Page 1169 – RTO Insider

April 12, 2020

MISO Exploring Emergency Pricing, Forward Market

By Amanda Durish Cook

MISO is gearing up for a forward market mechanism and improvements to its scarcity and emergency pricing as market-side solutions under its yearslong resource availability and need (RAN) project.

Emergency pricing is often “inconsistent” with system conditions, MISO has concluded. During a Market Subcommittee teleconference Thursday, Market Design Adviser Michaela Flagg said the RTO’s shortage and emergency pricing has generally been inefficiently low.

In a now familiar refrain, Independent Market Monitor David Patton said MISO does not accurately price the “true value of energy when we’re tight.”

MISO emergency pricing — Michaela Flagg, MISO | © *RTO Insider*

Suppressed prices during emergencies are prevalent in MISO South, Flagg said, because of a flaw in which the RTO’s pricing engine does not account for congestion from flows crossing the transmission constraint between the South and Midwest subregions. Accounting for that congestion is just one avenue MISO may pursue, she said.

Other solutions may include updating MISO’s value of lost load or changing the shape of the operating reserve demand curve.

“Prices should be high enough to reflect that MISO is running out of resources when it makes emergency declarations,” the RTO said.

Flagg said MISO will complete an evaluation of its emergency pricing by June and a scarcity pricing evaluation by December. Proposed solutions will follow the evaluations.

Director of Market Design Kevin Vannoy said MISO could stimulate imports and avoid making emergency purchases if it raises prices during scarcity events.

Customized Energy Solutions’ Ted Kuhn said MISO currently cannot compete for resources against neighboring RTOs, where prices can go as high as $8,000/MWh.

“At some point we’re going to have to match up on emergency pricing or ask FERC to join the bus,” Kuhn said at a Market Subcommittee meeting March 5.

Vannoy said MISO is also considering a forward market process that can guide commitment decisions before the day-ahead market is able.

“We definitely see that resource commitments and margins are becoming more challenging with lower operating margins and system volatility,” he said, noting that MISO’s must-run coal units have entered a retirement trend and lower LMPs incent fewer commitments.

“We definitely need more information earlier on capacity sufficiency and earlier than the day-ahead market,” Vannoy said, adding that long-lead units “are out of reach of the day-ahead market commitment.”

He said MISO is looking for members to provide input on what they look for to make unit commitment and availability decisions.

“For the most part, owners with long-lead and high-start-up-cost resources were making those decisions based on their own optimizations and their view of the market. Those decisions are becoming more and more challenging,” Vannoy said.

MISO is also experiencing an increase in emergency-only capacity as part of the overall portfolio, he said. Such resources require an emergency declaration before the RTO can access them.

But Madison Gas and Electric’s Megan Wisersky said MISO could encourage the construction of the more flexible generation it wants, saying insufficient transmission buildout in the footprint is restricting utilities’ ability to build new generation.

“It isn’t for grins that you see the growth in load-modifying resources. We as load-serving entities have to do something, and it takes years in the interconnection queue and some unknown dollar amount for network upgrades,” Wisersky said. “The easiest, fastest, cheapest thing we can do is put in demand-side resources.”

Scarcity and emergency pricing and a forward market mechanism comprise the market-side improvements in MISO’s multifaceted RAN effort. The changes under discussion include moving capacity resource accreditation and the capacity auction from an annual basis to a seasonal or subannual basis.

MISO Executive Vice President of Market and Grid Strategy Richard Doying said the RTO’s annual resource adequacy design is also open to further changes.

“Is it worth conducting [the auction] four times a year, or is there something else to provide that platform for liquidity and trading?” Doying asked rhetorically.

“We can all see the portfolios evolving. We’re not sure it’s an imperative for this change,” WPPI Energy economist Valy Goepfrich said.

April 12, 2020

MISO Considers COVID-19 Queue Waivers

By Amanda Durish Cook

MISO on Friday gathered interconnection and transmission customers in a special teleconference to discuss potential waivers of its queue requirements because of the ongoing COVID-19 pandemic.

Senior Corporate Counsel Chris Supino told call participants that MISO is “willing to consider seeking waivers” from FERC of some generator interconnection and agreement requirements to give extra time to parties navigating the queue under the cloud of the pandemic.

Supino asked interconnection customers and transmission owners to tell their pandemic-related impacts to MISO. The RTO said it’s exploring some deadline extensions related to satisfying site control requirements, temporarily relaxing deadlines around study deposits and extending time frames for facility studies.

MISO COVID-19 Queue Waivers — Chris Supino, MISO | © *RTO Insider*

“We understand it’s hard to get out to the land and talk to landowners,” Supino said of MISO’s requirement that customers demonstrate 100% site control 90 days before proposed projects enter the first of the three-part definitive planning phase of the queue for study.

Supino also said interconnection customers have expressed concerns over the “general availability of consultants, advisers and legal teams” during social distancing mandates. The limited accessibility of third-party contractors could delay critical aspects of generation projects, some stakeholders said.

Other stakeholders are asking MISO to extend its usual three-year grace period for projects to achieve commercial operation in generator interconnection agreements.

