Page 1172 – RTO Insider

April 19, 2020February 12, 2025

NYISO Launches Fuel Security Effort

By Michael Kuser

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.

April 19, 2020

FERC Tweaks Entergy Bandwidth Decision

By Amanda Durish Cook

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).

Entergy bandwidth — 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.

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

April 19, 2020

FERC Grants NYISO Public Power Definition Waiver

By Michael Kuser

FERC on Thursday granted NYISO a waiver of the Tariff language defining a public power entity, extending the definition to cover any government entity, regardless of whether it owns or controls distribution facilities and provides electric service (ER20-922).

The ISO in January requested the waiver of Section 26.5.3.6 of its Market Administration and Control Area Services Tariff in order to allow it to continue granting unsecured credit, up to $1 million annually each, to government entities that do not meet the definition of public power entity.

NYISO also said it is working with stakeholders to revise the relevant definition and seek approval from the commission.

“NYISO acted in good faith because it did not intentionally disregard the limitations set forth in the currently effective definition of public power entity and … took this self-correcting action promptly upon discovering the limitation in its current definition,” the commission said.

The ISO said it extended unsecured credit to government entities, regardless of whether they own or control distribution facilities and provide electric service, based on a good faith understanding of how Section 26.5.3.6 should be administered in light of the credit profiles of government entities.

NYISO Public Power Definition — Workers do maintenance on a turbine in a New York Power Authority project. | *NYPA*

The commission also found NYISO’s waiver request was limited in scope, being in place for nine months and only involving a subsection of a definition, noting that the ISO said that it may not need the waiver for the full nine months.

FERC said that granting the waiver will avoid needlessly creating practical business difficulties for certain municipal and government entities. It is also consistent with the underlying Tariff recognition that municipal entities generally do not present significant risk of nonpayment but are unable to demonstrate creditworthiness through conventional indicators, the commission said.

NYISO identified 10 municipalities or other government entities that would be affected by the requested waiver, resulting in an extension of up to $10 million in unsecured credit among them.

Finally, the commission found that the waiver request would not have undesirable consequences “because, as NYISO explains, there has not been any material increase to the financial risks of NYISO or other market participants, and denying the requested waiver could needlessly harm government entities that do not own or control distribution facilities and provide electric service.”

Given that the ISO admitted to having been violating the Tariff definition since as early as 2004, the commission said it would “exercise our discretion in addressing such matters and, given the facts and the record before us in this matter, take no action with respect to the instances of NYISO’s past noncompliance.”

April 17, 2020January 26, 2025

Danly Introduces Himself at 1st FERC Open Meeting

By Michael Brooks

James Danly attended his first FERC open meeting as a commissioner Thursday, albeit virtually, as the proceeding was held by teleconference because of the COVID-19 pandemic.

Danly, who served as general counsel for the commission from September 2017 until March 31, did not issue any concurrences or dissents during the meeting, joining Chairman Neil Chatterjee in voting “aye” on the consent agenda. But he did give some insight into his priorities and regulatory philosophy during his opening remarks.

He listed “correctly incentivizing needed transmission,” ensuring electric reliability and “the efficient and thorough review of our certificate applications” as his top issues.

FERC’s approvals of gas infrastructure “have been challenged repeatedly with ever greater frequency in the courts, and we have a nearly unblemished affirmance rate for the last two and a half years,” he said. “That is a testament to the reasoned decision-making of the commission in issuing these orders and to the legal durability of the commission’s orders. … I am adamant that we continue to maintain those high standards in our certificate issuances.”

He also said he was “committed to further refining the pricings in our markets,” asserting that the commission’s rejection Thursday of rehearing requests on its order expanding the minimum offer price rule in PJM “marks an important step in ensuring accurate price signals in the capacity market. But I think there’s more to be done.” He said he was interested in looking at pricing in the energy markets, as well as “the price effects of the participation of non-energy-producing resources in the capacity market.” (See related story, FERC: RGGI, Voluntary RECs Exempt from MOPR.)

Danly concluded with his ideology. “We have to respect the federalist principles that are enshrined both in our authorizing statutes and the Constitution. You know, the commission is not in the business of — typically not in the business of pre-empting state actions. What we do is administer the matters in our jurisdiction, specifically the wholesale rates in interstate commerce. …

“We need to observe those lines of authority that Congress has laid out for us. And on that subject, I don’t think the commission should be quick to expand its jurisdiction. As tempting as it can be sometimes, Congress has laid those lines very scrupulously, and we should follow them scrupulously. …

“Reasoned decision-making is not simply a sine qua non. … It is what the entities who we regulate deserve. … I would like to see us dispense with as much case-by-case analysis as possible when unambiguous, bright-line rules are feasible.”

