A Network on the Sea: Benefits and Obstacles in Europe
Offshore wind development has become a hot topic in the energy community and beyond. In this post I will present some key facts and figures about offshore energy infrastructure and discuss the importance of streamlining its regulation in order for a real electricity network on the sea to materialise.
I’ll begin by briefly illustrating the contribution of offshore wind to our energy system today.
Six countries defining offshore wind
Offshore wind like Ireland — The total size of the turbines at work
The total offshore wind capacity installed in Europe by the end of 2015 equaled 11 GW, which is over 91% of the global offshore wind capacity installed. This power is delivered by 3,230 turbines spread over 82 sites. As as an easy comparison, 11 GW is approximately the total installed capacity on the island of Ireland. Off course comparing the aggregated capacity of a national generation fleet with Europe’s offshore wind capacity is unfair. Wind is not blowing 24/7, while conventional thermal generation, still the major category of the generation portfolio in most EU nations, can be switched on and off when deemed appropriate.
Offshore wind like Bulgaria — The total energy flow
Therefore when comparing numbers, it makes more sense to look at electricity production. In the EU a total of slightly more than 40 TWh of offshore wind electricity was generated in 2015. Such a level of generation means an average capacity factor, defined as the average power generated divided by the rated peak power, of 42% was obtained. This was 18 percentage points more than onshore wind in Europe for that year. To put this number in perspective, 40 TWh is about the same volume of electricity consumed in Bulgaria, a country inhabited by 7.2 million people, that year. Looking at the broader context, 11.4% of the total energy consumed in 2015 in the EU was generated by wind turbines, with 9.9 % onshore and 1.5 % offshore.
Offshore wind like Latvia — The speed of capacity growth
On the figure below the spectacular increase in offshore wind capacity installed in Europe over the period between 1993 and 2015 is shown. In 2015, 3 GW of additional capacity was installed, which was twice as much as the additional capacity installed in 2014. In financial terms, 2015 saw €13.3 billion was invested in new offshore wind assets. As a reference, €13.3 billion amounted to about half of the of Latvia’s GDP that year. Today, about two third of clean energy investment in Europe is in wind energy. 2015 was the first year in which the total investment in new offshore wind assets was slightly higher than that of onshore wind assets.
UK accelerating, Denmark standing still and Germany catching up
On the figure below, the evolution of installed offshore capacity from 2000 to 2015 per country is displayed. Only the countries with a significant amount of offshore wind are shown.
Interesting trends are visible on the figure above. We can see that Denmark was pioneering offshore wind together with the UK and while the capacity installed in the UK is increasing significantly every year, the growth in Denmark has dropped off. Also it seems that Germany has recently started investing strongly in offshore wind, from being the 6th offshore wind nation in 2010 it caught up with the other countries and now convincingly ranks 2nd. In the first half of 2016, relatively little capacity was added in Europe, only in Germany and in the Netherlands were new offshore wind farms connected to the grid.
Technology and business versus policy and regulation
Explaining these somewhat diverging evolutions is not straightforward. Offshore wind project developers are global players and they all have access to the same turbines, why would they prefer building wind farms near the coast of one country over the other? Are wind conditions and the depth of the sea, two major cost drivers, really that different between countries? Or alternatively, can these developments be better explained by national energy policy and regulation? Are these national policies and regulations both efficient and effective? Should they be harmonised? Some of these questions are easier to answer than others.
One of the regulatory matters influencing the deployment of offshore wind generation concerns the way connections of the offshore farms to the consumption centers onshore is organised. So how is this done in Europe’s two leading nations in offshore wind energy?
UK vs Germany: two different songs for transporting energy to shore
The UK: Love me tender
The UK is currently the biggest offshore wind market in the world. By the end of 2015, about 5 GW of wind power was connected to the UK grid, and this capacity is expected to be doubled by 2020. Connecting these generators to the mainland costs billions of euros. The UK decided to organise tenders to allow third-parties, Offshore Transmission Owners (OFTOs), to compete for the ownership and operation of offshore transmission assets. The main reasons for doing so are to deliver cost efficient investments, attract the necessary fresh capital and bring in technical expertise.
The OFTO regime has been in place since 2009, before offshore wind farm grid connections were built, owned and operated by the wind farm owners themselves. Because of unbundling requirements, the offshore generation developers could no longer hold both generation and transmission assets. However, in the current regime, developers of offshore generation projects may still choose to either build the transmission assets themselves or to let the OFTO be in charge of the construction.
Although ultimately electricity consumers pay for the cost of the transmission system, both onshore and offshore, it is of significant importance how these expenses are recuperated. In the UK, the offshore generation developers pay for their connection to the mainland.
Offshore wind projects are becoming larger, more complex and located at a greater distance from the shore. As a result, there are potential efficiencies to be gained from greater coordination in the development of transmission infrastructure. However, the approach followed where OFTOs bid for individual assets focusses mainly on achieving value-for-money on a case-by-case basis and does not directly support coordination. (Coordination between sites has been limited thus far. Ofgem is developing measures that will help to enable coordination of offshore transmission networks while retaining the benefits of the competitive offshore transmission regime.
