ScotWind

224. In June 2020, CES launched the ScotWind leasing round to grant option agreements for new commercial scale fixed, floating or hybrid offshore wind projects in Scottish waters. A total of 17 ScotWind sites were awarded in January 2022 at a total combined estimated capacity of 24.8 GW (CES, 2022).
225. The site options selected for ScotWind were informed by the Scottish Government’s spatial framework set out in the Sectoral Marine Plan for Offshore Wind Energy (SMP). The SMP, set out what are considered by Marine Scotland to be the most suitable and sustainable locations (excluding those previously awarded) for future development of commercial offshore wind energy in Scottish waters. The SMP provided the strategically planned spatial footprint for offshore wind development in Scotland and identified 15 Plan Options (“POs”), split across 4 regions which were considered capable of generating several GW of renewable energy.
226. A strategic plan-level HRA was carried out to underpin the SMP and this is to be updated through an iterative review process and to take account of INTOG (see above). It is understood that the updated plan-level HRA will not be available until winter 2023/2024 (no firm timeline commitment has been made).
227. The following observations are made:

• Even assuming improvement on historic OWF development timescales (see Figure 6 above), these projects are unlikely to be generating power before 2030. Timescales may increase for some ScotWind projects due the sites being in deeper waters, as well as the low proportion of fixed offshore wind (a quarter of capacity awarded).
• As noted earlier, there is 3.7GW of ScotWind sites listed with grid connection agreements effective from 2033[70]. While some ScotWind projects aim to be advanced in the late 2020s, challenges remain in securing National Grid connection agreements which could result in delays to some projects. Due to the uncertainty around National Grid connection options and potential supply chain issues it is likely that projects leased through the Scotwind project could have varied timelines for project development. As a result, it is hard to predict how many projects will contribute to 2030 targets with a number of projects likely to come online in the following decade.
• There will be project attrition in the years ahead[71] and not all proposed ScotWind projects will progress on time, or at the full potential capacity. Some projects may not proceed at all.
• The purpose of the ScotWind round is to provide additional capacity towards the Scotland target of 8 – 11G and the UK target of 50GW, not make up a "capacity gap" created by a failure to deliver remaining Round 3 projects such as The Project.
• It has been concluded above that “do nothing” (i.e. no The Project) is not an alternative solution and that Scottish and UK OWF capacity targets for 2030 will not be met without The Project’s contribution. The existence of the ScotWind does not alter that conclusion.
  228. For all these reasons, it is concluded that reliance on ScotWind projects (alone or in aggregate) is not an alternative solution to The Project in the context of the legal commitments and policy objectives to be delivered by 2030.

Repowering Existing Offshore Wind Farms

229. Most operational wind farms to date typically have an expected operational life span of between 20 and 35 years (although TCE / CES lease periods can be much longer) before either decommissioning or repowering is considered. To date only Blyth OWF has been decommissioned (in 2019, 4 GW). As wind turbine technology continues to evolve and the understanding of turbine condition and performance monitoring grows, OWF assets may be expected to operate for longer periods than originally anticipated. However, it is possible that some existing OWFs will be repowered in the next decade.
230. The following observations are made:

• Even if some of the earliest OWFs (2003 onwards) are repowered in the future (using larger turbines), these will not contribute materially towards the 2030 targets as the majority or at least a proportion of their capacity is already accounted for in the existing baseline.
• Not all existing OWFs will necessarily repower[72].
• Many of the earlier OWFs (Rounds 1 and 2) are closer to shore and larger/modern scale turbines may give rise to greater landscape and visual impacts, with additional consenting risk.
• Given all the above, it cannot be assumed that repowering will have a material additive effect in terms of increasing the baseline of installed OWF capacity, or that it would provide anything approaching 4.1GW of additional/new installed OWF capacity.
• While it could reasonably be assumed that consenting and development timescales will be shorter than for new ‘virgin’ locations, that may be offset to some degree by downstream complexities around decommissioning (old) / construction (new) stage. Furthermore, to contribute to 2030 targets, any such repowering projects would need to be coming forward in the next few years at the very latest.
• Repowering of existing OWF projects will not achieve The Project core project objective 5 (deliver a significant volume of new low carbon electricity generation as soon as possible, with a substantial contribution to the UK national grid before 2030) nor core project objective 6 (helping ensure the UK energy supply security from the mid-2020s).
• It has been concluded above that “do nothing” (i.e. no Project) is not an alternative solution and that Scottish and UK OWF capacity targets will not be met without The Project’s contribution. The possibility that some existing schemes will repower over the next decade does not alter that conclusion.
  231. For all these reasons, reliance on repowering of existing OWF projects (alone or in aggregate) is not an alternative solution to The Project.

