A group of Connecticut lawmakers urged ISO-NE last week to take action in the wake of the Supreme Court’s June 30 ruling barring the EPA from requiring generation shifting to reduce carbon emissions. (See Supreme Court Rejects EPA Generation Shifting.)
In a letter to CEO Gordon van Welie, the legislators asked ISO-NE to “move more aggressively to adopt market reforms that will increase our reliance on renewable energy sources and establish carbon emission standards for power plants.”
The letter is the latest development in the continuous back and forth between ISO-NE and the New England states over the right approach and appropriate jurisdiction for greening the region’s electricity markets. (See NE States, ISO-NE Start to Wrestle with Next Steps on Pathways.)
The Connecticut lawmakers pointed to work they’ve already done as a state, such as power purchase agreements, and a region, such as the Regional Greenhouse Gas Initiative, but said it’s not enough.
“The Supreme Court’s decision puts the ISOs and RTOs in the driver’s seat when it comes to shifting how this country procures energy,” the letter says. “The time to act is now. And it is our hope that ISO-NE will be our partners in that process.”
The letter was led by House Majority Leader Jason Rojas (D) and Energy and Technology Committee Chair David Arconti (D), with 44 other state representatives signing on.
NYISO on Monday filed a request with FERC for a 90-day extension of the Aug. 16 compliance deadline for Order 2222 and a separate request for clarification or rehearing regarding the order’s requirements for operating reserves (ER21-2460).
In response to NYISO’s original compliance filing, the commission June 17 directed the ISO to make more than 30 tariff revisions related to utility opt-in provisions and interconnection procedures, and to propose an effective date in the fourth quarter. (See FERC Partially Accepts NYISO Order 2222 Compliance.) Issued in September 2020, Order 2222 directed all commission-jurisdictional RTOs and ISOs to revise their tariffs to allow participation of distributed energy resource aggregations in their markets.
“Several of the required tariff modifications are extensive, require significant resources to develop and time to coordinate with the appropriate stakeholders,” the ISO said. It said it must work with New York’s distribution utilities to develop protocols that can be consistently applied by each utility, evaluate the burdens of the proposal against other options and work with stakeholders to resolve any outstanding concerns.
Extending the compliance filing deadline to Nov. 14 would result in rules that are fully compliant with Order 2222, the ISO said.
NYISO initially planned to implement its DER participation model, devised independently by the ISO in 2019, by the fourth quarter. But it “has faced several challenges in developing the databases, workflows and software automation necessary for DER implementation,” it told FERC. “The complexity of the software, combined with staffing resource limitations, has led to significant delays to the 2019 DER project, which impacts the NYISO’s ability to move forward with designing and developing the software necessary for compliance with Order No. 2222.”
Heterogenous Aggregations
NYISO also requested clarification or, in the alternative, rehearing of a specific directive in FERC’s June 17 order that addresses the provision of ancillary services by heterogenous DER aggregations — those consisting of different types of resources.
FERC had said that “so long as some of the DERs in the aggregation can satisfy the relevant requirements to provide certain ancillary services … we find that those DERs should be able to provide those ancillary services through aggregation.” It directed NYISO to file a proposed effective date “by which it will allow DERs in heterogeneous aggregations to provide all of the ancillary services that they are technically capable of providing through aggregation.”
NYISO argued that the directive would require it to incorporate the operation of individual DERs into its real-time commitment and dispatch solution in a manner that is inconsistent with the accepted parts of its DER market design.
That could also compromise reliability, as it would require the ISO’s “real-time commitment and real-time dispatch to solve a host of new constraints” and “could delay the timely posting of real-time dispatch instructions,” it argued.
NYISO said its accepted DER market design does not require it to consider the operational status of each individual DER; instead, it is the aggregator’s responsibility to dispatch its set of DER consistent with the composite offer it submits for the aggregation and the instructions the ISO issues to the aggregation.
VALLEY FORGE, Pa. — PJM’s Operating Committee last week conducted a second first read on RTO and Independent Market Monitor proposals to address the management of remaining run hours for coal and other generating resources limited by fuel shortages or environmental restrictions.
The proposals would change PJM operating procedures for generators in “maximum emergency” status, used to conserve remaining run hours.
Manual 13 currently limits generators on maximum emergency status to a 32-hour remaining run time for steam units, and 16 hours for combustion turbines.
Denise Foster Cronin, representing the East Kentucky Power Cooperative, which owns the coal-fired H.L. Spurlock Station near Maysville and John Sherman Cooper Station near Somerset, said 32 hours is not sufficient. “PJM needs more flexibility than current rules provide,” she said during the meeting Thursday.
The session featured a briefing on the current coal supply shortage on behalf of EKPC and America’s Power. Seth Schwartz of Energy Ventures Analysis showed slides illustrating a 200 million ton drop in coal burn in the U.S. from 2018 to 2020, a reduction of one-third, before rebounding by 65.6 million tons in 2021.
In PJM, coal plant capacity factors dropped from 70% to 33% between 2007 and 2020 before jumping to more than 45% in the first quarter of 2022.
Many coal plants are dispatched after gas combined cycle plants and are run for reliability, Schwartz said.
The uncertainty makes it difficult for coal plants to maintain adequate fuel inventories. Coal suppliers need longer-term contracts to support investments to increase production, Schwartz said, and railroads often require annual contracts with take-or-pay penalties.
PJM’s Chris Pilong said resources in maximum emergency status are not excused from performance assessment intervals.
The RTO proposed allowing coal units only to qualify for maximum emergency with between 32 and 240 remaining run hours. Use of the status would be barred under hot or cold weather alerts, or when conservative operations have been declared. PJM also could deny use of maximum emergency for “any reason,” including potential thermal or voltage violations, black start concerns or extreme weather.
PJM proposed notifications be made via eDart and Markets Gateway with verbal notification to generation dispatch. “Dispatchers are looking at a lot of data,” Pilong explained.
David “Scarp” Scarpignato of Calpine said it could be “overkill” to require the notification in so many different channels, with the risk that one might be missed.
“We don’t want to create a compliance trap,” Pilong said.
Monitoring Analytics’ Joel Luna offered the Independent Market Monitor’s alternative proposal, saying “we don’t want to expand ‘MaxE’ without some consequences.”
The Monitor’s proposal would create a new availability status for “fuel conservation.” That would allow any committed capacity resource with 10 days or less of inventory that does not qualify for the maximum emergency fuel limit (e.g., not beyond the owner’s control, not a temporary interruption, not the result of limited on-site storage) to be made unavailable for economic dispatch.
The catch: Units would forfeit their daily capacity revenues during that status.
