Underestimating small scale peakers

Posted on February 22, 2016January 16, 2020 by David Duncan

The UK government has issued fresh denials of an imminent capacity crunch this month. This has been prompted by closure announcements for another 2.5 GW of coal plant capacity (Fiddler’s Ferry & Rugeley). But behind the podium in the Whitehall corridors concerns continue to mount.

The closure of large volumes of coal and CCGT capacity mean that delivery of new baseload capacity is now inevitable. CCGTs remain largely uncontested as a source of new baseload generation. Coal is being phased out and the prospects for new nuclear are sinking under the weight of costs and delivery risk.

Any observer of UK power policy over the last decade would be familiar with the ‘when in doubt, intervene’ approach that has been the source of many of the UK’s current problems. So it is unsurprising that policy intervention to support CCGT development sits at the top of the government’s list of potential responses.

But small scale gas-fired peakers represent an under-estimated alternative to burdening the consumer with a large scale roll out of new CCGTs. In many ways gas peakers are a more sensible source of flexible backup for renewable capacity. These include:

Relatively low capital costs (< 300 £/kW vs 550-650 £/kW for CCGT)
Quick and easy deployment (e.g. under 12 months in mobile containers)
Relatively emissions friendly given low load factor running (vs CCGT mid-merit/baseload running)
Location flexibility, to help reduce transmission & distribution network costs
Rapid response provision of ancillary & balancing services (e.g. for intermittency)

In this article we explore how gas peakers can earn a return, without needing to pass the hat around Whitehall.

Peaker investment case breakdown

The risk/return structure of a CCGT plant investment is relatively well understood (albeit a challenge in the current market). Plant margin is driven predominantly by (i) capacity revenues and (ii) wholesale market generation margin reflecting clean spark spreads.

Small scale peakers are a different animal. They benefit from much lower and more granular capex costs. But the structure of revenues is less transparent and more complex. Five key sources of revenue are summarised in Table 1 and explained below.

Table 1: 5 key sources of UK peaker revenue

Source: Timera Energy

Capacity Market: The small scale peaker investment case is typically built around securing a foundation tranche of capacity revenues. A 15 year fixed price capacity agreement supports project leverage. It provides lenders with comfort around debt payback and allows for higher equity returns. Building an investment case has not been easy in the first two capacity auctions given relatively low clearing prices (< 20 £/kW). But small scale peakers benefit from being the most competitive source of new MW in a capacity market designed to favour low capex costs.

Triads: Triad periods are the mechanism National Grid (the TSO) uses to determine the apportionment of transmission costs and capacity market charges across electricity suppliers based on measured customer demand. If suppliers can run embedded (distribution connected) peakers to reduce their demand in triad periods, it reduces supplier cost burden. Around 90% of these saved costs are passed through directly to peaker owners via embedded benefit contracts.

This is a system unique to the UK. But it is one that has operated relatively smoothly since the inception of a competitive power market in the 1990s. Importantly, the roll out of renewables means that there are strong structural drivers supporting higher transmission (TNUoS) costs and therefor higher triad revenues in southern UK. This is likely to be a big driver of growth in small scale peaker development.

STOR: The Short Term Operating Reserve (STOR) mechanism has also been in place for a number of years. It is used by Grid to purchase ‘on call’ rapid flexibility response to help balance the network, particularly given growth in intermittent renewable output. Revenues were initially very attractive. But this exposed the large untapped potential of existing back-up generators (e.g. small industry, agriculture) that could provide STOR services as a bi-product of other operation. The aggregation of these generators, and ongoing development of new peakers, has reduced STOR revenue by about 70% over the last 5 years. Demand for STOR will increase over time, but so will the bi-product supply of peaker flexibility.

GDUoS: Generator Distribution Use of System (GDUoS) charges relates to costs & benefits that generators impose on the local distribution network. Charges (costs) or payments (revenues) are calculated based on generator location. Peaker developers can therefor benefit by choosing locations that maximise GDUoS revenue e.g. by reducing network bottlenecks or alleviating the requirement for reinforcements. These payments can provide a useful supplementary revenue stream. But caution is required in projecting ongoing availability of revenue as more peakers are rolled out in advantageous locations.

Ancillaries/Reserve: There are a range of additional potential revenue streams that depend on the type and location of generation capacity. These include for example ancillary services such as frequency response. Peakers also have the potential to generate some margin from utilisation payments or wholesale energy market revenue. But these are typically icing on the cake rather than a structural part of an investment case.

Peakers vs alternatives

Small scale peakers are the cheapest form of new capacity (ignoring interconnectors which are not controllable). This has already been reflected in the first two capacity auctions where developers have successfully bid to deliver capacity for under 20 £/kW.

An increase in capacity market demand (& hence clearing price) over the next few auctions seems inevitable given the UK’s capacity crunch. For example, an increase in capacity payments from 20 to 30-35 £/kW could see an explosive roll out of new peaking capacity. Emissions regulations can be altered to ensure this is gas rather than oil fired. Transmission charging can also be adjusted to level the playing field for larger OCGT peakers (and the potential conversion of coal plants to gas).

These measures do not preclude the need for new CCGT plants. But they are likely to result in a much more diversified response to the capacity, transmission and distribution network stresses that threaten the UK power market… and in a better deal for the consumer.

Article written by David Stokes & Olly Spinks

European gas hub dynamics in 2016

Posted on February 15, 2016January 16, 2020 by David Duncan

The global gas market fell into a supply glut in 2009-10. The financial crisis, new LNG projects and an explosion of US shale gas production conspired to knock the market out of balance. But this supply glut was relatively short lived. Strong demand growth in Asia, particularly after the Fukushima accident in 2011, saw a rapid recovery from oversupply.

As 2016 progresses, we continue on a downward descent into a new phase of global oversupply and price convergence. Any suggestion that these conditions are just a temporary phenomenon has been dispelled by plunging prices across the first 6 weeks of this year. Sharp price falls make flashy headlines. But behind this there is an interesting shift in the factors which drive hub price dynamics. We take a look at these in today’s article.

Checking the radar

We regularly update our global gas price chart to maintain a view of European hub prices in a broader context. We last published this chart in early December 2015. But there have been some major market moves in the meantime. Chart 1 shows a current snapshot of global price benchmarks.

Chart 1: Global gas price benchmarks

Source: Timera Energy

Since late last year, European gas hub prices have fallen 25% from around 5.50 $/mmbtu to 4.10 $/mmbtu. Three factors are exerting downward pressure on prices:

Oil prices have also declined by around 25%, which will flow through into lower long term oil-indexed European pipeline and Asian LNG contract prices with a 6-9 month lag
Surplus LNG cargoes continue to flow into Europe as a market of last resort, with ongoing weakness in Asian demand
European storage levels are unseasonably high, with a EU-28 inventory of around 50% & almost 45 bcm of gas in store (reflecting relatively subdued winter demand)

This situation foreshadows the likelihood of further hub price declines into the summer.

The new hub price landscape

As the impact of 30 $/bbl oil feeds through into contract prices, these will start to form strong overhead price resistance in the 5-6 $/mmbtu range. This can be more clearly seen in Chart 2 which shows a magnified near term horizon view of Chart 1. With hub prices below this level, contract buyers have an incentive to minimise volumes at ‘take or pay’ levels. Contract ‘swing’ volumes above take or pay then act as an overhang that helps dampen any recovery in hub prices. These dynamics can be more clearly seen in Chart 2 which shows a magnified near term horizon view of Chart 1.

