Page 1106 – RTO Insider

April 26, 2020

ISO-NE Planning Advisory Committee Briefs: April 23, 2020

New England’s grid will see diminishing returns from the incremental addition of offshore wind as more megawatts are added, with as much as 13.9% spilled annually, analysis from ISO-NE shows.

The yearly production pattern does not follow the pattern of load, causing spillage to be highest during low-load months and lowest during high-load months, according to Richard Kornitsky, ISO-NE assistant engineer for system planning.

Kornitsky was presenting a follow-up to questions from last month’s meeting related to the economic study conducted for the New England States Committee on Electricity. The organization, Anbaric and RENEW Northeast last year each requested separate studies from ISO-NE. (See “Modeling More Offshore Wind, Slowly,” ISO-NE Planning Advisory Committee: March 18, 2020.)

Annual spilled energy vs. total available energy of offshore wind for all scenarios, as shown in the NESCOE study (0 to 8,000 MW) | *ISO-NE*

Kornitsky’s presentation focused on spillage stemming from oversupply, building on analyses performed for the NESCOE study for the year 2030.

Theodore Paradise, Anbaric senior vice president for transmission strategy, asked about the assumptions around the dispatch of the non-wind resources.

“Have we taken off all the oil units and any remaining coal, which is barely any, and all the natural gas we can, save for the stuff that needs to ramp and load follow? Or are we keeping a fair bit of that on, causing more spillage than you might have if it was off?”

“It more depends on how the wind is behaving at that specific hour, since in some hours, even in months such as April or May, you’ll have moments when you’ll have quite a bit of offshore wind,” Kornitsky said. “So, there might be hours where offshore wind is the main generation that’s serving load and you won’t have much of that conventional natural gas generation online.”

But Kornitsky also pointed to situations where the system will have very little or no offshore wind, at which point natural gas will be coming back online — and points in between.

“The main thing, especially when you get up to 8,000-MW cases, is there wind available, and that really dictates what other generation is online,” Kornitsky said.

The RTO’s next steps are to complete the ancillary services component of the NESCOE study for presentation in May and to publish the final report by June 1. The final Anbaric study will be published by June or July.

RENEW Study Shows Minimal Spillage

Kornitsky also presented the preliminary RENEW study results for 2025, reminding participants the study does not focus on offshore wind additions “but rather the impacts of the conceptual increases in hourly operating limits of the Orrington-South interface from conceptual transmission upgrades.”

The study has two scenarios based on estimated 2016 limits, which were modified to approximate the addition last year of a voltage regulating system at the Cooper Mills substation in Windsor, Maine.

Scenario 1 shows the same limits as the base case but has a transmission device at the Orrington-South interface with the equivalent impact of a large synchronous generator dispatched nearby, meaning all monthly limits are equal to or higher than the base scenario.

Scenario 2 also shows similar limits to the base case but includes a new 345-kV transmission path from the Orrington substation to the Maine Yankee station, with monthly limits higher than base or Scenario 1.

“We use threshold prices to decrease production of $0/MWh resources during oversupply and use of different threshold prices than indicated will produce different outcomes, particularly spillage by resource,” Kornitsky said.

“Under our base assumptions, we see New Brunswick imports, Hydro-Quebec imports, native New England hydro and utility PV would be all curtailed before curtailing NECEC [New England Clean Energy Connect], and finally, behind-the-meter PV would be curtailed last,” he said.

NECEC is a $950 million project to deliver 1,200 MW of Canadian hydropower to the New England grid in Lewiston, Maine, along a 145-mile transmission line controlled by Avangrid subsidiary Central Maine Power.

A set of NECEC sensitivity scenarios were performed assuming a higher threshold price of $11/MWh, which results in the curtailment of the line before other resources.

However, raising the NECEC threshold price from $2/MWh to $11/MWh does not greatly change the amount of total spilled energy systemwide.

Among the key observations: Systemwide production costs and load-serving entity energy expenses are similar among all the scenarios, and varying price separation is seen in LMPs at Bangor Hydro because of congestion at the Orrington-South interface.

Also, the base case provides the most congestion at the Orrington-South interface, while Scenario 2 provides the least congestion. Spillage is minimal across all scenarios.

“The scale of what’s being changed in this study is very different and smaller than the scale of what was being changed in the other two studies here, so there won’t be much impact on the total system,” Boreas Renewables President Abigail Krich said. “We’re looking at a very small pocket of the system, so in terms of looking at the results, I would hesitate to describe them as not significant on a system scale and more look at the impacts it has on the local area being studied.”

The RTO will publish the final RENEW report by July.

National Grid Study Request

National Grid lead analyst Kai Van Horn presented a new economic study r equest that would aim to build on earlier studies, modeling year 2035 to provide insight on wholesale energy market impacts, unit economics, utilization of resources, and the role of transmission and battery storage on a system with a high proportion of variable resources.

“The significant decarbonization targets are being set at the state level, which have major ramifications for the energy system,” Van Horn said. “Meeting those targets is going to require a lot of changes, and there are a lot of ways to get there. The broader set of solutions that we can consider, the better outcome we can get to in terms of meeting those targets.”

The proposed study focuses on two pathways: the efficient use of clean energy resources, and leveraging transmission and storage in order to do so, Van Horn said.

April 26, 2020

NEPOOL Reliability Committee Briefs: April 22, 2020

ISO-NE energy demand has fallen 3 to 5% since stay-at-home orders began being implemented across New England around March 16, the RTO’s Load Forecasting Manager Jon Black told the New England Power Pool’s Reliability Committee on Wednesday.

“System operations as well as load forecasting in planning are doing ongoing analysis [and] monitoring the situation very closely,” Black said.

