PJM, IMM at Odds on 5-Minute Dispatch, Pricing Rules

By Rich Heidorn Jr.

PJM backed off plans to seek a vote next month on short-term changes to its five-minute dispatch and pricing procedures after pushback from the Independent Market Monitor and stakeholders.

PJM’s Tim Horger told the Market Implementation Committee on Wednesday that the RTO was prepared to make manual changes detailing short-term changes but needs more time to evaluate the operational benefits and impacts of long-term changes it has been discussing with the Monitor.

Horger said the short-term changes comply with FERC Stalls PJM Fast-start Compliance Filing.)

The commission ordered PJM and NYISO a year ago to revise their tariffs to allow fast-start resources to set clearing prices. (See FERC Orders Fast-start Rules for NYISO, PJM.)

PJM’s proposed short-term fixes would align the locational price calculator (LPC) to use the reference real-time security-constrained economic dispatch (RT SCED) case for the same target time. LPC would calculate prices for the interval from 11:55 a.m. to 12 using the RT SCED solution for a 12 p.m. target time.

PJM Dispatch Pricing rules — Proposed short-term implementation | *PJM*

The RTO would execute LPC cases every five minutes after the start of a dispatch interval, using as inputs resource offers, parameters and ancillary service assignments for the interval ending at the target dispatch time. Offers for 11 to 12 would be effective up to and including the 12 p.m. target; offers for 12 to 1 p.m. would be applied to a dispatch target of 12:05.

Horger said PJM also has committed to conduct operator training and make software changes to limit automatic execution of RT SCED cases to once for every five-minute target time. Additional cases may be manually executed and approved as needed by dispatchers under what PJM calls this “intermediate” change.

The long-term changes would include auto-execution of RT SCED cases every five minutes with a target time of 10 minutes into the future.

If dispatchers do not manually approve an RT SCED case for a target time, a case would be automatically approved before the start of the dispatch interval. It would also add transparency when cases are not approved for a target time because of data errors or software failures.

Horger said PJM wants to prioritize and consider parallel or incremental implementation of the long-term changes. “It might look good on paper, but until we get a comfort level on an operational level, we can’t commit to it.”

IMM Joe Bowring said the Monitor thought it had reached an agreement with PJM following “months of productive discussions” on a compromise that would give dispatchers better information closer to the dispatch time and help ensure consistency between dispatch and pricing.

But he said the RTO posted a presentation and a proposal matrix the night before the meeting that indicated the RTO no longer supported the agreement. The RTO’s current long-term proposal “is vague at best and probably years away,” he said.

In addition to aligning pricing and dispatch, Bowring said in an email later, it also is essential to reduce “the RT SCED dispatch interval from 10 minutes to five minutes, running RT SCED on a regular five-minute interval to match the pricing interval to minimize running multiple RT SCED cases and changing dispatch instructions for the same target time, and using the prior RT SCED case as inputs to the current RT SCED case.”

“Our goal continues to be a single comprehensive package,” he said at the meeting. “We believe the entire package is needed to make SCED and LPC work consistent with the FERC order … and it’s really required for fast-start pricing to work correctly.”

“This is something were going to need to test. It requires operator training,” responded Horger. “It won’t be years away. It will be a lot closer than that.”

PJM says the long-term changes may require a revised approach to ancillary service products.

“If we slow down the dispatch, [our concern is] what other compensating measures we [might] need to take,” explained Adam Keech, PJM vice president of market services. “Do we need more regulation if we slow down the dispatch? Sitting here today, I don’t know that we know the answer to that.”

Bowring noted that PJM recently changed the automated case execution for SCED from three to four minutes without operator training. “I don’t know why training is needed to go from four to five minutes,” he said.

Keech said the RTO believes the intermediate and long-term changes aren’t required by the FERC order because they are not used “uniformly” in other RTOs/ISOs. He acknowledged that the recent change in the automated SCED case execution from three to four minutes has not caused any operational issues.

But he said that shift still allowed dispatchers to manually order additional cases in response to changing conditions. Preventing dispatchers from such manual intervention “is much different than where we are today,” he said. “TBD on an exact timeline, but I will say there is motivation to make the change quickly, but I will add, judiciously.”

Keech also said PJM’s long-term goal is to greatly reduce dispatchers’ interventions while retaining operators’ ability to approve SCED cases if, for example, they unexpectedly lose a large generating unit. “The desire is not to [intervene] unless it’s absolutely necessary.”

He said about one-third of approved RT SCED cases do not set prices currently because they are supplanted by new cases.

One stakeholder representing a trading firm who said he was not permitted by his company to be quoted by name said PJM’s current practices are preventing proper transient shortage pricing even when the system is in a “critical state.”

He cited a spinning reserve event in February that resulted from an under-forecast for load, an incident in October in which load rose faster than forecast and a July 2018 time error correction at noon and subsequent unit trips that resulted in a drop in system frequency on the Eastern Interconnection.

