Blog Content Types: Featured Article

Will LNG bunkering transform the LNG market?

Posted on by David Duncan

Tightening emissions standards are supporting structural growth in the uptake of LNG as a shipping fuel.  Europe has led this transition, dominating the fleet of existing vessels and associated infrastructure. But growth is now accelerating globally.

LNG bunkering has created considerable excitement as a new source of demand in the LNG market.  Today we look at the drivers and potential scale of LNG demand growth from shipping.

Emissions regulations driving change

In 2016 the International Maritime Organisation (IMO) announced requirements for significant reductions of marine fuel sulphur by 2020.  Under the new provisions, marine fuel used in ships will have to have a sulphur content of no more than 0.5% versus the current limit of 3.5%.  Emissions standards have already been tightened to a cap of 0.1% for designated Emission Control Areas (ECA’s) for coastlines in the US and Northern Europe.

The IMO 2020 regulations will require ship owners to decide whether to:

  1. continue using high sulphur fuel oil and add scrubbers/exhaust gas cleaning systems or
  2. switch to low sulphur fuel options i.e. distillates or LNG.

Tighter emissions standards are acting as a tailwind for LNG-fuelled vessels.

Growing fleet & order books

There is an existing global LNG-fuelled fleet of around 120 vessels.  More than 60% of these are European based.  LNG consumption of the current fleet is around 0.25 mtpa.

The fleet has been growing recently at a rate of about 20% a year, with a current global order book of a similar size to the existing fleet.

While this headline growth rate is impressive, understanding different vessel classification segments is important for estimating implications for LNG demand growth.  This is the primary reason for uncertainty in forecasts of future bunker fuel LNG consumption.

Passenger ships account for around 35% of existing and ordered vessels. Demand here is driven by leading cruise ship operators placing orders to help avoid emissions constraints in city ports.

But the strongest recent growth in vessel demand has been for larger LNG-fuelled tankers and bulk carriers.  In addition to an in-service fleet of 19 vessels, 10 chemical/product tankers have been ordered. Four Aframax ice class oil tankers have been ordered by Socomflot which will be taken on charter by Shell.

The LNG-fuelled marine industry focus is shifting from Norway and the Baltic region northern Europe and North American trade. Four of the LNG fuelled vessels in operation already operate globally and 22 newbuilds are also destined for global trade.

Oil and gas offshore industry service vessels rank second in terms of LNG uptake. However, this is unlikely to be a major source of significant future growth.

Higher growth is expected in the tanker, car/passenger, cruise and container segments.  Container ships are well suited for LNG fuel, with fixed routes and a high fuel consumption to earn back the additional investment.

In late 2017 Total agreed to supply French shipping firm CMA CGM with around 300,000 t/year of LNG bunker fuel for 10 years from 2020 – the largest such contract to date. CMA CGM has ordered nine 22,000 twenty-foot equivalent unit (TEU) container ships with LNG fuelled engines.  The French government is planning to support development of LNG bunkering infrastructure at the country’s ports.

LNG bunkering infrastructure

LNG bunkering infrastructure is currently concentrated in areas affected by the existing tighter ECA emissions standards and with access to LNG from regas or liquefaction related storage tanks and port facilities.  These include:

  • North west Europe (for example, in the ports of Rotterdam, Stockholm and Zeebrugge)
  • The US Gulf and East coast (including the ports of Jacksonville and Fourchon)

These make up the bunkering nodes around which a global LNG-fuelled shipping industry will be developed.

Key Asian ports serving deep-sea shipping routes are in the process of establishing LNG bunkering facilities and looking to co-ordinate activities with their European and North American counterparts. This is most evident in the infrastructure being developed by Singapore and in ports in eastern China, for example Ningbo-Zhoushan, the world’s biggest cargo port.

Chart 1: Global infrastructure for LNG bunkering

Source: DNV.GL

Current EU policy requires at least one LNG bunkering port in each member state. About 10% of European coastal and inland ports will be included, a total of 139 ports. Coastal port LNG infrastructure will be completed by 2020 and for inland ports by 2025.

There are several ports under development in North America, mostly in the south east, the Gulf of Mexico and around the Great Lakes, but also for ferry and deep-sea operations in the Pacific Northwest.

China is extending LNG bunkering infrastructure from inland waterways to coastal areas and is expected to be able to service the LNG demand of all vessel types. South Korea offers LNG bunkering in the port of Incheon and is considering a second facility in Busan. Elsewhere in Asia, in addition to Singapore, Japan and Australia are also working to develop LNG bunkering facilities.

Potential impact on global LNG demand

The IEA, in their 2017 World Energy Outlook, see the use of LNG replacing heavy-fuel oil as a bunker fuel providing around a 25% reduction in CO2 emissions. Notwithstanding the challenges in forecasting LNG bunker fuel outlined above, the IEA make the following projections for their ‘New Policies Scenario’ and a ‘Sustainable Development Scenario’.  In the latter it is assumed that the IMO limits on sulphur are further tightened – hence the increased LNG consumption in bunkering.

Chart 2: IEA LNG marine fuel demand forecast (bcma)

Source: IEA World Outlook 2017

To put these LNG bunkering demand numbers in context, they are equivalent to the projected demand growth of one of the larger emerging Asian buyers e.g. Thailand or Pakistan.

As such LNG bunkering is an interesting demand growth trend to keep an eye on.  But it is unlikely to have a transformational impact on global LNG market demand.

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Gas market explodes into action

Posted on by David Duncan

Cold weather across North West Europe sparked a surge in gas price volatility last week.  The epicentre of system stress was the UK gas market. But the parallel spike in NBP and TTF prices reflected a UK and Dutch fight for gas across the interconnectors, with price shocks reverberating across the European gas hub network.

In today’s article we summarise the events that culminated in one of the sharpest bursts of gas price volatility this decade. We also touch on how this impacted other European hubs and the UK power market.  But more importantly we consider the potential implications for policy, supply flex value and the re-pricing of portfolio risk.

Anatomy of a gas market shock

System stress built over the course of last week as temperatures plummeted across NW Europe.  The impact of the arctic blast peaked on Thursday where the UK TSO (National Grid) forecast a 50 mcm shortage of gas for the day and issued its first ever gas deficit warning.

