Page 1113 – RTO Insider

April 9, 2020March 12, 2025

Trader Challenges PJM FTR Forfeiture Rules

By Rich Heidorn Jr.

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

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

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

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

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

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

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

Financial Leverage Test

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

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

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

Monthly FTR forfeitures for physical and financial participants | Monitoring Analytics

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

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

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

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

PJM did not respond to questions about the complaint.

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

Leaving the Markets

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

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

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

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

April 9, 2020

ERCOT Stakeholders Dig into Real-Time Co-optimization

By Tom Kleckner

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

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

The task is not without consequence for staff and stakeholders.

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

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

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

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

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

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

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

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

Comments Encouraged

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

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

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

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

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

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

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

The nine revision requests the task force is working on:

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

April 9, 2020March 12, 2025

EIA: Renewable Capacity to Grow in 2020

By Michael Brooks

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

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

| EIA

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

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

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

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

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

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

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

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

April 8, 2020January 29, 2024

Co-ops, Public Power Seek US Aid in Pandemic

By Rich Heidorn Jr.

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

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

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

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

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

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

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

LIHEAP Funding

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

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

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

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

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

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

Financing

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

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

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

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

IOUs Seek Help on Commercial Paper

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

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

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

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

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

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

April 8, 2020May 6, 2025

NEPOOL Markets/Reliability Committee Briefs: April 7, 2020

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

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

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

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

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

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

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

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

Grid Study Procedures

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

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

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

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

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

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

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

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

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

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

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

Opening the DA Offer Window

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

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

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

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

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

Enhancing Info Policy

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

The effective date of these revisions is proposed for October.

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

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

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

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

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

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

— Michael Kuser

April 7, 2020

Fire Victims Challenge PG&E Deal as Vote Looms

By Hudson Sangree

The $13.5 billion settlement that Pacific Gas and Electric struck with wildfire victims may be in trouble, threatening one of the main components of the utility’s plan to exit bankruptcy by the end of June.

PG&E fire victims — Judge Dennis Montali | *Commercial Law League of America*

On Monday, the official Tort Claimants Committee (TCC), which represents the majority of the case’s 70,000 fire victims, petitioned U.S. Bankruptcy Judge Dennis Montali to allow it to send out a letter asking victims to postpone voting on the utility’s Chapter 11 reorganization proposal until at least May 1 because of “problems and risks the TCC has identified with PG&E’s plan.”

PG&E and lawyers representing the case’s second-largest group of fire victims objected. Montali scheduled a hearing on the matter for Tuesday morning.

The surprise move came after three members of the TCC, composed of 11 fire victims, resigned so they could openly criticize PG&E’s plan to fund the $13.5 billion trust with $6.75 billion in company stock. They fear the shares could decline in value, especially now that the COVID-19 coronavirus pandemic is pummeling stock markets worldwide.

“The TCC believes that the … coronavirus’ economic ripple effect presents an unforeseeable and significant risk that the shares of stock will not have the value necessary to match the $13.5 billion that PG&E has stated would be available to pay fire victim claimants,” the committee’s lawyers wrote.

The victims’ attorneys had been trying to get PG&E to guarantee the full amount, regardless of stock market changes, but mediation to resolve the matter broke down March 27, attorney Robert Julian said in the motion to Montali.

“The TCC believes the parties have not made any substantial progress, and the TCC believes it is important that the proposed letter be sent to fire victim claimants disclosing such issues,” it said. “The information provided in the proposed letter may have a material impact on how and when fire victim claimants vote.”

‘Complete Lack of Transparency’

In a statement Monday, PG&E took issue.

“The TCC’s filing is an attempt to change the settlement it agreed to despite the fact that the agreement has the broad support of the parties and the governor’s office and is the best and fastest path to getting victims paid,” the utility said. “The TCC’s effort to recut the deal puts at risk their clients’ ability to be paid quickly.”

The TCC’s move appeared to be partly a response to a growing grassroots movement among wildfire victims to oppose the $13.5 billion deal reached in December. (See PG&E Reaches $13.5B Deal with Wildfire Victims.)

Lawyers stand to be paid 30 to 40% of the trust amount.

