Renewable Electricity and Backup Capacities: An (Un-) Resolvable Problem?

• Author: Praktiknjo, Aaron

1. INTRODUCTION

   Public support of renewable electricity normally aims at ensuring recovery of total cost plus a given return on investment. For wind and photovoltaics (PV), total cost consists almost exclusively of investment cost. However, in liberalized electricity markets, all power is indiscriminately sold on the same market. Having almost no marginal cost, wind and PV power generation are preferred in the merit order over coal-fired and gas-fired power generation. State aid in favor of renewables therefore implies reduced operation hours of conventional generators, particularly for combined cycle gas turbines (CCGT). Under current European market conditions, they have higher marginal cost than coal-fired power generators. The squeezing out of gas-fired power generation by renewables reduces wholesale power prices which in turn has a negative impact on the profitability of conventional power plants. This effect is called the merit order effect of renewables. There are several studies that have quantified the merit order effect of renewables. Our study also presents estimates for the merit order effect to give a quantitative overview of the financial situation of power producers but it differs from most other studies in that we do not use a complex fundamental model of the electricity market but a simpler econometric approach.

   However, our main goal is not a mere quantification of the merit order effect but rather its implication on the current contribution margins of the remaining power generators that do not benefit from governmental support. In market economies, declining prices usually lead to declining supply. But in the case of renewables, support schemes prevent standard market reactions. In the end, potential investors might even call for public support to build conventional generation capacities to provide security of supply, especially in times of little wind and sun (backup capacities). If governments are willing to accept such claims, both types of capacities (renewable and conventional) would end up being subsidized. In our opinion, this is obviously a contradiction to the idea of liberal electricity markets. We present two alternative concepts that may solve the described dilemma. The first concept is the state control of renewable generation investments through auctions as proposed in the guidelines of the European Commission on renewable energy state aid (Brussels 2014/C 200/01). The second concept is a modified support scheme to representatives of the demand side in favor of renewables which accounts for overcapacities in the market for electricity generation.

   In the next section 2, we give a short overview of the market for electricity and the support scheme for renewables in Germany. In section 3, we estimate the merit order effect of renewables to facilitate the understanding of the current financial situation of conventional power producers. We present and discuss the first alternative market concept consisting of renewable capacity auctions in section 4. In sections 5 and 6, we review our second market concept consisting of premiums for renewable power generation to representatives of the demand side before concluding this manuscript in section 7.

2. BACKGROUND

   State aid in favor of renewable electricity generation has led to an unexpected investment momentum in many countries. In the case of Germany, the generation share of renewables increased from 5 percent to about one third within a time frame of only 15 years. In 1990/1991, feed-in fees for renewable electricity generation were introduced (Electricity Feed-In Act 1990) to stimulate innovation and technical progress. In 2000, the support scheme was extended in order to incentivize the market integration of renewable power generation against the resistance and market power of incumbent utilities. For the time being, the explicit aim of the German support scheme is a share of at least 35% renewable generation until 2020. The feed-in fees are set to correspond to the technology-specific full cost of renewable power generation (1) and are legally secured for a period of 20 consecutive years after commissioning. (2) Assuming ongoing technical progress, it was foreseen that feed-in fees decline with the year of installation. For many technologies, however, this decline had been reverted by amendments (approximately every third year).

   On the one hand, thanks to this generous support in Germany, installed capacities of wind, PV, and biogas combined already exceed the annual peak load which is about 80 Gigawatts. On the other hand, expenditures for the state aid are skyrocketing. In Germany and many other countries, the state aid is not financed via public budgets but by a levy on electricity consumption. The resulting market distortion is indicated in Table 1 which shows the total final user expenditures of electricity in Germany. In recent years, both support for renewable electricity and grid fees have passed the total expenditures for electricity generation including marketing and sales.

   Due to the merit order effect of renewables, wholesale electricity prices have fallen below marginal cost even of highly efficient CCGT. Thus, investments in conventional generation capacities deemed to be necessary in the long run have been cancelled. In addition to this, several modern units have been taken out of operation. However, gas-fired power plants are regarded as being ideal backup units due to their potential for a flexible operation.

   In fact, the withdrawal of investment projects is a typical market reaction to situations with obvious production overcapacities. Investors are waiting until they anticipate an increase in wholesale prices which allows them to achieve expected rates of return. However, this simple market mechanism does not apply for subsidized renewables in Germany. The renewable energy policy legally guarantees cost recovery (more or less) and thus, eliminates the economic incentive to adapt investment behavior to market conditions. Accordingly, the market for electricity becomes increasingly distorted.

   Following the lack of market signals to control the investments in renewable generation, operators of wind and PV plants have an unusually attractive business environment which obviously cannot be sustainable for the power system in the long run. Governments may eventually proceed to also guaranteeing cost recovery to fossil generators that are deemed necessary to secure electricity supply. However, we believe that more market-oriented alternatives are also suitable to provide supply security. We will present and discuss two of them in the last part of this paper. But first, to improve the understanding of the context of those solutions, we estimate the merit order effect of renewables for 2014.

3. MERIT ORDER EFFECT OF RENEWABLES

   In competitive day-ahead markets, hourly prices usually correspond to marginal cost of generation. As already explained, increasing generation from wind and PV leads to decreasing wholesale electricity prices, the so-called merit order effect of renewables. This section is dedicated to enable a better understanding of the current financial situation of conventional generators by estimating the merit order effect of renewables in 2014.

   Several studies have quantified this merit order effect in Germany in the past. An overview of ex-post results for the German day-ahead market is presented in Table 2. Most of them are based on fundamental models (structural models) where supply and demand functions are explicitly modeled, specified, and estimated starting from the economic theory of marginal cost pricing. To estimate the merit order effect of renewables, these models calculate the optimal least-cost power plant dispatch assuming there is no wind and PV feed-in and derive average day-ahead prices. These average prices are compared with average prices resulting from the optimal power plant dispatch if wind and PV feed-in are included.

   In contrast to fundamental (structural) models, econometric (reduced form) models are the result of solving the system for endogenous variables expressing them as a function of exogenous variables. Such an approach is used in vbw (2011) and Cludius et al. (2013). In these studies, an econometric approach (reduced form model) is used to quantify wholesale power prices. Again, the model compares two cases, with and without wind and PV. In our manuscript, such an econometric estimation is proposed for a three year period between 2012 and 2014 (1,096 days).

   In the literature, fundamental models are usually preferred over econometric models when making market forecasts because of the model's higher degree in detail. However, fundamental models require a much larger data basis (e.g. production capacities and efficiency rates of all generators, failure rates of generators, etc.) and thus, have a higher degree in complexity. In our case, however, the goal is to make a hypothetical backcast of the market instead of a forecast resulting in a lower level of uncertainty. We assume that for such a purpose, choosing a less complex econometric model instead of a more complex fundamental model is appropriate. Our model takes hourly day-ahead prices [p.sub.h,t] (in Euros/MWh) as dependent variables. These data are defined as pooled cross-sectional time series whereby the cross sections represent the 24 hours {h, h = 0,...,23} of a day and the time series represent the 1,096 days. (3) The implicit assumption is that the power price of say the 9th hour of the day is dependent on the 9th hour of the previous day (reflected by an autoregressive term) but not on the 8th hour of the same day. This assumption is not quite correct as shown by the correlation matrix of the residuals (see appendix Table A.2). The alternative specification would be a regular time series model with 24 x 1,096 = 26,304 hourly data points. However, thanks to the robustness of the underlying relationship...