Page 1088 – RTO Insider

June 1, 2020

UCS Analysis Knocks Coal Self-commitments

Coal plant self-commitments saddled Midwest electricity customers with $350 million in unnecessary costs in 2018, according to a new analysis from the Union of Concerned Scientists, which is calling on regulators to rein in the practice through investigations.

“Used, But How Useful?” concludes that individual ratepayers could have saved an average of $60 if the most efficient existing resources in MISO were deployed instead of coal self-scheduling in 2018.

“We found that not every coal plant in the Midwest operated uneconomically, but the utilities that did it the most drove down market prices, effectively squeezing out cleaner, cheaper sources such as wind and solar power,” Sandra Sattler, senior energy modeler at UCS, said in a press release.

UCS said savings from eliminating the self-dispatches could have more than doubled the amount MISO claimed it saved its members that year through efficient centralized dispatch. The RTO’s 2018 value proposition estimated its efficient energy dispatch saved members anywhere from $282 million to $312 million during the year.

“We decided that having a published report on which utilities were not acting in the public interest would be useful to regulators. We hope this will be a helpful tool for commissioners trying to tackle this problem,” UCS Climate and Energy Senior Energy Analyst Joe Daniel told RTO Insider.

This isn’t the first time UCS has publicly questioned the practice of vertically integrated utilities being allowed to operate units out of merit at times when their production costs exceed the wholesale market price. UCS pressed the issue last year at the National Association of Regulatory Utility Commissioners’ annual meeting. (See Enviros, States Question Coal Self-commitments.)

Daniel said the solution isn’t as simple as just abolishing must-run designations in MISO.

“There are plenty of power plants that use the must-run designation economically,” he said. “The uneconomic commitments will continue in another loophole unless state regulators come in and stop it.”

Daniel said a good first step for regulators is to open investigatory dockets into utilities that exhibit high costs.

“That way there’s a frank discussion between regulators, utilities and intervenors,” Daniel said. “The regulators have an obligation to disallow imprudent costs. … Running power plants that are expensive when there’s lower-cost energy available on the open market is imprudent. … If a commission would scrutinize and disallow tens of millions in imprudent costs, I am confident that the utility’s reaction would be to figure out how to solve the problem themselves. Smart utilities won’t let it get to that point. Smart utilities will see that commissions are taking things seriously and be proactive.”

When the Minnesota Public Utilities Commission opened a docket last year to investigate Xcel Energy’s self-scheduling of coal plants, Daniel said, the utility quickly proposed converting its coal plants to seasonal and economic use. Missouri and Indiana have also opened investigatory dockets into utility self-commitments. (See Ind. Regulators Scrutinize Duke Self-commitments.)

Biggest Offenders

According to the UCS report, Xcel subsidiary Northern States Power uneconomically ran its Allen S. King and Sherburne Country coal plants at a $56.9 million loss in 2018. If the utility had opted for more efficient generation in the MISO market, the average residential ratepayer could have saved $54 that year, UCS said.

UCS named Cleco Power the worst offender, saying it uneconomically generated electricity from its Dolet Hills and Brame Energy Center coal plants at a $123.3 million loss in 2018, costing Louisiana ratepayers an average of $184 over the year compared with more economic electricity available in the market.

Dolet Hills co-owners Cleco and Southwestern Electric Power Co. have indicated they may retire the plant as early as 2021. Earlier this year, the utilities agreed to retire the plant by 2026 as part of a deal reached with the Sierra Club. The conservation group has claimed that closing the plant would save ratepayers more than $60 million per year.

UCS Coal Self-commitments — Dolet Hills power plant | *Cleco Power*

Cleco spokesperson Jennifer Cahill pointed out that the company and SWEPCO pledged beginning last year to only operate Dolet Hills in the demand-heavy summer months, or when requested by MISO.

“Furthermore, Cleco Power intends to seek regulatory approval to retire the Dolet Hills Power Station and the nearby mine that supplies the plant with coal. The closing dates for the power station and mine will be subject to discussions with stakeholders, including the Louisiana Public Service Commission and regional transmission organizations,” Cahill said in an email to RTO Insider.

DTE Energy’s five coal plants uneconomically generated power at a $94.7 million loss in 2018, costing individual ratepayers an extra $61, UCS also reported.

UCS said MISO’s greatest potential for savings “generally appear where the worst actors operated: Xcel Energy in Zone 1, Cleco in Zone 9, and DTE and Consumers Energy in Zone 7.”

The report also said coal self-commitments in MISO suppressed market clearing prices by 2.4% — or 63 cents/MWh — in 2018. The group also noted the self-commitments suppress independent power producers’ revenue in “all MISO transmission zones.”

“By exploiting gaps in regulatory oversight and loopholes in wholesale market rules, rate-regulated utilities are cutting ahead in the merit-order line. Rate regulation, coupled with a lack of scrutiny when it comes to cost recovery, has enabled these utilities to lose money in the market without incurring actual losses on their balance sheets,” UCS wrote, adding that in many parts of the U.S., the cost to buy and burn coal “exceeds the market price in most hours of the year.”

Self-commitment ‘Loopholes’

UCS said it makes economic sense for coal plants to respond to market price signals and begin operating more infrequently, allowing lower-cost natural gas and renewables to fill the gap. But the group characterized existing state regulatory frameworks and rate cases as “loopholes” that allow unchecked self-commitment decisions to persist.

“It is doubtful that changes to this practice will materialize if regulated utilities are continually allowed to recover fuel costs, without scrutiny or incentives to improve operations,” UCS said. “Utilities will throw up strawman excuses for why their coal plants are so uneconomic, but it is not incumbent on the regulator to innovate on behalf of the utility. Rather, utility companies are obligated to come up with a solution, and regulators should either approve or disapprove of the companies’ proposals.”

Daniel said residential ratepayer costs are more important than ever, with many staying at home more often because of the ongoing coronavirus pandemic.

And he said new resource additions to achieve UCS’ saving estimates are unnecessary.

“You could safely operate the grid with lower-cost existing resources that already exist. You should use what you have as efficiently as possible. And that’s not what happening. Utilities are preferentially selecting coal-powered plants at the expense of customers,” Daniel said.

To arrive at the millions in potential savings, UCS used modeling software that accounts for MISO system limitations, transmission constraints and power plants’ ramping times and capabilities, Daniel said.