Germany: Paper plan(e)s
Germany was the strongest growing offshore wind nation last year with about 3.5 GW of offshore power connected to the mainland. Last year, the government extended the country’s support for offshore wind until the end of this decade. In Germany, the offshore connections are constructed, owned and operated by the TSOs. The way the TSOs in Germany organise offshore grid connection can be split up into two periods with a regime switch around 2013.
In the first period, it could be said that a “reactive TSO model” was applied. Grid connection was legally guaranteed and was, therefore, not a part of the wind park developers’ responsibility. The government obliged the relevant TSOs to provide a guaranteed grid connection, but the TSO in charge of the connections of offshore wind farms in the North Sea faced severe challenges in providing the grid connection. Grid delays, as can be seen in the figure below, lead to foregone revenues (which were later settled and became a grave risk for wind park developers.)
Being confronted with these significant delays, Germany worked on a new approach to offshore grid connection. The model applied in the second period could be referred to as the “proactive TSO model”. Since 2013, an Offshore Grid Development Plan (O-NEP), drawn up by the German TSOs and updated yearly, is submitted to the Federal Network Agency (BNetzA). The developer’s right to request connection has been replaced by an objective, transparent and non-discriminatory allocation procedure that allows for transmission assets to be shared across individual wind farms.
The offshore generation developer does not pay for the grid connection; the cost is socialised by the TSO charging levies to the consumers. This is an additional financial support for offshore wind projects, next to the conventional renewable support received for production. By not having to pay the connection costs generators are not exposed to a price signal that they can internalize in the total investment cost. This is a serious issue in the ‘reactive TSO model’, but became less critical in the ‘proactive TSO model’ as in this case it is the TSO, who is informed about the connection costs, in charge of the siting decision.
Although there were significant coordination issues between the construction of offshore generation and offshore connection in Germany, it can be argued that by making the TSO responsible for the connection offshore grid planning, more specifically the coordination among generation projects, is encouraged. An example is the Borwin project in which several offshore wind farms have been developed in a short time span in the same area (clustering). By coordinating the project and anticipatory investment, approved by the regulator, significant economies of scales could be profited from.
Who’s leading the dance?
No country with significant investment in offshore wind applies exactly the same governance to offshore grid connection; the matter is too broad, but trends are visible. It can be argued that the recent German ‘proactive TSO model’ is very similar to the Danish model, that has been in place since the first significant investments in offshore wind took place. Belgium and the Netherlands, both with concrete plans to develop a ‘power socket at sea’, are converging to the German model. Only in the UK it is not the TSO who owns the offshore cables but a third party. Score: 1–4 for Germany
From an economic theory point of view, it is important that offshore grid investments respect a set of regulatory principles. A balance between those principles has to found. After this short analysis, it could be said that regarding planning and coordination the German proactive-TSO model prevails, while the UK seems to be leading the way in terms of who should construct, own and operate the offshore grid assets. Competition is introduced, and cheaper capital is attracted lowering the costs, and delays are better under control by the alignment of incentives. Also regarding cost recovery, directly linked with the beneficiary pays principle, the UK appears to be on the winning side. Below a summarising scorecard is presented, score: 2–1 for the UK.
End score: 3–5 for Germany? Not so quick, for “who’s following who’s model” approach, it should be noted that today the capacity of offshore generators installed in the UK nearly equals that of Germany, Denmark, Belgium, and the Netherlands put together. Should this score then be 1–1 or stay 1–4? Moreover, regarding the economic analysis, who says all three ‘dimensions’ have the same weight? Should planning and coordination, long-term efficiency, not be valued more over short-term efficiency? At least for me this duel is undecided for now. Let’s do a replay in 5 years.
Next to the organisation of the connections, also decisions about the way financial support mechanism are set up can influence strongly deployment rates. Investment in offshore wind generation is still too costly and risky to leave it entirely to the market. The potential of this promising technology can only be realised through continuous deployment and long-term political commitment, and therefore it makes sense to support investment in this technology today. But how can we stimulate deployment? After some experimentation, it seems that we are converging towards a single approach.
Bidding farewell to high prices
The experimental phase
It can be seen on the map below that in 2014 various types of support schemes were in place in the EU, each with pro and cons.
At that time a quota system was in place in the UK, Belgium and Sweden. An advantage of such a support scheme is that offshore generation operators have to sell their electricity in the market and thus are exposed to a price signal. On top of this market revenue they receive a price for their green certificates which they sell in a different market. However, the price for which they can sell these certificates is very uncertain. This is the main reason for the abandonment of the quota system in the UK and Belgium. Only in Sweden, a quota system is still the main support mechanism for offshore wind.
In Germany, fixed feed-in tariffs were the main support instrument before 2014. A price per every MWh produced was guaranteed to wind developers. This price was set administratively based on the estimated Levelised Cost of Energy (LCOE). The advantage of fixed feed- in tariffs is the increased confidence for investors, as the revenues of a windmill installed are not subject to the volatility of the market. On the other hand, this also means that the generators lack a guiding price signal and may not adapt its production to the system needs. Finally, by setting the tariffs administratively there is a risk for under- or overcompensation.
