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September 27, 2024

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Granholm Discusses Net-zero Tech at ARPA-E Energy Innovation Summit

DENVER — Leaders in energy innovation from across the U.S. traveled to Denver last week to participate in ARPA-E’s 2022 Energy Innovation Summit.

The three-day conference ended with a fireside chat led by U.S. Secretary of Energy Jennifer Granholm.

Granholm started by expressing her excitement to be back in person.

“Since the last time we met virtually, so much has gone on in the world, even yesterday, so much horrible stuff,” Granholm said, referring to the school shooting in Uvalde, Texas.

Jennifer Granholm 2022-05-25 (RTO Insider LLC) FI.jpgU.S. Energy Secretary Jennifer Granholm | © RTO Insider LLC

“[And] the war in Ukraine as well,” she continued. “The impacts on the global energy markets and the fact that gas prices are through the roof and people are really hurting. It just tells you that we have got to move.”

Granholm expressed frustration with the current legislature’s inability to “get the full array of our climate policy through,” but she said she remains optimistic.

“Technology is going to move forward regardless of what’s happening on the policy side, and this is how we are going to ultimately fix the biggest problems that are facing us,” she said.

Beth Zotter, CEO and co-founder of UMARO Foods, and Natron Energy CEO Colin Wessells joined Granholm for a conversation about the technologies their companies are working on to aid the transition to net zero.

Zotter’s company started out by producing algal biofuels out of seaweed to use in the transportation sector.

“UMARO Foods is really built on the vision that the ocean is the most scalable and efficient bioreactor for producing biomass,” Zotter said. She added that the company’s goal is to create the technologies that can unlock the ocean’s potential for producing clean energy.

Her company has moved into the food industry, using seaweed biproducts to produce plant-based foods to complement its existing biofuel production. UMARO plans to roll out plant-based bacon to restaurants in the coming months.

“Right now, algal biofuels need a high-value co-product to basically make the economics for large-scale biorefineries work out,” Zotter said. And with a growing demand for plant-based meat alternatives, it’s a new market opportunity, she added.

On the battery storage front, Wessells said, “Natron Energy is developing sodium-ion batteries to solve electricity reliability problems,” while avoiding widespread industry supply chain issues.

ARPA-E panel 2022-05-25 (ARPA-E) Content.jpgU.S. Energy Secretary Jennifer Granholm (right) participates in a fireside chat with Natron Energy CEO Colin Wessells (left) and UMARO Foods CEO Beth Zotter. | ARPA-E

“We’re removing the supply chain constraints,” he said. “We don’t have the lithium; we don’t have the cobalt; we don’t have the nickel; we don’t have the copper. We can onshore all these materials. We just use iron; we just use manganese.”

Natron is planning a large battery storage project in Holland, Mich., with its new sodium-ion technology. It plans to run about 600 MW of battery production per year of utility-scale grid storage for “data centers, telecom [and] short-duration grid storage. … This will be phase one of a longer-term growth plan,” he said.

With LG Energy Solutions’ investment in battery manufacturing for electric vehicles in March and the various auto manufacturers in the area, Wessells said Holland is poised to become a battery hub in the Upper Midwest.

Wessells said Natron’s goal is “to avert a doomsday scenario for grid storage, where if we don’t have the lithium minerals, we don’t have the grid storage we need.” Being independent of the mineral supply chain may allow Natron to fill the battery storage gap that will get the U.S. to net zero, he said.

Both companies were able to launch with help from funds awarded through ARPA-E grants. Granholm stressed the importance of government working with industry to fund technologies to avert climate change and aid the energy transition.

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Counterflow: Transmission and Technology

tesla powerwallSteve Huntoon | Steve Huntoon

Around the middle of the massive FERC Notice of Proposed Rulemaking on transmission planning, etcetera, we come across a discussion of new technologies.

The NOPR says transmission planning will be improved with the use of dynamic line ratings and other “grid enhancing technologies” (GETs).[1]

Dynamic Line Ratings

It’s hard to see how this can be so. Dynamic line ratings are very important for reducing congestion, as I discussed back in 2019.[2] But they can’t relieve reliability violations — arising from future system conditions or from interconnecting new generation.

Planning is based on worst-case system conditions. Dynamic line ratings can be used to increase dispatch of lower cost resources when temperature and other ambient conditions are better than worst case. But they can’t make the worst-case planning topology better. It’s that simple.

The only apparent use of dynamic line ratings in planning would be this scenario: Assume multiple potential solutions to a reliability violation. Maybe a more expensive solution would be better if its incremental production cost savings outweigh its incremental solution cost. The odds of this happening in practice are slim to none, and Slim left town.

