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The Future of Electricity Markets

British philosopher and mathematician Alfred North Whitehead once wrote "fundamental progress has to do with the reinterpretation of basic ideas."

If recent trends are any indication, such a re-evaluation is imminent if not already underway in many electricity markets around the world, a process that could have wide ranging implications for the world’s most capital intensive sector.

Two related processes are driving these changes: first, the move toward more competitive electricity markets; and second, the growth of renewable energy sources, namely wind and solar.

While these two processes have unfolded in parallel over the past few decades, there are signs that a deeper convergence may be underway. From capacity markets to energy storage, smart grids to demand response, electricity systems are already beginning to show signs of change; however, the most fundamental changes may be required in the basic design of electricity markets themselves. 


Due to the fact that renewable energy technologies like solar and wind power have little to no marginal cost, they represent a significant departure from fossil-based power plants. As a result, when wind farms and solar plants are located in liberalized markets, they typically bid into the spot market at zero (sometimes less); this strategy helps ensure that their electricity gets purchased whenever the wind blows, or the sun shines.

One of the consequences of this is that as the share of renewable electricity with zero marginal cost in the overall mix grows, renewable energy sources actually push spot market prices down since power plants with higher short-term marginal costs are no longer needed to meet demand.

In the absence of clear power purchase agreements (PPAs), bilateral contracts, or feed-in tariffs, this entails significant risks for investors. To date, most RE capacity in the world has been financed with one of these three mechanisms and has therefore remained largely sheltered from spot market fluctuations. And yet,  a moment’s thought will quickly reveal that in a liberalized market, as soon as RE technologies start to represent a sizeable share of the market, RE producers quickly begin to undermine their own revenues.

This is a point often only dimly appreciated by economists and regulators, who are inclined to focus on how electricity markets should work in theory, rather than how they work in practice.


To draw on an example, consider Germany. Due to feed-in tariffs that guarantee a minimum price (in what amounts to a de facto PPA), Germany has seen a surge of renewable energy development since the early 2000s. The consequences of this surge in zero marginal cost power have been clear: electricity prices during the summer on Germany’s  spot  market are often lower during the day than they are during the evening, as the large influx of solar power (approximately 32 GW as of Q4:2012) enters the grid. (The same has occurred with wind power in the north of the country).

Figure 1: Profile of Electricity Supply in Germany, May 21st – 27th 2012. 

Source: Fraunhofer ISE, EEX

During the week of May 21, 2012, solar PV produced over 1.1TWh of electricity, representing approximately 18 percent of total electricity demand in Germany over the same period, and supplying almost 50 percent of instantaneous electricity demand during certain hours of the day.

While producers are paid mostly via 20-year feed-in tariffs, the electricity they produce is now mostly sold on the spot market, marketed by the system operator. Unsurprisingly, this has a profound impact on spot market prices, both inside and outside  Germany’s  borders due to European grid interconnections.

The graph below provides a snapshot of price evolution and supply dynamics on a typical summer day in Germany. 

Figure 2: Electricity Supply Profile and Spot Market Prices    

Source: Photon GmbH 2012

As can be seen on the right axis, the spot market price dropped to EUR 20/MWh (USD $27/MWh) during the middle of the day when the sun was shining.

The implications of this are profound: if the German market truly were fully liberalized (i.e. if there were no long-term PPAs or feed-in tariffs), this would have wrenching consequences for renewable energy producers — they would effectively become victims of their own success. RE projects would collectively push electricity prices down, and in the process, they would inadvertently push themselves below their debt service requirements, and into insolvency.

In the absence of a supportive policy framework, this “negative network externality” would bring the RE market to a halt, and make it next to impossible to obtain financing for electricity projects, whether fossil-based or renewable. In the longer term, it would be next- to-impossible to transition towards electricity markets with high penetrations of renewable energy such as solar and wind (which remains the objective in Germany and in many other jurisdictions around the world — indeed, scenarios up to 80 percent have been modeled and deemed technically feasible by the National Renewable Energy Lab (NREL) in the U.S.).

The absence of such a framework for fossil plants is already prompting many in the industry to push for some form of price support for natural gas plants, as many realize that projects are simply not bankable without them. A similar debate is playing out in the UK, as the latter attempts to develop price supports for nuclear and other forms of generation.

This points to a deeper tension within the current debates about the future of electricity markets: investing in generation assets in liberalized markets requires some form of price support to provide the revenue certainty required. Failing that, investments are likely to grind to a halt, primarily because of the sector’s high capital intensity.

Thus, the liberalization underway in many jurisdictions may end up having undesirable consequences: by largely doing away with long-term contracts, they have begun to undermine the basic conditions required to ensure that investments in electricity generation assets are sustained.

Tellingly, the absence of long-term contracts in countries like Chile is what has prevented it from seeing virtually any investment in renewable energy in recent decades, despite the fact that it is blessed with among the world’s best renewable energy resources: the geographic conditions are present, but the institutional ones are not.


Current attempts to solve this problem for conventional power plants are focused primarily on developing forward capacity markets, as has been done in certain markets such as the PJM region of the U.S. northeast. While this solution may help improve reliability, it is a partial solution at best. As it stands, there are currently no credible, long-term solutions for incorporating high proportions of renewable energy into existing electricity markets.

Thus, a new market design for the electricity system is likely to be required in the decades ahead. As Whitehead suggested, this is likely to require a fundamental reconsideration of some very basic ideas, including ideas about grid parity, about the role and function of spot markets, and about what role price signals should play in the supply, demand, and allocation of this essential resource.

Finally, it is important to underscore that this is not (or at least, should not be) an ideological debate about free-markets vs. regulation: it is, at root, a debate about institutions, and about how best to sustain the flow of capital to one of the world’s most critical sectors.

Toby D. Couture, MA, MSc. is Director of Renewable Energy at IFOK GmbH in Berlin.

Dr. David Jacobs is a research associate at the Institute for Advanced Sustainability Studies in Potsdam and lecturer at the Freie Universität Berlin.

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