Understanding the proposed energy policies of the main UK political parties

The 2017 UK general election is taking place on 8 June and most parties have released their manifesto. This article takes an objective look at the energy policy component of the main parties. It starts off with an overview of the policies before looking in detail to the proposals regarding energy bills. Reading time is 4 minutes and 30 seconds.

Figure 1: Summary of manifestos

Source: Carbon Brief.

The manifestos for Conservative, Labour, Lib Dems and the Greens are summarised above in Figure 1. The following conclusions jump out:

• Conservative and Labour are both proposing a price cap on energy bills. Labour’s is more aggressive with a cap at £1000 and the introduction of publicly owned energy companies;
• The Conservatives hint that they would remove intermediary climate change targets in 2030 and relax the carbon budgets, but retain the 2050 target. This is in line with the recent House of Lords recommendation[1] to slow the UK’s progress towards reducing CO2 emissions by 2050;
• Challenger parties represent a greener option by adhering to existing CO2 targets and promising 60% of energy to be generated by renewables in 2030; and
• Most parties are proposing a diverse set of energy technologies, including tidal and offshore wind. Lib Dems and the Greens are advocating onshore wind. Labour and Lib Dems want to introduce CCS schemes.

The main battleground for energy policy in the 2017 election is energy bills. Ed Miliband initially launched a price freeze policy in 2011, which was extremely well received by the public and caught the Tories off guard. This time the Conservatives have been on the front foot by launching their own version of the price cap.

Public perception is that bills have increased significantly and that energy companies have been making huge profits at the UK consumer’s expense. Figure 2 is the annual cost of bills since 1996 and it shows that bills rose by two-thirds between 2004 and 2010, but since this date, a bill today is roughly the same as the cost in 2010. This suggests that pledges made today are a little late and that Ed Miliband’s price freeze in 2011 was much more reflective of the pressure felt by UK consumers.

Figure 2: The cost of UK energy bills (£, 1996 to 2016)

Source: UK Government, Statistical data set – Annual domestic energy bills. Note: Direct debit, all consumers, 2010 real prices.

Further, the profits earnt by the ‘Big 6’ energy suppliers (British Gas, npower, EDF, EON, Scottish Power and SSE) were £1.1 billion in 2014[2]. On the face of it, this appears to be a large number and corresponds to £43.50 for each UK household. However, comparing this to the size of the bill, profit margins are only 4%. We can also compare this to the profits of the three largest supermarkets (Tesco, Sainsburys and Morrisons), which in 2014 were £7.4 billion[3], or £285 per household. On a relative basis, companies supplying electricity and gas are receiving less than 15% of the profits earnt by companies supplying food to the UK household.

However, many consider that bills are too high in the UK today. Figure 3 shows the breakdown of some of the components of an energy bill and highlights two problems. First, direct costs have increased because of an increasing number of subsidies for renewable energy. The government and UK consumers cannot expect to transition to a low carbon economy without incurring additional costs. This point is especially important for Labour’s and the Lib Dem’s manifesto promise to provide 60% of the UK’s energy using renewable sources. The costs to achieve this will be high from an initial build cost perspective and from a system instability perspective. Should the UK public proceed down the path of 60% renewables by 2030, then they must be ready to accept the high cost to deliver this policy.

Second, the operating costs and profit have increased. These are the two items that are controllable for energy suppliers. It is disappointing to see that in a period when there was significant competitive pressure from new independent suppliers, who grew their market share from nothing to 16% of the market, that the Big 6 energy providers failed to reduced operating costs or lower profit margins. Instead, profit margins increased from 2.8% to 4.0%[4] with the ‘Big 6’ passing some of the additional costs onto consumers. Coupled with the poor levels of customer service experienced by energy markets, it is fair to conclude that change is needed.

Figure 3: Changes in UK energy bills (£, 2011 to 2015)Source: Ofgem CSS data.

