator retirements and the ability to interconnect new generation to meet their service obligations.
“Staff is of the opinion that relying on the three-phase process alone won’t get us out of the hole anytime soon,” Kelley said. “We think success is measured when we reduce and eliminate the study backlog and we’re interconnecting new resources on a timeline that customers expect. It took us many years to get into [the hole], and it’ll certainly take us a while to get out of it. It’s going to take some pretty fundamental changes to the process.”
Staff project they can eliminate the GI queue’s backlog by October 2024. | SPP
Omaha Public Power District’s Luke Haner said he was supportive of SPP’s proposals and urged the RTO to take steps to accelerate the process. “We would like to see serious requests sped up,” he said.
Al Tamimi of Sunflower Electric Power argued against a suggestion that cluster sizes be reduced to speed up the process. “I’m concerned we’re focusing on efficiencies and reducing the backlog, but we would be losing the quality of the studies,” he said. “I feel the quality of the studies need to be measured as you make those changes.”
“If your intention today was to get robust discussion, you got that,” Grant said. “I also heard people say, ‘The status quo is good; let’s work our way through it.’ The status quo is not good. Taking four to five years to get a [GI agreement] when you have load to serve is not acceptable, but I do think we’re on the right track.”
SPP COO Lanny Nickell admitted staff still have some work to do in generating consensus about the mitigation proposals. “For far too long, a majority of our members and stakeholders haven’t understood all the things happening behind the scene,” he said.
Nickell said staff need to further develop the proposal and share it further with stakeholder groups and the Board of Directors before it can begin drafting revision requests and tariff language.
SPP on ‘Cutting Edge’ with ESR Initiatives
SPP continues to grapple with how best to integrate electric storage resources (ESRs), belying at times its traditional “evolutionary, not revolutionary” approach to gaining stakeholder consensus.
The Strategic Planning Committee on Wednesday approved the Electric Storage Resource Task Force’s recommendation to continue developing rules to allow ESRs to participate in the markets as generation resources and transmission-only assets. The idea is to create a foundation for ESRs to eventually perform as multiuse transmission assets.
The task force said stakeholders and staff should complete rules and policies governing ESRs as transmission assets before evaluating their use in providing energy, capacity and ancillary services. Staff should continue to monitor rules being developed by other grid operators and regulatory efforts, it said.
“No RTO has it worked out. In some cases, we’re more on the cutting edge than normal,” Richard Dillon, SPP’s director of market policy, told the MOPC.
He said SPP now has a greater understanding of ESRs’ complexity. “By the same token,” Dillon said, “we don’t want an extremely complicated filing at FERC that gets rejected. We need to take smaller bites, so if revisions are necessary after FERC has seen [the proposal], we don’t take the ship down with one massive filing.”
Dillon serves as staff secretary on the Electric Storage Resources Steering Committee (ESRSC), which reports to the MOPC and is led by its chair, Evergy’s Denise Buffington. The group is responsible for coordinating and overseeing the stakeholder groups working on 37 different ESR-related initiatives spread over six issue categories.
Ten of those initiatives are focused on transmission, energy and capacity issues, work that had been on hold pending the task force’s recommendations. The initiatives encompass how to use ESRs for transmission only, energy and related services, and meeting resource-adequacy requirements. The ESRSC has determined that planning items, reliable-response items (capacity, fast start) and hybrid resources are high priorities.
Dillon said ESRs’ role as a distributed energy resource is out of scope. That issue will be taken up by another task force working on FERC Order 2222.
“If you look through all of the items, what I believe needs to be resolved first is the hybrid resource,” Dillon said. “Those are on our doorstep. We already have hybrid units we’re working around. We already have storage as transmission.”
The committee has engaged SPP’s Project Management Office to help with bundling the initiatives into a comprehensive project. It has also increased its membership to expand its experience and geographic representation, including a yet-to-be named representative from the Dakotas. Among the new members are Southern Co.’s Chase Smith, who chaired the ESR Task Force; Greg Rislov, an adviser to the South Dakota Public Utilities Commission; NextEra Energy Resources’ Matt Pawlowski; and attorney Heather Starnes.
EDP Renewables’ David Mindham complimented SPP on the governance structure, saying it would “bring clarity to the issues.”
“Clarity around these installations is really important for these developers,” he said.