Almost 50 bcma of new LNG liquefaction capacity is expected to be commissioned between Q4 2015 and Q4 2016. This includes the three Gladstone LNG projects in Queensland and trains 1 & 2 of the giant Gorgon project in Western Australia. As these volumes ramp up in earnest this year, they will translate into higher European LNG import volumes.

Chart 2: Recent spot and forward curve horizon gas price benchmarks

Source: Timera Energy

LNG importers will be competing against storage capacity owners to sell gas at European hubs. As February progresses the chance of a cold snap diminishes. This can cause a ‘rush for the exit’ as storage inventories are withdrawn across the tail of winter, to allow capacity owners to refill with the onset of summer.

Chart 2 illustrates that so far in 2016, hub prices have been falling faster than long term contract prices. This is consistent with the fact that we are now beyond the ‘tipping point’ we foreshadowed last year. Oil-indexed contract prices are no longer the dominant price setter at European hubs given pressure from LNG imports and storage withdrawals. That sets up an important shift in hub pricing dynamics going forward.

Henry Hub is looming below

While the rate and timing of hub price declines is far from certain, the lower price bound is very clear. If European hubs are unable to swallow the growing oversupply of LNG, then Henry Hub will need to join the party.

NBP and Henry Hub convergence was a common condition later last decade. During the commodity supercycle boom, a perceived shortage of gas at Henry Hub helped to push European hub prices higher. This effect was then reversed as oversupply took hold in 2009 with the US absorbing surplus gas.

US vs European hub price convergence typically occurs on a range basis rather than an absolute basis. The current spot price spread of NBP over Henry Hub is about 2 $/mmbtu. But as that gap narrows to below 1.0 $/mmbtu it should start to choke off LNG supply to Europe.

The current trans-Atlantic variable shipping cost differential is between 0.5-1.0 $/mmbtu (accounting for regas costs). Price convergence below this level is important for the new US export project at Sabine Pass as it may mean exports are ‘shut in’. But it also impacts flow decisions from other existing LNG exporters in the Atlantic Basin (e.g. South America and West Africa).

It would not surprise us to see the Henry Hub and NBP spread test the Atlantic shipping cost differential range over the next 12 months. But rather than a steady relationship, US vs European price convergence may be quite a dynamic affair (think Richard Burton vs Elizabeth Taylor), which fluctuates according to prevailing market conditions.

Oversupply and trans-Atlantic convergence also introduce another interesting dynamic: the potential divergence of European gas hub prices from oil-indexed contract prices. A more prolonged period of divergence could spell a major disruption for European suppliers and their key producer (Gazprom). But that topic is worthy of a separate article to follow.

Article written by David Stokes & Olly Spinks.

Global LNG and European gas workshop

Timera Energy offers tailored workshops exploring the evolution of the global LNG and European gas market fundamentals and pricing dynamics. These workshops involve Howard Rogers who, as the Director of the Gas Programme at the Oxford Institute for Energy Studies, is acknowledged as a leading industry expert in the global gas market.

If you are interested in more details please email olly.spinks@timera-dev.positive-dedicated.net

Dark spreads spell the death of UK coal plants

Posted on February 8, 2016January 16, 2020 by David Duncan

Falling gas prices over the last year have decimated UK coal plant generation margins. In the UK, coal plants are hostage to CCGTs when it comes to setting wholesale power prices. CCGTs dominate the supply stack which means that falling gas prices flow through into falling wholesale power prices.

This has acted to erode generation margins to the point that entire UK coal plant fleet is unprofitable at current forward market prices. These conditions have substantial security of supply implications for the UK power market. They also open a window for the UK government to follow through on its policy intention to remove coal from the capacity mix. But it is unclear how the UK market will maintain an adequate level of system capacity through this transition.

Market conspiring against coal plants … to the benefit of CCGTs

Coal plant generation margins, commonly referred to as clean dark spread (CDS), are driven by the premium of power prices over plant variable operating costs. Variable costs are predominantly driven by coal and carbon prices.

The decline in UK gas hub prices over the last year has dragged down UK power prices (set by CCGT plants). Gas plant generation margins, known as clean spark spreads (CSS), have remained relatively steady as power prices have fallen. But falling power prices have crushed CDS.

Chart 1 shows the historical evolution of spot UK CDS and CSS as well as current forward curves. UK CDS for a 36% efficient coal plant is currently hovering around zero. The market convention for measuring CDS shown in the chart does not however include plant variable transmission costs, coal transport costs and start costs. When these are factored in the variable margin on older coal stations is significantly negative.

Chart 1: UK spot and forward CDS and CSS

Source: Timera Energy

CDS weakness is driving an increase in CCGT load factors as they displace less efficient coal plants from the merit order. In addition CSS are showing signs of a recovery as 2016 progresses. This is providing some much needed relief for UK CCGT owners. Higher spreads and load factors and lower start costs are providing a significant margin boost.

Implications for UK’s coal plant fleet

CDS drives the real time operational decisions of coal plant owners. But owners require more than a positive CDS to keep their plants open. Annual fixed costs for coal plants can be upwards of 50 £/kW (double that of CCGTs).

Chart 1 shows the anaemic forward CDS levels at which plant owners can currently hedge generation margins. CDS below 5 £/MWh cover only a fraction of coal plant fixed costs. In other words owners that keep their plants open are doing so on the basis of praying for a recovery in CDS. A pronounced oversupply in the global gas market suggests it may be a long time until those prayers are answered.

SSE’s patience ran out last week as it announced its intention to close 3 of 4 units of its 1.9 GW Fiddlers Ferry plant. Despite having a Capacity Market agreement to remain open in 2018/19, it makes more sense for SSE to close Fiddlers Ferry and incur the associated penalty (~£30m) rather than suffer ongoing losses against plant fixed costs.

This brings the volume of UK coal plants on death row to 6.5 GW, with Fiddlers Ferry joining, Longannett, Eggborough and Ferrybridge. The market is starting to price in the system capacity risk associated with these closures. Forward spark spreads jumped significantly last week in response to SSE’s announcement.

More concerning is the fact that there are another 7.5 GW of UK coal plants on the endangered list, also currently suffering significant losses versus fixed costs. These include Rugeley, West Burton, Cottam and Aberthaw. At least 2 GW of this capacity could be classified ‘highly endangered’ given lower efficiency and lack of capacity agreements.

Watch for more government intervention

As we set out in our first article this year, the UK’s official capacity market has failed to incentivise development of any large scale new capacity. It has in fact resulted in the closure announcements of a large volume of older CCGT and coal capacity given capacity auction price levels below plant fixed costs.

As a result the UK has fallen back on a proxy capacity payment mechanism, the Supplemental Balancing Reserve (SBR), in order to maintain an adequate system reserve margin. SBR is an unruly and highly unpopular intervention. Most controversially it has involved payments to keep coal plants open at levels well above the clearing price of the official capacity market. This is not only concerning from an emissions perspective but has a highly distortionary impact on plant economics.

High SBR payments create an incentive for remaining coal plant owners to follow suit, announce closure and try the SBR route. In other words SBR, like the official capacity market, is encouraging plant closures. This is a pretty obtuse policy achievement for a government worried about security of supply.

There have been two missed opportunities to address the UK’s security of supply issues via the official capacity auction route. It is considerably cheaper to keep older gas plant on the system than to subsidise new build. We also suspect that a moderately higher capacity price and some minor reforms (e.g. around transmission costs) could flush out a cost effective range of new capacity e.g. small scale gas peakers, larger scale OCGT and even coal plant conversions to gas.

