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Renewable project finance: Can corporate PPAs replace renewable energy subsidies?


  • Many companies procure renewable energy to reduce their carbon footprint and hedge energy costs
  • As corporate Power Purchase Agreements (PPAs) for renewable energy projects become more common we ask:
    • To what extent can corporate PPAs replace renewable energy subsidy schemes?
    • Will debt-to-equity ratios stay at current levels in the face of countervailing trends?
  • We conclude that the amount of senior project finance debt which renewable energy projects (for onshore wind and solar PV projects in 2020, 2030 and 2040) can raise on the back of a corporate PPA will be substantially lower for the short-term
  • In the medium-to-long term (2025-2040) it will slowly increase due to decreasing capital and operational expenditure
  • This implies a huge demand for project equity during the transition period which may partly be met by mezzanine financing
  • It is debatable whether corporate PPAs alone can sustain the past subsidy-based growth in renewable energy. If countries are to achieve their renewable energy targets, additional governmental support may still be required

Co-authors: Ruurd Immel, Marjella de Vries and Floris van Schade Westrum 


In this Special we ask whether corporate PPAs can replace the fading subsidy schemes. The research is relevant in light of the broader question of financing and bankability of the energy transition. We investigate how the phasing-out of subsidies affects the debt-to-equity ratio of a renewable energy project and examine the main drivers affecting the debt-to-equity ratio of renewable energy projects.

For this study, we conducted interviews for a qualitative assessment of the trends and drivers related to corporate PPAs. We also developed a financial model for a quantitative assessment of how the debt-to-equity ratio will develop in the period 2020-2040 in a subsidy-free world and in the presence of corporate PPAs.

What are corporate PPAs?

To tackle climate change, companies and corporations are looking to reduce their carbon footprint. Energy procurement from renewable energy sources is both a way to lighten their footprint and to bring down or hedge against increasing energy costs.

Companies can adopt different strategies to purchase renewable electricity which are generally distinguished as (i) on-site/near-site generation and (ii) off-site generation. In both cases the company can invest directly in a renewable energy asset or purchase renewable electricity via a corporate Power Purchase Agreement (corporate PPA – see Box 1) from a third party who owns the renewable energy asset. This paper focuses on off-site generation, where the company purchases its electricity from an off-site renewable energy project via a corporate PPA.

Box 1: What is a corporate PPA?

According to the WBCSD, “A PPA is a contract between the buyer (off-taker) and the power producer (developer, Independent Power Producer, investor) to purchase electricity at a pre-agreed price for a pre-agreed period of time. The contract contains the commercial terms of the electricity sale: contract length, point of delivery, delivery date/times, volume, price and product. The electricity sold under a PPA can be from existing renewable energy supply or a newly built project.” There are two common Corporate PPA structures:

Sleeved or physical structure
If the renewable energy asset is on the same grid network as the company, the corporate buyer can enter into the Corporate PPA with the generator and appoint a utility to deliver electricity on its behalf. The buyer needs to enter into a back-to-back PPA to sell the electricity to the utility. The generator then transfers the electricity to the utility, which sleeves it through the grid to the buyer. The utility often receives a sleeving fee. Sleeved Corporate PPAs are prevalent in Europe.

Synthetic, virtual or financial structure
Virtual PPAs are more flexible – the generator and off-taker do not have to be connected to the same network. The corporate buyer agrees a fixed PPA price and, potentially, a price for renewable certificates with the generator. Renewable energy is delivered to the grid and the generator receives a variable spot price for it. The generator and the buyer settle the difference between the variable market price and the fixed PPA price. The corporate buyer receives continues to buy its power from the local utility at the market price which is hedged by the synthetic PPA. Synthetic corporate PPAs are found in the USA and the UK.