Asked to endorse an ESR-related white paper, MOPC members instead agreed to send the document to the ESRSC and task force for their consideration. The Operating Reliability Working Group (ORWG) drafted the paper, which recommends that SPP manage the charging and discharging of transmission-only ESRs and coordinate any transmission operators’ reliability actions.
“I’m concerned about the arguments of the resources being treated differently without due cause,” the Advanced Power Alliance’s Steve Gaw said.
The committee separately approved two other white papers related to the ESR initiative:
the ORWG’s recommendation that SPP require ESR data for all unregistered behind-the-meter sites so it can determine their overall effect on the grid. The paper also suggests developing minimum ramp-rate requirements and determining the ESRs’ minimum and maximum limits for charging and discharging.
the Transmission Working Group’s (TWG) paper that included a recommendation to use a load-curve analysis to determine the ESRs’ required duration in the planning processes.
PTP Tx Revenue Service Tweaked
Members approved a Regional Tariff Working Group’s (RTWG) recommendation to modify SPP’s point-to-point (PTP) transmission service revenue allocation that essentially leaves the process in place.
Stakeholders have generally agreed that the current process is complex, prone to inaccuracies and lacks transparency. SPP currently splits its distribution of PTP service revenues to TOs 50/50, with half determined by the ratio of the annual transmission revenue requirement and half allocated by a megawatt-mile process.
When some megawatt-mile modeling effects forced the RTO to resettle revenues, engineering staff conducted a review in 2018 that found the process was developed 11 years ago using a source-sink methodology that current staff were unfamiliar with and resulted in more than 1 million combinations in the calculations.
Following a staff presentation on the issue last July, the MOPC directed the RTWG to simplify the process with the TWG’s technical input. (See “Point-to-point Revenue Allocation Sent Back,” SPP MOPC Briefs: July 15-16, 2020.)
However, the group was unable to reach consensus, settling for minor tweaks to the process that leave the status quo in place. The RTWG looked at 10 different options, but all shifted revenue between various TOs.
“So it’s up to staff to simply make it less burdensome?” American Electric Power’s Richard Ross asked.
“That’s fair,” SPP’s Charles Hendrix responded.
“The way I read the literal language, the only mechanism we would be given … would be simply to reduce the number of needed or requested reruns. Revenue shifts would be off the table,” SPP’s Nickell said.
The measure cleared the MOPC’s 67% approval threshold at 74%. Twelve of the 17 TOs and 28 of 36 transmission users voted for the motion.
Order 2222 Task Force Underway
Michael Desselle, SPP’s chief compliance and administrative officer, said the RTO has created a task force to take on compliance with FERC Order 2222, which directs grid operators to allow DER aggregators to compete in their markets. (See FERC Opens RTO Markets to DER Aggregation.)
The 16-person Order 2222 Task Force, comprising a cross-section of stakeholders and two regulators (Arkansas’ Ted Thomas and Missouri’s Scott Rupp), will be responsible for developing and approving policies and governing document changes to comply with the order. Evergy’s Grant Wilkerson will chair the committee, Desselle said.
SPP’s Order 2222 Task Force team members | SPP
The group has an ambitious schedule of 14 meetings over the next six months in order to meet FERC’s July 19 compliance deadline. SPP will propose a “reasonable implementation date” in its filing.
The task force will evaluate 10 policy issues, which include establishing minimum size requirements for DER aggregations that don’t exceed 100 kW.
Coming Soon: Order 1000 Task Force
MOPC Chair Buffington and Nickell, the committee’s staff secretary, are working to provide a “game plan” for yet another task force, this one charged with improving SPP’s Order 1000 selection process.
SPP followed a similar process after approving its first competitive project in 2016. In October, the RTO’s Board of Directors approved an industry expert panel’s (IEP) recommendation to grant SPP’s second competitive project, the 75-mile, 345-kV Sooner-Wekiwa project in Oklahoma, to Transource Missouri. (See Transource Tapped for SPP’s 2nd Competitive Tx Project.)
Staff in December reviewed with stakeholders initial suggestions to improve how it awards competitive transmission projects. The suggestions focused on the continued use of incentive points for future projects; whether to share with project bidders how the IEP will score proposals; and developing and publishing standardized scoring guidelines. (See SPP Out to Improve Competitive Tx Selection.)