Summary and Conclusions

232. The analysis in this Section 7.3 has demonstrated The Project is critical to achieve the Scottish and UK Government targets for 2030 and there are no alternative offshore locations which constitute feasible alternative solutions to The Project. This conclusion is reached on one or more of the following key grounds:

• Existing / in construction / consented OWF projects form part of the baseline which is ‘baked’ into the 2030 11GW and 50GW installed capacity targets – these projects do not provide additional new installed capacity.
• The Project has a grid connection and is in planning and can substantially contribute during the 2020s. Conversely, even assuming improvements on historic OWF development timescales (see Figure 6 above), OWF projects without a grid connection and not yet in planning are unlikely to be operational before 2030.
• Without The Project’s contribution, Scottish and UK OWF installed capacity targets for 2030 will not be met. There is no other currently proposed single alternative project capable of generating the 4.1 GW of energy of The Project.
• Current and any future OWF leasing rounds are complementary and required in addition (and are not an alternative) to 4.1GW from The Project, given the scale and urgency of the need case (as described in Section 3);
• TCE Extensions Round (2017), Round 4 and the Celtic Sea Round projects do not meet The Project core project objectives 2, 3, 5 or 6.
• There are more complex pathways and cost premiums associated with the floating wind OWF projects (as compared to fixed bottom in shallower waters) that will come forward in the ScotWind, INTOG and Celtic Sea Rounds. Such projects in these rounds do not or are unlikely to meet The Project core project objectives 3, 4, 5 or 6.

Table 12 Performance of alternative locations outside former Firth of Forth zone against project objectives

7.4. Alternative Array Locations within Former Firth of Forth Zone

233. In arriving at the final site boundary for the Proposed Development, a wide array of alternative options in the former Firth of Forth Zone were considered during an extensive and iterative process which has identified the most suitable, feasible site to achieve the Project’s core project objectives.
234. The boundary refinements and final site boundary are shown in Figure 8 below. The approach taken to site selection and project definition involved a number of stages as summarised below.

• stage 1 – Firth of Forth Zone Identification and Award;
• stage 2 – Zone Appraisal and Planning (ZAP);
• stage 3 – Project Identification and approval (PIA) Process; and
• stage 4 – Development of the Proposed Development.
  235. Further information on site selection and boundary refinements is presented in Offshore EIA Chapter: Site Selection and Consideration of Alternatives (Volume 1, Chapter 4). Key information is summarised in the following sections below.

Figure 8 Phased boundary refinement for Firth of Forth Zone projects

Identification of Firth of Forth Zone

236. The former Firth of Forth Zone was a fixed region identified and defined by TCE during Round 3 and leased with exclusive development rights to SSER in 2010.
237. The Round 3 zones were identified, and refined, by TCE through a systematic process of analysis and assessment of spatial data included in their Marine Resource Geographical Information Systems (GIS) System (MaRS) (TCE, 2012).
238. The approach taken by the TCE was to identify zones for offshore wind projects within the broader geographical areas identified by the Offshore Energy Strategic Environment Assessment.
239. During 2008/2009, TCE completed three iterations of its three-stage approach to the delineation of the Round 3 Zones outlined below.

• Stage 1: Identification and removal of areas identified as being unsuitable for offshore wind due to, e.g. exclusions to development or technical conditions or external interests such as excessive water depths or an International Maritime Organisation shipping lane.
• Stage 2: Evaluation of remaining areas of seabed to determine suitability based on restrictions present and possible constraints.
• Stage 3: Outputs from the national scale mapping and modelling then reviewed against other detailed review datasets.
  240. During each iteration, the outputs from the modelling were discussed by TCE with key stakeholders. Taking into account feedback from engagement with stakeholders and refinements applied to the mapped data, spatial analysis and review of other datasets, the number of zones identified were reduced from 11 to the final nine Zones, including the Firth of Forth Zone.
  241. A Zone Development Agreement was set up between SSER and TCE for the former Firth of Forth, to facilitate delivery of several GWs through several OWFs. The Zone Development Agreement has since been replaced by Agreements for Lease for each OWF project, namely Seagreen Alpha/Bravo and now The Project.
  242. The evolution from award of the Firth of Forth Zone to the definition of the final layout of the Proposed Development (basis of this application) is illustrated in Figure 9 below. Further detail on this process is provided in Offshore EIA Chapter: Site Selection and Consideration of Alternatives (Volume 1, Chapter 4), with key stages summarised here.

