sou · GWB313d2 · 2009-01-01 00:00:00 — , earlier connection of conventional power plants does not result in any preference in the access to the grid. A slight con- flict occurs between renewable energy sources and CHP sources, which are both guaranteed priority treatment in the relevant laws, however it is not clear which ranks higher in a case where a bottle- neck is entirely created by renewable energy sources and CHP. 3.5Costs Associated with the Connection to the This is regulated in general in the directive on the access to power supply networks (). According to § 10 I RES Act, also the operators of renewable energy facilities have to bear the grid connection costs themselves. The legal regulations state that the decisive point of reference regarding a decision on who will bear which costs when connecting renewable energy generation facilities is whether it is a grid connection or a grid upgrade.TPF71FPT The facility operator has to pay for the grid connection; the distribution as well as the transmission network operator has to pay for a network exten- sion. This rule which is in principle clear is unclear regarding indi- vidual cases. Whether an individual case constitutes a network exten- sion or a network connection is not defined by the law and requires an interpretation. Such disputes are typically solved in civil courts. This results from § 102 I National Energy Act, which states that 71TP PT Different for offshore wind farms, see below. civil legal disputes resulting from this law fall under the exclusive jurisdiction of the district courts, regardless of the value of the matter of dispute. § 4 II 3,4 RES Act also determines that the obligations regarding the network extension include all technical facilities required for network operation as well as connection facilities that are owned by the network operator or that will be transferred to the ownership of the network operator. Also according to § 13 II RES Act, the network operator has to bear the costs required only for network extensions due to newly connected, reactivated, extended or other- wise renewed facilities for power generation from renewable energies or firedamp corresponding to § 4 paragraph 2 on the purchase and transmission of renewable energies. Currently, network companies can recover the costs for network upgrades via higher network consumer tariffs, see Section 3.1.4. Costs related to network extensions related to offshore wind farms are shared by all transmission companies and recovered via higher network tariffs, see Infrastructure law in Section 3.1.3. 3.6Costs and Obligations Related to Metering According to § 21 b I of the National Energy Act the operator of a power supply network is responsible for installing, operating and maintaining the metering equipment as well as for metering the supplied power. However, for renewable energies, the facility ope- rator has, according to § 13 I RES Act, to bear the costs for the metering equipment required for recording the supplied and con- sumed electric work.TPF72FPT The actual metering installation can be done by the network company or any other company. In principal the metering code 2006TPF73FPT of the German network association treats conventional power plants and renewable units similar. The equipment required for installations larger than 500 kW must be capable of providing 15 minute metering. For units smaller than 500 kW the readings will be done once a year. Even for a stand alone renewable energy unit, e.g. a wind farm, the metering equip- ment must be capable of metering delivered electricity and electricity taken from the grid separately. This also applies for self-generator, 72TP PT RES Act: ... measuring devices for recording the quantity of electrical energy transmitted and received shall be borne by the plant operator. residential house with PV equipment; however an aggregated metering (the metering equipment runs backwards in case of de- livery of energy into the grid) is in principal possible but requires a special agreement between network company and the operator of the renewable energy unit. Typically, renewable energy operators prefer two separate meterings because the feed-in tariffs are typically higher than the power purchase price for electricity. Generators in general are not required to pay network fees or net- work tariffs in . Until 2005 there was no legal definition about network tariffs in general in . Until then everyone followed the definition outlined in the associations´ agreement (Verbändevereinbarung II plus)TPF74FPT of the German network association that power plants in general are not required to pay any network fee. With the introduction of the National Energy Act of 2005 and the Charges OrdinanceTPF75FPT, this definition has become legally binding. 3.8Rights and Obligations Regarding Real Time Operation This topic is not relevant in because renewable energy operating under the RES Act are not required to consider real time operation, i.e. transmission system operators have to balance renewable energy. The only exception is defined in the grid codes which requires faultride-through of wind turbines in certain situations. 