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July 28, 2024

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ISO-NE Details Resource Modeling Plans for Capacity Accreditation

ISO-NE provided stakeholders with additional detail on its plans for modeling capacity demand and resource reliability attributes as the RTO and stakeholders continued work on the resource capacity accreditation (RCA) project at the NEPOOL Reliability Committee meeting Jan. 16. 

“Improvements are required to the Resource Adequacy Assessment (RAA) used currently to calculate capacity requirements (demand) and develop resource-specific accreditation values,” said Fei Zeng, ISO-NE technical manager. 

ISO-NE is working to improve the RAA modeling to better assess the risks and severity of loss-of-load events, and how different resources would affect system reliability during these periods. The RTO is trying to better capture resource reliability performance under different weather and system loading conditions, and with different resource mixes. 

The RAA resource modeling includes specific cases focused on season risk, resource accreditation, and system and zonal capacity requirements. 

ISO-NE has outlined four different modeling options for different resource types: thermal modeling based on seasonal qualified capacity and outage rate; profile modeling based on an “hourly expected performance profile;” storage modeling based on expected energy limitations; and perfect capacity modeling, based on seasonal qualified capacity. 

At the January RC meeting, Zeng detailed which modeling options would be used for different resource types: 

    • Thermal model: nuclear, coal, fuel cell, nonintermittent hydro, imports, tie benefits, and (from March to November) gas and oil resources. 
    • Profile model: active and passive demand resources, and intermittent resources like solar, wind and landfill gas. 
    • Storage model: battery storage and pumped hydro. 
    • Perfect capacity model: distributed energy capacity resources and co-located generators that function as a single capacity resource. 

For peak winter months, ISO-NE is proposing to take a more varied approach to modeling oil, gas and dual-fuel resources, instead of just using the thermal model, which would apply to them in all other months. 

From December through February, gas resources would be modeled as a single fleet using the profile model, intended to account for gas network limitations and demand from local gas distribution companies.  

“A regression model is used to establish a relationship between the amount of daily gas available to generation and temperature conditions based on historical data,” Zeng said. “The daily available gas will be apportioned to each hour during the day based on historical hourly gas generation patterns and the representative heat rate of the gas fleet.” 

For oil resources, ISO-NE proposes using the thermal model for residual fuel oil (RFO) resources in all RAA cases and for distillate fuel oil (DFO) resources in the accreditation and capacity RAA cases.  

For the RAA seasonal risk assessment, ISO-NE would model DFO resources as an “aggregate energy storage resource with a limited amount of energy available during a two-week period.” 

Zeng noted that DFO resources have smaller storage tanks than RFO resources, causing them to exhaust their stored fuel more quickly and require more frequent replenishment. Because of variability in tank sizes and replenishment strategies, “DFO resource risks are better captured on a fleet level,” Zeng said.  

The two-week DFO energy constraint would be based on data from the past five winters. 

Fuel Requirements

To compare the reliability benefits of different types of resources that rely on a limited supply of energy, ISO-NE proposes creating a “daily operating hours requirement” (DOHR), which would equal the number of hours per day a resource must be able to operate at its seasonal capacity rating during peak winter months. Resources that can’t meet this requirement would have their qualified capacity derated.  

The RTO would use RAA results to calculate the daily operating requirement and would update the requirement at each capacity auction. ISO-NE also is considering a winter peak seasonal operating hours requirement (SOHR) and a fuel storage hours requirement (FSHR) for stored fuel resources. The calculation of SOHR and FSHR would consider RAA results and historical weather data.  

FSHR would be calculated by “multiplying the DOHR by the number of days in a winter cold snap,” said Alex Mattfolk of Levitan & Associates (LAI), which is working as a consultant for ISO-NE on the project. For this calculation, the consulting firm has determined that modeling a four-day cold snap would cover more than 99% of days. 

The seasonal requirement would be determined by multiplying the DOHR by the number of days cold enough to significantly stress the grid. LAI determined that 11 days would cover over 99% of days.  

Operationally Limited Resources

Mattfolk also presented on the firm’s proposal for “operationally limited resources” — gas plants that typically are unable to run on cold days due to “physical and/or operational constraints on gas delivery.” These resources would not be credited with any qualified capacity.  

LAI proposes to flag operationally limited resources based on historical performance during cold periods. Flagged resources could appeal their designation by providing evidence the gas constraint no longer applies or that the lack of operations was due to some unrelated factor. 

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EPA Proposes Methane Emission Penalties

EPA is moving to impose financial penalties for excessive methane emissions within the oil and gas sector. 

The proposed rule, announced Jan. 12, is part of the ongoing Methane Emissions Reduction Program established through the Inflation Reduction Act, which called for the penalties. 

