Why do energy suppliers purchase energy ahead of delivery and should we expect headwinds for independent suppliers going forward?

December’s article looks at the UK energy supply market and digs into wholesale energy procurement and the concept of ‘hedging’ to reduce cost uncertainty. The combination of shorter hedging strategies and falling wholesale energy prices has benefited independents over the past four years. Should wholesale prices continue to rise then the Big 6’s longer hedging strategy is likely to become a strength rather than a weakness. Such a scenario would also test the financial strength of independent suppliers and it is highly possible for a few more to go out of business in addition to GB Energy. Going forward, expect to see greater scrutiny of supplier’s risk capital and risk management practices.

1. Why do suppliers ‘hedge’ energy prices for customers?

Suppliers purchase energy ahead of delivery to reduce their financial exposure to changes in the wholesale energy prices. This ‘hedging’ activity increases the certainty of a supplier cost base, which reduces the difficulty in passing on wholesale energy cost changes because either the:

• tariffs is fixed price and cannot be changed; or
• market dynamics mean that passing through costs to customers would to likely incur greater losses from customers leaving to competitors with a lower price.

Consumers also benefit because hedging reduces the volatility of their bill (Figure 1 and 2). Purchasing energy further in advance means consumers are less exposed to short term variations in supply or demand and instead pay a price which is more closely aligned to fundamental costs of electricity production. It also allows a supplier to use an ‘averaging in’[1] strategy, which purchases small proportions of the total energy volume required for a delivery date over a period of up to three years. This can be compared to a ‘one shot’ procurement strategy, which purchases the total volume required at a single point in time and is highly dependent on luck as to whether the purchase point was advantageous or detrimental.

Figure 1: Longer term hedging strategies have lower price volatility (UK power – baseload)

Source: ICE.

Notes: The M+1 is the month ahead price. The M+12 is a 12 month ahead hedging strategy and the M+24 is the 24 month ahead hedging strategy.

Figure 2: Price volatility reduces considerably from month ahead at over 40% (annual standard deviation) to 25% at around 18 months ahead

Source: ICE.

Notes: Annual standard deviation is calculated by multiplying the standard deviation of daily returns by using the square root of time rule.

One concern with hedging is that consumers do not value fixed price deals very highly. Surveys completed by Ofgem show that consumers are motivated by relative prices between tariffs and much less by the stability in bills. I expect, however, that if consumers were exposed to the full volatility of prices (i.e. spot prices on a time of use basis) then I expect that they would place a much higher value on stability than they do today.

Figure 3: Only 6% switched to get a fixed priced deal, but 91% switched to save money

Source: Ofgem, 2016, Consumer engagement in the energy market since the Retail Market Review.

There is also a cost associated with hedging in advance of delivery. Estimates suggest that the cost of hedging 24 months ahead rather than 12 months ahead is £27/customer/year for a dual fuel bill.[2] Further, the use of hedging reduces transparency of costs. It makes it difficult to determine when changes in the wholesale price will translate into changes to customers’ bills. Politicians are regularly frustrated when suppliers do not immediately pass through falling wholesale prices into bills because of the hedges they already have in place.[3]

2. What does a rising wholesale price mean for suppliers?

Wholesale gas (Figure 3) prices have fallen by 58% since Dec-13 at £24/MWh to £10/MWh in Jun-16. Wholesale electricity prices also fell from £55/MWh in Dec-13 to £32/MWh in Jun-16 for baseload power, a 42% decrease. Such a decline has favoured new independent suppliers who buy a larger proportion of their energy requirements closer to delivery than the Big 6. The Big 6’s standard variable tariffs (‘SVTs’) have been relatively more expensive because they are hedged across a period of 3 years prior to delivery when prices were higher. Compare this to a fixed term contract which will have an average hedge period of 6-9 months and can benefit from recent lower prices.

Figure 4: UK Wholesale gas prices (averaged month ahead)

Source: ICE.

Figure 5: UK Wholesale electricity prices (averaged month ahead)

Source: ICE.