The introduction of a basic price cap on the most visible part of the UK energy system, the consumer bill, is not a sustainable fix. Instead, the next government should take a total system view when setting costs which assesses the combined costs of generating electricity, transporting it through the network and the cost to use low carbon energy sources. The independent review of the cost of energy in the Conservative manifesto is a start to this, but I consider that the total system view should be part of an ongoing process and independent of the government in power, rather than a one off.

With regards to energy suppliers, the UK needs to establish a new pricing mechanism that fosters transparent competition. Dieter Helm[5] proposes another method which caps the sections of the bill that energy companies cannot control, which are wholesale and direct costs so that these are the same for all customers. Then, for the parts of the bill which are in the control of energy companies like operating costs and margin, facilitate transparent competition so it is easy for UK customers to determine the lowest prices in the market.

Lastly, Labour’s call for energy bills to be less than £1000 is unrealistic. The uncontrollable costs for energy companies in 2015 were £933 and operating costs were £184. To meet the £1000 cap, energy companies would either need to be subsidised from other government funds or end up leaving the market. I would also expect that the introduction of additional publicly funded energy companies would not be beneficial for the UK. They might result in lower energy bills, but the public funds required to do this would likely offset any gains and result in a net loss for the UK consumer.

So in summary, the manifestos represent the long-running energy trade-off between sustainability and affordability. Labour and Lib Dems propose a more environmentally friendly way with 60% of energy produced by renewables in 2030. This is opposed by pledges from parties propose to cap household energy bills, but the Conservative policies are the only ones that are consistent with delivering it.

[1]        House of Lords, The Price of Power: Reforming the Electricity Market, 2016/17.

[2]        Profits refer to EBITDA figures. 2014 was the year with the highest EBITDA where data is available between 2009-2015.

[3]        Goldmann Sachs, UK Supermarkets equity note, 2015.

[4]        CSS data, EBITDA margins.

[5]        Dieter Helm, Why intervention on energy tariffs is needed and how to do it without undermining competition, April 2017.

Four practical tools that improve strategic decision making

Research finds that process is 6 times more important than analysis when making decisions.[1] It is therefore clear that businesses can get more value by improving their decision making process rather than putting extra effort into their analysis.

Establishing a robust process helps to limit the variability in decision making and brings the baseline level of decisions to a reasonable standard. This article explains four recommended techniques (shown in Figure 1) that businesses should consider using as part of their decision making processes.

Figure 1: Practical decision making techniques

1. Pre-mortem

A pre-mortem sits in a category of techniques that alter the mindset of decision makers by requiring them to think using a specific perspective. In this case, the technique stress-tests a favoured decision by asking participants to imagine that the business is 1 to 3 years ahead of today and the favoured decision resulted in a massive failure. The participants must generate reasons to explain the “cause of death”.

The role-play essentially acts as a shortcut to constructive criticism. Decision makers are often overconfident with their chosen course of action, but the pre-mortem empowers participants to hunt for blind spots and reduces the emotion that often occurs in traditional head-to-head debates. It also helps decision makers to transition from day-to-day activities and bridge into the long run when strategic decisions play out over multiple years.

Pre-mortems are a relatively new concept and were introduced by Gary Klein in 2007.[2] A very similar technique of falsification, which seeks to disprove the prevailing hypothesis, is a much older concept. It is however, rarely performed in practice. Groups often succumb to the confirmation bias where they gather evidence to justify their decision.

2. War Gaming

War Gaming simulates a market by considering the perspectives of the key players in the industry and recreating their competitive responses. A game typically involves 3 to 6 main stakeholders (which can include non-competing parties such as the regulator) who set business levers such as price and capital expenditure. The game repeats over a number of turns where stakeholders submit choices and then receive feedback about the market position (e.g. market shares, pricing, and profitability).

Figure 2: The steps of a War Game

The simulation is a practice ground to try different strategic directions and understand what competitive responses each option might face. This multi-party, multi-iteration aspect of the game makes it more powerful than just regular strategic planning. The typical insight obtained through War Gaming is not a specific set of actions, but rather guidance on general trends, strengths and weaknesses of market players and promising moves.

