Industry Pushes Back on FERC Cyber Incentives

Stakeholder comments on FERC’s proposals for encouraging cybersecurity investments by utilities reveal widespread misgivings about the commission’s planned framework, even as most respondents acknowledged the need for action on protecting the grid from cyber threats (AD20-19).

FERC solicited comments in June on a white paper calling for an incentive framework that would complement the current Critical Infrastructure Protection standards, which the commission called an “effective technical baseline for cybersecurity practices.” The commission proposed two approaches for identifying cybersecurity investments that should be incentivized: one that would encourage entities to apply the current CIP standards voluntarily in areas where they are not currently required — specifically, to low-impact bulk electric system cyber systems — and a more open-ended alternative that would incentivize utilities to meet goals based on the National Institute of Standards and Technology’s (NIST) Cybersecurity Framework.

Commenters Lean Toward Combined Approach

The commission’s first question to stakeholders was which of the two frameworks — or whether a combination of both — should be adopted. A number of respondents endorsed the combined approach; International Transmission Co., for instance, asserted that the NIST framework and the CIP standards are “not mutually exclusive,” while Boston Consulting Group (BCG) favored including the Department of Energy’s Electricity Subsector Cybersecurity Capability Maturity Model as well in order to “provide a comprehensive view of cybersecurity … with the corresponding methodology for cybersecurity maturity assessment.”

The U.S. Bureau of Reclamation was an outlier, arguing for an incentive approach based solely on the NIST framework. Calling the CIP standards “compliance focused [and] overly prescriptive,” the bureau said a NIST-only approach would allow utilities greater flexibility and creativity to craft their own solutions.

FERC Accused of Overstepping Role

The commission also received some sharp dissents, with several commenters focusing on the potential impact to ratepayers. One such criticism came from Transmission Dependent Utility Systems, an ad hoc group of rural electric cooperatives, which said the commission’s incentive plan would essentially allow transmission owners to profit from essential cybersecurity investments rather than simply recouping the costs, potentially raising rates for end-use consumers.

“[Customer] interests are not even an afterthought; they do not draw a single mention, at a time when unemployment is at levels not seen for nearly a century and the media are filled with stories predicting a coming wave of housing and small-business evictions,” the group said. “For this reason alone, it would be appropriate for the commission to direct its staff to reconsider its proposal.”

FERC Cyber Incentives — | *Shutterstock*

It also accused the commission of assuming authority delegated by Congress to NERC, as the CIP-based framework would have the effect — if not necessarily the intent — of applying those standards to systems explicitly excluded by NERC. Supporting this view was the New Jersey Board of Public Utilities, which compared the proposed scheme to “the era of voluntary utility engagement” that was ended by the Energy Policy Act of 2005.

“Congress did not intend for FERC to create reliability standards itself. … It is for NERC, the ERO, not FERC, to utilize its technical expertise in deciding the adequate level of reliability and designing standards that ensure it,” the board said. “While the commission can request that NERC modify the CIP reliability standards, it cannot propose its own mechanisms to augment reliability on a voluntary basis.”

Even those that supported the incentive proposal in general tended to disagree with FERC on specific aspects of implementation. The commission’s question about adopting a sunset date for incentivized cybersecurity investments in order to encourage utilities to keep up to date with the changing security environment attracted dissent from trade group WIRES, which said that because every threat is different, there is no point in “drawing an arbitrary line in the sand” to declare a particular mitigation measure no longer useful.

BCG and the Indiana Utility Regulatory Commission were less categorical in their rejection of sunset dates, but both cautioned against setting them too broadly. The IURC recommended tying sunset periods to the useful life of the upgrade — for example, shorter periods for software that can be replaced relatively quickly, and longer for physical investments that will stay in place longer — while BCG urged the commission to adopt a “review cycle” to periodically reassess utilities’ cybersecurity investments.

Canadian Regulators Urge International Focus

The response from Canada’s Energy and Utility Regulators (CAMPUT) — the Canadian approximation of the National Association of Regulatory Utility Commissioners — sought to remind FERC of the high degree of interconnection between the U.S. and Canadian grids. While Canadian utilities are not under FERC’s jurisdiction, as a practical matter, Canadian provinces normally implement similar or identical reliability standards to those in force in the U.S., as “security is a matter of mutual interest.”

While CAMPUT noted that commenting on the proposed incentive framework would be outside of its prerogatives, the organization voiced concerns that any FERC incentive package could create a “disparity in North American CIP practices” if similar programs were not offered in the Canadian provinces. CAMPUT requested the commission consider a “North American cybersecurity dialogue” that would enable regulators to address this new threat collectively.

“Cybersecurity matters are very different than traditional reliability considerations such as vegetation management, and may require a new approach to address risk,” CAMPUT said. “By utilizing NERC to facilitate such a conversation amongst all stakeholders of the BES, there would be an opportunity to ensure that cybersecurity risks are optimally and collaboratively addressed throughout North America.”

August 18, 2020

FERC Rejects Exelon’s Mystic Complaints Against ISO-NE

FERC on Monday rejected Exelon’s complaint against ISO-NE alleging that the RTO’s request for proposals for competitive transmission projects addressing reliability needs in the Boston area violated its Tariff (EL20-52).

