Blog Content Types: Featured Article

Major energy surprises of 2017

Posted on by David Duncan

At the beginning of 2016 we started a tradition of publishing 5 surprises to watch out for on the radar screen.  In 2016 we focused on major reversals in market prices given cyclically depressed market conditions. Our surprises included major price reversals in oil & German markets, a recovery in spark spreads and an energy credit shock.

After the market fireworks of 2016, 2017 has been a relatively calm year. But there has been no shortage of surprises along the way.

As 2017 draws to a close, we revisit the 5 potential surprises we set out in January.  We also use the benefit of hindsight to look at 3 other major surprises that turned heads this year.

Revisiting our 5 surprises from Jan

As we set out in Jan, our surprises are not forecasts or predictions.  They are areas where we think it is worth challenging prevailing industry consensus. A quick status check on each.

1. Macro shock – e.g. political upset, rising inflation &/or interest rates
In a sigh of relief from markets, Macron & Merkel prevailed and the Italian government limped through the year.  Broad based global growth continued and there were no major macro shocks to interrupt it.  However there was a step up in inflation in some European countries, e.g. UK breaching 2% target rate with Germany hovering just under 2%.  Watch for a reversal in monetary stimulus in 2018 if inflation continues to rise.

 2. Asian LNG demand upside surprise
Asian LNG demand growth was definitely one of the surprises of 2017.  This has underpinned a recovery in spot LNG prices in Q4 2017 to 10 $/mmbtu as Asian buyers have been competing for spot cargoes.  China has played a pivotal role with LNG imports increasing 40% vs 2016 as shown in Charts 1 & 2.  The surprise within China has been the effectiveness of the government’s pollution driven policy shift to gas. Despite the absence of market based mechanisms, the Chinese authorities have implemented a rapid shift to gas, focused on industry, space heating and some power-generation near key cities.

 Chart 1: Historical Asian LNG Demand

*Note: 2017 has been estimated by combining actual demand data up until the end of October with demand estimates for November and December.

Chart 2: 2016 vs 2017 Asian LNG demand

Source: Timera Energy

3. Growth in European gas & power M&A
There has been a steady pick up energy transactions activity flow in 2017. Fortum’s ongoing €8 bn bid for Uniper has featured (& may be the catalyst for further German portfolio restructuring). Utilities have also continued to sell assets e.g. Engie’s $1.5 bn upstream LNG portfolio sale to Total, DONG’s $1.3 bn oil & gas sale to INEOS and Centrica’s E&P and CCGT sales.  The proposed SSE/Innogy retail merger suggests that utility restructuring is set to continue.  There has also been a significant pick up in infrastructure & private equity fund competition to acquire energy assets.

4. Capacity payments becoming more widespread in Continental power markets
There was no watershed moment in 2017, but capacity price penetration continued to grow.  France joined the capacity market club in Jan 2017, with capacity prices for 2017 & 2018 clearing at 9-10 €/kW. Italian capacity market plans took a step forward this year. Some issues remain with clarifying the structure and pricing of the reliability options that will underpin Italian capacity pricing.  But these are likely to be resolved in 2018 to pave the way for implementation. The EU also turned up the heat on Germany to move to a more market based capacity solution, announcing a probe into its strategic reserve mechanism.

 5. Jump in value of gas supply flex
The UK gas market has seen a major shift in supply flex value in 2017. The permanent closure announcement of Rough storage has seen a step change in buyer interest to acquire flexibility. Part of this is portfolio repositioning to replace Rough capacity.  But there is a broader focus on accessing gas deliverability, particularly with the demand recovery driven by the power sector.  The UK transition has not yet spilled over into Continental gas markets, where seasonal price spreads remain structurally weak and spot volatility is well below UK levels.

Major 2017 surprises in hindsight

As well as those above, there have been 3 other surprises that have caught our attention this year.

1. Ongoing strength in coal prices
Despite the looming reality of ‘peak coal’, prices have had a very strong year in 2017. Spot European (ARA) coal prices have consistently held above 80 $/t and look set to close the year near 95 $/t. As with spot LNG price strength, the drivers are focused on China (responsible for half of global coal demand).  Chinese authorities have stuck to their policy announcements and significantly reduced the overhang of inefficient and unsafe domestic coal production.  This has seen a surge in Australian coal exports & prices, with a knock-on impact in Europe.

 2. Strong European gas demand
European gas demand is likely to rise around 6% in 2017 after a similar strong increase in 2016.  Power sector demand growth has played a pivotal role.  The coal to gas switching transition that took off last year, continued to gain momentum in 2017, helped by higher coal prices. French nuclear outages in Q1 supported higher gas plant load factors.  There were also unusually dry conditions on the Iberian peninsula which saw substitution of CCGTs for hydro capacity.

3. Renewable & battery cost declines
Wind and solar capacity costs continued to steeply decline.  UK offshore wind costs in the 2017 CfD auction (58 £/MWh) were half the level of the previous auction in 2015. Solar panel costs have continued to plummet, driven by cheaper Chinese production.  This was evident in the first non-subsidised UK solar farm at Flitwick (developed in combination with batteries). Battery costs have also fallen sharply with shorter duration lithium-ion batteries breaching the 200 $/kWh level.  Longer duration battery costs are falling too, but are still well short of levels that support widescale commercial deployment.

These surprises set up some of the issues on our radar screen for 2018.

Timera news

The Timera team has been growing in 2017.  New members include:

  • Phil Robinson, previously the commercial head of UK power producer Calon Energy, who will play a key role in growing Timera’s power advisory business.
  • Henry Crawford, coming from a gas trading and analytics background from Nova Energy, who is strengthening our commercial analysis expertise.
  • Sonia Youd, previously commercial director of Centrica Storage Ltd, who is providing commercial subject matter expertise to support our midstream gas work.

Their experience is also feeding valuable additional insights into our blog material.

Our client base has continued to expand in 2017 with new clients including Fluxys, Interconnector UK, Sembcorp, Arcus & Stonepeak Infrastructure.  Transaction work with existing clients has also been a focus this year, advising on acquisition & development of flexible power and midstream gas assets.

