a crisis in uk energy policy looks inevitable

This document is a marketing communication and is not independent research prepared in accordance with legal requirements designed to promote the independence of investment research and is not subject to a prohibition on dealing ahead of the dissemination of investment research. For Reg-AC certification, see the end of the text. Liberum Capital does and seeks to do business with companies covered in this communication. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

30 April 2013 European Equity Research

A Crisis in UK Energy Policy Looks Inevitable We Identify the Possible Triggers UK | UTILITIES | SSE.L | SSE LN | CNA.L | CNA LN | DRX.L | DRX LN | NG.L | NG/ LN

When the crisis hits there will be three possible casualties, the government of the day, the consumer, and

the investors who have funded the government’s radical energy policy. Whilst no doubt there will be plenty

of pain to go around, in our view investors should be under no illusions that the government of the day will

seek to protect itself and the consumer (who are also the electorate) by heaping most of the financial pain

on to investors.

UK Energy Policy is not Plausible: in our view successive UK governments have grossly underestimated the

engineering, financial, and economic challenges posed by the drive to decarbonise the electricity sector by

2030. Moving from a largely fossil fuel based power system to one dominated by renewables and nuclear in just

a decade and a half, whilst keeping the lights on and consumer bills affordable, may simply be impossible.

Policy Cost: we estimate that the total required investment to deliver policy goals is £161bn from now to 2020

and up to £376bn by 2030. Even with the large increase in public support provided by the Energy Bill it is

extremely hard to envisage that this finance will be forthcoming given that the large European Utility companies

are actually reducing capex. If the investment does take place we see electricity bills rising by at least 30% by

2020 and 100% by 2030 in real terms.

Economic Rationale Looks Weak: the fundamental economic argument for the EU’s energy policy is that

fossil fuels are scarce, and will therefore become ever more expensive. The belief is that those that move first

away from fossil fuels will gain a substantial competitive advantage. But the arrival of unconventional gas and oil

makes this assumption look shaky at best. Without clear economic benefits it is not at all certain that the public

will be willing to bear the costs. Without public support the policy is bound to fail at some point.

Re-nationalisation: the decarbonisation agenda has required the government to intervene in the energy market

in ever more aggressive ways. The Energy Bill takes this to a new level and effectively re-nationalises the

investment-making decision process in the power sector. But it is not clear that policy makers yet appreciate

that this also means that the risks and costs associated with these decisions must also transfer to the public.

Probable Triggers for the Crisis: we identify a number of possible triggers; a generation capacity crunch in the

2014-17 period leading to a sharp spike in power prices, a lack of dispatchable generation by the end of this

decade onwards, and spiralling consumer costs / developer profits that a future government will find untenable.

Utility Companies & Investors Should Limit Exposure: political risk looks certain to rise sharply in the UK

energy space in the coming years as the implausibility and contradictory nature of policy is exposed by events.

We welcome recent moves by both Centrica and SSE to take a more cautious approach to allocating capital to

UK renewables. UK utility stocks have benefited in recent years by being viewed as having relatively low

political risk, this may well change in coming years. Most exposed will be Drax, SSE and Centrica.

Peter Atherton +44 (0)20 3100 2088 [email protected]

Guillaume Redgwell +44 (0)20 3100 2195 [email protected]

30 April 2013 A Crisis in UK Energy Policy Looks Inevitable

2 www.liberumcapital.com

Contents Summary Conclusions 3

A Crisis in UK Energy Policy Looks Increasingly Inevitable 3

UK Energy Policy – Not Plausible 3

EU & UK Energy Policy 6

UK Gold Plates Policy 6

The Energy Bill 6

Renationalisation of the Power Sector? Very Nearly 7

Policy Survives Unchanged in a Changed World 8

Economic Rationale for UK Energy Policy Looks Weak 8

Is the UK Playing Russian Roulette? 10

And Guess Who Gets Shot? 11

Utility Companies and Investors Need to Limit Exposure 11

Potential Crisis Trigger 1: Near Term Security of Supply & Price Spike Threat11

The Recent Position – Ample Capacity 12

2014-16 Period – Gas Closures are the Concern 12

Quality of Reserve Margin Declines 13

Price Spike More Likely than ‘Lights Out’ 14

Potential Crisis Trigger 2: Security of Supply Threat in the 2020’s 14

What is the Plan? 14

What Does the Plan Mean in Practice? 15

New Generation Additions Mix 17

Lack of Dispatchable Generation 19

Potential Crisis Trigger 3: The Cost 21

Capital Costs 2012-2030 21

Impact on Consumer Bills – The Levy Framework 23

Capacity Payments 24

Total Capacity Payment Costs 25

Impact on Bills 25

Energy Efficiency 26

Bills and Profits Rise 27

Conclusions 28


www.liberumcapital.com 3

Summary Conclusions In this note we conclude that:

1) EU policy makers have grossly underestimated the difficulties and risks of their

drive to decarbonise the power sector.

2) EU policy makers have failed to take into account the huge changes in the

economic, commodity and financial environments and adjust policy accordingly.

3) The economic arguments supporting the current climate change dominated

energy policy look weak and public support is uncertain.

4) Given the hostile rhetoric that utility companies face today from across the

political spectrum on bills and profits, it takes quite a leap of faith to believe that

future governments will steadfastly defend the huge bill and profit increases that

will inevitably result from current policy.

5) Political risk is bound to rise sharply in the UK energy space in the coming years

as the inherent implausibility and contradictory nature of the policy goals are

exposed by events.

6) A crisis in UK energy policy looks increasingly likely and therefore utility

companies and investors would be prudent in limiting their future exposure.

A Crisis in UK Energy Policy Looks Increasingly Inevitable The UK looks increasingly certain to be heading for a crisis in its energy policy in our

view. The crisis is likely to come to a head via either:

1) a huge spike in wholesale prices as the power market anticipates a short term

shortage of physical capacity; or

2) a longer term shortage of dispatchable generation capacity that puts security of

supply at serious risk, or

3) through spiralling consumer costs that will inevitably force a future government

to renege on its policy commitments; or

4) sharply rising profit levels reported by developers coinciding with rising

consumer bills which become politically unacceptable to the government of the

day.

There is a high probability in our view that several of these catalysts could combine

together to create a ‘perfect storm’ of a crisis within the next decade. If this happens

then there will be three casualties in the crisis – the government of the day, the

consumer, and those investors who have thus far funded the policy. Whilst there is

likely to be plenty of pain to go around, the experience in continental Europe in

recent years has shown that the government of the day is likely to try and protect

itself and consumers by heaping the bulk of the financial pain onto investors.

UK Energy Policy – Not Plausible In our view successive UK governments have grossly underestimated the

engineering, financial, and economic challenges posed by the drive to de-carbonise



the electricity sector by 2030. Far too much is being asked of the power sector,

which is taking on the burden of climate change policy for the whole economy.

Furthermore the government has largely failed to take account of the lessons from

other EU countries that are further advanced in implementing the policy than the UK.

UK policy requires the power sector to migrate from a largely fossil fuel based

system to one that is overwhelmingly based upon renewable and nuclear capacity

by the end of the next decade – i.e. within the next 17 years. What’s more the

government has an interim target of providing circa 35% of electricity from

renewable sources (up from around 10% now) by 2020 – a mere 7 years away. This

would be one of the biggest industrial transformations in British history.

Delivering government plans would be hugely challenging even:

if renewable technologies were easy to deploy at the utility scale – which they are

not;

if renewable technologies were economic to deploy – which they are not;

if new nuclear stations could be built quickly and economically – which they can

not;

if the public were willing to pay any price in their bills to fund this policy – which

they are not;

if the utilities companies were in the financial position to fund the transformation –

which they are not;

if the capital markets had the capacity and were willing to fund the policy – which

at the moment they are not.

Scale of the Task Figure 1 below illustrates the tremendous challenge that just hitting the 2020

renewables target poses. In 2012 total renewable output was circa 39TWh, but

needs to rise to around 115TWh by 2020. The conversion of 3x600MW units at Drax

over the period to 2016 to run on biomass should add around 15TWh. But beyond

that it will take a spectacular build out of offshore wind in the 2016-2020 period to hit

the target.



