The recent report by the Intergovernmental Panel on Climate Change (IPCC) made for grim reading. It declared that climate change was now inevitable and irreversible and that humanity was losing the race to limit global heating to 1.5 degrees Celsius above pre-industrial levels, as had been agreed at the COP21 Paris climate agreement of 2015. The task ahead is both extremely challenging and incredibly straightforward – to drastically reduce greenhouse gas emissions.

While this may seem like a daunting feat, expectations are running high in the build-up to COP26 and governments have increasingly been stepping up – Earth Day 2021 saw the most significant renewal of promises to combat climate change by national governments since 2015 and the hope is that COP26 will deliver another wave of ambitious targets. So far this year, the US and Canada have pledged to reduce their carbon emissions by 50% and 40-45%, respectively (on 2005 levels), Japan has pledged to reduce emissions by 46%(on 2013 levels), while the UK and EU have vowed to cut emissions by 78% and 55%, respectively (on 1990 levels), all by the end of the decade.

The lead-up to COP26 has also seen the formation of new groups set to play a crucial role in mobilising the global financial services sector. These include the Glasgow Financial Alliance for Net Zero, which will see financial institutions with $70 trillion of assets under management register for science-based carbon-reduction certifications, and the UK Infrastructure Bank which aims to tackle climate change, support regional and local economic growth and accelerate investment by deploying an initial £12 billion of capital into infrastructure projects.

Given how fossil fuel energy remains the most significant source of carbon emissions, investment needs to continue to be channelled into the development of clean energy and green infrastructure. Continued technological innovation, deeper capital pools and competition are making clean energy and green infrastructure a competitive and attractive investment prospect.

Banking on renewables

With ESG a significant boardroom priority across the financial services sector, debt funders are looking to channel funding into green projects. Subsidised clean energy technologies such as onshore wind and solar PV continue to be a safe investment but, with subsidies in the rearview mirror for these technologies, subsidy-free projects and newer technologies such as energy storage and electric vehicle charging infrastructure (EVCI) are generating increased interest from lenders. However, the challenge for debt funders is negating the risk posed by the lack of guaranteed revenue streams that FiT and ROC accredited projects have traditionally enjoyed.

Even for those more established technologies where the funder is comfortable with the technology – like onshore wind and solar – debt funding subsidy-free schemes can still face some challenges. For new technologies such as EVCI, green hydrogen and energy storage, not only is there the risk associated with banking unknown and relatively unproven technologies, but there is also the revenue stream risk.

However, funders are feeling the pressure to find a way forward and finance green. As ESG becomes a boardroom priority, there is a need to demonstrate to a wide range of stakeholders – from investors and regulators to consumers and employees – that they are gearing towards sustainable investments. This in turn is increasing competition in the market as more players look to diversify lending portfolios into green projects, making clean energy projects and green infrastructure key lending targets.

The biggest question for lenders therefore is how do I finance green? One of the challenges has been mitigating merchant risk for technologies that do not have established floor revenues and have fluctuating power prices. There have been significant developments on this front with innovative new models that limit risk and help secure viability. For example, in the energy storage space, Santander’s model adopted a multi debt tranche approach to the tiered risk profile of the battery energy storage system revenue model.

Other routes to market include setting floor prices with debt financed corporate power purchase agreements (PPAs) – though these generally require large, investment-grade corporate off-takers – extending loan repayment periods and cash sweeps. Risk can also be mitigated by lending to a diversified portfolio of clean energy projects, encompassing subsidised and subsidy-free schemes as well as established and new technologies.

Unfortunately, there is no one-size fits all model and bankable project modelling is still on a scheme by scheme basis. However, it’s clear that the appetite from funders is there and as more projects are funded and different routes to market are presented, the risk will continue to reduce until funding subsidy-free clean energy projects and green infrastructure becomes the new norm. In addition, the Subsidy Control Bill could open the doors for funding into newer technologies such as carbon capture and storage and green hydrogen where there is still a viability gap.

In short, funders are equipping themselves to take advantage of the significant investment growth in clean energy and green infrastructure projects that underpins the UK’s road to net zero.

Private equity trailblazers

The adage that debt follows equity remains true. Equity investors have been spearheading the growth of clean energy and green infrastructure for years and as lending diversifies into newer technologies, it is the equity investors who are again leading the way.

