sou · GWB313d2 · 2009-01-01 00:00:00 — 16,175,906 Total number of ROCs 4,973,091 6,914,524 9,971,851 12,232,153 Percentage obligation met by Total buy-out paid/ £79,251,930 £158,466,502 £136,169,914 £127,167,900 What a ROC was worth to a Table 4-7 lists the detailed prices for ROCs from 2002 to 2007. 116 When combined with the buy-out price that suppliers effectively avoid paying by pre- senting ROCs, a ROC produced against the RO was "worth" £42.54 to suppliers in 2005-06. Table 4-8: ROC prices from 2002 to 2007 based on e-Roc auctions. (Exchange rate Sept 2007) 2,856,330 Figure 4-11 provides an overview of ROCs issued by technology type in 2006 (, , and Northern ). As can bee seen landfill gas generation attracted just of the total ROCs issued in 2005–06, which is comparable to the share it received in 2004–05 (). Co-firing generating stations received of total ROCs with on-shore wind receiving . Figure 4-11: Breakdown of ROCs issued by technology type in 2006 (, , and Northern ).117 When the RO was first introduced, the most prevalent technology type (in terms of the number of accredited generating stations) was landfill gas with 202 projects accredited at . The most prevalent technology in the 2005–06 obligation period in terms of the number of stations and capacity was on-shore wind with 63 sta- tions (630 MW) being accredited, see also Figure 4-12. Co-firing and on-shore wind stations made up around 70 per cent of the total renewable capacity installed and accredited under the RO in 2005– 06 obligation period. Figure 4-12: Eligible capacity by technology in kW. (, , and Northern ).118 D. Renewables Obligation 2008 and Beyond Subject to Parliamentary approval, further changes will be made to the Renewables Obligation () Order to introduce a (MSO), i.e. a supplier who supplies in will be obliged to meet a certain supply with ROCs issued to generating stations that generate electricity from wave and tidal devices. Furthermore, some key changes are proposed to be implemented in 2009 (see also Section 4.1.3) such as:119 to brand the RO to provide differentiated levels of support for different technologies; to introduce a mechanism intended to maintain Renewables Obli- gation Certificate (ROC) prices in a situation of ROC oversupply. 119http:///files/file34470.pdf, also whitepaper/consultations/renewables-obligation/page39555.html Table 4-9 provides an overview of the proposed new support levels for different technology bands. Under this proposal established technologies such as landfill gas would only receive 0.25 ROCs per MWh generated while post demonstration projects would receive 1.5 ROCs per MWh and emerging technologies, such as wave or tidal energy, would get 2 ROCs per MWh. Overview of proposed bands. Sewage gas; landfill gas; co-firing of non-energy crop (regular) biomass Onshore wind; hydro; co-firing of energy crops; Offshore wind; dedicated regular biomass ; tidal stream; advanced conversion technologies (anaerobic digestion, gasification and pyrolysis); dedicated biomass burning energy crops (with or without CHP), dedicated regular biomass with CHP; solar photovoltaics; geothermal 4.2Application Procedure for Access and Connection to the Anyone interested in connecting to the different transmission systems in the UK needs to get in contact with National , the trans- mission system operator. Figure 4-14 outlines the connections pro- cess. Figure 4-13: Process for connection to the transmission system in the UK.120 120 14355/NationalGridconnectionprocessv10.pdf All potential applicants, renewable energy generators or conven- tional generators, are treated equally in the connection process. applicant that wishes to connect directly to the transmission system will be offered to enter into a Bilateral Connection Agreement (BCA) with National within 3 months (i.e. in box NGET issues the offer to the applicant in Figure 4-13) of application121. The BCA Agreement sets out the provisions for generators to comply with the Connection Use of System Code (CUSC), and Balancing & Settlement Code as well as defining the terms of the arrangements for connection to the transmission system. The agreement also sets out provisions for any balancing services as with this type of agreement will be actively participating in the electricity balancing market. The relevant application fees are discussed in Section 4.6. Queue management, i.e. handling of large numbers of connection applica- tions is discussed in Section 4.4. 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. The size is dependent on the network area, i.e. in which Transmission Owners network the site is located, see below: Transmission Owner - National : Medium <100 =>50 MW Transmission Owner - : Transmission Owner - Scottish Hydro: 121 agreements/ FDADF4C2/16068/GBCCMI3R0FINAL.pdf Small or medium sized power stations that do not wish to have access rights to the transmission system do not need an agreement with the to facilitate their connection. all agreements will be with the Operator. Large generators that want to connect to the distribution system in can choose between obtaining a Bilateral Embedded Generation Agreement (BEGA) or a Bilateral Embedded License Exemptable Large Station Agreement (). Large gene- rators that want to connect in and can only apply to National for a BEGA agreement. This is because a can only be signed by a customer that is classed as a large power station and exempted from obtaining a generation license. In & however a large power station is equal to or greater than 100 MW, and only power stations between 50-99.9 MW can apply to () for exemp- tion from holding a Generation license.122 The key difference between BEGA and is that only gene- rators that have signed a BEGA agreement have the right to use the transmission system and have to pay Transmission Use of System charges. Bilateral Embedded Generation Agreement (BEGA) The BEGA Agreement sets out the provisions for generators to comply with the Connection Use of System Code (CUSC), and Balancing & Settlement Code. This agreement will be offered to that have requested access to the GB Trans- mission System, but that are not directly connected to the GB Trans- mission system. This type of agreement is therefore applicable to embedded (distributed) generators that wish to export to the GB Transmission system. The BEGA will also provide the customer with Transmission Entry Capacity (TEC), see also Section 4.5. The agreement also sets out provisions for any as the agreement gives the customer rights to operate in the energy balan- cing market. 