Page 1118 – RTO Insider

March 31, 2020

N.Y. Looks at Grid Transition Modeling, Reliability

By Michael Kuser

NYISO stakeholders on Monday explored detailed assumptions and modeling descriptions for a study on transitioning the New York grid to a cleaner future.

Roger Lueken and Sam Newell of the Brattle Group presented the Installed Capacity/Market Issues Working Group (ICAP-MIWG) the thinking behind the study, which will simulate market operations and investment through 2040 to inform ISO staff and stakeholders on market evolution. (See NYISO Focus Turns to Grid ‘Transition’.)

“The model is reasonable for painting a broad-brush picture of how the supply and demand will look in the future,” Newell said. “It’s not a super granular model, it’s zonal, with a ‘bubble’ [representation] transmission layout and is a somewhat stylized representation of the generation fleet where we aggregate individual units

“There are a lot of unknowns currently about how we will meet the state goals, and what kinds of new resources will come in,” Newell said.

NY Grid Transition — In conjunction with NYISO, Brattle developed a 5-zone “pipe-and-bubble” representation of the New York grid. | *The Brattle Group*

The modeling helps the ISO answer several questions, he said, such as what types of renewable resources will be needed to meet the Clean Energy Standard, including flexible resources and storage, and how electrification will affect load profiles and market operations.

“Wow, the world is so different now, three weeks after our last meeting, but we’re just building on what we did then to provide more detail on the assumptions and on some of the modeling approaches,” Newell said.

New York Gov. Andrew Cuomo in February propo s ed a budget amendment to speed up the permitting and construction of renewable energy projects in order to meet the state’s ambitious clean energy goals. (See Cuomo Proposes Stream l ining NY’s Renewable Siting.)

The Climate Leadership and Community Protection Act (A84 2 9), signed into law last July, calls for 70% of New York’s electricity to come from renewable resources by 2030 and for electricity generation to be 100% carbon-free by 2040. It also nearly quadrupled New York’s offshore wind energy target to 9 GW by 2035.

The CLCPA’s clean energy mandates also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.

Modeling Approaches

David Clarke, director of wholesale market policy for Power Supply Long Island, asked how the study would simulate the impact of shortage pricing on energy revenues in the CLCPA future, which might hinge on the supply-demand balance and the amount of surplus capacity in the system.

“We are only partly representing [shortage pricing] in the study,” Newell said. “First of all, we’re not necessarily representing all of the features of either extreme net load conditions that could lead to shortage pricing, nor are we fully representing the dynamic challenges of ramping, and so we’re not fully going to capture that, even if we do represent the upgrade in demand reserve curves in the model.

“Secondly, we’re not actually designing this study to explore the different ways to implement enhanced shortage pricing, for example, through a richer demand curve,” Newell said. “That actually takes a lot of design and is tricky to do well.”

In modeling generators, Lueken said the study is accounting for known retirements and additions to occur over the next few years and not just existing resources, as in the ISO’s 2019 Gold B ook.

“So, for example, we are accounting for the potential for downstate peaker retirements due to the new NOx rule,” Lueken said. “We’re currently planning to assume that downstate peakers built before 1986 retire, that frame units built after 1986 retire, that the aero-derivative units built since 1986 could, instead of retiring, decide to economically retrofit. However, we’re reevaluating these assumptions based on the compliance plans the generators have submitted to the ISO.”

The new NOx regulations go into effect May 1, 2023, with initial rate limits of 100 parts per million on a dry volume basis, corrected to 15% oxygen. Generator compliance plans were due March 2, 2020. (See NY DEC Kicks o f f Peaker Emissions Limits Hearings.)

The study also models the declining capacity value of wind, solar and storage.

“The capacity value of the 5,000th MW of solar will be much lower than the first MW of solar because as you get so much solar in the system, it tends to shift the hours that capacity is needed to other hours in which the solar is not generating,” Lueken said. “It’s the same for wind, and there’s a similar dynamic in place for energy storage.”

The high-level approach to develop the relationship between the amount of resources deployed and the capacity value of these resources entails varying the amount of each technology in turn while holding everything else constant, he said.

“For all the resources, the capacity value falls off quite a bit when you have 10,000 MW deployed,” Lueken said.

Capacity Market and Reliability

Clarke pre s ented a study by PA Consulting and the Long Island Power Authority on how the transition to renewable energy resources will impact the ISO’s installed capacity market, moving to a system dominated by low variable-cost, high fixed-cost resources from one now dominated by the opposite: high variable-cost, low fixed-cost units.

“We are basing our capacity market on the premise that new capacity is needed,” Clarke said. “If you have to add capacity for something and it’s not monetized [in the capacity market], in this case greenhouse gas abatement, the premise that you’re going to need new capacity for reliability is really no longer a valid premise.

“Making a more granular market, making sure there are sufficient market signals for generators to recover the ‘missing money,’ breaking down what things capacity is providing, different kinds of capacity and paying them for things they are providing — that is the kind of approach I see as being necessary in the long run,” Clarke said.

Voluntary bilateral markets should continue, but the underlying market price should be disaggregated. These structural changes are necessary in the long run, as the existing structure may not best advance the state’s clean energy mandates, he said.

“As energy margins and prices are declining, [and] the needed capacity is facing retirement, we recognize the essential need for long-term support for renewable resources,” Clarke said.

Howard Fromer, director of market policy for PSEG Power New York, asked why a resource would need long-term support: “Is your own model still going to encompass out-of-market support? That seems to undermine everything you’re talking about in terms of [market] efficiency.”

“I don’t think it needs to,” Clarke said. “There will be attributes that will be monetized as we move in this direction, and attributes that aren’t, so to the extent that we have not monetized the attributes that we need, there will be need for renewable resources and out-of-market payments in the long term.”

The proper place to recognize the desirable attributes of renewable energy resources is in the energy market, said Mark Younger, president of Hudson Energy Economics.

