Page 1187 – RTO Insider

October 20, 2019

NEPOOL Markets Committee Briefs: Oct. 16, 2019

The New England Power Pool Markets Committee on Wednesday continued discussing ISO-NE’s Energy Security Improvements (ESI) proposal, with a focus on the plan’s treatment of day-ahead ancillary services.

One document up for discussion was a memo from ISO-NE COO Vamsi Chadalavada on the RTO’s draft 2020 Work Plan to file a long-term fuel security mechanism, as presented to the Participants Committee earlier this month. The other was a schedule of ESI milestones. (See “ISO-NE Draft 2020 Work Plan,” NEPOOL Participants Committee Briefs: Oct. 4, 2019.)

ISO-NE Chief Economist Matt White reviewed the monthly components of the ESI project through FERC’s April 15, 2020, filing deadline, starting with the design and impact assessment of core day-ahead ancillary services.

The RTO’s work on ancillary services falls into two distinct areas. The first is the time-intensive process of completing the full mathematical formulation for the day-ahead co-optimized design. The second is addressing stakeholder questions about how the core design will actually work.

A footnote on the schedule said the RTO “plans to prepare a summary for the November MC on the current state of the ESI design, e.g., the status of the various components.”

Speaking about the conceptual design for mitigation of day-ahead ancillary services at the Sept. 3 MC meeting, External Market Monitor David Patton expressed willingness to elaborate on the views he presented, which likely will be provided before the discussion scheduled for January. (See ISO-NE IMM Details Market Power Concerns on ESI.)

Patton has direct experience monitoring markets that have co-optimized day-ahead ancillary services in both NYISO and MISO, and also has views on how the current mitigation can be made to work under ISO-NE’s design.

NEPOOL — Day-ahead marginal units by transaction and fuel type show the percentage of time that each transaction type set price in the day-ahead market since Winter 2017. | *ISO-NE*

NESCOE Seeks ESI Analysis

New England States Committee of Electricity (NESCOE) representative Ben D’Antonio submitted a memo ahead of the meeting outlining the group’s priorities for the extra months of planning provided by FERC’s deadline extension.

NESCOE said it seeks a comparison of the differences between the ISO-NE ancillary services proposal and those currently used in other markets, and how they would be modeled differently by the RTO’s consultant, who also should provide an annual simulation of the ESI proposal’s impacts.

The memo requested analysis of the External Market Monitor’s recommendation to incorporate operating reserves into the day-ahead market, asking that the RTO demonstrate that the ESI ancillary services proposal is better than other more straightforward approaches for integrating operating reserves into the day-ahead market.

NESCOE also requested further evaluation of the sensitivity of the results to the underlying input assumptions.

ESI Impacts

ISO-NE economist Chris Geissler presented on improvements to the production cost model used in the impact assessment of ESI, including enhancements that extend the model to non-winter months, further assess its fuel input assumptions and improve its calculation of energy imbalance reserves (EIR).

ISO-NE agrees with NESCOE that inclusion of non-winter months in the model will allow the RTO and stakeholders to better assess the expected market and reliability impacts from ESI, Geissler said.

Geissler pointed out that there may be some instances where the model assumes that resources will procure more or less incremental oil than would be expected. Further analysis could help the RTO determine whether to modify those assumptions to better reflect their impact on incremental incentives, fuel inventory and reliability, he said.

He also said that while the current practice of setting the EIR at a fixed value for each hour captures the historical gap between the forecast load and cleared day-ahead generation, it does not account for proposed rule changes under ESI that could decrease the size of the gap. Enhancement would modify the model’s assumptions about day-ahead load to include price-responsive demand bids, as occurs in the day-ahead market in practice.

Benefits to improving the EIR calculation, he said, are market and reliability outcomes that better reflect those expected under the ESI proposal; increased day-ahead energy awards and reduced EIR awards; reduced impacts on energy and ancillary service clearing prices; and a weaker impact of ESI on consumer costs.

Geissler said the RTO hopes to publish an impacts analysis report in February in preparation for an MC vote in March ahead of an April filing with FERC.

Other ESI Business

Brett Kruse, vice president of market design at Calpine, briefly outlined the company’s proposal for a forward enhanced reserves market (FERM), which would value existing fuel-secure resources in the region and provide a forward price signal to incentivize fuel supply arrangements or investments.

The Connecticut Public Utilities Regulatory Authority presented an amendment to insert Tariff language requiring the Internal Market Monitor to prepare a quarterly report assessing the competitiveness of energy call option offers in the day-ahead energy market.

David Errichetti of Eversource Energy presented the utility’s proposed amendment dealing with the overlap of the inventoried energy program and ESI operating at the same time in winter 2024/25.

Enhancing Search in GIS

The MC unanimously approved changes to the Generation Information System (GIS) and its operating rules to provide additional searching and sorting capabilities for users, effective Jan. 1, 2020.

NEPOOL Counsel Lynn Fountain presented the changes, which will allow users to access GIS data related to imports for New England state renewable portfolio standards, aggregated separately by type of generator and resource for each control area where an importing generator is located. Parties would remain unable to identify individual generators or load-serving entities associated with any data, Fountain said.

The GIS Agreement provides that the system administrator perform up to 200 hours of development work for enhancements to the GIS each year without additional cost. The administrator estimates that the proposed changes would require 34 hours to complete. Because changes approved earlier this year required 166 hours to complete, the 200-hour credit would be fully used for 2019. The MC has authority to approve the changes without Participants Committee action.