That situation is changing by the week, and ongoing changes are likely, especially as the stay-at-home orders may become relaxed or lifted in various parts of the region, he said.

“While we’re seeing impacts today, there’s a lot of uncertainty about the ongoing duration of the effects of the stay-at-home orders, first and foremost in terms of the duration of what we’re witnessing and observing now, but perhaps more importantly from a long-term forecast perspective, what will be the recessionary impacts of the fallout of the pandemic,” Black said.

It’s still too early to understand the longer-term impacts of the pandemic, but the RTO relies on sources like Moody’s Analytics to inform its thinking, he said. (See Moody’s: Coronavirus Recession to Cut GDP 2.3%.)

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

CELT 2020 Forecasts up on Electrification

Black presented the final data behind the long-term energy and demand forecasts to be published May 1 in the 2020 Capacity, Energy, Loads and Transmission (CELT) report.

Both the gross and net annual energy forecasts for 2028 are up from last year’s CELT, by 1.5% and 5.4%, respectively, “largely due to the forecast impacts of large-scale electrification expected throughout the region,” Black said.

“The numbers have all been finalized, but there’s a lot of work that goes into publishing all the final reports,” he said.

NEPOOL Reliability Committee — New England 2020 CELT final gross annual energy forecast | *ISO-NE*

The RTO has posted the 2020 Forecast Data workbook.

CAGR up Slightly

Black explained that, other than adding electrification forecasts, the RTO adopted no significant modeling changes compared to the 2019 CELT.

“This year’s compound annual growth rate [CAGR] is up a bit from last year over the 10 years, at 1.4% from 2020 through 2029, up from 1.1% in last year’s CELT.”

The final 2020 net annual energy forecast for the region has a CAGR of 0.4% from 2020 through 2029, up from the -0.4% reported in CELT 2019, he said.

Other highlights from the 2020 CELT:

The gross 50/50 summer peak demand forecast exceeds the 2019 CELT’s by 0.3% for 2020 and 1.5% for 2028, and is forecast to increase at a CAGR of 0.9% from 2020 through 2029, up slightly from 0.7% in CELT 2019.
The final net 50/50 summer peak demand forecast for the region is 0.4% higher in 2020 and 1.2% in 2028. It’s expected to decrease at a CAGR of -0.2% from 2020 through 2029, up slightly from -0.4% for CELT 2019.
The final 2020 gross 50/50 winter peak demand forecast is up 0.4% for the winter of 2020/21 and by 4.2% for the winter of 2028/29, and forecast to increase at a CAGR of 1.1% from 2020 through 2029.
The final net 50/50 winter peak demand forecast for the region is down by 0.2% for the winter of 2020/21 and up by 4.3% for the winter of 2028/29. It is expected to increase at a CAGR of 0.1% from 2020 through 2029, up from -0.6% as reported in last year’s CELT.
New England 2020 CELT final gross 50/50 summer peak forecast | ISO-NE

EE Reconstitution

Black also provided the RC with background on energy efficiency participation in the Forward Capacity Market and its “reconstitution” in the gross load forecast.

“Taking it all the way back to the beginning of the Forward Capacity Market, as part of that inception, it was decided that EE would be treated as a capacity supply-side resource and receive capacity supply obligations [CSOs] in the same manner as any other supply-side resource,” Black said.

“In order for that to work, we have a section of our Tariff that requires us to reconstitute — in other words, add back —the demand savings associated with the EE that participates as supply, and that reconstitution is done on the historical loads that we use to develop a long-term load forecast, and in particular the long-term gross load forecast,” he said.

The intent of the gross load forecast is to ensure that passive demand resources are not double-counted in the Forward Capacity Auction as both a load reduction and a capacity supply resource, Black said.

ISO-NE has observed over time that the total amount of EE measures installed exceeds the amount of such CSOs acquired in the primary auction, meaning that reconstituting all installed EE measures results in a forecast of gross demand that overestimates the amount of EE CSOs acquired in the FCA.

Shifting to EE CSO as the basis of its gross load reconstitution will better approximate future EE supply-side participation, Black said.

The change in load forecasting methodology is the first of three initiatives the RTO is introducing to relevant NEPOOL technical committees over the next several months, as detailed in a memo posted after the meeting from COO Vamsi Chadalavada. The second initiative considers the impact of behind-the-meter solar PV on future planning assessments, and the third will better integrate the FERC Order 1000 request-for-proposals process into the reliability delist bid review, starting with FCA 15.

The RTO will present the EE methodology topic for further discussion next month ahead of an advisory vote in June. If the Participants Committee approves them, the Tariff changes will be filed with FERC with a requested effective date of Aug. 30.

FCA 15 Fuel Security Reliability Review

ISO-NE Manager of Outage Coordination Norm Sproehnle presented initial inputs to the fuel security reliability review for FCA 15, feedback from the March RC meeting and preliminary results.

Stakeholders in March pushed back on ISO-NE’s draft assumptions showing that several variable changes between FCAs 14 and 15 would improve system fuel security. (See NEPOOL Reliability Committee Briefs; March 17, 2020.)

Appendix L of the Tariff stipulates the RTO must apply a multiprong trigger for the FCA 15 preliminary analysis that would result in a resource being retained for fuel security if its retirement would: result in the depletion of 10-minute reserves below 700 MW in any hour in the absence of a contingency in more than one LNG supply scenario case; or precipitate the use of load shedding in any hour pursuant to Operating Procedure No. 7.

Using the trigger criteria and the existing Planning Procedure 10 (PP10) inputs, as updated for FCA 15, the RTO has been able to assess the preliminary results of resources that have submitted retirement delist bids (1,935 MW total). Appendix I of PP10 requires the RTO to consult with the RC on 18 static inputs and three variable inputs: imports, LNG injections and dual-fuel resource tank inventory.