75TP PT See § 15 Abs. 1 S. 3 StromNEV (Verordnung über die Entgelte für den Zugang zu Elek- trizitätsversorgungsnetzen), from 25.07.2005, see de/textonly/content/Lehre/Vorlesungen/NEMIII/downloads/StromNEV.pdf (in German). A special law for renewable energy grants priority access to renew- able energy by forcing operators of power grids to give priority to electricity fed-in by renewable energies into the grid and to pay a defined, fixed power purchase prices (feed-in tariff) for this. Based on this law, conventional power plants have to regulate down their production in case of network bottlenecks or access production to guarantee priority production to renewable energy. size limit in the regulations for renewable energy? In general, there are no size limitations such as the 1.5 MW re- gulation in . However, the feed-in tariff paid to different renewable energy sources can vary depending on the installed capacity. This is particular the case for biomass, geothermal, photovoltaics and hydro power, but not for wind power. Addi- tional size definitions are used in the definitions for meeting re- quirements. Generators in general are not required to pay network fees or net- work tariffs in . This rule was always applied for con- ventional as well as for renewable power generators, hence grid tariffs played historically no role in the energy policy to pro- mote renewable energy technologies. In principal renewable energy generators are required to pay the costs for the grid connection, i.e. all costs from the wind farm to the connection point, and grid companies are required to pay all network upgrading costs. The issue is typically the definition of the best grid connection point. The general rule for defining the grid connection point applied is based on the understanding that the total network connection costs, i.e. grade costs, should be minimized independent of who covers which part of the costs. This could mean that a low voltage net- work must be upgraded to a high voltage network if this is the most economic solution, but it is also possible that the wind farm operator must build a long line itself to a suitable connec- tion point if this is more economic than upgrading the existing network. Network concessions also exist in , however, wind farms can build their own network for the sole purpose of connecting the wind farm to the power system. These wind farm networks are treated as industrial networks, i.e. the rules and regulations of distribution or transmission networks do not apply to these industrial networks. The procedure is not clearly described, but the network associa- tion has developed a guideline for the network companies of how to deal with applications. The relevant law defines that system operators shall immediately and as a priority connect plants generating electricity from renewable energy sources, hence appli- cations can complain to the German regulator in case of delays and the network company then has to explain to the regulator what caused the delays. Renewable generators larger than 500 kW need 15 minute mete- ring systems, metering im/export separately. For small genera- tors only a continuous metering system is required but also measuring im/export separately. The (UK) has currently around 76 GW of electri- city generation capacity to meet an annual consumption of about and peak demand of about 63 GW. The UK has also a diverse electricity generation mix. In 2006, was generated by gas-fired power stations, from coal, from nuclear, and from renewables, see also Figure 4-1. Figure 4-1: in 2006. Figure 4-2: Electrical Generating Capacity of Renewable Energy from 1997 to 2006 (excluding large scale hydro, which had a capacity of 1,369 MWe in 2006; (2) includes both onshore and off- shore and also includes solar photovoltaics (9.9 MWe in 2006) and shoreline wave (0.5 MWe in 2006); (3) All waste combustion plants are included because both biodegradable and non-bio- degradable wastes are burned together in the same plants. Figure 4-2, shows the development of renewable energy installations, excluding large hydro power, from 1997 to 2006. Even though the installed capacity of renewables (excluding large hydro power) in- creased from 1000 MW in 1997 to more than 3600 MW in 2006, see also Table 4-1, the installed capacity is still small compared to other European countries, e.g. . In 2006, renewables provided 4.55 per cent of the electricity gene- rated in the UK and total electricity generation from renewables amounted to 18,133 GWh, an increase of 7.5 per cent on 2005. This number includes the electricity generation of large hydro power stations, see also Figure 4-3. Without large hydro stations, the share of renewables was only , see also Table 4-2. Figure 4-3: Growth in Electricity Generation from Renewables since 1990. The main contributors to the increase in renewable energy pro- duction between 2005 and 2006 were onshore wind (+43 per cent), offshore wind (+62 per cent), landfill gas (+3 per cent) and muni- cipal solid waste combustion (+12 per cent). There was no increase in co-firing of biomass with fossil fuels and a decrease (-8 per cent) in large scale hydro generation which can be attributed to drier weather. Only 23 per cent of generation from renewables was from large scale hydro in 2006 compared with 26.5 per cent in 2005. Hydro (taking both large and small scale together) remains the most im- portant renewables technology in output terms closely followed by landfill gas and wind (both onshore and offshore), with the co-firing of biomass the next most prominent. to the importance of wind power and similarly to the other countries, the UK Chapter of this report will concentrate on the issues related to wind power but will also include experience related to network connection/integration gathered from other renewable energy technologies. Table 4-1: Installed capacity of Renewable Energy Sources in the UK from 1998 to 2006.76 Large scale 1) Biofuels and wastes: 1)Excluding pumped storage stations. Capacities are as at the end of . 2)Includes the use of farm waste digestion, waste tyres, poultry , meat and bone, straw combustion, and short rotation coppice. 3)This is the proportion of fossil fuelled capacity used for co-firing of renewables based on the proportion of generation accounted for by the renewable source. Table 4-2: Electricity generated from Renewable Energy Sources in the UK from 1998 to 2006.77 Generation (GWh) Small scale 1) Large scale 2) Co-firing with fossil fuels Non-biodegradable wastes 6) Load factors (per cent) 7) Offshore wind (from 2004 (excluding co-firing) Total (including wastes) Load factors on an unchanged configuration basis (per cent) Offshore wind (from 2006 1)Actual generation figures are given where available, but otherwise are estimated using a typical load factor or the design load factor, where known. 