Supino said MISO wants to keep the waivers “reasonably limited” to the next few months to prevent cascading impacts to the queue.

“We are looking to address requirements that are an issue for a large portion of our stakeholders, or at least a substantial group,” he said. “We’re not looking for one-off circumstances. I know that many different things can happen with a project, and there might be temptation … but we want to keep this focused on the issue at hand here.”

Supino said customers who believe that special circumstances related to the pandemic are impacting their interconnection projects should “contact MISO to discuss their specific situation and why further waiver relief is needed.” He said stakeholder feedback so far appears reasonable, focused on “pushing deadlines out,” not weakening or rewriting queue requirements.

“We don’t want to over-relax requirements or cause problems for customers, or impact the next queue cycle,” he said, adding that MISO also doesn’t want to put renewable projects in jeopardy of not receiving production tax credits.

MISO has several queue deadlines looming in the next 90 days, including: a June 25 application deadline for a new cycle of project proposals; proof of site control for MISO South projects in the 2020 cycle; the first decision point on whether to remain in the queue and risk monetary penalties for the 2019 batch of South generation projects; and the second decision point for Central and East projects that entered the queue in 2018.

Staff so far said they haven’t fallen behind in the processing of applications or the study of interconnection requests. “We’ve successfully transitioned to most of our employees working from home,” Manager of Probabilistic Resource Studies Ryan Westphal told stakeholders.

NextEra Energy Resources’ John Dailey said interconnection customers beyond those entering the queue in June will be affected. He said interconnection customers planning to enter the queue over the remainder of the year had already been working on securing land.

WPPI Energy’s Steve Leovy cautioned MISO not to tie temporary queue extensions to any federal or state declarations, as the stages of the pandemic are quickly evolving. He instead urged the RTO to examine the “general circumstances” of the crisis.

Clean Grid Alliance’s Rhonda Peters thanked MISO for considering waivers and asked how quickly it could put them in place. Supino said that FERC has been processing pandemic-related waivers “very quickly.”

PJM has already filed a queue waiver to extend study deposit due dates, feasibility studies and reviews of new service requests and processing. NYISO has obtained a waiver of its notarization requirements.

MISO will discuss possible queue waivers with the Planning Advisory Committee during its April 15 conference call.

April 12, 2020

COVID-19 Transforming MISO Load, Outage Schedules

By Amanda Durish Cook

The MISO footprint sank deeper into the COVID-19 twilight zone in early April, with demand flattening further and some maintenance outages frozen until some semblance of normalcy is restored.

As the coronavirus pandemic wears on, the RTO is experiencing lower loads that no longer follow a sharp uptick in demand in the morning or evening. MISO said the usual morning peak at about 9 a.m. has given way to a gentler bump in demand around noon that holds steady until the evening, when it gradually drops off. (See MISO Deepens Insights into Pandemic Impact.)

But MISO now says the slight morning and evening bumps have become even flatter in early April.

“The evening peak is now almost nonexistent,” MISO Director of Central Region Operations Ron Arness told stakeholders on a Market Subcommittee teleconference Thursday. “As people started staying home more, we began to see a shift in our load profile. … But then as we got into further restrictions and less activity in more and more areas in the country, we started to see a bigger deviation.”

MISO’s deviation from its historical load trends currently stands at about 8% for the first week of April.

“We continue to track it,” Arness told stakeholders. “We see that load continues to tweak down.”

MISO load COVID-19 — MISO load deviations because of the coronavirus pandemic | *MISO*

Arness said MISO South so far is the least impacted by different load shapes during the pandemic.

Independent Market Monitor David Patton said his analysis of the impacts are “on the same page” as MISO’s.

Skeleton work crews at some generation and transmission sites continue to delay some planned maintenance outages, Arness reported. MISO continues to assert that outage delays and reschedules aren’t a threat to reliability.

MISO said it has received 33 requests to move or cancel planned transmission outages since the pandemic took hold, representing about 10% of planned transmission outages. Arness said only some of those reschedules are related to COVID-19 restrictions. Half the outage reschedules will be moved to May and the first part of June; the other half have been canceled.

On the generation side, 30 generator outages representing about 16 GW will be moved from their original dates; all are pandemic-related. Arness said about a third of these will be rescheduled in the fall; another third are “still determining their reschedule plans.”

Arness said MISO is working with transmission and generation owners to reschedule outages, being careful to avoid clustering them around the summer peak.

“Again, we don’t see any big alarms when the COVID-19 [emergency] lifts,” Arness said, adding that MISO has seen “very few” reschedules to June.

“It is a dynamic situation, and we’ll continue to monitor it,” he added.

Stakeholders asked if MISO might become jammed up with outages come fall. Arness said he’s discussing the possibility with the RTO’s outage coordination team.

Stakeholders also asked if MISO would grant amnesty to members that violate the 120-day outage notice requirement because of the pandemic-related scheduling. Arness said members should contact their assigned outage coordinators to discuss their rescheduling needs.

April 9, 2020

PAS Seeks Better Weather Data for Reliability Reports

By Holden Mann

NERC’s Performance Analysis Subcommittee (PAS) this week reviewed the first draft of the organization’s annual State of Reliability (SOR) Report and identified a number of issues to resolve before releasing the document this summer.