The preliminary results indicate that no resources that submitted a retirement delist bid for the FCA 15 capacity commitment period or were previously retained for fuel security — both totaling 1,935 MW — will be retained for fuel security for the period.

The additional work to complete the analysis will not change the outcome of the fuel security reliability review, as the items to be finalized will further improve fuel security, Sproehnle said.

Given the preliminary results of the FCA 15 fuel security reliability review, the additional changes suggested thus far would not materially alter the outcome, he said.

For example, stakeholders asked if the Distrigas LNG tanks will be available and utilized in the fuel security reliability model if Mystic Units 8 and 9 retire.

The RTO derived the three LNG scenarios — 0.8, 1 and 1.2 Bcfd — based on the output of the region’s three LNG facilities and their previously observed winter production. If the Distrigas facility is excluded, the capability of the remaining LNG facilities can support the three scenarios, he said. Therefore, ISO-NE will continue to use them for the review.

The RTO timeline calls for the RC in August to review FCA 15 fuel security analysis results for submitted retirement delist bids. Participants that have submitted a retirement delist bid will be notified by the RTO if their resource is needed for fuel security reliability reasons no later than 90 days after the existing capacity June 11 retirement deadline.

ICR and Related Values Development

Manasa Kotha, ISO-NE senior engineer for resource studies and assessment, presented the RC with the 2020 development schedule for installed capacity requirement (ICR) values that will be used in auctions conducted in 2021.

The ICR, as well as the net installed capacity requirement, are calculated for each FCA and annual reconfiguration auction and are inputs to the sloped demand curves, Kotha said. The ICR represents the minimum total system capacity needed in New England to meet the Northeast Power Coordinating Council’s resource adequacy criteria.

Details of the ICR-related values development will be discussed with the NEPOOL Power Supply Planning Committee over the summer and brought back to the RC for review and a vote in September. If approved by the Participants Committee in October, the RTO plans to file the values with FERC by Nov. 10.

Committee Actions

The RC’s notice of actions included approval of several motions, noting that all sectors had a quorum.

The committee approved a 10-MW fuel cell interconnecting to the 23-kV bus of the Judd Brook substation in Connecticut, with an in-service date of Dec. 1.

Also approved was NextEra Energy’s 20-MW Keay Brook solar facility in York County, Maine, interconnecting to the 34.5-kV Lebanon-Sanford line, which went into service Feb. 12.

The RC approved pool transmission facility (PTF) cost allocation of $18.5 million to Eversource Energy for transmission upgrade costs associated with the replacement of wooden structures on the 115-kV 1655 line with steel poles.

Eversource also had $16.6 million in PTF cost allocation approved for work associated with the replacement of the high creep insulator system at the Millstone 15G substation in Waterford, Conn.

The RC approved National Grid PTF cost allocation of $212 million in transmission upgrade costs for work associated with the 345-kV 327 and 315 lines and asset condition refurbishment as submitted to ISO-NE by New England Power.

It also approved a revision to Operating Procedure 14 (OP-14) related to technical requirements for generators, demand response resources, asset-related demands and alternative technology regulation resources.

April 26, 2020

Ohio OKs FirstEnergy Brokerage Despite Protests

By Michael Yoder

Ohio regulators last week approved the application of a FirstEnergy subsidiary to operate as an energy broker and aggregator despite protests from consumer advocates and competitors over what they called a conflict of interest.

The Public Utilities Commission of Ohio on Wednesday granted approval for Suvon, doing business as FirstEnergy Advisors, as a competitive retail electric service (CRES) provider to help customers select electricity suppliers. FirstEnergy filed its application in January, and PUCO staff recommended approval of it earlier this month.

Critics, including the Ohio Consumers’ Counsel and the Northeast Ohio Public Energy Council (NOPEC), challenged the filing, saying use of the FirstEnergy name provided an unfair advantage and represented “too great a threat” to Ohio consumers in the retail electric market.

The OCC and NOPEC argued that having Suvon’s offices in the same building as the FirstEnergy’s headquarters in Akron, and having the company controlled by members of the same management team that controls the FirstEnergy utilities, violates state law requiring that a competitive retail electric supplier be “fully separated” from its regulated utilities.

FirstEnergy owns three utilities — Ohio Edison, Toledo Edison and The Illuminating Co. — with monopoly electricity distribution services regulated by PUCO.

NOPEC and the OCC argued that barring the use of the FirstEnergy name was consistent with a 2018 report filed by SAGE Management Consultants, PUCO’s outside auditor, in the commission’s corporate separation audit. The report recommended disallowing a former FirstEnergy affiliate, CRES provider FirstEnergy Solutions (FES), from using the FirstEnergy name.

FES recently emerged from bankruptcy under a new name, Energy Harbor, but the corporate separation case remains pending before the commission (17-974-EL-UNC).

FirstEnergy Brokerage — FirstEnergy’s Akron, Ohio, headquarters

The commission said that issues regarding Suvon’s use of the trade name and compliance with corporate separation requirements “are best raised” in that proceeding, noting that the commission has not adopted the SAGE report’s conclusions. “The finding and conclusions of the auditor should be litigated in that proceeding rather than this case,” it said.

PUCO also determined that the shared service arrangement between FirstEnergy and Suvon does not present a conflict of interest and is permissible under federal law. The commission cited other utility subsidiaries that have been certified as CRES providers, including a case involving Interstate Gas Supply’s (IGS) DPL Energy Resources in 2000.

“We note that the existing requirements for proper disclosure of the affiliate relationship has been considered to be a necessary and sufficient protection in all prior cases,” the commission ruled. “We expect Suvon to include and present the required disclosure in a conspicuous and efficacious manner in all communications with consumers.”