2)Excluding pumped storage stations. Capacities are as at the end of . 3)Latest years include electricity from shoreline wave but this amounts to less than 0.05 GWh. 4)Biodegradable part only. 5)Includes the use of farm waste digestion, poultry combustion, meat and bone com- bustion, straw and energy crops. 6)Non-biodegradable part of municipal solid waste plus waste tyres, hospital waste and general industrial waste. 7)Load factors are calculated based on installed capacity at the beginning and the end of the year. The power system in (GB), i.e. , and , can be considered almost an power system, taking into account the rather small connections to Northern (500 MW HVDC) and to (2000 MW HVDC) in compari- son to the overall installed capacity of 76 GW in GB. The transmission system in and is owned by National (NGET) and the transmission system in is owned by two companies, Trans- mission Limited (SPTL) for Southern , and () for Northern . Figure 4-4 shows the transmission network owned by National in blue, while the Scottish network owned by SPTL and SHETL is shown in red. National is the transmission system operator in GB, i.e. National is responsible for managing the operations of its own transmission network in and as well as, since April 1, 2005 the electricity transmission network in . A detailed map of the transmission system in , and is shown in Figure 4-5. The map also indicates the distri- bution areas and the relevant distribution companies (see next Section for details) as well as the main generation sources/locations. Figure 4-4: in & and . The transmission system operator and each transmission owner operate based on a license from Ofgem (Office of Gas and Elec- tricity markets), the regulatory body in the GB. They are subject to regular price controls, see Section 4.1.4. Figure 4-5: in , and . The map also indicates the distribution areas and the relevant companies as well as the generation sources/locations. Ofgem has licensed 13 distribution network operators (DNOs) in GB (14 including Northern ) each responsible for a distri- bution service area. DNOs came into existence on 1 October 2001, evolving from ex-Public Electricity Suppliers. These companies have distribution service areas corresponding to the areas in which they were formally the incumbent. Within these areas they have cer- tain license obligations, see Section 4.1.4. The 14 DNOs are owned by seven different groups, see Figure 4-6 for details. Figure 4-6: Schematic representation of distribution companies in . In addition, there are four independent licensed network operators that own and run smaller networks embedded in the DNO networks, called Operators (IDNO). An IDNO is any electricity distributor with a license granted after 1 October 2001. The Utilities Act 2000 amended the Electricity Act 1989 and introduced distribution as a separate activity requiring authorisation. Ofgem is responsible for granting licenses to distri- bution companies. IDNOs own and operate electricity distribution networks which will predominately be network extensions connected to the existing distribution network, e.g. to serve new housing de- velopments. IDNOs do not have general distribution service areas. Ofgem has issued four distribution licenses to IDNOs so far:78 An alternative arrangement is a private network. This private net- work allows distributed generation to be connected directly to this network and allows a certain amount of unlicensed generation and supply to take place completely outside the main market. A private network is exempt from the licensing regime when it:79 distributes without any limitation electricity over private wires to business , and up to 2.5 MW to domestic – exemption from the requirement of a distribution license; supplies electricity directly to up to a maximum of 5 MW in aggregate of which no more than 2.5 MW can be supp- lied to domestic – exemption from the requirement of a supply license. generates no more than 50 MW (or no more than 100 MW with Secretary of State approval) – exemption from the requirement of a generating license; The benefit of this approach is that the unlicensed operator is able to avoid a number of costs that a licensed energy supplier usually would incur. In particular, the unlicensed operator avoids the costs 78Applications from ECG (Distribution) Ltd and UK Utilities (Electricity) Ltd are currently being considered. 79http:///Networks/ElecDist/Policy/DistGen/Documents1/15939-193_ 06.pdf related to the Renewables Obligation, the Climate Change , and the Energy Efficiency Commitment. The consists of four constituent countries: , , and Northern . In the following, only , and , i.e. – which partly have different legislations related to the electricity sector – will be analyzed. Statistical data may, however, include all four countries. The deregulation and liberalisation in the UK power industry started with the Electricity Act of 1983 which abolished the legal monopoly by opening up the grid and allowing wholesale wheeling between independent generators and retail . However, no competitive market developed. In February 1988, the British govern- ment published a regarding a further increase of com- petition in the electricity industry. In 1989, the revised became law as the Electricity Act of 1989.80 The new approach focused particularly on the introduction of a mandatory as well as on splitting up and privatizing the power indu- stry. A. Non-Fossil Fuel Obligation Part of the Electricity Act of 1989, was the Non-Fossil Fuel Obli- gation (NFFO)81, which provided a premium-price, market-enabling mechanism which attempts to encourage renewable-based electri- city generation (a similar mechanism was created for , the Scottish Renewable Orders (SRO)). Under NFFO, potential project developers for renewable energy projects were invited to make