Page 1123 – RTO Insider

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.

March 29, 2020

FERC Denies Rehearing on PJM Arbitrage Fixes

By Rich Heidorn Jr.

FERC on Thursday denied rehearing requests on two orders rejecting PJM’s efforts to prevent capacity market participants from attempting to arbitrage between the Base Residual Auction and Incremental Auctions.

PJM and several of its member utilities requested rehearing and clarification of the commission’s May 2018 and May 2014 orders that rejected the RTO’s proposed rule changes to prevent participants from obtaining capacity supply obligations in the BRA and buying out of them with lower-priced replacement capacity in subsequent IAs (ER18-988-001, EL14-48-001, ER14-1461-002).

The 2014 order rejected a proposal to prohibit the submission of capacity sell offers not tied to an underlying physical capacity resource. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

The 2018 order rejected PJM’s proposal to create a sell-back offer floor at the relevant BRA clearing price and eliminate two IAs while increasing charges and penalties. (See FERC Closes Book on PJM’s ‘Paper Capacity’ Concerns.)

FERC PJM Arbitrage — Net replacements to cleared capacity by resource | *PJM*

“As explained in the May 2018 order, and as reaffirmed here, PJM failed to justify the Incremental Auction modifications that have been proposed,” FERC said.

The commission said PJM’s evidence that resources, particularly demand resources, seek to buy out of their BRA commitments “may not necessarily demonstrate that resources are engaging in speculative behavior.” It noted that the commission approved changes in 2014 requiring DR providers to designate that their resources will be available in the delivery year.

It also noted that PJM’s Capacity Performance rules impose large penalties on resources that fail to perform during a performance assessment interval. “This creates a substantial downside risk for would-be speculators or any market participant … that fails to buy out its capacity obligation in the Incremental Auction.”

And it said PJM was attempting to address the cause of the price differentials between the BRA and IAs by revising its load forecasting methodology in 2015 to reduce over-procurements.

“We do not find it advisable to design a market on the assumption that over-procurement in capacity auctions will result in lower energy market prices,” the commission said. “Each market ought to be designed properly.”

The commission added that it encouraged PJM and its stakeholders “to continue to monitor the issues raised in this proceeding and to develop, if appropriate, solutions to address them.”

March 29, 2020

PNM, NV Energy Hit with NERC Penalties

By Holden Mann

FERC accepted settlements Friday with Public Service Company of New Mexico (PNM) and two utilities owned by Berkshire Hathaway Energy — Nevada Power (NEVP) and Sierra Pacific Power Co. (SPPC) — for violations of NERC reliability standards. The settlements with NEVP and SPPC carried penalties of $231,000 and $153,000, respectively; a penalty of $70,000 was assessed for the PNM settlements.

NERC submitted the settlements to the commission on Feb. 27, filing a spreadsheet Notice of Penalty for PNM’s violations (NP20-8) and separate NOPs for NEVP (NP20-9) and SPPC (NP20-10). In a notice Friday, FERC said it would not review the settlements, leaving NERC’s penalties intact.

Rating Revisions

Although SPPC and NEVP both operate under the NV Energy brand, the utilities were cited separately by the Western Electricity Coordinating Council for violations of reliability standard FAC-009, covering the establishment of facility ratings, and VAR-002, relating to the maintenance of generator voltage or reactive power schedules.

PNM NERC penalties — NV Energy headquarters in Las Vegas, Nev.

The FAC-009 violations were assessed following self-reports submitted by both entities on Dec. 14, 2016, after a joint internal technical assessment revealed that several of their facility ratings did not include all applicable facilities. In addition, the ratings did not include all required elements. Further investigation found that the violation began on June 18, 2007, when the standard went into effect. In particular:

Eleven transmission lead lines — including one owned by SPPC, one owned by NEVP. and nine owned jointly — did not have established facility ratings.
Wave traps and relay settings were not taken into consideration by SPPC when rating transmission lines of 200 kV and above, or by NEVP for any applicable facilities.
Current transformers were not included in facility ratings by either utility, and relays were also not included by NEVP.
Lead lines to certain substations did not have established facility ratings.
Facility ratings were not established for series and shunt compensation devices.
SPPC did not update facility ratings following changes to its system.
NEVP had no facility ratings, or incorrect ratings, for 24 transmission lines when the facility ratings methodology changed from FAC-009 to FAC-008.

Overall, SPPC had 92 of its 210 facilities with incorrect or no established ratings, while NEVP had no or incorrect ratings for 76 of its 223 facilities.

WECC assessed the violations as posing a serious and substantial risk to reliability of the bulk power system because of the possibility of overloading a BPS element and causing neighboring facilities and protection systems not to operate as intended. Neither NEVP nor SPPC had effective preventive or detective controls that could have prevented this outcome.

