Timera Angle

Interesting timing for Centrica nuclear sale

Centrica is progressing towards sale of its 20% minority stake in the UK’s 9GW nuclear fleet by 2020. 5 factors driving the outcome:

  1. Exposure Low variable costs support high load factors, meaning assets have a clean (but substantial) exposure to baseload UK power prices & capacity market prices.
  2. Sales timing UK wholesale power prices are driven by gas prices. Pressure to raise capital is forcing Centrica to sell its nuke stake in a period of gas market oversupply and weaker prices.
  3. Price upside A structural tightening in the global gas market is set to underpin a recovery in UK & global gas prices between 2020-25. This means a parallel recovery in UK power prices.
  4. Volume upside Nuclear life extensions are likely given new build delays. The UK can’t afford a gap between existing & new nuclear from an emissions or security of supply perspective.
  5. Buyer & price? Interest will likely focus on large strategic & infrastructure investors but finding a buyer palatable to both EDF & the UK government won’t be easy. Sales price will be driven by cost of capital and the pricing of market & decommissioning risks.

Timera is recruiting power analysts

Timera Energy has developed a strong franchise advising clients on investment, valuation & monetisation of flexible power assets.

  1. Why are we recruiting? To expand our Power team to service a rapidly growing client base of private equity & infrastructure funds, independent generators & utilities.
  2. What roles are open? We are seeking a Senior Power Analyst and a Power Analyst with strong technical skills and a practical ability to solve client problems.
  3. Who are we looking for? Important characteristics of our team members include logical reasoning, creative thinking, comfort with numbers and direct practical experience of power analytics from within the energy industry.
  4. Why work for Timera? We are an entrepreneurial and innovative company with a dynamic work environment. We offer very competitive packages and significantly more flexibility, autonomy & upside participation than other energy companies or consultancies.

See further details at Working with Timera.  If you are interested contact us via info@timera-energy.com.

Expansion plans for Asian LNG players

Asian LNG buyers are bulking up their commercial & trading capabilities and expanding their presence in Europe. 5 reasons why:

  1. Managing near term over contracted positions (e.g. Japanese & Korean portfolios).
  2. Erosion of captive domestic markets and associated ability to pass through long term contract costs.
  3. Using the spot LNG market as a source of flex (e.g. Chinese demand due to limited domestic gas storage).
  4. Managing on optimising US export contract FOB cargoes against spot market prices.
  5. Accessing European hub liquidity to manage LNG portfolio exposures (e.g. hedging against liquid European forward curves).

UK T-1 auction implications

5 takeaways from the T-1 auction results:

  1. Coal closure The 1.8GW Eggborough coal plant was unsuccessful in the auction and will close end of Sep 2018. 0.4GW Fiddlers Ferry U1 also missed out. No surprises here given weak dark spreads. T-4 auction may precipitate further coal closures.
  2. Peaker build 1.0GW of new peakers/DSR were successful in the auction, likely dominated by early delivery of already committed capacity.
  3. Next winter Otherwise Win 18/19 set up looks similar to Win 17/18. 1GW Peterhead CCGT survives another year (lower TNUOS costs). 0.6GW Drax unit 4 missed out in T-1 but is scheduled to return from biomass conversion by Nov 18.
  4. Peak pricing Replacing coal with high variable cost peaking/DSR capacity should continue to support super peak prices.
  5. System transition Grid continues to face diminishing control/visibility as transmission connected assets close. This focuses the need to push through with reforms of balancing & ancillary service markets and system charges.

UK suppliers wiped out by market risk

Two small suppliers have ceased trading this winter, with wholesale market risk exposures playing an important role. 5 things to consider:

  1. No surprise Player entry and exit are characteristics of a well functioning market. Supplier failures are also consistent with an increasing number of new entrants. Regulators should not overreact to signs of a competitive market.
  2. Managing market risk Hedging isn’t trading. It is more like margin insurance. You need to understand what risks are covered and how much cover costs. Determining whether hedging is ‘expensive’ depends on the level of cover.
  3. Shape risk The UK power market makes hedging retail shape difficult. Market dynamics mean this may get worse rather than better.
  4. Market vs sales Properly reflecting market risk in product pricing decisions is both complex and critical. This can often be overlooked as a priority in a sales driven business.
  5. Market access Route to market services for small suppliers are expensive and limited by credit. The need to balance business growth with maintaining good credit worthiness is essential to be able to manage market risks effectively.

