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).
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.
Commissioner Shelly Botkin shares her thoughts on the PUC’s COVID-19 relief fund.
“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.
“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:
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 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.
NYISO’s Management Committee on Wednesday saw graphic evidence of how the COVID-19 pandemic response is impacting power demand and heard how the ISO’s operations team continues to be sequestered at the two control centers, alternating shifts.
“Even though they were sequestered on-site, we didn’t take for granted that they weren’t infected, so after a 14-day period we allowed them more liberty to move around the site,” NYISO CEO Rich Dewey said.
“We’re almost exclusively working from home, except for the operators,” he said. “We still have to run operations and issue invoices, so from a business process viewpoint, I’m happy to report that’s all going very well. I’m happy to report that we have not experienced any operational issues yet.”
Regional impacts of COVID-19 pandemic on daily energy patterns | NYISO
Demand Forecasting Manager Charles Alonge presented estimated impacts of the pandemic on NYISO demand.
“We saw approximately a 4% drop in daily energy across the New York Control Area for that first week,” Alonge said. “Moving into the second week of the shutdowns, we saw the decline grow to about 8% during the week beginning March 22, and then the last week, March 29 through April 4, stayed the same at about an 8% decline.”
The week ending April 11 saw a further 1% decline in load, to 9% below the expected levels, he said.
The same energy information plotted on daily, regional and NYCA bases showed varied regional impacts.
“The biggest impact on load was seen in Zone J, New York City, and Zone J also has the largest commercial percentage of load in the New York Control Area,” Alonge said. “The biggest signal that we have observed with respect to demand impact is the morning ramp, which is lagged against where we expect it to be, and also the morning peak for this time of year is delayed.”
Recent impacts of COVID-19 on daily energy by week | NYISO
Budget Precautions
The committee approved a staff proposal for the ISO to retain $6.4 million remaining from the 2019 budget cycle to potentially offset a shortfall in 2020 Rate Schedule 1 (RS1) recoveries and unplanned expenditures resulting from the pandemic.
The NYISO Board of Directors will vote on the budget proposal at its meeting this week.
“If we do find that these funds are not needed for the estimated budget shortfall, we still will have the opportunity to pay down principal on outstanding debt in the fourth quarter of 2020,” CFO Cheryl Hussey said.
The recommendation was discussed with market participants at the Budget and Priorities Working Group meeting March 31 following completion of NYISO’s 2019 financial statement audit.
The 2019 $6.4 million budget surplus stems from a RS1 overcollection of $700,000 combined with a spending underrun of $5.7 million.
ESR Scheduling Performance Proposal
The MC approved a proposal to resolve scheduling performance issues related to energy storage resources (ESRs).
Michael DeSocio, NYISO’s director of market design, presented a proposed Tariff revision that would allow the ISO to provide stakeholders advanced notice of performance concerns no later than 4 p.m. on the day before day-ahead bids must be submitted for a day-ahead market (DAM) day.
The Tariff provision also would suspend the use of ISO-managed energy levels with DAM offers until the performance concerns have been addressed.
The Tariff change will be bundled with other ESR revisions and voted on by the board this week ahead of filing with FERC later this month.
Enhancing Mitigation Rules
The MC also approved a fast-track approach for the ISO’s proposal to revise its buyer-side mitigation (BSM) Part A exemption test based on the Market Monitoring Unit’s two-pronged recommendation as part of the 2020 Comprehensive Mitigation Review (CMR) project. It recommended that the board approve measures for filing with FERC so that the changes could be used for the current class year.
ICAP Mitigation Engineer Christina Duong presented the CMR project overview, saying the goal is to complete a market design this year, and that revisions to the Part A test are part of BSM enhancements.
NYISO’s BSM rules provide that, unless exempt from mitigation, new installed capacity (ICAP) suppliers in mitigated capacity zones may only participate in the ICAP spot market auctions at a price at or above the applicable offer floor until their capacity clears 12 months (not necessarily consecutively).
FERC in February narrowed the resources exempt from NYISO’s BSM offer floor determinations in southeastern New York, ordering the ISO to subject storage and special case resources to a minimum offer floor in its capacity market (EL16-92). (See FERC Narrows NYISO Mitigation Exemptions.)
Prong 1 of the CMR involves changes to the parts A and B exemption tests such that public policy resource (PPR) examined facilities would be placed in the supply stack before non-PPR ones. Projects currently go in the supply stack from lowest to highest net cost of new entry.
