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The Energy Transition: Is Offshore Wind Done Or Going For Other Bids?


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The Energy Transition: Is Offshore Wind Done Or Going For Other Bids?

Chart 1


Seven Players Are Driving Growth In European Offshore Wind

Offshore wind is largely a European story for now. We estimate that about 80% of the global offshore wind in operation was in Europe at end-2018, and most of the substantial pipeline of projects planned, or already under construction, remain in the region. Seven European utilities dominate the market: Orsted A/S (BBB+/Stable/A-2), RWE (not rated), Vattenfall AB (BBB+/Stable/A-2), Iberdrola S.A. (BBB+/Stable/A-2), EnBW Energie Baden-Wuerttemberg AG (EnBW; A-/Stable/A-2), Electricite de France S.A. (EDF; A-/Negative/A-2), and SSE PLC (BBB+/Stable/A-2). The more prominent role of utilities, compared with solar or onshore wind, is due to offshore wind projects requiring massive capital deployment.

With about 20GW installed at end-2019, offshore wind accounts for a small 1% of the European energy mix. But this share is increasing where there is already a high concentration, particularly in the North and Baltic seas. There, weather conditions are optimal, with superior average capacity factors as high as 45%-65%, and environmental constraints are reduced. As a result, in 2019, offshore accounted for 4% of the capacity mix in the U.K., 15% in Denmark, and 3% in Germany. We see penetration of offshore wind increasing rapidly given the EU's target of carbon neutrality by 2050 and investments likely supported by the recently agreed European Green Deal. Unlike for onshore wind and solar, in our opinion, permitting constraints, land scarcity (due to weather and geographic limitations and arbitrage on land utilization) and local opposition will likely be less of a hurdle for growth in Europe. However, we acknowledge the rising number of research on the environmental impacts of offshore wind energy and that some projects, such as some in France, have faced significant local hostility.

Chart 2


Chart 3


Chart 4


Even though Orsted, Iberdrola, and EnBW have targeted international projects in the U.S. and Taiwan for instance, Europe will remain the region with the highest growth. Recently updated national energy policies show ambitious capacity targets totaling 90GW by 2030, with the U.K. and Germany representing more than half (see table 1).

While still immature for now, floating offshore wind technology may give way to greater perspectives in the coming years. It offers the potential for less foundation material, shortened installation cycle and decommissioning, as well as additional wind power generation at greater water depths. This technology involves an offshore wind turbine mounted on a floating structure, that allows the turbine to generate electricity in water depths where bottom-mounted structures are not feasible.

Table 1

European Policies Target Up To 90GW Installed Capacity By 2030--4x Today's Level
Country Policy Capacity target Year set
U.K. U.K. Offshore Sector Deal Up to 30GW by 2030* 2019
Germany Climate Action Plan 2019 20GW by 2030 2019
Netherlands The Offshore Wind Energy Roadmap 11.5GW by 2030 2017
Denmark Energy Agreement 5.3GW by 2030 2019
Poland Draft National Energy and Climate Plan Up to 9.6GW by 2030 2018
France Multi-Annual Energy Plan 10GW by 2028 2019
Belgium Draft National Energy and Climate Plan 4GW by 2030 2019
Ireland Climate Action Plan 2019 3.5GW by 2030 2019
Italy Draft National Energy and Climate Plan 0.9GW by 2030 2018
*40GW is the target communicated as part of the conservative party's election campaign. Source: Governments, IEA, and S&P Global Ratings.

Orsted, Vattenfall, Iberdrola, and EnBW have pioneered the offshore wind industry. We believe these four have gained a pronounced competitive advantage in this field, notably in project construction, management of the supply chain, procurement, weather forecasting tools, and asset maintenance optimization. Their installed asset base allows for secured cash flows from the favorable long-term pricing mechanisms in place. These companies also restored their balance sheets in recent years and have the financial means to continue to expand--especially by attracting and teaming up with investment funds to share the risk and lower the cost of capital. All in all, these four are likely to be well placed to seize a large share of the investment opportunities in the coming decade.

We believe the lack of expertise in this field makes it hard for other players to massively penetrate the market. To become more competitive, ENGIE SA and EDP - Energias de Portugal S.A. recently finalized their partnership in offshore wind. Enel SpA has been focusing on renewables, with no appetite in offshore wind. Moreover, we currently believe that European oil majors' interest in offshore wind investments remains subdued, notably because they find returns are too low at this time. This is despite their multi-decade experience in offshore projects and their increasing willingness to diversify into power markets.

