This is an extract from a recent report “U.S. Hydropower Market Report (2023 Edition)” prepared by Oak Ridge National Laboratory for the U.S. Department of Energy’s Water Power Technologies Office

U.S. Hydropower and PSH Development Pipeline

At the end of 2022, the U.S. hydropower development pipeline included projects to construct 117 new facilities with a combined capacity of 1.2 GW (versus plans for 217 new facilities with a total proposed capacity of 1.49 GW at the end of 2019); only 8 of them are under construction. Non-powered dam (NPD) retrofits accounted for 95% of the proposed new capacity. In addition to the projects to construct new facilities, 23 active upgrade projects would increase the capacity of the existing fleet by 254 MW. 

Twenty-nine states have at least one new hydropower project in the pipeline. Pennsylvania stands out as the state with the most proposed new hydropower projects (26) of which 25 are NPD projects.

Fifty-six (48%) of the proposed new projects—with a combined capacity of 514 MW—already have authorization from FERC or the U.S. Bureau of Reclamation (Reclamation). Only eight of them (14 MW) have started construction. Six of the yet unauthorised projects have already submitted a final licence or exemption application. The remainder include 37 projects (339 MW) with issued preliminary permits and 18 projects (304 MW) with pending preliminary permit applications.

Of the 93 NPDs for which adding hydropower is proposed, 65 are owned by the U.S. Army Corps of Engineers (USACE), 5 by Reclamation, and the remaining mostly by states. Who owns the dam matters for NPD permitting because it might result in federal permitting requirements either different from, or in addition to, a FERC licence.

Most of the 23 proposed capacity additions to the existing fleet are capacity upgrades resulting from turbine replacements and generator rewinds, but three owners plan on adding new turbine-generator units to their plants. Two of the three projects that involve unit additions seek generating power from mandatory environmental flows. Production from these additional units would be eligible for Section 242 incentives of the BIL which might result in increased number of installations.

The number of projects in the pumped storage hydro (PSH) development pipeline has increased by 43 percent in 2022 versus 2019. Ninety-six PSH projects were on the development pipeline at the end of 2022 (versus 67 at the end of 2019) with a combined storage power capacity of 91 GW. Developers have advanced beyond the feasibility evaluation stage for 10 of them. Of those 10, three have already been authorised by FERC but no new PSH is under construction.

Twenty-eight states have at least one PSH project in the development pipeline. The top five states by number of PSH projects (California, Arizona, Utah, Pennsylvania, and Nevada) do not include any of the eight states with variable renewable (wind plus solar) shares greater than 30% of their in-state electricity generation capacity. Siting decisions are highly dependent on topographic conditions, and the Great Plains—where many of the wind-rich states are located—do not have many well-suited sites for PSH development. Along with topography, other factors important to PSH siting decisions include proximity to transmission capacity, ability to secure the necessary water rights, and ease of access to the project site.

More than 80% of the proposed PSH projects have closed-loop configurations. In a closed-loop PSH plant, the reservoirs are not continuously connected to a naturally flowing water feature such as a river or lake. The high percentage of proposed PSH projects that are closed-loop contrasts with the characteristics of the existing U.S. PSH plants, which are all open loop.

The range of proposed PSH generation capacities is very wide (17–9,000 MW), and proposed storage durations are typically 8–12 hours. Some developers are exploring longer storage durations, and others are proposing hybrid projects that combine PSH with other renewables.

Except for PSH (new and capacity upgrades), all other hydropower projects in the U.S. development pipeline fall in the small (<=10 MW) or medium (>10–100 MW) size categories. The most active type of developer for new projects are private non-utilities. They account for 94% of NPD projects and 82% of PSH projects. Investor-owned utilities have shown an increased interest in PSH projects in the last two years.

U.S. Hydropower Prices and Revenues

Hydropower plants provide energy, capacity, and grid services. Depending on region and owner type, these products and services may be sold through long-term contracts or power purchase agreements (PPAs), short-term bilateral transactions, or bids into the day-ahead or real-time wholesale markets managed by independent system operators (ISOs) and regional transmission operators (RTOs). Additionally, some hydropower plants also sell renewable energy certificates in either mandatory compliance markets connected to a state-level renewable portfolio standard or voluntary, green power markets.

