Timera Energy

Price levels: Spot prices for delivery in Nth Asia are rapidly rising through 10 $/mmbtu. This has opened up a 2.5 $/mmbtu gap to TTF (exceeding variable transport costs).

China key: Chinese buyers are driving prices higher, given the ongoing policy push to gas, strong industrial demand and building of inventories ahead of winter. 

Other demand: Competition for spot cargoes is also coming from Japan & Korea (low storage balances after a cold winter) as well as India & Pakistan.

Supply constraints: Unplanned & maintenance outages are restricting supply over the summer (e.g. Gorgon, Sabine Pass, Sakhalin, Angola), with new Australian volumes unlikely to ramp up until Q3/Q4.

Europe impact: The Asian spot vs TTF price differential will see flexible LNG supply diverted to Asia, with cargo reloads coming back into the money.  This will support summer prices at NBP/TTF.

Sale of regas terminal stakes (e.g. Dunkerque, Dragon, Adriatic) as well as possible new terminals (e.g. Germany, Croatia) are drawing in new investors.  5 value drivers to consider:

1. Contract position: many facilities have LT contracts in place de-risking front year margin – buying time for utilisation recovery
2. Utilisation: Declining domestic production in Europe key to utilisation recovery over time. Understanding potential utilisation profiles key to value.
3. Option value: Regas capacity is a ‘put option’ allowing cargo sale into European hubs. Merchant value linked to utilisation + premium. ST capacity prices capped at regulated tariffs / LTC capacity prices (~0.2-0.3 $/mmbtu).
4. Portfolio value: Regas capacity value can significantly increase when considered as part of portfolio (e.g. unlocking constraints within portfolio, adding additional physical optionality). Important for Asian buyers, LNG portfolio players, producers.
5. Competitive position: Important considerations (i) relative variable costs (including transport), (ii) access to liquid hubs (iii) commercial flexibility (e.g. TPA vs tariff).

Demand Side Response (DSR) has been a storming success in UK capacity auctions (e.g. 1.2GW cleared last T-4 auction). What impact will this have on the power market:

1. True DSR: The UK’s resources of ‘true’ price responsive load flex is limited by relatively low levels of flexible industrial processes & low penetration of power for space heating (dominated by gas). Grid estimates 1-3GW by 2030.
2. Other sources of DSR: The majority of DSR bidding into the CM is backed by engines & batteries behind the meter. As such dispatch dynamics & costs are driven by these technologies, often in combination with some ‘True’ load flex.
3. High dispatch cost: Whether DSR is ‘True’ or engine/storage backed, it has high variable dispatch costs (e.g. 70-200 £/MWh). This supports higher peak power prices & volatility.
4. Duration: There is considerable uncertainty around duration of flex response from ‘True’ or battery backed DSR. This may also support price volatility & induce policy changes (e.g. reform of CM derating factors).
5. Load shifting In addition to price responsive ‘dispatchable’ DSR there is significant potential for shifting / flattening of daily load profiles e.g. from smart appliances/software & EVs.

Don’t underestimate the importance of demand side flex on power prices, volatility & asset margins.

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 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.

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).

China has embarked on a concerted policy driven push towards gas to tackle urban pollution. LNG demand growth in 2017 was 11 mtpa (39% y-o-y). But rapid growth is exposing regas & storage infrastructure constraints, particularly to meet peak winter demand. The chart shows Chinese LNG imports vs aggregate regas capacity. Behind the headline regas constraint are local constraints in getting gas from terminal to burner tip. China is trying to alleviate these in the short term with LNG trucks.

The chart shows some key emerging trends in US export flow. The ‘natural home’ for US exports on a transport cost basis is Latin America. But in periods of strong Asian demand, higher spot prices have been attracting US cargoes to Asia (e.g. Winter 17-18).  Any US export volumes surplus to Asian & Latin American requirements typically flow to Europe (e.g. over summer 2017). A surge in Asian spot prices across the last 3 weeks is providing a price signal for US exports to flow to Asia this summer.

Gas for coal switching levels are driving hub pricing dynamics at European hubs. The German power market is key for switching given large volumes of coal plants combined with underutilised CCGTs. The chart shows current German switching boundary levels for lower efficiency coal units (40%) vs different efficiency CCGTs. Increasing coal & carbon prices are raising switching levels and supporting hub prices. Backwardation in the gas curve implies significant levels of switching across the next two summers.

Timera Managing Director Olly Spinks presented at the Flame conference this week.  The presentation covered LNG import volumes into Europe, drivers of evolution of TTF, CCGT margins, gas vs coal switching and US export contract management.  You can download the presentation slides here.

The current wave of committed new LNG liquefaction projects consists of 222 bcma (163 mtpa) entering the market between 2015-22. As of Q2 2018, with the Dominion Cove US export terminal currently undergoing commissioning, we are 45% of the way up this mountain.  The chart shows liquefaction project volumes by commissioning year.  But in practice projects are taking 6-9 mths to ramp up to full production. That means 40 bcma (29mtpa) of 2017 commissioned projects are still ramping up into 2018 on top of an equivalent volume of new projects undergoing commissioning this year. That’s a lot of gas… and there is even more coming in 2019.

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.

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.