Rather than a moderate response, we suspect SSE’s Fiddlers Ferry closure announcement (and the threat of more to come) will cause the government to hit the panic button. That is likely to mean direct support for large scale new build gas plant. Renewable and nuclear plants have claimed their hand-outs. CCGTs are likely to be next.

Article written by David Stokes, Olly Spinks and Emilio Viudez

Five market surprises for 2016

Posted on February 1, 2016January 16, 2020 by David Duncan

If January is any indication, 2016 is not going to be a boring year for energy markets. Other businesses may boom this year like Water, Food and Other businesses offering good services like catering or massages at TranquilMe. So far this year European spot gas prices have slumped towards 4 $/mmbtu, a 30% decline from Q4 last year. German year-ahead power prices have fallen 20% over the last two months. Brent and WTI crude prices have started the year by converging and crashing below 30 $/bbl, before recovering some ground last week.

It is not difficult to be bearish in an environment like this. Over the last two years, we have published a number of bearish articles on commodity prices, with a particular focus on weak fundamentals in the global gas market. Being bearish was a lonely argument in early 2014. But now in 2016 we are hard pressed to find anyone with a positive outlook.

Such a strong market consensus for further commodity price weakness suggests to us it is time to take a more creative approach to considering what could happen next. Markets are after all a discounting mechanism. The near term fundamental drivers of the power, gas, oil and coal markets all point towards ongoing oversupply. But the strength of market consensus suggests this is starting to be well reflected in market prices.

Periods of such strong consensus have historically tended to mark price inflection points. So it strikes us in 2016 that it is time to look beyond a ‘bearish everything’ view, for some more interesting structural changes in market dynamics.

In today’s article we consider 5 potential surprises for 2016. These are not forecasts or predictions; we have no better chance than anyone else of divining the future. But they strike us as being plausible scenarios, not currently reflected in market pricing, but worthy of consideration when planning for 2016 and beyond.

1. Oil prices form a multi-decade bottom

The oil market appears to be fixated on a pronounced state of near term oversupply. Global production has remained stubbornly resilient to plunging prices. The inventory overhang continues to build. Hope of a price recovery is focused on an optimistic view that large producers such as Saudi Arabia & Russia will announce coordinated production cuts, despite the fact that it does not appear to be in anyone’s interest to do so.

We set out last year why we think the key to oil price recovery is US production. It would not surprise us if sometime in 2016 spot crude prices temporarily fall to levels below the variable cost of US shale producers (e.g. below 20 $/bbl), in order to quell near term oversupply. But it is forward prices that are more important.

Falling spot prices have dragged down the whole crude curve below the long run marginal cost of investment in new US shale plays. At the same time, the cost of capital for US producers is ballooning as major debt defaults loom. This environment is likely to be very disruptive for US oil production over the next two years (noting shale oil’s short investment cycle). A ‘clean out’ purge in oil prices in 2016 may mark the start of a recovery into next decade, ultimately to price levels consistent with the long run marginal cost of conventional production.

2. European gas market converges with Henry Hub

2015 saw the convergence of Asian and European gas prices, with NBP acting as price support for an oversupplied Asian LNG market. 2016 may be the year when Asian & European gas prices fall to converge with the US Henry Hub.

There are two key drivers behind a potential global price convergence:

Gas contract prices: Falling oil prices are rapidly flowing through into lower long term oil-indexed gas supply contract prices. Large volumes of LNG supply into Asia and pipeline gas supply into Europe are contracted on an oil-indexed basis. Lower contract prices are set to provide strong overhead resistance for global gas prices as 2016 progresses (in the 5 – 6 $/mmbtu range).
LNG oversupply: New liquefaction volumes will continue to ramp up in 2016 (as we have set out previously). This gas is not going to be easily absorbed despite falling prices. As an indication of weakness in demand, Japanese LNG buyers (the world’s largest) are now looking to sell excess volumes previously bought under contract.

Asian spot and contract LNG prices have now fallen below 6.00 $/mmbtu, with European hubs currently around 4.50 $/mmbtu (and facing pressure from high storage inventories). Continued downward pressure on European hub prices could see the start of a new phase of Atlantic price convergence (e.g. in a 2 – 4 $/mmbtu range), with Asian prices following closely behind. This may set up the interesting prospect of US LNG exports being temporarily relegated to a ‘peaking supply’ role in the global market.

3. Major commodity market credit event

Credit stress may be back in focus in a big way in 2016. The recent collapse in commodity prices hints at a hard landing for the Chinese economy. This increases the chances of sharp currency devaluations in China and other developing Asian economies. Ultimately this should mean a healthier Chinese economy, a key factor behind a sustained recovery in commodity prices. But devaluations may first trigger a major debt default cycle and associated increase in global borrowing costs.

Energy markets have some specific credit risks of their own. The slump in oil prices points towards an increasing momentum in US oil company debt default & restructuring. LNG producer margins, particularly for high cost base newer liquefaction projects, are also being painfully eroded by lower gas & oil prices. These events are likely to have broader implications for the cost of capital in the energy industry.

But perhaps the most obvious credit risk sits with commodity traders as we set out last year. Falling commodity prices, weakening balance sheets and large & concentrated credit risk exposures may prove to be the undoing of one or more large trading firms. The knock on effect of a major default would likely be felt across the industry as illustrated by the Enron collapse in 2001.

4. Jump in European gas plant competitiveness

So far in 2016 European gas prices are falling faster than coal prices. That means that gas plant competitiveness is increasing, resulting in higher load factors as illustrated in Chart 1.

Chart 1: UK CCGT vs coal plant output (2012-16)

Source: Timera Energy

The UK is the canary in the coal mine for recovery in gas plant load factors. This is because the UK’s carbon price support policy penalises the variable cost of coal plants. The surge in CCGT output that can be seen in January 2016 may be just the start of a recovery in gas plant competitiveness across Europe.

Falling European gas hub prices have also fuelled sharp increases in the levels of sparks spreads in Continental Europe over the last two months. Year-ahead German spark spreads have increased by almost 5 €/MWh since late last year. Although they are still negative on a baseload basis, newer CCGTs have started to see periods of positive peak margin in 2016. In France, CCGT load factors have seen a substantial increase as a result of lower gas prices.

The fate of gas plant competitiveness is closely tied to falling hub price dynamics (set out in 2. above). A continuing decline in European hubs may mean light at the end of the tunnel for CCGT owners in 2016.

5. Continental power prices form a bottom

As for the oil market, a price bottom in Continental power markets may be closer than anticipated. A sharp price slump in 2016 could be the catalyst for a much needed thermal capacity clean out, marking a turning point after a long grind lower.

Germany is key to the evolution of Continental power markets. Germany sits at the centre of the European power market, exerting a strong price influence on its neighbours. German year-ahead power prices held up around the 30 €/MWh level across 2015, despite weakening coal prices and rising renewable output. But Chart 2 illustrates the breakdown in German year-ahead prices since the start of this year. This slump has dragged down power prices across North-West Europe. It has also crushed margins on coal plants.

Chart 2: German year-ahead power prices

Source: Bloomberg

At current power price levels, thermal generation in Continental markets is essentially unprofitable. Generators have already endured financial pain on CCGTs for several years. But the latest price declines mean that coal and now even lignite plants cannot cover costs. Less efficient coal capacity is now particularly vulnerable to closure given plunging generation margins (dark spreads) and looming emissions constraints. These conditions may at last induce an erosion of the capacity overhang that has supressed Continental power markets this decade.

