A grid that runs mostly on renewables
Panama’s power sector stands out for how little it relies on fossil fuel for electricity. Renewable sources supplied about 79.3% of the country’s total electricity output in 2021, a level that had held in a similar range for several years, 78.4% in 2020 and 80.4% in 2018, after a lower base earlier in the previous decade [1]. In practical terms that means roughly four out of every five kilowatt-hours consumed in Panama come from renewable generation, with only the remaining fifth drawn from thermal plants burning imported fuel.
That share matters for two reasons. The first is cost and exposure: a grid that imports fuel for only a fraction of its generation is less exposed to oil and gas price swings than a thermal-dependent system, and its operating costs are dominated by the upfront capital of the renewable plants rather than by a recurring fuel bill. The second is climate: the high renewable share keeps the carbon intensity of Panama’s electricity low, which is a meaningful advantage for a services economy that markets itself on connectivity and sustainability. Both feed into the wider story of an economy that runs on throughput and would prefer its power to do the same.
The headline renewable figure is, however, a snapshot of a system that swings year to year. The same data show the renewable share dipping notably in some years and recovering in others [1], and the reason is the composition of the renewable base, which is dominated by a single, rainfall-sensitive technology.
Hydro: the backbone of the system
The largest component of Panama’s renewable generation is hydropower, and it is hydropower that explains both the high renewable share and its year-to-year volatility. The country’s relief, interior highlands and significant rainfall, is well suited to large hydroelectric plants, and several of them, along with a fleet of smaller run-of-river and reservoir schemes, supply the bulk of the grid’s renewable megawatt-hours. When rainfall is normal, hydro fills the system and the renewable share is high; when rainfall is short, hydro output falls and the renewable share dips, with thermal generation taking up the slack.
A representative example of the scale involved is the Bayano hydroelectric complex. The Central Hidroeléctrica Bayano, operated under the regulator ASEP’s oversight, has an installed capacity of 260 megawatts across three Francis vertical-axis turbines (87 MW, 87 MW, and 86 MW), with a firm capacity of 160 MW and a reservoir of substantial useful volume impounded by a main dam roughly 75 metres high and 450 metres wide [2]. A single plant of that size is a material slice of a small country’s generation fleet, and Panama has several hydro complexes of comparable or larger scale. Together they set the ceiling on how much renewable power the system can deliver in a given month. That ceiling moves with the weather.
The engineering of these plants is shaped by the same freshwater system the canal depends on. A hydro plant stores water behind a dam and releases it through turbines; the Bayano complex’s emergency-action planning, prepared under ASEP oversight, addresses the downstream populated places along the rivers it controls [2]. The point for an economic reader is that the canal and the power sector draw on the same resource, Panama’s freshwater, and a shock to that resource is felt in both places at once.
Thermal generation and the balance
The roughly one-fifth of generation that is not renewable comes from thermal plants, which burn imported fuel, principally natural gas and diesel, to produce electricity. That thermal slice is the system’s flexibility: it is what ramps up when hydro is short, and it is what covers the gap between renewable output and peak demand on the driest, highest-use days. The cost of that flexibility is exposure to fuel prices and to import logistics, since Panama does not produce the hydrocarbons its thermal plants burn in any significant volume.
The mix between hydro and thermal is therefore not just a technical statistic; it is the mechanism through which rainfall variability becomes an electricity-price variable. In a wet year, cheap hydro dominates and thermal sits idle; in a dry year, thermal runs harder, imports rise, and the marginal cost of power increases. The same dynamic that forced the canal to cut transits in the 2023–2024 drought, low freshwater supply, also pushes the power system toward its more expensive thermal margin, so a drought shows up simultaneously as fewer ship transits and higher-cost electricity.
The generation fleet, plant by plant
The hydro backbone is a fleet rather than a single plant, and its largest members set the scale. The biggest station is Fortuna, at 300 MW, with Changuinola (223 MW) and Estí (122 MW) the next largest alongside the Bayano complex described above, and a longer tail of smaller reservoir and run-of-river dams below 100 MW each [4]. The thermal margin that firms this fleet is concentrated in a few large units: AES Colón II, a 381-megawatt gas-fired plant commissioned in 2018, is the largest thermal station and a marker of the sector’s shift toward natural gas; the 300 MW Cobre coal-fired station (commissioned 2019) and an older 72 MW bunker-oil unit at AES Colón I complete the dispatchable base [4]. The shape, then, is a hydro fleet led by a handful of big dams, balanced by a gas-and-coal thermal margin that ramps when the rains are short, the engineering form of the rainfall risk that defines the sector. The fleet was also built in waves across four decades (Fortuna in the 1980s, Estí in the 2000s, Changuinola in the 2010s, and the AES Colón gas plant in 2018), so the dispatchable margin has modernised even as the hydro backbone rests on dams commissioned a generation ago [4].
