Core Elements of the Reform
Dynamic development of renewable energy
The German government adopted a comprehensive Energy Concept on 28 September 2010. A core element of this Energy Concept consists of the reform of the Renewable Energy Source Act – Erneuerbare Energien Gesetz (“EEG”), which was enacted on 8 July 2011. The Energy Concept plans a drastic increase in the share of energy produced from renewable sources in relation to the overall power production. Accordingly, the Renewable Energy Act 2012 (“EEG 2012”) aims to increase the share of energy produced from renewable sources until 2020 to 35 percent, until 2030 to 50 percent, until 2040 to 65 percent and until 2050 to 80 percent. Furthermore the EEG 2012 pursues the objective to integrate this amount of energy into the electricity supply system (Sec. 1, para. 2). The EEG 2012 shall become effective on 1 January 2012.
Reform adheres to the basic principles of the EEG
As before, the development of renewable energy is to proceed, based on the basic principles of the Renewable Energy Act. The structural elements of the Act are a) the provisions obligating system operators to connect renewable energy generation facilities to the grid and to expand the grid as necessary to accomplish this purpose, b) the provisions giving priority to power from renewable energy for purchase, transmission and distribution (feed-in priority) and c) the rules governing payment, typically at tariffs, which are fixed for a period of 20 years.
Improving market and system integration
The core of the reform is comprised of the provisions aiming to improve market and system integration for renewable energy. The motivation behind these provisions is the fact that demand-based generation of power from renewable energy will be increasingly important as the share of renewable energy in overall energy production increases. Such a demand-based generation system can only emerge if generation from renewable energy is determined by the market price, i.e., if feed-in volume is based on demand. In order to accomplish the goal of market integration, the system for direct selling of power from renewable energy is expanded substantially. In order to improve system integration, feed-in management is improved and extended.
Increasing cost efficiency
The differential costs of the Renewable Energy Act were estimated at about €9 billion in 2010, a substantial sum. In an effort to limit the resulting financial burden for private households and businesses, the reform aims to correct errors in connection with the compensation of differential costs.
Securing the basis for financing
The Renewable Energy Act follows the basic principle that the costs arising from implementation of the Act should be divided among all power consumers. Since any deviation from this principle would mean that the other power consumers would have to bear a heavier burden, deviations from this basic rule should be limited to “objectively necessary areas.” In light of this circumstance, the reform should eliminate, e.g. possibilities of abuse in connection with application of the special equalization scheme.
Rules for Facility Operators
The section of the Renewable Energy Act of 2012 dealing with direct sales of the power generated by the renewable energy installations (direct selling) (Part 3a) is divided into two parts: the first defines general provisions which are to apply to all forms of direct selling, the second defines specific terms and conditions. Section 33a, para. 2 clarifies that the consumption of power in the immediate geographic vicinity without utilizing a (public) grid, e.g., in accordance with Sec. 33, para. 2, does not constitute direct selling within the meaning of Part 3a. The three forms of direct selling specified in Sec. 33b (direct selling for the purpose of claiming the market premium, direct selling for the purpose of decreasing the so called “EEG apportionment” and other direct selling) are mutually exclusive. Direct selling in multiple forms would violate the prohibition of multiple sale (Sec. 56).
The market premium model in Sec. 33g represents a paradigm shift for the promotion of renewable energy: renewable generation facility operators are to receive an incentive to become active market participants. To this end, the operators receive technology-specific premiums which essentially cover the difference between the technology-specific feed-in tariff and the (average) market price. These premiums are to take into account the fact that e.g., power from solar energy generation facilities draw higher prices on the market than power from wind energy generation facilities because of its feed-in properties. In addition to the market premium, facility operators are also to receive a management premium to cover the cost of participating in trading and deviations from forecasting. The precise calculation of the market premium and the amount of the management premium are defined in Annex 4 to the EEG 2012. The obligor of the market premium payment is the system operator whose system the facility is connected to or in whose system the power is transmitted in accordance with Sec. 8, para. 2. Direct selling may only take place on a calendar monthly basis (Sec. 33d, para. 1).
Other direct selling
Sec. 33b, No. 3 covers all other modes of selling and, therefore, serves to encompass e.g., power from renewable energy or mine gas which is sold directly without any subsidization through the Renewable Energy Act.
