Scottish Hydro Electric Transmission Limited Keeping the lights on and supporting growth A consultation on our plans for the next decade
Contents
Executive summary 1 3. Investing for a greener future 16 Key questions 16 1. About this consultation 2 How we plan the network to meet 17 users’ needs Background 2 Our initial views on generation that 18 Price controls 3 might want to connect to our network Transmission price control 3 Our initial views on the 21 from 1 April 2013 reinforcements we might need to This consultation 4 accommodate renewables Factors that will influence our 28 2. ‘Business as Usual’ – 5 investment decision keeping the lights on Managing the uncertainties to 30 Key questions 5 minimise costs to customers 31 Maintaining and investing in our 6 Delivering the local connection works existing network Identifying the necessary connection 31 Delivering a reliable service to our 10 works customers Funding connection works 32 Keeping our customers, our 11 colleagues and our network safe 4. How we recover our costs 34 How we manage the environment 12 we work in 5. How our future transmission plans 37 Innovation in our planning for the 15 might impact on customers’ bills future Key question 37
Contact details 40 A consultation on our plans for the next decade
Executive summary
Scottish Hydro Electric Transmission In contrast, we expect to significantly Limited (SHETL) is the licensed electricity increase expenditure on expanding the Transmission Owner (TO) in the north of network to facilitate the growth Scotland. As the regional monopoly in this of renewable generation in the north activity, SHETL is regulated by the Gas and of Scotland to meet the UK renewable Electricity Markets Authority through a energy targets. ‘price control’. Amongst other things, this The potential scale and timing of this determines the amount of revenue SHETL investment is not fixed. Nevertheless, is able to earn from users of the network our forecasts indicate that the size of the to cover the efficient cost of maintaining SHETL network could increase by some and developing the transmission system. £3 – £4 billion compared to the value of the The next price control period will be from existing business of around £400 million. 2013 to 2021. We therefore need to develop The day to day cost of running and a robust business plan that identifies the maintaining the network assets is forecast activities and associated costs that require to rise by a factor of around three or four funding over that eight-year period. times the current level. Again the increase The purpose of this consultation paper is driven by the scale of investment forecast is to seek views from a wide range of to facilitate the growth of renewable stakeholders who have, or may have generation in the north of Scotland leading in the future, an interest in our activities. to an increase in size and complexity of Your views will help us to develop our the network. business plan. The cost of these initial proposals is up We have provided an overview of our to £4 per customer. proposed ‘business as usual’ activities This consultation paper provides and associated indicative, initial forecast stakeholders with an opportunity to expenditure. These activities include comment on, and thus influence, our investment to accommodate growth in proposed approach. demand and investing in our existing assets to maintain current levels of network performance. Expenditure on these activities is forecast to remain stable and similar to that experienced in recent years.
1 Keeping the lights on and supporting growth 1. About this consultation
Background Scottish Hydro Electric Transmission Limited (SHETL) is the licensed electricity Transmission Owner (TO) in the north of Scotland. SHETL owns the 5,000km high voltage electricity network of underground cables and overhead lines that serves the northern part of Scotland, and connects to central and southern Scotland and the rest of Great Britain. SHETL is responsible for maintaining and investing in this transmission network, which serves around 70% of the land mass of Scotland.
A consultation on our plans for the next decade
Figure 1.1: GB transmission licensees
Scottish Hydro Electric Transmission
Scottish Power Transmission
National Grid Electricity Transmission
SHETL is an asset owner, but does not Transmission price control from operate the transmission system. That is 1 April 2013 the responsibility of National Grid Electricity SHETL’s current price control was set Transmission plc (NGET), which acts as the to take effect for a five-year period from National Electricity Transmission System 1 April 2007 to 31 March 2012. Operator (NETSO). As NETSO, National Grid is also responsible for access to, and Over the past two years, Ofgem has charging for use of, the GB transmission undertaken a review of the way in which system. National Grid also owns the electricity and gas networks in Great Britain transmission system in England and Wales. are regulated - the ‘RPI-X@20’ review. This review concluded in October 2010 with the Figure 1.1 above shows the area of the publication of the final decision document transmission network that we own. It also ‘RIIO: A new way to regulate energy shows the area owned by Scottish Power networks’. In the document Ofgem explains Transmission Limited (SPT) and National Grid. that RIIO stands for ‘Revenue = Incentives + Price controls Innovation + Outputs’ and that an outputs- led approach to network regulation will be Electricity networks provide an essential used to set future price controls. physical link between electricity generators and electricity users. As such, the owners Under Ofgem’s RIIO model, regulated of networks have statutory obligations companies will need to consult with their including ensuring that they are able to customers and, from this, define the service provide an economic and efficient service levels or outputs they expect to deliver to generators who wish to connect onto going forward. The prices that they will their network. be allowed to charge for the use of their networks will be based on delivering those Electricity transmission businesses like service levels or outputs. The companies SHETL are natural regional monopolies. might face penalties for not meeting the As a result, they are regulated by the Gas defined standards, or secure rewards for and Electricity Markets Authority (Ofgem) exceeding them. More information about through a ‘price control’. Amongst other the ‘RPI-X@20’ review and Ofgem’s final things, this determines the amount of decision paper can be found on Ofgem’s revenue they are able to earn from network website: users and the framework for the capital investment they are able to spend in www.ofgem.gov.uk/Networks/rpix20/ maintaining and upgrading the networks. ConsultDocs/Pages/ConsultDocs.aspx SHETL cannot charge customers more than is allowed by Ofgem under the price control.
3 Keeping the lights on and supporting growth
Figure 1.2: Timetable
Initiation of SHETL Green Paper issued RIIO-T1 RIIO-T1 process implemented SHETL Green Paper responses
SHETL White Paper issued
SHETL White Paper responses
Jul 2010 Jan 2011 Aug 2011 Feb 2012 Sep 2012 Mar 2013
SHETL Business Ofgem – sets price control SHETL Plan submitted Pre-consultation process ends Ofgem – detailed assessment SHETL Business SHETL Plan finalised Pre-consultation Ofgem – fast track assessment starts
During the review process, Ofgem decided In September 2010 we wrote to stakeholders that the new regime should apply to the next seeking views on a number of potential transmission price control. However, since primary outputs for the new price control. the process and associated timeframes This pre-consultation stage has been very involved with setting a new price control helpful and we thank everyone who has take some time, Ofgem decided to delay taken the time to feed into the process so the application of the next transmission far. The views we have received have helped control by one year from April 2012 to April us in the development of this consultation 2013. The year 2012/13 is the subject of a and will be used, along with the responses separate process based upon a ‘rollover’ of we get to this consultation, in the ongoing the existing price control arrangements for development of our business plan. one year. In preparing this paper, we are conscious This consultation that there are a number of wider energy This consultation is associated with the industry issues under consideration such as price control that will be set for SHETL Ofgem’s project on transmission charging under the RIIO framework and which will (TransmiT); DECC’s Electricity Market apply from April 2013. The timetable for this Reform; and European legislative changes. consultation is set out in Figure 1.2 above. These issues are outside the scope of this The purpose of this consultation is to seek paper. However, changes in these areas the views of a wide range of stakeholders may impact our operations and users of our who have, or may have in future, an interest system which could change the assumptions in our activities. Your views are important we have adopted at this stage. to us and we will use them over the coming months to inform the development of the business case that we will put to Ofgem in July this year for funding for the eight-year period from 2013 to 2021.
4 A consultation on our plans for the next decade 2. ‘Business as usual’ - keeping the lights on
Key questions in this section Are the ‘business as usual’ activities we undertake appropriate? If not, what are your views on what additional activities we should be doing or what activities we should not be doing? Is the level of service we provide to our customers appropriate? If not, should we be providing a higher or lower level of service and, if so, to achieve what? Is your initial view of our expenditure over the next period reasonable, if not, what more, or less, should we be spending money on?
This section is about our ‘business as usual’ network activities that are essential to keeping the lights on in the north of Scotland.
