Power Engineering

Small-scale Hydro Gets BIG

Will regulatory changes allow developers to push out projects faster and more efficiently than before? 

By Lindsay Morris, Associate Editor

A small hydro plant has been churning on the Kansas River since 1874. Having withstood over a century of production on a river that could be dubbed a prairie stream, the Bowersock Mills & Power Co. hydro plant has been as much a part of the history of Lawrence, Kan. as the Kansas River itself. In the 21st century, owners Sarah Hill-Nelson, the great-great-granddaughter of the original owner, and her father Stephen Hill, have set their sights on expansion. The plan is to build a 4.85 MW powerhouse on the north side of the river. And the original 2.2 MW plant isn’t going anywhere. The original generators circa 1925 and the switchboard from the 1920s all are still operating, proof that this small hydro plant was built to last. (See the Bowersock Mill postcard, opposite, postmarked 1911).

A Bowersock Mill postcard postmarked July 27, 1911. The plant originally started production in 1874. Courtesy Bowersock Mills & Power Co.

But it never hurts to make a good thing even better. That’s the mentality of these descendants of Justin D. Bowersock, the original owner. If the Hills’ expansion plans are any gauge of the small-scale hydro sector, then small is about to go big.

Hydropower makes up 6 to 7 percent of the nation’s electricity consumption and almost 75 percent of its installed renewable power capacity, according to the Energy Information Administration, the statistical arm of the U.S. Department of Energy. In September 2009, U.S. Energy Secretary Steven Chu said the hydro industry could add 70,000 MW of capacity by installing more efficient turbines at existing dams, increasing the use of pumped-storage projects and encouraging the use of run-of-the-river turbines. That capacity is equivalent to 70 nuclear plants or 100 coal-fired plants.

Instead of producers attempting to build Hoover Dam 2, the focus has been on reviving small scale. Thanks to new tax credits, grants and initiatives to reduce gas emissions for small-scale hydro plants, requests to build projects are flooding into the Federal Energy Regulatory Commission (FERC), the principal federal permitting agency.

Of Regulations and Power

Small hydro developers had an opportunity to present concerns before FERC during a technical conference in December 2009. Attendees’ fundamental question: Why should a 500 kW project with no environmental issues follow the same regulatory process used for a 500 MW project? Why should the waiting process be as long and the fees as high? FERC has been responding to the inquiry through simplifying approval processes state-by-state.

On Aug. 25, Colorado became the fifth state to sign a Memorandum of Understanding (MOU) with FERC on a hydrokinetic project. The purpose of an MOU is to simplify procedures authorizing the development of small-scale hydro projects. Other states with MOUs are California, Maine, Washington and Oregon.

FERC Chairman Jon Wellinghoff said that through MOUs and other approaches, small hydro permitting costs are decreasing. “We want to do whatever we can to lower those transactional costs so that we can facilitate as much small hydro development as possible.” (See graph of “Increased Interest in Small Hydro”).

Wellinghoff said that if companies have done their homework before approaching FERC, the regulatory process can be expedited. “They can look at our requirements and have as much material developed before they come in for that pre-licensing meeting.”

With so many processes, it can be difficult for small hydro developers to know which route to choose. Wellinghoff said the first step for developers should be a visit to the checklist of regulation requirements at ferc.gov.

Nancy Skancke, co-chair of the National Hydropower Association’s (NHA’s) Small Hydro Council, said small hydro developers proposing a project can choose among three FERC processes. The first, known as the alternative licensing process (ALP), requires the applicant to discuss the proposed license with federal and state resources agencies and other potential stakeholders before filing an application for a license with FERC.

Under the integrated licensing process (ILP), FERC becomes involved in the process before the license application is filed and works with federal and state resource agencies, stakeholders and the company.

The traditional licensing process (TLP) is distinguished from the other two processes because consultation with the resource agencies and stakeholders generally takes place after the application is filed with FERC. While the developer can choose between these three processes, the ILP is the default process used by FERC. That means the developer must obtain prior approval from FERC to use either the TLP or the ALP.

Skancke said every project is different and the process selection is important. “If you choose the correct process, licensing can proceed most efficiently.”

The approval process for projects that add incremental power production to an existing licensed hydro project involve an amendment to that existing license, which can “generally be more expeditious than a full licensing or relicensing under the ALP, ILP or TLP,” Skancke said.

Wellinghoff said Colorado is now the state with the highest number of small hydro applications to FERC. The small-hydro boom in Colorado stems from the state’s renewable energy standard signed by Gov. Bill Ritter on March 22, which requires investor-owned utilities to obtain 30 percent of their power from renewable sources by 2020. Ritter also backed efforts to develop more than a dozen small hydro sites out of 200 potential locations in the state.

