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According to an OECD/NEA report, between 2008 and 2015 the use of low marginal-cost variable renewable energy had ‘caused an electricity market price reduction of 24% in Germany’ (OECD 2018). However, while wholesale costs may have fallen, this has not always resulted in the savings being passed on to consumers in terms of reduced retail prices, with residential electricity tariffs having increased in Germany by 16% between 2010 and 2017. It has been similar in the United Kingdom and in some cases elsewhere.

Power costs are becoming increasingly controversial, but it is also complicated to assess the factors leading to rises. The power utilities argue that the retail cost hikes have been because they face increased overall system costs, some of this, it is sometimes claimed, being due to the costs of the various green levies. They certainly have added some extra cost to bills, although that has to be set against the energy and cost savings from some of the green energy schemes. For example, the UK government’s advisory Committee on Climate Change has claimed that the costs of green power subsidies to consumers have been more than offset by savings they enjoyed due to the various energy-efficiency initiatives (CCC 2019). I will be coming back to that issue in chapter 5.

The power utilities also complain about system-balancing costs incurred in managing the system with increasing amounts of variable renewables on the grid. Conventional plants may have to operate less efficiently to cope with variable renewables on the grid, ramping output up and down regularly. As has happened in Germany, some conventional plants will be forced to go offline for a while, so losing income when lower marginal cost renewables are available, the market for gas plants thus being undermined by smaller-scale, often locally owned, renewable projects. These extra costs/losses have sometimes been called ‘market profile’ costs since they result from the changed pattern of generation in the new power market, adding to the overall system-management and subsidy costs.

However, these various system costs will not have been the only extra costs faced by the power companies. Fossil fuel costs have risen and so have operational costs generally. Set against that, while the big utilities may be losing some of their markets to green energy in some countries, there are also savings. For example, about €8.8 billion of primary fuel import costs in Germany were avoided in 2015 as a result of renewable energy use, and these savings will grow as renewables expand, while the system-balancing costs should begin to fall as new smart systems are adopted, replacing the use of fossil plants for backup (see Box 2.1).

Meantime, gas turbine plants can offer a relatively cheap balancing option. In the United Kingdom, the government has introduced a capacity market system to ensure that sufficient balancing capacity is available, offering a subsidy to support it. However, while other balancing options (including storage) were also eligible for support, so far this system has focused mainly on gas plants and also, somewhat perversely, on existing nuclear capacity, despite this not being very useful for balancing variable renewables.

You might see the subsidy payments under the UK capacity market as being interim compensation for the ‘market profile’ losses of these existing plants. While it is hard to justify the inclusion of already subsidized and inflexible nuclear in this, it is important to keep flexible gas turbines online to help with balancing, although gradually other balancing options, including storage, interconnectors and demand management, will hopefully get more support. That may also happen in Germany, under market pressures, with utilities focusing on what could become a lucrative balancing market rather than on supply, much of which (although, as indicated later, perhaps not all) will come from local self-generation by ‘prosumers’ and energy co-op projects.

Clearly, whichever side of the debate you are on, the subsidy issue can be provocative. Some say subsidies are vital to help new technologies to enter well-established markets; others see them as undermining competitiveness and leading to extra costs. For example, a Chicago University study claims that the US Renewable Portfolio Standards (RPS) ‘significantly increase average retail electricity prices, with prices increasing by 11% (1.3 cents per kWh) seven years after the policy’s passage into law and 17% (2 cents per kWh) twelve years afterward’ (EPIC 2019).

The RPS system is based on targets and market-determined prices, and, as the Chicago University paper says, the latter reflect ‘the costs that renewables impose on the generation system, including those associated with their intermittency, higher transmission costs, and any stranded asset costs assigned to rate payers’. The latter outcome, where some old plants sometimes become uneconomic and perhaps have to be subsidized by consumers to keep them going, reflects the fact that renewable generation costs are low and getting lower, so that, as in Germany and the United Kingdom, some conventional plants cannot compete in the changed market (see Box 2.2).

Is it fair to include that changed so-called ‘market profile’ cost as a cost of renewables? It is arguably just a commercial loss or cost faced by their rivals. True, grid-balancing costs are an extra but arguably they reflect the cost of moving away from an inefficient, inflexible, centralized system to one based on distributed variable green sources and flexible backup and demand management. It is claimed by supporters of the latter that, although it may take time to bed these new systems in, if it is done right the new system should lead to more efficient supply and demand balancing and overall cost savings (see Box 2.1). Given also the emissions savings that the new system can deliver, the optimists look ahead to an unstoppable change process, with green energy technologies replacing the old technologies in an increasingly productive and competitive way (Lovins and Nanavatty 2019).