MIC Chair Lisa Morelli concluded the discussion by saying the committee will hold a second first read of the proposal in May. “I think it’s pretty apparent we’re not ready to move this to a vote at the next meeting,” she said.

In the interim, the MIC will hold a special meeting on the issue May 1.

Horger said that because the short-term changes only affect the manual and do not require FERC approval, the delay should not prevent the RTO from making the changes by July as planned.

April 20, 2020

PJM PC/TEAC Briefs: April 14, 2020

RTMEP Process Ready to Move Ahead

PJM told the Planning Committee on April 14 that it is standing behind its intention to seek stakeholder approval of a new regional targeted market efficiency project (RTMEP) process without first developing cost allocation rules.

PJM attorney Pauline Foley reiterated her statements from the committee’s March 10 meeting, saying LS Power Challenges PJM on MEP, SATA.)

LS Power’s Sharon Segner acknowledged that cost allocation is the TOs’ responsibility, but she said FERC Order 1000 requires any regional planning process to be accompanied by a cost allocation methodology. Segner reviewed a legal memo filed by LS Power regarding cost allocation for the new project category.

Foley said she agreed with LS Power’s contention on the importance to know the cost allocation methodology before PJM designates a project or implements a planning process. But she disagreed with the memo’s contention that a methodology must be simultaneously filed with the planning process. “I don’t see anything in Order 1000 that says that,” she said.

PJM officials noted that stakeholders have been working on the issue for at least 18 months and said that if it’s pushed back any further, it could prevent implementation before 2022. PJM stated it is prepared to seek a vote on a new measure at the May PC meeting.

Alex Stern of Public Service Electric and Gas provided a response from the TOs regarding the LS Power memo. He said the plans that have been proposed follow existing transmission planning principles and comply with Order 1000.

“Once we have an effective [stakeholder-approved] package, the TOs will begin developing any needed cost allocation revisions that emerge,” Stern said. “This is consistent with the transmission planning approach that has been followed in the past.”

Segner said there remains a “long path ahead” on the RTMEP process for stakeholders. She said there has been no consensus on the proposals submitted thus far.

“The members deserve to know the cost allocation methodology for an entirely new type of regionally planned project category,” Segner said. “If FERC can’t accept these filings without understanding what the cost allocation methodology is going to be, why should the members? Why is it that the members are considering approving changes without knowing what the cost allocation framework is going to be?”

Competitive Planner Nears Debut

Ilyana Dropkin of PJM presented an update on the Competitive Planner, a new web-based application for TOs and developers to participate in the RTO’s competitive planning process under Order 1000.

By publishing a set of criteria violations and soliciting solutions from competing developers in the new application, Dropkin said, PJM and FERC are hoping to encourage innovative and cost-effective solutions for transmission needs.

Dropkin said that having a web-based application increases the speed and accuracy of the process and provides near-real-time tracking of submissions.

Anyone looking to participate in PJM’s competitive planning process can get access to Competitive Planner by prequalifying through the critical energy/electric infrastructure information (CEII) process, Dropkin said.

Training for the application is expected to be available on May 6, Dropkin said, and the full implementation of Competitive Planner is expected by June 24.

Transmission Expansion Advisory Committee

Deactivation Notifications

Phil Yum of PJM provided the Transmission Expansion Advisory Committee an update on two recent generation deactivation notifications.

The first highlighted was PPL’s Keystone NUG, a 4.9-MW coal-fired unit scheduled to retire on May 31. Yum said PJM determined during analysis that no violation was identified with the unit’s closure.

Generation deactivations for 2018-2020 | *PJM*

Second, Chesterfield Units 5 and 6, producing 1,015 MW in the Dominion zone, are scheduled to retire on May 31, 2023. Yum said a generation deliverability problem was discovered at the Chickahominy 500/230-kV transformer that was overloaded for loss of the Chickahominy-Surry 500-kV line.

Yum said PJM is recommending installing a second Chickahominy 500/230-kV transformer at an estimated cost of $22 million.

PJM: Error had no Impact on Project Selection

PJM’s Brian Chmielewski told the TEAC that FirstEnergy’s admission that it included an incorrect winter-normal rating in its proposed rebuild of the 115-kV Hunterstown-Lincoln line did not affect the RTO’s selection of the project (HL_622).

PJM selected the $7 million proposal by FirstEnergy’s Mid-Atlantic Interstate Transmission (MAIT) subsidiary as the solution for the Hunterstown-Lincoln congestion driver following the 2018/19 long-term window.

After MAIT told PJM of the error on March 6, the RTO’s market efficiency unit reran the proposal with the updated rating, Chmielewski said. “There was no change to the congestion or dispatch when that rating was updated,” he said, adding that PJM stands by its decision.

