PJM MRC/MC Preview: March 26, 2020

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

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

Markets and Reliability Committee

Consent Agenda (9:45-9:50)

Members will be asked to approve the following manual changes:

B. Manual 12: Balancing Operations. Periodic review.

C. Manual 13: Emergency Operations. Periodic review.

D. Manual 14A: New Services Request Process, Manual 14E: Upgrade and Transmission Interconnection Requests and Manual 14G: Generation Interconnection Requests. I ncorpo r at ing changes related to FERC Order 845 on generator interconnection procedures and agreements.

E. Manual 22: Generator Resource Pe r formance Indices. Periodic review.

F. Manual 33: Adm i nistrative Services for the PJM Interconnection Operatin g Agreement. New sections added for member roles and responsibilities and contact management and company account manager (CAM) roles and responsibilities. Existing sections relocated.

G. Manual 37: Reliability Co o rdination. Periodic review.

Endorsements/Approvals (9:50-10:35)

1. Opportunity Cost Calculator (9:50-10:05)

PJM will seek approval of a compromise p r opos a l to eliminate the RTO’s opportunity cost calculator and make the Independent Market Monitor’s calculator the required tool for market sellers, effective June 1. The switch includes changes to Manual 15: Cost Development Guidelines to document the IMM calculator and provide for an annual review of the calculator to ensure compliance with the manual and Operating Agreement (OA). (See “PJM Seeks to Retire Opportunity Cost Calculator, Use IMM Tool,” PJM MRC/MC B r iefs: Feb. 20, 2020.)

2. Market Participation Risk Evaluation Enhancements (10:05-10:35)

The MRC will be asked to approve OA and Tariff revisions endorsed by the Financial Risk Mitigation Senior Task Force (FRMSTF) to improve the RTO’s risk evaluations of market participants. At a daylong “page turn” of the proposed changes last month, some stakeholders complained that PJM was seeking excessive authority and that several of its proposed definitions were overly broad. (See PJM Stakehold e rs Debate Credit Rule Changes.)

Members Committee

Consent Agenda (1:05-1:10)

C. Members will be asked to approve cha n g es to the fuel cost policy as proposed by the PJM Industrial Customer Coalition. The changes were approved by the MRC last month on a sector-weighted vote of 3.57 (71%) despite concerns that new safe harbor provisions would create loopholes permitting the exercise of market power. The new rules are spelled out in revisions to Schedule 2 of the OA and Manual 15: Cost Development Guidelines. (See PJM MRC OKs R evised Fuel-cost Policy.)

Endorsements/Approvals (1:10-2:00)

1. Opportunity Cost Calculator (1:10-1:20)

See description in MRC, above.

2. Market Participation Risk Evaluation Enhancements (1:20-1:45)

See description in MRC, above.

3. Elections (1:45-2:00)

A. Members will be asked to e lec t a new End Use Customer sector representative on the 2019-2020 Finance Committee to replace Mike Peters of Messer LLC, whose term expires in 2020.

B. The committee will be asked to approve on first read a wa i ver of the Manual 34 requirement that elections of board members be by secret ballot. The waiver is needed to allow use of the PJM Voting Application “due to potential exigent circumstances.”

— Rich Heidorn Jr.

March 22, 2020

FERC Shelves Grievances over MISO Capacity Auction

By Amanda Durish Cook

FERC on Thursday denied what might be a final bid to recalibrate the results of MISO’s 2015/16 capacity auction, blocking Public Citizen’s request for rehearing over the highest capacity prices ever seen in the footprint.

MISO’s 2015/16 Planning Resource Auction has lived on in legal proceedings for more than five years. FERC last year wrapped up a three-year investigation into the PRA when it ruled the RTO’s Zone 4 $150/MW-day clearing price just and reasonable, declining to set up an evidentiary hearing. It also found that Dynegy had not manipulated the market to produce the high prices in southern Illinois. (See FERC Clears MISO 2015/16 Auction Results.)

midcontinent iso capacity auction — 2015/16 MISO PRA results | *MISO*

The commission said a clearing price isn’t unjust simply because it’s higher than expected. However, the decision remains unsubstantiated because FERC didn’t make any evidence from the investigation public when it abruptly ended the probe.