As required by the IRA, the waste methane emissions charge would apply to certain oil and gas facilities that report emissions of more than 25,000 metric tons of carbon dioxide equivalent per year to the Greenhouse Gas Reporting Program. The charge would start at $900/MT of excess emissions in 2024, then increase to $1,200 in 2025 and $1,500 in 2026. 

EPA’s proposed rule spells out how the charge will be calculated and how exemptions will be granted. The agency said the charge will encourage the industry to stay on target to reduce its emissions, which can be accomplished through readily available technology. 

The agency said it expects gradually fewer facilities will be at risk of incurring the charge as they reduce their emissions sufficiently to comply with the recently finalized final rule in December establishing performance standards for new sources of methane and setting emissions guidelines for states to follow. 

There are two other key components of the IRA’s methane program: EPA is offering more than $1 billion in financial and technical assistance to speed the transition to low- and non-emitting oil and gas technologies. The agency is also working with the industry and other stakeholders to improve the Greenhouse Gas Reporting Program and increase the accuracy of reported methane emissions. 

Oil and natural gas operations are the largest industrial source of methane emissions in the U.S., EPA said. Methane is targeted because it is a superpollutant, roughly 28 times more potent as a greenhouse gas than carbon dioxide and responsible for about a third of the warming effect of all greenhouse gases.  

“Today’s proposal, when finalized, will support a complementary set of technology standards and historic resources from the Inflation Reduction Act, to incentivize industry innovation and prompt action,” EPA Administrator Michael Regan said in a news release. “We are laser-focused on working collectively with companies, states and communities to ensure that America leads in deploying technologies and innovations that aid in the development of a clean energy economy.” 

“It’s common sense to hold oil and gas companies accountable for this pollution,” Environmental Defense Fund President Fred Krupp said. “Proven solutions to cut oil and gas methane and to avoid the fee are being used by leading companies in states across the country.” 

The American Petroleum Institute had a different take. “As the world looks to U.S. energy producers to provide stability in an increasingly unstable world, this punitive tax increase is a serious misstep that undermines America’s energy advantage,” it said. “While we support smart federal methane regulation, this proposal creates an incoherent, confusing regulatory regime that will only stifle innovation and undermine our ability to meet rising energy demand. We look forward to working with Congress to repeal the IRA’s misguided new tax on American energy.” 

U.S. Sen. Kevin Cramer (R), representing the oil-rich state of North Dakota, decried the impact of the “burdensome” charges. “Democrats in Washington and their climate-zealous allies jammed the partisan Inflation Reduction Act through Congress, placing backwards, overburdensome regulations on domestic energy. This fee will reduce production and increase costs, disproportionally harming the working-class Americans who depend on affordable and reliable energy the most. Burdening North Dakota energy producers with more fees and penalties while saddling every American with higher energy is a foolhardy mistake Democrats will have to answer for.” 

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Wisconsin Senate Votes to Fire Commissioner Huebner 4 Years into Job

Wisconsin’s GOP-controlled Senate voted Jan. 16 to reject Public Service Commissioner Tyler Huebner’s nomination to the commission — nearly four years into his time at the regulatory agency.

Tyler Huebner | RENEW Wisconsin

Until Tuesday, Huebner had been performing duties unconfirmed. Wisconsin Gov. Tony Evers (D) first appointed Huebner in 2020 to fill former Commissioner Mike Huebsch’s unexpired term. Huebner’s first term came and went in 2021 without a confirmation or hearing vote, and Evers re-enlisted Huebner to a new term ending in early 2027. The Senate’s confirmation of Huebner subsequently was pushed into the 2023-2024 legislative session.

The 21-11 vote mostly along party lines to fire Huebner appeared to hinge on Republican senators’ unease with Huebner’s support for determining rates on customers’ ability to pay and cutting carbon emissions. Some said his aims veered from strictly regulatory into policymaking.

During testimony, Sen. Julian Bradley (R) said it was a problem that Huebner used his position to be “an activist” and said state law doesn’t allow the PSC the authority to enact income-based ratemaking.

Last week, the Senate Utilities and Technology Committee voted 3-2 against confirming Huebner after they questioned him in the fall over a 2022 water utility decision that established a subsidy pilot program for low-income customers and the PSC’s Strategic Energy Assessment Plan, which modeled an 80% reduction of CO2 emissions in the state’s energy production by 2039.

Sen. Jeff Smith (D) said the vote to remove Huebner is “such a head-scratcher at a time when Wisconsin is experiencing an unprecedented expansion of renewable energy.” He said Huebner brought valuable experience to the table.

“It is shortsighted [and] leaves us less prepared for the challenges ahead,” Smith said.

Huebner is a former executive director of RENEW Wisconsin, a nonprofit dedicated to accelerating the clean energy future.

The vote throws the three-person Wisconsin PSC into upheaval. Last week, Chairperson Rebecca Cameron Valcq announced her departure from the commission effective Feb. 2 after five years. At the time, Valcq said it was the “right time for me to pass the baton as I leave the agency in very capable hands.” She said the PSC had become “more transparent and accessible” during her tenure.