Keeping the lights on and supporting growth
In this section we consider our approach to Maintaining and investing in the following in the context of the next price our existing network control period from 2013 to 2021: Most of what we do is looking after the • Maintaining and investing in our existing assets we already have to ensure that they network; provide as good a service as possible for as long as possible. There are three broad • Delivering a reliable service to our activities we undertake on a day-to-day customers; basis: • Keeping our customers, our colleagues • Investing in new assets to accommodate and our network safe; growth in demand; • How we manage the environment we • Investing in replacements for our existing work in; and assets to maintain network performance; • Innovation in our planning for the future. and We welcome views on any of the issues • The day-to-day running of and raised here, or anything else you feel we maintenance of network assets. need to take into account as we develop our The first two of these activities involve business plan. installing new equipment, for example at We consider how customers are connected substations or on overhead lines. This is to our network, and the investments we need because the existing equipment is either to make for those customers in section 3. inadequate for customers’ needs or is in poor condition and needs to be replaced. The third activity includes inspection, repairs and operation to ensure our network is looked after. Our expenditure on each of these activities over the past five years is shown later in this section.
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Investing in new assets to accommodate we comply with National Electricity growth in demand Transmission System Security and Quality of Supply Standard (NETS SQSS). The requirement to use our transmission This sets out the minimum criteria for the system comes from two sources: development and operation of the national • Users of electricity who are typically electricity transmission system. connected to the low voltage electricity • Connections to the transmission system distribution network such as domestic of new demand or generation, or households and commercial premises; modification to existing connections. This and also includes infrastructure investment • Exporters of electricity (generators) who to maintain compliance with standards. might be connected to the transmission • Investment to manage fault levels, system directly or indirectly through the voltage profile and transient stability on local distribution network. the transmission system. In this section we discuss electricity users’ In addition, we may be asked by the needs. We consider the needs of larger NETSO to undertake investment in our electricity generators in section 3. system to assist them in their operational Looking forward, we do not expect the requirements. demand for electricity in the north of Each item of primary plant and equipment Scotland to grow significantly. However, (overhead lines, cables, transformers, we do expect the volume of generation switchgear) is assigned a capacity rating. connected to the distribution network to We develop our system to ensure that no grow. With stable demand and growing items of plant or equipment are loaded ‘embedded’ generation, there will be an beyond their capacity, and that voltage overall reduction in net demand in the north profiles and stability on the system are of Scotland. Thus we expect we will need to maintained within defined limits. Forecast invest in new assets to accommodate this increases in demand and embedded change. generation are compared with transmission We go through a number of steps to assess capacity. Where reinforcement is deemed the need for investment in new assets to necessary, options are identified, evaluated accommodate demand changes. These and compared, before proposing a steps include: recommended solution. Reinforcements are carried out to ensure that there is no risk • Ensuring that there is sufficient of overload on the system for the secured capacity and resilience in the system to events defined in the NETS SQSS. accommodate the demand forecast using information supplied from the NETSO. This information includes forecasts for aggregation of small generators connected to the local distribution network. In doing this, we ensure that
7 Keeping the lights on and supporting growth
Figure 2.1: Load-related expenditure
25 Spend in £m
0 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21
We have applied these principles to the The foundation of our asset management period 2013 to 2021 and our initial forecast policy is the recognition of the need to of expenditure is shown in Figure 2.1 above, balance three main factors: cost, risk, along with our historic expenditure. and performance. Satisfactory network performance must be delivered at an Two specific reinforcement projects acceptable risk and within the constraints of account for the main increases in forecast efficient cost. In managing our assets, safety expenditure in 2013 to 2015: reinforcement issues are given priority. Historically, our works to address network needs arising investment proposals have been developed from the re-powering of Shetland; and to ensure that the level of network risk is reinforcement of the Keith-McDuff grid maintained at an acceptable level. supply group necessary to accommodate a growing cluster of generation connected to This category of expenditure is based on the local distribution network. our asset condition assessment processes and is mainly asset replacement or Many load-related schemes involve refurbishment of existing plant and circuits. replacing existing assets with higher capacity plant. As a result, assets may be We perform condition assessments on replaced before they are at the end of their equipment to determine remaining useful useful lives. However in replacing the assets life and replacement needs. This has been on this basis, a future need to replace them incorporated into our established Network on a condition basis is deferred. Where it Output Measures Methodology, which also is worthwhile, recovered assets are re- describes how the criticalities of assets are deployed elsewhere on the system, or held assessed. Criticality is a representation of as strategic spare stock. the risk to stakeholders in terms of safety, environment and reliability. Investing in replacements for our existing assets to maintain network performance We consider both condition and criticality in developing a prioritised asset replacement We are constantly aware of our ongoing programme. Condition assessments are responsibility to keep our network in good carried out every two years by field staff. order. We also consider fault performance, spares Our policy for managing the transmission and obsolescence, safety, and age. assets is assessed and certified as meeting From our initial analysis, and to maintain the Publicly Available Specification 55 the same level of risk and performance, (PAS55) for the ‘Specification for the we expect the volume of asset replacement Optimised Management of Physical activity determined by the above Assets’. Our policy focuses on making good methodology to remain broadly similar stewardship decisions and, through those between now and 2021. decisions, improving the management of our network.
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Figure 2.2: Non load-related expenditure Figure 2.3: Operating costs
30 30 Spend in £m Spend in £m
0 0 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21
Operating costs (£m) Deviation range (£m)
Examples of schemes programmed We are interested in your views on the above between 2013 and 2021 include: categories of expenditure. • 132kV overhead line reconductoring For example, do the business as usual and rebuilding works; activities we undertake and spend money on seem appropriate or do you think we should • Transformer replacements; be doing more or less of something? • 132kV switchgear replacements; and • 132kV gas compression cable The day-to-day running and maintenance replacements. of network assets In some cases schemes can be deferred Controllable operating costs are the costs where interest from generation developers incurred by us in maintaining, repairing has raised the possibility that reinforcement and operating the electricity transmission may be required. In such cases it is network. preferable to defer asset replacement, if There are two categories of operating possible, whilst a clearer picture emerges, costs: direct and indirect. Direct operating to minimise the risk of stranded assets. costs are the costs involved carrying out Other more minor non load-related works work directly on the network assets. This have been identified to be on going: includes fault rectification activities and • Flood prevention measures that have been a programme of regular inspection and identified for up to 20 sites based on SEPA maintenance of network assets. Indirect data where there is a 1 in 200-year flood operating costs are the costs involved risk, or flood risk presented by nearby in supporting the direct work that takes hydro electric generation installations; place on the network, such as planning, engineering, control room activities and • A number of early solid state protection project management and also the central relays are nearing the end of their life support costs such as finance, human and a replacement programme has been resources and IT. An element of gross planned to address this; and indirect costs are directly associated with • Industry work has been undertaken the delivery of the capital expenditure to assess resilience requirements for programme. This is identified and excluded substation supplies in a ‘black start’ from the calculation of indirect costs. scenario where we experience wide- Level of operating costs spread power cuts. It is anticipated that In comparison with the level of the size of 72-hours’ resilience will be recommended the network, we have historically had a very and some expenditure has been forecast low level of operating costs. The level has to implement this. been approximately £6 - £7 million per year Our initial forecast of expenditure for the (1.4% of network value). As shown in Figure period 2013 – 2021, along with historic 2.3 above. This has remained relatively expenditure is shown in Figure 2.2 above. constant over the last five years.