Demand reached its highest level since 2010 on Thursday (410 mcm).  There were also significant weather related supply infrastructure outages (Kollsnes 16 mcm, SEGAL 18 mcm & a temporary halt on South Hook terminal send out). This saw the UK’s first real test of system deliverability in a post Rough environment.

Within-day prices were elevated across the day, peaking at an unprecedented 450 p/th on Thursday evening. Grid was actively buying back gas from large industrials at elevated prices to help balance the system.

Within-Day prices at the Dutch TTF hub also rose above 120 €/MWh as Europe’s two primary hubs battled for limited gas supply.  Other hubs across Europe were caught in the price uplift, although most traded at a significant negative basis to NBP and TTF as we showed in our Snapshot column on Fri. The exception was PEG Nord with Northern France facing a shortage of gas driven by declining LNG send out and falling Norwegian deliveries.

Chart 1 illustrates how UK supply flex responded to the sharp jump in price signals. Storage withdrawals (~80 mcm) and LNG tank send out (~60-80 mcm) played a key role in plugging the gap.  The ability for LNG terminal send out at this rate is typically restricted to a couple of days given limited inventories.  Interestingly the IUK interconnector was importing at lower than normal rates as TTF price rises kept pace with NBP.

Chart 1 Evolution of UK gas supply across key sources Source: National Grid

These short term fireworks had little impact on NBP and TTF forward curves beyond the horizon of the current cold spell.  The fact that the impact of system stress was focused on prompt prices is a sign of a well functioning commodity market.

UK power market reaction

UK power prices leapt in sympathy with gas prices, but market stress was actually less acute.  A liquid gas market ensures direct pass through of higher spot gas prices into power prices.  Very high gas prices saw power prices jump above 100 £/MWh later last week, even in the context of a market that had capacity headroom to spare.

Stress in the power market was highest on Thursday morning when unusually cold weather impacted the ability of several large CCGTs and a nuclear plant to start.  But elevated gas prices ensured that CCGTs were at a significant variable cost disadvantage to coal units.  This saw 11GW of coal capacity running baseload which along with healthy wind output helped to cap system tightness.

The events of last week are a reminder of several evolving power market dynamics:

  1. Gas volatility: As the UK gas market becomes more import dependent, rising gas price volatility is set to translate into higher power price volatility, given the price setting dominance of gas-fired power plants.
  2. Coal closures: The replacement of 11GW of coal capacity with other flex is causing a major transition in price setting dynamics to the right of the supply stack (e.g. GTs and engines have much higher variable costs than coal).
  3. Outages: Flexible infrastructure outages tend to be correlated with market shocks (e.g. due to cold weather), particularly for ageing assets.

Policy implications of this market shock

The key takeaway from the events of last week is that markets worked as they should.  Security of supply was maintained through a period of major system stress driven by a combination of very high demand and supply outages.

In the short term, gas supply is inelastic (unresponsive to price). This means temporary market shocks cause extreme short term price movements to ensure the balance of supply and demand.  This price volatility is evidence of well functioning markets rather than system failure.

The UK gas market in particular needs investment in new deliverability flexibility after the closure of Rough storage (as we have written about previously).  Spot volatility is the price signal required for investors to commit capital.

Expect a repricing of portfolio risk & supply flex

While recent gas market tightness does not constitute market failure, it is likely to trigger a re-pricing of ‘tail risk’.  A low volatility environment has steadily eroded risk premiums over the last five years. But market shocks are set to increase in frequency and magnitude as import dependency increases.  The extreme nature of recent price moves reinforces the portfolio insurance role of supply flexibility.

Energy supply is a high volume, low margin business that is vulnerable to irregular market shocks.   A number of new entrant suppliers have already fallen victim to market price risk this winter.  More may follow after last week.  As the new entrant supplier model matures, demand for flexible insurance products (e.g. price caps) is set to rise significantly.

This dynamic is already being anticipated by larger gas portfolio players.  A re-pricing of risk is reflected in a step change in demand for gas supply flexibility since the closure of Rough.  Interest here is twofold: (i) to cover own portfolio risk and (ii) to enable the origination and sale of insurance products to new entrants and less sophisticated players.

The value of flexible gas supply infrastructure is in a cyclical trough.  But increasing portfolio demand for gas supply flex points to recovering prices ahead for storage and regas assets.

 

Deconstructing LNG shipping costs

Posted on by David Duncan

Shipping costs seems like a relatively obscure topic.  Yet one of the most popular articles in our blog archive is a 2013 article that provides a breakdown of LNG shipping cost components.

So why are people interested? The delivery of LNG cargoes is increasingly being optimised against spot price signals. Margin opportunities in moving LNG between regions depends on the cost of transportation. This means that shipping cost differentials have become key drivers of LNG flows & regional price spreads.

Given that context we are publishing an updated version of the article to address a number of developments over the last 5 years.

Cost component breakdown

The following factors are the key determinants of shipping costs from point A to B.

Chartering fee: This is the payment for securing access to shipping capacity by chartering a vessel.  There are broadly three ways to access shipping capacity: (1) own vessel capacity (2) time charter and (3) single voyage or spot charter.   Spot charter rates are generally higher and certainly more volatile than longer term time charter rates.  Strong Asian demand across this winter has seen spot charter rates rise to between $70-80k per day for 160,000 mcm vessels.

Brokerage: Vessel charters are typically arranged through specialist brokers and attract a 1-2% fee.

Vessel type: Historically most LNG vessels were powered by Steam Turbines (ST) which can burn a combination of heavy fuel oil (HFO) and boil-off gas in their boilers. Modern diesel engines have replaced STs in new vessels delivered over recent years. Dual / Tri Fuel Diesel Engine (D/TFDE) can also burn a mixture of HFO and boil-off gas but are much more efficient (reducing fuel costs).  Vessel size is also an important determinant of voyage economics and cost.  The most common size is around 147k to 160k m3 but larger vessels are also available between 210k m3 (Q-Flex) and up to 260k m3 (Q-Max).

