ERCOT said Tuesday it confronts a historically low 8.1% planning reserve margin next summer in the face of continued high electricity demand from oil and gas producers in West Texas and the cancellation of several generation projects.
ERCOT’s December Capacity, Demand and Reserves (CDR) report shows more than 78 GW of operational generation capacity available next summer to meet expected demand of 74.9 GW. That marks a 600-MW increase in capacity over the May CDR forecast and a 1-GW jump above this summer’s record peak demand of 73.5 GW.
The ISO had an 11% reserve margin this past summer, when it met multiple demand peaks without resorting to emergency actions.
ERCOT faces historically low reserve margins next year in the face of expected increases in demand. | ERCOT
The grid operator has approved 1.7 GW of various resources for commercial operations since the May CDR. However, three proposed gas-fired projects totaling 1.8 GW of capacity and five wind projects totaling 1.1 GW have been canceled since May. Another 2.5 GW of gas, wind and solar projects have been delayed.
“The ERCOT market has experience in these cycles of [generation] retirements and resource investment,” Pete Warnken, the ISO’s manager of resource adequacy, said during a media conference call. “What we’re encountering now is nothing new.”
Warnken said ERCOT’s energy-only market is working as it was intended, with pricing signals incenting new generation. However, prices increased only slightly during the scarce times of the past summer.
“We are in a transition period where we’re facing lower reserve margins. Operationally speaking, we think the market is functioning the way it was designed,” Warnken said.
The report does indicate operating reserves will increase to 10.7% in 2020 and 12.2% in 2021, before falling again to 9.8% and 7.5% the following two years. More than 7.4 GW of installed capacity — all wind or solar, save for 100 MW of gas generation — is eligible for future inclusion in the CDR.
Warnken and Senior Director of System Operations Dan Woodfin worked hard to allay concerns during the call, reminding listeners that the CDR is a snapshot of resource availability “based on the latest information from resource owners and developers.”
Woodfin said ERCOT doesn’t view the shrinking reserve margin as a concern. He said the ISO can take several actions as operating reserves approach or drop below the minimum level of 2.3 GW, including using switchable resources in neighboring grids, procuring emergency responsive service, releasing ancillary services held in reserve and reducing load.
“Our role is to manage the grid and ensure it’s reliable on a systemwide basis. We certainly have the tools in place,” Woodfin said.
Asked whether ERCOT faces a greater risk of entering into an emergency situation, Warnken said, “We don’t know at the present time.” He said future CDR reports could show increases in capacity.
Warnken pointed to West Texas oil and gas development as driving the increased demand. ERCOT projects an 8% annual growth rate in West Texas peak demand through 2023, quadruple the ISO’s 2% systemwide load growth during the same time period.
Warnken admitted the oil and gas sector is volatile, but he said ERCOT has been in close contact with transmission and distribution providers about their service requests.
“Like the CDR in general, [ERCOT’s West Texas forecasts] are based on the current information we’ve been given,” he said.
“Industrial load growth has been central to ERCOT from the beginning,” CEO Bill Magness said last month in Houston. “That type of load comes in big chunks.”
ERCOT has a target planning reserve margin of 13.75%, which Warnken said is “purely informational” and not used to set requirements for generation standards.
Woodfin said ERCOT will be able to provide a clearer picture of summer expectations when it issues its next seasonal assessment of resource adequacy (SARA) in March. The SARA will include various scenario assessments, while the CDR relies on a 50/50 forecast with a 50% probability the peak will be higher or lower than predicted.
CARMEL, Ind. — MISO stakeholders are skeptical of a year-end Tariff filing intended to guarantee the RTO will have access to additional megawatts by spring through stricter outage rules and load-modifying resource (LMR) requirements.
The RTO last month announced it will focus on three short-term fixes it can roll out early next year to increase availability of 5 to 10 GW of additional supply. (See MISO Pivots to Near-term Resource Availability Fixes.) The proposed changes include stricter LMR obligations, more advanced notice of planned outages by members and firmer planned outage requirements.
Speaking at a Nov. 29 Reliability Subcommittee meeting, MISO Executive Director of Market Development Jeff Bladen said the RTO thinks it needs the incremental changes to give it time to work on long-term fixes throughout 2019. MISO will publish a straw proposal on longer-term solutions in the first quarter of next year.
Without the smaller changes, MISO could confront a serious emergency and face changes dictated by an outside entity, Bladen said.
Several stakeholders have criticized MISO for what they call a rush to a Tariff filing before the end of the year. Some pointed to the absence of an emergency driving the FERC filing and asked what the RTO could accomplish without a Tariff filing.
“Anytime you do these very forced Tariff changes … these rushes are extraordinarily expensive [for load-serving entities] to accommodate,” Madison Gas and Electric’s Megan Wisersky said during a Nov. 16 workshop on the project.
But staff said upcoming maintenance seasons pose a real risk.
Bladen said MISO has spent more than a year detailing the growing disparity between resource availability and need.
“I think there’s general consensus that we are facing real issues that we have to take real action on,” Bladen said, adding that he hasn’t heard stakeholders refute the position that MISO could face a reliability threat in spring.
“This community has agreed that there’s a problem,” he said.
Bladen noted that each of MISO’s most recent maximum generation events have become more difficult to manage. “We really run the risk of reliability challenges becoming more than just challenges. … We really are not in a position to sit on our hands.”
LMR Testing and Data
Dustin Grethen of MISO’s market design team said the RTO is planning to require annual tests of demand response resources that physically curtail load. LMRs that opt out of the real power test would be subject to triple monetary penalties for nonperformance. MISO currently requires LMRs to replace their undelivered energy at corresponding LMPs. The new rule would not apply to behind-the-meter generation, which is already required to perform a generation verification test.
“What we want to make sure is that all resources can be relied on for the amount they say is available through the MISO Communication System,” Grethen said.
The RTO will propose a two-year transition to the rule for LMRs operating under non-retail tariff contracts, which is intended to allow time to renegotiate contracts.
“We have contracts in place. It’s going to take time,” Grethen acknowledged.
For its part, MISO has pledged to convert anticipated emergencies to a declared event at least two hours prior to emergency conditions. Grethen said MISO will issue LMRs scheduling instructions hours in advance based on the resources’ notice requirements but will declare the emergency or cancel the call for emergency-only resources two hours in advance. Even canceled calls will count as one of five required responses per year, and emergency DR will still be eligible to recover shutdown costs.