In February, Ameren asked PJM to reconsider its selection of the project over 22 other proposals, including the company’s proposal for installing a SmartWires SmartValve. (See PJM Rejects Ameren Challenge on Tx Project.)

RTEP Window Delayed

PJM’s Aaron Berner said delays in the development of Regional Transmission Expansion Plan cases have pushed its schedule back by three weeks. Posting of preliminary violations, originally targeted for April 15, is now expected on May 8. The opening of the 60-day proposal window, originally expected June 1, is now set for June 24.

Supplemental Project

Paul Mills of Commonwealth Edison presented needs and a solution for several supplemental projects, including the Lisle 345/138-kV Transformer No. 83 that acoustic testing showed higher-than-expected vibration levels and increased frequencies associated with looseness in the core/coil assembly. The solution calls for replacing the transformer and adding a high-side circuit breaker at a cost of $8.5 million.

— Michael Yoder

April 20, 2020

PJM Eyeing New Black Start Changes

By Michael Yoder

While PJM’s controversial initiative to tighten fuel requirements for black start resources is on pause, the RTO said last week it wants to clarify and update its documentation on the substitution and termination of those resources.

PJM’s David Kimmel presented a first read of a proposed problem statement and issue charge at the Operating Committee meeting Thursday, saying PJM officials have identified four areas in the Tariff and manuals in need of updates.

Last month, PJM suspended its initiative looking at black start fuel requirements, which faced opposition from state regulators and consumer advocates. (See PJM Backs off Black Start Fuel Rule.)

Kimmel said while the fuel requirements initiative remains on “hiatus,” the RTO wanted to clean up black start resource language in the Tariff not related to fuel.

“We have received a lot of questions on substitution, and we wanted to make those rules more clear,” Kimmel said.

PJM is first rewriting language for testing requirements for black start resources not compensated through Schedule 6A of the Tariff. Kimmel said PJM has identified the need to provide clarity within testing requirements to ensure consistency, including test submittal timelines, for black start units compensated by either PJM or transmission owners.

PJM Black Start — Tasley, a single-unit 33 MW industrial gas turbine that began commercial operation in 1972 in Tasley, Va., is a black start capable unit. Calpine acquired Tasley in 2010 as part of its purchase of the Conectiv Energy assets. | *Calpine*

Kimmel said the black start units in PJM are typically compensated through Schedule 6A, while some units entered service through a contract with a TO that was integrated into the system. In order to receive compensation, the unit must submit a successful black start test to PJM every 13 months.

The second clarification PJM is seeking is on black start unit substitution rules. Currently the Tariff allows a black start unit owner to substitute another unit as long as it’s on the same voltage level and has a valid annual black start test.

Kimmel said PJM has received increased questions on adding, maintaining and managing units as black start substitutes. He said some of the questions that have been raised include the notification time required to allow a substitution and how to manage updates to system restoration plans documenting black start resources.

Black start termination rules are also being addressed, Kimmel said, to address potential delays in planning and replacement.

PJM and black start unit owners are currently required to provide a one-year advance notice of intent to terminate service. Kimmel said that could allow a unit to remain in the system without a successful test on file for an extended period of time before being terminated, delaying PJM from procuring a replacement.

The RTO also is looking to update the black start capital recovery factor (CRF) table in the Tariff to reflect current tax law and interest rates. It also is exploring a new process for automatically updating and documenting the table to remain current.

Kimmel said black start units electing to recover new or additional capital costs must commit to provide black start service for a term based on the age of the unit, and the CRF table lists the term periods of commitment and applicable capital cost recovery factors. He said recent tax law and interest rate changes don’t reflect the assumptions used in the current CRF and need to be updated.

Work on the proposed changes is expected to take two to three months, Kimmel said, and it could be another six months before the changes would take effect in the Tariff. Changes are also anticipated to Manuals 10, 12 and 14D.

Process Questions

Independent Market Monitor Joe Bowring said he agreed with PJM’s proposal that the CFR table needs to be modified for tax law changes. He recommended that a reference interest rate be used as part of the problem statement and issue charge for the new changes and that the Moody’s Utility Index for bonds already in use in the Tariff for black start-related matters be the benchmark.

Bowring also said he would also like to see the black start minimum tank suction level (MTSL) issue addressed in the new changes. He said the MTSL has been an issue for several years that has not been clearly addressed. PJM had agreed with the Monitor’s position and had included such an agreement in the black start fuel requirement initiative that is now on hiatus, he noted. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: May 1, 2018.)

PJM’s Tom Hauske said the MTSL is still part of an active stakeholder process with the fuel resource initiative and should remain there.

“We’re not sure that you can pull something from one stakeholder process and then bring it over into a whole other stakeholder process,” Hauske said.

Bowring said he didn’t see why the MTSL issue couldn’t be addressed in the new process, as the fuel cost committee is currently on hiatus. Bowring also pointed out that the CRF table was part of the fuel assurance matrix being discussed in the black start fuel requirement.