Soon after the ruling, Public Citizen claimed FERC wrongfully dismissed complaints alleging Dynegy manipulated pricing in the auction, violating the Administrative Procedure Act for not providing explanation or summarizing evidence and abandoning its just and reasonable ratemaking responsibility under the Federal Power Act. (See Public Citizen Contests FERC Ruling on MISO Auction.)

The commission rebuffed those arguments in its March 19 order (EL15- 70), leading Commissioner Richard Glick to once again issue a dissent and separate statement over the transparency of FERC’s investigation.

FERC’s other two commissioners, Chairman Neil Chatterjee and Bernard McNamee, said they remained unpersuaded that results were underhanded because Dynegy’s bids were permitted under a “valid, market-based rate tariff” and the bids met criteria under the FERC-approved MISO Tariff at the time. They also said they have discretion in market manipulation investigations, though they again declined to reveal any specifics of the investigation into Dynegy and Zone 4 prices.

The commissioners said they were able to monitor Dynegy’s market-based rate through accurate quarterly reports, triennial market power updates and change-in-status updates. They also said they oversaw the market monitoring and mitigation rules in MISO’s Tariff.

Public Citizen had argued that just eight months after the auction, FERC found MISO’s 2015 market power provisions no longer just and reasonable and ordered MISO to reset its $155.79/MW-day maximum bid to about $25, while also directing the RTO to better gauge power exports. (See FERC Orders MISO to Change Auction Rules.) But the commission said those new policies were to be viewed on a going-forward basis.

Glick Hints at Unfinished Investigation

However, Glick said the order was another “sidestep” of the crux of the proceedings, failing to answer the question of whether the resulting prices were reasonable considering the allegations of market manipulation on Dynegy’s part.

“Rather than directly confronting that issue, the commission states that the relevant Tariff language was followed and that a non-public investigation was conducted and did not, in my colleagues’ view, uncover manipulative conduct. That enforcement proceeding, however, was terminated by the chairman without a vote by the commission and the details of that investigation remain confidential,” Glick wrote. “Accordingly, the commission has at no point provided Public Citizen with an adequate response to the concerns raised in its complaint or explained why, in light of those concerns, the auction results were just and reasonable.”

Glick added that following relevant tariffs does not create a “safe harbor” for market manipulation.

“I am not aware of any authority to support the proposition that a market participant can commit market manipulation with impunity so long as it does not violate the relevant tariff language,” Glick said. He also said that courts’ interpretations of the Securities Act of 1934 “have repeatedly recognized that a facially legal action can constitute manipulation when it is taken for an improper purpose.”

Glick also reiterated his displeasure that he was not consulted before Chairman Chatterjee closed the nonpublic investigation. He also hinted that there might have been evidence that Dynegy had committed wrongdoing.

“Had I been consulted, I would have argued against terminating the enforcement process. Because the details of the investigation remain non-public, I cannot explain why I believe that the chairman erred in terminating the enforcement process. Suffice it to say that I am confident that the evidence uncovered in that investigation was more-than-sufficient to press ahead,” he wrote.

Glick ended by echoing complaints that the commission’s decision “does not provide even the scantest reasoning to support its finding that the nearly 1,000% year-over-year increase in the MISO Zone 4 capacity price had nothing to do with market manipulation.

“Instead, all we have is the Commission’s unsubstantiated assurance that there is nothing to see here.”

March 22, 2020March 12, 2025

Rehearing Denied over MISO RA Construct

By Amanda Durish Cook

FERC last week affirmed its 2018 ruling approving MISO’s current resource adequacy construct, rejecting multiple rehearing requests from critics of the decision.

Among those requesting rehearing were a collection of Midwest transmission-dependent utilities, a group of major capacity suppliers, Main Line Generation and MISO’s Independent Market Monitor.

The commission said most of those arguing for rehearing sought to make MISO’s RA construct more like the centralized capacity markets of Eastern RTOs/ISOs. But FERC noted that those designs ignore the fact that the RTO must defer to multiple state jurisdictions in its 13-state reach and that its RA design is meant to be complementary to states’ authority (ER18-462).

MISO Little Rock headquarters | MISO

The commission also pointed out that 90% of MISO’s load is served by vertically integrated load-serving entities that for the most part don’t use the RTO’s capacity auction to meet capacity requirements.

