Pacific Gas and Electric has cleared another hurdle in its bid to exit bankruptcy, but the latest comes with a caveat: If the company can’t win court approval of its Chapter 11 reorganization plan by June 30, the state or a third-party bidder could buy the utility under a fast-track process outlined Friday.
The sale process will “be implemented in the unlikely event the debtors fail to meet certain dates regarding the administration of these Chapter 11 cases,” PG&E said in a motion filed with the U.S. Bankruptcy Court in San Francisco, seeking rapid approval of its “case resolution contingency process.”
Gov. Gavin Newsom has been an outspoken critic of PG&E.
The plan is part of a deal the company struck last week with Gov. Gavin Newsom, under which Newsom dropped his objections to PG&E’s bankruptcy proposal in exchange for a series of concessions.
In addition to agreeing to sell itself, PG&E said that it would allow a state-appointed observer to monitor its safety operations until it exits bankruptcy and that it would refrain from paying shareholder dividends over the next three years.
On March 13, the state’s largest utility largely agreed to greater oversight by the California Public Utilities Commission and a process of escalating enforcement that could result in PG&E losing its electric monopoly — its certificate of public convenience and necessity — in extreme circumstances. (See CPUC President Wants More Control over PG&E.)
Newsom’s opposition to PG&E’s plan to issue billions of dollars in new debt and equity appeared to be one of the last major obstacles to PG&E leaving bankruptcy by June 30. That is the deadline for PG&E to participate in a state wildfire insurance fund created by Assembly Bill 1054, a measure Newsom pushed through the legislature last July.
Wildfire victims and other stakeholders must still vote on PG&E’s bankruptcy plan, and the CPUC must approve it under an investigation it opened in September.
PG&E filed for bankruptcy protection in January 2019 after a series of devastating wildfires in 2017 and 2018 saddled it with billions of dollars in liabilities to those who lost family members, homes and businesses.
PG&E, headquartered in San Francisco, was incorporated 115 years ago.
Its stock plummeted from more than $46/share in October 2018 to $7.23/share immediately after it filed for bankruptcy. PG&E’s share price has been on a roller coaster since, and the stock market meltdown caused by the COVID-19 coronavirus outbreak sent its stock from $17.92/share on Feb. 21 back to $7.22/share on Friday.
Amid the uncertainty about its financial future, the utility is eager to resolve Newsom’s concerns as quickly as possible. In its court papers filed Friday, PG&E urged federal Judge Dennis Montali to hear and approve its agreement with Newsom on April 1.
“Approval of the case resolution contingency process will facilitate the debtors’ ability to timely exit these Chapter 11 cases, provide a positive signal to the financing markets and further solidify support for the plan and the likelihood of a smooth and largely consensual resolution of these Chapter 11 cases,” the utility’s lawyers said.
Montali, however, disagreed that the matter was as urgent as PG&E contended. In an order signed Friday, he set April 7 as the hearing date.
“The relief requested … does not appear to require imminent action by the debtors, the CPUC, the governor’s office or others,” the judge wrote. “[N]othing suggests that the governor’s office insisted on court approval as quickly as debtors request.”
The hearing will be conducted by telephone because the federal courthouse in San Francisco is closed due to the virus, Montali noted. The health crisis justifies giving opponents additional time to file briefs and not to rush things at PG&E’s insistence, he said.
“The world-wide coronavirus pandemic is reason enough [to] make sure there is sufficient cause to act so quickly,” the judge said.
PJM’s expanded minimum offer price rule (MOPR) won’t hinder renewables as much as some had feared if the RTO’s interpretation of FERC’s Dec. 19 order is accepted by the commission, according to solar and wind trade groups and a new analysis by the Independent Market Monitor.
The Monitor released an analysis Friday that concluded that expanding the MOPR will not have an impact on clearing prices or auction revenues for the next Base Residual Auction, for delivery year 2022/23. That came after the American Wind Energy Association (AWEA) and the Solar Energy Industries Association issued upbeat reviews of PJM’s compliance filing Wednesday. (See PJM Makes MOPR Compliance Filing.)
FERC ordered PJM to expand the MOPR to all new state-subsidized resources, including nuclear plants and renewables. AWEA was among numerous critics of the ruling, saying it “threatens states’ rights and hinders their ability to bring more clean energy to their communities.” The Sierra Club called it “disastrous,” saying it will “essentially exclude new renewable energy resources from the PJM capacity market.”
But AWEA and the Solar Energy Industries Association said last week that PJM’s interpretation of the order would allow new renewable generation to clear the capacity market in the short term.
PJM’s conclusion that voluntary renewable energy credits (RECs) are not state subsidies and its decision to allow an asset life of up to 35 years means that new wind and solar projects will be able to bid below the default MOPR floor values and clear the market, officials for the organizations said.
“PJM’s submission will allow renewable generators to properly identify a project-specific bid price for bidding into the capacity market auctions,” said Katherine Gensler, vice president of regulatory affairs for SEIA. “This process provides renewable generators a better opportunity to compete on a level playing field with other capacity providers and to help meet states’ clean energy goals.”