122 The application procedure and deadline is identical to transmission application, see also Figure 4 14. Bilateral Embedded Licence Exemptable Large Station The sets out the provisions for generators to comply with the CUSC and . This agreement does not commit users to adhere to the Balancing and Settlement Code as a does not give the customer rights to operate in the electri- city balancing market, i.e. another party may be responsible for the output under the CUSC and BSC. According to the distribution network licence requirements, the distribution network company must follow the deadlines for the connection application as outlined in Table 4-10. Table 4-10: Overview of deadlines for distribution companies related to con- nection applications.123 Provide a quotation for a new generation connection where the highest voltage of the assets at the point of connection and any days of receiving the associated works is not more than one kilovolt. Provide a quotation for a new generation connection where the within fifty working days highest voltage of the assets at the point of connection and any of receiving the request associated works is more than one kilovolt but not more than 22 Provide a quotation for a new connection that is not included within three months of within the preceding categories. Information and design submissions Provide the technical information necessary to enable the applicant to identify the proposed location and characteristics of the point of connection of the premises to the licensee's distribution system, where the highest voltage of the assets at that point or any associated works is more than 22 kilovolts but not more than 72 kilovolts In response to a design submitted for low voltage and high voltage connections by the applicant, outlining a new proposal for connecting premises to the licensee's distribution system, provide a written approval of the proposed design, or a written rejection stating reasons for rejection. within thirty working days of receiving the request within ten working days of receiving the proposed design (unless any part of it would require the use of extra high voltage assets) 123 searchable%20Licence%20mod.pdf In response to a design submitted for an extra high voltage connections by the applicant, outlining a new proposal for days of receiving the connecting premises to the licensee's distribution system, provide a written approval of the proposed design, or a written rejection stating reasons for rejection. Final works and phased energisation Complete the final works for a low voltage connection. within ten working days of receiving the request Complete the final works for a high voltage connection. days of receiving the Inform the applicant of the date by which it is proposed to complete the final works for an extra high voltage connection. within twenty working days of receiving the request (and complete the works as soon as reasonably practicable) Complete low voltage phased energisation works within five working days of receiving the request Complete high voltage phased energisation works. within ten working days of receiving the request The relevant applications fees are discussed in Section 4.6. 4.2.1Definition of the Capacity of a Production Installation While other countries have certain clear definitions what maximum capacity can be connected to which voltage level, there are no such definitions in the UK. The actual capacity that can be connected to a certain voltage level depends only on the technical feasibility. As seen in the last chapter, regulations in the UK include the option that generation units larger than 100 MW are connected to the distri- bution system. The Electricity Act of 1989 Section 4(1) introduces a system of licensing for electricity generators, which allows connection to the power system and entry to the electricity generation market. generation of electricity without a license is expressly prohibited in the Electricity Act, however Section 5(1) of the Electricity Act provides that the Secretary of State may, by order, grant exemption from Section 4(1)(a). Section 5(2) of the Electricity Act sets out the procedure for making such an order. On 1 October 2001, the Electricity Class Exemptions from the Requirement for a License Order 2001 (the Class Exemptions Order) came into force.124 Among other things, this Order exempts small generators that do not at any time provide more electrical power from any one generating station than: 1)10 megawatts; or 2)50 megawatts in the case of a generating station with a declared net capacity of less than 100 megawatts 3)as well as offshore generators and on-site (= consumer side of meter) generators. Generation units between 50 MW – 100 MW, including renewable generation, need a license. However, typically the Secretary of State grants exemption from section 4(1)(a) based on Section 5(1) for re- newable generators larger than 50 MW, for instance for wind farms.125 , it is quite common for the capacity of a distributed gene- ration project to be set at or limited to 99 MW to avoid requiring a license.126 The generators that need a license must apply to Ofgem for the license. All generators that wish to become a licensed generator