The falling price has helped new independent suppliers be highly competitive in the UK energy supply market and ultimately increase market share from 1% in 2012 to 16% today.[4] Wholesale prices have, however, risen sharply since September 2016 because of a range of factors including expectations of a colder winter, nuclear outages in France and a small capacity margin in the UK. If prices continue to increase then the Big 6’s longer hedging strategy will become a strength rather than a hindrance. The Big 6 have announced price freezes through the winter in until March 2017.

Should wholesale prices rise significantly or for an extended period of time then it is possible that SVT tariffs become cheaper than fixed price tariffs. This would occur if the trailing longer term hedges from an SVT tariffs are cheaper than forward wholesale costs for new tariffs. Greg Clarke MP, Secretary of State for BEIS, recently commented that “Customers who are loyal to their energy supplier should be treated well, not taken for a ride”. In this wholesale price scenario, customers would get a loyalty discount, but only through luck rather than deliberate action by the Big 6. It would also inhibit the growth of Independent suppliers who have been able to capture market share through their favourable wholesale cost position.

3. What risks do energy supply businesses have and will some go bust?

Energy supply is not capital intensive. Instead, the business model is exposed to significant risk because of cashflow mismatches between tariffs and costs (wholesale, networks). The low operating margins of supply businesses (2.9%[5]) mean that small differences can quickly wipe out this profit buffer. There are three major reasons why energy suppliers go bust:

• wholesale procurement mistakes – insufficient hedging for the suppliers exposure, cost disadvantages relative to competitors, shape risk;
• wholesale price volatility – energy imbalance, swing or weather risk;
• billing failures – inability to bill customers for the energy they consumer.

GB Energy went bust in November 2016 because it had insufficient cash available to cover its wholesale purchases and energy imbalance charges. It is highly likely that several more independent suppliers encounter similar financial difficulty over the coming winter because they typically have very limited capital relative to the risks that they are exposed to in the wholesale market.

One main advantage that the Big 6 has relative to independent suppliers is their size and superior access to finance. This significantly reduces their probability of default should their supply business be subject to adverse financial shocks. Smaller suppliers have avoided scrutiny surrounding their much higher probability of default because they have much smaller numbers of customers (hundreds of thousands rather than million). I expect this will no longer be the case following this winter if a number of other small suppliers also fail.

[1]        The ‘averaging in’ strategy is equivalent to a moving average and is used in other industries. For example, it is best practice for wealth managers with new funds (which form a large proportion of a portfolio) to deploy into equity/fixed income markets should do so over a period of months or even years.

[2]        Nera, 2015, Energy Supply Margins: Commentary on Ofgem’s SMI, Table A.3

[3]        This is not just a problem in the power and gas markets but also for petrol/diesel prices where input prices are often hedged up to a year in advance.

[4]        Ofgem data portal, 2016.

[5]        Ofgem, CSS, 5 year average EBIT margin for all Big 6 suppliers.

Is battery storage commercially viable in the UK today?

My article for November assesses costs, revenues and financing to see whether utility scale lithium-ion batteries are commercially viable in the UK today. The current costs of £100k to £140k per MW per year and revenues (through EFR) of approximately £100k per MW per year suggest that batteries are just about viable. Asset owners are, however, unlikely to be factoring an adequate rate of return on their capital which is exposed to high uncertainty, which would likely be priced at an additional £50k per MW per year. Instead, owners are likely to be making strategic investments in the hope of gaining future advantage in the battery storage market.

1. Batteries are on the rise

The challenge to store electricity rather than consuming it immediately has led to a wide range of technical solutions: pumped hydro, chemical batteries (e.g. lithium ion), flow batteries, compressed air and storage (CAES) and flywheels. Each solution has different technical characteristics which determine its power, capacity and cycling / response time. Commercial viability, however, remains a difficulty for all solutions. The value of today’s storage technical capability is predominantly to:

• alter load profiles – shift the peak load of a system (Figure 1) which reduces a system’s need for generation and network capacity that is only used for a few hours each year; and
• stabilise the grid – increasing quantities of variable supply has created an increasingly unstable grid for system operators to manage. Batteries are well placed to help balance and maintain voltage at very short notice (<1 second).

Figure 1: Shifting system load profile caused by energy storage

Source: The Economics of Battery Energy Storage, Rocky Mountain Institute 2015.

