EEG Posts

Germany: 24 Bids Accepted in First Solar Auction of 2019

Germany: 24 Bids Accepted in First Solar Auction of 2019

Germany held its first solar auction of the year and as a result, 24 bids for large-scale projects of over 750 kW were accepted, amounting to a new capacity of 178 MW. The average rate was 4,80 cents per kWh.

Photovoltaic Plants are establishing themselves more and more as a Liquid Asset Class

Photovoltaic Plants are establishing themselves more and more as a Liquid Asset Class

The photovoltaic market is currently facing a paradigm change. While the former tumultuous expansion of solar projects has come to a halt, the secondary market for photovoltaic systems is largely flourishing. The market for trading existing PV-plants is becoming more and more liquid due to an increased market understanding of PV-plant operators and investors. This trend will proceed in 2016.

Guest Article: Focusing on the German so-called “Market Bonus” Scheme

In the previous article, the limelight shone on the direct marketing options as a way of adding value to your German renewable energy assets. Of the three revenue-generating options discussed, besides the classical EEG Feed-in-Tariff, the predominant choice to date has been the “Market Bonus Scheme”.

Some Statistics on Direct Marketing vs. Classical FiT

Up until April 30, 2013, PV assets accounted for a total installed capacity of 33,533 MWp. Of these, 27,413 MWp benefit from the Renewable Energy Law (§ 20a Abs. 2 Nr. 2a EEG), having been grid connected between January 1, 2009 and April 30, 2013. Prior to 2009, only 6,120 MWp worth of PV capacity had been built. At the start of June 2013, 3,527 MWp, or roughly 10% of the installed PV capacity, had opted for the “Market Bonus Scheme”.

When interpreting the low percentage (in comparison with wind parks) of PV assets having opted for direct marketing one has to bear in mind that, from the total installed power in Germany, many PV plants are under 100 KW for which direct marketing is not technically feasible. The threshold from an economic perspective (feasibility) lies around 300-500 KW – systems. In the wind industry, the installed capacity tends to be on average far larger (the current smallest “large” wind turbines tend to be 1 MW, while the standard for onshore is approx. 3 MW). If you check the table below, taken from p. 58 in a recent study published by the “German Association of Energy and Water Industries” (BDEW), you will note that as of Dec. 2012, 80.6% and 100% of the onshore and offshore wind parks respectively, had already switched to Direct Marketing. This percentage has increased in the meantime; as of June 2013, 25,138 MW (onshore) and 378 MW (offshore) are operating in direct marketing versus 23,929 MW and 248 MW in Dec. 2012.

This table shows the EEG Assets under Direct Marketing in 2012.

This table shows the EEG Assets under Direct Marketing in 2012.

Who Pays What?

Figure 1 compares the two „tariff“ systems. The classical FiT is equivalent to the sum of the “average spot market price” and “variable market bonus”. The Average Spot Market Price (as a function of the average monthly reference market price) is paid by the energy trader/utility in charge of managing the sale of energy produced by your asset. For comparison purposes, in the classical FiT, the grid operator pays you.

Subtracting the Average Spot Market Price from your originally allocated FiT, the resulting residual value is the Floating Market Bonus. This portion continues to be borne by the grid operator (e.g. E.On, RWE, Vattenfall or EnBW).

Figure 1 shows a comparison between the classical EEG scheme and Market Bonus Scheme.

Figure 1 shows a comparison between the classical EEG scheme and Market Bonus Scheme.

What is “new” are the bonuses paid on top of the FiT level, e.g. the sections marked in green shades in Figure 1, comprising the “Management Bonus” and “Remote Control Bonus”, both paid by the same business partner (energy trader/utility) handling the spot market sales. The EEG legislation differentiates between a Management Bonus “with” and “without” remote control facilities. To enjoy the mark-up available through remote controlling, the assets must be equipped with the electronic devices allowing your energy trader to disconnect the asset from the grid in cases of extreme negative prices. Although the dimensions of the green rectangles look relatively large compared to the FiT, this is done only for illustration purposes. In reality, the added margin accounts for approximately 2% of the original FiT.

What Occurs in Case of Insolvency?

Suppose your asset is already operating under the Market Bonus Scheme and your energy trader is filing for insolvency. This is undoubtedly an extreme hypothetical case, as to date no German grid operator has ventured into such dire straits. Nevertheless, legally a renewable energy asset is entitled to the EEG FiT. The local grid operator exercises this entitlement and receives the corresponding FiT compensation for the renewable energy (assuming the asset operates under the umbrella of the EEG), fed into the transmission grid, which in turn is transferred to the asset owner.