Sunsetting Fuel Security Reliability Review Provisions

The MC discussed revisions to Market Rule 1 to sunset the fuel security reliability review provisions following Forward Capacity Auction 14, one year earlier than the currently effective period. Allison DiGrande, ISO-NE director of NEPOOL relations, presented the changes.

Committee Chair Alex Kuznecow scheduled the item for a vote by the MC at its Nov. 12-13 meeting.

The MC last month approved amending Market Rule 1 to limit the retention of resources needed for fuel security to two years. (See NEPOOL Markets Committee Briefs: Sept. 18, 2019.) Continuing retentions into the 2024/25 capacity commitment period (FCA 15) is not necessary with the expected implementation of ESI in the same period, DiGrande said.

The proposal would delete any language referring to 2024/25 from Section III.13.2.5.2.5A and Appendix L in Market Rule 1.

The RTO wants the change to become effective prior to March 13, 2020, the retirement delist and permanent delist bids deadline for FCA 15.

— Michael Kuser

October 20, 2019

FERC Queries PJM on Virtual Transaction Rules

By Christen Smith

PJM must provide FERC with a refreshed briefing on whether the RTO still wants to charge uplift on all virtual trades — including the currently exempted up-to-congestion transactions (UTCs) — in light of recent market changes.

In its order issued Thursday, the commission gave PJM 30 days to respond to 10 questions that probe deeper into the “typical magnitude and direction” of UTCs’ impact on uplift and how the RTO might quantify those costs — whether it be a flat fee, a percentage-based allocation or some other methodology — given the reduced volume of virtual trading over the last two years. FERC also invited stakeholders to update the proceeding with their responses (EL14-37).

In January 2017, the commission extended PJM’s financial transmission rights forfeiture rule to cover UTCs, but it denied the RTO’s proposal to extend uplift charges to the trades as well. Under existing rules, only increment offers (INCs) and decrement bids (DECs) accrue uplift, though PJM asserts that UTCs play a crucial role in how expensive those charges can be across different bidding locations — or nodes.

In February 2018, the commission approved PJM’s proposal to reduce the number of nodes by 90%, which in turn limited INCs and DECs to those where either generation, load or interchange transactions are settled, or at trading hubs where forward positions can be taken. They also barred UTCs from zonal, extra-high-voltage and individual load nodes. The changes reduced the number of INC/DEC trading nodes from 11,727 to 1,563, and UTC nodes from 418 to 49. (See FERC OKs Slash in Virtual B idding Nodes for PJM and FERC Upholds PJM Orders on Virtual Trading Nodes, Uplift.)

Two months later, FERC issued Order 844, which incorporated additional uplift transparency rules for all RTOs and ISOs, but it withdrew a requirement that grid operators categorize real-time uplift costs based on their causes and allocate them only to market participants “whose transactions are reasonably expected to have caused” the uplift. (See FERC Orders RTOs to Shine Light on Uplift Data.)

Day-ahead marginal resources by type/fuel: 2011 through 2018 | *Monitoring Analytics*

“The commission stated that it continued to believe that uplift ideally should be allocated to those market participants whose transactions caused the uplift and that allocations of uplift costs should avoid penalizing behavior that can improve price formation,” FERC wrote. “However, based on the record in that proceeding, the commission found commenters’ substantial concerns about the proposal sufficiently persuasive to decline to take generic action at the time.”

The proceeding represents six years of debate between PJM and its stakeholders over whether uplift can be accurately pinpointed to a specific UTC, given the day-to-day variability of the energy markets. Others argue there’s no proof that UTCs even cause uplift, let alone should be charged for it.

Given the challenges of appropriately assessing uplift on individual UTCs, PJM must tell FERC if it’s possible to instead determine an aggregate impact. The commission also wants updated analysis that shows changes to unit commitment caused by UTCs. Other questions from FERC included:

Are there considerations other than UTCs’ impact on uplift that would still render the PJM Tariff unjust and unreasonable because it does not allocate the costs of uplift to all deviations?
If some types of transactions typically have a smaller impact on uplift than other types of transactions, is it appropriate for PJM to allocate uplift differently to some deviations based on the impact of that transaction type? Why or why not?
Could create an allocation factor to allocate a certain percentage of uplift associated with deviations to UTCs?
Would PJM be able to allocate uplift costs to UTCs by assessing a fixed fee on a per-transaction basis? How would PJM determine such a fixed fee?

October 20, 2019February 13, 2025

EBA Panelists Debate Role of FERC in Regulating Carbon

By Michael Brooks

WASHINGTON — FERC observers have grown used to Commissioner Richard Glick criticizing his Republican colleagues at open meetings for not considering the downstream impacts of greenhouse gas emissions from the natural gas pipelines they approve.

In Glick’s view, Chairman Neil Chatterjee and Commissioner Bernard McNamee are simply ignoring the D.C. Circuit Court of Appeals’ August 2017 ruling in Sierra Club v. FERC (the “Sabal Trail” case), in which the court remanded the commission’s environmental impact statement on the Southeast Market Pipelines Project. The court ordered FERC to estimate the project’s impact on GHG emissions or explain more fully why it could not do so.

FERC ultimately chose to do the latter, arguing that it does not have sufficient information to determine the source of the gas being transported over pipelines, nor its end use. (See FERC Narrows GHG Review for Gas Pipelines.)