The exits leave freshly confirmed Commissioner Summer Strand as the sole Wisconsin regulator beginning next month unless Evers is swift with new appointees. The Wisconsin Senate confirmed Strand’s April 2023 appointment 27-5 in the same Jan. 16 session following the vote to oust Huebner. Strand is set to succeed Valcq as chair.

In a statement released by the Wisconsin PSC, Huebner said he was “proud” of the decisions he made as a state regulator and “especially grateful” to be involved with Wisconsin’s energy planning and reliability direction through his involvement with the Organization of MISO States (OMS).

“I am moving forward, and I plan to build on my work at the commission and throughout my career to tackle some of the big challenges of our times in a different capacity,” Huebner said.

The Senate vote disrupts OMS leadership. In 2023, the OMS Board of Directors unanimously elected Huebner to serve as the 2024 OMS president.

Current OMS Vice President and Iowa Utilities Board Commissioner Josh Byrnes is now considered OMS president. According to OMS Bylaws, in the event of a vacancy in the office, the organization’s vice president will succeed the presidency until the next annual election occurs.

OMS Executive Director Marcus Hawkins said the OMS community “will sorely miss Tyler’s expertise and credibility.”

“The high quality of his character, intellect and work ethic were a rare and powerful combination that made every OMS discussion better. His departure is a significant loss for Wisconsin and for the state regulatory community as a whole,” Hawkins said in an emailed statement to RTO Insider.

In a press release, Evers said Huebner’s dismissal continues a trend of legislative Republicans terminating appointees without grounds or leaving them unconfirmed indefinitely. Senate Republicans in October rejected seven of Evers’ appointees to the Wisconsin Natural Resources Board, Wisconsin Elections Commission, Wisconsin Medical Examining Board and the Governor’s Council on Domestic Abuse.

“Commissioner Huebner is an exemplary public servant who’s dedicated to serving the people of Wisconsin and building the sustainable future we want for our state. The decision by Senate Republicans to fire him today defies justification and logic,” Evers said in a Jan. 16 press release. “It’s my job to appoint the best and most qualified people to serve our state — that’s what I have been and will continue doing, regardless of the apparent Republican position that every appointee must agree with them 100% of the time to earn their support.”

Evers said state Republicans’ ongoing efforts to “harass, disparage and fire dedicated public servants is a serious threat to the basic functions of our government and democracy in our state.”

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Xcel Says Coal Retirements on Track Despite South Dakota PUC’s Plea for Extensions

Xcel Energy insists its plan to retire two Minnesota coal plants won’t mar reliability even though the South Dakota Public Utilities Commission sent a letter urging the utility to hold off on shutting down the units.  

The South Dakota PUC asked Xcel in a letter this month to reconsider its planned closures of the Sherburne County Generating Station (Sherco) and Allen S. King coal plants in Minnesota.  

“Closing these plants will take nearly 3 GW of reliable dispatchable electricity generation off the [MISO] grid precisely at a time when those resources will be needed the most to keep electricity flowing 24/7/365 throughout Xcel and MISO’s footprint,” South Dakota commissioners wrote to Xcel. “Premature closure of these plants adds to the uncertainty of electric generation resource adequacy in the upper Midwest including Xcel’s customers in South Dakota.” 

South Dakota commissioners cited NERC’s finding in its Long-Term Reliability Assessment that the MISO footprint could face a 4.7-GW shortfall through 2028. 

“Evidence is mounting that the premature closure of dispatchable generation will elevate the risk of electricity outages, particularly in tight load hours including hours of extreme cold and extreme heat, as well as those hours when wind generation is low,” the commissioners wrote.  

Commissioners also expressed concern South Dakota ratepayers may bear the costs of closing the plants early. They said Xcel said in a docket that choosing not to operate the two coal plants for the duration of their useful lives paired with a decision against extending the Prairie Island nuclear plant could cost customers $453 million more than keeping the plants open.  

“We do not want Xcel to be part of the impending problem of [a] generation shortage in the MISO footprint. Reliability should be your number one commitment!” commissioners told Xcel leadership.  

Xcel, however, said both the PUC and it are taking threats to reliability seriously and that it appreciates the feedback on plans to decommission its coal plants by 2030.  

“We are in alignment with the commission’s priority to ensure reliability throughout the clean energy transition and ensure South Dakotans have a dependable supply of electricity at all times, including periods of extreme weather and high demand,” Xcel said in an emailed statement to RTO Insider.  

Xcel pointed out that it plans to infuse 2.1 GW of wind and 2.5 GW of solar onto its Upper Midwest grid by 2032 and said it has another 1.1 GW of wind and solar waiting in the wings beyond 2032. It added that its two nuclear plants will be able to complement the variable supply with dispatchable, carbon-free electricity.  