If a local grid operator files for insolvency, an alternative grid operator would take over its role, for example, by taking control of the local electricity grid. Another possibility could be that one of the transmission lines operators (e.g. 50Hertz, TenneT, Amprion, TransnetBW) temporarily or permanently assumes ownership of the local electricity grid operator, thus, receiving the FiT but acting as a mere payment intermediary by handing over the money to the renewable energy asset owner. A delay in these payments may occur depending on the complexity of the process. The switching time back into the classical EEG regime takes a total of three months, e.g. 1st month = invoice month, 2nd month = when delay of payment is registered, 3rd month= based on delay in 2nd month, the process initiated in month 2 reverts back to EEG/FiT. The EEG sanctions the maximum “switching time” as 3 months. Considering this time span and depending on the credit rating of the direct marketing utility, the financing banks may insist on a 3-month payment guarantee, to cover revenue shortfalls.

What are the Switching Costs?

a)      Direct Marketing Scheme:

This will depend on various factors. What are the internal reporting requirements of your company? Will you require extensive legal advice? Is your asset project financed? Who is the selected commercialization partner?

Some banks charge a one-time “study fee” per Direct Marketing contract (SPV), entailing the legal review of the contracts and the necessary internal paperwork, such that direct marketing contracts adjust to the bank’s legal department’s criteria. If your overall installed capacity is distributed amongst X SPVs, be prepared to pay the study fee X times.

Utilities, who benefit by handling your account, normally do not charge any fees – they benefit from the management fee shared with their customer.

b)      Remote Control:

Your commercialization partner may charge one-time set-up fees per SPV. Furthermore, the asset owner must also pay for the installation of the remote control sensors (e.g. either to the O&M supplier or the utilities’ trusted installers).

Enabling Remote Control

In general, renewable energy assets will require the installation of electronic elements permitting the remote monitoring and grid connection management. The components are supplied by different hardware manufacturers and installed either by the O&M contractor or the utilities’ trusted third party. To gauge whether it is viable to apply for the remote control bonus, the asset owner needs to analyze installation costs and the potential for additional revenues. Some utilities, prefer taking a step at a time by beginning the business relations with the market bonus scheme. For smaller green assets (

Once the viability of such an installation has been financially studied and approved by the asset owner, the direct marketer begins the application process with the grid operator. The direct marketing agreement is thus extended to include an addendum for the “remote control” system. Depending on your counterparty to the contract, the bonuses paid per kWh will vary, thus, it is sensible to compare offers.

Suppose the market price is extremely negative (e.g. Market Price < – (FiT+Management Bonus+Remote Control) ), every kWh sold generates a negative margin to the utility. Under the given circumstance, it is more profitable for the asset to be disconnected than to continue selling in the market. The asset owners, nevertheless, continue to perceive the FiT + management premium +remote control bonus, thus, nothing changes from an economic perspective. For the utility, however, there is an incentive to minimize losses if the market price dips below zero, by temporarily taking generating capacity offline.

Additional Remote Control Revenues

The added revenues available to a renewable energy asset depend on installed operating capacity and the rate offered by the energy trade. A 24 MW asset could generate until the end of 2014 (roughly 17 months), some EUR 50,000 in total. This should be more than sufficient to cover the one-time investment costs of the remote control devices, provided your park was not equipped with these from the outset. Operating costs that could arise are generally related to component replacement and/or software updates.

Switching Process

To transfer from the regular FiT regime to direct marketing, the customer must complete, with the help of the direct marketer, an application form,  whose technical and legal data is subsequently incorporated into a standard legal contract. In case the PV investment is project financed, the mentioned contract must receive the approval of the bank. Based on the experience of some utilities, banks tend to approve signature-ready contracts, i.e. all project-relevant data must already be incorporated. Prior experience of the direct marketing utility with financial entities tends to accelerate the process as they are well aware of the banks’ common requirements.

Once the owner has both signed the bank’s Consent Letter (presupposes debt financing of the asset), Assignment and the Direct Marketing Agreements, your asset is ready to initiate the switch to the market bonus scheme. The current utility provider is not involved in this legal process as it is already covered by a previous Assignment Agreement. For a timely switch, it is vital for the utility to obtain bank approval and the asset owner’s signature a few days prior to the month’s end, otherwise the process may be delayed by an additional month.