From left to right: Jay Costan, Dentons; Jamie Simler, Ameren; Matthew Christiansen, FERC; and Ari Peskoe, Harvard Law School. | © RTO Insider

And it is not legally obligated to seek out that information, Jay Costan, a partner at Dentons, argued at the Energy Bar Association’s Mid-Year Forum last week. He cited the Supreme Court’s 2004 ruling in Department of Transportation v. Public Citizen, which held that an agency has no obligation to gather or consider environmental information if it has no statutory authority to act on that information.

“To be clear, the statutory authority issue that’s involved here is not about what the pipeline does, but about the end use of the gas after the pipeline makes delivery,” Costan said during the conference’s opening panel Oct. 15. “Because the commission has no jurisdiction over end users or the end use of gas, the question becomes whether the commission can deny a pipeline certificate because it determines that the combustion of gas and the production of CO₂ do not comport with the public convenience and necessity.”

Glick’s legal adviser, Matthew Christiansen, said that the court ruled in Sabal Trail that Public Citizen required FERC to do the analysis, as it knew that the pipeline in question would exclusively serve several natural gas plants in Florida.

Glick and Christiansen also argued in an article published in the Energy Law Journal, “FERC and Climate Change,” that “because 97% of natural gas is combusted, the emissions resulting from the combustion of natural gas will generally be a reasonably foreseeable result of a [Natural Gas Act] Section 7 certificate, even if the specific end-use consumer of the gas is not identified in the Section 7 proceeding.”

Even if FERC is not legally obligated to seek the downstream emissions data, it can and should still do so, Glick has argued. “The urgent threat of climate change does not necessitate a wholesale reinterpretation of the commission’s jurisdiction or a novel regulatory paradigm,” they wrote. “Instead, climate change increases the stakes of many commission actions, making it all the more important that the commission carry out its existing obligations.”

Question of Carbon Pricing

FERC will soon face new questions once NYISO files its proposal to price carbon into its markets.

Ari Peskoe at this year's EBA Mid-Year Energy forum

Ari Peskoe, Harvard Law School | © RTO Insider

Panel moderator Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative, wondered if FERC could rule the ISO expanded too far beyond its core mission if it starts pricing carbon. “Is this taking it just a step too far if you have the RTO deciding or just asking for permission to price carbon?” he asked.

“If the commission had to make a finding [under Section 206 of the Federal Power Act] that the markets are unjust and unreasonable because they don’t consider carbon or other environmental benefits, I think that would be a heavy lift,” Christiansen said.

But “because there are a range of reasonable results under Section 205 … if an RTO were to come and say, ‘Hey I want to do this for this reason and it has these market benefits,’ I could imagine that being the kind of thing that the commission could consider,” he said. “I guess what I would say is I don’t see [any reason] that once you put the word ‘CO₂’ in the filing, it somehow dings it.”

“I think it’s a very interesting issue,” Costan said. “Most people’s normal expectation is that fees or taxes [or] charges on something like carbon are going to come from the legislature, either the federal legislature or the state legislature. And these proposals are unique in that there’s not explicit legislative mandate for the charge or the fee.”

NYISO, however, is developing its proposal with the New York Department of Public Service through the Integrating Public Policy Task Force. As ICF International has pointed out, “Unlike most U.S. regional transmission operators, NYISO encompasses only one state and is thus likely to have an easier path to such an outcome than an RTO covering many states with diverse policy agendas, such as PJM,” which is also studying carbon pricing.

October 20, 2019

Changes Proposed for MTEP 19 as PAC Vote Nears

By Amanda Durish Cook

MISO’s Planning Advisory Committee will vote by email on whether to send the RTO’s nearly $4 billion 2019 Transmission Expansion Plan (MTEP 19) to its Board of Directors for approval — but the committee could also advise two changes just ahead of the vote.

PAC leadership was set to conduct its annual vote over whether to move the plan forward for board consideration at its Wednesday meeting, but members called for an email vote.

MISO’s Environmental and Other Stakeholder Groups sector, led by the Clean Grid Alliance (CGA), also tacked on two separate motions that call for planners to re-examine a possible market efficiency project and delay the RTO’s first storage-as-transmission asset (SATA) project for more study on alternatives. Taken together, PAC members have three ballots to consider. Voting will take place through Wednesday.

The PAC will decide on the plan itself, plus two additional stakeholder-originated motions that might delay a project or add another to the buildout package.

Project Manager Sandy Boegeman said MTEP 19 now contains 479 transmission projects costing $3.97 billion. The RTO will post the final MTEP 19 project list Nov. 6.

MISO MTEP — MTEP19 investment by facility type ($ millions) | *MISO*

Helena-to-Hampton Corners

CGA’s first motion asks that MISO revisit the Helena-to-Hampton Corners second-circuit project, which the group said should have been included in MTEP 19 as a market efficiency project. (See MISO Readies MTEP 19, Debates Futures Change.) The $36.1 million, 345-kV project, originally identified in this year’s Market Congestion Planning Study, was set to solve congestion in southern Minnesota at a 4.22:1 benefit-to-cost ratio, but MISO said the project quickly lost value once forecasted wind generation was removed from the equation.

Sean Brady, CGA’s regional policy manager for the East, said he thought MISO’s order of evaluations shortchanged the benefits of the project because the RTO simply finished evaluations first on the nearby 18-mile Helena-to-Scott County line rebuild, which was studied as a network upgrade for proposed generation in the interconnection queue.

