Page 443 – RTO Insider

July 18, 2022June 14, 2023

PJM MIC Briefs: July 13, 2022

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.

Tim Horger 2022-07-13 (RTO Insider LLC) FI.jpg

Tim Horger, PJM | © RTO Insider LLC

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.

Sharon Midgley 2022-07-13 (RTO Insider LLC) FI.jpg

Sharon Midgley, Exelon | © RTO Insider LLC

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.

Jason Barker 2022-07-13 (RTO Insider LLC) FI.jpg

Jason Barker, Constellation Energy | © RTO Insider LLC

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.”

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Dave Anders, PJM | © RTO Insider LLC

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.

July 18, 2022December 10, 2023

PJM Adopting New Web Protocols in Response to Cybersecurity Concerns

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.

July 18, 2022November 30, 2023

PJM Operating Committee Briefs: July 14, 2022

Issue Charge OK’d on Internal NITS Process

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.

July 18, 2022December 27, 2023

FERC Rejects Niagara Mohawk Tx Cost Formula, ROE Adders

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.”

July 17, 2022March 13, 2024

PJM Challenged on Interconnection Rule Transition

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.

July 17, 2022November 30, 2023

PJM Planning Committee Briefs: July 12, 2022

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.

July 17, 2022

Biden: ‘I Will not Back Down’ on Climate Action

With Sen. Joe Manchin (D-W.Va.) once again shutting down negotiations over a budget reconciliation package that includes clean energy incentives, a range of voices and views have emerged to answer the crucial question of what comes next.

President Biden and Energy Secretary Jennifer Granholm both struck a note of defiance. In a statement released by the White House on Friday, the president said the need for climate action remained as urgent as ever, and he vowed not to back down.

“If the Senate will not move to tackle the climate crisis and strengthen our domestic clean energy industry, I will take strong executive action to meet this moment,” Biden said. “My actions will create jobs, improve our energy security, bolster domestic manufacturing and supply chains, protect us from oil and gas price hikes in the future, and address climate change.”

Granholm took to Twitter with a thread acknowledging her frustration while calling for broad action at all levels. “We will fight like hell with the tools we have to build a clean energy future and move forward on climate action,” she said. “This moment calls [for] every city, state, tribe, business, community and organization to get in the fight if you’re not already. We have to leave it all on the field.”

In an interview on West Virginia MetroNews radio on Friday, Manchin maintained that he wants action on climate, but in the wake of June’s 9.1% consumer price index — up 1.3% from May — fighting inflation and reducing the federal deficit have to come first.

Manchin in December gave similar reasons for pulling out of negotiations over the original Build Back Better Act. The bill was passed by the House of Representatives, but all 50 Republicans in the Senate are opposed. Democrats want to use the reconciliation process, which would only require a simple majority vote (with Vice President Kamala Harris breaking the tie) if Manchin joined in support, to bypass a filibuster.

“We’ve had good negotiations. … Our staffs have been working diligently for the last two to three months,” Manchin told Hoppy Kercheval, host of “MetroNews Talkline.” But he also said he had been clear with Senate Majority Leader Chuck Schumer (D-N.Y.) and other Senate staffers that his support would depend on the June inflation figures that were released on Wednesday.

“They knew exactly where I stood,” he said. “When we saw 9.1%, that was an alarming figure to me … so I said, ‘Oh my goodness, let’s wait; this is a whole new page.’”

With the war in Ukraine, and Europe looking to the U.S. to replace Russian fossil fuels, Manchin argued that the U.S. can decarbonize while continuing to “produce more fossil [fuel] cleaner than anyone in the world and replace that dirty fossil going into the atmosphere.”

“Also, what you can do is invest in the cleaner technologies that we know that will work,” he said. “We know hydrogen is going to work; we know we need storage for batteries, and battery storage takes care of wind and solar; we know that. New transmission — we know all these things. Geothermal and small nuclear reactors, I’m for all these things.”

Manchin said he is also consulting economic experts to ensure that any tax increases that would be used to fund clean energy incentives don’t cause further inflation or cause companies to cut back production or lay off employees. A budget reconciliation package, with or without energy incentives, could still be passed when Congress returns from its August recess in September, he said, “if it’s a good piece of legislation.”

Post-election Green Pivot?

Biden’s statement did not detail the specific executive actions he might take to provide momentum for his stalled vision for an aggressive climate agenda. Manchin’s latest defection comes two weeks after the U.S. Supreme Court’s decision in West Virginia v. EPA undercut EPA’s ability to cut emissions at existing power plants through generation shifting — changing out dirtier fossil fuels for cleaner low- or no-carbon generation. (See Supreme Court Rejects EPA Generation Shifting.)