Hauske said the previous fuel assurance matrix discussion dealt only for new units that were going to provide fuel assurance and did not apply to current units that were switching to black start, which is what the new proposed changes are meant to answer.

April 20, 2020

Texas Public Utility Commission Briefs: April 17, 2020

The Public Utility Commission of Texas on Friday issued several orders revising its efforts to mitigate the economic effects of the COVID-19 pandemic (50664).

The commissioners approved:

A July 17 end date for enrollment in the PUC’s COVID-19 Electricity Relief Program.
A May 15 end date for suspension of disconnections by vertically integrated utilities outside the state’s competitive areas. The order applies to Entergy, El Paso Electric, Southwestern Public Service and Southwestern Electric Power Co.
A May 15 end date on waivers of late fees for retail electric providers’ residential customers in competitive areas.

The relief program was originally set to expire in September. It is funded by a 3.3-cent/kWh charge added to electricity bills. Among its other provisions, the program suspends disconnections for nonpayment for eligible residents who sign up for payment plans with their electricity providers.

PUC Chair DeAnn Walker said during the commission’s open meeting Friday that, upon reflection, six months was “too long.”

“That’s why I dialed it back to July,” she said, promising to revisit the issue during the PUC’s May 14 open meeting.

“I firmly believe that no one is going to get out of this unscathed,” Commissioner Shelly Botkin said. “Everyone is going to be impacted, personally and financially.”

Commission Approves Advanced Metering Rules

The commission adopted a rulemaking on advanced metering that would use on-demand reads instead of real-time information sharing with home appliances and systems. The rules will allow utilities outside ERCOT to recover costs of the smart meters (48525).

The state’s utilities said the real-time requirements would have been more costly to customers.

— Tom Kleckner

April 20, 2020

FERC Agrees to Defer Standards Implementation

By Holden Mann

NERC Requests FERC Defer Standards Implementation.)

“The [FERC] chairman and I have talked, and we both agree that 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 said at the Member Representatives Committee’s premeeting informational conference call last week. “[We] want to [be] very clear that our commitment is to work with industry to address these issues together.”

Delays to Ensure COVID-19 Preparedness

As NERC requested, the following cybersecurity supply chain standards that are scheduled to become effective July 1 will be delayed to Oct. 1:

CIP-005-6 (Electronic security perimeter(s))
CIP-010-3 (Configuration change management and vulnerability assessments)
CIP-013-1 (Supply chain risk management)

The following standards scheduled to take effect Oct. 1 will be moved to April 1, 2021:

PER-006-1 (Specific training for personnel)
PRC-027-1 (Coordination of protection systems for performance during faults)

In addition, the July 1 compliance deadlines for two standards that are already effective will be pushed back to Jan. 1, 2021. Under PRC-002-2 (Disturbance monitoring and reporting requirements), which took effect July 1, 2016, entities are required to demonstrate 50% compliance with requirements R2-R4 and R6-R11, while PRC-025-2 (generator relay loadability) requires entities to establish compliance with certain measures.

“It is now necessary to balance the important role these NERC reliability standards play in protecting the reliability and security of the bulk power system with the need for registered entities to respond to the immediate challenges of COVID-19,” FERC said. “Therefore, we expect entities to continue their work in implementing the standards and to take advantage of the additional time to ensure they are fully compliant with these reliability standards when they become enforceable.”

Critics Warn of Reliability Risks

NERC’s request sparked limited opposition, with FERC receiving filings of support from Reliable Energy Analytics, the ISO/RTO Council, the American Public Power Association, Edison Electric Institute and others. However, the commission did note critical responses from advocacy group Protect Our Power and from author and activist Michael Mabee.

FERC Standards Implementation — FERC headquarters in D.C. | *FERC*

Both Protect Our Power and Mabee warned that FERC should not overlook the security benefits provided by the affected standards that prompted the original deadlines. Protect Our Power’s filing called for the commission to provide a 30-day delay for CIP-013-1, rather than 90 days; Mabee went further, saying that NERC and the broader industry knew of the possibility of a pandemic for years and should not be allowed to claim COVID-19 as a reason for deferral.

Moreover, he said the pandemic has made the U.S. more vulnerable to physical and cyberattacks on the grid, and that implementing the CIP standards should be completed sooner rather than later.

“Now is not the time to defer protections to the electric grid that the industry has had ample time to prepare for — because of a pandemic that the industry is telling the public they are prepared for. Granting NERC’s motion places the U.S. in further danger and is not in the public interest,” Mabee said in his filing (emphasis in original).

FERC noted that as it considered NERC’s request on an expedited basis, both objections arrived following the end of the comment period. However, the commission said that it would have denied both motions on their merits even if they had been submitted on time, as even if registered entities could have been expected to be prepared for a pandemic by now, “it is nevertheless reasonable to provide them additional flexibility” to address the impacts of COVID-19.

