Page 1186 – RTO Insider

March 19, 2020

PJM Makes MOPR Compliance Filing

By Rich Heidorn Jr.

PJM on Wednesday submitted proposed Tariff changes to comply with FERC’s controversial December order requiring expansion of the minimum offer price rule (MOPR) to new state-subsidized resources.

A quick review of the 683-page filing did not reveal any major surprises (EL16-49, ER18-1314, EL18-178). The RTO had discussed its planned compliance filing in nine stakeholder meetings since December, including two last week. (See PJM MOPR Floor Prices Reduced for Gas, Nuclear, Solar Units.)

“These issues have been the subject of rigorous review and consideration of varying stakeholder interests within the time limitations allotted by the commission for the submission of this compliance filing,” PJM said, noting that RTO officials also have communicated with state regulators and the Organization of PJM States Inc. (OPSI).

“PJM has heard and thoroughly considered the views of all stakeholders and representatives of states and, through this compliance filing, has attempted to balance all of the competing views on these various issues into a proposal … which is designed to meet the commission’s Dec. 19 order’s directives while also ensuring orderly and timely capacity auctions going forward.”

In addition to extending the MOPR to new state-subsidized resources, the rules would continue the existing MOPR on new combustion turbine and combined cycle natural gas resources.

“Where certain elements of the commission’s Dec. 19 order required additional details to support the design and application of the modified MOPR, PJM has used its best efforts to add these additional detailed elements to comply with the overarching goal of the Dec. 19 order,” the RTO said. “To provide market certainty, PJM will await commission action on this filing before implementing the modified MOPR in the next Base Residual Auction (BRA).”

Schedule

PJM asked the commission to allow at least 35 days for comments on its filing (no sooner than April 22). “Such an extension is appropriate given the volume of this filing and current circumstances,” the RTO said. “This will afford market participants sufficient time to review and comment on the proposed changes, which is necessary given the relative importance of this filing to PJM’s capacity market.”

It proposed “an orderly, but compressed” auction schedule following commission action on the compliance filing, saying it would complete all pre-auction activities and open the BRA for the 2022/23 delivery year within six-and-a-half months after the commission’s acceptance of the compliance filing. (See PJM Proposes Auction for 6 Months After FERC Ruling.)

PJM MOPR Compliance Filing — Proposed capacity auction schedule | *PJM*

“Capacity market sellers should know before they make concrete auction preparations, for example, the specific definition of a state subsidy, the details of available exemptions, the net CONE [cost of new entry] and ACR [avoidable-cost rate] screening values for the various resource categories, and the parameters of an acceptable unit-specific exception showing — just to name a few,” it said.

Exemptions

Exempted from the MOPR would be existing resources participating in state renewable portfolio standard (RPS) programs; existing demand response, energy efficiency and storage resources; and existing self-supply resources. Federal subsidies would not trigger the MOPR.

FERC’s order also provided for exemptions for resources that forego state subsidies and those that can prove through the resource-specific exception that their costs are lower than MOPR reference values.

“While FERC’s order combined exemptions for demand resource, energy efficiency resources and capacity storage resources, PJM proposes to separate out capacity storage resources as a separate categorical exemption given the distinctions with demand resources and energy efficiency resources,” the RTO said.

It said it will offer “non-binding guidance” for capacity market sellers as to whether their resources qualify as subsidized.

“PJM and the Market Monitor will work together to develop a non-exhaustive list of programs, based on information provided by capacity market sellers, that they consider to be a state subsidy and post this list in a guidance document. Given the myriad state and local programs that may exist throughout the PJM region and the fact that such programs may change over time, it would not be practical to include a list of specific state subsidies in the Tariff,” it said.

“Instead, PJM will develop and maintain, in collaboration with the Market Monitor, a list of specific state subsidies to provide guidance on many of the most common programs that may be applicable to capacity resources. Importantly, however, it is ultimately the capacity market seller’s responsibility to ensure that they correctly certify whether its capacity resource is subject to a state subsidy, irrespective of any guidance provided by PJM and the Market Monitor.”

It said such certifications should be subject to fraud and misrepresentation rules modeled on the provisions the commission previously approved regarding to capacity market sellers seeking a categorical exemption from the MOPR (ER13-535).

Legal Challenges Expected

FERC approved the expanded MOPR on a 2-1 vote, saying it was needed to combat price suppression from growing state subsidies, such as those for nuclear plants in Illinois, New Jersey and Ohio. Commissioner Richard Glick dissented, calling the order an attack on decarbonization efforts that would add billions in increased capacity costs.