“Those will be the conversations we have going forward,” SPP’s Ben Bright said. He noted that SPP has begun accepting applications for the pool of experts from which the IEP is formed to review competitive construction proposals in 2021. “We always need new experts.”
Buffington Lays out Goals
MOPC Chair Denise Buffington, Evergy | SPP
Buffington marked her first meeting as chair by outlining her goals, which include increasing stakeholder engagement in a committee that has grown to 104 members representing 10 sectors across 14 states.
“We’re excited there’s growth in SPP, but we’re interested in hearing new voices and ideas in our discussions,” she said. “We want to encourage new ideas to challenge traditional thoughts.”
Board Chair Larry Altenbaumer applauded the MOPC’s “diversity initiative,” saying he is “looking forward to hearing what comes out of that.”
2 HITT White Papers on Consent Agenda
The MOPC unanimously approved a consent agenda that included a pair of white papers stemming from the Holistic Integrated Tariff Team’s work.
The Market Working Group recommended approval of its white paper on offer requirements for variable energy resources in the day-ahead market. The study found wind resources’ effect on price divergence are largely dependent upon the offer behaviors … exhibited in the [day-ahead market] from both a financial and physical offer perspective.”
The MWG also combined with the ORWG and TWG on a second white paper that urged SPP continue supporting dynamic line ratings’ implementation and use, as they remain voluntary at the TO’s discretion.
The agenda also included the Project Cost Working Group’s recommendation for a $25.6 million cost reduction to SPS’ Multi-Hobbs-Yoakum 345/230-kV project in West Texas and a $5.1 million cost increase to an 230/115-kV SPS network upgrade north of Amarillo; withdrawal of RTWG RR334, which included the 20-year Integrated Transmission Planning assessment (ITP20) as an eligible study for determining competitive upgrades; and six revision requests:
MWG RR429: corrects and/or clarifies existing Market Monitoring Unit language in the Integrated Marketplace protocols. The changes do not change functionality or policy and do not require tariff adjustments.
MWG RR433: updates tariff and protocol language by replacing references to the jointly owned combined resource option that no longer exists under MRR266.
RTWG RR417: clarifies that no projects can be approved for construction from ITP20.
RTWG RR436: removes all facilities associated with an interconnection study preceding the Integrated System’s 2015 membership in SPP. Following the system’s integration, SPP completed a study that resulted in different network upgrades.
Staff RR424: removes duplicate language currently located in the system operating limit methodology.
TWG RR434: modifies outdated tariff language that is not consistent with current processes, including clarification that aggregate transmission service studies are now a six-month process.
A Western resource adequacy program proposed by the Northwest Power Pool could require state regulators and utilities to relinquish some control over their integrated resource planning (IRP) processes, according to a report discussed in a webinar Friday hosted by the Western Interstate Energy Board.
The biggest impacts would be on RA targets and resource capacity credits, while load forecasts and transmission expansion would also be affected, researchers at the Lawrence Berkeley National Laboratory, the University of Texas and WIEB concluded.
Resource capacity credits allocate values to categories of generation. If a regional RA entity and its members were to assign different values to wind and solar power, for example, the conflicting assessments could undermine Western RA efforts, researchers said. Local planners would have to defer to the regional entity in the case of disagreements.
“There should be a regional resource capacity accreditation process that would create capacity credits for different variable resources or, in general, all the resources,” Juan Pablo Carvallo, the report’s lead author and senior scientific engineering associate at Lawrence Berkeley, said.
The footprint of Northwest Power Pool, in blue, covers eight states and two Canadian provinces. | NWPP
States would also have to defer to a regional entity to establish RA planning targets, he said.
If states wanted to be “super adequate” and have stricter RA criteria than a regional body “that would be perfectly fine … [but] it would be particularly problematic if it was the other way around. If some state, for some reason, had a lower reliability target than the regional level, that would create numerous problems,” Carvallo said.
The report, titled “Implications of a regional resource adequacy program on utility integrated resource planning: Study for the Western United States,” elaborated on the conclusion.
“States have historically assigned different capacity credit factors for similar resources — especially for wind, solar and demand response — which may create friction among members if some states recognize higher or lower capacity than others for similar resources,” it said.
