Renewable Portfolio Mix Calculator

A generation portfolio is described by three numbers per technology: installed capacity in megawatts, capacity factor, and levelized cost per megawatt-hour. Multiplying capacity by capacity factor by the 8,760 hours in a non-leap year gives annual energy, and dividing summed cost by summed energy gives the blended portfolio LCOE. That blended figure is what matters to a planner, because the cheapest single technology is rarely the cheapest system once timing is considered. Typical capacity factors used in planning studies are 20 to 30 percent for utility-scale photovoltaics, 25 to 45 percent for onshore wind, 40 to 55 percent for offshore wind, and 35 to 60 percent for conventional hydro, though run-of-river schemes can fall well below that in dry years. The arithmetic here is deliberately energy-balance only: it compares annual generation against annual demand and reports coverage as a percentage. Coverage above 100 percent does not mean the load is met, because solar and wind output is not dispatchable and surplus midday generation cannot serve a winter evening peak. Systems with high variable renewable shares routinely curtail energy, and the curtailed fraction climbs steeply once instantaneous penetration passes roughly 50 to 60 percent without storage or transmission. Storage cost in this model is treated as a simple annualized adder rather than a chronological dispatch simulation. Avoided emissions use a displacement factor near 0.4 tonnes of CO2 per MWh, which is close to a mixed grid average; a coal-heavy system displaces closer to 0.9, a gas-heavy one closer to 0.4.

Formal planning of generation mixes dates to the utility integrated resource planning practice that spread in the United States after the Public Utility Regulatory Policies Act of 1978 opened the market to independent producers. The idea of treating a set of power plants as an investment portfolio rather than a ranked list of least-cost options was argued most forcefully by economist Shimon Awerbuch in the early 2000s, who applied Harry Markowitz mean-variance portfolio theory to electricity generation and showed that adding fixed-cost renewables to a fuel-price-exposed fossil fleet could lower expected system cost risk even when the renewable looked more expensive in isolation. Mandated mixes came from legislation. Iowa enacted the first state renewable purchase requirement in 1983, and Texas adopted a renewable portfolio standard in 1999 that became the template most other states followed; by the 2010s roughly thirty states had some form of standard. The European Union pursued the same goal through the 2001 electricity directive and the 2009 Renewable Energy Directive, which set binding national shares for 2020. Cost benchmarking became routine when institutions began publishing comparable technology data: the National Renewable Energy Laboratory Annual Technology Baseline, the International Renewable Energy Agency cost reports, and the Energy Information Administration Annual Energy Outlook now supply the capacity factor and LCOE inputs that portfolio calculations like this one depend on.