Exelon’s Constellation Mystic Power filed the complaint in June on behalf of its Mystic Generating Station, an eight-unit, 2-GW fossil power plant north of Boston. Constellation charged that ISO-NE was putting the region’s reliability at risk “by prematurely substituting the uncertain outcome” of its RFP “for the certainty provided by Mystic.” (See Exelon Challenges ISO-NE RFP in Bid to Extend Mystic.)

The complaint came two days after the grid operator’s announcement that it had awarded its first RFP under FERC Order 1000, a $49 million project, to incumbent utilities National Grid and Eversource Energy. (See ISO-NE Chooses Incumbent as Boston RFP Winner.)

The RFP was issued to address transmission violations expected with the closing of Mystic Units 8 and 9, whose retirement was extended to May 30, 2024, under a two-year, $400 million cost-of-service contract to preserve the region’s reliability. The National Grid-Eversource project has an in-service date of Oct. 1, 2023, eight months before the end of the contract.

Exelon has been trying to extend the plant’s cost-of-service contract for an additional year. It said ISO-NE violated its Tariff by shortcutting its transmission security review and prematurely culling bids (36 were submitted) received in response to the solicitation.

FERC found that the RFP results provided the grid operator with “sufficient information” to ensure it can address reliability criteria violations without the two retired units. It said ISO-NE conducted the Boston-area needs assessment “to assess transmission security needs resulting” from Mystic 8’s and 9’s retirements.

“Based on the [assessment’s] results … ISO-NE issued the corresponding Boston RFP, which was designed to address the transmission security needs caused by the retirement of Mystic 8 and 9 and involved modeling of whether each proposal addresses the identified reliability needs,” the commission wrote. “For those reasons, we find that ISO-NE was not required and, given the information it obtained from the Boston RFP results, had no need to use the network model in order to comply with [the] Tariff.”

FERC also disagreed with Constellation’s argument that the RTO had violated or circumvented the Tariff by depriving Mystic 8 and 9 of being able to receive compensation from the February 2021 forward capacity auction (FCA) for providing transmission security.

The commission also rejected Constellation’s contention that ISO-NE modified its planning procedures to qualify the National Grid-Eversource project in time for Forward Capacity Auction 15 in 2021, which will procure resources for capacity commitment period 2024/25. The New England Power Pool Participants Committee in June approved over Exelon’s opposition Planning Procedure 10 (PP10), revising the rules for determining whether planned transmission can be included in the network model for the studied capacity commitment period.

FERC said the revision is consistent with ISO-NE’s existing authority under its Tariff “to consider transmission enhancements that may address its reliability concerns.” It noted that the RTO said PP-10 is a business practice manual intended to “detail requirements and procedures … that are conducted pursuant to” the Tariff’s provisions.

The commission further noted that ISO-NE’s Tariff allows it to consider transmission projects as part of its transmission security review, giving the RTO “broad authority to address reliability concerns arising from the retirement of a resource ‘through other reasonable means (including transmission enhancements).’”

Exelon announced the retirement of Mystic 8 and 9 for economic reasons, citing the plant’s dependence on more expensive LNG than natural gas from pipelines.

August 18, 2020

MISO Board Primed for 1st Major Interregional Project

MISO’s Board of Directors is expected next month to approve MISO and PJM’s first major interregional transmission project, about a year after the RTOs first recommended it.

The nearly $25 million reconstruction of the 138-kV Michigan City-Trail Creek-Bosserman line in Indiana’s northwestern corner was identified last fall in the 2018/2019 MISO-PJM coordinated system plan. (See MISO, PJM Poised for 1st Major Interregional Project.)

Project costs will be split on a 90-10 basis, with PJM covering the larger share. The 11-mile rebuild is located in MISO’s Northern Indiana Public Service Co.’s (NIPSCO) transmission zone and is expected to be in service by January 2023.

MISO PJM Interregional Project — | *PJM*

PJM’s Board of Managers approved the project at its December 2019 meeting. MISO’s board has yet to meet for a vote.

MISO’s nine-month approval lag comes because it did not have a cost-sharing plan in place for its interregional market efficiency projects (MEPs). After twice rejecting the RTO’s cost-allocation plans, Another Rejection for MISO Cost Allocation Plan.)

“Now that we have cost allocation in place, MISO is going to present this project to our Board of Directors meeting in September to put the final touches on that project approval,” MISO Economic and Policy Planning Adviser Ben Stearney told stakeholders during a virtual MISO-PJM Joint and Common Markets meeting Tuesday.

MISO staff had proposed the project not be regionally allocated in the RTO, reasoning that its 138-kV rating disqualified it from allocation beyond the transmission pricing zone where MISO’s project share is located. The RTO’s two rejected cost-allocation filings reserved regional allocation for interregional MEPs 230 kV and above.

FERC in 2016 lowered MISO’s interregional economic project voltage threshold from 345 kV to 100 kV after a 2013 NIPSCO complaint over the MISO-PJM interregional planning process.

No 2020 Coordinated Plan

There are currently no additional interregional projects on the horizon for the RTOs, which have agreed not to start a two-year coordinated system plan study in 2020.

“We didn’t find any strong issues to support a study,” Stearney said, adding that the RTOs will continue to gather and analyze historical congestion data. He said they will meet in the fourth quarter to discuss potential economic needs and the possibility of a CSP that would begin next year.