National Guard soldiers search for human remains in the rubble of the Camp Fire, which tore through Paradise, Calif., on Nov. 8, 2018. | *California National Guard*

The latest fire victim to resign from the TCC told the Associated Press that attorneys had violated their fiduciary duty to clients by hiding the risks of funding half the trust with PG&E stock.

“They’re just not breaching their fiduciary duty; they’re blowing it up,” Karin Gowins said. “There has been a complete lack of transparency.”

Gowins was the comptroller of Paradise, Calif., the town of 27,000 largely destroyed by the Camp Fire in November 2018 after a PG&E high-voltage line ignited the state’s deadliest and most destructive wildfire, killing 85.

State fire investigators have also determined that PG&E equipment started the deadly Northern California wine country wildfires of October 2017 and the Butte Fire, in the Sierra Nevada foothills near Sacramento, in September 2015.

Since filing for bankruptcy in January 2019, PG&E has reached settlements with fire victims, insurance companies and local governments worth $25.5 billion and won Gov. Gavin Newsom’s approval for its restructuring plan. The dispute over the fire victims’ settlement threatens to undermine its efforts.

Plaintiffs’ Lawyers at Odds

In its proposed letter, which requires the judge’s approval, the TCC says PG&E revised its agreement with fire victims by increasing its debt load and lowering the amount of cash it expects to raise by issuing stock. The changes were made without fire victims’ consent, it says.

“Both of those changes impact the value of PG&E’s stock,” it says.

The TCC’s proposal would give PG&E until April 28 to resolve the outstanding issues; lawyers would notify victims of the status of negotiations by May 1.

Disclosure statements outlining PG&E’s plan and ballots are being sent to fire victims and other creditors, with a voting deadline of May 15.

In a motion opposing the TCC’s request, two lawyers representing about 7,000 fire victims say the motion is an ill-timed attempt to sway the voting.

“The content of the proposed letter interferes with the bankruptcy principle that claimants should be free to exercise their voting rights after being provided a neutral statement approved by the court. The court should deny TCC’s request that it put its ‘finger on the scale’ by entering an order approving the proposed letter after voting has already commenced,” Gerald Singleton and Richard Marshack said.

The TCC lawyers, however, argued the proposal is a familiar move in bankruptcy proceedings.

“Committees often inform their constituents of their views on various aspects of bankruptcies,” they said. “Mass tort cases are no exception.”

PG&E is trying to exit bankruptcy by June 30 to participate in a state wildfire insurance fund established last year. Its agreement with Newsom would allow the state or a third party to take over the utility if it doesn’t meet that deadline. Montali has yet to approve that agreement, which he’s scheduled to hear Tuesday.

April 7, 2020

ERCOT Technical Advisory Committee Briefs: April 1, 2020

In its first report since the COVID-19 coronavirus pandemic forced most Texans to stay at home, ERCOT said last week it has seen a weekly 2% reduction in energy usage.

ERCOT Senior Director of System Planning Warren Lasher said during the Technical Advisory Committee’s webinar Thursday that the grid operator has seen little change to its daily afternoon peaks. However, load has been off as much as 10% from 6 to 10 a.m., according to the grid operator’s analysis.

Lasher cautioned that ERCOT is hampered by a delay in obtaining customer-specific data and has “limited operational” data to work with. He cautioned that spring break has also had some effect “on what we see.”

Staff developed their analysis by taking a load forecast from January used for daily operational forecasts and added actual weather conditions to create a backcast model. The data Lasher referred to came from the week beginning March 22.

“Much of the variability in customer demand is driven by weather variability,” Lasher said. Texas saw unseasonably high temperatures during March, with temperatures reaching the low 90s in some parts of the state.

Lasher promised to share a more granular look at the data in the near future and regular updates with the TAC.

Staff Following Pandemic Plan

Meanwhile, ERCOT continues its efforts to minimize the effects of the pandemic on operations.

Kristi Hobbs, who is responsible for ERCOT’s enterprise risk management, said staff are following the grid operator’s pandemic plan. Most have been working from home since March 18 — “We’ve been able to maintain a lot of productivity,” Hobbs said — while operators have been alternating shifts between both control rooms. That allows for deep cleaning of the control rooms between shifts.

ERCOT has yet to report a positive test for the virus. Hobbs said a contractor is on call should a workspace need to be disinfected following a positive COVID-19 test.

