What’s happening in the North American hydroelectric power industry, in a nutshell? Below are four important areas of hydropower activity in the U.S. and Canada.
By Elizabeth Ingram
According to the International Renewable Energy Agency’s Renewable Capacity Statistics 2018 report, the U.S. had 102,132 MW of hydroelectric power capacity in 2017, while Canada had 81,478 MW. This is out of a total renewable energy capacity of 229,913 MW in the U.S. and 98,697 MW in Canada. This means that about 44.4% of all renewable capacity in the U.S. is supplied by hydropower, with this percentage jumping significantly in Canada to 82.6%. Obviously, hydro is a valuable contributor to the energy mix of both countries.
But what has happened more recently with this resource? This annual feature provides an update on four key trends going on in the North American hydropower industry, with the relevance for these trends to the U.S. and Canadian sides of the border.
Interest in pumped storage
The U.S. — with its mature hydropower industry and increasing focus on building intermittent renewable energy resources (wind and solar) — is a hotbed for the discussion of pumped-storage development. In fact, the U.S. Energy Information Administration recently reported that hydroelectric power is expected to continue contributing to electricity supply at about the same level of capacity as is currently installed, but it is expected to drop from 38% of all renewable production in 2018 to 18% in 2050. Solar PV is expected to be the dominant source of renewable electricity production by 2050, at 48% of the total.
Energy storage capacity is vitally needed to help stabilize the grid and allow full use of these intermittent resources, and pumped storage is the single largest available source of this capacity. However, in the U.S., no significant pumped-storage capacity has been added for more than 30 years.
Recently, the Federal Energy Regulatory Commission (FERC) issued a preliminary permit for study of the 1,200-MW Southeast Oklahoma Pumped Storage Hydroelectric Project in Oklahoma. And in Oregon, the 393.3-MW Swan Lake North Pumped Storage Project took a step forward, with FERC issuing a final environmental impact statement for licensing of the project. Across the country, in New York, FERC received a preliminary permit application to study feasibility of the 240-MW Lyon Mountain Energy Storage Project.
And in Canada, the Alberta Legislature approved the construction and operation of the 75-MW Canyon Creek Pumped Hydro Energy Storage Project, the first ever pumped hydro project to be approved in the province. As with the situation in the U.S., “pumped hydro energy storage will be a critical feature of Alberta’s electricity grid as the grid accommodates increasing production from renewable energy, particularly large-scale wind,” said Kipp Horton, president and chief executive officer of WindRiver Power Corporation, the parent company of the project development company.
New hydro development
Canada continues to move toward completion of the 824-MW Muskrat Falls station, with developer Nalcor Energy announcing a reorganization in February it says will allow it “to continue to focus on the successful completion of the Muskrat Falls project … [and] to prepare the provincial electricity system for integration of Muskrat Falls power.” Muskrat Falls, on the Churchill River in Labrador, is one component of the Lower Churchill complex that could eventually include the 2,250-MW Gull Island plant.
Another new hydro capacity addition taking place in that country is expansion of the Taltson hydroelectric project in Northwest Territories. The proposed initial expansion will deliver 60 MW of clean energy, removing up to 240,000 tonnes of polluting emissions from the air each year. The existing Taltson generating station has a capacity of 18 MW. This expansion will more than double the territory’s current hydroelectric capacity.
In the U.S., where new hydro development is more sparse, the New York City Department of Environmental Protection announced in December it was revising the generating capacity of its proposed hydroelectric plant at the Cannonsville Reservoir, reducing it to 6 MW from the initially planned 14 MW. The smaller plant may qualify for a license exemption from FERC because it is less than 10 MW.
Challenging business conditions
Most people who are following the state of the electric power industry in North America are aware that U.S. utility Pacific Gas & Electric has filed for Chapter 11 bankruptcy reorganization. The utility faces significant potential liabilities for a variety of wildfires in northern California over the past two years. This is despite the fact that in late January, CAL FIRE concluded PG&E equipment was not to blame for the 2017 Tubbs Fire that killed 22 people. However, in late February, the utility notified the U.S. Securities and Exchange Commission that it believes transmission failure ignited the 2018 Camp Fire, which killed 86 people and damaged about 150,000 acres.
Earlier in the month, PG&E and FERC were in court regarding whether FERC can enforce the conditions of the more than 380 power purchase agreements PG&E may want to exit under its bankruptcy filing. FERC said the federal bankruptcy court cannot unilaterally invalidate commission rulings and approval must be gained from FERC before terms may be altered. The fear is that PG&E may look to exit some of its older, more expensive renewables contracts to cut back on liability during its Chapter 11 proceedings.
In other PPA news, a report was released in February saying BC Hydro’s power purchases from independent power producers, starting in 2002, were flawed, with the utility buying too much energy and energy with the wrong profile and paying too much for the energy it bought. BC Hydro said it accepted the findings in the report, which said, “The government directed BC Hydro to purchase 8,500 GWh of firm energy it did not need, and the utility acquired 8,075 GWh of firm energy, which cost ratepayers an estimated $16.2 billion over 20 years.”
And in news that crosses the border, in late January Hydro One Limited of Canada and Avista Corporation of the U.S. mutually agreed to terminate their previously announced merger agreement. More than one of the parties that needed to approve the merger had denied it, and the boards of directors of the two companies determined termination was the best course of action, after careful consideration and analysis of the likelihood of achieving a timely reversal of those orders.
Dam safety issues
Dam safety continues to be a top of mind topic, in the wake of the Oroville Dam spillway incident and the subsequent rebuilding work. An after-action panel report was released in December that said modifications in the Part 12 review process on FERC’s part are warranted and FERC needs to develop a list of the highest dams and spillways which could be of significant hazard to downstream populations.
We have reported on some recent dam safety-related initiatives in North America, and I am sharing the highlights here:
In January the Grant County Public Utility District agreed to condemn and purchase for public use 2.9 acres needed to rebuild the right embankment of its Priest Rapids Dam. The embankment is being rebuilt for seismic resistance, after personnel determined there is a need to anchor the monolith at Priest Rapids, where leaking was discovered last year.
And in December 2018, the U.S. Department of Interior’s Bureau of Reclamation awarded a $19.7 million contract for dam safety modifications to Boca Dam, on the Little Truckee River in California. Boca Dam and Dike is at risk from structural failure during an earthquake due to the presence of sand and gravel within the dam’s foundation. The work will modify the dam to better resist seismic forces during an earthquake, bringing the risk of structural failure “within acceptable levels.”
In one unfortunate case, a fatality is what led to the recognition of a dam safety problem. At Chelan County PUD’s Rock Island Dam, a PUD employee was killed when a heavy steel beam fell during the lifting of a spillway gate. A subsequent independent investigation revealed that latent design weakness from the 1990s was the engineering root cause of the failure incident.
Fortunately, three engineering recommendations and two human and organizational performance improvement recommendations were identified, and Chelan County PUD plans to fully implement all five. An additional 11 considerations were identified, and some have already been addressed, while the PUD plans to fully evaluate the remainder for action.
HydroVision International 2019 will cover all of the above important trends, and much more. Visit the website to learn more about the content being offered this July in Portland, Ore., U.S., and plan to be there to join the discussion.
Elizabeth Ingram is content director for Clarion Energy.