Page 1105 – RTO Insider

May 5, 2020

PJM End-of-life Tx Proposals Near Vote

PJM stakeholders debated for nearly two hours Thursday over transmission owners’ spending on end-of-life (EOL) projects, suggesting there is little chance for compromise on an issue that has been disputed for years within the RTO.

Three EOL proposals were given first reads at Thursday’s Market and Reliability Committee meeting, setting up votes at the next MRC meeting on May 28. The proposals — which would require TOs to share how they make EOL determinations and potentially open at least some replacement projects to competition under the Regional Transmission Expansion Plan (RTEP) — are the result of deliberations over six special MRC meetings since December.

Three Proposals

A proposal by a group of PJM stakeholders, including American Municipal Power and Old Dominion Electric Cooperative, would require TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would be made a new category of regionally planned projects. It was endorsed by the PJM Industrial Customer Coalition, the Public Power Association of New Jersey, Consumer Advocates of the PJM States (CAPS) and the D.C. Office of the People’s Counsel.

LS Power supports the stakeholder package but would require six years’ notice for lower-voltage facilities and at least eight years’ notice for facilities of 230-kV and above.

PJM also offered a package requiring TOs to identify EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions. Like the stakeholder and LS Power plans, PJM’s proposal would require each TO to have a formal program for EOL determinations. The RTO said it would prevent TOs that don’t already have a EOL determination process from using a “run to failure” asset management approach.

Under current rules, said Mark Ringhausen, vice president of engineering for ODEC, some TOs don’t identify EOL projects, choosing instead to replace “pieces and parts.”

“Some have told me that they never make EOL determinations,” Ringhausen said.

Divergence of Plans

But PJM disagreed with the stakeholder proposal on the RTO’s jurisdiction over EOL facilities, saying the Consolidated Transmission Owners Agreement (CTOA) transferred to PJM only the responsibility to prepare an RTEP “for the enhancement and expansion” of the transmission system to meet demands for firm transmission service. Section 5.2 of the CTOA says, “PJM shall not challenge any … sale, disposition, retirement, merger or other action.”

PJM also said its role is limited by two ‘Asset Management’ not Subject to Order 890, FERC Rules.)

Dave Souder, PJM senior director of system planning, said the proposal honors the TOs’ responsibility over asset management decisions while allowing the RTO to determine when an RTEP project is more cost-effective than a TO’s proposed replacement. “We believe the PJM package takes a reasonable approach,” he said.

Several parties, including AMP and ODEC, insisted the FERC rulings do not preclude their proposal. They said the PJM proposal lacks transparency and would not require TOs to have EOL criteria or to share the list of EOL projects with stakeholders. Souder said PJM hasn’t decided whether the retirement list would be public.

Ed Tatum, AMP’s vice president for transmission, said PJM data from 2019 show $4.8 billion in TO supplemental projects, about 75% of which are for EOL assets that could benefit from longer-range planning. Robert Taylor of Exelon said he disagreed with the $4.8 billion statistic, saying the dollar amount appeared to combine supplemental and baseline projects, inflating the number by as much as $1.5 billion.

Tatum conceded that the retirement of a transmission asset should be determined by the TO that owns it. But he said PJM should take over planning once a retirement decision is made.

PJM End-of-life Transmission — Greg Poulos, CAPS | © *RTO Insider*

“Asset management includes operational maintenance activities, as well as the decision as to when an asset has reached the end of its life,” Tatum said. “But asset management ends at that point, and planning begins. … We need to have the assurance that this is being planned by an independent organization that is not bound by its stockholders to put together a construction project.”

CAPS Executive Director Greg Poulos said the advocates are frustrated that the TOs have “dug in” and been unwilling to negotiate a compromise. (See Stakeholders Seek TO ‘Engagement’ on End-of-Life Tx.)

“We’re supposed to be working together and not going straight to legal arguments,” Poulos said. “The stakeholder process does not work if we’re just going to go to FERC with things.”

The TOs filed a “statement of legal and contractual issues and reservation of right s” with the MRC on Wednesday. The statement said the stakeholder and LS Power proposals infringe on TOs’ contractual rights and are attempts to “rewrite” the CTOA and relitigate FERC rulings.

‘Scorched-earth’ Tactics

Alex Stern of Public Service Electric and Gas said TOs worked hard for a compromise problem statement and issue charge when EOL was brought up at Planning Committee meetings last year but that an agreement could not be reached. (See PJM Members Debate Dueling Tx Replacement Plans.)

Stern said he still had hope that a compromise could be reached during the special stakeholder process in the MRC over the last five months. But he said the packages that emerged are an attempt “to leverage the stakeholder process” to force PJM to make a filing at FERC that individual stakeholders should be making themselves.

“If stakeholders want to challenge the FERC-approved paradigm governing the authority of TOs to make determinations regarding the end of the useful life of their asset … there’s absolutely nothing stopping them from doing so,” Stern said.

John Horstmann of Dayton Power & Light agreed, calling the EOL stakeholder meetings a “scorched-earth process” to force PJM into a Federal Power Act Section 205 filing. Horstmann said the issue should have been brought to FERC as a Section 206 filing rather than going through the stakeholder process.