Lack of Weather Data Questioned

Most of the topics discussed by subcommittee members revolved around relatively uncomplicated issues such as consistency of language or adding additional context to the report’s narrative sections. However, the collection of data on severe weather events led to a longer discussion, as participants questioned the exclusion of such events from the report’s record of transmission events with loss of load. Several members said leaving out such information seemed counterproductive to the purpose of the report.

“If you want to define resilience as the ability of the system to withstand these types of events, we need to include weather,” said David Penney of Texas Reliability Entity. “So, maybe for next year’s SOR, do you think it’s possible to … separate out the weather events so we can put that in the discussion of system resilience?”

Ed Ruck, a senior reliability engineer at NERC, warned the subcommittee that while it might be possible to incorporate information on weather conditions into future reports, there are major practical challenges that preclude getting it done this year. Even gathering the data for next year could represent a prohibitive time investment, as the Event Analysis Subcommittee (EAS) — which provided the data used in the report — is not required to include weather-related data in its event reporting.

“This data is not in a database anywhere,” Ruck said. “We have to go through each event one by one … to find out this information. This is not going to be an easy undertaking.”

Several members asked why the EAS was not required to store this information in the first place. Nobody present had direct knowledge of the reason, though Penney suggested that it was “because [entities] can’t control the weather,” and NERC preferred that data collection focus on events that operators could have helped prevent.

Recovery Data Recommended for Inclusion

In addition to collecting data on the contribution of severe weather to transmission events, members also suggested future reports include data on recovery that are not presented in the current version of the report. In response, Ruck warned that this too would be a more difficult and time-consuming effort than members realized.

“That is also something that [the EAS] does not do; we don’t look at how long it takes something to recover,” Ruck said. “We look at what happens that leads up to that incident, but we really don’t go into how long it takes to recover from an incident. I don’t even think that data would be there.”

The next PAS meeting is scheduled for July 28-29, though whether the subcommittee will meet in person or via conference call again has not been decided. The team has also agreed to conduct an online meeting each week for one to two hours, starting next week, so that the subgroups working on smaller issues can keep the full subcommittee up to date on their progress.

April 9, 2020

MISO Offers Concession on LMR Capacity Credit Plan

By Amanda Durish Cook

MISO is offering stakeholders a compromise on one of two resource adequacy proposals it will file with FERC next month, removing a provision that would eliminate capacity credits for slow-response load-modifying resources (LMRs).

Zakaria Joundi, MISO’s recently appointed director of resource adequacy coordination, acknowledged he’s entering his new role as the RTO completes a contentious proposal. Nevertheless, he called the LMR measure “a step in the right direction” for MISO.

But several stakeholders on a Resource Adequacy Subcommittee teleconference Wednesday blasted the filings as poorly supported and questioned their need. The proposals include measures to reduce capacity accreditation for LMRs based on their actual ability to mitigate reliability issues and require resources to procure transmission deliverability to their full installed capacity levels before receiving full capacity credits. (See MISO Prepares Deliverability, LMR Accreditation Filings.)

The proposals are set to take effect in time for the 2021/22 Planning Resource Auction.

LMR Accreditation Alterations

MISO said employing an LMR accreditation “based on lead times and call capacity” will lead to more reliable operations.

The RTO plans to base an LMR’s capacity accreditation on the smaller of either an average of its actual availability over a three-year period or its tested availability. LMRs that can respond more often and with shorter lead times will receive a larger capacity credit, while those that can respond to 10 or more calls in a year will receive full capacity credit. (See MISO Pursues Leaner LMR Accreditation.)

MISO LMR Capacity Credit — MISO’s new proposal for LMR capacity credit | *MISO*

But MISO said it will put a two-year hold on its plan to eliminate capacity credits for LMRs that cannot be ready to reduce load within six hours.

Instead, the RTO now proposes that LMRs with lead times greater than six hours but less than or equal to 12 hours receive a 50% capacity credit if they can respond to at least 10 calls in a year. MISO said the compromise should only be effective until 2023, when the RTO will again seek a 0% capacity credit for the long-lead resources.

MISO has previously said that LMRs needing more than six hours’ notice don’t help mitigate emergency conditions, when time is of the essence.

The proposal still calls for demand response resources to receive a 100% credit if they can be available within six hours or less to 10 calls or more in a year, while resources that can respond to five to nine calls would receive an 80% accreditation. Behind-the-meter generation (BTMG) that can deploy with notice of six hours or less and respond to five or more calls in a year would also receive a 100% capacity credit. MISO staff explained that BTMG accreditation requirements are more lenient because their credits are already reduced by a forced outage rate.

Stiffer Capacity Deliverability

MISO is holding firm on a provision that would eliminate capacity resources’ ability to demonstrate full deliverability by way of unforced capacity (UCAP) levels, plucking full capacity credits from resources that use a UCAP-based determination. Instead, the gold standard in capacity deliverability would be resources that can procure firm transmission up to their installed capacity (ICAP) levels.