Transmission line ratings that are relevant to planning, including generator interconnection, are unique emergency (contingency) ratings. In its December rulemaking requiring use of ambient-adjusted ratings, FERC also required unique emergency ratings for operations/dispatch, but did not do so for planning/interconnection studies.[3]

But the latter is what matters to save consumers from transmission overbuild, and to save renewable generators from unnecessary costs and delays. FERC did not address the expert engineering comments in that proceeding,[4] creating the irony of higher emergency ratings for operations than for planning.

FERC did not address this subject, yet again, in this NOPR.

Other ‘Grid Enhancing Technologies’

The NOPR also mandates consideration of other “grid enhancing technologies,” which beside DLRs, are specified as “advanced power flow control devices.” As with DLRs, such devices have little, if anything, to do with increasing grid capacity. In looking at the study[5] supposedly supporting the planning/interconnection value of GETs, I can’t find anything relevant. The study at different points refers to planning but then says “GETs focus on operational improvements,”[6] and the value proposition seems limited to improved dispatch.[7] Not planning/interconnection.

What technologies actually do increase grid capacity for planning/interconnection purposes? Technologies that increase physical capacity of grid elements such as those that the Electric Power Research Institute has identified.[8] These include simple things like sag studies to identify possible retensioning and tower raising, and more sophisticated technologies like reconductoring with advanced conductors[9] and applying high-emissivity conductor coatings.[10] None of these are discussed in the NOPR.

Bottom Line

In the worthy endeavor to increase grid capacity and increase renewable interconnections, the NOPR is pushing the wrong set of technologies.

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

[1] Docket No. RM21-17-000, ¶ 267-277, issued April 21, 2022.

[4] https://elibrary.ferc.gov/eLibrary/filedownload?fileid=020C3BCD-66E2-5005-8110-C31FAFC91712. And I addressed this toward the end of my column in footnote 2.

[6] Slide 23.

[7] Slide 26.

[10] Per an Oak Ridge National Laboratory study of conductor coating: “a coated conductor affords approximately a 20% increase in ampacity when operating at the same temperature as an uncoated conductor.” https://info.ornl.gov/sites/publications/Files/Pub138393.pdf (pdf page 10).

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Alliant Energy Leads Challenge of ITC Midwest Capital Structure

Alliant Energy is spearheading a coalition of utilities, industrial customers and consumer advocates contesting ITC Midwest’s capital structure at FERC.

The Iowa Coalition for Affordable Transmission filed a complaint last month, alleging that the equity ratio used in ITC Midwest’s capital structure is unfair and should be reduced to 53% from 60% (EL22-56).

The coalition includes Alliant subsidiary Interstate Power and Light (IPL), the Iowa Office of Consumer Advocate, the Resale Power Group of Iowa, the Iowa Business Energy Coalition and the Large Energy Group, a group of IPL major electric service customers.  

The coalition argued that since FERC accepted ITC’s current capital structure in 2007, “ITC Midwest and MISO have changed substantially.” It said Midwest’s rate base grew by 550% since 2007 “to the point that network and firm point-to-point transmission rates are over 275% higher than the average rates of other transmission owners.”

“Financially, ITC Midwest and its affiliates performed strongly for their investors, so much so that their parent, ITC Holdings Corp. was acquired by Fortis Inc. [in 2016], an international public utility holding company,” they wrote.

The coalition argued that ITC no longer meets the commission’s three-part test to ensure a capital structure won’t result in excessive costs for consumers. It said ITC Midwest doesn’t have its own credit rating separate from ITC Holdings and Fortis, and that its parents effectively guarantee its debt. The group also said ITC Midwest’s 60% common equity ratio “significantly exceeds those set by recent FERC orders and the equity ratios of publicly traded proxy companies.” Thy said it is “excessively skewed toward equity.”

“This conclusion is based on evidence including ITC Midwest’s complete lack of any management-level employees of its own — all of its officers are officers of ITC Holdings — and evidence indicating that debt rating agencies look to ITC Holdings and Fortis when evaluating ITC Midwest’s creditworthiness,” the coalition said.

The group’s suggested 53% is the median of other MISO transmission utilities with similar bond ratings.

“Fifteen years ago, when ITC Midwest was first created to acquire IPL’s transmission system … ITC Midwest had no track record of transmission ownership or investment; it did not even have its own credit rating — FERC approved its capital structure proposal based on an expectation that ITC Midwest would have its own credit rating separate from its parent company,” the coalition said.

The Iowa Utilities Board and the Minnesota Department of Commerce took notice of the complaint and wrote to FERC in support of it.

“ITC Midwest owns transmission in Minnesota, and therefore its existing capital structure and transmission rates have direct implications for Minnesota ratepayers. In addition, the equity ratio issue raised has important long-term implications for Minnesota ratepayers as transmission owners in Minnesota and throughout the MISO region consider adding significant amounts of new high-voltage transmission into their rate base,” the Minnesota Department of Commerce said.