The End Of Double-Digit Returns?

Orsted CEO Mr. Henrik Poulsen was realistic when he said the "era of double-digit returns for offshore wind in Europe would soon be over." We see rising competition and more stringent auction processes leading to tighter remuneration and lower returns compared with the past decade. Reaching double-digit returns on projects has become more challenging as technology and project management matures. At the same time, we continue to see higher construction risks on these large projects than on other renewable technologies, and we believe execution risks could jeopardize profitability going forward.

Historically, offshore wind projects were supported by feed-in tariffs or other supporting (and non-competitive) pricing mechanisms, covering a relatively long period (10-20 years). This led to double-digit equity returns as evolving technology ushered in more efficient and cheaper equipment. Wind performance exceeded expectations of €85 billion, according to the wind developer association WindEurope (see chart 5).

Chart 5


The European market changed, however, in 2017 with the transition to competitive auctions. Now that the technology is maturing and costs are dropping, governments are adopting more advanced ways of supporting offshore-wind development. It has become commonplace to award contracts for offshore-wind projects through reverse auctions in which bidders compete by accepting lower and lower subsidies. This transition first resulted in a 55% drop in investment, also related to a limited number of auctions that year, but the market picked up again the following year. New offshore wind investments in Europe rose to €10.3 billion in 2018, up 37% from 2017. But beyond this drop in investments lies the more significant consequence of lower returns. Fierce competition during the auction process in a race for market share, combined with a more maturing industry, leads to more aggressive bids, lower acceptable buffers, and ultimately lower-than-expected returns. In the most recent auctions for near-shore offshore wind in the North Sea, prices have reached close to $50/MWh, including transmission costs (see table 2).

Table 2

Strike Prices For Offshore Wind Are Falling
With Transmission Without Transmission
Project Strike Price ($/MWh) Expected COD Project Strike Price ($/MWh) Expected COD
U.K. Germany
Beatrice 185 2019 Baltic Eagle 74 2023
Hornesa 1 178 2019 Gode Wind 3 68 2024
East Anglia 1 152 2020 Gode Wind 4 112 2023
Triton Knoll 95 2021 Borkum Riffgrund 3 Market based--no subsidy 2024
Moray East 73 2022 Netherlands
Hornsea 2 76 2022 Borssele I/II 83 2020
Neart na Gaoithe 148 2023 Borssele III/IV 62 2021
Cr. Beck A Dogger Bank 51 2024 Hollandes Kust Zuid I/II Market based--no subsidy 2022
Cr. Beck B Dogger Bank 54 2025 Hollandes Kust Zuid III/IV Market based--no subsidy 2023
Dogger Bank Teeside A 54 2025 Denmark
Seagreen 54 2025 Horns Rev 3 118 2020
Sofia 47 2026 Kriegers Flak 57 2021
-- -- -- Vesterhav Nord/Syd 73 2023
-- -- -- France
-- -- -- Dunkirk 50 2026
Source: The International Energy Agency.

While the competitive auction process leads to lower returns and less subsidies, we still value the long-term visibility offered by the remuneration mechanisms in place. Although the existence of a fixed-price contract is sometimes mistaken for a subsidy, it can be seen as a long-term price swap removing the exposure to the volatile spot market. Thanks to 10-20 year contract terms, developers and owners of offshore-wind installations enjoy stable cash-flow streams, thus reducing risk. This cash flow predictability has proven to be supportive from a rating perspective. (See the Appendix for an overview of the subsidy schemes in Europe.)

Costs Will Decrease Further, Albeit At A Slower Pace

The cost of offshore wind in Europe declined massively over the past decade and is set to continue falling, but now at a decelerated pace. We believe continuous optimization of industrial processes, a more experienced supply chain, and increased turbine size will notably drive this declining trend. That said, we believe it becomes more challenging to further optimize financing costs, given the historically low cost of financing we now see.

The material increase in projects allowing suppliers to reach critical industrial scale, technological improvements (e.g., larger turbines), and lower cost of debt translated into a dramatic decrease in the levelized cost of energy (LCOE). Offshore wind became cheaper than some other technologies, notably new nuclear build in 2018.