” … [U]nlike the centralized capacity constructs used in the Eastern RTOs/ISOs, MISO’s auction is not — and has never been — the primary mechanism for its LSEs to procure capacity,” the commission stressed.

Two years ago, MISO pre-emptively refiled its entire RA construct in response to a D.C. Circuit Court of Appeals ruling that FERC overstepped its “passive and reactive” role when it prescribed revisions to PJM’s minimum offer price rule. MISO was concerned the decision could impact some of the RA rules that had been guided by FERC’s recommendations.

In a pair of orders a few months later, FERC both vacated and reinstated MISO’s entire RA construct, ultimately leaving the RTO’s current capacity auction format — and past auction results — undisturbed. (See FERC Vacates, Upholds MISO Resource Adequacy Rules.)

Still No Sloped Demand Curve, MOPR, Forward Mechanism

MISO Independent Market Monitor David Patton used the RA refiling as an opportunity to ask FERC to order the RTO to employ a sloped demand curve in its capacity auction in order to produce more efficient pricing. (See MISO Monitor to FERC: Order Sloped Demand Curve.)

On rehearing, Patton again argued that a good RA design “will produce price signals sufficient to attract and retain the necessary amount of capacity” and that FERC itself made that issue paramount when accepting the sloped demand curves used in NYISO, PJM and ISO-NE’s capacity auctions.

But in last week’s ruling, FERC said MISO’s high percentage of vertically integrated utilities sets it apart it from NYISO, PJM and ISO-NE because MISO’s RA is not determined by its capacity auction prices alone. It said the RTO’s vertical demand curve is fine for now.

” … [W]e continue to find that MISO’s resource adequacy construct enables the MISO region to maintain sufficient resources to meet system-wide and locational reserve requirements,” the commission said, noting that last year’s Organization of MISO States-MISO RA survey indicates sufficient capacity supply through 2022.

The commission also rejected the capacity suppliers’ request that the RTO conduct the auction on a three-year forward basis for retail-choice areas in Illinois and Michigan. FERC found that both a prompt auction and a multi-year forward capacity auction can be reasonable, and the suppliers’ support of one design over the other wasn’t a justification to order MISO to change its auction timing. The commission also told the suppliers that MISO’s auction didn’t require a minimum offer price rule, again noting that vertically integrated utilities own about 90% of capacity in MISO.

The commission also rejected the suppliers’ argument that it’s discriminatory for the MISO capacity auction to be voluntary for buyers and mandatory for sellers who have uncommitted capacity. FERC said while it does have an obligation to ensure that “similarly situated market participants are not unduly discriminated against … it does not follow that market participants who are not similarly situated are unduly discriminated against simply because they are subject to different sets of rules.”

The transmission-dependent utilities argued that the RA construct should allow new capacity resources to obtain long-term financial hedges to shield against inter-zonal price separation in the auctions. FERC said such a provision fails to consider the capacity auction’s main purpose of ensuring reliability during peak days.

The commission said MISO’s local clearing requirements and capacity import and export limits are essential to zonal reliability and declined to order alterations so more resources could compete inter-zonally. The commission also left in place MISO’s zonal delivery charge, which the RTO uses to cover congestion between zones when an LSE that submits its own fixed resource adequacy plan taps resources in a lower-priced local resource zone to serve demand in a higher-priced zone. The commission disagreed that the zonal delivery charge is a form of rate pancaking, pointing out that the charge is meant to cover auction price separation between the LSE’s location and its load, not transmission service. Capacity prices should reflect the “locational cost of capacity,” FERC said.

MISO’s RA construct “appropriately balances the competing goals of maximizing competition and ensuring reliability by allowing LSEs to serve their load with remote resources but having them bear the risk of auction price separation if there are impediments to the deliverability of such resources,” FERC said.

March 22, 2020

NEPOOL Reliability Committee Briefs; March 17, 2020

New England stakeholders on Tuesday pushed back on ISO-NE’s draft assumptions showing that several variable changes between Forward Capacity Auctions 14 and 15 will improve system fuel security.

ISO-NE Manager of Outage Coordination Norm Sproehnle presented the New England Power Pool Reliability Committee with assumptions based on the RTO’s capacity, energy, loads and transmission (CELT) forecast and consistent with Planning Procedure 10 (PP-10) Appendix I.

