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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

PJM Members OK Tighter Credit Rules

By Rich Heidorn Jr.

Stakeholders on Thursday overwhelmingly approved an overhaul of PJM’s rules for managing the credit risks of market participants.

PJM credit rules — PJM Chief Risk Officer Nigeria Poole Bloczynski | © *RTO Insider*

“I applaud the investment by stakeholders and members in their actions to protect our energy markets,” PJM Chief Risk Officer Nigeria Poole Bloczynski told the Members Committee after the final vote.

The new rules were developed by the Financial Risk Mitigation Senior Task Force (FRMSTF) in response to the GreenHat Energy default in the financial transmission rights market.

The Markets and Reliability Committee approved the Operating Agreement and Tariff revisions in a 4.5 to 0.5 (90%) sector-weighted vote after PJM officials agreed to accept three friendly amendments and members rejected a motion to delay the vote. The MC later endorsed the rules by acclamation with one vote in opposition and three abstentions.

Exelon’s Sharon Midgley called the changes a “significant leap forward in PJM’s credit and risk management program.”

What Changes

After the default of Tower Research Capital’s Power Edge hedge fund in 2007, FERC ordered an end to collateral-free trading with the issuance of Order 741. PJM and other RTOs tightened their credit rules as a result.

But the changes weren’t enough to protect PJM against GreenHat, which purchased a staggering 890 million MWh of FTRs — the largest FTR portfolio in PJM — before defaulting in June 2018. (See Doubling Down – with Other People’s Money.)

PJM formed the FRMSTF to implement recommendations made by an independent investigation of the debacle, which led to the departure of the RTO’s CEO, CFO and general counsel and the hiring of Bloczynski. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)

The new rules require companies wanting to become a market participant to provide PJM with financial records, corporate information and details of any prior defaults in energy markets or involvement in market manipulation.

To allow PJM to conduct ongoing risk evaluation, companies also must make annual officer certifications and notify the RTO of any “material adverse change in the financial condition of the participant or its guarantor.”

PJM will determine whether a company presents an “unreasonable credit risk” based on factors including “a history of market manipulation based upon a final adjudication of regulatory and/or legal proceedings, a history of financial defaults, a history of bankruptcy or insolvency within the past five years, or a combination of current market and financial risk factors such as low capitalization, a reasonably likely future material financial liability, a low internal credit score … and/or a low externally derived credit score.”

Unbeknown to PJM, GreenHat’s principals, Andrew Kittell and John Bartholomew, had come to FERC’s attention for their roles in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the CAISO and MISO markets between 2010 and 2012.

The new rules also seek to prevent applicants who have defaulted from participating in PJM markets under a different name. Factors for determining whether an organization should be treated as the same market participant that experienced a default include “the interconnectedness of the business relationships, overlap in relevant personnel, similarity of business activities, overlap of customer base and the business engaged in prior to the attempted re-entry.”

After GreenHat’s default, Kittell continued trading in PJM for a time under a new corporate name, Orange Avenue.

Amendments

PJM officials made several changes to the language Thursday in response to stakeholder comments at a second “page turn” on the proposals March 13. In addition, PJM accepted three “friendly” amendments to the proposal it had negotiated with stakeholders in the days before the MRC vote.

Bloczynski acknowledged before the votes that some members were concerned the new rules would result in “unintended consequences.”

“We do not believe this is the case,” she said. “However … I commit to you that we’ll continue to review and reform the language to ensure that what the Tariff contains is what we all intended.”

One amendment, sponsored by attorney Steve Huntoon, representing H-P Energy Resources, modified the definition of the term “market participant.”

Huntoon’s amendment eliminated the phrase “or any other PJM member whose application to participate in the PJM markets has been approved by PJM.”

As amended, the definition is “a market buyer, a market seller, an economic load response participant, an FTR participant, a capacity market buyer or a capacity market seller.”

“The problem is the definition of ‘PJM markets’ is very, very broad,” Huntoon said.