In his own opening remarks, Commissioner Richard Glick welcomed Danly and remarked on his impressive vocabulary, including his frequent usage of Latin terms. Because of that, he said, he had a Black’s Law dictionary on hand. At the end of the meeting, Glick explained that sine qua non meant “an indispensable requisite.”

Danly also announced the first two members of his staff, who followed him from the Office of General Counsel: Matthew Estes, a former colleague of his at Skadden, Arps, Slate, Meagher & Flom; and Kyrstin Wallach, a 2017 graduate of the George Washington University Law School.

April 17, 2020

‘Most Efficient’ Coal Plant in Bankruptcy Again

By Rich Heidorn Jr.

Longview Power, a 710-MW supercritical coal-fired generator that claims to be the most efficient coal facility in North America, filed for bankruptcy Wednesday — for the second time.

Its first bankruptcy in 2013 — when it said malfunctioning equipment hampered its operations — resulted in lenders taking all the equity in the company.

This time, the company says it was done in by liquidity problems resulting from rock-bottom natural gas prices, the loss of a nearby mine, and warm winters and energy efficiency that suppressed demand.

The COVID-19 pandemic didn’t help either, CEO Jeffery L. Keffer said in a 21-page affidavit that accompanied the company’s Chapter 11 filing in U.S. Bankruptcy Court in Wilmington, Del. The company, which said the plant generated $28.1 million of adjusted EBITDA in 2019, has $355 million in debt.

Longview Power plant near Morgantown, W.Va. | *Longview Power*

But the company said it has a prepackaged agreement that will allow it to emerge with lower debt. The company has been approved for a Payroll Protection Program loan to cover the wages of its 140 employees and says it plans to continue operations uninterrupted — and even expand with a 1,210-MW combined cycle gas turbine (CCGT) plant and a 70-MW solar farm. Keffer noted, without apparent irony, that the additional generation would increase revenues “at lower fixed costs per kilowatt” than the coal plant.

But Keffer insists that the coal plant isn’t a white elephant. “Despite recent trends, the PJM region requires a dependable coal-fired option in place for when energy demands inevitably increase. At times of national crisis, dependable utilities are at their most essential, and one key feature distinguishes coal from other existing energy sources — it can be stored.”

The $2 billion plant in Maidsville, W.Va., was “the first clean coal facility,” Keffer said, with equipment designed to be “one of the most environmentally compliant and cleanest coal plants globally.”

With an 8,750-Btu/kWh heat rate, 20% more efficient than older technology coal plants, “Longview is the future of coal,” the company’s website boasts. Indeed, Energy Secretary Rick Perry deemed it so in a 2017 visit.

But after two bankruptcies, does Longview have a future, or are the plant’s owners whistling past the graveyard? And what does its struggles say about the fate of the nation’s less efficient coal-fired generators?

Michelle Bloodworth, CEO of coal trade group America’s Power (formerly the American Coalition for Clean Coal Electricity), said wholesale markets are failing to compensate coal plants for their resilience and fuel security attributes.

“The exorbitant support in the form of subsidies, over $100 billion, that renewable sources of electricity have received over the past several decades has only further distorted the electricity markets,” she said. “We remain concerned that unless action is soon taken to address these flaws, more coal plant owners could be in the situation that Longview Power is in — which will mean we risk further loss of an important piece of a diverse electricity grid.”

Star-Crossed

Longview has had a star-crossed history.

The plant was designed with infrastructure to allow for development of a second “clean coal” generator, including a 4-mile-long conveyer belt to carry coal to the plant from a nearby mine owned by a Longview subsidiary, Mepco Holdings.

But when the plant went into operation in 2011 following construction delays, unscheduled outages and extended planned outages left the plant running at a capacity factor of only 68%, well below its design level of 90%.

Longview began a multiyear arbitration with its building contractors; unable to repay a $1 billion loan that helped fund construction, it filed for Chapter 11 protection in August 2013.

It emerged from bankruptcy in April 2015, with the company winning repairs to the plant and a $325 million loan as the original lenders took all the equity in the reorganized company.

Since the repairs, the plant has generally operated at its design levels, Keffer said.

But it was saddled with high financing costs, including a $30 million senior note at 12%. Then, in 2018, Mepco discontinued operations at all of its mines, including the one supplying Longview, citing “the aging of the mine and adverse geological conditions” that reduced its productivity and made it uncompetitive.

