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November 20, 2024

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Stanford Webinar Explores Fate of Junked Gas Appliances

As more homeowners switch from natural gas to electric appliances, environmental researchers are thinking more about the fate of discarded gas appliances, speakers said at a Stanford University webinar.

“What happens to the old appliances?” said Chris Field, director of the Woods Institute for the Environment at Stanford, who moderated the session. “Are we just going to get a secondary market in junky gas appliances as a consequence of the push for electrification?” Field was relaying a question from a webinar listener.

Rob Jackson, a professor of Earth system science and a senior fellow at the Woods Institute, said that’s a question he’s been hearing a lot recently.

“If we just dump a bunch of gas appliances on the market and lower their cost, then we’ll make it more likely they’re used,” Jackson said. “I don’t know what the best approach for that is.”

Stephanie Greene, managing director of carbon-free buildings at the Rocky Mountain Institute, said incentives may be needed to address the issue of used gas appliances.

“Maybe not cash for clunkers per se, but some level of incentivizing, getting these older appliances out of the market entirely, is likely the right solution,” Greene said.

The webinar, which the Woods Institute hosted on Jan. 26, focused on electrification of the building sector. The idea behind building electrification is to phase out carbon dioxide emitting gas appliances, such as gas stoves, furnaces and water heaters, and instead use electric appliances, which may be fueled by clean energy.

Greene said that electrifying new buildings makes economic sense and will also help contractors, builders and the market in general get used to the electric technology. At the same time, homeowners should be offered incentives to replace gas appliances with electric when the gas appliances reach the end of their useful lives, she said.

When it comes to replacing gas appliances before the end of their useful lives, the decision depends on whether a homeowner has the financial means and wants to be at the forefront of new technology, Greene and other panelists said.

Methane Leakage Studied

Gas appliances contribute to GHG emissions in a couple of ways. The combustion of methane, the main component of natural gas, produces carbon dioxide. In addition, the appliances may leak methane, which is a potent greenhouse gas.

And methane leakage from gas stoves may be substantial, says new research from Jackson and colleagues at Stanford. The findings were published this week in the journal Environmental Science & Technology.

The study, which measured emissions from natural gas stoves in 53 California homes, found that up to 1.3% of the gas used by the stoves was emitted as unburned methane. More than three-quarters of those methane emissions occurred while stoves were turned off, suggesting the presence of leaks.

Another finding was that the age or cost of a stove didn’t seem to be related to the amount of emissions.

More than a third of U.S. households, or more than 40 million homes, use gas cooking appliances, the researchers said. They estimated that the amount of methane leaking from residential gas stoves in the U.S. each year has a climate impact comparable to annual CO2 emissions from 500,000 gasoline-powered cars.

The use of gas stoves can also cause nitrogen dioxide (NO2) to quickly build up in kitchens, especially if ventilation is poor or range hoods aren’t used, the study found. NO2 is a pollutant that may have harmful impacts on the human respiratory system, according to the Environmental Protection Agency.

Federal Efforts

Another speaker at the Stanford webinar was U.S. Sen. Martin Heinrich (D-NM), who discussed efforts at the federal level to promote building electrification. In November, Heinrich joined with other lawmakers to form the first bicameral Electrification Caucus. The group’s goal is to advance policies to accelerate widespread electrification.

Heinrich also led efforts to introduce in July the Zero-Emission Homes Act, which would provide rebates for buying and installing electric appliances in single-family homes and multifamily buildings. The bill includes additional support for low- and moderate-income households. A companion bill was introduced in the House that same month.

Heinrich said a version of his Zero-Emission Homes Act is included in the climate package that is part of the Build Back Better Act that was passed by the House. Although Build Back Better is facing roadblocks in the Senate, Heinrich said, the climate package seems to be the area that has the most agreement.

“I remain confident that we’re going to find a way to get many of those climate investments to the president’s desk,” he said.