As originally written, Huntoon said, it could have inadvertently included generators that provide ancillary services directly, rather than through a wholesale affiliate, as well as transmission owners and customers, including hundreds of municipals and cooperatives that participate in PJM markets through wholesale entities like American Municipal Power and Old Dominion Electric Cooperative. It was an issue Huntoon had raised at the first “page turn” session in February. (See PJM Stakeholders Debate Credit Rule Changes.)

Gary Greiner, director of market policy for Public Service Enterprise Group, won two amendments, including one that makes the judgments of rating agencies such as Standard & Poor’s, Moody’s Investors Service and Fitch Ratings, if available, “the source” for calculating the unsecured credit allowance of market participants. If no external ratings are available, PJM’s internal credit score will apply. If there is difference of opinion among rating agencies, the lowest rating will apply.

“It’s a metric that’s monitored by members, consistently applied and transparent,” Greiner said. “It’s what investors use to buy our stock and bonds.”

Bloczynski supported the change, saying, “We do not believe that this takes anything away from us.”

The rules include a scale ranging from “very low risk” (S&P/Fitch: AAA to AA-; Moody’s: Aaa to Aa3) to “high risk” (S&P/Fitch: BB- and below; Moody’s: Ba3 and below).

PSEG also won a change that PJM only “consider” rather than “apply” any changes to best practices or principles by third-party industry associations relating to risk management in the North American electricity, natural gas or electricity-related commodity markets.

PJM will “bring [the new policies] into the equation, but it won’t be applied it in a hard way that … members would be forced to put into their policies,” Greiner said.

Paul Sotkiewicz of E-Cubed Policy Associates, representing Elwood Energy, moved to delay the MRC vote to give other members time to submit friendly amendments.

But Bloczynski said the “amendments do not change the substance of anything that’s been put in front of you since December” and cautioned that a delay would prevent PJM from winning FERC approval of the changes in time to apply them for FTR auctions in June.

“We do not believe that more time to review the package is necessary or advisable,” she said.

Members voted almost 4 to 1 (80%) against a delay.

March 27, 2020

CPUC Approves Big Boost in Storage, Solar Targets

By Hudson Sangree

The California Public Utilities Commission approved historic increases in the state’s clean energy targets Thursday, calling for almost 25 GW of renewable energy and storage by 2030 at an estimated cost of $45 billion (16-02-007).

The CPUC’s new reference system portfolio (RSP) targets adding 11 GW of utility-scale solar; 3.4 GW of wind; 1 GW of pumped storage; and 8.9 GW of battery storage — eight times the total installed battery capacity nationwide as of 2018, the commission said.

Load-serving entities — including the state’s three big investor-owned utilities and a growing number of community choice aggregators — must use the reference portfolio figures, which the CPUC describes as “optimal” outcomes, in their individual integrated resource plans in 2020. The RSP also is used by CAISO in its annual transmission planning process.

The goal of the effort is to help the state reach its goal of providing 100% “renewable and zero-carbon” energy to retail customers by 2045, as mandated by Senate Bill 100, passed in 2018.

CPUC President Marybel Batjer thanked fellow commissioners, staff and stakeholders before the unanimous vote.

“I think [this] is a very, very good decision, one that will double the clean energy capacity of the state over the next 10 years and one I do believe will keep us on track for the 2045 goals that we must meet … not only for the good of California, but really for the good of the world.”

GHG Reduction not Enough?

Not everyone was as thrilled as Batjer with the result.

The Natural Resources Defense Council issued a statement Thursday saying the CPUC’s order didn’t do enough to address climate change because it maintained a target of reaching a greenhouse gas emissions level of 46 million metric tons by 2030 — the same figure the CPUC adopted in its last two-year IRP cycle.

“Despite recommendations to the contrary from the entire environmental community, multiple electricity providers and even the CPUC’s own Public Advocates Office, the commission adopted a proposal with a relatively high emissions scenario as the state’s reference system plan to guide California’s electricity providers for the next two years,” the NRDC said.

However, the plan also requires retail electric providers to outline how they would reach a more ambitious target of 38 million metric tons, a concession to the chorus of those calling for greater GHG reductions.

Commissioner Clifford Rechtschaffen voted for the plan but expressed support for the stricter target in his comments.