“This change will allow legitimate PPR supply resources to be awarded a Part A exemption before non-PPR resources that may be less expensive but do not further the state’s policy objectives,” Duong said. “This is an incremental improvement as part of that larger goal, but we still may revisit the Part B mitigation study period as well.”
“Among the stated goals in doing this [CMR] was to help enable the state’s achievement of the recently enacted climate act,” said Howard Fromer, director of market policy for PSEG Power New York. “In a related vein, earlier this week there was a petition filed at FERC seeking a technical conference on carbon pricing and pointing to all the extensive work that NYISO has done.” (See related story, IPPs, Renewable Groups Seek FERC Carbon Pricing Conference.)
Addressing Dewey, Fromer said, “If you haven’t seen the petition, I encourage you to do so, and I hope the New York ISO would be supportive of that request. It’s not asking for a rulemaking; it’s asking for just a technical conference to discuss these issues … and hopefully put in a filing at FERC indicating you would support this technical conference and participate in one.”
“I read [the petition] earlier this morning, and I absolutely would support any open discussion that supports the advancement of carbon pricing,” Dewey said. “The New York ISO continues to be very supportive of New York state’s goals. … The pandemic aside, we do recognize that the clock is still ticking on the achievement of these goals and the timeline it’s going to take.”
Fromer said he hoped that Dewey would share his support with FERC.
“Yes, I have personally told that to each of the FERC commissioners, and at the next opportunity I’ll reiterate it,” Dewey said. “We still think [carbon pricing] is the most effective, efficient means for the state to achieve its goals.”
The Climate Leadership and Community Protection Act (A8429), signed into law last July, calls for 70% of New York’s electricity to come from renewable resources by 2030 and for electricity generation to be 100% carbon-free by 2040.
A new initiative will aim to help NYISO improve its monitoring of fuel and energy security (FES) across the New York grid, stakeholders heard last week.
The effort comes after NYISO last year engaged Analysis Group to produce an FES study, which was posted in November along with ISO management’s response.
The study’s findings have prompted NYISO to include additional fuel security elements in both its winter capacity assessments issued each fall and cold weather operations presentations provided each spring, Vice President of Operations Wes Yeomans told the Installed Capacity/Market Issues Working Group during a teleconference April 14.
The ISO also plans to create forward load forecasts and possibly develop fuel-related “thresholds or triggers” to help identify potential future FES concerns.
NYISO will expand the outlook of its forward-looking, short-term internal operational assessments by an additional week to allow for improved consideration of FES matters, Yeomans said.
“Certainly in the winter time frame, there’s an opportunity for us to take a lot of those constructs from the FES study and do it internally when we do that weekly capacity review,” Yeomans said. “Ultimately, that weekly internal review is intended to evaluate electric capacity sufficiency, out seven or 10 days, to meet the projected loads or peaks, and now we’re going to extend the time frame to be 14-plus days.”
| Analysis Group
Any large deviations in actual conditions versus the assumptions used in the FES study that impact reliability may trigger a need to refresh the study, he said.
“There are two categories of thresholds, or triggers, that may require a full-blown rerunning of the study,” Yeomans said. “One would be if some set of variables change in a radical way; another one may just be that actual events don’t play out as assumed. There may be less wind developed, or less solar gets developed, or maybe the offshore wind assumptions for Long Island get delayed by two or three years; maybe there’s some accelerated retirements — there are a lot of variables that went into that study.”
Luthin Associates’ Aaron Breidenbaugh, representing a group of nonprofit institutional customers known as Consumer Power Advocates, asked “if the ISO has any process going forward for looking at the general reliability implications of the COVID-19 pandemic.”
Yeomans responded that NYISO’s operations department talks to the New York transmission owners every week to assess issues specific to the pandemic. NYISO says it “has communicated with generation operators to facilitate awareness of asset plans for ensuring continued operations and any concerns about impacts of COVID-19 on availability of critical staff.”
“A lot of those discussions are more on critical employees than infrastructures, but we do talk about implications out in the field,” Yeomans said. “If any TO was projecting implications with transmission capability transfers, whether Central East or otherwise, the NYISO would be informed of such conditions.”
Regarding longer-term infrastructure enhancements, the ISO has to date not been informed of any projected delays in four large transmission infrastructure projects over the next couple of years, including public policy transmission projects, he said.
