SACRAMENTO, Calif. — California’s grid operator, government agencies and utilities bolstered actions this week to prevent the spread of COVID-19, in keeping with the state’s increasing limits on residents and businesses.
CAISO said Tuesday it would extend its ban on in-person meetings at its Folsom headquarters until at least May 1. The ISO previously established the restriction through April 1 to protect its employees and prevent operational disruptions. (See RTOs Take Steps to Address COVID-19’s Spread.)
“These measures, part of our pandemic response plan, are intended to protect our staff, customers, stakeholders and our community, and to fulfill our critical mission to reliably operate the grid, as important as ever during these trying times,” CEO Steve Berberich said in a statement.
CAISO plans to host meetings via teleconferencing and webinars. It suspended non-essential business travel for its employees and stopped tours of its facilities.
“To maintain reliability of electricity transmission, critical staff essential to the ISO’s core business services, such as grid operators, continue to work at the ISO control centers, and the coronavirus developments have had no impact to the system or markets,” CAISO said.
California Energy Commission Chair David Hochschild announced Tuesday the CEC will postpone meetings that could draw more than 250 people and will provide remote participation options for all other meetings and gatherings. Many commission staff members will be teleworking at least through the end of March, he said.
“Internally, we are quickly implementing processes to minimize disruptions to the Energy Commission’s workflow. Our focus is to ensure business continuity at the Energy Commission, including grant administration and invoice processing,” Hochschild said in a statement.
The California Public Utilities Commission told utilities under its jurisdiction — including Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to stop disconnecting customers who can’t pay their bills.
“In these unsettling and unprecedented times, many people are concerned about the health and safety of themselves and their loved ones, said CPUC President Marybel Batjer. “They should not also have to worry about their essential utility services being shut off for non-payment because they are unable to report to work due to illness, quarantine or social distancing.”
The protections — spelled out in a letter from CPUC Executive Director Alice Stebbins to the electric service providers — apply retroactively to March 4, when Gov. Gavin Newsom declared a state of emergency in California. The order still must be ratified by the commission.
Some utilities, including PG&E, had already announced a voluntary moratorium on disconnections due to nonpayment. PG&E’s moratorium, announced March 12, applies to both residential and commercial customers, the utility said.
The Sacramento Municipal Utility District, which also has stopped disconnecting customers who don’t pay their bills, said Wednesday it was closing its buildings to the public through at least April 17 and plans to handle all customer business online and by phone.
“Most importantly though … all SMUD outage response levels remain unchanged and all functions necessary to run the power system will operate as normal,” it said.
A growing number of Californians are under “shelter-in-place” orders, with residents told to stay home and avoid contact for at least the next three weeks. Seven of the San Francisco Bay Area’s nine counties have issued the orders, along with counties in the Sacramento regions. Violators could be convicted of misdemeanors.
Many nonessential businesses, such as restaurants and movie theaters, have shut down, and almost all schools are closed, a condition the governor said Tuesday could last through the end of the academic year.
Millions of residents staying home could alter California’s typical “duck curve” of electricity demand, which peaks in the morning and evening when people are home and drops midday, as solar output ramps up, when they’re at work and school.
A CAISO spokeswoman said Wednesday it was too soon to tell how the pandemic is affecting electricity demand, especially because the weather has been cool and rainy in recent days, but the ISO is monitoring the situation for changes in load and trends in customer demand.
The average load-weighted, real-time LMP in PJM was $27.32/MWh last year, a 28.6% decrease from 2018 and the lowest in the RTO’s 21-year history, the Independent Market Monitor said Thursday.
According to the Monitor’s annual State of the Market report, energy prices made up only 54.3% of the average total price of PJM’s markets ($50.33/MWh), also the lowest of any year. Capacity and transmission made up 22.4% and 20.6%, respectively, of the total price.
“The most significant single source of the reduction was natural gas and coal prices,” Monitor Joe Bowring said in an online press conference presenting the report. “The rest was the lower markups as people add less to their costs. That’s a way for saying the market was more competitive. In addition, load was down annually 2.4%, so it was a combination of three of those things.”
Of the $10.92/MWh decrease, 41.5% was a result of lower fuel costs, the dispatch of lower-cost units, decreased load and lower markups, Bowring said.
2019’s average LMP beat the prior record low, set in 2016 at $29.23 MWh.
Inflation-adjusted top three components of quarterly total price ($/MWh): January 1999 through December 2019 | Monitoring Analytics
Load was down 2.4% from 2018 to 88.1 GWh. Bowring said the early months of the year were mild compared to the brutal cold of January 2018.
Natural gas continued to increase its dominance in the RTO’s resource mix last year, with gas-fired output exceeding that of both coal and nuclear for the first time. Gas provided 36.2% of energy, followed by nuclear (33.6%) and coal (23.8%). Gas-fired output exceeded coal-fired in 2018 but not that of nuclear. (See Monitor Says PJM’s Capacity Market not Competitive.)
Although the Monitor found the energy markets competitive overall, Bowring pointed out a recommendation to correct flaws in the implementation of market power mitigation rules. Bowring said the rules depend on having accurate cost-based offers equal to the short-run marginal cost and clear definitions for cost-based offers highlighted in Manual 15.
He also noted a recommendation, made in the third-quarter of last year, that “PJM always enforce parameter-limited values by committing units only on parameter-limited schedules when the [three-pivotal-supplier] test is failed or during high load conditions such as cold and hot weather alerts or more severe emergencies.”
“Unfortunately, some generation participants in PJM are trying to undermine the entire role of market mitigation and are attacking the very idea of fuel-cost policies,” Bowring said.
PJM issued a hot-weather alert on Sept. 30 for Oct. 2, expecting an unusually hot day. But the RTO declared a synchronized reserve event around 3 p.m. ET on Oct. 1, leading to a spike in LMPs close to $700/MWh.