Luna said the new availability status is needed because PJM’s proposal doesn’t change the requirement that the maximum emergency status be the result of physical causes.
“The disruption in the coal market, those are not physical events,” Luna said. “Those are decisions plant owners make based on the future. We don’t think it warrants the current definition of MaxE.
“We believe our option is better. … Otherwise we still have the same situation with MaxE being driven by physical events — bridges, barges — not a contractual, procurement decision. This allows both PJM and the market seller to allocate that energy when it’s needed the most,” Luna said.
Becky Robinson of Vistra asked whether units under the IMM’s option would see their equivalent demand forced outage rate (EFORd) reduced for future capacity auctions. “If we’re not doing that, we’re pretending we have more capacity than we do.”
“That’s a really good point, on how to represent these megawatts in the future,” responded Luna.
Tom Hyzinski of GT Power Group said he disagreed with the IMM’s proposed penalties “because there is no failure to meet one’s capacity obligation — one is still subject to CP penalties, and PJM can deny MaxE status and call the unit for reliability at any time.”
Hyzinski said it would be “retroactive ratemaking” to apply the new rules to resources with existing capacity obligations. “If the [Base Residual Auction] has not cleared, and the IMM proposal is in place for that delivery year, then I understand that before I sell the capacity,” he wrote in a WebEx message to other meeting participants.
The committee will be asked to choose between the two proposals at its next meeting.
You young’uns don’t know, but back in the Middle Ages of the 1970s there was a famous commercial for Fram oil filters: You could pay the Fram guy $4 for an oil filter now or pay hundreds for engine repairs later.[1]
Having slightly less pizzazz is the question of how consumers pay for transmission project costs during the pre-construction and construction phases, i.e., before they are completed and placed in service. Consumers can pay a transmission owner’s return (aka cost of capital, aka carrying charge) on such costs on a current basis before and during construction (pay now) or start to pay that return when the project is completed (pay later). The former is often called the “construction work in progress” or CWIP approach, and the latter is often called the “allowance for funds used during construction” or AFUDC approach.[2]
Are you with me so far? Let me give a simple example of the difference. A transmission owner spends $100 million on a project in year 1, and let’s assume an annual return of 9%. Under the CWIP approach the transmission owner charges consumers $9 million in (or shortly after) year 1. Under the AFUDC approach the transmission owners books the $9 million and adds it to the capital cost (aka rate base) of the project, to be charged to consumers starting when the project goes into service (or is abandoned).
When consumers pay that transmission owner return — now or later — is a timing question. There is no obvious answer to which is better for consumers.
Time Value of Money
All else equal, the answer turns on the time value of money — an esoteric concept that compares what someone would take in the future for not having a given sum today. So, for example, if someone would be indifferent to receiving $105 a year from now versus having $100 today, we would say that person has a time value of money with a 5% “discount rate.” In the context we’re considering, the question is whether the consumer would rather pay the transmission owner now or pay a higher amount later.
We can take a shot at estimating this. There’s about $18 trillion in bank accounts averaging 0.1% interest,[3] so that might be a decent estimate of consumers’ discount rate. If someone would accept $100.10 a year from now on his/her $100 today then there’s a really low discount rate.
At the other end of the spectrum are consumers with credit card debt paying 16% interest, implicitly choosing (or having to pay) a 16% discount rate.[4] If they don’t pay the transmission owner that $100 up front, instead paying down credit card debt by that amount, they could save $16 in credit card interest. But there’s around $840 billion in aggregate credit card debt,[5] versus $18 trillion in bank accounts, so there’s a rough ratio of 20-1 for a low discount rate of 0.10% versus a high discount rate of 16%.
I hope I haven’t lost you because we still need to compare consumers’ discount rate with an estimate of what the transmission owner charges consumers for the time value of money. It’s roughly 9% using current allowed returns (weighted average cost of capital including income tax allowance).[6]
Based on the foregoing, the vast bulk of consumers would rather pay now than pay later. For every $100, forego $0.10 now versus pay $9 a year from now. Conceptually most consumers would take $100 from a bank account, foregoing $0.10 in annual interest, in order to pay a transmission owner that would otherwise charge an extra $9 a year later.
Cut to the April NOPR
Now we can cut to FERC’s April Notice of Proposed Rulemaking, which suggests the opposite — that consumers overall would rather pay later. The NOPR says: “… we are concerned that the CWIP Incentive, if made available for Long-Term Regional Transmission Facilities, may shift too much risk to consumers to the benefit of public utility transmission providers in a manner that renders commission-jurisdictional rates unjust and unreasonable.”[7]
There’s no analysis supporting this conclusion — it’s just asserted. As I pointed out above, the transmission owner charges consumers for its return under either approach; it’s just pay me now or pay me later. And most consumers would rather pay now because of their low discount rate, as well as to avoid what the commission has called “rate shock” if the return on large projects is deferred and accumulated until the project goes into service.[8]
Perhaps the NOPR’s focus is on situations when the project is abandoned instead of going into service. The NOPR says: “Should the regional transmission facilities not be placed in service, then ratepayers will have financed the construction of such facilities that were not used and useful, while ultimately receiving no benefits from such facilities.”[9]
There are problems with this focus. First, abandoned project costs are a small percent of total transmission costs because the vast majority of projects are not abandoned and because abandoned projects are abandoned in the pre-construction phase where relatively few dollars have been expended. So, to have abandoned project costs decide the overall CWIP v. AFUDC issue is to have the tail wag the dog.
Second, under commission precedent, consumers generally pay that transmission owner return even for abandoned projects that provide consumers no benefit.[10] The NOPR seems to assume that it would spare consumers from this cost of abandoned projects when the commission’s own rules and precedent are the opposite.
The NOPR doesn’t propose to change the commission’s rules and precedent on this (although Commissioner Mark Christie’s concurrence seems to suggest it does[11]). And the commission seems unlikely to change the rules given the inevitable transmission owner objections that this would discourage the big transmission projects that the commission wants to promote.
And let me add that even if recovery of abandoned project costs were to be disallowed then transmission owners would argue for a higher rate of return because of increased investment risk — another wrinkle on pay me now or pay me later. Consumers seem unlikely to win that tradeoff against transmission owner lawyers and consultants (who consumers pay for[12]). And a risk of disallowance might skew a transmission owner’s incentive against abandoning a project that ought to be abandoned.
Wrapping Up
OK, I’ll wrap this up by saying I would love to be wrong — that somehow consumers would be better with the AFUDC pay-later approach. But that doesn’t seem possible for projects that go into service. And as for abandoned projects, consumers might be better off but only if return on capital were actually denied instead of deferred and billed to consumers later.
P.S. errata note, in my last column on transmission competition the references to $136,070,000 should have said $128,750,000. Import unchanged. I regret the error.
Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.
[2] These terms can be confusing. Sometimes the return/carrying charge amount is referred to as AFUDC, which is added to the CWIP balance. Also I should note that generally under both the AFUDC and CWIP approaches, the amount in question is return on capital, not return of capital. In both approaches the capital costs of construction are treated the same – recovery from consumers is deferred until the project goes into service (or is abandoned).
[6] For illustrative purposes take last year’s settlement of a rate complaint against PPL Electric Utilities, a PJM transmission owner, with an allowed common equity return of 10.4% and allowed equity/debt ratio of 56%/44%, https://elibrary.ferc.gov/eLibrary/filedownload?fileid=F83FB3CC-1092-CA7D-87C8-7B6442400000. Grossing up the equity return for a 21% federal income tax rate yields a pretax equity return of 13.2%. Applying the equity/debt proportions to that equity return and to a long-term debt cost of 3.6% from data in PPL’s Form 1 yields a weighted average cost of capital of 9.0%. Your mileage may vary.
[7]Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, Notice of Proposed Rulemaking, 179 FERC ¶ 61,028 (April 21, 2022) (“NOPR”), at P 332.
[8]Potomac-Appalachian Transmission Highline, L.L.C., 122 FERC ¶ 61,188, at P 42 (2008).
[10] Order No. 679, 116 FERC ¶ 61,057 at P 163 (2006); MidAmerican Central California Transco, LLC, 168 FERC ¶ 61,197 at P 3 (2019); GridLiance West Transco LLC, 164 FERC ¶ 61,049, at P 19-20 (2018); Potomac-Appalachian Transmission Highline, L.L.C., Opinion No. 554, 158 FERC ¶ 61,050, at P 5, fn. 10 (2017) (“PATH”); Xcel Energy Services, Inc., 121 FERC ¶ 61,284 at P 62 (2007).
[11] Commissioner Christie concurring, at P 5 and 15. If the Commission actually intends what Commissioner Christie suggests it does, then a Final Rule should make that clear.
Rule on Variable Environmental Costs and Credits Advances
VALLEY FORGE , Pa. — The PJM Market Implementation Committee last week approved a joint RTO-Independent Market Monitor proposal to update rules governing variable environmental charges and credits and their inclusion in cost-based energy offers.
Under the proposal, generation units receiving the production tax credit (PTC) or renewable energy credits (RECs) would have to reflect them in their fuel-cost policies (FCP) when submitting non-zero cost-based offers in the energy market.
The package includes changes to Manual 15 and Schedule 2 of the Operating Agreement. Under the changes, the review of emissions rates would be reduced from annual to every three years to align with the FCP review process. Emissions rates should not change drastically year to year, said PJM’s Melissa Pilong. The market seller is responsible for updating rates to ensure their accuracy.
The new rules would also add transparency on the information required from market sellers.
The IMM’s Joel Luna told the committee that RECs and PTCs must be included in cost-based offers under the same standards as fuel costs, and must be “accurate, verifiable and systematic.”
“In plain terms, it cannot be made up,” Luna said.
RECs can be based on the actual transaction price (inventory cost or contract-based) or spot price (replacement cost). If the actual price is used, the FCP must say how often the price will be updated and the period for the price (e.g., last year). If a spot price is chosen, the FCP must identify the source (e.g., broker/publication), data point used (e.g., midpoint/settled) and update frequency (e.g., weekly).
Units with bundled power purchase agreements making non-zero cost offers can use the actual REC price or spot REC price.
PTC rates are defined by the Internal Revenue Service and grossed up based on the effective corporate tax rate. For a company with a 21% tax rate, the $27/MWh PTC converts to $34.18/MWh ($27/(1-0.21)).
Jeff Whitehead of GT Power Group questioned why the RTO is including out-of-market revenue, saying it’s at odds with the effective elimination of the minimum offer price rule.
“We have a couple of ‘no’ votes [because of] the policy implications,” he said. “We’re wondering if we’re going the wrong direction with this policy.”
“Having the net cost reflects the true marginal cost of the units,” said Luna. Without such considerations, “you’ll be sending [solar and wind generators] a signal to curtail, and they will not respond.”
The proposal passed 180-39 (82%) with five abstentions. Stakeholders said they preferred the new rule over the status quo by 178-32, with 21 abstentions. It will receive a first read at this week’s Markets and Reliability Committee meeting.
Market Suspension Rules OK’d
Members also approved a revised PJM/IMM package of changes to the treatment of long-term market suspensions.
The changes are intended to address a gap in tariff language regarding how to settle the real-time market if prices can’t be determined. They would set separate rules for suspensions of less than and more than 24 hours.
Under a compromise, the intermediate suspension category was eliminated, and the “short term” suspension was expanded to 24 hours from six.
The changes apply to the real-time market when dispatch is unable to provide zonal economic dispatch results for at least seven five-minute intervals within a market hour. For suspensions up to 24 hours, PJM would substitute the missing prices with the average real-time price of those from the preceding and subsequent hours.
Suspensions longer than 24 hours would use day-ahead prices, if available. If not available, energy LMPs would be priced hourly based on an aggregate supply curve from available offers (including available resources not running), with actual generation megawatts serving as the proxy for demand. Loss LMPs and congestion LMPs would be set to $0.
The change included a friendly amendment by Shell Energy’s Sean Chang that stated if the suspension is greater than six hours but less than 24 hours, PJM would use day-ahead prices for corresponding hours.
The changes do not affect suspensions of the day-ahead market, which will continue to use real-time prices as defined in tariff section 1.10.8(d).
Tom Hyzinsky of GT Power Group expressed concern with the changes, saying “day-ahead and real-time can be two completely different markets.”
PJM’s Tim Horger said 90 to 95% of load clears in the day-ahead market. “That’s why I feel confident using it for six to 24 hours.”
The changes were approved by acclimation with no objections or abstentions.
Initiative Approved on Weather-sensitive Load Compliance Rules
Members approved an issue charge proposed by Sharon Midgley, of Exelon (NASDAQ:EXC) and subsidiary Baltimore Gas and Electric (BGE), to explore an alternative demand response/price-responsive demand (PRD) compliance construct for weather-sensitive load, such as residential demand impacted by summer air conditioning.
Midgley said the current rules compare metered load under prevailing weather conditions to the peak load contribution (PLC) based on weather-normalized peak weather conditions. Capacity compliance for DR and PRD is currently based on the firm service level (FSL), calculated as the PLC minus the amount of installed capacity that the DR/PRD resource cleared in the capacity auction. Compliance is achieved if metered load is at or below the FSL.