While subsidised operational onshore wind and solar projects remain highly viable market segments, over recent years many of these projects have been consolidated into portfolios and demand far outweighs availability. When operational projects do come to market – either as portfolios or as single assets – intense competition drives up market price leaving only the investors with deep pockets able to bid.

With operational projects off the table for many, equity investors have been diversifying into non-subsidised projects and newer technologies including energy storage, EV infrastructure and green hydrogen. For those who want the comfort of investing in an established technology, albeit without the security of subsidies, subsidy-free projects which combine onshore wind or solar with energy storage (and EVCI) either from the outset, or the option to add as a future proofing mechanism, are garnering considerable investor interest. The sticking block? Ensuring the viability of each co-located asset to maximise project performance and long-term revenues.

Investors have been quick to recognise the role that storage infrastructure will play in underpinning the clean power of tomorrow and have been at the forefront of funding energy storage projects. Currently, most investors are looking at projects at the ready-to-build stage as this enables them to secure operational projects in a shorter timescale without development risk. However, as competition for projects increases, we are seeing an increased appetite to move to invest at an earlier stage.

Investors entering the project lifecycle downstream is a trend across technologies and is being driven by intense competition to secure viable and future proofed projects that have the flexibility in design, real estate documentation, planning, construction, import and export capacities to both add additional technologies such as storage or EVCI, and extend the scope and life of the project to create fresh revenue streams and boost yields. Investors are looking to enter into partnership arrangements with reputable developers at consent or even greenfield stage. And while this does come with added uncertainty in the early years of a project, it can help secure a pipeline of projects and maximise long-term returns, so it can play out as a very smart move.

Like debt funding, finance green will continue to drive investment into clean energy and green infrastructure and with intense competition and an increasing amount of capital driving the market, equity investors are poised to take advantage of the journey to net zero.

A glimpse of the future

The investment decisions of today reveal the world we will live in tomorrow, so it is vital that in the context of climate change the financial services sector turns its attention towards decarbonising the global energy system. The positive news is that investors of all kind are alive to how opportunity-rich financing green really is and are acting on this knowledge. The challenge that lies ahead is huge, but the seismic shift towards the financing of clean energy over fossil fuels and investment in green infrastructure is well under way and gathering pace. Financing green is good for our planet, our people, and, crucially, it makes good business sense.

When the leaders of Canada, France, Germany, Italy, Japan, the UK and the US gathered for the G7 summit in Cornwall, they knew that expectations were high and that the eyes of the world would be upon them. Not only did these leaders need to work together to bring an end to Covid-19 by mobilising support for an unprecedented international vaccination effort but they also had to revive the vast swathes of the global economy that had hampered by the pandemic. They additionally, of course, had to tackle the other emergency hanging over the world – catastrophic climate change.

In the communiqué that resulted from the summit, leaders pledged to limit the rise in global temperatures to 1.5 degrees Celsius, in line with the COP21 Paris Agreement, and reiterated their commitment to reach net-zero carbon emissions by 2050.

The race to decarbonise our economies has been ongoing for decades but it is in recent years that we have seen the most progress, with the transition of the energy system from fossil fuels to clean energy gathering pace. The prospect of a decarbonised, non-polluting clean energy system providing new business opportunities and jobs is certainly an enticing one however it does bring extra challenges in terms of grid balancing – ensuring the right balance between energy supply and demand to avoid blackouts on the one hand and overly high voltage levels on the other.

The challenges of grid balancing

One of the challenges brought about by renewables is their natural intermittence – the fact that the sun doesn’t always shine (and simply doesn’t shine at night) and that the wind doesn’t always blow. The issue of intermittence used to be a question mark over sources of clean energy but with the rapid scaling of energy storage solutions, we are learning to manage the issue.

The other main problem is the loss of inertia in the grid. Clean energy sources generate power to the grid electronically rather than directly as power stations with vast turbines running on coal or gas do. These heavy turbines rotate at the same frequency as the electricity grid and carry with them significant momentum, such that if there is a dip or rise in energy production the natural inertia of the machinery rotating at near-constant speed will largely stabilise the increase or decrease, keeping grid frequency steady. The energy system of tomorrow, therefore, will need to compensate for the loss of inertia built into the system. Thankfully new technologies are bringing inertia back.