April 19, 2020

PJM Ordered to Recalculate Wind Farm’s Capacity Rights

By Rich Heidorn Jr.

PJM must recalculate an Illinois wind farm’s incremental capacity transfer rights (ICTRs) based on the information available to the RTO when it completed the interconnection customer’s system impact study (SIS) in 2015, FERC ruled Thursday (EL18-183).

ICTRs — available to interconnection customers that are required to fund a transmission facility — are awarded based on how much the improvement increases the transmission import capability into a locational deliverability area (LDA). ICTR holders receive revenues if the LDA in question is constrained in subsequent capacity auctions. The rights are good for up to 30 years.

In 2018, the commission granted a complaint by Radford’s Run Wind Farm, which said PJM unfairly denied ICTRs for funding an upgrade identified in its SIS to mitigate a thermal overload on the 345-kV Loretto-Wilton Center line. Radford’s upgrade increased the rating of the line by 47 MVA.

The commission’s 2018 ruling ordered a paper hearing to determine whether the upgrade increased the capacity emergency transfer limit (CETL) of the ComEd LDA, entitling it to ICTRs.

PJM contends that although Radford’s SIS was completed in December 2015, the CETL calculation should be forward-looking, and thus based on the planning model developed in in January 2016, which set the CETL values for the May 2016 Base Residual Auction. PJM said the 2016 analysis showed that the Radford upgrade did not increase the CETL for the ComEd LDA because a voltage collapse concern on the 765-kV Dumont-Wilton line was more constraining.

PJM Capacity Rights — Radford’s Run Wind Farm | *E.ON*

Radford owner E.ON Climate & Renewables N.A. — which opened the 306-MW wind farm in Macon County, Ill., in 2018 — said the analysis should have used the base case for the 2015 BRA, which it contends would have entitled it to 279 MW of ICTRs.

FERC sided with Radford, saying PJM’s Tariff did not allow the RTO to delay Radford’s SIS or its ICTR calculations.

“While we appreciate PJM’s desire to use the most up-to-date data for all its analyses, we find PJM’s suggested use of later data inconsistent with the certainty and predictability required by the Tariff provisions addressing the timing of studies,” FERC said. “For these reasons, we direct PJM to award any ICTRs that would have been assigned to Radford as of December 2015, as PJM would have done had PJM followed its Tariff.”

It required PJM to make a compliance filing within 60 days. If PJM determines Radford is entitled to ICTRs, it must determine whether the company would have received payments relating to the BRAs held in 2016, 2017 and 2018.

“We see no reason not to require PJM to apply its Tariff correctly and to rebill parties for their correct quantity of ICTRs. Accordingly, we will exercise our discretion and require PJM to resettle payments for ICTRs resulting from the 2016 Base Residual Auction with a 2019/20 delivery year and to rebill affected entities for that period.”

Rule Change

In response to FERC’s 2018 ruling, stakeholders last year approved revisions to the timing and study parameters for determining ICTRs. (See “Revisions on Incremental Capacity Transfer Rights Endorsed,” PJM MRC/MC Briefs: Jan. 24, 2019.)

The change, accepted by FERC last April, allows new service customers to request an ICTR determination on customer-funded upgrades after executing a facility study agreement (FSA) — a later phase in the interconnection process than the SIS — and before the issuance of an interconnection service agreement or construction service agreement. It also limits the requests to no more than three LDAs (ER19-982).

PJM said the change was needed because the procedures detailed in the Tariff would result in delays in processing interconnection requests. PJM said it takes from an additional day to more than one work week to conduct ICTR determinations for each customer-funded upgrade identified across all 27 LDAs in the RTO.

It noted that of the 2,073 customers receiving SISes over the prior decade, only 729 customers proceeded to execute an FSA. PJM also said that when projects drop out of the queue, it must repeat SISes for projects lower in the queue. Delaying ICTR determinations until after execution of an FSA also provides more certainty on costs, PJM said.

EDF Renewables and Renewable Energy Systems Americas filed a joint protest contending that interconnection customers need all possible information at the SIS stage in order to make an informed decision about whether to remain in the queue. They noted that ICTRs can be worth millions of dollars over a 30-year period.

The commission rejected the protest, concluding that the RTO’s changes “appropriately balance the needs of new service customers seeking ICTRs … with promoting the efficient processing of PJM’s interconnection queue.”

April 19, 2020

Morenci Project Dropped from MTEP 18

By Amanda Durish Cook

FERC last week affirmed that a small Michigan transmission project in MISO’s 2018 Transmission Expansion Plan (MTEP 18) is in fact a local distribution facility that should not be included in the annual portfolio.

The ruling leaves no doubt that Michigan Electric Transmission Co.’s (METC) $21 million, 138-kV Morenci line near the Michigan-Ohio border will be removed from MTEP 18 (EL19-59).