In the report, the Monitor said several factors led to the spike. PJM drastically underestimated load for 2 to 6 p.m. in most of its forecasts; the Monitor noted that for the 2 to 3 p.m. hour, the actual load was 2,706 MWh above the day-ahead forecast and 1,202 MWh above the one-hour-ahead forecast. For the 5 to 6 p.m. hour, the actual load was 4,014 MWh above the day-ahead forecast.
It also faulted inadequate generator response to the event. Between 2:25 and 2:55 p.m., at least 79 units failed to achieve the output level requested by PJM, for a total of 872 MW.
But in his presentation, Bowring focused on a 25-minute gap on Oct. 1 in which PJM’s real-time security-constrained economic dispatch (RT SCED) solutions were not approved, meaning the RTO’s Locational Price Calculator (LPC) continued to use the last approved solution, produced at 4:48 p.m.
“Without an updated approved RT SCED solution, PJM does not send an updated dispatch signal to generators,” according to the report. “The dispatch signal from the case that was approved at [4:48 p.m.] continued to be the target until a new case was approved at [5:14 p.m.] that solved for a target time of [5:25 p.m.]. … For three five-minute intervals, the prices for the solved RT SCED cases differed from actual average RTO price by hundreds of dollars per megawatt-hour.”
Bowring said this could be prevented by fixing a mismatch between RT SCED, which is automatically executed every three minutes, and the LPC, which runs every five minutes. The Monitor recommended that PJM approve one RT SCED case for each five-minute interval to dispatch resources during that interval, and that the RTO calculate prices using the LPC for that five-minute interval using the same approved RT SCED case.
MOPR ‘Hysteria’
PJM held no capacity auctions last year because of the wait on FERC to act on proposals to change the minimum offer price rule (MOPR), which it eventually did in December, expanding it to all new state-subsidized resources.
“Contrary to the hysteria, there is no evidence that the expanded MOPR will lead to increased prices,” Bowring said. He said that renewable developers have told him they expect to continue to be competitive in the capacity market and qualify for unit-specific exemptions.
The Monitor’s report was critical of state consideration of exiting the capacity market via the fixed resource requirement (FRR) alternative.
“The rationale for leaving the PJM capacity market via the FRR option is based on the incorrect premise that the MOPR order will increase capacity market prices. The FRR option is more likely to increase the cost of capacity to customers than to decrease it,” according to the report. “If new renewables are not competitive in the longer run, the least-cost option for customers in states that wish to pursue renewable targets is more likely to be competitive markets plus separate state subsidies for desired technologies than ending participation in the capacity market through the FRR option.”
Other Recommendations
The Monitor made 23 new recommendations in 2019, including 12 in the annual report:
Capacity Performance resources should be required to perform without excuses. “Resources that do not perform should not be paid regardless of the reason for nonperformance.” (Priority: High.)
Remove all maintenance costs from the cost development guidelines. (Priority: Medium.)
Review the FRR rules, including obligations and performance requirements. (Priority: Medium.)
Modify the market data posting rules to allow the disclosure of expected performance, actual performance, shortfall and bonus megawatts during a performance assessment interval (PAI) by area without the requirement that more than three market participants’ data be aggregated for posting. (Priority: Low.)
Base the net revenue calculation used by PJM to calculate the net cost of new entry and net avoidable-cost rate on a forward-looking estimate of expected energy and ancillary services net revenues using forward prices for energy and fuel. (Priority: Medium.)
Prohibit emergency stationary reciprocating internal combustion engines (RICE) from participation as demand response when registered individually or as part of a portfolio if it does not meet emissions standards because the environmental run hour limitations mean that emergency RICE cannot meet the capacity market requirements to be DR. (Priority: Medium.)
Eliminate the total regulation signal sent on a fleet-wide basis and replace it with individual regulation signals for each unit. (Priority: Low.)
Remove the ability to make dual offers (as both a RegA and a RegD resource in the same market hour) from the regulation market. (Priority: High.)
Replace the static MidAtlantic/Dominion Reserve Subzone with a reserve zone structure consistent with the actual deliverability of reserves based on current transmission constraints. (Priority: High.)
Eliminate the variable operating and maintenance cost from the definition of the cost of tier 2 synchronized reserve and remove the calculation of synchronized reserve variable operations and maintenance costs from Manual 15. (Priority: Medium.)
Define the components of the cost-based offers for providing regulation and synchronous condensing in Schedule 2 of the Operating Agreement. (Priority: Low.)
Require all PJM transmission owners use the same methods to define line ratings, subject to NERC standards and guidelines, subject to review by NERC and approval by FERC. (Priority: Medium.)
The drafting team working on changes to NERC standards on supply chain risks will regroup next week after an initial ballot indicated widespread opposition to the team’s proposed changes.
Comments on Project 2019-03 opened on Feb. 7 and closed last Wednesday. With 266 votes cast, the weighted results indicated 50.51% acceptance for the proposal — short of the two-thirds majority required for approval by the ballot pool.
Project 2019-03 was initiated in response to FERC Order 850, which directed NERC to submit modifications to address electronic access control or monitoring systems (EACMS) for high- and medium-impact bulk electric cyber systems. (See FERC Finalizes Supply Chain Standards.) The proposed standard also includes a recommendation from NERC staff’s supply chain risks report, which called for requirements on physical access control systems (PACS), excluding alarming and logging, for high- and medium-impact cyber systems.
The comment form asked stakeholders whether:
they agree with FERC’s justification for adding EACMS to CIP-005, CIP-010 and CIP-013;
they agree with the addition of PACS to CIP-005-7, CIP-010-4 and CIP-013-2;
they agree with designating failing to have a method for determining or disabling PACS as a moderate violation severity level (VSL), and failing to have a method for determining and disabling as a high VSL;
the proposed 12-month implementation plan is sufficient; and
the modifications in CIP-005-7, CIP-010-4 and CIP-013-2 meet the FERC directives in a cost-effective manner.