We launched a new blog format in August 2017, with the addition of two new columns (Angle & Snapshot) and a revamped Blog Archive.  The additional content has been well received with a big jump in blog subscriptions, allowing free access to a weekly subscribers list of new content. We are also publishing blog content now via Linkedin & Twitter.

This is our last feature article for 2017. We will back in early Jan with 5 new surprises for 2018.  In the meantime we will be continuing to publish material via the Angle and Snapshot columns. We have also published a briefing pack on LNG market transformation over the next 5 years (see link in blue box below).

All the best for a relaxing and enjoyable festive season.

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

 

Asian portfolios drive LNG contracting evolution

Posted on by David Duncan

Asian demand growth has never been more important for the LNG market.  Two credible scenarios bound the range of likely outcomes:

  1. High demand – where demand growth broadly keeps pace with currently contracted supply
  2. Low demand – where a significant surplus of LNG emerges vs contracted positions by 2020.

In either scenario the LNG market needs substantial volumes of new supply in the first half of next decade.  But it is the pace of Asian demand growth that will determine whether new LNG will be required by 2020-21 or 2023-24.

This timing is key given a hiatus in new liquefaction project FIDs and 4 to 5 year lead times to bring new supply to market. To date there has been limited willingness by either producers or buyers to invest or contract in anticipation of a high demand scenario.

In the meantime, Asian portfolio positions are helping to drive a rapid evolution in the way LNG is contracted.  Over contracted buyers are selling surplus volumes (e.g. Japanese utilities).  Under contracted buyers are purchasing spot cargoes (e.g. China).

This is supporting a transition to shorter term LNG contracting and hub-linked pricing. It is also eroding the dominance of long term oil-indexed supply contracts.

The ‘Big 5’ Asian buyers

The top 5 buyers (Japan, Korea, Taiwan, China & India) make up more than 90% of Asian LNG demand (173 mtpa in 2016).  Growth dynamics across smaller buyers (Thailand, Malaysia, Indonesia, Singapore & Pakistan) are strong, but these countries currently only account for 13 mtpa of demand.

Chart 1 shows the historical and projected net long term contracted position of the Big 5.  2017 has seen strong demand growth (12% vs 2016), driven particularly by China. This has been consistent with a high Asian demand growth scenario.

If growth were to continue on this trajectory then the net over-contracting of Asian LNG portfolios is likely to be limited. A low demand scenario could see a more than 20 mtpa surplus evolve over the next three years, much of which may be sold at European hubs.

Chart 1: Big 5 Asian net contracted LNG position vs demand

Source: Timera Energy.

Note: Charts show future contract volumes as signed on an ACQ volume basis. In practice there may be some flexibility for buyers and sellers to negotiate lower contract volume take, particularly over summer periods.  

All eyes on China

China is the key driver of Asian demand growth uncertainty. There is a credible range of 25 mtpa between low and high Chinese demand paths by the beginning of next decade, as shown in Chart 2.

Chart 2: China’s contracted LNG position vs demand

Source: Timera Energy

2017 has been a strong growth year for Chinese demand, consistent with the high demand scenario.  This has seen Chinese buyers actively sourcing spot cargoes this year. But that does not necessarily mean a further 3 years of growth at this pace to follow.

Persistently high coal prices have helped support Chinese LNG demand this year.  2017 has also been important in the Chinese political cycle, given the lead up to the 19th National Congress which saw Xi Jinping consolidate his power. There has been a strong associated incentive for the incumbent Chinese leadership to support economic growth.

Looking forward, the pace of Chinese economic growth remains a key factor.  But LNG demand is also set to be influenced by a combination of coal price levels, pipeline volume take, responsiveness to prevailing LNG spot prices and a pollution driven policy shift towards gas.

Japanese positions key to LNG contracting innovation

Beneath the net position of the big 5 buyers, there are some more substantial contractual imbalances in Japan and South Korea. Chart 2 illustrates this issue, with Japan facing a 15-20 mtpa contract surplus by 2019.

Chart 3: Japan’s contracted LNG position vs demand

Source: Timera Energy

The surplus of contracted LNG in Japan and Korea is driving a rapid commercial evolution amongst utilities. Buyers are trying to negotiate increased flexibility in legacy supply contracts e.g. allowing cargo resales and relaxing destination clauses.

But Japanese & Korean buyers are also increasing their focus on short to medium term contracts to manage LNG portfolio exposures.  This is evident in the current push by Japanese utilities to expand their LNG trading & optimisation capabilities to manage:

  1. Over-contracted positions, with surplus LNG being priced against European hubs
  2. The ramp up in flexible hub-indexed US export contract volumes, with forward exposures that are managed against US and European hub prices.

LNG market liquidity is also being boosted by rapid growth in the role of commodity trader intermediaries (e.g. Gunvor, Vitol, Trafigura & Glencore). These players are injecting innovation and expertise developed in oil and other commodity markets.

This evolution of the LNG contract market is driving a virtuous cycle which is acting to increase the influence of hub price signals.  It is also seeing Asian portfolios shifting their focus to the west, in order to access liquid US & European hubs to manage portfolio exposures.

Funds taking on market risk to boost returns

Posted on by David Duncan

Investment funds have made a big push into European energy infrastructure this decade. This has been fuelled by a search for yield in a record low interest rate environment. But yields on regulated infrastructure assets are now also being driven down to historically low levels.

A key issue is that energy infrastructure investors are competing with utilities for the same sort of assets and development projects. In both cases capital preservation is key. And this has meant a focus on regulated or long term contracted assets, for example ‘feed in tariff’ or CfD protected renewable assets and regulated or contracted pipes and wires.

However as regulated asset yields compress further into single digits, infrastructure investors are being forced out along the risk curve. Alternative pools of capital are also being formed with a more open investment mandate than that of classic infrastructure funds.

The search for yield is driving a greater tolerance for market risk exposure. And this is becoming evident in the types of assets that fund investors are targeting (e.g. conventional power assets, gas & electricity storage, pipelines & regas).

Investment funds targeting European energy assets

In Table 1 we have grouped funds that are active in European energy infrastructure into 3 categories based on capital type, target returns and risk appetite. We have also provided some examples of specific funds and transaction case studies.

