LNG supply next wave: the challengers

Posted on June 25, 2018January 16, 2020 by David Duncan

We set out the prospects of the ‘Top 5’ LNG producers club last week. Amongst these, Qatar is the only ‘sure bet’ contributor to the next wave of LNG supply (2023-2030). The other members of the Top 5 have substantial gas reserves, but all could face major cost hurdles in bringing these to market.

This opens the door to competitive challengers from a group of ‘second tier’ LNG producing nations. These challengers are not merely also rans. Advantaged liquefaction projects from within this group will almost certainly displace some projects from the top 5 producers.

In today’s article we take a look at several of the less well known producing nations that may contribute to the next wave of LNG supply in the 2020s. These are considered in alphabetical order rather than ranked, with an illustrative scenario for volume growth shown in Chart 1.

Chart 1: Illustrative scenario for next wave supply from non Top 5 producers

Source: Timera Energy

Equatorial Guinea

Equatorial Guinea has been on the verge of breaking into the LNG producers club for the last two years with the Ophir LNG project (Fortuna).

But in 2018, this project has hit difficult waters in finalising financing arrangements. Nic Cooper, the CEO has resigned, and the company has received a government ultimatum that it will lose its licence if it can’t achieve Final Investment Decision (FID).

As a result of these challenges, it looks like Ophir has slipped to a 50:50 prospect for commissioning in the mid-2020s prospect.

Indonesia

Indonesia is already member of the producers’ club with the Tangguh Train 3 project expected to start in mid 2020.

The most developed of Indonesia’s other prospects is the Abadi/Masala project (Inpex & Shell). This is now an onshore liquefaction project with 9.5 mtpa capacity. FID looks possible in 2019-20, which would set up commissioning in 2024-25.

Mauritania/Senegal

BP and Kosmos hope to take FID in late 2018 for an initial floating LNG facility of 2.5 mtpa capacity. This project is split 50:50 between Mauritania and Senegal. Production is expected to commence 2022. It is reasonable to assume a second phase of 2.5 mtpa by 2025.

Mozambique

Mozambique has been one of the big African LNG growth hopes in the 2020s. Many substantial offshore gas discoveries have been made, but a lack of government experience in dealing with large upstream projects has slowed the pace of projects towards FID.

The leader of the pack has been the Coral South floating LNG project (ENI Operated, 3.4 mtpa). This achieved FID (mid 2017) with production expected in 2022.

There are also some other promising next wave candidates, the most prominent of which are:

An Anadarko project which received government approval in March 2018. This would entail two liquefaction trains with a total of 12.88 mtpa capacity. Contract sales for the first train are advancing – suggesting FID in early 2019 and production in 2024. A second train may follow (e.g. online in 2025).
An Exxon-led project is also advancing and could take FID in 2018-19. Details have not yet been announced but our best guess is a 6 mtpa train online in the mid 2020s.

The scale of Mozambique gas reserves would definitely support additional projects in the late 2020s/early 2030s if costs prove competitive.

Nigeria

Nigeria is a long established LNG producing nation. After a lengthy hiatus for investment in liquefaction, momentum appears to be building for NLNG Train 7. This would be a 8.5 mtpa train. Given the propensity for delay in Nigeria we think a conservative assumption of an FID in 2020 with start-up in 2025 is reasonable.

No further specific LNG export projects have been announced yet, but reserves support the possibility of further trains in the late 2020s/early 2030s.

Papua New Guinea

The Exxon operated PNG plant has been a success (aside from a temporary earthquake related stop earlier this year). Commissioning went smoothly and the plant has frequently operated above nameplate capacity.

Expectations are now building around an expansion of 8 mtpa, likely to reach FID in 2019 and come onstream by 2025.

Tanzania

Tanzania was considered another strong East African prospect several years ago given large scale gas discoveries. But progress towards monetising these has been slow given a number of regulatory challenges.

The first LNG project (which we assume is notionally a 5 mtpa train) has been delayed due to lack of decisive government decision making and challenging economics. As a result FID looks to be 5 years away, suggesting commissioning in the second half of next decade.

The longer shots

In addition to the main challengers above, there are several other producing nations that could also contribute volumes in the 2020s. These include Brazil, Egypt, Iran, Israel, Norway and Oman. New projects in these countries are more likely to proceed in a higher global demand growth scenario or if Henry Hub price rises unexpectedly disadvantage US export projects.