Over the summers of 2018-2021, the actual peak load for BGE’s weather-sensitive residential customers averaged 13% higher than the weather-normalized peak load. The disparity was the largest in 2019, with weather-normalized load 22% lower than actual load.
The discrepancy means DR and PRD providers may not be able to offer the full capability of their programs into the capacity market because of unachievable FSL, Midgley said.
Midgley revised the issue charge to make out-of-scope changes to the current compliance construct’s ruleset, which caps monetization to the customer’s PLC.
Monitor Joe Bowring opposed addressing the issue separately from ongoing discussions at the Resource Adequacy Senior Task Force. “We don’t think this is a narrow issue, and we don’t think it should be carved out from the RASTF,” he said.
Midgley said the RASTF’s work plan didn’t envision “getting to that level of detail.”
“I don’t see this as asking for special treatment,” she added.
The issue charge was approved with one objection for 22 members.
First Read on Day-ahead Zonal Load Bus Distribution Factors
PJM’s Amanda Martin gave a first read of a problem statement and issue charge addressing day-ahead zonal load bus distribution factors.
This example shows the July 14 DA nodal load (left scale) is consistently 13% of the zonal load (right scale), while the July 7 RT load is only 6% of the zonal load. | PJM
The RTO’s current rules state that the default distribution of load buses for a zone in the day-ahead energy market is the state estimator distribution of load for that zone at 8 a.m. one week prior to the operating day. That means the share of the zonal load attributed to each node remains constant for all 24 hours, even though the node’s share of total load may vary throughout the day because of nonconforming loads, such as behind-the-meter solar and data centers. This can cause a mismatch between the day-ahead nodal loads and real-time state-estimated load.
“This seems overly simplistic given the data we have,” said consultant Roy Shanker. “I’m surprised we’re doing it this way.”
The committee will be asked to approve the issue charge at its next meeting under the “CBIR Lite” (Consensus Based Issue Resolution) process. The work is expected to take four months, with changes to tariff section 31.7c(i) and updates to Manual 11 and Manual 28.
IMM Balks at New Capacity Options for Generation with Co-located Load
Bowring expressed concern over proposals to change how PJM treats capacity offers from generation with co-located load.
According to the problem statement proposed by Brookfield Renewable Trading and Marketing and Constellation Energy — and approved by stakeholders in January — PJM’s current rules do not allow capacity offers for the full output of generating units that are contracted to physically serve co-located loads, instead requiring owners to retire a portion of their capacity to serve such loads.
The companies said large commercial customers with fast-response curtailment capability (less than 10 minutes) are seeking physical supply options for loads that are directly interconnected behind carbon-free generation resources such as hydro and nuclear.
Changing the rules would provide customers more options and give PJM the ability to call on the generators serving such interruptible customers, backers say. The initiative could result in modifications to capacity market rules, cost-based offer rules and relevant manual provisions to account for co-located load configurations.
“We have lots of large loads that can drop at any time on the system,” said Shanker. “Operationally, I don’t think this is anything new.” He added, however, that the magnitude could be increasing.
But Bowring said the proposal is a “significant change” that removes, rather than adds, flexibility. He said it could mean that a large nuclear power plant will no longer provide its energy to PJM in most hours but will be paid as if it is a capacity resource.
Discussing the impact of an unexpected drop in the behind-the-generator load, he said, “It’s not just a load drop. It’s a sudden increase in generation. … Everyone needs more details about this to be convinced it’s business as usual.”
He also said the impact of the proposed change on the provision of reactive power and frequency control by the generator must be explicitly defined.
Constellation Energy’s Jason Barker asked Bowring to be specific about the analysis he seeks, saying he wanted to avoid his request from “unduly delay[ing] consideration of this process.”
“The process has worked in the past to adjust interconnection service agreements,” Barker said.
PJM’s Jeff Bastian said the RTO currently operates the system prepared for the loss of its largest units. “If you lose a 300-MW load behind the meter of a generator, the system is going to react the same as if you lose a 300-MW paper mill or any other kind of load that’s connected to the system. So I’m not sure I understand the concern,” he said.
PJM’s Lisa Morelli said she will continue discussions outside of the MIC “to make sure we’re not talking past each other.”
CT Make-whole Loophole Discussed
Members discussed a proposal to close a loophole that allows combustion turbines to ignore PJM dispatch without financial consequences.
Under PJM rules, most resources are made whole to the lesser of their actual megawatt output or the RTO’s desired output. But CTs are always made whole to their actual megawatts, regardless of how well they follow dispatch, Morelli explained.
The distance between the orange (dispatch) line and blue (actual operation) line represents excess MWs for which the combustion turbine can receive make-whole payments under current PJM rules. | PJM
PJM and the Monitor said the special treatment made sense before the implementation of Capacity Performance, when CTs were not required to have a dispatchable range. Most CTs now share similar dispatchability to the rest of the fleet, they said.
Flexible CTs received 72% of all balancing operating reserve credits in 2021, “so changes to this rule can be quite meaningful,” said Morelli.
PJM reran the highest uplift days for CTs from summer 2021 and found that with the CT exception eliminated, uplift payments to CTs would drop from $13.4 million to $12.2 million over the eight days — a reduction of $1.3 million (10%).
“$1.3 million for eight days is pretty significant, so that would grow over a whole year,” Morelli said. “I think it does make a strong case for removing the CT rule.”
She called the change “low-hanging fruit,” although she acknowledged, “we realize some CTs are not flexible.”
Timing of ARR/FTR Market Task Force Talks at Issue
PJM backed off from a recommendation to delay additional work on new seasonal auction revenue rights (ARRs) and financial transmission rights (FTR) products in the face of opposition by DC Energy.
In a poll of 129 members of the ARR/FTR Market Task Force, 98% answered “yes” to the question: “Should the annual ARR/FTR products be retained and seasonal products be added (recognizing that fewer rounds would be required)?”
Almost two-thirds (64%) of those polled also supported “pursuing any other ARR/FTR market reforms at this time.”
A much smaller majority (57%) supported retention of the annual ARR/FTR products. “So no real conclusory evidence there on where people want us to go,” said task force facilitator Dave Anders.
Asked what process changes the task force should pursue to simplify auctions to allow additional products, 60% favored adjusting the structure of the annual auction (e.g., number of rounds), and 83% supported modifications to overlapping periods and/or class types.
In contrast, “adjustments to the annual ARR allocation process” drew only 26% support.
After reviewing the poll results, Anders recommended that the task force delay discussions on new products until late 2023 or early 2024 to allow the September 2022 Phase I (new FTR product type) and February 2023 Phase II (ARR changes) be implemented first. Those changes were approved by FERC on March 11 (ER22-797).