Xcel also said it has plans to include 800 MW of “hydrogen-ready” combustion turbines in its generation portfolio and soon will build 500-700 miles of new transmission lines to further bolster reliability. It said it looks forward to “continuing to meet with the commission” for insight on the “complex task” of ensuring a reliable and affordable clean energy future.  

Xcel remains on track to exit coal generation by the end of the decade. It officially retired the first of its coal units at Sherco on the last day of 2023, with plans to retire the other two in 2026 and 2030.  

Ryan Long, president of Xcel Energy Minnesota, South Dakota and North Dakota, said there’s “tremendous potential for the plant site in the Upper Midwest’s energy future.”  

“Just as we’re taking a phased approach to decommissioning the coal units, we’re building replacement generation in phases to support clean, reliable and affordable energy for our customers,” Long said in a press release at the time.  

Xcel is building the first two phases of the total 710-MW Sherco Solar project adjacent to the Sherco site. It also plans to construct a 10-MW, 100-hour battery storage facility onsite as a pilot project from Massachusetts-based Form Energy. Xcel received a grant of up to $35 million from the U.S. Department of Energy for the battery project. 

Xcel said Sherco Unit 2 is slated to become a synchronous condenser to manage system stability after retirement.  

Finally, Xcel said it’s proposing to build the Minnesota Energy Connection, a 175-mile, 345-kV transmission line in southwest Minnesota that will use existing interconnection at Sherco to connect a minimum 2 GW of wind and solar.  

“There’s a lot of life left at the Sherco site, and our dedicated coworkers will manage the transition over the next decade,” plant director Michelle Neal said in the release.  

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ERCOT Meets Demand, Sets New Winter Peaks

ERCOT set a new winter peak for demand Jan. 16 as it easily met demand during a frigid blast that pushed temperatures 30 to 50 degrees below normal in Texas. 

The grid operator had expected electricity consumption to match the record levels set last summer, projecting demand as high at 86 GW as the winter storm approached. However, demand averaged 78.14 GW during the interval ending at 8 a.m. Jan. 16. 

That broke the previous winter mark set the day before, when demand averaged 76.34 GW during the 9 p.m. interval, surpassing the previous record of 74.53 GW set in December 2022. It also exceeded ERCOT’s earlier all-time peak of 74.53 GW set in 2019. 

The ISO issued conservation appeals for Jan. 15 and the morning of Jan. 16. With a hard freeze expected as far south as Houston, ERCOT is expecting similar conditions the morning of Jan. 17. 

The grid operator thanked Texas residents and businesses on X. 

“Your conservation efforts, along with additional grid reliability tools, helped us get through record-breaking peak times today and yesterday morning,” it posted Jan. 16. 

ERCOT was also boosted by energy storage and solar resources. Batteries peaked at more than 1,200 MW during the early morning hours Jan. 16; solar produced a record 14.21 GW of energy at 10:40 a.m.  

The grid’s staff said in December that there was a 1-in-6 chance of outages this winter if conditions matched those of the 2022 winter storm. While the temperatures have been frigid — Dallas has been below freezing since the afternoon of Jan. 13, with a low of 11 degrees Fahrenheit the morning of Jan. 15 — thermal outages were slightly below average at 7 GW. 

Texas Gov. Greg Abbott (R) took to X to praise ERCOT’s “flawless” performance, a credit, he said, to recent measures to weatherize critical facilities and strengthen the grid. 

Wholesale electricity prices hit $500/MWh during one 15-minute interval the morning of Jan. 16 but have generally stayed below $200/MWh since Jan. 13. 

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NERC Taking Comments as Winter Reliability Standard Deadline Looms

NERC is taking comments on a winter reliability standard for generators that has failed to clear its stakeholder process twice, the ERO announced Jan. 16.  

Comments are due by 8 p.m. EST on Jan. 22. NERC hopes to get one more vote on the rule, which failed to clear the stakeholder process its second time Nov. 30 with only 58% in support, short of the two-thirds required. If stakeholders fail to approve it this time, NERC Board of Trustees Chair Ken DeFontes has said the board might have to move the standard forward on its own. (See Standards Committee Authorizes Shortened Ballots.) 

FERC has required a new reliability standard to be filed by February based on the recommendations from its joint report with NERC on Winter Storm Uri, which led to deadly blackouts in Texas in February 2021. 

The proposed rule (EOP-012-2) would require generators to review their risks for extreme cold weather, which equates to the lowest 0.2 percent of hourly temperatures measured in December, January and February from Jan. 1, 2000, until the date temperatures are calculated. Any generator with extreme temperatures at or below freezing (32 degrees Fahrenheit) will have to comply with the standard. 