“PJM’s proposal provides the flexibility necessary for renewable resources to demonstrate that they are among the lowest cost and most reliable sources of capacity available today,” said Amy Farrell, AWEA’s senior vice president of government and public affairs.
AWEA said that while PJM’s compliance filing offers renewables short-term relief, the wind industry will be seeking long-term changes to the RTO’s resource adequacy construct to ensure renewables’ future.
IMM Analysis
The Monitor’s analysis concluded that the new MOPR rules won’t impact prices in the next BRA in part because they don’t significantly change the treatment of gas-fired resources and they allow categorical exemptions for existing self- supply, demand response, energy efficiency and storage resources. It also cited the “competitiveness of unit specific offers for existing subsidized nuclear resources.”
The Monitor said “although preliminary estimates of the default MOPR floor prices for new renewables are relatively high, those estimates are based on existing renewable facilities in PJM and based on standard assumptions about technologies, financing costs, capacity factors and revenues. Renewables suppliers assert convincingly that many new renewables are competitive now and will demonstrate that fact through requests for unit specific exceptions to default MOPR floor prices. Renewables suppliers also assert that they will become even more competitive in the future and for the 2024/2025 RPM BRA.”
Lazard’s current levelized cost of energy analysis estimates utility scale solar PV at $32-$42/MWh and onshore wind at $28-$54/MWh — well below nuclear ($118-$192/MWh), coal ($66-152/MWh) and gas peakers ($150-$199/MWh) and competitive with combined cycle plants ($44-$68/MWh).
In the last decade, the levelized cost of energy (LCOE) for utility-scale solar has dropped by 89% and the LCOE for onshore wind has declined by 70%. | Lazard
The Monitor’s analysis included a base case with current MOPR rules, offers from the 2021/22 Base Residual Auction and an adjusted supply curve to account for retirements, must-offer exceptions, projected new supply and updated offer caps for the 2022/23 delivery year. The demand curve was updated using the 2022/23 planning parameters.
The impact analysis applied the new MOPR rules to the base case supply and made no changes to fixed resource requirement (FRR) elections. The Monitor said its report did not include detailed locational deliverability area (LDA) prices or cleared quantities for confidentiality reasons.
Errors in Glick Analysis?
The Monitor contrasted its conclusions with analyses by Commissioner Richard Glick and consulting firm Grid Strategies, both of which predicted an expanded MOPR would add billions in annual capacity costs. “Neither are based on supportable, detailed analysis of the capacity market,” the Monitor said.
Glick dissented on the December order, calling it an attack on decarbonization efforts and warning it could increase PJM capacity costs by at least $2.4 billion annually. Glick’s “back of the envelope” estimate was cited in rehearing requests by Maryland, New Jersey, public power groups and environmental advocates.
The Monitor said Glick’s calculation is based on an incorrect assumption on the total capacity of previously cleared nuclear power plants that receive zero-emissions credits in Illinois and New Jersey (4,837 MW, not 6,670 MW). The monitor said Glick also incorrectly assumed the order would cut cleared demand resources by 25% when the order allowed a categorical exemption for existing demand resources.
The Monitor said Glick also erred in his assumptions about the slope of the demand curve and failed to adjust a baseline of 2021/22 BRA prices for changes to the supply and demand side.
“We are aware of the Bowring report and we are reviewing it,” Glick said via email. “I can’t say more because this remains a pending proceeding and the issue is likely to be part of my consideration of the rehearing requests.”
Grid Strategies Report
The Monitor also challenged Grid Strategies’ report last August that concluded an expanded MOPR could increase capacity market prices by $5.7 billion annually, a 60% increase. Grid Strategies President Rob Gramlich repeated that estimate in testimony before the Illinois legislature earlier this month. (See MOPR Impact Study Ruffles Feathers Ahead of FERC Ruling.)
The Grid Strategies report drew “broad and incorrect conclusions [due] to a conflation of the IMM’s analysis of the PJM extended resource carve out proposal (RCO) with all proposals to modify PJM capacity market rules,” the Monitor said.
Gramlich said the Monitor’s study cannot be verified because its “data, methods and assumptions are covered in six sentences of words with no numbers.” The Monitor said details of its report cannot be published because it is based on confidential data.
Gramlich agreed that “if all of PJM’s rehearing and compliance proposals are accepted by FERC, and the unit-specific process turns out favorably for clean resources, then that version of broad MOPR will likely be less costly initially than some of last year’s versions. Of course, those are some big ‘ifs.’ And it won’t change the fact that broad MOPR gets costly soon and fails the `over-mitigation’ test since it is not tied to any identified market power.
“While the immediate impacts may be muted, the longer-term harm exists, and states are likely to pick up consideration of alternative options when they are able to resume policy making,” he said. (See related story, Study: Retail Design Key to Escaping Capacity Markets.)
Mike Hogan, a senior advisor with the Regulatory Assistance Project, said the Monitor’s report “conspicuously addresses only the impending auction, when it was clear that, due to FERC’s shrewd grandfathering of the small share of existing renewable resources, the significant economic impact would grow increasingly over subsequent auctions.”