August 18, 2020

Dominion Buys Rights to Va. Solar Farm

Dominion Energy is adding to its growing solar portfolio with the acquisition Monday of a generating facility scheduled to be built in Central Virginia.

The Richmond-based company announced it obtained the rights to the 62.5-MW Madison Solar generating facility in Orange County, Va. The facility, owned by California-based Cypress Creek Renewables, will be transferred to Dominion’s contracted assets arm.

Terms of the deal were not disclosed.

Dominion Energy solar farm in Virginia | *Dominion Energy*

Madison Solar has received all state and local permits and is expected to come online by the second quarter of 2022. About 660 acres of land along State Route 20 in Locust Grove are being purchased to house the solar project.

Northrop Grumman will purchase the project’s electricity as well as its renewable energy credits under long-term agreements, according to Dominion. Northrop officials said they anticipate the facility will provide enough renewable power to the grid to match 100% of the electricity used for its Virginia manufacturing and office operations.

Dominion is continuing its plans to add about 16 GW of solar generating capacity through company-owned projects and power purchase agreements it is signing with third-party developers in Virginia. Its proposed long-term integrated resou r ce plan for 2021-2045 would quadruple the amount of solar and wind generation in its previous 15-year plan a response to the Virginia Clean Economy Act (House Bill 1526 and Senate Bill 851). Signed by Gov. Ralph Northam in April, the law established that 16,100 MW of solar and onshore wind is “in the public interest.” (See Va. 1st Southern State with 100% Clean Energy Target.)

Virginia-based SolUnesco began securing the Madison Solar site in July 2016 before selling it to Sol Systems, a solar developer, and then transferring it to Cypress Creek Renewables in early 2019. The project will interconnect to a 115-kV line utilizing an easement for 0.1 miles from the parcel through an application filed with PJM in November 2017 (AC1-076).

“Our mission of powering a sustainable future one project at a time drives us to create valuable partnerships and projects,” said Cassidy DeLine, vice president of project finance for Cypress Creek Renewables. “Our collaboration with Dominion and Northrop Grumman on the Madison project reinforces our commitment to developing solar in the nation’s largest wholesale electricity market, PJM, and delivering long-term benefits for Orange County, Va.”

August 18, 2020

CAISO Blames Blackouts on Inadequate Resources, CPUC

CAISO on Monday blamed inadequate preparation by others for a supply shortfall that caused rolling blackouts over the weekend during the Western heat wave.

During an emergency meeting of the Board of Governors, CEO Steve Berberich immediately jumped to the defense of the ISO, which received the brunt of criticism for ordering statewide rolling blackouts Friday and Saturday.

The California Public Utilities Commission authorizes load-serving entities to procure energy, he said. CAISO has told the CPUC that an additional 4,700 MW would be needed to meet summer peaks during the state’s transition from fossil fuels to renewable energy. The CPUC directed LSEs to procure a total of 3,300 MW by next year, when the shortfall is expected to grow worse, he noted.

“The ISO does not direct procurement. We are the system operator,” Berberich said. “The situation we are in could have been avoided. For many years, we have pointed out to the procurement-authorizing authorities that there was inadequate power available during the [evening] net peak,” after solar has left the system but demand remains high.

The weekend outages occurred as solar power waned, he said. About 12,000 MW of battery storage are needed to store renewable energy, along with an “overbuild” of solar and wind generation to charge the batteries, he said. There’s currently only 200 MW of storage on CAISO’s grid.

Hotter summers caused by climate change also need to be taken into account, Berberich said.

“We have indicated in filing after filing after filing that the resource adequacy program was broken and needed to be fixed,” he said. “That program requires the load-serving entities to only procure to a 50/50 weather forecast. That is the worst weather you might have on average 50% of the time — not to an extreme heat storm like we have now.

“Resource adequacy must be reformed so that every hour of the year is properly resourced,” he said.

The CPUC rejected Berberich’s argument that it was mainly to blame.

“This is a shared responsibility, and we are working with our sister agencies to better understand why this occurred,” spokeswoman Terrie Prosper said in an email. “Our current focus is the public’s safety and to emphasize the importance of energy conservation to reduce the strain on electric supply.”

Demand during the heat wave was in line with predictions and should have been manageable, Prosper said.

“The electricity demand of the last few days is consistent with the level the agencies have for August, and the utilities and community choice aggregators procured the resources that were required to meet the forecasts,” she said. “The question we’re tackling is why certain resources were not available.”

Millions Could be Without Power

CAISO predicted even worse outages Monday and Tuesday than those that roiled the state last week. (See CAISO Warns Blackouts Could Continue, Calls Emergency Meetings.)

It had predicted up to a 4,400-MW shortfall Monday, with rolling blackouts in the afternoon, increasing after sunset. About 3 million customers could lose power, Berberich acknowledged in a call with reporters.

“We have a perfect storm going on here,” Berberich said. “The entire region … is extremely hot. We can’t get the energy we’d normally get from out of state because it’s being used to serve load natively.”

On Monday night, however, CAISO lifted a Stage 2 emergency declaration, saying “no rotating power outages are anticipated, thanks to reduced demand due to consumer conservation and cooler-than-expected weather.” The ISO had not updated its predictions for Tuesday as of press time.