The North Iowa Corridor Economic Development Corp. also sided with the complaint, noting that high energy costs have detracted from potential economic development in the area.

“Our organization has seen directly how higher energy costs here have led local and prospective businesses to choose other locations for expansion,” it said.

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Mayflower Wind Interconnection Change to Reduce Power Price 10%

Mayflower Wind is seeking to amend an 804-MW offshore wind power purchase agreement with Massachusetts’ utilities to reflect a change in the project’s interconnection point to land. The new location will allow Mayflower to reduce the original project bid price by about 10%.

The joint venture of Royal Dutch Shell (NYSE:RDS.A) and Ocean Winds North America, itself a joint venture of EDP Renewables and ENGIE, wants to interconnect the project at Brayton Point, about 50 miles west of the original interconnection point on Cape Cod, according to May 25 testimony to the Massachusetts Department of Public Utilities by Katherine Wilson, manager of long-term clean energy supply at National Grid (Dockets 20-16, -17, -18).

Eversource Energy (NYSE:ES), National Grid (NYSE:NGG) and Unitil (NYSE:UTL) selected the project in a 2019 OSW solicitation, and the department approved the utilities’ PPAs in 2020 for an initial 408-MW phase and a second 396-MW phase.

A change in the project’s interconnection point stems from the developers’ winning a 405-MW project bid in the state’s latest OSW procurement round last year, which includes interconnection at Brayton. Mayflower plans to build common offshore transmission infrastructure to serve the 804-MW project and the 405-MW project, Wilson said. Doing so, she added, would enable other project interconnections at the original site on Cape Cod, where ISO-NE has determined that only up to 1,200 MW of interconnection capacity is available based on planned system upgrades.

The two projects that Mayflower plans to interconnect at Brayton are in a 127,000-acre lease area (OCS-A 0521) that the developers say has 2 GW of generation potential.

Mayflower’s PPAs for the two phases of the 804-MW project allowed for a maximum price of $77.76/MWh, with potential to adjust the price down based on the developers’ ability to qualify for investment tax credits in the future. The maximum price is based on Mayflower receiving a 12% tax credit, and the PPA allowed for a minimum price of $70.26/MWh should a change in law provide for a 30% credit.

By combining the interconnection points at Brayton, Mayflower said it can lock in a price of $70.26/MWh, thereby eliminating ITC uncertainty. Currently, OSW projects that begin construction by the end of 2025 are eligible for a 30% ITC.

Mayflower’s change to the interconnection includes delaying the commercial operation dates (CODs) for the two phases of the 804-MW project by 18 months, according to a joint motion to amend the PPAs filed by the utilities. The CODs for the two phases would change from February 2026 to September 2027, and from June 2026 to December 2027, respectively.

Eversource, National Grid and Unitil filed a petition May 25 with the DPU (Docket 22-72) for approval of a PPA with Mayflower for the 405-MW project awarded last year. Under that PPA, Mayflower would place the project into commercial operation in March 2028.

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PNNL: Communities Should Take Bigger Role in Coal Plant Closures

Twenty-eight percent of U.S. coal-fired power plants are expected to be retired by 2035. 

A recent report by the Pacific Northwest National Laboratory in Richland, Washington, said that the communities hosting those plants need to do a better job of preparing for the loss of these major employers.

“Community impacts of power plant decommissioning are not limited to job and revenue losses. Communities are likely to be impacted culturally, socially, environmentally, and have long-term health-based impacts that should be acknowledged and addressed in post-retirement plans,” the report said. “Despite the economic spillover effects that decommissioning will have on the surrounding community, residents often do not have a say on the decision to decommission a coal plant.”

The report, which is dated September 2021 but was released in April, seeks to understand who in a community is affected when a coal-fired plant shuts down, and how to get those people involved in planning for economic recovery, Bethel Tarekegne, a PNNL equity and renewables researcher, said in an interview. “It’s what is realistic for the community to move ahead,” she said.

The report’s recommendations focus on how a community can get involved as soon as a coal-fired plant is considered for closure, extensive research into options on how to recover from that loss, and public transparency in dealing with the effects

“Understandably, no one size fits all,” Tarekegne said.

As of February, the U.S. had 240 active coal-fired power plants. Between 2010 and the first quarter of 2019, U.S. utilities announced the retirement of more than 546 coal-fired power units, totaling about 102 gigawatts.  Plant owners intend to retire another 17 GW of coal-fired capacity by 2025, according to the U.S. Energy Information Administration, with 12.6 GW slated to shut down this year.

In another report, the EIA said utilities plan to retire 28%, or 59 GW, of the coal-fired capacity currently operating in the country by 2035.

The PNNL study looked at four communities that have lost or will lose their coal-fired power plants.

Wise County, Va. 

