Page 1125 – RTO Insider

March 20, 2020

ERCOT, SPP Adapt to ‘New Normal’ in Pandemic

By Tom Kleckner

When ERCOT this week instituted mandatory work-from-home requirements for staff that do not need to be in the office to handle their job responsibilities, spokesperson Leslie Sopko quickly encountered one of the major distractions of working from home: children.

“They followed me everywhere,” she said Wednesday — with a laugh — of her daughters, 7 and 4. The oldest was home from school, the youngest from daycare.

Sopko spoke from the safety of her back porch, where, armed with her laptop and cell phone, she said she could see her trees and the setting sun. It had been a day packed with responding to media inquiries and joining conference calls determining the next steps to respond to the coronavirus disease (COVID-19).

Besides ensuring employees and contractors have the proper tools and resources to do their jobs, either at ERCOT facilities or from home, the grid operator has been using a wide array of communication channels to reach staff. An internal newsletter is constantly updated with new information stressing caution and offering tips on working from home, social distancing and well-being. CEO Bill Magness has sent several well-received messages of encouragement and comfort.

ERCOT SPP pandemic — An ERCOT operator monitors the grid in the Operations Center. | © *RTO Insider*

“We’re definitely taking as many precautionary steps as we can to keep our staff healthy and safe,” Sopko said. “We’ve been very consistent with our communications … We have received positive feedback that they do feel informed. We know we provide a critical function, and we’re dedicated to maintaining the grid’s reliability.”

On Tuesday, ERCOT iss u ed “Pandemic Plan Preparations for Coronavirus (COVID-19),” which listed the steps it has taken to protect employees and ensure it continues to manage the grid. The plan also included a link to a redacted v e rsion of its pandemic preparedness plan.

The ISO has closed its facilities to most outside visitors since March 3, instituting travel restrictions for staff and canceling in-person meetings. Staff that need to be on-site must be on a pre-determined list and undergo temperature screenings when reporting for work. Even then, they are expected to maintain social distancing as much as possible.

Sopko said she is not aware of any confirmed cases of the virus among staff.

She said it is too early to see any change in the ISO’s load patterns, as school and business closures have only recently begun. On Thursday, Texas Gov. Greg Abbott issued an executive order that will close schools, restaurants, bars and gyms as COVID-19 continues to spread.

“We need some time to trend the data,” Sopko said of potential changes in ERCOT’s load patterns. “We need things to settle into the new normal, if you will.”

The grid operator will announce any changes to the summer peak load forecast when it releases the summer’s final resource adequacy assessment in May.

SPP Protects Operations Staff

SPP is taking similar proactive measures, “strongly encouraging” staff to work from home if they are able and scrubbing in-person meetings through April. The RTO has closed its gates and doors to all but mail and other deliveries, as well as maintenance work — and only if visitors have been screened by security.

“Pretty much everyone is working from home,” said David Kelley, director of seams and market design, during a conference call Thursday with the Western Markets Executive Committee.

Spokesperson Derek Wingfield said the RTO’s emergency management team meets daily, “constantly monitoring and assessing” the situation. He said the current requirements could be extended if necessary.

To protect SPP’s operations and dispatch staff, all but essential traffic between the operations center and the corporate building has been prohibited, Wingfield said. The ISO has also shifted some of its operations staff to its backup operations center, 17 miles from the corporate center.

“It allows a little more distance,” Wingfield said.

Whether any staff had contracted the virus, he was unable to say with any certainty, pointing to the beginning of the allergy season.

SPP said RTOs could see “new and evolving patterns of energy use” as the coronavirus continues to spread. However, it has not yet seen a “discernable difference” in load within its footprint.

“SPP continues to closely monitor the situation as it develops, and we are confident in our ability to reliably manage the operation of the bulk electric system,” spokesperson Meghan Sever said in an email.

March 20, 2020

Memphis Muni Mulls Move to MISO

By Amanda Durish Cook

Memphis Light, Gas and Water is mulling whether to defect from the Tennessee Valley Authority to acquire power from MISO or another wholesale supplier.

A decision could come as early as this spring.

MLGW spokesperson Angelika Taylor confirmed that the utility is weighing an exit from TVA for another supplier for economic reasons.

“We are doing an integrated resource plan to determine the optimal electricity-producing resource mix to provide MLGW customers and our community with reliable, low-cost power as we consider whether or not to discontinue being a wholesale customer of TVA,” Taylor said in an email to RTO Insider.

The municipal utility’s I R P is scheduled to be completed by May, though Taylor warned that the spread of COVID-19 could delay that schedule. The city’s elected officials are expected to decide on the plan sometime this year.

Their decision could allow MISO to add another state to its 13-state footprint. As a rule, MISO does not reveal the names of utilities and companies that approach it for membership until its board of directors vote on approval during one of its public meetings.

MLGW’s move makes sense to environmental nonprofit Friends of the Earth (FOE), which for two years has urged the utility to pursue an alternative to TVA.

FOE commissioned The Brattle Group to prepare an analy s is, released in September, that finds MLGW could save anywhere from $240 to $333 million per year by 2024 if it accesses lower-cost power across the Mississippi River and builds at least 350 MW or more of its own renewable generation.

“Certainly in our analysis, and the work that The Brattle Group has done for us, MISO is right at the top” as an alternative supplier option, said FOE attorney Herman Morris, Jr., also a former MLGW CEO.

MLGW has a few options as it crafts its IRP: Attempt to join MISO or another wholesale power supplier, produce its own power or undertake a combination of the two. The utility doesn’t currently generate any of its own power.

Another less probable option would involve sales from the embattled and unfinished Bellefonte Nuclear Power Plant in Alabama. Former Chattanooga developer Franklin L. Haney is trying to finalize the purch a se of the plant from TVA, which contends he lacks the proper permitting. The dispute will likely head to trial this year.