UK power transition & flex asset value

The UK power market is undergoing a transition with major implications for flexible asset value. 5 key takeaways:

  1. Capacity mix transition Structural transition in UK supply stack continues apace. Renewables (low SRMC) and engines/batteries (high SRMC) are replacing coal & CCGTs (mid-range SRMC).
  2. Price shape & volatility Stack changes increase price shape & volatility, pushing asset value into prompt. Changing load patterns & long duration batteries should dampen impact over time.
  3. Flex investment battle Engines, CCGTs, batteries & DSR competing at margin to provide capacity. There is no clear winner. Cost of capital, value management & market access are key.
  4. Value management Flex asset value is being realised in prompt horizon & BM. This means higher risk and more complex hedging & optimisation. Value extraction requires scale & sophistication.
  5. Market access Key asset owner decision: ‘in-house’ or ‘out-source’ market access. Outsourcing can provide scale & sophistication. But contract structure must be water-tight.

More details in our briefing pack Capacity mix transition driving flexible asset value.

Timera Snapshot

Carbon rise may accelerate UK coal closures

Carbon EUA prices have rallied ~75% since the start of the year (7.8 to 13.5 €/t).  CCGTs dominate price setting in the UK power market.  This has seen the carbon price rise passed through into higher power prices at the carbon intensity of CCGTs (with limited impact on UK CSS).  But the impact of rising carbon prices is having a larger impact on the variable cost of more carbon intensive coal plants. This is pushing UK baseload dark spreads back into negative territory after a recovery in 2017.  Coal prices are also recovering in Q2 18 reinforcing the CDS decline. Further weakness in CDS (via either higher carbon or coal costs) may accelerate closure decisions for UK coal assets.

UK seasonal gas spreads continue recovery

In this week’s feature article we flagged the potential for a tightening seasonal flex balance in the European gas market.  Its already happening in the UK, accelerated by the closure of the Rough storage facility (70% of UK working gas volume).  The chart shows NBP front year summer/winter price spreads doubling since the beginning of 2016 (major outages started at Rough in Q2 2016).  A sharper seasonal price signal has been required to attract incremental seasonal flexibility from the Norwegian delivery network and flows across the interconnectors. Spread levels are well short of those required to develop new seasonal storage assets (~15 p/th), but provide a shot in the arm for fast cycle storage economics.

Timera update: clients & projects

Some key areas of Timera client work over the last few months:

  • Market and asset valuation analysis across German, French, Belgian & Dutch power markets.
  • Analysis of interaction between gas engine, DSR & battery flexibility & investment dynamics.
  • Deep dive on evolution of UK gas engine risk/return distributions (wholesale & BM margin).
  • Asset & offtake contract valuation for North-West European LNG regas terminals.
  • Analysis of changing NW European gas price & flow dynamics & interconnector capacity value impact.
  • Advising on gas storage asset investment and capacity valuation.

Pricing in an oversupplied LNG market

The chart shows how tightness in the Asian LNG spot market has been a seasonal phenomenon within a broader oversupplied global market.  Low volumes of Asian gas storage are behind this, particularly in China. LNG spot prices have risen across the last two winters to attract incremental cargoes.  But in Q1 18 Asian prices have rapidly converged back to a 0.5-1.0 $/mmbtu transport cost differential to TTF (just as in Q1 17).  The US export volumes that have fed Asia over the winter are now flowing back to Latin America. Meanwhile European hub prices remain supported by robust coal prices which have raised gas vs coal switching levels.

US & OPEC play cat & mouse with crude

From 2011 to late 2014 WTI crude prices remained in an 80-100 $/bbl range, with OPEC supply restraint making way for growth in US shale oil production. In Nov 2014 OPEC abandoned cuts to directly compete against US production for market share.  This sent crude prices plunging below 50 $/bbl for most of 2015-16, with marginal US production falling in response. The latest round of OPEC & Russian production cuts in 2017 have supported a recovery in both US production and price. But behind this cat and mouse game, global demand growth remains strong, upstream investment remains low and inventories are declining relative to demand.  These conditions are likely to continue to support prices.

Russia & LNG support rising EU gas demand

European gas demand (net of reverse flow) rose another 17 bcm across 2017 (~3.2%). Rising power sector demand was the primary driver as CCGT load factors continue to increase.  The chart shows a summary of changes in the key sources of European supply to meet this rising demand (note storage inventory changes excluded).  Russian flows increased a further 17 bcm, supported by more proactive sales of gas at hubs.  But LNG imports also rose significantly (10 bcm), helped by strong Iberian imports in a dry year for hydro output.  10 bcm of new European LNG demand is not trivial – to put it in context the much headlined increase in Chinese LNG demand across 2017 was 16 bcm.

Surging gas prices, jump in basis risk

Gas market stress this week has caused unusual price spread behaviour across European hubs. Cold weather had the biggest impact on the NW corner of Europe with UK, NL and FR fighting for available supply. The chart shows the day-ahead price basis for different hubs vs  TTF (85 €/MWh) at market close on Thu 1st Mar. Normal basis relationships broke down in spectacular style with NCG and PSV trading at sharp discounts to NW hubs, reflecting milder weather. Basis risk is often the Achilles heel of gas portfolios during market shocks.