Climate-Smart Mining: The Economics of Renewable Power in Copper Operations

In 2013, Collahuasi and Gabriela Mistral, two large copper mines in Chile’s Atacama Desert, began integrating solar into their energy supply. A decade later, solar installations cover 30-45% of their energy requirements, and the project has been renewed through 2032 (Mine Australia, 2025). The decision was made on financial grounds, at operations that collectively rank among the largest copper producers in the world.

The economics have since moved further in the same direction. In 2010, utility-scale solar cost more than four times the cheapest fossil fuel generation. By 2024, it had fallen 41% below that benchmark, reaching USD 43/MWh on a global weighted average. Onshore wind reached USD 34/MWh, 53% cheaper than fossil fuel alternatives. Battery storage costs fell 93% over the same period, to USD 192 per kWh (IRENA, 2025). For a remote mine running diesel generation at USD 150-200/MWh, the gap is substantial (247Solar, 2025).

Copper mining is energy-intensive, and energy is one of the two or three variables that most directly determine whether a mine is profitable. This article examines the energy profile of a hypothetical medium-scale copper mine and what a transition to renewable power could realistically look like, using the Chilean precedent and others as the benchmark for what is already commercially proven.

The energy profile of a copper mine

A medium-scale open-pit copper mine is, at its core, a material-handling and chemical processing operation: diesel-powered for haulage, drilling and blasting, and electricity-driven for crushing, grinding and flotation. Mines run every hour of every day of the year. The rule of thumb in the industry is approximately 1.5 MW of installed power per 1,000 tonnes of ore processed per day (Daigle & Mottram, 2015). A mine processing 30,000 tonnes per day carries an electrical load of roughly 45 MW continuous, with peak demand approaching 55 MW. For remote mining operations, power typically accounts for more than 20% of total operating costs (Daigle & Mottram, 2015).

That cost is rising structurally: the average global grade of copper mines has declined 40% since 1991 (IEA, 2026), a trend recognized across the industry as one of the primary constraints on future copper supply (ICSG, 2025). Lower grades mean more rock moved and processed per tonne of copper recovered. New high-grade, near-surface discoveries have become scarce, and what remains in the pipeline requires deeper mining and more complex processing. The energy intensity of copper production will continue to increase regardless of what powers it.

The Arida copper mine: an energy scenario

The hypothetical mine at the centre of this analysis is a 30,000 tpd open-pit copper operation situated in a remote, arid environment representative of real operating contexts in northern Chile, north-western Australia, or parts of Central Asia. It is called Arida. At 60,000 tonnes of copper per year, it sits well below the scale of OyuTolgoi in Mongolia’s South Gobi Desert, one of the largest copper operations in the world (Rio Tinto, 2025), but is representative of the mid-tier operations that collectively account for the majority of global copper output.Mining regions in the Atacama, the Pilbara and parts of Central Asia are arid, high-irradiation and remote, the geographies where solar performs best and diesel logistics costs are highest.

Arida’s electrical load is 45 MW continuous. Annual solar irradiance at the site, the amount of solar energy reaching each square metre per year, is 2,200-2,500 kWh/m², typical for arid mining regions and among the highest recorded anywhere. Approximately 60% of total mine energy is consumed by mobile mining equipment. Of the electrical load at the processing plant, the largest single consumer is comminution, crushing and grinding ore, which accounts for around 36% of total mine electrical energy (CEEC, 2021). The remainder covers flotation, pumping, dewatering, ventilation and lighting. Some of these processes can absorb variability in power supply; others require continuous, uninterruptable electricity. A renewable energy system must be designed around that distinction, which is why battery storage is an essential part of any viable configuration.

The renewable potential, capacity factors and intermittency

A solar or wind installation does not produce its rated power continuously. The capacity factor is the ratio of actual annual energy output to what the plant would produce if it ran at full capacity every hour of the year. For solar PV in a high-irradiation arid location a realistic capacity factor is around 28%, and for onshore wind at a well-sited location around 35% (IRENA, 2025). Wind resources at mining sites are highly site-specific but often substantial, particularly in elevated terrain, where modern turbines in the 3.5–5 MW class deliver a capacity factor of 35–40% at conservative wind speeds. This means installed capacity must significantly exceed the load it is designed to serve.