9 Keeping the lights on and supporting growth
Figure 2.4: Availability, incidents, energy not supplied and reliability
Percentage annual system availability Year 2005/06 2006/07 2007/08 2008/09 2009/10 System availability (%) 96.87 95.72 97.74 96.65 97.38
System Security - Number of supply incidents Year 2005/06 2006/07 2007/08 2008/09 2009/10 Number of transmission system incidents involving 3 or less customers 1 0 0 0 0 Number of transmission system incidents involving more than 3 customers 9 17 18 14 34 Total number of transmission system incidents 10 17 18 14 34
System Security - Estimated Unsupplied Energy Year 2005/06 2006/07 2007/08 2008/09 2009/10 Unsupplied energy in incidents involving 3 or less customers (MWh) 1423.20 0.00 0.00 0.00 0.00 Unsupplied energy in incidents involving more than 3 customers (MWh) 78.20 176.60 64.20 178.58 21.70 Total unsupplied energy (MWh) 1501.40 176.60 64.20 178.58 21.70
Overall Reliability of Supply Year 2007/08 2008/09 2009/10 SHETL 99.99924% 99.99791% 99.99973%
Figure 2.3 on page 9 also shows our initial However, we do not expect these costs view of operating costs until 2021 which, as to rise in direct proportion to the level of explained below, shows an increase going network growth. We expect that controllable forward. As the level of investment in the operating costs will increase by a factor of network and construction of additional assets around three to four times the current level, increases significantly to accommodate which is approximately 0.5% of the projected renewable generation (discussed in section network value in 2021. 3) it is expected that the level of operating We are interested in your views on our level costs will also increase. This is primarily of operating costs. due to the increased size and complexity of the network and also the costs associated Does it seem reasonable for them to with the increasingly complex regulatory increase as described above? and financing environment that we operate within. Delivering a reliable service to our The level of direct operating costs and customers engineering related indirect costs will Problems on the transmission network that increase due to the new technologies that affect customers are a rare occurrence. will be used on the network (i.e. 400kV The reliability of our transmission system equipment, High Voltage Direct Current over the past five years is shown in (HVDC) and submarine cables) associated Figure 2.4 above. with the investment programme. This will require additional knowledge and From time to time, we need to take the engineering skills to those we currently transmission system out of service in order require. There will also be increased system to undertake essential maintenance or to planning and outage management activities upgrade the network. This will not normally required during the 2013 to 2021 period. result in an interruption of supplies to customers. We record planned unavailability Business support indirect costs will also in three categories: rise with higher IT, telecoms, human resources and insurance costs due to the • User connection; increased network size and the increased • System construction; and number of staff employed by SHETL. Due to an increasingly complex regulatory • Maintenance. environment and further GB and European In addition, we record unplanned availability legislation there will be a rise in finance, as events primarily driven by the health/ regulatory, commercial and legal costs. risk/condition of the network once you take out the effect of severe (often described as ‘exceptional’) weather events.
10 A consultation on our plans for the next decade
Figure 2.5: Planned and unplanned outages
2009/10 Monthly variation in planned and unplanned system unavailability (Unavailability is defined as (100 - availability)%) Month of year User connection System construction Maintenance Unplanned Total Apr 0.99 3.01 0.56 0.09 4.65 May 0.79 2.98 0.36 0.01 4.14 Jun 0.82 3.93 0.56 0.11 5.42 Jul 0.62 2.62 0.89 0.02 4.17 Aug 1.29 2.05 1.01 0.01 4.36 Sep 0.62 3.05 0.61 0.01 4.29 Oct 0.00 1.44 0.61 0.01 2.06 Nov 0.19 0.42 0.64 0.00 1.25 Dec 0.01 0.23 0.02 0.00 0.26 Jan 0.01 0.00 0.01 0.08 0.c0 Feb 0.00 0.01 0.00 0.12 0.13 Mar 0.33 0.41 0.31 0.03 1.08
As shown in Figure 2.5 above, when broken We are interested in your views on our down into these categories on a month- performance. by-month basis, the analysis of 2009/10 For example, do you think the measures shows that the overwhelming reason for our that are used to assess our performance system unavailability is planned outages outlined above are appropriate? associated with system construction. Unplanned events accounting for only a very Do you think the historic performance has small proportion. been at an acceptable level? Because of our approach to asset Do you think additional investment should be management, we expect the underlying made to improve this level of performance trend in the base level of system going forward? performance and reliability to remain the same in the coming years. Keeping our customers, our colleagues However, as we discuss in the next and our network safe chapter, connection and associated system Safety is one of our core values. reinforcement activities are forecast to be ’To comply fully with all safety standards significantly higher in the coming decade. and environmental standards’ is also one of In order to deliver the volume of new our network objectives. Safety is an intrinsic connections and the wider reinforcement part of how we carry out our day-to-day requirements consistent with our planning activities. The protection of the public, our assumptions, system availability is likely to staff and contractors from the potential decrease as sections of the network are de- impacts of our activities is critical to us. energised under planned outages to carry out this work. This activity will necessarily Over the last 20 years our safety record has increase the risk of unplanned events on steadily improved for all of those affected by the single and double radial circuits on our our activities. However, with the growth in system. However, in accordance with best renewables, and the associated requirement industry practice, we will deploy mitigation to deploy significantly more assets to serve measures to ensure that, as far as possible, them, we are mindful to ensure our safety customers do not experience deterioration systems continue to be fit for purpose and in the reliability of supply. deliver industry-leading performance.
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SHETL policy and strategy Our safety targets Our improved safety performance over the Put simply, our target is to operate in an last 20 years shows we are a progressive accident-free environment. We firmly supporter of workplace and public safety. believe this is achievable and will use all the As safety has improved we have sought devices at our means to achieve it. Our plans to strengthen our existing policies and in this respect are embedded in the core of strategies by the introduction of new ideas our business. and concepts. Looking forward, we plan to develop and use three main safety strands: We are interested in your views on our approach to safety. Robust reporting and addressing of issues – We recently completely revised For example, do you support our prime our incident reporting system to improve its focus on safety and agree that future effectiveness. Our new database is easier to funding should enable us to take the same access for users, provides much improved approach going forward? management reporting and allows detailed Are there additional safety measures you analysis of incidents to improve learning. think we should consider? Introduction of a new Safety Management System (SMS) – We are currently introducing How we manage the environment we work in a new SMS that is based on best practice. It covers four main areas: plant; process; One of the key concerns of our stakeholders people; and performance. and our customers is the environment. We It further subdivides these into 15 important recognise this and an important part of areas that are vital for safety including: our forward planning is about how we can safe systems of work; management of minimise our impact on the environment. change; human factors; asset integrity; and For our business, we have three main emergency planning and response. environmental concerns: Improving our risk assessment procedures • Our contribution to an improved – Risk assessment is a fundamental pillar environment; of working safely. We already use generic and site-based risk assessment to identify • Our impact on the environment; and hazards to either remove or mitigate them. • The impact of the environment on us. We are now developing, through using the new SMS, better ways to risk assess hazards Each of these is discussed in more detail on and find more enduring solutions. One the following pages. example of this is the introduction of Risk Boards within offices and their equivalent for onsite use. These are user friendly and easily accessible to promote wide discussion and acknowledgement of these important issues.
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Our contribution to an improved Delivery of our projects – Historically we environment have aimed to achieve a proper balance between the environmental benefits brought The decarbonisation of the UK economy by schemes and the impact of them on is clearly a hugely important issue. At the existing environment. Where possible, the forefront of this change will be the we look to deploy new and/or alternative introduction of a greater proportion of technologies to help achieve this balance. renewable energy to the overall energy mix. Each scheme is subject to rigorous Government policies are encouraging large environmental analysis, the results of which numbers of developers into the market. A form part of our submissions to both Ofgem huge proportion of these are in Northern and Government for approval. We believe Scotland. it is vital that the balance between these In order to support this process we are benefits and impacts is seen in the broadest proposing a number of projects, both context and are judged as a whole with all overhead and underground, that represent relevant factors taken into account. a huge investment in transmission We are committed to full engagement infrastructure and will in themselves with all relevant stakeholders at various have impacts on the environment. While stages throughout each individual project’s these projects are essential to overall development in respect of environmental decarbonisation, we recognise their inherent considerations. Consistent with statutory environmental impact and seek to minimise it. and our own tried and tested non-statutory Our impact on the environment processes, this consultation is undertaken to ensure that all environmental issues, There are three main areas of activity community and local businesses’ concerns, where we have a specific impact on the planning constraints and impacts on other environment: stakeholders are properly accounted • Delivery of our projects; for in the routing, site selection, design, construction and operation of each new • Carbon footprint; and development. • The effects of oil leakage from older We plan the level of stakeholder engagement cables. to be proportionate to the scale of the project and where necessary will tie in with statutory processes as defined within legislation. We have followed a planning and stakeholder engagement process to good effect in projects currently in development. As a result we intend to maintain and further develop this process for future projects taking into account recent changes to the planning process for Major Developments (as defined in the Planning etc (Scotland) Act 2006).
