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Editor's Pick : A marathon and a sprint? What next for onshore renewables?

James Brabben James Brabben Wholesale Manager
18th February 2020

This article was originally published in Energy Spectrum Issue 702 on 17 February 2020. For recent news and analysis on the energy market, find out more about our weekly publication, Energy Spectrum, here.

In this week’s Energy Perspective, we take a look at the renewables pipeline and ask whether the volume of new development needed to achieve net zero goals can be delivered in current market conditions.

Ready, set, go!

With a long-term lens, the growth of renewables capacity over the last decade has been incredibly impressive. Overall capacity now stands at 46.9GW compared to 9.2GW in 2010. In this time solar PV and offshore wind capacity have grown from virtually nothing to become two of the three major technologies along with onshore wind, while Anaerobic Digestion and Energy from Waste have progressed to over 500MW and 1.1GW respectively.

Despite policy changes and interruptions, by the end of the last decade renewables generation continued to achieve new highs. Output records were set across 2019, culminating in a record of 16GW of wind generation on the system on 8 December.

As we enter the next decade these records are in jeopardy of not being surpassed. Notable recent news reports have highlighted Renewable UK’s research that less than 700MW of onshore wind capacity across 23 projects in the UK was installed in 2019, similar to the 651MW seen in 2018. Much of the previous growth was supported through the RO or early CfD rounds. 

This growth is set against a backdrop of net zero targets which suggest multiple GWs of new renewables capacity is needed over the next decade to keep the UK on track for 2050 targets.

Our own long-term power market model, utilised to produce our Benchmark Power Curve, incorporates net zero scenarios and shows that onshore wind capacity is likely needed to be 16.0GW to 22.0GW by 2030 to ensure we are on a pathway to meet net zero targets. For solar PV, the level is forecast between 16.0GW and 19.0GW of total capacity.

These levels are set against a current fleet of 13GW for onshore wind and 13.5GW for solar PV. While much of the solar fleet is expected to be online in 2030, owing to most build-out being since 2010, over 2GW of onshore wind capacity built pre-2007 is likely in need of re-powering to support future operations.

Therefore, as we head into the 2020s a gap of potentially 15.5GW (40GW of total onshore and solar need against a 13.5GW solar fleet and a shrinking onshore wind fleet of ~11GW) could need to be filled by new solar PV and onshore wind assets. This equates to an incremental rate of 1.5GW per year through the 2020s. At current build rates this looks unlikely to be achieved.  

Carb loading

It is worth noting that the slowdown in build out is not due to a lack of projects. Far from it, with our Subsidy Free Pipeline Tracker report noting that over 10.5GW of onshore and solar have at least submitted planning consents. For those classed as more advanced projects, typically with all planning consents in place, this figure stands at 4.4GW for onshore wind and 1.8GW for solar PV.

Whilst there is a shortfall here against our calculations, this is to be expected considering the fast build rates, especially for solar PV, which mean planning applications for projects in this decade may not emerge for several years.

The concerning aspect from our Tracker is the lack of projects considered to be “under construction” in our assessment, which falls to below 500MW in total for onshore wind and solar PV. The reasons for this lack of build are well known with the decline of subsidy routes for onshore renewables and this perspective isn’t designed to re-open debates around subsidy changes and timings.

On the contrary, we have seen renewables developers innovate and look at new business models and routes to market. Subsidy free Corporate Power Purchase Agreements (CPPAs) have already been signed, while co-location with battery assets has also been utilised by several solar PV developers. Some generators have taken on more risk or control over their trading operations to support active management and others have looked at business partnerships and behind the meter generation opportunities.

Of the sites progressing with development in our Tracker, 10 are through CPPAs, 5 through PPAs and several others through internal trading agreements or ownership structures, for instance projects developed by large utilities.

We have worked with many of the developers and investors in this subsidy free world and it is evident that a consensus approach on development, or rather a deployable model at scale, is yet to emerge.


Many successes have been site or developer specific with existing grid connections, favourable connection arrangements or other strategic elements such as long-term partnerships or local benefits aiding projects.

Many new developments face several key challenges, even if they get past planning and grid hurdles.

Mid-race stitch

Ongoing reforms under the Targeted Charging Review (TCR) and Network Access and Forward Looking Charges (NAFLC) Significant Code Reviews are altering the landscape of network charges. Whilst there are winners as well as losers from this depending on where projects are connecting, the uncertainty on the impact of changes is a concern for prospective sites.

In the wholesale market, the short-term view shows multi-year lows for seasonal and annual prices, with the annual April 20 baseload power contract currently trading below £38/MWh, a two-year low. Longer-term, the threat of price cannibalisation for wind and solar is increasing.

Cannibalisation is already a factor in pricing of renewables PPAs and the growth of offshore wind assets through the 2020s is likely to increase this.