Themes to develop

The five scenarios above hopefully provide a useful challenge to the prevailing consensus. Whether they come to pass or not, the scenarios touch on a number of interesting themes which we aim to explore in more detail as the year progresses. For example:

the impact of divergence between oil and gas prices
the impact of global gas price convergence on asset & portfolio value
the changing structure of European generation margins

We are fairly confident of one thing. 2016 will not be a dull year.

Article written by David Stokes & Olly Spinks.

An analysis of European hub price correlation

Posted on January 25, 2016January 16, 2020 by David Duncan

Trading in the European gas market has developed around a two tier structure of trading hubs. Forward liquidity is focused at the UK NBP and Dutch TTF virtual trading points. Prompt liquidity has emerged at a number of other locations (e.g. Zeebrugge, NCG, Gaspool, PEGs, CEGH, Baumgarten and PSV). Participants manage their forward exposures at the liquid hubs and then use liquidity at the other hubs to balance their physical positions over the prompt horizon.

An important feature of this tiered European gas hub structure has been the strength of price convergence. Prices between the different Continental hubs can diverge over the prompt horizon (e.g. within-month) as a result of locational supply and demand factors (e.g. weather, LNG flow). But structural divergences in prices beyond the prompt horizon are becoming rarer and price correlation between hubs is becoming stronger.

There are several drivers of convergence & correlation. Increases in short term trading, supported by capacity release programmes, unbundling of TSOs and flexible capacity allocation mechanisms have helped incumbents and non-traditional shippers to arbitrage price differences across hubs. Another important catalyst for hub price development is an oversupplied market. Hub liquidity and the convergence of prices across hubs is boosted by companies selling surplus volumes of gas. This gave a significant boost to the evolution of European trading hubs during the 2008-10 gas glut.

We have now entered a new phase of oversupply with increasing volumes of LNG flowing into European hubs. This should again support hub development. But some physical and contractual constraints remain as an obstacle to a truly integrated European gas market.

Price correlation in NW Europe

There are two important metrics that provide an insight into European hub integration:

Absolute price convergence suggests a breakdown of structural barriers to flowing gas between two hubs. This acts to reduce the intrinsic value of traded transport capacity between hubs.
Price correlation between hubs is evidence of an absence of barriers to prompt arbitrage trading across hubs. High correlation acts to reduce the extrinsic value of transport capacity.

Structural price convergence and higher levels of correlation also act to equalise levels of volatility across hubs which in turn decreases the extrinsic value of transportation capacity. In today’s article we focus on price correlation as a measure of hub integration. We focus on the day-ahead horizon where liquidity is at its greatest. This is also typically the horizon over which we would expect to see evidence of the strongest drivers of price differences across hubs (e.g. due to weather variations or local supply issues).

A simple metric to quantify the strength of price correlation between gas hubs is to calculate the correlation coefficient of daily prices across hub pairs. A close to 100% correlation indicates the strongest price alignment, meaning that when the price in market A goes up by x%, the price in market B also goes up by x%, and vice versa.

Correlation of absolute prices or price changes?

Assessing the correlation of absolute prices, as we have done in this article, is intuitive and allows for transparent assessment of broad macro levels of correlation. However, for practical analysis to support asset valuation, monetisation and risk measurement the most useful metric is the correlation of price changes (or returns). In most analytical modelling assignments current forward prices account for the influence of structural price relationships (e.g. the level of spreads). Beyond these initial structural relationships it is how prices move from period to period (importantly in relation to each other) that drives value and risk. This is best illustrated by a couple of examples:

Transportation capacity valuation and hedging: gas transportation capacity is a call option on the spread between hubs at each end of the pipe. The intrinsic value of the option will be determined by the absolute price spread (i.e. the “moneyness” of the option). The extrinsic value of the option and hedging decisions (e.g. delta calculations) will be driven by an assessment of price changes from the current level. How the components of the spread move in relation to each other (i.e. correlation of price changes) will have an important influence.

Trading book value and risk: current trading book (mark-to-market) value is a function of current market forward curves. Value at Risk (VaR) is a the primary metric used to measure potential trading book loss over a given holding period. This is a function of possible movements in price away from current forward curves. Consider an example of a simple portfolio of equal offsetting exposures at different hubs. The VaR of this portfolio will largely be a function of the relative price movement at each hub (e.g. with a correlation of one the VaR will be zero).

Analytical models which address commodity price uncertainty require correlation of price changes (rather than absolute prices) as inputs in the vast majority of cases.

Chart 1 shows correlation scores for different combinations of European hub prices over the 2007-14 period.

Chart 1: Average yearly correlation scores for OTC day ahead prices, 2007-2014 (%)

Source: OIES Analysis of Tankard Parties data

The first two groupings of correlation scores in the chart, illustrate the strong parallel movement of day-ahead gas prices within the well-integrated North West European hub grouping (TTF, NCG, GSL, ZEE, PEG Nord). This reflects the fact that in NW Europe there is adequate transmission capacity across hubs, no barriers to trade across borders, and a limited impact of anti-competitive behaviour. Shippers can take advantage of these conditions to exploit any short-term trading opportunities across hubs.

Strong price convergence and increased correlations have also hit trading book margins over the last few years. Whilst not so good for trader bonuses it provides clear evidence at a broad level of an efficient and well functioning market that ultimately will have benefited many European consumers. It also acts to highlight cases and the impact of temporary or structural price de-linkage.

Evidence of problems on the southern boundaries

The 3^rd, 4^th and 5^th grouping of correlation scores in Chart 1 tell a different story of price convergence between NW European hubs and some important peripheral pricing points. The lower correlation scores here reflect price de-linkages at the PEGS (Southern France), PSV (Italy) and CEGH (Austria) hubs. These are caused by barriers to trade that remain between these markets and NW European hubs, preventing full integration.

PEGS de-linkage: The nature of these barriers is primarily physical for France and Austria: de-linkages occur when there is physical congestion of the interconnecting infrastructure. For example PEGS de-links when physically separated from PEGN given congestion on the North-South (N-S) transport link. This has typically been due to LNG supply being diverted away from Europe, requiring consumption to be met by higher flows from north.

As the LNG market tipped into a state of oversupply in the second half of last year, the volume of cargo diversions from the south of France fell. The resulting increase in supply to this region restored a single price for gas within France as can be seen in Chart 2.

Chart 2: PEGS-PEGN OTC day ahead price spread (€/MWh) and utilization rate of the N-S link (%)

Source: Tankard Parties, GRTgaz

The prevalence of congestion issues on the French N-S link has already prompted the decision for investment in reinforcing the physical infrastructure, aiming at creating a single French market by 2018.

PSV de-linkage: Price de-linkage at the Italian PSV hub is a somewhat different story. Although the PSV premium increased significantly in H2 2013 and H2 2014, most of the time the route from the lower-priced NW European hubs to the Italian hub was not physically congested. For example in 2014, at least 20% of interconnection capacity was available and it was fully utilised only for limited periods in September.

Under-utilisation of transmission capacity linking the NCG and PSV hubs reflects contractual rather than physical barriers to trade as we have written about previously. Congestion has to some extent been alleviated by re-sales of pre-booked capacity on an interruptible basis carried out by TSOs and by ENI’s release of long term booked capacity through periodical auctions. But full price convergence with NW Europe requires regulatory attention to progress a further reduction in contractual barriers.