“It’s a more cost-effective line based on the information we’ve seen,” Brady said of the Helena-to-Hampton Corners project.

“We believe that we followed the Tariff. We believe that we followed the process,” MISO Director of Planning Jeff Webb said, adding that the RTO could review its policy of studying interconnection upgrades before it evaluates an annual crop of reliability projects.

Webb added that there are going to be “sequencing” issues as long as MISO evaluates transmission projects by type.

Entergy’s Yarrow Etheredge said stakeholders shouldn’t “upend” the planning process this year. She reminded stakeholders that the Helena-to-Hampton Corners project can always be re-examined as part of MTEP 20.

Waupaca Opposition

CGA also submitted a second motion to delay MTEP 19’s lone SATA project until MISO examines more alternatives. (See MISO Recommending 1st Storage-as-Tx Project.)

Brady said he thought the economic analysis behind American Transmission Co.’s Waupaca-area energy storage project was “lacking,” and he urged MISO to re-evaluate the project. He said it’s likely that a traditional wires solution would have more economic benefits.

“A wires solution would be available 24/7, 365, where a battery solution is only available two hours at a time,” Brady said.

Other PAC members seemed unreceptive to the idea.

Etheredge said it wasn’t the PAC’s place to “second-guess” MISO’s MTEP evaluations. ATC’s Bob McKee also pointed out that MISO did evaluate the battery solution against traditional wires alternatives submitted by his company. He pointed out that CGA itself wasn’t offering up any alternatives with its opposition.

CGA’s Natalie McIntire argued that MISO’s evaluation process for SATA projects is nascent and largely untested.

“To me, it’s not clear we have an agreed-upon process to evaluate projects like these,” McIntire said.

MISO has yet to file its SATA proposal with Despite Pushback, MISO Pursuing TO-only SATA.) So far, the Waupaca project remains in Appendix B of the MTEP 19 report, listing projects considered to have a documented need but not yet ready to deploy, with costs not included in MTEP spending totals. The board will hold a separate vote to approve the project after the RTO has SATA rules in place.

New Task Team Put to Vote

As if three motions weren’t enough, PAC members will also decide via email ballot whether to form a new task team to examine sharply rising network upgrades in the interconnection queue and whether MISO’s annual transmission planning process might be overlooking projects. Renewable proponents raised the idea at the September PAC meeting as a growing number of stakeholders press the RTO to address transmission planning assumptions and devise ways to prevent new generation projects from becoming responsible for most transmission development. (See More MISO Members Join Call for Tx Planning Change.)

Sector representatives first debated whether the creation of new task teams needed to go before the Steering Committee, which assigns new issues to stakeholder committees. Webb said he didn’t want to burden the SC unnecessarily with a “bureaucratic loop,” as the PAC doesn’t need permission to spin off its own task teams.

Special MTEP 20 Studies

The PAC will also work out what areas MISO will single out for one-off studies as part of MTEP 20.

In lieu of newly designed futures scenarios next year, MISO has promised unique, targeted studies in the MTEP 20 cycle to identify possible transmission projects. The RTO this summer decided to stop work on a futures update for 2020. (See MISO Halts Futures Work for 2020, Plans 2021 Rebuild.)

Members of the Environmental and Transmission Owners sectors have recommended the RTO study the Minnesota-Wisconsin transfer limitation — known to the MISO community as MWEX — because of the constraint’s voltage stability issues and its location between renewable-rich areas of the footprint and customer bases to the east.

“This study is recommended not only to evaluate this particular constraint, but also as a valuable opportunity to better understand how to assess the implications of non-thermal constraints within the MISO footprint in future economic planning studies,” the TOs wrote in comments to the RTO.

EDF Renewables also asked the RTO for a review of the top congested flowgates in MISO West in light of generation additions and retirements.

October 20, 2019

Challenge to Ameren Illinois Rate Rejected Again

By Amanda Durish Cook

FERC last week again denied Southwestern Electric Cooperative’s multiple challenges to Ameren Illinois’ 2017 update to its transmission rate formula, saying the co-op had rehashed arguments previously rejected by the commission.

The ruling, issued Thursday, showed that Southwestern came up short in nearly all its arguments for a rehearing of the Ameren subsidiary’s accounting for accumulated deferred income taxes (ADIT), regulatory expenses and undeveloped land holdings (ER17-1198-002).

The complaint wasn’t the first time Southwestern has contested Ameren Illinois’ formula rate. The cooperative previously teamed with Southern Illinois Power Cooperative to unsuccessfully challenge several aspects of the utility’s 2016 filing. (See FERC: Ameren Illinois Formula Rate Stands.)

In the more recent complaint, Southwestern had contested allowing Ameren Illinois to direct construction work in progress (CWIP) expenses and renewable energy compliance costs to certain accounts for the recovery of ADIT. The cooperative argued that parent company Ameren — not its subsidiary — should be recovering CWIP expenses for the 500-mile, 345-kV Grand Rivers project in Illinois and Missouri.

But FERC said it already addressed those ADIT issues in 2016 when it ruled that Southwestern’s arguments amounted to a “collateral attack on an allocation specified in the formula rate” because the co-op only challenged the ADIT accounting, not Ameren Illinois’ ability to recover the CWIP.