The assumptions show FCA 15 will see increases in gas pipeline capacity, total PV, onshore and offshore wind nameplate and demand response, coupled with lower peak load, lower winter LDC natural gas demand forecast and lower equivalent forced outage rate demand (EFORd).

NEPOOL Reliability Committee — Utilization of gas supply vs LDC demand in New England. | *ISO-NE*

The RTO also is wrapping up its Energy Security Improvements (ESI) initiative ahead of an April 15 filing deadline with NEPOOL Markets Committee Briefs: March 10-11, 2020.)

Chris Hamlen, the RTO’s assistant general counsel for markets, clarified “that the fuel security retention rules are in place only through FCA 15, and so beyond FCA 15 there is no mechanism in place for performing this type of review.”

Further, the RTO indicated that, in response to stakeholder concerns raised during the meeting, it would consider whether it is possible to adjust some of the assumptions in the retention analysis performed for FCA 15 to better reflect the way in which the impact analysis was performed for ESI.

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

The committee will review FCA 15 fuel security inputs and results in April and May and vote on the proposed PP10-I revisions in May, if applicable. If necessary, NEPOOL’s Participants Committee will vote on the revisions in June.

The RTO also is preparing for fuel security reliability reviews of FCM retirement de-list bids, substitution auction demand bids, bilateral transactions and reconfiguration auction demand bids submitted in connection with FCA 15.

FCA-14 Auction Results

Ryan Hoskin, ISO-NE senior analyst for transmission services and resource qualification, presented results of FCA-14, which was held in the first week of February.

The RTO’s 2020 capacity auction cleared at a record low of $2/kW-month, a nearly 50% drop from $3.80/kW-month in 2019. (See ISO-NE Capacity Prices Hit Record Low.)

ISO-NE filed the auction results with FERC on Feb. 18 (ER20-1025) and posted its capacity supply obligations (CSO) spreadsheet on its website. No capacity supply obligations were traded this year under the substitution auction.

FCA 15 Capacity Zones OK’d

The RC also voted to recommend that ISO-NE identify the zonal boundaries to be used in modeling criteria for FCA 15 — unchanged from FCA 14 — in accordance with Tariff rules.

Al McBride, the RTO’s director of transmission strategy and services, reviewed the proposed capacity zone construct for FCA 15, as well as the interface transfer capabilities and external interfaces.

For FCA 15, the RTO will evaluate potential export-constrained zones, including Northern New England (NNE), which includes Vermont, New Hampshire and Maine, and a portion of Maine nested within NNE.

Potential import-constrained zones to be evaluated include Southern New England (SENE), which includes Northeast Massachusetts/Boston (NEMA), and Southeast Massachusetts/Rhode Island (SEMA/RI), and Connecticut.

The RTO will test the potential capacity zone boundaries and present the results at the May 2020 Power Supply Planning Committee, McBride said.

Zones that trigger the objective criteria indicating constraints will be modeled in FCA 15 and associated reconfiguration auctions, which will determine whether any of the modeled zones bind in the auction and experience price separation, he said.

Regarding internal interface transfer capability, the study noted increases associated with various transmission system upgrades, including ones in Greater Boston, Greater Hartford/Central Connecticut, Southwest Connecticut, as well as with SEMA/RI reliability project upgrades.

The study found a decrease in internal interface transfer capability associated with the updated load assumptions, updated NNE-Scobie transfer capability and the retirement of Mystic units 7, 8 and 9.

One stakeholder assumed that a drop in load would increase import capability and that the Mystic retirements will increase import capability.

“No, all these factors have the effect of lowering the transfer capability,” McBride said. “The load change really becomes as much about relative load changing, [and] in particular, changes in where load is on the key transmission lines.

“If you’re lowering load at a point on the transmission system that causes less local drawdown and more flow to remain on the system, but it seeks to try to get into, in this case, southeast New England, lowering load at particular points can actually cause more flow to be on those lines as it tries to serve the load beyond that point, lowering the transfer capability,” McBride said.

“We did some sensitivity analysis in an attempt to identify what the factors were,” he said. “The predominant thing we were looking at was the change from Mystic 8 and 9 at retirement, and we wanted to make sure we understood what the other factors were.”