Stakeholders filing under Section 206 must first prove the RTO’s existing rules are unjust and unreasonable to win FERC approval of changes. A PJM filing under Section 205 would not need to make that showing, needing only to convince the commission that its new rules are just and reasonable.

The Members Committee has Section 205 filing authority over the Operating Agreement (OA); the PJM Board of Managers has Section 205 authority over the Reliability Assurance Agreement and the Open Access Transmission Tariff (excluding provisions under the exclusive control of the TOs).

The stakeholder and LS Power proposals would require changes to the OA.

PJM said its proposal would only require manual changes. LS Power’s Sharon Segner disagreed, saying FERC Order 1000 requires such planning process rules be included in the OA. She also said the PJM proposal fails to eliminate “redundancy between the supplemental and regional planning process” that would require an OA fix.

Stern said the focus on EOL by some of the stakeholders seems to be less on planning criteria and appropriate decision-making to ensure local and regional grid reliability, and more on the dollar amount being invested. He said transmission decisions are supposed to be made on ensuring the reliability of the grid and not the cost.

“PJM certainly has a role to play in planning, but it is not to decide how a transmission owner goes about addressing the impact of the end of useful life of an asset,” Stern said.

Tatum said he agreed with Stern’s assertion that planning shouldn’t be based solely on costs. But he said he would have more confidence that projects were being done in the most cost-effective way if PJM was conducting the planning.

Tatum said the TOs “unfairly discount” the importance of the PJM stakeholder process and the rights of the rest of the stakeholders. He said that since the inception of PJM as an RTO, the TOs demanded many of the provisions in the OA so they could have control over the new entity that was being developed.

“It’s not just [TOs that are] concerned about reliability and keeping the lights on,” Tatum said. “We all have a vested interest in that. But we see a majority of planning being driven outside of [the RTEP] process. Independent planning is essential in order to have successful markets, and we’re moving away from that.”

Susan Bruce, representing the PJM ICC, said industrial customers have seen their transmission bills increase “exponentially” over the past two years, largely because of EOL costs. Aligning the EOL asset management process with RTEP would ensure the transmission investments being made are cost effective and well planned, she said.

“Industrial customers want to see a reliable and robust grid, but they also want to make sure that their investment in transmission is optimized,” Bruce said.

Costs

Citing PJM statistics, Horstmann said that only 30% of the RTO’s transmission system is less than 40 years old, causing a glut of assets nearing their EOL that must be replaced. He said a high price tag is inevitable no matter who oversees the planning.

“You’re looking at a lot of money over the next period of years to basically maintain what we have, let alone improvements,” Horstmann said. “To me, that’s the elephant in the room here. This [dispute] just sort of dances around the edge of that problem.”

Tom Hyzinski of GT Power Group asked how much would be saved by identifying EOL projects six years in advance and making it subject to competitive bidding.

Ringhausen cited a Brattle Group report that showed 30% savings from competitive bidding. “You’re talking tens of billions of dollars,” he said. (See Study Findings Clash on Value of Competitive Tx.)

Next Steps

PJM’s Jim Gluck said the MRC will schedule one more special session (May 11 or May 15) to discuss the packages and seek opportunities for consensus before the three proposals are brought to sector-weighted votes May 28. The package with the most stakeholder support and meeting the two-thirds threshold will be brought back to special meetings to draft governing document language. The package receiving the greatest support will become the main motion for a vote of the MC.

May 5, 2020

PJM Analyzes Potential COVID-19 Generation Losses

PJM could support the loss of up to 40% of installed generation capacity on a summer day and up to 60% on a spring day in a worst-case scenario situation in which units were knocked offline from a COVID-19 outbreak among plant workers, the RTO said last week.

Ray Lee, senior engineer in generation, and Jason Sexauer, senior engineer for outage analysis technologies, presented the generator availability analysis to stakeholders during PJM’s weekly coronavirus call Friday.

Lee said the analysis was intended to determine the maximum generation loss PJM could handle without curtailing power to the hardest hit areas. The analysis began by considering the impact of an outbreak at one plant spreading and disabling a generating company’s entire fleet, he said.

Sexauer said the 40% and 60% outage levels in the scenario are about twice as many outages as typically occur during summer and spring. “These scenarios are worst case, far and above what we normally screen for from an operational perspective,” Lee said.

PJM COVID-19 — An overlay map of generators located within the PJM footprint compared with cases of outbreaks of COVID-19 | *PJM*

PJM has not seen any generator outages from the pandemic thus far, they said.

Analysts used overlay maps to compare the highest levels of COVID-19 infection within the PJM footprint with generator locations, Lee said, focusing specifically on New Jersey, the Interstate 95 corridor from New Jersey to D.C., and Chicago and its suburbs.

Lee said coal-fired and combined cycle plants were judged most likely to be impacted by an outbreak because they require higher numbers of on-site personnel to operate.

The final step in the planning process was to define the appropriate time frames for outbreaks at the sites, Lee said.

Because of uncertainty over how long the pandemic will last, PJM decided to perform the studies for the spring and summer peak loads. The findings “could then be used to potentially consider proactive actions, such as limiting future outages if we’re seeing a trend towards these worst-case scenarios,” he said.