The deployment of storage technologies (excluding pumped hydro) have risen from 0.5GW in 2006, to 4.5GW in 2015 (Figure 2). This trend is primarily driven by reducing costs. Improvements in revenue streams to monetise storage flexibility have also contributed.

Figure 2: Increase in energy storage capacity since 2000 (excluding pumped hydro)

Source: US Department of Energy, Global energy storage database.

2. Costs of battery storage today

At a global scale the costs of lithium-ion batteries has fallen in the past decade at a rate of 10 to 20% per year (Figure 3). Estimates from industry experts expect the cost reduction to continue at 10% per year.

Figure 3: Reduction in battery storage (Lithium-Ion) since 2005

Source – Nykvist and Nilsson, 2015,  Nature Climate Change – Rapidly falling costs of battery packs for electric vehicles.

The UK has built two utility scale (>1MW) lithium-ion battery storage assets. One of these is the Smarter Network Storage (SNS) in Leighton Buzzard built by UK Power Networks with 6MW power / 10MWh of capacity. The other is a 2MW battery built in Orkney built by SSE.

The total project cost of SNS is £16.8 million for an asset that can provide or use 6MW of power at any given time. 70% of these costs correspond to upfront capital expenditure and the remaining 30% are ongoing operating costs. The operators of SNS estimate that the adjustment from a ‘first of a kind’ (FOAK) project to a ‘Nth of a kind’ (NOAK) project reduces lifetime costs to £11.4 million, which corresponds to £1.9 million per MW. In addition, they estimate further cost reduction of the technology since the construction date would correspond to £8.5 million, or £1.4 million per MW.[1]

Translating these costs into an annual charge depends on the expected operating life of an asset. Estimates of technical capability vary between 10 and 15 years. This implies a cost range for utility scale lithium-ion in the UK today of between £100,000 and 140,000 per MW, per year.

3. Revenue sources to deploy battery storage flexibility

There are five key areas where storage flexibility can be monetized:

• Reserves – Capacity available to increase or decrease load for energy balancing, frequency and voltage control. Procured by the System Operator (SO). Annual revenues £25k to 100k per MW, per year depending on the reserve product;
• Capacity – Ensuring a system’s peak load requirements are met. Annual revenues of £20k per MW, per year;
• TRIADs – Avoided consumption during the top 3 half hour peaks during the year (historically between 5-6.30pm between Nov-Feb). Annual revenues of £35 to 50k per MW, per year;
• Networks – Reducing constraints within a distribution or transmission network to delay or avoid investment by altering the peak load profile. Annual revenues vary by location[2]; and
• Energy market – Price responsive load to wholesale market prices. For storage this means charging when prices are low and discharging when prices peak. Limited annual revenue opportunity based on SNS testing.

Creating a profitable storage business model requires the optimum combination of products to maximise revenues. Several products have technical and regulatory barriers to operating in simultaneously (i.e. to ‘stack’ revenues). For example, it is not possible to operate in the energy market while providing services to the frequency reserve market which typically requires 95% availability.

The UK System Operator, National Grid, recently launched a new product called ‘Enhanced Frequency Response’ (EFR). This product requires immediate load change (<1s) for a short duration (to 9 seconds before primary and secondary reserves start at 10 seconds and 30 seconds respectively) and was expected to be available for 95% or more of the time. Both requirements are well suited to the technical capabilities of battery technology. All EFR contracts last for four years.

The tender results (Figure 4), indicate a wide range in bids from £61k to £380k per MW per year. The winning bids ranged from 61k to £105k per MW per year. Given the stringent availability requirements, the only area possible additional revenue streams was TRIAD avoidance. Bidders had the choice to reduce their availability so that they could operate in TRIAD windows during the winter months. Only two of the eight winning bids chose to stack TRIAD revenue and reduce availability from 100% to 96%.

Figure 4: EFR Tender in Summer 2016 (storage bids for Service 2 (±0.015 deadband) ranked from low to high)

Source – National Grid, Enhanced Frequency Response Full Results.