The RTO’s Tariff requires capacity resources to demonstrate capacity deliverability by having network resource interconnection service (NRIS), which stipulates that the entire ICAP of the resources must be deliverable. However, the Tariff also allows resources to demonstrate deliverability by securing energy resource interconnection service (ERIS) and procuring firm transmission service up to their UCAP levels, which tend to be about 5 to 10% below full ICAP levels. MISO’s Independent Market Monitor has contended that the RTO doesn’t properly account for capacity deliverability because its loss-of-load expectation study assumes that all capacity resources are fully deliverable on an ICAP basis.

MISO has said that while it would not require planning resources to procure full transmission service up to their ICAP levels, resources that are only partially deliverable would not receive full capacity credits. The RTO said it would be fine for conventional generators to opt not to purchase additional transmission service and settle for fewer zonal resource credits.

“There will be impacted entities,” Joundi said of the stricter deliverability requirement. He conceded that it may be expensive for some resources to secure firm transmission service up to their ICAP levels.

Customized Energy Solutions’ Ted Kuhn asked if MISO has determined a course of action if FERC rejects either the LMR capacity accreditation or ICAP deliverability proposals.

“Although it’s a policy to never answer a hypothetical, this depends on the reaction from FERC,” MISO Executive Director of Market Operations Shawn McFarlane said. He said the RTO would only rework the proposal if FERC indicates there’s a “tremendously fatal flaw” in the LMR filing. It would, however, have enough time to pursue a “two-step” process with FERC, he said, meaning a refiling to correct small concerns, if the commission has them.

However, McFarlane said the proposals at this point aren’t open to further stakeholder suggestions.

Opposition

Some stakeholders remain opposed to both measures, with most pushback against the LMR measure. Critics say MISO hasn’t made a convincing argument that the LMR accreditation process needs more rules.

Customized Energy Solutions’ David Sapper, representing MISO load-serving entities, said the RTO hasn’t demonstrated that its proposals will make capacity more abundant or available.

“MISO has neither clearly defined a problem with LMR contribution to resource adequacy nor demonstrated benefits from its proposed solutions that outweigh expected high costs of the solutions,” Sapper said.

He pointed out that it was only a little more than a year ago that MISO got permission to require its LMRs to offer capacity in less than 12 hours and in accordance with a seasonal availability report. (See MISO LMR Capacity Rules Get FERC Approval.)

“It’s not clear why MISO is not letting the new processes work,” Sapper said, adding that the RTO’s six-hour lead time benchmark “will drive at least some” LMRs from the PRA.

Sapper advanced a motion that the subcommittee formally oppose the LMR filing — which it will put to an email vote.

McFarlane said the number of LMRs registering as capacity resources within the footprint only continues to increase, as do the number of emergency events. He said the uptick in both means MISO doesn’t have the luxury of waiting longer to propose new rules.

Staff also said the first FERC filing regarding LMRs was always intended to be a stopgap as MISO worked on a fuller solution.

“We think the 50% accreditation, especially in the next PRA, is a drastic change,” Michigan Public Service Commission staff member Bonnie Janssen said.

WPPI Energy’s Steve Leovy said he remains dissatisfied with the solution and what he perceives as rigidness on MISO’s part to change the proposal on stakeholder advice.

“We were careening towards a solution that I felt was pretty clear at the outset,” Leovy said, adding that he remains concerned about “shocks to MISO’s resource adequacy” as a result of the reductions in LMR capacity credits.

“What I’ve seen is a sharpshooter approach where [MISO] singles out a certain resource and just picks on it when there are other things it could do,” Kuhn said.

April 9, 2020March 12, 2026

Trader Challenges PJM FTR Forfeiture Rules

By Rich Heidorn Jr.

A financial transmission rights trader has filed a new challenge to the way PJM and its Independent Market Monitor prevent gaming, saying it is “so broad that it captures competitive market conduct and leads to less efficient market outcomes.”

XO Energy, of Landenberg, Pa., asked FERC to order PJM to change its FTR forfeiture rule or abandon it and adopt “a structured market monitoring approach” like the one used by MISO (EL20-41). The company said it exited PJM’s virtual market in December after getting hit with $4.3 million in forfeitures.

FTRs allow load-serving entities to hedge the risk of transmission congestion costs; they also allow financial traders to arbitrage day-ahead and real-time congestion.

Ten largest positive and negative FTR target allocations summed by sink: 2019/2020 | Monitoring Analytics

PJM implemented the forfeiture rule to prevent market participants from using virtual transactions to create congestion that benefits their FTR positions. The FTR holder forfeits the profit from its FTR when it submits an increment offer (INCs) or decrement bid (DECs) at or near an FTR location that results in a higher LMP spread in the day-ahead market than in real time.

In January 2017, FERC ordered PJM to change how it implements the forfeiture rule, saying the RTO’s focus on individual transactions failed to capture the impact of a market participant’s overall portfolio of virtual transactions on a constraint (EL14-37). (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)

PJM filed Tariff revisions in April and June 2017 describing its new approach (ER17-1433). In September 2017, PJM began billing forfeitures based on its new approach, XO said, despite the fact that the commission has never acted on it.

Financial Leverage Test

To encourage legitimate hedging while preventing manipulation, XO said PJM’s forfeiture rule should be changed to identify when participants that hold physical assets and engage in virtual transactions have a leveraged portfolio — when the net benefits to the participant’s FTRs exceed the net losses of its virtual transactions on a given constraint.

