RENSSELAER, N.Y. — NYISO on Monday recommended its carbon pricing proposal no longer include a mechanism that would make emissions-free resources with existing renewable energy credit contracts pay the LBMP carbon component.
The ISO’s clawback proposal “creates a distortion in the market … that places the ISO in the position of picking winners and losers, which is not where we want to be,” Michael DeSocio, the ISO’s senior manager for market design, told the Integrating Public Policy Task Force (IPPTF) on Monday. (See NY Carbon Task Force Looks at REC, EAS Impacts.) The ISO initially proposed the idea to reduce the potential for REC resources to receive double payments for their lack of emissions.
DeSocio noted REC payments are not solely linked to carbon abatement or avoidance but are primarily intended to support renewable resources. Withholding the LBMPc from resources with existing RECs would increase the uncertainty in the value and potential cost of such contracts going forward and also create a disconnect between the wholesale market price and payment to the resource, he said.
Double Payment Issue
Multiple stakeholders expressed concern about the potential for double payments, with ratepayers paying for both REC contracts and an unforeseen bonus or windfall for holders of such contracts that pre-date the existence of a carbon charge.
“As much as there could be a concern with costs … we don’t view this as a problem with the design,” DeSocio said. He estimated the possibility for between $30 million and $60 million in such payments in an overall program representing a few billion dollars, whether through the state’s Clean Energy Standard alone or with carbon pricing.
The $60 million estimate is an upper bound of any double payment, said Sam Newell of the Brattle Group.
One of the motivations for RECs “was to develop a new way of getting energy… So did you pay a little extra to help pave the way for the much larger amounts of clean energy the state plans to procure? Maybe. That was part of the purpose,” Newell said.
Newell also pointed out carbon pricing was being contemplated at the time some of the existing REC contracts were signed. “To what extent did the REC prices get discounted accordingly? Were they willing to take a little bit lower price in a competitive process because they saw some upside from some future carbon prices?”
“It’s not very accurate to just blithely call it a double-payment issue,” said Warren Myers, director of market and regulatory economics at New York’s Department of Public Service. “We’ve heard from a lot of parties about what they have to go through to get financing and the hedges they sign, so to say that generators are going to get double paid is a misstatement … What the ISO proposed, while well-intentioned, was a remedy that was worse than the malady.” (See NY Task Force Talks LBMPc, Residuals, Hedge Effects.)
Brattle Updates
Newell presented the task force with updated analyses on carbon price effects, including the outcome if NYISO’s AC transmission project in western New York — the two components for which are now before the ISO’s board — does not get built by 2024 as the study projected.
Effects of a carbon charge on wholesale energy prices | Brattle Group
The study assumes the projects would be built by 2023 to provide 350 MW of increased transfer capability across the Central East interface, while they could actually provide as much 875 MW of increased transfer capability, he said.
“So what would happen if these projects weren’t there at all?” Newell asked. “Then you would just see a little more bottling in upstate and less LBMP upstate from a carbon charge, and the opposite downstate … If you get the full 875-MW increase in transfer capability, the state would be a little more uniform than we modeled with only a 350-MW increase on Central East.”
2022 Scenario
While the study motivation and scope remain unchanged, “we also did the updated [modeling and pricing software] runs to look at a 2022 scenario, as requested by stakeholders, and to look at what the market would look like if a carbon charge was implemented,” Newell said.
Brattle’s analysis continues to show minimal retail price impacts from a carbon charge, with the strongest impact in 2022 — the year of implementation, when consumer bills are projected to increase by 1.6%, mainly due to the retirement of Indian Point nuclear plant coupled with no AC transmission upgrades in service and a doubling of renewables upstate.
The biggest observation is relative to both the retail rate and the generation component of the rate, Newell said.
“If you look at the graph, it’s visually not far off the zero point, so that’s the main conclusion, with a little bit of a trend over time towards more benefit,” he said.
However, wholesale prices are expected to register their largest carbon cost impact — $17.60/MWh — in 2025, with an estimated carbon charge of $49/ton.
Summary of Modeled 2022 Scenario | Brattle Group
Nuclear Retention
Brattle also revised its projections of the retention of nuclear generation in 2030, increasing its assumption from 450 MW to about 850 MW of the 3,300 MW of upstate capacity.