In response, both entities implemented mitigation plans — identical except for minor differences in phrasing — that WECC verified as completed by June 20 in the case of SPPC and June 30 for NEVP. Elements of the plans include establishing peer-checked facility ratings for solely and jointly owned facilities consistent with facility ratings methodology; creating a facility rating change control process; and creating an internal task force to ensure that facility ratings follow reliability standards in the future.

Repeated Voltage Deviations

NEVP and SPPC’s VAR-002 violations stemmed from a joint quarterly compliance review conducted on Oct. 26, 2017, with each entity submitting a self-report on July 22, 2018.

During the review, SPPC found that between April 10 and Sept. 13, 2017, one of its generation facilities deviated from the transmission owner’s generator voltage schedule eight times, with a maximum deviation of 1.15% for six hours. In addition, between June 25, 2017, and Aug. 17, 2018, another facility deviated from the voltage schedule 22 times; the maximum deviation was 0.96% for more than 22 days.

WECC identified the root cause of SPPC’s violation as “a lack of clear instructions, training or guidelines” for meeting the established voltage schedule. SPPC also lacked preventive controls, which WECC considered a systemic issue because it revealed a “lack of consistency in SPPC’s approach to meeting the voltage schedule.”

In response, the utility implemented mitigation measures that included revisions to its internal generation procedure; in-house training focused on taking and tracking voltage measurements; and creating additional warning systems for deviations in voltage. WECC verified the measures were completed on March 28, 2019.

NEVP discovered 659 deviations from the voltage schedule at one of its facilities between Dec. 7, 2016, and Nov. 29, 2017, with a maximum deviation of 2.27% for 10 minutes. Further investigation revealed two additional facilities that deviated from the schedule: One deviated eight times between Dec. 7, 2016, and March 14, 2017, and the other five times between March 15 and Sept. 1, 2017.

The utility attributed the deviations to “incorrect methods employed by plant personnel to take voltage readings.” Mitigating steps, completed on Jan. 16, 2019, included revising internal generation procedure for maintaining network voltage schedules; rescinding internal policies that conflicted with the voltage schedules; and expanding reporting requirements at the affected facilities.

In assessing the utilities’ penalties, WECC credited both NEVP and SPPC for self-reporting the violations, cooperating throughout the process and accepting responsibility. However, the regional entity also noted that both companies’ internal compliance programs failed to detect or address the issues. In addition, the FAC-009 violation was particularly lengthy, lasting nearly 10 years. NERC’s Board of Trustees Compliance Committee agreed that the monetary penalties in both cases were “appropriate for the violations and circumstances at issue.”

PNM Files SOL, Maintenance Issues

PNM’s penalties concerned violations of reliability standards TOP-002 and TOP-004 — concerning operations planning and transmission operations — as well as PRC-005, relating to transmission and generation protection system maintenance and testing.

The violations of TOP-002 and TOP-004 concern the same event on Sept. 12, 2016, when a circuit breaker in one of the utility’s 345-kV switching stations faulted internally. Although the breaker was in two separate zones of protection, one did not operate because of a previously undetected malfunction; as a result, the fault was not fully addressed, and several transmission lines and generation units tripped offline.

The TOP-002 violation began when PNM’s system operators failed to update the system operating limit (SOL) after the fault was cleared, having assumed that this would be done automatically by the energy management system; instead, the limit was not changed until the following day. The TOP-004 violation arose from the failure to restore system operations within 30 minutes. Both violations were self-reported to WECC on Feb. 6, 2017.

WECC determined that PNM had “failed to maintain accurate computer models utilized for analyzing and planning system operations,” but that the utility had quickly invoked contingency reserves, started all available load-side generation and requested emergency assistance. PNM did not operate above SOLs at any time during the event. The RE also credited PNM for not only mitigating the specific issues that arose during the incident, but for taking “above and beyond” actions and investments in the years since to proactively reduce risk in its system.

PNM’s violations of PRC-005 stem from two incidents of failure to document maintenance on its facilities. In the first case, the utility reported on Oct. 26, 2016, that it lacked full maintenance records on four batteries, two transmission relays, eight battery chargers and 155 instrument transformers. The second instance was reported on May 25, 2018, and involved maintenance and testing records for two microprocessor relays and one electromechanical relay at a substation.

The root cause of the violations was determined to be ambiguous instructions for documenting and retaining evidence in the first incident, and “a lack of internal controls to ensure accuracy” in the second. WECC noted that the utility was following a stricter timeline for its protection system devices than is required by the standard. In addition, the relays involved in the second violation were considered secondary protection and their failure would likely not result in a significant loss of load in the BPS.

To mitigate the violations, PNM has ensured maintenance on the relevant hardware is completed and has corrected any inaccurate records. It has also established regular meetings to discuss maintenance issues on relays and monthly compliance reviews on all protection system devices subject to PRC-005.

March 27, 2020

CAISO Board OKs $141.7M Tx Plan, RMR Contracts

By Robert Mullin

CAISO’s Board of Governors on Wednesday approved $141.7 million in transmission spending and reliability-must-run contracts covering three power plants in Central California.