13 Keeping the lights on and supporting growth
Business carbon footprint – In this area The impact of the environment on us our impact on the environment is dominated The impact of global warming is a key by the electrical losses from our network. priority behind the move to decarbonise the The transport of energy by means of economy. The Climate Change Act requires electricity is always accompanied by lost operators affected to: energy. For our network this translates as a 2% reduction in throughput as losses but • Identify the effects of climate change on represents 98% of our carbon footprint. its functions; and However the transport of huge amounts • Propose how they intend to measure and of renewable energy will, we believe, be mitigate it. on a scale considerably more important. Nevertheless, initiatives to reduce We have been working with the Energy network losses such as the use of modern Networks Association, to produce a transformers with lower losses for all new document that describes the positioning of and replacement units; and the choice of the industry with respect to this issue and cable size are important considerations. review its impacts. Typical amongst these are: Most manufactured switchgear at transmission voltages contains sulphur • Transformers, cables and overhead lines hexafluoride (SF6) as an insulant. This is a derated due to rising temperatures; potent greenhouse gas and its use is being • Transformers, cables and overhead line closely regulated within the European structures affected by ground movement Union. Because we use this equipment due to drought conditions; and extensively we are taking steps to minimise leakage and improve our maintenance • Substations affected by flooding. procedures. We are also engaged in Water ingress into our substations and several research and development projects equipment is a serious issue for us with developing new insulation materials. over 90 key transmission substations on Effects of oil leakage – Most older our network. We take a balanced judgement underground cables used at transmission on the likelihood of flooding against voltages contain oil as an insulant. This oil the importance of the equipment being can leak due to third-party damage or age- protected. In the context of our overall related deterioration and contaminate the investment it is a relatively small amount ground. We have commissioned research but it is of significant importance to securing to improve the process of finding leaks and electricity supplies in both the north of sealing cables to minimise this risk. Other Scotland and the UK as a whole. risk mitigation measures are to replace such cables.
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We are interested in your views on the above Examples of our current research projects discussion. are: For example, do you agree that the • Novel insulated cross arms for approach described above continues to be transmission towers to save time and an appropriate approach to adopt going money during installation; forward? • New ways to monitor transformers for Are there other things you think we should condition in order to minimise capital be doing? investment; Are there other environmental issues we • Devices under trial to allow overhead should focus on? lines to be run dynamically to allow more renewable generation onto our network; What are your views on, for example, flood protection and replacing oil-filled cable, • Detection of incipient faults using partial should we prioritise these activities on a risk discharge techniques to reduce network basis or request funding to do them all? costs; and • Active Network Management schemes to Innovation in our planning for the future allow more generation onto the network. We firmly believe that innovative companies Historically, the revenue allowed by Ofgem will lead the UK networks into a carbon- has included a sum for research and free future. We have an active research and development. We support this approach and, development programme, and intend to at this stage, it is our intention to include continue this into the 2013 to 2021 period. funding for innovation in our business plan. Our aim is to be in the forefront to develop and deploy new technologies; improve the We are interested in your views on the way we do things; and find alternative ways above. to use and develop our system. We are progressing some projects independently For example, do you support our inclusion and undertaking some joint projects with of funding for innovation of all kinds in our other network owners. business plan?
15 Keeping the lights on and supporting growth 3. Investing for a greener future
Key questions in this section What are your views on the likely development of onshore, marine and offshore wind technologies in the north of Scotland between now and 2025? What are your views on our forecast transmission investments and their timings? Do you believe that the existing arrangements for dealing with funding uncertainty are appropriate for SHETL going forward? How else can we help you to achieve timely connection of new generation?
This section discusses the impact of the growth in renewable generation on the requirements to develop SHETL’s transmission system.
A consultation on our plans for the next decade
How we plan the network to meet users’ infrastructure. Each new scheme requires a needs new connection to the system and may also need the local network to be extended. As Planning the network to meet future users’ the number and size of schemes in the area needs is one of the most important things increase, they become the driver for wider we do. reinforcement to the Main Interconnected In transmission network planning there Transmission System (MITS). are rules that are set and administered While the local works necessary to provide at a national level which are used by a connection between the generator and all transmission companies. The most the transmission system can typically important of these rules is the National be undertaken at the same time as the Electricity Transmission System Security generating station is being developed, and Quality of Supply Standard (NETS reinforcement of the MITS can take much SQSS), which sets out minimum criteria longer. It is the development of such wider for the development and operation of the works – and in particular getting the timing national electricity transmission system. right for these works – that is the focus of Through application of the NETS SQSS, much of our network planning activities. we gain an understanding of how much transmission infrastructure we might need In order to meet in a timely manner the to meet users’ needs. MITS reinforcements needed for future generation connections, assumptions must However, as with any type of forward be made as to the mix, location and timing of planning, there are uncertainties that will likely generation connections. In recognition determine how we apply the NETS SQSS. of this, the Electricity Networks Strategy These uncertainties need to be identified, Group (ENSG) (a cross industry group jointly assessed and a ‘best view’ reached. We chaired by the Department of Energy and believe that a robust engineering approach Climate Change (DECC) and Ofgem) asked underpinned by evidence is the best way to the three transmission licensees, with plan for the future. support of an Industry Working Group, to The main uncertainties we face are how develop electricity generation and demand much electricity will be used, and how scenarios consistent with the EU target for much generation will be connected and 15% of the UK’s energy to be produced from where it will be located. In recent years a renewable sources by 2020; and to identify significant number of renewable generation and evaluate a range of potential electricity schemes have applied to the NETSO for transmission network solutions that a connection to our network in the north would be required to accommodate such of Scotland. We expect to receive more scenarios. This work concluded with the applications in the future, particularly publication of ‘Our Electricity Transmission since the introduction of the ‘connect and Network’ in March 2009. manage’ regime which allows generators access to the transmission system without the need to await upgrades to the main
17 Keeping the lights on and supporting growth
Figures 3.1: Onshore renewable – contracted development profile
1,400 7,000 Cumulative (MW) Cumulative Total annual (MW) Total
0 0 Historic 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20+
Small Large Cumulative
Since then, we, along with the other In this section we set out our initial views licensees, have adopted the ENSG ‘Gone on onshore generation, wave and tidal Green’ scenario (updated in November 2009) generation, and offshore wind generation. as the basis of our investment plan in order We have used renewable generation to meet the 2020 environmental targets - growth forecasts based on UK and meaning that approximately 30% of the UK’s Scottish government targets, together with electricity will have to come from renewable information from developers both in the sources. form of their forecasts and their contracts for connection. From this joint planning work, we have been able to establish a framework of The established contracts provide a good likely network reinforcements that will be basis for determining the requirements required in the SHETL area. The forecast to provide local connection and new cost of these reinforcements at this time is infrastructure works in order to connect in the range of £3 – 4 billion. the individual generation projects into the existing network. These contracts and While the joint ENSG work has been very broader forecasts provide the basis for helpful in setting a high-level vision for assessing the requirement to develop the the planning of our network to meet our main interconnected 275kV and 400kV national renewables targets, it does not set transmission system, and the requirement out in detail where new generation might for HVDC links. be located, when and how much. Within our own geographic area, the volume and timing Onshore generation of onshore renewable technologies, marine Activity in the development of onshore and offshore wind generation is a key generation is forecast to remain strong influencing factor for our investment plan. over the coming decade, with a number We explore this in more detail below and of large wind farm projects commencing seek your views on the likely development of construction following the gaining of these renewable sources. consents and financing. Smaller-scale Our initial views on generation that might wind, hydro and other forms of renewable want to connect to our network generation are also expected to continue to develop. The connections of these small The assumptions we make about generation schemes onto the lower voltage distribution that will connect to our system are critical networks will increase the export of power to our investment planning decisions. If onto the transmission system and, hence, we get this wrong, then we might build too impact on our investment plans. soon or too late. We recognise the potential cost to customers of getting our investment Figure 3.1 above shows the anticipated decisions wrong; hence we are keen to connection profile based on some 6GW of understand your views on what might be contracted onshore generation. our future generation mix in the north of Scotland.