FERC in the same order also declined to launch an investigation into MISO’s Tariff to find out whether the RTO should take an active role in determining whether particular projects function more as transmission or distribution.

Consumers Energy in April 2019 filed a complaint against MISO and METC, claiming the Morenci project was “improperly” included in MTEP 18 because it failed FERC’s seven-factor transmission test. The utility asked FERC to forbid MISO from approving the construction of a distribution facility. (See Michigan Regulators Intercede in MTEP Complaint.)

MISO Morenci Project — Michigan Public Service Commission headquarters | © *Google*

The Morenci project was intended to address anticipated load growth; METC submitted an expedited project review request to MISO for the project in 2018.

The Michigan Public Service Commission in November determined the line had more in common with distribution than transmission, dropping it from MTEP eligibility. FERC waited until Michigan regulators had concluded their investigation before it ruled on the matter.

The federal commission dismissed METC’s argument that the line will be used to transport wholesale power, noting that although technically true, it wouldn’t be the primary purpose of the line.

“The Michigan commission found that although wholesale transactions occur over the Morenci project, that does not mean that its function is a transmission facility; rather, the function of the Morenci project is to deliver power leaving Michigan Electric’s looped transmission system to Midwest Energy’s distribution system for exclusive consumption by Midwest Energy’s retail end users,” FERC said.

Consumers also alleged that MISO should have performed a seven-factor test on the Morenci project before it included it in MTEP 18. The utility asked FERC to open an investigation into MISO’s Tariff and determine whether the RTO should develop additional procedures to test transmission projects before they’re included in an MTEP cycle.

The Michigan PSC also asked the commission to “determine if, and when, in the transmission/distribution classification process it would be appropriate for a utility or MISO to request a state commission determination of whether or not a project is transmission and, thus, eligible to be included in MTEP.”

MISO maintained that the process is already clear-cut, placing the classification responsibility on transmission owners who “have the best knowledge of their own systems and facilities.”

“It is MISO’s role to evaluate transmission projects developed through its planning and stakeholder processes; it is not MISO’s role to initiate hundreds of classification proceedings with state regulators or this commission,” the RTO wrote in December.

FERC agreed with MISO’s view and said the RTO made the right move when it largely kept itself out of the dispute and suggested the “parties request classification by an appropriate regulatory authority” once it saw the impasse.

The commission said it wouldn’t entertain Consumers’ request to investigate MISO’s Tariff and recommend the RTO adopt additional procedures to test projects.

“We agree with MISO that the classification of assets of a regulated entity is a regulatory function that should be performed by the commission and state commissions and that requiring MISO to perform a seven-factor test for projects proposed during the MTEP process would be overly burdensome without providing significant benefit,” FERC said.

“MISO only has authority to classify facilities for transmission owners that are not subject to regulation by a regulatory authority,” it reminded Consumers.

April 19, 2020

Stakeholders not Sold on PJM SATA Plan

By Michael Yoder

PJM stakeholders last week questioned the scope and timing of the RTO’s proposed initiative for considering storage as transmission assets (SATA) in the Regional Transmission Expansion Plan (RTEP) process.

The RTO is hoping to develop rules by the end of the year for treating storage that would be dispatched to address thermal, voltage or stability violations or to relieve transmission constraints. Other potential uses for SATA include operational performance (mitigating real-time violations not identified in planning studies) and public policy (grid enhancements requested by a state to further its policies).

PJM’s proposed issue charge says it is seeking “transparent rules for stakeholders to understand how PJM evaluates these assets as opposed to an ad hoc evaluation process to evaluate SATA proposals submitted to mitigate baseline RTEP violations.”

During a first read of the RTO’s SATA plan at the April 14 Planning Committee meeting, Adrien Ford of Old Dominion Electric Cooperative (ODEC) expressed concern that the issue charge states that “PJM needs to initiate a stakeholder process” to add the SATA category.

‘Bias Toward Change’

“We often have a bias toward change” instead of giving proper weight to the status quo as an equally viable alternative, she said.

PJM — Adrien Ford, ODEC | © *RTO Insider*

Ford said she hopes PJM and its stakeholders determine whether planning rules require changes and SATA resources are appropriate for transmission. She said ODEC believes that guidance from FERC on the issue is needed, as the current definition of transmission doesn’t include SATA.

“It really seems as though PJM has come to the foregone conclusion that we should have storage as a transmission asset,” Ford said. “FERC really needs to answer the threshold question on whether storage should or shouldn’t be defined as a transmission asset.”

Marji Philips, LS Power’s vice president of wholesale market policy, said the timing of PJM’s proposal was “aggressive” because FERC will be presenting information on SATA in upcoming months that could potentially be utilized in the planning.

FERC has scheduled a technical conference for May 4 on MISO SATOA Proposal Set for Technical Conference.)