Table 1: Summary of investor categories

Investment drivers Fund examples Transaction examples
Infrastructure & pension funds Focus on capital preservation. Regulated or contracted cashflows. Low market risk tolerance. JP Morgan, Ardian, iCON Infrastructure, Allianz Capital Partners Denmark PKA pension fund wind investments. Allianz Capital Partners acquisition of Gas Connect Austria.
Alternative infrastructure & Sovereign Wealth Requirement for a base level of secure cashflows (e.g. from capacity payments). Some market risk tolerance to increase returns. Macquarie, Blackrock, Brookfield, ADIA, CKI Macquarie UK CCGT acquisitions. Fund investment in UK peakers (e.g. Infrared, AMP). Brookfield acquisition of Mitsui stake in First Hydro pump storage.
Private equity Comfortable with market risk. Need clear value growth & exit strategy. Business model efficiencies also important. KKR, Riverstone, ECP, Blackstone, Warburg Pincus ECP acquisition of UK CCGTs. KKR acquisition of French CCGTs. Star Capital development of Eleclink interconnector.

Source: Timera Energy

Infra & pension funds

The investment mandates of infrastructure & pension funds drive a focus on protected cashflow. Risk tolerance of these funds is steadily rising, for example taking on greater development or regulatory risk. But any assets with significant exposure to market risk struggle to make it past the investment committee approval stage.

Alternative infra & sovereign wealth

A recognition of this challenge by some of the larger infrastructure fund managers has seen new pools of capital emerging. This can be in the form of ‘special situations’ funds, or alternatively via raising specific capital to pursue a target asset or portfolio.

Behind this transition are institutions, sovereign wealth funds and individual investors who are also being pushed into riskier asset classes to boost returns. As long as the low interest rate environment persists, energy asset acquisitions from this category of alternative infrastructure capital is set to grow. But the key challenge these funds face is how they manage market access, hedging and optimisation of assets post acquisition.

Private equity

Private equity funds are already big owners of energy infrastructure in the US. Step forward five years and it may be the same in Europe. Value growth and a clear exit strategy are key. But these funds have a strong tolerance for market risk, which can either be managed via in-house trading functions or outsourced via market access contracts.

Private equity backed acquisitions of European energy assets have been more opportunistic to date. These have included for example KKR, ECP and Castelton’s acquisition of CCGT assets. PE funds have also been active with oil & gas assets e.g. upstream and midstream acquisitions from Blackstone, Riverstone, Hitec Vision & Warburg Pincus.

As utilities and producers continue to offload energy assets, we are set to see a shift from opportunistic purchases to structural growth in private equity asset ownership in Europe.

 

Taking nuclear life extensions seriously

Posted on by David Duncan

France has reignited the debate around nuclear power plant closures in Europe this month. The French government has just reneged on its promise to reduce the nuclear share of generation output from 75% to 50% by 2025.

Why? Nuclear closures of that scale and pace cannot realistically be replaced by renewable generation. So the practical impact of the closure policy would have been to commission a fleet of new gas-fired plants in order to maintain security of supply.

France’s decision may mark the start of shift towards a more pragmatic stance on nuclear life extensions across Europe.

Nuclear closures in numbers

North West Europe could lose more than 40GW of nuclear capacity, based on the current retirement schedules of regulators and policy makers. And this is after accounting for the recent French policy shift.

In Chart 1 we show closures across Germany, France, UK and Belgium. This does not include other European markets also planning to close nukes such as Sweden and Switzerland.

Chart 1: Scenario of Nuclear closure assumption in NWE

Source: Timera Energy

The scenario assumes:

  • All German reactors are closed by 2022 as currently scheduled.
  • UK reactors close at the end of their currently regulatory approved lives (accounting for EDF life extensions granted in 2016).
  • Belgium closure of Doel & Tihange plants between 2023-25, consistent with 2015 legislation.
  • France closes 16GW of nuclear capacity by 2030, broadly consistent with achieving the 50% output target (with closures focused in 2025-30 period).

It is important to note that the chart is not our projection of what is going to happen. We expect a significant policy shift to reduce and delay nuclear closures via life extensions. We set out the logic behind this below.

The German closure case study

Germany permanently closed 8GW of nuclear plants after the Fukushima disaster in 2011. The closure of the remaining 11GW of German reactors by 2022 looks politically difficult to reverse. Yet Germany is a case study of the unintended consequences of rapid closures.

German nuclear output has predominantly been replaced by incremental coal-fired generation, either from within Germany or imported from its Eastern neighbours. This is a key factor driving Germany towards a substantial miss of its 2020 emissions target, with a projected deficit of more than 100 mt per year of CO2. Closures are also causing major transmission stress issues, supporting the life extensions of thermal assets via Germany’s strategic reserve mechanism.

There has been a degree of political dishonesty in the German nuclear debate, whether intended or otherwise. The proposition put to the German people was the replacement of nuclear plants with renewables. This has not been the outcome, despite Germany’s major ramp up in renewable investment. And it was unrealistic to suggest it could have been.

Replacing nuclear with what?

The key fact that is being glossed over in the political debate, is that the closure of a nuclear plant requires a much larger replacement volume of renewable capacity to maintain security of supply and carbon neutrality.

European security of supply standards are based on an equivalent firm capacity logic, where different types of plants are de-rated based on output and availability. Nuclear typically receives a capacity credit of around 84%, wind around 22%.  So for example replacing 40GW of nuclear plants with wind alone requires 150GW of incremental wind capacity development in order to maintain the same level of system security of supply.

In practice, nuclear closures are being replaced by a combination of renewables and fossil fueled output (whether domestic or imported). But the incremental impact of closures is heavily skewed towards fossil fueled plants, given cost & resource constraints around the rollout of renewables.

The German closure case study is starting to unveil these inconvenient facts. As a result, we believe other European countries are likely to shift towards a more pragmatic approach. This month’s decision by the French government is evidence of that shift.

The case for life extensions

Nuclear closures are a complex political issue. But we see three key incentives aligning to support the case for life extensions:

1. Decarbonisation: Europe is pushing to lead the global decarbonisation effort. Removing an existing high load factor, low carbon source of generation is akin to chopping off a limb before going into battle. Germany is evidence of the fact that closing reactors makes emissions reduction much harder.