To understand it in practice, a global chemicals company used War Gaming to understand what might happen if they built a new plant to produce more of a specific product. Their simulations suggested that competitors would react aggressively to defend market share. These insights led to the company adopting a more transparent implementation strategy, which publicly announced the new plant in advance of it being able to produce. This reduced the aggressiveness of its competitors’ response.

War Gaming is often most valuable when a business is facing impending change and wants to better understand what tomorrow might look like. Ideally, there are a handful of options to test and the market has meaningful competitive dynamics driven by a small number of stakeholders who have the most influence. The simulation itself provides an immersive experience where people better understand the mindset of their competitors and ‘live’ through the consequence of their strategies.

Some of the best outcomes that I have seen from War Gaming often test the boundaries of perceived market ‘rules’. Games should ideally trigger an optimum level of stress for players – one that forces problem solving but provides enough space to do so – tends to draw out innovative and lateral thinking. For example, in a War Game which simulated how countries would negotiation for a finite supply of vaccines, the more innovative and successful players ‘bent the rules’ by forming coalitions between multiple countries.

3. Submit your homework

The ‘Homework’ technique requires each decision maker to formally submit their views ahead of a decision meeting to choose course of action. There are three key benefits to this. First, the act of formal submission means that decision makers are directly accountable for their actions and will therefore become much more active in any decision process.

The second benefit is that that each person’s view is independent of another, rather than being swayed by group opinions. This helps to access the ‘wisdom of the crowds’ when making decisions because each player’s own expertise and diverse perspective is considered.

Third, the process provides a forum for all stakeholders and ensures that the most vocal members do not dominate the group’s discussion.

Most decision making meetings usually combines an information session (where the facts are presented) with the decision session (where the evaluation and debate happens). The Homework approach separates these activities. Despite it appearing like more work, putting in the groundwork is likely to facilitate faster, less painful and more successful decisions.

4. Spell it out

‘Spelling it out’ is a method that requires decision makers to explicitly state the components that make up their decision. There are a number of components to define:

• question –a precise articulation of the question that decision makers need to answer (e.g. selecting from a range of options, yes/no to a course of action);
• key decision factors – considerations like financial (NPV, rate of returns, cash flow profiles, payback periods), safety, reputation and ease of implementation;
• evaluation criteria weightings – prioritising and then assigning percentage weights to each of the key decision factors;
• probabilities of scenarios – where any scenarios depicting future states of the world are used, like high / medium / low, assign a percentage likelihood for each one occurring; and
• decision criteria –approaches to combining evaluation scores like maximum expected outcome (maximax), maximum worst outcome (maximin), or least regrets (minimax)

This technique is an analytical way of approaching decision making. While it appears complex, parties are making these selections implicitly within their own thought processes. Laying it all out explicitly can simplify discussions between multiple parties and reduce the chances of getting stuck in the weeds when evaluating options.

Spell it out is best used when people are trying to trade off multiple criteria which mix qualitative and quantitative factors. A recent project saw a utility client who was deciding what to do with a large capital asset that was incurring operational losses. They were grappling with three options with different financial outcomes and also different outcomes regarding asset safety and company reputation. Initial discussions got stuck because different stakeholders placed different weightings on things like reputation. Explicitly agreeing a common set of criteria weightings helped the company to discuss the overall packages in a more holistic manner.

5. Conclusion

There are a number of ways that businesses can improve their decision making. This article has looked at how four practical techniques – Pre-mortems, War Gaming, Homework and Spell it out – that business can deploy within a wider decision making process. My next articles are going to look at improving regular decisions through automation and use of specialist, in-house ‘decision teams’.

[1]        McKinsey Quarterly, 2010, The case for behavioral strategy

[2]        Klein, 2007, HBR, Performing a Project Premortem

How are utilities trying to embrace innovation?