The revenue streams of the winning EFR bidders (Figure 5) are low relative to estimates of current cost in Section 2, which ranged from £100k to 140k per MW per year. When TRIAD revenues are taken into account, six of the eight bidders are likely to recover costs at the low end of the cost range for the coming four years. There is then significant uncertainty for the achievable revenues for the rest of the asset life in order to recover the remaining costs and potentially achieve a return on capital for their owners.

Figure 5: EFR Tender winners in Summer 2016

Items	Capacity MW	Total revenue £k /year/MW	TRIAD hours exclusion?	Estimated total revenue £k /year/MW
EDF	49	61	FALSE	61
Vattenfall	22	65	FALSE	65
Low Carbon	10	67	TRUE	117
Low Carbon	40	s79	TRUE	129
E.ON UK	10	97	FALSE	97
Element Power	25	101	FALSE	101
RES	35	105	FALSE	105
Belectric	10	105	FALSE	105

Source – National Grid, Enhanced Frequency Response Full Results.

Notes – Estimated total revenue includes an additional £50k/MW/year for TRIAD inclusion.

4. Financing battery storage

Funding battery storage today is a high risk venture, even for winning bidders of the EFR because the infancy of the technology contains a large number of unknowns:

• Revenue – EFR may not be sufficient to cover costs and is only fixed for four years despite the asset operating for 10 to 15 years;
• Capital expenditure – large ‘first of a kind costs’ which SNS estimated was 47% of actual costs. This is potentially mitigated through fixed price EPC contracts, if available;
• Operating expenditure – limited knowledge today of ongoing operating costs to run and maintain battery storage assets. This is potentially mitigated through longer term operation & maintenance contracts, if available;
• Technical delivery and availability – limited / untested asset availability and capability to deliver at very short notice over the long run; and
• Asset life – wide range of asset life estimates and uncertainty surrounding asset degradation over a large number of charge cycles.

Such risks would require a high rate of return on capital in a market funded venture, potentially 10 to 20%. Financing costs at 10% for a 10 year project with capital costs of £850,000 per MW would cost a further £500,000 per MW, or £50,000 per MW per year.

It is important to note that the winning EFR bidders were typically large companies, like EON, EDF and Vattenfall, who were able to fund the projects through their existing balance sheet. These players are likely to be willing and able to incur small losses on initial assets in order to learn and develop internal capabilities. This could provide future strategic advantages to these first movers.

It is unlikely to see players without balance sheet initiate projects of such a scale because of the gap between pilot financing through grants and project finance for fully commercial projects. In the medium to long term finance becomes increasingly viable if:

• Costs continue to fall at coming down 10% per year;
• Uncertainty about operating costs, asset life and technical delivery is reduced because of battery storage learning from FOAK projects; and
• Increasing flexibility value caused by growing variable generation.

In summary, batteries are commercially viable today with costs of £100k to £140k per MW per year and revenues through EFR of approximately £100k per MW per year. Asset owners are, however, unlikely to be factoring an adequate rate of return on their capital which is exposed to high uncertainty, which would likely be priced at an additional £50k per MW per year. Instead, owners are likely to be making strategic investments in the hope of gaining future advantage in the battery storage market.

 

Footnotes:

[1]        Corroborated by a recent estimate of capex of £850,000 per MW (Elexon, 2014, Storage business models in the UK), which corresponds to a total lifetime cost of £1.2 million per MW.

[2]        The SNS avoided a traditional network reinforcement which would cost £5.1 million. Therefore, the avoided cost was 850k per MW which corresponds to 28k per MW per year over a 30 year lifetime of the traditional asset.

Consistently use a quantitative framework to inform the UK’s electricity policy on how to best place bets on technology options

My article for October sets out a framework which quantifies potential future cost reductions for different generation technologies. It specifies a £ per MWh cost target for the country and then recommends that subsidies are distributed according to each technology’s likelihood that it can achieve the cost target in the future. In particular, the article:

• identifies the need for a consistent energy framework in the UK;
• establishes a cost target for the UK in £ per MWh;
• suggests a framework for how to assess the likelihood of costs being lower for each technology;
• quantifies the value of learning using Hinkley Point as a specific example; and
• summaries the framework within a series of recommendations for an ongoing annual Generation Option Assessment (GOA).