The commission has also scheduled a conference on hybrid storage and generation resources for July 23 (AD20-9). (See FERC Sets Tech Conference on Hybrid Resources.)

Marji Philips, LS Power | © *RTO Insider*

Philips also contended that evaluating the cost determination methodology for SATA should not be included in the scope of the proposal until it is decided “there is a separate and unique role” for battery SATA. She said SATA could be ruled to be a hybrid asset, making it subject to existing generation rules.

Independent Market Monitor Joe Bowring called the issue charge a “very significant change,” citing several concerns, including why it makes sense to allow transmission companies to treat a type of generation asset as a cost-of-service transmission asset that would compete with market assets owned by competitive companies. “Is it reasonable to have regulated assets competing directly with competitive assets?” Bowring asked, while also questioning whether battery projects treated as transmission would be open to competitive bidding.

“If you’re really going to evaluate this, you have to do it comprehensively, and you can’t do it piece by piece,” Bowring said. “As the proposal is written, other market-based generation assets could be treated as transmission assets by transmission owners.”

Sharon Segner, vice president of LS Power, suggested that the issue charge or problem statement should address whether SATA is an appropriate policy to tackle. Segner previously raised questions about a proposal from American Electric Power to use storage to correct repeated outages on its Falcon-Prestonsburg 46-kV circuit (AEP-2018-AP010). Segner said PJM cannot include non-transmission alternatives such as storage in the RTEP until it has been designated as transmission by FERC. Allowing AEP to win approval of the project under the M-3 process — which is limited to TOs — discriminates against non-TOs, she said. (See LS Power Challenges PJM on MEP, SATA.)

Dave Mabry, representing the PJM Industrial Customer Coalition, questioned the RTO’s proposal to rule issues over dual usage — considering storage both as transmission and as a market participant — out of scope.

Looking for Gaps

PJM’s Jeff Goldberg said the RTO’s plan is intended to evaluate business rules and assess opportunities for the technology. “We want to explore the existing rules and performance measurement and methodology and look for gaps and opportunities in those in order to integrate storage transmission assets,” Goldberg said.

The key work activities and the scope highlighted by Goldberg in Phase I of the process included ensuring the planning criteria address both performance measurement and cost measurement methodologies while also reflecting system operations input to maintain reliability.

The issue charge also calls for development of criteria regarding the size of SATA projects, including peak load, load duration and recharging characteristics.

It also would develop a framework for comparing storage to traditional transmission reinforcements.

Goldberg said modeling processes will be a key element to the project to address a storage asset’s state of charge (injecting power to the grid, recharging or standing by for deployment). PJM wants to be able to conduct sensitivity analyses to expose any reliability deficiencies.

Finally, PJM seeks to evaluate the methodology for determining the total cost of SATA facilities. The methodology would include an initial cost and ongoing maintenance cost; the life expectancy and cost to ensure usable life compared to traditional transmission assets; the consideration of losses associated with charge and discharge cycles; and comparability to existing transmission reinforcement.

“The idea is we want to formalize these as a proposal by taking all those concepts together,” Goldberg said.

Phase 1 of the proposal was not intended to address issues associated with storage as a market participant, Goldberg said, because the terms “energy storage resource” and “capacity storage resource” are already in the Tariff.

Also out of scope for Phase 1 are operational mechanics such as model and telemetry requirements.

PJM’s Aaron Berner said the issue charge is centered on examining PJM’s requirements in relation to the RTEP and how storage could be used as “reinforcements” in meeting compliance obligations.

“In the end, that’s what this effort at this phase is about: Can PJM accept a storage resource as a mitigation project for any of our compliance obligations?” Berner said. “If we can’t get past that issue, we don’t feel that there’s any discussion around whether or not these facilities might be used for any dual use.”

PC Chairman Dave Souder thanked the stakeholders for their feedback and said the committee would discuss the issue further at its May meeting.

April 19, 2020

Golden Spread Ordered to Further Comply with Order 845

By Tom Kleckner

FERC last week partially approved Golden Spread Electric Cooperative’s Order 845 compliance filing but directed the Texas utility to make another filing proving compliance within 120 days (ER19-1900).

The commission in November partially accepted Golden Spread’s first compliance filing but found the cooperative’s proposed tariff revisions lacked the requisite transparency required by Orders 845 and 845-A. It directed Golden Spread to make another compliance filing, which it did in January. (See FERC Finds Partial Compliance on Order 845.)

FERC issued the two orders in 2018 to increase the generator interconnection process’ transparency and speed. The changes are grouped into three categories: improved certainty for interconnection customers; promoting more informed interconnection decisions; and process improvements. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

The commission found Golden Spread’s tariff revisions related to provision of interconnection service and surplus interconnection service complied with the orders.