The IEA published in March 2019 that offshore wind costs are to decline further over the next decade to between $50/MWh and $80/MWh (see chart 6). The most important conclusion we draw from the IEA's report is that offshore wind will be as competitive as onshore wind and solar. A key support is that offshore wind has a much better energy value/capture rate, since it has a more stable generation profile throughout the year and intra-day. This, together with its relatively high +40% capacity factor, in our view, will become a bigger differentiating factor as the share of renewable generation grows, the importance of capacity market gains increases, and grid fluctuations need to be managed. The IEA captures such higher reliability by adjusting the LCOE.

Chart 6


Chart 7


We do not believe that much lower cost of funding (35% of total) is a likely scenario. This is because interest rates are expected to remain at a low level, as will investor appetite. This suggests that other elements will drive cost reductions. We believe, however, that developers still have room for improvement in three areas they can directly influence:

  • Adopting efficient EPC (engineering, procurement, and construction) practices, which include minimizing losses on commissioning. This will notably rely on a more efficient and more mature supply chain in Europe.
  • Streamlining operations and maintenance, which will cut costs and prevent revenue leakage. Digitalization is bringing new techniques for monitoring that proactively identify failures not only in the turbines but also in structures and connections, helping to reduce costs. For example, the use of drones for visual inspections can enable preventative maintenance and cuts down on the need for labour-intensive inspections, along with speeding up maintenance work.
  • Turbine size. In particular, the average turbine size used in offshore wind farms increased from 3.0MW in 2010 to 5.5MW for projects completed in 2018. In the same period, annual capacity factors for new projects increased from 38% to 43%. New turbines of 10MW-12MW promise to achieve capacity factors well over 50% (before wake losses), according to IEA. Compared with smaller units, a bigger turbine can achieve a capacity factor improvement of two to seven percentage points given the same site conditions.

The best barometer to acknowledge the reduction in costs is the strike price from the most recent auction processes (see table 2), and recent prices in Europe for offshore wind indicate significant cost reductions are on the horizon. At this stage, while still not the norm, we can see some strike prices embedded in the CfDs that are at the level of wholesale electricity prices.

Cost reductions could also stem from further improvements in capacity factors, possibly by 5% by 2030. Yet the offshore wind industry faced a stark reality in October 2019 when Orsted stated its expectations of lower rates of return on its offshore wind projects, notably related to forecasting issues. In particular, Orsted revised from 7.5%-8.5% to 7.0%-8.0% its anticipated unlevered internal rate of return for several projects in Europe and Taiwan. The underlying issue is an underestimation of wake and blockage effects. Orsted insisted the problem is not company-specific, but rather an industrywide issue, adding that its forecasts are usually more conservative than those of third parties. While this was credit neutral, given the limited impact on our expectations and expected future credit metrics for Orsted, it is a signal of potential underestimation of risks for a rapidly maturing industry and potentially higher-than-expected pressure on returns. We will closely monitor the aforementioned risks also for the other players active in the industry.

Merchant Risk: Big, But Still Far Out

One of the biggest risks we see in the renewable energy space is the growing share of exposure to merchant power, transitioning away from the subsidized or long-term fixed-price contracted model. Yet we believe this is a more remote risk for offshore wind over the coming decade. This is because the existing capacity is operating under feed-in tariff schemes, and because current auctions are still being signed under this kind of secured remuneration mechanism, while these projects will only be commissioned over 2022-2025.

Some recent auctions concluded with winning bids for no subsidy at all, but we view each of the following cases as unique, notably because they are adjacent to a plant: Orsted's zero-subsidy bids (or zero bids) in 2017 and 2018 for three offshore wind plants in Germany, and Vattenfall in the Netherlands in 2019. Zero-subsidy auctions have been achieved due to distinctive circumstances, such as markedly bigger turbines, probably producing 13MW-15MW, which should be in the market in 2024, and the opportunity for Orsted and Vattenfall to combine different projects into a large one. We also view these bids as having a high degree of optionality at this stage. Before the companies reach a final investment decision, it is likely that a big share of the capacity will be contracted through a long-term power purchase agreement, thereby leaving only marginal exposure to merchant risk. We think this is still a prerequisite to obtain good financing conditions. If the companies decide to drop the projects, they would only pay a relatively small penalty. Still, zero bids point to the increasing pressure on profitability, which we expect will continue to be a major risk for the offshore wind sector.