The recent development of new technology which can collect information from cheap sensors, transmit the data across the world, then store and process it in novel ways, enables the potential for new ways of working in all industries. The energy industry is no different. This article looks at what incumbent utilities are doing to develop new technologies. The reading time is 5 minutes, 13 seconds.

1. Energy innovation is recovering in the UK following a long slump after privatisation

Figure 1 illustrates the changes in R&D spending on energy in the UK. The UK experienced a 90% decline in R&D spending between an annual rate of £800 million (2015 prices) before 1985, to less than £100 million per year from 1995 to 2005. Experts attribute this decline “to the run down of nuclear technology and the loss of R&D function after the privatisation of the energy utilities”.[1]

Figure 1: Total energy technology research development and demonstration expenditure 1974–2014 (in £ million, 2015 prices)

Source: International Energy Agency, ‘Data Services: RD&D statistics database’: http://www.iea.org/statistics/RDDonlinedataservice. Accessed December 2016.

The past five years have seen an increase in the UK’s energy spending on R&D to around £400 million. We are still, however, spending only half of the pre-privatisation rate. There are two main reasons for the pick up:

• decarbonisation of generation technologies – the development and improvement of low carbon generation technologies like nuclear, onshore/offshore wind, solar and carbon capture storage (CCS);
• digital technology – the growth of cheap sensors, which are wirelessly connected to a central cloud storage service and the potential to process and analyse the data using new techniques like neural networks

Both of these will remain important themes for the coming decades. Also, the current narrowing of the capacity margin in the UK may trigger further increases in R&D spending in the shorter run.

2. Most utilities innovate by mixing in-house development with VC funds

The incumbent utilities, like Centrica and SSE, need to adapt to remain competitive in future new energy environments. There are four main ways to innovate:

• In house development – internal teams working on specific projects;
• Partnerships – collaboration with other parties on specific projects;
• Venture Capital (internal fund) – equity investment directly into start-up businesses;
• Venture Capital (external fund) – investment into a Venture Capital fund which has multiple underlying equity investments in energy start-ups.

Each approach has different risk and return profiles, but it is extremely difficult to conclude that one is more successful than the another. VC funds typically aim for a 20% annual return but achieve it by making outstanding returns in only one or two investments out of a portfolio of ten (10x to 100x). [2] The remaining eight investments fail. In contrast, in-house innovation is likely to be more targeted and requires a less uncertain return structure.

We can, however, draw some comparisons from the strategic positioning of each of the four approaches (Figure 2). The main benefits of in-house and partnerships are the greater control over the project, the development of internal skills and also the greater potential to apply the technology to the utilities own generation or supply portfolio. In contrast, VC funds provide wider exposure to innovation across different technologies, countries and firms. It also provides a separate unit with a ‘start-up’ culture which is more tolerant to failures, but expects 10x to 100x returns on a small number of its investments.

Figure 2: Comparison of the four approaches that utilities are taking to innovation

Source: Company websites and accounts. Accessed March 2017.

When we look at how utilities are actually innovating (Figure 3), we see that all of the UK’s Big 6 firms (or their group companies) use some form of VC fund. Five of them have an in-house fund and only EDF rely on an external VC approach – utilities clearly value specialised units that think in a different way to the main business.

In addition to their VC units, most of the utilities surveyed also use in-house projects and partnerships. In-house projects tend to be favoured when the utility identifies a specific problem to be solved. For example, Centrica developed Io-Tahoe, a ‘data lake’ which combines multiple sources of customer data into a single source for analysis. The initial need was for British Gas, but the end product is one that can be applied in other businesses. Partnerships are often used when the identified problem requires specialist skills or assets which are not held within the company. For example, RWE has extensive partnerships with universities to develop specific products and processes.

Figure 3: Approaches taken by the Big 6 UK utilities and their group companies in relation to VC innovation

Source: Company websites and accounts. Accessed March 2017.