CAISO blackouts — CAISO predicts resource deficiencies of up to 4,400 MW this week. | *CAISO*

The ISO can’t dip deeper into its contingency reserve, which can total thousands of megawatts, because the reserve is necessary to protect the Western grid from failure, CAISO officials said.

John Phipps, director of real-time operations, said CAISO must follow NERC and WECC standards that protect the Western Interconnection from failure should a large generator drop offline or another serious problem occur.

CAISO contains 35% of the load in the interconnection, which stretches from the Rocky Mountains to the Pacific Ocean and into Canada and part of Mexico. A serious disruption in the ISO could prove disastrous to the entire region, Phipps said.

Governor Weighs in

During a televised address Monday, Gov. Gavin Newsom said record-setting heat had set the stage for the blackouts but acknowledged the state was culpable for the crisis.

“We failed to predict and plan for these shortages, and that’s simply unacceptable,” Newsom said. “I am the governor. I am ultimately accountable and will ultimately take responsibility to immediately address this issue and move forward to make sure this simply never happens again here in the state of California.”

Newsom said his office had launched an investigation into the interrelationship among CAISO, the CPUC and the California Energy Commission, which he said have a shared responsibility to maintain reliable electricity delivery.

“We’ll get to the bottom of it, and that’s why that investigation into what happened and its implications for the future will be done swiftly and immediately,” he said.

In the meantime, the state is “working with partners across the spectrum” to alleviate the immediate energy shortages, including reducing consumption at the state’s ports, allowing utilities to tap resources reserved for public safety power shutoffs from wildfires, and procuring more power from the Los Angeles Department of Water and Power (LADWP) and the State Water Resources Control Board, the governor said.

Newsom also called for a broader examination of how California will continue to reliably serve electricity customers while pursuing its ambitious renewable energy and decarbonization targets. State law requires all LSEs to supply 100% carbon-free energy to retail customers by 2045.

“We now have to sober up to the reality that in this transition, we’re going to have to do more and be much more mindful in terms of our capacity to provide backup [energy] and insurance,” he said.

Convergence Bidding

In a move signaling that its own market mechanisms might be contributing to its real-time shortfalls, CAISO on Sunday notified market participants that it would suspend convergence bidding throughout its footprint beginning Monday for the Aug. 18 trading date.

“As a result of the record-breaking heat wave that has led to load curtailments, the California ISO has determined that convergence bidding is detrimentally affecting the ISO’s ability to maintain reliable grid operations,” the ISO said in a market notice.

Convergence — or virtual — bidding allows market participants to hedge their physical positions and limit exposure to day-ahead and real-time price differentials. The bid is a purely financial one, implying no obligation to take or deliver electricity. Instead, a market participant buys or sells “virtual” energy in the day-ahead market, a position required to be automatically liquidated in the opposite direction in real time.

CAISO said Monday that it had eliminated convergence bidding to give it a clearer picture of day-ahead market conditions, but the practice has a checkered history in California.

A week after implementing convergence bidding at interties into California in February 2011, the ISO suspended bids at nodes on nine interties linked to the Mountain West because of a software glitch that risked overscheduling those points in the physical day-ahead market.

That incident was followed months later by the more serious discovery that some CAISO market participants were using virtual supply bids on the interties to offset virtual demand bids at nodes located just inside the state, a gaming strategy that produced no benefit for the physical market and cost the ISO more than $50 million.

The scheme prompted CAISO to suspend intertie convergence bidding altogether, and it completely eliminated the bidding at interties in March 2016. (See FERC Eliminates Intertie Convergence Bidding in CAISO.)

Robert McCullough, an energy economist who was among the first to spot the market manipulation behind the Western energy crisis of 2000/01, pointed to why the convergence bidding market that still exists inside the CAISO remains “worrisome.”

“By allowing node-level bids and not requiring physical assets, this allows any single party the ability to dominate transactions at a specific location. Enron called such exploits ‘load shift,’” McCullough told RTO Insider. “However, that exploit required lying to the ISO about the ‘virtual’ supplies.

“The convergence market doesn’t even require a lie — just a willingness to gamble on the ISO’s computer systems,” he said. “Past experience has tended to make this less of a gamble than you might think since critical information is often learned by specific market participants and then used to advantage.”

McCullough, long an outspoken critic of organized electricity markets, questioned how Friday’s unforeseen demand could have sent CAISO into a Stage 3 emergency.

“Their 15% reserve margin should have handled this easily,” he said. “The congestion data indicates that this is a Southern California issue, although, mysteriously, LADWP was not affected.”

CAISO’s demand peaked at 46,777 MW on Friday, above the 1-in-2 peak forecast of 45,907 MW in the ISO’s 2020 Summer Loads and Resources Assessment, but below the 1-in-5 (47,755 MW) and 1-in-10 (48,457 MW) forecasts. That assessment also estimated a 3.7% probability the ISO would enter Stage 2 operations this summer and a 1.1% probability for Stage 3.

CAISO on Sunday also declared a capacity procurement mechanism (CPM) significant event to solicit any available resources not already offered into the CPM’s competitive solicitation for August.

Resource owners were urged to contact the ISO if they were willing to accept its soft offer cap of $6.31/kW-month. CAISO will give preference to resources able to deliver energy from 2 p.m. to 10 p.m.