Commissioner Liane Randolph, who headed the effort to draft the new reference portfolio, acknowledged not everyone was completely satisfied with the result but said there would be opportunities to revisit the GHG reduction target in the next two years.

“Having LSEs submit their plans toward the additional target of 38 MMT [million metric tons] will allow us to conduct a more practical and less theoretical analysis of what resources are needed to achieve that … target from the perspective of the individual LSEs doing the planning and procurement,” Randolph said.

The 46 MMT figure is 56% below 1990 levels and would exceed the state’s legislative mandate to reduce GHG by 40% below 1990 levels over the next decade, the CPUC said.

Renewables, Storage to Double

Randolph said the dramatic increase in renewable energy and storage statewide deserves praise.

“The decision adopted today provides guidance to load-serving entities to go out and procure approximately double the amount of renewable and storage capacity that is currently online in the electric system in California,” she said in a statement.

From 2020 to 2030, the reference portfolio projects a total increase in utility-scale solar from 16,310 MW to 25,905 MW and wind power from 7,367 MW to 10,293 MW, including 606 MW of wind power from new out-of-state transmission.

Natural gas generation would decrease by about 2.5 GW over the same period but remain as one of the state’s two main power sources, along with large-scale solar.

Commissioner Martha Guzman Aceves called for more effort to eliminate natural gas from the state’s resource mix. Methane, which accounts for about 12% of GHG emissions, has a more potent effect than carbon on global warming, she noted.

Wednesday’s vote was the culmination of a process that began with an administrative law judge seeking input in November 2018 and dozens of utilities, environmental groups, consumer advocates and others commenting on the plan’s iterations during the past 16 months.

The commissioners made their decision in a web conference because of the COVID-19 coronavirus pandemic. Technical problems with the phone company’s virtual setup plagued the commissioners, who also regulate the state’s telecommunications industry.

While obviously irritated, they didn’t threaten repercussions.

March 27, 2020

SPP, MISO Tweak Pseudo-Tie Practices in JOA

By Tom Kleckner

FERC last week approved SPP’s revisions to its joint operating agreement with MISO that improve pseudo-tie coordination requirements between the RTOs, effective Monday (ER20-904).

The March 19 letter order accepted revisions addressing definitions, requirements, modeling, interchange schedules and general pseudo-tie coordination. SPP said the changes would improve transmission system efficiency along its seam with MISO by including obligations already in pseudo-tie agreements where MISO is the external balancing authority.

The changes include:

adding certain definitions set forth in the NERC glossary of terms used in reliability standards;
incorporating language requiring the native BA and the attaining BA to coordinate the pseudo-tie’s modeling in accordance with the rules of the native BA and attaining BA, respectively;
adding new subsections to the JOA that outline authorities for pseudo-ties from one RTO into the other; and
revising the requirements with language that includes the impacts of pseudo-ties in the attaining BA’s market flow impacts for the purposes of congestion management procedures. “Neither MISO, nor SPP, nor the entity seeking to pseudo-tie shall tag or request to tag the energy flows from a pseudo-tie into the attaining BA,” the language says.

SPP borrowed from the MISO-PJM JOA to define pseudo-ties as involving the real-time transfer of a generating resource’s or load’s control from the native BA where resource or load is physically located to an attaining BA that is responsible for operating the grid in a different geographic location.

SPP MISO Pseudo-Tie — MISO’s control room in Carmel, Ind., where the RTO manages pseudo-tie connections. | *MISO*

Its pseudo-tie agreement permits load and generating resources external to the SPP BA to be served by SPP. It also allows load and generating resources internal to SPP to function as part of an external BA.

ESR Data Added to Interconnection Procedures

FERC on Tuesday accepted SPP’s Tariff revisions to include specific information related to energy storage resources (ESRs) in the grid operator’s generator interconnection procedures (ER20-918).

With the commission’s approval, the generator interconnection forms will now ask whether or not ESRs will take energy from the system when operating in charging mode and the maximum rate of charge capability.

SPP filed the request on Jan. 31, shortly after stakeholders agreed to form a steering committee charged with determining how best to integrate energy storage. (See SPP Planning Approach to Battery Storage.)

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.”