Fuel cost: The voyage fuel or ‘bunker’ consumption is directly proportional to the distance and speed of the vessel.  This is typically the second largest cost component after the chartering cost.   The different propulsion mechanisms and fuel burn options add some complexity.  Most LNG vessels can burn fuel oil, boil-off gas or a blend of both in their boilers.  As a result the calculation of fuel cost is closely tied to that of boil-off gas.

Natural boil-off occurs at a rate of ~0.1-0.2% of inventory per day and at times boil off is forced above this level to further reduce fuel oil requirements.  Some modern LNG vessels also have the ability to re-liquefy boil-off gas, keeping the cargo whole (while running on more fuel efficient diesel engines).

LNG vessels also require a minimum inventory (called “heel”) to keep the tanks cool (and fuel for unladen voyages if running on boil-off).  Calculation of direct fuel consumption is fairly straightforward but the opportunity cost of LNG boil-off is also an important consideration.

The choice of fuel blend influences achievable speeds e.g. around 14 knots running on boil-off alone compared to around 19 knots running on HFO or forced boil-off.  Speeds in turn can also have implications for charter costs and ability to reach a destination in time to capture premium spot prices.

Port costs:  The components and level of the costs of loading and unloading at ports can vary widely depending on location.  For example, ports in less stable regions can levy large security charges associated with ensuring the safety of the vessel.

Canal costs: Transit costs have to be paid for using the cross-continental Suez and Panama canals.  Canal transit costs are in the region of USD 300-500k per transit.  The Panama canal widening project, completed in 2016, has opened up the route to the majority (~80%) of LNG vessels. Previously only a small fraction of the LNG tanker fleet could squeeze through. This is an important development for US export projects as the canal transit reduces the distance and cost from the US Gulf Coast to premium Asian markets.

Insurance costs:  Insurance is required for the vessel, cargo and to cover demurrage (liabilities for cargo loading and discharge overruns).

Putting the pieces together

Once you have reflected the components above in a shipping cost calculator, it is a relatively simple analytical exercise to estimate shipping costs.  In Chart 1 we show OIES analysis by Howard Rogers (a senior member of the Timera gas team) illustrating the cost breakdowns of different vessel types.

Chart 1 DFDE vs ST shipping cost estimates on major routes 

Source: Howard Rogers; assumptions: Charter rates: DFDE $60k pd, ST $47k pd. Speed DFDE (on HFO) 19 knts vs ST (on boil-off) 14 kts.  HFO price: 380 $/tonne.

Optimising shipping logistics is a challenging problem e.g. choice of vessel type, propulsion & speed.  But across a range of complex options, route costs are broadly the same as illustrated by DFDE vs ST costs in Chart 1.  This is not a total coincidence as charter rates tend to broadly adjust to equalise shipping costs given a significant degree of vessel substitutability.

Market interest in shipping costs extends beyond optimisation of cargo logistics. A high proportion of new supply being commissioned over the 2016-21 period consists of flexible FOB cargoes (dominated by US exports). At the same time traded LNG market liquidity is increasing.

These forces mean that regional price differentials and LNG portfolio value opportunities are increasingly being driven by shipping costs. That is bringing the behaviour of cost components into sharper focus.

Implications of UK capacity auction results

Posted on by David Duncan

There have been genuine reductions in the costs of flexible capacity over the last 12 months.  These have been supported by falling costs of capital as investors target UK power infrastructure.  But capacity cost reductions had little to do with an auction clearing price of 8.40 £/kW.

The auction result was instead driven by lower than expected exit price levels for older coal & CCGT plants.  These are hard to reconcile with the gap between current unit margins and fixed costs.  But low bids suggest an unwillingness from owners to close older plants, whether for ‘strategic’ or other reasons.

A range of analysis has been published on why the T-4 auction cleared at 8 £/kW. In today’s article we focus instead on implications of the auction result.  We consider what it means for evolution of the capacity mix, market pricing dynamics and asset investment.

Capacity mix changes

Successful and unsuccessful capacity in the auction are summarised in Chart 1.

Chart 1: New and exited capacity from 2021-22 T-4 auction


Source: Timera Energy, National Grid

What’s in?

2.2GW of interconnector capacity was successful across three projects, Eleclink (UK-FR), NEMO (UK-BE) and IFA2 (UK-FR). 0.8GW of new generation capacity was dominated by distribution connected gas engines. 1.2GW of new DSR was also strongly influenced by engines and batteries behind the meter.

What’s out?

8.5GW older existing thermal capacity exited the auction. 7.7GW of coal units, 0.7GW of older CCGTs and 0.1GW of coal plant GTs and engines.

These exits will have some important near term implications for coal plant closures:

  • Eggborough (1.8GW) has announced closure this year after exiting the T-1 auction
  • Fiddlers Ferry (1.7GW) and Cottam (1.8GW) will likely close after the 2018-19 capacity year given these plants have no capacity support beyond.
  • Aberthaw (1.5GW) will likely close after 2020-21 given no agreement beyond.
  • West Burton (1.8GW) has no capacity agreement in 2019-20 but does have one in 2020-21. This plant is likely to remain open until early next decade hunting T-1 support, but in doing so may supress T-1 prices.

Beyond 2021-22 the UK coal fleet is likely to be reduced to the IED compliant Drax coal units (1.2GW) and Ratcliffe (1.8GW).  Based on current market conditions the UK may well achieve its targeted closure of all coal stations prior to 2025, on an economic basis alone.

Market pricing impact

The capacity mix changes from this year’s auction set up a major shift in the UK supply stack:

  • Removal of large grid connected coal assets from the middle of the stack
  • Replacement of this capacity with:
    • high variable cost engines/DSR (at the far right of stack)
    • interconnectors whose pricing/volume depends on conditions in foreign markets

The replacement of mid-merit with peaking plants, accelerates a trend established in the previous three auctions.  While it fulfils the government’s goals in a capacity accounting sense, it will have some important implications for wholesale market pricing dynamics.

Changing stack shape is set to support super peak prices.  The removal of coal units means prices will more often need to rise to bring on gas engines during periods of high net system demand.  This is likely to increase the peak/offpeak price ratio as well as supporting spot price volatility.