He acknowledged that MISO aggregates the number of uneconomic coal commitments in its footprint but doesn’t call out specific generators or utilities like UCS’ latest analysis.

“What really differentiates this research is we used a production cost model and the same software MISO does to come up with these numbers,” Daniel said.

June 1, 2020

ERCOT Technical Advisory Committee Briefs: May 27, 2020

Given the continued uncertainty of future in-person meetings, ERCOT stakeholders last week endorsed several bylaw amendments and rule changes to improve electronic meetings and votes.

As if to hammer the point home, the changes were among 15 voting items in an email vote that did not become official for two days. ERCOT rules currently require two full business days to allow stakeholders to return their votes.

Vickie Leady, ERCOT’s assistant general counsel, told the Technical Advisory Committee on Wednesday that the grid operator’s bylaws “never contemplated a situation with the scale and duration” in which stakeholders “could not safely convene together in one place.”

“It’s creating a risk to ERCOT,” Leady said.

ERCOT closed its facilities to most outside visitors and canceled in-person meetings in early March. Meetings have been conducted virtually ever since.

Legal staff proposed widening the definition of “urgent matters” to include when it would be “difficult or impossible” for a quorum of directors or subcommittee members to physically convene in one location. The changes would allow teleconference meetings and actions that, if otherwise delayed, “may result in operational (including, but not limited to those activities and functions affecting the ERCOT market or system), regulatory, legal, organizational or governance risk.”

Staff made other changes to the bylaws to closely align with the Texas Open Meetings Act and Texas Business Organizations Code’s teleconference technology methods.

The changes will now go before the Board of Directors during its June 9 teleconference. If approved, the board would issue a call on June 10 for a special meeting to vote on the bylaw changes by July 2. The changes would then be filed with the Texas Public Utility Commission by July 31 for its approval.

The TAC also approved several changes to its rules allowing for roll call votes. Chair Bob Helton, with ENGIE, said the committee would be using consent agendas to compensate for the extra time taken by email votes.

Corpus Christi Tx Project Gets OK

The TAC unanimously approved a $219 million transmission project, previously approved by the Regional Planning Group, that addresses more than 1 GW of future industrial load growth on the north shore of Corpus Christi Bay expected by 2024.

As recommended by staff following an independent review of AEP Texas’ proposal, the Corpus Christi North Shore RPG Project will comprise 36 miles of 345-kV lines, 8 miles of new and upgraded 138-kV lines, two new 345-kV substations and three 345/138-kV transformers.

LNG plants account for more than half of the additional load. Cheniere Energy has developed an LNG export terminal in Corpus Christi’s harbor. Two trains are currently in operation, with a third planned to come online in the first half of 2021.

ERCOT’s review concluded that its recommended option does not cause new or additional congestion. Staff determined the 138-kV upgrade met economic planning criteria and added it to the project.

AEP’s Richard Ross said the company “supports and is comfortable at this point in time” with ERCOT’s recommendation.

ERS Payments up 1.6% to $48.2M

Staff shared ERCOT’s annual report on its emergency response service but received no questions from members. The report is required annually by the PUC (27706).

According to the report, demand response and behind-the-meter generation received $48.2 million in capacity payments during the program year for curtailing load or sending power to the grid, a 1.6% increase from the $47.5 million for the previous time period.

ERCOT deployed ERS twice last year during August’s two energy emergency alerts. The two deployments lasted a total of 95 minutes.

Members Disagree over Change to ERS’ Return

The TAC on Friday took up a second email vote to consider the only Nodal Protocol revision request (NPRR1006) that did not clear the email vote.

In a vote that closes at 5 p.m. Tuesday, committee members will weigh NPRR1006’s approval as amended by comments from Direct Energy.

The NPRR had received only four votes (Lower Colorado River Authority, South Texas Electric Cooperative, Exelon and Reliant Energy Retail Services), with 20 members opposing and two abstaining.

The change would return ERS resources in a linear curve over a four-and-a-half-hour period following recall, instead of 10 hours. It also changes the process for annually updating the parameter by removing a real-time deployment price adder from the real-time ancillary service imbalance payment or charge.

Direct Energy expressed concern over the unintended consequences of the price adder’s elimination from the equation. The company urged interested parties to file their proposed changes in a separate NPRR “to facilitate the quick movement of the original intent of this NPRR through the approval process.”

Direct Energy’s Sandy Morris said stakeholders have not had the time or analysis to understand the full implications of the proposed change. Should the matter be separated, she wrote, “it could possibly continue through the proper channels of analysis and debate and still be implemented at the same time as … NPRR1006.”

The committee’s email vote unanimously approved eight other NPRRs, a change to the Nodal Operating Guide, an Other Binding Document revision request (OBDRR) and two system change requests (SCRs):

NPRR 933: adds specific timing requirements for retail electric providers and non-opt-in entities to notify ERCOT of the DR and price-response programs they offer to customers, the level of participation in those programs and the deployment events associated with those programs.
NPRR9 75: clarifies that load forecast models will be used to select the seven-day load forecast based on expected weather and requires ERCOT operations to explain its selection, improving transparency for market participants.
NPRR9 87: includes the contribution of energy storage resources (ESRs) to physical responsive capability and real-time online reserve capacity in the ancillary service imbalance calculation.
NPRR9 8 9: establishes ESRs’ technical requirements for voltage support service (including reactive power capability) and primary frequency response.
NPRR 1018: clarifies several provisions regarding the termination and suspension of a qualified scheduling entity (QSE) and the ability of a load-serving entity or resource entity to act as a “virtual” or “emergency” QSE.
NPRR1019: addresses switchable generation resources (SWGRs) moving from a non-ERCOT control area to the ERCOT control area by creating a proxy energy offer curve with a price floor of $4,500/MWh for each RUC-committed SWGR and including a lost revenue cost component to the switchable generation cost guarantee.
NPRR10 21: shortens the default uplift invoice’s issuance timeline from 180 days to 90 days and allows ERCOT to use the best available settlement data when calculating each counterparty’s share of the default uplift.
NPRR 1022: modifies how QSEs and congestion revenue right account holders (CRRAHs) submit banking information changes to ERCOT by removing the ability to submit the information with a Notice of Change of Information via email or fax. The NPRR creates a new form, Notice of Change of Banking Information, that a QSE/CRRAH must execute and submit through the market information system’s certified area.
N OGR R 204: together with NPRR989, codifies concepts described in the Battery Energy Storage Task Force key topics and concepts No. 4 (KTC-4) and establishes ESR technical requirements.
OBDRR017: aligns language within the operating reserve demand curve’s methodology for calculating the real-time reserve price adder with protocol revisions under NPRR987 and changes the real-time operating reserve calculation to consider an ESR’s state of charge when calculating the resource’s contribution to the online operating reserves.
SC R 807: increases the CRRAHs’ total CRR transaction limit by 33% to 400,000 market transactions during CRR auctions.
SC R 809: updates the validation rules imposed on ERCOT’s external telemetry and used in the resource limit calculator.