2. Security of supply: There is very low public and political tolerance for blackouts. Closing baseload nuclear plants at the pace projected in Chart 1 creates a major system capacity deficit. This cannot practically be filled by wind and solar at the rates required. This precipitates a requirement to build new gas plants with economics lives of 20-25 years, at least until load shifting batteries can be rolled out in scale. This does not help with decarbonisation.

3. Commercial: Nuclear plant owners are commercially incentivised to extend lives (e.g. EDF is pushing for at least 10 yr extensions across its fleet). Most nuclear plants are currently very profitable given low variable costs. The commercial incentives of larger commercial and industrial consumers of electricity are also aligned, given the competitive implications of higher power prices caused by nuclear closures.

The nuclear versus renewables debate has become too polarised. The nuclear industry is preoccupied with trying to demonise renewable intermittency. And a dogmatically anti-nuclear ideology dominates the renewables lobby.

Europe should be focusing on closing coal not nukes if it wants to decarbonise. And that is a path that suits both nuclear and renewables supporters well.

Looking forward, Small Modular Reactor (SMR) technology may transform public perceptions of nuclear safety over the next ten years. As this technology matures, the orderly replacement of Europe’s nuclear fleet looks increasingly viable.

Life extensions are the bridge that buys time for this to happen. A 10 year life extension of the non-German nuke fleet could push 30 of the 40GW of closures from the 2020s into the 2030s. If Germany changed tack this could be more than 35GW.  Buying 10 years of low carbon innovation and cost reduction is not a pro-nuclear standpoint.  It is common sense.

Oil price animation shows bulls taking charge

Posted on by David Duncan

Crude prices have broken through some key resistance levels over the last two weeks.  Brent front month futures pushed above 60 $/bbl for the first time since Jan 2015. This helped drag the US WTI benchmark above 55 $/bbl shortly after.

This bullish breakout in oil prices comes against the backdrop of an intense energy industry debate about the long run future of oil.  Many senior industry participants are projecting ‘peak oil’ to occur at some stage next decade.

The logic behind peak oil projections is an anticipated decline in the use of oil as a transportation fuel.  This is the result of the increasing penetration of fuel-efficient engines and electric vehicles.  The arguments to support this logic are sensible and it is interesting that the peak demand thesis has now surpassed the peak supply narrative.

But there is an important question of timing.  Over the remainder of this decade, there are stronger forces driving the oil market than a fear of peak demand.

Strong demand & cuts rebalancing market

Global oil demand growth is strong and has been so for three years.  Global demand rose by 2.0 million barrels per day (mb/d) in 2015 and 1.6 mb/d in 2016.  Demand growth for 2017 is forecast to be 1.6 mb/d.  Demand is being supported by lower prices and relatively strong global economic growth since 2015.

On the supply side, OPEC’s production cuts are helping to steadily erode global oil inventories.  The current production cut agreement expires in Mar 2018 with a meeting on Nov 30th likely to see OPEC extend cuts beyond this.  OPEC have indicated a willingness to extend, possibly by 6 to 9 months, and this has been a key factor supporting the recent price rally.

The excess of OECD oil inventories over their 5 year average levels has fallen by more than 50% in 2017, with inventories currently at around 160 million barrels. If current trends continue, inventories are likely to return to the 5 year average at some stage in 2018.

What are crude futures prices telling us?

Oil market sentiment has been weighed down by bearish supply side drivers for the last two years.  This has reflected the threat of lifting of OPEC production caps (or non-compliance), given significant production headroom particularly from Saudi Arabia and Russia.  Large incremental volumes of US unconventional oil production also loom over the market.

But despite these supply side threats, crude price behaviour in 2017 is being driven by a tightening global market. Chart 1 shows an animation of the monthly evolution of the Brent futures curve over the last 10 years.

Chart 1: Brent curve animation

 

Source: Timera Energy, ICE data

Chart 1 illustrates three important factors that point to a tightening market:

  1. Spot price strength: Both key global crude price benchmarks have broken above resistance levels that have defined the top of trading ranges since the Q1 2016 price slump (Brent above $60 and WTI above $55).
  2. Shift to backwardation: The Brent curve has swung from contango to backwardation in Q3 2017. Contango typically indicates a near term oversupply, with spot prices at a discount to the curve. Backwardation on the other hand indicates buyers are willing to pay a premium to secure physical supply today, rather than waiting to buy it more cheaply in the future.
  3. Rising calendar spreads: The oil market focuses on the price spread between the spot contract and a point further out along the curve (e.g. 6 mth or 12 mth) as a curve shape barometer for a tightening market. Calendar spreads have been increasing for three years as the market has swung from contango to backwardation and are currently at their highest levels since 2014.

US shale is still key swing provider

Strong demand has helped to rebalance the oil market from 2015-17.  Further demand growth strength through 2018-19 looks key to determining whether the market continues to tighten, or falls back into a 40-60 $/bbl Brent range.

But even in a tight scenario, oil prices are unlikely to run away to the upside.  WTI remains anchored by the scale of response of incremental US shale production.  If the WTI curve pushes significantly above 50-55 $/bbl then US producers can sell into the rally to hedge forward production expansion.

There may be a 6 month lag to bring new US production to market.  But market tightness over this horizon is likely to be reflected via steepening backwardation rather than a structural move higher in the futures curve (e.g. back towards $70).

The ability of OPEC to respond to higher prices will depend on the conditions under which it extends the production cap.  A longer extension (e.g. to Dec 2018) could precipitate further near term tightening.  But at the end of the cap horizon it is unlikely that OPEC will sit back and watch US producers dominate incremental supply growth without a fight.

Cracking the new US export business model

Posted on by David Duncan

48 mtpa of 2nd wave US export projects are queued to go.  They have sites, FERC approval and in many cases good access to infrastructure and skilled labour.  Behind this are at least another 50 mtpa of projects currently progressing through the FERC approval process.

The problem these projects face is a lack of long term offtakers.  Only one 20 year LNG supply agreement has been signed so far in 2017 and it was small (1 mtpa between Edison and Venture Global, developers of the Calcasieu terminal, yet to get FERC approval). Buyers are instead pushing for shorter term contracts with greater flexibility, for example the 2.5 mtpa 3 year offtake contract Petronas signed In October with JERA.