Market for corporate PPAs

According to the BloombergNEF 2019 Corporate Energy Market Outlook, in 2018 clean energy corporate PPAs were signed by 121 corporations in 21 different countries for a total of around 13.4 GW. This is more than double the 2017 amount (6.1 GW). More than 60% of PPAs were signed in the USA (8.5 GW), e.g. by Facebook, AT&T and ExxonMobil. In Europe, the Middle East and Asia, corporate PPAs amounting to 2.3 GW were concluded, mostly in the Nordics, e.g. by the aluminum producers Norsk Hydro and Alcoa Corp, but also by Facebook, Amazon and Google. Deals were also signed in Poland (for the first time), Denmark and Finland (second time) and several deals were signed in the UK.

Role of Rabobank

Since 2016, Rabobank Project Finance has participated in nine projects backed by corporate PPAs (1.9 GW) in Europe, mostly in the Nordics and in Spain. Another eight PPA-enabled projects (1.9 GW) are in the pipeline and are expected to close in the coming months.

Figure 1: Rabobank’s corporate PPA Experience in Europe
Figure 1: Rabobank’s corporate PPA Experience in EuropeSource: Rabobank

Subsidies versus corporate PPAs from a lender’s perspective

Subsidy regimes in the renewable energy sector

The renewable energy sector in Europe has been characterized by various subsidy regimes in the last two to three decades: Germany and the UK introduced feed-in-tariffs in 1991 and 2010 respectively, the Netherlands in 2003.

The purpose of feed-in-tariffs is to accelerate investment in renewable energy technologies by guaranteeing a fixed price for the electricity produced for a substantial period of time, generally 15 to 20 years. The resulting stable and predictable cash flows have substantially improved the bankability of renewable energy projects. The feed-in-tariffs implied that both equity and debt providers were exposed only to performance risk and not to electricity market-price risk—or only to a very limited extent (see Figure 2).

Figure 2: Subsidy regimes and their effect on project finance for renewable energy projects
Figure 2: Subsidy regimes and their effect on project finance for renewable energy projectsSource: Rabobank

PPAs with corporates and utilities

This rather comfortable situation is gradually starting to change in Europe. A transition from feed-in-tariffs to regimes based on tenders is in full swing. The UK announced that the feed-in-tariff scheme would close to new applicants from April 2019.[1] In Germany, the recent revision of the Renewable Energy Law aimed at a general system change, away from feed-in-tariffs to a competitive bidding process, which was already introduced for large-scale solar photovoltaic projects in 2014.[2] In the Netherlands, a tendering scheme is available under the support scheme (SDE+) for offshore wind.[3]

The move away from subsidies will affect the level and stability of future cash flows of renewable energy projects since the market-price risk will increase for both equity and debt providers. Yet, as Figure 3 shows, PPAs are not perfect substitutes for subsidy regimes: they will affect the availability and/or the amount of long-term project finance debt that lenders are willing to provide to renewable energy projects.

Figure 3: PPAs with corporates and utilities and their effect on the amount of senior project finance debt for renewable energy projects
Figure 3: PPAs with corporates and utilities and their effect on the amount of senior project finance debt for renewable energy projectsSource: Rabobank

What makes a corporate PPA bankable?

Whether and to what extent a renewable energy project can raise senior project finance debt on the back of a corporate PPA will depend on the corporate PPA’s terms and conditions and on the counterparty risk in relation to the PPA off-taker. Project finance lenders will not accept a corporate PPA off-taker which is not sufficiently financially sound unless substantial third party security is in place (e.g. bank guarantees or parent company guarantees from a highly rated entity). Assuming the other corporate PPA’s terms and conditions are acceptable to the project finance lenders, the total amount of long-term project finance that debt lenders are willing to provide will be largely dependent on three factors: the (fixed) price level, the volume contracted and the term as applicable to the corporate PPA.

The effect of these three factors is to decrease the amount of long-term debt project finance that lenders are willing to provide: whereas debt-to-equity ratios were generally around 80:20 under the feed-in tariff regimes, such high levels are no longer attainable.