The power of storage

Energy storage provides the best way to handle potential intermittence issues and the UK’s battery storage capacity is accelerating rapidly as a consequence. Indeed, more and more developers are fitting solar and wind sites with large-scale storage facilities, not only because batteries provide the solution to intermittence but because they improve the viability of schemes. Energy storage not only has the obvious advantage of providing readily accessible power in times of need when clean sources are generating insufficient supply, they also allow for greater cost-efficiency by controlling when electricity is stored or released. This means, for example, that energy generated during off-peak periods can be stored and sold at a higher price during times of high demand – enhancing profitability.

The current battery technology deployed in energy storage projects works very well but, just as encouraging, is the continued development of new technologies that will make grid balancing efforts easier going forward. As R&D investment continues to be ploughed into exciting technologies such as flow batteries, molten salt batteries, liquid air and hydrogen storage, new solutions will be commercialised and, benefitting from economies of scale, become viable for widespread use.

When one considers the prospects of these new products, in addition to the fact that existing battery and clean energy technologies are set to continue becoming even more cost-effective, the future clean energy landscape looks extremely bright and appealing for investors.

While energy storage solutions tackle the significant majority of grid balancing concerns, they do not address the lack of inertia in the system. Luckily, new technological solutions – consisting of large spinning machinery made up of a generator and flywheel – have been produced to tackle this issue and National Grid ESO has three pathfinder projects designed to roll out this technology and solve the inertia problem.

More broadly, National Grid ESO is taking an active approach to balancing an increasingly clean grid, with dynamic containment, dynamic moderation and dynamic regulation. For example, NGESO has implemented an Optional Downward Flexibility Management Service (ODFM) to provide small clean energy generators with additional commercial agreements if they reduce their output at times of oversupply. In essence, this means that in certain circumstances clean energy operators will be paid to stop generating power – once again demonstrating how the challenges of grid balancing are creating new opportunities within the energy system.

Devolving the grid

Another important reality that will make the grid easier to balance through the energy transition is the fact that we’re likely to see a proliferation of devolved micro-grids. There are already plenty of examples of local community micro-grids, with their own clean energy generation and storage facilities to regulate the network, but these are set to become increasingly common. The rise of these localised grids could, in time, mean that fairly significant portions of the UK end up largely autonomous from an energy perspective, reducing the pressure on the national grid.

This reasoning also applies to private wire or corporate power purchase agreements (PPAs) where clean energy operators sell directly to a private party, for example to an industrial site or business park. Once again, the result is that of power-hungry sites being taken off (or at least made significantly less reliant) on the national grid – thereby reducing demand.

EVs: the ultimate utility tool

While the majority of electric vehicles (EVs) will depend on the grid for their charging and the electrification of transportation will undoubtedly create a significant additional demand on the grid, EVs and EV charging infrastructure will also offer new solutions. With charging infrastructure set to rise rapidly up and down the country as the uptake of EVs accelerates, ahead of the UK’s 2030 ban on the sale of petrol and diesel cars, a growing proportion of charging sites will feature battery storage. As with other forms of energy storage, the batteries will supply electricity to charging points during red-band periods when demand on the grid is high and will be charged up at off-peak times.

EV to grid (V2G) connectivity also presents an interesting prospect, with an innovative use for vehicles. V2G consists of charged EVs being used to help power homes. Unfortunately, at present, it may result in vehicle warranties being annulled, however if regulatory change goes ahead, it could become a game-changer by turning every household vehicle (which in the future will be electric) into personal storage units. This would enable households to save money by charging their vehicle when electricity is cheapest to plug into the grid and use at times when prices are higher. Changing the rules to allow such a practice would not only encourage EV adoption but also help reduce demand on the national grid at peak times and aid in balancing efforts.

With societies around the world quite literally feeling the heat, the transition towards decarbonised, clean energy systems is accelerating. As we electrify our power (including heat and transportation), clean energy is set to take up an ever-more important role. While this is not without its challenges for grid balancing, the fact is that the technologies that already exist, as well as those that continue to be developed, are managing the issue and offering myriad new opportunities. Challenges are there to be met and opportunities to be seized. What are we waiting for?

NP: What is RegTech?
It is software to help comply with regulations, standards and codes of practice. It uses automation to help improve market governance, reduce risk and ease the compliance burden.

NP: How is the job done now?
It varies by sector. The financial services industry is well ahead on the use of digital technology. Energy is catching up, but market governance and compliance is often managed through analogue processes and the sector has yet to scratch the surface of digitalisation.