The Public Service Commission approved the zero-emission credit program in 2015 to prevent the premature retirements of three New York nuclear power plants, Exelon’s FitzPatrick, Ginna and Nine Mile Point. (See Appeals Court Upholds NY Nuclear Subsidies.)
Newell said a carbon charge could boost the net revenues for upstate nukes and prompt owners of units in good physical condition to apply for license extensions.
The study assumes Nine Mile Unit 2 will remain under any case, while it considers the other three units to be at risk of retirement.
“You can see that there’s a fairly good case for some likelihood of retaining some of these plants,” he said.
Why Price Carbon?
Why even do carbon pricing, Newell asked.
“I really see two closely related reasons. One that we’ve talked about a lot is that you provide a price signal that directly signals to the market how to operate in such a way that cost-effectively reduces carbon and how to invest in such a way… where you avoid the most emissions, that’s where the biggest rewards go,” he explained.
Another major factor — harmonizing state policies and wholesale markets — has not been emphasized enough, Newell said.
“I’m talking about this from the perspective of somebody who works nationally and is seeing a lot of conflict on these issues,” Newell said. “And [I’m] seeing an opportunity for New York ISO and New York state to address this issue more successfully than the rest of the country and to be a leader in this regard.”
The IPPTF will next meet on Dec. 17 at NYISO headquarters to consider the final draft carbon proposal, which will be posted by Dec. 7.
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.
ERCOT’s Technical Advisory Committee last week endorsed a staff suggestion to increase by 50% the boundary thresholds used to project future loads in Far West Texas.
During the committee’s last meeting of 2018, stakeholders unanimously approved the recommendation, which, assuming Board of Directors approval, raises the Far West weather zone’s boundary threshold from 5% to 7.5%.
The change would allow ERCOT to nearly double the Far West load from its current 3.6 GW to 6.9 GW in 2027, and support 500 MW of growth for 2019-2021 without supporting documentation. The growth has been fueled by the Permian Basin’s rich petroleum reserves, the largest in the U.S. Production has nearly doubled in the last three years, to 3.4 million barrels/day.
Staff said it has been challenged in keeping up with the load growth. The grid operator adjusted its 2019 forecast by 200 MW to keep up with the rapidly increasing demand, and it foresees about a 500-MW increase over the 2018 summer peak (consistent with a similar increase as compared to 2017).
“We’ve understated the Far West load the last two cycles,” said ERCOT’s Calvin Opheim, manager of load forecasting and analysis. He told the TAC the ultimate goal is to produce more realistic projections.
Permian production has been hampered recently by a lack of sufficient pipeline infrastructure. Falling oil prices have also made production less economical, leading some stakeholders to question the need to increase forecasts.
“Our concern is whether [the suggested change to the forecast process] results in building transmission for speculative load,” Golden Spread Electric Cooperative’s Mike Wise said. He referenced a recent ERCOT regional transmission study that forecasted increased load based on rising oil prices.
“We thought all this load was coming on, but approximately 80% was canceled,” Wise said. “You’ve got these loads out there, but we don’t want to build unnecessary transmission. I’m concerned about building transmission ahead of speculative load, then having a V8 moment later on when the load does not materialize.”
“We have a tremendous amount of holes punched in the ground,” Morgan Stanley’s Clayton Greer said of the Permian Basin region. “The capital’s been expended, but there’s no way to get it to market. When production increases, there’ll be a dramatic increase in load. They wouldn’t be punching holes if they were speculative. The holes are in the ground, and extraction is going to happen.”
ERCOT Senior Manager of Transmission Planning Jeff Billo said the grid operator will conclude a major load study next June that could predict “the next piece of infrastructure we need.”
Reliant Energy Retail Services’ Bill Barnes noted that a two-year revision to the planning guide (PGRR042) gives staff flexibility while establishing a methodology for setting their load forecasts.
“Having ERCOT understand load growth is a good thing,” Barnes said.
Stakeholders Tweak Ancillary Service Methodology
Stakeholders endorsed staff’s recommendation to not change how ERCOT computes regulation and responsive reserve service as part of its 2019 ancillary service methodology, after first removing a 1,375-MW floor on non-spin quantities during peak hours.