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MISO Weighing New Capacity Accreditations for Renewables, Storage

CARMEL, Ind. — MISO’s resource adequacy stakeholder group is starting the new year by tackling new capacity accreditations for renewable and energy storage resources.  

Lynn Hecker, senior manager of resource adequacy coordination, said the RTO hopes to have some new accreditation designs drafted by the end of the year.

She said during a Resource Adequacy Subcommittee (RASC) meeting Wednesday that a “fundamental shift” continues in the resource mix, with the generator interconnection queue dominated by renewable energy. Hecker said the footprint’s record-breaking, weather-dependent generation warrants a fresh look at accreditation.   

Hecker asked stakeholders for suggestions on what new accreditation designs might look like for renewables, storage and hybrid formats that are combinations of both.

Currently, a new availability-based accreditation for thermal resources is pending before FERC. MISO did not propose a new accreditation design for renewable or storage resources as part of its recent capacity auction redesign. Instead, it kept its effective load carrying capability (ELCC) method in place for wind resources, explaining that the calculation already accounts for output that varies by season. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)

Some stakeholders have said that using two different methodologies for fossil fuel-fired and intermittent resources constitutes unfair treatment. RASC meetings during 2021 saw contentious debate on the appropriateness of applying an accreditation based on historical availability to fossil resources, with many members critical of the idea.

MISO plans to evaluate the usefulness of its wind resources’ ELCC method . Staff said it might not accurately capture capacity contributions during the footprint’s highest reliability risks.

The grid operator only has about 2 GW of solar currently participating in its markets, not enough yet to provide the historical data the ELCC relies on.

Hecker said solar is poised for explosive growth. “We feel like this is the appropriate time for us to start looking into solar accreditation changes,” she said.  

Hecker also said MISO will first focus on renewable energy accreditation before proposing capacity credit treatment for storage resources.

When pressed by stakeholders, she said she couldn’t yet pin down a gigawatt threshold for participating energy storage before MISO would need an accreditation method.

“The magnitude of it cannot be overstated. We’re seeing more rapid change of the industry than at any point in our careers,” said the Brattle Group’s Sam Newell, who was contracted by the RTO to give advice on accreditation.

Newell called out record wind and solar additions, increasing demand response, changing daily load shapes and climate change as affecting capacity contributions.

“And now we’re in the news about reliability, about the transformation to clean energy,” he said. “Accurate accreditation is key to verifying adequate supply, signaling adequate planning … and identifying the economic tradeoff between resources.”

Newell said an ELCC calculation still “makes a lot of sense.” He said grid operators will need “quite a few years of data” to model energy-limited and intermittent resource performance. He also said they must consider that load is also weather driven.

“We’re going to have to argue about this a lot. That’s the business we’re in,” Newell told the RASC.

Staff Preps for Annual Auction

MISO is gearing up for possibly its final annual capacity auction. In advance of the auction, stakeholders have asked whether the RTO can share information on capacity resources that plan to take seasonal outages. Staff said it might provide that data at the local resource zone level to avoid revealing proprietary information.

For the 2022-23 planning year, the grid operator anticipates a 121-GW coincident systemwide peak with 157 GW in total installed capacity and almost 128 GW in total unforced capacity.

Fleet-wide, MISO’s wind capacity resources will have a 15.5% capacity credit in 2022-23, down one percentage point from the prior planning year.

MISO will conduct the Planning Resource Auction in early April.

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MISO, SPP Roll out $1.755B Joint Tx Portfolio

MISO and SPP staff on Friday gave stakeholders their first chance to discuss and comment on the Joint Targeted Interconnection Queue (JTIQ) study, the culmination of a rare collaboration by the RTOs that began in 2020.

Staff said during a joint stakeholder meeting that the study resulted in seven projects that would cost an estimated $1.755 billion and “fully resolve” its targeted transmission constraints. The projects, six 345-kV transmission lines and a 345-kV bus reconfiguration, would deliver $724 million and $247 million of adjusted production cost (APC) benefit to customers in the MISO and SPP footprints, respectively, with a cumulative benefit-to-cost ratio of 0.56.