For external interface import capability, limits are usually for the summer period, may not include possible simultaneous impacts and should not be considered as firm, McBride said.

For example, the electrical limit of the New Brunswick (NB)-New England (NE) Tie is 1,000 MW, but downstream constraints, particularly in Orrington South, led planners to adjust that tie’s transfer capability to 700 MW for ability to deliver capacity to the greater New England Control Area.

Similar to what it did with NB-NE, the RTO has assumed transfer capability for capacity and reliability calculation purposes to be 1,400 MW for the 2,000 MW Hydro-Quebec Phase II interconnection, lowering the figure due to the need to protect for the loss of the line at full import level in the PJM and New York Control Areas’ systems, he said.

— Michael Kuser

March 22, 2020

SPP Launches Western Market Groups

By Tom Kleckner

An executive committee charged with overseeing administration of SPP‘s Western Energy Imbalance Service (WEIS) last week launched the working group responsible for developing and maintaining the market’s protocols.

The Western Markets Working Group (WMWG) will report to the Western Markets Executive Committee (WMEC), which approved both the group’s scope and its leadership during a March 19 conference call.

The WMWG will work with other stakeholder groups in recommending the protocols and associated Tariff changes to the WMEC and prioritizing approved system and process changes. It will also coordinate with regulators and task forces in implementing the WEIS market.

SPP Western Energy Imbalance Service and legacy footprint — SPP’s WEIS and legacy footprints. | *SPP*

The committee unanimously approved Basin Electric Power Cooperative’s Valerie Weigel as the WMWG’s chair and Municipal Energy Agency of Nebraska’s Jeff Lindsay as vice-chair. They will serve two-year terms.

The working group will replace the WEIS Protocol Review Task Force, which has been developing the market’s protocols. The WMWG will consist of up to 12 members, with one representative from each non-affiliated signatory to the Western Joint Dispatch Agreement, the contractual arrangement between SPP and WEIS participants that governs SPP’s obligations to administer the market and its compensation.

SPP filed its WEIS Tariff in February, asking for an effective date of Feb. 1, 2021.

The WEIS market is modeled on the Energy Imbalance Service market SPP operated from 2007 to 2014. The RTO will centrally dispatch energy from the participants every five minutes using the most cost-effective generation to reduce wholesale electricity costs for participants. SPP says the market will provide price transparency and bilateral trades.

The WEIS market has attracted eight participants with the early March addition of Utah’s Deseret Power Electric Cooperative, a regional generation and transmission cooperative with six member retail systems. It is scheduled to launch next February. (See SPP Board OKs $9.5M to Build Western EIS Market.)

March 22, 2020

FERC OKs PJM Tx Cost Containment

By Rich Heidorn Jr.

FERC on Friday approved PJM’s proposed rules on how the RTO will evaluate voluntary cost commitment proposals on competitive transmission projects (ER19-2915).

The Operating Agreement changes, which resulted from stakeholder-drafted motions at the Markets and Reliability Committee, require PJM to evaluate projects submitted in competitive proposal windows on multiple criteria, including “cost effectiveness.” (See PJM TOs Wary of Cost Containment Rules.)

The revisions clarify that PJM may not require developers to submit cost containments and that those that are voluntarily proposed are binding.

PJM would evaluate “the quality and effectiveness” of provisions that limit project construction costs, total return on equity (ROE) including incentive adders or capital structure.

PJM Interconnect Transmission Cost Containment — Annual revenue requirement under partial and full cost caps | *PJM*

The RTO will submit to the Transmission Expansion Advisory Committee (TEAC) an analysis comparing the risks to be borne by ratepayers as a result of developers’ binding cost commitments or non-binding cost estimates.

In approving the rules, the commission rejected the objections of transmission owners, which argued the revisions did not provide enough details on how PJM will conduct its comparative analysis.

“We find that PJM’s filing is just and reasonable because it may assist PJM in its selection of the more efficient or cost-effective transmission solution and provides additional transparency of PJM’s evaluation of competing proposals,” the commission said. It noted that PJM is developing implementation details for the comparative analysis in Manual 14F.