“This report finds that for an efficient and effective operation of a regional RA program, states in the footprint will need to defer to the program’s definitions of resource adequacy targets … and resource capacity accreditation. States would effectively surrender control over those two assumptions and let the regional program define them,” it stated. Members of a regional RA program would also have to find ways to coordinate load forecasts and transmission planning instead of going it alone.
“These elements could continue to be developed by the [load-serving entities] under state IRP mandates, but coordination of input data, modeling assumptions and outcomes will be needed with the regional RA program,” the report said.
A regional entity could establish transmission plans from the top down or compile a larger plan from local planning efforts, Carvallo said.
NWPP launched its RA effort in 2019 after studies showed the Pacific Northwest could start to see resource shortfalls as soon as 2020 or 2021. As designed, the program would be voluntary but could impose mandatory RA requirements on entities that join to avoid LSEs “leaning” on the program to meet their own RA requirements.
NWPP’s sprawling footprint covers eight Western states and two Canadian provinces, meaning the RA program could potentially govern much of the Western Interconnection except for Arizona, California and New Mexico. (See NWPP RA Effort Quickly Ramping Up.)
The Northwest, California and other parts of the West face tightening supply caused by the retirement of coal plants and a greater dependence on wind and solar resources. Those conditions contributed to California’s energy emergencies last summer including rolling blackouts in August, and CAISO to Focus on Resource Adequacy in 2021.)
“Monitoring and maintaining RA is becoming increasingly complex and challenging due to plant retirements, higher penetration of variable renewable energy resources and COVID‐related load fluctuations that translate to higher uncertainty on the amount of generation that will be available during periods of peak demand,” the report, funded by the U.S. Department of Energy, said.
“This paper is primarily aimed at state regulators, public utility commission staff and resource planners from states in the NWPP footprint that are pondering how their IRP guidelines and regulations may need to adjust to operate jointly with a regional RA program,” it said.
“SPP is an interesting case study for this paper, because many LSEs in its footprint are required to conduct IRP while also complying with SPP RA requirements,” the report said. SPP and its members generally have been able to communicate and reach agreement on the types of issues that will likely arise in NWPP’s program.
“Ongoing work among states lead to consensus even when there were initial disagreements on a range of topics,”
the report said. “This relationship has made [local] IRP and SPP guidelines naturally follow each other as evidenced from IRP reports and statutes.”
LSEs, for instance, tend to defer to SPP on transmission planning because they “do not want to be redundant, and they inherit in their IRPs many of the assumptions coming out of the transmission planning process from the Southwest Power Pool,” Carvallo said.
The report said the “SPP experience shows that load forecasting can be left to the member entities in the regional program provided that they develop and share forecasts with standardized statistical characteristics.”
“Ultimately, interviewees from public utility commission staff from SPP states indicated that LSEs have an incentive to develop IRP assumptions that are consistent with SPP’s in order to fulfill their membership duties,” it said.
In the NWPP RA program, the report said, “LSEs should be able to develop NWPP‐aligned forecasts as part of their IRP processes and benefit from the public stakeholder engagement as long as IRP regulations in the NWPP states are based on a broad and flexible set of principles.”
New York University’s State Energy and Environmental Impact Center released a new report on Thursday that recounts actions that state attorneys general took to mitigate the Trump administration’s weakening of regulations on energy, climate and the environment.
The report details measures by state AGs on clean energy, environmental justice and addressing per- and polyfluoroalkyl substance (PFAS) contamination. It also focuses on maneuvers in federal agency rulemaking processes and in court that prevented the administration from cementing its climate and energy policies and reversing regulatory protections for air, waters, wildlife, public lands and public health.
‘Strong Defense’
According to the report, state AGs worked together to prevent political appointees to EPA and the departments of Energy and the Interior from freely shunning rulemakings, delaying compliance deadlines and ignoring statutory directives from Congress.
“Putting up a strong defense has always been the focus of our work during this reckless administration,” Massachusetts AG Maura Healey said.
The AGs said they worked to uphold obligations to address power sector carbon emissions and keep auto emissions reductions on track. They sought to prevent unlimited methane emissions from the oil and gas industry and defeat the Department of Energy’s push for a bailout of the coal industry.