Shape of the next wave

The conditions are falling into place to spark an onset of new liquefaction project investment decisions. Global gas demand remains strong. This month’s run up in Asian spot LNG prices towards 12 $/mmbtu is also flashing on producers radar screens.

But the volumes, timing and source of next wave of LNG supply still remain highly uncertain. 2019 is set to be a key year for first mover FID decisions that will shape the next wave.

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Next LNG supply wave: the 5 major players

Posted on June 18, 2018January 16, 2020 by David Duncan

The current wave of new LNG supply consists of more than 150 mtpa of committed liquefaction projections coming online between 2015 and 2022. But considerable uncertainty remains as to the size, source and timing of the next wave.

In today’s article we take a tour of the 5 countries likely to dominate the provisions of additional liquefaction capacity to meet LNG supply growth across Asia, Europe and Latin America. Chart 1 shows an illustrative scenario of next wave supply across the top 5 players.

Chart 1: Next wave LNG supply by country

Source: Timera Energy

Qatar

Qatar is currently the world’s largest LNG supplier. A relatively low feedgas cost base means it is best placed to participate in the next wave, albeit with volume constraints.

The North Field supplying feedgas to current trains has been under a moratorium (self-imposed in 2005) preventing further development until a technical assessment of impact on the rapid rise in output on the reservoir was completed. Most recently Qatar has announced it intends to expand its output from 77 mptpa to 100 mtpa by building 3 new trains (assumed 8 mtpa each). A further debottlenecking project could also add an additional 7 mtpa at low cost (a future possibility should not be discounted). The 3 new trains are likely to come onstream in 2024-25. We set out more detail on new Qatari supply here.

US export projects feature strongly in the current supply wave. Projects under construction include Elba Island (2.5 mtpa, 2018), Sabine Pass T 5 (4.5 mtpa 2019), Freeport T 1-3 (15 mtpa 2019-20), Cameron T 1-3 (13.5 mtpa 2019), Corpus Christi T 1-2 (9 mtpa 2019).

As long as Henry Hub remains around current levels (~ 3 $/mmbtu), a new wave of US export projects looks likely over the next few years. Key prospects for the next wave include:

Sabine Pass Train 6 – 4.5 mtpa project with FTA and FERC approvals in place; FID awaits sufficient customer contracts to attract financing. FID likely in 2019 with start-up in mid 2023. There may be further upside from Sabine Pass (online in the later 2020s).
Freeport Train 4 – An additional 5 mtpa train for which Freeport have non-FTA approval (which allows cargoes to be delivered to countries with-out a free trade agreement with the US) and awaits final FERC approval to construct. It is assumed FID is taken in mid 2019 and start-up in 2024.
Corpus Christi future trains – Train 3 (4.5 mtpa) has been securing contracts with an FID taken this year setting up commissioning around 2023. There could be further trains online in the later 2020s.
Magnolia LNG project – based in Lake Charles, Louisiana, has both non-FTA and FECR approval to build four trains, each of 2 mtpa capacity. FID of train 1 and subsequent trains, awaits the negotiation of contracts with customers for offtake. Reasonable prospects to come online across second half of next decade.
Lake Charles project – Three trains, each of 5 mtpa, with non-FTA and FERC approvals and Shell as the key project investor. It has recently sought to extend the construction start deadline to Nov 2019 (i.e. it has delayed the project). Start-up timing likely 2024-26.
Golden Pass project – Three trains each of 5.2 mtpa. ExxonMobil, ConocoPhillips & Qatar Petroleum make up a strong base of sponsors/investors, but little progress recently. An FID around 2020 would see trains online mid-decade.
Driftwood LNG project – developed by Tellurian as a multiple train concept aiming for total export volumes of 3.4 bcfd (26 mtpa). Final FERC approval is not expected until early 2019. The project is searching for a new business model to secure finance.
Calcasieu LNG project – likely to comprise two trains each of 5 mtpa. Recent contracts with Shell have increased the likelihood of this project proceeding (e.g. online from mid 2020s).