June 1, 2020May 6, 2025

NEPOOL Markets/Reliability Committee Briefs: May 27, 2020

Participants at a joint meeting of the New England Power Pool Markets and Reliability committees were encouraged to look west, think big, consider NYISO’s example in planning for a grid in transition and keep the bigger picture in mind to avoid getting bogged down in irrelevant details.

Advanced Energy Economy (AEE) submitted a paper recommending that ISO-NE and NEPOOL consider borrowing from NYISO’s effort, which identified as its central proposition: “how the wholesale markets in New York can continue to provide the pricing and investment signals necessary to reflect system needs and to incent resources capable of resolving those needs.”

New England’s study “should similarly address the transition to the future grid, not just the end state,” AEE said.

NYISO in December 2019 issued its Grid in Transition report to map the planning for a grid increasingly dominated by a slew of clean energy resources, a transition driven primarily by state policy. The ISO this year is devoting at least one day a month for stakeholders to discuss reliability and market issues related to the challenge of integrating renewable resources. (See NYISO Focus Turns to Grid ‘Transition’.)

Change in New York supply, 1990-2040 | NYISO

“Importantly, discussion of these potential market reforms is not being held up while The Brattle Group completes a longer-term quantitative analysis as part of a related but separate process that kicked off earlier this year,” AEE said.

Brattle representatives in May presented NYISO stakeholders with an interim report on New York’s evolution to a zero-emission power system, modeling operations and investment in scenarios of increasing electrification for the years 2024, 2030 and 2040. They are considering feedback before presenting the final study results in June. (See NYISO Examines ‘Evolution’ to Zero Emissions.)

Focus on Task

New England States Committee on Electricity Senior Counsel Ben D’Antonio presented NESCOE staff’s preliminary thinking on the transition study that NEPOOL expressed interest in conducting. The presentation was to focus stakeholders on prior and ongoing studies to help define what study areas remain.

In response to a stakeholder question about possible gaps in current market rules, NESCOE Director of Analysis Jeff Bentz clarified the states’ collective aim.

“We didn’t want to be in a place where we are with ESI [Energy Security Improvements], where we have this market construct problem and we’re all forced to do it in a hurry,” Bentz said. “The idea here was, can we look at where we think we’re going to be 10 years from now and then try to determine whether the market construct we have today will work in that future state, and if not, what market construct will we need?” (See ISO-NE Sending 2 Energy Security Plans to FERC.)

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

Bentz added that “by knowing where we need to be in the future, it could inform the best transition path.”

Pete Fuller of Autumn Lane Energy agreed that NEPOOL and the RTO need to focus on a “broad-brush” effort.

NESCOE points out the gap in current studies between business-as-usual versus mitigation scenarios through 2050 for New England. | NESCAUM

The goal isn’t to hit a precise target, such as “intercepting an asteroid in a particular time and place,” but to establish a market framework to move the system in the right direction, said Fuller, who presented recommendations with the endorsement of NEPOOL members NRG Energy and Sunrun.

“I’m concerned that we could get ourselves caught in some highly detailed analysis … and missing the big picture here,” Fuller said.

“I think we can make a number of assumptions about what is the transmission topology and that it will resolve itself over time as offshore wind gets developed and integrated, as new resources enter, as electrification happens and flows change, as energy storage comes and so forth,” Fuller said. “That all can largely be left to be worked out by parallel, different processes, not this one.”

Giving policymakers comprehensive economic comparisons of various levels of decarbonization? Determining whether the region needs a higher-voltage bulk network, potentially including offshore cables, to integrate the future resource mix? Evaluating the technical potential and viability of hydrogen electrolysis and storage, CCS, modular nuclear and any number of other new technologies?

“That’s not our task here,” Fuller said.

The task, according to Fuller, is to focus on two key questions: “Will our current market designs support a reliable low-carbon resource mix? And if not, what should we do about it?”

Future is Now

Other stakeholders said that New England has already effectively started the future grid planning process, as Brattle last September issued a study on what the region must do to achieve at least an 80% reduction in greenhouse gas emissions by 2050.

Xiaochuan Luo, ISO-NE technical manager for business architecture and technology, presented a slidedeck covering the RTO’s current capabilities for modeling and tools addressing various time horizons.

“If the Future Grid study would benefit from these capabilities, the ISO offers them to assist in that effort,” Luo said. “If there is a gap between our modeling processes and tools and those deemed necessary for the Future Grid studies, the ISO will work with stakeholders on the best way to address such gaps.”

The RTO is accepting stakeholder proposals for what kinds of analysis should be performed in the future grid study and associated analysis assumptions this year, with agenda topics and timing to be submitted to the MC secretary by June 12 for the next meeting.

May 31, 2020

PJM MRC Briefs: May 28, 2020

Stakeholders at PJM’s Markets and Reliability Committee meeting on Thursday endorsed a proposal to allow market participants to use surety bonds as collateral that had been awaiting a vote for more than a year.

The proposal, originally endorsed in October 2018 at the Market Implementation Committee with 61% support, allows the use of surety bonds as collateral for all market purposes except financial transmission rights, with a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer. It was endorsed Thursday through acclamation vote with three members voting “no” and three abstaining.

If the Tariff change is approved at the Members Committee meeting on June 18, PJM said it will require the use of bond companies on the U.S. Treasury Department’s certified list and a minimum credit rating of A with S&P Global Ratings, Fitch Ratings and AM Best, or A2 with Moody’s Investors Service. PJM also will require one-day payment demand terms.

