FOLSOM, Calif. — CAISO’s Board of Governors unanimously approved a proposal Thursday meant to ensure that bidders from outside the ISO deliver electricity as promised or face more stringent financial penalties.
“The existing charge [for non-delivery] is relatively ineffective,” Brad Cooper, CAISO’s manager of market design policy, told the board in his presentation. That’s because participants rarely exceed a 10% monthly threshold when the charge kicks in. The new policy does away with that threshold.
Currently, “if intertie declines are less than 10% of total transactions, no charge applies,” the ISO wrote in an Aug. 15 issue paper. Anything more than a 10% failure-to-deliver rate can result in a charge of up to $10/MWh.
The lack of a financial incentive to follow through on bids can cause headaches, CAISO said in the paper.
“When an intertie resource receives a market award to import energy into the balancing authority area but does not deliver the awarded energy, the grid operator must maintain system balance by increasing internal supply or finding another intertie resource to import from,” it said.
Grid reliability and stable pricing depend on expectations being met, Cooper said at Thursday’s board meeting.
“When exports don’t deliver, they can cause intertie congestion,” he said. And “undelivered imports in a critical hour can have a big effect.”
The revised policy is also meant to curb speculative bidding — when a market participant submits a bid and doesn’t deliver because it can’t find the energy it promised or can’t find it at the right price.
When the 10% threshold was enacted in 2007, ISO computers couldn’t distinguish between an intertie “decline” and a reliability curtailment, officials said. That meant that reliability curtailments, which weren’t the fault of the market participant, could still count toward the decline charge.
The bar was set high at 10% to avoid penalizing participants who were unable to deliver because of unforeseeable problems.
Now the ISO’s system can distinguish between curtailments and non-deliveries, meaning the 10% threshold can be eliminated. Instead, non-delivery charges will be assessed in 15-minute intervals and “non-delivery will be subject to a charge equal to 50% of the maximum of the 15-min market or the five-minute real-time dispatch LMP, with a $10/MWh minimum, plus any imbalance energy,” according to the ISO.
Cooper said most stakeholders supported the plan as a way to reduce speculative bidding and to enhance reliability.
Severin Borenstein, a University of California Berkeley professor attending his first meeting as a newly appointed CAISO governor, asked planners to clarify why the charge applies to interties but not inside the ISO’s system.
Keith Casey, CAISO’s vice president for market and infrastructure development, explained that if an intertie bid — always scheduled an hour ahead of delivery — doesn’t materialize, the ISO can’t clear additional intertie energy until the next hour, but internally it can resort to the five-minute market to cover the shortfall.
The New York Public Service Commission on Thursday authorized utilities to spend $31.6 million to build up to 1,075 fast-charging electric vehicle stations and recover costs from ratepayers over seven years (18-E-0138).
The program is intended to help spur sales of EVs by reducing people’s “range anxiety” — the fear of running out of juice on the road — and to achieve Gov. Andrew Cuomo’s Charge NY goal of 10,000 EV charging stations by the end of 2021 and 800,000 zero-emission vehicles by 2025.
The commission’s Feb. 8 order outlines a flow of actions, including annual reviews, that “are smart and timely steps to enable new and needed infrastructure at sensible budgets and at sensible payment structures,” PSC Chairman John B. Rhodes said. “It puts a wide range of partners in a position to invest their money in our agenda for the benefit of all New Yorkers.”
In a related case (18-E-0206), the PSC in November rejected tariff filings for residential EV charging from all the major utilities in the state and ordered them to file revisions that implement time-of-use rates equal to the traditional residential customer charge. (See NYPSC OKs CCA, Rejects Residential EV Charging Tariffs.)
The new proceeding grew out of a joint petition last April by the New York Power Authority, along with the state’s Department of Environmental Conservation, Department of Transportation and Thruway Authority, seeking rate relief for DC fast-charging (DCFC) facilities for EVs.
The state’s Department of Public Service held a technical conference on the issue last summer, and in November the utilities joined the state agencies in filing a consensus proposal for the program.
Rate Design
Mary Ann Sorrentino, chief of electric rates and tariffs for the DPS, testified that rate design was the PSC’s main concern.
Mary Ann Sorrentino, N.Y. DPS
“To capture cost savings from potential technology cost declines, the draft order requires that initial incentive amounts be tied to the year in which the station qualifies for the program,” she said.
Sorrentino said plugs must have a 50-kW minimum charging capability to qualify for the program and that higher incentives will be provided to plugs with a minimum simultaneous charging capability of 75 kW.
Within 90 days of Thursday’s order, the New York State Energy Research and Development Authority must disburse the $31.6 million in unencumbered legacy system benefits charge (SBC) funds to the state’s six regulated utilities in the following amounts: Con Ed ($6.4 million); Orange and Rockland Utilities ($1.66 million); Central Hudson Gas & Electric ($4.4 million); Niagara Mohawk Power ($9 million); New York State Electric and Gas ($5.1 million); and Rochester Gas & Electric ($5 million).