“We have a multiyear effort to properly try and capture the value of those renewable attributes but have not yet been successful. But that is the proper way to capture it, to put a price on energy attributes and incorporate it into the market,” Younger said.

Storage resources would still have value in scarcity conditions requiring a price signal, “but it’s not a capacity signal. Trying to do it through a capacity price is a very blunt instrument being wielded by blind people,” Younger said.

Clarke said the paradigm of trying to include everything possible in a 2040 energy price was “not particularly workable.”

Clarke highlighted differences among those who would allow highly volatile and perhaps extreme energy and ancillary service prices driven by flexible resource shortages to provide the incentive for their construction from those that would assure development of sufficient flexible resources through a targeted capacity payment.

“We do support the NYISO’s proposal to enhance ancillary services revenues as a means of more efficiently distinguishing resources that can provide flexible resource services over and above those that cannot,” he said. “However, we do recognize that an additional missing money payment for flexible capacity attributes could signal an appropriate mix.

“I see energy as declining in price and in value generally,” Clarke said. “I also see some reliability challenges going forward — increasing ICAP requirements, net load shifting, a changing load shape and frequency of ramping, saturation of particular renewable resources in certain load pockets and continued need for firm dispatchable resources.”

Clarke showed a graph indicating that offshore wind speed — and ultimately power output — is more broadly distributed than the duration of conventional generation outages.

“If the Long Island buoy data perfectly correlated with the sites offshore New York City, then the capacity value of offshore wind would be effectively zero,” Younger said. “While this is informative to indicate that we probably are massively overvaluing the capacity value of wind, because there are so many hours with very low wind speed, it doesn’t really take us beyond that observation.”

March 31, 2020

FERC Sets Hearing on FirstEnergy PPAs

By Rich Heidorn Jr.

FERC on Monday ordered a paper hearing to consider FirstEnergy Solutions’ bid to void power purchase agreements with wind generators and others as part of its bankruptcy proceeding. (EL20-35).

The commission acted days after the Sixth Circuit Court of Appeals issued a mandate on its December 2019 order overruling a U.S. bankruptcy court’s May 2018 injunction that prevented FERC from issuing any order requiring FES to continue complying with its obligations under the contracts. The appellate court also reversed the bankruptcy court’s ruling allowing FES to reject the contracts.

FES changed its name to Energy Harbor upon emerging from Chapter 11 bankruptcy on Feb. 27 with former bondholders owning 50% of the equity. (See FERC OKs FES Sale to Bondholders.)

The Sixth Circuit ruled “that the public necessity of available and functional bankruptcy relief is generally superior to the necessity of FERC’s having complete or exclusive authority to regulate energy contracts and markets.”

FirstEnergy PPA — Kyger Creek Power Plant

But it said that, although the bankruptcy court’s jurisdiction is “superior to FERC’s position,” it is not exclusive and that the court had exceeded its authority.

“Through this rash and unnecessary overreach, the bankruptcy court has prevented FERC from timely completing an investigation into or holding a hearing about the public interest in the proposed rejection of these contracts, which … would have been appropriate and might have been valuable or beneficial to the ultimate determination,” the Sixth Circuit said.

The appeals court said the bankruptcy court must consider the impact of rejecting the contracts on the “public interest,” rather than using the “business judgment” standard that normally applies in bankruptcy cases.

The Sixth Circuit required that the bankruptcy court give the commission “a reasonable accommodation” in providing the commission’s views to the bankruptcy court with respect to whether the rejection is consistent with the public interest.

The appeals court said that when a Chapter 11 debtor asks the bankruptcy court for permission to renege on energy contracts that are FERC jurisdictional, the bankruptcy court “must consider the public interest and ensure that the equities balance in favor of rejecting the contract, and it must invite FERC to participate and provide an opinion in accordance with the ordinary FPA approach (e.g., under the Mobile–Sierra doctrine).”

Mobile-Sierra requires FERC to presume that the rate set out in a freely negotiated wholesale energy contract meets the FPA’s “just and reasonable” requirement unless the commission determines that the contract seriously harms the public interest.

The Supreme Court has ruled that the public interest can require canceling contracts that impair the financial ability of a public utility to continue its service, imposes excessive burdens on consumers or is “unduly discriminatory.”

FERC said Monday that it was initiating a hearing and investigation under Section 206 of the Federal Power Act in order to develop a record that would inform the commission’s views on the contracts’ cancellations.

The commission ordered Energy Harbor to submit a filing within 30 days, identifying each contract the company seeks to reject, the status of any negotiations with the contract counterparties and an explanation of why the rejection meets the public interest standard.

“To the extent that such explanation relies on the standard that the contract might impair Energy Harbor’s financial integrity, include a discussion of the effect of the completed bankruptcy reorganization and Energy Harbor’s emergence from Chapter 11 bankruptcy protection on the application of this standard,” FERC said.

Counterparties and intervenors will have 30 days to respond to Energy Harbor’s filing.

“Any counterparty that does not submit such a response shall be deemed to acquiesce in the rejection of its contract for the purpose of the commission’s public interest determination,” FERC said.

The commission said it plans to issue an order within 180 days. The refund effective date will be the date of the publication of Monday’s order in the Federal Register.

The contracts FES sought to renege were with Allegheny Ridge Wind Farm (Phase 1 and Phase 2), Blue Creek Wind Farm, Casselman Windpower, High Trail Wind Farm, Krayn Wind, Meyersdale Windpower, North Allegheny Wind (Phase 3 and Phase 4), Maryland Solar and Forked River Power.

FES also sought to escape and the multi-party intercompany power agreement with Ohio Valley Electric Corp., which runs through June 30, 2040. OVEC provides power from its two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — to Energy Harbor and seven other corporate “sponsors.”

March 29, 2020

MISO Board of Directors Briefs: March 26, 2020

MISO Board of Directors Chair Phyllis Currie last week paused to reflect on the unprecedented circumstances that converted the RTO’s Board Week into a teleconference format.