The relationship between installed capacity, capacity factor and annual output can be expressed as:

Annual energy output (MWh) = Installed capacity (MW) × Capacity factor × 8,760 hours/year

A 100 MW solar installation at Arida, with a 28% capacity factor, would produce approximately 246 GWh per year. Arida’s 45 MW continuous load draws roughly 394 GWh per year, meaning solar alone would require approximately 160 MW of installed capacity. Solar produces during daylight; wind often peaks at night and during seasons of lower insolation. Together, they reduce the periods when neither source is generating and storage must carry the load alone.

Three configurations for Arida

The table below illustrates three renewable configurations for Arida’s 45 MW electrical load, with installed capacity figures, expected renewable penetration, and estimated capital cost based on current IRENA benchmark costs (IRENA, 2025).

Configuration	Solar (MW)	Wind (MW)	Storage (MW / MWh)	Renewable penetration	Est. capex (USD million)
Solar-first	80	–	20 / 40	~35%	~90
Hybrid	60	40	30 / 60	~65%	~120
High-penetration hybrid	100	60	50 / 100	~80%	~220

All three configurations retain diesel or gas backup for periods when solar and wind output fall below minimum plant requirements. Projects at comparable scale are already operating. In March 2024, Gold Fields approved a project at its St Ives gold mine in Western Australia integrating 42 MW of wind and 35 MW of solar, projected to cover 73% of electricity needs and cut carbon emissions by 50%. In 2023, AngloGold commissioned a 62 MW hybrid wind-solar facility at the Tropicana gold mine, also in Western Australia, expected to reduce carbon emissions by over 65,000 tonnes per year (Mining Technology, 2025).

The harder problem: the haul fleet

Decarbonising Arida’s electrical load is achievable with current technology. The haul fleet presents a different timeline. Battery-electric haul trucks are entering commercial deployment, with Fortescue, Caterpillar and Komatsu advancing programs in the 150-300 tonne payload class, but battery mass, charging infrastructure and thermal management in extreme heat remain real constraints (MDPI Mining, 2025). Green hydrogen is the other candidate for heavy haulage, though cost parity with diesel is not imminent. Full fleet electrification at scale is realistically a 2028-2032 horizon.

The practical implication is a sequential transition: electrify the processing plant first using solar, wind and storage, which is technically mature and financially viable today, then electrify the haul fleet progressively as the technology matures.

Fiscal design and the energy transition

A mine that remains diesel-dependent pays fuel import costs that compound the fiscal gap for host countries. Governments designing mining fiscal regimes have a practical instrument available: renewable energy milestones as a condition of licensing, or royalty rate adjustments tied to verified renewable penetration targets. Primary copper mines emitted an estimated 53.64 million tonnes of CO2 equivalent in 2024 (S&P Global, 2025), a figure that will become commercially significant as carbon border mechanisms in Europe begin to apply to mining supply chains. Scope 1 and 2 emissions data from mining operations are moving from a reporting requirement to a market variable.

What has lagged is not the availability of fiscal instruments but the institutional design to deploy them consistently, and the willingness of host governments to use the leverage they already hold.

From mine infrastructure to regional energy systems

Developing a mine in a remote region requires building infrastructure that rarely existed before: access roads, water supply systems, transmission lines and grid connections. A 60-100 MW solar or wind farm constructed to power the mine represents permanent energy infrastructure that, with the right regulatory design, can be connected to a nascent regional grid and supply surrounding communities long after the mine has closed. The energy assets become public capital built from private investment, which is precisely the kind of transformation that resource wealth should enable (Daigle & Mottram, 2015).

The scale of mine-level renewable installations also makes distributed generation economically viable in regions where centralised grid extension would otherwise take decades. A mine operating a hybrid solar-wind-storage microgrid pilots the architecture of a modern decentralised power system. The physical infrastructure it installs, substations, interconnectors, metering points, becomes the backbone of a regional grid that did not previously exist.

Operating a hybrid renewable microgrid at mining scale also requires energy management systems, SCADA platforms, advanced metering infrastructure, and battery management systems, that once deployed constitute the digital foundation of a modern power sector. These are not mine-specific tools. Host countries that structure mining investments correctly through licensing and fiscal conditions can retain this capability after the mine closes.

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