The SBC provides funding for NYSERDA programs targeting energy efficiency, research and development and the low-income sector.
Commissioner Diane Burman
Commissioner Diane Burman brought up the $128 million New York received as its share of Volkswagen’s national settlement for flagrant emissions standards violations, which the state has earmarked for clean transportation measures such as promoting EV use.
“I understand there’s a separate track for that; I’m not looking to get involved in stuff that’s outside our jurisdiction,” Burman said. “To the extent that it complements us … it is extremely important that we are complementing each other in a way that makes sense. Here we’re talking about taking unencumbered legacy funds that seem to never, ever be ending over at NYSERDA, and utilizing them now for part of this.”
The state estimates EV sales were up 50% last year from 2017, with more than 43,000 EVs on the road by October, one-third of them battery electric and the rest plug-in hybrids.
“EVs, as is well known, have a chicken-and-egg problem,” Commissioner Gregg C. Sayre said. “Chargers aren’t being built because there aren’t enough EVs, and EVs aren’t being bought because there aren’t enough chargers. This item helps us get out of that cycle.”
Notable Differences
Commissioner Gregg Sayre
The PSC decided to minimize some of the “notable differences” contained in the consensus proposal.
“For example, pursuant to the consensus proposal, the Con Ed and Orange and Rockland per-plug incentives were to provide a combined benefit in conjunction with delivery rate discounts offered under the Business Incentive Rate [BIR] and Economic Development Rate, respectively, whereas the other utilities’ per-plug incentives were designed assuming that DCFC stations will not receive other delivery rate discounts,” Sorrentino said.
The Con Ed and O&R proposals were also unique in that they contained a separate load-factor incentive whereby station owners would earn a $500 incentive annually for achieving a 5% load factor, and $1,500 annually for achieving a 10% load factor, she said.
The commission found “the load-factor incentive to be unnecessary at this time, as station owners have a natural incentive to maximize station utilization,” Sorrentino said.
Bridget Woebbe, N.Y. DPS
Under Con Ed’s tariff, the BIR was available to owners of EV quick-charging stations with a minimum aggregate charging capacity of 100 kW and a maximum aggregate demand of 2,000 kW in New York City and Westchester County.
“This BIR has been open to electric vehicle quick-charging station developers since April, and that market has not materialized,” testified Bridget Woebbe, assistant counsel for the DPS. “Removing the restrictions really allows site hosts that are providing a direct capital investment by building the critical infrastructure to receive the appropriate incentive to deliver the public good of the DCFC.”
MANHATTAN BEACH, Calif. — NERC stakeholders last week got a first look at a draft report on supply chain risks as part of a FERC directive to develop a standard addressing risk management of the industry’s vendors.
Roy Thilly, chairman of NERC’s Board of Trustees, called the initiative a “very important undertaking,” but he also cautioned that it is not a “silver bullet.”
Supply chain risk management “requires a practical, effective, measured response,” he said during the NERC Member Representative Committee’s Feb. 6 meeting.
NERC staff have been working with the Electric Power Research Institute to assess the bulk electric system’s (BES) product and manufacturer types, analyze BES cyber assets, and gather best practices and standards used by other industries to mitigate supply chain risks.
At the board’s request, the North American Transmission and Generator Forums and other industry groups have developed white papers, which can be found on the initiative’s website.
The report suggests applying industry practices to third-party accreditation processes; ensuring that hardware and software are protected during physical transport; processes to mitigate risks from unsupported or open-sourced technology components; and using supply chain controls to address common-mode vulnerabilities.
Staff are recommending the standards include electronic access and physical access controls for medium- and high-impact BES cyber systems, and to collecting more data on low-impact BES cyber systems. They also plan to monitor emerging technologies for new risks.
Howard Gugel, NERC’s senior director of engineering and standards, said the industry’s reliance on technology and the use of single platforms to host multiple applications has increased the risk of access through “the back door.”
Despite that, he said he would be reluctant to endorsing a particular methodology for certifying third parties.
“I’m not sure we as the reliability regulator would want to get into any sort of third-party endorser of people selling in the market,” Gugel said. “However, if there are third-party options for providing that, we’d certainly like to be involved with it.”
FERC ordered NERC in 2016 to draft a “new or modified” standard addressing supply chain risk management for industrial control system hardware, software, and computing and network services associated with the BES. (See FERC Orders NERC to Develop ‘Flexible’ Supply Chain Standard.)
Staff are still accepting comment on the report. A final draft will be presented to the board in May.
Members Elect 4 Trustees to Board
The MRC elected the board’s class of 2022, filling a vacancy created to add a Canadian trustee and re-electing three incumbents to three-year terms.
Colleen Sidford will step into the Canadian vacancy. She spent 10 years with Ontario Power Generation in various financial positions, following a career in international banking.