Biden has already used executive orders to set the U.S. on a path to a 100% carbon-free electric system by 2035 and a net-zero economy by 2050. More recently, he invoked the Defense Production Act to ramp up clean energy manufacturing and ordered a two-year suspension of potential tariffs on solar cells and panels from Cambodia, Malaysia, Thailand and Vietnam in the face of a pending Commerce Department investigation. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)

Meanwhile, the Department of Energy is continuing to distribute new funding, much of it from the Infrastructure Investment and Jobs Act, for clean energy initiatives.

If fully funded, the law will continue to pump out funds for clean energy through 2026. For example, on Thursday, the DOE announced $29 million in funding, about a third from the IIJA, to increase the reuse and recycling of solar technologies and develop solar panel designs that reduce the cost of manufacturing.

In the wake of West Virginia v. EPA, California Gov. Gavin Newsom (D) and Washington Gov. Jay Inslee (D) both vowed to step up their efforts to cut carbon emissions. More recently, the D.C. Council passed legislation, pending before Mayor Muriel Bowser, that would ban natural gas hookups in new construction and require all new construction and major renovations in the district to be net-zero by 2026.

But, in its analysis of the post-Manchin state of play, industry analysts ClearView Energy Partners suggest that if the Republicans do gain majorities in the House and Senate in the midterms, Biden might “pursue muscular intervention into energy markets and capital formation … potentially including ‘a climate emergency’ declaration.”

“If the White House was also modulating its oil and gas policy in recent months to woo [Sen.] Manchin’s support for clean energy incentives, then Manchin’s latest defection could bring an even bigger post-election green pivot,” ClearView said.

In the absence of a “mini-BBB” budget reconciliation deal, ClearView also sees the potential for a congressional pivot toward passing a package of clean energy tax credit extenders in the lame-duck session between the midterm elections and the opening of the next Congress in January. Although the option of tax extenders has not been discussed thus far, “we would not be surprised to see extenders text proposed (or at least mooted) by the House Ways and Means and Senate Finance Committees before lawmakers leave for their August recess,” ClearView said.

Some Republicans might support extender legislation for two reasons, ClearView said. First, even if the GOP takes both houses of Congress, Biden will still have veto power, and second, a growing number of red states are now generating about half of the country’s onshore renewable and other clean forms of energy.

Underway and Unstoppable

Perhaps with such tax extender legislation in mind, clean energy advocates and business groups continued to call for congressional action on federal tax credits and other incentives, echoing administration arguments that they will help fight inflation, spur economic growth and protect energy security.

Clean energy tax credits “would deliver much needed relief, helping to cut energy prices and reduce U.S. dependence on price-volatile fossil fuels, by spurring the domestic manufacturing and deployment of clean, affordable and reliable advanced energy technologies,” said Heather O’Neill, president of Advanced Energy Economy. “Failing to use this opportunity to boost the domestic advanced energy manufacturing industry would mean American workers get less benefit from the world’s transition to clean energy, and would all but assure that our economic competitors, particularly China, reap the economic rewards instead.”

O’Neill and others also pushed hard on the business case for clean energy. The transition is “underway, and it is unstoppable,” O’Neill said. “We see it in corporate procurements driving clean energy investment across the country. We see it in consumer demand for electric vehicles as drivers seek to free themselves and their pocketbooks from the volatility of gasoline prices.”

“The private sector is making record-level investments in the clean energy transition, but a predictable and long-term national tax and policy framework is needed to support accelerated and expanded deployment,” said Lisa Jacobson, president of the Business Council for Sustainable Energy.

Any effort to find common ground on tax credits might begin with carbon-capture technologies and that industry’s 45Q tax credit, both of which have had strong support from Manchin, whose family still operates the coal company he started.

“While there is uncertainty about next steps with the reconciliation process, it remains clear that there is broad, bipartisan support for Congress to provide robust investments in carbon-management policies,” said Madelyn Morrison, external affairs manager for the Carbon Capture Coalition. “To achieve carbon capture and removal at climate scale, Congress must deliver the full portfolio of federal policy support for carbon management in any moving legislative vehicle, including a direct-pay option for the 45Q tax credit.” Manchin has recently opposed any direct-pay options for clean energy tax credits.

July 17, 2022

MISO Promises Stakeholder Discussions on Capacity Auction Reform

MISO leadership last week committed to holding future talks with stakeholders on how to retool its capacity auction to stimulate more supply.