Four of the transmission projects are in MISO’s footprint in the Dakotas and Minnesota; one is in SPP’s; and the last crosses the seam. The bus reconfiguration is in SPP’s region.

David Kelley, SPP’s director of seams and tariff services, said he was unsure whether other grid operators had undertaken a similar collaborative effort to produce what he called “pretty exciting” information. (See MISO, SPP to Conduct Targeted Transmission Study.)

“I wanted to just mention briefly how cool, honestly, it has been to be part of such a novel study that has never been conducted before, at least between SPP and MISO,” he said. “You guys get to see the work as it’s taking place … but you all really miss, I think, the interaction that takes place on a week-to-week basis between what has been a really good team of engineers, analysts and a number of other supporting cast members that have … worked so closely together to bring to you the product that we’re very happy to share with you today.”

SPP’s power-flow models found the projects could enable as much as 53 GW of generating capacity for new interconnection projects on the seam. MISO’s models came up with 28 GW of new capacity.

Asked why the RTOs’ models were off, Kelley said their planning processes are “fundamentally different.”

“We even started with somewhat of a different future in the production cost modeling,” he said. “Even when you call the futures the same thing, different assumptions go into them. It’s more indicative and should be viewed as qualitative.”

David Johnson, an Indiana Utility Regulatory Commission staffer, asked to see the numbers in dollars per megawatt to interconnect to the system “because it says it’s an interconnection study.”

“Tell me what the [bogey] would be if all of these projects that are connected individually along the way and those interconnection costs,” he said. “All these studies make tons of assumptions.”

Staff agreed with Johnson that it would be a “monumental task.” MISO’s Andy Witmeier, director of resource utilization, said the capacity enabled calculations included generation enabled by JTIQ-mitigated constraints and additional generation by using unused capacity on mitigated constraints and the study’s projects.

Witmeier said a supplemental study conducted by an SPP consultant found that, consistent with the JTIQ analysis, 60% of the constraints assigned to MISO interconnection customers for mitigation could be addressed by the joint portfolio. The consultant’s work also indicated the portfolio alleviated the need to mitigate 44% of the constraints — representing more than $301 million of the assigned network upgrade costs — in an SPP study cluster.

JTIQ Projects (MISO SPP) Content.jpgThe draft JITQ portfolio of projects | MISO, SPP

 

Cost allocation conversations are ongoing and additional stakeholder meetings will be scheduled in the first quarter, staff said.

“I believe it’s important to continue cost allocation discussions, but under the banner of the JTIQ,” Witmeier said. “We want to come up with cost allocations to hopefully get these projects built.”

Staff have already run modifications revising the joint operating agreement’s queue priority through the stakeholder process in both RTOs. A joint filing at FERC is expected in the next couple of weeks.

Stakeholders have until Thursday to provide feedback on the JTIQ study; a final report is expected Feb. 10.

The JTIQ study began as a mechanism to identify transmission projects required to address the significant transmission limitations restricting the interconnection of new generation near the SPP-MISO seam. Recognizing that large-scale transmission often provides multiple benefits, the study’s “novel” approach meant simultaneously considering whether transmission necessary to unlock the RTOs’ bulging generation interconnection queues could also provide economic and reliability benefits to their transmission customers.

The team closely coordinated the grid operators’ technical analyses, using each RTO’s respective transmission and generation planning methodologies to determine the project requirements that would cost-effectively resolve the transmission constraints inhibiting new generation near their seam. Staff performed reliability, economic and transfer capability studies and coordinated with stakeholders to develop solutions that met the study’s objectives.

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MISO Moves to Restrict Emergency Commitments

CARMEL, Ind. — MISO has come up with one possible fix on how it could more easily access its resource stack outside of emergencies: prohibiting some resources from using an emergency commitment status.

The tightened ruleset is poised to affect units that have been designated to meet the grid operator’s resource adequacy requirements (RAR). Currently, such resources can use an emergency commitment status in the energy markets, making their entire output unavailable unless there’s a generation emergency. The emergency commitments don’t affect the resources’ capacity credits.  

