Today the LPO announced a conditional commitment for a low-interest loan guarantee of up to $15 billion for PG&E’s Project Polaris, which was submitted to the feds for consideration in June 2023. If finalized, the loan guarantee will support a portfolio of projects to expand hydropower generation and battery storage, upgrade transmission capacity through reconductoring and grid-enhancing technologies, and enable virtual power plants throughout PG&E’s service area. The utility, which serves about 16 million customers in Northern and Central California, says the loan will help it meet forecasted load growth, increase electric reliability, and reduce costs for its rate base.

Today’s announcement is the second Energy Infrastructure Reinvestment (EIR) project under LPO’s flexible loan facility and disbursement approach tailored for regulated, investment-grade utilities. The first was for the restoration and repowering of the Holtec Palisades nuclear plant, slated to become the first shut-down nuke plant to be recommissioned in the United States.

Electric utility borrowers for EIR projects must demonstrate that the financial benefits received from the DOE loan guarantee will be passed on to the customers of that utility or the communities it serves. LPO borrowers must develop and implement a comprehensive Community Benefits Plan (CBP), which ensures borrowers meaningfully engage with community and labor stakeholders to create good-paying, high-quality jobs and improve the well-being of the local community and workers. In its CBP, PG&E plans to expand its outreach programs to boost engagement and deliver community benefits in partnership with key stakeholders, including local governments, Native American Tribes, community-based organizations, and low-and-middle-income customers. PG&E has committed to locating many projects in disadvantaged communities, as identified by the Climate and Economic Justice Screening Tool.

LPO’s holiday spending spree

It’s no secret that the LPO is trying to get as much money as possible out the door before the Trump Administration takes office on January 20. In September, Trump pledged to rescind any unspent funds under the Inflation Reduction Act (IRA), the bipartisan infrastructure law that has pumped billions of dollars into the domestic supply chain and clean energy projects from coast to coast.

“To further defeat inflation, my plan will terminate the Green New Deal, which I call the Green New Scam,” Trump promised.

While it’s understandably easier for the President-elect to reign in unspent funding, he will have a tougher time navigating conditional loan guarantees and virtually no chance of recalling funds that have been distributed. According to the Wall Street Journal, the LPO is expected to extend the loan to PG&E via multiple cash installments spread out over several years, and the funding cannot be withdrawn by subsequent administrations. The LPO has closed on more than a dozen loans so far, totaling more than $13 billion.

The LPO has been especially this month, announcing a flurry of new loan activity. Yesterday, it announced $9.63 billion for BlueOval SK to finance the construction of three electric vehicle (EV) battery plants in Tennessee and Kentucky. Last week, DOE closed on a $1.25 billion guarantee with EVgo to expand public fast-charging infrastructure nationwide. The week before that was highlighted by a $303.5 million loan guarantee for Eos Energy Enterprises to support two Pennsylvania-based manufacturing facilities developing long-duration batteries. DOE also inked a conditional commitment of up to $7.54 billion with StarPlus Energy, a joint venture between automaker Stellantis and South Korean battery maker Samsung SDI, that will finance two lithium-ion battery cell and module factories in Indiana. According to an analysis by TechCrunch, automakers and battery manufacturers have attracted more than $112 billion via the IRA to build out domestic facilities.

How much more can DOE’s LPO spend?

The LPO has been granted the authority to distribute hundreds of billions of dollars to innovative clean energy and advanced manufacturing projects.

Through September 2024, the office reported financing nearly $44 billion worth to date. As of the EVgo announcement referenced above, that total was closer to $55 billion. Tacking on the billions for BlueOval SK’s battery plants and the PG&E guarantee brings LPO’s total near $90 billion. And there’s more to come.

Through November 2024, DOE’s LPO reports more than 200 active applications accounting for more than $324 billion in requested funding.

As of the start of this month, DOE estimated it had around $397 billion left to play around with, including more than $244 billion for Title 17 Energy Infrastructure Reinvestments, which PG&E just dipped into.

Cause for concern?

Electric utilities are rightfully concerned with the survivability of the LPO once Trump returns to the White House. Entire programs went dormant during his first presidency, and Trump will have the support of a Republican-majority House and Senate this time around.