CEGH de-linkage: CEGH is significantly better integrated with NW European hubs than PEGS and PSV. But there are physical constraints that can arise that cause price separation. For example issues arose from the requirement to ship gas eastwards, due in part to reverse flow to Ukraine and Russia not meeting nominations in the summer of 2014. This led to frequent saturation of transmission capacity at Oberkappel, especially favoured by physical constraints on the German side (disparity between entry and exit capacity, plus pressure constraints in the MEGAL system). Offered interruptible capacity was not enough to solve the bottleneck between NCG and CEGH under these conditions.

Barriers to integration are expensive

Although they may appear relatively minor, the cost of de-linkages is not negligible. Some simple calculations below illustrate the increased costs of purchasing gas as a result of congestion in 2014:

Physical congestion between Germany and Austria ~ €60 million
Physical congestion within France ~ €240 million.
Non-physical barriers between NW Europe and PSV ~ €330 million

These numbers provide a clear incentive for regulators to ensure policy and capital is being directed in the right places.

A fully integrated European gas market will also require a degree of foresight. Market conditions are also set to structurally change over the next decade with declining domestic production, a new wave of LNG and a potentially changing Russian export strategy. These factors may drive a new set of congestion problems. The evolution of a fully integrated European gas market against the backdrop of these structural changes will require regulators to show proactive anticipation rather than reactive response.

Todays article was written by Beatrice Petrovich, David Stokes and Olly Spinks. Beatrice (Research Fellow at the OIES) has published a full paper on hub price correlation.

Risk management done the right way

Posted on January 18, 2016January 16, 2020 by David Duncan

A risk manager’s life is not an easy one. Their role by definition is one of vigilance and challenge. Yet a good risk manager can be a facilitator within the bounds of their control mandate, rather than a blocker.

Risk management in gas and power markets poses a particular set of challenges given the unique nature of these as traded commodities. But this does not justify the fact that in many energy companies, risk management is often accepted as a function with the negative purpose of tidying up after the ball has been dropped.

Risk management should be a commercially-contributing discipline. Achieving this does not need to threaten the independence and objectivity of a risk management function in pursuing its control mandate. A number of cardinal factors can be identified that should be developed purposefully to underpin a positive role for risk management. We explore these below.

Symptoms of the problem

Before addressing the solution we start with a quick summary of the problem.

It is a reality that dynamic commercial functions such as trading and origination do not enjoy being given the answer ‘no’. But this is not in itself the problem. There may be junior traders who do not appreciate the importance of maintaining a robust risk boundary, but their bosses usually get the picture.

Instead, problems typically stem from broader perceptions of risk management function weakness, including:

Remoteness
A lack of understanding of the business and its needs
Slow response to enquiries
Uninformative answers
A lack of authority and inadequate grasp of risk policy issues
An aptness to price risk conservatively
An ability to identify problems, without contributing to solutions

Some of these criticisms are an inevitable function of different vantage-points, responsibilities & incentives. But others often have some legitimacy. Importantly a number of these issues can be resolved and doing so is good for business (i.e. it saves risk capital and supports commercial value creation).

Key factors that underpin positive engagement

There are a number of factors that drive a positive and effective engagement between the risk management and commercial functions.

Diagram 1: 5 factors that underpin positive engagement

Source: Timera Energy

Authority:

The successful evolution of risk management within a company starts at the top. That means adequate resourcing, a clearly defined risk mandate and effective delegation of authority. Senior management support for risk management must be real and obvious (e.g. serious breaches mean serious discipline). Risk management also needs to be adequately represented at an executive level, something which is increasingly being facilitated in energy companies by hiring in executive level risk managers in a Chief Risk Officer (CRO) role. A constructive relationship between senior risk and commercial managers is the foundation of the other positive engagement steps described below.

Capability:

There is a well understood front office relationship between investing in good people and generating P&L. In contrast, risk management functions are often treated as operational cost centres. This can lead to key gaps in skills and expertise, including a lack of:

Business knowledge e.g. company business model, commercial goals/strategies, market understanding, knowledge of traded instruments
Analytical and technical competence e.g. ability to deconstruct and value more complex asset & contract exposures
Practical knowledge of policy e.g. being able to efficiently make decisions based on a solid grasp of the rules and their current application / interpretation in the business

It is difficult to plug these gaps by hiring bank staff without energy knowledge or energy people without technical risk management skills.

Adding value:

The capability described above can also add value to commercial functions (e.g. trading and origination). The most obvious example of this is a constructive engagement between commercial and risk functions to ensure deals are competitively priced within the constraints of the risk boundary. This can be via more effective pricing of embedded risk premiums or via the design of tailored products with better understood & managed risks. Origination is where this can really come into its own, particularly for complex or structured deals. Many of the best origination opportunities effectively involve selling a company’s risk management capability to a counterparty. This means that commercially-aware and creative risk managers are highly valued members of commercial teams. They facilitate conversations like ‘you can’t do it like that, but here’s another way’ or ‘it would be cheaper if you could do this instead’.

Sharp response:

Efficiency of response is an important service provided by risk managers. Commercial functions know that external customers like swift responses – it wins business. In turn they expect a similar response from their ‘internal customer’ relationships. For risk management this applies to decisions on policy rulings, valuation sign offs and new product & counterparty approvals.

Good process is key to success in this area. This means streamlining routine processes & decisions to the maximum degree possible, sometimes even to the extent of ‘automation’ (an aspect we will consider in a later blog post). It also means well-oiled and efficient communication between risk and commercial teams, and the constructive two-way sharing of information (e.g. on limit headroom and market events). Good risk management functions also exercise a degree of intelligent anticipation, where decision-support tools & methods are in place and calibrated before they are needed, not after.

Realistic conservatism:

A risk manager’s job involves providing an independent view on deal valuation and the quantification of risk (e.g. premiums for basis risk). This is not always an easy job. Conservative numbers kill business, while being too aggressive undermines the integrity of the risk management function. But finding an intelligent balance and backing it up with robust analysis engenders respect. A good risk manager can issue the challenge back to front office ‘bring us stuff in the right format, that is policy compliant and not covered in basis risk and we’ll be able to put a value on it cleanly & keenly’.

Implementing change

There is often no-one more acutely aware of the issues described above than the risk manager responsible for addressing them. But change requires a recognition of these issues at a senior management level, adequate resource allocation and the constructive support of commercial functions.

The implementation of change can also come with governance issues. For example the tight integration of risk managers with commercial staff can undermine the integrity of a risk management function. The contribution of risk management to commercial value-added can also be problematic given incentives and potential conflicts that can arise. In a subsequent blog post we will consider how these can be resolved within the commercially dynamic framework we are advocating.

A business is as strong as its weakest link and risk management is a key part of the chain, not just the hand-cuffs. Intelligently constituted, risk management can make a positive and valuable commercial contribution, at the same time as meeting the proper requirements of governance and control.

Article written by Nick Perry, David Stokes and Olly Spinks

Timera Energy provides tailored in-house workshops covering, among other areas, energy risk and portfolio management. If you are interested in finding out more please contact us.

US exports are now a reality

Posted on January 11, 2016January 16, 2020 by David Duncan

By all reports commissioning of Cheniere’s Sabine Pass terminal has been progressing smoothly and will export its first cargo in the next few weeks. This marks the start of the ‘1^st wave’ of North American export capacity that will reconnect the US gas market with the global LNG market. More than 80 bcma of US liquefaction capacity is now contracted and under construction. Behind this is a similar volume of ‘2^nd wave’ projects that are in an earlier stage of development.