“Despite claiming that it would not relitigate issues, Southwestern is doing precisely that by raising the same arguments on rehearing of the June 2019 order as it did in the 2016 formal challenge proceeding. We reject those arguments for the same reasons the commission rejected them in [2016],” FERC said.

Southwestern also argued that all of the utility’s regulatory expenses should be recorded in one specific account and that certain regulatory expenses should be excluded from recovery “because they relate to Ameren Illinois’ retail business.” But FERC agreed with the utility that not all expenses related to rate calculations and true-ups are “in connection with formal cases before regulatory commissions.”

The co-op also insisted that Ameren Illinois exclude regulatory expenses linked to generator interconnections from the transmission formula rate, which FERC said was an unreasonable request.

“As a transmission owner in MISO, Ameren Illinois may incur costs associated with disputes it may have with generators involving, for example, payments for network upgrades,” FERC said.

The commission additionally rejected Southwestern’s argument that Ameren Illinois should not be earning a return on land held for future use but not associated with a specific plan. It said the utility previously explained that the land is earmarked for future transmission expansion projects “anticipated to be needed due to projected generation additions or retirements.”

However, FERC did call for a review of Ameren Illinois’ regulatory expenses, directing the company to file within 30 days two separate summaries of any changes it may have made in how it records expenses related to formal challenges and cases before regulatory bodies.

October 20, 2019

FERC Sets GridLiance ATRR Dispute for Settlement

By Tom Kleckner

FERC last week established hearing and settlement judge procedures for Xcel Energy Services’ challenge to GridLiance High Plains’ annual informational filing reflecting its 2019 projected net revenue requirement.

The commission also accepted Xcel’s motion that it combine the docket with a previous settlement proceeding involving GridLiance’s proposed annual transmission revenue requirement (ER19-1357, ER18-2358).

Acting for subsidiary Southwestern Public Service, Xcel in July filed a formal challenge, arguing that inclusion of GridLiance’s Oklahoma Panhandle transmission facilities in its annual update is improper.

GridLiance, which shares the same SPP transmission pricing zone as SPS, submitted its annual update for the upcoming rate year in March. It included in its projected total costs those associated with the Oklahoma assets, which have been upgraded and have a projected ATRR of nearly $8.9 million.

Xcel said the facilities’ inclusion would result in a cost shift to SPS of more than $6 million in 2019 and more than $1 million per year for other load-serving entities in the zone.

The company argued that GridLiance’s Oklahoma facilities are the only assets in service under GridLiance’s formula rate and said that its entire rate base is premised on the claim that they are eligible for recovery as transmission facilities under Attachment AI of the SPP Tariff. Xcel said GridLiance’s entire rate base should be removed from its formula rate because GridLiance has failed to demonstrate that the assets qualify as transmission facilities under Attachment AI or the commission’s seven-factor test.

FERC Order 773 established a process allowing an entity to seek a determination regarding whether facilities are “used in local distribution.” The seven-factor test involves a case-by-case analysis of seven indicators.

FERC found that Xcel’s challenge “raises issues of material fact that cannot be resolved based on the record before us” and said they would be more appropriately addressed in settlement procedures.

“In the event that the [Oklahoma facilities] fail to meet the definition of transmission facilities under Attachment AI, the [assets] could be included in SPP transmission rates if they meet the commission’s seven-factor test,” FERC wrote.

GridLiance said the order confirms its position that Attachment AI governs the definition of transmission within SPP, despite FERC’s clarification. It said “arguments to the contrary” conflict with more than a decade of precedent regarding how facilities are included within SPP’s Tariff.

“Most notable in the order is FERC’s validation of SPP’s use of Attachment AI … in determining whether facilities qualify for inclusion within SPP,” GridLiance High Plains President Brett Hooton said.

GridLiance acquired the facilities in question — 410 miles of 69- and 115-kV lines and related substation infrastructure — from Tri-County Electric Cooperative in 2016.

FERC last year accepted GridLiance’s ATRR for the facilities. (See FERC Sets GridLiance’s Zonal Placement for Hearing.)

Commission Approves Westar’s Settlement Offer

The commission also approved Westar Energy’s contested settlement offer updating loss factors in its tariff (ER18-1418).

The Kansas utility, now operating as Evergy Kansas Central after a merger with Kansas City Power & Light, was seeking to raise its loss factors from 3.07% to 3.47% based on a study it performed using data and load-flow models from 2016 supplied by SPP. That figure was a result of a 2013 settlement that locked it in for five years, with an updated study to be filed every succeeding five-year period.

FERC accepted the proposed revisions in June 2018 and established hearing and settlement judge procedures. Several Kansas utilities intervened and filed comments or protests in the proceeding, including Nemaha-Marshall Electric Cooperative Association. (See FERC Sets Westar Loss Factors for Settlement.)

Nemaha-Marshall argued the settlement was unjust and unreasonable because it removed all references to “composite loss factors” from the relevant section of Westar’s tariff. The co-op said the composite loss factors are used in several other agreements and are necessary to protect customers from paying Westar transmission losses that it does not incur and that are already being recovered under other tariffs.

FERC found Nemaha-Marshall’s contention “unpersuasive,” saying it did not raise issues of material fact concerning the loss factors’ just and reasonableness. It said language in Westar’s network integration transmission service agreements still prohibits Westar from recovering transmission losses.

“Nothing in the settlement allows for Westar to collect transmission losses already recovered under the SPP Tariff,” the commission said.