In 2019–2021, most federal hydropower was marketed at rates similar to or below wholesale electricity prices. Severe drought conditions in most of the Southwest in 2020–2021 did not result in large changes in average revenue per megawatt-hour for the power marketing administration that markets federal hydropower in that region because of the long-term nature of its contracts with customers. However, its total revenue was 20% lower than the 2010–2018 average because of lower sales volumes.

The four power marketing administrations (PMAs) within the U.S. Department of Energy—Bonneville Power Administration (BPA), Southeastern Power Administration (SEPA), Southwestern Power Administration (SWPA), and Western Area Power Administration (WAPA)—market the output from the federal hydropower fleet. Across the four PMAs, average revenue per megawatt-hour from 2019 to 2021 ranged from $27.75/MWh (BPA) to $35.78/MWh (SEPA). The average revenue per megawatt-hour for the PMAs was lower than the average wholesale price in 2019–2021, except for SEPA.

The impact of the acute droughts experienced in the Southwest over the past 20 years is not apparent on the average revenue per kilowatt-hour for WAPA, but it is visible when looking at volumes sold and total revenue. The effects of the drought on a PMA-wide average energy price are smoothed by the diversity of hydrologic conditions in the vast area where hydropower plants marketed by WAPA are located. Another factor that contributes to smoothing out the effects of drought on WAPA’s average revenue is the large size of some of its hydropower storage reservoirs, which makes them capable of buffering the effects of multi-year droughts.

For non-federal plants selling their electricity through PPAs, the national median energy price for hydropower purchased power transactions in 2020 was $45/MWh. It was the second lowest price for the 2006–2020 period (after $44/MWh in 2017). The low median price for 2020 is consistent with the drop in electricity prices observed in wholesale markets that year because of the effect of the COVID-19 pandemic on electricity consumption. The range of hydropower PPA prices is wide. For 26 PPAs where the first year of data is 2018 or later, the average price of energy ranged from $23/MWh to $80/MWh.

As of 2020, 19% of PPA transactions involving hydropower included a capacity component in the price (a fixed charge per kilowatt of capacity available over a period regardless of the number of kilowatt-hours actually generated). But there is substantial regional variation in the fraction of hydropower PPAs that include a capacity component: from 9% in the Northwest to 60% in the Southwest.

Since energy revenue is the dominant component, the overall pattern of total revenue (decreasing from 2018 to 2020 and bouncing back in 2021 and 2022) roughly follows the trends in ISO/RTO energy prices during the 2018–2022 period, which also were the lowest in 2020 because of the effect of the COVID-19 pandemic on electricity demand and increased sharply in 2022 in connection with a spike in natural gas prices after Russia’s invasion of Ukraine.

The main difference in the revenue composition of PSH plants versus conventional hydropower plants is that energy revenue per kilowatt of installed capacity per year is lower than for hydropower (because of the low average number of hours in generation mode per day) and capacity revenue is as high or higher than energy revenue in some cases. Ancillary services revenue was no greater than 25% of total revenue for any of the PSH plants in the sample from the past five years.

Going forward, hydropower and PSH revenue composition will likely shift toward higher shares of revenue from the capacity and ancillary service markets. In regions with high penetration of variable renewables, the average marginal energy price will tend to decrease while the value of firm, dispatchable capacity and the need for ancillary services will increase.

Apart from the traditional set of ancillary services (e.g., frequency regulation, spinning and supplemental reserves), flexibility services such as ramping are becoming increasingly necessary for system operators. As a result, ISO/RTOs have adopted or are planning energy and ancillary service markets reforms geared towards incentivizing generators to provide the needed level of operational flexibility.

Policy Developments

The BIL, signed into law in November 2021, includes $753 million in appropriations for incentives targeted explicitly at hydropower facilities: A new incentive (codified as Section 247 of the Energy Policy Act (EPAct) of 2005) for capital investments in existing non-federal hydropower facilities that will improve grid resilience, improve dam safety, or make environmental improvements is authorised with $553 million of funding.

Section 242 incentives (authorised for an additional $125 million) are available for non-federal hydropower production added to an NPD, conduit, or non-federal hydropower facility with capacity less or equal to 20 MW in areas with inadequate electric service.

Section 243 incentives (codified in EPAct of 2005 but never funded until now) for funding hydroelectric efficiency improvement incentives are authorised with $75 million. Existing hydropower facilities (including PSH) improving efficiency by 3% or more are eligible to apply for Section 243 incentives.