18 A consultation on our plans for the next decade
Figure 3.2: Potential marine developments in Pentland Figure 3.3: Pentland Firth and Orkney Firth and Orkney Waters Waters programme – build-out profile
SSE Renewables Developments (UK) 450 1800 Costa Head 200MW Scottish Power Renewables UK Ltd SSE Renewables Marwick Head 50MW Developments (UK) Ltd Westray South 200MW E.ON Climate & Renewables UK developments Ltd West Orkney Middle South 50MW Brough Head Wave Farm Ltd Brough Head 200MW E.ON Climate & Renewables UK developments Ltd West Orkney South 50MW
Cantick Head Tidal Development Ltd Cantick Head 200MW Sea Generation (Brough Ness) Ltd Brough Ness 100MW (MW) Annual Capacity Installed Ocean Power Delivery 0 0 Ltd Farr Point 50MW (MW) Capacity Installed Cumulative
MeyGen Ltd Inner Scottish Power Renewables UK
Sound 400MW Ltd Ness of Duncansby 100MW 30/12/13 30/12/14 30/12/15 30/12/16 30/12/17 30/12/18 30/12/19 30/12/20 Tidal Wave Cumulative Installed Capacity
The uneven growth profile is a result of The agreements indicate a total potential some large schemes forecast to connect in capacity of 1.6GW being phased in time to 2014/15. This figure only reflects projects 2020. Their locations are shown in Figure that have already entered into connection 3.2, and their proposed build-out profile is agreements with us. Clearly there will be shown in Figure 3.3, above. other schemes in development that we are In developing our investment plan, our not aware of and this volume will increase in initial assumption is that around 30% of the respect of later connection dates. potential capacity will be constructed within While our focus is on new generation the period to 2020. schemes, we are also aware of the impact Other marine developments are proposed of changing use of electricity on our on the west coastline, around the Inner and investment programme. At a high-level, Outer Hebrides. as we discussed in section 2, we forecast
broadly steady use of electricity in the north We are interested in your views on the of Scotland over the coming decade. timing and speed of development of marine However, developments in smart grid and renewable generation, specifically in the smart metering technologies are likely to Pentland Firth and Orkney Waters, and improve efficiency of electricity usage in the more generally as a maturing technology. region, potentially shifting times of energy For example, is our assumption reasonable use and storage. Electricity demand might that around 30% of the total potential marine increase, as we move away from a carbon generation already under development will economy, and will have a beneficial effect materialise? in utilising locally generated renewable energy, although it is likely to only mitigate the requirement to accommodate increasing Offshore wind generation power flows to the south of the area. Offshore wind technology is advancing Wave and tidal generation rapidly and the industry is expected to see major and rapid deployment. Around the There is currently little marine and tidal north of Scotland coastline in areas adjacent generation connected to our network, to SHETL’s licensed area there is potential although we expect this to change within the for several large offshore wind farms. next decade. These comprise: developments within In 2010, the Crown Estate announced Scottish Territorial Waters (STW); a number of agreements with marine developments within the 12 nautical renewable developers to allow them to mile limit; and Crown Estate ‘Round 3’ develop projects in the Pentland Firth and development leases which are outside the Orkney Waters. 12 nautical mile limit.
19 Keeping the lights on and supporting growth
Figure 3.4: Potential offshore wind development
Development MW Comments Moray Firth Moray Offshore Wind Round 3 1,500 Contracted for SHETL connection Beatrice STW 1,000 Contracted for SHETL connection Firth of Forth Firth of Forth Round 3 3,700 Contracted via NETSO. First 1GW may connect into Tealing, Dundee. Remaining capacity may connect to Scottish Power. Inch Cape STW 900 Awaiting application Western Coastline Islay STW 700 Awaiting application Kintyre STW 400 Awaiting application Argyll Array STW 1,000 Awaiting application, Likely to connect to Scottish Power area
Round 1 Wind Farm Site Scottish Wind Farm Exclusivity Award Round 3 Wind Farm Zone
20 A consultation on our plans for the next decade
Figure 3.5: Summary of large capital projects under construction/completed
Projects under construction / complete Completion date Inverarnan Completed 2010 Knocknagael Substation 2011 Beauly–Denny 2014/15 Beauly–Blackhillock–Kintore 2014/15 Beauly–Dounreay 2012/13
A summary of the potential developments Our initial views on the reinforcements we which may connect into SHETL’s might need to accommodate renewables transmission network are shown in the Taking the ‘Gone Green’ scenario Figure 3.4 on page 20. established for the national Electricity For the majority of these developments, Networks Strategy Group (ENSG) study our initial view is that the connection will as a starting point, we have looked at be via HVDC links. Under the current the evidence within our area of future offshore transmission regulatory regime, generation connections described above. a competitive tender will be run by Ofgem From this, we have developed proposals to identify who builds these links. Our for a number of major transmission involvement will be in the provision of the reinforcements that progressively allow connection from the shore into the existing connection of an increasing volume of transmission system, and the reinforcement renewable generation to the MITS. of the main transmission system which will The basis for our analysis is the be required to accommodate the potentially existing transmission system and those high volume of offshore renewable reinforcements which are recently generation. completed or currently under construction
is summarised in Figure 3.5 above. We are interested in your views on offshore development. • A new 275/132kV substation at Inverarnan, near Sloy beside Loch For example, what are your views on the Lomond, to support renewable generation size and timing of both the commencement growth in Argyll and Bute; and completion of the phased development of offshore wind farm projects? • The replacement Beauly-Denny 400kV overhead line and associated substations that will facilitate the connection of 1.5GW of renewable generation; • A new 275/132kV substation at Knocknagael, near Inverness, that will provide transmission capacity for additional renewable generation in the far northwest, and prior to the completion of the Beauly-Denny upgrade; • The reconductoring of the existing 275kV overhead line between Beauly and Kintore, near Aberdeen to allow for the connection of an additional 850MW of renewable generation; and
21 Keeping the lights on and supporting growth
Figure 3.6: Summary forecast of future large capital projects
Project Completion date Beauly–Mossford 2014/15 Caithness strategy 2015/16 – 2017/18 Kintyre–Hunterson 2016/17 – 2018/19 East Coast 400kV upgrade 2016/17 – 2018/19 East Coast HVDC subsea link 2018/19 – 2020/21
Western Isles link and associated onshore infrastructure on Lewis 2015/16 Shetland link 2015/16 Orkney 2015/16
• The installation of a second 275kV Beauly-Mossford circuit on the existing overhead tower The existing Beauly-Mossford 132kV line between Beauly and Dounreay and overhead line runs west from Beauly to the upgrades of the existing Beauly and connect several existing hydro stations Dounreay grid substations to allow the and a number of proposed wind farms connection of an additional 400MW of and small hydro schemes. The proposed renewable generation in the Caithness- reinforcement would upgrade the double Sutherland area. circuit 132kV line between Beauly and As we are already committed to these Mossford and establish a double-busbar projects they are not within the scope of this 132kV substation near Mossford 132kV consultation. substation. This reinforcement is necessary to provide transmission connection Building on this, we have undertaken and access for renewable generation in detailed analysis to identify further projects Strathconon and Strath Bran area. that are likely to be required in order to connect and support the forecast growth The estimated cost of this scheme is around in renewable generation. These projects £50 million and could be completed between would accommodate further onshore wind, 2014 and 2016. new offshore wind and emerging marine Caithness strategy generation. They include potential links to the main island groups. Taken together The March 2009 ENSG report ’Our electricity these network upgrades would provide transmission network: a vision for 2020‘, increased transmission capacity for the recognised the need for reinforcement export of this power to the southern demand of the transmission network in the far centres summarised in Figure 3.6 above. north of Scotland to accommodate future onshore and offshore renewable generation In total, these schemes represent the in the region. Our view at this time is that majority of our capital expenditure the optimum network development to investment requirements over the next accommodate the proposed generation in decade to 2020, and our main focus is this area and on the northern islands of getting these reinforcements right and then Orkney and Shetland could comprise the delivering them at the right time. elements described on page 24. Figure 3.7 on page 23 and the following descriptions provide an overview of the planned transmission system developments.
