sou · GWB313d2 · 2009-01-01 00:00:00 — The queue management by National focuses on suggesting and discussing new flexible methods with the regulator to deal with the queue, i.e. not necessarily follow the approach first come first served but focusing on the progress of the various projects and allowing more generators access to the grid based on suggestions that are similar to the ones developed by the above mentioned TIRG working group. National is particularly focusing on matching progress in the development of generator projects with transmission network upgrades which can only be achieved with regular com- munication/milestones between applicant and National Grid.133 For grid access to the distribution system requiring transmission up- grades, the same method as described above applies regarding the transmission upgrades. In case the connection to the distribution system requires any distribution network upgrades, the applicant must 131http:///Networks/Trans/PriceControls/TPCR4/ConsultationDecisions Responses/Documents1/9139-28804.pdf 132http:///uk/Electricity/gb_agreements/gbqueue/ 133http:///NR/rdonlyres/47B95865-0225-45C2-B3BE-F753821B1E1B/ 18039/FinalConclusionpaper.pdf pay of the costs.134 These , less any relevant connection charge associated with reinforcement, would be recoverable by the DNO from the applicant over the assumed asset life of 15 years on an annuity basis, starting in the year after the expenditure has been incurred. In addition, the applicant must pay £1/kW/year to cover the on-going operation and maintenance (O&M) costs for the net- work upgrade and £1.50/kW/yr as additional fee to the network ope- rator related to the DNOs effort to connect the local generation. Ofgem has allowed the additional fee as well as the cost re- covery as an incentive for DNOs to connect distributed generation fast and efficiently.135 A connection is currently only possible after the necessary network upgrades in the distribution and transmission system. In addition, generators have to pay connection charges – inde- pendent of whether the connection has caused any network upgrade – and possible fees related to the transmission system, see also Section 4.8. 4.5Reservation of Transmission Capacity Within the Connection and Use of System Code (CUSC), a Trans- mission Entry Capacity (TEC) is defined which sets the generator's maximum allowed export capacity into the transmission system at any point during the financial year. The TEC is subject to the pay- ment of Use of System (TNUoS) charges calculated in accordance with the Statement of the Use of System Charging Methodology. The TEC is purchased for one year, but procuring TEC in one year gives the User a free option to secure the same level of access in the subsequent charging year. , as outlined in Section 4.2, distributed generation which has not signed the CUSC also has no TEC and therefore cannot use the transmission system, i.e. they have to sell the power within the distribution network. If a generator seeks additional TEC or a new generator seeks an initial allocation of TEC this may be done by completing an app- lication and sending it to National . If the TSO considers that 134http:///Markets/RetMkts/Metrng/Metering/Documents1/8944-26504 135http:///Networks/ElecDist/Policy/DistGen/Documents1/15939-193_ 06.pdf the additional generator capacity will require network reinforcement for its system to continue to comply with its security standards, National will typically provide a connection offer on an invest- then-connect basis. However, there is also an alternative way, i.e. if somebody holding TEC wishes to sell, parties can negotiate bilaterally the purchase of TEC.136 4.6Costs Associated with the Connection to the Application fees are payable in respect to applications for new connec- tion agreements based on the reasonable costs transmission licensees incur in processing these applications. Users can opt to pay a fixed price application fee (derived from analysis of the historical costs of similar applications) in respect of their application or pay the actual costs incurred. The fixed price fees for applications are detailed in the Statement of Use of System Charges.137 An example of selected fixed application fees is shown in Table 4-1. If a user chooses not to pay the fixed fee, the application fee will be based on an advance of transmission licensees and out-of pocket expenses and will vary according to the size of the project and the amount of work involved. Where actual expenses exceed the advance, National will issue an invoice for the excess. Conversely, where National does not use the whole of the advance, the balance will be re- funded. Also distributed generators which want to use the transmission system, see Section 4.2, have to pay transmission connection charges. 136http:///uk/Electricity/Codes/systemcode/tectrading/ 137http:///NR/rdonlyres/65364814-0D47-482A-8B9E-EB32BA5C3259/ 7871/UoSCI2R1Final4.pdf Table 4-11: Fixed Prices for New Bilateral Agreements.138 Fee (£000) (as table C) If a generator connects to the distribution system and is not using the transmission system, it only has to pay the reasonable costs that DNOs incur in processing the application. The connection charging methodology can be defined by each DNO but must be approved by Ofgem.139 If the generator is using the transmission system, the applicant must pay distribution and transmission connection charges. Annual connection charges are discussed in Section 4.8. 