‘Really Significant’ Savings

“From at least the Friends of the Earth perspective, all alternatives are preferable for the potential for new green and renewable sources as well as reliability and lower cost,” Morris told RTO Insider. “It’s certainly my personal view that MISO is a more than viable option … They serve a lot of capacity, and they’re reliable, greener and a whole lot cheaper than TVA. My sense is we’ll probably see some combination of self-generation and purchases of power from across the river, somewhere, somehow.”

Morris said TVA’s wholesale power costs about 7.5-8 cents/kWh versus the 4-4.5 cents/kWh that MISO offers.

“It’s simply hard to overcome the math in these things. That’s not just significant, that’s really significant. You can go a long way with savings of $300 million a year,” Morris said.

Some of MLGW’s savings from switching suppliers could be spent on the construction of its own renewable generation and to defray the cost of connection to the MISO system, Morris said.

“Interest rates are so low, especially now. It just can be done,” he said.

“As large as [MISO] is, there’s a river between us. There’s not a great understanding by people on our side of the river of who MISO is,” Morris said. “[FOE] is not trying to promote MISO so much as we’re trying to educate the community as to what its options are. What we want to see is a fact-driven discussion: Is it possible to get a wholesale supplier less expensive than TVA? Is it possible to create a greener portfolio? We want to put these in front of community leaders and have them make a decision.”

TVA’s current generation portfo l io consists of 37% nuclear, 24% coal, 20% natural gas, 9% hydro, 7% energy efficiency and 3% wind and solar generation, with a total capacity of about 35 GW. Peak load can reach 32 GW, and MLGW accounts for about 10% of TVA load. TVA sometimes purchases power from MISO.

“When you’ve got a fleet of old coal plants, many of which are supplied by Kentucky and West Virginia coal fields in the valley, and you’ve got 50-plus-year-old nuclear generation, you can’t turn that on a dime. You can’t say, ‘we’re going to be this next year,’” Morris said.

Majority in Favor

Last year, TVA’s board of directors approved an integr a ted resource plan that adds 14 GW of new solar generation, 5.3 GW of energy storage and up to 2.2 GW of energy efficiency savings by 2038. The plan also includes between 2 and 17 GW of new natural gas generation. TVA also has plans to retire its Paradise and Bull Run coal plants in 2020 and 2023, respectively.

Morris points out that about a third of Memphis residents live at or below the poverty line. “It’s important for people at the bottom economic rung that we are prudent and judicious in selecting our supplier. We believe that by having a more economical source of wholesale power, we can save this community close to a million dollars a day.”

He said there’s popular support in Memphis for getting cheaper and cleaner energy, especially considering that TVA generation and transmission costs comprise about 80% of customers’ residential electric bills.

“Right now, if you’re in the TVA valley, TVA sells you 100% of your power. And that’s it. It’s an all-requirements contract. And that’s probably made them a little less energetic — no pun intended — and more willing to ride these coal and nuclear plants to the bitter end,” Morris said. He also questioned the societal cost of TVA’s coal ash and spent nuclear rods.

The reduction in load from a MLGW exit could make it easier for TVA to consider speeding up retirement of some of its aging, inefficient plants, Morris added.

He estimates it would take at least five years for MLGW to make the transition from a non-generator to a modest generator for some of its load. He also noted that an exit from TVA would involve negotiations.

“There might be some legal issues to parse through, but we think the philosophy of the industry — and FERC — is strongly supportive of communities getting the best-cost supplier they can find.”

FOE this month conducted a p o ll that found 57% of Memphis residents would like to see MLGW leave TVA, with 20% opposed to such a move.

“The most important thing for this community is to identify a cheaper, more economical and greener source of wholesale power, and MISO is all of those things,” Morris said. “There is a robust voice from environmentally-conscious citizens in our community. I think whatever the outcome is, it will have to involve some element of renewable, clean, green supply.”

March 20, 2020

BlueIndy Pulls Plug on EV Rideshare Service

By Amanda Durish Cook

Marketed as an eco-friendly alternative to car ownership, Indianapolis’ BlueIndy electric vehicle rideshare service will cut the engine and go out of business this spring.

After four years of providing shared EVs, French owner Bolloré Logistics will end BlueIndy’s operations May 21, leaving city leadership to decide whether to purchase the company’s assets.

BlueIndy said it “did not reach the level of activity required to be economically viable,” reporting that it attracted about 11,000 members who took about 180,000 rides over the ride-sharing service’s existence.

BlueIndy EVs — One of 90 BlueIndy charging stations across Indianapolis | © *RTO Insider*

Complicating matters, BlueIndy indefinitely suspended the service beginning this week in response to the spreading COVID-19 pandemic in Indianapolis.

“We thank you for your understanding and hope to be able to restore service as soon as the situation permits. Let us remain united and responsible,” BlueIndy’s homepage read.

It remains to be seen whether customers will ever again have the chance to drive a BlueIndy car.

Wrong Market?

BlueIndy had bestowed the Indiana capitol with the distinction of the largest network of public charging stations of any U.S. city. However, critics from the start said the service only makes sense in a higher-density city with a smaller geography — not Indianapolis’ nearly 880,000 inhabitants spread over 372 square miles. Bolloré Logistics spun off a Los Angeles version of the service — Bl u eLA — in partnership with the Los Angeles Department of Transportation. The sister rideshare remains open though operations there are also suspended due to COVID-19.

“Indianapolis drivers have been slow to adopt alternative transportation options and car ownership remains extremely high,” BlueIndy explained in a late 2019 press release.

Now Indianapolis is weighing whether it should purchase the approximately 90 EV charging stations scattered on public rights-of-way throughout the city. BlueIndy originally anticipated owning as many as 500 cars and up to 200 stations in the city.

“Leading up to [May 21], we will be having conversations with neighbors, corporate partners and personal mobility advocates to explore whether financially sustainable options exist that would allow us to put the existing infrastructure to use — either with another ride sharing program or as charging stations for electric vehicles,” City of Indianapolis Deputy Chief of Staff Taylor Schaffer said in an email to RTO Insider.