22 A consultation on our plans for the next decade
Figure 3.7 – Overview of planned transmission developments
132kV circuit 9 275kV circuit 1. Beauly–Denny rebuild 400kV circuit 2. Lnocknagael substation 3. Beauly to Kintore 275kV re-conductor 4. Beauly–Dounreay second circuit on existing towers 4 5. East Coast re-insulation and re-conductor 7 6. Western Isles Link (HVDC) 7. Caithness–Moray with hub option 8. Kintyre–Hunterston subsea link 6 9. Orkney reinforcement 10. East Coast HVDC link (Plus other local, radial reinforcements)
1 3 2
5
10
8
23 Keeping the lights on and supporting growth
Caithness-Moray The estimated cost of this scheme is around £600 million, and could be completed • A new 600MW HVDC link between a between 2015 and 2018. new 132kV substation at Spittal near Mybster in Caithness and Blackhillock Additional to the Caithness-Moray Project, in Moray, to add to the export capacity and within the overall strategy for this of the Caithness region provided by the region are: upgraded Beauly-Dounreay line; • The option of an offshore HVDC hub and • At Spittal, the new convertor station switching station in the Moray Firth with for the HVDC link, and 132kV switching the uprating of the HVDC link between equipment; the hub and Blackhillock from 600MW to around 1.2GW (the hub and incremental • At Blackhillock, the other new convertor works project); and station for the HVDC link, together with a 400kV switching station, connecting into • The option of terminating the proposed the new 400kV network on the east coast; HVDC link from Shetland at the hub, rather than Blackhillock. • Rebuild the existing Dounreay-Thurso- Mybster 132kV tower line at 275kV; The hub and incremental works project has been developed over the past 18 months • A new 275kV/132kV substation near in response to a grant programme from Cambusmore, at the crossing of the the European Commission for innovative Beauly-Dounreay 275kV and Shin to incremental works that might be added to Brora/Mybster 132kV overhead lines; existing planned works. In December 2009, • A new 275/132kV substation near the SHETL was successful in gaining 50% grant existing Alness 132kV Tee point and funding (up to 74.1 million) for the project interface with the existing Alness Grid under the European Energy Programme for Supply Point, and Recovery (EEPR). The hub and incremental works project is acknowledged to be a • Reconductor the existing single 275kV ‘strategic’ investment that is unlikely to be circuit between Beauly and the proposed economic without the grant funding. Cambusmore substation. SHETL is of the view that the offshore hub While this project comprises a number of would represent an economic and efficient elements, including some new onshore development of the transmission system transmission assets, our initial view is that in the north of Scotland. Our preliminary this is the most environmentally acceptable analysis suggests that this would be the and cost-effective reinforcement to open up most economic means to accommodate the region including the marine potential. new generation connections in the far north; The alternative option set out in the ENSG for example, the initial proposed marine report was for full onshore rebuilds generation in and around Orkney and the between Dounreay, Beauly and Keith. Pentland Firth or offshore wind in the Moray Firth.
24 A consultation on our plans for the next decade
In addition, there is the innovation benefit of Following completion of the Beauly-Denny proving multi-terminal HVDC technology – overhead line, the uprating of this system essential for the realisation of large-scale to 400kV operation is required to further offshore generation, using an integrated increase the capability to export renewable approach for offshore connections and energy from the north of Scotland to the leading towards a future offshore ‘super demand centres of central Scotland and the grid’. north of England. Kintyre-Hunterston SHETL works comprise a number of elements which include: This project would allow for the connection of around 550MW of renewable generation • The uprating of the existing 275kV tower in the Argyll and Bute area, which has line between Blackhillock, Moray to seen significant development of onshore Kincardine in the Central Belt to 400kV wind generation over recent years, and operation; anticipates the future development of • The uprating of the existing 275kV marine technologies. tower line between Peterhead and This project comprises the installation of Rothienorman to 400kV operation; and subsea cables between a new substation • Substation works at Rothienorman, near Crossaig on the Mull of Kintyre and Kintore, Alyth and Blackhillock. Hunterston in Ayrshire, and the rebuild of the existing 132kV overhead line between The estimated cost of this scheme is around Crossaig and Carradale to a higher capacity £350 million, and could be completed 132kV construction. between 2016 and 2019. The estimated cost of this scheme is around We have also identified a possible future £200 million, and could be completed requirement to uprate the capacity of between 2016 and 2019. the second 275kV tower line on the east coast, and would achieve this by changing East Coast 400kV upgrade the conductors to an increased size and The existing 275kV system on the east capacity. side of SHETL’s licensed area runs from East Coast HVDC subsea link the boundary with Scottish Power in the Central Belt, to Dundee, at Tealing, onto This project comprises the installation of Aberdeen, at Kintore, with connections at a subsea HVDC link between Peterhead Rothienorman to Peterhead Power Station in the north of Scotland and Hawthorn Pit on the Buchan coast, before continuing to in north east England, over a route length Blackhillock, by Keith. of approximately 360km. The link will be rated between around 2GW and will operate in parallel with the upgraded mainland transmission system to provide a significant increase in north-south transfer capacity.
25 Keeping the lights on and supporting growth
SHETL is developing this project jointly with The estimated cost of this scheme is around National Grid, and is sharing the design and £400 million, and could be completed by 2015. development costs of the subsea link. Shetland link The estimated cost of our share of this The Shetland project comprises a new scheme is around £370 million, and could be 600MW HVDC link between Upper Kergord completed between 2018 and 2021. on the Shetland mainland and Blackhillock Western Isles link and associated onshore on the Scottish mainland. The link infrastructure on Lewis comprises a single circuit of 320km subsea and 25km onshore underground cable, The Western Isles project includes a and includes AC/DC converter stations 450MW HVDC link between Grabhir on the at each end. The project is driven by the Isle of Lewis, and Beauly on the Scottish contracted generation seeking connection mainland. A cable will be laid from Lewis to on Shetland, principally one potentially Dundonnell on Little Loch Broom, and then large-scale development, but allowing continue cross-country as underground for some smaller-scale generation to be HVDC cables to Beauly. The project includes accommodated. The timing of construction AC/DC converter stations at each end. The start and the resulting completion date will 450MW rating of the link is driven by the depend upon the large developer confirming volume of contracted generation seeking readiness to proceed. connection on Lewis, which comprises two potentially large-scale developments The estimated cost of this scheme is around and a number of smaller-scale schemes £450 million, and could be completed in 2015. connecting into the island’s distribution As described on page 24, in the event that network. the proposed offshore hub is established Preconstruction work is substantially in the Moray Firth, the link could be complete, with the project ready to move established via this hub point. to the construction stage. The timing of construction start and the resulting completion date will depend upon the larger developers confirming their readiness to proceed. Additional 132kV transmission infrastructure on Lewis will connect the AC/DC Convertor station at Grabhir with the existing transmission system at Stornoway. This allows the smaller generation schemes to connect and allow the new link to have a role in securing demand on Lewis, and so reducing reliance on the existing diesel generation station.
26 A consultation on our plans for the next decade
Orkney Other projects In developing our investment plan, our initial The projects identified and described view is that around 30% of the potential here are sufficient for the majority of the capacity of marine generation already under contracted generation, which includes development will materialise within the onshore wind generation in the Western period to 2020. We believe this will mean Isles and Shetland, offshore generation a requirement for an initial subsea link of in the Moray Firth and some marine around 180MW capacity between the Orkney generation in the Pentland Firth and Orkney Islands and the Scottish mainland in 2016, Waters. Should all of this contracted and a 132kV link with Caithness which will generation fail to be developed, some provide capacity for the first tranches of specific projects may be delayed until such marine generation together with developing time as the requirement for transmission onshore renewables. We anticipate that capacity is re-established. these would be followed by an Orkney link On the other hand, further investment and of greater capacity, perhaps using HVDC upgrading of the transmission system technology, later in the eight-year period. would be required within the price control This would depend upon the rate of growth period should additional generation be of deployed marine services in these waters. successfully developed. Some upgrading However, it may be necessary to establish a of existing 132kV radial networks may be further HVDC link if: required. Furthermore, particular areas • All of the generation materialises within and technologies which will significantly the period; influence further development include the development of marine generation, not only • The location of the generation clusters that currently the subject of Crown Estate develop in a particularly dispersed leases in the Pentland Firth and Orkney manner; or Waters, but also on the western seaboard • Other generation develops independent of of the Inner and Outer Hebrides, where these Crown Estate agreements. the planned deployment of smaller-scale schemes may precede the establishment Costs for these two links are estimated at of larger schemes. Similarly, further £500-£700 million. additional offshore wind around the coast of the north of Scotland, perhaps together with increased marine volumes, would require future large HVDC links from these locations to HVDC hub points on the Scottish mainland, with even higher capacity HVDC links taken from these hubs to the north of England.