LNG is currently a buyer’s market.  The pace of comitted new supply is for the moment outstripping expected demand growth and is likely to continue to do so until at least 2020-21. This is driving liquefaction project developers to adapt and innovate in order to build a robust business model to underpin investment in the next wave of export capacity.

Balance shifting from sellers to buyers

Table 1 summarises five key concerns of LNG buyers and the implications of these concerns for sellers in developing a viable project business model.  The table applies not just to second wave US export project developers but more generally to all investors in new liquefaction capacity.

Table 1. LNG buyers concerns & implication for sellers 

Buyer Concern Implications for sellers
1. Contract duration LNG market transitioning to shorter term contracting. Buyers unwilling to sign 15-20 year offtake contracts. Tough to find long term contracts to underpin financing.  Constrains debt financing opportunities. Pushes risk onto equity.
2. Price level Buyers unwilling to sign contracts at price levels that cover supply LRMC. Demand of some emerging buyers price sensitive. Market price recovery has become a producer’s problem.
3. Price indexation Increasing preference for gas hub vs oil indexation. Producers losing option to link LNG contract pricing to oil.
4. Market risk 1. 2. & 3. combine to undermine buyer appetite for taking long term market risk (e.g. via US export tolling model). Market risk pushed onto upstream equity investors.  Increases focus on supply chain presence to access market & monetise gas.
5. Flexibility terms Buyers want diversion flexibility & ability to resell cargo to support portfolio optimization. Access to LNG supply chain flexibility transitioning from seller to buyer.

Source: Timera Energy

 

There is no magic – success comes down to low costs & high flex

Charif Souki kickstarted the 1st wave of US export projects when he set up Cheniere.  He left there in 2015 and has been doing his best to catalyse the 2nd wave via his new company Tellurian.

The business model Tellurian are proposing involves an integrated presence across the supply chain from upstream equity gas, through liquefaction to shipping, marketing & trading.  Tellurian is trying to convince buyers to not only sign up to LNG offtake, but also to provide 65-70% of project equity. This is only one example of a range of business model innovations currently being undertaken by prospective US project developers.

In our article last week, we set out why a successful next wave LNG supply project was all about:

  1. Achieving the cheapest delivered gas cost, while
  2. Offering buyers maximum flexibility

Acheiveing this largely comes down to low cost of capital, ability to execute new terminals efficiently and having an established trading and supply chain presence.

We are not convinced by some of the other arguments being put forward to support project economics. For example:

  • Treating US gas production on a cost basis, versus recognising its market value measured against US hub prices (e.g. Henry Hub or Dominion South)
  • Viewing required project return on an aggregated cross supply chain basis, versus looking at the return required on individual elements of the supply chain
  • Assuming that extrinsic value from cargoes (e.g. from destination flex) accrues to the liquefaction project as opposed to the marketing and trading function required to monetise it.

So what ingredients are likely to drive a viable next wave project business model?

Driving down costs & increasing flex

Chart 1 shows our view of how the cost structure of a 2nd wave US export project may compare to a 1st wave project.  Again there is no magic.  Numbers are falling based on investor expectations of declining costs of liquefaction and feedgas.

Chart 1: Long run marginal cost of 1st vs 2nd wave projects

Source: Timera Energy

One of the key changes likely to feature in 2nd wave business models is the internalisation of project costs and exposures.  This is facilitated by an integrated supply chain presence from upstream equity gas through to active marketing & trading.

This model stands in stark contrast to 1st wave US export project developers that used tolling contracts to outsource the costs and exposures associated with getting gas to and from the terminal.

Cost & exposure internalisation means that 2nd wave FID decisions are likely to be based on equity investor’s expectations of market prices (US hub and LNG spot prices) and project costs, rather than depending on the external pricing of tolling contracts and non-recourse debt.

Investment likely to be dominated by large players

The shifting behaviour of LNG buyers is pushing 2nd wave developers towards a more merchant oriented marketing model.  Limited availability of long term offtake contracts means market exposures are likely to be managed via a combination of shorter term contracts (e.g. 3 to 5 years) and spot cargo optimisation.

What does it take to finance liquefaction projects with retained market exposure like this? In short: big balance sheets and an ability to price and manage market risk.

That points to oil and gas majors and large LNG portfolio players with an existing supply chain presence as the main sources of next wave project equity.  These companies have lower equity hurdles and can raise incremental corporate debt faster and cheaper than independents relying on non-recourse financing from banks.

In addition to low cost of capital and ability to retain & manage market risk, there are some genuine sources of cost advantage that large players can access via an integrated supply chain business model.  For example:

  • Avoiding transaction costs, by moving gas through the supply chain instead of having to transact in the market e.g. bid/offer spread and credit risk costs.
  • Accessing relatively low cost commercial capability to monetise cargo value, via existing LNG marketing and trading functions.

That said it is important to recognise that incremental value generated via commercial optimisation of cargoes accrues to the marketing and trading business, not to the liquefaction project.

What happens next

There is one clear hurdle hindering the progress of 2nd wave US exports.  The current ownership structure of projects does not reflect the backing of large gas and LNG players.  Aside from Golden Pass (Qatar Petroleum, Exxon & Conoco), 2nd wave ownership is skewed towards specialist developers and smaller scale players.

This suggests to us that a period of project consolidation, aggregation and change in equity ownership is approaching fast. This process should help sort out a more credible subset of viable projects, with a number of 2nd wave options unlikely ever to be commissioned.

Changes in ownership do not mean that existing owners will be cut out entirely.  But the balance sheets and supply chain presence of large players is required to propel 2nd wave projects past FID. How this is facilitated in practice is the next real challenge for US LNG.

Where will the next wave of LNG supply come from?

Posted on by David Duncan

The 2015-2020 wave of new LNG supply has been built on Australian and US export projects. Australian liquefaction projects were underwritten by long term oil-indexed contracts with Asian buyers. In contrast, US terminals were financed off the back of long term Henry Hub indexed tolling contracts that pushed US gas price risk onto LNG buyers.

Both these models now appear to be ‘broken’. In the current market environment there is little interest from Asian buyers or LNG portfolio players to sign new long term contracts on either basis.

Many Asian LNG importers are already over-contracted, particularly in Japan, China, India and South Korea. Projecting future LNG requirements is also challenging given uncertain energy demand and policy-induced changes to the energy mix.