1. Government policy needs a framework to consistently evaluate options and to guide decision making.

While the current UK Government is an advocate of the free market, its energy policy is “hands on” whether or not it likes to admit it. The UK Government spends £7.3 billion on generation subsidies and the OBR expects this to almost double by 2020/21 (Figure 1).

The bulk of subsidy spending is on Renewable Obligations and CfDs to incentivise the build of renewable generation which can meet environmental targets. The unintended consequences of these policies are that not a single new conventional power station has been built since 2012, despite the extremely tight capacity margins we experience today in the UK and the introduction of the Capacity Market. Every pound invested in renewables, reduces aggregate wholesale electricity market by 60p.[1] Subsidies have unrecognised consequences, so Government energy policy needs to be consistent with the market over the medium to long run.

Figure 1: Current and forecast spending on emissions related energy policy

Source: July 2015 Economic and Fiscal Outlook: Fiscal Supplementary Tables.

Amber Rudd’s ‘reset speech’ in November 2015 outlined the UK Government’s energy policy and established sensible ambitions: to support technologies through their incubation phase; to provide subsidies in specifically targeted areas; and to focus on new gas, nuclear and offshore wind if their costs can become competitive.[2] It did not, however, explain how the Government intended to practically achieve these principles. Instead, policy has been inconsistent with cancellation of CCS funding and a stop-start approach towards Hinkley Point. What the UK needs is a consistent framework to objectively assess technology options and to apply this on an annual basis. This article sets out a basic suggestion of how to achieve this.

2. Commit to a specific and measureable cost target.

What does success look like for UK generation in 2030? A gold-plated electricity system would meet security of supply requirements, but at unreasonably high cost. Likewise, picking a specific technology winner today creates additional risks to security of supply and could result in high future costs relative to other options forgone.

Considering the behavioural angle can instead provide a more objective target. People do not like to pay more for electricity than they have done in the past because we expect progress rather than decline. Baseload day-ahead power has been between £40/MWh and £60/MWh since 2010 (Figure 2). Adding in the additional costs of peak supply and risk management result in a Weighted Average Cost of Electricity (WACOE) for the ‘Big 6’ supply companies of approximately £60/MWh.[3] Finally, to estimate the total cost of electricity generation, the costs of subsidies (Figure 1) need to be included. This results in total generation costs since 2010 of approximately £70/MWh.

Figure 2: UK baseload electricity price

Source: Ofgem, Electricity prices: Day-ahead baseload contracts – monthly average (GB).

Setting a well-defined, specific and challenging goal for the cost of future electricity generation has two main benefits. First, people like a clear challenge to strive towards. JFK’s goal of sending a man to the moon and bringing him back safely by the end of the decade, resulted in an obsessive catalyst for the entire US nation. Second, it allows for measurement. ‘Expensive’ or ‘cheap’ are no longer subjective statements in the eye of the beholder. Instead, technologies must be assessed relative to a defined cost of, for example, a £70/MWh[4] target so that the UK is are no worse off than our recent past.

3. Assess the likelihood of lower costs in the future

Learning is required for zero carbon generation technologies to supply at scale and reasonable cost. New nuclear technology with EPR is expensive, slow to build and has no operational cases to base decisions on. Carbon Capture and Storage (CCS) has a handful of pilots globally and none of these are in the UK. Battery technology, which could make wind’s intermittent generation more stable, is untested at scale and expensive. Any learning process consists of a number of steps:

• Demonstrating technical feasibility of a new technology;
• Commercialisation of technology (realising value through market mechanisms rather than subsidies);
• Scaling technology; and
• Delivering large capacity projects with incrementally lower costs.

The early steps need extensive research and development funding to create something new that has never existed before. Commercialisation and scaling require pilot studies to check the technologies work within markets on an increasingly large scale. Last, trial and error learning is needed at large scale to squeeze every last cost efficiency out of the construction and operational process.

Three technologies of the future have been nurtured over the past year using a seed funding and pilot approach. Carbon Capture and Storage schemes were competing for a £1 billion pot provided by the Government before they withdrew it in November 2015. Demand Side Response has been nurtured through multiple mechanisms including specific balancing products and its own auction in the capacity market. Most recently, battery storage was supported through the new Enhanced Frequency Response (EFR) product, through which National Grid tendered for 200MW of battery capacity.