FERC directed the utility to file the revised tariff provisions within 30 days.

October 20, 2019

NYISO Business Issues Committee Briefs: Oct. 16, 2019

The NYISO Business Issues Committee last week voted to recommend that the Management Committee and Board of Directors approve a cost-containment mechanism for the ISO’s public policy transmission planning process that features voluntary cost caps in developer proposals.

NYISO Senior Manager for Transmission Planning Yachi Lin joined Assistant General Counsel Carl Patka in presenting the case to make a filing with FERC over the cost-containment provisions.

Under the proposed rules, transmission developers could propose either a hard or soft cap for capital costs. The hard cap would represent the amount over which the developer agrees not to recover capital costs from ratepayers, while the soft cap will be defined as an amount above which shareholders and ratepayers share excess costs, based on a defined percentage, with the developer’s share at least 20%.

“It’s up to developers to propose what risk percentage of the capital costs they want to bear,” Lin said.

NYISO — One scenario of 2030 public policy transmission needs from the New York City mayor’s office. | *New York City Mayor’s Office*

Developers would be able to use the procedures in proposing projects as solutions to any public policy transmission need (PPTN) identified by the New York Public Service Commission.

“No doubt this is going to be a huge issue with the [Climate Leadership and Community Protection Act], for which transmission will need to be built,” said BIC Chair Aaron Breidenbaugh, who represents Consumer Power Advocates.

A stakeholder who wished not to be identified asked what the ISO would do in cases in which the developer is also the transmission owner, and a delay by the TO is in the list of excusable conditions for exceeding the cap.

Patka said he did not want to go into debate on the issue, and that “it would all come out in the wash at FERC … but we will make it clear that we’re talking about actions that are not controllable by the developer themselves.”

A developer that proposes a solution may voluntarily provide a capped amount for defined categories of capital costs and may only rely on the permitted excusing conditions to recover costs over those amounts.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said the group has “long felt that the Tariff had a gaping hole when it comes to cost containment … while this measure may not be perfect, it does advance the ball.”

The New York State Energy Research and Development Authority and NextEra Energy echoed that support.

Couch White attorney Devlyn Tedesco, who represents New York City, commented that the city does not support the proposal because of a concern that it may not provide full cost containment and may not adequately protect consumers for the duration of the useful lives of the projects.

Patka said, “We added language to the Tariff expressly at the request of end users that the cost-containment mechanism must achieve ratepayer protection at least as effective as that proposed by the developer [OATT 6.10.6.3].”

Jane Quin, director of the energy markets policy group for Consolidated Edison, said her utility and Orange and Rockland Utilities appreciated the work and supported the concept, but that they would be abstaining because the changes also include changes to the ISO evaluation processes, with no provision in the case where the TO upgrades its own facilities.

Patka committed to address cost containment for upgrades as soon as the ISO begins to address the treatment of rights to build and own such upgrades in its PPTN planning.

The FERC filing is slated for December if the plan is approved by the MC on Oct. 30 and by the board next month.

“If approved by FERC, the measures would be effective in time for the public policy transmission solicitations that will start to be prepared early in the year,” Patka said. “We’re basically running out of time in our current public policy planning process.”

Enhancing Credit Requirements

The BIC also voted to recommend the MC and board approve changes to enhance credit reporting requirements and remedies.

Sheri Prevratil, manager of corporate credit, presented the proposed changes, including Tariff revisions that would require FERC approval.

The changes were prompted after certain market participants last year defaulted on their payment or credit obligations to NYISO. Some of those parties filed for Chapter 11 bankruptcy, while others were expelled from the ISO.

The proposed Tariff changes would increase minimum participation criteria, requiring a market participant to certify it has appropriate experience and resources to satisfy obligations as they become due. The changes would also clarify what investigations need to report, if legally permitted, and add an obligation to disclose information on nonpublic investigations when possible.

A new provision would allow NYISO to reject a new applicant determined to be an unreasonable credit risk based on a credit questionnaire and other review. The ISO would request additional information from new applicants upon registration and from existing market participants on an annual basis, with a new credit questionnaire to be included in the officer certification form due by April 30 each year.

LBMPs down 43%

NYISO locational-based marginal prices averaged $22.22/MWh in September, down about 20% from August and more than 43% from the same month a year ago, Principal Economist Nicole Bouchez said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $33.88/MWh, a 26% decrease from a year ago.

Day-ahead and real-time load-weighted LBMPs came in lower compared to August. Average daily sendout was 419 GWh/day in September, down from 487 GWh/day in August and 458 GWh/day a year earlier. Transco Z6 hub natural gas prices averaged $1.78/MMBtu for the month, down slightly from August and 35.4% from a year ago.

Distillate prices were down 14.3% year over year and up slightly from the previous month, with Jet Kerosene Gulf Coast averaging $13.86/MMBtu, compared to $13.32 in August, while Ultra-low Sulfur No. 2 Diesel NY Harbor climbed to $13.79 from $13.02 in August.

September uplift increased to -13 cents/MWh from -20 cents in August, while total uplift costs, including the ISO’s cost of operations, came in lower than the previous month.

The ISO’s 17-cent/MWh local reliability share in September was down from 25 cents the previous month, while the statewide share climbed to -30 cents/MWh from -45 cents.

The Thunderstorm Alert cost was 43 cents/MWh.