Schaffer said Indianapolis’ 15-year contract with Bolloré Logistics stipulates the city can notify the company it would like to purchase the infrastructure at any point within 90 days of the contract’s end.

“This means the city has until mid-August to decide whether to purchase the infrastructure or not,” Schaffer said.

Schaffer did not comment on a possible purchase price for the assets, though the city has previously said it has the option to appraise and negotiate a fair market value.

BlueIndy got off to a rocky start in 2016 when the Indianapolis City-County Council contended that Bolloré Logistics’ process for placing stations lacked transparency. (See BlueIndy EV Sharing Program Seeks Re b ound.) As a result of negotiations, BlueIndy paid the city an annual $45,000 franchise fee meant to cover the loss of parking meter payments due to the curbside stations.

The project was slated to cost a total of $50 million, with the company investing $41 million, the city contributing $6 million and Indianapolis Power & Light Co. ratepayers covering the remaining $3 million.

In 2017, BlueIndy show e d a $22.5-million deficit. The company has not released recent financial standings.

Indianapolis’ former Republican Mayor Greg Ballard called the service a “clean, affordable transit option to help connect visitors and residents with all that Indy has to offer” when the collaboration was announced in 2015.

It’s unclear how much BlueIndy was affected by IndyGo’s new rapid transit electric bus line, which opened its first route last year along many of BlueIndy’s curbside electric charging stations.

Multiple requests to interview remaining BlueIndy employees went unanswered. BlueIndy Managing Director James Delgado appeared to stop tweeti n g about the service in early 2019.

“We believe that the continued reliance and predominant use of traditional personal vehicles is not sustainable long term in a growing urban environment and the need for additional mobility options to complement operators in Indianapolis including BlueIndy, IndyGo and the Pacers Bikeshare is significant,” BlueIndy said last year.

March 20, 2020

NYISO BIC Briefs: March 19, 2020

The Business Issues Committee on Wednesday approved additional Tariff language for the energy storage resource (ESR) participation model to address issues identified during software development for the ESR project.

The language spells out details regarding day-ahead margin assurance payments (DAMAP); the method for setting feasible day-ahead and real-time schedules; generator offer caps, mitigation and reference levels; and installed capacity (ICAP) supplier bidding requirements.

The revisions to MST Section 25 Attach m e nt J clarify which of the two energy contribution formulas will apply to ESR schedule changes.

A portion of the attachment that applies to fast-start units also will be revised to specify that those units that increase their minimum generation bids in real-time will not be eligible for DAMAP, consistent with Tariff rules that apply to increasing incremental energy bids or start-up bids in real-time.

The ISO also is revising MST 4.4.2.1 to support the market software used to ensure feasible real-time schedules for ESRs.

The ISO’s real-time dispatch software will account for the energy level of all ESRs to prevent infeasible dispatch of both self-managed and ISO-managed resources. The ISO’s original Order 841 compliance filing stated that the software will reduce the ESR’s upper operating limit (UOL) or increase its lower operating limit (LOL) as needed to produce a feasible schedule. But during the software development, the ISO realized such adjustments are unnecessary and may be inefficient. (See FERC Partially Accepts NYISO Storage Compli a nce.)

Under the change, the software will determine feasible real-time schedules based on an ESR’s actual telemetered energy storage level.

The offer price capping logic in MST 23.7.2 will be revised so that offers to withdraw energy are capped at the lowest of the energy offer, the price allowed by the current capping logic or the price needed to account for the unit’s round-trip efficiency. The ISO said the change will prevent performance issues with security-constrained unit commitment (SCUC), real-time commitment (RTC) and real-time dispatch (RTD).

The current price capping logic will continue to be applied if a unit’s energy offer does not cross zero and will be applied to all energy segments that are greater than zero.

Revisions to MST 23.4.2.2 will allow adjustments to the mitigation of an ESR’s incremental energy curve if needed to account for the ESR’s round-trip efficiency.

Revisions to Section 23.1.4.3 will exempt ESRs from requiring a new unit reference level, specifying that they should be calculated using cost-based reference levels. “New unit reference levels are based on historical LBMPs and would not be representative of ESRs’ costs or operating parameters such as round-trip efficiency,” the ISO said in a pres e ntation.

The ISO had proposed that ESR ICAP suppliers have a day-ahead market (DAM) bid/schedule/notify (B/S/N) obligation equal to the ICAP equivalent of unforced capacity (UCAP) sold, like other ICAP suppliers.

After making its Order 841 compliance filings in December 2018 and May 2019, the ISO realized that when an ESR uses the ISO-managed energy level bidding parameter and enters the DAM with an energy level insufficient to satisfy its obligation, the ESR could submit bids to inject energy that appear to satisfy the B/S/N commitment, but that would not provide the ISO with all the promised energy.

NYISO is proposing that all ESR ICAP suppliers must B/S/N the full range of the ESR, including both the ISO- and self-managed energy level bidding parameters.

The ISO said the language is needed to “harmonize” the physical and operating characteristics of ESRs with the purpose of the existing B/S/N requirements: to either make the energy backing the ICAP supplier’s capacity available or notify the ISO that the capacity is unavailable so the NYISO can respond to maintain reliability. “Without the proposed requirement for an ESR, an ESR could meet its Tariff obligation and yet not make that energy available, which is inconsistent with the purpose of the requirement,” the ISO said.

Failing to reflect an ESR’s anticipated charging in the DAM “could cause reliability issues in real-time by not having enough resources committed from the DAM to meet actual load, reserves, and the ESRs’ charging,” the ISO said.

The ISO will bring the Tariff modifications to the March Management Committee meeting and hopes to make them effective with its other Order 841 compliance changes, no later than Sept. 30.

BIC OKs BTM:NG Revisions to Load Forecasting Manual

The BIC also approved the first revisions since 2013 to the Load Forecasting Manual, reflecting the impact of behind-the-meter net generation (BTM:NG) in the installed capacity market forecast. A BTM:NG is a BTM generator that has excess capability after serving its host load at the same location.