Russia

The Sakhalin project on Russia’s eastern seaboard has operated successfully with Shell as a major partner since 2009. More recently Novatek has, against all expectations, successfully commissioned the first of three trains at Yamal LNG on the Yamal peninsula of northern West Siberia. The second and third trains are expected to come onstream in September 2018 and January 2019 respectively. Novatek will proceed with a small Train 4 (0.9 mtpa) to test a novel ‘arctic cascade’ liquefaction process which, if successful, will be used in later trains. Start-up of Train 4 is scheduled for end 2019.

Novatek is then planning to proceed with a second project ‘Arctic LNG 2’ with three trains of 6.1 mtpa each, starting in end 2023 onwards. Sakhalin 2 expansion is also an even money bet, which would result in an additional train of 5.4 mtpa from around 2024.

Canada

Canada was anticipated to be a big next wave player a few years ago. But Canadian projects now face major challenges in the form of overly complex regulatory/fiscal hurdles, cost base (particularly labour availability) and a waning Asian buyer interest in oil indexed long-term contracts. Two projects currently remain as ‘live’ prospects for nearer term FID:

Woodfibre – This is a relatively small (2.1 mtpa) project. It took ‘conditional’ FID in 2017 – subject to meeting many environmental commitments – some of which are with First Nation groups. In late 2017 it announced it would push back its ‘decision on construction start’ until these had been resolved. A 50:50 prospect with likely start from 2023.
LNG Canada – A Shell-sponsored project which was delayed but is now been actively progressed again. It comprises 2 trains of 6.5 mtpa located at Kitimat. Momentum is building to achieve FID before end 2018. Start up likely to be around 2024.

No other LNG export projects are approaching maturity at present.

Australia

Icthys & Prelude projects are due to be commissioned in 2018. No other new LNG export projects are approaching FID at present. Woodside’s large Browse project was shelved in 2015/16, but resurrected in 2017 and is a possibility for FID in the early 2020s. There are a range of other projects which could come online the late 2020s/early 2030s, most of these brownfield extensions. Given Australia’s poor recent track record of project slippage and cost overruns, both buyers and investors are likely to be wary.

What about the others?

While these top 5 producers are likely to dominate the next wave, a number of other producing countries are also likely to contribute. If market consensus on Henry Hub is wrong and prices recover towards (or above) 4 $/mmbtu, then countries in East Africa & South-East Asia may step up to displace US export projects.

We’ll return next week with a summary of the ‘second tier’ competitors.

Monetising European gas storage value

Posted on June 11, 2018January 16, 2020 by David Duncan

Storage capacity is a feature of most European gas portfolios. Traders and portfolio managers use storage as a key source of midstream flexibility to manage volume and price risk within portfolios.

Storage capacity may be acquired or developed in order to manage inherent ‘short flexibility’ positions in a portfolio e.g. to service retail load swings or fluctuations in gas-fired power plant demand.

Alternatively, storage may be contracted purely as a value play e.g. by a trading desk that expects higher seasonal price spreads or spot price volatility.

In either case, the hedging and optimisation of storage capacity is typically driven by hub price signals. In today’s article we look at some of the practicalities that drive the monetisation of storage in Europe.

Overview of strategies

There are three core strategies for the hedging and optimising of storage against hub prices: spot, rolling intrinsic, spot & delta hedging. The risk/return profiles of these 3 strategies are illustrated in Chart 1.

Chart 1: 3 core storage monetisation strategies

Source: Timera Energy

Spot:

A spot monetisation strategy involves optimisation of capacity against current and expected future spot price levels.

Under a pure form of this strategy no forward hedging is undertaken. This results in the broader red distribution shown in Chart 1 (higher expected value, higher risk). The advantage of not hedging is that there are no associated transactions costs. The disadvantage is the strategy results in a relatively wide distribution of asset returns (i.e. higher risk).

Pure implementation of a spot strategy is rare – it forms one extreme of the spectrum of monetisation approaches. But modelling of spot strategies often provides storage traders with an important benchmark that feeds into their optimisation decisions.

Spot strategies are particularly important in capturing prompt price volatility, where storage flex is difficult to hedge given available tradeable products.

Rolling intrinsic:

Probably the most common strategy adopted for monetisation of flexibility value is the rolling intrinsic strategy. Asset flexibility is optimised & hedged against the forward curve, with the owner ‘rolling’ or adjusting hedges if better opportunities present themselves.

