A 14-year drought in the Southwestern U.S. caused water levels upstream of the Hoover Dam to drop to record low levels in 2014.
When Arild Tanem started working for Statkraft AS as a market analyst in 1995, he imagined little would change about the core commodity managed by Norway's state-owned power utility: the water stored behind its dams and flowing through the rivers that criss-cross the country and produce virtually all of its electricity.
Fast forward 25 years and Tanem oversees Statkraft's entire hydropower portfolio in the Nordics, close to 300 power plants that hold almost a quarter of Europe's entire reservoir capacity. Aside from his job title, Tanem has seen another marked change in the intervening years: Annual hydro generation in Norway has grown by more than 10% and continues to rise.
"A small part of that are new power plants," Tanem, now the company's senior vice president of energy management, said in an interview. "But the main increase is climate change."
Statkraft's experience is shared by other utilities from Canada to the Swiss Alps and illustrates how operators of hydropower, one of the cleanest sources of electricity, are increasingly forced to deal with the effects of global warming.
In Norway and other regions, rising temperatures have brought more rain and are causing the glaciers feeding hydropower plants to melt faster, leading to more frequent floods and higher water inflows. At the same time, longer and more intense droughts are depleting water basins from Central Europe to the Western U.S., while the changing climate is also shifting patterns of precipitation and, in some places, remolding the landscape altogether.
Other types of power stations also face physical risks due to climate change. Nuclear plants in Europe have shut down more frequently during summer heat waves, which have cut them off from river and sea water that is needed to cool reactors. But for hydroelectric dams and run-of-river turbines, access to water is arguably a more existential issue.
"The running water is basically our revenue. It's our entire business," said Erik Røysem Sterud, CFO of Småkraft AS, which owns more than 100 run-of-river plants in Norway.
That means power producers and other investors have had to adapt their approach to building and managing these often decades-old assets, by strengthening infrastructure, incorporating greater flexibility or looking for new sites to make up for dwindling water resources — all at a time when many countries are betting on hydropower to play an increasingly important role in balancing variable wind and solar generation.
"These are things we didn't think about 20 years ago," said Tor Syverud, head of hydropower investments at Aquila Capital Investmentgesellschaft Mbh, a German asset manager that controls Småkraft and owns hydropower plants in Portugal.
"If you are in front of that, you can use it to your advantage. If you are the little dog running after the bike when it comes to climate change, then it will mostly cause you problems," he said.
A 'material' challenge
There have long been widespread concerns about the environmental impact of large-scale hydropower developments, and massive dams have also become geopolitical flash points. Long-simmering tensions between Egypt, Ethiopia and Sudan over a vast reservoir project on the Nile river have recently escalated into a bitter fight about water rights and electrification, for example.
But in most cases, hydroelectric dams, pumped storage facilities and run-of-river plants offer a cheap way to reliably generate renewable energy. They produced more than 4,300 TWh of power in 2019, about 15% of the global total. With more inflexible wind and solar capacity coming online, pumped storage especially is seen as a vital tool to store surplus electricity and even out swings in supply and demand.
In recent years, the largest new dams have been rising up in countries like China and Brazil, but the U.S. and Europe boast large fleets of older hydropower assets. Iberdrola SA is also working on a €1.5 billion complex of three dams in northern Portugal, which will single-handedly raise the country's power capacity by 6%.
Meanwhile, major utilities with large hydropower portfolios, including Electricité de France SA and EDP - Energias de Portugal SA, have suffered from droughts in recent years, which shaved tens of millions off their earnings. Lower nuclear and, to a lesser extent, hydropower generation reduced EDF's EBITDA by an estimated €889 million in 2019, the company said. It did not respond to a request for an interview. Meanwhile, EDP noted in its latest annual report that the recent sale of six of its larger hydropower plants in Portugal would reduce the company's "hydrological risk."
Scientists say extreme weather events will only increase in regularity and intensity. A team of researchers at the Helmholtz Center for Environmental Research in Germany found that the 2018-19 drought in Central Europe was the most severe on record and predicted that similar ones could occur up to seven times more frequently in the second part of this century, depending on how fast global greenhouse gas emissions continue to rise.
Rui Teixeira, a member of EDP's executive board, acknowledged that climate change effects could continue to cut into the company's profits, including by damaging physical assets and causing structural changes to its hydro fleet. Teixeira said the company is now building new reservoirs so they are more resilient to both acute and long-term physical risks. EDP is also adjusting in smaller ways, for example by installing floating solar panels, which allow closer monitoring of the water and also reduce evaporation.
"Naturally we consider that, in the long term, there are potential challenges generated by climate change [that] can be material," Teixeira said in an email.