“A critical defect of the FTR forfeiture rule is that … it fails to consider whether a market participant has financial leverage, rendering the rule unjust and unreasonable,” XO said. “If financial leverage does not exist, further scrutiny of a market participant’s activity is unnecessary.”

XO said the rule also must require the Monitor to determine the participant’s intent.

Monthly FTR forfeitures for physical and financial participants | Monitoring Analytics

“There is no such thing as a properly designed automatic forfeiture rule; any forfeiture rule should only relinquish profits from conduct that, if combined with sufficient credible evidence of intent, would constitute a potential violation,” XO said. “In Order 670, the commission found that a fundamental component of any alleged manipulation claim is whether the market participant acted with sufficient scienter or intent.

“Although the presence of financial leverage can be easily determined, a comprehensive, fact-specific examination is necessary to identify sufficient evidence of intent.”

Although PJM and CAISO use forfeiture rules, XO said MISO, NYISO, SPP and ISO-NE “use their market monitoring function to provide surveillance in lieu of a rule that oftentimes captures rational economic behavior.”

XO complained that market participants lack access to the data on which forfeiture determinations are made and that the assessments are made more than two months after the activity in question. “The current FTR forfeiture rule has resulted in market inefficiencies by penalizing financial market participants whose virtual activity is profitable. In addition, market participants with physical positions are unable to hedge their physical load or generation positions.”

PJM did not respond to questions about the complaint.

Monitor Joe Bowring said in an email that “the complaint rehashes old and discredited arguments in an effort to overturn a rule which efficiently and effectively protects the markets from manipulation. … It would be a waste of the commission’s, PJM’s and stakeholders’ time to proceed.”

Leaving the Markets

In 2019, XO said, it forfeited $4.3 million, while its gross FTR revenue was only $1.4 million, resulting in a net loss of $2.9 million.

As a result, XO said it withdrew from the virtual market in December 2019. It said Exelon and NextEra Energy Marketing stopped virtual trading also. NextEra did not reply to a request for comment on the complaint Thursday. Exelon declined to comment.

Exelon raised concerns similar to XO’s complaint in a problem statement in February 2018, and it backed a proposal to change the FTR impact threshold from PJM’s “penny test” to one of FTR flows of 10% or more across a constraint.

The Markets and Reliability Committee declined to adopt the proposal in April 2019. (See “Load Interests Block FTR Rule Changes,” PJM MRC/MC Briefs: April 25, 2019.)

April 9, 2020

ERCOT Stakeholders Dig into Real-Time Co-optimization

By Tom Kleckner

ERCOT stakeholders have begun the arduous process of reviewing and commenting on the protocol changes the grid operator has drafted to add real-time co-optimization (RTC) to its energy-only market.

Members of the Real-Time Co-optimization Task Force and other interested stakeholders began walking through staff’s initial set of protocol revision requests during a conference call Wednesday. The goal is to reach consensus and secure the changes’ approval before the year is out.

The task is not without consequence for staff and stakeholders.

Staff have drafted seven Nodal Protocol revision requests (NPRRs) and two other changes, using language the RTCTF developed last year as a starting point. The task force’s key principles were approved by ERCOT’s Board of Directors in February. (See “Real-Time Co-optimization Team Finalizes Scope,” ERCOT Board of Directors Briefs: Feb. 11, 2020.)

The revisions take up 549 pages, 248 alone for NPRR1010. The changes align the language related to the adjustment period (for trades, self-schedules and resource commitments) and real-time operations with the upcoming RTC terminology and operating environment.

ERCOT Real-Time Co-optimization — Matt Mereness, ERCOT | © *RTO Insider*

“That’ll be the pain point,” predicted ERCOT’s Matt Mereness, the task force’s chair.

During the call, stakeholders debated the more efficient methods of reviewing the language. Some called for going NPRR by NPRR, but others agreed with staff’s recommendation to review the NPRRs by areas of common processes.

“To me, we would be a whole lot better off if we took [individual NPRRs] … and go through the whole darn thing top to bottom,” consultant Floyd Trefny said. “The problem is when you break it up in all these pieces and try to put it back together again, it seems like it’s going to fall apart. That’s what concerns me.”

Mereness responded by saying it would be “embarrassing” to say how many hours staff spent on devising the review process. ERCOT’s approach, he said, would place the right subject-matter experts in the same room at the same time.

“We’re seeing the efficiencies of the stakeholders having the right people in the room,” Mereness said.

Comments Encouraged

Staff said they welcomed formal comments through the revision request process. They also encouraged market participants to send red-lined revisions to the task force for its consideration.

ERCOT has scheduled nine meetings for the group to finalize the revisions, culminating in a number of Technical Advisory Committee subcommittee meetings in October. The TAC would then be given a chance to endorse the NPRRs in November, with the board taking them up in December.

“For the task force’s purposes, anyone at any time has the right to make comments,” Mereness said. “We don’t want to create so much structure that we can’t move forward. TAC will be the place to get unstuck.”