The proposal would require generators to develop and implement plans designed to mitigate the reliability impacts of cold weather. If the generators see lower extreme temperatures on their five-year reviews, those plans would have to be reviewed to ensure that they are in compliance with the standard and if they would have to identify additional mitigation measures. 

Generators would have to implement freeze protection measures that protect critical components so they could keep operating at their calculated extreme cold weather temperatures with sustained wind speeds of 20 mph for a period of not less than 12 continuous hours, or the maximum operational duration for intermittent energy resources. 

If a generator cannot meet the proposed standard’s requirements, it would be required to add new or modify existing freeze protection measures to provide the capability to operate at the extreme cold temperatures for its location. 

Generators will have to show that they have followed those cold weather plans and trained their staff to implement them, the proposed standard says. 

NERC plans to hold a nonbinding poll on the associated violation risk factors and violation severity levels through Jan. 22. 

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Congressional Democrats Urge FERC to Complete Transmission Rule

Nearly half the Democrats in Congress sent a pair of identical letters to FERC on Jan. 16 urging the commission to finalize its proposed transmission planning and cost allocation rule.

Sens. Martin Heinrich (D-N.M.) and Ed Markey (D-Mass.) led the group of 21 senators from the party in sending the upper house’s letter, while Rep. Paul Tonko (D-N.Y.) led the group of 113 House members in its version of the letter.

“In recent years, we have witnessed numerous examples of grid resilience issues, which have highlighted the inadequacy of the grid to handle changing load patterns, interconnect new clean energy resources and respond to increasingly frequent and severe extreme weather events,” read both letters, which were addressed to FERC Chair Willie Phillips. “FERC’s final rule should ensure that transmission planners account for these factors by requiring a long-term, forward-looking, 20-year planning horizon that addresses the changing circumstances and the evolution of our energy system.”

Phillips has said since assuming the chair that he wanted to move forward the Notice of Proposed Rulemaking on transmission, which was issued in April 2022. The commission also has to issue an order on rehearing for Order 2023, which updated its minimum standards for interconnection queues around the country. (See FERC Updates Interconnection Queue Process with Order 2023.)

The congressional letters follow some from stakeholders last month urging FERC to complete the rule this year. (See FERC Gets Growing Call to Finish Transmission Rule in 2024.)

The Department of Energy has said improved and increased transmission is needed for reliability, affordability and clean electricity. The department’s National Transmission Needs Study found capacity will need to double in many parts of the country by 2035 to meet the Biden administration’s clean energy goals, assuming just moderate load growth, the members said.

“In order to grow our economy, keep communities safe during extreme weather events, address historic environmental injustices and decrease energy costs for consumers, a robust and well-planned transmission grid is essential,” the letters said. “With a strong final rule, FERC can play a critical role in achieving these goals, fulfilling the promise of the most consequential infrastructure and climate laws in history.”

The Inflation Reduction Act and the Infrastructure Investment and Jobs Act have committed the country to a historic energy transition, they said, but the electric grid needs to be expanded to make that possible.

Americans for a Clean Energy Grid Executive Director Christina Hayes welcomed the support for finalizing the rule from Congress.

“The grid is in need of a 21st-century update, and the reforms currently pending at FERC will go a long way toward increasing the reliability and resiliency of our energy system and ensuring the delivery of cost-effective energy to all Americans,” Hayes said in a statement. “We will continue to work closely with FERC to help finalize a durable rule that advances the development of high-capacity transmission for the benefit of customers throughout the country.”

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Christie Denounces Tx Incentive Process as FERC Approves More MISO LRTP Project Perks

Commissioner Mark Christie has used FERC’s latest order on transmission incentives to condemn the commission’s process as requests for incentives come in fast and thick from MISO’s long-range transmission projects.

This time, FERC granted Xcel Energy’s ask for construction work in progress (CWIP) incentives and abandoned plant incentives for four 345-kV long-range transmission plan (LRTP) projects in South Dakota, Minnesota and Wisconsin, which allow Xcel to recover incurred costs in rates if the lines are canceled for reasons beyond its control (ER24-409).

The incentives apply to Xcel’s portions of the Big Stone South-Alexandria-Cassie’s Crossing project, the Wilmarth-North Rochester-Tremval project, the Tremval-Eau Claire-Jump River project and the Tremval-Rocky Run-Columbia project.

Xcel said it plans to spend up to $1.2 billion on construction for its portions of the projects. The utility said its Wisconsin- and Minnesota-based Northern States Power subsidiaries “expect to face a negative cash flow position while undergoing extensive levels of capital expenditures over the next several years” to build the LRTP projects.

Xcel said the CWIP incentive will improve cash flow and credit ratings during construction. It also said the projects carry heightened risks of abandonment because multiple utilities over multiple states are working in concert to build the lines. Xcel added that an economic downturn could hurt the chances for the lines, which were planned to serve projected, not existing, generation.