NERC is required to have two Canadian trustees. It has three with Sidford’s election, but it is expected to reduce the number to two when Fred Gorbet’s term expires next year. That will also leave NERC with 11 trustees.
Re-elected to three-year terms were:
Robert Clarke, who has served on the board since 2013. He chairs the Corporate Governance and Human Resources committees and serves on the Enterprise-wide Risk and Nominating committees.
Ken DeFontes, a trustee since 2016. He is the liaison to the Standards Committee and serves on the Compliance and Technology and Security committees.
David Goulding, who was first elected to the board in 2010. He chairs the Enterprise-wide Risk Committee and serves on the Finance and Audit Committee.
NERC’s trustee succession policy provides that no independent trustee may be re-nominated or re-elected if he or she has served 12 consecutive years.
Ford, Sterling Step into New Leadership Positions
The meeting marked Greg Ford’s first as MRC chair. Ford, CEO of Georgia System Operations Corp., replaces Wabash Valley Power Association’s Jason Marshall, who cycled off the committee.
Jennifer Sterling, vice president of NERC compliance and security for Exelon, is serving as vice chair.
NERC General Counsel Charles Berardesco shared with the MRC the organization’s Participant Conduct Policy, which is applicable to participants in all organization activities. The policy was based on similar rules for the NERC Operating Committee and standards development process.
However, the policy doesn’t apply to the MRC itself, Ford said. “The MRC is a creature of the bylaws,” he explained.
Berardesco said the policy will create a professional environment for all participants supporting NERC’s mission, including standing committee members and observers, drafting team members and observers, and other stakeholder volunteers that participate in the organization’s activities or groups.
The policy calls for those it covers to conduct themselves in a professional manner, not to use NERC activities for commercial or private purposes, and not to distribute confidential information or certain work products.
HARTFORD, Conn. — With fewer than four months to go in this year’s session of the Connecticut General Assembly, state regulators made their cases short and sharp Tuesday when briefing legislators on the Energy and Technology Committee.
“One of the big challenges that we face is that our wholesale electricity market is governed by FERC, and at the federal level, there has been no recognition of the need to address climate change and reduce carbon emissions through the design of the wholesale electricity market,” said Katie Dykes, commissioner-designate of the Department of Energy and Environmental Protection and chair of the Public Utilities Regulatory Authority.
Dykes, nominated to be DEEP commissioner by new Gov. Ned Lamont last month, made her remarks in a presentation to committee members and the public at an informational forum held in the Legislative Office Building.
She said that the state has had to work by itself over the past several years to ensure that an increasing volume of power is being sourced from zero-carbon and renewable resources, mainly through utility-backed contracts and state procurements.
“The challenge, though, is that in our wholesale market, we are not always getting credit for what we are procuring in these contracts and in these different mechanisms that the state has had to establish in order to correct for the failure of the wholesale markets to ensure investment in those types of resources,” Dykes said.
The urgency of climate change requires a speedy transition to a zero-carbon electric grid, while at the same time retaining units such as Dominion Energy’s Millstone nuclear plant in Waterford, which supplies a “significant share” of the region’s carbon-free generation, she said.
In December, the 2,111-MW plant was one of the winning bidders in a state solicitation for nearly 12 million MWh of zero-carbon energy, securing purchase of about half its output for 10 years. (See Conn. Zero-Carbon Awards Include Nukes, OSW, Solar.) The PURA deemed Millstone at risk for retirement without ratepayer support, which allowed its bids to be considered in terms of environmental and grid reliability benefits, as well as price.
Dykes pointed to another challenge for New England: fuel security. The region sits at the end of the U.S. natural gas pipeline system, and while the wholesale market has driven investment into natural gas-fired power plants, it has not provided the infrastructure needed to supply those plants, she said.
“So this challenge of fuel security, a very gas-dependent wholesale electricity market that is not achieving carbon reductions, has also reached a tipping point where the ISO New England is not confident … that they can maintain the reliability of that electric grid in the near term if certain units that do not run on natural gas were to retire,” Dykes said.
“Just to be explicit,” she said, ISO-NE concluded it can’t run the grid without the Millstone units, the largest power plant in the region.
The RTO’s fuel security analysis released last year actually showed the New England grid would become extremely stressed if the Millstone units were lost under a scenario of maximum retirements of coal- and oil-fired generators.
Dykes also cited a state report from a year ago that projected regional CO2 emissions would increase by 25% if Millstone retired.
Unfortunately, Dykes said, the wholesale market is not designed to value carbon reduction and fuel security benefits, which leaves the responsibility to the state.
While Connecticut has been able to procure power at good prices, “the challenges now are in respect to ISO New England, whether its leadership is acknowledging where this future is heading us … and whether they have the ability to adapt their market design to accept and help to achieve the carbon emission goals of the states and to address in a proactive manner the fuel security needs of our grid, or whether they’re going to continue to adopt a reactive posture to the states’ leadership role,” Dykes said.