“Our goal is to ensure we protect our employees and ensure ERCOT can maintain the key business functions you expect from us,” Hobbs told the committee.

Staff have also drafted a document for qualified scheduling entities (QSEs) that describes how to set up remote control rooms and the importance of redundancy. The draft was to be finalized Friday and then posted publicly after a conference call to be scheduled with the QSEs.

Credit Becoming an Issue in ERCOT’s Market

Reliant Energy Retail Services’ Bill Barnes, who chairs the Market Credit Working Group, warned that there may not be enough collateral in the market to keep some retail electric providers (REPs) from defaulting on their credit.

“We’ve done a good job to assess market-pricing risk. This event we’re facing is not a market-pricing risk,” Barnes said. “We have to prepare for an event where you’ll see some REPs default. The concern is the collateral level that is held. The collateral ERCOT is holding may not be enough.”

Barnes said his group is taking a hard look at all the parameters related to market participants’ short payments, including: the timing of when ERCOT can recover short-paid funds (currently six months); the $2.5 million cap on the amount that ERCOT can recover in each default uplift invoice; and the time between when ERCOT issues default uplift invoices (30 days).

The working group, which evaluates credit-risk mitigation and the effect of protocol or market design changes on credit, will discuss a Nodal Protocol revision request (NPRR) addressing a quicker recovery of short-pay amounts during its scheduled April 15 meeting.

“The impact of COVID-19 on retail markets is something that was not contemplated in the ERCOT credit rules. This could be a long, drawn-out process,” Barnes said. “Everything is being looked at to see if there’s a better way to recover amounts quicker.”

Real-time Co-optimization’s Cost: up to $55M

Real-time co-optimization’s (RTC) price tag has grown to $50 million to $55 million with an estimated timeline of up to four-and-a-half years, according to an impact analysis following the development of principles, or boundaries, that will guide ERCOT’s implementation of the market tool.

ERCOT had originally projected it would cost at least $40 million to add RTC to its energy-only market. RTC procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements.

ERCOT’s Matt Mereness, chair of the Real-Time Co-optimization Task Force, told the TAC that the group has identified about 190 different protocol sections that will need to be modified or written. The task force has produced a 44-page document encapsulating the nine months of work on the key principles, which were approved by the grid operator’s Board of Directors in February. (See “Real-Time Co-optimization Team Finalizes Scope,” ERCOT Board of Directors Briefs: Feb. 11, 2020.)

“2020 is the year to get the protocols done so we can work on the business requirements,” Mereness said. “The key is to be wrapped up by the middle of 2021 so we can develop the systems.”

Mereness promised more details during the task force’s April 8 meeting, when the group will take its first dive into the protocol section.

The RTC project will touch at least a dozen systems. The task force expects ERCOT’s Market Management System to be the most affected system.

Mereness said there is little slack in the project’s timeline and that the task force plans to avoid mistakes similar to those of the nodal market project, which was beset by ballooning costs and delays as teams added unnecessary elements to the systems.

“If there’s something wrong or missing, we’ll get in there and fix it,” he said. “But if it’s additional functionality or something nice to have, that’s where we would challenge any and all changes that will affect the schedule and the budget.”

TAC Endorses 4 More Energy Storage Concepts

The committee endorsed four additional key topic/concepts (KTCs) brought forth by the Battery Energy Storage Task Force, which has been charged with integrating battery energy storage resources (ESRs) into ERCOT:

KTC 11: Establishes how DC-coupled resources register and participate in the combo-model and single-model “era” (before single-model ESR implementation). Single-model will be implemented in 2024 when RTC goes live.
KTC 12: Recommends that the existing market rules and practices are sufficient for co-located AC-connected ESRs for registration, participation model, forecasting, performance, mitigation treatment in security-constrained economic dispatch, wholesale storage load treatment and data requirements from QSEs.
KTC 13: Defines a self-limiting generation site as a combination of one or more resources combined with an energy storage system behind a single point of interconnection, where the generation and energy storage system’s total capacity is greater than either the interconnection agreement’s maximum power export (Pmax) rating or the inverter rating. Similar consideration may also apply to maximum power withdrawal (Pmin). QSEs should manage a self-limiting generation site’s performance to not exceed the established Pmax or withdraw more than the established Pmin from the grid.
KTC 15: Describes the proxy process for both ESR models.