August 16, 2020April 30, 2025

CAISO: Blackouts May Continue, Calls Emergency Meetings

CAISO warned residents Sunday that rolling blackouts could continue for days and called emergency meetings of its Board of Governors to address the system deficiencies.

“A persistent, record-breaking heat wave in California and the Western states is causing a strain on supplies, and consumers should be prepared for likely rolling outages during the late afternoons and early evenings through Wednesday,” the ISO said in a news release. “There is not a sufficient amount of energy to meet the high amounts of demand during the heat wave.”

CAISO declared a Stage 3 emergency for two hours Friday night, ordering rolling blackouts across the service territories of the state’s three big investor-owned utilities. Hundreds of thousands of customers in Northern and Southern California were without power for an hour or more.

The ISO triggered a Stage 3 emergency again Saturday night for 20 minutes when, it said, 1,000 MW of wind power and a 470-MW power plant dropped offline.

“The load was ordered back online 20 minutes later at 6:48 p.m., as wind resources increased,” CAISO said.

Pacific Gas and Electric said it began restoring power to 220,000 residents on California’s coast and in the Central Valley after the brief outage but warned that restoration could take additional time.

Earlier in the day, CAISO had assured residents on Twitter that the “ISO is expected to cover electrical demand with no stage emergencies planned at this time.”

The CAISO board met Sunday in closed executive session and scheduled a public teleconference for Monday at 11 a.m.

Friday was the first time the ISO, which encompasses 35% of electrical load in the Western Interconnection and covers 80% of California, went to its highest emergency level since market manipulation schemes and rolling blackouts plagued the state during the Western energy crisis of 2001. A similar heat wave in 2006 strained the system but did not cause blackouts.

“The ISO requires load curtailments [and] use of interruptible load, and requests out-of-market and emergency energy from available sources,” CAISO said in an alert. “Maximum conservation efforts are requested.”

A Stage 3 alert means the “ISO is unable to meet minimum contingency reserve requirements, and load interruption is imminent or in progress.” Notices are issued to utilities of potential interruptions, CAISO says on its website.

CAISO spokeswoman Anne Gonzalez said the ISO had ordered 1,000 MW of load shed.

PG&E said it had been directed by CAISO to “turn off power to approximately 200,000 to 250,000 customers at a time in rotating power outages given the strain on the power grid during the statewide heat wave. Other power utilities in the state are being directed to take similar actions.”

Southern California Edison and San Diego Gas & Electric also shut off power to tens of thousands of customers. Roughly 750,000 account customers — and at least 2 million residents, based on average household size — lost power between 6:36 p.m., when the emergency was declared, and 8:54 p.m., when CAISO lifted its declaration.

Customers of public utilities including the Los Angeles Department of Water and Power and the Sacramento Municipal Utility District were not affected by the blackouts. The utilities operate their own power lines and generation resources.

The transmission grids of the three large IOUs are operated by CAISO.

Lead-up to Blackouts

On Friday afternoon, CAISO issued a Stage 2 alert after capacity dipped below its 15% reserve margin. It said it had taken all possible mitigation measures and was still unable to meet its energy requirements.

The heat wave drove temperatures into the triple digits in Sacramento, Phoenix, Las Vegas and other areas of the inland West on Friday and is predicted to last into next week. Temperatures in Los Angeles and typically cooler cities such as Portland, Ore., rose well beyond summer norms.

ERCOT, which instituted rolling blackouts during an extreme cold snap in February 2011, weathered the heatwave amid record-setting demand in Texas over the weekend. Dallas, Austin and other cities topped 100 degrees Fahrenheit.

The temperature reached 120 degrees in Death Valley Friday. | National Park Service

Throughout the West, families working and learning from home during the coronavirus pandemic cranked up their air conditioners, straining the system.

CAISO’s day-ahead forecast predicted a peak of 46,258 MW on Friday, but the ISO raised it to 46,824 MW in the afternoon. Available supply, at its peak, was about 53,000 MW but declined to 48,378 MW as solar power dropped offline when the sun set.

The ISO said it was “declaring a Stage 3 electrical emergency due to high heat and increased electricity demand. The emergency initiates rotating outages throughout the state. A Stage 3 Emergency is declared when demand outpaces available supply. Rotating power interruptions have been initiated to maintain stability of the electric grid.”

“The Stage 3 emergency declaration was called after extreme heat drove up electricity demand across California, causing the ISO to dip into its operating reserves for supply to cover demand,” it said. “The California ISO is working closely with California utilities and neighboring power systems to manage strain on the grid and to restore the power grid to full capacity. As portions of the grid are restored, local utilities will restore power in a coordinated fashion.”

“Although a Stage [3] emergency is a significant inconvenience to those affected by rotating power interruptions, it is preferable to manage an emergency with controlled measures rather than let it cause widespread and more prolonged disruption,” CAISO said.

National Weather Service map | National Weather Service

On Thursday and again on Friday morning, CAISO issued a “flex alert” urging customers to voluntarily conserve power, including by setting thermostats at 78 F. It restricted utility maintenance operations and then issued a warning midday Friday followed by the first emergency alert at 3:25 p.m.

The Stage 2 emergency, announced Friday afternoon, was the ISO’s first in 15 years.

Unexpected Early Test

The shortfall tested the state’s transition from fossil fuels and nuclear power to renewable resources. The percentage of renewables serving load fell from about 30% midday to single-digits after sunset as natural gas plants ramped up to meet demand.

