8. Affordability

8.1. Setting the scene

465. The third pillar of GB’s energy strategy, is economic efficiency. The UK has 40% of Europe’s wind resource [40] and most renewable energy resources can only be developed where the resource exists and where economically feasible. Scotland, as a part of Great Britain, is served by the GB Electricity Market and therefore an assessment of the affordability of the Project is relevant at the UK level.
466. Analysis [commissioned by the NIC] suggests that there is no material cost impact, either over the short or long term, of deploying renewables faster. Renewables are now the cheapest form of electricity generation due to dramatic cost reductions in recent years. Cost reductions have been greater than was predicted in 2018 when the Commission made its recommendation on what level of renewable generation the government should be targeting. [84]
467. This section discusses broad principles of affordability and economic efficiency, by explaining how the UK's electricity market operates and demonstrating how recent gains in experience, technology and scale have increased the economic efficiency of offshore wind.

8.2. UK electricity pricing

468. In the UK power market, generators schedule themselves to generate in response to whether a market price signal for a specific period is above or below their marginal cost of generation (The cost of generating one additional MWh, usually including variable fuel and transmission costs). Each day is subdivided into 48 half-hour periods (Settlement Periods) and power is traded ahead of delivery for these periods, or continuous groups thereof, from just 90 minutes ahead, up to months or even seasons ahead. Typically, wind farms have very low or zero marginal costs and therefore generate as much as they are able to, when they are available (i.e. whenever the wind is blowing). Because of the variable nature of the wind, they also tend to trade on the near-term power markets, therefore much of their impact on power price is felt in the few days close to delivery. Thermal and hydro plants have higher marginal costs (relating to the cost of the fuel they are converting into that additional MWh), therefore will generally only when the market is providing a higher price signal. They may also trade power and fuel costs further ahead in order to lock in a gross margin. All generators produce active power (MWs), and to balance the electricity system, the active power generated must meet the system load at all times. If wind farms are generating electricity during a settlement period, then less electricity is required from plants with more expensive marginal costs, therefore the price of electricity for that settlement period reduces.
469. This market mechanism is illustrated in Figure 8‑1.
470. The blue line, increasing from left to right with the x-axis, represents the marginal cost of generation in the UK at each level of generation required to meet anticipated demand. As demand increases, more expensive supply must be scheduled into the market. This is represented by the three red lines. At a mid-level of demand, the solid red line crosses the blue line at about £45 / MWh. This becomes the price of power. If demand falls (e.g. to the left-hand dashed red line), less plant is required to run to meet demand, therefore the marginal cost of the most expensive asset required to run to meet demand is lower. Therefore the price of power reduces (here, to about £10 / MWh). Conversely, as demand increases, (e.g. to the right-hand dashed red line) assets with higher marginal costs of production are required to run; therefore the price of power increases (in this example, to about £65 / MWh).

Figure 8‑1: Representative marginal cost stack for the GB electricity system.

[Author analysis]

471. Critically, the blue line in Figure 8‑1 also varies for each half hour settlement period, as generating assets become available or unavailable due to outages or breakdowns, or maybe more or less wind is expected than was forecast. Therefore as more electricity is generated by wind, the blue line within the red ellipse (around a zero marginal cost of power) will stretch horizontally, and as a result, the blue line slides to the right for all higher levels of demand. The marginal cost of production to meet demand over these periods will therefore be lower and as a result, the traded price of power will be lower. By running this type of analysis over every settlement period over the future trading horizon, it is possible to derive a power price view for the next hour, day, week, month, quarter or season.
472. The conclusions are consistent though: increasing the capacity of renewable assets in the UK has a reducing effect on power price at delivery. This demonstrates that offshore wind power reduces the market price of electricity in the UK. However the effect is not limited to the UK. The Energy Institute of 104 have quantified the impact of deep solar penetration in California, an historically conventional generation market. Their paper concludes that renewable investment has had a significant impact on power prices, and appears to be responsible for the majority of price declines over the last half-decade in California [104].

8.3. Levelised cost of offshore wind generation

473. Technological advances in fixed base wind generation are unfolding, although the scope is limited by the specific nature of wind turbines. The blade design, the steel in the supporting structures, and the efficiency of the conversion to electricity are all areas for incremental improvements. Given that wind is a small-scale and low-density form of generating electricity, many of the cost reductions have come from logistics and maintenance, especially offshore, and new designs of floating platforms may add further opportunity although floating offshore wind is as yet unproven. Although incremental, the cost reductions have been dramatic [102].
474. The market mechanisms described in Section 8.2 only reduce the price of power if wind projects come to market, or if developers believe they are able to make reasonable returns on their investments. The cost of wind generation is an important enabler of offshore wind development, and the Offshore Wind Sector Deal was struck on the expectation that costs would continue to fall, and UK content would increase for future developments.
475. As well as the incremental cost improvements detailed above, wind turbines have got bigger and more efficient, and are being installed in larger populations to increase the size of wind farms. See Figure 8‑2. The product of all of these factors is that offshore wind is now a leading low-cost generation technology globally and the UK and Scotland are leading the field. See Figure 8‑3.