Last, we can drill down into the investment themes that each of the six utilities have focused on (Figure 4). RWE, EON and SSE are the most active companies with the most investments. The others like Centrica have only started their fund recently, or take a more hands off approach like EDF.

Low carbon generation, which includes storage, is the most active investment activity area for all utilities. There is then a thinner coverage across demand management, asset intelligence, data management and trading / portfolio management. The majority of customer focused solutions concentrate on technologies that enable demand awareness and response.

Figure 4: Thematic areas of VC investment by the Big 6 UK utilities and their group companies

Source: Company websites and accounts. Accessed March 2017.

3. But is the utility culture ready to maximise the benefits of innovation?

The traditional utility business model is still rooted in an asset backed culture, which is expected to generate consistent cash flows in proportion to the asset base size. Innovation does not follow this cash flow profile. The strategy to set up in-house VC is a sensible start in transitioning to a more flexible and service led business model.

When new technology and services become successful then the next challenge utilities must manage is to scale. Businesses capture the majority of a technology’s value when it diffuses amongst the masses and not in the innovation or early adoption stages (Figure 5). The first mover is often not the most successful firm, despite being the pioneer of the new offering. Utilities are on the right track to creating winners, but they also need to be ready to successfully scale when they find one.

Figure 5: The ‘Diffusion curve’ which charts the spread of a new technology amongst a population

[1]        House of Lords. Select Committee on Economic Affairs. 2nd Report of Session 2016–17. Written evidence from Prof Richard Friend and Prof Richard Jones

[2]        10x corresponds to a return that is 10 times the initial investment. 100x corresponds to a return that is 100 times the initial investment.

A wave of energy supply business transactions is approaching, but are you ready to price them?

1. Will the UK energy supply market consolidate?

The UK energy supply market was quiet until 2012, with between 10 and 15 firms competing. Participants have since tripled to 44 firms (Figure 1). However, most suppliers are small in size with only 12 firms operating more than 400,000 accounts. Dermot Nolan, Ofgem CEO, thinks it is “highly possible that there will be a shakeout of firms in the coming years, and we may have much fewer than 50 suppliers in five years’ time.”[1]

Figure 1: The number of active domestic suppliers by fuel type has tripled since 2011

Source: Ofgem data portal

It makes sense for independent suppliers to consolidate. Some firms might be seeking a way to quickly boost their customer base. Others might be hoping to achieve greater economies of scale. The recent decisions by European utilities, like ESB[2] and Engie,[3] to enter the UK market shows that there are a number of willing buyers circling energy suppliers.

A number of willing sellers are also lined up. Flow Energy recently announced that “the Board received a number of approaches expressing interest in its Flow Energy business… As a result, the Board has concluded that the disposal of Flow Energy is something that it should actively pursue.”[4] Ovo Energy sold 15% of equity to Mayfair Equity Partners in August 2015[5] and First Utility shelved original IPO plans in favour of a potential equity sale.[6]

There has also been one unwilling seller, GB Energy, who experienced financial distress in November 2016.[7] Given the wholesale price volatility in recent months and the aggressive pricing of a number of new entrants, it is highly possible that more unwilling sellers are uncovered in 2017.

2. What is a fair transaction price to pay for an energy supply business?

Given that buyers and sellers of energy supply businesses already exist, the next obstacle is finding an agreeable price for a transaction. There are three main approaches to valuing a business, which we look at in more detail for energy supply firms:

• income – estimating future cash flows of a business and discounting them back to today’s present value;
• market – identifying comparable market transactions to infer a reasonable range of market price for a business; and
• cost – estimating the replacement cost to re-construct a business from scratch.

Income

The income approach requires that cash flows are forecasted and then discounted back at a cost of capital which reflects the business’ risk profile. This is a discounted cash flow (DCF) approach which provides today’s value of the future business.