If a BTM:NG resource does not require power to serve load from the hour of the NYISO or locality peak, the load of the resource will not be included in the actual and weather-adjusted load in the transmission district (TD).

If the resource does require power, its load will be deducted from the TD’s actual load and weather-adjusted load.

The forecast load of a BTM:NG resource will be based on a weather adjustment of its actual load, a projection of the load’s losses and a growth rate “consistent with” that of the transmission district in which it is located, the ISO said.

“This is a little different than other loads … We normalize [transmission district loads] as a whole. But we recognize that BTM:NG might have load characteristics much different than the average load in the area,” explained engineer Arthur Maniaci, the ISO’s principal forecaster.

The ISO said the changes will reflect the specific weather response of each resource and is consistent with the Tariff and ICAP Manual, using the top 20 hours of each resource from within the top 40 New York Control Area hours during summer. It also mirrors current NYISO demand response processes.

The changes were developed by the Load Forecasting Task Force in 2018 and 2019 and modified after feedback from the ICAP Working Group last year.

Working During the Coronavirus Pandemic

Several stakeholders had questions about the impact of the coronavirus pandemic on ISO operations.

Mark Seibert, manager of the Member Relations team, said the ISO will provide a secondary call-in number for meetings because of heavy loads on remote meeting services that resulted in some stakeholders getting busy signals in attempting to listen to the BIC meeting.

NYISO’s Member Relations team: (from left) Selina Dean, Leigh Bullock, Kirk Dixon, team manager Mark Seibert, Debbie Eckels and Jennifer Davies. | *NYISO*

He also said that ISO staff who interact with stakeholders were directed to forward their work phones to their cell phones to remain accessible while working from home. Stakeholders should contact Seibert or Debbie Eckels in the Member Relations team if they have difficulty reaching an ISO official, he said.

Mike DeSocio, director of market design, said ISO employees are able to access the grid operator’s software systems remotely to allow continuity of operations. “Folks are able to get into the systems they need to get into and perform the work they need to perform, so we don’t expect any issues there,” he said.

— Rich Heidorn Jr.

March 19, 2020

FERC, NERC Relax Compliance in Light of COVID-19

By Holden Mann

FERC and NERC are working to ease the compliance burden on utilities grappling with the impact of the COVID-19 outbreak, the organizations announced Wednesday.

In a press release, FERC and NERC said they “are using regulatory discretion” to address the difficulties registered entities may have with complying with reliability standards as follows:

Regional entities will consider the impacts of the coronavirus an acceptable reason for the inability to obtain and maintain personnel certification for the period of March 1 through Dec. 31, 2020. Registered entities are advised to notify their REs if they are using system operator personnel that are not NERC-certified.
Failure to perform periodic actions required by reliability standards will be accepted on a case-by-case basis between March 1 and July 31, 2020. REs should be notified of any periodic actions that will be missed during this period.
REs will postpone on-site activities, including audits and certifications, until at least July 31, 2020. Registered entities should notify REs of any resource impacts associated with remote activities.

While these are the only specific measures announced so far, the organizations said they will “continue to evaluate the situation” to see if any updates are needed in light of the uncertain trajectory of the pandemic.

FERC NERC COVID-19 — NERC’s office in Washington, D.C. | © *ERO Insider*

The announcement follows NERC’s issuance of a Lev e l 2 Alert on March 10 and comes as organizations across the ERO Enterprise develop their own policies to reduce the risks of exposure by staff and stakeholders. Last week, the Western Electricity Coordinating Council joined other REs in canceling all in-person gatherings during the pandemic and holding only webinars and teleconferences. (See Coronavirus, Cybersecurity Top WECC Board Discus s ion.)

NERC has been working with the industry to provide advice and information about the coronavirus, including publishing a document titled Assessing and Mitigating the Novel Coronavirus (COVID-19) on the Electricity Subsector Coordinating Council’s website. Internally, the organization has activated its Business Continuity Plan and is reviewing its meeting schedule on a case-by-case basis. The majority of its upcoming meetings have been shifted to conference calls or video conferences in light of safety recommendations from global health authorities and travel restrictions by many stakeholders.

According to the World Health Organization’s latest situati o n report, more than 191,000 coronavirus infections have been confirmed worldwide since the disease was first reported in Wuhan, China. More than 7,800 deaths have been directly attributed to the virus globally.

March 19, 2020

FERC OKs PJM TOs’ Critical Tx Process

By Rich Heidorn Jr. and Michael Yoder

FERC on Tuesday approved the PJM Transmission Owners’ critical infrastructure mitigation plan, the subject of several months of contentious debates over complaints that it lacks transparency and improperly restricts input by stakeholders and the RTO (ER20-841).

The TOs’ plan, which details a confidential process for removing critical transmission infrastructure from NERC’s critical infrastructure protection (CIP-014) list, became Attachment M-4 to the PJM Tariff, effective March 17. Attachment M-4 allows for consultation with PJM and the affected state commissions regarding CIP-014 Mitigation Projects, including discussion of siting issues and the estimated costs of a project, subject to confidentiality safeguards.

“The proposed revisions provide a just and reasonable approach to planning CIP-014 Mitigation Projects that appropriately balances the need to maintain strict confidentiality regarding the names, locations and vulnerabilities of CIP-014-2 facilities with stakeholders’ interests in transparency regarding the PJM Transmission Owners’ planning of these projects,” FERC said.

NERC requires TOs to protect CIP-014 assets, whose loss or sabotage could result in widespread instability, uncontrolled separation or cascading outages. Incumbent TOs say their proposal will harden these facilities — of which fewer than 20 exist within PJM’s footprint — and get them off the list, improving reliability for everyone. But other sectors remain in the dark about most of the plan’s details, including which assets are involved and how much it will cost.

PJM critical transmission — PJM backbone transmission system | *PJM*

Consumer advocates, industrial customers and state regulators asked FERC to reject the plan while trade groups WIRES and Edison Electric Institute called for approval. State consumer advocates were particularly upset that PJM endorsed the plan in a FERC fili n g despite a stakeholder resolution at the January Members Committee meeting arguing that the proposal conflicts with the RTO’s Operating Agreement. (See PJM Supports TO Critical Tx P lan.)