Stakeholders said MISO was heaping more penalties on a class of resources that already have more requirements than the average resource. Some said the move risks driving away LMRs.
“We’re definitely asking for more than we have in the past,” Grethen said.
The RTO is also looking to require more information from LMRs that will sell their capabilities after clearing in the upcoming capacity auction in spring. Those resources will have to provide their seasonal availability based on expected load output and retail tariffs and the shortest reasonable notification time for eliciting a response. MISO will require supporting documentation of availability if an LMR is not available within two hours for at least nine months out of the year. DR personnel would also have to participate in at least one LMR drill per planning year if they have not successfully met a call to curtail load or submitted results from a real power test.
“MISO is not looking to assign a notice time. We’re trying to get an idea of your best reasonable notice time. Tell us with documentation,” Grethen said.
Coalition of Midwest Power Producers CEO Mark Volpe criticized MISO’s use of the term “survey” to describe the new information requirement.
“‘Survey’ implies optional,” Volpe said, asking what deadlines MISO is planning to impose.
MISO Director of Resource Adequacy Coordination Laura Rauch said data submittal will become part of annual LMR asset registration. For the upcoming planning year, MISO plans to defer LMR registration from the beginning of February to March 1.
Century Aluminum’s Brian Helms asked if MISO would improve its outdated Communication System to allow for easier input of LMR data.
Rauch said the RTO will not have the system in time for the new LMR requirements but promised improvements in the nonpublic platform soon.
Helms said MISO may not realize that when his aluminum smelter is called up for load reduction for four hours during the summer, he deals with the fallout and monetary implications for months afterward.
“At what point is it not worth registering my LMR anymore?” Helms said. “How do you explain these requirements to outsiders? We want to provide reliability to the grid, [but] there needs to be some kind of balance.”
He said there are more reliability benefits and megawatts to be extracted from outage coordination, not LMR requirements. More stringent outage rules are the second piece of MISO’s near-term resource availability filing.
Outage Planning
MISO is weighing additional penalties for planned outages that are not scheduled in a timely manner. It plans to label short lead-time planned outages that occur during maximum generation events as “forced” outages, which will count against a resource’s capacity accreditation.
The RTO wants resources to provide 120 days’ notice for planned outages, with only one “limited adjustment” to the outage schedule allowed up to 60 days before the outage. The new notice requirement will supplement existing outage coordination requirements and not affect MISO’s required three-year lead time for nuclear units or two-year lead time for other units. MISO will also provide a safe harbor clause from the 120 days when an outage is rescheduled at the RTO’s request.
“We’ve received a lot of feedback, anywhere from ‘do not proceed’ to ‘require more,’” MISO engineer Matt Sutton said.
He said the “limited” outage scheduling adjustment MISO will allow must not exceed seven days and can apply to either the length, start date or end date of an outage. However, Sutton said generation owners are not allowed to make such adjustments when it moves the outage from a low-risk to a high-risk period based on the volume of supply available in MISO’s public maintenance margin forecasting tool. The 120-day requirement would begin in earnest on June 1, 2019, in time for the 2020/21 planning year. In the meantime, MISO is requiring that owners request any spring outages no later than Feb. 1 to qualify for safe harbor.
But some stakeholders said the 120-day requirement does not consider the forecasting updates and weather volatility that create high-risk situations with little notice. Some said generators could inadvertently move outages to higher-risk periods.
“Please think about the behavior you’re driving with this activity,” Xcel Energy’s Kari Hassler urged.
Other stakeholders asked the RTO to separate the maintenance margin for MISO Midwest and MISO South, which is more affected by generator outages.
Staff said they were considering creating stakeholder focus groups to hear more suggestions on improvement to outage coordination processes and tools.
MISO is accepting more feedback on its short-term filing through Dec. 13 and is targeting a Tariff filing by Dec. 21. In response to stakeholder requests, the RTO has scheduled a Dec. 7 conference call to discuss more finalized Tariff language before the filing.
PHOENIX — California legislators will struggle with wildfire liability and prevention in 2019, while lawmakers in Washington and Nevada could debate clean energy and utility-choice plans after voters in those states rejected related ballot measures, panelists told the Western Energy Imbalance Market’s Regional Issues Forum (RIF) on Wednesday.
In California, “it’s fair to say the legislative session will be dominated by the wildfire issue,” Sacramento utility attorney Tony Braun said as part of a panel on state policy developments and impacts on markets. “The wildfire issues, which are energy issues, are going to take all the air out of the room.”
California lawmakers were sworn in Monday, when bills can also be introduced for the start of the 2019/20 legislative session. Already there’s been talk of bills that could either help Pacific Gas and Electric remain solvent or break it up after the devastation of the Camp Fire in Butte County, the state’s deadliest wildfire. (See Camp Fire Prompts Talk of PG&E Bailout or Breakup.)
State Assemblyman Chris Holden (D), chairman of the Assembly Utilities and Energy Committee, has indicated he may introduce a bill as early as this week that would fix last year’s wildfire measure, SB 901, to allow PG&E to issues bonds to pay for wildfire damage. (See California Wildfire Bill Goes to Governor.) State Sen. Jerry Hill (D) has said he’s looking into a measure that would break up the state’s investor-owned utilities or make them public.
PG&E has become a prime suspect in the Camp Fire following its report to the California Public Utilities Commission of equipment failures near the fire’s ignition points. It potentially faces billions of dollars in liability for the fire that has killed at least 88 and destroyed the town of Paradise, Calif., population 27,000.
One question, Braun noted, is where Governor-elect Gavin Newsom stands on wildfire issues. “Little has been revealed,” Braun told the audience, but he said he expects Newsom to remain on a “similar trajectory” as outgoing Gov. Jerry Brown, who supported efforts to provide liability relief for PG&E.
Washington and Oregon
In Washington state, a ballot measure failed in November that would have placed a fee on the state’s carbon emissions, with the revenues used to fund environmental programs. I-1631 went down with 56% voting against it after a costly fight between petroleum interests and environmentalists. (See High Failure Rate for Western Ballot Measures.)
Lawmakers have shown little interest in trying to legislate a similar plan, said Therese Hampton, RIF chair and executive director of the Public Generating Pool, which represents 10 consumer-owned utilities in Washington and Oregon. Hampton briefed the RIF meeting Wednesday on Washington’s policy plans.