This county of 38,000 expects to lose 153 full-time plant jobs and 300 to 400 plant-supported jobs, $6-$8.5 million in annual tax revenue and $25-$40 million in local economic activity. In 2019, the county had a 9.4% unemployment rate when the national average was 5.3% and Virginia was 4.6%.

“This translates into a significant impact on schools and other public services in the area. For a region with high unemployment and poverty rates, the job losses and decrease in economic activity due to the plant closure would be a critical threat. The issue of environmental cleanup is another huge concern among community members, especially the resources for cleaning up gob [accumulated spoil] piles, for which the only remediation solution currently is to burn the gob at the power plant,” the PNNL report said. 

After going online in 2012, Dominion’s 668-MW Wise County plant has picked up many state air pollution violations. It has underperformed in producing electricity, dipping to 22% of expected performance in 2019, and suffered financial losses in 2013 and 2014. 

Virginia passed a law in 2020 that requires most of the state’s coal-fired plant to close by 2024. The rest must be decommissioned by 2045. There is no timeline set for decommissioning the Wise County plant. However, Dominion Energy has the option of revamping the site as a renewable energy facility, the PNNL report said.

Wise County leaders were instrumental in getting a 2021 Virginia law passed that required a public hearing on the decommissioning of coal power plants, required the state to maintain a website detailing decommissioning dates for large carbon-emitting plants, and required investor-owned carbon-emitting utilities to provide decommissioning studies to the public.

Anderson County, Tenn.

This county of 75,000 expects to lose 100 full-time jobs, $70 million in annual tax revenue, and 54% of the Clinton, Tennessee, school district’s tax base when the 881-MW Bull Run Fossil Plant (BRFP) closes in December 2023. The Tennessee Valley Authority opened the plant in 1966.

In 2002, the plant accounted for roughly 60% of the greater Knoxville area’s air pollution. Emissions controls have improved, but the plant’s pollutants have been linked to many deaths, including 21 in one year, the PNNL report said. It has collected multiple federal air pollution violations.

The site has stored more than 10 million cubic yards of coal ash, worrying local residents about the environmental impacts.

“Community opinions about whether the coal ash should be moved offsite or kept in its current location at the BRFP facility are mixed. The decision is a difficult one, because the community will be faced with environmental ramifications and public health consequences if the ash pile is kept onsite but will also encounter significant impacts if the coal ash is removed,” the report said.

TVA is closing the plant because it is unprofitable to run and faces $1.3 billion in needed improvements. TVA has determined it can serve its customers without the facility.  The agency is considering tearing down the plant, but there has been little community input into the site’s fate since the closure decision was made in 2019.

“TVA’s noncommittal attitude toward engaging the community in the decommissioning process has strained their relationship with the community and constituted a large barrier in setting the stage for a just transition process,” PNNL said. “The community wants more direct input in the retirement planning process, and more specifically, a formal negotiation agreement to be signed by the TVA, especially to ensure that the community has some influence on the landfill permitting issue. Since 2018, the TVA has hosted or planned a total of 13 sessions for information dissemination/public involvement in the (the plant’s) retirement process … [three sessions] did not provide opportunities for formal public comments.”

Muskegon County, Mich.

Opened in 1948 and located one mile from Lake Michigan, Consumers Energy’s 320-MW B.C. Cobb plant was closed in 2016 and demolished in 2020. The closure eliminated 160 jobs and about $70 million in annual tax revenue in the county of 173,000. Roughly 13.5% of the county’s population lived below the poverty line in 2019. 

The Muskegon County plant was the last of seven coal plants Consumers Energy decided to close because they were no longer economical to operate, prompting the utility to convert to more economical natural gas and renewable energy. In closing the seven plants, Consumers, which wants to reach net zero emissions by 2040, reduced its carbon emissions by 90%.

The PNNL report said the community was largely uninvolved in the pace and direction of the plant’s closure, although the local government provided some expedited permitting in return for Consumers Energy removing its ash ponds.

“Although the decision-making process was neither equitable, nor entirely transparent, [Consumers] Energy did give the community some leeway in assessing the best future use for the site. [Consumers] Energy recommended alternative uses for the site, including an expanded deep-water port, an agribusiness center, and a sustainable manufacturing center, but ultimately provided funding for the community to conduct studies to better understand their options,” the report said.

Through a third party, Consumers Energy sold the site to a shipping company at the nearby port.

Sherburne County, Minn.

Xcel Energy’s Sherburne County Generating Station (Sherco) in Becker, Minnesota, consists of three coal-fired units capable of producing 2,400 MW and burning 30,000 tons of coal a day. The utility plans to close one unit in 2023, another in 2026 and the third in 2030, and is proposing to open a 460 MW solar plant at the site in 2024.

The closures will eliminate 300 jobs, as well as 14% of Sherburne County’s tax base and 75% of Becker’s tax base.