FIrth of Forth Zone Appraisal (2010-2012)

243. The ZAP process was used to identify sites for individual projects within the Firth of Forth Zone. This was a discretionary, non-statutory process recommended by TCE (TCE, 2012), the aim of which was to:

• optimise the development opportunity by identifying the most technical and environmentally suitable development sites within the Firth of Forth Zone;
• promote stakeholder engagement at a strategic level to inform the long-term development strategy; and
• consider cumulative impacts across the former Firth of Forth Zone, particularly in relation to other offshore wind farm developments.
  244. The ZAP process involved detailed mapping and analysis of a range of environmental and technical constraints within, and surrounding, the Firth of Forth Zone. Data considered in the ZAP process included:
• water depths (UK Hydrographic Office (UKHO) bathymetry dataset) and seabed conditions;
• wind speed and metocean conditions (Met office 10-year wind dataset);
• nature conservation designations SPAs, SACs, SSSIs and Important Bird Areas (IBAs);
• ornithological data (data from 24 months of boat based surveys (2009 to 2011) covering the entire Firth of Forth Zone, sightings data from TCE aerial surveys (2009/2010), SPA bird tracking studies (2010);
• benthic and intertidal ecology data;
• fisheries spawning and nursery grounds (Centre for Environment, Fisheries and Aquaculture Science (CEFAS) mapped data);
• marine mammals including cetaceans and seals (18 months boat-based survey sightings 2009 to 2011 for the entire Firth of Forth Zone and sightings data from TCE aerial surveys (2009/2010));
• fisheries activity (Marine Scotland data);
• shipping and navigation — Automated Identification System (AIS) data and radar surveys (summer and winter 2010 to 2011 completed by the Forth and Tay Offshore Wind Developers Group (FTOWDG);
• seascape and landscape – landscape designations and protected areas;
• marine archaeology and cultural heritage;
• aviation and telecommunications issues, including civil and military aspects;
• oil and gas infrastructure;
• emergency services; and
• cables and pipelines.

Figure 9 Approach to Site Selection and Project Definition

245. The outcome from the ZAP process was the division of the Firth of Forth Zone into three areas which would be developed in phases. These areas are illustrated in Figure 10 below.

Figure 10  Evolution of Project Boundaries and Names in the Firth of Forth Zone from 2010 to 2020

Project Identification and Approval (2017 – 2020)

246. The Project Identification and approval (PIA) process commenced in 2017 and further refined boundaries for each of the three prioritised sites, primarily due to a greater understanding of environmental constraints and impacts and through stakeholder engagement.
247. The PIA process involved the following:

• identification of areas largely beyond the foraging range of key seabird species;
• review and analysis of available boat based ornithology survey results;
• review and analysis of 2010 and 2011 metocean survey data acquired across the entire Firth of Forth Zone by Seagreen;
• review and analysis of 2012 nearshore measurements and wavebuoy data;
• consideration of other conservation interests (including new nature conservation designations - Firth of Forth and St. Andrews Bay Complex SPA, Firth of Forth Banks Complex NCMPA and SNS SAC) to determine extent and nature of potential interactions with these designations);
• analysis of water depths; and
• consideration of separation distance from Seagreen 1, Seagreen 1A Project and adjacent STW projects.
  248. The outcome from the 2017 PIA process was the identification of two separate 1 GW projects within Phases 2 and 3 (Seagreen Charlie and Seagreen Delta respectively).
  249. In 2018, SSER carried out analysis on the boat based ornithological survey data obtained for the Firth of Forth Zone, and ornithological data from the other Forth and Tay projects. From this analysis it emerged that there is potential for areas of ornithologically sensitivity to overlap the Phase 3 part of the Firth of Forth Zone (referred to as Seagreen Delta at the time, prior to becoming Seagreen 3 in 2018 and then Marr Bank in 2020). However, taking into account these ornithological sensitivities, it was concluded that, based on the published review of collision avoidance rates (BTO, 2014), sufficient ‘headroom’[73] was potentially available for further offshore wind farm development in the Forth and Tay region.
  250. Having identified the potential for ornithological headroom, the PIA was further progressed to consider advances in wind turbine technology including the deployment of fewer, larger wind turbines (e.g. wind turbines with capacity of more than 10 MW) to deliver the same project capacity and the ability to increase the minimum sea level to blade tip clearance (air gap) from the standard 22 m towards 30 m or more.
  251. Whilst progressing the PIA, all three of the Forth and Tay projects applied to vary their Section 36 consents to use fewer, larger wind turbines capable of generating the same capacity as the consented designs, reducing potential impacts on ornithology. The variations are summarised in Offshore EIA Chapter: Site Selection and Consideration of Alternatives (Volume 1, Chapter 4).
  252. Importantly, for each project, it was concluded in the AA that there would be a reduction in the predicted collision impacts due to the use of fewer larger wind turbines. As such, considerable headroom in the region has been released through the revised Forth and Tay consents, with further potential headroom available from current and ongoing empirical research designed to reduce uncertainty in ornithology assessments, and from as-built versus consented designs outside of the Forth and Tay region as explored through the Offshore Wind Evidence and Change Programme.