Hogan, who collaborated with Gramlich on a June 2019 report on market designs for decarbonization, said the Monitor has “for years publicly maintained a doctrinaire and widely discredited insistence that scarcity pricing offers in the energy market should be presumed to be an abuse of market power to be suppressed unless proven otherwise, which leaves them with no option but to defend the [Reliability Pricing Model] as a way of maintaining resource adequacy. This despite the fact that while the Market Monitor has consistently found the energy market to be workably competitive, they have just as often found the RPM to have market power issues.”
IMM Joe Bowring denied that he has opposed scarcity pricing. “The IMM has been and continues to be supportive of scarcity pricing as an essential element of wholesale power markets as documented in multiple FERC filings and in the State of the Market Reports,” he said.
“The IMM supported a different approach to the definition of competitive offers which was rejected by FERC in the MOPR order. The IMM has also published a report pointing out that the [fixed resource requirement] option referenced by Grid Strategies is likely to cost state consumers substantially more than remaining in the PJM capacity market.”
Market Power Allegation
The Monitor said its conclusion that MOPR won’t affect prices in the next auction does “not mean that the IMM expects that prices in the 2022/23 BRA will be unchanged from the 2021/22 BRA,” noting its previous conclusion that market power was exercised in the 2021/22 auction. (See IMM: PJM 2018 Capacity Auction was ‘Not Competitive.’)
The Monitor filed a complaint with FERC last year alleging PJM consumers will be overcharged by $1.2 billion for 2021/22 because PJM’s market seller offer cap is too high (EL19-47). “Those overpayments would be eliminated if the commission modifies the market seller offer cap as requested,” it said. PJM has disputed the Monitor’s conclusions and sought to have its complaint dismissed. (See Monitor Defends Offer Cap Complaint.)
Will PJM’s Interpretation Stand?
How renewables ultimately fare will depend in part on whether the commission accepts PJM’s interpretation of the order.
The commission said that privately funded voluntary RECs cannot be distinguished from those issued under state-mandated or state-sponsored procurements.
But PJM said owners of renewable generation that generate RECs would qualify for the competitive exemption if they certify that the credits “will only be used and retired for voluntary obligations as opposed to state-mandated renewable portfolio standards.” The RTO said it will modify its Generation Attribute Tracing System (GATS) to “to ensure that any capacity market sellers’ self-imposed limitations on use of the RECs can be effectuated.”
In their joint rehearing filing in January, the Environmental Defense Fund, Natural Resources Defense Council, Sierra Club, Sustainable FERC Project and Union of Concerned Scientists contended the unit-specific review will not prevent over-mitigation and excessive prices.
They cited the nominal levelization of gross costs, an assumed asset life of 20 years, exclusion of sunk costs and assumptions based on the economic incentives of gas units, and said the rules fail to reflect the low incremental avoidable costs of renewable resources. “Far from providing a safety valve, unit specific review is of a piece with the order’s blanket exclusion of state-supported renewable resources from the capacity market,” they said.
In its compliance filing, PJM said it would allow capacity market sellers to submit resource-specific justifications of an asset life other than the default 20-year assumption. It said it would cap the permissible term at 35 years, identical to the asset life assumption used in the Avoidable Cost Rate (ACR) for existing resources.
Representatives of the environmental groups said this week that PJM’s filing did not resolve their concerns.
“While some renewable energy projects may be able to clear using resource-specific offer floors, that’s only if developers can convince the Market Monitor that they are competitive on terms that FERC allows. And critical resources like offshore wind are almost certainly priced out,” said Casey Roberts, senior attorney in the Sierra Club’s Environmental Law Program.
“This conflict is not resolved if — in the near term — some renewable projects qualify with unit-specific costs,” agreed UCS’s Mike Jacobs.
“PJM embraces the conflict with state policies and has not addressed the problem of environmental externalities,” he added. “The two sides (policy vs markets) haven’t agreed on the terms of this debate. PJM and market adherents point to the cost of distorted investment signals, while policy proponents are watching for the costs of air quality and climate.”
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committee meetings on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:45-9:50)
Members will be asked to approve the following manual changes:
D. Manual 14A: New Services Request Process, Manual 14E: Upgrade and Transmission Interconnection Requests and Manual 14G: Generation Interconnection Requests. Incorporating changes related to FERC Order 845 on generator interconnection procedures and agreements.
PJM will seek approval of a compromise proposal to eliminate the RTO’s opportunity cost calculator and make the Independent Market Monitor’s calculator the required tool for market sellers, effective June 1. The switch includes changes to Manual 15: Cost Development Guidelines to document the IMM calculator and provide for an annual review of the calculator to ensure compliance with the manual and Operating Agreement (OA). (See “PJM Seeks to Retire Opportunity Cost Calculator, Use IMM Tool,” PJM MRC/MC Briefs: Feb. 20, 2020.)
The MRC will be asked to approve OA and Tariff revisions endorsed by the Financial Risk Mitigation Senior Task Force (FRMSTF) to improve the RTO’s risk evaluations of market participants. At a daylong “page turn” of the proposed changes last month, some stakeholders complained that PJM was seeking excessive authority and that several of its proposed definitions were overly broad. (See PJM Stakeholders Debate Credit Rule Changes.)