Currie expressed gratitude that MISO decided against in-person meetings for both Board Week and upcoming stakeholder committee meetings to help stem the spread of the COVID-19 coronavirus. The spring meetings were scheduled to be held in New Orleans, which has since become a hotspot for the disease.

“This is an extraordinary period of time with the coronavirus … and I thank MISO for accommodating the need for distancing,” Currie said during the Thursday conference call.

Currie said MISO is faithfully executing its purpose: “Keeping the lights on across America” during crisis times.

“This is really our job, and this is our mission, and I thank you,” Currie said to MISO staff and members. “You’re providing a service that most people take for granted.”

Currie said the board is likewise limiting its meetings to conference calls and canceling some meetups that don’t translate well to phone format.

MISO will discuss COVID-19 impacts on the grid with members during its nonpublic Reliable Operations Working Group meetings, RTO executives said. The pandemic’s effect on the grid will also be revisited in upcoming public meetings of MISO’s Reliability Subcommittee.

“Clair and I have stayed in different cities, making sure we don’t become ill at the same time,” MISO CEO John Bear said of himself and President Clair Moeller. Bear said the idea is to make sure that the RTO has uninterrupted senior management in place.

Bear said MISO continues to monitor the latest information from the White House and Centers for Disease Control and Prevention, as well as conducting its own consultations with infectious disease experts and epidemiologists.

“We’ve not had any employees confirmed to have the virus, but we have had employees exposed to someone with the virus, and they’re in self-quarantine,” Bear told stakeholders.

Bear said most MISO employees began working from home beginning March 17. The RTO has also been holding virtual all-hands meetings on Fridays, where more than 1,000 employees log in, he said.

He said MISO is making sure that employees have certain basic necessities as supply chains struggle to keep up with consumers stockpiling supplies, “simple things like toilet paper and cleaners,” he said.

Many utilities in the MISO territory have pledged to suspend disconnections for nonpayment but still meter usage for billing for when customers can catch up on payment.

Ameren is suspending all disconnections for nonpayment and forgiving any late payment fees for residential and business customers. It noted that normal billing for customers’ usage will continue as usual.

DTE Energy said it was halting all shutoffs for nonpayment for low-income customers through April 5 and possibly longer, depending on the outbreak trajectory. Consumers Energy likewise said its shutoff pause applies to certain classes of residential customers. Northern Indiana Public Service Co. said its suspension of shutoffs “will remain in effect until further notice” for residential, commercial and industrial customers. It also froze late-payment charges through May 1. Entergy pledged March 14 to temporarily suspend disconnections for the next 30 days.

Indianapolis Power and Light said it “recognizes the impact and stress COVID-19 is causing in people’s daily lives” when it announced a similar suspension through April 15.

“IPL recommends all customers do their best to maintain timely utility bill payments, as they will be responsible to pay all charges associated with usage during this period,” the utility said. “We will continue to read meters and send bills. Customers should pay what they can to avoid building up a large balance that will be difficult to pay off later.”

MISO on Budget

Three months into 2020, MISO is on track to meet its $264.7 million base expense budget.

CFO Melissa Brown said the RTO has so far spent $41.8 million of the $42.8 million it predicted it would spend by now. Brown said the $1 million in savings can be put down to smaller-than-expected building and computer maintenance costs.

The RTO is also trending toward a $50.7 million year-end spend on its $50.2 million investment expense budget. Brown said the overspending will likely be because it expended more time and resources on its resource availability and need solutions.

But Brown also warned that MISO has yet to account for any financial impacts from the COVID-19 pandemic. She said it will assess the financial implications and share them with the board at future meetings.

Nominating Committee Begins Work

MISO’s Nominating Committee is ready to begin a search for candidates that could fill two seats on the board this year.

The RTO’s Advisory Committee installed North Dakota Public Service Commissioner Julie Fedorchak and Otter Tail Power’s Stacie Hebert, of the Transmission Owners sector, as the two stakeholder representatives on the Nominating Committee this year, which vets and selects board candidates to be put to member voting. The AC late last year decided against doubling the number of stakeholder representatives to serve on the committee. (See No-go for MISO Board Election Changes.)

Directors Theresa Wise and Baljit Dail will reach their term limits at the end of the year. Wise is eligible to serve another three-year term; Dail has already exceeded his total three-term limit through a special waiver in 2017, which was granted to retain his IT expertise. (See “Committee Permits Consideration of Extra Term for Dail,” MISO BoD Briefs: June 22, 2017.)

MISO Reports IT Incident

MISO had one IT concern to report for the quarter during a scorecard presentation to the board during a Tuesday conference call of the board’s Technology Committee.

Chief Information Security Officer Keri Glitch said the control room was forced to manage operations manually without the dispatch system for 75 minutes on Jan. 23.

Glitch said the problem originated during a planned market business continuity transfer for the day-ahead, real-time (DART) market system. During the data transfer, the DART system “could not connect to the market database, resulting in a unit dispatch system outage” from 4 to 5:15 p.m. ET. She explained that the root cause of the problem was that the system administrator selected an outdated option for direct connectivity to the failover site, which should have been removed from the tool.

Over that time, the control room managed operations manually without the dispatch system until connection to the market database was restored. Glitch said MISO members didn’t incur any losses as a result of the downtime.

“If you can’t hear it in my voice, I’m not happy. The bottom line is this should not happen and will not happen again,” Glitch said. “We have had many, many conversations with the employees. … A lot of this is training awareness of how critical these systems are.”

Glitch said MISO is retraining staff and looking into automating the manual portion of the process. She said she would speak more about the issue in closed session of the committee.

— Amanda Durish Cook

March 29, 2020

Soapbox: IPPs Band Together on COVID-19 Response

EDITOR’s NOTE: Independent power producer and transmission developer LS Power, which operates 29 power generation facilities totaling 14,000 MW, has been an aggressive competitor for Order 1000 transmission projects. Marji Philips, LS Power’s vice president of wholesale market policy, is a fixture at PJM stakeholder meetings and a tenacious advocate for the company. But the COVID-19 crisis has it and its competitors working together, Philips says. Here is her account of a week that was.