Earlier this month, Duke Energy Carolinas and Duke Energy Progress paused their consideration of utilizing DOE loans, recognizing the money may not be there under Trump 2.0. According to a recent filing, Duke was about to hire a consultant to review EIR opportunities, but will now wait for the dust to settle.

“It is in the best interest of customers to pause any further efforts or expenditures until February, following the appointment of the new administration to gain clarity on the future of the EIR Program,” Duke Energy said.

PG&E is curious to see how it shakes out too.

“I think the number one thing that we’re interested in learning more about is the approach to the DOE loans,” detailed Shawn Adderly, director of PG&E’s Transmission Performance Center in a recent webinar on POWERGRID.

Adderly notes the application language is currently tied to renewable projects coming online, and he wonders whether the incoming Trump Administration will reframe consideration around something like predictability or grid security.

“We do need to upgrade our infrastructure,” Adderly admitted, referencing transformers operating past their expected lifespan and aging transmission lies. “I’m really hopeful, especially with the incoming administration campaigning on removing some of the bureaucracies, that they would encourage the permitting reforms to continue and to streamline the processes of regional planning and actions siting.”

“The biggest concern is just where the DOE loans land,” he reiterated.

Originally published in Renewable Energy World.

This award of more than $12 million went to the Lewis Ridge Pumped Storage Project in Bell County, Ky. The project is led by Lewis Ridge Pumped Storage LLC, an affiliate of Rye Development. The $12 million (of the total project federal cost share of up to $81 million) in funding was given to begin Phase 1 activities.

The project involves converting former coal mine land into a 287 MW pumped storage hydroelectric facility. This closed-loop facility would consist of two artificial reservoirs at different elevations. The project can store up to eight hours of electricity when demand is low and provide a generating capacity of up to 287 MW during times of peak electricity demand. The Lewis Ridge Pumped Storage Project would be one of the first pumped storage hydropower facilities constructed in the U.S. in more than 30 years and the first to be built on former mine land, DOE said.

During Phase 1 of the project, Lewis Ridge Pumped Storage LLC will begin work on budgeting, scheduling, permitting, land rights and licensing with the Federal Energy Regulatory Commission (FERC).

In March 2024, Hydro Review reported that the Lewis Ridge project was one of the projects included in a DOE announcement of up to $475 million for five projects to accelerate clean energy deployment on current and former mine land. Developing clean energy projects on mine land provides an attractive economic alternative to using undisturbed natural and agricultural land. Mine land is often located near critical infrastructure that makes it suitable for clean energy development, including electric substations, transmission lines and access to roads or railroad lines.

The Lewis Ridge project plans to interconnect with local transmission, improving grid reliability. And as part of its community benefits commitments, this project anticipates creating about 1,500 construction jobs and 30 operations jobs, adding millions of dollars in tax revenue to the community over the project’s projected 100-year lifetime. In addition, Lewis Ridge plans to support workforce development opportunities through partnerships with unions and the Southeast Kentucky Community & Technical College and by providing a Registered Apprenticeship Program and other subsidized workforce training activities.

Today, most power generation facilities, including hydropower plants, are connected via the internet. While NREL says interconnectedness improves operational efficiency and keeps costs low, it also increases the risk of cyberattacks. In the last 20 years, over 40 cyberattacks have targeted hydropower facilities, per NREL.

“Older hydropower facilities were built long before the digital era, so it follows that they were not designed with modern cybersecurity in mind,” said NREL cybersecurity researcher and network security engineer Anuj Sanghvi. “Now that we’re in the digital era, adversaries that use data as their main source of leverage are thinking, ‘How can we hold energy generation hostage?’”

The CVF offers managers of hydropower facilities a self-guided, automated way to assess their plant’s cybersecurity risks and consider upgrade investments. The tool provides risk probabilities and scores, which NREL said highlights the financial value of cybersecurity improvements needed to handle future threats. Whereas the original CVF allowed users to assess only one facility per organization, CVF 2.0 allows users to assess multiple facilities in an organization.

“Any given organization has multiple projects and multiple facilities,” Sanghvi said. “With these updates, users can conduct any number of assessments for any number of facilities. This allows users to compare multiple facilities and then make informed decisions at the organizational level.”