The BESTF has developed an issue-tracking spreadsheet to monitor discussion points and its progress. Chair Kenneth Ragsdale, with ERCOT, said the group is working through the NPRRs that will be submitted to the Protocol Revision Subcommittee.

TAC Approves 4 Change Requests

The committee approved three NPRRs and a single change to the Planning Guide (PGRR) in a nearly unanimous email vote that concluded Friday. The lone dissent was independent power marketer Morgan Stanley’s opposing vote against NPRR998.

NPRR 953: Defines relay loadability rating to align with NERC’s definition changes, which adds a requirement to include protection system limitations for operational planning analysis and real-time assessments. The changes also support ERCOT housing and monitoring the relay loadability rating in Energy Management System applications.
NPRR 997: Requires an entity controlling a primarily natural gas-fired generation resource to supply ERCOT with a declaration contained in the summer weather preparedness form. The declaration should state that the resource entity or the resource entity’s QSE has made a written effort to communicate with the operator of each gas pipeline that is directly connected to the entity’s generation resource to coordinate any planned pipeline outages to maximize the resource’s availability during the summer peak load season.
NPRR9 98: Establishes a requirement that ERCOT post a message to the Market Information System’s public area every time emergency response service is deployed or recalled.
P G RR 075: Requires resource entities and interconnecting entities to provide model-quality test results that demonstrate appropriate performance for submitted dynamic models. Also clarifies that dynamic model data shall be provided using the appropriate dynamic model template; raises awareness of requirements associated with user-written dynamic models; and makes various miscellaneous language updates and corrections, including the elimination of a section superseded by NERC Reliability Standard PRC-002-2 and a Nodal Operating Guide section on phasor measurement recording equipment.

ERCOT’s legal staff have approved the use of electronic votes by stakeholders during the pandemic emergency, asking only that such meetings use communications equipment that allows attendees to hear each other. If necessary, votes can be validated after the meeting, staff said.

— Tom Kleckner

April 7, 2020

PJM Preps 3rd Control Room, Plans for Sequestration

By Michael Yoder

No PJM dispatchers have tested positive for COVID-19 yet, but RTO officials are planning just in case their luck runs out.

During the weekly coronavirus update Friday, PJM officials were asked how they would respond if a dispatcher tested positive for the virus.

Paul McGlynn, PJM’s executive director of system operations, said no control room workers have tested positive, but that the RTO has enough employees to fill gaps if someone becomes infected.

McGlynn said PJM’s control center best practices document includes procedures for bringing back former employees in an emergency. “We look at staff that has previously worked in the control room and develop plans to get them trained and ready so that they could go back on the board if needed,” McGlynn said.

Telecommuting Extended

Scott Heffentrager, PJM’s chief security officer, said the RTO is extending telecommuting for all personnel until May 4. Heffentrager said the telecommuting measure does not apply to the control room staff, IT operations center, security or other critical on-site support personnel.

Crews have been prepping the PJM campuses for more than a week for sequestration — healthy workers required to remain on site if the pandemic becomes worse — if it becomes necessary. Heffentrager said crews are installing temporary bedding, entertainment, food and other accommodations for employees.

“We have not made the decision to go to sequestration, but this was just to prep the campus in the event that we do pull the trigger to do that,” Heffentrager said.

Besides adding accommodations for employees, a team has also been working on converting PJM’s control room simulator to a potential third control room in case of an emergency. Heffentrager said the control room is currently being tested, and security and compliance teams are converting the room to a “physical security perimeter” to meet NERC standards.

Generator Outage Coordination

PJM’s David Schweizer updated stakeholders on generator outage coordination, saying most generators intend on going ahead with planned and maintenance outages despite the pandemic. He said the RTO continues to track any changes that members bring to PJM’s attention, including planned outages.

PJM COVID-19 — David Schweizer, PJM | © *RTO Insider*

About 5% of the planned outages this spring have been canceled outright without being rescheduled, Schweizer said, with about 25% being deferred until later this spring, the fall and the spring of 2021. Schweizer said many generators are reducing the scope of the spring outages by supplementing them with short duration maintenance outages during off-peak hours.