Later that day, the Connecticut Power and Energy Society (CPES) partnered with the state’s bar association to host a panel discussion with the leaders of the Energy and Technology Committee at the University of Connecticut.
Day Pitney attorney Sebastian Lombardi, who represents the New England Power Pool, moderated the panel of Rep. Charles Ferraro and Sen. Paul Formica, the ranking Republican members, and Rep. David Arconti and Sen. Norm Needleman, the Democratic co-chairs.
“We need to make sure that our public utilities are accountable,” Needleman said. “We are trying to move to renewables and at the same time trying to manage rates, which seem to be pretty high in Connecticut. I have some pretty well-known issues with management decisions that Eversource [Energy] has made, but I’m going to put those on the shelf, to some extent.”
Needleman last month criticized the utility for asking the state to allow it to charge ratepayers an extra $150 million to recover storm-repair costs incurred over the past two years.
A local news source, CT News Junkie, quoted him saying: “If Eversource had invested in effective weather responses in the past, instead of reducing staff and equipment to save money, they wouldn’t need to ask for $150 million in repairs.”
“My priority is to not allow one bill or issue suck up all the oxygen in the room,” Arconti said, adding that technology could be a big part of the committee’s agenda given the IT background of Gov. Lamont, who has yet to announce his legislative program.
Ferraro said it was important “to keep ratepayer rates as low as possible, but still keep opportunities open for procurement of renewable energy sources and letting them come to bear by also limiting the effect of subsidies that we add on the ratepayer, because if you subsidize renewable energy, eventually somebody’s going to pay for it.”
Lombardi said it seemed legislators were striving to find a balance between protecting ratepayers and increasing investments in procurements like offshore wind, fuel cells and grid-scale solar.
Dan Dolan, president of the New England Power Generators Association, said one of the challenges is balancing how the market is structured.
“Over the years, my organization has raised a lot of concerns about carving out more and more of the market to individual resource types,” Dolan said. “How do you folks think about trying to integrate some of these different attributes within the market and be able to move away from a long-term contracting structure?” He added that NEPGA is specifically “looking at putting a more meaningful price on carbon emissions” beyond the Regional Greenhouse Gas Initiative.
“I think working with our colleagues at PURA and with DEEP … is going to be a big focus point for me,” Arconti said. “They just have way more institutional knowledge at this point when it comes to striking those balances.”
Needleman said he thought the idea of a carbon tax was more of a national issue and that he wouldn’t know how to implement it in Connecticut without making the state less competitive, “but I would certainly support it in a broad way.”
Needleman also expanded on Arconti’s point of consulting with state agencies.
“Meeting Commissioner Dykes today and listening to her blew my socks off,” he said. “She’s very knowledgeable, and I think [Arconti] is right that we have to follow the institutional knowledge. In some of the presentations we’re hearing about offshore wind, they’re comparing it to other forms of generation and emphasizing that we are a coastline state and that we have the perfect area to launch a lot of work and reap the benefits.”
Offshore Wind Base
Asked what single issue he would focus on more than any other, Formica replied that he would try to make the Port of New London part of the supply chain for the growing offshore wind industry in the Northeast.
“With no overhead obstructions, it puts itself in good position to be a base of operations for offshore wind,” Formica said. He recounted how years ago he had served “on a regional rail committee that created a freight line from that pier moving north” through the state and all the way to Montreal.
“There’s going to be $30 million to $50 million invested in the New London pier specifically to accommodate wind,” and if the state can establish some assembly or manufacturing plants for turbine components up north it could take advantage of the economic opportunities in renewables, he said.
Ferraro said people talk about New London, but “we also have offshore wind capability in Bridgeport. … Once those industries are up and running, it’s going to make sense to have the large components — the wind turbines — made right here in Connecticut in the ports, instead of shipping them from a place like Denmark, which would bring jobs and economic development to our state.”
California’s investor-owned utilities submitted enhanced wildfire mitigation plans to the Public Utilities Commission on Wednesday, as required by last year’s sweeping fire safety law, SB 901.
The utility filed for Chapter 11 bankruptcy reorganization last month, citing the more than $30 billion in claims it faces for Northern California’s disastrous wildfires in 2017 and 2018. (See Bankruptcy Only Viable Option for PG&E, Lawyer says.)
The PUC will review the IOUs’ plans and hold an all-day workshop on Feb. 13 — the start of a six-week process of weighing and instituting measures to prevent the type of devastating fires the state has experienced in the past two years.
Those measures include de-energizing power lines in fire-prone areas during high-risk weather conditions, according to the plans submitted by PG&E and Southern California Edison. Both utilities have been blamed for massive, deadly fires in 2017 and 2018. The utilities, in turn, have cited climate change as a major factor in the disasters.