FERC disagreed, saying CIP-014 Mitigation Projects are a “a subset of Supplemental Projects and therefore are appropriately planned by the PJM Transmission Owners, rather than PJM.

“In interpreting the Operating Agreement, the question is not, as protestors argue, whether a CIP-014 Mitigation Project offers a reliability benefit by removing a facility from the CIP-014-2 critical facility list, but rather whether the project is required by PJM planning criteria,” the commission said. “PJM confirms, in its supporting comments, that there are no PJM planning criteria in the Operating Agreement that would allow PJM to plan CIP-014 Mitigation Projects through its RTEP [Regional Transmission Expansion Process] process, and therefore CIP-014 Mitigation Projects can be developed only as Supplemental Projects.

“Similarly, we disagree with protestors’ arguments that PJM should implement competitive bidding procedures for CIP-014 Mitigation Projects,” FERC added. “Supplemental Projects are not part of the RTEP process and thus are not part of the competitive window process.”

Cost Allocation, Transparency Provisions Upheld

The commission also rejected challenges to the cost allocation of M-4 projects as beyond the scope of the proceeding.

“Although protestors raise concerns regarding the potential for double-recovery, unjustified project costs and a lack of transparency regarding the prudency of costs incurred, we find that the currently effective cost recovery process provides sufficient safeguards against these concerns,” it said.

“We find that members of OPSI [Organization of PJM States Inc.] will receive sufficient information regarding the estimated costs related to CIP-014 Mitigation Projects. After submitting its preferred and potential solutions for a project to PJM, the Transmission Owner will seek a meeting with the relevant state commission(s). Upon completion of PJM’s review and assessment of the CIP-014 Mitigation Project ultimately selected for construction, the Transmission Owner will again seek to meet with the relevant state commission(s) to discuss … the efficiency and cost-effectiveness of any and all of PJM’s recommendations. …When public notice is provided regarding the existence of the CIP-014 Mitigation Project and cost recovery is sought, OPSI has the ability to submit a formal challenge regarding the prudency of costs associated with a CIP-014 Mitigation Project.”

FERC also rejected complaints that M-4 failed to comply with Order 890’s transparency provisions. “Order No. 890 allowed for flexibility in how the RTOs and transmission owning members meet these requirements for open, coordinated and transparent planning,” FERC said. “CIP-014 Mitigation Projects present unique concerns related to openness and transparency. The standard non-disclosure agreements upon which PJM and the PJM Transmission Owners typically rely to protect confidential information in the transmission planning process are insufficient for CIP-014 Mitigation Projects.”

Partial Dissent

FERC Commissioner Richard Glick dissented in part from the ruling, saying the mitigation projects should be planned by PJM and their costs regionally allocated because “by their very nature [they] have the potential to benefit the region as a whole.”

“In my view, the better course of action would have been for PJM to plan and allocate the costs of these projects regionally, but to create whatever procedural safeguards are appropriate in light of the need to keep these critical stations and substations confidential,” he continued.

Because the projects will be allocated only to customers in the zone in which each project is located, rather than in a manner commensurate with their benefits, Glick said, the proposal is unjust and discriminatory.

Glick cited a D.C. Circuit Court of Appeals ruling that “‘the commission generally may not single out a party for the full cost of a project, or even most of it, when the benefits of the project are diffuse.’ And yet that seems to be the most likely outcome of today’s order.”

March 19, 2020

Beaver Valley Nuclear Plant to Stay Open

By Rich Heidorn Jr. and Michael Yoder

The owners of the Beaver Valley nuclear plant have told PJM they will keep the plant in operation, citing Pennsylvania’s efforts to join the Regional Greenhouse Gas Initiative (RGGI).

FirstEnergy Solutions had filed a deactivation notice for the two-unit, 1,872-MW nuclear plant in Shippingport, Pa., in March 2018, targeting a 2021 retirement.

FES changed its name to Energy Harbor Corp. upon emerging from Chapter 11 bankruptcy last month with former bondholders owning 50% of the equity. (See FERC OKs F E S Sale to Bondholders.)

Energy Harbor CEO John Judge said Gov. Tom Wolf’s commitment to join RGGI “will begin to help level the playing field for our carbon-free nuclear generators. In addition, our retail growth strategy now offers carbon-free energy that allows customers to meet their environmental, social and sustainability goals.

“We are excited about the RGGI process implementation in early 2022 but would need to revisit deactivation if RGGI does not come to fruition as expected,” he added. Pennsylvania’s Republican-controlled legislature has challenged Wolf’s authority to enroll the state in RGGI. (See Critics: Pa. RGGI Hearing Stacked with Detract o rs.)

Beaver Valley Nuclear Plant — Beaver Valley Nuclear Power Plant

Company officials did not respond to requests for comment on the revenue impact expected from RGGI.

According to the PJM Independent Market Monitor, Beaver Valley has been profitable in all but two of the last 12 years and had a surplus of $3/MWh in 2019. The IMM projects that Beaver Valley will have a surplus of $0.91/MWh in 2020 ($13.6 million total) and $3.41/MWh in 2021 ($50.3 million).

The company said it has verbally notified the Nuclear Regulatory Commission of its rescission of the deactivations and will submit written notification within 30 days.

Beaver Valley Unit 1, which went into service in 1976, is licensed through 2036. Unit 2, which went into service in 1987, is licensed through 2047.

Energy Harbor also inherited from FES one unit at the Davis-Besse Nuclear Power Station in Oak Harbor, Ohio, and one unit at the Perry Nuclear Power Plant in Perry, Ohio. FES withdr e w its retirement notices for Davis-Besse and Perry in July after Ohio lawmakers approved legislation subsidizing the plants. (See Ohio Supreme Cour t Dismisses FES Nuke Lawsuit.)