By Marji Philips

A remarkable thing happened recently that merits a shoutout. The independent power producers in the Eastern RTOs set aside competitive differences and came together as a collective to protect our communities. Alongside other generation owners, we dedicated all of our resources to ensure our power plants will remain online during the COVID-19 coronavirus pandemic. Unfortunately, this is probably only the beginning, and not the end, of what will require long-term and sustained efforts to ensure the lights stay on during this crisis. Fortunately, the amount of cooperation we experienced with our local and state officials augurs well for the future.

There are some lessons learned already. It was not that long ago that the RTOs were required to outline their resilience plans for FERC. As part of that, we debated what resilience meant and viewed it as low-probability, high-impact events, with the concern that the RTOs were too focused on natural gas pipelines disruptions. We had been through Hurricane Katrina, saw what happened in Puerto Rico with Hurricane Maria and declared ourselves basically ready for a disaster, but as events unfolded, we found that we as an industry were not as prepared as we could have been. While initially slow to organize community discussions and reach out to local and state governments, RTOs quickly adapted to a more proactive stance to support us in getting our needs identified and addressed.

This came to a head on the weekend of March 21, when the Electricity Subsector Coordinating Council (ESCC) announced it was shifting into high gear to deal with the pandemic. Our national association, the Electric Power Supply Association, started working with all the other industry associations through the ESCC at the federal level.

Not surprisingly, the primary concern was ensuring the ongoing safety of our workers and their ability to get to our power plants. This will require access to priority testing despite short supply and waivers regarding any transportation limitations. We grappled with communication challenges, as conference call networks were initially overwhelmed by the volume created by the widespread shift to remote operations. We had to identify and address all related issues. This included ensuring equipment, services and products (e.g. chemicals) could get to our plants, and that those suppliers also had testing and transportation available, in addition to our plant employees. Further, it became apparent that we would need to ensure that hotels remained open so we could house our workers, although contingencies were also made to allow for on-site work and shelter-in-place if need be. Thanks to the expediency and effectiveness of our regional associations — the PJM Power Providers (P3 Group), the New England Power Generators Association (NEPGA) and the Independent Power Producers of New York (IPPNY), as well as all of the dedicated state personnel responding to the crisis — none of the state lockdowns issued thus far has prevented us from keeping our power plants running.

So, what’s in the future? We are working to further refine our shift work so our employees stay healthy. We remain focused on continued access to ongoing supplies for a sustained duration. There is concern that supplies may be interrupted, which may require emissions permits to be temporarily exceeded in order to keep some plants online; the need to keep the lights on in our hospitals and home will require temporary tradeoffs. It also may be necessary to defer generation and transmission maintenance. The challenge will be to determine how long that maintenance can be deferred, especially if we have a hot summer. We will have to understand the market impacts of changes in transmission and generation outage scheduling. We will have to forecast the expected impacts of the shelter-in-place restrictions on our economy. On top of all this, we need to get back to work. In PJM, we have to get the capacity market running again. In ISO-NE, we need to get the Energy Security Initiative moving. And in NYISO, we need to address market power mitigation and carbon issues. Hopefully, in the near future we will return to the “new normal,” and all the hours we now have at home will enable us to successfully engage FERC to help keep the RTO electric markets operational and efficient. In the meantime, I’d like to extend LS Power’s appreciation for the hard work of our employees, partners and industry colleagues in these challenging times.

March 29, 2020

Texas PUC Briefs: March 26, 2020

Meeting in a hearing room absent of staff and regulatory lawyers, the Texas Public Utility Commission last week approved several measures addressing delinquent customer accounts and other issues related to the COVID-19 coronavirus pandemic.

The commissioners on Thursday voted unanimously to issue an order that will temporarily suspend a series of rules allowing retail electric providers (REPs) and other utility participants to disconnect service for nonpayment. Instead, all REPS must suspend late fees and offer a deferred payment plan upon customer request (50664).

The PUC also created the COVID-19 Electricity Relief Program, a funding mechanism through which REPs may recover a “reasonable portion of the cost of providing those uninterrupted services to customers facing financial hardship.” The program will last for six months, unless the PUC extends it (50703).

Texas PUC — PUC Chair DeAnn Walker (right) properly coughs into her elbow while practicing social distancing with Commissioner Shelly Botkin during the March 26 open meeting.

The commission said the initial funding mechanism is temporary and requires further review. Transmission and distribution utilities will collect funds from customers in ERCOT’s customer-choice areas through a rider — based on 33 cents/MWh — which will reimburse the utilities for unpaid bills.

The commissioners plan to revisit the order in a month.

“We’re going to do whatever we need to do to address this situation with electricity and the customers,” Chair DeAnn Walker said during the open meeting. “I’m concerned [the rider] may be too low. If we had a moratorium on disconnects for the next three months, the market couldn’t stand it. We need a reasonable balance to the needs of people losing their jobs with the needs of the market.”

Commissioner Arthur D’Andrea agreed.

“We can’t have disconnects while people have been ordered not to work by the government,” he said. “I think it’s the government’s responsibility to make sure they at least have lights and water while they’re sitting at home under government order.”

TXU Energy and Reliant Energy have already pledged to stop disconnections and late fees.

The order also covers Entergy, El Paso Electric (EPE), Southwestern Public Service and Southwestern Electric Power Co., which operate outside of the ERCOT market under PUC-set rates. The companies may not charge late fees or disconnect customers for nonpayment during the emergency, the commission said.

The commissioners and an IT technician were the only four people in the meeting room. They practiced social distancing, with Walker once coughing correctly into her elbow.

“It’s a new day for all of us,” Walker said.

AEP Texas Gets CCN in South Texas

The PUC also approved a certificate of convenience and necessity for AEP Texas to construct a $78 million, 138-kV transmission line in South Texas. The line could be 50 to 85 miles long (49347).