The competitive position of new interconnectors in the supply stack depends on price levels in foreign markets.  Under normal market conditions, the interconnectors will tend to import cheaper power from the Continent. But Winter 2016/17 has shown that flows can dry up or reverse during periods of UK system stress, if these coincide with stress in Continental power markets (e.g. FR, NL, BE).

3GW (nameplate) of new interconnector capacity will support price convergence with the Continent.  This will make it much more difficult for other new interconnector projects to follow.

The capacity mix transition from grid to distribution connected assets also poses challenges in balancing services markets.  For example reductions in:

  • active provision of flex in the Balancing Mechanism
  • provision of ancillary services

None of these are insurmountable, but they bring National Grid’s current review of balancing services procurement into focus.

Asset investment implications

Investors are keenly aware of a key policy question arising from the auction result.  Are the regulatory authorities and National Grid (as TSO) comfortable with the type of capacity being delivered by the market?

If the answer to that question is no, then watch out for potential policy changes that (i) support new CCGTs and/or (ii) reduce the competitiveness of engines/DSR. For example:

  • A rule change to limit cashout price chasing would present a major challenge to gas engines
  • Toughening of DSR performance standards would erode competitiveness of behind the meter flex.

Four capacity auctions have now passed and a large new CCGT project is yet to succeed. However behind the scenes new CCGT costs continue to fall, due to a combination of rising efficiency, falling turbine costs and reductions in cost of capital.  Despite this it will be difficult to build new CCGTs with capacity prices below 20 £/kW.  This means new CCGT projects remain queued to cap any capacity price rises above 25 £/kW.

More efficient and flexible existing CCGTs are set to benefit in the wholesale market from the supply stack transition.  The increasing influence of higher variable cost peaker/DSR capacity supports CCGT margin rents.  But an 8 £/kW capacity price is a tough price to absorb for these benefits.

A single digit clearing price has caught owners of existing CCGTs by surprise.  It brings brings future bidding strategy & closure decisions sharply into focus for older, less efficient and less flexible CCGTs.

These older CCGTs have fixed costs of 20-25 £/kW. On a risk adjusted margin basis it makes no sense to stay open with single digit capacity prices.  The dynamics around exiting CCGTs should provide significant price support around 15-20 £/kW in the next few auctions.

Interpreting TTF implied volatility

Posted on by David Duncan

The European gas options market is still in a relative state of infancy versus for example the crude options market.  But as TTF gas hub liquidity grows, the options market continues to mature.

This is improving the quality of information on volatility expectations that can be implied from TTF option prices.  These implied volatility data provide an interesting contrast to the more common backward looking historical volatility measures.

In today’s article we take a look at how TTF implied volatility is evolving as well as looking at the TTF ‘volatility surface’.

Front month implied volatility

Traders have a preference for implied volatility over historical volatility as a benchmark, to the extent that reliable options price data are available.  Implied volatility is:

  1. Market based (vs calculated via formula from historical prices)
  2. Current i.e. today’s option prices provide an ‘up to date’ view on current market conditions
  3. Forward looking e.g. implied volatility from a month-ahead contract provides a view on average volatility of the month ahead contract up to expiry (vs observed volatility over an historical period).

Chart 1 shows the evolution of implied volatility for the TTF ‘at the money’ front month options contract.

Chart 1: TTF front month implied volatility (2012-18)


Source: Timera Energy, Marex Spectron

The chart shows TTF implied volatility recovering since 2013.  Volatility evolution displays somewhat of a seasonal pattern, with levels lower across summer (with the exceptions of summer 2014 & 2016 which were influenced by broader commodity price volatility and events at NBP).

The level of volatility across these summer dips has risen since 2013.  The level of higher volatility periods (usually but not always associated with winters), have also been rising.

Jumps in implied volatility (for specific maturities) tend to come from sharp changes in underlying option prices.  These can be quickly eroded away as traders see value or arbitrage opportunities open up across particular contracts, causing prices to correct.

While a broad uptrend is evident across this period, volatility has fallen back in 2017 from significantly higher levels in 2016.  It remains to be seen whether this softening is a temporary setback within a broader up trend.  A more pronounced rise in NBP volatility across 2016-17 suggests that it is.

Historical vs implied volatility – the basics
If you are familiar with these measures of volatility feel free to jump ahead to the next section.Historical volatilityHistorical volatility involves a retrospective calculation based on observed market prices over a defined period in history. It is a statistical measurement of the realised price dispersions of a specified contract over a specified time period. For example: “Day-Ahead volatility in Apr 2017 was 55%”. Historical volatility is measured based on a dataset of realised historical price return observations. The wider the distribution of historical price returns, the higher the volatility measurement (and vice versa).Implied volatilityThe level of volatility expected by the market can be ‘implied’ from the prices of traded gas options. For example: “the Jan 2018 TTF at the money gas call option contract has an implied volatility of 40%”.The key to being able to imply volatility from traded asset prices is that the level of volatility is an input into the standard pricing formula (e.g. Black Scholes) used to value optionality. Option prices are a function of strike price, underlying gas price, time to expiry and volatility. So if the price of an option is known, then implied volatility can be backed out using an appropriate option pricing formula.

 

TTF implied volatility surface

The second aspect of implied volatility we look at is the ‘surface’ across multiple different option times to maturity and contract strike prices. Strike prices are shown as deltas, where a 0.5 (or 50) delta option is ‘at the money’. The TTF surface is shown in Chart 2.

Chart 2: TTF implied volatility surface


Source: Timera Energy, Marex Spectron*

In mature options markets, volatility surfaces can be very insightful into the market’s expectations of potential price behaviour.  It is important to be wary of reading too much into the TTF implied volatility surface given limited liquidity in a number of options contracts.  However some broader observations can be made.

The volatility surface shows some classic shape characteristics:

  • Decreasing term structure of volatility i.e. volatility falls as time to maturity increases
  • Volatility smirk / smile, where higher volatilities are observed for ‘out of the money’ options
  • Seasonal shape reflecting expectations of higher volatility (higher option value) during winter delivery periods

The high premiums for month ahead ‘out of money’ call options are influenced by contract illiquidity, but are consistent with the risk of sharp prompt price increases.  The price of these call options reflects an insurance premium for protection against shorter term gas price spikes.