Flexibility premium for biogas facilities
The optional flexibility premium is meant to promote investments in targeted fashion to improve the ability to generate power from biogas facilities in a market-based, i.e., demand-based fashion. The claim for this premium is against the system operator to whose system the facility is connected, or in whose system the power is transmitted in accordance with Sec. 8, para. 2. Pursuant to Sec. 33i, para 1, No. 1, the flexibility premium is only paid if all of the electricity generated in the biogas generation facility is distributed through direct selling pursuant to Sec. 33b, No. 1. Direct selling, in the form of utilizing the market premium, must be continued throughout the entire period of the flexibility premium, which is 10 years (Sec. 33i, para. 4, sentence 1). If the market premium is discontinued in the interim period, the claim to the flexibility premium is extinguished forever (cf. preamble of the EEG 2012). The amount of the flexibility premium is calculated every calendar quarter and is based on Annex 5 to the EEG 2012 (Sec. 33i, para. 2).
Technical conditions for connection
Both combined heat and power (“CHP”) generation facilities and facilities for the generation of electricity from solar radiation are now included in Sec. 6 in order to allow these facilities to be included in the feed-in management system pursuant to Sec. 11.
By expressly mentioning operators of CHP generation facilities in the first phrase of Sec. 6, para. 1, the new law clarifies that these facilities must be equipped with devices to regulate output if their installed capacity exceeds 100 kW. Furthermore, the following current alternative course of action for plant operators is set aside. Under the current regime, plant operators can ensure by operational measures that the feed-in capacity can be reduced externally, provided also that the grid operator has access to the actual power feed-in data (instead of having output regulation equipment installed).
Solar radiation facilities
Section 6, para. 2, No. 1 requires the operators of facilities for the generation of electricity from solar radiation with an installed capacity of more than 30 kW, to equip their facility with a system for remote-controlled output reduction pursuant to Sec. 6, para. 1. Facilities with an installed capacity of 30 kW or less may optionally take part in the feed-in management system pursuant to Sec. 6, para. 2, No. 2. If they do not take part, they must permanently reduce their output at the grid connection point to 70 percent of installed capacity through technical measures (Sec. 6, para. 2, No. 2 lit. (b)). This provision is meant to ensure that the development of the grid does not have to be based on the facility’s maximum output, which is reached only a few times a year. Section 6, para. 3, clarifies that multiple facilities for the generation of electricity from solar radiation count as a single facility if they are situated on the same land, or otherwise in the immediate vicinity of each other, and if they went online within 12 consecutive calendar months.
Operators of facilities for the generation of electricity from biogas must ensure that a fermentation residue depot is built at the place where the biogas is generated, that this depot is covered so that no gas escapes and that the hydraulic retention time within the system, which must be secure from leaks and connected to a gas recovery system, is at least 150 days. Additional gas consumption facilities must also be used to prevent the release of biogas (Sec. 6, para. 4).
Tariffs and reduction of tariffs
The following changes are made through the reform in connection with tariffs and the reduction of tariffs for the various facility types:
Wind energy: onshore
- the basic tariff is decreased to 4.87 ct/kWh (Sec. 29, para. 1)
- the initial tariff is decreased to 8.93 ct/kWh (Sec. 29, para. 2, sentence 1)
- the system services bonus for existing facilities is extended through 31 December 2015 (Sec. 66, para. 1, No. 8)
- the system services bonus is prolonged until the end of 2014 and decreased to 0.48 ct/kWh (Sec. 29, para. 2, sentence 4)
the repowering bonus (0.5 ct/kWh) provisions are changed (Sec. 30)
- the replaced installation must have entered into operation before 1 January 2002
- a claim for the feed-in tariff must exist for the replaced installation
- the repowering-installation must have at least twice the capacity of the replaced installation
- the number of the new installations must not exceed the number of the replaced installations
Wind energy: offshore
- rapidity bonus (installations commissioned prior to 1 January 2016 - Sec. 31, para. 2 Renewable Energy Act 2009) is integrated into the initial tariff
- during the first 12 years after the commissioning of any given offshore installation, the tariff shall amount to 15.0 ct/kWh (initial tariff)
the period during which the initial tariff is paid shall be extended (extension period)
- in the event a wind farm is located at least 12 nautical miles seawards by 0.5 months for each full nautical mile beyond 12 nautical miles, and
- in the event a wind farm is located in a water depth of at least 20 meters by 1.7 months for each additional full meter of water depth