Revitalizing Dams

Many of Colorado’s small hydro sites are slated to use existing dams and irrigation ditches, a relatively untapped infrastructure resource. Currently, 3 percent of the nation’s more than 82,000 dams include equipment to generate electricity, according to the NHA.

Kleinschmidt, a regulatory consulting and engineering firm, is assisting clients add small hydro to existing facilities. The largest of these “small” hydro developments are at two sites in Illinois: the Brandon Road and Dresden Island Locks and Dams. These are existing, Army Corps of Engineer navigation projects where Northern Illinois Hydropower proposes to develop hydroelectric facilities.

The Brandon Road Lock and Dam is on the Des Plaines River south of Joliet, Ill. With an estimated 10.2 MW capacity, the project will have an annual production of around 52,000 MWh. The Dresden Island Lock & Dam on the Illinois River near Morris, Ill. has a slightly greater capacity and is estimated to have an annual production of 66,000 MWh. Both projects are in the final stages of licensing and design with project completion and first power generation anticipated in late 2012.

Another proposed project is the Crooked River Project, being pursued by Portland General Electric in the Pacific Northwest. The project would be located at the Arthur R. Bowman dam outside the city of Prineville in Crook County, Ore. The dam, constructed in 1961, currently has no generation facilities, but could host a capacity of close to 6 MW upon project licensing and construction. Additionally, Kleinschmidt recently completed a number of feasibility analyses and licensing and design work of several other smaller projects on irrigation systems and water supply projects in California and Pennsylvania, among other states.

Kleinschmidt senior regulatory adviser Jay Maher said that in many cases the process to license small hydro under 1 MW in size is just as difficult as licensing a project 10 MW in size or larger. Maher said he hopes that recent initiatives by NHA’s small hydro committee as well as independent actions, such as the recent MOU between Colorado and FERC, is a sign of that small hydro licensing processes might be simplified.

“Small hydro is an amazing resource that begs to be developed, especially when we are talking about retrofitting existing facilities,” Maher said. “The development of this resource should be a no-brainer.”

Canada’s Hydro Deluge

Hydro power has never been so vibrant in Canada, where hydro generates 60 percent of the nation’s power. The National Energy Board projects that percentage will increase to 65 percent by 2015. Jacob Irving, president of the Canadian Hydropower Association (CHA), said that Canada has 74,000 MW of current installed hydro capacity, which includes storage and run of river facilities. CHA studies show that hydropower’s technical potential is 163,000 MW. In terms of capacity generation, Canada ranks No. 3 in the world, trailing China and Brazil, and leading No. 4-ranked the United States.

“We generate more from our hydro than the U.S. because we have the storage capacity from large hydro,” Irving said.

While storage is typically a function of large hydro facilities, Irving said small-scale hydro is also increasing in Canada, particularly in the leading hydro provinces of British Columbia, Manitoba and Quebec. Each of these provinces generates 90 percent of their power from hydro.

“There is now greater recognition that it [small hydro] is such a strong long-term investment,” Irving said.

British Columbia, with its wealth of natural resources such as a mountainous terrain and an average annual rainfall of 236 inches, is a prime hydropower environment. However, according to the Independent Power Producers Association of British Columbia (IPPBC), the province has been a net importer of power from both the U.S. and Alberta over the past seven years. The IPPBC has declared British Columbia on the path toward energy self-sufficiency by 2016, with much of that generation expected to come from hydro. BC Hydro, the utility serving 94 percent of British Columbia’s population, has implemented a power acquisition program that accepts regulatory-permitted small hydro developments up to 10 MW. That soon could be extended to include 15 to 20 MW projects as well.

Iain Cuthbert, president of British Columbia-based Barkley Project Group, a management consulting firm for hydro projects under 50 MW, said the benefit to BC Hydro’s power acquisition program is that a small hydro project is processed separately from larger projects.

“Regulators are getting hit with a large group of projects at the same time, but with small hydro, you’re not forced into an imposed deadline,” he said.

Cuthbert said there are time and financial benefits to choosing small hydro in comparison to a larger project.

Brett Bauer, Canyon Creek Hydro’s chief design engineer, and Loren Sweitzer, a Canyon manufacturing supervisor, inspect the Pelton runner and turbine housing for the Tyson Creek Project at the company’s manufacturing facility prior to shipping. This unit develops about 10 MW. Photo courtesy Canyon Creek Hydro.