But FERC’s order requiring PJM to apply the minimum offer price rule to the subsidized plants may jeopardize their ability to collect capacity market revenues going forward. (See related story, PJM Makes MOPR Compliance Filing.)

Perry, which began commercial operations in 1986, is licensed through 2026 but may seek a 20-year license extension. Davis-Besse, in operation since 1977, is licensed through 2037.

FES was unable to win legislative approval for subsidies in Pennsylvania.

March 19, 2020

PJM Makes MOPR Compliance Filing

By Rich Heidorn Jr.

PJM on Wednesday submitted proposed Tariff changes to comply with FERC’s controversial December order requiring expansion of the minimum offer price rule (MOPR) to new state-subsidized resources.

A quick review of the 683-page filing did not reveal any major surprises (EL16-49, ER18-1314, EL18-178). The RTO had discussed its planned compliance filing in nine stakeholder meetings since December, including two last week. (See PJM MOPR Floor Prices Reduced for Gas, Nuclear, Solar Units.)

“These issues have been the subject of rigorous review and consideration of varying stakeholder interests within the time limitations allotted by the commission for the submission of this compliance filing,” PJM said, noting that RTO officials also have communicated with state regulators and the Organization of PJM States Inc. (OPSI).

“PJM has heard and thoroughly considered the views of all stakeholders and representatives of states and, through this compliance filing, has attempted to balance all of the competing views on these various issues into a proposal … which is designed to meet the commission’s Dec. 19 order’s directives while also ensuring orderly and timely capacity auctions going forward.”

In addition to extending the MOPR to new state-subsidized resources, the rules would continue the existing MOPR on new combustion turbine and combined cycle natural gas resources.

“Where certain elements of the commission’s Dec. 19 order required additional details to support the design and application of the modified MOPR, PJM has used its best efforts to add these additional detailed elements to comply with the overarching goal of the Dec. 19 order,” the RTO said. “To provide market certainty, PJM will await commission action on this filing before implementing the modified MOPR in the next Base Residual Auction (BRA).”

Schedule

PJM asked the commission to allow at least 35 days for comments on its filing (no sooner than April 22). “Such an extension is appropriate given the volume of this filing and current circumstances,” the RTO said. “This will afford market participants sufficient time to review and comment on the proposed changes, which is necessary given the relative importance of this filing to PJM’s capacity market.”

It proposed “an orderly, but compressed” auction schedule following commission action on the compliance filing, saying it would complete all pre-auction activities and open the BRA for the 2022/23 delivery year within six-and-a-half months after the commission’s acceptance of the compliance filing. (See PJM Proposes Auction for 6 Months After FERC Ruling.)

PJM MOPR Compliance Filing — Proposed capacity auction schedule | *PJM*

“Capacity market sellers should know before they make concrete auction preparations, for example, the specific definition of a state subsidy, the details of available exemptions, the net CONE [cost of new entry] and ACR [avoidable-cost rate] screening values for the various resource categories, and the parameters of an acceptable unit-specific exception showing — just to name a few,” it said.

Exemptions

Exempted from the MOPR would be existing resources participating in state renewable portfolio standard (RPS) programs; existing demand response, energy efficiency and storage resources; and existing self-supply resources. Federal subsidies would not trigger the MOPR.

FERC’s order also provided for exemptions for resources that forego state subsidies and those that can prove through the resource-specific exception that their costs are lower than MOPR reference values.

“While FERC’s order combined exemptions for demand resource, energy efficiency resources and capacity storage resources, PJM proposes to separate out capacity storage resources as a separate categorical exemption given the distinctions with demand resources and energy efficiency resources,” the RTO said.

It said it will offer “non-binding guidance” for capacity market sellers as to whether their resources qualify as subsidized.

“PJM and the Market Monitor will work together to develop a non-exhaustive list of programs, based on information provided by capacity market sellers, that they consider to be a state subsidy and post this list in a guidance document. Given the myriad state and local programs that may exist throughout the PJM region and the fact that such programs may change over time, it would not be practical to include a list of specific state subsidies in the Tariff,” it said.

“Instead, PJM will develop and maintain, in collaboration with the Market Monitor, a list of specific state subsidies to provide guidance on many of the most common programs that may be applicable to capacity resources. Importantly, however, it is ultimately the capacity market seller’s responsibility to ensure that they correctly certify whether its capacity resource is subject to a state subsidy, irrespective of any guidance provided by PJM and the Market Monitor.”

It said such certifications should be subject to fraud and misrepresentation rules modeled on the provisions the commission previously approved regarding to capacity market sellers seeking a categorical exemption from the MOPR (ER13-535).

Legal Challenges Expected

FERC approved the expanded MOPR on a 2-1 vote, saying it was needed to combat price suppression from growing state subsidies, such as those for nuclear plants in Illinois, New Jersey and Ohio. Commissioner Richard Glick dissented, calling the order an attack on decarbonization efforts that would add billions in increased capacity costs.

Dozens of stakeholders filed requests for rehearing or clarification of the order, with some observers predicting the issue will end up in front of the Supreme Court. (See PJM MOPR Rehearing Requests Pour into FERC.)

Todd Snitchler, CEO of the Electric Power Supply Association (EPSA), whose members own and operate more than 50,000 MW of capacity in PJM, praised the filing. “Since December, there has been a productive and extensive public conversation among all stakeholders about how competitive electricity markets can best serve the interests of consumers and the power grid,” he said. “PJM has worked diligently under a compressed timeline to conduct a thorough stakeholder process and develop a MOPR implementation plan while ensuring that perspectives from all relevant groups were considered and incorporated into its compliance filing. … Now, FERC must act expeditiously in order for PJM to move forward and hold its long-delayed Base Residual Auction as soon as possible.”

The American Wind Energy Association also gave an upbeat review.