Members Committee
Consent Agenda (1:05-1:10)
C. Members will be asked to approve changes to the fuel cost policy as proposed by the PJM Industrial Customer Coalition. The changes were approved by the MRC last month on a sector-weighted vote of 3.57 (71%) despite concerns that new safe harbor provisions would create loopholes permitting the exercise of market power. The new rules are spelled out in revisions to Schedule 2 of the OA and Manual 15: Cost Development Guidelines. (See PJM MRC OKs Revised Fuel-cost Policy.)
A. Members will be asked to elect a new End Use Customer sector representative on the 2019-2020 Finance Committee to replace Mike Peters of Messer LLC, whose term expires in 2020.
B. The committee will be asked to approve on first read a waiver of the Manual 34 requirement that elections of board members be by secret ballot. The waiver is needed to allow use of the PJM Voting Application “due to potential exigent circumstances.”
FERC on Thursday denied what might be a final bid to recalibrate the results of MISO’s 2015/16 capacity auction, blocking Public Citizen’s request for rehearing over the highest capacity prices ever seen in the footprint.
MISO’s 2015/16 Planning Resource Auction has lived on in legal proceedings for more than five years. FERC last year wrapped up a three-year investigation into the PRA when it ruled the RTO’s Zone 4 $150/MW-day clearing price just and reasonable, declining to set up an evidentiary hearing. It also found that Dynegy had not manipulated the market to produce the high prices in southern Illinois. (See FERC Clears MISO 2015/16 Auction Results.)
2015/16 MISO PRA results | MISO
The commission said a clearing price isn’t unjust simply because it’s higher than expected. However, the decision remains unsubstantiated because FERC didn’t make any evidence from the investigation public when it abruptly ended the probe.
Soon after the ruling, Public Citizen claimed FERC wrongfully dismissed complaints alleging Dynegy manipulated pricing in the auction, violating the Administrative Procedure Act for not providing explanation or summarizing evidence and abandoning its just and reasonable ratemaking responsibility under the Federal Power Act. (See Public Citizen Contests FERC Ruling on MISO Auction.)
The commission rebuffed those arguments in its March 19 order (EL15- 70), leading Commissioner Richard Glick to once again issue a dissent and separate statement over the transparency of FERC’s investigation.
FERC’s other two commissioners, Chairman Neil Chatterjee and Bernard McNamee, said they remained unpersuaded that results were underhanded because Dynegy’s bids were permitted under a “valid, market-based rate tariff” and the bids met criteria under the FERC-approved MISO Tariff at the time. They also said they have discretion in market manipulation investigations, though they again declined to reveal any specifics of the investigation into Dynegy and Zone 4 prices.
The commissioners said they were able to monitor Dynegy’s market-based rate through accurate quarterly reports, triennial market power updates and change-in-status updates. They also said they oversaw the market monitoring and mitigation rules in MISO’s Tariff.
Public Citizen had argued that just eight months after the auction, FERC found MISO’s 2015 market power provisions no longer just and reasonable and ordered MISO to reset its $155.79/MW-day maximum bid to about $25, while also directing the RTO to better gauge power exports. (See FERC Orders MISO to Change Auction Rules.) But the commission said those new policies were to be viewed on a going-forward basis.
Glick Hints at Unfinished Investigation
However, Glick said the order was another “sidestep” of the crux of the proceedings, failing to answer the question of whether the resulting prices were reasonable considering the allegations of market manipulation on Dynegy’s part.
“Rather than directly confronting that issue, the commission states that the relevant Tariff language was followed and that a non-public investigation was conducted and did not, in my colleagues’ view, uncover manipulative conduct. That enforcement proceeding, however, was terminated by the chairman without a vote by the commission and the details of that investigation remain confidential,” Glick wrote. “Accordingly, the commission has at no point provided Public Citizen with an adequate response to the concerns raised in its complaint or explained why, in light of those concerns, the auction results were just and reasonable.”
Glick added that following relevant tariffs does not create a “safe harbor” for market manipulation.
“I am not aware of any authority to support the proposition that a market participant can commit market manipulation with impunity so long as it does not violate the relevant tariff language,” Glick said. He also said that courts’ interpretations of the Securities Act of 1934 “have repeatedly recognized that a facially legal action can constitute manipulation when it is taken for an improper purpose.”
Glick also reiterated his displeasure that he was not consulted before Chairman Chatterjee closed the nonpublic investigation. He also hinted that there might have been evidence that Dynegy had committed wrongdoing.
“Had I been consulted, I would have argued against terminating the enforcement process. Because the details of the investigation remain non-public, I cannot explain why I believe that the chairman erred in terminating the enforcement process. Suffice it to say that I am confident that the evidence uncovered in that investigation was more-than-sufficient to press ahead,” he wrote.
Glick ended by echoing complaints that the commission’s decision “does not provide even the scantest reasoning to support its finding that the nearly 1,000% year-over-year increase in the MISO Zone 4 capacity price had nothing to do with market manipulation.
“Instead, all we have is the Commission’s unsubstantiated assurance that there is nothing to see here.”
FERC last week affirmed its 2018 ruling approving MISO’s current resource adequacy construct, rejecting multiple rehearing requests from critics of the decision.