MISO says wider access to its capacity is crucial to “ensure reliable and efficient market outcomes.”

The RTO’s Dustin Grethen said during a Resource Adequacy Subcommittee Wednesday that restricting those units from making emergency-only offers could make a noticeable difference in the footprint’s resource adequacy.

Some stakeholders asked that MISO not altogether prohibit RAR resources from making emergency offers, especially for the top-end, emergency range of their output.  

“We thought this should affect their accreditation instead of them just not being able to do it,” MISO Independent Market Monitor Michael Chiasson said of RAR units’ emergency-only statuses.

Customized Energy Solutions’ David Sapper said MISO’s proposal was “draconian.”

“It does seem to me there’s a difference between a resource that’s in an emergency commit status for two days versus one that’s in for two months,” WEC Energy Group’s Chris Plante said, noting that he was not communicating his company’s position.  

Some stakeholders also pointed out that state emission regulations dictate that some generators only run in emergency situations.

MISO has spent several years searching for solutions that will improve its resource availability, which it says has been steadily worsening. It says it needs a clearer picture of what capacity is accessible to it and when.

The RTO’s Reliability Subcommittee plans to discuss and finalize the proposal in the second quarter.

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Conn. Advocates Seek ‘Upgrades’ to 2008 Climate Law

Climate advocates are seeking to update Connecticut’s 14-year-old climate law to bring the state closer to meeting its statutory greenhouse gas emission reduction targets.

“We’re not on track to meet our GHG reduction mandates and that means … we’re going to need to be playing some pretty serious catch-up in the coming years with some very bold climate action,” Leah Lopez Schmalz, vice president of programs at Save the Sound, said Tuesday.

Connecticut’s GHG emissions inventory, released in September, showed that the state’s emissions are increasing, which means “limited action” on climate issues “is going to get compounded,” Schmalz said during a Connecticut League of Conservation Voters Education Fund Environmental Summit.

The 2008 Global Warming Solutions Act set a mandatory 10% reduction in GHG emissions below 1990 levels by 2020, but the inventory showed the state emitted 2.9% more GHGs in 2018 than required for 2020.

“That 2020 goal of 10% reduction was seen at the time as a really modest goal; one that wasn’t going to be too hard to achieve,” Schmalz said. “But here we sit in 2022, having passed 2020, looking at data from 2018, and seeing that what we’ve done is insufficient.”

The law also sets targets of 45% and 80% reductions below 2001 levels by 2030 and 2050, respectively.

Certain “upgrades” to provisions in GWSA will help Connecticut follow the lead of neighboring Northeast states and make the “significant cuts” necessary to reach its targets, Schmalz said

Those upgrades include:

  • setting mandates for net-zero emissions by 2050 and 100% zero-carbon electricity by 2040;
  • enabling citizens to bring a suit against the state if mandates are not met; and
  • establishing regulatory authority for agencies to adopt regulations to address climate change.

In addition, Schmalz said, the law should set shorter intervals for the emissions reduction targets.

“We have 10-year and 20-year targets, which means by the time you get to that 10 years, if you’ve missed some progress along the way, you have a lot of catching up at the very end of your requirements,” she said.

Setting a five-year interval, she added, would allow the state to “adapt in real time to real data.”

Transportation Policy

The state GHG inventory highlighted continuous increases in the transportation sector since 1990, largely because residents are “driving more,” Department of Energy and Environmental Protection (DEEP) Commissioner Katie Dykes said on Thursday during the second day of the summit.

Adopting California standards was among the recommendations in the report for the sector.

“I hope this year we’ll be able to get adoption of legislation that will finally allow DEEP to join our neighboring states in adopting California’s emission standards for medium- and heavy-duty vehicles,” Dykes said. “This is going to be a major solution to help reduce [transportation] emissions, especially in communities living close to industrial zones and along our transportation corridors.”