NP: What digital technologies would be used?
RegTech uses automation technologies such as artificial intelligence, big data, cloud computing and machine learning to help minimise human error and speed up processes. The application areas include policy, workflow, reporting and document management.

NP Can you give us examples of how it would work?
Gemserv has introduced CodeWorks, which digitised the Smart Energy Code (SEC). It enables code parties to search across many code documents at the same time and has functions like filtering, which allows specific types of organisations (‘party type’) to see only those obligations that apply to them. This is more efficient – saving time and money.

NP: What’s in it for a company?
As well as saving time and money, RegTech reduces the risk of mistakes in regulatory compliance. This also builds trust for investors. The COVID-19 pandemic has shown that businesses tend to be less vulnerable in times of crisis if they have started to invest in digital environments. RegTech is one such application.
In the longer-term companies also benefit from unlocking the profit-making data hidden in customer interactions.

NP: What’s in it for customers?
Customers should be the final beneficiaries of lower costs and less risk, whether that is via savings in the cost of operating market governance arrangements (like the energy codes) or savings in their compliance costs. Gemserv’s work on digitalisation of the new Retail Energy Code, for example, should drive savings in managing that code and complying with it.

NP: In the UK energy sector, will all the Codes use the same RegTech and be interoperable?
Market participants have to comply with rules that are administered by different organisations in different ways. A single industry platform with all the rules available in one place could help reduce the regulatory burden. Such a platform would have to be developed on the principles of standardisation and interoperability.
NP: Will it be the same as that used in other industries – can we copy over?
Every firm and industry has unique needs and drivers to embrace RegTech. Broadly speaking, it brings four key characteristics: agility; speed; integration; and analytics. These characteristics are all connected through one resource: data. As new use cases are developed, learning from pioneering sectors is useful, but customisation is the key implementing it successfully.

NP: What are the barriers to adopting RegTech?
RegTech adoption is slowed by lack of awareness, weak use cases and lack of preparedness to integrate with a firm’s existing IT environment. A collaborative approach with RegTech providers is essential to ensure that these barriers are addressed.

NP: Is RegTech cyber-secure?
Cybersecurity is intrinsic to RegTech. In fact, it helps companies maintain cyber security as it means continuous monitoring of security compliance. It is due to its frequent security logs and technical audits of the organisation’s software and systems; dividing customer processes from corporate ones and transitioning to cloud-based software and servers, among other characteristics.

To find out more download The RegTech Advantage

 Izabela Kielichowska, 

The UK has been a leader in global and European offshore wind developments. In its 2020 Energy White Paper, the British government announced a 40GW target (including 1GW of floating offshore wind) by 2030, which reflects the UK government’s ambitious climate change target to reduce emissions by 78% by 2035 compared to 1990 levels. Such massive development of offshore energy sources requires rethinking the offshore wind grid delivery models in the direction of a coordinated and holistic development of meshed offshore grids, rather than relying on radial developer-led connections, as practised so far.

Discussion on the shape of offshore grids started as early as 2014, when the European Commission analysed the benefits of the meshed offshore grid for the North Sea, including the UK project pipeline. The study argued that a meshed grid is a more complex solution, but that it brings several additional benefits, including:

• Limited environmental and social impacts from additional infrastructure
• Better balance of variable renewable energy sources (RES) in a widespread meshed grid
• Lower emissions related to backup capacity needs
• Higher savings related to less cabling and better coordination of national energy systems

The UK, which invented developer-led grid delivery models, initiated a discussion on rethinking the domestic grid delivery model in late 2020 to respond to the growing offshore energy targets.

Milestone studies for the European Commission, EirGrid, RTE and some of the key stakeholders in the UK provide a thorough overview of existing and developing offshore market models globally. Each of the models has evolved, taking into consideration a broader national context. However, there are certain joint features for developer-led and centralised  models.

Developer-led models may be more complex and cost more

The traditional UK developer-led model may offer better risk management for developers and shorter lead times for offshore wind project development. However, this may happen at the expense of the overall societal, environmental, and energy system cost. This model often brings a higher procedural complexity, with many stakeholders engaged.

Taiwan is an example of the substantial number of public authorities engaged in the process. A large number of stakeholders may lead to less transparency, longer lead times (related to extended permitting timelines and the need to co-ordinate the permitting process among many players), and an increase in the overall system cost of offshore energy systems.