In the next section, we discuss the trends and drivers determining the long-term debt quantum for renewable energy projects on the back of a corporate PPA in more detail. We then discuss the quantitative model we built to predict the development of the debt-to-equity ratio for such projects in the mid-term future.

Trends and drivers affecting the debt-to-equity ratio

There are three factors which negatively affect the debt-to-equity ratio: (i) lower corporate PPA prices as compared to subsidy regimes, (ii) contracting less than 100% of the electricity produced, and (iii) shorter PPA tenors as compared to subsidy regimes. We now zoom in on these factors and highlight two others which positively affect the debt-to-equity ratio: (i) the decrease of capital and operational expenditure of renewable energy projects and (ii) project finance lenders gradually becoming more comfortable with market-price risk.

Corporate PPA prices are lower than past feed-in-tariffs and subsidies

The feed-in-tariffs were generally set above the electricity market prices with the goal of boosting renewable energy generation. Corporate PPA prices are largely impacted by the expected levelized costs of energy (LCOE)[4], the corporate off-taker’s intended energy cost savings, and the expected electricity market-price development[5]. Corporate PPA prices are generally set below the expected future spot market prices as the off-taker requires a discount for locking-in a fixed price for several years.

Corporate PPA prices vary substantially between regions in Europe due to varying electricity market prices. Whereas in Spain corporate PPA prices generally fluctuate between 35 and 40 euros per MWh[6], corporate PPA prices in the Nordics are substantially lower, i.e. 25 to 30 euros per MWh, due to lower electricity market prices in that region.[7] The reasons for the lower electricity market prices in the Nordics include a large share of (firm[8]) renewable generation capacity, especially hydro energy, and a very liquid electricity market. The electricity market in Spain, in contrast, is less liquid and Spain is more dependent on expensive LNG imports for its gas power plants.

Contracting less than 100% of the electricity produced under a corporate PPA

There are several reasons why, in most cases, not all the electricity produced is contracted under a corporate PPA. Firstly, the corporate off-taker may require less electricity than the renewable energy project is able to produce. Secondly, it may be beneficial for the project not to sell all the electricity produced, in particular for baseload structures (where the renewable energy generator is obliged to deliver a certain amount of electricity on an hourly, monthly or annual basis). Thirdly, shareholders may prefer the project to be partly exposed to market prices during the corporate PPA tenor, as they will receive the upside in case of higher spot market prices.

Trend toward shorter corporate PPA tenors

So far, the majority of the European corporate PPAs mature after 12 to 15 years. Tenors far beyond 15 years seem possible only in the Nordics, where electricity market prices are stable as a result of abundant and established hydro energy capacity. A clear example is Norsk Hydro which concluded several long-term corporate PPAs with tenors of 20 years and beyond.

However, the current trend is toward shorter corporate PPA tenors, i.e. 10 to 12 years. Demand for corporate PPAs is now mainly driven by the heavy industry and ICT sectors. Heavy industry, e.g. aluminium producers, traditionally hedges the price of part of its electricity consumption for long periods, i.e. 10 -15 years.[9] The time horizon of the ICT sector is often shorter, i.e. around 10 years. As soon as the heavy industry corporates have hedged most of their electricity consumption by long-term PPAs (which is currently the case in the Nordics) the average PPA tenor will automatically decrease since the only corporate off-takers in the market are those with shorter time horizons. Furthermore, when smaller and/or lower-rated corporates enter the corporate PPA markets, PPA tenors will shorten as equity and debt providers are unwilling to run counterparty risk on such corporate off-takers for a very long period of time.

Change in lenders’ appetite for market-price risk

In the coming years we expect project finance lenders to become more comfortable with corporate PPAs and market-price risk. We believe that most lenders will be prepared to take on some market-price risk during the tenor of the corporate PPA and even to be fully exposed to market risk after the initial corporate PPA expires. The underlying assumption for lenders being comfortable with full exposure to market-price risk after expiry of the corporate PPA is that the project will be able to conclude a new corporate PPA after expiry of the initial corporate PPA. Should the project be unable to secure such a new corporate PPA in time, mitigating measures embedded in the financing structure would come into play, such as cash sweep mechanisms.