*For more information about the Marex Spectron implied volatility data please contact Richard Frape.

 

Capturing UK gas peaker margin

Posted on by David Duncan

Small reciprocating engines are dominating delivery of new capacity in the UK power market.  3.5GW of engines have so far been successful in the UK’s T-4 capacity auctions (2014-16). Engines behind the meter have been the main source of another 2.1 GW of successful DSR capacity.

However since the 2016 capacity auction, a policy shift to remove the key triad revenue benefit has forced a major transition in engine economics.  The engine investment case has shifted to focus on margin capture from wholesale and cash out price volatility.

A shift in business model

Triad revenues were effectively a regulated annual revenue stream (albeit with policy risk attached).  Peaker developers have plugged the triad gap by pursuing a merchant business model focused on extrinsic value capture from gas engines.  That means a substantial shift in investment risk/return profile.

Rather than being scared off by this merchant risk profile, ‘alternative infrastructure investors’ are currently engaged in a fierce battle to try and dominate gas engine investment.  As a result, gas engines are again set to play an important role in the UK’s next T-4 capacity auction starting this week.

This enthusiasm is supporting some very optimistic forecasts of peaker margin evolution. It is one thing to forecast peaker returns in a cashflow model.  It is quite another thing to turn those forecasts into realised margin on a trading desk.

In today’s article we summarise how trading desks practically generate margin from gas engines.  We also quantify gas engine margin capture against historical market prices as a way of benchmarking returns.

Practicalities of peaker value capture

Traders optimise gas engine margin capture based on a series of sequential activities in the following four markets through to delivery:

  1. Forward markets
  2. Day-Ahead auction
  3. Within Day market
  4. Balancing Mechanism & cash out prices

Margin capture activities are summarised in Chart 1.  This assumes a ‘cash out’ price chasing strategy which is currently the most common approach to margin capture.  This strategy can also interact with margin capture from ancillary service markets (e.g. STOR), but we do not consider this in the diagram for simplicity.

Chart 1: Gas engine margin capture activities


Source: Timera Energy

Gas engines typically have very little margin that can be hedged in forward markets (intrinsic value), given relatively low unit efficiencies (35-40% HHV).

Margin capture instead usually starts with the day-ahead auction. Here certain peak hours may be hedged (particularly in the winter). But day-ahead margin capture is still relatively low as a portion of total margin.

Within-Day margin capture is also typically quite limited.  This is because of a high correlation between day-ahead and within-day prices and limited within-day liquidity.

That leaves the Balancing Mechanism (BM) as the main source of margin.  BM margin capture is focused on a ‘cash out price chasing’ strategy that relies on forecasting cash out prices as follows:

  1. Spill: If cash out prices are correctly forecast to be higher than unit variable cost, then units are ‘spilled’ into the BM to be cashed out profitably.
  2. Turn off: If cash out prices are correctly forecast to be lower than the price of any existing hedges, then units can be switched off and the hedges cashed out.

The success of gas engine margin capture therefore largely depends on (a) the volatility of cash out prices and (b) cash out price forecasting error (since errors cost money).

An alternative to the ‘cash out price chasing’ strategy is direct BM participation for engine units. But this requires significant set-up costs, takes volume control away from the generator and results in direct competition from other generators (e.g. CCGTs).

Quantifying margin capture

The robust projection of gas engine margin requires a modelling framework that captures the sequential activities above.  Importantly it needs to properly account for the uncertainty that trading desks confront across the activities required to monetise units. Overly optimistic forecasts of gas engine margin are typically the result of analytical shortcuts or a lack of practical commercial rigour.

We will come back to margin modelling approach in the future. But to provide an objective margin benchmark for today’s article, we have done a simple historical back-testing of gas engine performance against day-ahead and cash out prices since the start of 2016.

Chart 2 shows gas engine margin capture against the day-ahead auction (bottom blue series).  Above this we show two scenarios for cash out margin capture:

  1. Rule Based: The grey bars in the chart show BM value capture assuming cash out price uncertainty. Margin capture is based on a forecast of cash out prices generated from a range of variables at Gate Closure (e.g. estimated system imbalance volumes, wind variability).
  2. Perfect Foresight The blue hashed bars show the incremental value capture (above the Rule Based approach) assuming 100% accuracy in forecasting cash out prices. Although this is unrealistic, it gives an upper bound.

The Rule Based approach implies the capture of 75-80% of perfect foresight value (consistent with benchmarks of actual peaker value capture).

Chart 2: Historical gas engine margin capture (35% HHV efficiency)

Source: Timera Energy

A specific set of events drove the more extreme margins across Win 16-17.  Major French nuclear outages reversed flows on UK interconnectors, creating very high prices & volatility.  This was compounded by the SBR scheme (now defunct), which effectively removed a large volume of reserve capacity, acting to further tighten the market.

Unless you are a very optimistic generator, the events of last winter were outliers. Realised energy margins since then have settled mostly within a 30-50 £/kW/yr range (based on the Rule Based approach), and are falling across the current winter.  These margin levels a significant discount to some of the more optimistic projections underpinning peaker investment cases.

Looking ahead there is also considerable uncertainty as to how cash out margins will evolve.  There are currently only several hundred MWs of gas engines chasing prices.  Step forward 5 years and that is likely to be several GWs.  This raises a clear risk of margin erosion.  It may also increase cash out price forecasting error.

Large volumes of capacity choosing to take cash out price exposure also goes against the original principles of the NETA trading arrangements (i.e. self-balancing and driving liquidity into the voluntary markets ahead of Gate Closure).  This raises the risk of policy driven rule changes aimed at curbing cash out price chasing.

Gas engines here to stay… but not earning super rents

Gas engines will remain a competitive source of capacity for a number of years to come. Their role in providing capacity is underwritten by low capex, high flexibility and the benefits of distribution connection. But the barriers to new entry are relatively low, suggesting competition will drive out any structural margin rents.

Margin exuberance from a subset of investors and developers is setting up painful asset value write-downs by early next decade.  This is likely to support the peaker consolidation trend already underway.

Portfolio aggregation is set to ensure that gas engine investment is dominated by several larger players with a competitive cost of capital, a robust understanding of merchant exposure and a strong commercial capability to monetise it.