Figure 8‑2: Offshore wind turbine generation capacity has increased significantly since 2002.

[27]

476. An important measure of the lifetime cost of wind generation, is its Levelised Cost of Generation (LCOG). LCOG is calculated using a discounting methodology, and is a measure of the lifetime unit cost of generation from an asset. Critically this allows all forms of generation to be compared with each other on a consistent basis.
477. BEIS published Electricity Cost of Generation reports in 2013, 2016 and 2020. These reports provide a comparison of how cost forecasts have evolved over time; how costs of different generation technologies compare to each other; and how costs are expected to evolve into the future. Figure 8‑3 shows data from BEIS' 2020 report [65]. Each triple of blue columns illustrates a forecast range of levelised generation cost for assets commissioned in 2025, 2030 and 2035, for CCGT, Offshore wind, Onshore wind, large scale solar and CCGT + CCS. The red stripes show, for CCGT and CCGT + CCS, those costs vary with price sensitivities applied for fuel and carbon costs. The conclusions are clear: renewable generation assets are significantly cheaper over their lifetimes, than new CCGT stations, whether abated or not. Offshore wind costs reduce in the 2025 - 2030 timeframe as a result of economies of scale and technological advances reducing capital costs and fixed O&M costs.

Figure 8‑3: BEIS Cost of Generation comparison for technologies deployed in 2025, 2030, 2035.

Adapted from [65]

478. The levelised cost of offshore wind also reduces to be lower than that of onshore wind in the 2030 timeframe, continuing its trend of superior cost reduction performance versus since 2013. Figure 8‑4 shows how levelised cost forecasts have reduced from 2013 (light grey) to 2016 (darker grey) and through to 2020 (blue). The costs of offshore wind have reduced and are forecast to reduce further still.
479. The 2020 cost projections include a high and low range (dots) which also illustrates that the cost certainty of offshore wind has improved significantly and progressively since 2013.

480. The NIC have also concluded that RES represent a most likely low-cost solution for GB electricity generation, over large-scale conventional investments. Their conclusion recognises that more renewables do lead to more money being spent on operating the electricity system and matching supply and demand, but conclude that cheaper capital costs will more than offset these costs to reduce overall electricity and energy system costs for consumers [66].

Figure 8‑4: BEIS Cost of Generation – Evolution of levelised cost forecasts.

Author analysis from [65]

481. Wind costs are driven by capital infrastructure, development and integration costs, and lifetime O&M. Economies of scale and technological advances have reduced the costs of wind turbines, increased their efficiencies and extended their useable lifetimes. For example, due to improved manufacturing techniques and enhanced material choices, the Project may be expected to have a longer operational life than wind farms already now in operation. Development costs have also reduced as efficiencies in the build process have been captured through prior experience. This fact is also demonstrated in Figure 8‑4.
482. Other industry-sourced data and opinion concurs with BEIS' findings. For example a CCC illustration of data from IRENA analysis (2020) shows cost reductions in and competitiveness of renewable generation technologies against fossil fuel generation [43]. Lazard [105] are a globally recognised source of such comparative analysis, albeit that their reports focus on the US market, however their conclusions provide a useful global context. The most recent revision of their analysis, published in October 2021, provides additional evidence that offshore wind costs are reducing and that offshore wind is competitive against other forms of generation, particularly carbon intensive assets.

8.4. A comparison of floating and fixed bottom offshore wind costs

483. The development of floating offshore wind from demonstrator technology to commercial technology is expected to help reduce costs for deployment up to 2030 and beyond, but initial cost estimates for floating offshore wind are currently significantly higher than current fixed bottom installations. Figure 8‑5 shows OREC's forecast for levelised costs of FOW deployed from 2027 onwards. Critically, FOW levelised costs are anticipated to benefit from a higher deployment of total UK offshore wind capacity due to increased opportunities to share fixed O&M and other supply chain costs over a wider portfolio of projects.
484. Figure 8‑6 compares the cost forecast ranges for fixed bottom and floating offshore wind deployed in UK waters. FOW costs are expected to decrease rapidly because developments can learn from the technology, operational and asset management experience already demonstrated by fixed bottom offshore wind and by the offshore oil & gas industry, for example FOW will likely benefit from using state of the art turbine technology, O&M innovations and floating platform performance and cost enhancements. Much learning is transferable between industries and risks and opportunities are much better understood today than they were when fixed bottom offshore wind was in its infancy. An understanding of risks and opportunities will also drive a reduction in the cost of capital, driving greater forecast cost improvements and paving the way for FOW to benefit from greater levels of competition for project financing.