Customer account growth and EBIT margin are the key variables when forecasting cash flows of an energy supply business. Growth has been quick for Independents (i.e. non ‘Big 6 companies), but will it continue?

At an industry level, the current churn statistics are encouraging for continued growth of the Independents. Figure 2 shows that for any customer who switched supplier, 35 to 55% of these have switched to an Independent supplier rather than a Big 6 supplier. If this rate continues then the market shares of Independents will increase from 16% to in excess of 30% over the medium to long run. Recent analyst estimates suggest this level might be achieved by 2020 (see Figure 3)

Figure 2: The proportion of customers switching to Independents has ranged between 35 and 55% since 2014

Source: Ofgem data portal

Figure 3: Jefferies forecast of UK energy supply market shares

Source: Jefferies forecasts, 22 Sep 2016

Growth has also been impressive at a company level. The historic growth of accounts for Independent suppliers is in Figure 4. Growth is greatest for suppliers below the obligation threshold of 250,000 customers with a median rate of 90% per year. Account growth beyond the threshold for 250,000 to 500,000 customers is still impressive with a median rate of 64%.

The rate slows as a firm gets larger, but historical evidence indicates robust growth rates of 12 to 31% per year. Alongside the positive churn rates towards Independent suppliers (Figure 2), suggests that Independent suppliers could maintain similar growth rates until the end of the decade.

Figure 4: The annual growth rate of Independent companies, split by size, between 2012 and 2016

Source: Cornwall market share data

Note: There are 7 growth rate data points when customer accounts exceed 500k customer accounts and 46 data points below 500k.

The second key area for cash flow forecasting is the profit margin that energy suppliers earn. The EBIT margin for the Big 6 over the last 5 years averaged 2.9% and in 2015, ranged from -6.8% to 7.0%. Businesses operate at very low margins which are subject to significant volatility between companies.

Profitability is also volatile over time. Expect EBIT margins during growth phases to be low because retailers discount tariffs to attract customers. For example, Ovo Energy’s EBIT margin averaged -5% from 2011 to 2015[8] and Flow Energy is operating at a -10% EBIT margin. Suppliers hope that customer accounts can grow but indirect costs stay relatively fixed. The resulting economies of scale could drastically improve margins. It is therefore imperative for cash flow forecasts to set margins which are consistent with the growth phase of the business.

Further, a valuation needs to spend sufficient time to fully understand how a business operates, First Utility and Utilita are already achieving 1% and 6% EBIT margins, but are still experiencing robust account growth.[9] The differences in growth and margin expectations between suppliers create markedly different valuations.

Market

The market approach applies the prices paid for similar companies and applies the price to the business being valued. The popular market multiple used for energy supply transactions is price per customer account. Recent transactions have occurred at prices around £250 per customer account:

• Telecom Plus purchase of 770,000 accounts from nPower for £218 million in November 2013, corresponds to a £280/account;[10] and
• Mayfair Equity Partners bought 15% of OVO’s shares for £31million in August 2015, which corresponds to £250/account.[11]

We can crosscheck these multiples using very basic assumptions about the behaviour and margins for a single customer. Assuming an EBIT margin of 2% in the year of customer acquisition and an 8% EBIT margin for a further four years would correspond to a £225/customer value today.[12] However, more conservative assumptions with an acquisition EBIT margin of -2% for one year followed by 3 years at 5%, corresponds to only £86/customer today.

Energy supply businesses operate at very small margins and so valuation is highly sensitive to small percentage point changes. The crosscheck does not include any growth in customer numbers and acts as a ‘floor’ to a valuation.

Cost

Another way to determine a ‘floor’ value is to use a cost approach to value an energy supply business. This estimates the cost to rebuild the business from scratch and was used by the CMA in its recent Energy Market Investigation.