The 2019/20 transmission plan covers nine projects CAISO says are needed to maintain reliability according to NERC and ISO planning standards. Seven of the projects (totaling $120.7 million) will be located in Pacific Gas and Electric’s service territory, one ($16 million) in Southern California Edison and another ($5 million) in the Valley Electric Association/GridLiance West area straddling the California-Nevada border.

In his presentation to the board, CAISO Vice President of Infrastructure Development Neil Millar characterized the plan as a “modest” capital program and pointed out that all the projects are reliability-driven.

“We did not identify the need for any policy-driven projects or economic-driven projects in this cycle. The one qualifier was that the economic-driven analysis did identify the benefit of advancing a reliability project, but the driver remains the reliability requirement for that project,” Millar said, referring to the $16 million, 230-kV Pardee-Sylmar line-rating-increase project in SCE’s territory.

Millar said CAISO’s analysis of potential policy-driven projects relied on assumptions gleaned from the California Public Utilities Commission’s 2017/18 integrated resource planning cycle. The CPUC’s IRP reference system plan assumes that California’s electricity sector will cap its annual greenhouse gas emissions at 42 million metric tons by 2030 through a generation portfolio consisting of at least 60% renewables. It includes a “generic” base portfolio concentrated in various parts of the state needed to meet that target (see graphic).

“I’m not an engineer, but as a matter of common sense, can you explain how we can go from a 33% to 60% renewable system” without spending on new policy projects? Governor Ashutosh Bhagwat asked.

Millar responded that, in past years, utilities developed renewable portfolios under the expectation that the resources must be deliverable as resource adequacy under CPUC rules. But those portfolios have “started to shift” where some of the output can be energy-only, he said.

“So with the upgrades that were already put in place, we saw that we had considerable capability to take advantage of filling out those areas where developments had already taken place, as well as capacity to meet energy-only requirements where resources would be providing energy and not necessarily resource adequacy capacity,” Millar said.

The scope of the past transmission buildout accounts for the lack of policy-driven needs today, he said.

But Millar pointed to one “qualifier.”

“When you move to these higher [renewable] goals, we’re also seeing a steady escalation in the amount of transmission-related curtailments that’s showing up in the model, and unless there’s a policy requirement to address that curtailment, that would transition over to being an economic requirement,” he said. “Those could drive considerable transmission to address economic-driven transmission needs.”

The board additionally approved CAISO management’s recommendation to put three previously approved projects on hold for further review. The projects are all located in PG&E’s territory and include the North of Mesa upgrades, the 115-kV Morage-Sobrante line reconductoring and the Wheeler Ridge Junction substation project.

Not a Trend — Yet

The board also approved the designation of three Central California power plants as RMR resources for the summer peak season. The approvals are conditional because they will be revoked for any resource that obtains a resource adequacy contract by that time. The facilities include:

Starwood Energy Group’s Greenleaf II Cogen, which is required to help meet the 734-MW local capacity requirement (LCR) for the Drum-Rio Oso subarea within the Sierra local area. The 49.5-MW unit is not currently active in the CAISO market following termination of its Public Utility Regulatory Policies Act contract and is going through a qualifying facilities conversion process to become an ISO participating generator. The 230/115-kV Rio Oso transformer replacement project, which will mitigate the subarea’s reliability need, is not scheduled to be in service until June 2022.
California State University Channel Islands’ Channel Islands Power, which is required to help meet the 288-MW LCR requirement in the Santa Clara subarea of the Big Creek/Ventura local area. The 27.5-MW unit is currently under a resource adequacy contract set to expire on March 30. While 195 MW of new energy storage resources have been procured to meet the expected LCR shortfall in the subarea, they won’t become available until June 2021.
Atlantic Power’s E.F. Oxnard, which is also needed for the Santa Clara subarea. The 48.5-MW plant is currently under a resource adequacy contract that expires May 24. The unit will need to convert from a QF participant arrangement to a conventional market participant arrangement.

Governor Severin Borenstein noted that last year saw just one CAISO unit secure an RMR designation for the summer.

“Are we seeing an increase, or should I not think this is a trend?” Borenstein asked.

“From a local capacity perspective, we wouldn’t expect to see this being indicative of a trend,” Millar said. “Two of these units are qualifying facilities as opposed to being conventional market participants, and there’s a relatively small number of those. The other issue we’re dealing with is that we do have reinforcement projects under way generally to backfill for a number of these items, so there are individual cases that we’re going to have to deal with from a local perspective. So we don’t see this as a trend — at least yet.”

CAISO CEO Steve Berberich interjected: “I think the operative word being used is ‘yet.’ With the fragmentation of the load-serving entities in California, we expect that this could very well be the case. I agree with Neil that this doesn’t necessarily indicate a trend, but we’re going to continue to be vigilant about this issue.”