Natural gas generation ramped up steeply Friday. | CAISO

Gas generation began the day providing roughly 11,500 MW to the CAISO grid but was pumping out nearly 26,000 MW after an exceptionally long, steep ramp from 10 a.m. to 7 p.m.

Renewables in CAISO’s system, mainly solar power, peaked at more than 13,000 MW at 2 p.m. but began to fall off just as demand increased late in the afternoon.

Imports from other Western states gradually decreased throughout the day to about 3,500 MW at 4 p.m. as the heat wave drove demand in neighboring Nevada, Arizona and other states. Imports recovered in the evening, helping to alleviate the shortfall.

CAISO and the California Public Utilities Commission have repeatedly warned that the combination of retiring natural gas plants and constrained imports could result in capacity shortfalls starting as soon as this summer and grow significantly worse in the next three years. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)

However, the ISO reported in May that it expected to be able to get through this summer without a shortfall such as Friday’s. (See CAISO Predicts Adequate Summer Capacity.)

Resource adequacy in the West has become a major topic for organizations such as WECC and the Northwest Power Pool. The added problems of catastrophic wildfires and the COVID-19 pandemic have exacerbated those concerns. (See WECC Tackles Wildfires as Reliability Threat.)

Robert Mullin and Rich Heidorn Jr. contributed to this report.

August 16, 2020

Texas PUC to End COVID Relief Program

Texas regulators last week agreed with their staff’s recommendation to end a moratorium on retail customers’ cutoffs for nonpayment at the end of September.

Public Utility Commission staff filed a memo that recommended enrollment in the commission’s COVID-19 Electricity Relief Program halt on Aug. 31 and that the benefits end on Sept. 30 (50664).

“This is a hard balance to have, but I think it is the time,” PUC Chair DeAnn Walker said during the commission’s open meeting Thursday.

PUCT COVID-19 — PUC Chair DeAnn Walker opens the Aug. 13 open meeting.

The PUC created the program in March to help retail providers’ unemployed customers by shielding them from disconnections for nonpayment and offering bill payment assistance. The program is funded by a charge applied to customer bills within the ERCOT region.

A separate requirement to provide customers a deferred payment plan upon their request will continue, Walker said.

“The people who have been on the relief program will be transitioning off and may need to have that opportunity,” she said. “I still view … that we’re in a state of emergency.”

Texas on Friday became the third state to record 10,000 deaths from the coronavirus. The state has more than 545,000 confirmed cases and registered a spike of 6,755 cases the same day as the PUC’s open meeting.

In other actions, the PUC:

fined Reliant Energy $100,000 for failing last year to maintain and produce verification of 292 switch requests and for failing to energize 33 customers on the agreed service start dates, resulting in a loss of service. The utility agreed to change its processes for using third parties to enroll customers (51045).
approved a $39.4 million fuel refund for Southwestern Public Service. The refund had been authorized in April on an interim basis (50556).

August 16, 2020

PJM MRC Preview: Aug. 20, 2020

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

Members will be asked to endorse the following manual changes and Tariff revisions:

B. Manuals 14A, 14B and 14G. Revisions in response to PJM PC/TEAC Briefs: July 7, 2020.)

C. Dispatch Interactive Map Application (DIMA). Operating Agreement revisions to grant transmission owners access to the Dispatch Interactive Map Application. (See “DIMA Quick Fix Endorsed,” PJM OC Briefs: July 9, 2020.)

Endorsements/Approvals (9:10-10:55)

1. Manuals 14D and 27 – Zonal NSPL Values (9:10-9:25)

Members will be asked to endorse revisions to Manual 14D: Generator Operational Requirements and Manual 27: Open Access Transmission Tariff Accounting that alter the deadlines for adjustments associated with finalizing the zonal network service peak load values. (See “Manual 14D and 27 Revisions,” PJM MIC Briefs: Aug. 5, 2020.) The Manual 27 revisions were endorsed at the Aug. 5 Market Implementation Committee meeting, while the related Manual 14D revisions were endorsed at the Aug. 6 Operating Committee meeting.

2. Market Efficiency Process Enhancement Task Force (9:25-10:10)

Stakeholders will be provided an update on the Phase 3 work completed at the Market Efficiency Process Enhancement Task Force and asked to vote on several rule changes. (See PJM Stakeholders Debate Market Efficiency Proposals.)

A. PJM will review two proposals for creating a new regional targeted market efficiency project (RTMEP) process that transmission owners say will target small projects addressing persistent congestion not identified in the forward-looking planning model, which other members have criticized for excluding competition. Members will be asked to approve American Electric Power’s and FirstEnergy’s package, A4, which would award RTMEPs to the incumbent TO. If that vote fails, members will be asked to consider PJM’s proposal, A1, which calls for 30-day competitive windows to select the developer. The AEP-FE proposal won a 56% Planning Committee vote in May, edging out the PJM proposal, which received 55% support. Members also will be asked to approve corresponding OA revisions.

B. PJM also will seek a vote on the benefit calculation metric for RTMEPs and asked to approve AEP-FE solution package B4, which would average multiple Monte Carlo results and run them on Regional Transmission Expansion Plan (RTEP), RTEP+3 and RTEP+6 years. If that fails, members will vote on PJM proposal B1, which would use a single-draw Monte Carlo simulation, with simulations for both Reliability Pricing Model and RTEP years. The AEP-FE proposal won 54% support from the PC, compared to 52% for PJM’s proposal. Corresponding OA revisions also will be up for a vote.