FERC agreed that the CWIP and abandoned plant incentives are “tailored to address the risks and challenges” Xcel’s subsidiaries will face as they undertake the projects.

But in a concurrence, Christie repeated that FERC’s granting of incentives “has become nothing more than a check-the-box exercise.” Christie has become increasingly critical of transmission incentives in FERC orders allowing them for developers. (See FERC Approves Dairyland Incentives for Minn.-Wis. Transmission Line.)

Christie said though FERC followed its protocol to grant Xcel the incentives, it’s time for FERC to revisit its CWIP and abandoned plant incentives, as well as the RTO participation adder, which he called “an involuntary gift from consumers.”

Christie repeated concerns that the CWIP incentive allows utilities to recover costs before a line has been placed into service, effectively forcing customers to serve as a lender for transmission development while they earn zero in interest and even pay utilities a profit through return on equity. He also said the abandoned plant incentive makes ratepayers the “insurer of last resort” as well as the lender on projects.

“Just as consumers receive no interest for the money they effectively loan transmission developers through CWIP, they receive no premiums for the insurance they provide through the abandoned plant incentive if the project is never built,” he wrote. “There is something really wrong with this picture.”

Christie said he supports FERC’s recent proposals contained in notices of proposed rulemaking to limit the RTO participation adder to three years after a utility has joined an RTO and eliminate CWIP incentives. He said those steps, alongside a reconsideration of the abandoned plant incentive, will “ensure that all the costs and risks associated with transmission construction are not unfairly inflicted on consumers while transmission developers and owners stand to gain all the financial reward.”

“In short, revisiting all these incentives is imperative at a time of rapidly rising customer power bills,” Christie said.

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DOE Partners with HVAC Industry on Cold Climate Heat Pumps

With temperatures plunging and home heating bills rising across the country, the Department of Energy recently announced that four companies have developed high-efficiency cold climate heat pumps as part of the department’s Residential Cold Climate Heat Pump (CCHP) Technology Challenge.

The four companies — Bosch, Daikin, Midea and Johnson Controls — have completed laboratory testing for CCHPs that can “deliver 100% heating capacity without the use of auxiliary heat and with significantly higher efficiencies at 5 degrees Fahrenheit,” according to the Jan. 8 announcement.

The next phase of the challenge is “expected to involve the installation and monitoring of … prototypes in various cold-climate locations throughout the U.S. and Canada over the next year,” the announcement says.

Electric heat pumps, which can be used for heating or cooling, extract heat from the air or ground outside the building and then run the heat through a compressor before releasing it inside, according to a DOE factsheet. However, until recently, many of the available models did not perform well in subfreezing temperatures.

Launched in 2021, DOE’s CCHP Technology Challenge is aimed at fostering public-private partnerships “to address the technical challenges and market barriers to adopting next-generation cold-climate heat pumps,” the department says. The initiative has two tracks: one for heat pumps that can operate at 5 F, another optional one for ‑15 F.

The goal is to “ensure that Americans have access to more affordable clean heating and cooling options — no matter where they live,” Energy Secretary Jennifer Granholm said in the announcement.

In addition to the companies announced Jan. 8, four other companies ― Lennox International, Carrier, Trane Technologies and Rheem ― also have produced successful prototypes, according to DOE.

Space heating and cooling across all building types ― homes, offices, schools, hospitals and military bases ― accounts for 35% of U.S. energy consumption, according to DOE. Especially when paired with good building insulation and clean electricity, an electric heat pump may produce about half the GHG emissions of an oil- or gas-fired furnace while saving consumers an estimated $500/year on utility bills.

The Bosch prototype can operate down to a temperature of ‑13 F, according to a company spokesperson.

“The system is equipped with inverter technology, which ramps the compressor up or down to heat (or cool) the home in an efficient way,” the spokesperson said in an email to NetZero Insider. “What enables the cold climate heating is the enhanced vapor injection (EVI) compressor; it essentially borrows additional heat from the hot side of the … cycle and redirects it to help warm up the home on frigid days.”

Bosch and the seven other companies in the challenge are now field-testing more than 20 heat pumps at locations in 10 states and two Canadian provinces, according to a DOE spokesperson.

The Biden administration has promoted heat pump adoption as part of its drive to decarbonize the electric grid by 2035 and cut U.S. GHG emissions 50 to 52% by 2050, and states are following suit.

The Inflation Reduction Act includes a tax credit of up to $2,000 for the purchase and installation of heat pumps. State incentives in Maine have resulted in the installation of more than 100,000 heat pumps, leading Gov. Janet Mills (D) to set a new target of installing an additional 175,000 by 2027. (See Maine Blows Past Heat Pump Installation Target.)

Maryland’s recently released Climate Pollution Reduction Plan calls for state incentives to cover 100% of heat pump costs for low- and moderate-income households ― although the cash-strapped state will have to come up with extra funding to pay for such initiatives. (See Md. Emission-reduction Plan: High Ambitions, No Funding.)