In a legislative policy framework released this week, environmental advocates also supported adopting California’s Advanced Clean Cars II regulations when the California Air Resources Board finalizes them. Doing so, the framework said, would ensure Connecticut has a target for 100% of new light-duty vehicle sales to be zero-emission vehicles by 2035.

Solar Caps

Caps on community and commercial solar in Connecticut should be amended to promote progress in the sector, according to Mark Scully, president of People’s Action for Clean Energy.

Scully, who spoke on behalf of the Coalition for Sensible Solar Regulation, said the annual 50-MW cap on commercial solar and 25-MW cap on shared clean energy facilities could be doubled. The coalition, he added, also supports removing limitations on the size of solar arrays in the commercial and community sector.

“As a result of these constraints, the majority of proposed commercial and community solar projects get stranded,” Scully said. “Each of these constraints was created by legislative act, and we believe they could be remedied in this legislative session.”

The legislative changes, he said, would increase solar incentives, but the effect on electric rates would be “negligible.” Changing the caps for the commercial and community solar programs would increase monthly bills for an average ratepayer by 15 cents and 2 cents, respectively, according to Scully.

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NYISO Management Committee Briefs: Jan. 26, 2022

Sector Meetings Postponed to April

In-person stakeholder meetings will resume March 1 at the earliest, and annual sectoral meetings have been pushed back a month to mid-April to allow them to proceed in person as much as possible, NYISO CEO Rich Dewey told the Management Committee on Wednesday.

“We continue to look at infection rates related to the pandemic, and we’re starting to see some declines that we’re hopeful that we’ll be able to get back in person on March 1,” Dewey said.

The sector meetings are an “exceedingly valuable” opportunity to meet with each of the individual sectors, he said, and they constitute the practical kickoff of the ISO’s strategic planning process. The meetings give staff a chance to meet directly with stakeholders according to their line of business or sector for open conversation about what the ISO’s priorities should be, he said.

“Those meetings are far more effective if we can do them in person, so in order to try to maximize or increase the potential that we can actually hold those meetings in person, we’re going to push them back to the early and mid-April time frame,” Dewey said.

Cold Weather Ops Going Fine

Since the second week of January, New York has experienced colder than average weather conditions — but not extreme cold — and the peak so far came in above 23,000 MW, about 97% of the ISO’s forecasted peak winter load, COO Rick Gonzales said.

Natural gas prices during January have been significantly elevated and have ranged from $15 to $25/MMBtu, reaching as high as $35/MMBtu for some of the eastern New York gas hubs, he said.

“That has translated into significantly higher energy clearing prices in eastern New York and even throughout the state. … You might be aware we’ve often seen $200/MWh energy prices and higher throughout eastern New York,” Gonzales said.

New York and New England usually have slightly higher energy prices than neighbors Ontario, Quebec and PJM, he said.

“Quebec is actually almost not an importer to New York during these colder weather periods, but we are actually exporting to Quebec,” Gonzales said. “And Ontario and PJM power transfers are typically into New York, so the market systems are doing what we would expect, but … we are seeing the ties being fully utilized in almost all directions.”

NYISO is continuing to allow certain transmission work to proceed, except for on very cold days, he said.

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Con Ed to Refine $4B Offshore Transmission Plan for NYC

Consolidated Edison (NYSE: ED) must resolve several regulatory concerns before being authorized to build a new $4 billion substation complex in New York City dedicated to interconnecting offshore wind projects.

Those concerns took shape when the New York Public Service Commission issued a Jan. 20 order directing state solicitations for OSW proposals to require “mesh-ready” transmission plans, part of the broader effort to develop rules implementing the Climate Leadership and Community Protection Act (CLCPA), which requires that 70% of the state’s electricity generation come from renewable resources by 2030 and that generation be 100% carbon-free by 2040.

The PSC also asked Con Edison to supply detailed plans for a wind energy interconnection hub — and specifically one in lower Manhattan allowing the connection of up to 6 GW of OSW projects (Case No. 20-E-0197). (See NYPSC Mandates Meshed Offshore Tx Grids.)