“You have more certainty in the earlier stages of development; it’s easier to raise the investment required. If you’re in the larger process, you don’t know how many years you may have to wait to get the opportunity to bid your project.”

Even after bidding a large project, Cuthbert said, there is no certainty that a producer will obtain an electricity purchase agreement until the projects are quite well advanced.

Currently, more than 25 small privately-owned hydroelectric facilities (10 MW or less) supply energy to the British Columbia hydro system, some of which have been operating for nearly 20 years. While most of these small plants feed energy into BC Hydro’s main distribution and transmission systems, a small number of them provide clean electricity to remote communities like Atlin, Dease Lake, Sandspit and Bella Bella that would otherwise depend on diesel generation.

The Barkley Project, along with Amnis Engineering and Hazelwood Construction One, worked with Victaulic, a manufacturer of mechanical pipe joining solutions have developed a small hydro plant for one such remote community. The plant, Canoe Creek Hydro, is a 5.5 MW run-of-river hydroelectric facility on Vancouver Island. The facility is locally owned and operated by the Tla-o-qui-aht First Nation and located in the heart of the Nation’s Tribal Parkland. Canoe Creek Hydro was built to help the island become more energy self-sufficient, and less reliant on mainland power. Construction started in May 2009 and ended in May 2010. The plant went into service in June. (See the photo on page 116 illustrating the Canoe Creek penstock elevation.)

The Canoe Creek Hydro plant on Vancouver Island operates by diverting stream flow into a penstock at a high elevation – up to 84 percent grade – intake. The grade increase of the penstock is illustrated in this photo. Photo courtesy Victaulic

Canoe Creek Hydro operates by diverting stream flow into a penstock at a high elevation—up to 84 percent grade—intake. This made construction a challenge, as did the facility’s location in the Pacific Rim Rainforest, where annual precipitation is among the heaviest in the world, particularly in the winter months when construction took place.

Constructing the 4 km penstock line in these conditions through welding would have proven difficult. The companies replaced mechanical welding on the penstock with the use of mechanical couplings. In the field, the couplings proved advantageous in many ways. The couplings could be installed in any weather condition with no special requirements. Crews could assemble the joints even in downpours and snow showers. This also reduced the amount of excavation, bell holing and dewatering that would be common with welding.

The use of couplings also improved site safety. As the pipe was already on site, Hazelwood grooved and re-coated the pipe prior to sending it up the single-lane logging road to be assembled. In addition, the replacement of welding with mechanical joints allowed for a reduction in the number of laborers required on the job site. Canoe Creek also employed local laborers, which Cuthbert said is one of the benefits of developing small hydro.

“On the smaller scale, you’re usually able to get your project done relying on local resources, which helps integrate your business with the local community.”

The Concepcion HPP hydro plant in Panama. Two 5 MW Mavel Francis Turbines are installed at this location. Photos Courtesy Mavel

Environmental benefits were also gained by replacing welded joints with mechanical joints. Welding 1 km of straight-run 36-inch pipe produces about 40,338 kg of CO2 emissions using a diesel-powered machine and 9,463 kg of CO2 emissions using an electric-powered machine. Grooving and coupling that same run of pipe produces 62 kg of CO2 emissions. The use of couplings also reduced the amount of X-raying required on site, reducing radiation emission. Particulate emissions, CO2 and radiation were reduced, as well as electrical energy use.

Big ‘Small’ U.S. Developments

In U.S. small hydro technological breakthroughs, turbine manufacturer Hydro Green Energy (HGE) became the first hydrokinetic project to be approved by FERC in December of 2008 and began operations in August of 2009. A 100 kW turbine power station was installed at a 4.4 MW run-of-river hydropower project at the U.S. Army Corps of Engineers’ Lock & Dam No. 2 in Hastings, Minn. When complete, the barge-mounted project will have two turbines. The second turbine is expected to be installed in 2011.

The Hastings project features Hydro Green’s Hydro+ system, which reinforces the output of the existing facility in a manner that does not create back pressure on the existing facility. The Hydro+ system has been proven to be fish-friendly, having undergone a study by Normandeau Associates. At the time of the study, Normandeau’s patented methodology had been utilized by nearly 50 conventional hydro projects and by the Department of Energy, but never on a hydrokinetic turbine.

This methodology used a controlled experiment approach to produce statistically reliable and verifiable results on injury and survival of fish passed through a turbine, spillway or over falls. During the study, 402 fish swam through HGE’s hydrokinetic turbine, which rotates at 21 revolutions per minute. Pre-installation computer modeling performed by HGE, which relied on models created by the U.S. Army Corps of Engineers and the Department of Energy, revealed a 97 percent fish survival rating for the turbine, HGE reported.