Utilities Question PACS Inclusion
Most of the negative comments focused on the first two questions, with a number of operators objecting to the inclusion of PACS at all. Meaghan Connell of Chelan County Public Utility District observed that the supply chain risks report had recommended that protected cyber assets (PCAs) be excluded from critical infrastructure protection (CIP) standards because the risk is difficult to quantify, and suggested the same thinking applied to PACS.
| Shutterstock
“PCAs, like PACS, have no direct 15-minute BES impact. PACS, unlike PCAs, do not reside within an ESP [electronic security perimeter] and have no network access to the BCS [BES cyber system] or related ESP,” Connell said. “Therefore, if PCAs are not included, it seems logical for PACS to be treated in the same manner.”
Greg Davis of Georgia Transmission echoed this view, noting that NERC’s report “correctly refers to various reliability standards that mitigate security risks relating to PACS.” Naming CIP-004-6, CIP-006-6, CIP-007-6, CIP-009-6 and others, Davis said that “these protections are sufficient given the attenuated relationship that a PACS compromise has to BES reliability impacts.”
Broad Focus Taken on EACMS
Commenters were more accepting of the addition of EACMS to CIP-005, CIP-010, and CIP-013, although some registered concern about the burden that the proposed changes would bring to utilities. A common argument was that the team had defined EACMS much more broadly than FERC envisioned.
“The SDT has chosen to include all EACMS while the commission provided the SDT with enough latitude to include only those EACMS that represent a known risk to the BES,” said Mark Gray of Edison Electric Institute. “With this in mind, we encourage the SDT to re-evaluate its approach and develop more targeted [modifications] that only address the known risks associated with EACMS that perform the function of controlling electronic access.”
Several respondents took this argument further, such as Pamela Hunter of Southern Co., who provided an example of how the new standards could produce unintended confusion among utilities and disrupt their workflow to such an extent that it would outweigh any reliability benefits.
“[If] I must only allow vendor remote access through an authorized and authenticated session at an EACMS, and that EACMS is the asset I would use to prevent vendor remote access to a BCS, how then can I also prevent vendor remote access to that very asset that I use to terminate that remote access? This results in [an] illogical loop,” Hunter said. She recommended that the SDT remove EACMS from CIP-005 or consider a new definition of the term that would avoid this kind of conflict.
Dissents on Time and Expense
A number of commenters expressed misgivings about the proposed implementation time frame of 12 months, calling for an extension to 18 or even 24 months. Bobbi Welch of MISO said the proposed changes “may not be as simple as merely adding a few additional systems”; in particular, utilities may need to develop a different process for EACMS and PACS systems. Dennis Sismaet of Northern California Power Agency also said the SDT had not given enough thought to the financial burden that the standard would impose on operators.
“In my view, all these multiple changes and proposals are unnecessary and costly to entities, let [alone] confusing to [us and] our governing boards, and have little, if any, real reliability value,” Sismaet said.
The drafting team will hold its next meeting via conference call March 23-26 to discuss the feedback and plan its next steps. A second posting is being considered for April.
The Texas Public Utility Commission agreed during a short emergency open meeting Monday to take steps to minimize physical contact during the COVID-19 coronavirus pandemic.
Following social distancing best practices, the commissioners voted unanimously to suspend commission rules that require physical interactions, such as filing document hard copies, and said they may to loosen some deadlines related to the traditional filing approach. They also encouraged attendees to follow the PUC’s open meetings online when possible.
“Each and every Texan has an obligation to help ‘flatten the curve’ of COVID-19 infections through the adoption of social distancing, and this agency is no exception,” PUC Chair DeAnn Walker said. “There will certainly be challenges as we transition to a remote approach, but diligent utilization of communications technology can keep us connected as we do what is best for Texans.”
Texas’ Public Utility Commission meets to discuss its response to the COVID-19 coronavirus.
The commission opened a docket in response to Gov. Greg Abbott’s request for guidance on any laws that need to be suspended and other coronavirus-related matters (50664). Abbott declared a state of emergency Friday.
The PUC said it will continue conducting commission business. As a precautionary measure, it has instituted an agency-wide teleworking policy for the “foreseeable future,” with only certain “essential” personnel required to be on-site. The Customer Protection Division will continue fielding complaints.
The Board of Directors will convene its April 14 meeting by webinar to consider any matters that cannot be deferred until the its next regularly scheduled meeting in June.
Pacific Gas and Electric won approval Monday for its plan to issue $12 billion in new stock and to take on $11 billion in new debt to get out of bankruptcy, after California Gov. Gavin Newsom dropped his objection to the exit financing strategy in the face of the COVID-19 coronavirus pandemic-caused stock market meltdown.
The approval by U.S. Bankruptcy Judge Dennis Montali was another major hurdle PG&E had to clear in its effort to leave bankruptcy. It came during an unusual hearing held by telephone because Montali’s court in San Francisco, like many other institutions and businesses, was closed to slow the spread of COVID-19.
After hearing briefly from lawyers for PG&E, Newsom’s office and others, Montali said he was ready to declare PG&E’s financial plan sound enough.
“The exigencies of the circumstances today do not lend themselves to try to be more detailed. The record speaks for itself,” Montali said. “And therefore I’m going to compliment the moving parties and also the governor’s office and his advisers for working with the debtor to come to the point we are. There are numerous things that have to continue to get resolved, but this is one of the many milestones that I think is important.”
Wildfire victims and other parties to the bankruptcy must vote to approve PG&E’s Chapter 11 reorganization plan, and the California Public Utilities Commission still must approve the proposal. (See CPUC President Wants More Control over PG&E.)