C. PJM will review and seek a vote on PJM package C1 and corresponding OA revisions to clarify when capacity benefits of RTMEPs are calculated.

3. Risk Management Committee Charter (10:10-10:25)

PJM will seek approval of revisions to the Credit Subcommittee charter, which expand its scope to incorporate risk and changes the committee reporting structure. The panel will be renamed the Risk Management Committee. (See “‘Credit’ Subcommittee Proposed to Change to ‘Risk Management,’” PJM MRC Briefs: April 30, 2020.)

4. Critical Infrastructure Stakeholder Oversight Senior Task Force (10:25-10:55)

Stakeholders will be asked to revoke an issue charge being worked on at special PC sessions on critical infrastructure stakeholder oversight and endorse a replacement issue charge, which has a related problem statement. (See “Changes Approved to CISO Issue Charge,” PJM PC/TEAC Briefs: May 12, 2020.)

August 16, 2020

NY PSC Gets Update on Tx Planning, Investment Efforts

The New York Public Service Commission heard a progress report Thursday on a grid study underway to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals, as well as brief outlines of three separate petitions on large-scale public policy transmission needs (Case No. 20-E-0197).

“We need more; we need smarter; we need faster transmission,” PSC Chair John B. Rhodes said. “Recognizing this, there is necessarily a lot going on.”

Tammy Mitchell, chief of bulk electric systems for the state’s Department of Public Service (DPS), said the study results — due Nov. 1 — will inform two separate investment plans to be established by the PSC, one related to distribution and local transmission investments or upgrades, and another plan for bulk system transmission investments.

The commission in May authorized the study as directed the previous month by the Accelerated Renewable Energy Growth and Community Benefit Act (A09508), which set up the Office of Renewable Energy Siting and required investment plans to meet the renewable energy targets of last year’s Climate Leadership and Community Protection Act (CLCPA). (See NYPSC Launches Grid Study, Extends Solar Funding.)

The CLCPA mandates that 70% of the state’s electricity come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040. Its clean energy targets include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.

The PSC in May also directed utilities to file proposals to incorporate the statutorily mandated environmental benefits in utility planning and investment criteria, and proposals to prioritize such projects in their capital spending and apply benefit/cost analysis for potential investments. It also directed them to file cost-containment, cost-recovery and cost-allocation methods. All proposals are due no later than Oct. 5.

The commission will seek public comments on the grid study results and utility proposals and expects to be able to move ahead with distribution and local transmission upgrades early in 2021, Mitchell said.

Three Projects Now Being Sited

New York currently has three 345-kV transmission projects underway that were selected through the NYISO Public Policy Transmission Planning process and are in the Article VII — or full review — siting process, Mitchell said.

NYISO selected NextEra Energy’s Empire State Line proposal in October 2017 to obtain full output of the New York Power Authority’s (NYPA) Niagara hydro facility, maximize Ontario inflows and maximize exports of renewable resources out of western New York to the rest of the state. The line is expected to be in service in the first half of 2022.

NY PSC transmission — NYISO’s 2019 CARIS Report shows renewable generation pockets in western New York. | *NYISO*

The other two projects underway were selected by NYISO last year as part of the broader AC Public Policy Transmission Project. One being built by LS Power and NYPA will increase transmission capacity by approximately 800 MW at the Central East (Segment A) electrical interface, well above the commission’s minimum of 350 MW, she said. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

Another by New York Transco for the Upstate New York/Southeast New York (Segment B) interface will run from the Albany region to the Hudson Valley region, increasing transfer capability by about 2,000 MW, well above the commission’s minimum of 900 MW.

Both of the latter projects are expected to be in service by December 2023, Mitchell said.

Fast-track Proposals from NYPA, DPS, LIPA

On July 2, NYPA and the DPS submitted a two-part petition to the PSC that included DPS staff’s proposed criteria for determining priority projects and a NYPA proposal that the commission designate its “Northern NY Project” as a priority project to be developed under the new siting law.

The DPS criteria included an investment’s potential for unbottling existing renewable generation, avoiding future congestion and increasing the deliverability of existing and anticipated baseload renewable or low-carbon generation. It also factored in whether an early in-service date would increase the likelihood of meeting CLCPA targets and considered the transmission investment’s eligibility for expedited review under Article VII and its implementing regulations.

The redacted public version of the petition does not include cost estimates, but in it, NYPA estimates the project will result in approximately 7.5 TWh of avoided renewable curtailments annually, starting in 2025, and result in production cost savings of approximately $99 million per year, for a net present value of approximately $1 billion over a 20-year period.

The Northern NY Project “will establish a continuous 345-kV path that greatly expands the deliverability of renewable generation from northern and western New York to load centers,” while compounding the benefits from the Segments A and B projects already underway, NYPA said.

On July 13, NYPA filed another petition asking the PSC to designate its Western New York Energy Link Project (WNYEL) to also be a priority for the state.

NYPA said the project will upgrade assets owned by National Grid, New York State Electric and Gas and NYPA to reduce or eliminate existing curtailment of renewable and carbon emission-free generation, facilitate the siting of new renewable generation in the area and increase transfer capability from the region to load centers by approximately 600 MW.