Dozens of stakeholders filed requests for rehearing or clarification of the order, with some observers predicting the issue will end up in front of the Supreme Court. (See PJM MOPR Rehearing Requests Pour into FERC.)

Todd Snitchler, CEO of the Electric Power Supply Association (EPSA), whose members own and operate more than 50,000 MW of capacity in PJM, praised the filing. “Since December, there has been a productive and extensive public conversation among all stakeholders about how competitive electricity markets can best serve the interests of consumers and the power grid,” he said. “PJM has worked diligently under a compressed timeline to conduct a thorough stakeholder process and develop a MOPR implementation plan while ensuring that perspectives from all relevant groups were considered and incorporated into its compliance filing. … Now, FERC must act expeditiously in order for PJM to move forward and hold its long-delayed Base Residual Auction as soon as possible.”

The American Wind Energy Association also gave an upbeat review.

“PJM’s proposal provides the flexibility necessary for renewable resources to demonstrate that they are among the lowest cost and most reliable sources of capacity available today,” said Amy Farrell, AWEA’s senior vice president of government and public affairs. “We appreciate PJM’s efforts to develop sensible responses to the unsustainable policies that FERC mandated for the region’s competitive market. AWEA and our members will continue working constructively with PJM to restart the capacity market and find practical solutions that recognize the value of renewable energy and protect the ability of states to control the fuel mix within their borders.”

Katherine Gensler, vice president of regulatory affairs for the Solar Energy Industries Association, said that although the organization “objects to the underlying policies presented in the current MOPR construct, PJM took a positive step in proposing how to comply with FERC’s December order. PJM’s submission will allow renewable generators to properly identify a project-specific bid price for bidding into the capacity market auctions. This process provides renewable generators a better opportunity to compete on a level playing field with other capacity providers and to help meet states’ clean energy goals.

“We request that FERC act swiftly to restore PJM’s annual capacity auctions in a timely manner. Our member companies are ready to see market certainty return to PJM and to put this multi-year debacle to a close.”

March 19, 2020

California Agencies, Utilities Amp up Virus Response

By Hudson Sangree

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 Spr e ad.)

“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.

California coronavirus — The California Energy Commission is postponing meetings that could draw a crowd, such as its Feb. 20 session on rooftop solar. | © *RTO Insider*

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 let t er 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.

March 17, 2020

UPDATE: Monitor: PJM Saw Record-low Energy Prices in 2019

By Michael Yoder and Michael Brooks

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.

PJM energy prices — 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.

Oct. 1 Event

Bowring highlighted PJM’s handling of an emergency event on Oct. 1, which he said the RTO mishandled. (See PJM, Stakeholders Baffled by DR Event.)

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.)

March 17, 2020

Commenters See Overreach in Supply Chain Standards

By Holden Mann

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.

Supply Chain Standards — | *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.

March 17, 2020

PUCT Responds to COVID-19 with Online Filings, Meetings

By Tom Kleckner

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.”

PUCT COVID-19 — 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.

Meanwhile, NYISO, MISO Join Operators in Suspending In-person Meetings.)

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.

March 17, 2020

Judge OKs PG&E’s $23B Plan to Exit Bankruptcy

By Hudson Sangree

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.

PG&E bankruptcy exit plan — PG&E’s bankruptcy exit is being litigated in federal court in San Francisco. | © *RTO Insider*

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.

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.”

March 17, 2020

Report Slams PJM Forecasting, CONE Estimates

By Michael Yoder

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.)

PJM CONE — 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.

“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.”

March 17, 2020

PJM MOPR Floor Prices Reduced for Gas, Nuclear, Solar Units

By Rich Heidorn Jr.

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.

PJM MOPR — 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.

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.)

March 17, 2020

PJM MIC Briefs: March 11, 2020

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 present ation 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.)

Load management interval performance during Oct. 2, 2019, performance assessment interval event | *PJM*

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.

— Rich Heidorn Jr. and Michael Yoder

March 17, 2020January 18, 2024

Why 4 Colorado Utilities Joined CAISO EIM, not SPP WEIS

By Hudson Sangree

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.

Mountain West was a coalition of seven utilities whose effort to join SPP’s RTO fell apart when Xcel withdrew in 2018. (See Still ‘Committed,’ SPP Halts Mountain West Integration Effort.)

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.

“We’re ready to kick off,” he said.