Financing Power: Impacts of Energy Policies in Changing Regulatory Environments.

• Author: May, Nils

1. INTRODUCTION

   The rising share of capital-intensive assets increases the importance of financing costs for the total costs in power systems. In particular, this applies to renewable energies, as opposed to coal and gas power plants, because the costs of renewable energy deployment are, to a large extent, driven by the capital costs used to finance these assets. Bloomberg New Energy Finance (2017) project investments of $7.3 trillion into wind and solar power between 2017 and 2040, as well as an estimated further $5.3 trillion in order to achieve the goal of keeping the global temperature increase below two degrees.

   The financing costs depend on the risks faced by investors, which hinge on the regulatory framework. On the one hand, regulation impacts the mere risk allocation; for example, regarding project performance, which is usually best left with investors to avoid adverse incentives. On the other hand, the regulatory framework can also induce risks, for instance, linked to uncertain policy developments, or it can eliminate risks, e.g. by facilitating contracts between parties with complementary exposure. The regulatory regime can have two main impacts on financing risks: regulatory risks and market risks.

   First, regulatory risks arise due to uncertainty about the future revenues provided by support policies like feed-in tariffs, sliding premia, and green certificate schemes. The policy design may shift regulatory risk between parties, but where policy risk can be avoided altogether, policies can reduce, rather than shift, overall deployment costs. The deployment costs define how far investments into renewable energies are made and, for example, how high carbon prices need to be in order to facilitate the transition to renewable energies (Hirth and Steckel, 2016).

   Second, market risks are introduced where support mechanisms do not comprise explicit off-take guarantees, i.e. guarantees that all generated electricity will be remunerated at a pre-determined price. Then, investors typically sign bilateral long-term contracts to secure these revenue streams. As Newbery (2016) argues, some forms of long-term contracts between generators and retailers are required to hedge against market risks and to provide investors with sufficient certainty about their future cash flows. Discussing investments into peak generators, Joskow (2006) analyzes how the lack of long-term contracts does not necessarily deter investments, but increases financing costs. Both producers and consumers are risk averse, preferring a stable price over an uncertain price. However, under liberalized power markets, individual and industrial customers do not sign contracts for durations exceeding a few years. This may reflect constraints on switching time-frames (or compensation payments), counterparty risks that are difficult to hedge, and asymmetric information about what would be a competitive price.

   We quantify how much the regulatory and market risks under different renewable energy policies affect the overall deployment costs. To this end, we first analyze how far regulatory risks under feed-in tariffs, sliding premia, and tradable green certificates translate into higher financing costs for renewable energy investors. We test this with a unique dataset on wind power financing cost estimates for which investors, bankers, academics, and utilities provide estimates of the weighted average costs of capital in the EU. Second, we analyze the effects of market risks on long-term contracts when policies do not provide explicit or implicit off-take guarantees. We find structural reasons why the price renewable investors receive for long-term contracts is below the expected value, reflecting increased financing costs incurred by their counterparties when engaging in such contracts.

   Overall, our results indicate that policy instruments can change the level of financing costs by about 4.8 percentage points overall, when comparing fixed feed-in tariffs with green certificate schemes, which is equivalent to a change in the costs of renewable energy deployment of about 29 percent. The change in costs is a result of, on the one hand, reducing regulatory risk and, on the other hand, eliminating market-related risks by facilitating implicit hedging between producers and consumers.

   The remainder of this paper is structured as follows: After an overview over policies supporting renewable energy in section 2, we estimate policy impacts on investors' financing costs in section 3. We complement this with an analysis of the effects of long-term contracts on off-takers, i.e. the firms that commit to buy the electricity from project developers through long-term contracts. Section 4 analyzes how incomplete long-term contracts incur additional costs for off-takers. The paper ends with a conclusion.