— Michael Kuser

October 20, 2019

NYPSC Projects Lower Winter Energy Prices

By Michael Kuser

The New York Public Service Commission last week said it expects winter electricity prices will be slightly lower than a year ago, based on a declining price trend and normal weather forecast (19-M-0382).

“We anticipate energy consumers will benefit from lower-than-average energy prices this winter, which is welcome news for all of us,” PSC Chair John B. Rhodes said Thursday.

The commission’s Winter Preparedness Report forecasts a similar trend for natural gas, based on a normal weather forecast, but it noted that Enbridge, owner of the Texas Eastern and Algonquin Pipelines, told utilities it would reduce pressure at times this winter on both pipelines.

Resulting capacity reductions would impact deliveries into the Goethals station in Staten Island and the South Manhattan Gate station in Manhattan, requiring measures to offset the loss, the PSC said.

NYPSC — Statewide weighed average full service residential supply price – winter months (cents/kWh) | *NYISO*

Rhodes on Oct. 11 signed an order forcing National Grid subsidiaries Brooklyn Union Gas and KeySpan Gas East to connect 1,100 of 3,300 customers that had been denied natural gas service connections (19-G-0678).

“We will continue to closely monitor the utilities serving New York state to make sure they have adequate sources and supplies of electricity and natural gas to meet current customer demands this winter,” Rhodes said.

The commission reported sufficient capability to meet electric demand this winter, saying owners of major generators in southeast New York continue “to implement lessons learned from the polar vortex winter of 2013-2014, including having increased pre-winter on-site fuel reserves, having firm contracts with fuel oil suppliers, conducting more aggressive replenishment plans, and having more proactive pre-winter maintenance and facilities preparations.”

Largest Storage Project in New York

The PSC also approved construction of what will be New York’s largest battery storage facility, the 316-MW Ravenswood facility to be built on the Ravenswood Generating Station property in Long Island City, Queens (19-E-0122).

“When complete, this facility will displace energy produced from fossil plants during peak periods, resulting in cleaner air and reduced carbon emissions,” Rhodes said.

The storage facility will displace some out-of-service peaker units on the property and should be partially operational by March 2021, the commission said. It will provide peak capacity, energy and ancillary services; offset more carbon-intensive peak generation with power stored during the off-peak period; and enhance grid reliability in New York City.

Expanding Value Stack Eligibility

The commission also expanded the eligibility of New York Power Authority customers located within Consolidated Edison’s service territory for excess electricity generated by eligible distributed energy resources projects (19-E-0464).

According to NYPA, expanding value stack eligibility to its customers in Con Ed territory will open up DER market potential and help the state meet its goal of installing 6,000 MW of distributed solar by 2025. DER developers will have additional incentive to develop renewable projects in New York City, with many NYPA customers already having committed to develop renewable projects.

New Cybersecurity Rules

The commission also adopted new cybersecurity and data privacy requirements for third-party companies that electronically receive and exchange utility customer data with the utilities’ information technology systems (18-M-0376).

The new requirements provide a foundation of protections to ensure the privacy of customer data and protect utility IT systems, while at the same time enabling data access, the PSC said.

October 20, 2019

PG&E Says Blackouts Will Continue

By Hudson Sangree

PG&E Corp. officials told California regulators last week that its public safety power shutoffs (PSPS) could continue for another decade, and that it was making plans to turn off electricity to all its 5.4 million customers should circumstances warrant it.

“The likelihood of an event of this scale occurring is extremely low; however, in an abundance of caution, by next wildfire season, PG&E is looking into additional hardware and capacity to accommodate an outage at this scale,” the utility said in its written response to the California Public Utilities Commission’s request for information about its shutoff policies.

PG&E public safety power shutoffs — PG&E CEO Bill Johnson | *PG&E*

The CPUC called an emergency meeting Friday at which Bill Johnson, the company’s recently installed CEO, and Nora Mead Brownell, its new chair of its board of directors, addressed commissioners.

Johnson, former head of the Tennessee Valley Authority, defended PG&E’s decision to black out 738,000 customers, or about 2 million Californians, as an effective tool that prevented wildfires during dry, windy conditions from Oct. 9 to 12. The devastating North Bay fires of October 2017, for which PG&E bore most of the blame, occurred in similar circumstances, he noted. So did November’s Camp Fire, the deadliest and most destructive wildfire in state history.

“I feel my highest accountability is safety,” Johnson said.

PSPSes could continue until 2030 as the utility tries to harden its grid against trees and branches blowing into power lines, the chief executive said. The shutoffs will likely narrow, although the risk of catastrophic wildfires from climate change will increase, he said.

PG&E Blackouts — CPUC President Marybel Batjer | *CPUC*

“I think they’ll decrease in size and scope every year, but at the same time we’re doing this, the risk is not static,” Johnson said. “It’s dynamic, and it goes up every year.”

CPUC President Marybel Batjer asked Johnson about a letter he sent Friday to Gov. Gavin Newsom suggesting a government agency, such as the CPUC or the California Department of Forestry and Fire Protection, should call for PSPS, instead of utilities, to promote public trust.

Johnson said he wasn’t trying to shirk PG&E’s responsibility. But the public is skeptical of the troubled utility’s intentions, and “public confidence in the decision [to institute a PSPS] is really important,” he said.