Amber Rudd’s reset speech stated that the UK Government’s “intervention has to be limited to where we can really make a difference – where the technology has the potential to scale up and to compete in a global market without subsidy.” This is a sensible approach. The difficulty lies in identifying where likely potential exists, but also knowing when to stop funding and cut your losses when future progress for a technology is unlikely.

One potential approach is a framework which considers how likely costs are to change for each technology option in the future (Figure 3). If cost is highly uncertain (i.e. high volatility and a high likelihood of cost reduction), then there is a good chance that future cost could be significantly lower than the cost today. Small investments in such a technology today could provide value significantly in excess of the initial cost through cost savings of future deployments.

Figure 3: Cost volatility framework

Source: Author adaptation of Luehrman, Strategy as a Portfolio of Real Options, HBR Sep-Oct 1998.

If uncertainty is low (i.e. low volatility and low likelihood of cost reduction), then today’s cost is likely to be equal to the technology’s future cost. This is fine if costs are already low, but if the costs are high and unlikely to change then the technology is not a viable consideration for the future and should be avoided today.

Figure 4 plots a number of generation technologies onto the cost volatility framework. Interconnectors, a technology with seven links in progress that require little or no Government support is likely to be cost effective. The technology is also well established and costs are unlikely to change in the future. It therefore sits in the “green zone” and should be built today.

Figure 4: Cost volatility framework with estimated positions of generation technologies

Source: Author adaptation of Luehrman, Strategy as a Portfolio of Real Options, HBR Sep-Oct 1998.

Most other technologies are not cost effective today. New nuclear technology (EPR) is expensive relative to historic cost. Hinkley Point C is built based on £92.50/MWh. This is however, the starting point for nuclear. The last UK nuclear power plant was commissioned in 1995. It takes time to develop nuclear expertise such that the next nuclear plant is cheaper. Replacement of an ageing nuclear fleet on a global scale is likely to trigger high R&D spending over the coming decade, which could result in new and more cost effective designs, such as the Small Modular Reactor (SMR). Therefore, nuclear technology is placed in the high volatility section of the framework and is a useful option to hold today with the expectation that future costs are likely to change.

Offshore wind costs have been falling over the past 20 years. Its learning rate, the reduction in cost for a doubling in output, has been an impressive 5 to 19%.[5] The offshore wind market is also in relative infancy with only 8% of the EU’s 142 GW of total wind capacity.[6] There is clearly room for more as the deployment continues.

Biomass plants are reliant on Government support and are not viable at current LCOE. It is not however, the capital cost uncertainty but instead the input price uncertainty of the fuel feedstock for any plant. While cost reductions can be made in this area, the learning curve for reducing the costs of biological material is likely to be low. Further, storage costs today are extremely high, but also have high learning curve and likelihood of significant cost reduction in the coming decade.

4. Quantify today’s spending with its expected benefit in the future

The cost volatility framework can quantify the order of magnitude of spending today to see whether it is likely to be worthwhile investment in the future. It is easiest to understand using an example.

Hinkley Point C will cost the UK £92.50 per MWh for the life of the plant. This seems expensive relative to a hypothetical target cost of £70 per MWh, but this fails to account for the learning effects and the likelihood that future nuclear installations in the UK will be made at lower costs. We can put a rough estimate to the value of this learning by applying options pricing techniques.[7]

In the case of Hinkley, we can set the parameters of the Balck-Scholes pricing formula such that the current price (S) is £92.50/MWh, the strike price is £70/MWh, time for the cost reductions to take place of 10 years and a risk free rate (r) of 2% and a volatility of 15%.[8] These assumptions result in an option value of £2.80 per MWh, which when spread across the output of a further 10 GW of potential capacity is worth £10.3 billion of spending today to have the chance of lowering costs through future learning.