will be required to become parties to the BSC, the , the CUSC (for transmission system) and/or the distribution code and must comply with the BSC, the and the CUSC and/or distri- bution code.127 It is important to emphasize that unlicensed generators operate in a very different commercial environment to their licensed counter- parts. Generation licensing affects both trading arrangements and a distributed generators relationship with the transmission system. For example, a licensed generator has to be party to the Balancing 124http:///content.aspx?LegType=All+Legislation&title=The+ Electricity+(Class+Exemptions+from+the+Requirement+for+a+License)+Order+2001 125See for example and document_fetch.php?documentid=9358 as well as electricity-markets/license-exemp/page34529.html 126http:///Networks/ElecDist/Policy/DistGen/Documents1/15939-193_ 06.pdf 127http:///Licensing/Work/Documents1/5660-Electricity%20Generation %20handbook.pdf and Settlement Code. This defines and describes the trading arrange- ments for a generator selling their electricity into the market. More- over, a licensed generator also has to enter an agreement with the transmission system operator National for using the trans- mission system. An unlicensed generator avoids the costs and burdens associated with the Code and the need, in most cases, for an agree- ment with NGET. Unlicensed distributed generators also potentially have access to embedded benefits. These reflect the fact that distri- buted generators have a shorter delivery path to consumers. Under current arrangements, an unlicensed generator is effectively treated as negative demand on the system and the electricity they generate is not subject to National Grids charges relating to the use of the transmission system. In addition Ofgem is responsible for licensing transmission net- work operators, distribution network operators and independent distribution network operators. 4.3Obligations of a Regarding The transmission license conditions state the following obligations:128 not to discriminate between any persons or class or of per- sons in providing use of the GB system or in carrying out works for connection; to offer terms for connection to and use of the GB system or for the modification of an existing connection within three months of application; to offer terms for use of the GB system only within 28 days of application; that compliance with the Connection Charging Methodology facilitates effective competition in the generation and supply of electricity and (so far as consistent therewith) facilitates com- petition in the sale, distribution and purchase of electricity; 128 F4C2/16068/GBCCMI3R0FINAL.pdf , the transmission system owners have to treat renewable energy and conventional generators equal in regards to connection and have to offer a connection when technically feasible (see also Section 4.4). Similar conditions are outlined in the DNOs licenses, i.e. the distribution network operators are required to offer connections to any generation within a set timeframe. The DNOs design these con- nections to ensure that the distributed generator does not cause the quality of electricity supply to fall below agreed standards, poten- tially affecting other generators and . However, a recent Ofgem document states that despite progress in recent years, some argue it is still time-consuming and resource-intensive for distributed generators to obtain a cost-effective connection and that this remains a barrier to the development of distributed generation.129 Finally, private networks do not need a license, hence the regu- lator cannot put any obligations on these networks. 4.4Grid Access, Available Capacity and The Connection and Use of System Code (CUSC) sets out the standard commercial terms between the TSO and users of the trans- mission system. This is supplemented by a number of bilateral agree- ments, including construction agreements, which set out works required to accommodate a users access rights. The CUSC uses the concepts of Transmission Entry Capacity (TEC). TEC reflects the capability of the wider transmission system and defines the users access rights to the transmission infrastructure, i.e. a generator cannot export more than its TEC. Generators can ask the TSO to offer terms for connection to and/or use of the transmission system at any stage of their gene- ration project (provided that sufficient data can be provided to the TSO about the proposed development). The available transmission capacity will be calculated by the TSO (in cooperation with the transmission owners) using certain technical aspects (N-1 criteria, for instance) and will consider all power plants that have already accepted an offer for connection, i.e. the TSO follows the approach first come first served. In case the requested network capacity is not available, the TSO will offer terms for connection based on an invest then connect approach. The TSO will detail in its offer, the works on the transmission system that are required to provide connection to and/or use of the transmission system. The connection date offered reflects the customer's request but also the time required to complete transmission system works (con- nection and/or system reinforcement works). In general, connections will not be made until transmission system reinforcement works are complete. However, there have been circumstances where the TSO has been able to agree with specific arrangements to facilitate an earlier connection date on a constrained basis (i.e. their access may be limited without compensation). The key part of the offer from the TSO that includes transmission network upgrades is the construction agreement. The construction agreement sets out the provisions for construction or modification of a direct connection to the GB Transmission system or to facili- tate the connection of embedded generation. The construction