Figure 1: Required Renewable Power Build Out to 2020 (TWh)

0

20

40

60

80

100

120

140

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Drax biomass

Off-shore wind

Source: Liberum Capital estimates

In Figure 2 we show how the generation mix will have to evolve from now to 2020

and then to 2030 to satisfy the decarbonisation policy. As can be seen, coal fired

generation is expected to provide circa 140TWh of output from a total of around

330TWh in the current year. But this needs to fall sharply to less than 60TWh by

2020 and then to zero by 2030. Unabated gas fired output will also need to fall

dramatically from circa 130TWh in 2013 to probably no more than 50TWh in 2030.

Something like 220TWh in dispatchable coal / gas output will need to be replaced

over the next 17 years. Replacing this generation requires a gigantic expansion in

both offshore wind and nuclear output even if Carbon Capture and Storage (CCS)

becomes commercially available in the timeframe (which looks highly unlikely).

Figure 2: Generation by Fuel Type (TWh)

0

20

40

60

80

100

120

140

160

Off-shorewind

Onshore wind Nuclear Gas Coal BiomassConversion

Hydro Gas CCSNew

CCS Retro-fit

TWh

2013 2020 2030




EU & UK Energy Policy All modern governments face three, sometimes contradictory, drivers on their

energy policy:

1) Combat climate change

2) Ensure affordable and competitively priced energy for households and business

3) Ensure security of supply.

But the EU uniquely amongst the world’s economic powers has committed itself to

an energy policy that overwhelmingly emphases the first objective, combating

climate change. In a 2003 Directive the EU committed member states to reduce

average greenhouse gas emissions by 20% from the 1990 benchmark by 2020.

Member governments also endorsed the objective of achieving reductions of up to

80% by 2050.

The EU followed this up with an agreement in 2006 to deliver the 2020 target largely

through the deployment of large scale renewable energy programs. Thus was born

the target to have 20% of energy (electricity, household, and transport) produced

from defined renewable energy technologies by 2020.

These climate change targets have been the primary driver on EU energy policy

ever since. At the time these policies were designed and adopted little if any account

was taken of the other two objectives, affordability and security of supply. But across

Europe governments are finding, not surprisingly, that the cost to the consumer does

indeed matter a great deal and that security of supply is economically essential.

UK Gold Plates Policy Just in case implementing the EU’s policy targets was not challenging enough the

UK decided to gold plate the targets and to tie its own hands on how they might be

met. The 2008 Climate Change Act was passed with overwhelming cross party

support and put the 2020 and 2030 targets into UK law. It set up an institutional

framework that was designed to ensure future governments would have minimal

flexibility to rebalance energy policy back towards affordability and security of

supply.

The Energy Bill The Energy Bill came out of the current government’s electricity market reform

(EMR) process. EMR was begun in 2010 when the new coalition government

decided that the existing market arrangements and intervention mechanisms were

not bringing forward that level of investment at the speed that was required to meet

the EU emission targets. In conducting this review the new government had the

opportunity to either change or at least slow down the de-carbonisation agenda.

However, the government in fact choose to redouble its effort to deliver the policy

targets with further substantial interventions into the UK energy market. EMR had

four elements;

1) Carbon price floor: this has been introduced via the Finance Act and sets out a

path for a minimum carbon price in the UK from fiscal 2013/14 from £16 per

tonne to £30 (2009 money) by 2020.



2) New renewable and nuclear subsidy mechanism: the government will

replace the existing regime with a Contract for Difference (Cfd) mechanism. This

new mechanism will very largely transfer the price risk from the developer to the

consumer by guaranteeing an achieved power sale price for each power station

covered. Unlike the existing Renewable Obligation the new Cfd mechanism will

also provide subsidy support to the development of new nuclear.

3) Capacity market: the government will create a capacity market that will seek to

ensure the retention of sufficient existing generation capacity and the building of

new capacity. The design of the capacity market is still ongoing so the exact

nature of the market is still unclear. However, it is known that the plan is to hold

the first capacity auction in 2014 for delivery in 2018.

4) Emission performance standards (EPS): this has already been introduced

and sets the maximum emission levels for each generation technology.

The Energy Bill has cross party support and is likely to become law by the end of

2013. The only area of substantive debate in parliament over the Bill is whether or

not to require the government to set a mandatory carbon intensity target for

electricity generation. The current carbon intensity is circa 500g of CO2 per kWh and

the suggestion is to set a legally binding target of between 50g to 100g per kWh to

be achieved by 2030. The government has so far resisted this call, saying that it

would prefer to wait until 2016 to decide on setting a specific legally binding target

for 2030 or continue to rely upon the Carbon Budget process (that was established

in the 2008 Climate Change Act), that in fact has already set a legally binding

pathway towards the 50g total.

Renationalisation of the Power Sector? Very Nearly To deliver its policy goals the government requires utility companies (and third party

investors) to build assets that are fundamentally not economic, often in technologies

that are still far from robust or mature. The government has taken upon itself the

responsibly of deciding which generation technologies are bad (coal, unabated gas)

and good (wind, hydro, biomass, nuclear). It has also decided the pace of change,

that coal should be very largely removed form the power matrix by 2024 and that

unabated gas should operate only at peak from 2027. The government has even

decided what future technologies should or should not be developed and adopted,

for example placing much faith in the wholly unproven Carbon Capture and Storage

(CCS).

The Energy Bill will take government intervention up yet another level. Under the

powers granted by the Energy Bill, the Department of Energy and Climate Change

(DECC) will allocate Contracts for Differences (Cfd’s) to developers in those

technologies and at those locations that DECC favours. DECC will set the strike

price and so determine the revenue of the asset, what the consumer pays and the

returns on investment. DECC will issue enough Cfd’s to meet the EU’s targets but

within an annual subsidy budget (known as the Levy Framework) imposed by the

Treasury. Via the proposed capacity payment mechanism DECC will also decide

how much reserve capacity is required to back up renewable power and by

implication the revenue and returns for much of the legacy fossil fuel fleet.

All this amounts to the effective renationalisation of the investment decision process

in the power sector. It is now the government, not private companies, who will



decide what power stations get built, when, where, and using what technology. The

role of the power companies is reduced to acting as a facilitator for DECC decisions.

It is arguable that even when the industry was state owned prior to 1990 that central

government had considerably less control than envisaged by the Energy Bill. But

what is clear is that going forward it is inconceivable that any utility will build a new

power station using any technology unless the economics are formally underpinned

by the tax payer / consumer. In taking charge of the investment making process the

government has to accept that the costs and risks of these decisions will also fall on

to the state. It is not clear that policy makers have fully understood the implication of

this.

Policy Survives Unchanged in a Changed World Quite a lot has happened since 2003 when the EU adopted its climate change

driven energy policy. To name but a few;

the financial crash, global recession, and Euro crisis;

the massive contraction in the value of European utility share prices;

the near wipe out of the European listed renewable power sector;

the Fukashima accident and its impact on German energy policy in particular;

the US energy revolution;

the failure to agree new internationally binding carbon reduction targets;

increased public concern over climate science following the ‘climategate’ email

leaks and the acknowledged standstill in global temperatures since 1997;

the fact that renewable energy technologies have proven much harder and more

expensive to deploy at the utility scale than originally thought;

the continued use of coal as the primary source of power generation in the

fastest growing economies, especially China and India.

It might have been expected that any one of the above events would have provoked

a policy re-think. But the remarkable thing is that the EU, and the UK, has not

deviated at all from the climate change dominated energy policy strategy since it

was adopted in 2003. Politicians of all parties appear determined to press on placing

the achievement of climate change goals ahead of energy affordability, economic

competitiveness, and security of supply. But unless the policy makers can sign the

public up to this strategy there is considerable risk that its inherent contradictions will

fatally undermine it over time.

Economic Rationale for UK Energy Policy Looks Weak In recent years UK policy makers have tended to emphasise the economic benefits

of current energy policy rather than rely upon the climate change rationale. This

perhaps reflects the shift in public attitudes shown in many opinion polls that show

that public concern over global warming has waned.