This is the third part of a series of guest articles written by Martin Supancic. You can find the other articles in his series here:
1. How to Tune Your German Green Energy Asset Without Getting Sun Burnt in the Attempt
2. The German Direct Marketing Framework and Potential Benefits for your Assets

Guest Article: The German Direct Marketing Framework and Potential Benefits for your Assets

In the introductory blog post, I highlighted “tuning” options for your German renewable energy assets considering the nuances of the legislative framework. Next, I will elaborate on the first alternative mentioned: obtaining a slightly higher price for each kWh generated by, and exclusively available to, your (on- and offshore) wind or solar park. This is the so-called “direct marketing”, also commonly referred to as the “Market Bonus Scheme”.


Martin Supancic discusses the opportunities for renewable energy asset owners under the EEG

The German Renewable Energies Act (EEG) of 2012 allows renewable energy assets to generate electricity from different sources and to sell to the market with a guaranteed offtake contract, ie. all produced electricity is sold at the contractually secured Feed-in-Tariff (FiT), regardless of the volatility in output or market circumstances (e.g. prices). Under the EEG, however, owners can select between commercializing their electricity via the FiT, the Market Bonus Scheme or Power Purchase Agreements.

The Market Bonus Scheme was established under the EEG as a way of integrating renewable energies into the electricity market. It was established in a way that would enable operators to improve control on the amount of electricity supplied to the market. Under the EEG Amendment from January 2012, three forms of direct marketing are defined (Art. 33b no. 1 – 3 of the EEG):

a)     Market Bonus Scheme

b)     Green Electricity Privilege (max. 2 MW parks)

c)     Other direct marketing (Power Purchase Agreements)

The cited amendment permits a monthly switching to any of the three direct marketing mechanisms, as well as reverting back to the classic FiT tariff.

Market Bonus Scheme

To better understand the pricing mechanisms, I will briefly explain how the German electricity market has worked to date. Since most, if not all (biomass may be an exception), renewable energy (incl. PV electricity) has a marginal cost of 0 EUR (sun/wind are free!). Renewable energy can also be sold, no matter the current pricing in the market, at times of peak production. At certain instances during the year, supply may outstrip demand causing negative prices. For example, conventional power plants (e.g. coal/gas-fired) sell at the marginal market price (as a function of marginal cost or what is commonly also referred to as the “dispatch curve”), normally quoted on the Leipzig Electricity Exchange (EEX). The burnt fuels cost money, thus, they determine the subsequent market price curve.

For the electricity market to operate efficiently, demand needs to equal supply. When demand shifts abruptly, energy generators need to quickly adjust production to meet the new consumption (price will depend on the “dispatch curve” of the added capacity). Ideally, future demand and supply can be predicted with high precision such that the most competitive prices are achieved to the benefit of all. The goal of direct marketing is dual:

– Reducing the additional costs on the German economy due to imprecise wind and photovoltaics electricity generation forecasts

– Improving demand-based electricity feed-in (esp. biomass)

Instead of the “produce and forget” strategy, which can lead to negative prices or higher EEG costs that are subsequently paid by the majority (there are exceptions!) of German electricity consumers, the direct marketer must make multiple estimates daily on the electricity production for the following day. This forecast is then sold daily on the spot market (day ahead). Any deviation of this prognosis from the actual electricity production results in electricity compensation costs, borne by the direct marketer, who thus is incentivized to make every effort to ensure a precise forecast or otherwise bear the compensation risk.

Under the ordinary EEG framework, the grid operators supply very inaccurate electricity generation estimates to the transmission lines operators, causing additional (compensation) costs. These are covered through the EEG levy account, consequently shared via the so-called “EEG-Umlage” (renewable energy levy) amongst the majority of German energy consumers, particularly households. When a grid connection point is registered for direct marketing, it is the direct marketer who assumes the risk. To illustrate the costs to the German economy, for 2013 the expected compensation costs due to imprecise PV electricity generation forecasts will cost German consumers an estimated 1.9 to 3.1 €/MWh. Currently, grid operators can already disconnect renewable energy assets. For them, grid stability is vital, particularly due to technical risks arising from an oversupply of electricity. The direct marketer does not manage the grid, thus, the reason for disconnecting a renewable energy asset are purely commercial, i.e. negative market price (utility PAYS consumer to CONSUME). In practice, this means that the negative market price must exceed the sum of the EEG FiT and the management bonus. By combining intraday trading with continuously updated forecasts and weather data, that are updated every few hours for all wind and solar assets, managed by the respective utilities,  the direct marketer can immediately respond to prediction changes, thus, minimizing the deviations and costs to both its profit & loss statement, as well as the German economy.