Among those requesting rehearing were a collection of Midwest transmission-dependent utilities, a group of major capacity suppliers, Main Line Generation and MISO’s Independent Market Monitor.
The commission said most of those arguing for rehearing sought to make MISO’s RA construct more like the centralized capacity markets of Eastern RTOs/ISOs. But FERC noted that those designs ignore the fact that the RTO must defer to multiple state jurisdictions in its 13-state reach and that its RA design is meant to be complementary to states’ authority (ER18-462).
MISO Little Rock headquarters | MISO
The commission also pointed out that 90% of MISO’s load is served by vertically integrated load-serving entities that for the most part don’t use the RTO’s capacity auction to meet capacity requirements.
” … [U]nlike the centralized capacity constructs used in the Eastern RTOs/ISOs, MISO’s auction is not — and has never been — the primary mechanism for its LSEs to procure capacity,” the commission stressed.
Two years ago, MISO pre-emptively refiled its entire RA construct in response to a D.C. Circuit Court of Appeals ruling that FERC overstepped its “passive and reactive” role when it prescribed revisions to PJM’s minimum offer price rule. MISO was concerned the decision could impact some of the RA rules that had been guided by FERC’s recommendations.
In a pair of orders a few months later, FERC both vacated and reinstated MISO’s entire RA construct, ultimately leaving the RTO’s current capacity auction format — and past auction results — undisturbed. (See FERC Vacates, Upholds MISO Resource Adequacy Rules.)
Still No Sloped Demand Curve, MOPR, Forward Mechanism
MISO Independent Market Monitor David Patton used the RA refiling as an opportunity to ask FERC to order the RTO to employ a sloped demand curve in its capacity auction in order to produce more efficient pricing. (See MISO Monitor to FERC: Order Sloped Demand Curve.)
On rehearing, Patton again argued that a good RA design “will produce price signals sufficient to attract and retain the necessary amount of capacity” and that FERC itself made that issue paramount when accepting the sloped demand curves used in NYISO, PJM and ISO-NE’s capacity auctions.
But in last week’s ruling, FERC said MISO’s high percentage of vertically integrated utilities sets it apart it from NYISO, PJM and ISO-NE because MISO’s RA is not determined by its capacity auction prices alone. It said the RTO’s vertical demand curve is fine for now.
” … [W]e continue to find that MISO’s resource adequacy construct enables the MISO region to maintain sufficient resources to meet system-wide and locational reserve requirements,” the commission said, noting that last year’s Organization of MISO States-MISO RA survey indicates sufficient capacity supply through 2022.
The commission also rejected the capacity suppliers’ request that the RTO conduct the auction on a three-year forward basis for retail-choice areas in Illinois and Michigan. FERC found that both a prompt auction and a multi-year forward capacity auction can be reasonable, and the suppliers’ support of one design over the other wasn’t a justification to order MISO to change its auction timing. The commission also told the suppliers that MISO’s auction didn’t require a minimum offer price rule, again noting that vertically integrated utilities own about 90% of capacity in MISO.
The commission also rejected the suppliers’ argument that it’s discriminatory for the MISO capacity auction to be voluntary for buyers and mandatory for sellers who have uncommitted capacity. FERC said while it does have an obligation to ensure that “similarly situated market participants are not unduly discriminated against … it does not follow that market participants who are not similarly situated are unduly discriminated against simply because they are subject to different sets of rules.”
The transmission-dependent utilities argued that the RA construct should allow new capacity resources to obtain long-term financial hedges to shield against inter-zonal price separation in the auctions. FERC said such a provision fails to consider the capacity auction’s main purpose of ensuring reliability during peak days.
The commission said MISO’s local clearing requirements and capacity import and export limits are essential to zonal reliability and declined to order alterations so more resources could compete inter-zonally. The commission also left in place MISO’s zonal delivery charge, which the RTO uses to cover congestion between zones when an LSE that submits its own fixed resource adequacy plan taps resources in a lower-priced local resource zone to serve demand in a higher-priced zone. The commission disagreed that the zonal delivery charge is a form of rate pancaking, pointing out that the charge is meant to cover auction price separation between the LSE’s location and its load, not transmission service. Capacity prices should reflect the “locational cost of capacity,” FERC said.
MISO’s RA construct “appropriately balances the competing goals of maximizing competition and ensuring reliability by allowing LSEs to serve their load with remote resources but having them bear the risk of auction price separation if there are impediments to the deliverability of such resources,” FERC said.
New England stakeholders on Tuesday pushed back on ISO-NE’s draft assumptions showing that several variable changes between Forward Capacity Auctions 14 and 15 will improve system fuel security.
ISO-NE Manager of Outage Coordination Norm Sproehnle presented the New England Power Pool Reliability Committee with assumptions based on the RTO’s capacity, energy, loads and transmission (CELT) forecast and consistent with Planning Procedure 10 (PP-10) Appendix I.
The assumptions show FCA 15 will see increases in gas pipeline capacity, total PV, onshore and offshore wind nameplate and demand response, coupled with lower peak load, lower winter LDC natural gas demand forecast and lower equivalent forced outage rate demand (EFORd).