offers for new projects. The developers bid under different tech- nology brands, e.g. wind power, solar, for a feed-in tariff or for the amount of financial incentives to be paid for each kWh fed into the grid by renewable energy systems. Under the NFFO system, the difference between the premium price paid to green electricity suppliers and the market price has 80http:///acts/acts1989/Ukpga_19890029_en_1.htm 81http:///acts/acts1989/ukpga_19890029_en_4#pt1-pb7-l1g32 been financed by the Fossil Fuel ,82 a tax paid by licensed elec- tricity suppliers and ultimately passed on to consumers. In October 1998, the Government published a new that focused on a new approach to the wholesale electricity market.83 As a result of this and further – rather long – discussions, a new regulation approach was developed. Part of the discussion process was carried out by a joint working group for embedded generation84 (EGWG). The EGWG report concluded that there were a number of obstacles for distributed generation (DG) regarding their participation in the market, but that further investigations were needed to better address the relevant requirements. In addition, the EGWG report concluded that distributed network operators had no economic incentives to connect DG. As a result of the report DTI and Ofgem set up the ().85 The group initiated various studies to investigate the impact of market regulations and network regulations on the development of distributed generation.86 The new overall approach is known as the Arrangement () and finally became operational on 27 2001.87 The approach moved the overall market approach closer to the Scandinavian approach, i.e. the mandatory pool system was removed and buyers and sellers can use a wide range of contracts, e.g. bi- as well as multilateral contracts. Furthermore, a market for the settlement of system imbalance was introduced. The Office of Gas and Electricity Regulation (Ofgem) is currently the main regu- latory authority for the electricity and gas sector. () is the responsible organization within the Ministry. DTI's approval is required for key regulatory decisions. The arrangement was initially only applied to and 82http:///acts/acts1989/ukpga_19890029_en_4#pt1-pb7-l1g33 83A Fair for Consumers: Modernising the Framework for Utility Regulation: Response by the Director General, of Electricity Regulation, , 1998. 84Embedded generation = distributed generation = power generation installed in the distri- bution network. Many small scale renewable generation is typically connected to the distri- bution system. 85http:///Networks/ElecDist/Policy/DistGen/disenwg/Pages/ 86http:///Networks/ElecDist/Policy/DistGen/Pages/DistGen.aspx 87The Arrangements, Office of Gas an Electricity Markets, 2002. , but then extended to and is now known as Arrangements (). C. Renewable Obligations In parallel to introducing , the renewable energy policy was changed. Since February 2000, the renewables policy has consisted of four key strands: a new Renewable Obligation (RO) on all electricity suppliers in to supply a specific proportion of electricity from eligible renewables. The Renewable Obligation and associated Renewables () Obligation came into force in as part of the Utilities Act (2000)88. It requires power suppliers to derive from renewables a specified proportion of the electricity they supply to their . This started at in 2003, rising gradually to by 2010, and by 2015. The cost to consumers will be limited by a price cap and the Obligation is guaranteed in law until 2027. The system is know as certificate system or renewable obligations (ROCs) system with fixed quotas. exemption of renewable-generated electricity from the Climate Change , introduced in ; an expanded support programme for new and renewable energy including capital grants and an expanded research and develop- ment programmes; development of a regional strategic approach to the planning of and targets for renewables. In 2003, the government's future- creating a low carbon economy was published. It outlines the future energy policy.89 It formulates the long-term goal of a reduc- tion of CO2 emissions by about . It was outlined in the that renewable power generation, partly distributed, is expec- ted to play an important role in achieving this goal. In 2007, the government published another with the title Meeting 88 Utility Act: Re- newable Obligations: _en_8#pt4-pb8-l1g62 89 Energy : Our energy future – creating a low carbon economy, ()- , , UK, 2003. the – A on Energy.90 It confirms the original energy policy of a cut of CO2 emissions by about , but it also considers nuclear power an option, in addition to renewable energy. Regarding renewables, it particularly requires a re- view and update of the current transmission access arrangements, in order to support the timely and cost-effective connection of re- newable generation. The work on the review started in 2007.91 As the government has identified distributed generation, which includes distributed renewable energy, as an important part of its environmental agenda, Ofgem – the regulator – has put a lot of em- phasis on distributed generation, including Combined Heat and (), wind farms, hydro electric power and micro genera- tion technologies. Its main emphasis is on ensuring that the develop- ment of distributed generation facilities is not unfairly treated by the way networks are operated and regulated. Ofgems work in this area is of great importance, because it aims at developing a fair treatment of all generation sources within a deregulated market.92 In October 2006, a discussion process was started regarding a Reform of the Renewables Obligation System.93 The discussion pro- cess focuses on two main issues (see also Section 4.1.6):94 brand the RO to provide differentiated levels of support for different technologies; introduce a mechanism intended to maintain Renewable Obliga- tion Certificate (ROC) prices in a situation of ROC oversupply.