PG&E filed for bankruptcy in January 2019 after a series of devastating wildfires sparked by its equipment in 2015, 2017 and 2018 put it in the position of having to pay more than $30 billion to thousands of residents who lost family members, homes and businesses in the fires.
The utility is trying to leave bankruptcy by June 30 to participate in a $21 billion wildfire insurance fund established by the state under last year’s Assembly Bill 1054. The bill lists requirements PG&E must meet to take part in the fund, including the exit deadline.
As it met a series of milestones in its bankruptcy case, PG&E’s stock rose from a low of $5/share on Oct. 25 to a recent high of $17.92/share on Feb. 21. (See PG&E Resolves Dispute with Fire Victims, FEMA.) But its stock price tumbled to $8.95/share Monday as investors sought safer investments amid the pandemic.
Gov. Gavin Newsom | Cal OES
Lawyers for PG&E and the governor agreed Monday that it was crucial for PG&E to secure its exit financing plan before financial circumstances undermine it.
The governor withdrew his objection to the new debt PG&E plans to take on, which was based on his concern that a heavily indebted utility would be unable to make the estimated $40 billion to $50 billion in upgrades to its aging grid needed to ensure safe and reliable delivery of electricity. (See What Spring Could Bring for PG&E.)
Montali admitted he had trouble grasping details of the highly complex financing scheme, but he said he understood it from a “35,000-foot level.” The judge said he was relying on assurances from Kenneth Ziman, managing director of the restructuring group at investment bank Lazard, a longtime financial adviser to PG&E.
Ziman said the equity and debt commitments PG&E had obtained from large financial institutions and investors represented the largest injection of capital in the history of corporate bankruptcies and “outside of bankruptcy would also rank among the largest capital raises in the last 20 years across all industries.”
“These financial institutions and investors have committed significant capital to ensure the viability of the debtors’ plan of reorganization, and I believe therefore have an interest in seeing it through to completion,” Ziman wrote. “I believe these commitments also enhance the confidence of claimants, financial creditors, equity holders, ratepayers and other stakeholders that the debtors will timely emerge from Chapter 11 as a financially sound utility.”
PJM’s Reliability Pricing Model is acquiring more capacity than needed, leading to dirtier, less efficient generation and billions annually in excessive costs for consumers, according to a report released Monday.
Economist James F. Wilson said PJM is purchasing unnecessary capacity because of auction design features and inaccurate peak load forecasts, leading to a retention of “older, inefficient and often environmentally damaging” power plants that should be retired and the entry of new power plants that are not yet needed.
The report, prepared for the Sierra Club and the Natural Resources Defense Council, reiterates longstanding complaints about PJM’s capacity market while also attempting to quantify the impact of them.
Wilson said the total cost of the most recent Base Residual Auction, held in 2018, would have been $4.4 billion lower if its demand curve was corrected (by reducing the net cost of new entry (CONE) from $321.57/MW-day to $160.79/MW-day) and the reliability requirement was reduced by 8,000 MW. (See related story, PJM MOPR Floor Prices Reduced for Gas, Nuclear, Solar Units.)
Economist James F. Wilson says PJM’s administratively determined net cost of new entry (CONE) values for the RTO region (red) have consistently overestimated the “empirical” net CONE, as determined by the three-year average of clearing prices (green). | Wilson Energy Economics
Wilson also found that the excess capacity depresses spot prices for electricity and ancillary services, dampening price signals that could attract flexible resources that are increasingly needed to supplement renewables.
Although PJM’s target installed reserve margin is generally around 16% of the forecast peak load, Wilson found the RPM auctions regularly clear significantly more, accounting for an equivalent to reserve margins of 20% or more.
When the reserve margins were recalculated based on the final peak load forecast for each delivery year, the reserve margins have been 24% or more for all but one of the delivery years between 2012/13 and 2020/21. Wilson said RPM typically results in commitments that are roughly 10% or more in excess of the target, resulting in more than 15,000 MW of excess capacity in recent years.
Wilson said excess capacity is likely to increase in the future because FERC’s order expanding the minimum offer price rule (MOPR) will prevent additional resources that receive state subsidies from clearing the RPM. The removal of nuclear plants and renewable sources from the RPM through the MOPR will set a higher clearing price through duplicative capacity that falsely signal a need for additional resources, Wilson said, worsening the over-procurement issue.
PJM’s RTO peak load forecasts (red) have regularly overshot its weather-normalized actual peaks (green). | Wilson Energy Economics
“RTOs such as PJM are responsible for reliability and resource adequacy, not its cost, and they generally prefer more capacity, committed sooner, and under the most stringent performance requirements,” Wilson said in the report. “Capacity sellers also prefer market rules that raise capacity procurement quantities and, as a result, increase the capacity auction clearing prices they receive. Thus, the current planning procedures and market rules lead to over-procurement and higher capacity prices and have not been designed to achieve a reasonable balance in the interests of consumers between the value of more capacity and its cost and other market impacts.”
PJM Responds
Asked to respond Monday to the report, PJM said that its capacity market has helped to maintain a reliable system that has kept market-driven electricity costs flat for two decades, while at the same time incentivizing new technologies that have helped reduce emissions rates by 34% since 2005.
“PJM is constantly refining and enhancing its forecasting and capacity procurement models,” Jeff Shields, PJM’s media relations manager, said in a statement. “Changes made to the forecasting models starting 2016 — to account for energy efficiency, distributed solar generation and other factors — have greatly improved forecasting accuracy. In addition, the factors we used to determine the capacity needs for 13 states and the District of Columbia are developed through an independent consultant, thoroughly vetted in a stakeholder process, then submitted to FERC, which considered similar arguments raised in the report before it approved the best course to maintain resource adequacy.”