In terms of societal and environmental impact, the developer-led model leads to an increased number of landing points (a point of concern for coastal communities in the UK), a higher use of resources (i.e. cabling) and a less co-ordinated power system, which requires more conventional balancing capacity and potentially more curtailment of renewables.

Compared to centralised systems, developers  operating in developer-led models are more likely to invest in mature technologies rather than innovative ones, to ensure a fast and stable return on investment.

Centralised models may be less risky

Well-established centralised models may be seen as less risky in a stable investment environment, so they may attract a variety of financial players. By being less risky, they may also allow for more innovation. However, the Dutch experience with auction criteria stimulating innovation shows that truly innovative technology solutions can be driven only if the government stimulates the innovation with a deliberate action.

Centralised models seem to limit the level of risk that can be managed by the developers themselves. Furthermore, centralised systems may enjoy a lower procedural complexity and more process transparency, which is the desired environment for smooth project development. This leads to a lower cost of energy generation. The current Dutch system with an operating one-stop-shop is a good example.

Centralised systems may lead to a lower system cost for grid development and better coordination of system integration. According to a National Grid study, a more integrated, meshed approach has the potential to save approximately £6 billion (18%) in capital and operating expenditures between now and 2050. However, all of the benefits may be obtained at the expense of the project development lead time, which is extended because all the system development elements must be considered.

Centralised approaches can be beneficial — if applied rationally 

A more centralised approach can bring significant environmental and societal benefits, as the number of onshore and offshore assets, cables, and onshore landing points could be reduced by around 50%, according to National Grid.

The sea’s energy is becoming a critical element of new, sustainable energy systems — in the UK, in other European countries, and in other markets such as the US East Coast. The foundations of new offshore energy system design are being created now and will influence the shape of the new power system for the rest of the century.

The UK government’s decision to take a more centralised approach will allow for better integration of offshore energy assets into the UK energy system. The experience of other countries like Denmark, which experimented with shifting from a centralised system to a more developer-led one, may bring further insights to the UK in the months to come when the system foundations have been already developed and agreed.

Further information:

Iza Kielichowska, Associate Director, Guidehouse, Brussels

Mark Livingstone, Director, Guidehouse, London

The UK’s pipeline of waste-to-energy projects is potentially very strong. “Energy from waste is generally the best management option for waste that cannot be reused or recycled,” according to the UK government’s Waste Management Plan for England 2021. The report points to significant funding for waste-to-energy projects, especially those forming part of a heat network programme.  

Another report, 2020’s No Time to Waste: Resources, Recovery & the Road to Net-Zero – which has cross-party support – found that, “Widespread deployment of energy-from-waste (EfW) plants across UK regions is needed to deliver a coherent circular and sustainable waste policy.”

The growing role of hydrogen in decarbonisation strategies offers another route for waste-to-energy to contribute to renewable power generation. Showing the way are projects like the H2 Créteil collaboration between SUEZ and SIPEnR to build a green hydrogen production and distribution plant at the energy-from-waste unit of the Val-de-Marne Joint Syndicate for the Treatment of Urban Waste in Créteil, near Paris, France.

Gate fee effects

Currently, the gate fee for the waste feedstock, rather than the sale of power, is what makes UK waste-to-energy projects profitable. Viability, for this business model, requires projects to run to schedule and plant performance and availability in line with contractual terms. Programme certainty is also paramount when the business model is reliant on plant being fully operational to deadlines set by government programmes like Contracts for Difference or Ofgem’s Renewable Obligation Certificate scheme.

Achieving this, however, has proved challenging on some UK waste-to-energy projects. Performance issues have arisen due to a combination of factors including incorrect design and the selection of inappropriate or insufficiently mature waste incineration technologies – leaving some owners facing a loss of revenue. In addition, protection against risk afforded by a full engineer, procure, construct (EPC) wrap has – in some instances – been less than anticipated; occasionally leading to litigation.

Performance issues have arisen due to a combination of factors including incorrect design and the selection of inappropriate or insufficiently mature waste incineration technologies

In essence, on some UK waste-to-energy projects, the transfer of risk from owner to contractor associated with an EPC wrap has been less effective than envisaged. The most significant risks affecting owners have been:

• Plant performance – megawatt output, or heat efficiency, is lower than specified
• Schedule – projects subject to significant overruns
• Additional cost burden – revenue lost while plant is unavailable; cost of bringing underperforming assets up to specification.