USD points to higher commodity prices

Posted on by David Duncan

Two big years for energy prices

Global commodity prices started a major recovery in Q1 2016.  Energy markets played a core role in this recovery.  Brent crude doubled in price from 27 $/bbl in Jan 2016 to 54 $/bbl by year end.  European coal prices also doubled across 2016 to finish the year at 78 $/t.

Energy prices continued to rise in 2017 with crude up another 23% (to 67 $/bbl) and coal prices up 21% (to 95 $/t) by year end.  Gas prices also rose significantly in Europe and Asia, despite healthy volumes of new supply.

Entering 2018, prices rises in energy markets are starting to look stretched from a fundamental perspective.  Spot oil and coal prices are above consensus benchmarks for the long run marginal cost (LRMC) of new supply.  And gas markets will need to absorb large volumes of committed new supply coming online across 2018-20.

So what are the chances of commodity prices continuing to rise in 2018?

The USD suggests there is more to come

Jan 2018 has seen an important shift in currency markets. The US dollar has declined sharply against other major currencies, breaking out of its three year trading range (from 2015-17). A falling USD may have important implications for energy markets, given the strong negative correlation between the USD and commodity prices.

The USD has historically been an excellent barometer for major commodity price moves. This is illustrated by the inverse relationship between the USD index and crude prices shown in Chart 1.

Correlation does not necessarily imply causation and the drivers behind this inverse relationship are complex.  But the historical consistency of the inverse USD vs commodity price correlation means it is worth watching closely.

Chart 1: USD index (top panel) vs front month WTI crude price (bottom panel)

Source: Timera Energy, stockcharts.com

The USD decline is being driven by shifting investor expectations of monetary policy and capital flows. European currencies (EUR, GBP) are rising against the USD, in response to a stronger economic growth outlook and rising inflation expectations.  These factors may force European central banks to start to normalise historically loose monetary policies.  Capital is also flowing out of the US (weighing on the USD) as economic growth strengthens in Europe, Asia and South America.

Economic growth supports the story

So if a declining USD points to higher commodity prices, is this consistent with the fundamental drivers of commodity markets?

The catch phrase of 2017 was ‘synchronised global growth’. This is illustrated by a wall of green blocks in the 2017 columns of Chart 2 and it is driving higher commodity demand.  The last time this synchronisation occurred was back in 2009-10, a period of rapidly rising commodity prices (see Chart 1).

Chart 2: Quarter on quarter GDP growth across major global economies

Source: Doubleline Capital, Haver Analytics, Barclays Research

2017 was dominated by a falling USD and rising commodity prices.  So far markets are pointing to a continuation of this trend in 2018.

Commodity markets are notoriously vulnerable to the effects of inelastic short term supply curves. Commodity demand tends to rise more quickly than the ability of supply to respond.  Prices rise rapidly as a result until new supply can be brought online.  This can lead to curve backwardation and prices rising above the LRMC of new supply.

There is evidence of this dynamic currently in the coal, oil and LNG markets (although there are more temporary seasonal drivers for LNG). Strong Chinese demand is an important factor for all three markets. If the pace of demand growth continues to outstrip supply response this year, commodity prices may continue their upward trend in 2018.

Hub pricing is already winning in Asia

Posted on by David Duncan

Have you heard the following arguments?

The Asian LNG market cannot transition to hub pricing because:

  1. Existing Asian LNG supply contracts are almost all indexed to oil
  2. Asia does not have a reliable established trading hub to support gas on gas trading

The same arguments were made in Continental Europe 15 years ago and the UK in the 1990s. And they were wrong.

Gas on gas competition will evolve differently in Asia to Europe.  But there is already a quiet revolution underway supporting the growing influence of hub pricing in the Asian LNG market.

Asian portfolio evolution and a ramp up in US export volumes is driving an increase in spot and shorter term contracting of LNG.  Market liquidity is being reinforced by growth in the activity of commodity trader intermediaries.

European hubs are already the key reference price benchmark for shorter term LNG deals in Asia. But a more active Asian spot market is evolving with price formation based on prevailing regional market fundamentals. As liquidity is improving it is paving the way for a truly Asian price signal.

In today’s article we look at three drivers that will continue to support the increasing influence of hub pricing in Asia.

Asian portfolio evolution

The need to clear portfolio imbalances is a primary driver of spot trading. There are some pronounced imbalances in Asian LNG portfolios over the next 5 years.  Japanese and Korean utilities are over-contracted, driving short term contracting to reduce portfolio length.

On the other hand, many emerging Asian buyers are under contracted with a requirement to make up volumes via shorter term purchases. In addition, low volumes of domestic storage create a requirement for balancing via short term LNG purchases e.g. in China.

The rapid pace of ramp up in new global LNG supply from 2018-20 also supports increasing shorter term liquidity.

These factors are combining to create a growing structural requirement to transact cargoes which is helping boost the relevance of regional spot price markers.

LNG trading growth

Portfolio imbalances are providing a clear motivation for Asian LNG players to develop stronger trading & optimisation capabilities.  This is reinforced by the requirement to hedge and optimise US export contract volumes against prevailing market prices. Japanese utilities in particular have been active over the last 12 months in expanding their trading presence in both Asia and Europe.

The other shot in the arm for traded market liquidity is coming from commodity traders.  Companies such as Trafigura, Vitol, Glencore & Gunvor are applying expertise developed in the oil market to support expansion of their LNG midstream & trading presence.

As intermediaries, the business model of commodity traders strongly relies on hub price signals. By transacting between producers and buyers they are boosting both hub price penetration and LNG market liquidity.

The evolving dynamics around LNG traded market growth are summarised in Chart 1.

Chart 1: LNG market dynamics


Source: Timera Energy

Hub price penetration

European hubs already act as a strong marginal price signal for the LNG market.  The prices of short to medium term LNG contracts are typically priced at a basis to the TTF/NBP hub price alternative.  This is reflected in the clear relationship between Asian spot prices and TTF shown in Chart 2.