The OCC, Vistra Energy and NOPEC, Ohio’s largest nonprofit energy aggregator, filed motions opposing the certification. The Northwest Aggregation Coalition called for a hearing on it.

“In the long run, what we know in Ohio is when there is no competition, prices go up,” Chuck Keiper, NOPEC’s executive director, said in an email to RTO Insider. “We’ll be moving back to a toxic environment where the utilities control the marketplace.”

In a separate request, NOPEC and the OCC also asked PUCO to release public records of any communications the commissioners or staff had with FirstEnergy Advisors. Keiper said his concern that the commission did not hold a hearing in the case led to the public records request.

“We’re not afraid of another electricity broker coming into the market,” Keiper said. “In fact, we welcome it. But bring it on in a fair, honest, legal and transparent way. Let everyone see communications, if any, between FirstEnergy Advisors and the public body PUCO. Taxpayers and electricity consumers in Ohio are owed that and a fully public process to investigate this application.”

The commission noted that several of those intervening in the case were competitors of Suvon. “Competition should be determined ultimately by acumen in the marketplace, not by presumptive inhibition through a commission certification proceeding,” it said. “Although we have granted intervention in this case to Suvon’s competitors, we will carefully monitor the practice of competitors intervening in certification proceedings to ensure that this does not become a widespread, abusive practice and that competition is not unduly stifled by unnecessary litigation.”

PUCO denied the public records request, saying the staff determination that Suvon has the capabilities to serve as a power broker make the request “moot.”

“Staff has thoroughly reviewed Suvon’s managerial, technical and financial capability and has recommended that Suvon’s application should be approved,” the commission said. “Upon review of the many motions and memoranda filed in this case, we find that no other parties have raised material issues regarding Suvon’s managerial, technical and financial capability.”

J.P. Blackwood, a spokesperson for the OCC, said Thursday the organization was not satisfied by the decision.

“The Ohio Consumers’ Counsel is disappointed that the PUCO granted FirstEnergy Advisors’ operating certificate without imposing the conditions that we and many local governments recommended for consumer protection and fair competition,” Blackwood said.

April 26, 2020

SPP Western Markets Briefs: April 23, 2020

SPP’s effort to stand up the Western Energy Imbalance Service market is on budget and on schedule, the grid operator’s staff told the Western Markets Executive Committee last week.

“It’s going to take all of us to make that happen,” SPP’s David Kelley, director of seams and market design, told the WMEC during a conference call Thursday. “Understand when we’re pushing you and you’re pushing us, it’s to keep us marching to the same objective, and that’s to get the market up and running.”

SPP plans to begin operating the WEIS in February 2021. Modeled on the Energy Imbalance Market the RTO operated from 2007 to 2014, the WEIS has attracted eight participants. (See SPP Board OKs $9.5M to Build Western EIS Market.)

SPP Western Markets — SPP’s legacy and WEIS footprints | *SPP*

Kelley said that while the overall market development project’s status is yellow because some tasks are behind schedule, the project’s end date is “not in jeopardy.”

“We’ve been able to make up lots of lost ground we had early in the project,” Kelley said. “I’m still comfortable with where we are. The delays in some of the tasks won’t affect the overall health of the program.”

SPP staff are currently testing the first markets release from its vendor and have taken delivery of two key software systems. They are also preparing for various system tests, with market trials scheduled for the month of October. Parallel operations are scheduled to begin Dec. 10.

Kelley said SPP has yet to fill five of the 13 positions necessary to run a Western markets desk in its operations center because the RTO’s two control rooms have been “basically” locked down during the COVID-19 pandemic to protect the operators, he said.

“We have ample time to get the desk stood up and tested,” Kelley said.

The pandemic has also caused a change in training WEIS participants. SPP originally planned for in-person training in July but has now shifted to virtual, instructor-led classes.

FERC Finds SPP’s WEIS Tariff Deficient

FERC on April 20 issued a letter notifying SPP that its proposed WEIS Tariff, Western joint dispatch agreements and WMEC charter are deficient and requested additional information for the filings (ER20-1059, ER20-1060).

The commission asked for a response to 12 different categories by June 4, throwing into doubt SPP’s original requested effective date of May 21. The RTO filed the Tariff and other documents in February.

FERC asked SPP to break down the six categories of costs included in both its projected $9.5 million implementation costs and its ongoing administrative costs to be recovered through the WEIS rate. The RTO has proposed a WEIS rate of 22 cents/MWh of net energy for load, based on an estimated annual $5 million operating cost. That number includes the annualized payback of implementation costs.

FERC also asked SPP to explain why using its Integrated Marketplace market power mitigation thresholds are appropriate for the WEIS. The RTO said the market will be subject to market power monitoring and mitigation performed by its Market Monitoring Unit.

The proposed Tariff includes provisions for demand response and notes that aggregators of retail customers “shall be treated comparably to other market participants offering resources.” FERC said there was no mention of compensation for DR resources and asked the RTO to clarify whether those resources would be compensated at LMP like other participants; “if not, please explain how they will be compensated and why.”

April 26, 2020

PJM MRC Preview: April 30, 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. The Members Committee will next meet May 4.

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.

Consent Agenda (9:05-9:10)

Members will be asked to approve the following revisions to the PJM Tariff and other documents:

B. Administrative revisions to the PJM Tariff, Operating Agreement and Reliability Assurance Agreement as recommended by the Governing Document Enhancement & Clarification Subcommittee.