“Let’s make sure we’ve got some stability before we make additional changes,” he said.
Anders also proposed revising the task force’s issue charge to “narrow the focus down to, what do we want to accomplish going forward?”
“The issue charge was exceptionally wide open,” said Anders. “Being able to say the task force is done is an important thing.”
“Where did this recommendation come from?” asked Bruce Bleiweis of DC Energy. “It wasn’t discussed.”
“As facilitator of the task force, this is my recommendation,” responded Anders.
Bleiweis said he agreed with revising the charter, but he said he would oppose waiting “another year and a half to begin those discussions.”
“I don’t think we need to wait for the implementation of the new products and class types, because they’re different from what we’re recommending” he said.
“This is just my recommendation,” Anders responded. “We’ll go whatever direction the stakeholders want to go.”
Anders said he would return to the group with “a more definitive path forward.”
Separately, the MIC endorsed changes to Manual 6: Financial Transmission Rights as part of the periodic review and to make changes conforming with FERC’s March order. The changes include definitions of new FTR class types and clarification of the remaining time frame for existing off-peak classes. Also added was a new rule on the minimum price for clearing options. The first of the changes will be effective Sept. 1 and be applied first to the October 2022 auction, which opens in mid-September.
Wolf’s Appeal Reinstates RGGI Costs in Pa. — for Now
On July 11, Pennsylvania Gov. Tom Wolf’s administration appealed the Commonwealth Court’s injunction blocking the state from entering the Regional Greenhouse Gas Initiative (RGGI), effectively lifting the injunction. (See Court Blocks Pa. from Joining RGGI.)
“As a result, generators can include RGGI costs in their cost‐based offers per their approved fuel-cost policies beginning on July 13 for July 14, unless and until the injunction is reinstated, if it is,” the Monitor advised in a notice.
Manual Revisions Approved
Members also endorsed revisions to:
Manual 18: PJM Capacity Market to conform with FERC’s July 12 order regarding hybrid resources (ER22-1420). A hybrid is defined as a single generator plus a single storage facility operating as a composite. The change adds hybrid resources to the exemption from the capacity market must-offer rule currently applied to intermittent resources and capacity storage resources.
Manual 28: Operating Agreement Accounting to support the start-up cost offer development proposal the MRC approved in May. It clarifies what intervals are included in segments for determination of balancing operating reserve credits.
VALLEY FORGE, Pa. — PJM will stop supporting older, less secure versions of transport layer security (TLS) encryption in its remaining applications between now and Aug. 17 because of cybersecurity concerns.
TLS protects data on websites and securely transfers data between clients and servers.
PJM Chief Information Security Officer Steve McElwee told the Market Implementation Committee on Wednesday that passwords and market data can be intercepted and decrypted in TLS 1.0 and 1.1.
The RTO disabled 1.0 and 1.1 in its training environment last year and has replaced them on several production PJM Tools applications and on PJM.com. It is expediting the transition for the remaining applications in response to a recommendation from the U.S. Department of Homeland Security. Users will not be able to access the applications unless browser and browser-less API interactions use TLS 1.2.
“We’re really working aggressively to reduce the attack surface for adversaries,” McElwee said. “We had longer-term plans to let you adapt, but we had to accelerate that. We recognize that could cause some impact for you.”
McElwee said about 98% of PJM stakeholders have already adopted the new TLS. “It’s that 2% that we really want to track down,” he said.
Russian Threats
McElwee repeated his briefing about the changes before the Operating Committee on Thursday, saying that “if you get a communication from us, it’s not a phishing attempt. It is legitimate.”
He also told the OC of other cybersecurity issues, including a June 22 Microsoft intelligence report that said the software maker had detected Russian network intrusion efforts on 128 organizations in 42 countries outside of Ukraine.
Pro-Russia groups have been linked to many distributed denial of service (DDoS) attacks, he said, including a cyber collective called Killnet that claimed responsibility last month for DDoS attacks in Lithuania in response to the closure of transit routes within the Russian exclave of Kaliningrad.
PJM is following DHS’ “shields up” recommendations, including blocking international and anonymized network traffic and exercising incident-response plans.
“We recognize the threat of retaliation against the U.S. is very real, so we’re [doing what we can] to stay on guard against that threat,” McElwee said.
He recommended reading the Cybersecurity and Infrastructure Security Agency’s May alert on threats to managed service providers and their customers, and its June warning on exploits targeting VMware Horizon and Unified Access Gateway servers.
He also urged PJM member companies to use measures such as multifactor authentication to protect their email systems. “Business email compromise can have a lot of impact on your organization,” he said. “A cyberattack against one of us could affect all of us.”
GMD Vulnerability Analysis Update
PJM’s Stanley Sliwa told the Planning Committee on July 12 that the RTO hopes to complete its assessment of its vulnerability to geomagnetic disturbances (GMDs) by the end of the year.
NERC reliability standard TPL-007-4 requirement R3 requires the RTO to establish acceptable steady-state voltage performance for its system during a GMD event, and prevent a voltage collapse and cascading and uncontrolled islanding.
But it allows loss of generation, transmission configuration changes and re-dispatch of generation if time permits. Also permitted are interruptions of firm transmission and manual or automatic load shedding.
Voltage performance is examined in three stages, beginning with the posturing of the system in response to space weather information warning of a potential GMD. “If we know PJM is expecting a GMD, certain actions can be taken to prepare the system,” Sliwa explained.
Performance also is measured after the onset of the event, but prior to loss of elements. The final measurement is made after the potential loss of reactive power compensation devices and other transmission facilities as a result of protection system operations or misoperations during an event.
VALLEY FORGE, Pa. — The PJM Operating Committee last week approved an issue charge on an initiative to ease the process for scheduling internal network integration transmission service (NITS).
The RTO said its current tariff makes little distinction between internal and external service requests, requiring all requests be studied to ensure sufficient headroom or the need for system upgrades. (Internal requests are for internal generation serving internal load; external/cross-border requests refer to external generation serving internal load or internal generation serving external load, respectively.)
The rules require internal NITS customers to notify PJM a year in advance of the expiration of their service that they want a rollover, as required for cross-border service, which the RTO termed a “valueless procedure.”
The initiative seeks to revise the tariff and manual language to differentiate between the two types of requests and reduce administrative burdens on entities using internal service.
PJM’s Susan McGill said no changes had been made since the issue’s first read in June. (See “Internal NITS Process,” PJM Operating Committee Briefs: June 9, 2022.) She said the issue could have been dealt with as a “quick fix” but that the RTO wanted to solicit members’ feedback.
The issue charge was approved by acclimation.