Clockwise from top left: Stephen Read, State Energy and Environmental Impact Center; Maryland Attorney General Brian Frosh; Connecticut Attorney General William Tong; Massachusetts Attorney General Maura Healey; and Oregon Attorney General Ellen Rosenblum. | State Energy and Environmental Impact Center
“The Trump administration has spent the last four years doing the bidding of the fossil fuel industry, from rolling back limits on greenhouse gas emissions that undermine clean car standards to opening up protected areas to oil and gas drilling,” Healey said.
Oregon AG Ellen Rosenblum said that when the Trump administration took aim at California’s carbon cap-and-trade market with Quebec in 2019 with a lawsuit, her state joined more than a dozen others to defend the agreement. The Department of Justice alleged that California’s voluntary agreement with Quebec violated two rarely invoked constitutional provisions, the Treaty and Compact Clauses. In two opinions in March and July 2020, a federal district court rejected DOJ’s claims, noting that the California-Quebec agreement did not represent a “treaty” within the Constitution, nor did it rise to the level of a “compact.”
“The court saw right through the administration’s claims and rejected them outright,” Rosenblum said.
Maryland AG Brian Frosh said the Trump administration’s “zeal to prop up the fossil fuel industry caused them to embark upon a climate destruction program.”
“They refused to enforce and attempted to overturn dozens of rules that protect our climate and, not incidentally, our air and water,” Frosh said. The administration “tried to lift pollution caps on cars, trucks, industries, utilities, landfills [and] oil drilling. They have overridden the findings of scientists; they’ve ignored the opinions of experts.”
‘Collective Action’
In 2018, Connecticut AG William Tong and New York AG Letitia James sued EPA for its failure to meet its obligations under the Clean Air Act’s “Good Neighbor” provision, which requires action against upwind pollution sources that prevent downwind states from meeting required air quality standards under the National Ambient Air Quality Standards.
“Unfortunately, under the Trump administration, we’ve seen an aggressive, systematic effort to dismantle these basic protections,” Tong said.
The suit successfully found that EPA missed its deadline to promulgate federal plans to address upwind pollution and ordered the agency to do so by early December 2018.
When EPA responded with a rule that fell short of its CAA obligations, state AGs took the agency to the D.C. Circuit Court of Appeals and won. Tong, Healey and three other state AGs sued EPA again for dragging its feet and won again in July 2020, as the court cited the agency for its “failure to take immediate action.” The court gave EPA a March deadline to promulgate plans to reduce ozone emissions from upwind states. The AGs said the final rule will help protect millions of residents of downwind states from exposure to smog and other pollutants that cause asthma, lung damage and other respiratory harms.
Tong said the state AGs actions are “vindicated by core constitutional principles.”
“The environment, and our collective action on the environment and protecting the climate is in large part why we have a federal government because the federal government is there to help us accomplish the things as states that we cannot effectively do by ourselves,” Tong said.
PJM stakeholders unanimously endorsed a proposal to sunset the System Restoration Coordinators Subcommittee (SRCS), which was originally created in 2012 but has not met since February 2019.
Brian Lynn, PJM senior trainer, reviewed the proposal to sunset the SRCS during last week’s Operating Committee meeting. Stakeholders first discussed the proposal last month at the OC and adopted it by an acclamation vote. (See “SRCS Sunset Proposal, SOS Charter Review,” PJM Operating Committee Briefs: Dec. 3, 2020.)
Lynn said PJM acknowledges that all SRCS responsibilities are important and will continue to be supported by other groups in the RTO. He said the sunset of the SRCS will reduce duplicative work and meetings as the subcommittee has become less efficient since it was first created.
PJM control room | PJM
“We’re not asking the SRCS to be sunset due to its responsibilities somehow becoming obsolete or unimportant,” Lynn said.
The SRCS previously uniquely addressed responsibilities in PJM including administering, coordinating and debriefing restoration drills conducted within the RTO’s footprint. The subcommittee also served as a focal point for system restoration related issues like recommendations for changes to Manual 36 and the overseeing of the annual review of each member company’s restoration manual.
Lynn said the Dispatcher Training Subcommittee now handles the coordination of drills. SRCS communications related to COVID-19 drills were directed to the DTS because the group was “more effective” at handling them, he said.
The System Operations Subcommittee (SOS) currently handles system restoration related issues, Lynn said, including Manual 36 changes. And the PJM transmission operations department conducts the annual restoration manual review with members.