Johnson, Brownell Questioned

Commissioner Genevieve Shiroma asked Brownell — a former FERC commissioner, Pennsylvania regulator and president of the National Association of Regulatory Utility Commissioners — what advice she would give her and her colleagues about dealing with PG&E if she were in their place.

“As someone who has sat in our chairs and held utilities accountable, what specific advice — or specific laser-like things, if you were sitting here — [would you] be telling PG&E to effectuate in the aftermath of these PSPSes?” Shiroma asked.

Brownell said she would require PG&E to meet measurable performance goals, though she did not offer specifics.

“Thanks for the question, and I wouldn’t presume to tell you how to do your jobs,” Brownell said. “But I think the letters [exchanged] this week [between the CPUC and PG&E] and the ongoing focus on very specific outcome-based measures is very, very, very important.

“I think it’s one thing to talk platitudes. It’s another to actually measure people by the outcomes that you talked about,” she said. “And in fact, at NARUC, at FERC, even when I was a Pennsylvania state commissioner, we talked a lot about moving from that rate-based model to a business model that was more performance-based.”

Batjer repeated her assertions that PG&E had failed woefully in executing its massive power shutoffs, including by failing to prevent its website from crashing and by allowing its call center to become overwhelmed with customers demanding information. (See related story, CPUC Orders Changes to PG&E Shutoff Rules.)

“You guys failed on so many levels on fairly simple stuff,” Batjer said.

CPUC Commissioner Genevieve Shiroma | *CPUC*

Johnson admitted as much. “Making the right decision on safety isn’t the same as executing this decision well,” he said, vowing to improve.

Commissioner Martha Guzman Aceves noted that neither Brownell nor Johnson were Californians, nor were other PG&E board members appointed earlier this year after the company, facing $30 billion in fire debts, declared bankruptcy. (See PG&E Names New CEO, Board Members.)

“Being connected to the communities that are being disconnected” is inherently valuable, Guzman Aceves said. “This seems to me like something that I would really see value in … a board that really reflected California, that reflected in terms of the communities that are impacted and certainly that reflected the demographics of California.”

She asked whether Brownell was living in the state. Brownell said she had been staying with relatives before renting an apartment.

Guzman Aceves also questioned another executive new to California — Andrew Vesey, the CEO of Pacific Gas and Electric — about whether he was familiar with two small Northern California communities affected by the outages. Vesey, whose last job was in Australia, said he wasn’t.

“Is the board demographics and [its] experience and knowledge of California” reasonable and adequate? Guzman Aceves asked.

Johnson replied, “I think it’s really important to have a board that reflects the constituency, the customer base, the state, and understands it. And I think eventually this board will get there.

“I think this board was assembled in unusual circumstances having to do with a bankruptcy and some other things,” he continued. “But as to your basic premise about how a board should look and should it be able to relate, particularly a utility board, to the utility customers, I agree with that.”

October 18, 2019

MISO, PJM Poised for 1st Major Interregional Project

By Amanda Durish Cook

CARMEL, Ind. — MISO and PJM are close to embarking on their first major interregional transmission project after years of coming up short in identifying a joint effort worthy of the designation.

The RTOs say they will support the $21.6 million reconstruction of the 138-kV Michigan City-Trail Creek-Bosserman line in the northwestern corner of Indiana, a that project that qualifies as an interregional market efficiency project (IMEP) on their seam, according to MISO Senior Manager of System Planning Jarred Miland.

The RTOs have approved two portfolios of smaller targeted market efficiency projects in 2017 and 2018, but they have never agreed to an IMEP project until now.

“Both us and PJM think this is a good project. We want to move this forward,” Miland told MISO stakeholders at an Planning Advisory Committee meeting Wednesday.

MISO PJM project — Michigan City-Trail Creek-Bosserman project map | *MISO*

PJM officials the following day said rebuilding the line was the best option and deemed the project its preferred solution after determining it passed a “reliability no-harm test.” The project will undergo a “second read” in November under PJM’s process.

Both RTOs say they plan to recommend the project to their respective boards later this year.

PJM customers stand to pay for the lion’s share of the line rebuild, with MISO being allocated just 10.85% — or about $2.4 million — of the full cost.

MISO expects the project to yield a 3.12:1 benefit-cost ratio, while PJM estimates a ratio of 2.63:1 based on its own calculations.

The project need was identified by MISO planners in this year’s Market Congestion Planning Study, part of the RTO’s annual Transmission Expansion Plan (MTEP) — the only such project to be recommended from the study. MISO said its congestion forecast this year was relatively low because of flattened demand and little price difference between generating units.

MISO board approval of the IMEP will likely be delayed until the RTO can get a cost allocation method in place for its market efficiency projects. MISO’s first cost allocation plan — which includes the IMEP cost allocation method — was stalled earlier this year when FERC raised concerns about cost causation. (See Key Details Change in MISO MEP Cost Allocation Plan.)

Miland said the project will be mentioned in the MTEP 19 report, but included in Appendix B — rather than Appendix A — of the report, which lists projects with a documented need not yet ready for construction, with costs not included in MTEP spending totals. MISO’s board plans to hold a separate vote to approve the IMEP after FERC approves MISO’s cost allocation filing.

While progress continues on MISO-PJM seams work, no projects have been recommended for the MISO-SPP seam. This year, planners emerged empty-handed after producing a coordinated system plan study, prompting more intense calls for process changes between the RTOs. (See MISO, SPP Empty-handed After 3rd Project Study.)