The merchant market linked model that new onshore wind and solar projects are pushed towards is directly impacted by higher offshore wind capacity under the CfD. The disparity against the price protection given to these offshore wind projects under the CfD is forecast to become starker in the 2020s, especially with ramped up targets of 40GW of offshore wind by 2040. Our modelling shows an increase in price cannibalisation across all scenarios to 2030, aligning with recent market sentiment on the pricing of listed renewables infrastructure funds, which have seen downgrades in recent long-term assessments. Whilst a CPPA may be a way to mitigate against this risk through fixed pricing, our previous analysis shows that generators far outweigh willing and credit worthy corporate buyers in terms of MWh volumes.

Nonetheless, there are still new revenue stream opportunities emerging, especially in relation to flexibility and system services. The recent T-3 Capacity Market auction saw onshore wind competing and winning for the first time, with five projects successful. Additionally, there are moves to open up balancing services to renewables, especially for frequency provision. National Grid’s pathfinder projects and the increasing DNO local service provision could also provide revenues.

However, many of these markets have been designed for, or are being moved towards, short-term procurement timeframes. Whereas the longer-term signal sent by the Capacity Market, originally designed to help provide for the “missing money” problem, is still clearing at low levels. The recent T-3 cleared at a record low of £6.44/kW. For a 50MW onshore wind farm, this equates to an annual payment of just under £30,000.

Second wind

The result of all this market change makes financing more difficult, especially for project finance funding models which have proved popular with infrastructure investments in the subsided world. The model is reliant on long-term stability, revenue certainty and de-risking of projects. While the benefits of this can still be seen in the decreasing financing costs for offshore wind, investors are still grappling with how the model can fit in a merchant environment.

This is not to say development of the pipeline will cease and notably utilities that have re-entered the renewables market recently could potentially fund some projects through their balance sheets.

However, unless balance sheets are stretched and investment ramped up, utilities alone will be unlikely to meet the 15GW gap.

Personal best

So, what can be done? There is much talk in the industry of reintegrating onshore wind and solar back into the CfD scheme. Whilst this would certainly solve the funding issue, there are wider concerns here around incentives and market design. In a world where on our current modelling 15GW of solar and onshore wind needs to be added to potentially 40GW of offshore wind 2030 (the updated government target), is a market where 55GW of capacity is under a CfD a reasonable objective?

The threats of cannibalisation for those outside of scheme would heighten and issues around flexibility and responsiveness to market signals would also increase.

Of course, the CfD could be reformed and we have set out in previous Energy Perspectives and Insight Papers how this could be achieved through ideas such as the CfD floor, which would keep a greater link to wholesale market operations than the current CfD design. However, we believe a bigger question is building around not only incentivising new renewables, but what market they should exist and operate in by 2030 and beyond.

You deserve a medal

Whilst an answer on incentivising new generation is still up for debate, decisions need to be made realistically in the next 18 months to provide a pathway to 2030 and beyond.

These decisions will need to be informed with evidence and there are many examples on allocation to learn from in other markets and sectors. Inspiration from the workings of the New York Marathon could give some clues. The marathon is one of the biggest in the world with over 50,000 competitors but has to turn down over 100,000 more each year. The allocation and support for places is not based on one criterion but rather split across four allocation methods:

·         A uniform lottery (luck).

·         Merit entry (time based).

·         Money (either charity or cash payments exclusively for international entries).

·         Effort as a proxy for value (local runners who have run 9 races in New York before the marathon).

Whilst the lottery approach is not rational for energy, other approaches could be considered. For instance, should a flat £/MWh value of power (i.e. the merit approach akin to the current CfD) be the only criteria new generation is incentivised against?

Instead, could different values be placed on power through incentivising production at peak times or offering a scalar payment to store ready for optimal use later. There are examples in energy markets here too, with the Clean Peak Energy Standard currently undergoing development in Massachusetts to incentivise renewables production over seasonal peaks. Our recent Nutwood detailed how this could be adapted to the GB market.

Could generators have the option to prove they are providing more than just power? This approach would also have the potential to co-support emerging technologies such as electrolysis, EV charging or long-term storage.

From a system management perspective, a premium or incentive could also be given if assets can provide frequency or inertia support more readily. Additionally, assets located in areas of constraint or in need of reactive power management could be favoured or rewarded.

The effort-based approach is also of interest in potentially ensuring or evidencing local network benefits or proving local consumer buy-in, especially for onshore wind, which could be rewarded.

The New York marathon, and many other potential examples, shows that a combination of assessment criteria is much better suited to complex allocation problems such as renewables development and net zero.

Each element if adapted to an incentive mechanism would of course have its pitfalls. However, by having multiple incentives or allocation criteria running in tandem then the larger pitfall of the current CfD design, the creation of a dysfunctional wholesale market, could at least be mitigated. It may also provide the adaptability and flexibility to change or refocus the different incentives if new net zero challenges arise.

Our current view of 15GW of new onshore renewables by 2030 is certainly a big challenge for the sector. And remember, the CCC forecast up to 35GW of onshore wind by 2035…Ready, set, go!

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