The WNYEL project includes reconductoring two 42-mile Packard-Huntley-Gardenville 230 kV circuits; a tower separating 230 kV lines; converting the existing double-circuit common tower structures to single-circuit single tower structures; and installing a new phase angle regulator at the South Ripley substation to control the flow from PJM to the New York Control Area.

NYPA said NYISO’s 2019 Congestion Assessment Resource Integration Study, issued in June 2020, supports the need for additional transfer capability near the Niagara Power Project, citing the study’s identified renewable generation pockets. (See Bulk Tx, 115-kV Upgrades Needed for NY 70×30 Goal.)

NYPA asked that if the PSC does not designate WNYEL as a priority project, the commission instead direct National Grid and NYSEG to undertake the necessary improvements to develop the project in coordination with NYPA.

Collectively, NYISO projected that Zone A will be the site of more wind and solar generation than any other zone except for Zone J (New York City), and found three potential areas of transmission bottlenecks, identified as pockets W1, W2 and W3. NYISO projected curtailments of 20 to 30% for solar generation between and 5 to 8% for land-based wind resources.

The Long Island Power Authority (LIPA) on July 30 submitted to the PSC a FERC Order 1000 referral, as allowed under the NYISO Tariff, seeking the commission’s determination that the 2018 Offshore Wind Standard is a public policy driving the need for transmission. LIPA also asked the PSC to find a need for additional export capability on the Consolidated Edison interface, as well as for upgrades to the local transmission system on Long Island to support the 2018 OSW procurement target of 2,400 MW (18-E-0623).

Two years ago, NYISO solicited proposals for transmission needs driven by public policy requirements and, in October 2018, submitted to LIPA seven of the 15 proposed needs it received from stakeholders, including one from PSEG Long Island that summarized the OSW procurements as giving “rise to the need to optimize transmission development and to create a ‘transmission backbone’ structure in order to meet the state’s ambitious goal of 2,400 MW of resources by 2030.”

“The transmission system was originally built to serve native load of monopoly utilities, and ratemaking at both the state and federal level was based on that,” Commissioner John B. Howard said. “This new paradigm is as dramatically different from that as can be imagined, since the primary focus of our bulk transmission system will now be to enhance and provide environmental benefits through zero-emissions generation across the state.”

August 16, 2020

FERC Accepts Trimmer MISO LMR Capacity Accreditation

FERC approved new rules Friday likely to reduce load-modifying resources’ (LMRs) capacity accreditation in MISO, despite several protests from RTO members.

The commission said accrediting LMRs based on their notification times and the number of calls they respond to is an appropriate means for managing MISO’s increase in maximum generation emergencies (ER20-1846).

MISO will be able to set an LMR’s capacity accreditation at either an average of its actual availability over a three-year period or its tested availability, whichever is less. LMRs that can respond more often and with shorter lead times will receive a larger capacity credit:

Those that can respond in six hours or less to 10 or more calls per year will receive full capacity credit.
LMRs ready in six hours or less that can only respond to five to nine calls in a planning year will receive an 80% accreditation.
LMRs with lead times greater than six hours will be offered a 50% capacity credit for two years if they can respond to at least 10 calls in a year.

The percentage-based accreditation will take effect in the 2022-2023 planning year. Beginning with the 2023-2024 planning year, MISO will stop offering capacity credits for LMRs with six hours or greater lead times or that cannot respond to at least five calls in a planning year. The RTO maintains that LMRs needing more than six hours’ notice don’t help mitigate emergency conditions.

MISO’s proposal is more lenient than an earlier version that would have eliminated slow-response LMRs two years earlier. (See MISO Delays New LMR Accreditation Launch.)

MISO LMR Capacity Accreditation — | *Shutterstock*

FERC said the arrangement was reasonable considering MISO’s increased reliance on LMRs to meet its planning reserve margin requirement and the short notice it usually has before entering emergency procedures.

LMRs currently make up nearly 9% of MISO’s planning reserve margin requirement. The grid operator refers to the resources as the last line of defense before having to shed load.

The commission also said MISO’s two-year notice before disqualifying slow-response LMRs gives those resources enough time to adjust their response capabilities and better assist in emergencies.

“We find that MISO’s proposal to reduce the maximum notification time requirement from 12 to six hours reasonably reflects MISO’s ability to predict [maximum generation events] and the ability of LMRs to respond in a timely manner,” FERC said.

The commission said the new rules do not unfairly single out LMRs over other capacity resources, as some LMR-owning members argued. On the contrary, FERC said, MISO’s plan recognizes LMRs’ unique traits.

“We find that MISO’s proposal is not unduly discriminatory against LMRs as compared to other capacity resources because MISO’s proposal addresses the unique operating and reliability characteristics of LMRs, such as advanced notice requirements and that LMR deployments are limited to [maximum generation events] to prevent firm load shedding,” FERC wrote.

MISO isn’t done proposing new solutions to encourage LMR availability. Earlier this month, MISO staff said they must correct significant gaps between the LMR capability that clears capacity auctions and what actually responds to MISO emergency instructions. The grid operator has said several LMRs are unavailable in MISO’s times of need. (See MISO Investigating LMR Availability Problem.)