Climate change is also causing seasonal shifts in water availability, concentrating production in parts of the year that do not necessarily match up with high-demand periods. PJSC RusHydro, the world's second-largest hydropower producer, said climate change effects boosted inflows to some of its plants to all-time highs in the first quarter of 2020.
But water stress is broadly expected to increase in the coming decades. According to projections from the World Resources Institute, water stress could grow materially in many parts of the Western U.S., including areas that are home to scores of existing and planned hydropower facilities. At large dams, power generation already competes with other purposes, from irrigation to flood control.
Some southwestern reservoirs are already feeling the heat: The Colorado River Basin is suffering a 20-year drought, which has led the U.S. Bureau of Reclamation to install new turbines at Hoover Dam to make sure it can produce enough power even with lower water levels.
And in the Missouri River Basin, a 10-year drought ended only recently with several average or above-average water years, according to Lisa Meiman, a spokesperson for the Western Area Power Administration, which manages the output of hydropower plants in the Central and Western U.S., and one of the four federal power marketing agencies within the U.S. Energy Department.
"Variable water conditions are a normal concern in the hydropower business. Hydrologic cycles usually span multiple decades, so we are used to fluctuating availability of water," Meiman said in an email. Aside from Hoover Dam and the Parker-Davis project on the Colorado River, there has not been "an enduring change" in average generation for the past five years across the agency's hydropower fleet, she said.
Nevertheless, "you should expect any river basin in the Southwestern U.S. to receive less water in the future," said Flavio Lehner, a climate scientist at the Institute for Atmospheric and Climate Science at ETH Zürich, who previously worked at the National Center for Atmospheric Research in Boulder, Colo.
In the Pacific Northwest, researchers have also warned that longer, drier summers could soon deplete river flows while at the same time raising electricity demand for cooling, increasing the likelihood of power shortfalls, for example in the Columbia River Basin.
In a report to the U.S. Congress in 2013, the Energy Department warned that federally owned hydro assets, which make up about half of total hydropower capacity in the U.S., will have to cope with generally drier summers and wetter spring and fall seasons over the next 30 years, which could decrease power generation during the summer.
Effects in the Western Area Power Administration's service territory illustrate how differently individual basins are affected: While the Upper Missouri could see more water throughout the year, from both runoff and precipitation, the Rio Grande was expected to see drier conditions during most of the year, according to the report.
But even where water will increase, the report warned that reservoirs may not have capacity to make use of the extra inflow. "Extreme water years, both wet and dry, will pose significantly greater challenges to water managers, especially in water systems that have more limited reservoir storage and operational flexibility," it said.
That could have consequences for municipal utilities like Seattle City Light, which sources more than 85% of its power from hydropower plants, including those operated by the Bonneville Power Administration, the federal power agency responsible for hydropower in the Pacific Northwest. Seattle City Light and the Bonneville Power Administration did not respond to requests for interviews.
'Deal with it and optimize'
For now, many power producers find they have to manage vastly more water than a few decades ago and need to invest accordingly to upgrade their infrastructure.
In response, utilities have started to put in place adaptation measures ranging from increasing the capacity of turbines, to reinforcing river embankments, installing flood protection and building larger spillways to manage excess water.
Statkraft invests between 1.5 billion Norwegian kroner and 2 billion kroner in its Norwegian and Swedish hydropower assets per year. Although climate proofing is only part of that equation, a lot of the company's portfolio is up for refurbishment in the next 10 to 20 years, and Tanem said the company is taking the chance to put in place adaptation measures.
Småkraft has applied for permits to add reservoirs to some of its run-of-river plants, which Sterud said will allow the company to store some of the higher inflow but also even out volatility during droughts. The company also plans to build 10 new hydro plants each year, which will need to be built more resiliently than in the past to withstand severe floods, he said. Meanwhile, some areas are becoming off limits altogether because they are too risky.
"The entire business is so [dependent] on the weather and the water that we have in the rivers," Sterud said. "Power stations we construct now, we take into account what we believe it's going to be like in the future. We are constructing differently than we would have 40 years ago."
In Canada, state-owned Hydro-Québec is dealing with many of the same issues. The company's assets are spread over a vast territory, meaning impacts vary greatly from plant to plant, but it is generally expecting an increase in mean annual inflow, said Marie-Claude Simard, head of hydrology for the company's hydropower business.
By 2050, rainfall alone is expected to increase by up to 8% in Quebec, which already hosts 40% of the water resource in Canada, according to Simard.
"It's already contributing to the water in the reservoirs," she said. "We think, in the future, this is going to stay — there's going to be more and more water. And we have to deal with it and optimize."
The utility's internal engineering business now puts greater emphasis on future climate projections when working on new projects. In 2001, in the wake of a series of extreme weather events, the utility and the governments of Quebec and Canada founded Ouranos, a consortium of experts and policymakers that shares expertise in climate science and advises on adaptation strategies.