The latter include North America Transmission and the New York Power Authority building the double-circuit 345-kV line from Edic to New Scotland for Segment A of the AC Transmission Public Policy Transmission Need (PPTN), which feeds the Central East interface. National Grid’s Niagara Mohawk Power and NY Transco are building Segment B of the project, a section of the grid feeding the Upstate New York/Southeast New York electrical interface. (See “AC Public Policy Tx Projects near Approval,” NYISO Management Committee Briefs: Feb. 27, 2019.)
In addition, NYPA has a couple big projects of its own, including rebuilding and upgrading the existing 230-kV lines from Messina to National Grid’s Adirondack substation, Yeomans said.
NYISO will return to stakeholders in fall 2020 to discuss enhanced fuel security findings as part of the 2020/21 winter assessment, he said.
Planning the Future Grid
Energy market design specialist Ashley Ferrer led a discussion of the ISO’s “Grid in Transition” initiative, focusing on nine areas of market design that the ISO believes merit “immediate attention.”
Stakeholders last month began exploring detailed assumptions and models to be included in a Brattle Group study on transitioning New York’s grid to cleaner resources. (See N.Y. Looks at Grid Transition Modeling, Reliability.)
The ISO recommends that it implement market design changes through 2024 regarding carbon pricing; comprehensive mitigation review; participation models for distributed energy and storage resources; enhancing energy and shortage pricing; energy and ancillary services product design review; enhancing resource adequacy models; revising resource capacity ratings to reflect reliability contribution; and adjusting capacity demand curves.
New York’s 2019 downstate generating capacity, Zones F-K | Analysis Group
“Some of these recommendations do have projects that are current, mainly in the operating reserves portion, but some of them do not have projects,” Ferrer said. “The purpose of going through these is to understand what some of these market design recommendations are, and if there are specific ones that project ideas come from, then that is something that we’ll work into the normal project prioritization process.”
New York lawmakers this month passed a budget amendment to speed up the permitting and construction of renewable energy projects in order to meet the state’s ambitious clean energy goals, which are driving the grid transition. (See Cuomo Proposes Streamlining NY’s Renewable Siting.)
A reliability gap assessment identified potential high-level market design concepts for existing and potential future components of NYISO’s markets, which the ISO divided into two categories: ancillary service products and energy market mechanics.
“When you’ve identified a potential reliability gap, there still may be multiple different ways of closing that gap and addressing the issue,” said Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers.
Referring to the ISO’s standard approach of conducting consumer impact analyses only after a specific proposal has been finalized, Mager said, “We may get some idea of what the impact of the proposal is compared to the status quo, but we don’t really get any type of analysis of maybe three or four different ways to skin this cat, and these are the differing economic impacts associated with each of the options. I’d like the NYISO to bear this in mind as it starts developing potential proposals or market rule changes.”
NYISO will present on interregional coordination May 11 and is planning two additional presentations, tentatively for next month, to provide in-depth analysis of the market design components addressed. Planners by June will also present an overview of recommendations related to the ISO’s operations processes, Ferrer said.
FERC on Thursday reversed one part of a previous decision on the long-disputed bandwidth calculation that Entergy last used more than five years ago to equalize production costs among its operating companies.
In response to the latest rehearing request in the ongoing proceeding — this time from the Louisiana Public Service Commission — FERC ruled that some tax gains from the Waterford 3 nuclear plant near New Orleans can be included in bandwidth formula accounts (EL10-65-006).
Before it joined MISO in 2015, Entergy’s operating companies functioned as one system, although each had different operating costs. FERC in 2005 determined that production costs across the multistate Entergy system were not as equal as the company promised and imposed a bandwidth payment remedy, spurring a dispute that has lasted several years. Under the arrangement, Entergy’s low-cost operating companies made payments to the highest-cost company in the system using a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the system average.
Since then, the allocation of 2007-2015 production costs among Entergy’s half dozen operating companies under its multistate system agreement has been a source of disagreement for a decade.
In a March 2018 ruling, FERC made three findings regarding Entergy’s bandwidth equalization:
that it properly accounted for the 9.3% interest sale and leaseback of Waterford 3 in its accumulated deferred income taxes (ADIT) when it characterized the sale as financing and excluded it from bandwidth formula payments;
that Entergy could keep interruptible load in its system monthly coincident peaks used to develop the 2010 and 2011 bandwidth calculations, although all other years of Entergy’s bandwidth payments exclude interruptible load; and
that it appropriately accounted for the costs of the allowance for funds used during construction for the River Bend nuclear plant north of Baton Rouge in bandwidth payment calculations. (See FERC Affirms Ruling Favoring Entergy Bandwidth Calculation.)