After November’s election, she said, Democrats will hold larger majorities in both houses of the State Legislature and are likely to pursue ambitious carbon-free energy goals. “We fully expect they will pursue a 100% clean-energy standard” like that adopted in California last year, Hampton said.
Elysia Treanor, with Portland General Electric, said Democrats in Oregon now hold a supermajority in both houses and Democratic Gov. Kate Brown will return to office. The coming legislative session will be six months long, giving lawmakers time to negotiate and possibly pass a cap-and-trade bill, she said.
A similar bill failed in 2018, when lawmakers met for only 35 days and didn’t have time to work out such a complex issue, she said.
“In [20]19, it’s now a priority,” Treanor told the RIF.
Arizona and Nevada
Clean-energy measures in the desert Southwest played out differently in 2018 and will likely do so again in 2019, panelists said.
In Arizona, voters overwhelmingly rejected Proposition 127 in November. The measure would have required the state’s power providers to generate at least half their annual electricity sales from renewable resources by 2030.
The race became a high-priced battle between competing interests. California billionaire Tom Steyer, whose environmental advocacy group NextGen America backed the proposal, and Arizona utilities, including Arizona Public Service, spent more than $50 million in the fight.
Nevada voters went the opposite direction from their Arizona neighbors by approving new renewable energy mandates in the form of Question 6 by a vote of 59% to 41%.
The measure, also backed by Steyer and NextGen, would amend the state constitution to require utilities that sell electricity to retail customers source at least 50% of their energy from renewables by 2030.
Constitutional amendments in Nevada must be voted on in two consecutive elections, so the ballot measure will be taken up again in 2020.
With regard to another ballot measure, Question 3, Nevadans allowed NV Energy to keep its electricity monopoly in the state by 67% to 33%.
The measure would have required the legislature to provide for the “establishment of an open, competitive retail electric energy market that prohibits the granting of monopolies and exclusive franchises for the generation of electricity.” It would have allowed customers to exit NV Energy and obtain electricity from others without paying an exit fee.
Las Vegas casinos, which have had to pay hefty exit fees, helped finance the measure.
Question 3 was approved by 72% of voters in 2016, when NV Energy didn’t contribute. But this time the utility, owned by billionaire Warren Buffett, reportedly spent $63 million to defeat the measure, while supporters doled out $21 million. That made it the most expensive ballot measure in state history, with a combined $100 million in contributions over two election cycles.
Question 3 supporters vowed to continue their efforts to let Nevadans choose their energy provider.
David Rubin, a senior attorney with NV Energy, told the RIF meeting audience that he wouldn’t be surprised to see that happen.
“It’s certainly possible those proponents of Question 3 will seek to revisit legislatively what failed on the initiative side” when the legislature reconvenes in February, Rubin said.
He said a major difference between Arizona and Nevada regarding renewable standards is that Nevada doesn’t have any nuclear generation, while Arizona is home to the nation’s largest nuclear power plant, the Palo Verde Generating Station.
Opponents of Prop. 127 in Arizona argued that passing the renewable standards ballot measure would have threatened the economic viability of Palo Verde. The opposition was led by Palo Verde co-owner APS, which spent millions to defeat the measure while arguing Arizonans could pursue clean energy plans that weren’t forced on them by a California billionaire.
“We’ve said throughout this campaign there is a better way to create a clean energy future for Arizona that is also affordable and reliable,” Donald Brandt, CEO of APS’ parent company Pinnacle West Capital, said after Prop. 127’s defeat.
“As the nation’s largest producer of reliable emission-free energy, Palo Verde is the anchor of Arizona’s clean energy future,” Brandt said. “Any serious plan to reduce carbon emissions has to include nuclear energy and Palo Verde.”
Where Arizona will go with those plans remains to be seen.
FERC last week approved the extension of most of CAISO’s proposals to address reliability concerns posed by the Aliso Canyon natural gas storage facility, whose capacity has been limited since a massive methane leak in 2015.
The Aliso Canyon gas storage facility was closed in October 2015 after inspectors discovered a massive methane leak. | California Department of Emergency Services
The commission’s Nov. 26 order approved extension of six of the seven Tariff provisions, rejecting the continuation of gas price scalars used to calculate commitment cost caps and default energy bids for generators served by Southern California Gas and San Diego Gas & Electric (ER18-2520).
CAISO asked FERC in September for expedited approval to renew Tariff provisions first put in place in June 2016 and subsequently refined and extended. CAISO’s most recent update, called Phase 4, proposed extending the temporary provisions for another year beyond their expiration dates of Nov. 30 and Dec. 16, 2018. (See CAISO Seeks to Extend Aliso Canyon Rules.)
The provisions include a measure allowing the ISO to enforce constraints on the maximum amount of natural gas that can be burned by generators served by the two gas providers. The constraints were based on limited supply anticipated by CAISO during specific hours.
The provisions also allow CAISO to suspend or limit the ability of scheduling coordinators to submit virtual bids if it’s determined virtual bidding could undermine reliability or grid operations.
The ISO’s Department of Market Monitoring did not support the extension of the price scalars, arguing that they have not been useful tools for managing high prices.
FERC agreed, writing that “CAISO’s use of the gas price scalars over the past year were not effective and adversely affected the market through weakened market power mitigation and increased bid cost recovery for the period that they were active.
“We find DMM’s analysis regarding the market impacts of the gas price scalars to be persuasive,” the commission said, declining to extend the provision.
The damage to Aliso Canyon, once the state’s largest natural gas reservoir, poses challenges to generators and regulators alike.
Despite objections from local residents and Los Angeles County officials, SoCalGas resumed injections into the facility in July 2017 to comply with a state directive to maintain sufficient gas inventories to support gas and electric reliability. (See Aliso Canyon Resumes Injections.)
The California Public Utilities Commission in May authorized a temporary increase in the volume of injections to support summer grid operations but maintained a policy of allowing withdrawals only as a last resort. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)
FERC last week rejected Baja California Power’s request to guarantee debt its parent company took on to purchase independent power producer InterGen’s Mexican assets (ES18-58).
Mexicali combined cycle plant | Saavi Energia
Baja Power owns and operates a 6-mile segment of a 12-mile, 230-kV line that connects generating facilities near Mexicali, Mexico, with CAISO at San Diego Gas & Electric’s Imperial Substation.