Since Hydro-Québec's board identified climate change as a key business risk in 2018, the company has now started an "exhaustive assessment" of its exposure, Simard said, which will eventually lead to a fully fledged adaptation strategy to integrate climate risk into its decision-making process.
"When you build a power plant or reservoir, you don't build it for the next 10 years. You build it for a long time," she added. "And we want to make sure we have the best practices in place to take into account this kind of change in the future."
Seeing the future in a shrinking glacier
In other places, things are moving in the opposite direction. Statkraft also operates hydro plants in southeastern Europe, India and Latin America, and some of those regions are already seeing less water, which Tanem said means potential acquisitions and new projects now have to be evaluated much more carefully.
Aquila's Syverud said he is also observing less rain in Turkey and expects countries like Finland, which is further inland from the moisture-laden winds blowing in from the Atlantic, will also get drier in the future.
In the long run, many more areas can expect to see a drop in water availability and, consequently, lower power production. Statkraft expects water inflows to keep rising in the Nordics, but Tanem estimates the trend will reverse in the next half-century, once glaciers shrink far enough.
"The next 30 to 40 years, we don't see that. But at some stage, it will happen," he said.
In the Swiss Alps, Alpiq Holding AG thinks it has found a way to take advantage of disappearing glaciers. The utility wants to use new lakes formed by receding ice sheets to power additional turbines in the future, said Chrystelle Gabbud, environmental manager at Alpiq.
Switzerland's largest glacier, the Great Aletsch — which holds 11 billion tons of ice — has been shrinking by about five meters each year since 2000, laying bare a landscape that could be used to build new reservoirs. In a first project, Alpiq is planning to use a valley that it expects will become ice-free in the next 10 to 15 years as the site for a new power plant that could produce up to 100 GWh a year — most of it in the winter, when demand for electricity is already highest in the country.
A group of researchers found that the total volume of ice in Alpine glaciers declined by about 17% between 2000 and 2014 alone, with ice now melting even in the highest reaches. Hydroelectric plants produce about two-thirds of Switzerland's power, and new lakes such as the one below the Aletsch could help bridge the gap left by Switzerland's nuclear reactors, which are due to close over the coming years.
"These new lakes offer a new opportunity," Gabbud said. "We're only at the beginning of understanding what we can do."
Utilities 'in the limelight'
While the physical threat is felt more acutely with every drought and rainstorm, pressure is also rising from another direction. Investors that finance a large share of hydropower projects around the world are increasingly mandating that developers properly prepare for climate change-related risks.
Equity investors, insurers, rating agencies and lenders are "all beginning to ask questions about climate risk," said Craig Davies, associate director and head of climate resilience investments at the European Bank for Reconstruction and Development, or EBRD.
"Investors and capital markets are looking more closely at climate-related financial risks [and] utilities are really in the limelight," Davies said.
The EBRD, which is mostly active in Eastern Europe and Central Asia, has directly invested over €1.5 billion in rehabilitating large hydro projects and financing smaller run-of-river plants. The bank is carrying out an assessment of its existing portfolio with the World Resources Institute, combining environmental data and monthly generation statistics for specific assets with climate projections to get a better picture of how changing rainfall patterns could impact power production, for example.
But while the EBRD already integrated climate resilience into its processes to some degree, it has not been asking questions about climate vulnerability in a systematic way, Davies said. Now the bank is developing its own comprehensive climate risk framework, which could be rolled out across its operations as soon as 2021.
"We're doing what many other banks around the world are doing," Davies said. "It means then every single investment will be screened for physical climate risk, subject to a standard methodology. And that will affect our hydropower investments."
Another multilateral lender, the European Investment Bank, requires hydropower project sponsors to assess and mitigate any potential physical risks to infrastructure, for example from enhanced flooding or erosion. The World Bank Group, which has financed hydropower projects from East Asia to the Andes, also has mandatory rules to assess infrastructure project's risks from climate change.
In one example, the World Bank is using its climate risk assessment guidelines to probe the impact of glacial melt and snowfall in the Himalayas on a 1,000-MW hydro project planned for the border between China and Nepal. In the next stage, the bank will use that knowledge to consider adaptation measures at the site, said Pravin Karki, its global lead for hydropower and dams.
"Without a climate risk assessment, the bank will not finance any project," Karki said, adding that awareness of physical risk is also growing among the bank's partners, from governments to the bond market.
With more countries breaking temperature records every year, the issue is only likely to become more serious. In that environment, operators and investors that rely on past experience will pay the price, said Aquila's Syverud.
"It's not only enough to look backwards, but what will the next 30 to 40 years look like?" he said. "That could be a hidden cost for investors who look at the past and don't consider what could happen in the future."
As of Aug. 12, US$1 was equivalent to 8.93 Norwegian kroner.