In 2007, Minnesota lawmakers set economy-wide carbon reduction goals of 30% by 2025 and 80% by 2050. Xcel initially targeted a 40% reduction in its Midwest carbon emissions by 2030, but the retirement of the first two Sherco units would allow the utility to reach 60% reduction by 2030.

“The Becker and broader Sherburne County communities were initially in denial about the plant’s fate and thought Sherco might be saved because it powered a quarter of the Twin Cities. However, the Becker City Administrator strategically shifted the conversation from the need to save the power plant to developing plans for the anticipated power plant decommissioning. … Dealing with the anticipated decommissioning of the plant was a significant undertaking for the community,” the PNNL report said.

Local leaders then began researching options and what the community had to offer to prospective new businesses, including thousands of acres of buffer areas around the three units.  Becker has ended up building a metals recycling plant, helping expand two existing trucking companies, and is planning to obtain a data center to attract new businesses.

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Changes Coming to Massachusetts EV Rebate Program, Energy Commissioner Says

MOR-EV is at a crossroads.

Funding for the Massachusetts electric vehicle rebate program expires at the end of June, and while it’s likely to be renewed in some form, both the Baker administration and the Massachusetts legislature are eyeing policy tweaks to factors from the size of the rebate to the price cap on vehicles.

The state’s Department of Energy Resources commissioned a report on the program, published in March, which lays out several recommendations for targeting consumers in a no-longer-nascent industry.

DOER Commissioner Patrick Woodcock told RTO Insider that the Baker administration will pursue many of those tweaks as the state government prepares for a gubernatorial transition.

“We would like to begin to target the types of vehicles that provide the most emission benefits … and put these programs in a position to have some fiscal stability with them for our successors,” Woodcock said.

Another goal his department is eyeing is to improve equity in the program and reduce the number of “free riders” taking part, who would be purchasing EVs anyway, regardless of the rebate.

The program has shifted several times in its eight years of existence, but in its current form it offers a $2,500 rebate for battery or fuel cell EVs with a purchase price below $50,000, and a $1,500 rebate for plug-in hybrid EVs.

The price cap of $50,000 is one of the main targets for Woodcock and the Baker administration, who are recommending lowering it to $47,500.

“Reducing the vehicle purchase price cap is highly likely to improve financial sustainability, cost-effectiveness and equity,” the report said. It would reduce the percentage of EV sales eligible for the credit, reduce “free ridership” and ensure that more rebates are available for lower-cost vehicles.

Limiting rebates for plug-in hybrids (only allowing them when there are no EV alternatives in the same price point) is another central plank of the administration’s plans.

“We do think we’ve gotten to a saturation level that we really should be encouraging battery EV purchases,” Woodcock said.

The administration is also looking at moving the rebates to point-of-sale, expanding the rebate to used EVs and adding separate incentives for low- and moderate-income (LMI) consumers.

In the Legislature

Changes to the program might not all be up to the administration or even the next governor.

The two chambers of the Massachusetts legislature are working on an energy bill that could include new EV provisions. (See Mass. Legislators Try to Hash out Next Climate Bill). The House version is narrowly focused on offshore wind, but the Senate has proposed changes and an influx of money for EVs.

The Senate proposal takes a different tack from what DOER is putting forward. It would create a $100 million EV Adoption Incentive Trust Fund to keep the money flowing past June.

But it would maintain the $50,000 price cap, while increasing the rebate amount to as much as $5,000 and adding point-of-sale rebates and an extra value to the rebate for LMI consumers.

The Green Energy Consumers Alliance, which has been tracking possible changes to MOR-EV, notes that the funding itself would support less than 30,000 EVs.

“Let’s get the new MOR-EV program up and running with the understanding that we will need other policies beyond consumer rebates to reach the larger goal,” the advocacy group wrote in a May 9 blog post.

Short-term Solvency?

Unaligned priorities mean that DOER may have to dig into its reserves to keep the program running this summer.

MOR-EV funding expires at the end of June, but the legislature has until the end of July to agree on a compromise for the negotiation.

Woodcock said that a funding shortage for the program in 2019 forced the department to balance its resources in a way that prepares it for gaps.

“We have full confidence that we’ll be able to continue to administer this program for a number of months even if there isn’t an extension of the budgetary language,” he said. “We certainly hope there’s clarity as soon as possible with the program, but we don’t see that there would be a significant disruption in July or August.”

Woodcock wants to ensure stability for the program heading into the gubernatorial transition.

“Stability is one cornerstone of good public policy,” he said. “From my vantage point, from the discussions in the Massachusetts legislature … it’s just a question of how long, by what duration, and what funding levels the program will be in.”

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ISO-NE Summer Outlook Sunnier than Elsewhere, but not Without Clouds

New England might not be facing the same dire system reliability warnings as other regions this summer, but periods of above average temperatures could still stretch the grid and force ISO-NE into emergency action, the grid operator said Wednesday.