Chart 2: Global gas price benchmarks


Source: Timera Energy, SGX, ICE

LNG supply contracts which have delivery flexibility are being optimised against spot price signals.  And rapid growth in US export contract volumes will reinforce this, with forward exposures hedged against TTF/NBP and delivery optimised against regional spot prices.

Prices are increasingly being influenced by short term supply and demand conditions. The divergence between Asian LNG spot prices and European gas hub price levels in winters 2016/17 and 2017/18 is a good example.  This has been a function of high Asian winter demand (particularly in China). But it underlines the need for an Asian reference price, to provide:

  1. A signal for the market-led disposition of cargoes between Europe and Asia and
  2. A pricing basis for short to medium term transactions.

The development of a ‘triangle’ of price references – Henry Hub, European hubs and Asian spot LNG – provides the necessary guidance for market development as LNG volumes ramp up.

The factors above are driving a virtuous cycle supporting the strengthening influence of hub price signals on the Asian LNG market.  Hub price penetration will not wait for the end of oil-indexed contracts and an established Asian hub. It is here already.

Briefing pack: LNG market transformation
A Timera Energy briefing pack on ‘How the next 5 years will transform the LNG market’ can be downloaded here: LNG market transformation

 

UK capacity auctions set up stack transition

Posted on by David Duncan

The UK power market is preparing for two capacity auctions in Q1 2018.  There is no shortage of competition to provide capacity.  The outcome of these auctions will be key to determining how the capacity mix will evolve over the next 5 years.

In today’s article we look at auction dynamics.  We also consider what a changing capacity mix means for the supply stack, price formation and prompt margin capture of flexible assets.

Capacity market balance & pricing

This month’s T-1 auction for the 2018/19 capacity year looks very well supplied against a demand target of only 4.9GW. This points to a single digit clearing price, potentially low single digits.

The auction will be fought out at the margin between the older CCGTs (e.g. Peterborough & Corby) and 36% efficient coal units (e.g. Fiddler’s Ferry, West Burton) that missed out in the 18/19 T-4 auction.  Bidding will be driven by complex end of asset life economics. At least 2 or 3 large grid connected units are likely to miss out and may close as a result.

The Feb 18 T-4 auction for the 2021/22 also features a large surplus of existing and prequalified capacity over the 49.5GW demand target.  Key drivers to watch for in this auction are:

  1. Older existing thermal How much existing capacity is knocked out by cheaper new build, with a specific focus on the older 36% coal units with 35+ £/kW fixed costs and very low forward energy margin.
  2. New gas engines The volume of gas engines that manage to bid below 25 £/kW, despite a substantial reduction in triad avoidance revenue. A number of engine developers look to be under-pricing the risk associated with wholesale and BM margins in a chase for volume.
  3. New CCGTs Further efficiency increases with latest generation CCGT technology help with wholesale energy margin capture. This could lead to new CCGT projects bidding under 25 £/kW.  Damhead Creek 2 looks to be the most advantaged project given its location.
  4. Batteries Large volumes of prospective battery projects will not necessarily translate into large cleared volumes in the auction. Developers of short duration batteries were dealt a heavy blow in Dec 17 with derating factor reductions (18% for 30 min, 36% for 60 min). Frequency response revenues are also at risk given the rapid scale up in battery volumes.

Marginal price setting in the T-4 auction is likely to be dominated by competition between new gas engines, new CCGTs and older coal units.  Unit economics suggest bids converging around the 25 £/kW level.  But growing investor enthusiasm, and in some cases under-pricing of risk, is driving down project cost of capital. This opens up the risk of another downside price surprise e.g. to 20 £/kW.

Supply stack transition & peak pricing

The UK supply stack is set to rapidly evolve over the next 5 years as older coal and gas units are replaced by renewables, interconnectors, gas engines and batteries.  Chart 1 shows a simplified view of the 2021/22 supply stack.


Source: Timera Energy

Some observations:

  • Renewables with low variable costs are being pushed into the bottom left of the stack, with offshore wind particularly important. This capacity is dominating the provision of new energy but also significantly increasing system intermittency.
  • Thermal closures are causing the removal of flexible capacity from the middle to right hand side of the stack. The pace of closure of the remaining 11GW of coal units will be particularly important as will the volume of older CCGTs that close or are converted to run as OCGTs.
  • Gas engines and short duration batteries with high variable costs are being pushed into the top right hand side of the stack. These units are dominating the provision of new flexible capacity. But they have higher variable costs (e.g. 70+ £/MWh for 35% efficient gas engines) than the coal & CCGT units they are replacing which will drag up system prices when they are required to run.

So while the capacity market is currently well supplied, the energy market is likely to see increasing peak price shape & volatility over the next 5 years.  A growth in renewable output is gradually eroding the load factors of CCGTs.  But rising peak prices and volatility have a positive impact on CCGT margins.

Prompt and Balancing Mechanism returns

A higher volume of system intermittency is going to manifest itself in higher prompt price and Balancing Mechanism volatility.  Marginal prices may swing from low or negative levels in periods of low net system demand, to being set by 70-90 £/MWh peaker costs when there is high net system demand. This is going to significantly increase the emphasis for flexible asset owners on optimisation of unit flexibility against prompt prices.

Ofgem’s cash out price reforms are also set to drive more volatile cashout price behaviour.  Gas engine owners are targeting this volatility by ‘chasing’ cashout prices i.e. spilling when the system is short and turning off when the system is long.  Developer enthusiasm about returns from this strategy does not always properly account for:

  • The risk associated with forecasting cashout prices i.e. getting it wrong costs you money.
  • The impact of large volumes of new gas engines and batteries in dampening the impact of rising cash out price volatility.

Some engine and battery developers are ‘pricing for perfection’ i.e. assuming that BM returns will only improve. This may be setting up some painful writedowns in the 2020s.

The other interesting dynamic looming on the horizon is longer duration energy storage.  The economics of 4-6 hr duration batteries do not yet support large scale rollout.  But the pace of battery cost declines suggests that load shifting arbitrage will start to feature from the mid 2020s. The combination of grid scale and distribution connected storage arbitrage may be a game changer.

Briefing pack: UK power capacity mix transition and asset value

We have just published a briefing pack on the implications of the UK capacity mix transition for flexible asset value. This pack can be downloaded here: “UK power: capacity mix transition driving flexible asset value“.