27 Keeping the lights on and supporting growth
We are interested in your views on the local distribution network. For the main above discussion and on the list of potential interconnected system on the mainland, transmission investment projects, in the case will depend upon the impact of the particular, the timing of them. volumes of generation aggregating to form substantial flows of power from the north of For example, do you believe that there are Scotland to the south. other areas/programmes of investment that we should consider in addition to, or instead Some generation schemes are already of, those listed above? connected, whilst others are being constructed, have been consented, or are in the various stages of their planning Factors that will influence our investment process. Consequently it is necessary to decision confirm that there is sufficient certainty When we have identified particular projects around a portfolio of generation to provide that might meet users’ requirements in the requirement for a specific transmission a particular geographic area, we need to project. An understanding of the phasing decide when to invest. of the development of the generation schemes will also inform the timing of the The timescales indicated above are the dates transmission project. by which we expect to be able to complete the individual projects. The question of when we One tool we have to inform the needs case start work and then now long that work takes is the requirement for developers to provide is subject to a number of uncertainties, which a form of underwriting for the design and are described below. construction of the projects. This provides Project uncertainties a strong signal and certainty that the project is ready to proceed, and will avoid At a project level, the uncertainties include: unnecessary investment in the system. The needs case – This is a detailed piece of Project scope – This is about making sure analysis that confirms that the technical and the reinforcement is not too big or too economic case for the project is made and small and that it is at the right technical is robust. Since these transmission projects standard. The scope of the project is are driven by the requirement to connect determined from the requirement to and provide transfer capacity for the growth provide adequate transmission capacity in renewable generation, the needs case for the connection and power transfer of is heavily reliant upon the certainty of the developing generation in accordance renewable generation being developed and with the national planning standards. It connecting to the system. For an island will be refined as generation volumes and group or an area in the west Highlands locations are confirmed in order to provide served by a radial transmission network, the optimum design, but could be impacted this can depend upon an individual, or a by a significant change to the assumed small group of, relatively large generation generation. schemes, with the case supported by smaller schemes connecting onto the
28 A consultation on our plans for the next decade
Project duration – Getting the timing System outage requirements – This is an right for both commencing the build and issue of great concern within the north of connecting the generation ensures that we Scotland, as a restriction on the number keep costs down for our customers. The of concurrent outages is necessary to projected completion date for a project is ensure the reliability and continuity of determined by the requirements to provide the transmission system to meet local physical connection to generation schemes, demand and generation needs. A number of and adequate transmission capacity for the competing pressures will be placed on the region, and determined by the timescales system over the next decade to allow for the of the project itself to complete the various integration of these specific projects into phases of engineering and design, planning the existing network, to connect individual and consenting, supplier procurement, renewable schemes into the network, and manufacture, build and commissioning. to ensure the ongoing maintenance of the Timing of the completion date would existing assets is not compromised. be extended if any of these overrun, for Outage programming is a co-ordinated example if: activity between ourselves and the NETSO, • Planning applications become subject to with the NETSO having responsibility for appeals or unexpected conditions; the operational integrity of the overall system and co-ordination of the annual • System outage dates, required for outage programmes. We will continue to integrating the project into the existing work closely with the NETSO to ensure the network, are restricted due to other work programme is optimised and that the impact on the overall system; or of any restrictions on the construction of the • Manufacturing or contractor capacity projects is mitigated. is limited for a particular technology or Supplier capacity – This is an issue equipment type. about sourcing all the equipment we Portfolio uncertainties need increasingly from an international market, particularly for the provision As noted above, the overall development of transmission equipment. We already of the various projects is subject to procure transformers and switchgear, interactions between themselves and cables and overhead line conductor from development across the wider and global suppliers across the world. The recent marketplace. development in the growth of offshore renewable generation, often distant from onshore networks, and the increase in interconnections between countries and markets are resulting in an increase in the use of HVDC technology.
29 Keeping the lights on and supporting growth
Recognising these uncertainties and the The potential scale of investment until 2021 approach to the regulatory funding of the alone outlined means that the size of the projects is critical to us and is discussed in SHETL business could increase by some the next section. £3 - £4 billion compared to the value of the existing business, of around £400 million. Managing the uncertainties to minimise This unprecedented growth would present costs to customers new and very real business challenges The discussion so far on the wider, strategic associated with delivering such an extensive system reinforcement requirements capital investment programme. Against this associated with supporting renewable background, it is our view that we should development shows that there is minimise customers’ and our own risk over considerable uncertainty in respect of the our growth. scope, timing and cost of these projects. Given this, we would favour continuing As the level of uncertainty increases as existing funding arrangements that allow the planning horizon extends, our precise us to increase our allowed revenue to fund renewable-related funding requirements necessary investment as and when they are and phasing for the period 2013 to 2021 are required. not firm. The current mechanism for funding large Accordingly, as a responsible transmission capital projects is termed the Transmission company, we need to consider appropriate Investment Incentives (TII) mechanism. funding arrangements in the interests of Under this mechanism, we apply to Ofgem existing and future customers. for specific project funding once there One approach might be to set an up-front is a credible needs case to justify the allowance for delivering these projects. That project and the associated costings are is, we agree now what projects we might do sufficiently robust to enable Ofgem to make and how much they might cost. This could a confident funding decision. Transparent, be a direct allowance, i.e. project X and controllable and tangible outputs are cost Y. Alternatively, it could be a sliding associated with such funding allowances. scale, i.e. for each unit A of new capacity a This funding comes in two phases, firstly payment of B is made. to fund preconstruction works of design, environmental assessments and consents; In adopting this approach, what we are secondly to fund the physical construction allowed may, in retrospect, turn out to phase. This split provides further protection be too high or too low – the former being against the risk of investing too early or inappropriate for customers since it would too late. mean that in any one year they pay too much, the latter being inappropriate for us in that there would be a revenue shortfall gap which would render us unable to fund our statutory obligations.
30 A consultation on our plans for the next decade
Much work has been carried out over Delivering the local connection works the past five years to establish the TII As we described at the start of this section, mechanism. In our view, it has worked well there are two parts to supporting the as an uncertainty mechanism and is a good connection of new generation: example of how the industry and Ofgem have worked together to provide a relatively • The MITS reinforcements considered simple, transparent and pragmatic solution above; and to manage the considerable risks and • The local connection works between the uncertainties presented by these schemes generator and the existing system. to existing and future customers, as well as our business. In this section we consider the delivery of local connection works. There is a view, however, that extending the TII mechanism could be administratively Identifying the necessary connection burdensome for Ofgem, stakeholders and works the transmission companies. However, in The connection of each renewable generation our view, there has been no material change scheme requires new connection assets and to the overall circumstances within which new local infrastructure. Reinforcement of the mechanism would operate compared to existing local infrastructure is also required when it was introduced. Therefore, we see in some cases. no reason to believe that the cost benefit analysis that supported its introduction at We develop connection and infrastructure that time would have changed significantly. reinforcement schemes in response to However, we do believe that there may be connection applications from developers. some improvements that can be made to the The process for the connection of renewable process to reduce bureaucracy and costs. generation projects is dependent on the size of the scheme. Small schemes, under We are interested in your views on how best 10MW, typically connect into the local to manage uncertainties associated with distribution system, without any dependency the timing and funding of the large capital on works on the transmission system. projects. Larger schemes may connect onto the local 33kV distribution system or onto the For example, do you believe that it is high voltage transmission network. These appropriate to continue with the TII schemes will generally require some mechanism? transmission connection work. Do you have any views on how the Applications for connection are made by the mechanism may be improved, for example, developer to the NETSO either directly or via the criteria for determining when a needs Scottish Hydro Electric Power Distribution case should be deemed to have been met? plc. The NETSO then requests us to design and quote for the necessary transmission works to provide, or upgrade, the connection and any local and wider infrastructure.
31 Keeping the lights on and supporting growth
Figure 3.8: Forecast investment in sole-use infrastructure
300 Cumulative spend in £m Cumulative
0 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19
Service is one of our core values. We strive We are interested in your views on the above to ensure that good communication exists connections process. throughout the connections process between For example, could you be flexible about the the developer, the NETSO and ourselves, with time within which you receive a quotation if frequent engagement in all aspects of such your project is not time critical? projects to ensure realistic timescales are set and managed for all parties. Are there areas of the connection process that we can help you with? Accordingly, we welcome any developer wishing to seek a connection onto our In your view, what does ‘success’ look like network to discuss their project with us as for connections? early as possible in their process to ensure More generally, going forward, how would that all parties can gain an understanding you like us to engage with you to get of the possible connection solutions, feedback on the level of customer service timescales and costs. we provide? New developers may be unfamiliar with the connection process. We are happy to assist Funding connection works in developing that understanding in order to In addition to the wider system achieve a successful completion. We believe reinforcements described above, our offer that the more we can do to work together of connection will typically identify two types with related stakeholders, the more flexible of work: we can be and the better chance there is for a successful outcome for all involved. • Connection sole-use assets, which are funded by the user; and Once we receive an application, detailed studies are carried out to determine the • Sole-use infrastructure assets, which impact that a prospective generator has on are fully underwritten by the user but the transmission system. Connections and funded by us. infrastructure reinforcements are designed For the sole-use infrastructure works, we according to the criteria of the NETS SQSS, have made a best estimate of the investment with which we have a licence obligation that would be required to accommodate to comply. Where we identify a need for what we think will connect in the coming reinforcement, we evaluate and compare years and this is shown in Figure 3.8 above. options before selecting a proposal to form the basis of the connection offer. When a developer accepts a connection offer, we convert it into a construction agreement which becomes part of our investment plan.