Just as in the case of wind and sun, biomass can also be a source of electricity production. In this sense, the second objective of the EEG amendment is to better integrate into the grid demand-induced biomass-based electricity generation, particularly to make-up for the shortfall between forecast and actual energy production. Currently, this role is primarily played by gas/coal fired power plants.

Green Electricity Privilege

This mechanism is primarily of interest to renewable energy assets with relatively low FiTs (e.g. wind). It is a form of direct marketing as a means of reducing the EEG levy paid by the asset owners. Electricity is sold directly to the final consumer, thus, the electricity generator is legally entitled to savings of 2 cents per kWh on the EEG levy (costs that are shared by all German households). This type of commercialization is subject to very strict rules in terms of contribution of green energy sources to overall electricity production mix of the utility (asset owner and/or distributor). This commercialization option is extremely restricted and will probably be phased out, thus, it is challenging to create a final consumer product considering the regulatory backdrop.

Other direct marketing

Power Purchase Agreements (PPAs) fall under this category. Due to the low FiT and given the current construction and operating costs of PV plants, some PPAs are in fact, reaching break-even but primarily due to tax breaks. Legislators are scrutinizing these fiscal incentives and may scrap them altogether, reducing the attractiveness of PPAs.

Benefits of Market Bonus Scheme

The incentive of switching to the Market Bonus Scheme is revenue-wise. For electricity produced under the EEG since 1.1. 2012, the additional revenues amounted to 12.00 €/MWh (legally established by the EEG), which was and is shared between the direct marketer (e.g. utility, wholesaler) and the asset owner. The revenue sharing depends on the utility’s commercial strategy and the associated costs – some are willing to offer 60% or more, others less, particularly if additional costs have to be assumed (e.g. payment guarantees). In 2012, some utilities and traders offered between 4 to 6 €/MWh of the 12 €/MWh mandated by law. This means in 2012, a park, annually generating 25,000,000 kWh could have achieved additional revenues of approximately (assuming 0.006 EUR/kWh) € 150,000.

For 2013, considering the different payment guarantee levels and associated costs, utilities have offered clients between 3.00 €/MWh and 4.00 €/MWh. The table below reflects the legally sanctioned management bonuses.

Management Fee in Cents/kWh




Without Remote Control




Including Remote Control




Depending on the results of the German parliamentary elections in September 2013, many industry experts predict an end to the market bonus model either in 2014 or 2015. Thus, time is of the essence if one wishes to benefit from this window of opportunity. If you have already switched to the market bonus scheme or are in the process of doing so, feel free to share your experience with a comment. What risks do you see?

This is the second part of a series of guest articles written by Martin Supancic. You can find his first article on managing a renewable energy asset under the German EEG here.


Guest Article: How to Tune Your German Green Energy Asset Without Getting Sun Burnt in the Attempt

How can the returns on green energy assets be amplified without refinancing? What can be done to eliminate those “love handles” on wind or solar parks? For some readers, what follows will probably be a review of the basics of managing a renewable energy asset in general, however, I will highlight a few focus areas  that can generate further value, considering nuances of the German renewable energy regime (Erneuerbare Energien Gesetz – EEG). Perhaps as a backdrop, I have been focusing on the photovoltaic (PV) business (particularly large parks), yet, the EEG itself covers a much broader spectrum of technologies from hydropower and different types of biogases, to biomass, geothermal as well as wind (onshore, offshore, repowering), the tactics below, a priori, being applicable to all of them.

Martin Supancic writing about how to Tune Your German Green Energy Asset Without Getting Sun Burnt in the Attempt

German renewable energy assets are quite appealing due to the stable regulatory framework, although costs are mounting for German households. As a consequence, the pressure is growing for painful political decisions to be taken in order to curb this phenomenon. The surge of German renewable investments over the past few years has led to a gradual adjustment of the corresponding Feed-in-Tariffs (FiTs) in an attempt to disincentivise the amount of newly built capacity, especially in the form of large ground-mounted projects going forward. Thus, investors who were lucky enough to fetch a park in recent months have had to conform themselves to ever lower returns.