Scott Wright, the RTO’s executive director of market strategy, said the growing reliability risk will require staff and stakeholders to discuss modifications to price signals and how to value resources’ different attributes in the capacity market.

The discussions will be held in the Resource Adequacy (RASC) and Market subcommittees during the next few months, Wright said. He added that the conversations will likely include potentially adding a sloped demand curve in the capacity auction. (See MISO Warming to Patton’s Sloped Demand Curve.)

“MISO is committed to coordinated action and is developing plans for near-term evaluation and stakeholder engagement,” Wright told stakeholders during a Resource Adequacy Subcommittee meeting Wednesday. “We’re not deferring this to next year; we want to get going this year.”

The vow was repeated the next day during a Market Subcommittee meeting.

“We’re looking through what the plan is and will return to these forums,” MISO Senior Director of Transmission Planning Laura Rauch said.

Independent Market Monitor David Patton said after speaking with state regulators following the April planning resource auction (PRA), he’s “cautiously optimistic” that MISO will be on a path to applying a sloped demand curve within six months

“The best time to implement a sloped demand would have been when you’re not in shortage,” he said.

MISO Midwest is grappling with a 1.2-GW capacity shortage following the 2022-23 PRA. The shortfall triggered a $236.66/MW-day cost-of-new-generation-entry clearing-price for the Midwestern subregion. MISO has said the deficit might force it to order temporary, controlled load sheds this summer and next as it is not expecting sufficient firm resources to handle summer peak forecasts under typical demand. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

Though members approached this year’s auction with more capacity year-over-year, staff said the resource additions were mostly intermittent and generally less available than retiring thermal generators.

Stakeholders Ask for Data Improvements

Constellation Energy’s John Orr said staff’s posting of preliminary supply and demand data for the PRA could use some improvements and more regular updating.

Orr suggested MISO implement a standardized timeline for posting forecasted capacity positions by local resource zone, perhaps releasing the data in January and updating it on a weekly basis as market participants update capacity values. He said MISO should periodically update how much capacity has been converted to zonal resource credits. He said if a particular zone returns a zero value ahead of the auction, that could spur members into making arrangements to avoid another capacity shortfall.

Orr said a weakness of MISO’s 2022-23 preliminary data was that it was never updated beyond a singular release.

“We all knew those numbers are incomplete, but they gave us an idea of what to expect, especially in zones that are predicted to be tight,” Orr said. He, like other stakeholders, questioned why they failed to warn of a potential shortage.

Orr said he thinks “it’s time for stakeholders to ask MISO what they want to see” and asked stakeholders to work together to develop recommendations to MISO.

He said market participants need a better idea of what resources are expected to be unavailable, either due to retirements or auction exemptions and exclusions approved by the IMM.

“The exemptions and retirements that are protected by confidentially can really kind of can throw you off when you’re going to be very tight, as it appears we’re going to be for the next several PRA cycles. And the seasonal auctions could throw another wrinkle in that,” Orr said.

WEC Energy Group’s Chris Plante said his utility is having “a lot of difficulty” preparing quadrupled data for a yet-uncertain seasonal capacity auction. FERC has yet to approve MISO’s request to conduct four seasonal auctions per year.

In the meantime, MISO leadership continues to issue grim warnings over its forecasted capacity supplies.

During a July 7 meeting with Kentucky lawmakers, Melissa Seymour, vice president of external affairs, said that part of the state might face controlled load shedding next year.

Seymour delivered a similar message in front of the Illinois Commerce Commission in May. (See MISO Exec, IMM Debate Next Steps After Capacity Auction Shortfall.)

“Unless more capacity is built or bought, especially capacity able to reliably generate during tight system conditions, the shortfalls we experience this year will continue and get worse going forward,” she said.

MISO’s wholesale footprint affects just 14% of Kentucky’s retail power sales.

Seymour’s comments led Kentucky lawmakers to suggest ramping up coal production, delaying coal plant retirements, and even bringing some nonoperational coal plants out of retirement.

According to its pending 2021 integrated resource plan, Louisville Gas and Electric and Kentucky Utilities intend to retire a dozen aging coal and gas-fired units from 2024 to 2036.

“As a generation unit ages, the economics of retrofitting the unit to comply with new environmental regulations become less favorable,” LGE and KU explained in the filing. However, the utilities still plan to burn coal into 2066.

New Accreditation for Renewables in the Works

MISO continues to evaluate new capacity accreditation designs with stakeholders for the footprint’s renewable resources and load-modifying resources.

