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 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.
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?”
| AEP Texas
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.
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’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.
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.)
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.
“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.
The review process for ERCOT’s real-time co-optimization work | ERCOT
“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.
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.
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.
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.”
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.
No PJM dispatchers have tested positive for COVID-19 yet, but RTO officials are planning just in case their luck runs out.
During the weekly coronavirus update Friday, PJM officials were asked how they would respond if a dispatcher tested positive for the virus.
Paul McGlynn, PJM’s executive director of system operations, said no control room workers have tested positive, but that the RTO has enough employees to fill gaps if someone becomes infected.
McGlynn said PJM’s control center best practices document includes procedures for bringing back former employees in an emergency. “We look at staff that has previously worked in the control room and develop plans to get them trained and ready so that they could go back on the board if needed,” McGlynn said.
Telecommuting Extended
Scott Heffentrager, PJM’s chief security officer, said the RTO is extending telecommuting for all personnel until May 4. Heffentrager said the telecommuting measure does not apply to the control room staff, IT operations center, security or other critical on-site support personnel.
Crews have been prepping the PJM campuses for more than a week for sequestration — healthy workers required to remain on site if the pandemic becomes worse — if it becomes necessary. Heffentrager said crews are installing temporary bedding, entertainment, food and other accommodations for employees.
“We have not made the decision to go to sequestration, but this was just to prep the campus in the event that we do pull the trigger to do that,” Heffentrager said.
Besides adding accommodations for employees, a team has also been working on converting PJM’s control room simulator to a potential third control room in case of an emergency. Heffentrager said the control room is currently being tested, and security and compliance teams are converting the room to a “physical security perimeter” to meet NERC standards.
Generator Outage Coordination
PJM’s David Schweizer updated stakeholders on generator outage coordination, saying most generators intend on going ahead with planned and maintenance outages despite the pandemic. He said the RTO continues to track any changes that members bring to PJM’s attention, including planned outages.
About 5% of the planned outages this spring have been canceled outright without being rescheduled, Schweizer said, with about 25% being deferred until later this spring, the fall and the spring of 2021. Schweizer said many generators are reducing the scope of the spring outages by supplementing them with short duration maintenance outages during off-peak hours.
PJM has also continued coordination with gas pipelines to make sure gas is still being sent to generators. Schweizer said teams are tracking any pipeline maintenance plans, especially those that could “affect generation in the PJM footprint.”
Stakeholders are continuing to compile best practice information through a survey of generators that was started last month, Schweizer said. The survey was designed to be a portal to provide supplemental information to PJM so that the RTO is aware of issues related to outages, complications with contractor availability and other support needs.
Schweizer said the questionnaire is meant to be a “dynamic, ongoing survey” that will be updated regularly. He said one of the biggest concerns that has been voiced by generators are supply chain problems for outage-related materials coming from outside the immediate area.
“I think the thing we’re seeing mostly is comments about contractor availability not being 100% assured due to the fact that many outages are relying on critical workforce and resources coming from out of state or even from overseas,” Schweizer said.
Load Modeling
Elizabeth Anastasio, PJM senior meteorologist, said long- and short-term load forecasters are attempting to determine the impact of COVID-19 by comparing actual load with historical temperature and load data.
Anastasio said forecasters have been seeing some trends in load forecast errors.
After the first two weeks of March, the error in one of the short-term models fluctuated between +2% and -2%, Anastasio said, averaging out to a bias near zero for the forecast model.
In the last two to three weeks of March, she said forecasters observed the forecast error increase in magnitude, seeing an error of 4 to 6% depending on the time of day. She said the error has largely remained positive in that time, as the “models are over-forecasting almost exclusively.”
Anastasio said the warmer-than-usual weather has been playing a role in lower load levels.
“We’re doing our best to figure out how much of our decrease in load is due to the warmer temperatures and how much is due to COVID-19,” she said.
Chris O’Leary of PSEG Energy Resources asked if Anastasio believes PJM will be able to quantify the effect of COVID-19 with the higher-than-normal March temperatures and other factors.
Yes, Anastasio said. At least three or four methodologies are being pursued, she said, with each one having limitations that include simplistic modeling and subjectivity.
“What we’ve seen from early results of this analysis is that many of the methodologies are converging on a similar solution,” Anastasio said. “I suspect that we’ll be able to present a little bit more in this line at our Operating Committee meeting presentation” on April 15.
Additional Updates
PJM’s Donnie Bielak provided an update on transmission outage coordination, saying most planned transmission upgrades are proceeding on schedule. Although some transmission operators decided in late March to defer nonessential work until later months, time-sensitive work is proceeding as planned, Bielak said.
Michael Hoke, PJM’s senior lead trainer, updated stakeholders on operator training schedules. Hoke said his team is in the process of finalizing online simulations. He said the online simulations are used for operators who need a certification renewal in the next month or two and need simulation hours to complete the process.
The U.S. Department of Justice last week again threw its weight behind NextEra Energy’s ongoing effort to repeal a Texas law giving incumbent transmission companies the right of first refusal to build new power lines in the state.
Assistant Attorney General Makan Delrahim and other division attorneys urged the 5th Circuit to vacate the district court’s judgment and remand the motion to dismiss. The division also filed a brief in NextEra’s lawsuit before the U.S. District Court for the Western District of Austin. (See DOJ Weighs in on Texas ROFR Lawsuit.)
DOJ questioned whether the district court properly dismissed a dormant Commerce Clause challenge to SB 1938. The legislation, passed last May, essentially allows only incumbent transmission companies to build new power lines in Texas by granting regulatory certificates of convenience and necessity to the owners of the endpoints of a new transmission line.
Delrahim noted that the Commerce Clause gives Congress the power to regulate interstate commerce and that the Supreme Court has interpreted the clause to contain the negative implication that “strikes at one of the chief evils that led to the adoption of the U.S. Constitution, namely, state tariffs and other laws that burdened interstate commerce.”
NextEra has used the same argument in its appeal before the 5th Circuit.
In its brief, DOJ said the district court made three analytical errors in its decision, including:
Erring in its evaluation of discrimination, improperly distinguishing “binding Supreme Court precedent articulating principles of ‘ordinary Commerce Clause jurisprudence,’” failing to consider in-state physical presence requirements that are “viewed with particular suspicion” and affording improper significance to the location of a utility’s parent company.
Misreading and misapplying precedent from the Supreme Court ruling in General Motors Corp. v. Tracy to a “noncompetitive, captive market in which the local utilities alone operate.” DOJ said, “The unique factors and concerns for utility markets that determined the outcome in Tracy are not present here and were not evaluated by the district court.”
Failing to weigh whether any of the alleged burdens from SB 1938 “substantially outweigh the law’s putative benefits,” as required under precedent.