The economic argument behind the current energy policy is two fold. First, the claim

is that fossil fuels are scarce and will become scarcer going forward. Therefore the



cost of oil, gas, and coal on the international markets can be expected to rise

inexorably in the coming decades. By largely eliminating fossil fuels from the UK’s

power sector the country will protect itself the inevitable sky high fossil fuel prices.

There are a couple of problems with this argument:

US Energy Revolution: the development of non conventional gas and oil

exploration in the US has destroyed the notion that the world has hit peak oil /

peak gas. Looking at the 2020’s energy picture it is now just as possible that

fossil fuel prices are no higher (and possibly lower) than they are today.

Substantially rising prices are still a possibility but in no way is it certain.

Cost / Benefit of Being Right or Wrong: UK energy policy is effectively a

massive long position on the oil price i.e. if the world does indeed face sky high

oil prices in coming years then the policy will be seen to have worked. But even

if this bet proves correct will we see much benefit? The answer is probably not

unless the rest of the world follows the UK’s lead. The reason is that a future oil

price shock would hit the world economy and be transmitted into the UK via

trade. The trade effect is likely to overwhelm any benefits gained from the UK

power sector being ex-fossil fuel.

Whereas the cost of getting this bet wrong could be economic disaster, if the

UK’s major trade competitors retain a largely fossil fuel based power system. If

fossil fuel prices remain at current levels (or lower) in real terms then by locking

itself into a vastly more expensive power system the UK risks stranding its

economy with a wholly uneconomic cost base.

The second economic argument usually put forward for the current policy is closely

linked to the first. Namely, that by being in the vanguard of the fight against climate

change the UK will develop an industrial capacity that can be exploited for export

once the rest of the world recognises the fact of sky high fossil fuel prices and

belatedly follows the UK in decarbonising their power sector. Leaving aside for a

moment whether or not Europe’s industrial base (never mind the UK) is in fact

benefiting for the €30bn current annual subsidy being paid each year by energy

consumers, the fact is that unless fossil fuel prices do rise substantially year after

year it is pretty unlikely that the rest of the world will follow the EU and UK to

radically decarbonise its power sector within the same timeframes.



Figure 3: European Renewable Energy Manufacturing Index

0

500

1,000

1,500

2,000

2,500

3,000

Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13

58bn Euro peak market cap

Source: Bloomberg

Figure 3 above shows the index of listed renewable energy manufacturing

companies in Europe. The sector boomed after 2005 when the renewable targets

were set and the flood gates of subsidy were opened. But as can be seen the

market value of the sector has crashed and is now below its 2005 position. Demand

for renewable assets in Europe has faltered as some EU countries reduced support

mechanisms, overseas markets have failed to materialise as expected, and Asian

(especially Chinese) manufacturers have aggressively entered the market, often

brutally under-cutting EU suppliers. Virtually the entire German solar manufacturing

base has been wiped out by this competition. Vestas, the EU’s leading wind turbine

manufacturer has seen its share price crumble from a high of over 700 Krona to only

circa 46 Krona today. From this it is hard to discern that EU citizens are getting

much of a benefit from reviving their industrial base with the €30bn per annum

subsidy that renewables are costing.

Is the UK Playing Russian Roulette? It is not clear that UK policy makers comprehend the risks and possible

consequences of the current path they are on. Its like they are playing Russian

roulette with a gun loaded with three bullets;

1) A security of supply crisis in the 2014-17 period as coal and gas plant close with

little dispatchable generation being built.

2) A security of supply crisis post 2020 as the rest of the coal fleet is forced to

close, more of the older gas plant also closes, and the existing nuclear fleet

winds down.

3) An affordability crisis caused by surging consumer bills which would be triggered

by either a security of supply crisis (see above) or indeed by the government’s

radical de-carbonisation of the power sector being a success.



And Guess Who Gets Shot? When the crisis hits there will be three possible casualties in the firing line; the

government of the day, the consumer, and the investors who have funded the

government’s radical energy policy. Whilst no doubt there will be plenty of pain to go

around, investors should be under no illusions in our view that the government of the

day will seek to protect itself and the consumer (who are also the electorate) by

heaping most of the financial pain on to investors. The experience from across

continental Europe in the past three to four years shows clearly that investors simply

cannot rely upon government promises to protect their returns when the crisis hits.

Utility Companies and Investors Need to Limit Exposure The complacency of policy makers should not be matched by utility companies and

investors in our view. Political risk is bound to rise sharply in the UK energy space in

the coming years as the inherent implausibility and contradictory nature of the policy

goals are exposed by events. Companies and investors should be wary in our view

of committing further capital in support of UK energy policy goals, with the partial

exception of regulated network investment.

There are signs that utility companies are beginning to adjust their investment

intentions in anticipation of the higher risk. Both Centrica and SSE have signalled a

more cautious approach to investing in UK renewables. For example Centrica has

stated that it will restrict its possible investment in the £2bn Race Bank offshore wind

farm to only £200m and that it expects to focus its growth investment in North

America from now on. SSE has stated that its investment in renewables will run at a

rate of around £300m pa to 2015 compared to a run rate of circa £800m pa from

2009 to 2012. SSE has shifted its capex program back towards regulated networks

and away from power stations.

Foreign owned utilities and other potential investors should exercise caution in our

view when considering entry or expansion in the UK market. Apparently attractive

returns could soon evaporate when a crisis hits. The UK market could easily

become as hostile to investors in this space as Spain and Germany (amongst

others) have been in recent years.

If political risk does indeed rise sharply in the UK in coming years, especially if it is

due to a security of supply scare and / or a price spike, we would expect the political

heat to centre upon the so called big six – Centrica, SSE, E.ON, RWE (npower),

EDF Energy, and Iberdrola (ScottishPower) vertically integrated players. There is a

real risk that the government of the day could be tempted to directly intervene on

prices and / profits. We would expect network investment to be protected due to

UK’s system of independent regulation.

Potential Crisis Trigger 1: Near Term Security of Supply & Price Spike Threat The cold winter of 2012/13 has focused attention to security of supply, with Ofgem

and SSE both expressing the fear that tightening reserve margins over the next

couple of years could put the UK at risk of ‘the lights going out’.



The Recent Position – Ample Capacity Currently the UK actually enjoys an over supply of generation. At the start of 2013

total capacity on the system was circa 88GW against an expected peak demand of

some 58GW. This give a reserve margin of close to 50% compared to an average

over the past 20 years of around 25%. The reason for this exceptionally high reserve

margin is twofold. First, 7GW of new gas fired power plant has commissioned in the

last couple of years, this plant was built to replace the 12GW of old coal and oil plant

due to shut under the Large Combustion Plant Directive (LCDP). But as the new gas

plant was commissioning in 2011 and 2012 the price of coal / carbon fell relative to

gas giving a new lease of life to the older coal plant keeping them on the system

until very recently. Second, we have seen a steady build out of renewable power

with some 4GW added over the last couple of years.

Figure 4: UK Reserve Margins (%)

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

1990

/91

1991

/92

1992

/93

1993

/94

1994

/95

1995

/96

1996

/97

1997

/98

1998

/99

1999

/00

2000

/01

2001

/02

2002

/03

2003

/04

2004

/05

2005

/06

2006

/07

2007

/08

2008

/09

2009

/10

2010

/11

Source: National Grid, Liberum Capital estimates

The relative over capacity has manifested itself through very low spark spreads.

With coal operating firmly in the mid part of the merit order, gas has been pushed to

peak load. This means that a lot of gas fired capacity is competing for relatively little

volume – hence the low spark spreads.

2014-16 Period – Gas Closures are the Concern Power companies have announced that around 7.5GW of the 12GW of oil / coal

plant that was opted out of the LCPD will close ahead of next winter. The remaining

4.5GW of the LCPD is likely to shut after next winter.

However as mentioned above, 7GW of new gas plant has just commissioned

together with several GW of renewables. Therefore the system should easily be able

to absorb the LCPD closures. However, the unexpected risk to security of supply

comes from gas plant. The incredibly low spark spreads of the last year or so has

probably rendered all gas fired power plant in the UK loss making.