During the July RASC meeting, the RTO’s director of policy studies, Jordan Bakke, said staff and stakeholders are “learning together” about accreditation options for non-thermal generation. He said MISO is still in an evaluation stage and hasn’t internally settled on an option.

Patton said once MISO more accurately accredits intermittent resources, it should send economic signals to developers to pair their renewable energy with battery storage. He said co-located renewable and storage hybrid resources will likely have a much higher capacity credit.

MISO laid out three potential options this spring to accredit renewable resources: expand its effective load carrying capability (ELCC) calculation to include solar as well as wind; use the same performance-based accreditation design that it proposed for its thermal generation and currently pending before FERC; or use a blend of ELCC and performance-driven accreditation.

Some stakeholders expressed confusion with how the blended option would be handled. Staff said they would use its projected loss-of-load risk hours and MISO’s new concept of “resource adequacy hours” — the historical tight margin and emergency periods defined for the performance-based accreditation design — as possible inputs for the new accreditation method. (See MISO Stakeholders Insist on Consistency in Capacity Accreditations.)

The RTO filed with FERC late last year to change its accreditation for conventional resources to a seasonal value based on a unit’s past performance during resource adequacy hours. The new accreditation is contained in a larger filing to create four seasonal capacity auctions. (See Deficiency Notices for MISO’s Seasonal Capacity Auctions Bid.)

The grid operator said the blended approach for renewables has the potential to encompass a “broader range of planning and operational considerations.” Staff said loss-of-load hours and resource adequacy hours don’t necessarily occur on the same days.

MISO plans to discuss a new accreditation method for its non-thermal resources in RASC meetings and special workshops through the end of the year.

July 17, 2022November 30, 2023

NV Energy Surpasses 2021 RPS Requirement

NV Energy exceeded Nevada’s renewable portfolio standard requirement of 24% in 2021, with nearly 31% of its retail energy sales coming from renewable resources and related credits, according to a report approved by state regulators last week.

NV Energy subsidiary Sierra Pacific Power, which serves northern Nevada, achieved 31.9% renewable energy last year. Southern Nevada subsidiary Nevada Power reached 30.1% renewable energy. The statewide weighted average was 30.7%, according to the report filed by the utility in April.

Last year’s adjusted retail sales were 8,728,248 MWh for Sierra Pacific and 20,712,404 MWh for Nevada Power.

The Public Utilities Commission of Nevada (PUCN) voted 3-0 on Tuesday to approve the report and confirm that NV Energy complied with the 2021 renewable portfolio standard.

50% by 2030

Nevada’s RPS was 24% last year, an increase from 22% in 2020. The RPS grows to 29% in 2022 and 2023; 34% in 2024 through 2026; 42% in 2027 through 2029; and 50% in 2030. NV Energy said it is “well on its way” to meeting the 50% renewable requirement by 2030.

“Our commitment to evolving our generation mix is one of many ways we are helping meet our state’s sustainability goals,” Dave Ulozas, NV Energy’s senior vice president of energy supply, renewables and origination, said in a release shortly after the utility filed its report with PUCN.

Last year was the 12th year in a row that the company surpassed the state’s renewable energy requirement, the release said.

DSM, Carryovers

Under Nevada statute, energy efficiency measures may count toward up to 10% of the annual RPS requirement, through 2024. After that, energy efficiency measures — included within demand side management (DSM) — can’t be used toward meeting the standard.

NV Energy used energy savings from DSM to satisfy 10% of its RPS requirements last year.

In addition, the utility used excess portfolio credits carried over from 2020 to help meet last year’s RPS requirement. And surplus credits from last year will be carried over to this year.

State law allows a utility to sell excess portfolio credits when the surplus is more than 10% of the required amount. If the surplus is more than 25% of the amount needed to meet the RPS, the utility is directed to “use reasonable efforts to sell” credits in excess of 25%.

Sierra Pacific went over the 25% threshold with its surplus portfolio credits and solicited offers to buy them. Although the utility received seven offers, it ultimately decided to keep the credits in case it needs them later, according to the report.

Nevada Power had surplus portfolio credits in the 10% to 25% range. NV Energy said it would consider selling the credits “if the circumstances are favorable and the sale benefits our customers.”

New Solar Projects

At the end of 2021, Nevada Power had about 1,570 MW of renewable generation capacity in service, according to NV Energy’s filing. Nevada Power added one utility-scale renewable project last year, Copper Mountain 5, a 250 MW solar facility in Boulder City.

In addition, Nevada Power had nine solar projects totaling 2,044 MW in development at the end of last year. Eight of those projects include battery storage.