The company asked FERC for permission under Section 204 of the Federal Power Act to guarantee the debt Cometa Energia took on to acquire the InterGen assets, which includes six combined cycle generating plants totaling 2,420 MW. Cometa’s total debt for the purchases could exceed $1 billion, FERC said. Cometa is a subsidiary of Actis, a private equity firm based in the U.K.
Baja Power argued that it was the only one of Cometa’s 36 subsidiaries that hadn’t signed on as a guarantor, and that its guarantee of Cometa’s debt was in keeping with its performance as a public utility.
FPA Section 204 generally requires applicants to show that acting as a guarantor “will not impair [a public utility’s] ability to perform” as a public utility, the commission said.
“The commission typically bases its finding that proposed issuances of securities will not impair an applicant’s ability to perform service as a public utility in part upon the applicant’s demonstration that it will have an interest coverage ratio that is 2.0 or higher,” it said.
Baja Power did not submit an interest coverage ratio, however, “because Baja Power has no income,” FERC said. “Further, it did not submit any additional evidence that it would have the means to perform utility service if it is granted authorization to act as a subsidiary guarantor of its parent Cometa.
“The arguments presented by Baja Power indicate why a lender would find it desirable to have a subsidiary guarantor, such as Baja Power, step in to the shoes of the actual borrower, Cometa, but there is no demonstration that a guarantee by Baja Power is necessary or appropriate for, or consistent with, the proper performance by Baja Power of utility service and that a guarantee will not impair its ability to perform that service,” the commission concluded in denying the application.
California regulators will open a new phase of an investigation into Pacific Gas and Electric’s troubled safety practices as the utility faces allegations that its equipment was responsible last month for igniting the Camp Fire, by far the deadliest wildfire in the state’s history.
Aftermath of Camp Fire in Butte County, Calif. | California Governor’s Office of Emergency Services
Public Utilities Commission President Michael Picker announced the development Thursday after a turbulent start to what was meant to be a routine voting meeting. A group of raucous protesters briefly shut down proceedings before being removed from the commission’s San Francisco hearing room.
The first phase of the commission’s examination focused on the breakdown of safety practices leading to the September 2010 PG&E natural gas pipeline explosion that killed eight people and destroyed 38 homes in San Bruno. Picker said the next phase will look into the “corporate governance, [and] the structure and operation of PG&E to determine the best path forward for Northern California to receive safe, affordable, reliable electric and gas service.
Michael Picker | RTO Insider
“As I reviewed the [San Bruno] report, I found myself asking, ‘How can we do that better? What’s the role of the CPUC? How can PG&E actually pursue these duties and do it more safely? Is there a different model to ensure that we have safe and reliable gas and electric service?’” Picker said.
While the cause of the Camp Fire remains under investigation, PG&E filed a report with the CPUC on the day the fire started saying it had experienced an outage on a 115-kV line and observed damage to a transmission tower near the fire’s ignition point. At Thursday’s meeting, Picker said, “The details of the fire are still unfolding.”
Picker had signaled the move to expand the safety probe earlier in the month as the Camp Fire raged through Butte County in the northern part of the state. (See Destructive Fire Drives Down PG&E Stock.) Independent reports on prior deadly incidents criticized PG&E’s safety practices as “dysfunctional” or lacking clarity, he noted.
“This is the kind of thing that keeps me awake at night,” Picker said.
PG&E critics packed Thursday’s meeting, which featured an extended public comment period in which more than 30 residents spoke out against the company, urging the CPUC not to orchestrate a bailout. They pointed to Picker’s recent conference call in which he told Wall Street analysts that it would not be good public policy to allow the utility to go bankrupt. (See Camp Fire Prompts Talk of PG&E Bailout of Breakup.) Picker’s comments helped halt a sharp slide in the company’s share price, which had fallen by more than 62% in the course of a week.
Some speakers at the meeting aimed their anger directly at the CPUC — and Picker in particular.
“The commission’s disregard for the welfare of California has never been more blatant than when President Picker made a statement of the commission’s intent to rescue PG&E … while bodies from the Camp Fire were still being counted — and are still being counted,” said Barbara Stebbins of the California Alliance for Community Energy.
Picker defended his efforts to buttress PG&E, saying, “To operate the grid in a safe manner, PG&E has got to be able to sign contracts, borrow money, raise capital and sign contracts.”
A handful of speakers from Bay Area chapters of the Democratic Socialists of America called for PG&E to be converted into a publicly owned utility, blaming the company’s safety failures on its drive for profits.
Other speakers called for the arrest and prosecution of PG&E executives, who they said were ultimately culpable for the Camp Fire, which leveled the town of Paradise. At least 88 people died and nearly 200 area residents remain missing from the fire that began Nov. 8. Speakers also pointed to the 17 fires last year that investigators have already blamed on PG&E.
Janice Murota, a retired physician, told commissioners, “Not only do we not hold PG&E executives responsible personally for the deaths and the destruction, but we’re expected to bail them out financially. … Please don’t hold us on the hook to cover their liability and their costs. It’s just too much money.”
The public comment period concluded with several protesters unfurling a banner and chanting, “This meeting cannot continue until PG&E admits its crimes.” Picker at that point asked for a five-minute recess to allow protesters to chant before being cleared from the room. One protester could be heard yelling, “We’ll be back!” before exiting.
No ‘Firm Conclusions’
Once the dust settled, the CPUC voted to approve a decision requiring PG&E to adopt 60 safety recommendations laid out in an independent assessment of the utility’s “safety culture.” The CPUC commissioned the assessment by NorthStar Consulting Group in response to the San Bruno disaster.
In 2011, an independent review panel cited a “dysfunctional culture” at PG&E as the main factor contributing to the explosion. NorthStar noted that before the San Bruno incident, “the goals of [PG&E’s] enterprise risk management process were disconnected from the reality, decisions and actions throughout the company.”
While NorthStar credits PG&E for increasing its focus on safety, Picker noted the firm’s report found the company does not have a “clear vision” for its safety program.
Among the report’s “critical” recommendations to PG&E and the CPUC were:
Development of a comprehensive safety strategy, with associated timelines and deliverables, resource requirements and budgets, personnel qualifications, clear delineation of roles and responsibilities, action plans, assignment of responsibility for initiatives, and associated metrics to assess effectiveness.