Older CCGTs with low thermal efficiency rates will be severely loss making at

current spreads. The concern is that 10GW of the largest gas plant on the system

will be 20 years or older by 2016 with a further 7GW 15 years or older. CCGT plant

built in the 1990’s had a typical design life of 20 years. The life of this plant can be

extended but this usually requires substantial investment. For example SSE recently



spent £100m to refurbish its Keadby power station that had been commissioned in

1996.

Given current spark spreads it is inconceivable that any company would today

authorise a substantial investment in updating an old gas fired power plant. Indeed,

in March, SSE announced that it was to place the 735MW Keadby station into ‘deep

mothball’, meaning it would take around two years to bring the capacity back on line.

Centrica also closed two aging gas fired stations Kings Lynn (320MW) and

Roosecote (229MW) in 2012 due to market conditions.

When it announced the mothballing of Keadby, SSE called for the government to

bring forward the implementation of the proposed capacity market from 2018 to

2014, so that existing gas plant could receive support in order to keep them on the

system. The government has rejected this call so far. The danger for security of

supply is that other generators now follow SSE’s lead and take out more gas fired

capacity.

Quality of Reserve Margin Declines If we assume that all of the remaining LCPD plant closes in 2014 and we also see

5GW of additional gas fired power stations closed or mothballed, that would leave

around 73GW of capacity on the system to meet a peak demand that is unlikely to

be greater than say 58GW. This is still an apparently healthy reserve margin of over

20%. However, by the end of 2015, 8GW to 9GW of the capacity will be provided by

wind turbines and 3GW via the interconnectors. Wind and the interconnectors are

not ‘firm capacity’ in the sense that National Grid can dispatch the plant whenever

required.

In this possible scenario dispatchable generation could be as low as 60-63GW by

the winter of 2015/16. This would be uncomfortably low. On December 12 last winter

National Grid had to call upon all available generation capacity to meet demand. At

least 5GW of that capacity will not be on line next winter and anywhere between 7-

15GW won’t be available by winter 2015/16. Figure 5 shows how dispatchable

generation as a percentage of peak demand could evolve over the new few years.

Figure 5: Dispatchable Generation as % of Estimated Peak Demand

50%

60%

70%

80%

90%

100%

110%

120%

130%

140%

150%

2012 2013 2014 2015 2016 2017 2018


The UK government hopes and expects that this tight(ish) reserve margin will prove

to be temporary. The Energy Bill should receive Royal Assent by the end of

2013.The first Cfd’s should be awarded by the end of 2014. If government plans are



to be met then anywhere between 20-30GW of new renewable and gas fired

capacity will need to be added to the system from 2015-2020. That means around

5GW a year of new gas and offshore wind should be commissioning each year.

Price Spike More Likely than ‘Lights Out’ Despite the potentially tight reserve margins from winter 2014 onwards in our view

the risk of actual disruptions to supply is low. National Grid has considerable powers

to manage short term supply constraints and to maximise the use of available power

capacity. Mothballed plant can be brought back on, albeit with a delay, and there is

some scope for a limited demand response.

Nuclear Reliability is the Wild Card However, this can not be guaranteed and the real wild card is the reliability of the

existing nuclear power fleet. The seven (8.2GW) AGR nuclear power stations are

entering very late middle age and have had a troubled reliability record. If during the

winters of 2014-16 two or more of the AGR’s suffer an extended forced outage, then

the capacity crunch could become a physical reality. The point being that the system

is likely to be sufficiently tight so that an additional unexpected event like to loss of a

nuclear station could trigger a security of supply event.

Prices will Rise Ahead of the Lights Going Out But the real danger in our view is that the power market may get concerned about

security of supply and start to price in a material risk premium into the forward

prices. This is what happened in the gas market in the mid 2000’s when the decline

of the North Sea output exceeded expectations before new import capacity was

commissioned. We saw winter gas prices spike up over 50% until the concerns were

eased when the new pipeline to Norway and two LNG terminals were completed.

A similar move on power prices could easily push winter season wholesale prices up

to the £70 to £80/MWh range compared top £53/MWh today. Such a move would

likely increase retail electricity prices up by some 15%-25%. Current average retail

electricity bills are currently around £550 pa so such a rise would push prices up to

£690 pa.

Potential Crisis Trigger 2: Security of Supply Threat in the 2020’s

What is the Plan? The push to de-carbonise the power sector is scheduled to accelerate as we move

into the 2020’s. To meet the target of a 60% reduction in emissions versus the 1990

baseline the government’s official advisory body the Committee on Climate Change

(CCC) states that the carbon intensity of electricity generation needs to be reduced

from over 500g per kWh to close to 50g. The reason why a reduction of this scale is

necessary is that the plan requires a substantial electrification of transport and

heating by the end of the 2020’s. If this is to take place and reduce the UK’s

emissions by the required 60% then electricity has to be substantially carbon free by

2030.

Although the government has not yet set the 50g per kWh figure as a legally binding

target, it has formally adopted the Fourth Carbon Budget that sets out the pathway



for decarbonising the sector through to 2027 with the 50g target embedded into the

assumptions.

The Fourth Carbon Budget states: “To meet the indicative 2030 target … it is

essential to radically decarbonise power generation, cutting emissions

intensity from today’s level of around 500gCO2/kWh to around 50gCO2/kWh in

2030. This will require the addition of up to 40GW of (baseload equivalent) low

carbon plant during the 2020’s on top of the 30GW needed over the decade 2010-2020.”1

What Does the Plan Mean in Practice? The CCC sets out a series of possible demand and generation scenarios that would

achieve the 50g target by 2030. National Grid in its ‘UK Future Energy Scenarios –

September 2012’ also examines what the power generation mix would need to look

like to get down to around 50g carbon intensity.

Demand in 2030 The CCC forecasts that overall electricity demand will stay fairly flat through most of

this decade at circa 350TWh as the impact of economic growth pushing up demand

is largely off-set by greater energy efficiency. However, from the latter part of this

decade through to the 2020’s demand should pick up sharply as the impact of the

electrification of transport and heating kicks in. The CCC estimates that 43TWh of

transport load and 51TWh’s of heating will be added to the electricity system by

2030. Therefore the CCC estimates that demand will be around 460TWh in 2030.

We think this figure looks on the low side if such a large amount of load is moved

from transport and heating to electricity, but we will use that figure in the following

analysis.

1 4th Carbon Budget page 33



Figure 6: Electricity Demand Forecasts (TWh)

250

300

350

400

450

500

2012 2020 2030

Source: CCC Fourth Carbon Budget; Liberum Capital estimates

Generation Plant Closures 2020-30 The CCC in the 4th Carbon Budget (page 244) estimates that some 28GW of

existing power plants will be retired in the 2020’s. A combination of the ever growing

carbon price and the Industrial Emissions Directive (IED) is likely to kill off the

remaining coal fired power plant by the mid-2020’s at the latest – see Figure 7.

Some coal plant can be expected to convert to biomass burn and if Carbon Capture

and Storage (CCS) can be commercialised by the early 2020’s (highly unlikely in our

view), then one or two coal stations might be preserved if they have CCS retrofitted.

Figure 7: UK Carbon Price Pathway (£ per Tonne)

0

20

40

60

80

100

120

140

160

Jul-12 Jul-14 Jul-16 Jul-18 Jul-20 Jul-22 Jul-24 Jul-26 Jul-28 Jul-30




New Generation Additions Mix The precise mix of new generation capacity that needs to be built to hit the 50g

target depends on a number of factors. The most important being, first whether or

not CCS can be made commercially viable in the timescale, and how many new

nuclear reactors can be built? The fewer CCS and nuclear plants, the more reliance

will need to be placed on off shore wind.

Liberum 50g Carbon Intensity Generation Scenario Hitting the 50g carbon intensity target will require a remarkable amount of new build

in the 2020’s. The exact mix of plant depends on the assumptions discussed above.

We have modelled the generation mix to bring the carbon intensity down to 50g per

kWh by 2030, our assumptions are similar to those used by the CCC and National

Grid to achieve the same target;

1) Demand will be 460TWh;

2) CCS will be commercially available but is deployed only on a limited number of

existing gas fired power stations;

3) All coal plants are closed by 2025;

4) 32GW of existing plant closes in the 2020’s;

5) A large new nuclear program is undertaken.