US exports are set to drive a transformation in LNG market trading & pricing dynamics. This is because US export contracts are structured very differently to standard LNG supply contracts. They allow contract buyers to source gas on a Henry Hub rather than an oil-indexed price basis. They also allow buyers complete destination flexibility to respond to prevailing global spot price signals.

It is no coincidence that a substantial majority of US export volumes have been contracted by LNG portfolio aggregators. The inherent flexibility in US export contracts is set to be a catalyst for the evolution of LNG trading. As aggregators utilise contract flexibility it will drive both an increase in LNG market liquidity and in the influence of Henry Hub on global gas pricing.

The wave of new US export capacity

There is 83 bcma of committed US LNG export capacity which is contracted, has passed the Financial Investment Decision (FID) hurdle and is under construction. This includes the Sabine Pass, Freeport, Dominion Cove, Cameron and Corpus Christi projects. There has been much anticipation around the first cargo from Sabine Pass. But most of this 1^st wave of US export capacity is not scheduled to come on-stream until 2018-19.

In addition to the core 1^st wave projects listed above, there are several other projects (Lake Charles, Golden Pass, Jordan Cove) that have negotiated offtake contracts but have not yet given a clear commitment to proceed. The current state of oversupply in the global gas market will not help these projects, particularly when it comes to securing financing, but for the moment we include them as potential 2^nd wave candidates. All except Jordan Cove are ‘brownfield’ investments adding to existing facilities of regas import terminals which were ‘built in haste’ prior to the realisation of the shale gas boom.

Chart 1 shows a build-up of 1^st wave US export volumes, with the less certain projects on top. The bottom section of the chart shows a breakdown of capacity ownership for these projects. Some volumes have been contracted by Asian utilities. But the majority have been signed up by LNG aggregators & portfolio players. LNG export contract structures and a lack of fixed destination restrictions will greatly enhance the liquidity of LNG trading in the back end of this decade and early next decade.

Chart 1: Ramp up in US LNG exports

Source: Howard Rogers (OIES)

Impact of falling gas prices on US exports

There has been some confusion amongst LNG market commentators and the trade press as to how the current fall in global gas prices will impact US export projects. It is important to separate the impact of falling gas prices on:

Investment: i.e. the ability of new US export projects to contract and reach financial close, and
Flow: i.e. the LNG flow dynamics of committed projects once they come online.

Given that current Henry Hub prices are depressed by excess supply relative to US demand, one should not assume that by 2020, when the US may be exporting 80+ bcma of LNG, that Henry Hub will remain at present levels. Although estimates vary, $4/mmbtu is a more realistic view of the Henry Hub price needed to support the US production levels required to satisfy US demand and LNG exports in the longer term.

The Long Run Marginal Cost (LRMC) hurdle for new US LNG export projects is around $8.5 – 9.5 /mmbtu. This assumes a future long-term sustainable Henry Hub price of $ 4/mmbtu, the 15% premium to cover transport and feed-gas process consumption ($0.6/mmbtu), the export facility tolling fee of around $3/mmbtu and shipping/regas costs ($0.5 to $2.0/mmbtu). US netback price levels from current Asian and European LNG prices are well below this cost, meaning that new projects are going to struggle to reach FID until gas prices recover.

However this does not mean that the 1^st wave US export terminals will not flow gas when they come online. The flow decision for US export contracts will be driven primarily by two factors:

The variable cost (or SRMC) of US export contracts i.e. the Henry Hub gas price plus the (~15%) premium to cover transport and feedgas process consumption
The US netback from global spot price signals that represent the market value for exported gas, adjusted for appropriate shipping and regas costs from the US.

Chart 2: US Export flow utilisation and pricing dynamics

Source: Timera Energy

As illustrated in chart 2, As long as market conditions are such that 2. exceeds 1. then US gas will flow into the global market, constrained by the volume of US export capacity. The sunk capacity cost component of US export contracts (~3 $/mmbtu) will have no impact on flow decisions.

On a variable cost basis, US exports in the near term are still relatively cheap. Front month Henry Hub futures prices closed 2015 at around 2.35 $/mmbtu. Adding a 15% variable liquefaction cost premium gives an all in variable export cost around 2.70 $/mmbtu .

Falling fuel and vessel charter rates mean shipping & regas cost benchmarks are currently around 0.50-1.00 $/mmbtu to Europe and $1.50-2.00 to Asia. At the end of 2015, European spot hub prices are around 5.00 $/mmbtu and Asian JKM spot prices around 7.00 $/mmbtu. That means US netback prices of around 5.00 $/mmbtu. In other words US export contracts are still around $2.00 $/mmbtu in the money.

What US exports mean for the global gas market

The ramp up in US exports will have an important impact on the traded LNG market. Currently only a relatively small volume of global LNG supply has the contractual flexibility to respond to market price signals. BG estimates that only about 13% of contracted supply volumes are currently flexible as shown in Chart 2 (this is higher if you include uncontracted Qatari production volumes). US exports are estimated to almost double the amount of flexible contracted LNG to 25% by 2025.

Chart 2: Evolution of flexible (price responsive) LNG volumes

Source: BG

This ramp up in flexible LNG volumes will be a shot in the arm for LNG market liquidity. But flexible US export volumes will also have an important impact on global pricing dynamics by acting to drive:

Global price convergence: given US LNG will tend to flow to the highest price market on a netback basis.
Reduced LNG spot price volatility: given US exports will increase the volume of flexible gas to respond to fluctuations in global spot prices, dampening volatility.

It was assumed when US export contracts were signed that gas would primarily flow to Asia. But the Asian vs European price convergence that has prevailed in 2015 suggests that a substantial volume of US exports will now be sent to Europe, given a more attractive netback price.

The current discount of Henry Hub to Europe & Asia implies a baseload export profile for US LNG. But as LNG oversupply intensifies with the ramp up in new liquefaction capacity later this decade, it is possible that there is further compression in regional price spreads.

If spot LNG prices in Europe and Asia fall to the extent that they no longer cover variable liquefaction and shipping costs from US export terminals, it will start to choke off LNG flow from the US. This US export ‘shut in’ dynamic may become an important global price support mechanism if oversupply intensifies.

Article written by David Stokes, Howard Rogers & Olly Spinks

Global LNG and European gas workshop

If you are interested in more details please email olly.spinks@timera-dev.positive-dedicated.net

The UK’s dual capacity markets

Posted on January 4, 2016January 16, 2020 by David Duncan

There is an acute and increasing capacity shortage in the UK power market caused by the retirement of older gas and coal plants. This is being driven by ongoing weakness in thermal generation margins, due in part to increasing volumes of renewable output.

In response to security of supply concerns, the UK government introduced a capacity market in 2014. The aim of this intervention was to provide a reliable stream of income to support the flexible thermal capacity required to backup intermittent renewable output. But so far the capacity market has had the opposite effect.

Low capacity prices have contributed to the closure of existing thermal plants. At the same time the capacity market has incentivised delivery of very little in the way of new capacity. So the UK’s system reserve margin, rather than stabilising, continues to fall.

Security of supply is instead being maintained by a stop gap secondary ‘market’ for capacity known as Supplemental Balancing Reserve (SBR). SBR was designed as a temporary measure for the system operator to acquire emergency reserve while the government implemented a real capacity market. But SBR is increasingly becoming the real UK capacity market, by default rather than design.