Estimates of the costs to the UK for Hinkley Point have increased from £14 billion in 2015 to £37 billion in 2016.[9] The cost uncertainty is caused by assumptions for the wholesale price against which the CfD top up is calculated. Calculating the cost to the UK against a cost of £70 per MWh rather than the much lower wholesale prices (of £40 to 50 per MWh) would reduce the number below £14 billion. Our £10.3 billion estimate for value of learning seems that the UK is roughly paying a fair price for Hinkley Point, but only just.

5. Recommendations

The UK is making major decisions on its electricity generation future and a consistent and objective framework will help significantly in this process. It should consist of:

• a specific cost target, for example generation costs of £70 per MWh, to provide a challenge to aim for and a benchmark to measure against;
• an assessment of each technology option with regards to the likelihood that competitive costs can be reached and by when;
• a portfolio approach to placing bets on technologies by allocating capital to the most promising options and recognising when to walk away from technologies which are no longer viable; and
• a quantification before major spending to assess whether the potential benefits of learning are likely to be matched by the upfront cost.

The Government should repeat this framework regularly. The UK transmission network has an annual Network Options Assessment (NOA). In a similar way, an annual Generation Options Assessment is a sensible way forward.

[1] Good Energy, Wind and solar reducing consumer bills An investigation into the Merit Order Effect, 2014

[2] Amber Rudd’s speech on a new direction for UK energy policy, 18 November 2015.

[3] Ofgem, Energy companies’ Consolidated Segmental Statements (CSS), 2009 to 2015.

[4] A cost per MWh is used because of industry familiarity. A more accurate cost assessment should adjustment for differences in load factors (3 times as many wind plants are required for the same conventional plant on a MW basis) and for total system costs (e.g. intermittency, lack of inertia).

[5] Rubin et al, A review of learning rates for electricity supply technologies, 2015,

[6] Wind Europe, 2015 European statistics.

[7] Basic financial option calculations using the Black-Scholes formula.

[8] The assumption with greatest uncertainty is volatility because of limited data to create an estimate. The option has negligible value below 10% volatility.

[9] The Guardian, Estimated cost of Hinkley Point C nuclear plant rises to £37bn, July 2016.

Lifetime cost estimates of zero carbon electricity generation technologies are similar to each other. The UK must learn more to identify technology winners with lower costs.

1. The UK Government is faced with the challenge of minimising the cost of 20GW of new electricity supply by 2030 while also ensuring it complies with increasingly stringent emission targets.

Failures by successive UK Governments, stuck in the short-termism of modern politics, has resulted in UK energy policy being notably absent. Indicative of this is the decision of Theresa May’s new post-Brexit Conservative Government to delay the progress of Hinkley Point C despite EDF approving its construction. Another major example is the cancellation of Carbon Capture and Storage funding worth £1 billion. The only major area of Government support that remains is for offshore wind.

Time is now however, running out. By 2030, the UK must build almost 20GW of new electricity generation capacity to supply the nation and keep the lights on. This is equivalent to replacing 30% of power plants in existence today.

Historic margins of excess supply over demand have narrowed considerably in the past two decades, resulting in the current electricity supply squeeze the UK is experiencing today (Figure 1). Major closures of nuclear and coal capacity during the mid-2020s will create deeper gaps in supply that will need to be filled with new power plants. Should Hinkley Point go ahead today, the earliest it would be providing electricity is 2025. We are already playing catch up.

Figure 1: UK electricity supply with an estimate of future retirement dates of current plants closure dates, relative to UK electricity demand.

Source: Dukes, National Grid FES, Author assumptions on plant life based on numerous public sources which provide an indicative plant retirement date.

The major constraint on what technology the UK uses to replace aging power plants is its carbon emissions targets. Power station emissions have fallen by 39% from 1990 levels (Figure 2). Yet the UK has a long way to go. 2050 targets require a further 69% reduction in emissions.

Figure 2: UK carbon emissions by sector and future emission targets.

Source: UK Government Greenhouse gas emissions national statistics 1990-2014.

If we assume that the UK continues to adhere to European and International emissions targets, the UK Government must establish a policy framework which incentivises the construction of sufficient generation capacity, using technologies that meet environmental obligations, at the lowest cost. The UK spends £41 billion on electricity every year. This makes electricity spending larger than the cost of other public goods like Defence and Public order and about half the size of spending on Education.