Figure 8: Generation Plant Additions & Closures Total (MW)

-40,000

-20,000

0

20,000

40,000

60,000

80,000

Closures Newbuild


Figure 8 shows our assumption of the total plant closures and additions that would

be required in the 2020’s to hit the 50g per kWh benchmark. In our scenario circa

32,000MW of existing plant comes off line, including the remaining 16,000MW of

coal plant, 9,500MW of aging gas plant and all of the AGR nuclear reactors. To

replace the closures, and provide the additional generation capacity to still meet the

460TWh’s of demand, circa 60,000MW of new capacity would need to be added to

the system during the decade.



Figure 9: Generation Capacity Additions & Closures by Type 2020-30 (MW)

-20,000

-15,000

-10,000

-5,000

0

5,000

10,000

15,000

20,000

Off-shore wind On-shore wind Hydro Nuclear Coal Gas CCS Retro CCS New

Closures Newbuild


Figure 9 shows the additions and closures by plant type. As can be seen in this

scenario we add a fairly staggering 18,000MW of new nuclear in the period – the

equivalent of 11 new EPR reactors. If such a large nuclear program proves

undeliverable (highly likely) then more offshore wind would need to be built. For

every 1GW of nuclear not built, 2.5GW of offshore wind would need to be built to

give the same output and some additional capacity (probably gas) would be needed

to provide back up.

Figure 10: Generation Capacity 2030 – 50g Intensity (MW)

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2013 2014 2015 20 16 2017 2018 20 19 2020 2021 2022 2023 2024 20 25 2026 2027 20 28 2029 2030

MW

Off-shore wind On-shore wind Nucle ar Coal Gas Oil Coa l to Biomass Inte rco nnectors CCS Other


Figure 10 shows the total capacity that would be on the system in 2030. As can be

seen, we would end up with a system with around 130GW of capacity. There is still

a large amount of unabated gas plant on the system (34GW) compared to the circa



33GW today. However, to get to the 50g target unabated gas would only operate at

peak or as backup, and we envisage an annual load factor of only 15%. As

mentioned, all coal would be eliminated by 2025.

Market share by output is shown in Figure 11 & Figure 12. As can be seen the

market share of nuclear would increase from 16% today to some 34%. Offshore

wind would increase from negligible to 30% and on-shore wind would rise to 7%.

Low carbon generation (nuclear, wind, biomass, hydro, and CCS) would have a 90%

market share in 2030 up from around 22% today.

Figure 11: Generation Market Share 2013

Figure 12: Generation Market Share 2030

Biomass Conversion

1% Nuclear16%

Onshore wind3%

Off-shore wind2%

Gas37%

Coal40%

Hydro1%

Off-shore wind30%

Onshore wind7%

Nuclear34%

Gas10%

Biomass Conversion

7%

Hydro1%

Gas CCS New11%



Lack of Dispatchable Generation In our 2030 scenario total capacity on the system would be circa 130GW. However,

only around 65GW would be fully dispatchable by the system operator. Figure 13

below shows the build up of dispatchable plant (coal, gas, oil, nuclear, CCS,

biomass) in dark shades and the non dispatchable capacity (wind, interconnectors,

biogas) in green shades. The horizontal line on Figure 13 is an estimate of peak

demand. As can be seen, currently there is circa 75GW of dispatchable generation

to meet peak demand on around 57GW. But under our scenario by 2023 peak

demand will exceed the amount of dispatchable generation on the system. Bear in

mind that in this generation scenario we expect the amount of unabated gas fired

generation to remain at around 33GW which is by no means guaranteed and will

certainly need substantial subsidy via a capacity payment mechanism or some other

facility.

Looking at our own generation scenario, and those that have been produced by

others, the common theme is that dispatchable generation falls dramatically as a

percentage of total capacity. Indeed it is hard to model a generation scenario that

meets the 50g target that does not see dispatchable generation falling dangerously

close to, or indeed below, the level of peak demand. Clearly the lower the

percentage of dispatchable generation relative to peak demand the greater the risk

of demand not being met.



Figure 13: Generation Capacity 2030 (MW)

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Nuclear Coal Gas Oil Coal to Biomass CCS Off-shore wind On-shore wind Interconnectors Other


Another way of looking at this problem is to look at the percentage of peak demand

than could be met by non-wind resources. Figure 14 below shows that currently over

140% of peak demand can be met from non wind generation sources. This would

fall to less than 120% in 2020 and to only 105% in 2030. Again, it stands to reason

that the lower the ratio of non wind to peak demand the greater the risk to security of

supply.

Figure 14: % of Peak Demand from Non-Wind Capacity

0%

20%

40%

60%

80%

100%

120%

140%

160%

2013 2020 2030




Potential Crisis Trigger 3: The Cost We need to look at the possible cost in two ways. First, the total cost in terms of

upfront capital costs and then the impact that those investments are likely to have on

consumer bills.

Capital Costs 2012-2030 The generation scenario set out in this note has a number of key assumptions:

1) 110TWh of renewable power is produced in 2020 to hit the government’s target;

2) the carbon intensity of power generation is reduced to circa 50g per kWh by

2030 via a balanced build out of renewables and nuclear, together with a

modest contribution from CCS;

3) a substantial amount of new gas fired capacity (20GW) will also need to be

added to the system to cover peak load and provide system back up.

We also need to take account of other areas of costs that government policy is

driving, such as investment in networks, roll out of smart meters, compliance costs

to meet the IED etc.

Figure 15: Capex Required to Meet Government Policy (£bn 2013 prices)

2012-20 2021-30 TotalOffshore wind 45.5 54.0 99.5Onshore wind 6.5 3.3 9.8Hydro 0.8 0.8 1.5Nuclear 15.0 39.1 54.0Gas 8.0 8.0 16.0Gas CCS New 0.0 14.0 14.0CCS Retro-fit 1.0 5.0 6.0Biomass Conversion 2.5 0.4 2.9Biomass New 0.0 0.0 0.0Smart Meters 12.0 2.0 14.0Elect Transmission 17.4 12.2 29.6Offshore Transmission 9.1 10.8 19.9Gas Transmission 3.6 4.3 7.9Elect Distribution 16.0 40.0 56.0On-shore Wind Connection 1.3 0.7 2.0Gas Distribution 2.0 4.0 6.0Gas Storage 2.0 5.0 7.0IED 4.0 2.0 6.0Energy Efficiency 14.0 10.0 24.0Total 160.6 215.4 376.0Source: Liberum Capital estimates

The first column of Figure 15 sets our estimates of the capital costs required to hit

the 2020 renewable target. As can be seen, we estimate that a further £56bn needs

to be invested in wind and some £8bn on new CCGT gas stations. We assume 4

new EPR reactors are under construction (but not completed) by the end of the

decade, and that some £12bn will be invested in rolling out smart meters. Total

capex required in the period to 2020 across all categories comes to some £161bn or

some £20bn for each of the eight years.

Looking to the period 2021-2030 total expenditure would in fact be even higher at

some £215bn, with the really large costs being for offshore wind (£54bn), nuclear

(£39bn) and electricity distribution (£40bn). This last cost reflects the likely costs of

the infrastructure required at the distribution level to handle the proposed mass roll



out of electric vehicles and distributed generation as the electrification of transport

and heating is undertaken.

Therefore total required capex across the 18 years to 2030 would be £376bn or

some £21bn per annum. It is worth noting that this is not the only capital expenditure

that investors in UK utilities asked being ask to fund as it doesn’t cover the water

sector. If we add in water capex, the total utility sector capex would add up to

£445bn from now to 2030 or some £25bn per annum.

How Much Would Be Spent Anyway? Of course some of this expenditure would be required to be spent anyway

regardless of government policy just to replace assets that were reaching the end of

their economic lives, and normal course investment. Figure 16 sets out our view of

what the capex requirements would look like if there were no specific

decarbonisation targets. We would expect some wind to still be built, albeit at a more

modest scale and over a timeframe to allow the technology to mature. The

replacement of the nuclear fleet would not begin until the 2020’s and gas would

replace those coal plants that close for economic / engineering reasons. We would

still expect smart meters to be rolled out but again on a less rushed timescale.