Developments in capital and operational expenditure

As capital and operating expenditures on renewable energy projects decrease, this will have a countervailing effect on the debt-to-equity ratio: a renewable energy project that generates the same amount of electricity but can be constructed and maintained at lower costs will have a higher debt-to-equity ratio.

In the past decade the cost of solar and wind technologies decreased steadily (IRENA, 2018b). According to IRENA, the global weighted average of LCOE of utility-scale solar PV has fallen 73% since 2010. Onshore wind is seen as the most competitive source of new generation capacity. Although the levels of costs and expected cost decreases vary between regions (IRENA, 2018b; EIA, 2019), the trend is clear: both capital expenditure and operational expenditure of all renewable energy technologies are expected to fall substantially in the future.

According to BloombergNEF, capital expenditure for onshore wind projects in Germany will fall by ca. 20% until 2050, while fixed and variable operational expenditure is expected to decrease by 25%. These cost reductions translate into reductions of LCOE: according to Bloomberg, LCOE of onshore wind will be almost 40% lower in 2050 than in 2020. The trend is similar for solar PV: despite the regional variations, especially due to different intensities of solar irradiance, capital and operational expenditure developments will result in declining LCOEs (Fraunhofer, 2018).

Given these trends and drivers, the question is: how will the debt-to-equity ratio be affected in the future? Is the availability of a corporate PPA a perfect substitute for subsidies when it comes to determining the amount of senior project finance debt? The following section provides a quantitative answer.

Equity versus debt – a quantitative model

For the purpose of this research, we built a financial model to determine the expected debt-to-equity ratio for onshore wind and solar PV projects in 2020, 2030 and 2040. We have limited our research to Germany and the UK as these countries are the largest renewable energy markets in Europe. For other geographies and other technologies, e.g. offshore wind, a similar exercise could be conducted which might lead to other results. The main differences in outcomes are expected to be the result of differences in average capacity factors[10], capital expenditure and operational expenditure and/or the corporate tax rates applied[11].

The most important assumptions underlying the financial model are illustrated in Tables 1, 2 and 3 in the Appendix. The assumed capacity factors, capital expenditure and operational expenditure amounts have been derived from the Bloomberg 1H 2019 LCOE Data Viewer Index. Furthermore, we have assumed that the current corporate-tax-rate levels for Germany and the UK remain applicable.

Figure 4 shows the debt-to-equity ratios for onshore wind and solar PV projects in 2020, 2030 and 2040 in Germany and the UK for expected electricity spot market prices.[12] All graphs show an upward trend for the debt-to-equity ratio. This is due to the downward trend in capital and operational expenditure: when electricity spot market prices and all other assumptions stay constant, lower capital and operational expenses result in higher debt-to-equity ratios.

Expected debt-to-equity ratios for onshore wind and solar PV for several electricity spot market prices (20, 30, 40 and 50 €/MWh) and expected capital and operational expenditure for 2020, 2030 and 2040 in Germany and the UK.

Figure 4a: Germany - Onshore Wind
Figure 4a: Germany - Onshore WindSource: Rabobank
Figure 4b: UK - Onshore Wind
Figure 4b: UK - Onshore WindSource: Rabobank
Figure 4c: Germany - Solar PV
Figure 4c: Germany - Solar PVSource: Rabobank
Figure 4d: UK - Solar PV
Figure 4d: UK - Solar PVSource: Rabobank

There are several take-aways from this exercise:

  • Both for onshore wind and for solar PV, the availability of senior project financing is restricted in the short run (2020). We expect that, for most projects, too much equity will be required to make non-recourse financing viable in the presence of a 10-year corporate PPA. Corporate PPAs are therefore not one-on-one substitutes for feed-in tariffs in the short-term.
  • An exception could be Germany, but only in high and very high electricity price scenarios: then the average renewable energy project would be able to raise enough senior project finance debt to make these projects sufficiently attractive to equity investors.  
  • This will slowly change over time. Based on assumed reasonable electricity market prices, the debt-to-equity ratios will increase to around 50:50 and 70:30 in ten years from now. In Germany these levels may be attained somewhat faster.
  • Subject to electricity price developments in the coming decades, the currently observed debt-to-equity ratios of around 80:20 will not be reached until 2040.

Assuming that subsidies will gradually disappear and will be replaced by corporate PPAs across Europe, there will be a huge demand for project equity from renewable energy projects in the next two decades. The question is whether sufficient project equity will be available to meet this demand, especially since equity investors will also be more exposed to market-price risk: in contrast to the situation under a feed-in tariff regime, their rate of return will be largely dependent on future electricity price developments. As a result of the huge demand for project equity and as equity investors will try to limit their exposure to market-price risk, a market for mezzanine project financing might develop during the transition period, i.e. 2020 – 2035 to 2040.

Conclusions and discussion

In the short-term corporate PPA will not be a perfect substitute for renewable energy subsidies in most western European countries. This is one of the main conclusions from our analysis of how the debt-to-equity ratio of a renewable energy project will change as a consequence of fading subsidy regimes. Investors will need to deal with the fact that lenders will provide less senior project finance debt on the back of a corporate PPA. However, in the medium- to long-run, other drivers, such as technological developments, will make it possible for the debt-to-equity ratio to rise again. The pace at which this will happen will depend on the renewable energy technology in question, the geographical area and the future electricity price.

It is clear that a large amount of equity will be needed in the transition phase from 2020-2035. This demand for equity might open up the possibility for mezzanine financing to fill the gap. In the long-run, however, we expect the debt-to-equity ratio to rise again and the need for project equity to return to its current level of about 20%.

This analysis suggests that a word of caution is needed for policymakers in their decision making on subsidy regimes in the future: it is debatable whether the impulse for renewable energy development that previously came from generous subsidy regimes can be sustained in the absence of substantial electricity price increases. With the exception of large and efficient wind or solar parks, renewable energy projects might need to be incentivized in the short- to medium-term.


[1] Other subsidy mechanisms, such as the Contracts for Difference (CfD) and tax regulation mechanisms, will still be available. For a discussion on these amendments on the corporate PPA market see Bloomberg (2018a, 2018b, 2019).

[2] BloombergNEF (2019) discusses how the policy amendments in Germany affect the corporate PPA market.

[3] The ‘Stimuleringsregeling duurzame energieproductie’ (SDE, later SDE+) is a Dutch scheme to incentivize sustainable energy production.

[4] The levelized cost of energy, or LCOE, measures how much money must be made per unit of electricity (kWh, MWh etc. or even other type of energy like home heating) to recoup the lifetime costs of the system. This includes the initial capital investment, maintenance costs, the cost of fuel for the system (if any), any operational costs and the discount rate applied (e.g. for lenders or investors).

[5] Our expert interviewees identified these three variables as the main drivers for CPA prices.

[6] This information was retrieved from our expert interviews.

[7] This information was retrieved from our expert interviews.

[8] Firm energy sources are energy sources which can reliably generate energy whenever needed.

[9] This information was retrieved from our expert interviews.

[10] The net capacity factor is the ratio of an actual electrical energy output over a given period of time to the maximum possible electrical energy output over that period. Capacity factors can vary from region to region in Europe. Since the average capacity factor in the Nordics would be higher, a higher gearing could be achieved in the Nordics than in our example.

[11] Similarly, CAPEX costs in Sweden, for instance, are lower than the CAPEX costs assumed in our model, due to windfarms which, on average, are larger in size and can therefore be built more efficiently.