Sierra Pacific finished the year with about 692 MW of renewable capacity in operation. During 2021, one new project was added: the 101 MW Battle Mountain solar facility, which includes 25 MW of storage.

The utility also had six solar projects with a combined total of 824 MW in development at the end of the year. All the projects include battery storage.

NV Energy’s filing described a “positive” outlook for both of its subsidiaries to comply with the RPS and other future credit commitments.

However, the utility noted some risks. In particular, delays in receiving solar panels and other project components are causing project completion dates to be pushed back and could result in project cancellations, the RPS report said.

“Delays and shortages can drive up costs to a point where a project that was previously economical becomes uneconomical,” NV Energy said.

July 17, 2022November 30, 2023

Residents Voice Opposition to Upstate NY Wind Project Before PSC

Residents opposed to the Heritage Wind project planned for western New York spoke before the Public Service Commission on Thursday, citing human health concerns, danger to migratory birds in nearby game refuges and a lack of transmission capacity (22-E-0204 and 16-F-0546).

The developers “maintain that there will be no change in property value in our area. We would have six of the wind turbines almost 600 feet tall within 1 mile of our home and the fact that they tried to maintain that there would be no effect on our property value or anyone else’s property value in this area I think is considerably a falsehood,” Iva McKenna — a resident of Barre, where the project is to be located — told the PSC.

While only five people spoke at the hearing, all against the project, the initial proceeding drew 452 written comments, which were overwhelmingly opposed to the project, though about two-thirds of the total was form letters.

Only three of the 17 written comments submitted for the public hearing were in support. Austin Kuntz, union representative for Rochester-based Laborers’ Local 435, said the project will bring hundreds of prevailing-wage jobs to local residents, provide them and their families with health care benefits and a suitable retirement, and fund schools, public services and infrastructure without the need to raise local taxes.

The southwestern section of the Heritage Wind project lies within a mile or two of national and state wildlife areas. | Heritage Wind

The Office of Renewable Energy Siting (ORES) in January granted a construction permit for the project in Barre, between Rochester and Niagara Falls, contingent on securing a certificate of public convenience and necessity from the PSC. The project is owned by Virginia-based Apex Clean Energy, which manages 2 GW of renewable energy.

Barre resident Adrienne Daniels commented on July 1 that her seizure disorder “very likely will be further affected by the towers’ flicker effects. … The proposed heights of the towers are ludicrous. It has to cause problems with airspace for the small airport nearby, bird populations, migration routes, etc. An eagle has nested on my property; I strongly doubt we’ll have any other large birds establishing nests in this area.”

With 4,607 gravel truck trips projected, resident Georgette Stockman said that if “they plan to use Route 77, will the movement of equipment and components pass the new Western New York Veterans Cemetery, where two people have already lost their lives trying to negotiate their way onto Route 77? Will the equipment go through the Iroquois Wildlife Refuge and disturb the very nature of a refuge?”

Barre resident George McKenna reiterated his written concerns that the $198 million to be paid by NYSERDA for the project was “a wash” and that it would take at least 20 years to get that sum back in electrical energy value.

He also said Barre citizens have never had their opinions or concerns listened to.

“Surveys have shown approximately 70% of the population in opposition, and when the town board was in the process of changing the town’s wind ordinance to accommodate Heritage Wind, 87% of the population was opposed,” McKenna said.

Resident Kerri Richardson spoke of the inability of the transmission system to deliver increasing amounts of upstate renewables to downstate consumers and how that situation jeopardizes achieving the state’s public policy goals.

“The NYISO 2019 Power Trends report identifies that it is not actually in the public interest or public need to move forward with this project in particular,” Richardson said. Quoting from the report, she said, ‘Even with the Western New York and AC transmission projects already selected by the NYISO, congestion on the system will persist, complicating the state’s ability to meet its renewable energy goals.’”

In its January 2019 award of renewable energy credit (REC) contracts, the New York Energy Research and Development Authority (NYSERDA) noted that it was supporting 20 large-scale renewable projects, including Heritage, and that 93% of the awarded capacity would be located upstate (in zones A-E), where clean energy resources are already abundant and access to load centers in southeastern New York is heavily constrained, bottled in so-called generation pockets.

In its 2022 Power Trends report issued last month, NYISO projected that “transmission constraints in these pockets will likely result in curtailment of 11% of the total potential renewable energy production across New York, with curtailment levels in some individual pockets as high as 63%. As more renewables are added to the bulk electric system without additional transmission expansion, greater congestion and curtailment levels will occur.”