agree- ment will primarily set out the responsibilities of each party and the timescales and key milestones in which each party are required to complete each of their areas of work. Furthermore, the construction agreement provides the necessary financial security that a party must provide to secure against the cost of the appropriate works. Initially, generators that had entered into a contractual agreement with the TSO were required to provide finan- cial security against the transmission system reinforcement works identified in its bilateral agreement. The financial security regime ensures that the TSO and its (consumers) are protected from the risk of stranded assets if the project does not go ahead, i.e. the applicant only has to pay for the network upgrade if the project is not going ahead. If the project is going ahead as planned the network upgrade costs are socialized, i.e. recovered via network tariffs paid by all . However, such financial security regime caused a lot of problems particularly for groups of smaller, renewable generators. , the approach was changed and currently applicants must provide a finan- cial security equal to a certain share of the overall investment – typi- cally 2 years of the expected Use of System charge. In addition, they have to prove to the TSO that the project completes certain milestones so that the TSO can be sure that the project is going ahead as planned. The situation, however, is not considered satisfactory. Therefore Ofgem has started a cross-governance working group named () for developing other alternatives. ARODG has proposed the following general options regarding transmission network access:130 short term access arrangements; access trading arrangements; development of a Spill product to allow projects to connect and operate without enduring access rights. These suggestions reflect that intermittent renewable generation (principally on-shore and offshore wind, but also wave and tidal generation), which are often built in locations that currently have or no transmission network, do not require a level of transmission capacity, but need access when their primary fuel (e.g. wind) is available. A number of selected options developed by ARODG are listed below: An Interim TEC product would allow users to use the trans- mission system in all but a specified number of periods. During these periods, the TSO would be able to curtail a user at zero bid price, or the generator would be required to declare down its output. (This option might already be implemented at the end of 2007); Deemed Access Rights to the for Renewable Generators would allow a renewable generator to export onto the system without wider transmission system re- inforcements needing to be in place. Where there is insufficient transmission capacity, it is proposed that other non-renewable generators are constrained off the system first to enable priority access for renewable generators with a new access product, Deemed Transmission Entry Capacity (DTEC). The constraints that would be incurred as a result of taking conventional gene- rators off the system to make way for renewable generators would be funded from Use of System (TNUoS) 130 and ionAccess(ARODG).aspx charges and not Use of System (BSUoS) charges. (Proposal is currently discussed at the working group stage); Transmission Entry Capacity with restricted access rights (TEC-lite) would give only restricted access to the transmission system for new users. TEC-lite would confer different rights to use the transmission system rather than full TEC, and on this basis, those proposing this approach consider that transmission charges would be lower. (Proposal currently at the working group stage); TEC Transfer – arrangements to further facilitate the transfer of previously allocated transmission access rights between power stations; Extra TEC () – the TSO would identify additional trans- mission access available in operational timescales, which could be purchased before real time and priced ex-ante on a cost-reflective basis. Overrun (with ex-post pricing) – this would involve creating arrangements to allow power stations to generate above their TEC, charged on usage and priced ex-post on a cost-reflective basis. Shared TEC (subject to discussion) – TEC would be shared be- tween two nodes. The primary party has TEC liability, and the secondary party has rights through a bilateral contract. Charges would be calculated on a cost-reflective basis as a multiple of TEC. A number of new connection applications can trigger wider reinforce- ment works (sometimes called deep) on the transmission system, i.e. more than one project can be dependent on a specific set of transmission system reinforcement works. This can result in a 'queue' of projects dependent on major network reinforcements such as most network upgrades between and . to the costs and number of possible projects involved it is very complicated to include such projects in project-specific construction agreement. , it was decided that certain transmission upgrades are plan- ned and financed via the for Renewable Generation (TIRG) mechanism.131 to large numbers of applications for grid access, largely in , a queue management discussion has emerged in the UK.132 150, mainly renewable projects, totaling around 12 GW of generating capacity, currently seek connection in where the network is already constrained. Many of these projects emergerd at an early stage of development in order to take advantage of transitio- nal arrangements under the sion Arrangements (). In all likelihood, only a proportion of the projects currently in the queue will actually connect to the network. The most significant factor is likely to be whether the generator obtains planning consent, but other commercial and tech- nical factors may contribute. The large majority of projects in the queue do not yet have the necessary consents.