Round two of the official capacity market

Quite a bit of analysis on the second auction outcome has already been published. So we do not intend to do a detailed deconstruction here. But we highlight a few important headline facts:

Clearing price:

In the client briefing pack we published before the 2^nd auction, we set out our expectations for the price to clear in the 10-15 £/kW range. We also set out a 20 £/kW upper bound driven by CCGT fixed costs and 5 £/kW lower bound driven by the risk adjusted value of waiting to the T-1 auction. The auction cleared at 18 £/kW towards our upper bound (as shown in Chart 1), driven by the bidding behaviour of older CCGTs. This was marginally below the 2014 auction but broadly in line with market expectations.

Capacity exit:

5.1 GW of older existing capacity was unsuccessful in getting capacity agreements. This consisted of 2GW CCGT and 3.1 GW coal plants. In many ways this is the most important outcome of the auction. Without capacity payments, the economics of these older plants is unviable, in the absence of other regulatory support.

New build:

Genuine new build capacity consisted of 1.1 GW of smaller scale peakers, with 0.5GW of DSR. A significant volume of this was in the form of diesel generator sets, causing the government some embarrassment from an emissions perspective. The 810MW Carrington CCGT was also successful in bidding for a one year ‘new build’ agreement, although this plant was only new build in a technical sense, given it is already close to completion.

Exited capacity:

A relatively high volume of capacity (around 8GW) exited the auction above 50 £/kW as can be seen in Chart 1. This included the larger scale new build CCGT projects in an indication that under the current market rules, the capacity price will need to rise significantly to incentivise CCGT new build. The new UK-Belgium NEMO Link interconnector project also failed to secure an agreement. This was unexpected given that the link will presumably be developed anyway given healthy economics & other regulatory support.

Chart 1: 2015 T-4 capacity auction outcome

Source: National Grid

In summary there were no real surprises from the auction outcome. Much more interesting will be what happens to the 5GW of existing plants that exited the auction. This capacity joins a growing list of older coal and CCGT plants that are queueing up for life support from the SBR mechanism.

The UK’s other capacity market

In 2015 around 5GW of capacity announced its intention to close, after failing to secure a capacity agreement in the first auction. Another 5GW of capacity has now been added to the endangered list after the second auction. That leaves a cloud of uncertainty hanging over security of supply in the UK power market.

Through this cloud there are two things that are clear:

The UK cannot afford to lose 10GW of capacity. This would send the system reserve margin deep into negative territory.
Neither the capacity nor the energy market is currently incentivising older flexible plants to remain open.

This is where the UK’s unofficial secondary capacity market comes in. The results of National Grid’s procurement of SBR capacity for Winter 2016-17 were released just before the T-4 capacity auction. These show Grid paying an average of 34 £/kW for 3.6GW of capacity, close to double the clearing price in the last two T-4 capacity auctions. In fact one large unit (500MW+) appears to have been paid an 88 £/kW capability price (higher than the price cap of the T-4 auction). In addition to these costs, Grid must also pay utilisation fees if the units are called on to run.

Can the status quo really continue?

A cynic could be forgiven for questioning the logic of these dual capacity markets. The main T-4 capacity auctions have been incentivising capacity to close, given clearing price levels below the fixed costs of thermal assets. But at the same time, the SBR mechanism is paying a substantial premium to ensure that the same plants remain open once they have failed to secure an agreement in the T-4 auction.

The inconsistencies and distortions that have plagued the UK power market since the implementation of the Electricity Market Reform (EMR) policies continue. The UK government seems to be wandering along an expensive path towards an increasingly centrally planned capacity mix. There has to be a smarter way to run a power market!

We suspect that the fallout from the 2015 capacity auction and SBR procurement will cause the government to step in with further policy interventions in 2016. We will come back shortly with our thoughts on how this may impact the UK power market going forward. But the winners from a changing rule book are likely to be the developers of larger CCGT assets, with the losers likely to be high emissions diesel and coal generators.

Article written by David Stokes & Olly Spinks

Hub pricing in a converging global gas market

Posted on December 7, 2015January 16, 2020 by David Duncan

There has been a pronounced downward revision of future price expectations across the global gas market as 2015 has evolved. This has been reinforced by falling oil price expectations. There is now growing acceptance that the current oversupply of gas is more than just a temporary phenomenon. Demand growth projections are weakening at the same time that large committed volumes of new supply are ramping up. The world is getting used to a new phase of lower and more convergent global gas prices.

At the start of this year we wrote about two key drivers of European gas pricing dynamics in an oversupplied world:

Falling oil prices, given the oil-indexation of long term European gas contracts
Increasing LNG imports, as Europe acts as a sink for surplus volumes of flexible LNG

In today’s article we revisit those drivers to assess the current state of the gas market, as well as looking ahead to implications for 2016.

Oil is weighing on hub prices

European hub prices have fallen from levels around 7.50 $/mmbtu at the start of the year to 5.50 $/mmbtu in Dec 2015 as shown in Chart 1.

Chart 1: Evolution of key global gas price benchmarks

Source: Timera Energy

So far there has been almost no evidence of the usual seasonal price recovery as winter approaches. That is partly due to a mild start to winter. But it is also driven by the fact that falling oil prices have dragged down oil-indexed gas supply contract prices as the year has progressed. This is illustrated by the falling German border price proxy for Russian supply contracts in Chart 1 (the purple line). The typical 6-9 month lag in contract indexation means that the oil price declines of summer 2015 are still feeding through in the form of lower gas contract prices.

We have set out previously why lower contract prices weigh heavily on hub prices. In the boxed section below we recap the importance of oil-indexed contract prices in driving hub prices.

Who cares about oil?

Oil-indexation remains a powerful influence on European and Asian gas prices, although one that is gradually eroding as long term contracts expire. In Asia, almost all LNG contract volumes are indexed to crude benchmarks (e.g. JCC, Brent). In Europe, despite a much publicised trend towards the spot indexation of gas, the majority of long term pipeline swing contracts also remain indexed to oil (primarily gas oil & fuel oil) – albeit moderated via price formula concessions and rebates which have become prevalent post 2008.

Oil-indexation has a particularly important influence on spot prices in Asia and Europe because of its influence on the exercise of contract volume flexibility. The ability to vary swing contract take is optimised based on the differential between oil-indexed contract prices and spot gas prices. When spot gas is cheaper than oil-indexed contract prices, contract volume take is reduced and incremental hub gas purchased (and vice versa).

This means that oil-indexed contract prices act as an important longer term anchor for gas prices. This relationship is a loose one over a shorter term horizon given the influence of other supply and demand factors. But oil-indexed prices act as a ‘magnetic ceiling’ and typically draw spot gas prices back in line in a reasonably balanced market. That said, a very tight market can see spot gas prices ‘break through’ this ceiling (UK in 2005/2006) although such occurrences are rare and transitory. Alternatively an oversupplied spot market can see hub prices disconnect below contract prices (e.g. as in 2009-10).

Another interesting dynamic across 2015 has been the shaping of ‘take or pay’ volumes of contracted gas. Gas buyers have utilised contract volume flexibility to shape volume take into the second half of the year. This is because of the price lag in oil-indexed contracts.

At the start of the year oil-indexed contract prices were at a significant premium to hub prices (given the delayed impact of falling oil prices). This provided a clear incentive to reduce volumes earlier in the year. But it has meant a ramp up in contract volume take as the year has progressed in order to comply with take or pay constraints. This is now weighing on prices as 2015 draws to a close.

Europe now at the center of the global LNG market

The current global oversupply of LNG increases the importance of the linkage between the European and global gas markets. Europe’s role as a market of last resort for surplus LNG means that European hub prices are a key driver of spot LNG prices globally. In turn, the evolution of oversupply in the global LNG market is having an important influence on European hub price dynamics.