- if an installation is commissioned before 1 January 2018, the wind farm operator has the option to receive as initial tariff 19 ct/kWh for eight years (optional initial tariff - so called “compression tariff model”). The provisions regarding the extension period apply, too, provided however, that only 15.0 ct/kWh will be paid during the extension period
- commencement of the reduction of the tariff is pushed back from 2015 to 2018; rate is increased from 5 to 7 percent (Sec. 20)
- tariff system simplified to four output-based categories (rated output: 150 kW, 500 kW, 5 MW, 20 MW; tariffs: 6.0 – 14.3 ct/ kWh) and two categories based on materials used (Sec. 27)
separate tariffs are introduced for biowaste fermentation facilities with downstream digestate composting (Sec. 27a)
- tariff: up to a rated output of 500 kW: 16.0 ct/kWh
- tariff: up to a rated output of 20 MW: 14.0 ct/kWh
a separate tariff introduced for small (max. 75 kW) manure fermentation facilities (Sec. 27b)
- tariff: 25.0 ct/kWh
staggered additional tariff for feed-in of bioethanol introduced (Sec. 27c, para. 2 in connection with Annex 1 to the EEG 2012)
- additional tariff: 1.0 – 3.0 ct/kWh
- the percentage amount for the reduction of the tariff is increased from 1 to 2 percent (Sec. 20);
- the use of corn and grain is limited to 60 percent for power generated from biogas (Sec. 27 para. 5, No. 1)
- the tariff for waste wood incineration and liquid biomass for new facilities is eliminated (Biomass Ordinance)
- the market premium model will be mandatory starting in 2014 for facilities with output higher than 750 kW (Secs. 27, para. 2a, 27a, para. 1a)
- the percentage rate for the reduction of the tariff (reduction percentage rate) of 9 percent is maintained
- the provisions on the adjustment of the reduction percentage rate based on the capacity that was additionally installed in the preceding 12 month reference period (expansion rate) are maintained (Sec. 20a)
the adjustment as per 1 January of any given year may lead to
- an increase of the reduction percentage rate by between 3.0 and 15.0 percentage points (Sec. 20a, para. 3) or
- a decrease of the reduction percentage rate by between 2.5 and 7.0 percent percentage points (Sec. 20a, para. 4)
- an additional semi-annual adjustment mechanism is introduced (Sec. 20a, para. 5); the adjustment as per 1 July may lead to an additional reduction of between 3.0 and 15.0 percentage points
- the tariff applicable in the event the electricity produced is used in the immediate vicinity of the installation without using the public grid shall now apply to all installations irrespective of the date of commissioning (Sec. 33, para. 2)
- stand-alone generation facilities situated on land formerly used for national parks (Sec. 24 of the Federal Nature Conservation Act) or nature reserves (Sec. 24 of the Federal Nature Conservation Act) are not eligible for the feed-in tariff (Sec. 32, para. 2, No. 2 lit. (a) and (b))
- the heat use and early starter bonus are integrated into the basic tariff (25.0 kWh) (Sec. 28)
- the technology bonus for petrothermal projects is increased from 4.0 to 5.0 ct/kWh (Sec. 28, para. 2)
- the commencement of the reduction of the tariff is pushed back to 2018 and the percentage rate for the reduction of the tariff is increased from 1 to 5 percent (Sec. 20)
- to the rated output of the installation linked tariffs between 3.4 and 12.7 ct/kWh
- tariffs only apply for installations that exist in relation with an already existing or for another purpose built barrage or if the installation was built without a persistent cross lining
- the principle of the reduction of the tariff (1 percent from 2013) now applies to all installations (Sec. 20, para. 2, No. 1)
Landfill gas, sewage treatment gas and mine gas
- tariffs for landfill gas: 5.89 – 8.60 ct/kWh
- tariffs for sewage treatment gas: 5.89 – 6.79 ct/kWh
- tariffs for mine gas: 3.98 – 6.84 ct/kWh
- bonus for facilities with innovative technologies will be set aside (Secs. 24 – 26 EEG 2009)
Rules for Electricity Dealers/Suppliers
The green power privilege
Section 39 continues the green power privilege in Sec. 37, para. 1, sentence 2 EEG 2009 in modified form, limiting it to 2 ct/kWh. Section 39, No. 1 states that at least 50 percent of the total electricity must be comprised of power which is eligible for the feed-in tariff under the EEG. All forms of renewable energy and mine gas may be used to meet this target (provided they are eligible for the feed-in tariff). Also, Sec. 39, para. 1, No. 1 lit. (b) states that at least 20 percent of the total power portfolio must come from fluctuating renewable energy (Secs. 29 – 33). The entire share of fluctuating renewable energy is counted towards the 50 percent target, so that e.g. an utility company would meet these requirements if 20 percent of its total portfolio comes from wind energy and another 30 percent of its total portfolio comes from hydropower and biomass. Utility companies planning to take advantage of the green power privilege must inform their regular transmission system operator of this fact by 30 September of the previous calendar year (Sec. 39, para. 1, No. 2).