Greater coordination among PG&E’s lines of business and its corporate safety department to increase consistency, improve efficiencies, minimize operational gaps and facilitate sharing of best practices.
A non-punitive system for reporting actual and potential safety incidents to the CPUC to encourage transparency and sharing of lessons learned among all California utilities.
Adding a performance-based ratemaking mechanism with a safety element to the PG&E general rate ruling approved last year, which runs through 2019.
Development of an implementation plan for NorthStar’s recommendations, to be submitted to the CPUC.
Picker acknowledged that the NorthStar report did not address the 2017/18 fires being attributed to PG&E.
“I don’t have any firm conclusions [about the fires]. That’s why we’re opening the next phase” of the investigation, Picker said.
He likened the CPUC’s response to PG&E’s situation — including efforts to maintain investor support — to remodeling an airplane in mid-flight: “We can’t just crash the plane to make it safer. We have to keep flying at the same time.
“I recognize the public’s growing interest in the future of PG&E, and while everything’s on the table, I want the public to understand that this is going to be a deliberative process and it involves actors other than the CPUC,” Picker said, noting the involvement of the California legislature, capital markets and a federal monitor appointed last year to oversee PG&E’s progress on safety measures.
“The NorthStar report had very specific recommendations but also raised some key fundamental questions,” Commissioner Liane Randolph said. “The fact that they were seeing differences in the effectiveness of the safety based on different parts of the company … just raises some key questions about the management of the company and how the safety culture is handled throughout the enterprise and whether it’s even possible to have all the enterprises have an equal amount of safety.”
Commissioner Clifford Rechtschaffen said it was important to reiterate the ambitions of a safety culture.
“It’s about promoting a mindset, practices and institutionalizing processes that promote and prioritize continuing, ongoing safety improvement. There’s no such thing as being good enough … [but] always looking for how can we do better, how can we make our processes safer — not just [by] meeting compliance but going beyond compliance.”
TO Rate Request Goes to Settlement
In its 2020 transmission owner rate case filed with FERC earlier this year, PG&E cited the financial challenges stemming from the “new normal” of California wildfires when it asked to raise its base return on equity to 12%. The increase would translate into a base transmission revenue requirement of $1.96 billion, compared with $1.79 billion for 2019, pushing up retail transmission rates by an average 9.5%.
In asking for the rate increase, PG&E contended that the wildfires and California’s doctrine of “inverse condemnation” pose financial risks “substantially different” from those faced by utilities in other states. As evidence, pointed to the downgrading of its credit rating as well as the $11.9 billion in losses for the company’s shareholders last year.
Several protesters opposed PG&E’s filing, arguing the utility improperly increased its ROE based on a misrepresentation of the wildfire risks. The protesters also noted that the legislature had introduced legislation (which later passed) to reduce PG&E’s wildfire liability.
FERC on Friday accepted PG&E’s proposed rates but suspended them for five months, ordering the issue to settlement judge procedures after finding the rates “may yield substantially excessive revenues” (ER19-13).
WASHINGTON — The Sierra Club, which has spent eight years battling utilities with its Beyond Coal campaign, would seem an unlikely participant in a program by the utilities’ trade group. But Sierra Club attorney Joe Halso was on stage at the Newseum on Friday, taking part in the Edison Electric Institute’s program celebrating the U.S. reaching its 1 millionth electric vehicle.
The Electric Power Research Institute predicted earlier this year that EVs and other electrification efforts could result in load growth of 24 to 52% by 2050. So, on this issue, environmentalists and utilities have common interests.
“There’s a role for utilities to play obviously in the electric [vehicle] future,” Halso said. “I think also in a world … with either flat or declining load growth, a strategic opportunity to electrify 250 million vehicles must look pretty good to utilities.”
Indeed it does. EEI CEO Tom Kuhn said the alignment of the morning’s speakers — representing consumers, automakers, policymakers, utilities and charging companies — is “incredibly exciting.”
“And so I think we’re here not just to celebrate this milestone of 1 million vehicles, but also to celebrate the collaboration that got us here,” Kuhn said. “I’ve always said the things that change a market … are technologies, public policies and customers. And we’ve got all three of them, finally.”
Amid the celebration — yes, there was a cake — there were also sobering reminders of both the importance of EVs to addressing climate change and the obstacles that could prevent the technology from meeting its potential. Here’s the highlights of what we heard.
Signs of Progress
Participants in Friday’s celebration cited numerous signs of progress in addition to the 1 million milestone:
General Motors is developing its autonomous vehicles on an “all-EV platform,” said Dan Turton, GM’s vice president for North American policy.
ChargePoint, which last week announced a $240 million equity infusion, has pledged to install 2.5 million charging spots by 2025, up from more than 57,000 today. The company has raised a total of more than $500 million from investors including American Electric Power, Chevron, Daimler, BMW and Siemens.
Charger network EVgo, which recently completed installing nine fast-charging stations in the I-95 corridor from D.C. to Boston in a partnership with Nissan, also won a contract in August to operate a network of hundreds of stations across Virginia. Julie Blunden, executive vice president of business development, said the company also will increase its charging network in California, its largest market, by 50% by mid-2019 over mid-2018. It currently has more than 1,000 fast chargers at 700 stations. (A DC fast charger can add 60 to 80 miles in 20 minutes.) Virginia will use $14 million from its portion of the Justice Department’s settlement with Volkswagen, which agreed to spend $2 billion on zero-emission vehicle infrastructure in the U.S. after admitting to cheating on diesel emissions tests.
Arshad Mansoor, EPRI’s senior vice president for research and development, predicted there will be 130 EV models available in five years, up from about two dozen today. BMW will be adding an all-electric Mini and sport utility vehicle, with plans for 25 EV models by 2025, said Bryan Jacobs, vice president of government and external affairs.
Regulators have approved $1 billion in utility investments in EV charging infrastructure. Halso said the amount is “a drop in the bucket” compared to what’s needed “but leaps and bounds from where we were five years ago.”
More than 130 companies and organizations have signed the transportation electrification accord negotiated by environmentalists and others. The agreement outlines ways transportation electrification can benefit “all utility customers and users of all forms of transportation, while supporting the evolution of a cleaner grid and stimulating innovation and competition for U.S. companies.”