In addition, CVF 2.0 features updated dashboards that are meant to allow users to better visualize the CVF’s risk assessments, including an output called valuation guidance — a list of prioritized action items and recommendations that shows the potential impacts of cybersecurity risks in order to demonstrate the importance of minimizing those risks. This improved interface provides a clearer picture of potential losses like equipment damage, operational downtime, and safety — all of which can be mitigated by operators through cybersecurity investments.

“Cybersecurity investments can include buying a new gateway device or security application,” Sanghvi said. “They can also look like hiring new staff dedicated to cybersecurity or training existing staff on the most current cybersecurity technologies.”

The CVF team are now working on future CVF upgrades that will convert the tool’s value-at-risk score —which measures a facility’s risk level and shows the number and types of resources needed to improve cybersecurity — into monetary values. These values will show how much money a facility could lose if risks go unaddressed, as well as what it might cost a facility to invest in technologies, processes, and employees that will help address the facility’s cybersecurity risks.

“We hope these updates will make the CVF easier to use and also more helpful for users’ day-to-day-decision-making,” said Sanghvi. “Ultimately, we want the CVF to provide users with enough information that they can see cybersecurity not as a burden but as something to improve their operations and make them more resilient.”

Nearly 38% of 445 utility companies globally had weak cybersecurity management programs as recently as 2022, according to recent research by Morningstar Sustainalytics. The figure did improve to nearly 27% in 2023, but Sustainalytics said it believes cybersecurity has become a major concern for utilities companies, according to the report, The Downside of Digital Transformation for Utilities: Data Privacy and Cybersecurity Risks.

Among the recorded incidents affecting the companies tracked in the Morningstar Sustainalytics to date, the majority of data privacy and cybersecurity incidents in the utilities sector involved breaches that compromised thousands of customers’ personal information. 

Cyberattacks have also caused service disruptions. For example, Luma Energy, a grid operator in charge of modernizing the power infrastructure in Puerto Rico, suffered a cyberattack in 2021 that blocked users from accessing their customer portal accounts during outages. Similarly, Colombian utility, Empresas Públicas de Medellín, experienced a cyberattack in 2022 that caused disruptions to its office operations as well as to customers’ meter and bill payments. Hydro-Quebec, a major grid operator in Canada, suffered an attack in 2023 that caused its app and website for verifying outages to go offline.

“Significant” capacity expansions are driving the increase in solar generation, EIA said, with solar accounting for 59% of U.S. generating capacity additions in the first half of 2024. The increase in solar capacity was also supported by the development of new battery storage capacity, EIA said.

Perhaps not a surprise, Texas and California are expected to receive the largest gains in solar generation this year: 16 billion kilowatthours (BkWh) for the former, and 9 BkWh for the latter, per EIA.

The EIA credits part of the increase in generation to a hot start to the summer, which resulted in higher air conditioning demand. Next year, EIA predicts an additional 1% (60 BkWh) increase in generation, largely due to ongoing growth in electricity demand, primarily from the industrial sector.

Nationwide, EIA predicts a 37% increase in solar power (60 BkWh) this year, followed by a a 2% increase (35 BkWh) in natural gas, followed by smaller increases in wind (up 6%, or 27 BkWh) and nuclear (up 1%, or 11 BkWh).

Utility-scale solar generation is growing across all regions of the country, EIA said, and is expected to increase 34% nationwide this year through “rapid” installation of solar projects. Solar generating capacity grew in the first half of 2024 by 12 GW, which accounted for 59% of all capacity additions across all types of energy sources.

The increase in natural gas generation was driven by low fuel costs and higher overall electricity demand, EIA said. A few new combined-cycle plants have come online in the past year, but the new capacity has been offset by other plants’ retirements, EIA added. Forecast natural gas generation in 2024 is increasing the most in the Midwest (up 11 BkWh) and in the Mid-Atlantic (up 9 BkWh). EIA expects less natural gas generation in California this year (down 6 BkWh) and in the Southwest (down 2 BkWh), in response to large increases in solar generation.