FERC last week said it is now persuaded by the Louisiana PSC’s argument that the tax gain portion found in Waterford 3’s financing of ADIT “is directly related to amounts included in bandwidth formula accounts.” The commission said the amount “is generally and properly includable for FERC cost-of-service purposes” and should be included in the bandwidth calculation.
However, FERC told the Louisiana PSC it wouldn’t budge on its earlier decision to allow interruptible load to factor into the 2010 and 2011 bandwidth calculations but not any other years’ calculations.
“We continue to find that the commission already resolved the interruptible load issue … and that no further relief is available in this separate proceeding,” the commission said.
Rehearing Denied on Entergy Control Centers Transfer
FERC also denied several rehearing requests over Entergy’s two recently constructed transmission control centers in in Jackson, Miss., and Little Rock, Ark.
In September, FERC authorized the ownership transfer of the control centers from Entergy Services to Entergy’s Arkansas, Louisiana, Mississippi, New Orleans and Texas operating companies. (See Entergy Control Center Ownership Changes OK’d.)
Multiple regulators in Southern states sought rehearing on the fairness of the transaction itself (EC19-18-001) and the joint ownership agreement (ER19-211-001).
An Entergy control room at the Nelson coal plant site in Louisiana | Entergy
The Louisiana PSC charged that FERC ignored the impacts to retail rates when it approved the transaction. The costs incurred to acquire the control centers will become an input into the Entergy operating companies’ respective rate formulas.
But FERC denied the PSC’s rehearing request, finding that while the transaction will increase rates, the rate impact isn’t adverse. The commission said the transfer of the control centers is in the public interest because they contribute to the “safe and reliable operation of the Entergy transmission system.” FERC also reminded parties that the reasonableness of the transaction’s price impacts wasn’t in question.
“The commission’s Section 203 analysis concerning rate impacts of a transaction does not extend to retail rate impacts unless a state commission lacks the authority to review such rate impacts and specifically asks the commission to do so. We note that, although the Louisiana commission and the Arkansas/Mississippi commissions have intervened in this proceeding, they have not asked us to scrutinize such effects here. We also note that our approval of the transaction in this proceeding does not preclude the Arkansas/Mississippi commissions or the Louisiana commission from examining the transaction’s effects on retail rates,” FERC said.
The commission also brushed aside Louisiana regulators’ concerns that the transaction would alter its jurisdiction over Entergy. FERC said the state commission will continue to have the same regulatory authority over Entergy operating companies “before and after the transaction.”
FERC rebuffed the Arkansas and Mississippi Public Service Commissions’ concerns that Entergy Services acted as a public utility “without satisfying the requirements of a public utility” by constructing the control centers in the first place. FERC simply said the concerns were out of scope of the current docket.
“With regard to the claim that Entergy Services improperly transferred the facilities, we note that Entergy Services appropriately sought the commission’s approval of the transfer in this proceeding,” FERC added.
As to the transaction agreement, the Louisiana PSC said it was unfair that the ownership interests of the two facilities would be divvied up according to the Entergy operating companies’ coincident peak loads, claiming that Louisiana ratepayers were set to take on more costs stemming from the control centers. The state commission also claimed that an Entergy coincident peak is now meaningless because the Entergy companies “no longer operate as a system but are instead separate members of MISO, which has a different coincident peak.”
FERC was not persuaded by either argument.
“The coincident peak load allocation method is the traditionally approved method for allocating the costs of transmission facilities, and the historical and consistent use of this allocation method renders its choice presumptively reasonable,” the commission said.
Finally, FERC also said the Louisiana PSC’s concerns over the costs incurred to acquire the control centers is also outside the scope of the proceeding.
“As the commission explained in the agreement order, the costs incurred to acquire the control centers instead serve as an input to the operating companies’ respective formulas, and the reasonableness of such costs for inclusion as an input to those formulas is not before us,” FERC said.
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.
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.”
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.)
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.
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.
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.
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.
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.)
A gas turbine at Golden Spread’s Elk Station plant | GE
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.
Lyntegar Electric Cooperative is one of Golden Spread’s 16 members in oil-rich West Texas. | Lyntegar
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.
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: Record 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):
NPRR953: 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.
NPRR997: 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.
NPRR998: establishes a requirement that ERCOT post all emergency response service deployments and recalls to the Market Information System’s public area.
PGRR075: 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.