PJM’s Kathleen McElwaine reviewed the proposal, which was deferred at the December 2018 MRC meeting until completion of the independent consultants’ report on the GreenHat Energy default. It was deferred again in April 2019 pending PJM’s appointment of a chief risk officer and a new chief financial officer. (See PJM Stakeholders OK Risk Management Task Force.)

PJM opposed a proposal by Exelon that would have allowed surety bonds as collateral for all market purposes including FTRs, citing limited experience in the use of surety bonds in FTR markets and the large size of past FTR defaults. The Exelon proposal also would have set a $20 million cap per issuer for each member and a $100 million aggregate cap per issuer.

Sharon Midgley of Exelon said her company supports the PJM package as an initial framework to introduce surety bonds into the market. Exelon maintains its proposal is better suited for the market and may consider proposing a change in the future, Midgley said.

She said the PJM package is “inferior” because its caps are more restrictive than those of ERCOT and NYISO. Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the advocates had been struggling to find the best approach for the issue but found a “comfort level” with PJM’s endorsement.

“It’s been a good stakeholder process to allow PJM to get the expertise together and to help consumers make an informed decision on this,” Poulos said.

PMA Credit Requirements

Members endorsed a “quick fix” Tariff revision to address a regulatory change in Ohio concerning the billing of network integration transmission service (NITS). The change was endorsed through acclamation, with one abstention.

In 2015, the Public Utilities Commission of Ohio moved NITS and other related charges to a non-bypassable rider that is the responsibility of the electric distribution company. The change means competitive retail electric suppliers serving load in Ohio are no longer allowed to collect NITS or any other transmission-related charges from end-use customers.

PJM requires load-serving entities to sign NITS agreements and post collateral based on their peak market activity (PMA) and gives itself the ability to make changes to a participant’s PMA requirement when the RTO determines the PMA is not representative of expected activity. (See “‘Quick Fix’ on PMA Credit Requirements,” PJM MIC Briefs: April 15, 2020.)

Capacity Capability Senior Task Force Issue Charge

Members unanimously endorsed revisions to the issue charge of the Capacity Capability Senior Task Force in response to FERC orders issued April 10 concerning PJM’s methodologies for determining the capability of all resource types (ER20-584 and EL19-100).

PJM’s Andrew Levitt said that when the task force was launched on April 7, the RTO hoped FERC would hold the proceedings in abeyance until Jan. 29, 2021, when it planned to file Tariff changes applying effective load-carrying capability measurements for all intermittent and limited-duration resources. FERC instead gave a deadline of Oct. 30, Levitt said, requiring changes to the timing and the scope of the issue charge. Under the revisions, all resources will be considered in the first phase of the initiative rather than just wind, solar and storage. (See PJM MRC Moves Forward on Storage, Hybrids.)

Fuel Requirement Issue Charge

Stakeholders unanimously endorsed changes to the Fuel Requirements for Black Start Resources issue charge, removing the minimum tank suction level (MTSL) from the key work activities. The activity was added to the newly approved Black Start Unit Involuntary Termination & Substitution Rules issue charge.

The Independent Market Monitor recommends that only a proportionate share of the MTSL for oil tanks shared with other resources be allocated for black start units. (See “Black Start Issue Charge Endorsed,” PJM Operating Committee Briefs: May 4, 2020.)

Work on the black start issue is expected to take two to three months, and implementation of needed changes to governing documents is estimated to take about six months following the approval of Tariff changes.

Task Force Sunset

PJM’s Dave Anders presented a list of task forces the RTO is proposing to sunset because they have been dormant.

Anders acknowledged that some stakeholders are concerned about whether some of the groups that were being targeted would need to be reactivated because of new developments, including pending FERC orders.

Several of the task forces on the list have not met for several years, including the Generator Offer Flexibility Senior Task Force (last meeting November 2015), the Energy Market Uplift Senior Task Force (March 2017) and the Primary Frequency Senior Task Force (December 2018).

Anders highlighted a few of the task forces proposed for sunset that saw recent activity, including the Modeling Generation Senior Task Force (MGSTF) that last met on May 15 and the Distributed Energy Resources Subcommittee (DERS) on May 18.

Glen Boyle of PJM provided a report on the potential sunset of the MGSTF, as well as work completed regarding soak time and corresponding voting results. Soak time refers to the minimum period a unit must run from the generator breaker closure until it is dispatchable. (See “Modeling Generation Senior Task Force Recommendations,” PJM MRC Briefs: Dec. 19, 2019.)

The task force, created in 2017, developed the solutions to improve resource modeling for “complex resources” in PJM’s market clearing engines, including combined cycle units, coal units with multiple mills and pumped hydro. Boyle also presented a final report on the task force.

PJM’s Scott Baker discussed a proposal to consolidate the DERS and Intermittent Resources Subcommittee to create the DER and Inverter-based Resources Subcommittee (DIRS). The charter calls for providing a stakeholder forum to investigate issues and procedures related to distributed energy resources and inverter-based resources, including generation or electric energy storage resources connected to the distribution system and/or behind the meter.

Anders said stakeholders will be asked to endorse the task force sunsets at the next MRC meeting.

May 31, 2020

NEPOOL Transmission Committee Briefs: May 27, 2020

The New England Power Pool Transmission Committee on May 26 voted to recommend the Participants Committee support ISO-NE’s filing to address rejected portions its FERC Order 845 compliance filing (ER19-1951).

The PC will vote on the issue at its June 4 meeting.

FERC issued Order 845 in 2018 to set pro forma minimum standards for large generator interconnection procedures and agreements. In its March ruling on ISO-NE’s original compliance filing, the commission rejected the RTO’s proposed rules related to the availability of surplus interconnection service (SIS), which allows an affiliate or third party to obtain unused interconnection service from an original customer. That was followed by a May 19 reject ion of the RTO’s request for clarification on the issue.

“While ISO-NE’s pleading nominally styles itself as a ‘Motion for Clarification,’ in substance, it is a request for rehearing because, for example, ISO-NE is asking the commission to reconsider the requirement to identify the specific upgrades necessary for surplus interconnection service,” FERC said.

ISO-NE Director of Transmission Strategy and Services Al McBride presented the RTO’s plans regarding the application of SIS in relation to network resource interconnection service, developed in response to stakeholder feedback from the April TC meeting. (See NEPOOL Transmission Committee Briefs: April 28, 2020.)