Although Wilson acknowledged PJM has made improvements, he said its peak load forecasting model “has failed to fully capture this trend toward increasing efficiency, and its three-year-forward forecasts have generally been 10,000 MW or more too high.”
PJM officials told stakeholders last week that revised calculations show lower floor prices for gas, nuclear and solar generating units under the expanded minimum offer price rule (MOPR).
Last month, PJM and The Brattle Group received feedback from stakeholders on their initial calculations of net cost of new entry (CONE) and avoidable-cost rate (ACR) values, the default minimum price for existing units. (See PJM Stakeholders Get First Look at MOPR Floor Costs.)
At Wednesday’s Market Implementation Committee meeting, PJM and Brattle shared revised numbers. PJM’s calculations showed a 39% reduction in onshore wind’s net CONE, to $1,023/MW-day, because of an increase in the capacity value (to 17.6% of nameplate) and an increase in its energy and ancillary services (E&AS) revenue offset.
Existing Generation Gross ACRs, preliminary and updated ($/MW ICAP-day) | The Brattle Group
Net CONE for combined cycle plants was reduced to $152/MW-day, a 35% reduction from the price PJM shared last month, because of a near-doubling of its E&AS offset to $152/MW-day.
Solar PV (fixed) came in at $367/MW-day, an 18% reduction from the earlier calculation, because of a reduction in gross CONE and an increase in E&AS revenue.
FERC’s Dec. 19 order requiring an expansion of the MOPR required that net E&AS offset revenues be determined for each transmission zone. PJM plans to propose using zonal LMPs from the last three years.
Brattle’s ACR results also showed reductions for nuclear and coal plants largely attributed to PJM’s guidance that shifted costs from the gross ACRs to variable costs.
Average zonal net cost of new entry (CONE), capacity value basis | PJM
Under the new analysis, the combination of gross ACR and variable costs include all avoidable costs to operate the resource for another year but not infrequent costs to extend the asset’s life or enhance its long-term performance. Maintenance costs for systems used for electric production are included in the operating costs maintenance adder for cost-based energy offers and excluded from the ACRs.
The ACR for “representative” multiple unit nuclear plants was reduced 27% to $444/MW-day, and 22% to $692/MW-day for single-unit nuclear plants, primarily because of shifts of fuel costs, sustaining capital costs, and materials and services operating costs to variable costs.
Coal’s ACR was cut to $80/MW-day for the representative plant, a 46% reduction, after Brattle shifted necessary and routine expenditures to maintain performance from gross ACR to variable costs.
Updated existing generation gross avoidable-cost rate (ACR) (2022$/MW ICAP-day) | The Brattle Group
The diesel generator ACR was slashed to $3/MW-day from $102/MW-day based on a changed cost basis from a 12-MW wholesale resource to a 1-MW behind-the-meter resource at a commercial facility. The gross ACR was revised to include only an annual maintenance contract.
The energy efficiency net CONE value was cut 19% to $1,761/kW from $2,179/kW to correct an overcount of incentive costs. Brattle is now using the total resource cost of each program.
PJM must file a compliance filing in response to the order by Wednesday.
On Monday, the Sierra Club and the Natural Resources Defense Council released a report by economist James F. Wilson criticizing the RTO’s capacity market, particularly its net CONE estimates. (See related story, Report Slams PJM Forecasting, CONE Estimates.)
PJM is “confident” it will meet FERC’s deadline for resolving pricing and dispatch misalignment issues in its fast-start pricing proposal, the RTO’s Tim Horger told the Market Implementation Committee on Wednesday.
In January, FERC held PJM’s fast-start compliance filing in abeyance until July 31, after the Independent Market Monitor and others told the commission the RTO currently computes dispatch instructions using a different market interval than it uses to calculate prices. “PJM appears to dispatch resources for a target interval that is roughly 10 minutes in the future but immediately assign the prices associated with that future dispatch interval to the current interval,” the commission said. (See FERC Stalls PJM Fast-start Compliance Filing.)
In April 2019, the commission ordered PJM and NYISO to revise their tariffs to allow fast-start resources to set clearing prices, saying their current rules are not just and reasonable.
Horger said PJM staff conducted a site visit to SPP and scheduled a conference call with MISO to learn how those RTOs implemented fast-start pricing. PJM’s plan to visit MISO was canceled because of new travel restrictions implemented in response to the COVID-19 coronavirus pandemic.
“They’re not going to be able to sit in with the [MISO] operators, but we think that the conference call … should be beneficial. All the questions that we’re looking at should still be answered. We don’t think that’s going to get in the way of any decision moving forward,” Horger said.
He said PJM is working with the Monitor to solve the alignment issues to meet FERC’s directive and hopes to develop a “comprehensive package” that could include additional changes to the RTO’s real-time security-constrained economic dispatch application.
“If we can’t move forward with the comprehensive package, PJM still wants to move forward with the narrow approach that PJM feels is in compliance with the fast-start order,” Horger said. He said the RTO will return to the MIC in April with the “path forward.”
Scope, Name Change for Credit Subcommittee?
PJM’s Dave Anders said the RTO will propose a revised charter for the Credit Subcommittee that could have it reporting directly to the Markets and Reliability Committee to raise its “visibility” and improve meeting attendance.
Anders said the subcommittee — which hasn’t met since December 2018, as members have focused their efforts on the Financial Risk Mitigation Senior Task Force in the wake of the GreenHat Energy default — is the best venue for considering a planned problem statement over a credit risk issue the RTO identified last month.
PJM told members Feb. 12 that it had identified a potential credit risk for the third Incremental Auction for the 2020/21 delivery year. “The good news is the potential credit risk … did not materialize” in the auction, which began Feb. 24, Anders said Wednesday.