PG&E’s wildfire mitigation plan includes enhanced vegetation management around power lines. | PG&E
“Our state is faced with an extended and more dangerous wildfire season that demands urgent action and coordination,” Sumeet Singh, head of PG&E’s Community Wildfire Safety Program, said in a news release Wednesday. “While California’s energy companies have a critical responsibility and role to play in reducing wildfire risk, we must all work together to keep our communities safe.”
The IOUs have had to develop annual wildfire mitigation plans since 2017, but SB 901 required them to provide more detailed safety plans and seek PUC approval for their proposals. (See California Wildfire Bill Goes to Governor.) Under the new law, the PUC has authority to pursue enforcement actions if utilities fail to comply with the plans.
Along with PG&E and SCE, San Diego Gas & Electric, CalPeco Electric, Bear Valley Electric Service and Pacific Power must participate in the PUC process.
Under Scrutiny
In PG&E’s case, Judge William Alsup, of the U.S. District Court for the Northern District of California in San Francisco, said he was considering requiring the utility to inspect its entire grid for safety issues and make repairs prior to the start of the 2019 fire season this summer, a plan he was at least temporarily dissuaded from by opposition from PG&E and federal prosecutors.
Alsup is overseeing PG&E’s probation in the 2010 San Bruno gas line explosion, which killed eight residents of a suburban San Francisco neighborhood. Jurors convicted the utility in 2016 of six felonies for failing to comply with safety regulations and for obstructing a federal investigation.
PG&E was placed on probation for five years. Alsup concluded in late January that it had violated the terms of its probation by failing to report a legal settlement for a 2017 wildfire in Northern California. He criticized the utility for its repeated safety failures and starting fires.
Whether PG&E’s fire mitigation plan will satisfy the judge or result in further probation conditions remains to be seen. Alsup said he’d take up the matter at a future date, still to be determined. The judge gave interested parties until noon on Feb. 20 to file comments with the court regarding PG&E’s fire safety plan.
That plan lays out a strategy of vegetation management, grid hardening and line inspections that goes beyond the measures PG&E began implementing in 2017 and 2018.
The company said it is expanding its power-shutoff program to include 5,500 miles of transmission lines and more than 25,000 miles of distribution lines in extreme-risk fire areas designated on the PUC’s High Fire Threat District Map.
The California Public Utilities Commission adopted its High Fire Threat District Map in January 2018. | CPUC
“Proactively turning off power is a highly complex issue with significant public safety risks on both sides — all of which need to be carefully considered and addressed,” Michael Lewis, senior vice president for electric operations at PG&E, said in a news release Wednesday. “We understand and appreciate that turning off the power affects first responders and the operation of critical facilities, communications systems and much more. We will only turn off power for public safety and only as a last resort to keep our customers and communities safe.”
The PUC in December opened a dedicated proceeding to examine the controversial practice of de-energizing transmission lines during high-risk periods, a practice that one commission staffer said raises a “range of concerns” for the public. (See Calif. Regulators to Scrutinize De-energization.)
Other measures proposed by PG&E include installing 600 cameras in high-risk fire areas and adding 1,300 weather stations by 2022.
SDG&E’s extensive use of cameras and weather stations — along with grid hardening and targeted power shutoffs — have helped that utility achieve one of the state’s best fire-safety records in recent years and have been cited by state officials as a model for PG&E to follow.
“SDG&E’s efforts to mitigate the risk of wildfire and enhance grid resilience began over a decade ago after San Diego experienced some of the most destructive wildfires in the county’s history,” the utility said in its wildfire mitigation plan filed Wednesday.
In its plan, PG&E did not say it would inspect its entire grid, as Alsup proposed, but that it would inspect 725,000 electric towers and poles across more than 30,000 miles of transmission and distribution lines in fire-threatened areas.
Disabling automatic reclosers, installing stronger poles and covering power lines — or putting some underground — are among the other measures PG&E submitted to the PUC.
‘Going Far Beyond’
SCE outlined a similar set of measures in its fire mitigation plan. The company proposed removing 7,500 hazardous trees, replacing conductor across 96 circuit miles and installing 7,800 fuses on unfused lines. It too plans to install additional cameras and weather stations as well as deploy “covered conductor in high fire risk areas” and explore “targeted undergrounding” of lines.
“Many of the ignitions associated with utilities are caused by objects that contact distribution power lines or conductor-to-conductor contact,” the utility said in a news release. “Covered conductor has proven to be an effective mitigation measure against these ignition sources.”
“We are going far beyond traditional good utility practices and incorporating advanced mitigation measures deployed in high fire risk regions around the world,” Phil Herrington, SCE’s senior vice president of transmission and distribution, said in a news release.
“This is an aggressive plan to protect public safety,” he said. “We are implementing a variety of additional tools and technologies to advance fire safety even further throughout our system to respond to the ‘new normal’ of year-round wildfire risk.”