Beyond cost, cold climate heat pumps will have to prove themselves through field-testing during extreme weather events, such as the current polar vortex blanketing major parts of the U.S. with subfreezing temperatures. The thermometer dropped close to or below zero in North Dakota, Minnesota and Wisconsin on Jan. 16.

Heat pump sales in U.S. surged past gas furnaces in 2022 | Canary Media

According to Canary Media, 2022 saw heat pump sales edge past gas furnace sales for the first time. Business analysts such as Global Market Insights anticipate the CCHP market will grow 10% per year through 2032.

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Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024

Top legislators in Massachusetts this year hope to pass a major climate and energy bill, which could bring significant permitting and siting reform, and boost transportation and heating electrification.

“The clock is ticking,” Sen. Mike Barrett (D), Senate co-chair of the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE), told NetZero Insider. The legislature has until the end of July to reach a consensus.

“It’s my hope that we’ll have something by the springtime on the floor of the House,” said Jeff Roy (D), House co-chair of the TUE committee.

The TUE committee was responsible for a large portion of the omnibus climate bills passed in 2021 and 2022 under the administration of Gov. Charlie Baker (R). These bills contained wide-ranging provisions aimed at expediting the state’s clean energy transition, including setting emissions limits for the major sectors of the state’s economy and directing the procurement of 5,600 MW of offshore wind capacity.

The general template for the bills, which presumably will carry over into 2024, was for the House and Senate to pass distinct legislation compiled from smaller bills introduced earlier in the session. The two chambers then would form a conference committee to reconcile differences between the bills, with the resulting bill eventually passed by both chambers and sent to the governor.

“It’s going to be a really interesting time,” said Kyle Murray, director of state program implementation at the Acadia Center, a climate-focused nonprofit. Murray praised the steps taken in the previous two bills but added that “we’ve got so many areas we still need to cover.”

Permitting and Siting Reform

One major theme emerging for the session is reforming permitting and siting processes for clean energy projects and infrastructure.

“In order to get all this infrastructure built, and to get it built in a timely manner to have an impact on the goals we set, we need to do something about the permitting and siting process,” Roy said.

For most projects today, “it’s going to take you three to five years to get the shovel in the ground because you have to do so many steps in the permitting process,” Roy said. “We’re looking at legislation to revamp the process and bring it down to more like 18 months.”

Roy has introduced a bill that would consolidate the state and local permitting process under a new “electric decarbonization infrastructure permitting office.” The bill also would introduce a roughly six-month process for the office to respond to applications.

S.2113/H.3187, a separate bill aimed at expediting the development of clean energy while protecting environmental justice communities, would introduce significant reforms to the state’s Energy Facilities Siting Board. The bill is a top priority of the Mass Power Forward coalition, a coalition of many of the state’s most influential climate and environmental organizations.

The proposal is intended to prevent new polluting infrastructure in “the same communities that have been dumped on for decades and decades because of systemic racism,” said Claire-Karl Müller, coordinator of Mass Power Forward. The bill simultaneously would speed up the review process for solar, wind and geothermal projects.

“It’s important to do this transition quickly, but we want to make sure it’s done equitably,” Müller said.

The state’s Commission on Clean Energy Infrastructure Siting and Permitting also is due to publish its final legislative and regulatory recommendations at the end of March. (See Massachusetts Announces Permitting And Siting Reform Commission.) Created by Gov. Maura Healey (D) in the fall, the commission is aimed at cutting timelines and barriers for clean energy projects.

Transmission Planning

The state’s Clean Energy Transmission Working Group (CETWG), created in 2022 climate law, released its final report at the end of December, calling for a “more comprehensive, proactive and forward-looking transmission planning processes.”

The CETWG recommended the legislature amend state laws to allow the Department of Energy Resources to “competitively solicit and select proposals for transmission to deliver clean energy generation to help achieve the Commonwealth’s clean energy requirements, beyond existing authority to solicit and select transmission related solely to offshore wind.”

The final recommendations also called for increased efforts to reduce transmission needs through load growth including time-of-use rates, demand response and energy efficiency. The CETWG also advocated for a regional analysis of the potential of alternative transmission technologies (ATTs).

As an offshoot of their work on the CETWG, Roy and Barrett also introduced bills in the House and Senate that would require utilities to consider ATTs including grid-enhancing technologies, advanced reconductoring and energy storage when planning upgrades to the transmission system.

“We both filed that legislation, which is probably a good sign that it’s something we will agree on this session,” Roy said.

Heating Decarbonization and Electrification

The legislature also is considering a number of bills aimed at supporting heating electrification. Data from the U.S. Energy Information Administration shows that natural gas consumption in Massachusetts increased by about 8% in 2022, and natural gas remains one of the largest sources of carbon emissions in the state.