The region is “expected to have sufficient resources to meet consumer demand for electricity this summer under typical weather conditions,” ISO-NE said in its summer outlook.

But peak system conditions brought on by above average hot and humid weather could lead to “tight supply margins,” the RTO said. That could lead ISO-NE to call on emergency imports or reserves, ask residents to conserve energy, or issue controlled power outages in extreme cases.

“Climate change has caused weather to become more volatile and less predictable, increasing the potential for system operators to resort to these actions,” it said.

NERC has warned that large swaths of the country in the West, Midwest and Texas are facing possible supply shortfalls this summer. MISO in particular is facing a “high risk of energy emergencies during peak summer conditions” because of a capacity shortfall and the outage of a key transmission line. (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.)

ISO-NE is forecasting that under typical weather conditions, demand will reach 24,686 MW. An extended heat wave could push demand to 26,416 MW, which would be higher than last summer’s peak of 25,801 on June 29. The all-time record for electricity demand is 28,130 MW in 2006.

The region has more than 31,000 MW of capacity available for the summer, including generation, demand response resources and imports.

The summer forecast incorporates more than 2,100 MW of energy-efficiency measures, ISO-NE said, as well as a reduction of more than 900 MW from solar PV installations during peak hours.

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Enviros, NY RNG Developer Argue over Emissions

Bluebird Renewable Energy says its plan to transport renewable natural gas from existing anaerobic digesters in Western New York will reduce their on-site emissions, disputing claims to the contrary by environmentalists (21-G-0576).

In a late May exchange of arguments filed with the state Public Service Commission, a group of environmentalists continues to question the developer’s emissions analyses for a proposed facility that would take RNG produced from manure of nearly 7,000 dairy cows and truck it 70 miles to an interstate pipeline.

Bluebird Renewable Energy (BRE) is seeking approval of its project as furthering the state’s Climate Leadership and Community Protection Act (CLCPA) commitment to 100% zero-emission electricity by 2040 and a reduction of at least 85% below 1990-level greenhouse gas emissions by 2050. (See Western NY Dairy RNG Project Draws Opposition.)

A May 25 filing — by Irene Weiser, coordinator for Fossil Free Tompkins; Brian Eden of the Campaign for Renewable Energy; and Bob Wyman, a self-employed electrification advocate who is currently running for Congress — urged Administrative Law Judge James Costello to move the proceeding to a discovery period, followed by an opportunity to provide testimony. The signees said they believe that the emissions data provided by BRE reveal material issues of fact that interfere with attainment of the CLCPA greenhouse gas-reduction goals.

“In particular, we assert that BRE’s emission analysis does not account for all the emissions it should and that once a more complete emissions analysis is provided, it will demonstrate that the current system has lower emissions than the proposed RNG project,” they said.

Emissions Analyses (BRE) Content.jpgEmissions from the proposed equipment and the electricity required to replace the on-site generation (and emissions from truck transport of the RNG to the pipeline interconnection, which are very small comparatively) are summed and represent total annual Proposed Project emissions. | BRE

 

Specifically, they claim that BRE’s analysis has not accounted for emissions from the end use of the RNG; the transmission and distribution of the RNG following injection into the gas pipeline system; and the increased production of biogas.

In its May 27 response, BRE accused the intervenors of fishing for information in an untimely fashion and using the regulatory process to “request an opportunity for additional discovery at the 11th hour to, presumably, delay the proposed project from being approved.”

BRE said the information from its emissions analyses has been available since March and that the intervenors “could have, and indeed should have, executed the protective order, reviewed the emissions analyses and proffered additional information requests in a timely manner.”

Information relating to the emissions associated with transporting the RNG to the injection site were included in the emissions analyses, as were anticipated fugitive emissions, BRE said.

“The proposed project will not have any impact on the end use of gas, gas demand or the interstate pipeline itself. The RNG will be a one-for-one replacement of geologic natural gas in the interstate pipeline. As there will be no impact on the interstate pipeline, calculations relating to the emissions associated with the interstate pipeline are unnecessary. Moreover, the interstate pipeline is outside of the commission’s jurisdiction,” BRE said.

BRE also said it has not specifically calculated the potential emissions associated with compressing and decompressing the RNG for use in the interstate pipeline, and that nonetheless, such operations are outside the scope of the commission’s jurisdiction.

The developer asked Costello to determine that the letter filed by the intervenors fails to establish that issues of material fact exist; determine that no additional process is needed; and refer the petition to the PSC for approval.

In a May 31 response “correcting” BRE, Wyman said that he and the other environmentalists have consistently asserted that BRE’s statements that their proposed system will reduce emissions are incorrect or, at least, subject to significant doubt.