PJM received no feedback from stakeholders after the first read of the SRCS sunset proposal in December. Lynn said PJM will add a bullet point to the DTS charter clarifying that it will assume drill organization. He said the charter change will be introduced at the OC in February.
Members also unanimously endorsed minor changes to the SOS charter. Paul Dajewski, senior lead reliability engineer for PJM, reviewed the proposed charter update.
Dajewski said PJM removed the reference to the SRCS because of the sunset proposal. The changes also include referring to “user groups” as “forums” and the addition of the eDART XML Forum as a group established to assist the SOS in carrying out its responsibilities and make monthly reports to the subcommittee.
Manual Endorsements
Three manual updates resulting from the periodic review were unanimously endorsed by stakeholders.
Kevin Hatch of PJM reviewed Manual 12: Balancing Operations changes. The changes included updating the out-of-date two settlement terminology to day-ahead market terminology in the markets database application and adding references to the Dispatch Interactive Map Application and reliability assessment and commitment tool in Section 2.1.2: PC Applications.
Hatch also reviewed Manual 13: Emergency Operations changes. Those changes included an updated note in Section 2.2: Reserve Requirements increasing the proportion of contingency reserves that can consist of interruptible load from 25% to 33%. In Section 5.4: Post-Contingency Local Load Relief Warning, detail was added to the members action section requiring transmission owner dispatchers to check the PCLLRW application to ensure that no PCLLRW statuses are deficient.
“We wanted to make sure our procedures align with what the expectations are,” Hatch said. “Our operators coordinate back-and-forth together as more load needs to be selected.”
Liem Hoang of PJM reviewed Manual 38: Operations Planning changes. Hoang said minor grammatical changes were made throughout the manual, and references were added to Manual 3B: Transmission Operating Procedures to replace the Manual 3 references. (See “Manual 3 Update Prompts Questions,” PJM Operating Committee Briefs: March 12, 2020.)
Manual 40 First Read
Michael Hoke of PJM reviewed Manual 40: Training and Certification Requirements updates during a first read. Hoke said the update is part of the periodic review, and only one change was identified.
In Section 3.2.1: Transmission Owner Operators, a reference was added to the annual training requirements referenced in NERC standards. A second reference was added regarding using the PJM Learning Management System to track the annual task training requirement.
Hoke said the change was based on feedback from ReliabilityFirst on the TO/TOP matrix, which expressed a desire to “see a more explicit connection” between Manual 40 and standard requirements in the matrix for TOs.
The OC will be asked to endorse the updates at its meeting on Feb. 11.
Paul McGlynn of PJM provided an update on the RTO’s operations plan responding to the evolving COVID-19 pandemic.
McGlynn said PJM had its first group of dispatchers move back into sequestration on campus shortly after the December OC meeting. Several factors were considered in the decision, including rising infection rates in Pennsylvania and a concern for an even greater surge in cases around the Thanksgiving and Christmas holidays.
PJM’s plan for sequestering staff includes keeping dispatchers on campus for one month at a time and then rotating a new group of dispatchers into sequestration. McGlynn said staff are tested for the virus and then must isolate themselves in their homes before coming onto the campus for the sequestration.
McGlynn said when dispatchers were sequestered in the spring, the entire control room staff were kept on campus for two months instead of rotating in new staff after a month. The current staff in sequestration will remain there until early February, McGlynn said.
“There were a lot of details we needed to think through to rotate staff this time, but all of that has proceeded smoothly,” he said.
President-elect Joe Biden should avoid the mistakes President Barack Obama made in attempting to reduce greenhouse gas emissions, a panel of environmental law experts said last week.
Georgetown University law professor Lisa Heinzerling said Biden should reconsider the White House’s role in reviewing regulations by the EPA and others.
“In my view, the Obama administration lost precious time … by delaying, weakening and stopping agency rules,” Heinzerling, a former EPA adviser, said during a panel discussion Thursday by the C. Boyden Gray Center for the Study of the Administrative State at George Mason University.