FERC on Monday denied the Michigan Public Service Commission’s request to reconsider a decision over refunds associated with a two-year system support resource (SSR) agreement for an Upper Peninsula generating plant.
The PSC sought rehearing of a June 2018 order accepting MISO’s compliance filing containing a report setting out refunds for overcharges stemming from the RTO’s SSR agreement with P.M. Power Group’s White Pine natural gas plant. FERC rebuffed the request, saying it fell outside the scope of the compliance proceeding, among other issues (ER15-767-004).
The proceeding originated in a 2014 decision in which FERC ordered MISO to scrap its practice of allocating SSR costs on a pro rata basis to all load-serving entities in the American Transmission Co. service territory and instead assign costs to LSEs that required the White Pine, Escanaba and Presque Isle power plants for reliability. Two years later, FERC approved MISO’s plan to refund Wisconsin LSEs overcharged under the original rules of the White Pine SSR agreement. (See FERC Upholds MISO’s White Pine, Escanaba Refunds.)
White Pine power plant | Traxys
MISO was authorized to end the White Pine SSR in late 2016 after ATC submitted a transmission reconfiguration plan to split a load pocket, boosting reliability in the area. (See MISO Allowed to End White Pine SSR.)
The PSC argued that MISO’s refund report was problematic on three counts, saying the refunds run “contrary to [FERC] precedent where the commission has traditionally denied refunds in cost allocation cases” and that they amount to “retroactive ratemaking,” which is prohibited under the Federal Power Act. It also contended that MISO’s corrected cost allocation methodology should only be implemented prospectively.
“MISO did not make clear it would seek authorization to impose retroactive surcharges in this proceeding until the filing of the refund report,” the PSC added.
The state regulator further argued that FERC should not have considered the refund report final while a pending appeal of three other Upper Peninsula SSR reallocation cost methodologies was before the D.C. Circuit Court of Appeals. The court has since rejected the appeal.
In denying the PSC’s rehearing request, FERC said the White Pine proceedings weren’t the place to “challenge the commission’s authority to order retroactive surcharges.”
The “Michigan commission’s challenge to the requirement for refunds and surcharges, including its arguments that the refunds and surcharges are contrary to commission precedent, the FPA, the filed rate doctrine and the rule against retroactive ratemaking, are outside the scope of this compliance proceeding and, in any event, have been rejected by the D.C. Circuit,” FERC said.
RENSSELAER, N.Y. — NYISO stakeholders on Monday debated the need to consider the improbable: that a proposed carbon pricing scheme could occasionally leave New York electricity consumers paying into the carbon revenue account rather than drawing from it.
ISO staff prompted the discussion with a proposal for responding to such an event in the wholesale market.
“In the unlikely circumstance the carbon residual is negative, the Tariff will include rules for allocating these carbon residual shortfalls to” load-serving entities, Ethan D. Avallone, NYISO senior energy market design specialist, told the Market Issues Working Group.
The total carbon residual represents carbon charges collected from internal generators plus those collected from imports, minus carbon payments to exports, he said. Wheel-through transactions are netted out of the total. (See NYISO Looks at Carbon Charge Tariff Impacts, Residuals.)
The graph shows how the proportional method (C) of allocating carbon charge residuals results in an equitable impact across load zones without levelizing costs. | Brattle Group
A negative residual would occur when carbon payments exceed carbon charge collections, which could arise when an emitting resource is on the margin while much of the energy being delivered is being provided by zero-carbon resources, Avallone said. Dispatching that marginal emitting resource for export would trigger a payment to the resource, but the ISO wouldn’t be collecting charges to cover that payment in the interval.
To ensure that benefits are spread equitably across the state, NYISO has recommended allocating carbon charge residuals proportionally to consumers across all zones, Avallone said. But in instances when it must cover a potential negative balance in the residual account, the ISO is proposing to allocate costs back to load based on load-ratio share.
Avallone said the load-ratio share methodology makes more sense than a proportional one in dealing with negative residuals. It would prevent piling additional costs on load zones with higher locational-based marginal prices and also avoid further cost shifts.
Load in zones with higher prices will already bear a higher impact from the carbon charges in their energy payment. If the proportional carbon allocation were used, those zones would also carry a higher proportional burden for a negative residual, Avallone said.
Statewide Issue
“It’s important to note that any shortfall would be a statewide issue, because the calculation includes both imports and exports,” Avallone said.
NYISO’s principal economist, Nicole Bouchez, explained that renewables tend to be on the margin upstate, but that the negative residual phenomenon would become a statewide issue when no emitting generators are producing, an emitting resource is marginal and exports are occurring, which is unlikely with the current generation fleet.
“Over time, as you get more and more renewables, it might happen more often,” Bouchez said.
Asked if the ISO had done any analysis on the shortfall issue, Avallone replied, “No formal analysis; just the observation that it is possible to be a net exporter today around midnight when you have many renewables on.”