Mereness said ERCOT would “consider” adding changes if they save stakeholders money, but he wouldn’t guarantee changes outside the team’s scope would be accepted.

“We’re laser-beamed in how to get real-time co-optimization in successfully,” Mereness said. “We have to keep that laser-beam focus on getting through those 549 pages. If something is wrong, let us know. We’ve done our best to keep us in a good structural place.”

The delivery schedule remains aligned with upgrades to ERCOT’s Energy Management System, scheduled to go live in May 2024.

ERCOT is projecting it will cost $50 million to $55 million to add the RTC tool, which procures both energy and ancillary services every five minutes, to the market.

The nine revision requests the task force is working on:

NPRR1007: Updates the protocols for the ERCOT system’s management activities to address changes associated with RTC’s implementation.
NPRR1008: Updates day-ahead operations’ protocols.
NPRR1009: Updates transmission security analysis and reliability unit commitment to address RTC’s changes.
NPRR1010: Updates protocols to account for RTC’s changes to the adjustment period and real-time operations.
NPRR1011: Updates protocols on performance monitoring.
NPRR1012: Updates protocols on settlement and billing for RTC’s implementation.
NPRR1013: Updates the protected information provisions, definitions and acronyms; market participants’ registration and qualification; and market suspension and restart.
NOGRR211: The Nodal Operating Guide revision request updates language related to supplemental ancillary service markets, ancillary service deployment, and ancillary service responsibilities and obligations.
OBDRR020: The other binding document revision request updates the methodology for setting maximum shadow prices for network and power balance constraints to address changes associated with RTC’s implementation.

April 9, 2020March 12, 2025

EIA: Renewable Capacity to Grow in 2020

By Michael Brooks

Renewable resources will account for the largest proportion of new capacity this year, the U.S. Energy Information Administration predicted, though their growth will be tempered by the economic slowdown caused by the global COVID-19 pandemic.

Renewable capacity will increase by 11%, with the power sector adding 19.4 GW of wind and 12.6 GW of solar by the end of the year, EIA said in its monthly Short-Term Energy Outlook report released Tuesday. Those figures are 5% and 10%, respectively, lower than what the agency predicted in its previous report, which was published March 11, the same day the World Health Organization labeled the coronavirus outbreak a pandemic and just as the economic crisis was beginning.

| EIA

Throughout the report, EIA cautioned about the uncertainty of its projections because of the “rapidly changing economic conditions” resulting from state governors’ stay-at-home orders and the mass closures of nonessential businesses. “Although all market outlooks are subject to many risks, the April edition of EIA’s Short-Term Energy Outlook is subject to heightened levels of uncertainty because the impacts of the” virus, it said.

The agency predicted total electricity consumption to fall by 3% this year. The decline will mostly be driven by a 4.7% cut in commercial consumption. The industrial sector is expected to consume 4.2% less “as many factories cut back production.” Even residential consumption is expected to fall 0.8%, “as reduced power usage resulting from milder winter and summer weather is offset by increased household electricity consumption as much of the population stays at home.”

C&I prices are expected to dip this year before rebounding and surpassing those of 2019 in 2021. Residential prices will stay flat this year before following the C&I trend in 2021.

All U.S. grid operators will see a decrease in energy prices, according to EIA, but ERCOT will see the largest dip, with the North Hub average price falling 49.1% from $56.24/MWh in 2019 to $28.65, though its prices last year were inflated by an unusually hot summer. CAISO is second with a 27.5% drop, followed by ISO-NE (25.3%), NYISO (23.1%), SPP (13.2%), PJM (10.1%) and MISO (7.6%).

EIA predicts that RTO/ISO wholesale energy prices, which were already lower in Q1 this year because of a mild winter, will remain lower for the rest of the year because of the economic slowdown. | EIA

Carbon emissions will follow a similar trend. After decreasing by 2.7% in 2019, EIA predicted CO2 emissions would further decrease by 7.6% this year “as the result of the slowing economy and restrictions on business and travel activity,” before they increase by 3.6% in 2021.

Coal generation will fall by 20%, according to the report, while natural gas generation will rise by 1% as a result of low fuel prices.

“Although EIA expects renewable energy to be the fastest growing source of electricity generation in 2020, the effects of COVID-19 and the resulting economic slowdown are likely to have an impact on new generating capacity builds over the next few months,” the agency said.

April 8, 2020January 29, 2024

Co-ops, Public Power Seek US Aid in Pandemic

By Rich Heidorn Jr.

Public power and electric cooperatives are asking Congress to include them in future COVID-19 relief legislation, saying their utilities are facing a cash crunch because of unpaid utility bills.

“One in eight Americans depend on a not-for-profit electric cooperative to keep the lights on and empower their local economy,” Jim Matheson, CEO of the National Rural Electric Cooperative Association (NRECA), wrote in a letter to congressional leaders March 6. “As Congress crafts the next legislative response to this crisis, I write today to request the inclusion [of] remedies to challenges currently facing electric cooperatives.”

NRECA said “the vast majority” of cooperatives have temporarily suspended disconnections and waived late payment fees. The American Public Power Association (APPA) said a “large number” of public power utilities have suspended customer disconnects during the pandemic.