Vice President Mark Stover said that industry interest in low-head/small hydro in the U.S. is at its highest since the 1980s, but that most of the boom is occurring only on paper. Hundreds of projects have been proposed to FERC, Stover said, but few are actually coming on-line.

“I think the tide is about to turn, however, and we will see significant new hydropower development over the next decade from the conventional and new technology sectors.”

Stover said there is a “tremendous growth market waiting to be captured” for small-scale hydro, particularly from utilities and others who are interested in buying renewable power and/or new renewable power projects.

Some technology developers aren’t as confident about a small-scale hydro “boom.” Daniel A. New, president of Canyon Hydro, has been in the hydro business for 35 years. While he has experienced ups and downs in the industry, New said that overall, “it’s been a pretty steady climb” and he predicts small hydro to continue growing at a slow pace.

Canyon Hydro develops turbines for grid-connected customers in municipalities and also specializes in providing equipment to communities that are not grid-connected. In December 2009, Canyon headed the installation of a Pelton turbine for Tyson Creek, a 9.3 MW hydro plant in British Columbia operated by Renewable Power Corp. Tyson Creek is grid-tied, but is also stand-alone, perched on 865 meters gross head with a flow of 1.3 cubic meters per second, making it one of the highest head projects in North America.

That 865 meters of gross head converts to more than 1,200 pounds per square inch (psi) at the turbine, causing Renewable Power to become concerned that a traditional Pelton design would disintegrate under such a load. Likewise, operating in islanded mode creates a new set of concerns relating to load compensation and frequency control. Canyon Hydro was able to design and fabricate a heavily gusseted Pelton turbine that met the specifications of the Tyson Creek project.

“When the grid is down, they’re able to run quite a section of that community with this plant in an islanded condition,” New said.

Islanded operation requires control systems that are common on larger hydro systems, but is unusual for a 10 MW project. Canyon prepared for sudden changes in load by implementing a jet deflector shield, which adjusts to deflect more or less of the water jet to the turbine runner.

Is the U.S. Measuring Up Internationally?

Jeanne Hilsinger, president of Mavel Americas Inc., a unit of Czech Republic-based turbine manufacturer Mavel, a.s, said Europe has developed 17 percent of its economically feasible small hydro potential. By comparison, the U.S. has developed 14 percent. In 1940, hydropower accounted for 40 percent of the electricity produced in the U.S. That number is 6 to 7 percent today.

Europe has 17,571 small hydro plants, while the U.S. has 2,346, Hilsinger said. She attributed this gap to a lack of public awareness, as well as the rigor of U.S. regulation requirements.

“If you ask a child to draw a wind turbine or a solar panel, chances are they will get it right. But if you ask a child or even an adult to draw a small hydro plant or a water turbine, chances are pretty good they will get it wrong,” Hilsinger said.

In regards to regulation requirements, Hilsinger said the time invested to obtain the necessary licenses in the U.S. is almost always longer than the time needed to build a small hydro plant. “While the FERC permitting process is getting more efficient each year, the time required for permitting in the U.S. and the investment that must be made is daunting.”

In addition, she said, the capital invested in the legislative process can sometimes exceed the funds needed to purchase the generating equipment. This is especially true for smaller hydro facilities, Hilsinger said.

Skancke of NHA said that hydro is different from other renewables in that new development has a more rigorous regulatory approval process and, therefore, potentially higher start-up costs. Due to these regulatory requirements, “it’s not clear whether the financial industry will grab on to the benefits of small hydro and provide the financing that is necessary for a build out of hydro to its maximum potential.” However, hydro has a record of “consistent and sustainable power production for the long-term, as well as environmental and other benefits,” Skancke said.

Cuthbert of the Barkley Project Group said that small hydro produces a business model that most power companies cannot duplicate with another resource.

“For a company that’s looking at the triple bottom line with social, environmental, and economic values all built in, these projects are attractive from that perspective.”

For now, producers keep falling back on the reliability and longevity of small hydro as motivation for moving forward.

“The overall cost of generating power is very low, the equipment life is very long: 50 years or longer,” said Hilsinger. “The environmental impact is minimal and the generation is relatively stable as opposed to other intermittent renewable resources.”

Potential resounds for small hydro, from existing, non-generating dams that could be enlivened with hydropower, to increasing interest from utilities in buying renewable projects. And with FERC and Canadian small hydro regulations processes being simplified, it appears that small hydro will only continue to grow bigger.

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