“We look forward to providing more details on the benefits of these projects,” Con Edison spokesman Karl-Erik Stromsta told RTO Insider.

Changing Landscape

“Time is of the essence,” the commission said in its order, noting that the PSC and Con Edison are both aiming at moving targets in their efforts to identify the location for a substation. For example, the Rainey substation, which the state’s three-part power grid study last January identified as a good candidate to integrate OSW, has since been claimed by the Clean Path New York (CPNY) project to bring upstate solar and onshore wind into the city.

“The CPNY project is expected to carry generation associated with up to 1,300 MW of capacity, making it highly unlikely that the same substation can feasibly accommodate an additional 1,250 MW of offshore wind generation as assumed in the base case of the OSW study,” the commission said.

In March 2021 comments on the grid study, Con Edison reiterated earlier proposals for two New York City Clean Energy Hubs.

The first hub would create points of interconnection (POIs) for four 750-MW connections — or 3,000 MW total — and could be placed in commercial operation by summer 2027.

Phase 2 Additional Potential Projects (Con Edison) Content.jpgCon Edison estimates from 2020 on approximately $4 billion in Phase 2 projects to bring renewable energy into the city from from both upstate and offshore. | Con Edison

The second hub would create POIs for two new connections for about 1,500 MW total and simultaneously transfer load from three other constrained load pockets on Con Edison’s 138 kV system, relieving transmission constraints and reducing the load’s dependency on local fossil fuel power plants to maintain local system reliability. This project could be placed in commercial operation by summer 2029.

Con Edison first proposed the hubs in a local transmission and distribution report filed by all the state’s utilities in November 2020. The various utilities reported on their T&D status and proposed Phase 1 projects — traditional utility investments that address system reliability or resilience issues — and Phase 2 projects intended primarily for achieving CLCPA goals.

The PSC last April approved $800 million in cost recovery by Con Edison for three Phase 1 projects known collectively as the Transmission Reliability and Clean Energy (TRACE) projects. The projects are needed for reliability in 2023 and 2025 because of the retirement or unavailability of 399 MW of peaking generation made to comply with the state Department of Environmental Conservation’s “peaker rule,” new NOx regulations that go into effect May 1, 2023 (19-E-0065). (See NYPSC OKs $800 Million Tx Cost Recovery for Con Ed.)

Climate Resiliency

Con Edison is also collaborating with the Long Island Power Authority to consider ways to interconnect 9 GW of offshore wind.  The grid study and ensuing analysis identified scenarios in which 6,000 MW of interconnections into New York City and 3,000 MW into Long Island minimized onshore transmission system upgrades and involved very limited OSW curtailments.  The OSW portion of the study evaluated every New York City area and Long Island substation above 69 kV.

In addition, Con Edison identified the need to construct new feeders to redistribute the renewable energy throughout its local transmission system to both supply local loads and export to upstate load areas to prevent OSW curtailment.

The OSW analysis base case selected four POIs — with their injection capacities — in NYISO’s Zone J (NYC): Farragut (1,400 MW), Rainey (1,250 MW), Mott Haven (1,250 MW), and West 49th St. (1,200 MW). Still unresolved is whether those POIs have the physical space necessary to accommodate the upgrades for the planned injections.

Given the cost and difficulty of finding land for new electrical equipment and operations in lower Manhattan, Con Edison is proposing to build its first hub on land it already owns next to the Farragut substation on the East River in Brooklyn.

The commission is requiring all OSW proposals to include plans for high-voltage direct current (HVDC) transmission to make the best use of limited space available for cables in the Narrows and the harbor. It asked Con Edison for “a reasonable forecast” of where it will put an onshore HVDC converter station and the costs of routing an AC transmission line from there to the hub.

The commission also asked the utility to describe its measures to enhance resiliency, given that the hub would be “geographically concentrating, at a minimum, 3,000 MW of offshore wind interconnections at a single substation that would sit directly adjacent to another large substation (Farragut).”