With the 4-mile conveyor belt no longer of any use, the company spent $8.3 million on a dock on the Monongahela River to receive coal deliveries from other mines.

“Under normal operating conditions, the debtors’ steady cash flows enable them to reliably service their funded debt obligations and weather ordinary variations in customer demands, but recent extraordinary fluctuations in the energy market have presented the debtors with new balance sheet challenges,” the company said in its filing.

In addition to the “demand destruction” resulting from energy efficiency and warm winters in PJM, “the coronavirus pandemic has resulted in significant reductions in demand as industrial and commercial users are shut down throughout the region and country,” it added.

Although they designed the site to accommodate a second coal generator, company officials now say they will add a 1,210-MW CCGT and a 70-MW solar farm. “Realization of these development plans would provide operational and fuel diversity to help shelter Longview from the volatility of energy industry trends in the long term,” Keffer said.

Will the company get there?

Despite its efforts to reduce operating costs, renegotiate fuel contracts and seek cheaper financing, the company began “reviewing strategic alternatives” in January 2020. On March 31, the company and lenders reached a forbearance agreement on a $750,000 amortization payment due that day.

With that breathing room — and facing the inability to pay off a $25 million revolving debt that matured on April 13 — the company reached the prepackaged reorganization with its lenders. Twelve investment funds currently own almost 96% of Longview Intermediate Holdings, the plant’s parent company, led by KKR Credit Advisors with 42%. The Wall Street Journal reported that KKR will lose nearly all of its ownership in the deal.

Keffer said the plan will allow “a comprehensive balance sheet restructuring that will reduce Longview’s debt burden, increase liquidity and send a strong message to Longview’s employees, vendors and other business partners that Longview is well positioned for future success.”

Proportion of units recovering avoidable costs: 2011-19 | *Monitoring Analytics*

The deal will eliminate $350 million of first lien and subordinated debt and provide the company a $40 million
“exit facility” loan from secured term lenders that will take a 90% stake in the reorganized company. It also allows “unimpaired” payments to unsecured creditors to ensure “minimal impact on the debtors’ operations and their key business partners.”

The company asked the court to have creditors vote on the plan by May 1 and schedule a confirmation hearing on May 22.

But even if all goes as planned, Longview faces a difficult future.

The Independent Market Monitor’s 2019 State of the Market report said only 26% of PJM’s existing coal fleet was able to recover its avoidable costs from energy, capacity and ancillary services revenue in 2019, down from 68% the year before. New coal plants have not received enough net revenue to cover their costs in any zone in the RTO since 2009, two years before Longview began operation.

Conditions have worsened this year with day-ahead electricity prices at the PJM West hub averaging $19.83/MWh, a 47% drop from the $37.48/MWh average in 2018 and 2019, the company said.

Keffer had expressed confidence during Secretary Perry’s 2017 visit that natural gas prices would rise once more pipelines are built to take it from Pennsylvania and West Virginia. “The world is clamoring for our natural gas,” he said. “Once they start consuming that gas, your supply is going to start matching that demand. So the price is going to go back up.”

Natural gas is currently selling at about $1.40/MMBtu at the Dominion South hub, down from the $2.65/MMBtu average in 2018/19, Keffer said. “The price of natural gas is even lower in the immediate area where Longview operates due to the presence of shale gas,” he added.

His filing includes a 13-week pro forma projecting the plant will generate $20.3 million in revenue through July 10. Operating expenses of almost $25 million will leave it with a negative cash flow of $4.6 million for the period.

Expansion Plan

On the positive side, Longview said it will be able to add the combined cycle plant at $200 million less than the cost competitors would have to pay for a comparable new build in PJM, thanks in part to the Dunkard Creek water treatment facility, which can serve both Longview and the CCGT project.

Permitting for the CCGT project is expected to be completed during the first quarter of 2021.

The solar project would involve 188,000 370-watt panels over 300 acres in Maidsville and Greene County, Pa. The solar project will include the laydown areas for the CCGT project — the areas used for receipt, storage and assembly — after the gas plant is completed, the company said.

The math for new gas and solar plants is more encouraging than that of coal. In 2019, a new CCGT would have received sufficient net revenue to cover levelized total costs in half of PJM’s 20 zones, the Monitor reported. Recovery was 98% in 2019 in the APS zone, where Longview is located.

New solar projects would have sufficient net revenue to cover levelized total costs in AECO, JCPL and PSEG, where renewable energy credit revenues are high, but not enough to cover costs in Dominion or DPL, the Monitor said.