Figure 8‑5: UK FOW cost Reduction

Adapted from [83]

485. Fixed bottom offshore wind deployed this decade is likely to be significantly cheaper over its lifetime than FOW deployed over the coming twenty years. In the 2030s, if FOW deployments can expand an already large fixed bottom offshore fleet, significant and rapid cost reductions may be possible to the point of FOW achieving approximate cost parity with fixed bottom wind.
486. As would be expected with a more mature technology, the uncertainty range of current and future fixed bottom costs is smaller than that for FOW. This is partly attributed to the remaining unknowns of floating technology, as well as reflecting the wider possible geographies available for deployment of FOW, and the development costs associated with infrastructure required to bring the generated power to shore. Similar analysis has been undertaken by the United States Department of Energy [82] and their conclusions are consistent with those drawn by OREC relating to FOW deployment and cost reduction opportunities. DoE also see the potential for significant future cost reductions in FOW, but also anticipate fixed bottom assets to remain at a cost advantage to FOW assets through the next two decades.
487. The data presented draws to the conclusion that the development of fixed bottom assets is preferential to and therefore should be prioritised over FOW development in order to deliver earlier decarbonisation benefits as well as create a catalyst for future rapid and significant cost reductions for essential FOW fleet in the decades ahead.

Figure 8‑6: Comparison of future fixed bottom and floating offshore wind cost forecasts

Adapted from [83, 65]

8.5. The CfD as an indicator of UK offshore wind cost improvements

488. CfDs were first awarded to offshore wind projects in 2014 in the first Investment Contract round. Government has subsequently run four competitive Allocation Rounds, awarded in 2015, 2017, 2019 and 2022 respectively. Prior to Allocation Round 4 taking place, the UK Government signalled plans “to double the capacity awarded in the last round with the aim to deploy around 12GW of low-cost renewable generation.” Offshore wind, onshore wind and solar are key building blocks of the future generation mix, and £200 M was allocated to the AR4 offshore wind pot, without a capacity cap being set.
489. Figure 8‑7 illustrates the cumulative capacity of offshore wind contracts awarded by both allocation round and delivery year, and the weighted average strike price (all in 2012 monies) for projects within separate allocation rounds. The reduction in strike prices from round-to-round is very apparent, as is the associated increase in awarded capacity. This figure demonstrates that UK consumers are realising the benefit from offshore wind cost reductions as described in Section 8.3.

Figure 8‑7: CfD capacities and strike price evolution for offshore wind

Author analysis of [106]

490. The results of CfD Round 4 (issued July 2022) demonstrate the importance of offshore wind development to decarbonisation of the electricity system. Offshore wind was the major technology to be awarded a CfD in this round. Of almost 11GW awarded, 7GW went to offshore wind. The strike price for the allocation round was £37.35/ MWh for 2026/27 delivery, representing a significant reduction from the strike prices awarded through previous rounds. This government backed subsidy scheme has contracted projects which, when delivered, will reduce wholesale electricity prices.
491. Factors which contributed to the low price outturn for offshore wind in the latest allocation rounds include:

• Construction risk management of this technology is well advanced in the UK due to significant experience in UK territorial water installations, so developer bids included less allocation to construction risk;
• The technology has evolved over the last 5 + years, making advances in MW capacity and MWh output expectations per unit of infrastructure spend over previous projects; and
• Economies of scale and the development of an advanced supply chain have also contributed to the reduction in cost of offshore wind.

492. Many of the cost savings which have driven CfD prices lower over previous Allocation Rounds are expected to continue to transfer through to subsequent developments, however future developments will incur their own localised construction costs which may be higher or lower than those projects which have already secured CfDs. Nevertheless, it is clear that the industry is in a strong position with regard to unit cost improvements, and is prepared to pass much of this value through to consumers via a CfD. Offshore wind in the UK is currently, and is predicted to remain, super-competitive on a per MWh generated basis versus other low carbon renewable technologies.
493. The Project presents a low regrets opportunity to develop a globally significant low carbon generation asset in well-studied Scottish waters which is well located in relation to available and suitable grid connection capacity. As such, the Project has the potential to achieve a lifetime cost of electricity which is comparable to those achieved in other Scottish projects to date, when accounting for locational and technological differences. The Project will generate low cost, low carbon electricity for Scottish and UK-wide consumers while making a significant and tangible step towards meeting Scottish and UK climate change targets.