‘Quick Fix’ Changes OK’d for Manual 14D
Members also endorsed “quick fix” changes to Manual 14D: Generator Operational Requirements regarding the deactivation analysis timeline.
Current rules require notification of PJM at least 90 days in advance of the planned deactivation. Under the changes, desired deactivation dates would be no earlier than:
July 1 of the current calendar year for notices received between Jan. 1 and March 31;
Oct. 1 of the current calendar year for notices received between April 1 and June 30;
Jan. 1 of the following calendar year for notices received between July 1 and Sept. 30; and
April 1 of the following calendar year for notices received between Oct. 1 and Dec. 31.
PJM will study deactivations four times per year for all notices received prior to the study commencement dates (Jan. 1, April 1, July 1 and Oct. 1).
Terminology and categories in Manual 14D | PJM
PJM’s Dave Egan explained actions that PJM will take to address stakeholders’ concerns over the transparency of reliability-must-run (RMR) contracts, which are used to keep a generating unit operating beyond its requested deactivation date to maintain reliability until necessary transmission upgrades can be completed.
In response, a generation owner can either file its proposed cost-of-service recovery rate (CSRR) with FERC or receive the deactivation avoidable cost credit (DACC) specified in the tariff.
Egan said PJM will announce it had requested a plant to extend its operations at the second read of the deactivation notice before the Transmission Expansion Advisory Committee. The RTO will announce at subsequent TEAC meetings when the generation owner submits a CSRR to FERC and after the commission accepts the CSRR filing or the generation owner agrees to the DACC.
Michelle Bloodworth, CEO of coal industry group America’s Power, said RMRs would be little more than “a Band-Aid fix if there’s a flood of retirements.”
Egan acknowledged that RMRs are used only to ensure transmission security and not resource adequacy.
“We’re not looking at the long-term future,” he said. “It’s done on a case-by-case basis.”
First Read for Hybrid Rules
PJM’s Andrew Levitt presented a first read on manual language conforming to FERC’s July 12 order accepting the RTO clarifying its rules for hybrid resources and mixed technology facilities (ER22-1420-002). PJM filed its proposal on March 22.
Changes will be made to Manual 10: Pre-Scheduling Operations for eDART reporting requirements and Manual 14D: Generator Operational Requirements for changes regarding metering requirements, outage reporting and voltage schedules, with a new section 13 for mixed technology facilities.
The OC will be asked to endorse the changes at its next meeting.
PPL Delays DLR Implementation to September
PJM’s Dave Hislop told the committee that PPL (NYSE:PPL) has delayed the implementation of dynamic line ratings on three circuits until mid-September because further work is needed to finalize changes to its energy management system with its vendor.
The changes to the double-circuit 230-kV Susquehanna-Harwood and the 230-kV Juniata-Cumberland lines are scheduled to take effect on Sept. 13 for the day-ahead market and Sept. 14 for real time.
FERC on Friday rejected Niagara Mohawk Power’s proposed cost allocation and recovery for the utility’s share in the Smart Path Connect transmission project in upstate New York, including its request to increase its base return on equity (ROE) from 10.3% to 10.5% (ER22-1201-001).
The commission also denied the utility’s requests for a 50-basis-point adder to account for risks and incentives based on performance.
Niagara Mohawk is seeking to recover the $535 million in costs on the Smart Path Connect project, being built with the New York Power Authority (NYPA). The utilities estimate the total capital cost of the project at $1.2 billion, with an anticipated in-service date of December 2025. It would consist of rebuilding approximately 100 miles of 230-kV transmission lines to either 230 kV or 345 kV, along with associated substation construction and upgrades that, together with other projects currently under construction in New York, would establish a continuous 345-kV transmission path from northern New York to the downstate region to mitigate current and projected congestion.
FERC rejected the proposal as conflicting with a commission-approved 2015 transmission service charge (TSC) settlement with the New York Association of Public Power that set the utility’s ROE at 10.3% (EL14-29).
“Niagara Mohawk voluntarily entered into the 2015 TSC ROE settlement, in which it agreed to a 10.3% ROE for all of its transmission facilities, inclusive of any incentive adders,” FERC said. “Niagara Mohawk points to nothing in the [settlement] to suggest that the ROE established there applies only to either then-existing transmission facilities or transmission facilities that primarily have certain types of benefits. We find that, in the absence of any such language, the ROE established in the [settlement] should apply to all of Niagara Mohawk’s transmission facilities, including its going-forward investments.”
Stakeholders last week welcomed proposed changes to PJM’s interconnection procedures as long overdue but challenged the RTO’s timeline and transition plans.
PJM last month proposed to switch from a “first-come, first-served” approach to a “first-ready, first-served” cycle, with individual serial studies replaced with cluster studies (ER22-2110). (See PJM Files Interconnection Proposal with FERC.)
More than 30 companies and groups filed comments by the July 14 deadline in response to the RTO’s proposal, the result of 18 months of stakeholder talks.
The American Council on Renewable Energy said that while PJM’s proposal “does not address the full range of needed interconnection reforms, the reforms proposed are an important first step and will likely mitigate several causes of queue backlogs.”
The Organization of PJM States Inc. (OPSI) urged FERC to approval the proposal promptly but complained that PJM’s proposed four-year transition and two-year default processing timelines are too long. It noted that 11 of the 14 jurisdictions in PJM have renewable portfolio standards, but they rely heavily on imports for compliance because of insufficient renewable generation within their borders.
“Despite the fact that interconnecting new generation is a critical component of open-access transmission service and should be one of PJM’s core competencies, PJM’s generator interconnection queue has been inefficiently processing interconnection requests,” OPSI said. “PJM has been aware of state public policy goals for a number of years, but PJM continues to make little progress with the queue backlog. As a result, the current queue delays put some states in jeopardy of not meeting their near-term public policy goals as target dates inch ever closer.”
It said PJM reported completing only 13 facilities studies in April and May, versus a backlog of 1,585. “This slow pace will not clear the backlog and illustrates the urgent need to immediately reform the broken interconnection process,” the group said, adding that it will look to FERC’s interconnection Notice of Proposed Rulemaking (RM22-14) for additional improvements. (See FERC Proposes Interconnection Process Overhaul.)
OPSI said PJM’s proposals are similar to changes approved in other RTOs and proposed in FERC’s rulemaking. “However, the length of the proposed process does not live up to the standards set by other RTOs,” it said.
“OPSI is deeply concerned that, even under PJM’s proposed reforms, a project entering the queue today may not be able to achieve commercial operation until nearly 2030. This is because PJM proposes to not process any new interconnection applications until as late as 2026, at which point projects would then have to undergo a two-year interconnection process. The prospect of such a lengthy timeline is troubling. It is important that PJM’s proposed four-year pause on reviewing new applications be an absolute upper limit and that PJM invest the time and resources to substantially reduce this transition period.”