It is not just on the owner side that, in the context of UK waste-to-energy projects, EPC is not always perceived as the most appropriate contracting model. There are strong market signals that contractors too are becoming less inclined to bid on EPC terms.

 The transfer of risk from owner to contractor associated with an EPC wrap has been less effective than envisaged

While the drivers to develop the UK’s waste-to-energy infrastructure remain strong, however, an effective alternative to EPC is necessary to ensure the project pipeline can be delivered.

Engineer, procure, construction management (EpCM) contracting is not new. But in the UK, and not just on waste-to-energy projects, EpCM is finding favour as an effective way to provide execution certainty for both new projects; and as a way of revitalising challenged schemes.

The benefits of EpCM

In our experience, an EpCM approach has led to successful outcomes for both owners and the EpCM contractor, on many UK waste-to-energy projects. The flexible nature of EpCM contracting means that roles and responsibilities can differ between projects. Broadly speaking, however, the EpCM contractor is not directly involved in construction, but is responsible for the detailed design and overall management of the project, on behalf of the owner. Unlike an EPC contract the absence of a construction element makes EpCM a professional services contract.

Supervising, management and co-ordinating construction interfaces in accordance with a detailed schedule is the key responsibility of the EpCM contractor; and the EpCM contractor is also responsible for establishing contractual arrangements on behalf of the owner with other contractors, original equipment manufacturers (OEMs) and sub-contractors. The EpCM contractor is contracted for a construction management role, while the owner is bound to various contractual relationships for construction related works.

Our experience has been that the EpCM approach allows both owner and EpCM contractor to adopt a much more granular approach to risk than an EPC wrap affords. The owner, for instance, has the opportunity to be involved in decisions such as equipment, materials and contractor selection. This has the additional effect of fostering a closer and more collaborative approach to the project.

With an EPC contract there is also the potential for an underperforming contractor to become a single point of failure, placing the entire project at risk in terms of schedule and plant performance. EpCM can help spread risk across numerous contracts, reducing the chance of a single point of failure.

The EpCM contractor is doing the technical thinking for the owner

Significantly, EpCM offers the potential to greatly reduce performance risk for the owner. In essence the EpCM contractor is doing the technical thinking for the owner, the quality of front-end engineering design (FEED) and pre-FEED studies have a significant bearing on operational plant performance. So an EpCM contractor with a highly proven technical pedigree is a prerequisite to achieving as-specified plant performance and availability.

In addition, although the owner places the contract with the OEM, the best EpCM contractors will have the technical knowledge to create a specification, tender and contract that places the performance guarantees and warranties with the OEM. In the context of UK waste-to-energy projects, this means that the party most familiar with plant – rather than an EPC contractor – will have the most significant stake in ensuring plant performance is as specified. This helps ameliorate challenges that have affected a number of recent UK waste-to-energy projects.

Where challenges are manifest or changes of scope deemed necessary, the collaborative approach commonly engendered by EpCM typically extends to a less adversarial resolution process. The need to navigate change orders, for instance, is negated.

EpCM is not a silver bullet insofar as it will not be suitable for all owners’ business models. For some client types, however, it can offer an attractive alternative to EPC. The benefits are most likely to be realised by owners with balance-sheet financed projects, in which the owner is paying directly for the project. Some European and Chinese developers have shown how adopting EpCM can lead to successful projects and, as a result, a successful business.

The benefits are most likely to be realised by owners with balance-sheet financed projects

Where a project is being funded by a special purpose vehicle, set-up by private equity investors for instance, traditional EPC remains the likely delivery method of choice. In the context of UK waste-to-energy projects however – providing the EpCM contractor can demonstrate a high technical pedigree – the EpCM approach looks to offer an attractive way to ensure the desired level of execution certainty.

See the answers below and download here:  Gemserv for New Power – 11 questions on Code modernisation

Here goes:

1: What is an industry code?  

Codes set many of the rules of the gas and electricity markets.   They are there to ensure these markets operate efficiently to deliver least cost, secure supplies to customers. They include common technical standards and commercial arrangements covering areas like networks, smart metering, switching and settlement.

There are 11 codes operated by 6 code bodies.

2: Why are they a problem? 