8.6. Conclusions on affordability

494. The main conclusions of this section, relating to the economic efficiency and affordability of offshore wind and of the Project itself, are as follows:

• Offshore wind power reduces the market price of electricity by displacing more expensive forms of generation from the cost stack. This delivers benefits for electricity consumers;
• Due to technological advances, the costs of offshore wind power are now close to grid parity in the UK;
• Offshore wind power is economically attractive in GB against many other forms of conventional and renewable generation, including floating offshore wind;
• By increasing the offshore wind fleet through fixed-bottom assets, it is anticipated that benefits will flow through to the developing floating offshore sector, enabling more rapid and deeper cost reductions than if would otherwise be the case; and
• Size remains important, and maximising the generating capacity of projects improves their economic efficiency, so bringing power to market at the lowest cost possible.

495. The Project proposes a substantial infrastructure asset, to be located on a well understood and well studied area of seabed. Shallower seas, closer to shore, provide the opportunity for economic benefits against other deeper water projects. The proposed location is possibly the last suitable site available for exploitation by fixed bottom offshore wind in Scottish waters. The Project is capable of delivering large amounts of cheap, low carbon electricity.
496. Maximising the capacity of generation in the resource-rich, accessible and technically deliverable proposed location, is to the benefit of all consumers in the United Kingdom, and the wind industry generally, and is consistent with all aspects of current Scottish and UK energy policy.

9. Conclusion

497. This Statement has shown that offshore wind generation is economically and technically viable in the UK and Scotland, and that it is economically and technically preferential against other low carbon options, for the UK and Scottish electricity consumer. More importantly though, this Statement has demonstrated that the Project is critical in order to deliver urgent and necessary decarbonisation actions in order to halt climate change.

• Decarbonisation to Net Zero is legal requirement for Scotland and for the UK and is of global significance. It cannot be allowed to fail, and urgent actions are required in Scotland, in the UK and abroad, to keep decarbonisation on track to limit global warming;
• Wind generation is an essential element of the delivery plan for the urgent decarbonisation of electricity generation in Scotland, and in the UK. This is important not only to reduce power-related emissions, but also to provide a timely next-step contribution to a future generation portfolio which is capable of supporting the massive increase in electricity demand which is expected because of decarbonisation-through-electrification of transport and heat;
• As part of a diverse generation mix, wind generation contributes to improve the stability of capacity utilisations among renewable generators. By being connected at the transmission system level, large-scale offshore wind generation can and will play an important role in the resilience of the GB electricity system from an adequacy and system operation perspective;
• Internationally, and importantly, the UK is leading in this regard. UK offshore wind projects are increasing in capacity, and decreasing in unit cost. Hitherto, each subsequent project has provided a real-life demonstration that size and scale works for new offshore wind, for the benefit of consumers. Other conventional low carbon generation (e.g. tidal, nuclear or conventional carbon with CCUS) remain important contributors to achieving the 2050 Net Zero obligation, but their contributions, although important, will not be significant in the 2020s; and
• Offshore wind is already super-competitive against other forms of conventional and low carbon generation, both in GB and more widely.

498. These general benefits of offshore wind generation in GB also apply specifically to the Project:

• The Project proposes a substantial infrastructure asset, capable of delivering large amounts of low carbon electricity, from as early as the mid 2020s. This is in line with the CCC’s recent identification of the need for urgent action to increase the pace of decarbonisation in the GB electricity sector;
• The Project will make an essential contribution to the low 2030 Scottish Offshore Wind Capacity Target of 8GW: without it the target capacity will not be met. The Project is therefore also essential if the high target of 11GW is to be met by bringing forwards its grid connection date and the connection dates of other projects e.g. those within the scope of National Grid’s Holistic Network Design;
• Because the Project will connect to the NETS it will be required to play its part in helping NGESO manage the national electricity system. This includes participating in mandatory balancing markets (to help balance supply and demand and provide essential ancillary services) as well as providing visibility to the power market of its expected generation. This means that the low marginal cost wind power it will produce, can be forecast and priced into future contracts for power delivery by all participants, thus allowing all consumers to benefit from the market-price reducing effect of low-marginal cost offshore wind generation;
• The location of the Project’s two connections to the NETS means that it will not the reinforcements across the northern boundaries which other Scottish offshore wind developments will require; and
• Maximising the capacity of generation in the resource-rich, accessible and technically deliverable proposed location, is to the benefit of all GB consumers, and the Scottish offshore wind industry generally.

499. In summary: the Project is capable of making meaningful and timely contributions to Scottish decarbonisation and GB security of supply, while helping lower bills for consumers throughout its operational life, thereby addressing all important aspects of existing and emerging government policy.

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