Renewables beyond hydro
The renewable share is not only hydro. Across the 2010s and 2020s Panama added non-hydro renewable capacity (wind farms on the breezy western highlands and ridge-lines, and solar generation where land and insolation allow), which has broadened the renewable base beyond a single technology. These sources help in a specific way: their output is not tied to the same freshwater constraint as hydro, so a dry period that depresses hydro generation does not necessarily depress wind and solar to the same degree. Diversifying the renewable base is, in effect, a hedge against the rainfall risk that defines the hydro-heavy system.
That diversification is part of why the renewable share has held up even as overall demand has grown. A grid that leaned entirely on reservoir hydro would be maximally exposed to drought; one that adds wind and solar spreads the weather risk across independent sources. The investment signal in the sector is therefore toward continued additions of non-hydro renewables alongside the existing hydro fleet, with thermal retained as the firming resource that keeps the lights on when neither hydro nor variable renewables are sufficient.
Sizing the system around firm capacity
The hydro fleet as a whole swings between its installed capacity in wet periods and its firm capacity in dry ones. A grid planner cannot assume the installed figure; the system has to be sized and contracted around the firm figure, with thermal held in reserve for the periods when hydro cannot deliver. The cost structure follows that swing: cheap megawatt-hours in wet years, when hydro dominates, and more expensive ones in dry years, when the thermal margin sets the price. The reservoirs that make this possible are large civil works that do double duty, holding the water that generates power and regulating the flows that affect the communities and ecosystems downstream, and the Bayano dam, maintained under a documented emergency-action regime [2], is one example of an asset whose operating decisions trade off generation against flood control, downstream supply, and environmental flow.
Why a drought is an electricity event
Tying the hydro dependence back to the wider economy makes clear why the energy sector cannot be read in isolation from the canal. Both depend on the same freshwater (the canal because each lockage consumes water from Gatún Lake, the power sector because the hydro fleet depends on reservoirs fed by the same rains) [3]. A drought that lowers reservoir levels is therefore not only a shipping event, with fewer daily transits; it is simultaneously a power event, with hydro output falling toward its firm capacity and thermal generation rising to compensate. The two headline effects, canal transit cuts and tighter electricity supply, share a single underlying cause, which is why they tend to appear together.
For an electricity user, that coupling means the cost and reliability of power are partly a climate variable. In normal years the system is comfortable: hydro meets most of the demand, renewables dominate the mix, and the thermal plants run only at the margin. In a dry year, the thermal margin becomes load-bearing, the system’s exposure to imported fuel rises, and the marginal cost of electricity increases. That increase comes at exactly the same time as the canal’s capacity, and the logistics income that flows from it, is also under pressure. A reader trying to understand Panama’s macroeconomic risk should treat a drought as a compound shock: it tightens the waterway and the power grid at once, and both feed into the national accounts.
What this means in practice
For a reader trying to understand Panama’s energy sector, the essential picture is of a grid that runs roughly four-fifths on renewable electricity, led by hydropower from large plants like Bayano, balanced by imported-fuel thermal generation, and increasingly diversified by wind and solar [1] [2]. The system’s defining feature, its dependence on freshwater for the bulk of its renewable output, is the same feature that constrains the canal, which is why the country’s two great throughputs, ships and megawatt-hours, are sensitive to the same weather [3].
The practical takeaway is that Panama’s electricity is, in normal years, both low-carbon and relatively low-cost, with the proviso that a severe drought can tighten supply and raise the marginal cost of power at the same time as it disrupts shipping. Readers interested in the resource side, including the crude-petroleum arrangements under which Panama imports hydrocarbons, should turn to the mining-and-resources page, those interested in the infrastructure that carries the power alongside the canal to the infrastructure-overview page, and those placing the sector in the national economy to the economy-overview page. Energy in Panama is, at bottom, another expression of the same geographic fact that shapes everything else: the country’s freshwater and its location.
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