1. Hybrid Resources Issue Charge (9:10-9:35)

PJM will seek approval of an issue charge to create a new senior task force to clarify how existing rules for intermittent and energy storage resources would apply to inverter-based solar-battery hybrids. Some stakeholders at the March 26 MRC meeting questioned why some areas of hybrid resources are being considered out of scope for the proposed task force, including PJM’s compliance with FERC Order 845. (See PJM MRC Moves Forward on Storage, Hybrids.)

April 26, 2020

CISA Releases Pandemic Guidelines for Control Centers

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has provided a list of guidelines for safely operating control centers during the COVID-19 pandemic.

The Operations Centers and Control Rooms Guide for Pandemic Response applies to “operations centers and control rooms across the 16 critical infrastructure sectors required to operate in a pandemic environment.” As defined by CISA in its Guidance on Essential Critical Infrastructure Workers, these sectors include the electricity, natural gas, petroleum and other energy-related industries; health care and public health; law enforcement and other first responders; transportation and logistics; and water, among others.

“Operations centers and control rooms often operate 24/7, depend on unique equipment, and require specially trained staff who are difficult to replace,” CISA said. “As a result, specialized equipment and long lead times required to train personnel mean there is a higher risk to sustaining reliable operations.”

CISA Pandemic Guidelines — PPL’s control room | *Barco*

Recommendations in the guidelines cover preventive measures to keep workers and equipment from coming in contact with the coronavirus; mitigating actions when exposure has occurred; and coordination with federal, state and other authorities to prioritize testing and arrange for free movement of essential personnel during periods of travel restrictions. The measures are advisory and “should not be considered a federal directive.” Owners and operators are also advised to tailor their approaches based on industry and site-specific needs.

COVID-19 Mitigation to Continue

CISA’s guidelines complement the ongoing actions by NERC and the broader electric industry to mitigate the impact of COVID-19. In a recent report, NERC noted that while there are “no specific threats or degradations” to the operation of the bulk power system at this time, utilities must be prepared “to operate with a significantly smaller workforce, an encumbered supply chain and limited support services” as a result of the outbreak. Cybersecurity and shortages of protective equipment are also significant concerns. (See PPE, Testing Top Coronavirus Concerns for NERC.)

Since issuing a Align Tool Set for 2021 Rollout.) NERC has either canceled all external meetings through June or converted them to conference calls.

Along with these actions, NERC also obtained permission from FERC Agrees to Defer Standards Implementation.)

NERC has signaled that it will continue its pandemic response even as state governments begin taking steps to end shelter-in-place orders in hopes of restarting their economies. On Friday, the organization announced it would extend its suspension of on-site activities, including audits and certifications, through Sept. 7. FERC and NERC announced the suspension — originally scheduled to end July 31 — in March, along with other regulatory relief measures. (See FERC, NERC Relax Compliance in Light of COVID-19.)

“The ERO Enterprise recognizes that there are significant uncertainties regarding the duration of the outbreak and the subsequent recovery and will continue to evaluate the circumstances to determine when on-site activities may resume safely or whether additional regulatory relief is necessary,” NERC said. “In the interim, the regional entities are actively involved in remote oversight activities and are experimenting with innovative approaches … to continue assuring the reliability and security of the bulk power system.”

April 24, 2020

Utilities Alarmed as FCC Opens 6 GHz Band to Wi-Fi

The Federal Communications Commission on Thursday agreed to open a portion of the 6-GHz band for unlicensed use over the objections of utilities, which fear their communications in the spectrum could be disrupted.

The FCC said its ruling “will usher in Wi-Fi 6, the next generation of Wi-Fi, and play a major role in the growth of the Internet of Things,” noting Wi-Fi 6 will be more than two-and-a-half times faster than the current standard. It said it will nearly quintuple the amount of spectrum available for Wi-Fi and improve rural connectivity (Docket 18-295).

But the Utilities Technology Council blasted the move, saying the FCC had failed to balance protection of critical communications in its desire to be innovative.

“Opening the 6-GHz band can be done in such a way that can both unleash the new innovations the FCC and others hope for while also protecting the CII [critical-infrastructure industries] systems already in the band. Doing so would take time, additional study and stronger protections for incumbent systems,” the UTC said in a statement. “Today, the FCC appears to have decided on taking a much riskier approach that does not control low-power indoor operations using AFC [automated frequency coordination systems]. Nor does the FCC order provide additional testing to prevent interference from occurring or enforcement processes to resolve interference that does occur.”

“While we support the goal of using spectrum more efficiently, today’s decision by the FCC means there will be no field testing or AFC mechanism in place to protect incumbent users from interference by indoor low-power devices,” said Phil Moeller, the Edison Electric Institute’s executive vice president for business operations and regulatory affairs. “EEI’s member companies remain committed to providing their customers with reliable and secure energy, and we will carefully monitor the band for interference to prevent any significant impacts to mission-critical communications systems.”

Electric utilities use the 6-GHz band for point-to-point microwave links providing communications with substations, fault sensors, two-way meters and service crews. It is also used to provide situational awareness in rural areas where wired networks are not available. Other critical infrastructure such as police and fire dispatch, railroads, and natural gas and oil pipelines also use the spectrum. (See Utilities Warn of Encroachment on Communications Band.)

FCC Wi-Fi — A point-to-point microwave receiver “views” a region of about 37 kilometers by 6.5 kilometers. Given the population density of a city like Houston, such a receiver could face potential interference from more than 62,000 unlicensed Wi-Fi access points, according to a study conducted for utilities. | *Roberson and Associates*

The commission authorized indoor low-power operations over the full 1,200 MHz (5.925–7.125 GHz) and standard-power devices in 850 MHz of the 6-GHz band.

The FCC also issued a Further Notice of Proposed Rulemaking seeking comment on permitting very low-power devices to operate across the 6-GHz band to support high data rate applications such as wearable augmented-reality and virtual-reality devices. The notice also seeks comment on increasing the power at which low-power indoor access points can operate.