Clockwise from top left: Gene Grace, American Clean Power Association; Adam White, C. Boyden Gray Center; Jonathan Adler, Case Western Reserve University School of Law; and Lisa Heinzerling, Georgetown University Law Center | C. Boyden Gray Center
If the Office of Management and Budget’s Office of Information and Regulatory Affairs (OIRA) does review agency rules, it should do so quickly and provide the agencies clear rules for appealing its decisions, Heinzerling said.
“Let the head of the EPA actually be the head of the EPA, not the aides in the White House. Not the OIRA head. Not the economic advisers; not the new climate czar. … I think that will be the key to getting work done quickly,” she said. “It can seem right now in the beginning of the administration that four years is a long time. It’s not.”
But Jonathan Adler, professor at the Case Western Reserve University School of Law, said OIRA can help ensure EPA’s regulations are written in a way to withstand court challenges.
As an example, he said tightening National Ambient Air Quality Standards (NAAQS) on ozone and particulate matter could produce large reductions in carbon emissions.
Jonathan Adler, Case Western Reserve University | C. Boyden Gray Center
“One value of having OIRA involved in the process, if the right people are there, is to make sure that when EPA is tightening the NAAQS standards, even if carbon reductions are part of the reason why EPA’s really doing it, EPA is sure to give a justification that [uses] the traditional rationales for NAAQS standards setting — because that’s what the courts are going to want to see — even if we all know there’s some great carbon gains here too.”
“There is some legal risk” in seeking to capitalize on the co-benefits, Adler acknowledged. “But it’s less legal risk than going straight at greenhouse gas emissions.”
Clean Energy Standard vs. Clean Power Plan, Carbon Price
Adler and Heinzerling agreed, however, that the new administration should not attempt to revive the Obama EPA’s Clean Power Plan, which was stayed by the Supreme Court before it was formally abandoned by the Trump administration. The CPP would have set state targets to reduce carbon emissions from electricity generation by 32% from 2005 levels.
With the U.S. Senate split 50-50 between Democrats and Republicans, Vice President-elect Kamala Harris can cast the tiebreaking vote to pass a budget reconciliation bill. But the Democrats are short of the 60-vote majority needed to prevent other legislation from falling to filibusters. That means Biden will need to rely largely on his executive powers to try and meet his campaign proposal to eliminate power sector carbon emissions by 2035, panelists said. (See Dems’ Senate Gains Raise Hopes for Biden Agenda.)
“I think a Clean Power Plan 2.0 is incredibly high risk,” Adler said. “The Supreme Court before did not seem too enamored of the Clean Power Plan. It’s likely to be even more hostile today.”
Heinzerling noted that the Supreme Court did not issue an opinion on the CPP, which some critics said was illegal for going “beyond the fence line” in forcing carbon reductions at generating plants. Harvard Law School professor Laurence Tribe has said the rule violated the “non-delegation doctrine” — that EPA lacked authority to regulate those sources at all.
“So we don’t know why it went down, and I think it would be risky to try it again,” said Heinzerling, the lead author of the winning briefs in the Supreme Court’s Massachusetts v. EPA ruling, which held that the Clean Air Act gives EPA the authority to regulate GHGs. “As to what do you have to lose? You have to lose all that time in an administration committed to doing something about climate change. You just can’t spend that amount of time, resources, political capital and everything else on something that’s going to be a loser.”
The filibuster is not the only obstacle to Biden’s climate ambitions. “I think even getting 50 votes so that the vice president can cast the tie-breaking vote will be a challenge in some of these areas because I’m not sure that senators like Joe Manchin [(D-W.Va.), the incoming chair of the Energy and Natural Resources Committee,] are always going to be on board,” Adler said. “I think this administration is going to spend a lot of time focusing on the use of fiscal instruments, use of spending authority as a way of advancing environmental policy especially in the climate area.”
Adler said Biden has an opportunity to build a coalition “where you’re spending on infrastructure that a lot of folks on the right want, but you’re also doing it in a way that deals with some of the equity and justice concerns … and also focused on lower-carbon, lower environmental impact infrastructure and facilitating transitions away from carbon-emitting fuels.”
Gene Grace, American Clean Power Association | C. Boyden Gray Center
Gene Grace, general counsel for the American Clean Power Association (formerly the American Wind Energy Association), said that while Biden is unlikely to win legislation enacting a carbon tax, “things like a Clean Energy Standard do seem to be building bipartisan support and something that more Democrats like Manchin and others might be able to get behind — and Republicans as well. You need to probably get over the 60[-vote] threshold if you’re going to do that.”