Coal-fired generation is down in most regions as it’s displaced by natural gas, renewables, and plant closures, per EIA. Coal-to-natural gas switching is most evident in the Central/SPP region, where the EIA forecast 9 BkWh less coal generation this year than in 2023.

Regarding emissions, EIA expects energy-related carbon dioxide (CO2) emissions to remain flat between 2023 and 2025. EIA maintains that in 2024, the stability of total CO2 emissions is a result of rising natural gas consumption across sectors, offset by less generation from coal. Additionally, EIA expects emissions in 2025 to remain unchanged, as a less than 1% decrease in natural gas emissions, caused by a decrease in naturual-gas fired electricity generation, is offset by a 1% increase in petroleum emissions associated with increased diesel consumption.

EIA also expects the carbon intensity of energy (the total energy-related CO2 emissions per unity of energy consumed) to decline by 1% both this year and next. This reduction can be attributed to renewable energy sources supplying an increasing share of U.S. energy, EIA said. Primary energy consumption is expected to grow by about 1% in both years, with more than 50% of the growth met by solar, wind, and hydropower.

Through the agreement, which kicked off in July, FirstLight will deliver Burlington more than 54 GWh of hydropower and associated VT-1 renewable energy credits through 2025 from FirstLight’s Shepaug Generating Station in Connecticut.

Shepaug is Connecticut’s largest hydroelectric generation station and is also the second largest source of carbon-free electricity in the state, located on the Housatonic River in Newtown and Southbury. Built in 1955, it has a 42.6 MW capacity.

“Our new collaboration with FirstLight serves as another example of Burlington Electric Department’s and the City of Burlington’s commitment to continuing to source 100% of our power from a mix of different types of renewable generation, while maintaining reliability for our customers,” said Darren Springer, BED General Manager.

BED has purchased 100% of its power supply from renewable sources since 2014. As the city transitions away from fossil fuels in the thermal and ground transportation sectors largely through electrification, it expects electricity demand to grow.

To support this increased demand while ensuring its energy mix remains 100% renewable, BED is looking to strategic partnerships like this new PPA with FirstLight to secure additional clean power generation.

“As we electrify more of our heating and transportation needs, BED will continue to look for opportunities to source renewable power to meet demand,” he said.

“We are grateful for thoughtful partners like FirstLight, whose reliable, cost-competitive, clean electricity generation supports our climate goals in Burlington and helps to decarbonize the New England grid.”

FirstLight has a diversified portfolio that includes over 1.65 GW of operating renewable energy and energy storage technologies and a development pipeline with more than 4 GW of solar, battery, hydro, onshore wind and offshore wind projects. FirstLight specializes in hybrid solutions that pair hydroelectric, pumped hydro storage, utility-scale solar, large-scale battery and wind assets. The company’s mission is to accelerate the decarbonization of the electric grid by supporting the development, operation and integration of renewable energy and storage to meet the world’s growing clean energy needs and deliver an electric system that is clean, reliable, affordable and equitable.

Georgia Power is celebrating Generation Appreciation Month, a time to recognize the more than 1,100 team members who “work tirelessly in power plants across state to keep reliable energy flowing to the grid on hot summer days, cold winter mornings and every hour in between.”

“In life, as well as with Georgia Power’s power generation facilities, there is no one-size-fits-all option,” said Rick Anderson, senior vice president and senior production officer for Georgia Power. “From the existing facilities that have powered Georgia for decades, to newer sources of generation such as renewable energy, cleaner natural gas and battery storage, Georgia Power’s diverse generation mix continues to evolve to meet the needs of a growing Georgia. To keep the energy flowing, we need a workforce that is just as advanced and diverse.”

Based on available opportunities, a career in power generation offers many possibilities for those who join the team, Georgia Power said. Career paths exist in the areas of operations, maintenance, electrical, instrumentation, engineering and more. Last year, the company hired over 80 team members across generation facilities and expects the hiring trend to continue in the coming years. Strong training programs exist in Operations, along with apprenticeships in Mechanical and Electrical, which develop experienced journeymen who work safely to keep energy flowing to the grid, 24/7.