Although the risk was expected to apply to only a small number of bids, PJM said that if a capacity market participant submits buy bids in an IA that could result in a position that is in excess of the committed unforced capacity for the delivery year in the same account, the RTO would require the participant to post collateral to secure any uncovered position.
PJM said that it will introduce a problem statement and issue charge to provide “additional clarity and protections with respect to certain capacity market scenarios.”
In addition to having the subcommittee report to the MRC rather than the MIC, Anders said PJM is considering broadening the subcommittee’s charter to “look more at risk issues and risk mitigation.” The revised charter of the “credit/risk” subcommittee will be brought to the MRC, perhaps as early as this month’s meeting, he said.
PJM Developing Alternative on Stability-limited Generators
PJM officials outlined a potential change in how it curtails generating output when needed to maintain stability during nearby maintenance outages.
Units must sometimes be reduced below their normal economic max limit if a planned or unplanned outage presents stability problems that could result in damage to the units.
Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.
Alternatively, a generation owner can voluntarily reduce its eco max limit and submit a notification ticket to PJM. In that case, the RTO will not bind that constraint and the unit will be paid the system LMP at the reduced output.
Units can also agree to reduce output in lieu of making system upgrades when stability limits are identified in the interconnection study process.
The MIC agreed in August to consider alternative approaches in response to a problem statement and issue charge by Panda Power Funds’ Bob O’Connell, who said PJM’s decision to remove supply from the market to address stability constraints will result in some units committing at price-based offers, rather than cost. Under the RTO’s rules, only the affected generator would know of the constraint, O’Connell said, gaining a competitive advantage over other units and possibly incorporating greater mark-ups into their offers. (See “Modeling Units with Stability Limitations,” PJM MIC Briefs: Aug. 7, 2019.)
PJM’s Keyur Patel outlined a proposal to model stability limits on generating units as a “capacity constraint” that doesn’t directly affect the LMP. The sum of megawatts from stability-restricted units would be capped at the stability limit regardless of virtual bidding. The sum of energy megawatts plus reserve megawatts from stability-restricted units would also be capped at the stability limit. The output of stability-restricted units would be based on their offer curve and LMPs.
Stakeholders questioned some of the examples in Patel’s presentation, saying they did not respect merit order. None offered any additional suggestions to the solution matrix.
MIC Chair Lisa Morelli said the committee will begin considering complete packages at its next meeting.
Load Management Mid-Year Performance Report
PJM’s Jack O’Neill gave a presentation on the Load Management Mid-Year Performance Report, highlighted by the performance assessment interval (PAI) event on Oct. 2, 2019, the first to occur since April 2015.
PJM dispatched both Capacity Performance demand response long lead resources and base DR from 2 to 3:45 p.m. ET in the Dominion, PEPCO and BGE zones and from 2 to 4 p.m. in the AEP zone during the event, which was caused by an underestimated load forecast, combined with typical maintenance schedules and unexpected line losses. (See PJM, Stakeholders Baffled by DR Event.)
CP resources, which were in their mandatory compliance period, produced 19.9 MW of reductions, 78% of the committed capacity of 25.4 MW. Base DR, which was not mandated to respond, produced only 373 MW of an expected 704 MW.
PJM uses the expected energy reductions reported by curtailment service providers as part of the dispatch decision-making process when DR resources are required to maintain system reliability, the report said.
Demand response for the 2019/20 delivery year by lead time, product type, measurement method, program type and resource type | PJM
The event resulted in $40,049 in penalties ($284/MW) on CP resources that failed to produce required reductions and bonuses totaling $447,666 ($34.73/MW), nearly all of it to base DR resources.
The RTO has 8,159 MW of load management resources for 2019/20.
Xcel Energy and three other Colorado utilities decided to join CAISO’s Western Energy Imbalance Market instead of SPP’s Western Energy Imbalance Service in December because of projected economic benefits.
Those benefits could have been far greater, however, if the other former members of the Mountain West Transmission Group also had selected the EIM instead of the WEIS, a Brattle Group study found.
If all seven had joined the EIM, the benefits for Xcel and the three other utilities in its balancing authority area would be $17.34 million instead of $1.98 million per year, the study found.
“The benefits jump eight to nine times as high,” Jason Smith, senior manager of market operations for Xcel, told the EIM’s Regional Issues Forum on Wednesday. “There’s just a ton of transmission to optimize within that footprint.”
Smith gave the most detailed public explanation yet of the decision by Xcel’s Public Service Company of Colorado — together with Black Hills Colorado Electric, Colorado Springs Utilities and Platte River Power Authority — to join the EIM as soon as 2021. (See EIM Lands Xcel, 3 Other Colo. Utilities.)
Xcel’s BAA covers the greater Denver area and most of eastern Colorado. The utility alone serves about half the state’s load.
The three other one-time members of Mountain West — the Western Area Power Administration, Basin Electric Power Cooperative, and Tri-State Generation and Transmission Association — announced in September they would join SPP’s nascent WEIS, saying they thought it would be more cost-effective and collegial. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)
SPP said in June it would start the WEIS to compete with CAISO’s fast-growing EIM. SPP’s move, and a new Colorado law requiring the Public Utilities Commission to examine market options, prompted Xcel to examine the costs and benefits of joining the imbalance markets, Smith said.
They hired Brattle, which found that even if all seven Colorado utilities joined the WEIS and not the EIM, the benefits to the four entities in Xcel’s BAA would add up to just $1.62 million per year — about one-tenth as much as if all seven joined CAISO’s imbalance market.
The EIM has provided nearly $862 million in benefits to participants since it began operating in 2014, mainly through cost savings and the use of surplus renewable energy, according to CAISO.
Asked if he thought the Brattle study might encourage the utilities that signed on with SPP to change their minds, Smith said he couldn’t speak for them but wouldn’t rule it out.