Walmart installed chargers at 250 stores in 2018, nearly double the goal it had set, as part of its partnership with Electrify America, the unit VW set up to manage its settlement. It is now possible to drive an EV from Houston to Chicago using chargers at Walmart and Sam’s Club stores, said Sara Decker, the company’s director of federal government affairs.
The 1 million milestone would not have been reached without state ZEV programs, said Kathy Kinsey, senior policy adviser for Northeast States for Coordinated Air Use Management (NESCAUM), a group representing the air directors of New Jersey, New York and the six New England states. Until now, she said, states have made “ad hoc” investments in EVs and their infrastructure. But with the money from the VW settlement and utilities proposing infrastructure investments, “our states now have recognized the importance of thinking strategically and regionally,” she said.
The Stakes
Friday’s celebratory mood was tempered by the release a week earlier of the federal government’s Fourth National Climate Assessment, which declared that “the impacts of climate change are already being felt in communities across the country.” (See US Climate Report Spells out Coming Challenges.)
“We cannot continue to pretend that we can solve our climate crisis by only asking the power sector to do more,” said Rep. Paul Tonko (D-N.Y.), who noted that transportation has surpassed electric generation as the largest source of greenhouse gas emissions in the U.S.
Alan Oshima, CEO of Hawaiian Electric Co., said EVs are crucial to the state’s goal of 100% clean energy by 2045. He said the state needs to triple its rooftop solar capacity to meet the goal and that daytime EV charging is needed to absorb excess supply. While the state is fifth in per capita EV ownership, he said, it has only 8,000 EVs today.
Tonko acknowledged the limits of EV-boosting legislation possible in the new Congress, where Democrats will hold the majority in the House of Representatives while Republicans will increase their majority in the Senate.
“We need to focus on potential policy wins that might be considered singles and doubles,” said Tonko, who pledged to push the deployment of EV charging facilities in any infrastructure bill and to seek an extension of the federal EV tax credit.
President Trump threatened to eliminate tax credits for GM’s EVs after the company announced Nov. 26 it would close assembly plants in Ohio, Michigan, Maryland and Ontario. Although Trump lacks the power to take such action, “we pay a lot of attention to what any president says,” Turton told the EEI gathering. “But this EV movement is going forward regardless.”
Established in 2008, the tax credit provides $2,500 to $7,500 per new EV, depending on the size of the vehicle and its battery capacity. The full credit is available for the first 200,000 EVs per manufacturer, after which it begins to be phased out. Tesla has already hit the threshold, and GM is expected to reach it near the end of this year. In September, a group of Congressional Democrats introduced a proposal to eliminate the per-manufacturer cap and extend the credit for 10 years.
“I think that the evidence has shown that the biggest driver to future EV adoption will be the extension of the federal tax credit,” Tonko said. “We may disagree on what that tax credit may look like or how long we allow it to be in play, but I hope this is an area where the new House Democratic majority can focus next year.”
Fleet Electrification
EV proponents see big opportunities to electrify not only personal transportation but also shipping and buses.
Although Walmart’s Project Gigaton aims to reduce GHG emissions throughout the company’s supply chain, Decker acknowledged that electrifying its truck fleet is “probably just a white board exercise at this point.”
Electrification of school and transit bus fleets is on the way, however, said Eric McCarthy, senior vice president of government relations, public policy and legal affairs for electric bus maker Proterra. McCarthy said incentives to make the switch are being provided by the VW settlement, the Federal Transit Administration, and voucher programs in states including Maryland and New York.
McCarthy said his company no longer has to convince transit agencies to “experiment” with EVs, which he said are well suited to fleet use because of buses’ combination of high mileage, low fuel economy and predictable travel routes. Now, he said, the company is focusing on its relations with utilities and educating state regulators.
Because transit agencies have limited capital budgets, Proterra has begun leasing its batteries, with the original equipment manufacturers taking the operating risk, McCarthy said. “It was authorized by the [2015 Fixing America’s Surface Transportation Act] and many of our customers are taking advantage of that,” he said.
Proterra has buses operating or planned in locations including Georgia, Edmonton, D.C. and Baltimore (in partnership with Exelon unit Baltimore Gas and Electric). On Oct. 30, the company unveiled an electric school bus it is producing with Thomas Built Buses, a subsidiary of Daimler Trucks North America, which has also invested in Proterra.
The California Air Resources Board is expected to rule in January on a proposal requiring all transit agencies in the state to transition to ZEV fleets. “If that happens, and then we see other states adopt that as a model, I think you’re going to see this really take off in five years,” McCarthy said.
EVgo’s Blunden also sees fleets making a swift change.
“If there is one thing that has shocked me this year, it is how fast corporate fleet owners and operators are thinking about moving to electrification. It is going to make your head spin,” she said. “This reminds me very much of 2008 in the solar industry, where we had the very first … utility-scale solar plants. Four years later, utility [solar] was larger than residential.”
R&D
For GM, EVs represented only 1.5% of total sales in 2017, and none of them was a pickup truck or SUV, which have gained market share at the expense of sedans. GM’s Turton said electrifying those heavier vehicles is part of the company’s “all-electric future.”
“It’s going to take the next generation of batteries, the generation after that, to be able to advance the R&D … to be able to have better, more cost-efficient batteries that can do this with the longer range that’s necessary,” he said.
Alex Fitzsimmons, chief of staff for the Department of Energy’s Office of Energy Efficiency and Renewable Energy, said his agency has three R&D goals for EVs: reducing battery costs (currently more than $200/kWh) to less than $100/kWh; expanding their range to 300 miles (the second generation Nissan Leaf has a range of 151 miles); and completing a full charge within 15 minutes.
Consumer Ignorance
Speakers said the biggest obstacle to wider EV penetration, however, is not technology but consumer ignorance.
“It’s troublesome how little progress we’ve made in the last five years in consumer education,” NESCAUM’s Kinsey said.
“A lot of consumers still think that EVs drive like a golf cart,” lamented Michael Arbuckle, senior manager of EV sales and marketing strategy for Nissan, which has sold 365,000 electric Leafs worldwide. “They also think that they’re not affordable — they’re wrong. We know that EVs also have acceleration that’s exciting. They’re fun to drive. They’re great vehicles to drive.”