The commission said its order was critical to realizing its goal of “making broadband connectivity available to all Americans, especially those in rural and underserved areas.”

FCC Chairman Ajit Pai noted in a statement the importance of Wi-Fi during the COVID-19 pandemic.

“Sheltering in place would be a lot more difficult without Wi-Fi,” he said. “Of course, even before anyone had heard of COVID-19, Wi-Fi already carried more than half of the Internet’s traffic, and offloading mobile data traffic to Wi-Fi was vital to keeping our cellular networks from being overwhelmed. In a very real sense, Wi-Fi is the fabric that binds together all our digital devices.”

[NOTE: The commission’s order had not been posted as of press time Thursday evening.]

The FCC insists the AFC system will prevent standard power access points from operating where they could cause interference to existing services. But utilities say AFC — which uses a “database lookup scheme” to ensure that unlicensed users are not encroaching on an existing user’s priority access to the frequency in a specific area — should be required for low-power devices also.

‘Real-world’ Study

UTC, EEI, the American Gas Association, the American Public Power Association and the National Rural Electric Cooperative Association submitted a study to the FCC in January that looked at the impact of the proposed rule on 520 microwave sites and 2,325 point-to-point communications receivers in the nine-county Houston Metropolitan Statistical Area, chosen because its flat terrain simplified “propagation path loss issues.”

“The analysis clearly demonstrates that allowing unlicensed devices to operate in the 6-GHz band will render fixed point-to-point communications receivers serving critical infrastructure in [the] Houston MSA unreliable and unable to meet minimal performance objectives, specifically geographic coverage (i.e., long links), high bit rates, low latency and high reliability,” said the study, which was conducted by Roberson and Associates, a technology and management consulting company.

Utilities use the 6-GHz band because it allows microwave networks with multiple links to cover large areas with very low latency time delays, high bit rates and high reliability, with resilience to “rain fading.”

“Given the critical nature of the communications carried on the 6-GHz band, the public safety and CII networks operating in this band are built to extremely high standards of reliability — 99.999% or 99.9999% availability. These networks must also transmit with extremely low levels of latency — 20 milliseconds or less of roundtrip delay from one point to another over long distances. No other band has sufficient bandwidth with all key characteristics (large geographical distances, low latency time delays, high bit rates, high reliability) to permit reliable operations in large, dense metropolitan networks such as Houston,” the study said.

Millions, Billions

EEI noted in an April 15 letter to the FCC that “unlicensed advocates themselves predict the deployment and operation of millions if not billions of unlicensed devices in the band. The combination of this vast number of devices, the bandwidth of their operation, the duty cycle of their transmissions and that most will not be identifiable or controllable after sale make harmful interference a virtual certainty.”

Such interference, EEI said, “can lead to power outages, wildfires and other potential disasters.”

The Houston metropolitan area has 520 point-to-point microwave sites in the U-NII-5 and U-NII-7 sub-bands. | *Roberson and Associates*

It said the commission should form a stakeholder group including utilities to respond to interference and that AFC should be more widely required.

But even AFC is not a panacea, the utilities’ study said. “AFC cannot control interference from indoor RLANs [radio local area networks] in central Houston without degenerating to complete exclusion of the entire U-NII-5 and U-NII-7” sub-bands, which comprises most of the 6-GHz band.

April 23, 2020

MISO Extends COVID-19 Measures

MISO will extend its COVID-19 response measures of holding virtual stakeholder meetings and restricting access to control rooms to at least June 1, RTO executives announced Tuesday.

Additionally, the next quarterly MISO Board Week — originally scheduled for June 16-18 in Milwaukee — will also take place via teleconference. The RTO’s Advisory Committee is currently looking for ways to improve experiences during teleconferences and afford all stakeholders an opportunity to speak.

“What happens after June 1 is currently under discussion,” Vice President of System Planning Jennifer Curran said during an Informational Forum conference call.

The pandemic “hasn’t distracted us from reliable operations,” Curran added.

“The last time we held an Informational Forum, we were just learning about COVID-19,” CEO John Bear said, adding that no one in January could have anticipated how much the coronavirus would impact business operations and individuals’ lives.

Bear said day-ahead load forecasts remain difficult to pin down and that MISO is evaluating the possible impacts of continued outage deferrals. (See COVID-19 Transforming MISO Load, Outage Schedules.) Utilities have so far shifted about 18 GW of generation outages to later dates in response to the pandemic.

MISO has also explored the possibility of sequestering its essential control room employees to protect their health.

“We’ve decided not to sequester at this time,” Curran said, adding that the RTO relied on risk analyses from epidemiologists in deciding against that measure for the time being.

MISO began physical separation of its staff on March 9, with all non-control room staff working virtually.

Curran said it’s difficult to predict when employees will be able to return to on-site work, adding that it would undoubtedly occur “in phases” and depend on the availability of testing. She said MISO’s return to normal business operations involves “risks and tradeoffs.”

MISO COVID-19 — MISO March load and price comparisons | *MISO*

“I think the new normal will look different than the old normal,” Curran said.

With most of MISO’s 15 states under lockdown orders, load is down about 10% relative to historically normal conditions. Eleven states in the footprint are currently under explicit lockdown orders, compared with eight at the end of March.

MISO in late March began seeing loads down about 7% compared to normal conditions, Executive Director of Market Operations and Resource Adequacy Shawn McFarlane said.

“The past two weeks have been pretty close to 10%. We may have bottomed out depending on further developments,” McFarlane said. “I feel like we’re in a steady state unless something else changes.”

MISO experienced an 80-GW peak in March, down 18 GW from 2019. It has said that some of the load decline can be attributed to higher temperatures this year.