“PJM’s proposal provides the flexibility necessary for renewable resources to demonstrate that they are among the lowest cost and most reliable sources of capacity available today,” said Amy Farrell, AWEA’s senior vice president of government and public affairs. “We appreciate PJM’s efforts to develop sensible responses to the unsustainable policies that FERC mandated for the region’s competitive market. AWEA and our members will continue working constructively with PJM to restart the capacity market and find practical solutions that recognize the value of renewable energy and protect the ability of states to control the fuel mix within their borders.”

Katherine Gensler, vice president of regulatory affairs for the Solar Energy Industries Association, said that although the organization “objects to the underlying policies presented in the current MOPR construct, PJM took a positive step in proposing how to comply with FERC’s December order. PJM’s submission will allow renewable generators to properly identify a project-specific bid price for bidding into the capacity market auctions. This process provides renewable generators a better opportunity to compete on a level playing field with other capacity providers and to help meet states’ clean energy goals.

“We request that FERC act swiftly to restore PJM’s annual capacity auctions in a timely manner. Our member companies are ready to see market certainty return to PJM and to put this multi-year debacle to a close.”

March 19, 2020

California Agencies, Utilities Amp up Virus Response

By Hudson Sangree

SACRAMENTO, Calif. — California’s grid operator, government agencies and utilities bolstered actions this week to prevent the spread of COVID-19, in keeping with the state’s increasing limits on residents and businesses.

CAISO said Tuesday it would extend its ban on in-person meetings at its Folsom headquarters until at least May 1. The ISO previously established the restriction through April 1 to protect its employees and prevent operational disruptions. (See RTOs Take Steps to Address COVID-19’s Spr e ad.)

“These measures, part of our pandemic response plan, are intended to protect our staff, customers, stakeholders and our community, and to fulfill our critical mission to reliably operate the grid, as important as ever during these trying times,” CEO Steve Berberich said in a statement.

California coronavirus — The California Energy Commission is postponing meetings that could draw a crowd, such as its Feb. 20 session on rooftop solar. | © *RTO Insider*

CAISO plans to host meetings via teleconferencing and webinars. It suspended non-essential business travel for its employees and stopped tours of its facilities.

“To maintain reliability of electricity transmission, critical staff essential to the ISO’s core business services, such as grid operators, continue to work at the ISO control centers, and the coronavirus developments have had no impact to the system or markets,” CAISO said.

California Energy Commission Chair David Hochschild announced Tuesday the CEC will postpone meetings that could draw more than 250 people and will provide remote participation options for all other meetings and gatherings. Many commission staff members will be teleworking at least through the end of March, he said.

“Internally, we are quickly implementing processes to minimize disruptions to the Energy Commission’s workflow. Our focus is to ensure business continuity at the Energy Commission, including grant administration and invoice processing,” Hochschild said in a statement.

The California Public Utilities Commission told utilities under its jurisdiction — including Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to stop disconnecting customers who can’t pay their bills.

“In these unsettling and unprecedented times, many people are concerned about the health and safety of themselves and their loved ones, said CPUC President Marybel Batjer. “They should not also have to worry about their essential utility services being shut off for non-payment because they are unable to report to work due to illness, quarantine or social distancing.”

The protections — spelled out in a let t er from CPUC Executive Director Alice Stebbins to the electric service providers — apply retroactively to March 4, when Gov. Gavin Newsom declared a state of emergency in California. The order still must be ratified by the commission.

Some utilities, including PG&E, had already announced a voluntary moratorium on disconnections due to nonpayment. PG&E’s moratorium, announced March 12, applies to both residential and commercial customers, the utility said.

The Sacramento Municipal Utility District, which also has stopped disconnecting customers who don’t pay their bills, said Wednesday it was closing its buildings to the public through at least April 17 and plans to handle all customer business online and by phone.

“Most importantly though … all SMUD outage response levels remain unchanged and all functions necessary to run the power system will operate as normal,” it said.

A growing number of Californians are under “shelter-in-place” orders, with residents told to stay home and avoid contact for at least the next three weeks. Seven of the San Francisco Bay Area’s nine counties have issued the orders, along with counties in the Sacramento regions. Violators could be convicted of misdemeanors.

Many nonessential businesses, such as restaurants and movie theaters, have shut down, and almost all schools are closed, a condition the governor said Tuesday could last through the end of the academic year.

Millions of residents staying home could alter California’s typical “duck curve” of electricity demand, which peaks in the morning and evening when people are home and drops midday, as solar output ramps up, when they’re at work and school.

A CAISO spokeswoman said Wednesday it was too soon to tell how the pandemic is affecting electricity demand, especially because the weather has been cool and rainy in recent days, but the ISO is monitoring the situation for changes in load and trends in customer demand.

March 17, 2020

UPDATE: Monitor: PJM Saw Record-low Energy Prices in 2019

By Michael Yoder and Michael Brooks

The average load-weighted, real-time LMP in PJM was $27.32/MWh last year, a 28.6% decrease from 2018 and the lowest in the RTO’s 21-year history, the Independent Market Monitor said Thursday.

According to the Monitor’s annual State of the Market report, energy prices made up only 54.3% of the average total price of PJM’s markets ($50.33/MWh), also the lowest of any year. Capacity and transmission made up 22.4% and 20.6%, respectively, of the total price.

“The most significant single source of the reduction was natural gas and coal prices,” Monitor Joe Bowring said in an online press conference presenting the report. “The rest was the lower markups as people add less to their costs. That’s a way for saying the market was more competitive. In addition, load was down annually 2.4%, so it was a combination of three of those things.”

Of the $10.92/MWh decrease, 41.5% was a result of lower fuel costs, the dispatch of lower-cost units, decreased load and lower markups, Bowring said.

2019’s average LMP beat the prior record low, set in 2016 at $29.23 MWh.

PJM energy prices — Inflation-adjusted top three components of quarterly total price ($/MWh): January 1999 through December 2019 | *Monitoring Analytics*

Load was down 2.4% from 2018 to 88.1 GWh. Bowring said the early months of the year were mild compared to the brutal cold of January 2018.