“The longer the pandemic goes on and customers can’t pay their electricity bills, along with declining load, there could be negative effects on cash flows for utilities,” APPA said in a blog post Wednesday.

Desmarie Waterhouse, APPA’s vice president of government relations, said the organization is asking its members whether they are seeing load declines and “at what point in their billing cycle they are noticing an uptick in the number of customers who can’t pay their bills.”

“We are trying to gather information right now that would be helpful for us to make the case for some sort of additional funding that would be available to public power utilities,” she said.

Matheson asked for federal funding to help co-ops maintain service during the current economic stress. “Some electric co-ops have limited reserve margins to sustain high rates of nonpayment. As a result of nonpayments and load falloff resulting from economic hardship, some not-for-profit electric cooperatives are facing significant operational shortfalls,” he said. “Without federal assistance, co-ops may face severe financial distress.”

LIHEAP Funding

Congressional leaders are discussing hundreds of billions of dollars in aid for hospitals, state and local governments, food stamp recipients and small businesses.

The $2 trillion CARES Act enacted last month included an additional $900 million for the Low-Income Home Energy Assistance Program (LIHEAP), but many ratepayers now out of work do not qualify, NRECA noted.

State LIHEAP directors are calling for an additional $4.3 billion in LIHEAP funding, according to the National Energy Assistance Directors Association (NEADA).

“Due to the depth of the crisis, this funding only scratches the surface of what families will need to stay afloat,” NEADA said. Its estimate of need assumes an average grant of $325 to cover home energy costs for four months, plus $300 to provide window or room air conditioners for elderly and medically vulnerable households to keep their homes at a safe temperature.

Matheson said NRECA also would like Congress to provide vouchers to help needy families and small businesses to pay internet service providers. “Service is especially crucial during the pandemic for online school assignments, teleworking and telemedicine,” it said. It also seeks more funding for the Department of Agriculture’s Rural Utilities Service (RUS) ReConnect Broadband Loan and Grant Program to bring high-speed internet to rural areas.

NRECA also urged the Federal Emergency Management Agency to reimburse co-ops for past disasters. Some Florida co-ops are still awaiting reimbursements for rebuilding their systems after Hurricane Michael in 2018, NRECA said.

Financing

Financing is also a concern of NRECA, APPA and the investor-owned utilities represented by the Edison Electric Institute.

NRECA wants lawmakers to order the RUS program to allow co-ops to reprice or refinance RUS debt at current low interest rates without penalties. Co-ops hold more than $40 billion in RUS electric program loans.

The organization also is seeking an increase in the amount of lending available under the RUS Guaranteed Underwriter Program, which guarantees loans made to co-ops by private cooperative banks including the National Rural Utilities Cooperative Finance Corp. and CoBank.

APPA is seeking reinstatement of tax-exempt advance refunding bonds to allow public power utilities more flexibility in refinancing their debt. It is also seeking an expansion of the small issuer exception from $10 million to $30 million to allow smaller utilities to borrow directly from banks with tax-exempt debt.

IOUs Seek Help on Commercial Paper

Meanwhile, EEI — which announced on March 19 that its members had suspended disconnects for nonpayment — is seeking help to restore liquidity in utilities’ commercial paper market.

“Liquidity is rapidly declining,” they said, causing Standard & Poor’s to downgrade the outlook for regulated utilities sector to negative.

“Utilities are highly creditworthy, are significant issuers in the A2/P2/F2 commercial paper market and rely on liquid, smoothly functioning markets for working capital and other short-term needs. However, our operating and holding companies are facing severe degradation of revenue and extraordinary increases in short-term funding costs due to the current Tier 2 challenges, creating a serious economic strain on the most essential of services,” the trade groups said.

The trade groups asked the Fed to extend its CPFF purchasing to Tier 2 holding and operating companies in sectors designated as critical infrastructure under the Presidential Policy Directive on Critical Infrastructure Security and Resilience (PPD-21).

On Tuesday, FERC Chairman Neil Chatterjee and National Association of Regulatory Utility Commissioners President Brandon Presley wrote in support of the groups’ request.

“We believe that extending CPFF purchasing would be a constructive step toward ensuring a properly functioning, critically important short-term debt market during this challenging period,” they said. “Both their continued financial stability and their ability to continue to support the country’s essential infrastructure are supported by ready access to short-term debt.”

April 8, 2020May 6, 2025

NEPOOL Markets/Reliability Committee Briefs: April 7, 2020

ISO-NE’s wholesale market costs last fall declined 38% year over year to $1.5 billion, with both energy and capacity market costs decreasing significantly, the New England Power Pool Markets Committee heard Tuesday.

Energy costs dropped by 47% ($655 million) to $746 million because of falling natural gas prices, lower loads and higher nuclear availability because of fewer outages, the Internal Market Monitor said in its Fall 2019 Quarterly Markets Performance Report. Capacity market costs were down 24% from 2018, at $749 million.

Average day-ahead and real-time hub LMPs were $24.69/MWh and $24.98/MWh, 43% and 45% lower, respectively. Natural gas averaged $2.44/MMBtu, down 42% from the fall 2018 average price of $4.21/MMBtu.