138http:///NR/rdonlyres/65364814-0D47-482A-8B9E-EB32BA5C3259/ 7871/UoSCI2R1Final4.pdf 139http:///Networks/ElecDist/Policy/DistChrgMods/Pages/DistChrg 4.7Costs and Obligations Related to Metering Typically any generation asset must have half-hourly import/export metering installed. Microgenerators (<30 kW) are not required to install half-hourly metering, i.e. they are only required to install an import/export meter if they wish to sell their exports to a supplier. Similarly, any generator eligible for Renewable Obligation Certifica- tes (ROCs) and interested to collect ROCs needs half-hourly im/ex- ports metering if the export can be higher than 16 amps/phase.140 Renewable generators with less than 16 amps/phase export capacity do not need half-hourly im/exports metering but a yearly import/ex- port meter. If all or part of the electricity that is generated is used on-site by the operator of the generating station, it may be eligible for ROCs. In order to claim ROCs for eligible electricity used on-site, the operator of the generating station needs to measure the power out- put as described above and sign a declaration (a Permitted Ways declaration) and submit this to Ofgem each year. electricity consumption of the generator must be deducted from the gross generation. Net-metering is currently not allowed but some DNOs un- officially accept it. Regulatory changes related to net-metering are under discussion. The annual connection charges are individually calculated for each connected asset. The calculation considers the maintenance and trans- mission running costs including site-specific maintenance costs and may include costs for upgrading the connection point, but no costs related to transmission network upgrades. The details of the cal- culation method are outlined in the Statement of the Connection Charging Methodology from April 2007.141 140http:///Networks/ElecDist/Policy/DistGen/Documents1/15939-193_ 06.pdf , April%202007%20Final%20Large.pdf and Environmnt/RenewablObl/Documents1/small%20generator%20guidance_7707.pdf 141http:///NR/rdonlyres/538B0362-162B-4CE1-9483-27B3FDADF 4C2/16068/GBCCMI3R0FINAL.pdf Transmission use of System Charges Use of System (TNUoS) charges reflect the cost of installing, operating and maintaining the transmission system for the Transmission Owner (TO) and must be paid by all users that have signed the Connection and Use of System Code (CUSC), see also Section 4.2. , all generators connected to the transmission system as well as most distributed generators have to pay TNUoS charges. In National introduced a DC Loadflow (DCLF) ICRP based transport model for the and charging methodology. The DCLF model has been extended to incorporate Scottish network data with existing and network data to form the GB network in the model. The gene- ration TNUoS depend now on the area in which the generator is connected, see also Figure 4-15. The demand charges depend on a similar zonal approach but the zones are not identical with the zones for generators. The underlying rationale behind the TNUoS charges is that efficient economic signals are provided to users when services are priced to reflect the incremental costs of supplying them. Therefore, charges reflect the impact that users (generators and consumers) of the transmission system at different locations would have on the transmission owner's costs, if they were to increase or decrease their use of the respective systems. These costs are primarily defined as the investment costs in the transmission system, maintenance of the transmission system and maintaining a system capable of providing a secure bulk supply of energy. Figure 4-14: Generation Use of System Tariff Zones as at (Geo- graphical).142 142 7871/UoSCI2R1Final4.pdf, page 8 One special treatment exists for small generators in which are eligible for a reduction in the listed Generation TNUoS tariffs. This discount has been calculated in accordance with direction from the Authority and equates to of the combined generation and demand residual components of the TNUoS tariffs. The details of the calculation method for the TNUoS are outlined in The Statement of the Use of System Charging Methodology143 from 2007 and the current calculation method in the The Statement of Use of System Charges.144 Use of System charges The TSO recovers the costs of balancing the System through Use of System (BSUoS) charges. The BSUoS charges have to be paid by all parties that have signed the Balancing & Settlement Code, see also Section 4.2. The Statement of the Use of System Charging Methodology includes a detailed methodology for the calculation of daily BSUoS charges, some working example, and information on BSUoS charge settlement.145 Each DNO licence holder has the obligations to have in place three charging statements:146 the statement of Use of System (UoS) charging methodology, the statement of UoS charges and the connection charging methodology. The connection charging methodology outlines the method by which connection charges are calculated. 143http:///NR/rdonlyres/33828A47-C4A4-490B-AF7C-25E6E8D7 C1DC/17924/UoSCMI3R1FINAL_BSUoSandCAP142_2.pdf 144http:///NR/rdonlyres/65364814-0D47-482A-8B9E-EB32BA5C3259/ 7871/UoSCI2R1Final4.pdf 145http:///NR/rdonlyres/33828A47-C4A4-490B-AF7C-25E6E8D7C1 DC/17924/UoSCMI3R1FINAL_BSUoSandCAP142_2.pdf 146http:///Networks/ElecDist/Policy/DistChrgMods/Pages/DistChrg The proposed methodologies of each DNO will be reviewed and approved by Ofgem. As many charging methods are rather old, Ofgem is pressing the distribution companies to develop charging models that reflect the benefits and costs of distributed genera- tors.147 As an example the Use of System Charging Methodology of Distribution is here considered.148 According to this method, generators connected prior to will have to pay no UoS charges as they paid a higher connection charge to direct- ly cover the required deeper connection assets. The situation post- 2010 is still under review and no decision has yet been taken. Generators connected from will have paid a lower con- nection charge to cover the shallower connection assets and hence a separate UoS charge to cover reinforcement costs will be imple- mented in respect to the electricity that the generator exports to the system. The calculation of the UoS charges includes: Annuity pass-through calculation, which is based on a pass- through of the network reinforcements costs caused in the distri- bution network by the generator (cost recoverable by the DNO from the applicant over the assumed asset life of 15 years on an annuity basis); OR&M – based on an allowance for each kW of installed gene- ration capacity (£1/kW/year); Revenue Driver – based on an allowance for each kW of in- stalled generation capacity (£1.50/kW/yr) NGC Exit charges to the transmission network– a proportionate share of the NGC Exit charges apportioned on an agreed capa- city basis. , distributed generators which did not cause any network up- grades and are not using the transmission system will only be charged the revenue driver (£1.50/kW/yr), which was created by Ofgem as an incentive for DNOs to connect as much distributed generation as possible in an economic and efficient way. 147http:///Networks/ElecDist/Policy/DistGen/Documents1/15939-193_ 06.pdf 148http:///lib/liDownload/566/NEDL%20Use%20of%20system% 20charging%20methodology%20v1_8.pdf 4.9Rights and Obligations Regarding Real Time Operation Renewable energy is treated exactly the same way as conventional generation in the UK, i.e. renewable energy has the same rights and obligations as other forms of generation. Renewable generation can in principal participate in all ancillary service markets if it fulfils the technical requirements outlined for the different ancillary markets by National Grid.149 However, as renewable energy generation will only receive the ROCs for the actual electricity produced, renewable energy generators typically have interest to participate in any market that may result in a reduction of power output, such as markets related to frequency control. The UK has a Renewable Obligation scheme which came into force in . 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 Obligation is guaranteed in law until 2027. The certificates can be sold separately from the electricity to which they relate, i.e. suppliers can purchase these certificates in order to fulfill their obligation. This allows for open trading of certificates. To fulfill their obligation, suppliers can either present enough certificates to cover the required per- centage of their output, or they can pay a buy-out price for any shortfall. The Buy-Out price was set at £30.00 per MW/h in 2002/03 and increases each year by the Retail Price Index (RPI). The period 05/06 had a buy-out price of £32.33, the price for 07/08 is £34.30 per megawatt hour (MWh). All payments are back- channeled to suppliers in proportion to the number of ROCs they present. The certificates are currently traded at 48.12 £/ MWh (68.92 /MWh), which results in some of the highest payments for renewables in Europe. size limit in the regulations for renewable energy? In the UK, there are capacity limits for generators connected to the distribution grid regarding the payment of Transmission Net- work Use of System charges (TNUoS). These limits vary between different areas in the UK, but in most cases the limit is 50 MW in and and 30 MW in the trans- mission area and 10 MW in the Scottish Hydro transmission area. Most generators connected to the distribution network with a capacity below these limits are exempted of TNUoS in recogni- tion of the reduced demand in a zone served by the transmission system. However, generators that have been connected to the distribution network after have to pay Use of System charges if their connection required a distribution network upgrade. Use of System charge should then recover some of the network upgrade costs. In the UK, generators pay network tariffs (known as Use of System charges) if they are connected to the transmission system. The charges do not distinguish between renewable energy and conventional energy, but they vary based on the location of the connection point. , the connection charges to the trans- mission grid are high in , which has low load but many generation sources, and low (in some cases even negative) in South which has high load and limited local generation sources. In addition, small power stations connected to the distri- bution network, independent of their technology, do not have to pay Transmission Use of System charges (See above). In prin- ciple, power stations are defined as small if they have a total capacity of up to 50 MW in and , up to 30 MW in the transmission area and up to 10 MW in the Scottish Hydro transmission area. However, generators that have been connected to the distribution network after and which have caused reinforcement on the distribution grid have to pay Use of System charges. In the UK, costs for transmission upgrades are typically socialized. In principle, transmission reinforcements are only performed if sufficient requests for network connections are submitted. How- ever, this approach leads to long delays in cases where strategic works are needed. Recognizing this, the regulator Ofgem recently approved £560 millions for for Re- newable Generation. When it comes to upgrades in the distri- bution grid, producers in the UK connected to the distribution network after the , have to pay a Distribution Net- work Use of System charge (DUoS) which generally reflects the upgrading costs for the exclusive use of the generator. For connections to the distribution grid prior to , costs for distribution network reinforcement were charged upfront. In the UK, the creation of independent Offshore Transmission Owners (OFTO) are proposed. The OFTO would be selected by competitive tender and awarded a transmission licence which enables it to receive a regulated revenue stream in return for meeting its licence obligations for a predetermined regulatory period (20 years), and would be incentivised to achieve specified performance requirements during this period. OFTO would have the responsibility for designing, , financing and main- taining the offshore transmission network required to connect an offshore generator. Ofgem has licensed 13 distribution network operators (DNOs) in the UK (14 including Northern ) each responsible for a distribution service area (similar to a concession area). DNOs came into existence on 1 October 2001, evolving from ex-Public Electricity Suppliers. In addition there are four independent licensed network operators that own and run smaller networks embedded in the DNO networks, called Independent Distri- bution Network Operators (IDNO). An IDNO is any electricity distributor with a license granted after 1 October 2001. 