Rules for Electricity-Intensive Enterprises
Limitation of the EEG apportionment
The EEG apportionment (Sec. 37, para. 2 – i.e., the cost for the promotion of renewable energy to be passed on to endconsumers; please see also below) for electricity-intensive manufacturing enterprises with high electricity consumption (Sec. 41) and rail operators (Sec. 42) can – on application – be capped.
This applies to manufacturing enterprises only if and to the extent they can prove that in the last financial year:
- the electricity purchased and used by the enterprises exceeded 1 GWh at a certain delivery point,
- the ratio of the electricity costs of the enterprise to its gross value added as defined by the Federal Statistical Office equals or exceeds 14 percent, and
- the EEG apportionment has been passed on to the enterprise (Sec. 41, para. 1, No. 1).
Enterprises with an electricity consumption of at least 10 GWh also require certification pursuant to which energy consumption and the potential for the reducing of the energy consumption are assessed (Sec. 41 para. 1 No. 2).
Pursuant to Sec. 41, para. 3, No. 1 lit. (a) to (d), the EEG apportionment to be born by manufacturing enterprises with at least 1 GWh electricity consumption by the enterprise itself at one delivery point during the last financial year is limited to
- 10 percent of the calculated EEG apportionment in relation to the electricity consumption exceeding 1 GWh, up to and including 10 GWh,
- 1 percent of the calculated EEG apportionment in relation to the electricity consumption exceeding 10 GWh, up to and including 100 GWh ,
- 0.05 ct/kWh of the calculated EEG apportionment in relation to the electricity consumption exceeding 100 GWh.
Pursuant to Sec. 41, para. 3, No. 2, the EEG apportionment for manufacturing enterprises with at least 100 GWh electricity consumption is limited to 0.05 ct/kWh, if the ratio of electricity costs to gross value added is more than 20 percent.
Rules for System Operators
Pursuant to Sec. 11, para. 1, sentence 2, feed-in management expressly relates to facilities which are equipped with devices pursuant to Sec. 6 para. 1 and 2. In addition to renewable energy and mine gas facilities, CHP generation facilities are also included in the system. Section 11, para. 1, No. 1 states that system operators may take control over all facilities subject to feed-in management if there would otherwise be a congestion in the system or in an upstream system. Accordingly, the amended Renewable Energy Act extends the feed-in management system to allow for feed-in management in the event of overloads in the upstream system. However, the priority of electricity from renewable energy, mine gas and CHP generation facilities must be preserved in the context of the feed-in management scheme, i.e., these facilities may only be brought under control if it would otherwise be impossible to ensure the safety and reliability of the system (Sec. 11, para. 1, No. 2). Facilities for the generation of electricity from solar radiation with an installed capacity of no more than 100 kW are controlled subsidiary (Sec. 11, para. 1, No. 3, sentence 2).
The newly added Sec. 9, para. 1, sentence 2 serves as clarification. Since it was previously unclear in any individual case whether and when an immediate grid expansion obligation extends to upstream systems as well, the obligation for immediate grid expansion is now expressly extended to operators of downstream systems if a feed-in management scheme would otherwise be required to control the feed-in of power from upstream systems.
Section 35, para. 1a extends the system for equalization between system operators and transmission system operators to include the premiums to be paid to facility operators pursuant to Secs. 33g and 33i (market/flexibility premium). Pursuant to Sec. 35, para. 2, system fees in accordance with Sec. 18, para. 1, sentence 1 of the Electricity System Fee Ordinance which are not utilized because of Sec. 33c, para. 2 No. 1 lit. (b) are to be distributed to the transmission system operator in order to avoid unjustly enriching the distribution system operator. The payment obligations arising from Sec. 35, para. 1, 1a and 2 are to be netted, pursuant to Sec. 35, para. 3, so that in the end only one payment in favor of a system operator is to be made. Sec. 35, para. 4 states that excessive tariff payments or premiums higher than those provided for in Secs. 33g and 33i must be refunded by the purchasing system operator to the transmission system operator and by the generation facility operator to the purchasing system operator. The refund claim expires after 31 December of the calendar year following the feed-in, in deviation from the standard limitation period defined in Secs. 195, 199 of the German Civil Code (Sec. 35, para. 4, sentence 2).
Pursuant to Sec. 37, para. 1, transmission system operators are required to sell the renewable energy electricity purchased individually or jointly in accordance with Secs. 16 and 35, para. 1 in a transparent and non-discriminatory manner and with due regard for the specifications of the so called equalization mechanism ordinance.
Sec. 37, para. 2 defines the basis for the determination of the amount of the renewable energy promotions costs the transmission system operators can claim from the utility companies supplying end consumers (EEG apportionment). The EEG apportionment represents the difference between the cost of purchasing the power produced by renewable energy installations and the sales proceeds (please see above).