But it said Golden Spread’s proposed revisions to determine contingent facilities that provide sufficient transparency “appears to conflate” those facilities with network upgrades and interconnection facilities assigned to the interconnection customer and does not distinguish between the two.

“Golden Spread does not indicate how it will determine which of these facilities are contingent facilities applicable to a particular interconnection request,” FERC said. It directed the cooperative to describe in its pro forma large generator interconnection procedures (LGIP) the specific technical screens and/or analyses that it will employ to determine which facilities are contingent facilities and to describe the specific triggering thresholds or criteria applied to identify a facility as a contingent facility.

FERC defines contingent facilities as “unbuilt interconnection facilities or network upgrades upon which the interconnection request’s costs, timing and study findings are dependent and, if delayed or not built, could cause a need for restudies of the interconnection request or a reassessment of the interconnection facilities and/or network upgrades and/or costs and timing.”

The commission also found proposed revisions to the LGIP allowing interconnection customers to submit “proposed modifications” if they seek to incorporate technological advancements into their large generating facility did not comply with its November order.

FERC directed Golden Spread to revise its technological change procedure to state that an interconnection customer should submit a “technological advancement request” if it seeks to incorporate technological advancements into its proposed large generating facility. It also ordered the cooperative to make clear it will reach its final determination on whether a proposed technological change is a material modification within 30 days of receiving the request.

April 19, 2020November 30, 2023

ERCOT Board of Directors Briefs: April 14, 2020

ERCOT’s Board of Directors gathered briefly in a conference call April 14 to discuss the grid operator’s response to the COVID-19 pandemic.

CEO Bill Magness, acknowledging the “unusual meeting format,” detailed ERCOT’s plans and actions taken since March 3, when the Texas grid operator first limited employee travel and directed that all meetings be conducted via webinars or teleconferences. Staff were directed to work from home on March 18 if they did not have on-site responsibilities, an order that extends through May 3.

He thanked employees and contractors for staying in regular contact with ERCOT stakeholders and “working to ensure our response is coordinated with theirs.”

“In the best of times, ERCOT employees are good problem solvers and devoted to their mission,” Magness said. “Those characteristics have proven extremely important during these difficult times.”

ERCOT will continue to develop contingency plans to protect the health of on-site workers “before conditions become closer to normal,” Magness said. He said it continues to solicit advice and guidance from public health and regulatory authorities, its U.S. and Canadian grid operator counterparts and the Texas electric industry.

“There is great uncertainty about many things in today’s world, but I feel confident the Texas summer will still be hot,” he said.

ERCOT said in March that it foresees record electric usage and tight reserves this summer, but that it has sufficient capacity on hand. It plans to release a final summer resource adequacy report and a capacity report in May. (See ERCOT Sees Summer Repeat: Rec ord Peak, Tight Reserves.)

COVID-19 has begun to have a larger effect on the grid operator’s load patterns, according to its most recent analysis. Daily peaks were consistently lower during the week beginning April 5, dropping about 2% despite several hot days. Energy usage was down 4 to 5% during the week.

Virus’ Effects Begin to Affect Load Patterns

ERCOT on Thursday told the Texas Public Utility Commission that it has entered into loan agreements with Texas’ transmission and distribution utilities — Oncor, CenterPoint Energy, AEP Texas and Texas-New Mexico Power — to fully fund a $15 million COVID-19 relief program for residential customers having difficulty paying their bills (50664).

The PUC in March ordered the fund’s creation. It applies to customers within ERCOT’s footprint.

Board Approves 4 Change Requests

The board unanimously approved three Nodal Protocol revision requests (NPRR) and a single change to the Planning Guide (PGRR):

- - NPRR 953: defines “relay loadability rating” to align with NERC’s definition changes, which adds a requirement to include protection system limitations for operational planning analysis and real-time assessments. The changes also support ERCOT housing and monitoring the relay loadability rating in Energy Management System applications.
  - NPRR 997: requires an entity controlling a primarily natural gas-fired generation resource to supply ERCOT with a declaration contained in the summer weather preparedness form. The declaration should state that the resource entity or the resource entity’s qualified scheduling entity has made a written effort to communicate with the operator of each gas pipeline directly connected to the entity’s generation resource to coordinate any planned pipeline outages to maximize the resource’s availability during the summer peak load season.
  - NPRR9 98: establishes a requirement that ERCOT post all emergency response service deployments and recalls to the Market Information System’s public area.
  - P G RR 075: requires resource entities and interconnecting entities to provide model-quality test results that demonstrate appropriate performance for submitted dynamic models. Also clarifies that dynamic model data shall be provided using the appropriate dynamic model template; raises awareness of requirements associated with user-written dynamic models; and makes various miscellaneous language updates and corrections, including the elimination of a section superseded by NERC Reliability Standard PRC-002-2 and a Nodal Operating Guide section on phasor measurement recording equipment.

— Tom Kleckner