Mark Reeder, representing the Alliance for Clean Energy New York, said the analysis could be done with data from previous multiarea production simulation runs.
“You’d have to have downstate having almost no carbon emissions to have the shortfall situation arise,” Reeder said.
Upon implementation, the ISO would expect the “majority of hours” to see a credit to load, calculated on an hourly basis, Avallone said, but some stakeholders did not like the fuzziness of the term.
Mark Younger of Hudson Energy Economics pointed out that there would be carbon revenues both from emitting resources on the margin and those running at minimum load. He said NYISO had “undersold” the statistical improbability of getting a residual shortfall, which would require payments to exports to exceed the carbon revenues from all resources in the market, an unusual occurrence. The ISO would need to show a hypothetical example of potential negative residuals occurring when exports are coupled with generators running at minimum carbon generation, he said.
NYISO’s schedule for carbon pricing calls for discussing calculating its impact on LBMP and identifying marginal units on Feb. 15, Tariff revisions on Feb. 28 and March 18, and carbon bid adjustment for opportunity cost resources on March 4. Opportunity cost resources represent carbon-free resources able to store energy and structure their bids to achieve delivery schedules during the most economic periods of the day. (See NYISO Plan Revises Treatment of Carbon-Free Resources.)
VALLEY FORGE, Pa. — PJM stakeholders failed again to reach agreement on energy price formation rules Wednesday, as a last-ditch effort at compromise fell short in a 62% sector-weighted vote.
As a result, Stu Bresler, PJM’s senior vice president of operations and markets, said staff will move forward with recommendations to the Board of Managers next week for a unilateral Federal Power Act Section 206 filing with FERC.
Calpine’s David “Scarp” Scarpignato led an informal group of stakeholders in attempting to piece together a compromise after five proposals fell short of the two-thirds threshold at the Jan. 24 Markets and Reliability Committee meeting. (See PJM Stakeholders Deadlock on Energy Price Formation.)
“The proposal is not any individual company position and all parties moved off their underlying ideologies,” Scarp said in describing the proposal at a special Members Committee meeting.
The alternative plan included many of the revisions in Vistra Energy’s proposed modifications to PJM staff’s plan, which received 41% support at the MRC.
Like the Vistra proposal, the latest compromise included a concession by load interests to eliminate an energy and ancillary services (E&AS) revenue offset in the capacity market.
The Vistra proposal also included a concession by suppliers to phase in an increase in the penalty factor, beginning at $850/MWh for all products in all hours for the first two years. After that, the factor would increase to $1,000 to $2,000/MWh during hot or cold weather alerts.
The plan capped nested reserve pricing at $4,000/MWh — one-third the level in PJM’s proposal — and reduced the 30-minute time horizon on the operating reserve demand curve (ORDC) error distribution to 20 minutes.
Generators also agreed to remove about 30 outlier generators from the forced outage risk assumption, a concession to criticism by the Independent Market Monitor.
The proposal also would have boosted demand response’s maximum share of the synchronized reserve requirement to 50% from the current 33%.
Bresler said PJM’s preliminary calculations suggested the compromise would have reduced the increase in energy and reserve prices by an “order of magnitude … of about 25%” compared with the RTO’s proposal.
While the compromises won support by 43% of the End-use Customers sector, it was not enough to overcome unanimous opposition by the Electric Distributors, which voted 30-0 in opposition. Transmission Owners (100%), Generation Owners (96%) and Other Suppliers (76%) overwhelmingly supported the plan.
Before the vote, stakeholders thanked Scarp for his efforts to build a compromise.
“I think it was some of the more open and honest stakeholder discussions that I’ve seen,” said Adrien Ford of Old Dominion Electric Cooperative. “I think Scarp did a great job of pulling people together across different sectors.”
“Everyone who supports that has given blood,” Direct Energy’s Marji Philips said. “No one is extremely happy.”
“I think everyone is uncomfortable with some of the aspects presented here,” agreed Susan Bruce, representing the PJM Industrial Customers Coalition. “It was truly an exercise in mutual gains and consensus building. The best of Manual 34 in a microcosm.” Bruce said the ICC voted in favor as a measure of “risk management” because of the higher costs in the PJM plan.
Next Steps
Bresler said after the vote he expects staff will recommend the board file PJM’s proposal — which includes an immediate increase to a $2,000 penalty factor per reserve product — though he said stakeholder discussions helped evolve some of the RTO’s thinking since December.
“I don’t think our recommendation will have any sort of reduction in the penalty factors on the ORDCs,” he said. “We think $2,000 is the best answer.”
But he said staff “heard some compelling arguments [against] adjustments to ancillary and energy services … so that will all bake into our thinking as far as our recommendation to the board is concerned.”
In a letter to members, the board had included the E&AS adjustment as a transitional mechanism it thought should be included in the plan. Suppliers, however, said the change would be speculative.
