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.
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.
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).
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.
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