Utilization of gas supply vs LDC demand in New England. | ISO-NE
Chris Hamlen, the RTO’s assistant general counsel for markets, clarified “that the fuel security retention rules are in place only through FCA 15, and so beyond FCA 15 there is no mechanism in place for performing this type of review.”
Further, the RTO indicated that, in response to stakeholder concerns raised during the meeting, it would consider whether it is possible to adjust some of the assumptions in the retention analysis performed for FCA 15 to better reflect the way in which the impact analysis was performed for ESI.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings; those quoted in this article approved their remarks afterward to clarify their presentations.]
The committee will review FCA 15 fuel security inputs and results in April and May and vote on the proposed PP10-I revisions in May, if applicable. If necessary, NEPOOL’s Participants Committee will vote on the revisions in June.
The RTO also is preparing for fuel security reliability reviews of FCM retirement de-list bids, substitution auction demand bids, bilateral transactions and reconfiguration auction demand bids submitted in connection with FCA 15.
FCA-14 Auction Results
Ryan Hoskin, ISO-NE senior analyst for transmission services and resource qualification, presented results of FCA-14, which was held in the first week of February.
The RTO’s 2020 capacity auction cleared at a record low of $2/kW-month, a nearly 50% drop from $3.80/kW-month in 2019. (See ISO-NE Capacity Prices Hit Record Low.)
Results of New England’s FCA 14. | ISO-NE
ISO-NE filed the auction results with FERC on Feb. 18 (ER20-1025) and posted its capacity supply obligations (CSO) spreadsheet on its website. No capacity supply obligations were traded this year under the substitution auction.
FCA 15 Capacity Zones OK’d
The RC also voted to recommend that ISO-NE identify the zonal boundaries to be used in modeling criteria for FCA 15 — unchanged from FCA 14 — in accordance with Tariff rules.
Al McBride, the RTO’s director of transmission strategy and services, reviewed the proposed capacity zone construct for FCA 15, as well as the interface transfer capabilities and external interfaces.
For FCA 15, the RTO will evaluate potential export-constrained zones, including Northern New England (NNE), which includes Vermont, New Hampshire and Maine, and a portion of Maine nested within NNE.
Potential import-constrained zones to be evaluated include Southern New England (SENE), which includes Northeast Massachusetts/Boston (NEMA), and Southeast Massachusetts/Rhode Island (SEMA/RI), and Connecticut.
The RTO will test the potential capacity zone boundaries and present the results at the May 2020 Power Supply Planning Committee, McBride said.
Zones that trigger the objective criteria indicating constraints will be modeled in FCA 15 and associated reconfiguration auctions, which will determine whether any of the modeled zones bind in the auction and experience price separation, he said.
Regarding internal interface transfer capability, the study noted increases associated with various transmission system upgrades, including ones in Greater Boston, Greater Hartford/Central Connecticut, Southwest Connecticut, as well as with SEMA/RI reliability project upgrades.
The study found a decrease in internal interface transfer capability associated with the updated load assumptions, updated NNE-Scobie transfer capability and the retirement of Mystic units 7, 8 and 9.
One stakeholder assumed that a drop in load would increase import capability and that the Mystic retirements will increase import capability.
“No, all these factors have the effect of lowering the transfer capability,” McBride said. “The load change really becomes as much about relative load changing, [and] in particular, changes in where load is on the key transmission lines.
“If you’re lowering load at a point on the transmission system that causes less local drawdown and more flow to remain on the system, but it seeks to try to get into, in this case, southeast New England, lowering load at particular points can actually cause more flow to be on those lines as it tries to serve the load beyond that point, lowering the transfer capability,” McBride said.
“We did some sensitivity analysis in an attempt to identify what the factors were,” he said. “The predominant thing we were looking at was the change from Mystic 8 and 9 at retirement, and we wanted to make sure we understood what the other factors were.”
For external interface import capability, limits are usually for the summer period, may not include possible simultaneous impacts and should not be considered as firm, McBride said.
For example, the electrical limit of the New Brunswick (NB)-New England (NE) Tie is 1,000 MW, but downstream constraints, particularly in Orrington South, led planners to adjust that tie’s transfer capability to 700 MW for ability to deliver capacity to the greater New England Control Area.
Similar to what it did with NB-NE, the RTO has assumed transfer capability for capacity and reliability calculation purposes to be 1,400 MW for the 2,000 MW Hydro-Quebec Phase II interconnection, lowering the figure due to the need to protect for the loss of the line at full import level in the PJM and New York Control Areas’ systems, he said.
An executive committee charged with overseeing administration of SPP‘s Western Energy Imbalance Service (WEIS) last week launched the working group responsible for developing and maintaining the market’s protocols.
The Western Markets Working Group (WMWG) will report to the Western Markets Executive Committee (WMEC), which approved both the group’s scope and its leadership during a March 19 conference call.
The WMWG will work with other stakeholder groups in recommending the protocols and associated Tariff changes to the WMEC and prioritizing approved system and process changes. It will also coordinate with regulators and task forces in implementing the WEIS market.