Sexauer said four steps were used in the process for calculating the outages, including: selecting the hypothetical generation units that would go offline; building an “all-in case” for May 4 and July 7 using normal load on those dates; creating an “all-out case” where all scheduled transmission and hypothetical generation outages from COVID-19 were applied; and running a DC/AC contingency analysis on the hypothetical cases to look for thermal overloads and “non-converged contingencies,” in which no solution is found.

He said that while running the analysis, PJM found that thermal issues with the grid were more prevalent in the spring and voltage collapse issues were more prevalent in the summer. About 5,200 cases were analyzed, requiring two days of computer runs.

May 5, 2020

Public Citizen Seeks Rehearing of El Paso Electric Order

Emboldened by its victory in an affiliate case involving Goldman Sachs, consumer advocacy group Public Citizen last week asked FERC to reconsider a ruling involving another investment bank, JPMorgan Chase.

Public Citizen filed for rehearing of FERC’s March 30 conditional approval of JPMorgan’s acquisition of El Paso Electric (EC19-120). (See FERC Conditionally OKs JP Morgan’s Purchase of EPE.)

JPMorgan is funding its $4.3 billion purchase of EPE through a web of financial affiliates, led by its Infrastructure Investments Fund (IIF) and Sun Jupiter Holdings. Sun Jupiter is the sole shareholder of Merger Sub, a corporation formed for the purpose of merging with and into EPE, with EPE as the surviving entity. Sun Jupiter is also an indirect, wholly owned subsidiary of IIF Sun Jupiter Ultimate Holdings.

Tyson Slocum, Public Citizen’s energy program director, told RTO Insider that the order was a result of FERC’s “deeply flawed” paper hearing process, in which commissioners consider the written evidence in private before issuing a decision.

“FERC can pick and choose what it wants to focus on and what it wants to ignore,” Slocum said. “They simply ignored the evidence [of self-dealing] we provided.

Public Citizen said FERC’s order, which directed the companies to file a mitigation plan addressing market power screen failures, ignored evidence that “JPMorgan’s affiliation with IIF poses a risk to the rates of El Paso Electric’s captive customers.” The group noted that the commission declined “to address the arguments related to whether the IIF companies are affiliated with JPMorgan and/or J.P. Morgan Investment [Management].”

The commission agreed with the applicants’ assertion that any affiliation between the IIF companies with JPMorgan would not change its analysis under the Federal Power Act.

Public Citizen said FERC cannot decline enforcement under the FPA and “must make a determination of whether JPMorgan Chase & Co. is affiliated with the IIF shell companies seeking to acquire El Paso Electric, as JPMorgan’s affiliation with IIF — and the impact that affiliation has on rates — has been the only contested issue of this entire proceeding.”

“I don’t think they can lawfully decline to address the cornerstone of their obligations under the Federal Power Act,” Slocum said.

In the filing, Public Citizen pointed to FERC’s April 27 decision granting Public Citizen’s protest and ruling that Goldman Sachs Renewable Power Marketing was an affiliate of The Goldman Sachs Group investment bank. (See FERC: New Goldman Unit an Affiliate.)

The group said the Goldman Sachs ruling “demonstrates the need for” JPMorgan to produce the operating agreements, management services agreements, limited liability company operating agreements and all other corporate documents “that describe the powers and responsibilities of the various parties within each IIF shell company.”

“Such documents are necessary to determine affiliation of JPMorgan Chase & Co. with IIF,” Public Citizen said. “The issue of JPMorgan’s affiliation with IIF is necessary for FERC to determine whether the acquisition of El Paso Electric by IIF is consistent with the public interest.”

Public Citizen said evidence that JPMorgan instructed IIF to purchase 120 million shares of a power company held by the investment bank indicates the new owners’ “self-dealing” could increase rates for EPE’s captive customers.

Slocum said his organization will also be intervening in Xcel Energy’s proposed $680 million sale of its 760-MW Mankato Energy Center in Minnesota to Denver-based Southwest Generation. Southwest Generation is owned by institutional investors advised by J.P. Morgan Asset Management.

May 3, 2020

PG&E Says Most Board Members Will Leave

PG&E Corp. said Friday that 11 of its 14 directors would be leaving its board, mostly complying with a demand from California Gov. Gavin Newsom and the president of the California Public Utilities Commission for a complete replacement of the board.

Among those exiting will be PG&E Chair Nora Mead Brownell, a former FERC commissioner and Pennsylvania utility regulator. Kristine Schmidt, a former member of CAISO’s Western Energy Imbalance Market Governing Body who was an adviser to Brownell at FERC, will also be leaving.

PG&E Board Members — Former FERC Commissioner and PG&E Corp. Chair Nora Mead Brownell is among those who will leave the board. | *PG&E*

The announcement was part of PG&E’s first-quarter earnings report.

PG&E gave no date for its changes at the top. The holding company and its main utility subsidiary Pacific Gas and Electric Care trying to emerge from Chapter 11 bankruptcy by June 30, the deadline to participate in a state fund to insure investor-owned utilities from future wildfires.