The IRA became law in August 2022. It includes PTCs and ITCs through 2032 that incentivize investment in clean energy (including hydropower and PSH). Hydropower is eligible for the same IRA tax credit amount as other renewables. Other important innovations in the IRA tax credits for hydropower include the availability of an elective-pay option for tax-exempt developers, the eligibility of conduit projects (>25 kW) for the PTCs, and the eligibility of PSH projects for the ITCs.

For facilities placed in service from January 2022 to December 2024, the PTC extends and modifies the technology-specific Section 45 PTC that was first enacted in 1992 and extended multiple times. The credit amount stated in the IRA text is 1.5 cents/kWh, but the applicable value for each year will be adjusted for inflation (relative to calendar year 1992). The inflation adjusted value published by the Internal Revenue Service for 2023 is 2.75 cents/kWh. To be eligible for this credit amount a project must satisfy wage and apprenticeship requirements. Otherwise, only 20% of the credit will be received. Projects eligible for the Section 45 PTC can select to claim the Section 48 ITC instead. The ITC amount is 30% of the cost of the eligible energy property for projects that satisfy the wage and apprenticeship requirements. For projects that do not meet those requirements, the ITC amount is 6%. 

Projects that meet domestic content requirements (100% of steel or iron and 40% of manufactured products used in its construction are produced in the US) or are located in an energy community are eligible for an adder of 10% to their PTC or 10 percentage points to their ITC.

For facilities placed in service starting in 2025, the IRA sets up new clean electricity production (Section 45Y) and investment (Section 48E) credits. Qualified facilities for the clean electricity production credit are those for technologies, including hydropower, with a greenhouse gas emissions rate not greater than zero. The tax credit is available for the first 10 years of production of the facility. Facilities that were already operational before 2025 can apply for credit for any additional production due to capacity additions or installations of new units during the credit eligibility period.

Taxpayers eligible for the Section 45Y production credit can choose between it or the Section 48E investment credits. Since they are net consumers instead of net producers of electricity, PSH facilities placed in service starting in 2025 only are eligible for the Section 48E investment credits. The ITC is 30% of the eligible project costs if wage and apprenticeship requirements are met; otherwise, the facility qualifies only for a 6% credit. The domestic content and energy community bonus credits described above for the 2022–2024 PTC/ITC are also applicable for the clean electricity production and investment credits.

For both the 2022–2024 extensions of the traditional PTC/ITC and the clean energy production and investment credits, credit recipients that are tax-exempt entities can select an elective-pay option (i.e., to receive a cash payment equal to the amount of credits they would otherwise receive) as long as they satisfy wage and domestic content requirements. The possibility of a direct pay option is valuable for publicly-owned hydropower developers, such as municipalities and state agencies, that are tax exempt.

The Community and Hydropower Improvement Act (S. 1521), introduced in the Senate in May 2023, contains a licensing reform proposal developed by a coalition of representatives of the hydropower industry, environmental organisations, and Tribes.

For advancing low impact projects, the bill proposes an expedited licensing pathway for qualifying NPDs and closed-loop PSH projects. The expedited licensing process would apply to NPDs and closed-loop PSH projects with only incidental impacts to riverine systems. For NPDs, FERC would be directed to issue its final decision on a licence application within two years after it determines that the proposed project qualifies for the expedited process. Such determination must happen within 90 days of the filing of a Notice of Intent to submit a licence application.

The proposal components directed to streamline licensing procedures also include a request for FERC to establish more clear and robust procedures for licence surrenders by setting timelines (with an eye toward expediting the process for projects without complex environmental issues or public opposition) and providing opportunities for public participation. 

At the state level, since the 2021 edition of the Hydropower Market Report, seven states have increased their renewable portfolio standards (DE, IL) or clean energy mandates or goals (NE, NC, OR, CA, RI). Renewable portfolio standards often have restrictions on the types of hydropower projects that count toward compliance; all hydropower typically counts towards a clean energy goal or mandate.

Additionally, two more states (ME and CT) have adopted energy storage mandates and a few others (IL, VT, MI) are considering them. To date, most storage mandates are structured such that they are strongly geared toward short-duration, battery storage rather than PSH.

Access the complete report here