“The existing record, although incomplete, already establishes that BRE’s claim of emissions reductions is false. No additional information is required to support the development of testimony that establishes and explains the incorrectness of BRE’s claims,” Wyman said.

The request for additional discovery is motivated not by a desire to prove that an issue of fact exists, but rather to ensure that the issue and relevant facts are as well established in the record as possible, he said.

“The desire is not to discover information needed to make testimony possible, but rather to increase the quality and correctness of at least some of the testimony which will certainly be submitted, when the time for such testimony arrives,” Wyman said.

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The Pitfalls of Nuclear Energy Planning with Different Models

Depending on which high-level computer model is used to map out the role of nuclear in decarbonizing the U.S. power system, by 2050 the country could have anywhere from 2 to 329 GW of nuclear power in its generation mix, according to a new report from the Electric Power Research Institute (EPRI).

Such broad variability shows the inherent weakness of such widely used models — most of which have been developed by federal agencies — and the assumptions embedded in them. But the report also finds strong commonalities across the models, such as the critical role decarbonization policy, cost and regional economies may play in nuclear deployment. For example, the models all suggest that regions with strong decarbonization policies, but low wind or solar resources, will tend to have more nuclear, the report says.

Similarly, lowering costs — from $5,000/kW to $2,000/kW — will be a key factor in increasing nuclear capacity on the grid. Lower costs, plus a zero-carbon policy, pushes 2050 capacity to the high end of the range: 285 to 329 GW.

EPRI CEO Arshad Mansoor underlined the integral and intertwined role nuclear power and computer modeling must play in the energy planning needed to reach President Biden’s goal of decarbonizing the U.S. grid by 2035, especially for federal agencies.

The models in the study include EPA’s Integrated Planning Model, the Energy Information Administration’s National Energy Modeling System and the National Renewable Energy Laboratory’s Regional Energy Deployment System, as well as EPRI’s Regional Economy, Greenhouse Gas and Energy model.

Benchmarking and coordinating across these models will be critical to advancing nuclear power in the next decade, Mansoor said at a launch event for the report on Thursday in D.C. “We have to make sure there is an operational [small modular reactor]. We have to make sure there is an operational [next-generation] non-advanced lightweight water reactor. We have to make sure that the [Defense Department’s] Alaska project for microreactors actually works,” he said.

Nuclear Capcity in 2050 (EPRI) Content.jpgWith 100% carbon-free policies, the U.S. would maintain its existing nuclear plants, with cost again driving rapid growth, across all models. | EPRI

 

Without solid progress, Mansoor said, the current surge of interest in nuclear “will fizz out.”

Echoing Mansoor’s urgency, Alice Caponiti, deputy assistant secretary for reactor fleet and advanced reactor deployment at the Department of Energy, said, “It is essential that we have the ability to accurately model and communicate the benefits of nuclear energy, and therefore it’s critically important that we understand how these models account for nuclear energy production and where they have limitations and gaps.

“We need to ensure that planning tools are not biased by poor or outdated assumptions or by limitations in the tools, such as the ability of nuclear to operate flexibly or to assume that a plant is shut down at the end of its license,” Caponiti said.

The data that go into these models are therefore critical, said Brent Dixon, national technical director for nuclear systems analysis and integration at the Idaho National Laboratory. For example, with no new advanced reactors yet built, current models cannot accurately project how costs may go down over time, Dixon said.

Assumptions based on algorithms may produce different and less accurate results than actual data from the field, he said. “We need to look closer to find out why there is a difference between the data and what these algorithms predict.”

Angelina LaRose, assistant administrator for energy analysis at the EIA, agreed, noting that computer models are frequently wrong, but “the goal is to make them wrong in a useful way … so policymakers can identify attractive points of leverage, potential pitfalls and unintended impacts, both beneficial and detrimental, and approaches to achieve whatever policy goal they have in mind.”

Clean, Firm Electrons

Nuclear power now accounts for 20% of all electricity — and 50% of all carbon-free power — generated in the U.S. The need to keep the current fleet online into the next decades, beyond the existing licenses of individual plants, is one point of agreement across models in the study.

The public is still divided on nuclear, with a recent poll from the Pew Research Center showing 35% of those surveyed in favor of federal support for nuclear versus 26% against and 37% neutral. But as increasing amounts of solar and wind have come onto the grid, nuclear has become a focus in the industry as a source of clean, firm, dispatchable power, Dixon said.

“All electrons are no longer the same,” he said. “Some are worth a lot more, and those are the electrons that are clean, firm electrons, and that’s your area for nuclear to compete in as we go forward.”

The study tests the different models across a set of policy, economic and technical variables — what analysts call “sensitivities” — beginning with a “native” scenario based on existing policies and regulations, plus scenarios aimed at reducing greenhouse gas emissions by either 80 or 100% by 2050. The models were also run with “harmonized” cost and technology assumptions, a low-cost scenario, and one assuming regulations providing a nuclear “carveout” that would increase nuclear on the grid over time.