Georgia Power also highlighted the “continuous learning” it offers, including the Rockmart training facility where electrical, mechanical, and instrumentation and control technicians hone their skills each year. In 2023, this facility conducted nearly 3,000 hours of both hands-on and classroom instruction. Subject matter experts from both Southern Company and external entities visited to assist in this training program.

The U.S. Department of Energy (DOE) conducted supply chain “deep dives” on renewable energy technologies, including hydropower and large power transformers. Since the deep dives were published, the Water Power Technologies Office (WPTO) has focused on improving its understanding of the hydropower supply chain and developing strategies for addressing supply chain challenges. The report, Hydropower Supply Chain Gap Analysis, was prepared by NREL for DOE and WPTO.

Because the challenges outlined in the deep dives are most acute for large systems greater than 100 MW, NREL’s report focuses on large systems but expects that its recommendations will improve the supply chain for all hydro systems regardless of scale. Additionally, since the federal government owns almost 50% of the nameplate capacity for conventional hydropower systems with 40% (18 GW) of these units being at least 100 MW, the federal fleet is used to prime the development of the supply chain for the rest of the industry, NREL said.

State of the supply chain

The analysis focused on the upstream and midstream sectors of the hydropower supply chain, as they have “limited” domestic capacity, NREL said.

Upstream supply chain components include raw material extraction, concentration, and processing into engineered materials. The U.S. has strong iron mining and steel production capabilities, NREL said, but it has limited to no mining of the trace metals used in steel, and it imports more than 40% of its copper. Additionally, there are only two domestic facilities with forging capabilities for large hydropower shafts (50-75 tons) and a single domestic foundry that can cast large turbine runners greater than 10 tons.

In the midstream supply chain, the first stage is composed of the manufacture and assembly of hydropower components like hydrogenerators and turbines. Some U.S. companies manufacture components, but international competition is “intense,” NREL said, and acquiring components for 100-MW or larger systems is difficult to procure domestically — only one foundry is capable of producing castings greater than 10 tons, and no domestic manufacturers exist for hydrogenerators greater than 20 MW.

Gap analysis

Five “major” gaps in the domestic hydropower supply chain were identified in the report.

1. Unpredictable and variable demand signals

The development of a domestic hydropower supply chain is held back by an unpredictable and highly variable demand for materials and components, NREL said. Hydropower systems typically have long lives, so replacements and refurbishment schedules have cycles that last years or decades.

2. ‘Severely’ limited or nonexistent domestic suppliers for hydropower
materials and components

There are no domestic facilities for hydrogenerator manufacturing greater than 20 MW, and a single facility for less than 20 MW.

The following materials and components only have a single domestic facility or supplier:

• Windings greater than 100 MW for large hydrogenerators
• Large forgings (50-75 tons) for large hydropower shafts
• Foundry with casting capabilities greater than 10 tons for large turbine runners
• Grain oriented-electric steel (GOES) for U.S. transformer manufacturers

Additionally, there are two domestic suppliers of non-oriented electric steel (NOES) for U.S. hydrogenerator manufacturers

3. Federal contracting procedures and domestic content laws

The report identified several procurement regulators and/or general practices that NREL says inhibit the development of the domestic hydropower supply chain, including bonding requirements, specifying pre-contract design work, all-inclusive contracts, and focusing exclusively on the initial capital outlay rather than the total project life cycle cost.

4. Foreign competition, foreign subsidies, and ‘ineffective’ trade policies

NREL said discussions with companies in the hydropower industry highlighted “inequitable” competition from foreign companies and “ineffective” trade policies as other issues in the hydropower supply chain.

Several companies noted that other countries subsidize their steel industries, and China develops “pods” of manufacturing capability to shorten the supply chain, making it more cost-effective.

5. Shortage of skilled workers

Hydropower manufacturing and upstream support industries suffer from a “significant” lack of workers with appropriate expertise, the report said. These industries have been offshored over the last 40 years, leaving skilled workers to retire or move to other industries.

NREL’s recommendations

NREL said DOE and the WPTO should consider the following recommendations to address hydropower supply chain concerns:

Lead with the federal fleet to prime the development of an aggregated, consistent demand signal with the largest producers by examining federal procurement processes and developing best practices for the refurbishment of the domestic fleet. Improve federal procurement processes to include multi-entity or multi-project long-term contracts and ensure that small businesses can compete for federal contracts. Develop best practices for refurbishments to ensure a predictable, steady, demand.