“In the future, things may change, but that’s just a guess on my part,” he said.
‘A Close Call’
Brattle projected the four Xcel BA entities would spend roughly $1.6 million in start-up costs to join the market and $450,000 in annual administrative charges, Smith said. The WEIS wouldn’t require any start-up costs, but administrative fees would run about $3.5 million per year because of the relatively small number of participating entities to share the market’s expenses over time, he said.
Only the three other former Mountain West participants have decided to join the WEIS so far. The EIM has nine active participants and 11 more scheduled to join by 2022, not including Xcel and the three other Colorado utilities.
Imbalance markets allow utilities to trade excess energy across BAs, often maximizing use of renewable energy such as wind and solar, and Xcel was the first large investor-owned utility to commit to becoming carbon-free by midcentury, a pledge it made in December 2018 partly in reaction to customer demands. The city of Boulder, served by Xcel, has been trying to buy its assets there to create a municipal utility. (See Xcel Pledges to Go 100% Carbon Free.)
Smith said the time zone difference between Colorado and California and the states’ different resources would complement each other well. Colorado’s solar power comes online an hour before California’s morning peak, and eastern Colorado’s ample wind energy continues after the sun sets on the West Coast during the evening peak.
The same synergy wasn’t there if Colorado sent electricity east and south into SPP’s footprint, he said.
“The geographic distance gave us an advantage quite a bit,” Smith said. “That just wasn’t there when you look at a north-to-south diversity overall.”
Colorado has more transmission connections to SPP. Connection rights to CAISO and the other EIM entities are limited but should be adequate, he said.
“It was a close call, but we’ve got just enough transmission to make it viable,” Smith said.
Buying or building more transfer capability should increase benefits, he told the Regional Issues Forum during its teleconference. (The planned in-person meeting in Phoenix was called off because of the COVID-19 coronavirus.)
The four utilities are working toward signing an implementation agreement with CAISO and don’t anticipate any roadblocks, he said.
Some 375 people registered for Friday’s virtual version of Raab Associates’ 165th New England Electricity Restructuring Roundtable, held exclusively online in response to the COVID-19 coronavirus pandemic.
Three of seven panelists appeared in person at the Boston law offices of Foley Hoag with moderator Jonathan Raab, while the others joined via video link.
Robert Ethier, ISO-NE | ISO-NE
Robert Ethier, ISO-NE vice president for system planning, stayed away from the venue under a new policy from the RTO, effective the previous day, for staff not to appear in person at any conference or stakeholder meeting through the end of April.
Later that day, Massachusetts Gov. Charlie Baker prohibited gatherings of more than 250 people in the state, which was already operating under a state of emergency.
The webinar focused on the evolution of the transmission system in a decarbonizing New England. Electrification of the transportation and building sectors will increase power consumption, and transmission will serve as the linchpin to the region’s transition to a low-carbon and carbon-free future, Raab said.
“As New England states are pursuing their economy-wide greenhouse gas-reduction goals and mandates, our transmission grid will need to grow substantially to facilitate the development of renewable energy resources as we decarbonize our electricity supply,” Raab said.
Following is some of what we heard.
Choice of Focus
Higher load, lower clean energy capacity factors and renewable curtailments mean New England will need more than 200 GW of capacity by midcentury, said Jürgen Weiss, a principal with The Brattle Group.
Jürgen Weiss, The Brattle Group | The Brattle Group
“We concluded that if you decarbonize the energy economy in the New England states, you can count on roughly doubling electric load by 2050,” Weiss said during his presentation.
Brattle’s analysis found that growth in electricity demand by midcentury will range from about 77% when policy is focused on energy efficiency, to 103% when it’s focused on electrification, to 136% when it’s focused on electrification and renewable fuels.
“If we use electricity to make renewable fuels, to make some carbon-neutral substitute for natural gas, those processes are actually more energy-intensive; they use more electricity per unit of energy delivered to the end use than direct electrification, so in that case, you might actually see significantly more than a doubling of electricity demand,” Weiss said.
Any resource scenario has important implications for the transmission and distribution system, he said. Brattle estimated a rough doubling of incremental annual national transmission investment, largely related to connecting renewable energy resources to the grid.
New England 2050 resource scenario | The Brattle Group
“Relative to the annual transmission investments that have been occurring over the last few years, which are somewhere between $10 billion and $15 billion a year [in the U.S.], we probably need to add about twice that amount over the coming decades. So $25 billion of incremental transmission investments to do several things,” Weiss said.
“First, the new transmission will interconnect a lot of resources that are not going to be sitting next to load like the current generation is,” he said. “Here in New England, that’s obviously a lot of offshore wind.”
New distribution infrastructure also will address “very different load profiles, and ultimately much higher peaks,” Weiss said.
Big Wind Overflow
Ethier agreed with Weiss’s analysis and said that changing use patterns are “probably going to require an entirely new way of looking at the transmission system.”
“The integration of renewables and storage may significantly change the transmission flows, and we’re already seeing that with lots of resources added to the distribution system, which will cause some of our distribution feeders to actually flow in the opposite direction,” Ethier said.
He outlined ISO-NE’s transmission planning process and noted its first-ever solicitation in December for competitive transmission solutions for reliability needs in the Boston area, which drew 36 proposals — both AC and HVDC — ranging from $49 million to $745 million. The RTO is evaluating proposals and will review results with the Planning Advisory Committee. (See ISO-NE Issues First Competitive Tx RFP.)
“There are two issues with the transmission system: There’s paying for it, and then there’s getting it built,” Ethier said. “Both of those are time-consuming, and both of those are things that, if the past is any guide, we’re going to have a hard time keeping up with the states’ goals [and] meeting their carbon-reduction targets.”
Left to right: Peter Shattuck, Anbaric; Jonathan Raab, Raab Associates; Jürgen Weiss, Brattle Group; and Robert Kump, Avangrid.