They have successfully underpinned the energy system since the late 1990s, but have become complex over time and change is slow. In the meantime, markets and technologies have moved on and they need to be modernised in order to help drive the transition to net zero.

3: Why change them if reform is planned? 

Reform is needed and this should be driven by government. This is a big undertaking and could take several years. But we mustn’t sit on our hands and we think a few no-regrets interventions now could bring early benefits such as increased innovation, reduced regulatory burdens and better consumer outcomes.

4: How can you make it all simpler? 

There’s no silver bullet. Fundamentally there needs to be a shift to a more risk-based approach.  This would ensure only essential issues are regulated with more risk dealt with through commercial insurance arrangements for example.  This must go hand in hand with other steps such as digitalisation, joined up working across the code bodies, performance incentives and greater accountability.

5: Can’t you make it a one-stop-shop? 

It’s Gemserv’s vision that all rules of the market should be accessible through a single online portal, a one-stop-shop if you like.  This would allow the rules to be curated such that market participants access only what they need, removing complexity and burden.

6: Can it be done automatically, online? 

A market portal could bring other benefits like enabling easier participation in change processes, a platform for making data more accessible and for the regulator to more easily monitor market performance and  trends.

7: How can you monitor improvements? 

We think code bodies and panels need to be incentivised and accountable for their performance.  This would go hand in hand with greater transparency and reporting of performance KPIs.  Competitive tendering of code bodies can also help drive-up standards and ensure value for money.

8: Should this be Ofgem or BEIS’s job?  

Government should lead the reform process working with industry. While code bodies are making improvements, there just isn’t the vires, funding or agreement on the direction of travel for this to happen ‘bottom-up’.  Issuing strategic direction to code bodies will be key, ensuring they all pull together to achieve common outcomes.  This is something that could be done now, a function we think Ofgem should perform.

9: Who pays? 

Ultimately the consumer pays for market governance through their energy bills.  Improving code governance is an opportunity to drive innovation and efficiencies which will translate into better outcomes for consumers such as through greater innovation and competition in the market.  Digitalisation of market rules in other sectors has achieved a reduction in regulatory burdens of between 20% to 30%.

10:  What’s the first step?  

We’d like BEIS and Ofgem to consider our views and bring forward proposals which can be implemented in the short term, on the road to more fundamental reform which we appreciate will take longer.  It’s also for code bodies and panels to drive continuous improvement.

11: Where can I read the full proposal

 Read more on Gemserv’s code proposals here 

The energy market is becoming more complex, with uncertainty the new norm. The sheer amount of change occurring in the sector means there is a real need to understand how new ancillary services, market challenges or even changes that only seem to directly impact certain technologies will impact revenue streams for different projects in the future.

To address this, LCP have partnered with Frontier Economics to launch the GB Power Investment Index.

The Index, delivered through an interactive website, allows investors to visualise how different existing and new technologies are forecast to perform in the future, as well as providing investors with a summary of the key changes impacting the energy market and asset profitability.

LCP and Frontier Economics will also deliver a quarterly webinar series entitled ‘Investing in the GB Power Market’, which will drill into key market updates and policy changes that investors need to be aware of, and explain what the implications of those changes are.

When looking at the risks coming from the energy sector there are several areas that should be at the front of investors’ minds. 

The deployment of new large infrastructure projects such as nuclear, interconnectors and offshore wind will have dramatic impacts on the power market due to both the scale of the projects and the fact that these projects will have support mechanisms in place that will impact the rest of the market. Although the general direction of some of the bigger changes to policy is understood at a high level, such as reforms to network charging, evolution of the Capacity Market (CM) and the future design of carbon pricing mechanisms, the impact these will have on individual assets is still unclear. Combined with uncertain timing, this has the potential to create both upside and downside for different investors.

In the medium term, far reaching change could come about if policies to take us towards net zero in other parts of the economy take off. Public support (perhaps as part of a post-Covid stimulus) to areas such as clean hydrogen production, electric vehicles and decarbonised heat could have fundamental impacts on demand for electricity.

Technology evolution will also continue to shape the power market with cost reductions still expected for a number of technologies.  Investors will need to think carefully about the impacts of such reductions.  They could spark an increase in demand but could also see governments starting to wean technologies off support, or result in cannibalisation of prices in shallower markets due to rapid entry of new capacities.

A recent example: the impact of changes to the negative pricing rule for CfDs are already being realised by developers and investors.