Should merchant risk increase, strong mitigants will need to be put in place for creditors, such as a floor mechanism, or sufficiently long-term utility or corporate PPAs (see "Energy Transition: Renewable Energy Matures With Blossoming Complexity," published Nov. 8, 2019, on RatingsDirect). We believe utilities are particularly well positioned to keep their dominant role in large offshore wind projects, given their balance sheet strength, and ability to mitigate price risk through trading and to balance output within their broader generation portfolio, in addition to being integrated into supplies.


In the table below, a summary of the key terms of tender and subsidies for the principal countries active in offshore wind in Europe as of end-2018.

Table 3

Main Features Of Subsidy Schemes Across Europe
Country Total installed capacity Number of turbines (wind farms) connected Max tender amount (€ or £ for UK/MWh) Subsidy period Subsidy mechanism
U.K. 8,496 MW 1,975 (39) The government will control costs by capping offshore wind strike prices. Strike prices for delivery 2021-2022 are capped at £105/MWh (2011-2012 prices) and the government’s target to drop it to £85/MWh for projects commissioning by 2026. However, this may reduce further as two projects with delivery years of 2022-2023 received strike prices of £57.50 in the recent 2017 auction. 15 years for CfDs and 20 years for ROCs CfDs replaced ROCs as the primary support mechanism from April 2017. Renewable Obligation Certificates (ROCs) – a green certificate mechanism – are available to projects that have received grace periods until March 2018. Contracts for Difference (CfDs) – pays developers a pre-agreed price (strike price) for 15 years.
Germany 6,586 MW 1,305 (25) Interim regime: €120/MWh Centralized regime: minimum amount of 2018 auction within interim regime. Individual amount can be fixed by Federal Grid Agency. For projects commissioned until 2021: 20 years + year of commissioning For projects commissioned from 2021, i.e. awarded under the new tender system: 20 years. For projects commissioned until 2021: Market premium under fixed feed-in tariff system. For projects commissioned from 2021: market premium under a base price awarded in tender.
Denmark 1,703 MW 514 (14) Project specific Tender: 20 years and a set amount of power, project specific, normally corresponding to 50,000 hours of production at full capacity (e.g. 20 TWh for a 400 MW park). Open door: formula combining 6,600 hours of full load plus 5.6MWh per square meter of wing area (swept area). Tender: feed-in premium (Public Service Obligations (PSO)). Open door: set subsidy per kWh, tapering off above a market price of 33 øre/ kWh
Belgium 1,556 MW 274 (7) N/A Ranging from 19 to 22 years for the operational parks and parks under construction, for which a 10 year extension without subsidy is possible. For the three remaining concessions to reach financial close, the subsidy period has been capped at 16 years, which could be extended with 1 year in case of lesser wind conditions Offshore wind operators receive green power certificates for every MWh produced at a guaranteed minimum price over a 20-year period.
Netherlands 1,118 MW 365 (6) Yes, decreases each tender round (€107.50/MWh in 2017, decreasing to €100.00/MWh in 2019). In the future, the system may move toward a system where bidders can decide to pay for the licence (auction based). Maximum 15 years, +1 year banking Subsidieregeling Duurzame Energie+ (SDE+) Guaranteed price lowered by the electricity market price (market premium). The recent tender without subsidy shows that (more) projects without subsidies are a realistic forecast going forward.
Source: Wind Europe, PWC.

Related Research

  • ESG Industry Report Card: Power Generation, Feb. 11, 2020
  • ESG Industry Report Card: Regulated Utilities Networks, Feb. 11, 2020
  • The Energy Transition: The Implications Of Slow Decarbonization For Russia's Power Sector, Dec. 11, 2019
  • Industry Top Trends 2020: EMEA Regulated Utilities, Nov. 13, 2019
  • Industry Top Trends 2020: EMEA Unregulated Utilities, Nov. 13, 2019
  • The Energy Transition: Different Nuclear Energy Policies, Diverging Global Credit Trends, Nov. 11, 2019
  • The Energy Transition: Nuclear Dead And Alive, Nov. 11, 2019
  • Energy Transition: Renewable Energy Matures With Blossoming Complexity, Nov. 8, 2019
  • The Energy Transition: What It Means For European Power Prices And Producers, Nov. 7, 2019

This report does not constitute a rating action.

Primary Credit Analysts:Massimo Schiavo, Paris + 33 14 420 6718;
Pierre Georges, Paris (33) 1-4420-6735;
Karl Nietvelt, Paris (33) 1-4420-6751;
Research Contributor:Emeline Vinot, Paris (33) 1-4075-2569;

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