SPP’s WEIS and legacy footprints. | SPP
The committee unanimously approved Basin Electric Power Cooperative’s Valerie Weigel as the WMWG’s chair and Municipal Energy Agency of Nebraska’s Jeff Lindsay as vice-chair. They will serve two-year terms.
The working group will replace the WEIS Protocol Review Task Force, which has been developing the market’s protocols. The WMWG will consist of up to 12 members, with one representative from each non-affiliated signatory to the Western Joint Dispatch Agreement, the contractual arrangement between SPP and WEIS participants that governs SPP’s obligations to administer the market and its compensation.
SPP filed its WEIS Tariff in February, asking for an effective date of Feb. 1, 2021.
The WEIS market is modeled on the Energy Imbalance Service market SPP operated from 2007 to 2014. The RTO will centrally dispatch energy from the participants every five minutes using the most cost-effective generation to reduce wholesale electricity costs for participants. SPP says the market will provide price transparency and bilateral trades.
The WEIS market has attracted eight participants with the early March addition of Utah’s Deseret Power Electric Cooperative, a regional generation and transmission cooperative with six member retail systems. It is scheduled to launch next February. (See SPP Board OKs $9.5M to Build Western EIS Market.)
FERC on Friday approved PJM’s proposed rules on how the RTO will evaluate voluntary cost commitment proposals on competitive transmission projects (ER19-2915).
The Operating Agreement changes, which resulted from stakeholder-drafted motions at the Markets and Reliability Committee, require PJM to evaluate projects submitted in competitive proposal windows on multiple criteria, including “cost effectiveness.” (See PJM TOs Wary of Cost Containment Rules.)
The revisions clarify that PJM may not require developers to submit cost containments and that those that are voluntarily proposed are binding.
PJM would evaluate “the quality and effectiveness” of provisions that limit project construction costs, total return on equity (ROE) including incentive adders or capital structure.
Annual revenue requirement under partial and full cost caps | PJM
The RTO will submit to the Transmission Expansion Advisory Committee (TEAC) an analysis comparing the risks to be borne by ratepayers as a result of developers’ binding cost commitments or non-binding cost estimates.
In approving the rules, the commission rejected the objections of transmission owners, which argued the revisions did not provide enough details on how PJM will conduct its comparative analysis.
“We find that PJM’s filing is just and reasonable because it may assist PJM in its selection of the more efficient or cost-effective transmission solution and provides additional transparency of PJM’s evaluation of competing proposals,” the commission said. It noted that PJM is developing implementation details for the comparative analysis in Manual 14F.
“The proposed revisions provide reasonable flexibility both for developers to decide how to craft their voluntary cost commitment proposals and for PJM to evaluate and select the more efficient or cost-effective transmission solution. Moreover, the proposal provides for transparency, allowing stakeholders the opportunity to review any particular analysis conducted by PJM and raise any concerns via the TEAC process.”
FERC disagreed with arguments that the filing infringed on the rights of PJM transmission owners and nonincumbent transmission developers to exclusively make Federal Power Act Section 205 filings concerning transmission rates, revenue requirements and cost recovery.
It also rejected contentions that PJM will be determining whether the rate design elements under a proposal will result in just and reasonable rates. “PJM is proposing for the commission to determine, in reviewing the nonconforming DEA [designated entity agreement between PJM and a selected developer] with the cost commitment provision, whether any rate design component included in that provision is just and reasonable.”
FERC on Thursday denied NYC Energy’s (NYCE) request for a limited waiver of NYISO interconnection rules for its 80-MW energy storage facility proposed to be situated on a barge moored at the Brooklyn Navy Yard.
Manhattan as seen from the Brooklyn Navy Yard.
NYCE sought waiver of a Tariff provision that requires a project to withdraw from the ISO’s interconnection queue if it fails to comply with certain interconnection procedure requirements (ER20-629).
NYCE explained that its project is a modification of a previously permitted combined cycle gas/oil-fired generating facility and that the ISO also completed a materiality review of the project regarding a change in technology in August 2019. Further, the developer said it notified NYISO of its intention to enter the 2019 class year of the interconnection queue, and the ISO acknowledged the request on Aug. 16, 2019.
In addition, NYCE said it delivered an executed facilities study agreement (FSA) to NYISO on Sept. 11, 2019, along with all other required materials, including a $100,000 FSA study deposit.
But the company noted that when it submitted the FSA, it learned that NYISO had concluded that a previous finding of no adverse environmental impacts under state law applied only to the original project, not to the newer battery project, meaning the latter did not satisfy regulatory milestones required for the queue.
NYCE withdrew its effort to join the 2019 class year but sought a Tariff waiver in order to hold a position in the queue. NYISO supported NYCE’s waiver request, saying that absent a waiver from the commission, the ISO could not accept the two-part deposit for NYCE’s project after Sept. 16, 2019.
The ISO further said it did not dispute NYCE’s assertion that no adverse harm will result to other projects if the waiver request is granted because NYCE’s project no longer sought to participate in the 2019 class year.
The commission rejected NYCE’s arguments, saying “the record reveals no reason why NYCE could not have satisfied the regulatory milestone in accordance” with NYISO’s Tariff provisions, and the company “has not adequately explained why it assumed that prior regulatory reviews for a different generating facility would satisfy the regulatory milestone in the [Tariff].”