Develop domestic supply chain and end-user datasets to increase awareness of current and expanding capabilities of the domestic supply chain and installed hydropower fleet. WPTO is funding the development of two databases at Oak Ridge National Laboratory: a comprehensive database of suppliers in the hydropower supply chain, and an expansion of the HydroSource tool to provide unit and component-level information on the existing domestic fleet.

Work with other low-carbon technologies to create a “significant,” steady, and predictable demand signal for common materials.

Continue workforce development, including continuing collegiate competitions like the Hydropower Collegiate Competition and Marine Energy Collegiate Competition; in addition to acting on recommendations from the Hydropower Workforce report.

Originally published in Hydro Review.

“Looking backwards, why it was built, it was because there were people who took a bold decision,” said Dr. Klaus Engels, Director of Hydropower Germany for Uniper Kraftwerke.

Dr. Engels spoke as part of a utility executive roundtable at the HYDROVISION opening keynote. Minutes earlier he had accepted the honor of the Walchensee plant being inducted into the Hydro Hall of Fame.

The roundtable focused on challenges and opportunities for utilities with hydropower assets and the greater hydro industry. Dr. Engels said one of the industry’s single biggest challenges today is navigating community and political opposition to projects, along with lengthy re-permitting or re-licensing processes.

“Obviously it was possible to find a compromise,” he said, speaking of when Walchensee was build a century ago. “This is something which I personally miss very much in our society.”

Tom Roode, Chief of Operations and Maintenance for Denver Water, spoke of challenges his utility faces, including the availability of water in the West, long lead times and availability of parts and finding skilled labor. Maintaining the health of assets under inflationary pressures might be the most difficult, he said.

“As a broader water supplier that has hydropower, I think one of our biggest challenges is just aging infrastructure, and the demands for capital and to be able to replace and replenish and maintain that,” he said.

Other challenges included how the increasingly favorable economics of other renewables are driving decisions on the hydro side. Roode said Denver Water has a couple of projects that five years ago, it would have been a “no-brainer” to re-build or re-license.

“Now the question really is, do we put something solar-wise right next to it and not maintain the facility?” he said.

As thermal plants are retired and other renewables continue to come online, both Engels and Roode cited the need to balance environmental stewardship with producing the energy a modern industrial society needs.

“[Hydro] is, for me, the enabler of the energy transition, because it’s flexible, it can be stored and it’s baseload ready,” said Engels. “What we are heavily lobbying for is to put a price tag on flexibility.”

Both speakers highlighted the challenge of attracting and recruiting skilled employees. Engels said years of cost-cutting and restructuring, while not replacing old positions has brought us to this point.

“The problem is that we have a workforce which is condensed to 15 to 20 years,” he said. “That is not a healthy distribution of your workforce.”

Engels said like every company, Uniper Kraftwerke needs to navigate diversity, equity, and inclusion (DEI) while attracting strong talent. He said the utility is focused on the younger generation and recruiting in schools.

Roode said Denver Water has struggled to find enough electricians, mechanics and plumbers. He believes this is the product of trying to steer students toward college, rather than the trades, over the last 30 years.

“Hopefully, the market will start to reward the folks that do take the leap into that industry,” he said, “And they’ll be well-compensated to do it.”

In a call to action, he asked the HYDROVISION keynote audience to be a hydro “evangelist.”

“Hoping this group can go out and talk to their friends, talk to their neighbors, encourage people you know, kids that are going to look for a career in the trades,” said Roode.

Engels circled back to the need for the industry to “do hard things.”

“The easy jobs are for others,” he quipped.

From there, the 2.6 MW Robert V. Trout hydropower plant was born, coming online in 2012. Dozens of HYDROVISION International attendees on Monday toured the facility, which is located at Carter Lake, a reservoir of about 110,000 acre-feet of water.

The run-of-river plant, which consists of two Francis turbine-generator units, delivers raw water to local treatment plants and generates some electricity along the way.