Southern California Edison’s service territory claims 200,000 EV owners — one-fifth of the U.S. total. Yet less than half of Californians know what an EV is, said Phil Jones, executive director of the Alliance for Transportation Electrification. Jones also noted that the U.S. remains far behind China, which has accounted for about 37% of passenger EV sales since 2011 and about 99% of e-buses. The city of Shenzhen last year converted all of its 16,359 buses to electric.
Joel Levin, executive director of Plug In America, which represents EV drivers, said few auto salespeople are familiar enough with EVs to answer prospective buyers’ questions. “With a gas car, the dealer never has to answer questions like, ‘So, where do I get gasoline?’” he said.
Levin said consumers’ cost comparisons need to switch from sticker prices — at which EVs are a disadvantage — to total cost of ownership, which includes their lower fuel and repair costs.
Auto dealers generally earn more money from repairs than vehicle sales, a potential disincentive to promoting EVs, which have far fewer moving parts than vehicles with internal combustion engines. But Levin insisted that hurdle can be overcome. “There’s other pieces of the value chain that they can capture,” he said, citing rooftop solar sales and installing home chargers.
Multifamily Housing Challenge
Another obstacle to wider penetration is how those lacking individual garages can charge at home.
Multifamily housing remains a hurdle even in SCE’s territory, said Jill Anderson, vice president of customer programs and services.
Anderson said the utility intended to include multifamily housing in its first big launch of light-duty chargers, in part to address concerns that low- and moderate-income residents could be shut out of the transition.
“And that’s the area where we had the most difficulty,” she said. “I think only three or four sites were successful in multifamily charging. So it’s an area we have to think about differently. We might have to think about the utility doing more soup-to-nuts solutions for multifamily. It’s an area that’s going to be important.”
New York state is attempting to increase multifamily penetration by offering rebates on Level 2 chargers (240-V AC units that add up to 20 mph of charging) to apartment buildings in addition to office buildings and public and commercial locations, Rep. Tonko said. The state also is offering grants for DC fast chargers for cities, transportation corridors and hubs such as airports.
“It is my belief that the federal government can encourage similar investments, and we should ensure that charging is open to public access, interoperable and that the recipients of this funding are required to maintain the equipment,” Tonko said. “Without this type of concerted push, we are going to have many of the same problems and split incentives that we see on consumer-side energy efficiency, where building owners might not see the benefit of making efficiency investments on their tenants’ behalf. We can’t shut these potential consumers out of the EV market.”
Dave Packard, vice president of utility solutions for ChargePoint, said his company is working with competing charging networks to create a “seamless driving experience” that ensures drivers know where to charge and how much it will cost. “I think we have to take a lesson from the cellphone industry,” he said. “Those of you that remember in the early days when you roamed you had to call [through a different provider]. It was just a nightmare.”
Projections
EEI ended the event Friday with the release of a report projecting the U.S. will hit the 2 million EV mark by early 2021 and total 18.7 million by 2030. By then, annual sales would exceed 3.5 million, 20% of total car and light truck sales, EEI said. The report says the U.S. will need an additional 9.6 million charge ports to meet the 2030 projections. There are currently about 45,000 public Level 2 charging ports and 9,000 DC fast-charging ports, the report said.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees 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 in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report. NOTE: The meeting will be held at the DoubleTree by Hilton Hotel Downtown Wilmington instead of the Chase Center.
Markets and Reliability Committee
1. PJM Manuals (9:15-9:45)
Members will be asked to endorse the following proposed manual changes:
A. Manual 03: Transmission Operations. Revisions developed to update the generator voltage schedule with new processes that require transmission owners to verify and submit voltage schedules via eDART, generation owners to review the schedules and the eDART contact to acknowledge the schedule. This will all need to be done annually. (See “Generator Voltage Schedule,” PJM Operating Committee Briefs: Nov. 6, 2018.)
B. Manual 10: Pre-Scheduling Operations. Revisions developed as part of a periodic cover-to-cover review.
2. PRD Review for Capacity Performance Requirements (9:45-10:05)
Members will be asked to endorse at least one of several proposals developed by the Demand Response Subcommittee to address changes to price-responsive demand required for the Capacity Performance construct. The question is whether PRD should be required to reduce load in the winter like other CP resources. (See “Summer-only Demand Response,” PJM MRC/MC Briefs: Oct. 25, 2018.)
3. 2019 DASR Requirement (10:05-10:20)
Members will be asked to endorse proposed revisions to the day-ahead scheduling reserve for 2019. The 2019 calculation of 5.29% is a 0.01-point increase from the 2018 requirement. (See “Day-ahead Scheduling Reserve Recommendation,” PJM Operating Committee Briefs: Nov. 6, 2018.)
4. Surety Bonds (10:20-10:40)
Members will be asked to endorse at least one of two stakeholder proposals developed at the Credit Subcommittee related to allowing use of surety bonds as an acceptable form of collateral. (See “Surety Bond Use,” PJM Market Implementation Committee Briefs: Oct. 10, 2018.)
5. Gas Pipeline Contingencies (10:40-11:05)
Members will be asked to endorse a proposal endorsed by the Market Implementation Committee around gas pipeline contingencies. The proposal, originally developed by Calpine, would provide a broader scope of factors and time for which a unit can recover costs during and after a PJM fuel-switch directive. (See “Gas Pipeline Contingencies,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)
Members will be asked to endorse proposed Tariff revisions to remove an apparent overlapping credit reduction provision for qualified transmission upgrades, to clarify milestone documentation requirements for internally financed projects and to clarify that capacity market sellers should submit requests for reductions.
2. PRD Review for Capacity Performance Requirements (1:45-2:05)
Members will be asked to endorse proposed Operating Agreement and Tariff revisions related to CP changes required for PRD. (See MRC item 2 above).
3. Gas Pipeline Contingencies (2:05-2:25)
Members will be asked to endorse proposed OA and Tariff revisions related to gas pipeline contingencies. (See MRC item 5 above).
4. Elections (2:25-2:35)
Members will be asked to elect members of the 2018-2019 Finance Committee, the 2019 sector whips and the 2019 MC vice chair.
FERC last week accepted MISO’s revised cost allocation proposal for the RTO’s relatively new category of smaller interregional transmission projects with PJM.
The new cost allocation affects targeted market efficiency projects (TMEPs) between MISO and PJM and became effective Nov. 28 (ER18-2514). MISO made the allocation revisions as part of a larger update to its cost allocation as the five-year Entergy transition period — which limits cost sharing of transmission projects in MISO South — expires at the end of this month.