CEO Bill Johnson, who recently announced he will be retiring at the end of June and intends to move on to academia, said in a news release accompanying the first-quarter earnings report that PG&E is on track to meet the June deadline. (See PG&E CEO Johnson Says He’ll Step Down.)

“We have developed a plan of reorganization that has the support of a broad coalition of stakeholders, including the governor’s office,” Johnson said. “Our plan compensates wildfire victims fairly, resolves our liabilities, assumes the collective bargaining agreements with our labor unions and is energy-bill-neutral for our customers.”

PG&E filed for bankruptcy in January 2019, after devastating wildfires left it owing an estimated $30 billion to fire victims and insurers. The company has agreed to pay $13.5 billion to victims of fires in 2015, 2017 and 2018 and $11 billion to insurance companies and hedge funds that hold third-party subrogation (insurance) claims. It will also pay $1 billion to local governments affected by wildfires.

The next round of leadership changes will be the second in about 14 months. PG&E hired Johnson as CEO on May 1, 2019, its third chief executive in two years. Ten directors were also replaced, with Brownell and Schmidt among those joining what PG&E called its refreshed board.

In the impending turnover, Andrew Vesey, CEO of Pacific Gas and Electric, will stay in his position, PG&E said.

PG&E said the three board members who will remain are Bill Smith, a retired AT&T executive who will become interim CEO when Johnson leaves; Cheryl Campbell, previously with Xcel Energy; and John Woolard, CEO of Meridian Energy. All were named to the board last year.

“Smith is the retired president of AT&T Technology Operations … and brings more than 35 years of experience in the telecommunications industry including overseeing operations, planning, engineering, construction, maintenance and a field workforce of more than 100,000 employees,” PG&E said.

Campbell brings safety experience, a qualification that Newsom and PUC President Marybel Batjer have insisted must be a major part of a revamped PG&E board. Newsom and Batjer called for a replacement of PG&E’s entire board with new directors, at least half of them Californians. (See CPUC President Wants More Control Over PG&E.)

Newsom and Batjer have yet to say whether PG&E’s plan to leave three current directors in place will meet their expectations. The CPUC must still approve PG&E’s Chapter 11 reorganization plan.

The company noted it received a proposed decision from the CPUC on April 20 that found its reorganization plan generally complies with Assembly Bill 1054, which created the wildfire insurance fund.

PG&E reported first-quarter GAAP income of $371 million ($0.57/share), compared with income of $136 million ($0.25/share) in 2019. The company said its GAAP results were impacted by $205 million in after-tax costs related to the bankruptcy.

Its non-GAAP earnings, which exclude non-core items, were $576 million ($0.89/share), compared with $546 million ($1.04/share), in the first quarter of 2019.

May 3, 2020

NEPOOL Transmission Committee Briefs: April 28, 2020

New England Power Pool participants seem to be in “overall agreement” with ISO-NE’s approach to finalizing compliance with FERC Order 845, the RTO’s director of transmission strategy and services, Al McBride, told the NEPOOL Transmission Committee on April 28.

One lingering difference is related to participants’ concerns about the dynamic between New England’s capacity network resource interconnection service (CNRIS) and network resource interconnection service (NRIS), McBride said.

The TC was discussing ISO-NE’s April 20 request for clarification filed with FERC regarding Order 845 compliance, as well as the RTO’s proposed response in terms of Tariff language (ER19-1951).

Order 845, approved in April 2018, set pro forma minimum standards for large generator interconnection procedures and agreements.

FERC rejected the RTO’s proposed rules for obtaining surplus interconnection service (SIS). The commission on March 19 only partially accepted an Order 845/845-A compliance filing by ISO-NE and New England Transmission Owners (NETOs), ordering a further compliance filing within 120 days. (See FERC OKs NETOs, Emera Maine Order 845 Filings.)

NEPOOL Transmission — RENEW Northeast presented a proposed NEPOOL response to ISO-NE’s request for clarification on FERC’s order on the RTO’s Order 845 compliance filing. | *RENEW*

Further changes will become effective March 19 once accepted by the commission, with a further compliance filing required by July 17, McBride said in presenting the RTO’s plans.

The TC will review the Tariff changes again on May 27 ahead of a planned vote by the Participants Committee at its summer meeting in June.

Narrower Approach

NEPOOL counsel Eric Runge said the organization reviewed ISO-NE’s April 20 request for clarification and contacted RENEW Northeast, which proposed the amendments that prompted NEPOOL to file its alternative and submit a protest last May.

“The only remaining issue here is surplus interconnection service,” said Susan Muller of Boreas Renewables, presenting RENEW’s analysis on SIS, the subject of which was last brought before the TC a year ago. (See NEPOOL Rebuffs ISO-NE on ‘Surplus’ Interconnection.)

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

RENEW says the RTO’s request appears to eliminate all, or nearly all, SIS eligibility. It asked that NEPOOL clarify for the commission “that the identification of the need for any additional interconnection facilities should not cause the end of the expedited process, because interconnection facilities are typically needed and this would prematurely end the analyses for most, if not all, SIS requests.”

Runge is writing a brief response to the RTO’s request that would address both the amount of SIS available from an NRIS resource, and the expedited process and language regarding interconnection facilities, he said.