[12] We have assumed the corporate PPA price to be 10% below the electricity spot market prices.


AleaSoft Energy Forecasting (2019): “2018 ended as the second most expensive year of the Spanish electricity market history”. 

BloombergNEF (2019): “Corporate Energy Market Outlook – Double up”, January 2019.

BloombergNEF (2018a): “1H 2018 Corporate Energy Market Outlook – The Art of the Deal goes Global”, January 2018.

BloombergNEF (2018b): “2H 2018 Corporate Energy Market Outlook – One for the books”, August, 2018.

Fraunhofer (2018): “Levelized costs of electricity renewable energy technologies”, Fraunhofer Institute for Solar Energy Systems ISE, March 2018. 

IEA (2019): “Cost and performance characteristics of new generating technologies”, in Annual Energy Outlook 2019, January 2019.

IEA (2017): World Energy Outlook 2017.

InnoEnergy (2017): “Future renewable energy costs: offshore wind”, available at https://bvgassociates.com/wp-content/uploads/2017/11/InnoEnergy-Offshore-Wind-anticipated-innovations-impact-2017_A4.pdf

IRENA (2017): “Electricity storage and renewables: Costs and markets to 2030”, October 2017, available at: https://www.irena.org/publications/2017/Oct/Electricity-storage-and-renewables-costs-and-markets

IRENA (2018a): “Hydrogen from renewable power – Technology Outlook for the Energy Transition, September 2018.

IRENA (2018b): “Renewable power generation costs in 2017”, International Renewable Energy Agency, Abu Dhabi.

Sandbag & Agora (2018): “The European Power Sector in 2017 – State of affairs and review of current developments”.

Starn, J. (2018, 6 August): Power Worth less than zero spreads as green energy floods the grid – wind and solar farms are glutting networks more frequently, prompting a market signal for coal plants to shut off”, Bloomberg climate changed.


Interviewees – expert interviews

Expert interviews were held with the following persons:

  • Dirk Kaiser (Neas Energy A/S)
  • Rodrigo Berasategui and David Diez (Watson, Farley & Williams)
  • Kasper Walet (Maycroft)

Assumptions underlying the quantitative model

The assumptions underlying the financial model correspond to the mid scenario from the Bloomberg 1H2019 LCOE Data Viewer. Bloomberg data is reflective of projects that were financed in the six months before the publication of the data or which were then under construction. Projects which have been cleared in auctions more recently, but have not been financed, are not captured in the data.

For this research we have assumed a corporate PPA with a tenor of 10 years and senior project finance debt being sized on a 14 years tenor, i.e. 4 years beyond the corporate PPA tenor. Furthermore, a debt service coverage ratio (DSCR) of 1.50x for uncontracted revenues, i.e. revenues generated by selling electricity on the spot market, and a debt service cover ratio of 1.20x for revenues from electricity sold under the corporate PPA have been assumed. We have also assumed that 70% of the electricity is sold under the corporate PPA, and therefore that 30% will be sold on the electricity spot market. Please note that after expiry of the corporate PPA (10 years) all electricity produced will be sold on the spot market.

Table 1: General Assumptions - onshore wind and solar
Table 1: General Assumptions - onshore wind and solarSource: Rabobank and Bloomberg 1H2019 LCOE Data Viewer.
Table 2: Assumptions – Onshore wind
Table 2: Assumptions – Onshore windSource: 1H Bloomberg 2019 LCOE Data Viewer
Scenario: Mid case; Currency rate: USD 1 = Eur 0.90
Table 3: Assumptions – Solar
Table 3: Assumptions – SolarSource: 1H Bloomberg 2019 LCOE Data Viewer
Scenario: Mid case; Currency rate: USD 1 = Eur 0.90
Karolina Ryszka
RaboResearch Netherlands, Economics and Sustainability Rabobank KEO

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