Dave Moldal is a senior program manager for Energy Trust of Oregon, an independent nonprofit that helps people use less energy, lower costs and benefit from clean, renewable energy.
Every day water flows through thousands of miles of municipal pipes, arriving at homes and businesses ready to drink and use. As it moves from source to end user, the excess water pressure in the system is dissipated through pressure reduction valves, engineered safety devices that ensure the water pressure is not too high. Across Oregon, a growing number of cities have discovered that this water pressure can be converted into clean, cost-saving electricity.
In 2020, Hillsboro became one of the first municipalities in the U.S. to install an in-pipe hydropower system at an existing pressure reduction valve. This “in-conduit” hydropower turbine generates more than 200 megawatt-hours of carbon-free electricity annually — enough to offset much of the electricity used by the nearby Hillsboro Ballpark.
In 2025, Beaverton completed a retrofit of its Sexton Mountain Pump Station, a critical municipal facility. With the support of project development assistance and an installation incentive from Energy Trust of Oregon, the city designed and installed an in-conduit hydropower turbine that will generate approximately 426 MWh of carbon-free renewable electricity per year and offset about 27% of the station’s energy load. With an eye to the future, Beaverton engineers also designed the pump station to accommodate another hydropower turbine when water flow through the facility increases.
The city of Tualatin completed a similar project this year at its City Services Center. Its system will produce roughly 250 MWh of renewable electricity per year and result in about $14,000 in annual electric bill savings. The project is also wired to support city plans to add battery storage and establish a microgrid in the future.
Oregon's experience suggests this is a replicable model for municipalities across the country.
How it works
The technology is straightforward. A hydropower turbine in the water delivery system captures the water flow, which spins the turbine and generates electricity. But not every valve is an opportunity. There must be a large enough pipe, enough pressure differential, enough flow and, ideally, the ability to net-meter the generation or be close to an electrical interconnection point so the generation can be delivered to the grid.
In Oregon, net-metering often makes or breaks the economics of these systems. Instead of selling power back to the utility at avoided cost rates, a net-metered system spins the meter backward and gives a facility a credit at the retail rate for electricity. That difference — recovering value at the retail rate instead of the wholesale rate — can be a crucial factor in making the project financially viable.
Affordable and resilient
Energy costs are rising across the country. That trend alone improves the calculus for small, distributed renewable energy systems. But in-conduit hydropower almost always requires layered funding to reach a reasonable payback target period.
The funding stack, which would vary across different states and communities, could include state energy office programs, federal investment tax credits and utility renewable energy incentives. The key is to identify all available funding before making a go/no-go call on an in-conduit hydropower system. Many municipalities target a 10-year payback on these investments, and with the right combination of incentives and site conditions, that's achievable.
If installed and maintained properly, in-conduit hydropower systems can operate effectively for 50 to100 years. As long as water is flowing through the pipe — and it almost always is — the turbine will generate electricity. This can be helpful for resilience and emergency planning, where critical facilities need to be powered.
Tualatin understood when it built its project that in-pipe hydropower is a foundation for future resilience. The city installed extra conduit and electrical infrastructure to support battery storage and a potential microgrid down the road. Bend is taking this concept further, planning a future in-pipe 1.2-megawatt system at its Outback Drinking Water Plant large enough to power the entire facility when paired with solar and battery storage.
The full meal deal — hydropower, solar, battery, microgrid — is a serious infrastructure investment. But as electricity prices rise and communities face increasing grid stress from wildfires, extreme weather and aging transmission infrastructure, many Oregon municipalities are planning innovative solutions now, rather than scrambling later.
How to get started
If you're a public works director, operations supervisor or sustainability manager wondering whether your water system holds this kind of potential, the first thing to determine is what you are trying to accomplish. A reduction in operating costs? Meeting a clean energy goal? Creating a backup power system for a critical facility? The answer to these questions changes which technology makes sense and how you prioritize your investments.
From there, a pre-feasibility study turns those goals into real numbers. Are there viable pressure reduction valves that could be replaced with in-conduit hydropower turbines? What are the pressures and flows at those valves? Where's the nearest electric load to offset or the point of interconnection? What does the project cost, and what funding may be available to close the gap? Those questions require engineering expertise to answer, but they're the foundation of any decision to move forward.
The right time to think about these kinds of systems is before a scheduled valve replacement, not after. These projects work best when they are incorporated early into capital improvement plans, not bolted awkwardly onto a process already in motion.