The commission rejected the RTO’s proposed definition as it related to NRIS customers being limited to permanent service as opposed to periodic or other limited service.

Muller pointed out that while all generators have NRIS for provision of energy, only resources that have obtained a capacity supply obligation have CNRIS for provision of capacity.

She said Runge had a good suggestion in seeking some additional clarification from the RTO about when a resource has both NRIS and CNRIS, as “the relationship between those becomes very important in the context of surplus service.”

“It’s really important that there’s clarity about the fact that these two services coexist,” Muller said. “What we’re really talking about is: Can two devices or two resources share NRIS when one of them also has CNRIS?”

Liz Delaney, director of wholesale market development for Borrego Solar, supported the RENEW proposal.

“My company is developing a lot of hybrid resources, and we’re entering into this world where we’re going to need clarity on these issues soon,” Delaney said.

NETOs Settlement Close

The NETOs are nearing settlement with FERC staff and municipally owned power companies on pool transmission formula rates, with a commission administrative law judge on April 22 having ordered the hearing in abeyance until early June because of the COVID-19 pandemic.

On behalf of the NETOs, Eversource Energy’s director of transmission rates and revenue requirements, Lisa Cooper, presented an update on the regional network service (RNS) settlement proceeding initiated by the commission in 2015 (EL16-19).

The commission determined that transmission formula rates appear to be unjust and unreasonable, as they may be insufficiently specific with respect to calculation of some components.

Reporting for the Participating Transmission Owners Administrative Committee, Cooper said the commission argued that the RNS formula rate (Attachment F) may not be synchronized with local network service formula rates of individual transmission owners, which could potentially lead to over-recovery of costs.

The original settlement filed on Aug. 17, 2018, was opposed by FERC trial staff and contested by municipal TOs, and the commission rejected the settlement on May 22, 2019.

The parties reached agreements in principle in October 2019, and all parties are in the process of reviewing settlement documents and redline tariff changes, Cooper said.

May 3, 2020

NYISO Management Committee Briefs: April 29, 2020

NYISO will stop sequestering the operations teams at one of its two control centers even as the COVID-19 pandemic continues to reduce demand for electric power throughout New York, especially in New York City.

“We have made a decision, based on a number of factors, including the number of cases we are seeing locally in the capital region, that it is not necessary to continue to have operators sequestered at both control room sites,” NYISO Executive Vice President Emilie Nelson told the Management Committee on Wednesday.

“We plan to transition next week to have a single sequestered site at our Carmen Road facility,” Nelson said. “We will then be able to operate the Krey facility in a non-sequestered mode, but certainly with stringent, best practices in place from a health perspective.”

Most of the ISO’s staff continue to work effectively from home, she said.

In addition, the joint Board of Directors/MC meeting scheduled for June 15-16 will be held remotely, Nelson said.

COVID-19 Weighs on Load

The average location-based marginal price for March was $17.11/MWh, down from “the very low” $21.11/MWh in February and $34.91/MWh in March 2019, Vice President of Operations Wes Yeomans said as he delivered the CEO/COO report.

“The lower prices are not totally surprising as you move into March and to lower load from the impacts of the virus and lower fuel prices,” Yeomans said. “And about half the marginal price on average of last year — and again not totally surprising, given the situation.”

Demand Forecasting Manager Charles Alonge presented the estimated impacts of the pandemic on NYISO demand through April 24.

NYISO Management Committee — Regional impacts of COVID-19 on NYCA daily energy patterns | *NYISO*

“As you’ve noticed, we’ve been in a very consistent system pattern over the past four weeks with respect to the load deficit, which has leveled off at minus 8%” systemwide, Alonge said.

“The first quarter of 2020 was generally much warmer than average, and over the last two weeks, we have seen colder-than-average temperatures — some of you have experienced snow two weeks ago,” Alonge said. “Therefore, demand deficits have been ameliorated to some extent by colder-than-average weather over the past two weeks.”

As reported at the mid-month MC meeting, the biggest impact on load was seen in New York City’s Zone J, which also has the largest commercial percentage of load in the New York Control Area.

“Zone J is posting morning ramp load levels 20% below normal at 8 a.m.,” Alonge said.

Customer Satisfaction Trends Higher

An annual performance assessment and customer satisfaction survey conducted by the Siena College Research Institute (SCRI) shows NYISO last year scoring the highest marks — or matching the record — since a new platform was adopted in 2016.

“We simultaneously assess customer satisfaction and an assessment of the NYISO’s performance offered both by market participants and CEOs over the course of the year,” SCRI Director Don Levy said. “The 2019 final score for satisfaction at 91.1, and the performance assessment score of 76.7 are merged to achieve a unified score by combining 60% of the satisfaction score and 40% of the performance assessment.”

The year-end combined score was 85.4, he said.

The performance assessment score of 76.7 matches the ISO’s score from last year exactly, with a collective score of 75 equating to slightly above very good, Levy said.

Opportunities for improvement include explanation of policies and procedures; transparency; considerations of individuals’ input; comprehensive long-term planning for the state’s electric power system; advancing technological infrastructure; and providing factual information to policymakers, stakeholders and investors.