Identification of Marr Bank and Berwick Bank (2020)

253. Having confirmed that there is ornithological headroom available within the Firth of Forth Zone, SSER took the decision to progress development of the Phase 2 and 3 areas.
254. Following a number of internal boundary reviews and project iterations it was determined that the two projects identified within these Phase 2 and 3 areas (Seagreen 2 and 3) would be renamed Berwick Bank and Marr Bank respectively.
255. In August 2020, an Offshore EIA Scoping Report (SSER, 2020a) was submitted to MS-LOT for an offshore wind farm project within the Phase 2 area (2020 Berwick Bank). Although the Phase 3 area (Marr Bank) was also being progressed it was at an earlier stage of development.

Development and Refinement of the Proposed Development (2021-202)

256. The stages in the development and refinement of the Proposed Development from submission of the 2020 Berwick Bank Wind Farm Offshore EIA Scoping Report in August 2020 to finalisation of the Proposed Development boundary included in this application (May 2022) are summarised in Table 4.7 of EIA Chapter 4 (Volume 1).
257. In summary, in response to feedback received from stakeholders advising that it would be preferable to combine the boundaries of the 2020 Berwick Bank and Marr Bank projects into one single project, the Applicant commenced a detailed site assessment and refinement study. This study (March 2021 to October 2021) focused specifically on the exploration of options for maximising capacity within the Berwick Bank Wind Farm boundary whist reducing potential effects on ornithology and other key receptors.
258. To reduce effects on ornithology, analysis of a subset of the ornithological aerial survey data was undertaken to identify ‘hotspots’ for key species. Where possible, overlaps with these ‘hotspots’ were avoided or minimised. Consideration was also given to options to minimise potential barrier effects (including cumulatively with other Forth and Tay projects) for key species such as gannet.
259. Combining the 2020 Berwick Bank and Marr Bank boundaries to create the Proposed Development provided the Applicant with an opportunity to:

• Reduce the overall footprint of the array area: The combined total area of Marr Bank + Berwick Bank was 1,441 km2. Through refinements, to avoid/reduce overlap with sensitive areas and features, the Berwick Bank boundary reduced by 9%, to 1,314 km2
• Avoid areas of higher ornithological activity: through boundary refinements focused on the northern and north-eastern boundaries which overlap areas which may be associated with feeding grounds.
• Increase the buffer between the Berwick Bank Wind Farm and the other Forth and Tay projects (Inch Cape Offshore Wind Farm, Seagreen 1 and Seagreen 1A Project): This increased the area of open sea available for birds to pass through the area, reducing potential barrier effects.
  260. Development of the Proposed Development boundary was also necessarily informed by detailed engineering site studies, including preliminary assessment of ground conditions for the installation of preferred foundation options (suction caissons and jackets). This was necessary to ensure suitability of ground conditions including the associated consideration of the effects on the LCoE. The site assessment and refinement study culminated in the submission of the Berwick Bank Wind Farm Offshore EIA Scoping Report (SSER, 2021a) to MS-LOT in October 2021.