“We haven’t done it in the past,” Bresler said of the adjustment. “We’ll see what direction we get from the board.”
The board is expected to decide on its path forward at its Feb. 12 meeting, following a Feb. 11 Liaison Committee meeting. Bresler said a FERC filing is likely in early to mid-March with June 1, 2020, as a “reasonable target” date for implementation.
Wildfire victims, creditors and ratepayers have been lining up to participate in the Pacific Gas and Electric bankruptcy process.
On Wednesday, consumer watchdog The Utility Reform Network sent a letter to federal trustees formally requesting the U.S. Bankruptcy Court in San Francisco appoint a committee of ratepayers to represent the interests of PG&E’s 16 million customers in Northern and Central California. The utility filed for Chapter 11 last month, citing the more than $30 billion in claims it faced for Northern California’s disastrous wildfires in 2017 and 2018. (See Bankruptcy Only Viable Option for PG&E, Lawyer says.)
“Ratepayers have at least as much at stake as any constituency in these Chapter 11 cases,” TURN Executive Director Mark Toney said in a news release. “PG&E’s electricity and gas customers generate nearly all of its revenues, and hence are its main source of income.
“With bondholders, banks and others who are represented by creditors’ committees likely to assert tens of billions of dollars in claims, the court will be making critical decisions about which claims to allow and whether shareholders or consumers will pay them,” Toney said. “Customers deserve a seat at the table.”
The November 2018 Camp Fire was the deadliest and most destructive wildfire in California history. | Cal Fire
TURN’s request was addressed to officials in the Justice Department’s Trustee Program, which supervises the administration of bankruptcy cases. It was endorsed, TURN said, by the Public Advocates Office of the California Public Utilities Commission and by a number of public interest groups including the Sierra Club.
“Ratepayers form a unique creditor class with an interest in recovering funds owed to them,” the letter said. “For example, ratepayers are entitled to the California Climate Credit (approximately $450 million for 2019) which represents proceeds from PG&E’s sale of greenhouse gas allowances. Similarly, PG&E owes ratepayers $31.75 million from the calendar year 2019 Gas, Transmission and Storage proceeding as part of a settlement agreement, and $10 million from a settlement agreement regarding ex parte communication violations.
“PG&E also is authorized to collect in rates certain forecasted procurement costs recorded in its Energy Resource Recovery Account that could be subject to ratepayer refund. Thus, in some instances, ratepayers will be competing creditors.”
A long list of would-be creditors, including fire victims, is collectively claiming in bankruptcy court that PG&E owes them tens of billions of dollars.
They include Karen Roberds and Anita Freeman, who claim in a lawsuit that PG&E owes $16 billion to those who lost real and personal property in the November 2018 Camp Fire in Butte County. The cause of the Camp Fire has yet to be determined, but PG&E equipment is suspected. (See PG&E Troubles Mount After Camp Fire.)
Among the 62 other claims already filed with the Bankruptcy Court is a $10 billion claim from the owners of a restaurant in Glen Ellen. They filed a lawsuit for their losses and the losses of other businesses in Napa and Sonoma counties during the siege of wildfires in Northern California’s wine country in October 2017. State investigators have blamed PG&E for starting 18 of the 21 major fires there during that time.
Dozens of smaller claims, such as a $10 million claim from a veterans’ home in Napa County, have also been filed.
FERC on Monday conditionally approved South Central MCN’s proposed revisions to its transmission formula rate and protocols and granted a rehearing request that set a Federal Power Act Section 206 proceeding (ER15-2594).
In seeking the rehearing, South Central (now called GridLiance High Plains), a subsidiary of competitive transmission company GridLiance and an SPP member, argued that FERC erred in a 2017 order (EL18-16) by requiring the company to include a fixed federal income tax rate component in its formula rate instead of allowing for annual transmission rate adjustments based on the tax liability of the company’s various owners.
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FERC’s Monday order terminated a Section 206 paper hearing imposed on South Central in 2017, when the commission determined the company’s revised rate protocols “attempt to define the scope of future filings” under FPA Section 205. (See FERC Orders Section 206 Proceedings for 5 SPP TOs.) FERC said the utility’s proposed revisions to its formula rate protocols in that docket satisfied its concerns in the 2017 order and directed South Central to submit revised tariff records implementing its proposed revisions.
In granting the rehearing request, the commission noted that its general policy calls for estimated cost components of formula rates to be fixed in the formula rate. It said it has recently exercised “greater flexibility with other formula rate components that are traditionally fixed where formula rate protocols provide protection to customers in the form of information exchange and challenge procedures.”
The commission found that South Central’s formula rate protocols provided such protection in providing any information necessary to understand the inputs to its formula rate that includes income tax allowance and its subcomponents. FERC specifically pointed to federal and state income tax rates attributed to different categories of owners, and the percentage of federal income tax deductible for state purposes attributed to those different categories.
