WASHINGTON — PJM’s conference to discuss its $12.5 million settlement with two financial transmission rights trading firms produced neither protest nor complaint from any of the many stakeholders who phoned in to listen Thursday.
Held in a sparsely filled hearing room at FERC headquarters, the RTO had scheduled two hours to take stakeholder questions about its settlement with Apogee Energy Trading and Boston Energy Trading and Marketing (BETM). Instead, the meeting lasted less than an hour, with a full 10 minutes taken up by stakeholders identifying themselves over the phone.
Under the settlement (ER18-2068), Apogee and BETM would receive $5 million and $7.5 million, respectively, to resolve the firms’ claims of economic harm that resulted from PJM’s decision to not liquidate GreenHat Energy’s entire FTR portfolio after the company’s 890 million MWh default. (See PJM to Pay $12.5M to Settle GreenHat Dispute.) The RTO would also establish another fund of up to $5 million for additional claimants.
The claims would be funded by members’ default allocation assessments. Apogee and BETM are also subject to the allocation, meaning they would receive their payments as credits on their assessment bills, said PJM Associate General Counsel Jen Tribulski, who led the meeting.
It was the additional fund, however, that drew the most questions from stakeholders.
Tribulski explained that if a member submits a claim and, based on PJM’s calculations, that member would have benefited had the RTO liquidated the rest of the GreenHat portfolio, then it would contribute half of its calculated benefits to the fund. Adrien Ford of Old Dominion Electric Cooperative asked if that meant the “pot” would increase over $5 million by that amount. Tribulski clarified that the fund would never exceed $5 million. Any benefiting members paying more than their default allocation assessments would simply lessen the share other members have to contribute.
Bruce Campbell, of demand-side management company CPower, asked what benefit the settlement provided to members like his, which don’t participate in the FTR market. “I don’t understand why I should be happy just as a member” about the settlement, he said.
Tribulski said that without the settlement, PJM had estimated that members would be assessed $40 million to $60 million. Had the case gone to litigation and PJM lost, the assessment could have been even larger, said Paul Flynn, an attorney with Wright & Talisman who represented the RTO in the settlement.
Comments on the settlement are due Oct. 29. If there are no comments opposing it, PJM has asked FERC to waive the 30-day reply comment period.
“I really do hope people think long and hard before filing negative comments on the settlement,” Tribulski said. “I don’t know how much better of a settlement we could have gotten or better of an outcome of this case we could have gotten. If we were to go to litigation, this will be a very long, protracted proceeding.”
FERC on Thursday denied a complaint from Public Citizen that alleged PJM failed to disclose nearly $500,000 in political spending it purportedly financed with membership fees collected from rates.
The consumer advocacy group asked the commission last year to force PJM to itemize all political-related spending after it accused the RTO of contributing $456,500 to both the Democratic and Republican governors associations since 2007 without telling stakeholders or FERC about it, as required by its own Operating Agreement and the Federal Power Act (EL18-61). (See Advocate Group Questions PJM Campaign Contributions.) The group also asked FERC to declare the RTO’s filed rate unjust and unreasonable.
PJM said the contributions support educational services and argued that its Finance Committee — composed of stakeholder representatives from all sectors — supplies adequate oversight of how the RTO spends rate revenues. It also described the complaint as a “collateral attack on the commission’s previous denial of Public Citizen’s protest in PJM’s stated rate proceeding.”
The commission rejected Public Citizen’s arguments that PJM should provide greater visibility into what portion of its expense budget is spent on “outside services” that may have included political advocacy.
“We find that the oversight and review functions PJM has established through its Finance Committee provide sufficient transparency and review of these expenditures,” FERC wrote. “Therefore, we find that Public Citizen has not demonstrated that additional transparency measures, beyond those which already exist, are needed.”
The order also reiterates that RTOs are allowed to recover costs related to informational and educational efforts.
“These fees allow PJM to educate and inform state government officials about issues related to the wholesale markets and bulk power system at policy conferences and forums,” FERC wrote. “Participation in these meetings is directly related to the RTO’s educational function and undertaken in the collective best interest of PJM’s members.”
Susan Buehler, a PJM spokesperson, said the organization is pleased with FERC’s ruling.
“PJM has acted in accordance with all applicable laws and regulations, and participated in legitimate activities in the interests of our stakeholder,” she said in an email Friday. “PJM operates as a profit-neutral organization for which educating and informing elected officials, key stakeholders and government agencies are essential to our FERC-defined functions. PJM is committed to transparency throughout our organization and will continue to be so as required by our Tariff.”
Tyson Slocum, director of Public Citizen’s energy program, told RTO Insider that his group will file a rehearing request within the next 30 days.
“This is a really radical decision,” he said. “It underscores that FERC isn’t actually interested in doing its job of being a regulator and that RTOs are not closely monitored and are self-regulated entities.”
Slocum said PJM’s Finance Committee is composed of volunteer stakeholders — some of whom spoke to the organization off the record, he said — who don’t have the time or resources to effectively manage the RTO’s $300 million operating budget. Further, PJM bars nonmembers from attending the committee’s meetings.
“Relying on volunteer stakeholders to monitor your finances and budget might be appropriate for your local PTA, but it’s wildly inappropriate for a $300 million organization funded with public money,” Slocum said.
“When elected officials and their electoral counterparts charge entities or individuals for preferential access, and FERC literally endorses pay-to-play political advocacy — that’s an outrage,” he said.
At FERC’s open meeting Thursday, Commissioner Richard Glick said that though he had voted to deny the complaint, “I do think it would make some sense for PJM, and other RTOs as well, to provide stakeholders with more information about their political activities, whether it be their political contributions or their lobbying activities. And even though I don’t think necessarily it’s required under the [Federal Power Act], I would urge PJM but also urge all the other RTOs to be more transparent in terms of these activities.”
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.
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.
Historic coincident peaks | ISO-NE
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.
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.
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 Bidding 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?
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.)
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.
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.
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 $3.97 billion. The RTO will post the final MTEP 19 project list Nov. 6.
MTEP19 investment by facility type ($ 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.
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.
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.
Ameren Illinois linemen | Ameren
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.
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.
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.
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.
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.
NYISO monthly average internal LBMPs 2018-2019 | NYISO
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 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.
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).
The New York PSC approved a 316-MW storage facility to be built at the site of the Ravenswood Generating Station, on the East River in Long Island City, Queens.
“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.