Given the cost, it is sensible for the new UK Government to pause on Hinkley Point. Decisions made by today’s UK Government will determine the cost of electricity for the next 30 years. The current policy levers of CfD subsidies, the Capacity Market and carbon taxation are not incentivising the market to act in the way the UK needs it to. Instead, the Government must develop a new strategy and make consistent decisions that align with this way forward. Given the urgent need for supply, it cannot linger in designing this framework.

2. Assessing the UK’s zero carbon generation technology options by cost

The UK has only four main generation technology options available to its electricity generation mix:

• nuclear;
• carbon capture and storage (CCS) on gas / coal fired plants;
• biomass; and
• offshore wind (plus storage).

To meet the constraints on carbon emissions, the traditional unabated gas and coal plants are not feasible options. To meet security of supply requirements, intermittent generation like wind and solar cannot be the foundation of electricity supply because the UK cannot rely on them being able to generate electricity on a windless and cloudy day. This means that intermittent generation must add storage so they are able to supply the grid even when the weather conditions are unfavourable. Further, the security of supply constraint also limits the role of interconnectors for providing firm supply because the technology allows electricity to flow out of the UK as well as in.

The problem with assessing costs for these four options is that the technologies are new and typically not in commercial use today. The new nuclear technology, EPR, has yet to become operational. Three plants are currently in construction (Olkiluoto in Finland, Flamanville in France and Taishan in China) and all are delayed and significantly in excess of original cost estimates. There are no working Carbon Capture Storage pilots, let alone full scale operations in the UK. Battery storage is very expensive and the “intermittent plus storage” approach is only entering the pilot phase. This cost uncertainty creates significant challenges for decision making.

To get a basic understanding, Parsons Brinkerhoff on behalf of the UK government has estimated costs using best available information. Assessing this data yields some clear insights. First, initial costs of nuclear are significantly higher than alternative technologies. This is a range from £1.3 million/MW to £4.3 million/MW (Figure 3). Translating this into the 18GW of capacity required before 2030, costs would range from £20 billion to £80 billion. However, the story changes when assessing costs on a lifetime view (Figure 4). Nuclear has the lowest total cost of all zero carbon technology plants. The only technology with lower total cost is the traditional unabated CCGT plants which would fail to meet the carbon emission targets.

Figure 3: Initial construction costs for different generation technologies (£ per MW).

Source: DECC (Parsons Brinkerhoff), Electricity Generation Costs, December 2013.

Second, total lifetime plant costs for technologies tend to cluster around £16 million per MW. This corresponds to a 25 year cost to the UK of around £250 billion for the 18GW. There is no technology with costs that are materially lower relative rival technologies others and so there are no clear winners for the government or market to favour.

Last, interest costs form a large portion of total costs for nuclear and wind. For these technologies, no fuel input is required and so the costs are incurred either in construction and ongoing financing costs for the capital borrowed. The long borrowing period and high interest rate of 10% assumed by the Government’s study means that interest costs are up to 3.5 times the initial cost of construction.

Figure 4: Lifetime costs for different generation technologies (25 years, £ per MW).

Source: DECC (Parsons Brinkerhoff), Electricity Generation Costs, December 2013. Author analysis.

Note: The adjustment for intermittency uses average load factors relative to a CCGT plant.

These insights lead to the four following recommendations for the future of UK energy policy:

• The UK Government must act rapidly to develop a clear strategic framework within which to incentivise future generation technology;
• Take tactical steps to reduce the uncertainty on today’s cost estimates. Create a flexible strategy that enables targeted learning through pilot schemes. This keeps options open and minimises sunk capital;
• Take a lifetime approach when assessing costs. For example, nuclear has the highest upfront building costs, but lifetime costs that are slightly lower than other technology options; and
• Consider funding infrastructure projects at the public level, which benefits from significantly lower interest rates and creates large lifetime cost savings. Funding at 3% rather than 10% reduces interest costs for nuclear by over 75% and lifetime costs by 45%.

There is significant value at stake for all UK taxpayers. The UK spends £40 billion a year on electricity and we are stuck with policy decisions made today for the next 30 years. The UK must ensure it makes the right choices using the best information we can obtain.