PJM has also continued coordination with gas pipelines to make sure gas is still being sent to generators. Schweizer said teams are tracking any pipeline maintenance plans, especially those that could “affect generation in the PJM footprint.”

Stakeholders are continuing to compile best practice information through a survey of generators that was started last month, Schweizer said. The survey was designed to be a portal to provide supplemental information to PJM so that the RTO is aware of issues related to outages, complications with contractor availability and other support needs.

Schweizer said the questionnaire is meant to be a “dynamic, ongoing survey” that will be updated regularly. He said one of the biggest concerns that has been voiced by generators are supply chain problems for outage-related materials coming from outside the immediate area.

“I think the thing we’re seeing mostly is comments about contractor availability not being 100% assured due to the fact that many outages are relying on critical workforce and resources coming from out of state or even from overseas,” Schweizer said.

Load Modeling

Elizabeth Anastasio, PJM senior meteorologist, said long- and short-term load forecasters are attempting to determine the impact of COVID-19 by comparing actual load with historical temperature and load data.

Anastasio said forecasters have been seeing some trends in load forecast errors.

After the first two weeks of March, the error in one of the short-term models fluctuated between +2% and -2%, Anastasio said, averaging out to a bias near zero for the forecast model.

In the last two to three weeks of March, she said forecasters observed the forecast error increase in magnitude, seeing an error of 4 to 6% depending on the time of day. She said the error has largely remained positive in that time, as the “models are over-forecasting almost exclusively.”

Anastasio said the warmer-than-usual weather has been playing a role in lower load levels.

“We’re doing our best to figure out how much of our decrease in load is due to the warmer temperatures and how much is due to COVID-19,” she said.

Chris O’Leary of PSEG Energy Resources asked if Anastasio believes PJM will be able to quantify the effect of COVID-19 with the higher-than-normal March temperatures and other factors.

Yes, Anastasio said. At least three or four methodologies are being pursued, she said, with each one having limitations that include simplistic modeling and subjectivity.

“What we’ve seen from early results of this analysis is that many of the methodologies are converging on a similar solution,” Anastasio said. “I suspect that we’ll be able to present a little bit more in this line at our Operating Committee meeting presentation” on April 15.

Additional Updates

PJM’s Donnie Bielak provided an update on transmission outage coordination, saying most planned transmission upgrades are proceeding on schedule. Although some transmission operators decided in late March to defer nonessential work until later months, time-sensitive work is proceeding as planned, Bielak said.

Michael Hoke, PJM’s senior lead trainer, updated stakeholders on operator training schedules. Hoke said his team is in the process of finalizing online simulations. He said the online simulations are used for operators who need a certification renewal in the next month or two and need simulation hours to complete the process.

April 7, 2020

DOJ Joins NextEra Appeal of Texas ROFR Ruling

By Tom Kleckner

The U.S. Department of Justice last week again threw its weight behind NextEra Energy’s ongoing effort to repeal a Texas law giving incumbent transmission companies the right of first refusal to build new power lines in the state.

Attorneys with the department’s Antitrust Division filed an NextEra Appeals Court Decision on Texas ROFR Law.)

Assistant Attorney General Makan Delrahim and other division attorneys urged the 5th Circuit to vacate the district court’s judgment and remand the motion to dismiss. The division also filed a brief in NextEra’s lawsuit before the U.S. District Court for the Western District of Austin. (See DOJ Weighs in on Texas ROFR Lawsuit.)

DOJ questioned whether the district court properly dismissed a dormant Commerce Clause challenge to SB 1938. The legislation, passed last May, essentially allows only incumbent transmission companies to build new power lines in Texas by granting regulatory certificates of convenience and necessity to the owners of the endpoints of a new transmission line.

Delrahim noted that the Commerce Clause gives Congress the power to regulate interstate commerce and that the Supreme Court has interpreted the clause to contain the negative implication that “strikes at one of the chief evils that led to the adoption of the U.S. Constitution, namely, state tariffs and other laws that burdened interstate commerce.”

NextEra has used the same argument in its appeal before the 5th Circuit.