Finding strategies to lift the relatively low equity IRRs (5% to 6%) is challenging but not impossible. Buyers of PV parks prior to Jan. 2012 will probably find it easier to uncover hidden value – during the heydays of investment frenzy, project developers, EPCs and O&M contractors could easily turn a quick buck while dictating the transaction terms. Demand was gleaming hot and projects quickly sold in competitive bidding processes, even before being completed, to ensure the highest possible FiTs. As the tariffs dropped, all stakeholders adjusted to the circumstances: PV module prices fell substantially (e.g. global glut, new manufacturing capacity being added in China…), EPC and O&M costs came down to permit attractive prices perMWp, while project developers reined in their margins. As a result, both project costs (EUR/MWp) and O&M prices are quite different today compared to those two or more years ago, opening the door to optimisation potentials.

When we examine options allowing investors to extract further value from their existing assets, we can differentiate between pure financial (e.g. refinancing) and operational measures – I will focus on the latter. The typical “P&L” of a PV park is a good starting point:

– Sales
– Maintenance
– Insurance
– Miscellaneous Expenses: Accounting, Electricity…

Sales: Since the first of January2012 the revised EEG 2012 offers under §33b the opportunity to directly market renewable energy via the so-called “Market Bonus Scheme”, a limited-time opportunity. Provided the park is equipped with remote control devices, allowing it to be decoupled from the grid (e.g. negative market prices), the owners may earn two small margins (total approximately 1.4-1.7%) on top of the FiTs. Sounds like peanuts but for parks upwards of 20 MW, this can easily mean some EUR +100,000 over 18 months.

Maintenance: This is a more complex issue, where risk, covered/non-covered expenses and legal contracts must careful be considered. The result will depend on the existing supplieragreements, options to premature rescissions, and particularly bank consent, assuming the assets are debt financed. Its weight in overall operating costs is significant, thus, even a 1 or 2 EUR/kWp reduction positively impacts the recurring cash flow.

Insurance: As a percentage of operating costs, this is a relatively small item but it too, can be optimized, although absolute savings will be more limited.

Miscellaneous Expenses: This is a bit of a rag bag, with limited potential for a “hair cut”.

Stay tuned as subsequent blog posts shed additional light on the revenue-enhancing and cost cutting potential available to German green asset owners. Looking forward to your comments and particularly for your experiences in executing the mentioned optimization measures.

About the Author

Martin Supancic (37) is external financial advisor to Sojitz Europe plc, the European operations of Japanese trading company Sojitz Corp., with offices on all continents and in major European business capitals. He analyzes photovoltaic investments in Europe and Latin America, and has closed transactions worth 27 MW (more than EUR 65 mill.). In addition, he scouts for innovative cleantech start-ups, helping them grow their sales and arrange venture capital financing. Prior to advising Sojitz Europe plc, Martin advised companies in their internationalization efforts, headed international corporate development at now defunct Spanish biodiesel start-up Green Fuel Corporacion, SA, (shareholders included Endesa, Tecnicas Reunidas, Grupo TSK) and worked on multi sector deals, incl. wind and solar parks, at Deloitte Corporate Finance/Transaction Advisory Services in Madrid, Spain.

First milk, then store – the battery is the future of solar

“Battery storage space plays a crucial role in restructuring the electricity supply,” says Matthias Vetter, battery expert at the Fraunhofer Institute for Solar Energy Systems (ISE), in an interview with Intersolar. Batteries constitute an important part in solar energy generation as they regulate the supply ensuring grid stability, and store any excessive energy produced, at least in the short to medium term. The current research and investment in battery technology is attractive for the photovoltaic industry. Today’s political setbacks for the industry, most recently the planned cuts in solar subsidies, due to a supposed flooding of the market with clean electricity, could be somewhat cushioned by the development in long-term storage capabilities. Presently the industry is investing heavily in technology and research into the optimum storage and life duration of batteries. Hybrid designs and powerful lithium batteries, such as those used in electric vehicles, are the focus of making solar energy use more efficient. It is not the sole idea of ​​battery systems to store excess solar-produced electricity, but it is realistic, says Matthias Vetter. Germany will be “unable to avoid seasonal storage using hydrogen, and couple the use of electricity and gas network simultaneously”. With a supply of 30%, for example, storage systems for the energy transition are much debated. Also at the Intersolar Europe Conference on 11 June 2012 in Munich, the different battery technologies and their respective application areas will be discussed by a panel of experts in the Electricity Storage lecture series. A subsequent plenary debate will seek to clarify the question about which battery is most suitable for each application.


Milk the Sun is at the centre of redesigning the photovoltaic industry – therefore we will be present at the Intersolar Exhibition from 13.-15. June 2012. Visit us at booth B2.170D.