In addition, developers are proposing about 15 elective transmission upgrades (ETUs) to help deliver about 11,000 MW of clean energy to load centers in New England, he said.
“We’re seeing lines that are seeking to connect northern Maine; we see lines seeking to connect offshore wind to load centers in New England, and also lines for hydropower from Canada,” Ethier said. “In most cases, we see multiple versions of these things that would accomplish the same goals.”
The ETU proposals “are queued up now and waiting for an opportunity to sell their services and sell their project as part of some sort of clean energy procurement at the state level, and until then, they’ll just bide their time in our queue,” he said.
The largest public policy effect in the region these days is offshore wind, and studies have shown that the rate of spillage increases as the buildout increases, Ethier said.
The RTO last month presented its latest study results on integrating up to 8,000 MW of offshore wind into the regional grid, analysis requested by the New England States Committee on Electricity (NESCOE). (See “OSW Study: More the Better,” ISO-NE Planning Advisory Committee Briefs: Feb. 20, 2020.)
“Spillage is where we have excess generation in New England and we actually have to back down renewable resources,” he said. “At 8,000 MW we hit spillage in every month of the year, so we have to back down various economic resources to accommodate these renewables. To avoid that you either need to increase load in the region, shift load around, or add significant amounts of storage.”
Offshore Planning
Robert Kump, deputy CEO and president of Avangrid, said his company is working on both the Canadian hydropower side and offshore.
Robert Kump, Avangrid | Avangrid
Avangrid subsidiary Central Maine Power is nearing completion of permitting for its $950 million New England Clean Energy Connect (NECEC) project to carry 1,200 MW of power from Hydro-Québec to Massachusetts, he said.
“The latest approval was from the Maine Land Use Planning Commission, received in January,” Kump said. “We expect any day now to get a draft approval from the Maine [Department of Environmental Protection],” which in fact came later that day.
“The goal would be to have all of our permits completed by the summer, and to start construction in the third quarter with a year-end 2022 completion date,” Kump said. Four gigawatts of additional transmission is needed to balance variable resources, he said, citing a Massachusetts Institute of Technology study this year on the role of Canadian hydropower in decarbonizing the Northeast.
Peter Shattuck, Anbaric | Anbaric
Kump also presented data from Vineyard Wind, his company’s offshore wind joint venture with Copenhagen Infrastructure Partners, and called for increased state and federal coordination to reduce permitting and siting risks.
“The starting point for thinking about how we connect this brand new and significant resource to the grid is looking at where we can bring it ashore,” said Peter Shattuck, chief information officer of Anbaric Development Partners. “Overall, independent transmission can minimize interconnection costs, reduce marine cabling and enable offshore wind to scale.”
Shattuck presented an argument for networked HVDC offshore transmission that compared scenarios of planned and unplanned development, with the latter seeing energy losses of 8%, while a planned network had only 3% losses, with comparable reductions in environmental and fisheries impacts because of 49% fewer miles of cables needed.
Wholesale Market Design
The second panel focused on what wholesale market design should look like in a fully decarbonized regional grid.
MIT economist Paul Joskow discussed how wholesale markets will support the investment costs of new generation and storage technologies.
Paul Joskow, MIT | MIT
“The systems in place have worked least well in stressed conditions in terms of providing efficient price formation,” Joskow said. “There’s been a lot of discussion about resource adequacy and capacity compensation focused on adapting capacity markets in various ways to provide additional net revenues. I don’t think that the conventional capacity markets framework used in most RTOs is well-adapted to a system dominated by intermittent generation.”
Joskow’s observation that New England “is way behind the other states and regions in the smart meter or smart grid technology” prompted a question from Manuel Esquivel of the Boston Planning and Development Agency as to what municipalities could do to encourage the adoption of smart meters.
“Mandating real-time meters and other smart equipment, controllable sensing equipment, inverters that can do more; these are state public utility commission decisions,” Joskow said. “This is not some way-out thing. Philadelphia has 100% penetration of smart meters; Baltimore has 100% penetration.”
The most important thing is to get the real-time design correct, said professor William Hogan, of Harvard University’s John F. Kennedy School of Government.
“If not, you’ll create many new problems,” Hogan said.
(Clockwise) Abigail Krich, Boreas Renewables; Paul Joskow, MIT; and William Hogan, Harvard.
He highlighted that under scarcity pricing in ERCOT, high prices of $9,000/MWh last summer occurred at the right time and were not socialized through capacity market charges spread over all load. (See “Scarcity Pricing Likely Again in 2020,” Overheard at Infocast’s ERCOT Market Summit.)
Sue Coakley, executive director of Northeast Energy Efficiency Partnerships, asked what the market design would need in order to include carbon-free demand-side resources, especially energy efficiency.
“I have a long record of not being a big fan of capacity markets, so if you’re worried about this problem, the worst place to start would be the capacity markets,” Hogan said. “I would go much more towards the retail rate design side.”
Boreas Renewables President Abigail Krich agreed with Hogan, saying that ISO-NE’s current capacity market design “absolutely would not be sufficient” to decarbonize New England’s grid.
“Some other mechanism is needed to secure a new way of financing, whether it’s in the centrally run market by ISO-NE, or whether it’s some mechanism by the states, or hedging,” Krich said. “I think this is going to be an iterative process … and there is a lot of investment needed.”
Robert Stoddard of Berkeley Research Group asked if the states’ roles needed to fundamentally change: For example, does New England need to adopt mandatory retail choice, as in Texas?
“I actually think the Massachusetts attorney general has it right in pushing to eliminate retail choice at the residential customer level,” Krich said. “I think that experiment has not worked in Massachusetts so far. At a larger scale, there are customers who are able to make informed decisions.”