Bylaws Revisions Re. Press Access Approved

The MC approved changes to its own bylaws to make clear that nonmembers, including the public and press, may attend committee meetings in person or by teleconference.

Kevin Lanahan, NYISO vice president for external affairs and corporate communications, presented the revisions.

The press-related bylaws proposal was prompted by a request by RTO Insider to allow its reporters to attend committee meetings by teleconference, which the bylaws at the time forbade. (See Bid to Limit NYISO News Coverage Fails.)

Nonmembers must register beforehand and “announce their presence at the beginning of or upon entering the meeting by stating their name and any organizational affiliation(s),” according to the proposal.

“We made clear under this change that any recording in any format of the MC, and this will also go for the other committees, is prohibited except by the ISO,” Lanahan said. “This is a new change, a significant change. This language does not exist yet in the bylaws anywhere.”

The changes also clarify that the secretary, ISO staff and its counsel and advisers may attend and participate in discussions at meetings of the committee, including executive sessions, and clarifies that the Public Service Commission includes the Department of Public Service.

The bylaw changes now move for votes by the Business Issues Committee and Operating Committee, Lanahan said.

Tailored Availability Metric OK’d

The MC also approved Tariff changes for the tailored availability metric project and recommended the board approve a FERC filing under Section 205 of the Federal Power Act for a May 1, 2021, implementation.

Associate Market Design Specialist Emily Conway presented the project as part of the ISO’s “Grid in Transition” process to adapt to increasing amounts of renewable energy on the system. (See NYISO Focus Turns to Grid ‘Transition’.)

The tailored availability metric project is a market design based on analysis done for availability-based resources using the equivalent forced outage rate (EFORd) to determine the seasonal derating factor (AEFORd).

The EFORd is the portion of time a unit is in demand but is unavailable because of forced outages and derates. Under the project changes the ISO will weight peak months more heavily in the AEFORd calculation.

May 3, 2020

CMS Energy Stays Course Despite Virus Havoc

CMS Energy executives last week said they will stick to planned long-term investments and complete decarbonization plans despite uncertainties wrought by the ongoing COVID-19 pandemic.

However, the Michigan-based parent company of Consumers Energy also said it would institute some temporary cost-control measures.

“Our long-term investment thesis remains unchanged despite the near-term uncertainty presented by COVID-19. Over the years, we’ve been good stewards of the balance sheet, maintaining a healthy level of liquidity, and we plan conservatively. We still have a large and aging system and need a significant investment,” CEO Patti Poppe said during an April 27 first-quarter earnings call. “Our system remains in great need of replacements and upgrades, and that won’t go away as a result of the current pandemic.”

CMS Energy CEO Patti Poppe | *Whirlpool*

Consumers in February announced plans to achieve net-zero emissions by 2040. (See Consumers Energy Accelerates Zero-carbon Target.)

“Our net-zero carbon and methane goals remain as important today as the day we established them,” Poppe added.

The company so far seems financially unfazed by the onset of the coronavirus pandemic, reporting net income of $243 million ($0.85/share) for the first quarter of 2020, compared to $213 million ($0.75/share) for the same period last year.

CFO Rejji Hayes said Consumers has been experiencing 20 to 25% declines in commercial and industrial load based on its smart meter readings. However, Hayes said Consumers’ electric segment is more than 60% residential and offers the “highest margins.”

“The [commercial and industrial] load reduction has been partially offset by residential load, which is up over 5% over the same time frame, presumably due to mass teleworking and self-quarantine measures,” Hayes said. “So any uptick in growth in the residential segment should partially offset the expected declines we anticipate in the commercial and industrial segments.”

Despite the optimism, Consumers will implement a hiring freeze, minimize overtime and decrease travel and training expenses to save money, Poppe said.

“We have already implemented an initial wave of cost-control measures. Needless to say, we are not here to represent that any downside scenario can be overcome, particularly given the unprecedented nature of this global pandemic. However, we are confident that we can minimize the financial risk in 2020 without jeopardizing our long-term value proposition to our customers and investors,” Hayes said.

Poppe said CMS will take advantage of a recently approved measure by the Michigan Public Service Commission that allows deferred accounting for uncollectible account expenses above currently approved rates.

She also noted that Michigan regulators are reviewing other utility costs related to COVID-19. She said CMS hopes to defer other pandemic-related expenses, “including sequestration and quarantine-related costs.”

CMS currently reports that 11 of its more than 8,000 employees have tested positive for the virus.

“We’re thankful that seven of those coworkers have been able to return to work, and each identified case has yielded fewer and fewer ancillary cases of contact, which means our social distancing is working,” Poppe said.

May 3, 2020

PJM MC Preview: May 4, 2020

Below is a summary of the issues scheduled to be brought to a vote at the PJM Members Committee meeting on Monday.

Each item is listed by agenda number and description, 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 Tuesday’s newsletter for a full report.

Consent Agenda

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

7. PJM Board of Managers Nominating Committee

The Members Committee will be asked to elect a replacement to the Board of Managers for Susan Riley, who is retiring, and to re-elect Chairman Ake Almgren and member Charles Robinson.

The board waived its term limit policy for Almgren, who has been on the board since 2003, to allow him to serve an additional year to “ensure a successful leadership transition,” CEO Manu Asthana said. Since 2016, PJM rules have limited board members to five three-year terms.