$5 Million Threshold Challenged
Numerous stakeholders also criticized the RTO’s transition plan to bar projects from remaining in the serial process “fast lane” — rather than starting over in a transition cluster study — if it contributes to the need for a network upgrade that exceeds $5 million.
“PJM has not demonstrated that this threshold has any correlation to whether a project in the queue is commercially ready,” the PJM Power Providers Group said. “Instead, this arbitrary threshold will upend many projects that are fully permitted, have made significant investments based on the study results to date and are ready to move forward with construction and interconnection. … While a transition mechanism is needed to get to PJM’s new proposed interconnection process, one that is based on actual demonstrations of commercial readiness would be far superior and less disruptive than what PJM has proposed.”
Hecate Energy also challenged the $5 million cutoff saying FERC should “allow ‘ready to go’ projects (that are willing to post security and meet certain other milestones) to participate in the ‘expedited process’ during the transition, and to receive accelerated treatment after the transition, regardless of the cost of identified network upgrades.”
Hecate also joined in a separate protest with six other developers, including Acciona Energy and Leeward Renewable Energy in challenging the threshold. “The PJM stakeholder process was selective, controlled by PJM, overlooked key proposals to address PJM’s backlogged queue and cannot be relied upon as justification for PJM’s queue reform filing,” they said.
Competitive Power Ventures said “the proposal ignores late‐stage projects … that have made substantial strides in development and can prove their readiness in objective and substantial ways, and that may have been delayed only as a result of PJM study delays. Such projects will be catapulted back in time, erasing all of the study work completed and proceeding under a completely new paradigm, while a project that may be later in the queue and may not be as far along in their development progress can leap frog over them simply because their projected network upgrade costs are $5 million or less.”
But Pine Gate Renewables and Cypress Creek Renewables insisted in a joint filing that the $5 million threshold is “rooted in PJM’s current tariff provisions, which establish $5 million as the minimum threshold for inter-queue cost allocation. Moreover, it is a carefully negotiated term that active PJM stakeholders debated extensively.”
“PJM stakeholders and staff collectively and collaboratively developed and adopted the eligibility criteria and $5 million threshold to facilitate PJM’s clearing of the existing backlog, while also allowing mature projects with little or no network upgrade responsibility to complete the interconnection process in a timely manner,” they said.
The two companies asked FERC to approve the filing quickly, saying it was the result of “a robust, inclusive and consensus-driven stakeholder process.”
‘Awkward Position’
The Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project said that PJM’s filing restates existing tariff provisions that may be unjust and unreasonable under FERC’s interconnection NOPR, including the lack of firm deadlines for its transition cycles and new rules.
“This puts FERC in the awkward position of being asked to rule that a Section 205 filing is just and reasonable at the same time it investigates if portions of that filing are unjust or unreasonable through a rulemaking,” the groups said. “It is essential that FERC action in this docket does not prejudice the outcomes of the interconnection NOPR.”
They also asked FERC to reduce PJM’s proposed requirement that project developers provide proof of 100% site control to 90% and to add language “allowing flexibility when site control cannot be demonstrated because of regulatory requirements or obligations.”
Uncertainty
The Solar Energy Industries Association called the proposal a “significant improvement” that “ensures efficient processing of interconnection requests that will allow lower-cost resources to come online faster.”
But it said the proposed four-year delay in reviewing new applications will “create uncertainty for potential development in PJM once PJM begins reviewing new applications, as some developers will shift their efforts to other regions.”
It said FERC should require PJM to submit biannual reports on its progress in reducing its queue backlog and a breakdown of the interconnection delays by transmission zone, to determine whether individual transmission owners are to blame.
For their part, PJM’s TOs said in a joint filing that they “fully recognize that this reform is just an initial step that provides a flexible framework capable of accommodating future changes spurred by either PJM stakeholders or commission action.” They noted that PJM stakeholders intend to consider additional improvements through the new Interconnection Planning Subcommittee reporting to the Planning Committee.
Also filing a protest was the developer of the proposed 2,100-MW SOO Green HVDC Link ProjectCo, which said the proposal is unfair to merchant transmission facilities, “which are unjustly included in the new services queue and will be forced into even longer interconnection delays.”
Queue Groupings
National Grid Renewables Development, NextEra Energy Resources and RWE Renewables Americas said FERC should reject PJM’s proposal to include projects in queue groupings AG2 (cutoff date March 31, 2021) and AH1 (Sept. 30, 2021) in the transition along with projects in group AG1 (Sept. 30, 2020).
PJM’s initial transition proposal, presented to stakeholders in November 2021, included only group AG1.
“This decision respected projects that had some study work done and were thus entitled to rely on a continuation of the process they had embarked upon,” the companies said. By contrast, “most, if not all, AG2 and AH1 projects entered the queue knowing or on notice that PJM had already began with its stakeholders an initiative to make sweeping changes to its queue rules.”
PJM agreed to include AG2 and AH1 in the transition following lobbying by stakeholders holding positions in those groups, the three companies said.
The companies said including AG2 and AH1 would add 1,358 projects. Based on prior queues, only about 40 (3%) of those projects will be completed, they said.
‘Adjacent’ Parcels
Tenaska protested as arbitrary PJM’s proposal to allow a project developer to make changes to the project site at its first two decision points as long as the new site and the initial site are “adjacent parcels.” The company said PJM did not define “adjacent parcels” and provided no rationale for the requirement.
“A showing of ‘adjacency’ for a proposed site change is unnecessary for PJM in performing its function — assessing and studying a new project’s impact on the network transmission system — if the proposed site change does not result in a material modification,” it said.
Tenaska said solar project developers often file for a queue position after obtaining site control over a parcel of land but before conducting soil and geotech studies that could detect high levels of mercury or other elements that make the parcel undesirable. “Project developers then find nearby parcels of land, free from such environmental issues, and ‘perfect’ the site accordingly,” Tenaska said. “While these parcels sometimes are adjoining, sometimes they are nearby but not directly adjoining.”
The PJM study process examines the effect of new generation at a given point of interconnection to evaluate the effect of additional generation on reliability. “The real property status of the ground on which a project will be sited is wholly irrelevant to that analysis,” Tenaska said.
The company said site control requirements are intended to prevent speculative proposals from entering the queue.
Thus, it said, PJM should allow developers to change their sites unless they cause “a material adverse effect on the cost or timing” of interconnection studies related to system upgrades, “consistent with” the policies in MISO and SPP.