Liquefaction project developers are also confronted by a gap between LNG spot price expectations and prices required to support the cost of investment in new supply.

Yet the LNG market needs investment commitments for new liquefaction projects to be made before the end of this decade to avoid a supply squeeze in the early to mid-2020s. This sets up an interesting dynamic around the ‘next wave’ of new LNG supply projects.

Next wave characteristics

A successful investment & business model for ‘next wave’ LNG projects is yet to be defined. But it is likely to reflect the following characteristics:

  • Market risk: New supply will be dominated by projects whose investors do not require long term contracts i.e. equity investors will need to bear market risk.
  • Cost of capital: Cost of capital will be key to keeping project costs down. This is likely to drive a focus on robust balance sheets and low debt costs rather than project finance.
  • Reserve access: Investors looking to monetise existing upstream reserves, with infrastructure access to terminals are likely to dominate.
  • Market access: An absence of long term contracts means a greater importance of LNG supply chain presence and capability to monetise cargoes directly in the market.

These factors point towards oil & gas majors and large LNG portfolio players dominating the next wave of supply .

Competition for marginal supply

Chart 1 shows our estimates for the long run marginal cost (LRMC) of key generic sources of potential new LNG supply.

Chart 1: Next wave LRMC by supply source

Source: Timera Energy

Qatar

Qatari expansion options are at the head of the cost curve. Qatar has announced its intention to lift the 2005 moratorium on LNG export expansion and develop 23 mtpa of new supply over the next 5-7 years. Based on reported condensate yields, we estimate delivered LRMC of 5 $/mmbtu for this LNG, assuming 1 $/mmbtu for shipping and regas costs into Europe or Asia.

However it is our understanding condensate & LPG yields could be significantly higher (e.g. based on data provided by the Qataris in the late 2000s), in which case LRMC could be lower. Qatar may also be able to increase exports via relatively low cost debottlenecking of supply into its existing trains.

There is no doubt that Qatar is the cheapest source of new global supply. But expansion volumes are not enough to meet global demand growth. That means Qatari supply sits below the expansion options likely to drive the marginal cost of new supply.

US LNG

There is a growing consensus that US unconventional gas production can meet US consumption as well as LNG export volume requirements at Henry Hub prices of around 3.00-3.50 $/mmbtu. We have assumed a 3.00 $/mmbtu cost base for Chart 1.

US export contracts signed to date have included a 15% variable liquefaction fee. But this has included some margin for terminal owners. The true variable costs of liquefaction (e.g. costs of gas consumed) are closer to 10% (i.e. $0.30 at $3.00 Henry Hub).

The liquefaction tolling fee in existing contracts was $2.50 in early contracts, rising to $3.50/mmbtu in later contracts. But there is mounting anecdotal evidence that fixed and capital costs for the next wave of terminals may come in under even  the lower end of this range. Costs can be driven down by standardising terminal design rather than pursuing the specific site designs deployed to date. We assume 2.00 $/mmbtu for brownfield sites and $2.50 for greenfield sites.

We then assumed long run marginal shipping and regas costs of 2.00 $/mmbtu to deliver gas to Asia. That gives all in LRMC estimates (delivered into Asia) of:

  1. Brownfield: 7.30 $/mmbtu
  2. Greenfield: 7.80 $/mmbtu

Second wave US export projects look to be an increasingly competitive source of new supply. But ownership structures and business models may need to evolve to support new FIDs.

Russia

New Russian LNG supply also looks relatively cost competitive. But supply is likely to be limited to two projects.

Yamal LNG benefits from large onshore arctic fields (Russia’s core expertise). Yamal LNG comprises three trains each of 5.5 mtpa, the first of which comes onstream late 2017/early 2018. Arctic LNG (also known as Artic LNG II) may reportedly be able to supply up to 18 mtpa.

Russian state infrastructure funding and good project executions would support a delivered breakeven cost or around 8.0 $/mmbtu.

East Africa

There have been huge (dry gas) discoveries in East Africa. But progress to achieve development frameworks for investment have been hampered by government capability and opposition opportunism. The offshore Coral LNG project (Eni, Anadarko) is moving towards construction. However the likelihood and timing of other land based liquefaction projects are less certain.

Our estimates of delivered cost into Asia for an efficiently executed project is $8.5/mmbtu. This may increase to $9.5/mmbtu if additional infrastructure spend is required (or cost overruns).

Australia Brownfield

With cost reductions by competitors, new Australian supply projects are looking increasingly compromised. Further east coast export options are constrained by a shortage of feedgas. West coast and northern options suffer from expensive labour costs and/or incremental infrastructure requirements.

We estimate generic feedgas costs at 4.5 – 5.0 $/mmbtu, with a further $3.4 – 4.0 of liquefaction costs. Add on transport to Asia and project breakevens look to be in the 9-10 $/mmbtu range.

Canada

The economics of Canadian LNG projects are eroded by the relative distance of gas supply from export terminal access. Costs are also impacted by the complication of gaining ‘First Nation’ and environmental approval for pipeline corridors and navigation of an overlapping approval, regulatory and fiscal system. In addition the availability of sufficient skilled labour for liquefaction project construction is questionable which adds to the risk of cost escalation.

We estimate feedgas costs including transportation to the terminal at 4.5 $/mmbtu and greenfield liquefaction costs of another 4.5 $/mmbtu. That means a delivered cost into Asia of 10 $/mmbtu.

Summary of new supply options

The analysis above relates to breakeven costs for generic projects by location. There are also a number of specific projects likely to benefit from unique characteristics that give them a cost advantage.

For example:

  1. Offshore FLNG projects, if they are able to realise cost and schedule advantages, such as the Coral (Mozambique) and Fortuna (Equatorial Guinea) currently in the process of FID.
  2. Exxon’s PNG expansion option benefitting from existing infrastructure and an impressive implementation track record.
  3. Other projects with LPG and Condensate co-production which can significantly improve economics from those in Chart 1.

However we have focused on large generic sources of new supply as the key driver of the marginal cost of new LNG going forward. The cost structure of these supply sources will have an important influence on LNG pricing dynamics next decade.

In summary, Qatari volumes are cheap but limited. Incremental supply from the US (high volumes) and Russia (more restricted volumes) look most competitive. Advantaged East African projects look to be the ‘best of the rest’ of the major sources of new supply.