The Nominating Committee selected Margaret “Margo” Loebl, who has 30 years’ experience with Fortune 500 companies in finance, accounting and risk management to replace Riley. Loebl is the former CFO of AgroFresh Solutions, which provides technologies and services to extend the shelf life of fresh produce.

May 3, 2020

PJM Outlines Revised MOPR Compliance Filing

PJM last week shared its initial response to FERC’s April 16 rehearing orders on the minimum offer price rule (MOPR), which required the RTO to make an additional compliance filing by June 1.

The commission rejected rehearing of its June 2018 order declaring PJM’s capacity market unjust and unreasonable (EL16-49-001, et al.) and virtually all of its December 2019 ruling spelling out the expanded MOPR (EL16-49-002, et al.) but provided clarification on several points. (See FERC: RGGI, Voluntary RECs Exempt from MOPR.)

Lisa Morelli, PJM director of capacity, demand response and compliance, gave the Markets and Reliability Committee a presentation Thursday highlighting where FERC’s directives diverged from PJM’s initial compliance filing in March. (See PJM Makes MOPR Compliance Filing.)

Morelli said PJM will share how it is addressing each issue cited by the commission in future meetings. “In many cases, we’re still working through the interpretation of these items in developing what our compliance approach is,” Morelli said.

State Subsidy Definition

FERC agreed with PJM that renewable energy credits (RECs) are not considered state subsidies if they are used and retired for voluntary obligations rather than for state-mandated renewable portfolio standards.

PJM MOPR Compliance — Lisa Morelli, PJM | © *RTO Insider*

The commission also backed PJM’s position that fees paid by resources under the Regional Greenhouse Gas Initiative are not state subsidies but clarified that RGGI payments to specific generation units are subsidies and subject to MOPR.

Morelli said one of the biggest surprises in the ruling was the denial of rehearing requests seeking to exempt state default service procurements from the definition of a state subsidy, a ruling she said PJM will have to address in its new filing.

FERC’s directive can be read broadly to cover any resource that contracts to supply generation to a load-serving entity that won tranches of load in a default service auction, she said. But she said references to “specific winning resources” suggests “there are also more narrow readings that are reasonable, as well.”

Impacts to MOPR Floor Prices

PJM’s initial compliance filing based MOPR floor prices for energy efficiency on the verifiable level of savings. But FERC directed that the EE floor price be based on net cost of new entry (CONE) or — for existing resources — net avoidable-cost rate (ACR).

The net CONE and ACR must include the cost of measurement and verification, Morelli said, prompting PJM to examine whether further revisions may be needed to address the issue.

The commission also said net ACR should be based on resource-specific revenues rather than zonal averages, as PJM had suggested.

FERC also said PJM’s compliance filing should not contain any substantive changes to its existing MOPR rules; until the December order, MOPR applied only to new natural gas resources. Morelli said the order creates two different MOPR floor levels — one for new-entry natural gas and the expanded MOPR for state-subsidized resources.

New/Existing Capacity Resources

FERC clarified that only the cleared portion of a resource’s megawatts will be treated as an existing resource.

The commission denied a requested clarification that demand resources should be considered existing if they had previously cleared an auction regardless of the number of megawatts offered. The commission said demand resources increasing the number of megawatts they offer year to year must explain that the increase is not connected to additional construction costs or state subsidies that make the uprate possible.

Resources not subject to the Capacity Performance must-offer requirement, including demand response and intermittent renewables, will be treated as new resources if they seek to re-enter the capacity market after sitting out an auction.

Bilaterally procured capacity from a state-subsidized resource cannot serve as replacement capacity for unsubsidized capacity resources, the commission said, clarifying that public power self-supply entities cannot engage in voluntary, bilateral contracts with unaffiliated third parties without triggering the MOPR.

Morelli said PJM tried to balance FERC’s directive that public power is state-subsidized with not impeding normal commercial activity in contracting between public power and merchant entities. “We’re still evaluating this provision and whether it will indeed have an impact on our compliance filing.”

Stakeholder Responses

Tom Hyzinski of GT Power Group asked how PJM’s additional compliance filing could affect the capacity auction dates.

Morelli said the intention was to run the first auction about six and a half months after receiving FERC approval on its compliance filings. She said the auction has been set up as a “floating schedule” contingent upon receiving FERC approval, with PJM still anticipating that it could hold an auction by the end of the year.

Bruce Campbell, director of regulatory affairs for CPower, said that because FERC rejected rehearing requests to exempt EE from the MOPR, there needs to be a “fairly robust resource-specific offer methodology” established. Campbell asked PJM to give the process immediate attention recognizing that they will be new for staff and stakeholders.

“I think it’s incumbent on parties to really get a good understanding of how that will work before we push up against the deadline,” Campbell said.

PJM Independent Market Monitor Joe Bowring invited stakeholders concerned with the EE methodology to contact his office. “We’ll provide a template,” he said. “We’re committed to make it work efficiently.”

PJM will hold a stakeholder “listening session” regarding the FERC orders in a special meeting of the Market Implementation Committee on May 6 and a detailed session at the MIC’s regular meeting May 13. Rehearing requests are due to FERC by May 18, three days after the deadline for comments on PJM’s March compliance filing.