The variability of results can be dramatic. With federal policy pushing an 80% carbon reduction by 2050, EPA’s model provides mostly conservative estimates of nuclear growth ― below 100 GW ― except with a nuclear carveout. The EIA and NREL models, on the other hand, show a low-cost scenario with 250 GW of nuclear, but only 150 GW with a nuclear carveout.

The results of these different scenarios come with a big caveat: The technology and policy assumptions used in the study “do not reflect policy or market expectations of the modelers or their respective organizations” and are not intended as a “policy development exercise.” The modeling for the study was also completed before passage of the Infrastructure Investment and Jobs Act, so the law’s incentives for nuclear and other clean energy technologies were not factored into the scenarios.

But the report repeatedly shows that differences in results also provide major insights. For example, models using different “temporal resolutions” — that is, how many time units are factored into a scenario — demonstrate that simplified resolutions based on seasonal averages or the levelized cost of energy “tend to understate the value of broader technological portfolios … and can overstate the value of solar generation,” the report says. “The need for dispatchable, firm capacity is clearer with higher temporal resolution across all policy scenarios.”

In a recorded video message, Kathryn Huff, DOE assistant secretary of nuclear energy, pointed to the study’s work on temporal resolution as one of its significant advances. “Unless you accurately capture the two-minute or two-hour sorts of time scales on which our energy system has to balance, you may not get a realistic understanding of what our grid needs to look like,” she said.

Going forward, Mansoor said that models also must be able to incorporate the different values of nuclear, as a provider of inertia or for energy security in volatile markets. “We need an integrated model that values not just nuclear as an electricity provider but also as a tool to help industries to decarbonize,” he said.

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PUC OKs NV Energy Battery Project on Old Coal Plant Site

Nevada regulators on Tuesday approved a permit for NV Energy to build a 220-MW battery storage system at the former site of the Reid Gardner coal-fired generating station in Clark County.

The two-hour, lithium-ion battery storage system will cost an estimated $217 million and is expected to be operating by May 2023. The Public Utilities Commission of Nevada (PUCN) approved the construction permit on a 3-0 vote.

The project includes a new 230-kV substation, a 230-kV transmission line and interconnection facilities at the existing Reid Gardner substation. The site was formerly home to the Reid Gardner generating station, which closed in 2017 and was NV Energy’s last coal plant in southern Nevada.

NV Energy said the battery storage project would help it more efficiently manage the growing number of solar resources coming online as part of the utility’s decarbonization efforts.

The project is still subject to approval by other state and local authorities.

Part of IRP Amendment

The Reid Gardner battery storage project is one piece of a proposed amendment to NV Energy’s 2021 integrated resource plan (IRP). Tuesday’s approval assumes the commission will also approve the IRP amendment. A hearing on the amendment is scheduled for July 20.

The proposed IRP amendment also includes a power purchase agreement for 25 MW of renewable energy from the North Valley geothermal facility.

The amendment proposes upgrades to three peaker projects that would increase peaking capacity by a combined 48 MW and cost $24 million. The upgrades would be in service by May 2024.

In addition, NV Energy wants to spend $3.5 million to continue exploring a 1,000-MW pumped hydro storage project in White Pine County in eastern Nevada. The expenditure would give the utility exclusive rights to acquire the project. The project, which is being developed by rPlus Hydro, would interconnect at the Robinson Summit substation.

In its application filed with the PUCN, NV Energy said the IRP amendment would help address concerns about regional market capacity.

As a result of climate change, NV Energy said it must “re-evaluate established practices, in particular large reliance on market purchases, to ensure sufficient capacity to meet peak demands during the summer.”

NV Energy pointed to an energy emergency alert event on July 9, 2021, when a Southern Oregon wildfire cut off about 5,500 MW of transmission capacity on two primary lines from the Pacific Northwest to the Southwest. At the same time, demand was surging as Nevada and other states experienced near record-breaking temperatures. NV Energy set a new combined system peak load record that day.

“Climate related incidents such as this no longer appear to be isolated events,” the utility said.

Sierra Club Support

The Sierra Club filed comments with PUCN in strong support of the proposed Reid Gardner battery storage system.

“The project will provide peak capacity during times of high demand, reduce reliance on market capacity, and support the integration of solar energy resources into the grid,” wrote Elspeth DiMarzio, senior campaign representative for the Sierra Club’s Beyond Coal campaign.

Battery storage projects are a more cost-effective way to increase capacity than the utility’s proposed gas plant upgrades, DiMarzio said.

And by building at the Reid Gardner site rather than on undeveloped land, NV Energy will minimize environmental impacts of the project, DiMarzio wrote.