Electricity markets around the world are having difficulty incorporating policy objectives to market mechanisms. It is not a new issue. Since the opening of electricity markets, everyone had a suspicion that the markets favor natural gas. There were several reasons for this phenomenon. The most important one was the efficiency of fuel conversion. But this has to change…
The rise of natural gas in power markets or power systems may be traced the to late 1970s. In 1978, the Public Utility Regulatory Policies Act of 1978 of the USA had a definition called QF, qualifying facilities. These facilities are either small power production renewable facilities or cogeneration plants. Initial sunk costs, stranded asset discussions were started with this QF definition. As cogeneration became a bigger market, the technology improved. It also forced the system to accept new players with their small or cogeneration plants.
The early roots of the standard market model merited low-cost production. Low-cost production in a fossil fuel world can only be satisfied by either efficiency or low fuel cost. The reflection of this in economics is marginal cost. So, the system works on the competition of marginal costs. The more efficient and less variable costs lead to an ever cost-effective system.
As things move forward, natural gas has become the natural winner of the market system. Whenever the market liberalized, natural gas has become the star. The clean, efficient, flexible primary fuel system is an essential asset in power markets. But natural gas has one Achilles heel that is the oil-linked pricing of natural gas. The electricity prices were a shadow derivative of oil prices in most places.
During the early stages, the most visible problem was missing money problem. The competitors in the power market can earn their marginal costs, but the mechanism doesn’t guarantee their capital expenditures or investment costs and the security of supply. Therefore capacity mechanisms were invented as a necessary evil to solve investment returns problems.
This corrected, and the working mechanism creates a competition based on efficiency. But how about renewables? Think this way; we have a joke about 100 solar panels. If we have 100 solar panels and need –let’s say- 60 of them, which ones should be dispatched, which ones should not be dispatched? There is not an easy solution for such a mechanism to solve the renewable dispatch solution.
Some researchers proposed “on-demand” and “on available” market mechanisms. Some other offered flexibility mechanisms. There may be baseload power markets, as suggested in the Japanese market reform or separate fossil and renewable markets. But the main question remains: What is the competition criteria? If it is efficiency, how should we price efficiency within the renewable world? There is an easy solution; the most efficient renewable resource is the one closest to the source. But then this contradicts the inherent economies of scale of the power sector.
I think that the marginal cost paradigm is not the central pillar of renewable power markets. The competition among renewables should be based on the opportunity cost of not getting dispatched. It requires a complementary flexibility market. Current balancing markets may evolve into flexibility markets. Then there is the question of opportunity cost. Pricing an opportunity cost in zero marginal cost resources will be hard. Some may claim that it is LCOE, levelised cost of energy. But then you guarantee everyone their investments at least.
Markets are the main instruments of power system operations. If they can not handle price costs and policies correctly, the whole procedure will be inefficient, and it will be a burden to the customer. Long term contracts are a temporary remedy. Competitive renewable energy markets are the new challenge of the energy markets.
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