Specifically, the commission asked for further information on how Con Edison will mitigate the risk of storm damage to the co-located substations; how the substations can be protected from exposure to sea-level rise and static or dynamic flooding; and how the utility will comply with all applicable reliability criteria, including NERC standards for “extreme contingencies” as specified in NERC Standard TPL-001-4.

The PSC also wants the utility to document how it is considering use of advanced technologies in its analysis.

The commission noted comments by LS Power and NextEra Energy Transmission New York in response to the utility study that said despite sufficient detail for regulatory action, Con Edison’s hub proposal should nonetheless be referred to the NYISO public policy planning process because it cannot be considered a local transmission project.

“While the commission expects to address procedural matters following its review of the additional information, the availability of the NYISO process should not interfere with our broad planning authority and review of the options for establishing cost-effective POIs in service of our overarching goal of meeting CLCPA mandates at the least cost to ratepayers,” the commission said in its January 20 order.

The PSC in October 2020 designated the New York Power Authority’s $1 billion Northern New York transmission line as a high priority for meeting the state’s renewable energy goals, bypassing NYISO’s public policy transmission planning process and adopting criteria for identifying other such “priority transmission projects.” (See NYPSC OKs NYPA Project, ‘Priority’ Tx Criteria.)

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Electric, Gas Revenues Drive Xcel’s 2021 Earnings

Xcel Energy said Thursday higher electric and natural gas revenues aided the company in meeting its earnings guidance for the 17th straight year.

Xcel reported year-end earnings of $1.6 billion ($2.96/share), up from 2020’s performance of $1.47 billion ($2.79/share). For the quarter, earnings were $315 million ($0.58/share), compared to $288 million ($0.54/share) in last year’s fourth quarter.

“We had a solid year delivering earnings … and achieving our earnings guidance for the 17th consecutive year. We are well positioned for the future,” CEO Bob Frenzel said in a statement.

Analysts had expected fourth-quarter earnings of 56 to 57 cents/share.

Earnings were partially offset by increases in electric fuel and purchased power, costs of natural gas sold and transported, additional depreciation and lower allowance for funds used during construction.

The Minneapolis-based company reaffirmed its 2022 earnings forecast of $3.10 to $3.20/share.

Xcel is banking on clean energy to meet its guidance. It has filed resource plans in Minnesota and Colorado that it says will accelerate its exit from coal-fired generation in those states by 2030 and 2034, respectively. The company last year said it had reduced carbon emissions by 50% from 2005 levels and is on track to reach an 80% reduction by 2030.

Xcel’s share price closed up Thursday at $68.94, a $1.32 increase from the previous close.

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BPA Postpones Western EIM Entry by 2 Months

The Bonneville Power Administration will delay its entry into the Western Energy Imbalance Market (WEIM) by two months to work out technical and training issues, the federal power marketing agency said Thursday.

BPA was scheduled to begin trading in the WEIM on March 2 but is now pushing its “go-live” date to May 3, citing customer requests for more testing and training on the computer systems being used to integrate the agency’s operations into the market.

Speaking Thursday during an agency workshop, Chief Business Transformation Officer Nita Zimmerman said the “short delay” provides BPA with additional time “to ensure the most successful go-live outcome” and “to appropriately address some of the remaining functionality needed for some of the systems that we’re still bringing online.”

Zimmerman cited “continued challenges” with metering data, outage management, market settlement allocation and billing among its customer base of publicly owned utilities. Early participants in the WEIM have cautioned potential members on the complexity of integrating into the CAISO-operated market and the high level of “discipline” needed to prepare for joining. (See PacifiCorp Offers Lessons for Future EIM Participants.)

“Building in this additional time does demonstrate the care and rigor that we’re taking — along with our vendors — in bringing this initiative along,” Zimmerman said.

But Zimmerman and EIM Program Manager Roger Bentz both assured BPA customers that the agency is “pedal to the metal” and “continuing full-throttle” in its efforts to meet the May 3 timeline.