“Committee members described how arrangements could be made, for example, to identify when the surplus customer would not operate when the original customer needed to operate,” McBride’s presentation noted.

McBride said the ISO-NE has continued to “evolve” its understanding of how co-located resources using SIS can operate in the energy and capacity markets, including when a limiting device is used to limit the overall output of a co-located facility. The RTO is proposing that the original interconnection customer would identify and eventually memorialize in the interconnection agreement the terms of use of the SIS, McBride said.

The RTO is also now proposing to adopt FERC’s Order 845/845-A pro forma language regarding the scope of study for SIS requests, he said.

“They did speak to the scope of study in their response, and I think that essentially constituted feedback to us,” McBride said.

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

Further changes will become effective March 19 if accepted by the commission, with the compliance filing required by July 17.

Settlement with NETOs on PTO Rates

The TC voted to recommend that the PC support ISO-NE Tariff revisions to carry out the settlement agreed to among New England Transmission Owners (NETOs), FERC staff and municipal utilities on pool transmission formula rates (EL16-19).

A FERC administrative law judge on April 22 ordered the hearing in abeyance until early June because of delays related to the COVID-19 pandemic.

On behalf of the NETOs, Eversource Energy’s director of transmission rates and revenue requirements, Lisa Cooper, updated the TC, as she did in April, on the regional network service settlement proceeding initiated by the commission in 2015. The TC discussed the matter in executive session.

May 31, 2020

Online Protesters Reject NY Gas Supply Plans

More than 130 New Yorkers gathered in an online forum Thursday for a “people’s hearing” organized by nearly a dozen environmental groups to protest the possibility of National Grid increasing the state’s supply of natural gas by adding vaporizing capacity, trucking in compressed natural gas and other measures.

NY Gas Protesters — Michaela Ciovacco, NYCP

“This people’s hearing marks an unprecedented coming together of campaigns and minds to tackle getting off fracked gas and moving to renewables, first by focusing on the upcoming June 11 decision by the [New York] Public Service Commission on National Grid’s plan to meet downstate energy demand,” said Michaela Ciovacco of New Yorkers for Clean Power (NYCP).

The group helped organize the event as a member of Renewable Heat Now, along with Sane Energy Project, Alliance for a Green Economy, Mothers Out Front, Sierra Club, Food & Water Action, NY Renews, Stop the Williams Pipeline Coalition, Heatsmart Tompkins and No North Brooklyn Pipeline.

New Jersey and New York regulators two weeks earlier denied permits for the Williams pipeline, also known as the Northeast Supply Enhancement (NESE) project, which would have carried natural gas from Pennsylvania across New York Harbor into the Rockaways, Queens.

“Neither the utility nor the Public Service Commission have scheduled a public hearing, so that’s why we came together,” Ciovacco said.

The organizers claimed that any increase in fossil fuel usage would violate the spirit and the letter of the state’s Climate Leadership and Community Protection Act, signed into law last July. It mandates that 70% of the state’s electricity come from renewable resources by 2030 and that generation be 100% carbon-free by 2040. (See Cuomo Sets New York’s Green Goals for 2020.)

Conflicting State Policies

National Grid spokesperson Karen Young told RTO Insider that a May 8 press release detailed how the company has been fulfilling its 2019 agreement with the PSC to propose long-term solutions for downstate gas supply and demand.

The company’s “no-infrastructure” option includes reducing gas demand through incremental energy efficiency measures, demand response and electrification.

The company this past winter and spring held six public meetings attended by more than 800 people, and altogether more than 7,500 public comments have been filed with the PSC.

National Grid non-gas proposal | *National Grid*

National Grid found itself at odds with Gov. Andrew Cuomo last November when he criticized a company moratorium on new gas hook-ups that the company attributed to supply concerns. Cuomo issued a letter demanding that its gas subsidiaries connect all customers for whom it had denied service under the moratorium or he would seek “to revoke National Grid’s certificate to operate its downstate gas franchise.” (See National Grid Vows to Expand NY Gas Service.)

PSC Chair John B. Rhodes on Oct. 11 had signed an order forcing National Grid subsidiaries Brooklyn Union Gas (KEDNY) and KeySpan Gas East (KEDLI) to connect 1,100 of 3,300 customers that had been denied natural gas service connections (Case 19-G-0678). KEDNY has approximately 1.2 million customers, and KEDLI has 590,000 customers on Long Island.

Brooklyn resident Jackie Weisberg addressed her comments during the online protest to Cuomo: “I oppose the National Grid fracked gas proposal because these pipelines are like the COVID-19 virus. They are insidiously infecting our communities. Selling us the so-called benefits of fracked gas is not what we need now, or ever. They have no business continuing the work in North Brooklyn [on the Metropolitan Natural Gas Reliability Project], and they are opposed in Connecticut and elsewhere.”

Young said “the Metropolitan Natural Gas Reliability Project is a system integrity project, it’s not one of the long-term capacity solutions — it does not bring additional supply to New York.”

Eyes of the PSC

In its Nov. 26, 2019, agreement with National Grid, the PSC mandated that an independent monitor submit quarterly reports to keep it apprised of the company’s progress in finding ways to provide gas service to all its customers in downstate New York.

The monitor’s third report, filed May 26, said that it attended all the public meetings and afterward began “monitoring the key executive meetings conducted internally at National Grid to address its compliance.”

In assessing the company’s development of long-term solutions, the report said it reviewed implementation of energy efficiency and demand response and “makes no formal findings or recommendations but provides observations regarding National Grid’s progress and positions.”

The monitor highlighted National Grid in April having hired Ernst & Young to review the company’s “development of natural gas demand scenarios and the identification and selection of options to meet demand.”

National Grid’s analysis turns on a design day standard, currently a 24-hour period with an average temperature of 0 degrees Fahrenheit in Central Park. The last design day was in 1934, and many public comments questioned the suitability of that standard today, the monitor said.

“To illustrate the point, National Grid has determined that the 24-hour period with the coldest average temperature in Central Park over the last 30 years was approximately 4 degrees F and took place in 1994,” the report said.

The monitor faulted National Grid for being too conservative on the one hand and too extreme on the other for assuming the increased reliance on compressed natural gas trucking through 2035, despite the practice raising “risk, cost and reliability questions.”