Energy prices in March fell more sharply than load, with real-time LMPs averaging $18/MWh for the month compared with $26/MWh a year earlier. MISO said the more than 30% drop can be chalked up to falling natural gas prices and reduced load stemming from the stay-at-home orders.

MISO Now Displaying Self-commitment Data

MISO has begun publicly displaying information about must-run resources in response to concerns about self-commitment of coal plants, a practice that some in the industry criticize as expensive and inefficient. (See Enviros, States Question Coal Self-commitments.)

The RTO has added self-commitment data to its monthly operations reports, including both monthly and 13-month charts to presentations.

MISO executives said the data were requested by stakeholders and will be broken down by category: economically committed and economically dispatched by the RTO; self-committed and economically dispatched; and self-committed and non-economically dispatched.

In March, MISO reported 14 TWh of economically committed and economically dispatched self-committed coal and gas generation; 17 TWh of self-committed and economically dispatched generation; and 12 TWh of self-committed and non-economically dispatched generation.

Independent Market Monitor David Patton said his group continues to evaluate must-run patterns of behavior in MISO, though he’s not “nearly as concerned as others” about the issue. He said MISO resources “are being offered economically more often and more frequently not being scheduled day-ahead.”

Patton said must-run designations are being used less frequently. When they are used, it’s to prevent units from cycling uneconomically.

“It’s rational not to give MISO the opportunity to shut them down when their cycle is eight to nine days,” Patton told executives and stakeholders in March during a winter operations review.

“I think the concern that has jumped up recently is disproportionate compared to what it is. … We don’t see the same concern as we monitor the operation of these units,” Patton said.

A few years ago, coal resources provided more than half of all MISO’s energy, compared with about a third today. Patton said coal resources tend to set prices at night, while natural gas resources set them during the day.

April 23, 2020

PG&E CEO Johnson Says He’ll Step Down

PG&E Corp. CEO Bill Johnson announced Wednesday he would retire at the end of June, by which time the utility is hoping to exit bankruptcy.

The news came after most of the major obstacles to PG&E’s Chapter 11 reorganization plan appeared to have fallen by the wayside. The only significant issue the utility faces now is how tens of thousands of wildfire victims will vote on its restructuring proposal.

PG&E Bill Johnson — PG&E CEO Bill Johnson testifies before the U.S. House of Representatives’ Committee on Energy and Commerce on Jan. 28.

“I joined PG&E to help get the company out of bankruptcy and stabilize operations. By the end of June, I expect that both of these goals will have been met,” Johnson, 66, said in a news release. “As we look to PG&E’s next chapter, this great company should be led by someone who has the time and career trajectory ahead of them to ensure that it fulfills its promise to reimagine itself as a new utility and deliver the safe and reliable service that its customers and communities expect and deserve.”

The utility said Bill Smith, a retired AT&T executive and current PG&E board member, will serve as interim CEO after Johnson’s departure and until a new chief executive is appointed.

Andrew Vesey, CEO of Pacific Gas and Electric, the primary utility subsidiary of PG&E, will continue in his role, PG&E said.

“Mr. Johnson’s resignation … does not involve any disagreement on any matter relating to PG&E Corp.’s or the utility’s operations, policies or practices,” the company said in a filing Wednesday with the U.S. Securities and Exchange Commission.

Johnson’s Tenure

Johnson, the former head of the Tennessee Valley Authority, joined PG&E on May 1, 2019, with a mandate to lead the company out of the bankruptcy it had entered 15 weeks before. He replaced former CEO Geisha Williams, who led the company during the worst of its fires and stepped down in January 2019.

Johnson served for six years as head of TVA, the federally owned electricity supplier in the Southeastern U.S. He was previously president of Progress Energy, which merged with Duke Energy in 2012. Johnson served as CEO of Duke for less than a day before leaving with a $44 million severance package, according to news reports at the time.

His compensation at PG&E has included a $2.5 million base salary, a one-time transition payment of $3 million and an annual equity award with a target of $3.5 million.

He also received performance-based stock options that could become valuable if PG&E’s stock price increases to more than $25/share in the next four years, according to PG&E’s 2019 proxy statement filed with the SEC. If PG&E stock were to return to its prior worth of roughly $47 to $70/share, he could make tens of millions of dollars by exercising his options.

PG&E also said Wednesday it would release its first-quarter earnings report on May 1 before the market opens and will host an earnings call with financial analysts.

The company’s stock has been on a roller coaster since Johnson took the reins, based largely on news of how PG&E was faring in its fight to exit bankruptcy.

The stock fell as low as $5/share on Oct. 25, 2019, as a wildfire its equipment was suspected of starting burned through Sonoma County wine country, and the company instituted massive blackouts throughout Northern and Central California to prevent additional fires. Johnson bore the brunt of heavy criticism from the public and elected officials over the blackouts. (See PG&E Stock Plummets amid Wildfires, Shutoffs.)

PG&E stock rose to nearly $24/share last June, after California Gov. Gavin Newsom pitched a plan to insure PG&E and other utilities against wildfire liabilities going forward. PG&E is trying to exit bankruptcy by June 30 to participate in the $21 billion insurance fund under the terms of last year’s Assembly Bill 1054. The program will be paid for equally by ratepayers and utilities.

PG&E’s stock price stood at exactly $11/share at 4 p.m. ET Wednesday, having fallen precipitously since the COVID-19 pandemic-induced economic slowdown took hold in late March. The stock price has been buoyed in recent weeks by developments indicating PG&E is on track to leave bankruptcy by June 30.