The CMA capitalised supplier’s costs to acquire customers, which included “Customer acquisition costs comprise doorstep/energy advisers’ costs, telesales, commissions payable to brokers or PCWs, sales support, proposition development and other similar costs”.[13] Applying this approach can result in multiples of £50 to £150 per account depending on which costs are included and what the life of the customer.[14]

3. What next?

In conclusion, the income approach is the key tool for any buyer or seller who is valuing an energy supply business, but market and income based approaches form useful cross-checks. Make sure your valuation has:

• a realistic growth rate that decreases with company size and in line with industry dynamics;
• EBIT margins that are consistent with the level achieved by others in a competitive marketplace and with the rate of growth of the company; and
• a number of cross-checks which set cash flows into context.

A number of companies like Flow Energy and First Utility might be the next sellers in the UK market. Buyers must make sure they have their valuation tools ready to price transactions, which might need deployed at short notice to bid with confidence for distressed sellers.

[1]      Dermot Nolan, Beesley Lecture, 2016.

[2]        ESB to enter UK supply market.

[3]        Engie to enter UK household power market.

[4]        Flowgroup update, 08 February 2017.

[5]        Ovo and Mayfair Capital

[6]        First Utility Eyes Share Sale As IPO Spark Fades

[7]        Ofgem appoints Co-operative Energy to take on GB Energy Supply’s customers, 29 November 2016.

[8]        Capital IQ data

[9]        Capital IQ data. First Utility FY2010 to FY2015 and Utilita FY2014 to FY2016.

[10]      Telecom Plus and nPower transaction

[11]      Mayfair Equity Partners and Ovo Energy transaction. Assumes 815,000 accounts in Q215 (Cornwall Energy market share data).

[12]      Assuming a discount rate of 7.5%, annual tariff cost of £1050, tax rate of 20%.

[13]      CMA EMI, Appendix 9.10: Analysis of retail supply profitability – ROCE, Paragraph 67.

[14]      In particular, how any discounting of the tariff is included and the customer lifespan.

The future battlegrounds for energy suppliers

Retail energy supply has reached a transition point. New technology has created fresh opportunities to engage customers: the roll out of smart meters and personalised energy usage data; the connected home which generates and stores its own electricity; and tools which provide automatic tariff switching services. This article looks at different areas that suppliers might compete in and identifies the competencies required for success. (Estimated reading time 5 minutes and 47 seconds)

1. Where might energy suppliers need to compete next?

Today’s retail energy consumer in the UK is disengaged. The ‘Big 6’ suppliers have 60 to 80% of their customers on a Standard Variable Tariff (SVT), despite the cost being £137 higher (12% of total bill) on average than non-standard tariffs offered for new customers.[1] Those that are engaged only want basic electricity at the lowest price possible. with only 13% of customers citing service as a reason for switching.[2]

Technology is, however, changing the way customers behave and what retailers can offer them. Figure 1 categorises change along these two dimensions – differentiation and customer engagement. We explore each of the domains areas in turn below.

Figure 1: Competition domains

2-tier pricing

2-tier pricing is the core strategy of UK energy suppliers today. Competition occurs through acquisition tariffs which last about a year and are priced cheaply, with low profitability margins (EBIT) of 0 to 2%. Low customer engagement means that many customers roll onto a retention product when the year is up and tend stay there. The ‘retention’ product, or SVT, has higher prices with typical EBIT margins of 6 to 8%.

Success in a 2-tier world requires a large proportion of disengaged customers who are on the most expensive tariffs. The ‘Big 6’ have an incumbent advantage from retaining customers from the days of pre-privatisation. British Gas has 74% of customers on the expensive tariff, compared to new suppliers, like Ovo Energy, which only has 35% of customers on the expensive tariff.[3]

Analytics is then key to keeping high value customers by pricing the tiered tariffs correctly in the first place according to customer lifetime models and then monitoring customers through predictive churn modelling.

Bespoke tariffs

Expect a rapid expansion towards hundreds of tariffs from the limit to four that the UK experienced over the past five years. The removal of Ofgem’s four tariff rule and the arrival of smart meters will enable suppliers to tailor a bespoke tariff to an individual’s preferences and consumption patterns – thus, creating a differentiated offering at very low cost.