“Based on forecast figures provided by National Grid to the monitor, several more middle-ground approaches … indicate possible opportunities to move forward that are less stark than simply choosing between NESE or the no-infrastructure options,” the monitor said.

It also said that the company is not fully accounting for the reduced demand impact from the current pandemic, despite its own reporting that the reduced demand added a year to the predicted time when demand will exceed supply, to the winter of 2022/23.

May 31, 2020

Price Tag Rising for MTEP 20

The 2020 MISO Transmission Expansion Plan (MTEP 20) is shaping up to become one of the RTO’s most expensive ever.

Being developed virtually with stakeholders because of COVID-19 measures, the plan so far contains 510 proposed projects at a combined $4.06 billion, the priciest since MISO’s 2011 multi-value project portfolio. If approved by the RTO’s Board of Directors in December, MTEP 20 will best last year’s plan, which rang in with 480 projects at $4 billion. (See MISO Board OKs $4 Billion MTEP 19.)

Broken down, the transmission investment contains:

149 reliability-related projects at nearly $1.1 billion;
133 age- and condition-related upgrades at $1.05 billion;
77 baseline reliability projects at $783 million;
88 generator interconnection projects at $512 million;
55 projects necessary to accommodate load growth at $606 million; and
eight projects to be built for other local needs at $26 million.

Of those, MISO South accounts for 47 project proposals valued at $750 million.

Stakeholders at subregional planning meetings last week wondered whether some load-growth projects may be scaled back or withdrawn as the catastrophic economic impact of the COVID-19 pandemic continues to play out.

MISO Senior Manager of Expansion Planning Edin Habibovic said transmission owners might revise some projects based on COVID-19 effects, adding that the RTO will have more information on individual load-growth projects during a final round of subregional planning meetings in August. He said discussions over why some load-growth projects drop out likely won’t be disclosed publicly.

Ameren Illinois and Entergy Texas have so far submitted some of the costliest MTEP 20 projects, with the former planning four projects between $74 million and $91 million for reliability and age and condition needs, while the latter is tendering three projects between $65 million and $77 million in response to load growth in its territory.

MISO said it will test one of Ameren’s reliability project submissions — the 345-kV New Holland NW-Neoga South line rebuild in central Illinois — for economic benefits that might allow it to be cost-shared as a market efficiency project.

Altogether, Ameren proposed 152 new projects at an estimated $1.4 billion in its Illinois and Missouri service areas.

Some stakeholders asked why Ameren was suddenly making such big investments in transmission.

MISO expansion planning team member Scott Goodwin said Ameren is this year using a three- to five-year outlook on transmission projects instead of an annual planning horizon. Senior Manager of Expansion Planning Thompson Adu also said MISO has been coordinating with Ameren on issues that require transmission upgrades.

“We make sure we agree with the projects and justifications that they have given to us,” Adu said.

Stakeholders also asked if MISO performs any research to confirm the necessity of TOs’ age and condition projects.

Adu said TOs must justify those projects to MISO, but not all of them provide photos or engineering analyses.

No Midwest-South Tx Solution this Year

MTEP 20 will not contain a long-awaited transmission upgrade to secure more transfer capability on the Midwest-South subregional transmission constraint, stakeholders also learned.

David Severson, a MISO economic studies engineer, said that while there were a “couple promising project candidates,” the RTO will not recommend any Midwest-South transmission projects to the board this year.

Last year, MISO received and screened 35 project ideas to reduce dependence on its Midwest-South transfer constraint. Nine projects passed an initial screening, with three of those showing the required 1:1 or better cost-benefit ratio. (See MISO Floats New Option for Midwest-South Constraint.)

Missouri Public Service Commission economist Adam McKinnie asked why MISO planners don’t submit one of the three project finalists for consideration in the 2020 cycle of the RTO’s and coordinated system plan with SPP, developed to identify potential interregional economic transmission projects.

“I’m waiting for a good reason to hold off on a good solution for another year,” McKinnie said. The transfer limit study has been ongoing since the MTEP 19 cycle.

“We can use the project candidates for a really good starting point in the future,” Severson said. “Further study efforts under an expanded scope would be better served under MTEP 21 future assumptions and models.” MISO is currently redoing its 20-year futures assumptions to factor increased renewable generation and zero-carbon goals in time for the 2021 cycle of transmission planning.

Some stakeholders have criticized the study, saying that MISO focused too narrowly on only increasing the existing contract path capacity and not on a potentially more beneficial increase in physical transfer capability located somewhere else between the Midwest and South regions.

North Study Extends into 2021

Meanwhile, results are pending on MISO’s other special MTEP 20 study on the North Region economic transfer. The study evaluates transfer limitations caused by non-thermal constraints between the renewable-rich northwestern portions of the footprint and load centers in the Upper Midwest. MISO said it’s studying wind generation transfers from the Dakotas, Minnesota and Iowa to Wisconsin and Illinois.

That study will also extend into MTEP 21. MISO economic planner Ryan Hay said that while the study is largely academic, possible transmission projects could be identified and submitted in MTEP 21.

MISO has said the study is the first of its kind and will serve to develop a template for identifying and incorporating non-thermal transmission limits into its production cost analyses. Currently, MISO’s typical economic studies don’t consider non-thermal operational limits. (See MWEX Study Could Elicit New Tx Planning for MISO.)

May 31, 2020February 18, 2025

Exelon, FE Ask PJM to Tighten Sector Selection Process

Two incumbent transmission owners have called on PJM to take a more active role in policing stakeholder sector selections after the disclosure that LS Power had an affiliate improperly voting in the RTO’s senior committees.

“Generally, we think that PJM’s ruleset is a little lax, and some greater oversight of the process may be warranted,” Sharon Midgley, Exelon’s director of wholesale development, said during the Stakeholder Process Forum on May 26.

Exelon had previously raised questions about the propriety of two LS Power subsidiaries, West Deptford Energy and Riverside Generating, voting at the Jan. 23 Members Committee meeting in support of an LS Power resolution. The resolution, which was approved by the MC, objected to a Tariff attachment filed by the TOs to create a new confidential process to mitigate critical infrastructure on NERC’s CIP-014-2 list. FERC OKs PJM TOs’ Critical Tx Process.)