“Right now, as you might imagine, we are delivering a lot of water to hot, hot cities,” said Jeff Stahla, Public Information Officer for Northern Water.

The Robert V. Trout facility is part of the Colorado-Big Thompson project, with six original hydropower plants owned by the Bureau of Reclamation and two added more recently by Northern Water. The project spreads over 250 miles and stores, regulates and diverts water from the Colorado River on the western slope of the Continental Divide to the eastern slope of the Rocky Mountains.  

While the plant itself isn’t huge, Stahla told tour attendees the surrounding area has grown immensely.

“Because of the amount of growth in northern Colorado, it runs quite a bit,” he said.

In the afternoon, tour attendees visited a larger hydropower plant. The 45 MW Estes plant, operated by the Bureau of Reclamation, is also part of the Colorado-Big Thompson project. The three-unit plant is remotely operated from Wyoming.

Estes began operating in 1950 with a single Francis turbine-generator unit and takes diversion water delivered from the Marys Lake Power Plant and holds it in Lake Estes for the project.

Lake Estes is formed by Olympus Dam. Reclamation said the afterbay storage in Lake Estes and the forebay storage in Marys Lake enable the Estes powerplant to meet daily variations in energy demand. 

The Inflation Reduction Act sunsets the existing Production Tax Credit (section 45 of the tax code) and Investment Tax Credit (section 48 of the tax code) by limiting their availability to projects beginning construction before 2025 and transitioning to the Clean Electricity Production Credit (section 45Y of the tax code) and the Clean Electricity Investment Credit (section 48E of the tax code) for projects placed in service after December 31, 2024.

These new Clean Electricity credits provide incentives for the first time to any clean energy facility that achieves net zero greenhouse gas emissions. The credits also allow for new zero greenhouse gas emissions technologies to be developed and are intended to provide long-term clarity and certainty to investors and developers of clean energy projects.

The Notice of Proposed Rulemaking (NPRM) identifies specific technologies that meet the environmental standards set out in the Inflation Reduction Act and would categorically qualify as zero greenhouse gas emissions for the purposes of the Clean Electricity Production Credit and Clean Electricity Investment Credit. The technologies recognized in the NPRM include wind, solar, hydropower, marine and hydrokinetic, nuclear fission and fusion, geothermal, and certain types of waste energy recovery property (WERP).

The proposed guidance also clarifies how energy storage technologies would qualify for the Clean Electricity Investment Credit. The statute requires clean energy technologies that rely on combustion or gasification to produce electricity undergo a lifecycle greenhouse gas analysis to demonstrate net-zero emissions. The proposed rules seek comment on a range of questions related to this required lifecycle analysis for combustion and gasification technologies. Treasury, in consultation with interagency experts, will review comments received and continue to evaluate how additional clean energy technologies, including combustion and gasification technologies, will be able to qualify for the clean electricity credits. 

“President Biden’s Inflation Reduction Act has driven an investment boom that is adding historic levels of new clean power to the grid while keeping consumer energy costs in check, reducing greenhouse gas emissions, and bolstering energy security,” said U.S. Secretary of the Treasury Janet L. Yellen. “The Clean Electricity Tax Credits created under the Inflation Reduction Act provide certainty to the market and are poised to drive substantial further growth and lower utility bills over the long run.”

The guidance also proposes that any future changes to the set of technologies that are designated as zero greenhouse gas emissions or the designation of lifecycle analysis models that may be used to determine greenhouse gas emissions rates must be accompanied by an analysis prepared by the U.S. Department of Energy (DOE)’s National Labs, in consultation with agency technical experts and other experts. The NPRM also proposes a process by which taxpayers can request a Provisional Emissions Rate, which DOE would administer in consultation with the National Labs and other experts as appropriate.

Additionally, the NPRM includes proposed rules meant to clarify the inclusion of costs of interconnection-related property for lower-output clean energy facilities that take the Clean Electricity Investment Tax Credit. Eligible costs include the costs of upgrades to local transmission and distribution networks that are necessary to connect facility to grid. The proposed rules continue the approach taken in the proposed rules for the Section 48 Investment Tax Credit, which was modified by the IRA to cover qualified interconnection costs. 

Originally published in Renewable Energy World.