Lower gas prices and loads drove lower energy prices. The spark spread is the difference between the wholesale market price of electricity and its cost of production using natural gas. | ISO-NE

“Really this is driven by an auction that occurred several years ago,” said Dave Naughton, IMM manager of surveillance and analysis. “Fall 2019 was the second quarter of the Forward Capacity Auction 10 commitment period, with clearing prices of $7.03/kW-month for rest-of-system, compared to $9.55/kW-month the previous year.”

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

Average hourly load was down 6% to 12,551 MW because of lower temperatures in September and higher temperatures in late November. New England pipeline demand fell by about 20% for the season.

Net commitment period compensation costs (NCPC) totaled $8.5 million, down 26% from the prior fall, and represented about 1% of total energy costs, consistent with the historical range, Naughton said. Economic payments made up 57% ($4.9 million) of the total NCPC, down 46% from the previous year, and the decrease was consistent with lower gas and energy prices.

Grid Study Procedures

The MC held a joint meeting with the Reliability Committee on Tuesday afternoon and heard recommendations from the New England States Committee on Electricity (NESCOE) on how to proceed with a planned study on the future of the New England grid, the kickoff for which has been delayed until May because of the COVID-19 pandemic.

Heather Hunt and Ben D’Antonio of NESCOE presented preliminary staff suggestions on how best to assess the future state of the regional power system in light of state law requirements, as well as an overview of recent carbon-related studies. Day Pitney provided a compilation of recent ISO-NE economic studies and a list of relevant studies on the grid transition and carbon pricing.

Very different gas and energy prices season-over-season | ISO-NE

NESCOE highlighted five studies and summarized their findings, starting with a September 2019 report by The Brattle Group funded by the Coalition for Community Solar Access, which found that “annual clean energy resource additions need to increase by a factor of four to eight times the current level to achieve 2050 carbon emissions reduction goals.”

The second report covered deep decarbonization through increased coordination with Hydro-Québec and was funded by the utility and Sustainable Development Solutions Network. It found that “more interconnections between the Northeast and HQ may be a less expensive approach to decarbonization than an alternative with an even greater reliance on offshore wind and solar.”

NESCOE also highlighted a study of deep decarbonization in California by E3, which it said found the least-cost electricity portfolio to meet California’s 2050 economy-wide greenhouse gas goals includes 17 to 35 GW of natural gas generation capacity for reliability — compared with the state’s current 29-GW natural gas fleet.

The fourth study cited was funded by NRG Energy, wherein Brattle examined the forward clean energy market design concept, finding that “broad competition will minimize the costs of achieving carbon goals.”

Finally, D’Antonio brought up a 2018 study by the Northeast States for Coordinated Air Use Management on greenhouse gas mitigation in New England. The white paper found that immediate action is required and recommended electrifying end-use energy consumption.

D’Antonio emphasized that he was sharing information and not endorsing any proposal or study.

New England will need to deeply decarbonize the electric grid in order to ensure that GHG emissions significantly decline from the electric generation sector as the grid experiences a significant increase in load, the study said.

“We really think it’s important to know who your audience is when you do your reporting,” D’Antonio said, adding that the planned grid study should reach a broader audience if NEPOOL and ISO-NE want to achieve economy-wide effects.

Opening the DA Offer Window

ISO-NE proposed to modify the submission deadline for offers and bids in the day-ahead energy market from 10 a.m. to 10:30 a.m. to address feedback from stakeholders.

RTO staffer Dennis Robinson said this modification may afford some suppliers additional time to consider information before finalizing their day-ahead offers and bids.

In addition, ISO-NE will be addressing clean-up revisions in the Tariff, with a proposed effective date of Oct. 1.

“We may have to go back to the 10 a.m. time in 2024 as a result of [Energy Security Improvements] and the new day-ahead ancillary service products in the market, which could also impact the day-ahead market deadlines and time frames,” Robinson said. “We might have optimization of energy storage resources or other changes by 2024 as well.”

The MC will discuss the changes and vote on them at the May meeting ahead of a June vote by the Participants Committee.

Enhancing Info Policy

ISO-NE Corporate Counsel Tyler Barnett presented two proposed enhancements to Section 2.3 of the Information Policy in order to enable the RTO to take quicker action to protect the markets from default and improve communication with stakeholders on the status of defaulting participants emerging from bankruptcy.

The effective date of these revisions is proposed for October.

One proposed change would remove confidentiality restrictions applicable to defaulting participants to enable the RTO to act more quickly and efficiently when emergency judicial or regulatory relief is reasonably necessary, he said.

Another would permit the removal of a market participant from the weekly notification of defaulting parties sent to all market members when the participant’s plan to emerge from bankruptcy has been approved by bankruptcy court and the participant is not otherwise in default.

Court approval of a bankruptcy plan is a practical milestone to mark the end of bankruptcy, as business operations may resume prior to the case file being dismissed, Barnett said.

Accordingly, the weekly information policy notification will more accurately reflect a formerly bankrupt market participant’s status in the markets.

“We’re looking to avoid market confusion,” Barnett said.

The RTO proposes additional discussion before a vote at the June MC meeting ahead of a vote by the PC at its summer meeting in late June.

— Michael Kuser