Obstacles Falling

Newsom, who had been an outspoken critic of PG&E and repeatedly threatened a state takeover of the utility, withdrew his objections to PG&E’s restructuring proposal, provided it wraps up its Chapter 11 proceedings by the end of June. PG&E and the governor signed an agreement in mid-March creating a streamlined process for the state to buy the utility if it doesn’t leave bankruptcy by June 30. (See PG&E Deal with Gov. Allows for Utility’s Sale.)

On Monday, the California Public Utilities Commission, which must approve PG&E’s reorganization plan, suggested it would accept the plan with some adjustments. A proposed decision by an administrative law judge incorporates a program of enhanced oversight and enforcement for PG&E first proposed by CPUC President Marybel Batjer. PG&E has already agreed to most of Batjer’s terms.

Also on Monday, Commissioner Clifford Rechtschaffen contended the CPUC should raise its penalty against PG&E to nearly $2 billion — the largest fine the commission has ever levied — for its role in starting the catastrophic wildfires of 2017 and 2018.

The fires included the massively destructive North Bay, or wine country, wildfires of October 2017 and the Camp Fire, which killed 85 people and leveled much of the town of Paradise.

PG&E filed for bankruptcy in January 2019 in the aftermath of those fires.

Rechtschaffen’s proposal would modify a prior settlement agreement between PG&E and the CPUC’s Safety Enforcement Division, effectively “increasing the penalty amount in the settlement by $262 million because of the strong evidence of pervasive violations and unprecedented harm, including loss of life, that resulted from the wildfires,” the CPUC said in a news release.

The CPUC noted that PG&E agreed to plead guilty last month to 84 counts of involuntary manslaughter from the Camp Fire, the deadliest wildland blaze in state history. The utility reached an agreement with prosecutors to pay nearly $4 million in fines and costs related to the fire. (See Judge: PG&E Can’t Pay Criminal Fines from Victim Trust.)

The commission will take up PG&E’s reorganization plan and Rechtschaffen’s proposed penalty at its May 21 voting meeting.

If the CPUC approves the plan, and PG&E accepts the increased fine, it would leave the federal bankruptcy court in San Francisco as the company’s major remaining obstacle. U.S. Bankruptcy Judge Dennis Montali has said he wants PG&E to meet the June 30 deadline, but he has refused before to take steps against the wishes of wildfire victims.

Those victims — about 70,000 to 80,000 — are among the 250,000 creditors and interested parties who must vote on PG&E’s bankruptcy plan by May 15.

Some victims have argued against the proposal. PG&E intends to fund a $13.5 billion trust for wildfire victims with half cash and half stock, and victims worry about the company’s stock declining in value with no guarantee of its worth at the time of dispersal. They also argue the restructuring provides insufficient assurance that PG&E won’t be a “killer company” in the future.

Whether those encouraging a “no” vote can sway enough of their fellow victims to defeat the plan remains to be seen.

April 23, 2020

NextEra Plans to Combine FPL, Gulf Power Utilities

NextEra Energy said Wednesday that it will combine its two Florida utilities into a single entity that will stretch from the Panhandle to Miami Beach.

During its first-quarter earnings call, Florida-based NextEra said it has filed with the Public Service Commission to reflect the expectation that Florida Power & Light and Gulf Power will begin to operate as an integrated system in 2022. The utilities plan to file a combined rate case in the first quarter of 2021 for new rates that begin in 2022, NextEra said.

In its earnings release, NextEra said, “The companies expect that a merger will create both operational and financial benefits for customers.”

NextEra Energy plans to merge its Gulf Power and Florida Power & Light utilities. | *NextEra Energy*

FPL serves more than 5 million customer accounts along Florida’s Atlantic coast and is the nation’s largest rate-regulated electric utility, as measured by retail electricity produced and sold. Pensacola-based Gulf Power has more than 460,000 customers. NextEra struck a $6.5 billion deal with Southern Power in 2018 to acquire the utility. (See FERC Approves NextEra’s Gulf Power Acquisition.)

The companies filed a “Ten Year Site Plan” that projects an approximately 70% increase in zero-emission electricity that is generated in 2029, relative to 2019, largely through solar power. NextEra said FPL expects to have more than 10 GW of installed solar capacity, including nearly 1.6 GW within the current Gulf Power service territory, by the end of the decade.

CEO Jim Robo said FPL has six new solar energy centers operating, with four more scheduled to enter service in May. The 10 solar centers, FPL said, represent 745 MW of new capacity.

NextEra plans to connect the two systems with a new 161-kV transmission line. According to the PSC filing, the project will be completed before 2022.

The company’s first-quarter earnings surpassed expectations. NextEra reported earnings of $421 million ($0.86/share), compared to $680 million ($1.41/share) for the first quarter of 2019.

When adjusted for nonqualifying hedges, net investment gains and other impairments, and profit from disposal of a business, NextEra’s earnings were $2.38/share. Analysts polled by Zacks Investment Research had projected adjusted earnings of $2.21/share.

NextEra said it continues to expect year-end adjusted earnings of $8.70 to $9.20/share.

“While our expectations always assume normal weather and operating conditions, I have confidence in our ability to meet these expectations even when accounting for a reasonable range of impacts and outcomes that may result from the COVID-19 pandemic,” Robo said.

Robo did not address recent market rumors about an acquisition of Kansas City-based Evergy. (See NextEra Said to be Eyeing Evergy as Acquisition Target.)

Asked about another target, South Carolina’s state-run Santee Cooper utility, which the state’s governor has called a “rogue agency,” Robo said state lawmakers are in a budget standoff over the utility’s “hotly debated” sale.

“By no means is Santee Cooper done. There remains a lot of energy still behind wanting to sell Santee Cooper,” Robo said.

NextEra’s share price gained $11.75 on Wednesday, closing at $247.17 as Wall Street stopped a two-day slide.