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 developments. IDNOs do not have general distribution service areas. Finally, privately-owned unlicensed networks may operate within existing distribution networks. Advantages include exemption from some license charges and reduced energy loss in transmission. Ports and large industrial users often operate with private wire networks. All potential applicants, renewable energy generators or conven- tional generators, are treated equally in the connection process. There are very detailed network connection procedures in the UK, with detailed time lines and definitions of the relevant fees. The procedures were developed by National , the transmission system operator and reviewed and approved by the regulator Ofgem. applicant that wishes to connect directly to the trans- mission system will be offered to enter into a Bilateral Connec- tion Agreement (BCA) with National within 3 months of application. customer wishing to connect to a distribution system should initially contact the Operator in its area to discuss the proposed connection. For the type of interconnection agreement, the size of the power station and its location is important. Typically any generation asset must have half-hourly import/ex- port metering installed. Similarly, any generator eligible for Re- newable Obligation Certificates (ROCs) and interested to collect ROCs needs half-hourly im/exports metering if the export can be higher than 16 amps/phase. Renewable generators with less than 16 amps/phase export capacity do not need half-hourly im/exports metering but a yearly import/export meter. 5 Summary of Findings The following sections provide a brief comparison between , , , , and regarding issues that are important for . In the following chapter, we refer to , , and as the four studied countries. Each section starts with a table comparing the situation in and in the four studied countries, followed by a brief analysis of the differences and similarities between the different countries. At the end, we will present the conclusions. This section focuses on wind power and solar photovoltaics since these energy sources have had a remarkable increase in the four studied countries. For details on other types of renewable energies for the studied countries, please see the country-specific chapters. Table 5-1: Comparison of renewable energy regulations and its impact on wind power and solar photovoltaic development (market price + Feed-in tariff: 77.73 Market option: 91.01 (Premium 31 plus (buy out: 47.9) [/MWh] 2006 [MW] end 2006 [MW] 2006 [/MWh] Capacity[MW] PV added in 2006 150TP PT In addition, wind power producers on-shore with installations on place before the imple- mentation of the electricity certificate system in 2003 received an environmental bonus equal to 7 /MWh which corresponds to an average total payment of 76 /MWh. This system based on environmental bonus is being phased out and will be removed after 2009. Based on information, an exchange rate of /EUR has been used. 151TP rate of 1£ = . 152TP PT This payment is obtained when selling the production to the grid which is done only by a few installations (less than 5). Commonly in , solar photovoltaic installations use their electricity production to reduce their own consumption and not to sell it to the grid since the network costs (including compensation for reduction of network losses) to be able to inject electricity to the grid are typically higher than the payment they receive. When re- ducing their consumption, the payment can be assumed to be equal to the cost of electricity which is about 110 /MWh for domestic consumers. It is important to take into account when comparing different pro- motion schemes for renewable energies that each country has spe- cific national conditions that can be very different. This means that different promotion schemes may be needed to get the same power production. For example, the average wind conditions in are quite low, in 2006 each installed MW wind power generated on ave- rage an electric power of 1,560 MWh. In the same year, in each installed MW corresponded to a power production of 2,160 MWh, while in each installed MW generated 1,850 MWh and in the UK 2,780 MWh on average. The values shown in Table 5-1 regarding Total Payment Level 2006 for , UK and (market option) are exceptionally high since electricity market prices in these countries were exceptionally high during 2006. This must be kept in mind when comparing the payment levels between the different countries. Table 5-1 shows that in 2006 wind power producers in the UK re- ceived the highest payments and wind power producers in received the lowest payments. However, wind power producers in that have been producing for more than five years received lower payments than wind power producers in . When it comes to solar photovoltaics it is very clear that the feed-in systems in , and give much higher incentives than the certificate systems in and the UK. For photovoltaics, is the country with the highest payment among the studied countries and also with the largest installed capacity. Table 5-1 also shows that the promotion scheme in , and is based on feed-in tariffs which are defined for the different types of renewable energies.