The Wholesale Market Subcommittee and Reliability and Operations Subcommittee (ROS) have both suggested removing the floor during the hours ending 7 a.m. through 10 a.m. The Lower Colorado River Authority and Luminant were among the TAC members asking that the floor be maintained, saying it would provide more reliability insurance with the growth of volatile wind generation.
However, a motion to remove the floor passed with 71% of a roll call vote. The committee then endorsed staff’s recommendation, with two abstentions.
“I’m a little amazed we’re trying to preserve a floor that’s not necessary and that’s just increasing costs for no good reason,” Greer said. “I thought the goal the last couple of years was to get rid of artificial floors and artificial inefficiencies in our market, and to try and do things in a more analytical way.”
Sandip Sharma, ERCOT’s manager of operations planning, said the 1,375-MW floor has been in place since the nodal market went live in 2010. The grid operator removed a 2,000-MW cap on non-spin reserves in 2016 but left the floor unchanged.
“If you look at the numbers with and without the floor, it’s really not a big difference,” Sharma said, noting the number can be as high as 200 MW across summer peak hours. “Most of the other months, where there’s a higher risk of wind forecast error and net load ramp variability, we’re actually procuring more than what the floor is.”
Citigroup Energy’s Eric Goff said that during the summer months, non-spin deployment “generally” means generating units are turned on and made available for security-constrained economic dispatch (SCED) at a price floor.
“In the summer, when we do have [non-spin deployment] below the floor, we see this generation offered into SCED at a different cost than it normally would,” Goff said. “So it has nothing to do with reliability at all.”
TAC Confirms New ROS Leadership
Stakeholders confirmed new leadership for the ROS, which develops, reviews and maintains operating guides and planning criteria.
Tenaska’s Boone Staples was approved as the ROS chair, and Southern Power’s Tim Hall as vice chair.
Stakeholders Take on 31 Change Requests
Having not met since September and facing a year-end deadline to push through change requests, the committee considered 31 proposed Nodal Protocol revision requests (NPRRs) and other changes.
The TAC approved NPRR889, which adds the newly defined term “settlement-only generator” to replace “non-modeled generator,” after making several desktop changes. Stakeholders modified the definition of “settlement-only transmission generator” to include those units connected to the system with a rating of 10 MW or less and registered with the Texas Public Utility Commission as a “power generation company.”
The NPRR introduces new terms to clarify the distinction between transmission-connected resources and distribution-connected resources, and reorganizes various terms for resources that describe the status, services provided and/or technology used by resources.
Stakeholders agreed to table two other revision requests for a month and allow their further consideration. South Texas Electric Cooperative’s Clif Lange asked for more time to “discuss internally” with staff the co-op’s reliability concerns about NPRR871. The proposed change addresses the review process for transmission projects funded by customers or resource entities, using language pulled from NPRR837’s initial filing to allow for a standalone review. NPRR837 was approved in July.
The committee also tabled NPRR850, referring the proposal to the Credit Work Group and Market Settlements Working Group. The change would lay out principles for staff and market participants to follow during a market suspension and restart, and specifies how settlements will occur during a suspension.
The TAC approved 14 other NPRRs, a Load Profiling Guide revision request (LPGRR), two changes to the Nodal Operating Guide (NOGRRs), three Other Binding Document revisions (OBDRRs), four changes to the Planning Guide (PGRRs), a Retail Market Guide change (RMGRR), two revisions to the Resource Registration Glossary (RRGRR) and a system change request (SCR):
NPRR878: Prescribes ERCOT’s posting of an emergency response service obligation report for transmission and/or distribution service providers to the market information system certified area.
NPRR879: Proposes that intermittent renewable resources (IRRs) carrying ancillary service (AS) responsibilities receive a SCED base point calculated using the resource’s five-minute intra-hour forecast and adds generation resource energy deployment performance metrics to score performance during those intervals. The change corrects the unit of measure for some billing determinants and also contains administrative edits.
NPRR881: Reduces the residential validations requirements from an annual process to a triennial market event.
NPRR882: Updates the definition of initial synchronization and interconnecting entity to include certain types of facility equipment changes and clarifies fee language related to generation interconnection or change requests (GINRs).
NPRR884: Introduces various systems changes needed to manage cases when ERCOT issues a reliability unit commitment instruction to a combined cycle generation resource that is already qualified scheduling entity-committed for an hour. The resource will operate in a configuration with greater capacity for that same hour.