Consumers’ Consultant Says PJM Load Model Based on ‘Fiction’
VALLEY FORGE, Pa. — A consultant representing consumer advocates criticized PJM’s proposed load model for the 2022 Reserve Requirement Study, telling the RTO’s Planning Committee on July 12 that it would result in the over-procurement of about 1,000 MW.
Economist James Wilson — who represents advocates in New Jersey, Pennsylvania, Maryland, Delaware and D.C. — said that PJM is underestimating the assistance it could expect from its neighbors during peak loads because it models MISO, NYISO, the Tennessee Valley Authority and SERC Reliability’s VACAR subregion as a single entity it terms the “World.”
“The ‘World’ is a fiction,” Wilson said. “No other RTO aggregates regions as diverse as New York and VACAR and MISO and TVA.”
Wilson leveled his criticism after PJM’s Patricio Rocha Garrido presented the RTO’s proposal to use a load model from 2000-2010 for the capacity auction for delivery year 2026/27. The PC will be asked to endorse the selection at its August meeting.
Rocha Garrido said PJM considered 136 load models in its analysis, which he said is necessary because the coincident peak distributions from the RTO’s load forecast cannot be used directly in PRISM, the loss-of-load-expectation software.
Under a method approved by the PC in 2016, PJM seeks to match its forecasted peak day distribution with the historical diversity from the World’s peak.
In this year’s analysis, PJM switched the World peak to the fourth week in July so that the RTO — projected to peak in the third week of the month — tops out in the same month but not the same week as the World. The switch was made to match the historical diversity between PJM and World peaks, Rocha Garrido said.
Wilson said PJM made “very arbitrary” load choices in deciding on a model that has a 99% match between PJM’s and the World’s “per-unitized” peaks. “In previous years it’s always been 97% or 95%,” he said, noting that TVA peaked in the same day as PJM in only four out of the 23 last years, while NY, MISO and VACAR peaked in the same day as PJM in only seven or eight.
The four neighbors averaged more than 7,000 MW below their peaks at the time of the PJM peak — 3.9% of the PJM peak — over the 23 years, Wilson said. He said the choice would result in about a 1,000-MW increase in the reliability requirement. By combining the four neighboring regions, PJM is “pretending they would help each other rather than PJM,” Wilson said.
Michael Cocco, of Old Dominion Electric Cooperative (ODEC), asked PJM to provide a comparison of the individual regions’ peaks against its peaks.
Rocha Garrido said the RTO had conducted analyses that looked at the neighboring reasons separately and got “similar results.”
“The data supports 99% rather than 97%,” he said.
PJM’s Tom Falin, chair of the Resource Adequacy Analysis Subcommittee (RAAS), also defended the choice, saying the diversity between PJM and the World was less than 3% in 20 of the last 23 years.
“This is largely a judgment call in the end,” he acknowledged, saying there was no formula for determining the capacity benefit of PJM’s ties with its neighbors.
Falin also said not all of PJM’s assumptions were conservative, noting that PRISM assumes no transmission constraints within any of the regions. He also questioned whether other regions would call on demand response — which figures into their capacity calculations — to help PJM.
Wilson said he will make a presentation on his proposed changes to the load model at the next meeting of the RAAS on Aug. 3.
‘Time to Get Involved’ in Capacity Interconnection Rights for ELCC Resources
PJM’s Brian Chmielewski provided an update on the PC’s special session on capacity interconnection rights (CIRs) for effective load-carrying capability (ELCC) resources such as renewables, which cannot run at their maximum output for more than 24 hours.
CIRs set an upper bound on the amount of installed capacity attributed to a generation capacity resource.
At the June 24 meeting, stakeholders discussed competing proposals from PJM, LS Power, Global Infrastructure Partners’ Eolian and economist Paul Sotkiewicz of E-Cubed Policy Associates.
The group originally planned a final review of the proposals for this Wednesday, followed by a nonbinding poll. But the meeting was postponed until late August to allow for more offline discussions to forge compromises, Chmielewski said.
A first read is expected no sooner than the September PC meeting, with the new rules implemented for the 2025/26 Base Residual Auction.
“Now is the time to get involved before we get into polling,” Chmielewski said.
Informational Update on NOPRs
Members received updates on FERC’s Notices of Proposed Rulemaking on generator interconnection procedures (RM22-14), transmission system planning performance requirements for extreme weather (RM22-10) and a requirement that transmission providers submit one-time informational reports on extreme weather vulnerability assessments, climate change and electric system reliability (RM22-16).
PJM has planned two workshops on the extreme weather planning NOPR: one on July 21 to provide an update on its preliminary plans for its response and to solicit input from stakeholders, and one Aug. 12 to discuss the final draft response.
The RTO has previously recommended that FERC address resilience concerns by requiring a new transmission driver covering gas-electric vulnerabilities, reducing the number of critical grid facilities and strengthening infrastructure through storm hardening, winterizing generation resources and infrastructure redundancy.
ODEC’s Cocco said he hoped PJM would offer comments supporting its role as a “thought leader on gas-electric coordination.”
Generator Deliverability Education
PJM transmission planning engineer Jonathan Kern gave an update on the RTO’s proposed changes to generation deliverability testing.
Kern said the testing procedures “have been relatively unchanged for many years” despite the increased variability in dispatches because of the spread of renewables.
Among the changes is the grouping of resource types into three “block dispatches” based on their economics, with block 1 containing the units with the lowest offer prices (nuclear, wind, solar, hydro, pumped storage and other renewables); the more expensive block 2 (coal and combined cycle gas); and the most expensive, block 3 (IC/CT/ST oil and gas). “It better describes how PJM operates,” Kern said.
PJM also plans to redefine the “light load” period to include 10 a.m.-3 p.m. where the coincident peak load is between 40 and 60% of the annual peak for historical generation data necessary to represent the 50% load level.
“Solar is putting out large amounts of energy during the daytime. That’s completely unaccounted for” in PJM’s current modeling, Kern said.
Percentiles represent the share of hours with output below a particular level. This example shows that onshore wind is generating 40% or less of nameplate capacity in 90% of the hours. | PJM
PJM is also introducing the concept of “helpers” (generation with a negative DFAX, for which a decrease in the generation output increases the loading on a flowgate under study) and “harmers” (those with a positive DFAX, meaning a boost in generation would increase loading on the flowgate).
The new rules also will include more wind and solar in base case dispatches, with fixed solar rising from 38% to 47 to 55% of nameplate capacity in summer. Onshore wind would increase from 13% to 16 to 20%, and offshore wind would jump from 30% to 33 to 38%.
The RTO also plans to consider the impact of wind sited in MISO in both its light-load and winter tests. “Essentially, we’re looking at: What are the loopflows that would result from those wind units being dispatched at higher levels in MISO?” Kern explained.