Figure 16: Required Capex Without Decarbonisation Target (£bn 2012 prices)

2012-20 2020-30 TotalOffshore wind 5.0 5.0 10.0Onshore wind 6.5 3.3 9.8Hydro 0.8 0.8 1.5Nuclear 0.0 7.8 7.8Gas 8.0 14.0 22.0Gas CCS New 0.0 0.0 0.0CCS Retro-fit 1.0 0.0 1.0Biomass Conversion 0.0 0.0 0.0Biomass New 0.0 0.0 0.0Smart Meters 4.0 3.0 7.0Elect Transmission 8.7 9.1 17.8Offshore Transmission 1.0 1.0 2.0Gas Transmission 3.6 4.3 7.9Elect Distribution 16.0 16.0 32.0On-shore Wind Connection 0.7 0.3 1.0Gas Distribution 2.0 4.0 6.0Gas Storage 3.0 4.0 7.0IED 4.0 2.0 6.0Energy Efficiency 7.0 5.0 12.0Total 71.2 79.6 150.8Source: Liberum Capital estimates

As can be seen total expenditure over the period to 2030 would still total a very

sizable £150bn or £8.3bn pa. Capex spend would remain at a steady pace through

the 2020’s. Adding in the water sector, utility investors would need to fund a total of

£230bn of capex by 2030. This is a very substantial sum but is more plausible in

terms of financing than the £445bn required under the scenario of meeting the 2030

targets (including investment in the water sector). Figure 17 below shows the total

capex requirements under both scenarios (excluding water sector capex).



Figure 17: Capex: Govt Policy vs. No Decarbonisation Target (£bn 2013 prices)

0

50

100

150

200

250

300

350

400

Government Policy No Decarbonisation Target


Impact on Consumer Bills – The Levy Framework The Office for National Statistics classes payments made by consumers to support

renewable and other low carbon generation as a tax. Therefore the government

needed to establish a mechanism in its budgetary process to forecast and potentially

control the level of subsidy. Hence the government has created the Levy Control

Framework (LCF).

At the moment the LCF covers three subsidy mechanisms, the Renewable

Obligation, Feed-in Tariffs, and the Warm Home Discount. Going forward the

proposed Cfd’s and support for new nuclear will also be included. The government

has set a annual ‘budget’ limit for the LCF starting at £2.6bn for 2012/13 rising to

£7.6bn in 2012 . These figures are in real prices, so assuming 2.5% inflation the

money of the day limit in 2020 would be around £9.2bn. To put the £9.2bn in context

the total revenue of the electricity sector in the UK in 2012 was £31bn.

In our generation scenario the levy cost in 2020 would be £8.6bn, so in our view it

should be possible to deliver the required 110-120TWh of renewable power within

the proposed 2020 levy cap of circa £9.2bn.

Looking at the period 2020 to 2030 the costs under the LCF is likely to increase

substantially as the wave of new nuclear power stations and phase 3 offshore wind

comes on stream. Under the Cfd arrangement the exact size of the costs in the LCF

will depend on the difference between the strike price and the market price. If we

assume a range for new nuclear between £20 per MWh and £40 per MWh, we

calculate that the levy cost in 2030 would be between £24bn and £27bn. Bear in

mind that in 2030 around 400TWh of output would be subject to LCF support

mechanisms compared to circa 115TWh in 2020.



Figure 18: Levy Cap Total (£bn)

0

5

10

15

20

25

30

2020 2030 (20+) 2030 (+40)


Capacity Payments Details on how the capacity payment system will work are still few and far between.

But what is clear is that the capacity payment mechanism will need to work to retain

existing capacity and to attract new capacity in order to protect the security of the

system. It is very likely that these very different requirements will in effect require

two separate capacity markets.

To try and gauge the scale of the capacity payments that will be required to provide

security of supply we can make a couple of assumptions.

New Plant The capacity payment would need to cover fixed operating and financing costs.

Given the security of revenue provided by the capacity payment 80% leverage

would be achievable and a regulated like return (5% post tax) would be sufficient.

Energy sales by the plant would provide upside to the developer. Figure 19 sets out

the calculation that shows that for a 1GW CCGT with a build cost of £650m and an

expected load factor of 15% revenue support of £95m per annum (£8 per kW per

month) would be required.



Figure 19: New CCGT Capacity Payment Calculation

Capacity 1000 MWCapex 650 £mDepreciation -32.5 £mFixed operating costs -35.0 £mMaintenance capex -10.0 £mGearing 80% Cost of equity 7% Cost of debt 5% Tax rate 20% WACC 4.6% Annual FCFF requirement 50.4 £mTotal annual cash expense -45.0 £mCapacity revenue requirement 95.4 £mCapacity payment 95.4 £/kW/yearCapacity payment 8.0 £/kW/monthSource: Liberum Capital estimates

Existing Gas Plant Needless to say for an existing CCGT to capacity payment should be considerably

lower. Again, assuming fixed costs would need to be covered by the capacity

payment we calculate that the revenue support for a 1GW CCGT (80% depreciated)

would be £23m per annual, or £1.93 per kW per month. This would be in line with

the sort of prices paid in other capacity markets world wide.

Figure 20: Existing CCGT Capacity Payment Calculation

Capacity 1000 MWFixed operating costs -35 £mMaintenance capex -10 £mTotal annual cash expense -45 £mGeneration EBITDA 21.9 £mCapacity revenue requirement 23.1 £mCapacity payment 23.1 £/kW/yearCapacity payment 1.93 £/kW/monthSource: Liberum Capital estimates

Total Capacity Payment Costs In our generation scenario to hit first the 2020 targets and then the 50g target by

2030, we see 19GW of new CCGT’s required to be built from now to 2030 and a

further 14GW of existing CCGT plants retained on the system. Assuming all of this

plant requires capacity payment support, then the 19GW of new plant would need

total revenue support of £1.8bn pa and the existing plant some £320m pa, giving a

grand total of £2.2bn pa in 2013 money.

For the 2020 target alone to be met, we assume 10GW of new CCGT plant is built

(£940m) 13GW of existing plant is retained (£299m cost), requiring a total per

annum capacity payments of £1.3bn.

Impact on Bills To try and get a feel for the total impact on energy bills we need to add up all the

additional costs (LCF, network costs, capacity payments) whilst netting off those

costs saved, namely the cost of the fossil fuels that will no longer be burnt.

Impact 2020 We calculate that the government can deliver the circa 115TWh of renewable power

in 2020 for an annual LCF of £8.6bn (within the inflation adjusted £9.2bn cap). We

estimate that the additional revenue that will accrue to network operators



(specifically transmission) will be circa £800m by 2020 compared to the 2012

baseline. As mentioned above we estimate a capacity payment of some £940bn

would be required in 2020, giving a total additional cost of circa £10.34bn.

Assuming everything else stays the same, we can add this to the current sector

revenue of £31bn, giving a total revenue requirement of £41.3bn in 2020. However,

savings will be made in fossil fuel costs. In our generation scenario coal burn drops

from 142TWh to 55TWh in 2020, although gas burn actually increases from 132TWh

to 148TWh in the period. Assuming current coal costs the savings would be some

£2.13bn in 2020. Although this would be off-set by an increase in gas burnt of some

16TWh, which at today’s power price would cost £700m. So the net fossil fuel saving

would be in the order of £1.4bn.

So total costs would be £41.3bn - £1.4bn = £39.9bn. This is a 29% increase over the

2012 total power cost in 2013 money.

Impact 2030 As we set out above the LCF is likely to balloon in the period 2020-2030 due to the

impact of new nuclear and additional offshore wind. If nuclear maintains a £20/MWh

positive differential to the wholesale price the LCF could hit £24bn pa and a

£40/MWh differential would give a £27bn LCF. Add on estimated capacity payment

cost of £2.2bn and additional £4bn of network costs, this would give a total

additional cost of £30.2bn to £34.2bn. This would be a 100% rise in total power

costs compared to 2012.