An under-estimated driver of gas storage value

Posted on by David Duncan

Gas storage value is underpinned by an ability to shift gas from lower to higher priced periods. Differences in the value of gas across time periods are commonly referred to as time spreads.

Capacity owners focus on two key market price signals for time spread behaviour:

  1. Summer/winter price spreads drive the value from seasonal profiling of inventory.
  2. Spot price volatility drives the value of shorter term injection and withdrawal decisions.

But there is a third value driver, forward price correlation, which gets less attention than it deserves.

The correlation of forward gas price movements determines the value that can be created from hedging storage capacity.  If forward prices move up and down in unison, forward hedging opportunities are limited.  But as price correlations break down, the value that can be generated from hedging storage in the forward market rises.

The two primary storage hedging strategies

Storage traders use two basic strategies to monetise capacity value:

  1. Spot based strategies: The focus here is on a single decision: to injection, withdraw or do nothing (if variable costs cannot be covered). This decision is based on how the current spot price compares to the assumed behaviour of future spot prices. As such, it is an approach that relies on probabilistic modelling of spot price behaviour.
  2. Spread strategies: The focus here is on hedging observable time spreads (or price differences) across forward market contracts. Adjustments can then be made as time spreads evolve and new contracts become available (e.g. via a rolling intrinsic strategy). At any point in time the intended injection and withdrawal profile are covered by hedges.

Traders like spread based strategies because they provide access to extrinsic value, while significantly reducing risk (because they are essentially arbitrage trades). At any point in time storage inventory is not exposed to sharp changes in absolute gas price.

Traders also like the possibility of trading profitable spreads in volumes equivalent to the full capacity of the facility over the tenor of the forward contracts involved (e.g. one month), as compared with spot trades that are often only for a single day’s injection / withdrawal amount.

In practice, most storage traders will operate a hybrid strategy (a combination of spot + spread) overlaying market views and personal judgement.

Why price correlation matters

The behaviour of forward market time spreads is the key driver of spread based strategies. Traders generate margin via the placement and adjustment of forward hedges.  The amount of margin achieved is a function of both price volatility and the correlation between contract prices. For example if two contracts are very volatile but perfectly correlated, there will be no change in the underlying spread.

In less mature forward markets, price correlations across different contracts tend to be very highly correlated.  This is because forward curve movements are heavily influenced by movements in the spot price (‘prompt wagging the curve’).

In more mature markets (such as NBP and TTF), correlations can break down as different contract periods are influenced by unique supply and demand dynamics. For example, a forecast for a blast of cold weather over the next three days has little impact on the price of gas for next month.  Similarly announcement of dates for a maintenance outage on a key import pipeline will typically impact forward prices around those dates, but have little impact on other forward prices.

UK price correlation is declining

In order to illustrate the importance of price correlation we look at a UK gas market case study. The logic is also directly applicable to Continental hubs (e.g. TTF & NCG).

In table 1 we show an analysis of the correlation of prompt NBP contacts.  These are particularly important as a driver of fast cycle storage capacity value.

Table 1: UK prompt contract correlations (of price returns) (2009-2017)

Source: Timera Energy

Price correlation between contracts can be seen to decline the larger the time gap between periods.  For example, Within Day contract prices are highly correlated to Day Ahead (0.85), given similar supply & demand drivers.  But the Day Ahead contract correlation with the Month Ahead is only 0.38.

In Chart 1 we show how the price correlation between different price pairs has evolved since 2009.

Chart 1: Evolution of correlation of across key UK gas prompt contracts

Source: Timera Energy

Correlations generally strengthened from 2009 to 2014.  This significantly reduced the value that could have been extracted from storage capacity by spread based trading strategies.  The overhang of gas supply flexibility and increased competition across storage assets over the first half of this decade was a key factor behind this decline in correlations.

Interestingly, evidence is emerging that NBP prompt price correlations have started to break down again from 2015-17.  This coincides with a recovery in NBP spot price volatility over the same period.  Rough coming offline is an important driver. And these factors are coinciding with a pronounced pick up in market interest in purchasing storage capacity.

Energy from waste investment in the UK

Posted on by David Duncan

Energy from waste (EfW) is a relatively small but rapidly evolving sector in North West European power markets. EfW investment is being driven by technology improvements, cost reductions and stringent EU guidelines on landfill waste.

The UK is Europe’s second largest market for EfW with 12 mtpa of waste consumed in 2016. Other dominant markets include Germany (24 mtpa), Netherlands (8 mtpa) and Scandinavia (12 mtpa combined).

The UK EfW sector is focused on power production (6 TWh in 2016), complemented with additional revenue streams e.g. from steam and metals recovery. CHP and steam outputs play a much bigger role on the Continent e.g. via district heating plants.  In the UK, only 8 of a total of 40 EfW plants export heat.

UK EfW projects have historically focused on conventional incineration technologies (e.g. grate based systems).  But the government has now limited renewable CfD access to emerging EfW technologies.

The lure of government CfDs has supported renewed interest in Advanced Conversion Technologies (ACT) which involve waste gasification and Anaerobic Digestion (AD) to generate biogas.  64MW of small scale ACT projects were successful in the second UK CfD round announced last month.

In today’s article we look at investment value drivers and challenges for UK EfW assets.

EfW investment considerations

There have historically been a range of smaller EfW project developers in the UK.  But asset ownership is starting to consolidate as EfW technology matures, capacity volumes increase and a proven track record of financing is established.

There is also a substantial EfW project development pipeline in the UK, which is increasingly focusing on larger scale conventional grate technologies.

EfW assets however have a unique set of exposures that mean they sit on the fringe of the conventional infrastructure investment space.  Key asset value drivers and associated challenges are summarised in Table 1.