NPRR887: Creates a new market information system certified area posting that provides insight into the potential risk associated with each counterparty’s default uplift charges.
NPRR892: Places a $75/MWh floor on energy on units carrying non-spinning and responsive reserves and/or regulation-up service concurrently to ensure the non-spin capacity is priced above the floor.
NPRR893: Clarifies the effective fuel index price (FIP) used in market activities executed prior to the operating day’s index publication because the current FIP definition does not address the timing around receiving the data and when it can feasibly be used by market applications. The NPRR also incorporates the OBD “System-Wide Offer Cap and Scarcity Pricing Mechanism Methodology” into the Protocols.
NPRR894: Corrects the formula for allocating unaccounted for energy (UFE) to UFE categories by removing its obsolete components referring to distribution voltage level non-opt-in entities.
NPRR895: Removes the current exclusion for IRRs that are not wind-powered generation resources in calculating the real-time AS imbalance payment or charge. Photovoltaic generation resources (PVGRs) are currently excluded in both the methodology for implementing the operating reserve demand curve (ORDC) to calculate the real-time reserve price adder and the process for settling the real-time AS imbalance payment or charge.
NPRR897: Adjusts the black start service procurement and testing process timeline, adds a weather limitation disclosure form and aligns the load-carrying test procedure with actual practice.
NPRR898: Allows the electronic return of ERCOT-polled settlement metering site certification documents to the transmission and/or distribution service provider.
NPRR899: Creates a new process by which qualified market participants can request to opt out of receiving digital certificates and having to appoint a user security administrator (USA); clarifies ambiguous requirements certificate holders must meet to receive and continue to hold digital certificates; and clarifies that a USA may be responsible for managing access to certain ERCOT computer systems that do not require digital certificates. The NPRR also revises forms to give new applicants the ability to opt out of receiving digital certificates as long as they meet the necessary qualifications. Allows a qualified market participant that has previously opted out to opt back in.
NPRR901: Proposes a new resource status code (“EMRSWGR”) for switchable generation resources operating in a non-ERCOT control area to provide additional transparency for operations and reporting.
LPGRR065: Related to NPRR881, this change reduces the residential validations requirements from an annual process to a triennial market event and removes unnecessary load profile model approval process language.
NOGRR178: Clarifies language relating to automatic load shedding.
NOGRR182: Harmonizes the transmission operator emergency operations plan submittals with NERC Reliability Standard EOP-011-1 by clarifying that TOP plans should be received by Feb. 15 as part of the annual effort to review them within 30 days.
OBDRR006: Aligns language with NPRR884’s protocol changes.
OBDRR007: Changes the ORDC’s methodology to consider curtailed PVGRs in determining the ORDC price adders.
OBDRR009: Revises the online and offline capacity reserves for ERCOT out-of-market actions related to DC ties.
PGRR065: Documents and clarifies existing processes by including transmission project information and tracking report and data requirements.
PGRR066: Creates an inactive status for GINR projects that won’t be listed in ERCOT’s monthly generation interconnection status report but will retain the interconnection request numbers. The PGRR also defines a process that can be used to cancel interconnection requests that have failed to meet requirements.
PGRR067: Describes how wind and solar facility equipment changes are treated throughout the generation interconnection process and clarifies language for GINR-related fees.
PGRR068: Lays out the process for adding a DC tie to ERCOT’s planning models and associated requirements, related to the Texas PUC’s directive to determine how best to model the proposed Southern Cross DC tie in its planning cases (Project 46304). (See “Staff’s Determination on DC Tie Flows, Pricing Gets OK,” ERCOT Board of Directors Briefs: Oct. 9, 2018.)
RMGRR155: Related to NPRR889, the change uses the new term settlement-only distribution generator (SOG) to replace references to non-modeled generator and registered distributed generation.
RRGRR018: Also related to NPRR889, uses the SOG term to replace glossary references to non-modeled generator.
RRGRR019: Adds a modeling designation for switchable generation resources (SWGRs) to the resource asset registration form, indicating that SWGRs can potentially operate in another control area.
SCR797: Allows ERCOT to automatically share current operating plans with a transmission service provider (TSP) upon request by that TSP.
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.