The commissioners overcame their reluctance to approve the project, noting that ERCOT approved the line as a reliability project in 2015. AEP Texas reached an unopposed settlement agreement with landowners in January.

“It seemed like there was an abnormally long delay [from] when ERCOT approved it. I don’t know what caused that, but it puts the study further out of date,” D’Andrea said.

“I’m concerned about sending this back for remand, but based on the record, I would go ahead and approve the settlement,” Walker said. “[In the situation] we find ourselves, I think it’s the best way forward.”

CenterPoint Energy Hit with $250K Fine

In other actions, the PUC:

slapped CenterPoint Energy with a $250,000 administrative fee for failing to honor some customer-initiated switch requests while transitioning customers from a bankrupt REP (50230);
signed off on EPE’s interim fuel refund of $15 million to be returned to customers (50292); and
approved Entergy’s regulatory accounting treatment of the tax effects associated with a mark-to-market tax accounting method election with respect to its power purchase agreements. Entergy requested the change because it identified a specific PPA with its affiliate Entergy Louisiana that it can recognize as a significant tax loss. The company will provide ratepayers with net guaranteed upfront credits of $34 million, consisting of $3 million per year from 2021 through 2026 and $4 million per year from 2027 through 2030, based upon a gross credit of $46.72 million net of an estimated net operating loss of $12.72 million (50540).

— Tom Kleckner

March 29, 2020

DC Circuit Upholds FERC on BGE Rate Case

By Rich Heidorn Jr.

The D.C. Circuit Court of Appeals on Friday upheld FERC’s 2017 ruling denying Baltimore Gas and Electric’s bid to recover $38 million in taxes deferred over more than a decade (18-1298).

In 2016, BGE sought approval for three adjustments to its formula rate for how taxes are recovered, seeking recovery of $38 million from future ratepayers for costs incurred by the company dating to 2005 (ER17-528). The commission rejected the request, saying BGE took too long to make the adjustments. (See FERC Denies BGE Recovery of $38M in Deferred Taxes.)

The three-judge panel described the case as arising from FERC’s “effort to apply its ‘matching’ principles to divergences between the timing of deductions for tax purposes and timing for purposes of allocating costs to ratepayers. While Congress and other bodies imposing taxes may want to allow early depreciation of an asset (to encourage investment), for example, the commission wants a cost (less offsetting tax benefits) to be charged in the period over which the resulting asset provides services to the utility’s customers.”

FERC ruled that BGE had violated Order 144 by failing to file for recovery of these amounts in its “next rate case,” which the commission said was BGE’s 2005 rate filing.

BGE’s appeal alleged that FERC’s ruling was arbitrary and capricious under the Administrative Procedure Act and that the commission had failed to explain why it had previously allowed delayed recoveries under Financial Accounting Standard 109 (FAS 109) to four “similarly situated” entities: MISO, PPL Electric Utilities, Duquesne Light Co. and Virginia Electric and Power Co. (VEPCO).

FERC contended that the four prior actions were not binding precedent because three of them were issued by staff exercising subdelegated authority and that none of the four “squarely presented” or “necessarily resolved” the issues raised by BGE.

The court rejected part of FERC’s defense, saying “the commission cannot lend its authority to staff and then disclaim responsibility for the actions they take. Delegated staff actions are actions of the agency.”

“It is not enough for FERC to say, ‘The staff did it,’” the court continued. “Reasoned decision-making requires FERC to explain differential treatment under the same rules.”

However, the court found the commission ultimately did provide an adequate explanation to distinguish BGE’s case from the prior decisions.

The court noted that its standards for arbitrary and capricious review apply a lower burden of explanation for agencies when applying existing rules in individual cases. When an agency changes policy, it must meet the standards of FCC v. Fox Television Stations Inc., which require the agency to “display awareness that it is changing position,” show “the new policy is permissible under the statute” and “show that there are good reasons for the new policy.”

“The commission reasonably determined BGE waited far longer than the other four utilities to collect accumulated FAS 109 amounts and failed to offer an adequate reason for the delay (noting PPL and Duquesne involved delays of four and seven years, respectively, compared to BGE’s 12). Moreover, FERC offered specific ways in which each of the four prior cases differed from BGE’s filings in at least one key respect (distinguishing BGE from PPL, Duquesne and VEPCO based on the type of makeup provisions sought and on specific accounting matters) [and] (noting [MISO] and VEPCO sought collection on deficiencies going forward rather than accumulated amounts).”

Senior Circuit Judge Stephen F. Williams filed a partial dissent arguing that agencies such as FERC need not explain disparate outcomes under the same rule unless parties opposed the agency’s administration of the rule in the prior cases.

“Given the number of uncontested issues that an agency typically resolves — uncontested, we may infer, either because any adversely affected parties got no notice or, having notice, thought it not worth the trouble to oppose — a requirement that an agency address its past vermicelli, either by reconciling its current decision with the earlier record or by applying Fox Television, would tie courts and agencies in linguistic knots for little or no benefit to the rule of law,” Williams wrote.

“Indeed, the majority’s approach invites a litigant to dive deep into the records of past agency cases, find one with facts loosely comparable to its own case, and then require the agency to adjudicate, ex post and likely on a limited record, whether and to what extent each past case is like the present one. Our precedents do not require this.”

March 29, 2020March 12, 2025

Moody’s: Coronavirus Recession to Cut GDP 2.3%

By Rich Heidorn Jr.

Moody’s Analytics said Friday it expects U.S. gross domestic product to drop by 2.3% for 2020 as a result of the “sudden stop” in the economy because of the COVID-19 coronavirus pandemic.

Mark Zandi, Moody’s Analytics | Moody’s Analytics

Moody’s expects a 2.2% drop in first-quarter GDP to be followed by an 18% drop in Q2 before rebounding with an 11% gain in Q3 and a 2.4% increase in Q4, Chief Economist Mark Zandi said during a webinar Friday.