Table 1: 5 key drivers of EfW asset value

Value drivers Key valuation challenges
Power price exposure Power revenue can account for upwards of half of total revenue. This creates a strong implicit exposure to UK gas prices (which dominate marginal power price setting). Projecting UK power prices for 20+ years. UK supply stack evolution & extent of gas price recovery in 2020s are key drivers of EfW asset value upside.
Waste input revenue Revenue from long term contracts for waste disposal underpins asset revenues (e.g. 60-70 £/t). Waste prices have been increasing, with some assets retaining uncontracted exposures. Waste supply versus EfW capacity volume growth (in the context of other sources of UK capacity) are key drivers of waste price evolution.
Capacity payments CfD availability limited. But capacity payments provide an alternative revenue stream which is relatively stable (e.g. 20-30 £/kW/year). Evolution of UK capacity mix important. Focus on competition across peakers, CCGTs & batteries driving marginal capacity pricing.
Embedded benefits & other revenue Triad benefit to fall to 3-10 £/kW by 2020. But significant BSuoS benefit remains (e.g. 12-15 £/kW), given high EfW load factors. CHP benefits also possible. Understanding value revenue upside from avoided rising system balancing costs (BSUoS).  Capturing any CHP revenue dynamics.
Growth strategy Aggregation opportunities across 40 existing assets in the UK.  Significant development pipeline of EfW projects. Also expansion potential into NW Europe. Quantifying economies of scale from aggregating assets and defining a realistic EfW growth volume potential.

Source: Timera Energy

Conventional thermal power assets are primarily exposed to the correlated spread between fuel and power prices.  EfW however has an outright power price exposure.  While this can be relatively easily hedged in the forward market over a 18-24 month horizon, it still means equity bears significant market risk exposure.  But with that risk comes the potential for substantial value upside from gas price driven UK power price recovery in the 2020s.

The challenges associated with market risk are helped by EfW asset revenues typically being underpinned by long term waste contracts (at increasingly healthy prices). Waste revenues combined with capacity payments and embedded benefit streams are helping to support project financing.

The other important challenge investors face is defining a scalable business model.  There can be significant efficiencies and overhead reductions from developing a portfolio of EfW assets.  These include a central commercial function to market power, capacity and embedded benefits, as well as well as sharing operational capabilities across plants.  It is these factors that are likely to drive an ongoing consolidation across EfW assets, similar to that currently underway in the UK peaker sector.

European gas demand recovery: the comeback story

Posted on by David Duncan

European gas demand fell 20% across the first half of this decade. Declining CCGT load factors in the power sector were the main driver of this decline, as coal & carbon prices fell and renewable output increased.

The fall in gas demand contributed to the emergence of a significant surplus of European gas supply flexibility. Flex oversupply was compounded by new storage and pipeline infrastructure coming online, based on investment decisions made in tighter conditions towards the end of last decade. These factors combined to drive down market price signals for flexibility, with substantial declines in summer/winter price spreads and spot gas price volatility.

But European gas demand hit an inflection point in 2014. Demand across Europe recovered 52 bcma (11%) between 2014 and 2016. That recovery is continuing into 2017, with evidence of ongoing power sector switching of gas for coal plant, as well as the impact of a broader recovery in economic growth.

We take a look today at the key markets driving demand recovery.

Shining a light on the recovery drivers

Chart 1 shows the evolution of European gas demand across the ‘EU 29’ countries (including Norway, Switzerland & Turkey). 2014 marked the trough of this decade’s decline in gas demand. This was helped by weaker demand in 2014 given a relatively mild year of weather. The demand recovery since 2014 can be seen in Chart 1, with the power sector playing an important role, particularly across the last 12 months.

Chart 1: Evolution of pan-European gas demand (H1 2014 -H1 2017)

Source: Timera Energy

In order to better understand the drivers of demand recovery it is useful to focus in on Europe’s key gas markets, shown in Chart 2.

Chart 2: Market view of demand recovery (H1 2014 vs H1 2017)

Source: Timera Energy

Chart 2 shows the key role of the power sector in driving demand recovery. The power sector accounts for just over 20% of total European gas demand. But it has accounted for a much higher percentage of the demand recovery since 2014, particularly in the key Western European gas markets shown in Chart 2.

The power sector switching impact in boosting gas demand has been greatest in the UK and Italy, accounting for 86% and 59% of respective gas demand growth across this period. Switching is most pronounced in the UK given the carbon price floor (18 £/t premium).

The power sector has also played an important role in demand recovery in France, Iberia (Spain + Portugal) and the Benelux region. Increases in power sector demand have been particularly pronounced over the last 12-18 months. The rise in coal prices relative to gas prices across this period has supported switching across all markets. But there have also been specific issues in play e.g. the French nuclear outages of last winter and recent low hydro balances on the Iberian peninsula.

An 11bcm increase in German gas demand (H1 2014-17) has been a major factor behind the overall recovery in European demand. Chart 1 is misleading here in suggesting that the power sector has not been doing the heavy lifting in Germany (a function of the data series). When gas burn for both generation and heat is accounted for, the grid connected power sector accounts for around 5 bcm of the 11bcm increase. This is even higher if distribution connected gas assets are included (although data here is more difficult).  The commercial & residential sector account for most of the remaining increase (which is partly weather related with cooler temperatures in H1 17 vs 14).

A more positive economic backdrop is a factor that is helping with a broader demand uplift across most European gas markets.

Further demand recovery

Market consensus for European gas demand at the start of this decade was for slow but steady growth. Expectations had turned decidedly bearish by 2014-15, ranging from broadly flat to a steady decline. A power sector driven recovery in demand of more than 10% across the last two years has surprised almost everyone.

Two key factors are likely to determine what happens with gas demand going forward:

  1. Further switching: UK power sector switching has largely happened, but there is significant potential for further Continental European switching (e.g. across Germany, Benelux and Iberia), depending on the relative path of coal vs gas prices.
  2. Economic growth: Whatever your views on the longer term risks of the European Central Bank’s €60 billion a month of QE bond purchase programme, it has coincided with a recovery in European growth since 2015. Further growth is likely to be important in underpinning a continuing recovery in gas demand.

The recovery in European gas demand since 2015 has been an important factor allowing the orderly absorption of higher import volumes of Russian gas and LNG. Gazprom appears to be shifting towards defending a higher market share target than it has historically (closer to 170 bcma vs 150 bcma pre 2015).

There have also been early signs of a recovery in price signals for gas supply flexibility in the UK, with a significant pickup in NBP spot price volatility over the last 18 months. This is yet to be mirrored at the Dutch TTF. But a recovery in gas demand across Europe is an important factor in eroding the overhang of gas supply flexibility that has prevailed since the start of this decade.