renewable energy Posts

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.

Photovoltaics in Canada: Ontario

Area: 1,076,395 km2
: 13.5 million
Installed Photovoltaics
: 289 MW (2011)

Ontario has a clear lead in Canada’s solar photovoltaic (PV) industry and is even one of the leaders within North America. Approximately 91% of Canada’s 289 MW of PV was installed in Ontario alone, in 2011. Ontario is a leader in Canada’s renewable energy race due to its various procurement programs. These programs have all lead to increases in solar energy investment. It also helps that southern Ontario has one of the greatest solar resources in Canada.

Green Energy and Green Economy Act

In May 2009, Ontario’s government passed the Green Energy and Green Economy Act (GEA). Its main goals are to:

– Promote growth in renewable energy production such as  solar, wind, and biomass;
– Encourage energy conservation through savings and well-managed household energy expenditures;
– Create 50,000 jobs for people in Ontario within its first three years.

Ontario is one of the leaders of solar energy in North America.©xyno

Ontario is one of the leaders of solar energy in North America.©xyno

The GEA promotes energy conservation and attempts to build an economy based on clean energy. This act makes energy efficiency a key part of Ontario’s building codes and creates energy efficiency standards for household appliances. It also works with local electricity utilities to achieve energy conservation targets. Nevertheless, the GEA has been surrounded by some controversy as it demands a certain amount of labour and manufacturing to be done within Ontario in order to receive the tariffs. Ultimately, the GEA is part of Ontario’s effort to protect the environment and prevent climate change.

Ontario’s Feed-in Tariff Programs

One of the GEA’s most prominent features is its Feed-in Tariff (FIT) Program that acts to support its goals. In October 2009, the Renewable Energy Standard Offer Program (RESOP) was replaced by Ontario’s FIT program. RESOP was an incentive offered through the Ontario Power Authority (OPA) which enabled small-scale energy producers to sell their renewable power to the grid at a fixed price.

The FIT program offers a guaranteed funding structure through competitive pricing and long-term contracts for energy that come from renewable sources. Cansia, a national trade organization for Canadian solar companies, stated that FIT is the, “…single largest climate change initiative in North America.” Eligible electricity generators can sign a contract with OPA to sell energy produced by a renewable energy source and receive a fixed amount per kilowatt hour for 20 years. The FIT program is designated for larger solar projects while the microFIT program is intended for installations with a 10 kilowatt capacity or less (ie. homeowners, farmers, and small business owners). The tariff rates are reviewed annually and have decreased since its establishment. As of April 5, 2012, the FIT and microFIT rates are as follows in Table 1. A significant number of PV projects have been installed since FIT was introduced; Table 2 indicates the number of contracts and FIT applications in kilowatts. Approximately 75% of FIT projects are ground-mounted. This program also enabled one of the largest solar parks in the world to be built in Sarnia, Ontario at 97MW.

Table 1. Tariff rates for solar photovoltaic installations for FIT and microFIT program as of April 5, 2012.


Project Size

Price (cent/kWh)

Solar Rooftop ≤10kW


>10 kW ≤100 kW


>100 kW ≤500 kW


>500 kW


Solar Groundmount ≤10 kW


>10 kW ≤500 kW


>500 kW ≤5MW




Table 2. FIT contracts and large FIT applications as of January 31, 2013 (kW for contracts and applications).

Energy Type

Total Contracts (kW)

Existing Applications (kW)

Solar (rooftop)



Solar (ground-mounted)



Net Metering

Like most other provinces in Canada, Ontario has a net metering program available for those generating their own power through a renewable source. This program enables consumers to be paid for any excess electricity that is produced. The consumer connects to a distribution company that will read the meter and receive a credit for the excess power being supplied to the grid. Only generator facilities with less than 500 kilowatts are included in this program

Ontario’s Future

A shift in electricity supply in Ontario is expected in the near future. By 2030, 70% of electricity generation must occur in new or refurbished facilities. The demand for electricity will also increase, regardless of energy conservation measures. Ontario has developed the Long-Term Energy Plan (LTEP) to accommodate the change in Ontario’s energy supply and demand. LTEP calls for the majority of energy produced to switch to different sources such as solar and wind power. Solar PV is expected to contribute 1.5% of total generation by 2030. Ontario’s decision to phase out coal-generated energy by 2014 has also been revolutionary in promoting the move towards renewable energy. Ontario’s programs have attracted a significant amount of private investors towards the PV market. Its PV market is expected to generate $12.9 billion of total private investments by 2018.

Series in Photovoltaics in Canada
1. Photovoltaics in Canada – Introduction
2. Ontario

Source: Cansia, Ontario Power of Authority


Solar Energy is a Finally a Net Energy Producer

There has always been somewhat of an unsaid irony that so much fossil-fuel emitting energy is required to create solar panels, a fossil-fuel free energy source. Recently, research from Standford University has found that the amount of clean energy produced from already installed solar panels is finally exceeding the amount of energy that was required to manufacture the panels.

There are high energy costs to purify silicon.

There are high energy costs to purify silicon.

The amount of solar energy produced from all solar sources such as residential, industrial, and commercial, was compared to the energetic costs of manufacturing and installing PV systems as well as the costs required to maintain the systems. Michael Dale, a postdoctoral fellow from Stanford’s Global Climate Energy Project (GCEP) estimated that the world will reach net energy benefit by 2015 and at latest, 2020. Just five years ago, the manufacturing process was using 75% more energy than it actually produced. That value has decreased immensely due to continually increasing efficiency in the production of solar cells.

The manufacturing process of a solar panel can be heavily energy intensive. Approximately 90% of solar modules on the market are silicon-based. To extract silicon, silica rock must be melted at over 1500°C, often using coal-fired plants. Afterwards, the pure silicon must be melted again to obtain a crystalline structure, with an average purity of 99.9999%. Nevertheless, technology has improved and the process of making a solar cell has become more efficient. Thinner silicon wafers and less highly refined material for silicon feedstock are now used, while less expensive material is being lost throughout manufacturing process. The use of other elements for solar thin films such as copper, zinc, tin, and carbon can also be improved. The energy required to produce solar panels will likely continue to decrease over time.

The solar industry is still aiming primarily at reducing financial costs rather than energetic costs but there are several ways to reduce the latter. An easy solution is to place more PV installations in regions with greater solar resources. Using less material or switching to panels that have lower energy costs than silicon cells are also viable options. Other existing cells based on cadmium telluride and copper indium gallium diselenide can be also used. Together with silicon cells, these solar cells make up over 99% of the current market. Overall, Dale forsees a decline in the energy costs to manufacture panels, more durable panels, and more efficient conversion of sunlight with new technologies. Net energy production measurements should be taken into account in current and future renewable technologies to produce effective energy solutions. GCEP is also looking to apply these measurements to storage technologies and wind energy.

You can also see Stanford’s video on this topic

Source:; Environmental Science and Technology

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