The second-quarter GDP drop would be closer to 30% if Congress had not passed its more than $2 trillion in rescue packages, Zandi said.

He noted “about half the country is in some kind of lockdown,” with travel and restaurant sales down drastically and the equity market having lost $10 trillion in market capitalization. He predicted this week’s unemployment claims will be similar to the record 3.3 million filings reported Thursday. Moody’s expects the unemployment rate to peak at 8.7% in Q2 and to remain above 6% until 2022, not returning to full employment (4.5%) until late 2022 or the beginning of 2023.

PJM and ISO-NE use Moody’s Analytics’ projections as inputs in their load forecasts. The company has been criticized for overly optimistic predictions about the 2008 financial crisis. (See related story, PJM Staff Ponder Pandemic Effect on Load Forecast.)

Worldwide Recession

Moody’s expects worldwide GDP to drop 2.1%, with virtually every country in recession. “I’ve never seen anything like it,” Zandi said. “The entire global economy will be in recession,” he said. “The breadth of this is just incredible. … It’s going to be a very difficult couple of years.”

It estimated China, where the outbreak originated, will see a 29% GDP drop in Q1 but will have a 15% jump in Q2 and just a 0.1% drop for the year.

Europe will take much longer to get back to full employment because it has “fewer policy resources” than the U.S., Zandi said.

The good news in the U.S. is that the economy’s fundamentals are far better than they were in 2008, with financial institutions less leveraged and household debt also lower.

Moody’s expects the impact of the outbreak on business in the U.S. to diminish by the third quarter. “By July 4, the disruptions are largely played out,” Zandi said, adding that the country will likely need one or two additional economic stimulus packages as the impact of the initial spending recedes later in the year.

Projected annualized percentage change in real GDP growth, comparing January and March base cases with coronavirus update | Moody’s Analytics

Moody’s has developed three main epidemiological scenarios for the virus. The baseline assumes confirmed infections in the U.S. range between 3 million and 8 million, with new infections peaking in May. With 10% of those infected requiring hospitalization and 1.5% dying, Moody’s said the nation would have a 4% excess capacity of intensive care unit beds and 17% excess capacity of ventilators. Moody’s cautioned that some regions could face shortfalls of ICU beds, ventilators and trained medical staff even under this scenario.

Moody’s S3 scenario — rated as a 10% probability — is much grimmer, predicting infections peak in June with 9 million to 15 million total, a 20% hospitalization rate and a 4.5% fatality rate. With so many people infected, hospitals would have a 125% “capacity deficit” for ICU beds and a 56% deficit for ventilators.

Moody’s three main economic scenarios for the COVID-19 outbreak include a base case with a 72% probability and a 10% upside and 10% downside case. Not displayed are extreme upside and downside cases with 4% probabilities each. | Moody’s Analytics

The company also produced varying scenarios on the impact of the $2.2 trillion rescue fund — with a downside risk that the distribution of funds is delayed by bureaucratic bottlenecks — and whether there is a fourth or fifth stimulus bill.

It also highlighted other policy risks. The government “could botch the crisis management,” Zandi said. “The discussion about opening up the economy quickly by Easter would qualify as a mistake in all likelihood, and that would lead to a more significant downside scenario.”

‘We have not bent the growth curve.’

Moody’s Senior Director Cris deRitis said the number of confirmed cases in the U.S. grew by 27.5% on Thursday with the addition of 18,000 cases — equal to the U.S. total a week before — as the number of tests reached 580,000.

Cris deRitis, Moody’s Analytics | Moody’s Analytics

“We have not bent the growth curve,” deRitis said. “As we look at the testing data, we still see that the positive rate is … growing, [which] indicates that the rise in the total number of confirmed cases is not just due to the increased number of tests that we’re running but that the virus truly is continuing to spread at a rapid pace.”

The baseline scenario assumes that the Federal Reserve will ensure liquidity and serve as a “firewall” to protect the financial system from the real economy, Zandi said.

But Moody’s Damien Moore highlighted the risk of the “already stressed” corporate debt market. He said high yield spreads have increased in recent weeks, “but it’s nothing like what we saw in the financial crisis.”

U.S. companies have about $10 trillion of nonfinancial corporate debt outstanding, including $2.5 trillion in speculative grade leveraged loans or high-yield bonds.

“In a well-functioning world — sales [and] cash flow are solid — [leveraged debt is] not a problem,” Zandi said. “But in a world like the one we’re in, where sales are potentially zero and cash flow highly disrupted, these companies will now have a Hobson’s choice — no choice at all really. Do I make my debt payments, or do I cut investment and hiring?”

Defaults would impact the Fed’s ability to serve as the firewall; cuts in investments and hiring would exacerbate the downturn and slow the recovery, he said.

Zandi said there will be a large number of bankruptcies by small businesses that lack the cash or credit to survive the disruption. “How widespread the failures are will have a lot to say about the severity of the downturn and also the nature of the recovery — whether we have a more V-shaped or U-shaped or L-shaped kind of recovery.”

‘We will all be changed by this.’

“We will all be changed by this. Normal will be different, just like the financial crisis changed us,” Zandi said. “I can’t imagine that anyone who lived through this won’t remember this and not be affected by this. Even the young people in their teens and 20s. They’re going to remember this. And I do think it’s going to have an impact just like the Great Depression did on that generation and World War II did. This event certainly will have [a] long-lasting imprint on people’s thinking and behavior.”

He said he is concerned it will “cement” anti-globalization sentiments and nationalism. He lamented the impact on low-income households and those who were just getting back into the labor force after the Great Recession.

“Wage growth among low-income groups was even higher than high-income groups because of the tight labor market among unskilled workers,” he said. “Now that’s all been derailed. I fear the income and wealth distribution … now will widen out again.”