The RTO will also hold a final information session — tentatively scheduled for May 28, pending the agenda for the Markets and Reliability and Members committee meetings — before making its new compliance filing.

May 3, 2020

SPP Joint Quarterly Stakeholder Briefing: April 27, 2020

SPP CEO Barbara Sugg assured stakeholders that the RTO is taking very careful steps to reopen while the COVID-19 pandemic still rages, making clear it will be a slow process.

“We don’t want a flood of people back in the office,” Sugg said during the Joint Quarterly Stakeholder briefing April 27.

SPP Quarterly Stakeholder — SPP CEO Barbara Sugg addresses her virtual audience during the Joint Stakeholder Briefing.

She said SPP must first see a 14-day downward trajectory of cases in Arkansas, where it is based. “That hasn’t happened yet,” she said.

As of Thursday, Arkansas had more than 3,200 confirmed cases of COVID-19. Almost 1,300 of those cases have recovered, but 59 Arkansans have died. Sugg said no employees have tested positive for the virus.

The downward slope of confirmed cases is just one trigger SPP must meet before allowing its 622 employees to return to its Little Rock headquarters. Staff will return in five phases, 20% of the employees at a time.

“We’re in no hurry. This conservative approach to returning to the office will be extremely critical,” Sugg said. “We’re not calling it [return to work]. We’re calling it return to office. We’re not really working from home. We’re really working from about 500 different places.”

SPP Extends Wind, Renewable Penetration Marks

Bruce Rew, senior vice president of operation, backed off recent statements that wind could become SPP’s No. 1 source of generation in 2021.

“If we keep up the way we’re going, wind may be our No. 1 resource in 2020,” he said.

Rew was speaking several hours after the grid operator set new records for wind and renewable penetration. Both records came at 1:24 a.m. CT on April 27, with wind accounting for 73.2% of the fuel mix and renewables for 78.2%.

Rew said SPP has enough wind generation to exceed an 80% penetration level but that 75% might be more realistic. He said wind energy’s low prices would dampen more traditional generation forms, increasing its share of the fuel mix.

SPP has 22.7 GW of wind registered in its market. Wind output in the first quarter was up from the previous year.

Asked whether there is an upper limit to the amount of wind generation SPP can provide, Rew said, “As long as we have the resources to manage reliability, there’s no upper limit.”

Maintenance Outages Being Deferred Until Winter

COO Lanny Nickell said some member companies are deferring generator maintenance activities that would normally take place in the spring.

“We’re performing analyses to understand the implications of canceled and deferred outages, and we’ll share that information with our members so they can take precautionary actions and develop more informed plans,” Nickell said. “We expect to have excess generation capacity in winter 2021, which gives some headroom to take more outages then.”

SPP has seen a continued drop in load, with a reduction of between 5 and 7% for the week of April 19, as compared to historical load patterns.

FERC Makes Accommodations for COVID-19

FERC Relaxing Deadlines, Enforcement.)

The Office of Enforcement is postponing all previously scheduled audit site visits and investigative testimony. Technical conferences scheduled through May will be conducted via conference call or webinars, or postponed, and settlement conferences will continue through conference calls, Clarey said. Schedules will be posted to the FERC calendar.

Clarey said FERC’s 1,400 employees are working safely from home.

RSC Endorses Z2 Credits’ Elimination

The Regional State Committee met virtually for a brief discussion before the quarterly update, taking time to unanimously endorse a revision request (RR 401) that ran into opposition from renewable and independent generation developers before the Markets and Operations Policy Committee. (See “SPP MOPC Briefs: April 14, 2020,” MOPC Approves 2nd Run at Z2 Credits Elimination.)

The change eliminates Z2 revenue credits for sponsored transmission upgrades, replacing them with incremental long-term congestion rights (ILTCRs). EDF Renewable Energy again complained that SPP’s version of ILTCRs is “woefully inadequate” and not as “robust” as those in other markets.

Kansas Corporation Commissioner Shari Feist Albrecht told the group that the RSC and Organization of MISO States’ Seams Liaison Committee (SLC) hopes to conclude its work by the end of the year. The committee, composed of regulators from both RTOs’ states, have been working for almost two years on improving the grid operators’ interregional planning processes and other seams issues.

The SLC has scheduled a conference call on May 11 to review reports and studies from the RTOs’ market monitors. SPP’s Market Monitoring Unit has produced a study on coordinated transaction scheduling and Monitor Casts Doubts on MISO-SPP CTS Benefits.)

KCC staffer Christine Aarnes told the RSC that the Cost Allocation Working Group plans to bring a white paper on a proposed byway facility cost allocation review process to the committee’s July meeting for its approval.

Noting there is more generation than load in some areas, Aarnes said, “Byway facilities intended for local traffic are being used for highway traffic to export that energy.”

The CAWG is working on the Holistic Integrated Tariff Team’s recommendation to evaluate a narrow process through which 100- to 300-kV regionally funded byway project costs can be fully allocated on a region-wide basis. The review includes new and existing facilities under Schedule 11 of the Tariff.