Legislators so far have submitted a wide range of proposals aimed at cutting gas emissions, from a moratorium on the further expansion of the gas system to bills that would promote blending alternative fuels like renewable natural gas and hydrogen into the network.

For Senate TUE Chair Barrett, one key component is creating “linkage” between the expansion of the electric distribution system and the contraction of the natural gas system.

“Building out the grid — while it’s very important to delivering green juice everywhere it needs to be delivered — is going to make the utilities very wealthy because they make a rate of return on all construction projects,” Barrett said. “What do you ask of the utilities as you deliver vast riches to them? It can’t be zero.”

He noted that approval of increased investments in the grid could be coupled with requiring the utilities to speed up the interconnection of clean energy projects and downsize gas operations.

Barrett also expressed optimism that two programs passed in previous legislation — a new municipal opt-in building code which incentivizes electrification and a 10-town pilot program which allows municipalities to ban fossil fuels in new buildings — will start to make a significant dent in the state’s gas consumption in 2024.

However, both TUE chairs indicated they’re not likely to pass new provisions to directly prohibit the expansion of the state’s gas system, such as an expansion of the 10-town pilot program or a statewide moratorium.

“I think we need time for that pilot project to take place and to get some reporting and data back,” Roy said.

For climate activists pushing for a moratorium on new infrastructure, the verdict on new natural gas infrastructure is clear.

“It is more than beyond obvious that we need to stop building fossil fuels,” said Müller of Mass Power Forward. “We know we can’t be expanding gas.”

The legislature also could consider changes to the state’s Gas System Enhancement Program (GSEP), which is aimed at replacing old pipes to reduce methane leaks. The program has faced criticism for facilitating billions in new gas system investments that could become stranded assets because of the state’s decarbonization efforts. The program ultimately could cost ratepayers over $40 billion, according to a 2021 report.

The 2022 climate bill created a GSEP stakeholder working group, which is tasked with drafting recommendations on changes to the program that would align it with the state’s climate laws. The group released a draft outline of its recommendations in December and likely will publish its final recommendations at some point this session.

The Department of Public Utilities also included legislative recommendations in its recent order on the “Future of Gas” proceeding (DPU 20-80), which requires gas utilities to consider nonpipe alternatives when planning new infrastructure investments and discourages further expansion of the gas system. (See Massachusetts Moves to Limit New Gas Infrastructure.)

The 20-80 ruling also highlighted an apparent contradiction between the state’s required emissions targets and a law passed in 2014 that requires the DPU to “review and approve proposals designed to increase the availability, affordability and feasibility of natural gas service for new customers.”

The DPU recommended the legislature repeal this law to allow the department to “pursue fully its mandate to prioritize reductions in GHG emissions along with safety, security, reliability of service, affordability and equity.”

Speaking at an event in December, DPU Chair Jamie Van Nostrand said the state should reconsider laws that give residential and commercial customers the right to gas service.

“Customers are still going to be provided the essential utility service of heat, but it may be provided in some way other than gas,” Van Nostrand said. (See Clements Outlines Further Steps to Ease Interconnection Woes.)

Transportation

Transportation decarbonization also is likely to be on the docket this session, with the legislature weighing proposals to boost electric vehicle (EV) charging infrastructure and increase ridership on mass transit.

Roy has been especially vocal about the need for more robust charging infrastructure, and he highlighted the state’s ambitious goal to have 900,000 EVs on the road by 2030 (compared to about 70,000 in 2022).

“That’s going to require a huge investment in charging infrastructure,” Roy said. He introduced a bill in early 2023 that would direct state agencies to forecast EV demand and optimal charging locations and require the electric utilities to submit plans for the grid upgrades needed to meet this demand.

Murray of the Acadia Center stressed the importance of securing funding for public transport in the state. According to a recent assessment by the Massachusetts Taxpayers Foundation, the state would need to invest an additional $2 billion annually through 2036 just to make all the necessary repairs for the existing system. This excludes any potential expansion, resilience or modernization efforts to help the state meet its climate goals.

“We need a more stable funding source for the MBTA [Massachusetts Bay Transportation Authority]. I really do think we need to address that at some point in the very near future,” said Murray, while acknowledging the added difficulty of the state’s current financial troubles. Gov. Healey recently proposed a $375 million budget cut to stave off an impending shortfall.

Caitlin Peale Sloan, vice president for Massachusetts at the Conservation Law Foundation, echoed the need to properly fund the MBTA to help reduce total vehicle miles traveled. She added the state also needs to think long term about how to electrify trains and buses, particularly those that operate in environmental justice neighborhoods.

“When it comes to mass transit, it’s a balance,” Peale Sloan said. “We don’t want to make mass transit more difficult and more expensive to users — we want more people using it. But we need to have the big picture plan and start to get that moving.”