Zandi said he was not worried that the extended unemployment benefits approved by Congress will prove a disincentive for people returning to work. “The effect of the stimulus is not just about dollars and cents but people’s psyches,” he said. “People are freaking out.”

March 29, 2020

PJM Staff Ponder Pandemic Effect on Load Forecast

By Rich Heidorn Jr.

PJM pandemic load forecast — Chris Pilong, PJM | © *RTO Insider*

PJM staff normally count on their near-term load forecasting algorithm “learning” as it goes to improve its accuracy. But the COVID-19 pandemic was such an unexpected and unprecedented shock to the system, PJM’s Chris Pilong said Thursday, that they’re trying to make the algorithm “not quite as smart.”

“That’s part of our challenge here,” Pilong, director of operations planning, told the Markets and Reliability Committee in a briefing on the RTO’s plans for updating its load forecasts to reflect the new normal. “We’re trying to use our near-term load forecasting algorithm for something it’s not designed to do.”

Earlier in the day, the U.S. Labor Department announced 3.3 million unemployment claims for the week — almost five times the previous record set in 1982. Only three weeks ago, the economy was humming along at “full” employment, with claims totaling only 200,000.

Limited Visibility

PJM’s residential load normally equals its commercial load (37% each), with industrials representing the remaining 26%. Pilong said PJM expects the reduced commercial load from business closures will cause an increase in residential load as employees work from home, adding lighting, computer, and heating and air conditioning demand. Any reductions in industrial loads are not expected to shift to residential.

Actual load (blue) vs. forecast load (green) for March 14-24. The green line was adjusted — replacing the forecast weather with actual weather — to eliminate weather variability and show what the forecast would have been “if we had life proceeding as normal,” said PJM’s Chris Pilong. | *PJM*

Pilong said PJM can only observe changes in net load, however. “We’re not receiving updated information … that distinguishes between residential and commercial and industrial load usage,” he said. “What’s happening beyond a transformer [in] distribution is not something we have the ability to see.”

Between March 14 and 23, peak loads were 3 to 12% lower than the five-year average for March, while total electricity usage has been down 2% to almost 12%.

Those figures do not account for weather: March 14 and 17-20 were warmer than usual. Tom Falin, director of resource adequacy planning, estimated that about half of the 12% peak drop on March 20 was because of mild weather. (The Electric Power Research Institute reported last week that Italy has seen an 18 to 21% reduction in peak and energy use year-over-year following its nationwide lockdown.)

Pilong said PJM has seen the morning peak a bit later on some days, suggesting people are getting up later because they have no commute. “The peaks are moving some days. Some days they’re going down. Some days there’s no difference. We don’t have a ton of history.”

He noted that not all schools were closed during the time period. “We may see more patterns once the situation stabilizes,” he added.

Teams Collaborating

PJM has its operations load forecasters and resource adequacy forecasters working together to adjust their load projections during the crisis.

The RTO will post updates on the load analysis methodology each Monday on the Operating Committee’s webpage and discuss them at the OC and System Operations Subcommittee meetings. The postings will include actual and forecasted hourly data so market participants can conduct their own analyses.

PJM expects to continue updating load models to reflect load behavior for the duration of the economic shutdown and prepare for a transition to normal conditions. Results of the modeling will be shared with the Planning Committee.

Falin said PJM will be adjusting its long-term forecasts (2021-2035) once it receives updated economic forecasts from Moody’s Analytics for the “metro level.” Falin said staff hope to have a forecast reflecting the impact of the crisis by the PC’s April 14 meeting.

Moody’s doesn’t expect much change in the long-term gross domestic product from what it predicted before the outbreak last fall, Falin said. Moody’s expects a 2.2% drop in first-quarter GDP to be followed by an 18% drop in Q2 before rebounding with an 11% gain in Q3 and a 2.4% increase in Q4. (See related story Moody’s: Coronavirus Recession to Cut GDP 2.3%.)

“Once we have this behind us, the rebound will be quite sharp” according to Moody’s, Falin said.

Economist James Wilson said PJM should consider other economic forecasts in additions to Moody’s, recalling that the company predicted the impact of the 2008 financial crisis “wouldn’t be much of a recession or would be very V-shaped.

“Moody’s was quite wrong, and we suffered about a decade of forecasts that were way too high” as a result, Wilson said.

March 29, 2020

FERC OKs PJM Regulation Deal over Monitor’s Opposition

By Rich Heidorn Jr.

FERC on Thursday approved settlements of two complaints over PJM’s regulation market design despite opposition from Dominion Energy and the Independent Market Monitor (ER19-1651).

Regulation service is the injection or withdrawal of real power by facilities that respond to PJM’s automatic generation control (AGC) signal to maintain system frequency.

The settlements resolve complaints filed in 2017 by the Energy Storage Association (EL17-64) and Invenergy and Renewable Energy Systems Americas (RESA) (EL17-65), which alleged PJM’s January 2017 regulation market redesign violated commission precedent and discriminates against faster, dynamic “RegD” resources such as battery storage.

The complaints alleged that the January 2017 signal redesign directed RegD resources to operate outside of their design parameters, resulting in performance and efficiency issues, reduced compensation and damaged equipment.

FERC partially granted the complaints, finding that PJM implemented the redesign improperly through its manuals and not its Tariff. After initially ordering a technical conference on the issue, the commission initiated settlement proceedings in June 2018. (See FERC Postpones Tech Conference on PJM Regulation Market.)

FERC PJM Regulation Deal — AES’ 32-MW Laurel Mountain battery storage project in Elkins, W.Va., is one of the resources covered by the regulation market settlement approved by FERC. | *AES*

The commission said the “overall effect of the settlement is just and reasonable” because the compromise between PJM and the battery owners “outweigh the expense and uncertainties of further litigation, which could result in a very different regulation market design. The settlement supports grid reliability by facilitating the continued operation of short-duration resources on the PJM system, which reduces the potential for sharp market disruptions.”