2018 TMEPs | MISO
The RTO’s share of TMEP costs is currently allocated to transmission pricing zones based on each zone’s share of the relative positive congestion contribution, measured by the TMEP candidate study. (See FERC OKs MISO TMEP Cost Recovery Schedule.)
MISO made three complex changes to its cost-sharing formula while still preserving the premise that TMEP costs flow to benefiting transmission pricing zones.
The RTO had been calculating TMEP benefits by using a calculation of the nodal congestion contribution for each load node. Now it will include generator nodes in determining congestion benefits, rather than considering only load nodes. The two nodes will be aggregated to calculate the net benefits of the upgrade to each transmission pricing zone.
MISO will also discontinue its practice of applying the formula to all five-minute dispatches in the real-time market. The formula will now apply only to hours in the day-ahead market in which a reciprocal coordinated flowgate will experience congestion.
FERC said MISO’s proposal will simplify the TMEP cost allocation process.
“We find that the proposed revisions will better define the beneficiaries of avoided congestion as well as allocate the costs of TMEP upgrades more accurately, while removing undue complexities from the calculation of benefits,” FERC said.
The calculation will not account for the contract path on SPP’s transmission that connects MISO Midwest with South. Regulators in South had called for a stakeholder process to determine the impacts of the contract path on cost allocation.
But MISO said an analysis showed accounting for the contract path “indicated minimal change to the cost allocation.”
MISO and PJM have so far recommended seven TMEPs, five that received approval in 2017 and two up for approval this month from the RTOs’ respective boards of directors. The combined projects will cost under $25 million and are expected to reap about $132 million in benefits. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)
Roughly a year into the discussion and months past the deadline requested by PJM’s Board of Managers, details of potential changes to the RTO’s energy market remain anyone’s guess.
At Wednesday’s meeting of the Energy Price Formation Senior Task Force (EPFSTF), PJM reintroduced a substantially altered proposal for revising its operating reserve demand curve (ORDC), and both the RTO and its Independent Market Monitor revised their proposals for the allowable synchronized reserve offer margin adder. A new proposal submitted by the D.C. Office of the People’s Counsel would largely maintain the current two-step curve but include some revision details from proposals by both PJM and the Monitor. (See Skepticism Lingers Around PJM Price Formation Goals.)
PJM revised its ORDC proposal to account for the impact of units’ regulation requirements, shifting its proposed curve to the left and more in line with the current two-step ORDC for synchronized reserves. The current curve escalates from $0/MWh to $300/MWh at 1,590 MW, and the new one escalates gradually from $0/MWh at roughly 2,750 MW to $265/MWh at 1,575 MW. PJM’s original proposed revisions began escalating from $0/MWh at roughly 3,500 MW and reached $265/MWh at 2,100 MW. The revised proposal means that the value of synchronized reserve megawatts will be less until the reserve drops to the minimum reserve requirement (MRR), which remains $850/MWh.
PJM also revised its proposed margin adder down substantially. The current adder is $7.50/MWh, but PJM said the calculation should instead be based on the expected value of the penalty resources pay if they receive a synchronized reserve obligation and fail to perform during an event. For 2017, that value was 1 cent/MWh, and so far in 2018 it’s been 2 cents/MWh. Rather than setting it at $0, PJM argued that it should be allowed to change as clearing prices change.
The Monitor’s revised ORDC proposal includes a temporal concept meant to factor in the expected cost of a unit commitment to maintain the reserve requirement in the future. Instead of happening over 30 minutes to provide reserves necessary for 10 minutes in the future, as PJM has proposed, the Monitor’s proposal would look forward until the next expected demand peak based on historical load patterns.
The resulting curves have seasonal variations but rarely extend past $60/MWh before hitting the MRR.
The Monitor revised its adder proposal from a “compromise” of $3.80/MWh — which it now finds “unjustified” — to $0/MWh and recommended that penalties should extend back to the last reserve event when the resource performed to its full obligation but no longer than 12 months.
The Monitor also added a new option to the matrix that would include the changes to the synchronized reserve market but reserve the discussion on the ORDC to the second stage of EPFSTF, including discussion of the relationship between the day-ahead reserve products and real-time reserve products.
Stakeholder Reaction
Stakeholders appeared unconvinced by either proposal. Carl Johnson, representing the PJM Public Power Coalition, said the measuring stick for whether the RTO’s proposal is successful should be its impact on uplift payments.
“If uplift doesn’t go away, we’ve got a problem,” he said.
PJM’s Adam Keech agreed, saying, “I think zero uplift is a good target.”
The Monitor disagreed, however. Monitor Joe Bowring noted several market mechanisms that create uplift that aren’t addressed in the proposal.
“We think some uplift is necessary,” Monitor staffer Catherine Tyler said.
PJM and the Monitor also disagreed with some stakeholders over what the overall goal of the changes should be.
“The goal isn’t to have the lowest prices possible,” Keech said. “The goal is to reflect what the system operators are doing. We’re trying to drive to prices that reflect the system operators’ needs.”
Bowring said the “objective of markets is to have the lowest prices possible for the defined product, but no lower.”
Stakeholders and PJM staff questioned whether the Monitor’s ORDC proposal was more about addressing scheduling issues than generation scarcity.
“This is compensating to some extent for the lack of scheduling tools,” Tyler acknowledged. “However, what we do see in the market now is an operator looking ahead and seeing a need for reserves in the future, and we don’t have a market tool to address that.”
Vote Delayed
PJM’s Dave Anders, who is facilitating the task force, summed up the day by quashing any question about whether stakeholders may be ready to decide.
“It’s been a fluid situation with respect to proposals. I don’t know that we’re ready to vote,” he said, noting that PJM staff will update the board at its meeting this week.
Bowring pointed out that if the initial vote had happened when PJM had initially requested the vote, its proposed demand curve would have been substantially higher than with its revised ORDC presented for the first time at this meeting.
While no one questioned the decision, stakeholders differed on whether a vote should come sooner or later. Some expressed concern that further delay risks the board deciding to approve revisions without waiting for stakeholders’ advice.
Stakeholders have already missed the board’s request to receive stakeholder endorsement for some changes by the third quarter, which could have already allowed for FERC approval and implementation for this winter. (See PJM Board Seeks Reserve Pricing Changes for Winter.)