Boundary Change - Proposed Development Boundary (May 2022)

261. In March 2022 a boundary review process was initiated to explore options for further reducing impacts, whilst meeting The Proposed Development’s overarching aims and objectives. This process concluded in late May 2022, resulting in a further 23% reduction of the array area (from 1,314 km2 to 1,010.2 km2). A comparison with the previous site boundary is shown on Figure 8 above and Figure 11 below.
262. Key environmental benefits influencing the boundary change are summarised in Offshore EIA Chapter: Site Selection and Consideration of Alternatives (Volume 1, Chapter 4) but, so far as relevant to this Report, the change resulted in the removal of identified areas of high utilisation of seabirds (potential foraging hotspots) in the north of the array area and in western and south-western part of the array area, in particular for guillemot and kittiwake.
263. The boundary change, which resulted in a deepening of the northern notch by moving the north-western and northern boundary further south, and removal of the south-western corner was calculated to result in a >20% reduction in ornithological displacement impacts. Changes to the north-western boundary also reduced the extent to which the array area overlapped the Firth of Forth Complex ncMarine Protected Area (MPA). Features associated with the ncMPA were identified in the data sources above as typically being more frequently used by seabirds compared to areas further offshore (as a function of being closer to breeding SPA populations). The ornithological benefit of removing this area from the site boundary include a reduction in displacement impacts and slight reduction in modelled collision mortality, through an overall reduction in seabird densities figures.
264. The ‘stepped’ south-eastern boundary of the array area was originally delineated by the Outer Firth of Forth and St Andrew’s Bay SPA. As part of the boundary change, a 2 km buffer between the Outer Firth of Forth and St Andrew’s Bay SPA and the Proposed Development was added to ensure that there is no direct overlap relating to this site.

Figure 11 Influence of Firth of Forth Banks Complex ncMPA and Outer Firth of Forth and St Andrew’s Bay SPA on boundary

Conclusions

265. The preceding sections demonstrate that the final site boundary for the Proposed Development was the result of an iterative, careful and exhaustive process, one that supports the conclusion that there are no feasible alternative locations remaining within the former Firth of Forth Zone to achieve The Proposed Development core project objectives. This conclusion is reached on the following key grounds:

• The northern portion of the former Firth of Forth Zone has already been developed (Seagreen and Seagreen 1A) and is no longer available.
• Given the foraging range and behaviour of a number of the qualifying species of the affected SPAs, all possible locations for commercial scale OWFs within the former Firth of Forth Zone have connectivity with one or more species from the SPAs. There is no location within the former Firth of Forth Zone that could be developed without impacts on species from these SPAs.
• Locations further to the west would be in closer proximity to or encroach upon the closest SPA, and overlap to a greater degree with an MPA and give rise to greater impact on shipping and navigation[74] and commercial fishing interests.
• Locations further south would remain in similar proximity to or encroach upon the SPA (and overlap to a greater degree with an MPA).
  266. Summary of the performance of array alternatives within the former Firth of Forth zone is provided below in Table 13   Open ▸ .

Table 13 Performance of alternative locations within the former Firth of Forth zone against project objectives

7.5. Alternative Design solutions for The Proposed Development

Market Context

267. The scale and urgency of the need for offshore wind as described earlier in Section 3 of this Report necessitates solutions that maximise the feasible installable capacity at each available offshore site.
268. Constraining projects within Zones/ sites made available for OWF by TCE or CES will result in sub-optimal and inefficient use of areas of seabed identified as being least constrained / most suitable. That of itself is contrary to fundamental policy aims and objectives articulated in Section 3 of this Report. Moreover, if the available and least-constrained seabed areas are used sub-optimally, more projects need to be delivered in ever more challenging and constrained locations.
269. The consideration of alternative solutions must be approached on a reasonable basis and must be grounded in real world considerations of feasibility (legally, technically and commercially). These decisions involve the exercise of a degree of judgement, drawing on experience and available information and analysis of future market trends.
270.           In this context it is relevant and reasonable for the Scottish Ministers to place weight on the experience and expertise of the Applicant in offshore wind development. SSE Renewables is a world-leading developer, operator and owner of offshore wind energy. SSER developed the 588MW Beatrice offshore wind farm, which became fully operational in June 2019. Beatrice is Scotland's second largest offshore wind farm and it's 84 wind turbines are capable of providing enough wind powered electricity for up to 450,000 homes. With a capital expenditure of around £2.5bn, Beatrice was also one of the largest ever private investments in Scottish infrastructure and was delivered on time and under budget. SSER is currently building the world’s largest offshore wind energy project of capacity 3.6GW (Dogger Bank wind Farm) and Scotland’s largest and deepest fixed bottom offshore site (Seagreen OWF). When complete these projects will power millions of UK homes and businesses and add to SSER’s existing 487 MW offshore wind portfolio. SSER is also actively pursuing offshore wind projects in Denmark, Poland, Spain and Portugal.
271. The nature and viable scale of an OWF has to be considered in the context of the specific characteristics of the individual site (e.g. water depths), grid connection availability and the highly competitive commercial framework within which such projects are delivered. In addition to environmental impacts, factors which have influenced the PDE include:

• grid connection availability and capacity (4.1GW in this case);
• viable generation capacity (GW size) to optimise secured grid connection capacity;
• commercial expectations prescribed by funding mechanisms (such as CfD);
• construction costs of array, transmission and grid connection;
• technology availability, cost and reliability;
• health and safety considerations;
• supply chain capacity and availability; and
• project execution schedule (relative to Scottish and UK targets, e.g. for 2030).
  272. In this context, the Applicant has continued to re-appraise all elements of the PDE for The Proposed Development, to ensure that all feasible mitigation has been deployed. The Proposed Development has adopted commitments (primary design principles inherent as part of The Proposed Development, installation techniques and engineering designs/modifications) as part of their pre-application phase, to eliminate and/or reduce the negative effects arising from a number of impacts (as far as possible). These are outlined in full in the Enhancement, Mitigation and Monitoring Commitments Register in Volume 3 Appendix 6.3 of the EIA.
  273. The final PDE for The Proposed Development is informed by expert judgement and market leading expertise of the realities and challenges of construction in the marine environment. The Applicant believes that the vast experience it has in offshore wind delivery in the UK and overseas, combined with the evidence below, should give the Scottish Ministers confidence that the Applicant has considered all feasible options to avoid or reduce harm to European sites whilst ensuring a viable and deliverable project.

Scope of Consideration of Alternative Design

274. The scope to resort to feasible alternative solutions has been considered throughout the development process for The Proposed Development. This has been a fundamental driver for decision making, from the technical options in engineering through to macro-siting (avoidance of large-scale features and designated sites).
275. Details of refinements to date to the PDE are set out in Offshore EIA: Chapter 4: Site Selection and Consideration of Alternatives (Volume 1, Chapter 4).
276. The identified AEOI would arise from collision and/or displacement risk related to the operation of wind turbines, and so the primary project design parameters which may influence these impact pathways during operation are considered to be:

• Array location (relative to SPA);
• Array size / number of turbines;
• Height of turbine blades above sea surface.
  277. The justification for the Proposed Development array location (and the absence of feasible alternative locations) has been set out in preceding Section 7.4 of this Report. Accordingly, the further potential alternative design solutions considered during this stage of the Derogation Case are:
• A reduced/refined or alternative developable array area - aimed at further reducing/refining the geographical extent of the wind turbines to avoid sensitive areas for seabirds;
• A reduced number of turbines (and/or a change in their layout) - aimed at reducing the scale of potential effects from the wind turbines; and
• A higher minimum lower tip height (height of turbine blades above sea surface) – which reduces collisions by raising the rotor to heights where bird densities are lower due to the skewed nature of bird flight height distribution[75].

Reduction of Developable array Area / Turbine Numbers

278. The Applicant has carefully considered the size of the array area and the number of turbines taken forward to consent application. This has necessarily involved balancing environmental, engineering and economic constraints, access to other marine users, consenting and commercial considerations, alongside technical feasibility for construction.
279. Reducing ornithological impacts on the affected SPAs has been a key driver of the site refinement process and resulted in two site boundary changes (described in Section 7.4 above) which reduced the overall developable area by 9% (first refinement) and then by a further 20% (second refinement). That reduced the footprint overlapping areas of higher ornithological activity associated with feeding grounds; and created a wider passage for birds through the sites and adjacent OWFs to reduce barrier effects.
280. The assessment of effects on ornithological receptors is based on a resultant worst-case scenario, which is a maximum of 307 wind turbines, a minimum turbine spacing of 1,000m, at turbine parameters indicative of a minimum 14 MW turbine.
281. It is acknowledged that array size / density / wind turbine numbers have an influence on both displacement and collision risk impacts, with impacts increasing as wind turbine numbers increase. Indeed, this informed the site boundary reductions described above and the selection of turbine parameters indicative of a minimum 14GW turbine (increased from a previous minimum of 10MW, to minimise the number of turbines).
282. Potential impacts can therefore in theory always be further and further reduced with a corresponding decrease in array footprint / wind turbine numbers. However, it is necessary to consider technical requirements and market conditions (e.g. turbine availability), and the consequent risk that several core project objectives would no longer be achieved. Turbine procurement and availability are significant considerations in this regard.
283. It is not possible at this stage to further reduce turbine numbers and, consequently, not possible to further reduce the array developable area, because the accelerated development timeline for the Proposed Development makes it critical for the PDE to encompass turbine models which the Applicant is confident can be procured cost effectively and will be available within the Proposed Development’s delivery timelines (both of which flow from making an order at sufficient scale). This engineering and commercial flexibility is essential to secure a competitive and deliverable project in the 2020s.
284. Any reduction in developable area / minimum turbine numbers at this stage gives rise to an unacceptable risk of one or more of the following outcomes:

• Failure to achieve 4.1GW installed capacity;
• Failure to maximise export cable capacity and grid connection capacity;
• Inefficient use of seabed (lower overall capacity);
• Reduced flexibility to ‘micro-site’ turbine locations to optimise array layout, e.g. to account for ground conditions, to avoid any previously unknown constraints (e.g. UXO) or to accommodate other sea users;
• Suboptimal array layout / failure to maximise energy yield, with a higher density turbine layout within a reduced array area, potentially causing wake loss effects that decrease productivity and increase cost of electricity;
• Delays (and consequent additional cost) owing to lack of turbine availability when needed;
• Failure to maximise economies of scale, restricting ability to decrease the LCoE over that established in recent CfD auction rounds and achieve a further decrease in generation cost per MW;
• Jeopardise the Applicant’s ability to be able to put forward a competitive proposition in a future CfD auction round.
  285. A further reduction to the proposed maximum of 307 turbines is accordingly not considered feasible. Optimising the business case to fulfil the Proposed Development need and objectives is essential to develop a viable project. The Proposed Development must compete for a CfD in a competitive tender – without which it may not attract finance to be constructed and therefore not contribute to the mitigation of the “climate emergency” and would not help to address security of energy supply risks.
  286. The Proposed Development has secured grid connection capacity for 4.1GW and for urgent decarbonisation and security of supply reasons it is important to maximise that available export capacity and bring as much low carbon electricity online as quickly as possible, and before 2030. A failure to maximise the generation and export capacities of The Proposed Development is not compatible with the core project objectives or the urgent need which they serve.
  287. A lower capacity at The Proposed Development would also have a ratcheting effect on the number and capacity of additional OWFs required in order to hit Net Zero and corresponding timescales. Delivering low carbon generation capacity later than is achievable allows time for carbon emissions to further accumulate increasing the magnitude of subsequent action required.
  288. For all these reasons, further array area or turbine reductions are not feasible alternative solutions.

Table 14 Performance of alternative array / turbine design options against project objectives

Increase Minimum Lower Tip Height

289. The iterative project design process has culminated in raised turbine blade lower tip height of 37m above Lowest Astronomical Tide (LAT). The current 37m abobe LAT ‘is a material design change (i.e. alternative design solution) that has been implemented and increases the ‘air draught’ by 15m as compared to the former Berwick and Marr Bank projects blade tip to sea clearance of 22m above LAT.
290. This has delivered significant mitigation of collision risk impact. Moving the rotor swept area to altitudes where seabird densities are lower due to the skewed nature of bird flight height distribution[76] has significantly reduced the impact, by minimising the risk of collision for the key seabird species in flight so far as feasible within the current bounds of technical and economic viability of the Proposed Development.
291. A minimum air draught of 37 m LAT is considered to be the maximum technically feasible in the circumstances of the Proposed Development. Increasing the minimum air-draught beyond 37m above LAT would have implications on technical aspects, the related supply chain and consequent commercial implications. Further reduction in the intersection of the swept path with flight zones is considered to be unachievable, as vessels do not currently have the capability to achieve installation at this height in the conditions set within The Proposed Development. This is due to a combination of water depth (jack-up legs) and turbine height (crane height)).
292. Therefore, any further increase in air draught height is not currently feasible and would unacceptably increase the Proposed Development ’s costs and supply chain risk, which would jeopardise early delivery of low-cost generation for the benefit of UK electricity consumers.

Table 15 Performance of alternative turbine rotor design option against project objectives