 

5 energy market surprises for 2018

Posted on by David Duncan

Welcome back to our first feature article of the year.  We kick-off the year with a set of 5 potential surprises to watch for on the radar screen in 2018.  Usual caveat – these are surprises to take into consideration, not predictions to anticipate.

1. A setback for LNG prices?

Commodity price strength may continue to surprise in 2018.  In particular, oil looks to have broken out of its 40 – 60 $/bbl trading range of the last two years.  Commodity demand is being driven by China but also supported by healthy economic & manufacturing growth across most global economies.

Asian spot LNG prices have doubled across the last 6 months, rising above 11 $/mmbtu.  Behind this was a surge in Chinese LNG demand to 37 mtpa in 2017, up 40% year on year. A number of factors have aligned to support Chinese demand including a strong policy shift to gas, rising coal prices, colder Q4 weather, strong economic growth and lower H1 spot LNG prices.

So it seems reasonable to assume LNG prices will continue to strengthen in 2018… doesn’t it?  We’re not so sure. There is a risk that momentum behind the drivers of Chinese demand growth weakens in 2018.  This is particularly the case if China’s 2017 policy shift to gas captured much of the ‘low hanging fruit’ from residential heating & industrial production.

As new supply continues to ramp up from Australian and US producers, a slower pace of Chinese demand growth could erode the LNG market tightening trend of H2 2017.  That may support the re-convergence of Asian and European spot prices.

2. Blockchain transformation takes off

We wish you good luck if you want to convert your savings into bitcoin in 2018.  But the blockchain technology behind bitcoin could radically change energy markets. 2018 may be the year the blockchain moves from the fringe to the centre of energy industry debate.

Blockchain is a technology that supports ‘peer to peer’ transactions.  It is supported by the distributed storage of data across multiple users. As such, blockchain fundamentally challenges the conventional approach of centralised data storage e.g. via an exchange, a payment system or a grid operator.  It also facilitates real-time multilateral trading at very low cost.

The energy industry is enormously data intensive.  This provides powerful incentives to adopt blockchain technology, for example:

  • Transaction costs: Blockchain efficiency has the potential to crush energy transaction costs. With an eye on this, BP & Shell are leading a push to set up a blockchain based energy trading platform by the end of 2018.
  • Security: Cyberterrorism is rapidly becoming a key threat to energy systems, whether physical (e.g. grids) or financial (e.g. exchanges). Blockchain is effectively un-hackable and removes the risk of attack on a central data repository.
  • Connectivity: Blockchain supports a much broader range of decentralised energy transactions, e.g. facilitating the purchase & sale of electricity from distributed solar & wind and EV charging.
  • Disintermediation: The flexibility and transparency of blockchain encourages direct peer-to-peer dealings. Blockchain’s responsiveness and efficiency in doing this breaks down barriers for fully optimising smart grids, demand side response & distributed generation.

3. Reality check for UK batteries & engines

There has been enormous momentum behind investment in UK distribution connected reciprocating engines and batteries in 2016-17.  This been supported by a rapidly evolving requirement for flexible capacity as well as falling costs of capital and technology.

While battery cost reductions continue at pace, they are last year’s story.  The focus for battery developers in 2018 may shift from costs to revenues, as short duration lithium-ion batteries start to become a victim of their own success.

Frequency response revenues present the biggest risk for battery economics.  More than 500MW of batteries already have capacity agreements. At least as much again are likely to receive agreements in this year’s auction. 2018 may be the year when UK frequency response prices start to buckle under the weight of new battery supply.  Battery capacity market revenue was also dealt a blow in Dec 17 with more penal derating factors.

Competitive pressure may also rise for UK gas engine developers in 2018. Business model focus has shifted to wholesale market and balancing mechanism (BM) revenues, given the rapid decline in triad revenue by 2020.  But 4-5 GW of new peaking capacity over the next 3 years raises the risk of a surprise erosion in prompt energy & BM margin.

4. Big step towards global hub based gas market

Legacy long term gas contract positions will ensure that oil-indexation remains in Europe and Asia for many years to come.  But the relevance of oil-indexation is being rapidly overrun by the penetration of hub prices. This is creating greater spot price signal connectivity across the world’s regional gas markets as illustrated in Chart 1.

Chart 1: Global LNG price benchmarks


Source: Timera Energy, SGX, ICE

Gazprom’s change in strategic tack in response to the 2017 EU antitrust case is the last key hurdle on the way to hub dominance in the European gas market. Gazprom is allowing ‘TTF corridor’ price concessions on oil-indexed contracts as well as more actively managing the delivery of its gas at hubs. This transformation has helped Gazprom to grow its European exports, from levels averaging around 150 bcma across the first half of this decade, to almost 185 bcma in 2017. Gazprom’s willingness to recognise hub prices may surprise again in 2018.

Hub price signals are also transforming the LNG market as it transitions towards shorter term contracting and spot price optimisation. This is reinforced by a ramp up in flexible US export volumes that are being optimised against spot price signals.  These factors may support a step change in hub price penetration and trading liquidity in the LNG market in 2018.

5. Fund acquisition momentum builds

In a record low interest rate environment, infrastructure assets have become a key target for both dedicated infrastructure and private equity funds. The average infrastructure fund size has roughly tripled over the last 5 years, with 2017 seeing record capital raising for infrastructure.  2018 may be the year that fund acquisition of European energy assets causes some big surprises.

Big US and Asian funds are converging on European energy markets to compete for assets with the local players.  Decentralisation, decarbonisation and digitisation are strong catalysts for restructuring of utilities, assets sales and aggregation of smaller players.  Private equity capital is particularly targeting the more complex risk profiles of thermal power and unregulated midstream gas assets.

Transaction momentum may be helped by the restructuring or breakup of incumbent utilities. Fortum’s bid for Uniper may act as a catalyst for a broader restructuring of the large German utilities. This could have a knock-on effect in the UK, reinforced e.g. by Centrica’s current woes and the recent Innogy/SSE retail merger.

Again, it is unlikely to be a dull year.  We wish you all the best in navigating the surprises of 2018.