Energy Efficiency DECC’s latest impact assessment of government policy on bills was published on 27

March 2013.

Figure 21: Cost of Govt Policies and Estimated Energy Efficiency Savings

Source: DECC



As shown above DECC calculates that energy efficiency measures should more

than off-set the rise in power costs caused by the de-carbonisation policy. The

efficiency measures largely apply to heating and there is evidence that consumption

has reduced in recent years due to a combination of the high prices, better

installation, and more efficient appliances. However, there are a few concerns that

should be highlighted regarding DECC’s assumptions:

1) most of the energy savings require consumers to incur upfront costs and in the

case of the Green Deal ongoing annual costs which don’t appear in the

calculations;

2) DECC’s calculations assume duel fuel household, and one which is able to take

full advantage of all the energy savings measure available. Poorer households

are unlikely to be able take advantage of all the energy efficiency measures;

3) DECC’s comparison is for the year 2020 which is before the huge ramp up of

costs associated with new nuclear are due to kick in;

4) DECC admits that the unit cost of electricity will be substantially higher in 2020

than today, but argue that households will use less power so overall bills wont

be any higher. But it is also the policy that households will start to transfer

heating and transport load to electricity early in the next decade. Households will

be expected greatly increase their use of, and dependence on electricity,

despite very high unit costs.

Bills and Profits Rise The big test for the sustainability of policy will be the willingness of future

governments to defend both rising consumer bills AND the profits that will inevitably

flow from the £100’s of billons of investment that the government policy calls for.

By way of example, Figure 22 shows various scenarios for the EPS of SSE in the

second half of this decade. If SSE was to invest in proportion to its market share to

meet the 2020 targets, we would expect its annual capex to increase from £1.5bn pa

to £4.0bn, with the bulk of the increase going into offshore wind. Figure 22 shows

the sort of EPS growth that could result from such a level of capex at £55/MWh and

£70/MWh power prices (assuming current levels of subsidy levels are maintained).

At a perfectly feasible £70/MWh power price, SSE would be seeing 33% annual

increases in EPS towards the end of this decade. Investors have to believe that the

government of the day will be willing to stand behind these profit increases and

defend them to the public at the same time that bills are also rising sharply.

Given the hostile rhetoric that utility companies face from across the political

spectrum on bills and their profits today, it takes quite a leap of faith to believe that

future governments will steadfastly defend the sort of bill and profit increases that

policy will require.



Figure 22: SSE Profit Scenarios: EPS (pence)

50

100

150

200

250

300

350

2015/16 2016/17 2017/18 2018/19 2019/20

£4bn @ £55/MWh £1.5bn @ £55/MWh £4bn @ £70/MWh


Conclusions In summary we conclude that:

1) The scale of the industrial transformation and investment required to meet the

targets set by UK energy policy is implausible.

2) EU policy makers have failed to take into account of the huge changes in the

economic, commodity and financial environments and adjust policy accordingly.

3) The economic arguments supporting the current climate change dominated

energy policy look weak and public support is uncertain.

4) Given the hostile rhetoric that utility companies face from across the political

spectrum on bills and profits today, it takes quite a leap of faith to believe that

future governments will steadfastly defend the huge bill and profit increases that

will inevitably result from current policy.

5) Political risk is bound to rise sharply in the UK energy space in the coming years

as the inherent implausibility and contradictory nature of the policy goals are

exposed by events.

6) A crisis in UK energy policy looks increasingly likely and therefore utility

companies and investors would be prudent in limiting their future exposure.



Disclaimer

The circumstances in which this communication have been produced are such that it is inappropriate to characterise it as independent investment research, as it has not been prepared in accordance with UK legal requirements designed to promote the independence of investment research. Therefore, even if it contains a research recommendation, it should be treated as a marketing communication.

The individuals who prepared this communication may be involved in providing other financial services to the company or companies referenced herein or to other companies who might be said to be competitors of the company or companies referenced herein. As a result, both Liberum Capital Limited (“LCL”) and the individual employees who prepared this communication may have responsibilities that conflict with the interests of the persons who receive this communication and information may be known to LCL or persons connected with it which is not reflected in this communication. Therefore, you should not rely on this communication as being an independent or impartial view of the value or prospects of any companies and/or investments referred to herein

LCL has put in place procedures, systems and controls to identify, to prevent (where this is possible) conflicts of interest. LCL may rely on information barriers, such as “Chinese Walls” to ensure that conflicts of interest are appropriately managed. LCL has a conflicts management policy relating to its research and marketing communication activities, which is available on its website, http://liberumcapital.com/. In addition, a list of items which could create a conflict of interest and other material interests in relation to research material is set out on LCL’s website (see “Disclosures” below).

This communication is provided for information purposes only and should not be regarded as an offer or solicitation to buy or sell any security or other financial instrument. This communication has no regard for the specific investment objectives, financial situation and needs of any specific person or entity. LCL and/or its officers, directors and employees may have or take positions in securities of companies mentioned in this communication (or in any related investment) and may from time to time dispose of any such positions. If applicable, any decision to purchase or subscribe for securities in any offering must be made solely on the basis of the information contained in the offering memorandum (and supplements thereto) or offering circular issued in connection with such offering. LCL may act as a market maker in the securities of companies discussed in this communication (or in any related investments), may sell them or buy them from customers on a principal basis, and may also provide corporate finance or underwriting services for or relating to those companies, for which it is remunerated. LCL analysts, including the author of this report, receive compensation based on a number of factors including the quality of research, client feedback, firm profitability and normal competitive factors. The content of this communication may have been disclosed to the company referenced herein prior to dissemination in order to verify factual accuracy.

All expressions of opinions and estimates constitute a judgement and are those of the author and the research department of LCL only and are subject to change without notice. LCL is under no obligation to update the information contained herein. LCL shall not be liable for any direct or indirect damages, including lost profits, arising in any way from use of all or any of the information contained in this communication.

LCL may have issued other reports or documents that are inconsistent with and reach different conclusions from, the information contained in this communications. Those documents reflect the different assumptions, views and analytical methods of the individuals that prepared them.

This communication is based on materials and sources that are believed to be reliable; however, they are not independently verified and are not guaranteed as being accurate. This communication is not guaranteed to be a complete statement or summary of any securities, markets, reports or developments referred to therein. No representation or warranty either expressed or implied, is made nor responsibility of any kind is accepted by LCL, its directors, officers, employees or agents either as to the accuracy or completeness of any information contained in this communication nor should it be relied on as such.

This communication is provided with the understanding that LCL is not acting in a fiduciary capacity and it is not a personal recommendation to you. Investments in general involve some degree of risk. The value of and the income produced by products may fluctuate, so that an investor may get back less than he invested. Value and income may be adversely affected by exchange rates, interest rates, or other factors. Levels of taxation may change. The investments discussed in this communication may not be eligible for sale in some states or countries and may not be suitable for all investors. Investors should make their own investment decisions based upon their own financial objectives and financial resources and, if in any doubt, should seek advice from an investment advisor. Past performance is not necessarily a guide to future performance. The stated price of any securities mentioned herein will generally be as at the end of the business day immediately prior to the publication date on this document, unless otherwise stated and is not a representative that any transaction can be effected at this price. In the United Kingdom: this communication is for the use of (a) professional clients and institutional counterparties (as those terms are defined by the rules of the Financial Services Authority of LCL and (b) other persons who are not clients of LCL who have expressed interest in receiving it and who are investment professionals (persons having professional experience in matters relating to investments, as defined in Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2001 (as amended) and any other persons to whom this document for the purposes of sections 21 of the Financial Services and Markets Act 2000 can otherwise lawfully be communicated). This communication may not be re-distributed, re-transmitted or disclosed, in whole or in part, or in any manner, without the express written consent of LCL. For the purpose of clarity, this communication is not intended for and should not be relied upon by Retail Clients (as defined by the rules of the Financial Services Authority)

For EU investors: This communication is issued by Liberum Capital Limited (“LCL”). LCL is a member of the London Stock Exchange and is authorised and regulated in the United Kingdom by the Financial Services Authority in connection with its distribution and for the conduct of designated investment business in the European Economic Area. The registered address of Liberum Capital Limited is Ropemaker Place, Level 12, 25 Ropemaker Street, London EC2Y 9LY. Telephone: 020 3100 2000.