In its brief, DOJ said the district court made three analytical errors in its decision, including:

Erring in its evaluation of discrimination, improperly distinguishing “binding Supreme Court precedent articulating principles of ‘ordinary Commerce Clause jurisprudence,’” failing to consider in-state physical presence requirements that are “viewed with particular suspicion” and affording improper significance to the location of a utility’s parent company.
Misreading and misapplying precedent from the Supreme Court ruling in General Motors Corp. v. Tracy to a “noncompetitive, captive market in which the local utilities alone operate.” DOJ said, “The unique factors and concerns for utility markets that determined the outcome in Tracy are not present here and were not evaluated by the district court.”
Failing to weigh whether any of the alleged burdens from SB 1938 “substantially outweigh the law’s putative benefits,” as required under precedent.

April 7, 2020

SPP Seams Steering Committee: April 2, 2020

SPP and MISO are picking up the pace of developing their 2020 coordinated system plan (CSP), staff told the Seams Steering Committee last week.

SPP’s Neil Robertson said both RTOs have published project needs to their individual stakeholder groups. Once the project submissions come in, he said, staff will begin the evaluation phase of those projects. The RTOs will reveal their final portfolios in October and December, respectively.

The RTOs agreed to conduct a CSP this year to determine whether there are any interregional projects worth pursuing. (See MISO, SPP Staff Recommend 2020 Joint Study.)

SPP Director of System Planning Casey Cathey once again expressed his optimism that the CSP will result in a joint project this year. Three previous attempts between SPP and MISO have been fruitless, but Cathey said there has been a large jump in MISO’s prevailing north-to-south system flows.

“The likelihood of economic and reliability projects that meet the thresholds in the [joint operating agreement] is much higher this cycle,” he said. “That’s just by nature of MISO updating their models and SPP’s regional approach to reflect their range of futures and growth, including all new generation in the north.”

MISO’s models include additional wind generation in its northern regions not found in SPP’s models. Cathey said staff are aware of the situation and pondering additional sensitivities to meet those needs.

SPP, AECI Agree to Joint Study

SPP has also agreed to a joint CSP in 2020 with Associated Electric Cooperative Inc. following a March 30 meeting of their Interregional Planning Stakeholder Advisory Committee, Robertson told the SSC.

A scope document has been approved, and solutions will soon be shared. Robertson said the entities plan to finish their analysis in August, after which SPP will have to file a contract with FERC.

The joint CSP could include a 345-kV competitive project approved in January by the RTO’s board as part of the 2020 SPP Transmission Expansion Plan. Robertson said the $152 million, 105-mile Work Creek-Blackberry upgrade in Kansas and Missouri will be included in the study to determine whether there are any system reliability impacts. (See “Directors Approve $545M Transmission Expansion Plan,” SPP Board of Directors/MC Briefs: Jan. 28, 2020.)

Committee Endorses Study of MISO RDT Flows

The committee unanimously endorsed a summary report on the effect of MISO’s contract path to its southern footprint, after first inserting language making it clear the study “should not be used to draw broad conclusions about the impact of MISO RDT [regional directional transfer] flows” to SPP’s region.

The study was inconclusive as to whether MISO’s above-capacity RDTs created a “pattern of financial harm.” Several members pointed out the analysis does not consider the costs of real-time deviations from day-ahead market positions or the economic redispatch of the MISO system. (See “Congestion Study Inconclusive on MISO Contract Path,” SPP Seams Steering Committee Briefs: March 12, 2020.)

The study looked at the SPP day-ahead market’s external flows and solution costs to determine whether RDTs above the contract path capacity between MISO’s South and Midwest sub-regions created additional congestion or operating costs for SPP’s market. MISO is limited to 1,000 MW of contracted, firm capacity over the contract path as a result of a 2015 settlement agreement. (See SPP, MISO Reach Deal to End Transmission Dispute.)

SPP Again Winds up with Positive M2M Settlements

SPP recorded another $1.06 million of market-to-market (M2M) settlements in February, the fifth straight month — and 44th in 60 months — the M2M process with MISO has settled in its favor.

SPP’s market-to-market settlements were once again in its favor in February. | *SPP*

SPP has now earned $73.59 million from M2M settlements with its neighbor since the two began the process in March 2015. The process provides a compensation mechanism when SPP or MISO have to re-dispatch transmission around congested flowgates.

Temporary and permanent flowgates on the RTOs’ seam were binding for 453 hours during January. Temporary flowgates accounted for 385 of the binding hours.

— Tom Kleckner