Chart 1 provides a practical illustration of this linkage. Asian spot LNG price levels started 2015 above 9 $/mmbtu. But as LNG demand waned into spring, an absence of buyers saw spot prices quickly fall to NBP/TTF levels, reflecting the price at which European hubs could absorb surplus LNG cargoes.

LNG spot prices have stabilised across 2015 in a 6.50-7.50 $/mmbtu range. This represents a slight premium to European hub prices, but one that barely covers the transport differential to Asia. As a result, LNG import volumes into Europe have increased significantly.

The linkage between LNG and European hub prices is also being reflected in contract pricing terms, with NBP becoming the global benchmark for transaction price levels. For example pricing of the Egyptian and Jordanian tenders held in the second half of 2015 was driven by NBP, even though the contracts have been struck on a Brent indexed basis.

The Egyptian tender reflects another interesting dynamic in 2015. Although the much anticipated ramp up in global liquefaction capacity started in earnest this year with about 15 bcma of new supply coming online, there has been almost no net growth in LNG supply in 2015. This is largely because of a reduction in supply from existing exporters, particularly in the Middle East and North Africa e.g. Yemen, Egypt, Oman & Algeria.

But don’t expect this dynamic to continue into 2016! More than 40 bcma of new Australian and US LNG exports are due to come online across the next year, combined with an anticipated return in the Angola LNG plant. The wall of new supply to be commissioned from 2016-18 is set to become the real test of European hubs as a global gas price floor.

What does this mean for supply contract pricing?

Market conditions heavily influence the balance of power in gas supply contract negotiation. Gas producers held all the cards in the three years that followed the Fukushima disaster (Q2 2011 to Q2 2014). But price falls over the last 18 months have seen the balance of power shift firmly back in favour of contract buyers. Evidence of this shift can be seen via the increasing success buyers are having in purchasing gas contracts on a hub based pricing terms.

In the LNG market, hub indexation is becoming standard for the sale of short to medium term supply volumes (typically on an NBP or TTF basis). This has been helped by a number of LNG portfolio players which have been caught with surplus gas and been willing to offer relatively flexible indexation terms to shift volume. This has forced producers to follow suit in order to sell uncontracted LNG volumes. European buyers (e.g. E.ON) are now gaining traction in demanding hub indexation on long term LNG supply contracts into Europe.

Producers have also been granting concessions on European pipeline contract pricing. This is indicative of increasing competition between sellers in an oversupplied market. Falling prices have meant that LNG is now a credible alternative source of incremental supply for European gas portfolios. LNG contracts offer diversification benefits and increasingly flexible terms and European buyers no longer need to pay a premium to secure these. It is Russia that most acutely feels the threat posed by cheap LNG.

We end our thoughts for 2015, reiterating the importance of Russia’s strategy in an oversupplied gas market. Gazprom appears to be responding to increasing competitive pressure in a lower price environment. Oil indexation remains its headline policy for the moment, but beneath the ice the tide may be turning. Gazprom’s recent concessions on hub price indexation to a consortium of European suppliers supporting the development of the Nordstream 2 pipeline is a case in point. An increasingly flexible stance on pricing is not a case of Gazprom conceding defeat. It is just a pragmatic commercial response to an oversupplied market.

This is our last article for 2015. It has been another year of substantial growth in readership for the blog. We appreciate your support and are enjoying meeting an increasing number of you face to face at industry conferences and events. We are back at the start of January 2016. In the meantime we wish you all the best for the festive season.

Article written by David Stokes & Olly Spinks

Global LNG and European gas workshop

If you are interested in more details please email olly.spinks@timera-dev.positive-dedicated.net

Commodity price perspective: a 3 chart view

Posted on November 30, 2015January 16, 2020 by David Duncan

A seismic shift in commodity markets began in Q4 2014. From an energy market perspective this was focused on crude oil breaking out of its trading range above 100 $/bbl and plunging to under 50 $/bbl. But this was not an isolated oil market event. Global commodity markets have weakened in a highly correlated fashion suggesting that a bigger story is evolving. As Q4 2015 draws to a close, we take a step back to reflect on some key market benchmarks and what they may be point to in 2016.

What happened to the super-cycle?

Our first piece of evidence speaks for itself. Chart 1 shows the path of probably the most widely recognised global commodity index, the Reuters/Jefferies CRB Index.

Chart 1: The rise and fall of the super-cycle: CRB Index (1980-2015)

Source: StockCharts.com

As 2015 draws to a close, the CRB Index has broken below the level of its post-financial crisis plunge in 2008-09. In fact the commodity price index is back at the level of the 2001 trough in commodity prices (when oil prices fell under 20 $/bbl).

As striking as the absolute level of commodity prices is their rate of decline. The only commodity price fall that is comparable over the last 30 years is the 2008 collapse that followed the default of Lehman Brothers.

We have set out previously how the latest price decline has been caused by a substantial re-rating in forward projections of commodity demand, particularly in relation to China. This has been exacerbated by production development lead times, with new supply coming to market based on investment decisions made at much higher price levels several years ago.

This looks like a China problem

Our second piece of evidence is a key barometer of the health of the Chinese economy. Chart 2 shows the evolution of the Chinese Purchasing Manufacturers Index (PMI). Readings below 50 represent contraction. After bumping along at low growth rates for the last four years, China’s PMI looks to be heading into a more pronounced contraction as 2015 progresses. This is particularly the case for Chinese manufacturing output which is of key importance for commodity demand.

Chart 2: China Output PMI

Source: Markit, Caixin

Strengthening USD undermines a commodity price recovery

Our third exhibit relates to currency movements and their impact on commodity prices, specifically in relation to the US Dollar (USD). We described the key negative correlation between commodity prices and the USD in a previous article this year. This is illustrated in Chart 3 which shows an overlay of the USD Index versus front month WTI crude prices since 2000.

The chart shows that the sharp decline in crude prices in Q4 2014 coincided with a rapid strengthening of the USD against other major global currencies, most importantly the Euro. USD strength against the Euro in late 2014 was driven by the ramp up of European quantitative easing to support weakening economies, against a backdrop of a relatively resilient US economy.

Chart 3 shows the USD starting to rise sharply again in Q4 this year, reflecting expectations for ‘more of the same’. The US Federal Reserve now looks likely to embark on a rate hike cycle starting in December. But the European Central Bank appears increasingly inclined to move in the opposite direction, with more monetary easing on the horizon in 2016. If the USD continues to strengthen into 2016 it will provide strong headwinds for any recovery in commodity prices.

Chart 3: The inverse correlation between crude and the US Dollar (2000-2015)

Source: StockCharts.com

Looking ahead to 2016

The three charts above paint a pretty pessimistic picture of commodity prices heading into 2016. In fact together they present a reasonably compelling case for commodity price weakness to continue in 2016. But there are strong self correcting forces that tend to drive the cyclical behaviour of commodity markets.

Demand response to lower commodity prices is an important factor to watch. Future resource requirements can now be sourced at a fraction of the cost of even early last year. Ultimately sharp commodity price declines are supportive of economic growth in manufacturing intensive economies such as China and India. On the supply side, falling prices are choking off investment in new capacity. These factors are likely to form the foundations of the next cyclical recovery in commodity prices. But this may take some patience beyond 2016.

Next week we return to take a closer look at global gas pricing dynamics heading into 2016.

Article written by David Stokes & Olly Spinks