2. INVESTMENTS INTO RENEWABLE ENERGY

   Globally, three main policies that support renewable energy investments dominate: Fixed feed-in tariffs (FIT), sliding premia, and tradable green certificates (TGC). (1) In 2015, feed-in tariffs or sliding premia existed in 82 countries, whereas tradable green certificates were in place in 34 countries and many US states (REN21, 2017). (2) Egli et al. (2018) demonstrate that it is support policies that enabled renewable energy investments at low financing costs.

   Price-based support policies, e.g. feed-in tariffs and sliding premia, provide investors with a certain remuneration level. Under feed-in tariffs, the regulator takes the electricity output and guarantees a remuneration level such that operators face no uncertainty with respect to remuneration per kWh. Under sliding premia, investors sell their output to private off-takers and receive an additional sliding premium, where the sum of the two elements, on average, across all installations, equals the feed-in tariff remuneration. For any individual plant, there is some uncertainty with respect to the total remuneration due to deviations from average production patterns (May, 2017), while additional balancing costs or changes of price zones can induce risks (Tisdale et al., 2014), leading e.g. Couture and Gagnon (2010) to argue, based on theoretical arguments, that sliding premia entail risk premia as compared to feed-in tariffs. Yet, so far Klobasa et al. (2013) find no significant changes in investment conditions when analyzing descriptive statistics of the German experience after project developers were given the choice between continuing to receive a feed-in tariff or getting a sliding premium as of 2012. Kitzing (2014) goes as far as classifying feed-in tariffs and sliding premia as one, merely distinguishing higher risk fixed premia.

   Tradable green certificates constitute quantity-based instruments where investors sell their electricity output to private counterparties and further receive green certificates proportional to their output. Retail companies are obliged to obtain such certificates, creating demand for them; thus establishing a revenue stream for renewable energy operators in addition to the sale of electricity.

   Many authors raise concerns that, under real world conditions, green certificates induce additional investment risks. Butler and Neuhoff (2008) analyze the British green certificate scheme and the German feed-in tariff, finding that when correcting for the countries' different wind resources, the German system is more successful, in the sense that it triggered considerably more investments at lower cost to consumers. Similarly, Haas et al. (2011) scrutinize descriptive statistics on installation numbers and general remuneration costs for a small number of European countries, finding that feed-in tariffs are more successful in both respects. Further, Biirer and Wtistenhagen (2009) conduct a survey among investors and show, using a stated preferences approach, that they prefer feed-in tariffs over green certificates. A survey of British investors suggests that the expected risk premium of the green certificates compared to the newly-introduced sliding premium amounts to 0.8-1.7 percentage points (NERA, 2013). Similarly, Kitzing et al. (2017) show, using a real options approach, that policies have varying effects on capital costs, with green certificates leading to higher capital costs. Further, Kitzing and Weber (2015) and Klessmann et al. (2013) indicate that feed-in tariffs require lower support levels than policies that expose investors to more revenue risks. Nicolini and Tavoni (2017) evaluate data from five large EU countries and derive that feed-in tariffs lead to more deployment than green certificate schemes.

   Polzin et al. (2019), in their review of the literature exploring renewable energy support policies, find that more effective policies are associated with lower volatility of returns and higher returns. Similarly, De Jager et al. (2008) identify that credible commitment of policy-makers towards sustained renewable energy deployment lowers costs, which May and Chiappinelli (2018) show is more difficult under green certificate schemes than under feed-in tariffs, while sliding premia fall in between.

   Yet, some authors also argue in favor of the efficiency of quantity instruments. Applying a real options investment model, Boomsma and Linnerud (2015) argue that investment incentives do not differ strongly between green certificates and feed-in tariffs, meaning that additional risk premia under green certificates are small. Many authors ignore the effects of additional revenue risks. For example, Petitet et al. (2016) analyze investments based on high carbon prices, but ignore the effects of uncertainty about future carbon prices. Similarly, Farrell et al. (2017) treat costs as exogenously given and, thus, equal across policies, not accounting for additional financing costs when revenue risks are larger.

   However, studies on the impact of these policies on financing cost are based on theoretical assessments or on case studies for only very...