Bespoke tariffs make it difficult for consumers to compare tariffs between suppliers, which may enable suppliers to charge profit margins which are more in line with SVT tariffs. In return, consumers receive more choice and a more suitable product for their needs.

Success with bespoke pricing requires seamless and insightful IT software. Smart meters will increase relevant customer data by several orders of magnitude from today’s analogue world. Retailers must be able to turn this mass of information into insights, then, in real time, accurately select and price tariffs based on how a single customer consumes energy.

Smart products and services

This strategy requires an active consumer who engages with the next wave of retail energy technology. All of the Big 6 and a number of Independents have their own smart thermostat product (e.g. Hive – British Gas, Nest – nPower, Touch – EON, Tado – SSE, Connect – Scottish Power). This is the start of the connected home which moves beyond the smart thermostat to an integrated system.

The uptake on products has been slow to date with Centrica having only sold a total of 360k products which represents 3% of its customer households.[4] This will increase rapidly with the next generation who value high quality, time saving technologies.

Bundling of products and services will become commonplace within the connected home. For example including energy within a home service package which could include broadband, phone, music, TV, security, and maintenance. This might also be priced in different ways, such as a monthly fee to deliver heating to a 21 degree specification rather than billing on a per unit of energy basis.

The smart technology wave also enables ‘prosumer’ activity. Increasing use of solar panels, battery storage (fixed and electric vehicle) and demand side response means that consumers generate electricity as well as consuming it. This provides an opportunity for energy suppliers to provide adjacent goods and corresponding tariffs which match to the installed technologies within each home.

Successful adoption of smart products requires high quality branding and functionality which is easy to use. Energy suppliers are not consumer goods companies. They are not used to creating sleek and simple products such as Apple or Amazon. The opportunity for suppliers is that they are already in millions of homes today. This access must be leveraged, but success requires either in-house creation of products to match the standard of Apple or Amazon, or partnering with firms that can.

Single price

This domain is low margin, where suppliers engage in a price shoot out for the supply of electricity or gas (i.e. no differentiation in product or service) for highly engaged consumers. The transition towards engagement could be caused by:

• automated rather than manual switching (e.g. a new service called Flipper, which automatically switches a customer’s tariff four times a year to the lowest cost option for a fee of £25 per year); or
• third parties removing energy suppliers from direct contact with the customer and instead requiring energy in bulk volumes (e.g. an energy supplier providing energy on behalf of Amazon which bundles home services into a single package)

In a single price competitive market, the lowest price wins. Therefore, suppliers with relatively low indirect costs can offer lower prices than competitors and will succeed in such an environment. Another important competency in this domain is risk management. The ability to understand and manage the risks within an energy supply contract is technical and thus, a potentially higher value-add activity. If energy suppliers get removed from domestic customers, those with strong risk management offerings will succeed.

2. Which strategy area will be most important in the future?

The majority of homes will have smart products and services within the next 10 years because the millennial generation embraces new technology and technology cost will fall. The challenge for energy suppliers is to remain relevant in this new world market and maintain contact with the end consumer. If they fail, then there is a high likelihood of energy suppliers being removed from people’s homes and transitioning to the single price domain and supplying energy through a third party.

The most profitable pathway in the short run for energy suppliers is likely to be through bespoke tariffs, while maintaining a 2-tier price for customers who remain less engaged customers. It is, however, imperative for energy suppliers to develop competence in multiple domains to spread their bets. The direct value in some areas may be low today, but the true value for energy suppliers is instead the increased likelihood of remaining relevant for the customer in future.

[1]        Ofgem website, ‘Standard variable’ rate tariff information.

[2]        Jefferies, UK Utilities: Increasingly Tough Out There, 22 Sep 2016

[3]        CMA Energy Market Investigation

[4]        GfK NOP customer survey report, 2015

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.