Bentz pointed to the progress BPA has made in implementing WEIM systems and practices over the past two months, including commencing parallel operations with the market on Dec. 1. The parallel production environment provides new participants the ability to practice under real market conditions, allowing them to submit bids and base schedules, collect e-tags and learn how to adapt operations to real-time developments.

BPA has also successfully tested end-to-end transfers with two adjacent WEIM entities and finished testing the software that will allow it to “donate” transmission capacity to WEIM operations.

Additionally, the agency has also fully staffed and trained its EIM entity scheduling coordinator and operations desks, Bentz said.

Bentz said he was unsure what impact BPA’s postponement would have on Avista and Tacoma Power, the two other entities slated to join the WEIM on March 2.

“The latest information we have [is] they are likely to stay with their current schedule of March 2,” he said.

“The Tacoma Power team is quickly doing an analysis today and should have more details [Friday],” utility spokesperson Rebekah Anderson told RTO Insider.

Avista did not respond to an inquiry about the effect of BPA’s delay on its WEIM timeline.

If the two utilities stick to their current timelines, BPA will be modeled out of parallel operations early next month and then rejoin in early March, Bentz said.

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Mass. Has Bright EV Future Despite TCI-P Loss, Advocates Say

An impending influx of federal money, a regional partnership in tatters and a pandemic that has drastically changed Americans habits has Massachusetts transportation electrification policymakers’ and advocates’ heads spinning.

But there was optimism and momentum despite uncertainty during a panel hosted by the Northeast Energy and Commerce Association on Wednesday.

An estimated $63 million in formula funding for electric vehicle infrastructure headed to Massachusetts from the Infrastructure Investment and Jobs Act is a “hugely positive story,” said Jake Navarro, director of clean transportation products at National Grid (NYSE: NGG).

But even that money comes with worries about whether it will be spent efficiently.

“It’s really important that those funds get maximized by making them complementary with other programs that other players in the space can offer,” Navarro said.

In addition, the breakdown of the Transportation and Climate Initiative Program (TCI-P) has been frustrating for Daniel Gatti, director of clean transportation policy at the Massachusetts Executive Office of Energy and Environmental Affairs.

“You design a policy for an environment in which no state has any resources to spend on clean transportation … and then it comes time to implement the policy and all of a sudden the price of gas has gone up,” Gatti said. Add big federal funding for transportation to the situation and the circumstances become “challenging” for TCI-P to overcome, he said.

That reality has advocates watching closely to see what will develop in the vacuum.

“TCI-P was pretty central to the administration’s approach to reducing GHGs in the transportation sector,” said Anna Vanderspek, electric vehicle program director at the Green Energy Consumers Alliance. “That is one place where we are taking a really hard look at what is the state’s Plan B in the absence of that stream of revenue?”

Alignment and Opportunity

Participants in the Massachusetts EV sector see a strong landscape despite the market challenges and uncertainties.

“What we don’t really appreciate is the amount of alignment that exists in this state that doesn’t exist in other areas, even in some parts of California,” said James Cater, program lead for EV infrastructure at Eversource (NYSE: ES).

“It’s an amazing thing; I think our alignment enables us to make these really bold steps and make these really bold goals,” Cater said. “I think you are going to see increasingly this be a go-to location for thought leadership, deployment, for business development around this EV universe, and it’s exciting.”

It’s early still in the “adoption curve” for EVs, Navarro said.

“Massachusetts has a goal for 300,000 [EVs, and] … right now we’re at 40,000 to 50,000 vehicles on the road,”
 he said. “We are at the extreme early end.”

Political circumstances could be favorable to quick government action as Gov. Charlie Baker prepares to exit.

“The last year of the Baker administration, I’m thinking about what we can do in the next 12 months, what we can set up right now,” said Gatti.

One suggestion from Vanderspek: a clearinghouse or “scaffolding” to help consumers understand EVs.

“We’re increasingly getting questions from people saying, ‘I get it, electric school buses; where do I start?’” he said.