Natural gas continued to increase its dominance in the RTO’s resource mix last year, with gas-fired output exceeding that of both coal and nuclear for the first time. Gas provided 36.2% of energy, followed by nuclear (33.6%) and coal (23.8%). Gas-fired output exceeded coal-fired in 2018 but not that of nuclear. (See Monitor Says PJM’s Capacity Market not Competitive.)

Although the Monitor found the energy markets competitive overall, Bowring pointed out a recommendation to correct flaws in the implementation of market power mitigation rules. Bowring said the rules depend on having accurate cost-based offers equal to the short-run marginal cost and clear definitions for cost-based offers highlighted in Manual 15.

He also noted a recommendation, made in the third-quarter of last year, that “PJM always enforce parameter-limited values by committing units only on parameter-limited schedules when the [three-pivotal-supplier] test is failed or during high load conditions such as cold and hot weather alerts or more severe emergencies.”

“Unfortunately, some generation participants in PJM are trying to undermine the entire role of market mitigation and are attacking the very idea of fuel-cost policies,” Bowring said.

Oct. 1 Event

Bowring highlighted PJM’s handling of an emergency event on Oct. 1, which he said the RTO mishandled. (See PJM, Stakeholders Baffled by DR Event.)

PJM issued a hot-weather alert on Sept. 30 for Oct. 2, expecting an unusually hot day. But the RTO declared a synchronized reserve event around 3 p.m. ET on Oct. 1, leading to a spike in LMPs close to $700/MWh.

In the report, the Monitor said several factors led to the spike. PJM drastically underestimated load for 2 to 6 p.m. in most of its forecasts; the Monitor noted that for the 2 to 3 p.m. hour, the actual load was 2,706 MWh above the day-ahead forecast and 1,202 MWh above the one-hour-ahead forecast. For the 5 to 6 p.m. hour, the actual load was 4,014 MWh above the day-ahead forecast.

It also faulted inadequate generator response to the event. Between 2:25 and 2:55 p.m., at least 79 units failed to achieve the output level requested by PJM, for a total of 872 MW.

But in his presentation, Bowring focused on a 25-minute gap on Oct. 1 in which PJM’s real-time security-constrained economic dispatch (RT SCED) solutions were not approved, meaning the RTO’s Locational Price Calculator (LPC) continued to use the last approved solution, produced at 4:48 p.m.

“Without an updated approved RT SCED solution, PJM does not send an updated dispatch signal to generators,” according to the report. “The dispatch signal from the case that was approved at [4:48 p.m.] continued to be the target until a new case was approved at [5:14 p.m.] that solved for a target time of [5:25 p.m.]. … For three five-minute intervals, the prices for the solved RT SCED cases differed from actual average RTO price by hundreds of dollars per megawatt-hour.”

Bowring said this could be prevented by fixing a mismatch between RT SCED, which is automatically executed every three minutes, and the LPC, which runs every five minutes. The Monitor recommended that PJM approve one RT SCED case for each five-minute interval to dispatch resources during that interval, and that the RTO calculate prices using the LPC for that five-minute interval using the same approved RT SCED case.

MOPR ‘Hysteria’

PJM held no capacity auctions last year because of the wait on FERC to act on proposals to change the minimum offer price rule (MOPR), which it eventually did in December, expanding it to all new state-subsidized resources.

“Contrary to the hysteria, there is no evidence that the expanded MOPR will lead to increased prices,” Bowring said. He said that renewable developers have told him they expect to continue to be competitive in the capacity market and qualify for unit-specific exemptions.

The Monitor’s report was critical of state consideration of exiting the capacity market via the fixed resource requirement (FRR) alternative.

“The rationale for leaving the PJM capacity market via the FRR option is based on the incorrect premise that the MOPR order will increase capacity market prices. The FRR option is more likely to increase the cost of capacity to customers than to decrease it,” according to the report. “If new renewables are not competitive in the longer run, the least-cost option for customers in states that wish to pursue renewable targets is more likely to be competitive markets plus separate state subsidies for desired technologies than ending participation in the capacity market through the FRR option.”

Other Recommendations

The Monitor made 23 new recommendations in 2019, including 12 in the annual report:

Capacity Performance resources should be required to perform without excuses. “Resources that do not perform should not be paid regardless of the reason for nonperformance.” (Priority: High.)
Remove all maintenance costs from the cost development guidelines. (Priority: Medium.)
Review the FRR rules, including obligations and performance requirements. (Priority: Medium.)
Modify the market data posting rules to allow the disclosure of expected performance, actual performance, shortfall and bonus megawatts during a performance assessment interval (PAI) by area without the requirement that more than three market participants’ data be aggregated for posting. (Priority: Low.)
Base the net revenue calculation used by PJM to calculate the net cost of new entry and net avoidable-cost rate on a forward-looking estimate of expected energy and ancillary services net revenues using forward prices for energy and fuel. (Priority: Medium.)
Prohibit emergency stationary reciprocating internal combustion engines (RICE) from participation as demand response when registered individually or as part of a portfolio if it does not meet emissions standards because the environmental run hour limitations mean that emergency RICE cannot meet the capacity market requirements to be DR. (Priority: Medium.)
Eliminate the total regulation signal sent on a fleet-wide basis and replace it with individual regulation signals for each unit. (Priority: Low.)
Remove the ability to make dual offers (as both a RegA and a RegD resource in the same market hour) from the regulation market. (Priority: High.)
Replace the static MidAtlantic/Dominion Reserve Subzone with a reserve zone structure consistent with the actual deliverability of reserves based on current transmission constraints. (Priority: High.)
Eliminate the variable operating and maintenance cost from the definition of the cost of tier 2 synchronized reserve and remove the calculation of synchronized reserve variable operations and maintenance costs from Manual 15. (Priority: Medium.)
Define the components of the cost-based offers for providing regulation and synchronous condensing in Schedule 2 of the Operating Agreement. (Priority: Low.)
Require all PJM transmission owners use the same methods to define line ratings, subject to NERC standards and guidelines, subject to review by NERC and approval by FERC. (Priority: Medium.)