Best of both worlds
Denmark and the Netherlands were the first nations to implement a sliding premium support scheme. A premium payment per every MWh produced is added to the revenue made from selling the electricity in the market. The magnitude of this variable premium is determined ex-post, in most cases on a monthly basis. The premium is calculated as the difference between a reference tariff level, administratively set or determined by an auction, and the (monthly) average wholesale electricity price. This means that if the market price drops the premium goes up and vise-versa. With this support mechanism, offshore wind generators are more reactive to market signals but without their revenue risk being increased significantly.
Today the UK, Germany, and Belgium have adopted, or are in a transition towards the adoption, a sliding feed-in premium or a very similar mechanism to support the deployment of offshore wind generation.
A push from above: administratively set tariffs vs competitive bidding
Today there is a steady shift away from administratively determining the reference tariff levels, the remuneration per MWh electricity produced a developer expects to receive, towards a market-based approach in the form of an auction. Also the European Commission pushes towards the gradual introduction of competitive bidding processes for allocating public support.
The bidding process allows for price discovery, and, with sufficient competition, the auction outcome can be cost-effective. Also, by applying this approach, a steady hand can be kept on how much capacity is added each year. An auction can be site-specific and therefore very compatible with offshore wind development; this way site planning, installation approvals, and grid connections can be dovetailed. The main risk of auctions is the underfilling of political targets as it could happen that not all winning projects are being implemented.
To summarise, it seems that after some experimentation, the financial support mechanisms for offshore wind in the EU are converging, and they are converging for the right reasons, towards a site-specific auction-based sliding feed-in premium support scheme.
An issue with (nationalised) renewable support schemes today is that in order to benefit from financial support the electricity generated should be fed into the state funding the project. This frame does not facilitate investment in wind turbines connected to two or more nations. This obstacle could be solved with the introduction of cooperation set up under the Renewable Energy Directive. Experiments, for now outside of the offshore context, have been established between nations in order to collaborate in supporting investments in renewable technologies. But would it make sense to connect an offshore wind farm to multiple nations?
Avoiding the spaghetti-scenario: collaboration is key
Why opting for a meshed network
The WindEurope association projects that by 2030, 5% to 11% of the electricity demand in the EU will be covered by offshore wind generation. It is clear that it will cost much money to connect all those wind turbines to shore, but exactly how much seems to be strongly dependent on the degree of collaboration between North Sea nations. A study from the European Commission has shown a potential for up to €5.1 billion worth of annual savings in 2030 when a coordinated approach to offshore grid development is undertaken. In the same study the coordinated offshore grid is shown to be profitable in all assessed scenarios. But for as long as regulatory matters, such as the organisation of connections between wind farms to the grid and the way the technology is financially supported, remain desperate from country to country, this mutually beneficial approach will struggle to materialise.
Such a coordinated approach would aim to evolve towards a meshed offshore grid, connecting wind turbines to shore and to electricity markets overseas to kill two birds with one stone.
An offshore meshed grid would deliver benefits to offshore generation developers. Firstly, the cost to transport electricity from where it is generated, offshore, to where it is consumed, onshore, would decrease. Fewer cables will be necessary to serve this purpose and economies of scale could be profited from. The environmental impact would be mitigated as well since fewer components would be needed. Secondly, the reliability of electricity delivery would increase, a meshed network offers redundancy, implying that if one cable fails it would not necessarily mean that the electricity generated was lost. Thirdly, next to facilitating the integration of renewable energy generation, a meshed offshore network also connects overseas power systems. Electricity generated offshore can then flow to the onshore market most in need of additional power. As such the revenues obtained from electricity sales will be maximised for offshore wind developers. A general increase in pan-European social economic welfare would result. More precisely, by coupling markets the security of supply of the systems augments, the dispatch of generation can be done more efficiently, and competition between generation companies is increased.
A more regional approach
It is unlikely that this offshore meshed network in the North Sea will be created in one step, through a so-called ‘big bang’ approach. Instead, it is expected that it will be build up gradually, link by link. For this gradual build-up take place smoothly there are various challenges to overcome, both technical as regulatory. The previous paragraphs give a non-exhaustive overview of arising regulatory issues; many more questions arise in such a setting. For instance, how could we deal with the operation and trade in the context of an offshore grid which both transports electricity generated offshore and facilitates trade between electricity markets overseas. For example, would wind energy be subject to curtailment when prior commitments for trade take up the interconnector’s capacity? Also, who would operate this offshore grid?
It is clear that collaboration among the North Sea countries and the harmonisation of their regulatory regimes for offshore infrastructure development is essential. A regional approach should be favored to avoid an offshore “spaghetti” grid and move gradually towards a beneficial meshed “spider-web-like” offshore grid.
All of these questions should be answered at this early stage of offshore development as the economic case for integrated solutions in grid development is very path dependent; one or several bad choices now, can impede the development of an adequate meshed configuration later. In that respect, it is crucial that the value of investments made today to create more options in the future, so-called anticipatory investments, is captured correctly.
This essay was originally published as a series of fully referenced blog posts on the FSR website which can be read here.