Biden’s climate plan pledges to “scale up best practices from state-level clean energy standards,” which require that a certain percentage of retail electricity sales come from non- or low-emitting sources. He is expected to announce the U.S. will rejoin the Paris Agreement on climate change on Inauguration Day.
Adler said he believes a carbon tax could be adopted through budget reconciliation, without needing a 60-vote majority.
“I think if it’s pitched right and phrased right, there is more potential support for that among at least some Republicans than people sometimes think,” he said. “And if the choice is that or giving EPA more authority to pressure states to regulate [and] more authority to go sector by sector and impose regulatory standards, I think there are a lot of folks who view the use of fairly straightforward fiscal tools … as less intrusive to liberty [and] less bureaucratic. And I think [it is] of particular significance in the context of climate change in particular, the sort of things that can actually be adopted and implemented far more rapidly than the regulatory alternatives.”
Reversing Regulations, Rebuilding EPA
The new administration needs to rebuild the morale and expertise at EPA following the departures of many staffers under President Trump, Heinzerling said, noting the agency’s budget is more than $1 billion less than it was 10 years ago.
She cited Trump’s appointment of those with industry ties to scientific advisory panels and EPA’s rule on scientific transparency, which she said was intended to discourage the agency “from relying on foundational scientific studies showing a link between particulate matter pollution and human health.”
Heinzerling also criticized a rule excluding “co-benefits” from cost-benefit analyses and a final rule published Wednesday that creates barriers to regulating GHG emissions from sources such as oil refineries or steel plants. The rules say an industrial sector that contributes less than 3% of total U.S. emissions is not a “significant” contributor under the Clean Air Act.
Lisa Heinzerling, Georgetown University | C. Boyden Gray Center
“The outgoing leadership in EPA has broken a lot of things and left quite a mess, and they’re running through the tape; they’re issuing rules without the 30-day waiting period that normally accompanies rulemaking. They’re issuing final rules … without proposed rules,” Heinzerling said.
The good news, she said, is that many of the Trump rules can be reversed because of the administration’s “‘cavalier-ness’ toward law; toward science; toward legal process.”
Adler said it will take a long time to reverse Trump administration regulations regarding the National Environmental Policy Act. “But it would not take very long, necessarily, to adopt guidances on how to interpret those regulations, particularly as they apply to climate change.”
Congressional Democrats also are expected to use the Congressional Review Act (CRA) to reverse some regulations that were finalized in the final weeks of the Trump administration. “But there will have to be some choices about how to use it because it takes up floor time in the House and Senate, and that floor time will be a precious commodity for the budget; perhaps for an impeachment trial; perhaps for other matters,” Adler said.
He cited an analysis by George Washington University’s Regulatory Studies Center that found more than 1,300 final regulations that could be subject to the CRA, including about 200 on environmental policy.
FERC’s Role
Grace said FERC “will be critical for fast tracking the time in which clean energy can be deployed to meet the 2035 Biden climate targets.”
“Even under the Trump administration, work has already been done at [FERC] to drive carbon pricing in wholesale energy markets and ensure that transmission can deliver the amount of clean energy needed to meet climate goals,” Grace said. (See Wide Support for FERC Carbon Pricing Statement.)
“Incorporating carbon pricing into the energy markets really can go a long way to help facilitate something like the Clean Energy Standard at the federal level [and make it] more cost effective. It really [should not] be underestimated how much FERC can play a role in this process.”
He added a hope that under Democratic control, FERC will reverse its policy imposing price floors for state-subsidized renewables, such as the minimum offer price rule in NYISO Explores Improving BSM Processes.)
Grace said future infrastructure and economic recovery legislation “could offer opportunities to enact modest clean energy programs.”
Adler noted that the Justice Department’s Office of Legal Counsel recently issued a memorandum positing that the White House may impose regulatory review requirements on independent agencies such as FERC.
Citing a commentary by Sally Katzen, who served as OIRA administrator under President Bill Clinton, Adler said that the Biden administration “should embrace this and use this as a way of forcing agencies like FERC, the [Securities and Exchange Commission] [and] the [Commodity Futures Trading Commission] to incorporate climate change and environmental justice … into their policy development process.”