“Specifically, although we find no evidence of ill intent by NYCE, we find that NYCE has not demonstrated that it acted in good faith,” said the order confirmed by Chairman Neil Chatterjee and Commissioner Bernard L. McNamee.
The commission also found that NYCE failed to demonstrate that its waiver request was limited in scope.
It said “a waiver is not limited in scope if the party requesting waiver does not provide a compelling reason why it should be afforded special treatment compared to others. Here, NYCE seeks to shield itself from the consequences of its choices.”
Commissioner Richard Glick dissented in a separate statement.
“First, I see nothing in the record — or today’s order — indicating that NYCE did not act in good faith,” Glick said. “After all, it does not strike me as totally unreasonable to assume that, if an oil/natural-gas fired unit can pass environmental muster, then a non-emitting battery storage facility is likely to clear that bar as well.”
Glick argued that the waiver request is limited in scope insofar as it applies only to this facility and only to this single failure to comply with the applicable deadlines, and that the request remedies a concrete problem.
“Finally, I agree with NYISO that granting the waiver would not have undesirable consequences, such as harming third parties,” Glick said. “I also understand why NYCE sought to rely on its previous environmental determinations rather than fork over an additional quarter-million dollars in collateral … [which] does not, in my view, indicate that it acted in bad faith.”
Marketed as an eco-friendly alternative to car ownership, Indianapolis’ BlueIndy electric vehicle rideshare service will cut the engine and go out of business this spring.
After four years of providing shared EVs, French owner Bolloré Logistics will end BlueIndy’s operations May 21, leaving city leadership to decide whether to purchase the company’s assets.
BlueIndy said it “did not reach the level of activity required to be economically viable,” reporting that it attracted about 11,000 members who took about 180,000 rides over the ride-sharing service’s existence.
Complicating matters, BlueIndy indefinitely suspended the service beginning this week in response to the spreading COVID-19 pandemic in Indianapolis.
“We thank you for your understanding and hope to be able to restore service as soon as the situation permits. Let us remain united and responsible,” BlueIndy’s homepage read.
It remains to be seen whether customers will ever again have the chance to drive a BlueIndy car.
Wrong Market?
BlueIndy had bestowed the Indiana capitol with the distinction of the largest network of public charging stations of any U.S. city. However, critics from the start said the service only makes sense in a higher-density city with a smaller geography — not Indianapolis’ nearly 880,000 inhabitants spread over 372 square miles. Bolloré Logistics spun off a Los Angeles version of the service — BlueLA — in partnership with the Los Angeles Department of Transportation. The sister rideshare remains open though operations there are also suspended due to COVID-19.
“Indianapolis drivers have been slow to adopt alternative transportation options and car ownership remains extremely high,” BlueIndy explained in a late 2019 press release.
Now Indianapolis is weighing whether it should purchase the approximately 90 EV charging stations scattered on public rights-of-way throughout the city. BlueIndy originally anticipated owning as many as 500 cars and up to 200 stations in the city.
“Leading up to [May 21], we will be having conversations with neighbors, corporate partners and personal mobility advocates to explore whether financially sustainable options exist that would allow us to put the existing infrastructure to use — either with another ride sharing program or as charging stations for electric vehicles,” City of Indianapolis Deputy Chief of Staff Taylor Schaffer said in an email to RTO Insider.
Schaffer said Indianapolis’ 15-year contract with Bolloré Logistics stipulates the city can notify the company it would like to purchase the infrastructure at any point within 90 days of the contract’s end.
BlueIndy promotional photos | BlueIndy
“This means the city has until mid-August to decide whether to purchase the infrastructure or not,” Schaffer said.
Schaffer did not comment on a possible purchase price for the assets, though the city has previously said it has the option to appraise and negotiate a fair market value.
BlueIndy got off to a rocky start in 2016 when the Indianapolis City-County Council contended that Bolloré Logistics’ process for placing stations lacked transparency. (See BlueIndy EV Sharing Program Seeks Rebound.) As a result of negotiations, BlueIndy paid the city an annual $45,000 franchise fee meant to cover the loss of parking meter payments due to the curbside stations.
The project was slated to cost a total of $50 million, with the company investing $41 million, the city contributing $6 million and Indianapolis Power & Light Co. ratepayers covering the remaining $3 million.
In 2017, BlueIndy showed a $22.5-million deficit. The company has not released recent financial standings.
Indianapolis’ former Republican Mayor Greg Ballard called the service a “clean, affordable transit option to help connect visitors and residents with all that Indy has to offer” when the collaboration was announced in 2015.
It’s unclear how much BlueIndy was affected by IndyGo’s new rapid transit electric busline, which opened its first route last year along many of BlueIndy’s curbside electric charging stations.
Multiple requests to interview remaining BlueIndy employees went unanswered. BlueIndy Managing Director James Delgado appeared to stop tweeting about the service in early 2019.
“We believe that the continued reliance and predominant use of traditional personal vehicles is not sustainable long term in a growing urban environment and the need for additional mobility options to complement operators in Indianapolis including BlueIndy, IndyGo and the Pacers Bikeshare is significant,” BlueIndy said last year.