Renewables have support schemes in place to incentivise investment in these technologies to meet our carbon commitments.

If a wind farm receives £50/MWh through a support scheme, for every MWh of power it produces it can still sell its power at -£49/MWh because it would still make a £1/MWh profit on the electricity it produced. We saw this happening in May when GB experienced the longest period of negative pricing, a 17 consecutive hour period of negative pricing on 23 May  followed by an 11 hour period on 24 May.

This is significant because although old renewable support mechanisms don’t have any rules around negative pricing, newer contracts do. CfD, AR2 and AR3 get no support payments when prices are negative for six hours or more, while AR4 will receive no support payments whenever prices are negative. Merchant projects are exposed to all variations in price, making them the most risky projects.

The captured prices for offshore wind under different contract structures can be seen below.

While a CfD was once considered an almost entirely de-risked investment, you can now see that this relatively small change to the negative price rule is bringing risk into the CfD. With the amount of negative pricing hours forecast to increase in the future, developers and investors will need to factor this into both bidding strategies and asset values.

Staying ahead with the GB Power Investment Index

This change in the CfD rules will not just impact the assets bidding for and receiving these contracts, but will have a fundamental change on the number of negative price hours seen, and as such will impact every technology. It is increasingly common that seemingly small changes to policy and regulation have far reaching impacts that must be considered by investors across asset classes.

The Power Investment Index summarises the impacts of policy changes, commodity prices, ancillary services, market behaviour and a number of other factors into simple charts with commentary.

This will help users track and understand the value and profitability of the existing fleet under different scenarios, as well as assess the profitability of new technologies being deployed. The models underpinning the data shown are the same models used by the UK government as their primary energy market forecasting tools for long term policy impact analysis.

See more here

 Stefan Leedham, director of governance services, ElectraLink, says the impact of lockdowns and social distancing present an opportunity for the energy sector to future-proof working practices.

The world is currently in a period of unprecedented challenges. COVID-19 has laid bare our reliance on technology, with many workplaces enforcing working from home due to social distancing. But with these challenges comes an opportunity for the GB energy market to examine how we work and interact with industry parties, and the wider energy network.

As we take this opportunity to examine our ways of working, we must also take into account the wider changes we are seeing across the energy market, including the increased expectations of our customers. Customer focus has now expanded beyond merely cost and security of supply to include issues such as digitalisation, innovation and decentralisation. This, combined with the fact that technological advances are developing faster than ever, means we need solutions that embrace digital ways of working, allowing for greater collaboration and engagementand utilising technology to promote innovation, competition and positive customer outcomes.

As a code manager, ElectraLink has taken steps to incorporate technology, such as video conferencing and live chat functions, but as an industry, the requirement to continuously improve codes to match the speed and efficiency of other markets is constantly being challenged. We are living in a time where we expect to access, influence and implement changes with immediate effect – the typical six-month plus change process timeline is no longer feasible.

To meet this challenge, our proposals include:

• A digital workspace – where the industry can collaborate effectively and quickly deliver innovations,
• A digital code – where anybody can find the information that they require,
• A central governance repository – ensuring that vital changes are secure and discoverable,
• Change Clinics that bring together innovators and technical experts to drive fully understood and optimal change,
• Sandboxes, such as the one ElectraLink manages for DCUSA, that provide a clear user journey with supporting information, guidance and code experts to take new entrants smoothly through the best innovation pathway.

We are the first code manager in the GB Energy Market to provide a digitalised industry code through the Smart Metering Installation Code of Practice (SMICoP). This went beyond purely transcribing the code into a digital format to one which provided a platform that improves the experience of those already engaged and ensures anybody can engage and not be confronted with a complex legal document presented in a PDF format. We hope that all codes will follow our lead and digitalise their codes enabling automated cross code collaboration.

Technology can provide for these significant steps forward and can also provide the means for better collaboration such as document collaboration platforms and virtual forums for further sharing and cross-sector engagement. In addition, as demonstrated through the current COVID-19 lockdown, it also means that we can move away from the default position where every meeting must be held face to face to one where meetings can be held virtually with zero impact on business as usual.

However, an efficient change process needs more than just technology. It needs a code manager who understands industry data, technology, people and rules. A code managers should provide a comprehensive and diverse knowledge base, as well as host collaborative efforts that bring together innovators and technical experts to meet the needs of the market and the end consumer.