32 A consultation on our plans for the next decade
Recently, a number of developers have Under the existing arrangements, a sought advanced connection dates under fixed allowance is made, based on the the new ‘connect and manage’ access assumption that a certain volume of new framework. This framework is now an generation would connect. To recognise enduring arrangement and going forward that more than that could materialise, a we expect this will lead to further changes mechanism was included that automatically to contracted dates. It enables new increments the revenue allowance based generators to connect earlier than would on a £/MW formula once the assumed have been possible under the previous volume was exceeded. This is known as the access arrangements. For example, ‘revenue driver’. It also made an allowance generators no longer have to wait for large for high cost projects and includes a ‘claw reinforcements such as Beauly-Denny to be back’ mechanism in the event that the completed before they can connect. predetermined volume of generation did not materialise. We anticipate that works will be in progress to facilitate the connection of over 1.5GW We believe that the principle of this during 2012/13 alone. We have a good level mechanism has worked well. It allowed of confidence in these proposals, given the funding for projects that were certain, planning consents granted to developers. and then provided automatic funding for The large number of developments subsequent developments. It is our view gaining consents is driving the increase in at this time that this mechanism should expenditure under this category. Many of continue. the developments forecast to be connected in the future are more expensive due to We are interested in your views on the greater distances from the existing network, above. and the need for larger reinforcements For example, is it appropriate to continue since existing spare capacity has been taken the principle of a revenue driver to manage by prior connections. the uncertainty associated with this However, over the period to 2020/21 there category of investment? is significant uncertainty in predicting the number, size and location of generation schemes which will require connection and infrastructure works. As highlighted above, renewable- related expenditure falls into a number of categories. Connection assets are categorised as those that are paid for by the developer. Local sole-use infrastructure is funded by us and we consider the appropriate funding arrange for this below.
33 Keeping the lights on and supporting growth 4. How we recover our costs
For completeness, in this section we describe how we recover the costs we have described in the previous chapters. We are not seeking specific views on this at this stage of the development of our business plan. However, if you have views, please let us know.
A consultation on our plans for the next decade
The costs we and the other network In practice, this balance is achieved by operators are allowed to recover through treating a fixed proportion of a network our charges in any particular year (or over operator’s relevant costs as current the price control period) is determined by customers’ costs. This proportion relates a number of discrete ‘building blocks’. In to the operational spend of the business. previous sections, we have set out how The remaining share is deemed to relate our forecast requirements for investment to network investment and is subject to a in the network and the costs associated slightly more involved route. It is funded with running the networks - which include over a number of years through an annual inspections and maintenance programmes, ‘depreciation’ allowance which is consistent and staffing costs. with spreading the cost of any investment across both current and future customers. In this section we set out how these different Given that network operators do not get elements are financed through the price their money back immediately for this control mechanism and the additional investment there is a ‘borrowing’ cost elements that need to be factored in. Taken associated with that expenditure. together, these make up our allowed revenue. This borrowing cost is designed to cover Investment in the network today benefits the costs that an efficient network operator both current and future customers. would be expected to incur in financing We expect assets installed today to be its activities, i.e. is a rate of return. The operational for many years. As such, it rate of this return is determined by Ofgem is appropriate that the costs associated and applies to the deemed value of capital with network investment are spread over employed in the business. a period of many years, thereby ensuring the right balance between both current and To summarise, the allowed revenue of a future customers. network operator is the sum of the operational costs incurred in the year and a contribution The costs of operating and maintaining the towards investment costs (the depreciation networks are more directly linked to current allowance and the borrowing cost). customers’ needs. Thus, these costs are funded in the year in which they are incurred and by the customers that directly benefit.
35 Keeping the lights on and supporting growth
There can be circumstances where the network operator’s allowed revenue is less than its actual costs in any year. This is likely to be the case for SHETL during 2013-21 given the large capital investment programme. Where a network operator’s allowed revenue in any year is insufficient to cover its costs of investing in and running the business, this shortfall is met through a mix of cash from within the business, funding from external investors and company debt. All of these attract additional costs as a result of the lag that exists between the up-front nature of any investment and the delayed recovery of these costs through customer charges. The allowed return that forms part of the price control settlement should ensure that these inherent costs in operating the network business are funded. External investors, for example, are not bound to investing in network businesses. Their decision as to where to invest will depend on which businesses best meet their return expectations and risk profile. Similarly, financing through debt attracts costs in the form of interest payments. Admittedly, debt tends to be a lower cost option relative to equity due to the lower risk attached, however, it is key that a balance is struck between debt and equity in order to ensure a stable and sustainable business model. This is reflected in Ofgem’s assumptions that inform the overall rate of return.
36 A consultation on our plans for the next decade 5. How our future transmission plans might impact customers’ bills
Key question in this section Does an annual increase of up to £4 a year on an average customer’s bill to pay for the investment in our network necessary to facilitate the achievement of the UK renewables targets sound affordable?
Keeping the lights on and supporting growth
Figure 5.1: Share of transmission costs by Figure 5.2: Transmission costs as a company percentage of customers’ bills
SHETL 57 SHETL transmission NGET & SPT transmission SPT 180 costs 0.09% costs 2.91%
NGET 1,407 Non transmission related costs 97%
As explained in the introduction to this As a consequence, SHETL does not set consultation, SHETL’s price control individual tariffs for individual users or determines the amount of revenue we define the methodology by which those are allowed to recover from users of tariffs are set. Therefore, it is not possible the network to fund our activities. It is for us to take the initial analysis set out in important, therefore, that we consider the this consultation and confidently say what impact of our future plans on users of the this would mean for customers’ bills. The system in terms of the charges they pay. examples provide here, therefore, are for illustration only and the actual tariffs would SHETL does not charge its customers be determined by National Grid. directly. Rather we charge National Grid, in its role as NETSO, for our transmission In order to describe the impact of initial services. National Grid is then responsible views on costs for the period 2013 to 2021, for setting GB-wide transmission charges we have produced the series of charts which recover the allowed revenue for shown above and on page 39. all the TOs and the NETSO. That is, the allowed revenues of all three transmission companies are added together and recovered from system users through Transmission Network Use of System Charges (TNUoS).
38 A consultation on our plans for the next decade
Figure 5.3: SHETL costs (doubled) as a Figure 5.4: SHETL costs (ten-fold increase) percentage of customers’ bills as a percentage of customers’ bills
SHETL transmission costs 0.22% SHETL transmission costs 1.08%
Non SHETL related costs 99.78% Non SHETL realated costs 98.92%
Figure 5.1 on page 38 illustrates the size Currently, transmission costs make up of SHETL’s allowed revenue in the context approximately 3% of a customer’s bill. of the overall allowed GB transmission SHETL’s allowed revenue in 2008/09 revenues. As can be seen, SHETL’s was £57 million, or 0.09% of the average proportion of the overall pot is small. customer bill. Figure 5.2 on page 38 illustrates the Ofgem calculates that the average customer proportion of an average customer’s bill electricity bill in 2010 was £424. The current which is transmission costs; and Figures 5.3 allowed revenue of our transmission system and 5.4 above illustrate the proportion within that bill is approximately 38p. of an average customer’s bill which would Even increasing those allowed revenues be transmission costs if SHETL increased ten-fold would represent a payment its allowed revenue by two-fold (Figure 5.3) of under £4 each year, to just under 1% or ten-fold (Figure 5.4). of the average customer bill.
39 Keeping the lights on and supporting growth
Contacts
To respond to this document or request further information please write to: Landel Johnston Scottish Hydro Electric Transmission Limited Inveralmond House 200 Dunkeld Road Perth PH1 3AQ Or send your views via: [email protected] Please submit your comments by 21 March 2011. Media enquiries should be directed to SSE’s Press Office on +44 (0)845 0760 630 Registered in Scotland No. SC213461 Scottish Hydro Electric Transmission Limited is a member of the Scottish and Southern Energy Group
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