During PJM’s Annual Meeting on May 4, Dave Anders, director of stakeholder affairs, said the RTO had determined that the two companies are under common control and that West Deptford has been recategorized as an affiliate of Riverside, which is listed as the “parent” for 15 members in the Generation Owner, TO and Other Supplier sectors.

Midgley said LS Power “had been voting with two affiliates at the MRC and MC for many years.”

An LS Power spokesman said Friday that “when notified of a challenge, LS Power cooperated with PJM to provide supporting information, but some of the additional information requested could not be provided prior to the PJM Annual Meeting, when PJM took action. LS Power has decided not to challenge PJM’s decision.” The company declined to comment further.

Under PJM rules, companies with multiple members are entitled to a vote for each of them at lower committees. But they only get one vote at the MC and Markets and Reliability Committee, where votes are sector weighted.

Those rules meant that Pepco Holdings Inc., which had been a strong voice for consumers within PJM as a member of the Electric Distributor sector, lost its independence and its MRC and MC votes when it was acquired by Exelon in 2016. Exelon Business Services, the parent for Exelon’s 14 affiliates, votes in the TO sector. (See Pepco to Lose its PJM Voice; Consumers Lose Frequent Ally.)

A 2017 study by the University of Pennsylvania’s Kleinman Center for Energy Policy found that generation and transmission owners with multiple affiliates can dominate the voting at PJM’s lower committees on proposed solutions. The power dynamic is reversed during votes at the MRC and MC, the report said, because sector-weighted voting often results in buyer-side stakeholders (the Electric Distributor sector and End-Use Customer sectors) exercising veto power over proposals resulting from the lower committees. (See Can RTO Stakeholders Find Consensus on Big Issues?)

Annual Sector Certification

At the May 26 forum, Midgley noted that PJM members are required to recertify or make changes to their sector assignments annually, with changes announced at the Annual Meeting. After sector changes are announced, stakeholders have 30 days to request PJM to investigate any questionable sector selections.

Midgley said that before this year’s Annual Meeting, Exelon identified a member of American Municipal Power attempting to join the TO sector “when they weren’t qualified to do so.” Midgley declined to identify the company.

AMP votes at the senior committees as a member of the Electric Distributor sector, although it has affiliates in the TO and Other Supplier sectors. “That was certainly concerning to us,” Midgley said.

Under section 8.1.2 of the Operating Agreement, companies considered a “related party” of a generation and transmission cooperative (i.e., one of its distribution cooperative members) or a joint municipal agency (joint agency members) are required to vote in the Electric Distributor sector.

Lisa McAlister, AMP’s general counsel for regulatory affairs, said the company learned of the issue after being contacted by RTO Insider for comment Friday.

“From a conversation this morning with PJM … we learned that one of our members was unaware of the related parties sector limitation and mistakenly requested membership in the TO sector, since they are a transmission owner. PJM contacted our member and the error was rectified,” McAlister said. “PJM administers its governing documents and quickly and correctly did so here. There was nothing nefarious about the member request, and we are uncertain as to Sharon’s concern.”

Rule Changes?

Midgley said PJM should consider whether members should be able to review proposed sector changes before they are implemented and if members challenged on their sector change should be required to vote in their old sector until the challenge is resolved by the RTO. She said existing rules allow members to vote in their new sector until a challenge is resolved, a process that can take up to three months to determine.

Exelon would also like a process to examine incorrect sector selections at any time of the year and to allow members to challenge sector selections rather than just during the annual review process, Midgley said. “We think this is a fertile ground for discussion.”

FirstEnergy’s Jim Benchek said his company also would like PJM to take a greater role in overseeing the process. Benchek said the “know your customer” procedures that came out of the special report on the GreenHat Energy default should be implemented by PJM regarding sector selections.

Anders said the RTO is implementing updates to the member onboarding process and know-your-customer efforts as a result of actions taken by the Financial Risk Mitigation Senior Task Force. Anders said some of the issues deal directly with sector selection, and PJM may formulate a report to present to stakeholders later this summer on some of the changes.

Midgley said she was “happy to hear this is on [PJM’s] radar screen.”

Susan Bruce, representing the PJM Industrial Customer Coalition, said her members would be more comfortable having the RTO rather than stakeholders look at “individual business activities” of members, citing confidentiality issues.

20 Sector Changes

During this year’s Annual Meeting, PJM announced that 20 stakeholders had changed sectors, more than double the number of sector selection changes in recent years. For comparison, five sector changes were announced at the Annual Meeting in 2019, six changes in 2018 and eight in 2017.

PJM spokesman Jeff Shields told RTO Insider that “there doesn’t appear to be much out of the ordinary” in the sector changes.

PJM announced at the Members Committee meeting May 4 that these members have updated their sector selection. | PJM

“These new sector classifications reflect changes in corporate structures or the natural evolution of businesses within PJM,” Shields said. “The decisions to make these changes are up to the individual members, in accordance with the Operating Agreement.”

Several PJM stakeholders who changed sectors in May were contacted to determine what prompted their moves.

FirstEnergy’s The Illuminating Co. moved from the TO sector to the Electric Distributor sector. Jennifer Young, manager of external communications for FirstEnergy, said the sector change reflected that the subsidiary does not own or operate transmission assets.

Young said FirstEnergy’s transmission assets in Ohio are owned by another of the company’s subsidiaries, American Transmission Systems Inc.

“The sector change was not prompted by any changes to asset ownership, but rather just to better reflect the type of operations performed by The Illuminating Co.,” Young said.

The Northern Illinois Municipal Power Agency (NIMPA) moved from the Electric Distributor sector to the Generation Owner sector. Gary Holm, president of NIMPA, said the company has been filing as a Generation Owner since 2018 after filing as an Electric Distributor in 2016 and 2017.

Holm said he received an inquiry from PJM in early May about the sector selection, and he informed the RTO that the company had been filing as a Generation Owner since 2018 and wished to be filed in that sector.

“I cannot comment on any change in sector status because, according to our records, our status has remained constant since 2018,” Holm said.

CPV Three Rivers, an affiliate of CPV Power Holdings, updated its sector from Generation Owner to Other Supplier. Tom Rumsey, CPV’s senior vice president of external and regulatory affairs, said to qualify as a Generation Owner, an entity must have cleared a Base Residual Auction or have signed an interconnection service agreement, which Three Rivers has not done.