For US Investors

Analyst Certification

The analyst (s) who prepared this report hereby certifies that all of the views expressed in this report accurately reflect his / her personal views about the subject securities or issuers. No part of his/her compensation was, is, or will be directly or indirectly related to the inclusion of specific recommendations or views in this report.

The analyst (s) responsible for preparing research report received compensation that is based upon various factors, including total revenues of Liberum Capital Inc. and its affiliates, a portion of which are or have been generated by investment banking activities of Liberum Capital Inc. and its affiliates.

Liberum Capital Limited may make a market in the securities of the issuer and may act as principal with regard to sales and purchases of this security.

This publication has been approved by Liberum Capital Inc. (member of FINRA), which is a U.S. registered broker-dealer and which accepts responsibility for this report and its dissemination in the United States. Any U.S. recipient of this report that is not a registered broker-dealer or a bank acting in a broker or dealer capacity and that wishes further information regarding, or to effect any transaction in, any of the securities discussed in this report, should contact and place orders with Liberum Capital Inc.

Disclosures

Please refer to http://www.liberumcapital.com/legal/legal.aspx for detailed disclosures relating to:

the meaning of LCL’s investment ratings system (buy, hold, sell),

quarterly information on the distribution of LCL buy, sell and hold ratings; giving within each category the proportion to which LCL provided corporate finance services in the last 12 months,

previously published non-independent research on the companies mentioned herein,

whether LCL acts as corporate finance adviser or provides investment banking services to the companies mentioned herein and receives remuneration thereto.

whether LCL has in the last 12 months lead or co-managed an offer of securities for the companies mentioned herein.

whether LCL and / or its affiliates held more than 1% of the issued share capital of the companies mentioned herein.

whether LCL makes markets in the shares of the companies mentioned herein.

whether the author of this communication is a director or officer of any company mentioned herein,

whether the author or an individual who assisted in the preparation of this report received or purchased shares in the companies mentioned herein prior to a public offering.

Research

Large Cap Research

Banks

Cormac Leech +44 (0)20 3100 2264 [email protected]

Building Materials & Housebuilders

Charlie Campbell +44 (0)20 3100 2090 [email protected]

Consumer Goods

Pablo Zuanic +1 212 596 4814 [email protected]

Anubhav Malhotra +1 212 596 4834 [email protected]

Media

Ian Whittaker +44 (0)20 3100 2089 [email protected]

Lisa Hau +44 (0)20 3100 2098 [email protected]

Mining, Metals

Richard Knights +44 (0)20 3100 2087 [email protected]

Ash Lazenby +44 (0)20 3100 2085 [email protected]

Kate Craig +44 (0)20 3100 2077 [email protected]

Ben Davis +44 (0)20 3100 2083 [email protected]

Kit Bottomley +44 (0)20 3100 2052 [email protected]

Charlie Bendon (Specialist Sales) +44 (0)20 3100 2078 [email protected]

Oil & Gas

Andrew Whittock +44 (0)20 3100 2073 [email protected]

Rob Mundy +44 (0)20 3100 2107 [email protected]

Kate Sloan +44 (0)20 3100 2217 [email protected]

Fergus Marcroft (Specialist Sales) +44 (0)20 3100 2242 [email protected]

Pharmaceuticals

Naresh Chouhan +44 (0)20 3100 2095 [email protected]

Roger Franklin +44 (0)20 3100 2096 [email protected]

Graham Doyle +44 (0)20 3100 2031 [email protected]

Real Estate

Alison Watson +44 (0)20 3100 2276 [email protected]

Rob Jones +44 (0)20 3100 2252 [email protected]

Specialty Chemicals & Materials

Adam Collins +44 (0)20 3100 2075 [email protected]

Sophie Jourdier +44 (0)20 3100 2072 [email protected]

Technology

Janardan Menon +44 (0)20 3100 2076 [email protected]

Eoin Lambe +44 (0)20 3100 2191 [email protected]

Telecom Services

Lawrence Sugarman +44 (0)20 3100 2074 [email protected]

Transport, Travel & Leisure

Peter Hyde +44 (0)20 3100 2094 [email protected]

Alexia Dogani +44 (0)20 3100 2254 [email protected]

Utilities

Peter Atherton +44 (0)20 3100 2088 [email protected]

Guillaume Redgwell +44 (0)20 3100 2195 [email protected]

Alternatives & Funds

Conor Finn +44 (0)20 3100 2257 [email protected]

Rob Jones +44 (0)20 3100 2252 [email protected]

Nicole Kwan (Specialist Sales) +44 (0)20 3100 2259 [email protected]

James Bouverat (Specialist Sales) +44 (0)20 3100 2253 [email protected]

UK Small & Mid Cap

Support Services

Joe Brent +44 (0)20 3100 2272 [email protected]

William Shirley +44 (0)20 3100 2271 [email protected]

Jack O'Brien +44 (0)20 3100 2273 [email protected]

Renewable Energy, Agriculture & Water

Nick Walker +44 (0)20 3100 2267 [email protected]

Sophie Jourdier +44 (0)20 3100 2072 [email protected]

Daryl Smith +44 (0)20 3100 2092 [email protected]

Capital Goods

Ben Bourne +44 (0)20 3100 2275 [email protected]

Consumer Cyclicals

Patrick Coffey +44 (0)20 3100 2192 [email protected]

Equity Sales – London

Richard Mawer (Head of Sales) +44 (0)20 3100 2114 [email protected]

Simon Champ +44 (0)20 3100 2112 [email protected]

Edward Blair +44 (0)20 3100 2117 [email protected]

Sean Dixon +44 (0)20 3100 2124 [email protected]

Tim Mayo +44 (0) 20 3100 2127 [email protected]

David Parsons +44 (0)20 3100 2125 [email protected]

Tajender Sandhu +44 (0)20 3100 2238 [email protected]

Iain Whiteley +44 (0)20 3100 2126 [email protected]

UK Small & Mid Cap

Steve Tredget +44 (0)20 3100 2236 [email protected]

Julian Collett +44 (0)20 3100 2113 [email protected]

Thomas Inskip +44 (0)20 3100 2274 [email protected]

Equity Sales – New York

Mark Godridge +1 212 596 4823 [email protected]

Harry Jaffe +1 212 596 4811 [email protected]

Larry Stevens +1 212 596 4812 [email protected]

Sarah Port +1 212 596 4818 [email protected]

Sumeet Gupta +1 212 596 4807 [email protected]

Sales Trading – London

Nina Dixon +44 (0)20 3100 2109 [email protected]

Nick Worthington +44 (0)20 3100 2106 [email protected]

David Thompson +44 (0)20 3100 2062 [email protected]

Paul Somers +44 (0)20 3100 2063 [email protected]

Mark J. Edwards +44 (0)20 3100 2061 [email protected]

Keith Raulli +44 (0)20 3100 2116 [email protected]

Harry Preece +44 (0)20 3100 2118 [email protected]

Trading

Jonathan Plant +44 (0)20 3100 2102 [email protected]

Dominic Lowres +44 (0)20 3100 2103 [email protected]

Simon Warrener +44 (0)20 3100 2105 [email protected]

Peter Turner +44 (0)20 3100 2170 [email protected]

Michael Wackar +44 (0)20 3100 2104 [email protected]

Convertibles

Simon Smith +44 (0)20 3100 2171 [email protected]

Richard Tomblin +44 (0)20 3100 2172 [email protected]

Market Making

STX 77440 +44 (0)20 3100 2200

Liberum Capital Limited Ropemaker Place, Level 12, 25 Ropemaker Street, London, EC2Y 9LY Tel: +44 (0)20 3100 2000 Fax: +44 (0)20 3100 2299 www.liberumcapital.com

Authorised and regulated by the Financial Services Authority Registered in England & Wales No. 5912554

a crisis in uk energy policy looks inevitable

Documents

uk energy policy

eus energy policy

energy bill

policy goals

policy cost

policy makers

energy market

investment decision