“The proposed revisions provide reasonable flexibility both for developers to decide how to craft their voluntary cost commitment proposals and for PJM to evaluate and select the more efficient or cost-effective transmission solution. Moreover, the proposal provides for transparency, allowing stakeholders the opportunity to review any particular analysis conducted by PJM and raise any concerns via the TEAC process.”

FERC disagreed with arguments that the filing infringed on the rights of PJM transmission owners and nonincumbent transmission developers to exclusively make Federal Power Act Section 205 filings concerning transmission rates, revenue requirements and cost recovery.

It also rejected contentions that PJM will be determining whether the rate design elements under a proposal will result in just and reasonable rates. “PJM is proposing for the commission to determine, in reviewing the nonconforming DEA [designated entity agreement between PJM and a selected developer] with the cost commitment provision, whether any rate design component included in that provision is just and reasonable.”

March 22, 2020

FERC Denies Brooklyn Battery Waiver

By Michael Kuser

FER C on Thursday denied NYC Energy’s (NYCE) request for a limited waiver of NYISO interconnection rules for its 80-MW energy storage facility proposed to be situated on a barge moored at the Brooklyn Navy Yard.

NYC Energy had proposed to add a battery to their project at the Brooklyn Navy yard (seen here). — Manhattan as seen from the Brooklyn Navy Yard.

NYCE sought waiver of a Tariff provision that requires a project to withdraw from the ISO’s interconnection queue if it fails to comply with certain interconnection procedure requirements (ER20-629).

NYCE explained that its project is a modification of a previously permitted combined cycle gas/oil-fired generating facility and that the ISO also completed a materiality review of the project regarding a change in technology in August 2019. Further, the developer said it notified NYISO of its intention to enter the 2019 class year of the interconnection queue, and the ISO acknowledged the request on Aug. 16, 2019.

In addition, NYCE said it delivered an executed facilities study agreement (FSA) to NYISO on Sept. 11, 2019, along with all other required materials, including a $100,000 FSA study deposit.

But the company noted that when it submitted the FSA, it learned that NYISO had concluded that a previous finding of no adverse environmental impacts under state law applied only to the original project, not to the newer battery project, meaning the latter did not satisfy regulatory milestones required for the queue.

NYCE withdrew its effort to join the 2019 class year but sought a Tariff waiver in order to hold a position in the queue. NYISO supported NYCE’s waiver request, saying that absent a waiver from the commission, the ISO could not accept the two-part deposit for NYCE’s project after Sept. 16, 2019.

The ISO further said it did not dispute NYCE’s assertion that no adverse harm will result to other projects if the waiver request is granted because NYCE’s project no longer sought to participate in the 2019 class year.

The commission rejected NYCE’s arguments, saying “the record reveals no reason why NYCE could not have satisfied the regulatory milestone in accordance” with NYISO’s Tariff provisions, and the company “has not adequately explained why it assumed that prior regulatory reviews for a different generating facility would satisfy the regulatory milestone in the [Tariff].”

“Specifically, although we find no evidence of ill intent by NYCE, we find that NYCE has not demonstrated that it acted in good faith,” said the order confirmed by Chairman Neil Chatterjee and Commissioner Bernard L. McNamee.

The commission also found that NYCE failed to demonstrate that its waiver request was limited in scope.

It said “a waiver is not limited in scope if the party requesting waiver does not provide a compelling reason why it should be afforded special treatment compared to others. Here, NYCE seeks to shield itself from the consequences of its choices.”

Commissioner Richard Glick dissented in a separate statement.

“First, I see nothing in the record — or today’s order — indicating that NYCE did not act in good faith,” Glick said. “After all, it does not strike me as totally unreasonable to assume that, if an oil/natural-gas fired unit can pass environmental muster, then a non-emitting battery storage facility is likely to clear that bar as well.”

Glick argued that the waiver request is limited in scope insofar as it applies only to this facility and only to this single failure to comply with the applicable deadlines, and that the request remedies a concrete problem.

“Finally, I agree with NYISO that granting the waiver would not have undesirable consequences, such as harming third parties,” Glick said. “I also understand why NYCE sought to rely on its previous environmental determinations rather than fork over an additional quarter-million dollars in collateral … [which] does not, in my view, indicate that it acted in bad faith.”

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.