Rumsey said that when CPV Three Rivers’ membership application was originally approved, the company was told they were being placed in the Other Supplier sector, but they were later notified by PJM that they had been placed in the Generation Owner sector.

“We both agreed that the project should really be in the Other Supplier sector until the project achieves either of those milestones,” Rumsey said.

Energy Harbor, which emerged from the bankruptcy of FirstEnergy Solutions, switched from the TO to the Generation Owner sector, reflecting its separation from former parent FirstEnergy.

May 31, 2020

Texas RE Board Briefs: May 27, 2020

Texas Public Utility Commission Chair DeAnn Walker last week took advantage of a NERC trustee’s presence at a virtual meeting to plead for ERCOT representation on the ERO’s board.

Texas Reliability Entity — PUC Chair DeAnn Walker in 2019 | © *ERO Insider*

“I’m not going to surprise anyone on the board when I say what I’m about to say,” Walker said, following NERC Trustee Suzanne Keenan’s introduction during the Texas Reliability Entity Board of Directors’ meeting Wednesday. “I feel very strongly that NERC needs to consider having a member on the board from the ERCOT region that understands this interconnection,” echoing comments she made during the Texas RE board’s December meeting. (See “Walker Raises Concerns with NERC Representation,” Texas Reliability Entity Briefs: Dec. 11, 2019.)

Keenan, in her third year on the 11-member independent board, was diplomatic in her response.

“Thanks for sharing that with me,” she said. “I am on the [Nominating] Committee this year, so I will definitely take your comments back.”

Texas RE board Chair Fred Day backed up Walker, saying, “I think I speak for the entire board … we all feel that way. It’s time we were represented on the board.”

NERC’s Compliance and Certification Committee, which advises the trustees on all facets of the ERO’s compliance monitoring and enforcement program, has revised its charter to eliminate six regionally allocated seats — one for each regional entity — and replace them with six at-large seats.

Staff Adjust Well to Working Remotely

Texas RE CEO Lane Lanford said some staff could be returning to the office as soon as July 6 but noted the date has already been moved three times.

“July 6 is just another date,” he said.

Lanford said those staffers that return to the office would do so on a voluntary basis, where they will find a different workspace with signage, one-way “streets” through the cubicles and social distance requirements at the coffee machines. The Texas RE may not hold in-person meetings until 2021, though the final decision hasn’t been made.

“We’re pretty good working this way,” Lanford said. “Two years ago, when he started practicing [working remotely], I was wondering what we would ever do taking this much time off. We haven’t had too many bumps in the road.”

He gave kudos to IT staff, saying they were able to improve remote connectivity on the fly.

Day, who is serving his last year on the board, also said he was looking forward to some “actual face time” with staff and directors before the year is out.

“Nothing beats being in the same room, talking,” he said. “Socially distancing, of course.”

Board Approves New RDA, Budget

The board unanimously approved a new regional delegation agreement (RDA) with NERC to replace the current agreement, which expires at year-end. The RDA, which was developed with NERC’s legal staff, includes the option for a five-year extension.

NERC plans to file all six REs’ RDAs with FERC for the latter’s approval by the end of June.

The board also approved a 2021 budget of $14.2 million, a 2.8% increase from 2020, and an “unmodified” audit of Texas RE’s 2019 financial statements with no reported findings. Salaries will increase by 3.2%, primarily because of three new compliance positions.

May 31, 2020

NERC Expands Self-logging During Pandemic

NERC and the regional entities have temporarily expanded their self-logging program to allow registered entities to focus on their response to the coronavirus pandemic.

The self-logging program was introduced in 2015 and allows utilities, with permission of their regional entities, to log instances of potential noncompliance with NERC reliability standards that pose minimal risk to the bulk power system for future review by the ERO Enterprise, rather than submitting a self-report. Noncompliance events logged in this manner are typically resolved as compliance exceptions, which are not included in a registered entity’s compliance history for penalty purposes.

According to the guidance released on Thursday, all registered entities — regardless of whether they are already part of the program — will now be allowed to self-log instances of noncompliance that pose either a minimal or moderate risk to the BPS, as long as the noncompliance is because of “actions to address coronavirus impacts [that] disrupt, complicate or otherwise alter the normal course of business operations.”

NERC has posted a logging spreadsheet template on its website for its compliance monitoring and enforcement program (CMEP). This form should be used by all registered entities for coronavirus-related noncompliance logging, including those that are already part of the self-logging program. Utilities that have not already registered for self-logging will not be entitled to do so for noncompliance instances that are not pandemic-related and will not be considered enrolled in the program following the expiration of the guidance on Sept. 30.

NERC Self-logging — NERC headquarters in Atlanta | © *ERO Insider*

“This expansion allows [registered entities] to focus their immediate efforts and resources on maintaining the safety of their workforce and communities,” NERC said in a statement. “Under this temporary expansion … potential noncompliance related to coronavirus impacts and logged consistently with this guidance is expected to be resolved without further action.”

NERC and the REs, as well as FERC, will review registered entities’ logs at least once each month. Registered entities are required to maintain evidence related to noncompliance incidents for 18 months from the date the logs are submitted to their REs.

NERC Pushes Regulatory Relief

The expansion of the self-logging program is in keeping with several previous moves to ease compliance burdens for utilities dealing with the COVID-19 outbreak. In March, NERC and FERC announced they would use “regulatory discretion” to address difficulties registered entities may have in the following categories:

Inability to obtain and maintain personnel certification for the period of March 1 through Dec. 31;
Failure to perform periodic actions required by reliability standards between March 1 and July 31; and
On-site activities through at least July 31, including audits and certifications, that would ordinarily be performed by REs. (See FERC, NERC Relax Compliance in Light of COVID-19.)

In addition, FERC agreed in April to defer the implementation of seven reliability standards scheduled to take effect this year. (See FERC Agrees to Defer Standards Implementation.) The commission said the delay was intended to reduce pressure on registered entities to ensure compliance with the new standards while implementing coronavirus response measures.

“We don’t want FERC and NERC to be a burden to industry while we’re in this very constrained operating posture,” NERC CEO Jim Robb told the Member Representatives Committee in April. “[We] want to [be] very clear that our commitment is to work with industry to address these issues together.”