Invenergy said it supported the settlement, despite its continued exposure to the “30-minute conditionally neutral signal” implemented in 2017 “because it believes that the limited window of market and operational stability the settlement provides is preferable to continued litigation,” the commission said.

PJM estimated the settlement will cost about $8 million over its three-and-a-half-year term.

The commission said the settlement “is no worse for Dominion and the IMM than the likely result of continued litigation.”

“Load-serving entities like Dominion will benefit from the settlement’s contribution to controlling ACE [area control error] while the cost of the settlement to load is minimal.”

FERC said the Monitor failed to provide evidence to back its contention that the compensation under the settlement exceeds that which was available to batteries before 2017. “Further, the commission need not find that the settlement rate is exactly the same as the rate the commission would establish on the merits after litigation. Settlements by nature are compromises, and the commission typically does not require settling parties to justify individual elements of a settlement package.”

The commission on Thursday also denied rehearing of its March 2018 order rejecting PJM’s proposed revisions to build on the January 2017 redesign (ER18-87).

The March 2018 order rejected PJM’s regulation changes, saying they were inconsistent with commission regulations and Order 755 because it did not compensate for actual mileage — the absolute amount of regulation up and down a resource provides in response to the system operator’s dispatch signal — and did not compensate all regulation resources based on the quantity of regulation service provided.

Monitor Joe Bowring criticized the rehearing ruling Thursday during a Markets Committee briefing on his recently released State of the Market Report, which found that the regulation market design is “flawed.”

FERC “said the regulation market was just fine,” Bowring said. “It’s actually not just fine. Its horrifically bad.”

The Monitor’s report said the design fails “to correctly incorporate a consistent implementation of the marginal benefit factor in optimization, pricing and settlement” and uses an incorrect definition of opportunity cost. The IMM also said the market structure is “not competitive” because it failed the three-pivotal-supplier (TPS) test in almost 91% of the hours in 2019.

However, it concluded that participant behavior and market performance are competitive because market power mitigation requires competitive offers when the TPS test is failed “and there was no evidence of generation owners engaging in noncompetitive behavior.”

“We had a hard time deciding whether we wanted to call the regulation market results competitive because the regulation market design is so bad,” Bowring told the MC. “It’s not compensating people correctly. It’s not calculating the economic value of regulation.”

March 29, 2020April 14, 2025

MISO Records Mild Winter

By Amanda Durish Cook

The tamest winter in recent memory brought no emergencies for MISO, though the RTO’s South region was the subject of three weather-related alerts.

Speaking during a teleconference of the Board of Directors’ Markets Committee on March 24, Executive Director of Market Operations Shawn McFarlane said the winter resulted in “minimal drama” over the three months.

He said MISO’s “lowest winter peak in recent years” was driven by relatively high temperatures. Winter load peaked early at 96 GW on Dec. 19, far short of the forecasted 104 GW. While Midwest region temperatures were higher than average, the South region experienced temperatures about 4 degrees lower on average than in early 2019.

McFarlane said low gas prices and smaller load brought a 28% decrease in prices from last winter. Real-time LMPs averaged $21/MWh, down 28% from last year’s $29/MWh winter average.

“This is about as low as we’ve seen gas prices since they were deregulated in the ’80s,” Independent Market Monitor David Patton said. “It’s fundamentally changing MISO’s dispatch.”

MISO declared just one maximum generation alert for its South region, on Feb. 21, when cold weather in the Southeastern U.S. caused tight conditions.

McFarlane said in addition to the cold that morning, three major long-lead generation units failed to come online, dropping the operating margin to 500 MW, which triggers a maximum generation alert. The no-shows led MISO to call up all area short-lead units. He said two of the three long-lead units eventually started.

“The alert was only in effect for 90 minutes to cover the morning peak from 7:30 to 9 a.m. We weren’t at risk of not being able to serve load,” McFarlane explained.

MISO winter wind production | MISO

MISO South was also the subject of two separate severe weather alerts as tornados and heavy rain hit the region Dec. 16-17 and again Jan. 10-11.

MISO also set a new all-time wind generation peak of 18 GW on Feb. 22.

“It seems like it occurs every season other than summer,” McFarlane said of wind peaks.

However, McFarlane said MISO also experienced a “nearly zero” wind output from Jan. 28-30, illustrating the need to continue the resource availability and need projects to better manage the intermittent nature of renewable resources. (See MISO Forward Report Stresses Near-term Change.) Altogether, the three days brought 39 hours of wind production below 200 MW.

Lake Erie Loop Flows Re-emerge

MISO’s winter prices were impacted by loop flows on lines around Lake Erie that are not being controlled through phase angle regulators, Patton said.

According to the Monitor, Ontario’s Independent Electricity System Operator (IESO) throughout January and February requested transmission loading relief (TLR) on the Michigan-Ontario interface related to the loop flows. IESO’s requests resulted in PJM curtailing about 162 GW worth of exports to MISO across 80 hours in the winter, Patton said.

“Now that’s a really big deal. That’s like losing two nuclear units. MISO doesn’t plan for this,” Patton said. “This is hugely costly to MISO when IESO takes these actions.”

As a result, Patton said hourly market-wide energy prices exceeded $370/MWh, and market participants that had scheduled imports from PJM in the day-ahead market lost about $3.5 million collectively.

Patton said he’s concerned that it appears IESO is calling for relief not because the Michigan-Ontario interface is overloaded, but because the PARs aren’t enough to control the loop flows.

“It’s important for IESO to tighten down and only take these actions when they’re warranted,” Patton said.

He said MISO is in discussion with IESO, PJM and NYISO about the appropriate criteria to call for TLR.

“This is an ongoing issue that we’ve been struggling with for years,” MISO President Clair Moeller told board members. Unscheduled loop flows around the Lake Erie region have been a problem since the late 1990s. (See MISO not Allowed to Allocate Lake Erie PARs Costs to PJM and NYISO.)

MISO management said it plans to examine IESO’s TLR requests to see if there may be a means to mitigate their frequency.