In other words, re-optimisation and hedge adjustment is only undertaken if profitable (i.e. adjustments are risk free). Most importantly it enables the capture of some extrinsic value on an ongoing (rather than a one off) basis. The owner does not retain any downside market risk as the intrinsic hedges are only unwound if profitable adjustments can be made to the strategy.

This strategy results in the unusually shaped blue distribution in Chart 1. Value downside is limited to the value of the initial intrinsic hedge. Value upside beyond this depends on the correlation and volatility of prices. Expected value is however always lower than for the pure spot strategy due to the negative impact of transaction costs (20% value reduction as a broad benchmark).

Delta hedging:

The delta hedging strategy is a more complex approach for the dynamic hedging of storage optionality. But greater complexity does not necessarily mean higher returns. Liquidity constraints and transaction costs are also key practical challenges in implementing the strategy.

Under a delta hedging strategy, storage flexibility is optimised against current & expected future spot prices as for the spot optimisation strategy. But probabilistic forward ‘delta’ exposures are also calculated and hedged using linear products (i.e. fixed price/volume futures or forwards) in the underlying market. Forward delta exposures are then hedged and hedges are dynamically adjusted as deltas change with market price movements.

The theoretical benefit of a delta hedging strategy is that it targets capture of the ‘full’ option value of storage capacity, whilst reducing earnings risk when compared to a spot optimisation strategy.

Delta hedging requires exposures generated by complex analytical tools (which have ‘black box’ characteristics). Exposures generated by these tools depend heavily on the robustness of the pricing engine in representing price uncertainty. If actual price behaviour structurally deviates from the model then large losses can occur. For example, a structural change in summer winter spreads may cause rapid changes to delta exposures and result in losses on existing hedges (outside the expected distribution of values).

Practical strategy implementation

Defining 3 core strategies helps with categorisation of storage value capture strategies. But in practice traders typically use hybrid strategies that draw on elements of some or all of these approaches.

Most storage buyers also purchase capacity for use as a component of a broader physical portfolio (e.g. to manage production flow, LNG deliveries, customer/power plant load). Storage positions are still hedged & optimised against the market. But portfolio considerations also come into play.

Rolling intrinsic is the dominant hedging strategy in European markets. This involves placing initial hedges on the summer/winter spread, then optimising hedge positions as contracts cascade.

As part of a rolling intrinsic strategy, traders typically exercise price views via leaving open exposure legs (e.g. sell winter, but retain summer exposure to buy at lower price). Risk limits however typically constrain a trader’s ability to carry large open exposures.

Faster cycle storage naturally has a more open exposure into the prompt given greater flexibility to respond to short term price fluctuations. Hedging strategy focus here is on capturing the value of prompt price volatility.

Delta hedging has a more limited use in practice. Trading desks may use elements of delta hedging to feed into a storage monetisation strategy. But value erosion is a real issue given analytic complexity and the impacts of liquidity/transaction costs (e.g. bid/offer spread costs and the inability to execute hedges at modelled prices given liquidity related slippage).

Storage value is transitioning to the prompt horizon

At the start of this decade, summer/winter price spreads at TTF were above 5 €/MWh. For the last 3 years spreads have mostly traded in a 1.0-1.5 €/MWh range. The substantial decline in seasonal price spreads has pushed the value of both seasonal and fast cycle storage assets into the prompt horizon nearer to delivery.

The importance of capturing spot price volatility is likely to increase going forward. Increasing European import dependency means that the European gas market will become more exposed to outages and response delays in gas supply chains e.g. via imports of LNG and Russian pipeline gas. The extreme volatility at TTF and NBP across Feb-Apr 2018 is a good example of this. Rising power sector intermittency is also set to translate into greater swings in gas demand as power plants ramp up and down.

Storage value capture from prompt price volatility is strongly influenced by the variable costs of cycling. The lower cycling costs are the lower the strike on the spread option between two time periods. This translates directly into a greater number of value capture opportunities and the generation of higher margin from cycling.

From a storage monetisation strategy standpoint, an increasing focus on prompt value means a greater proportion of extrinsic vs intrinsic value. That creates a challenge for traders who are pushed towards holding a higher level of exposure into the prompt, with an associated increase in risk. It also creates a challenge for storage asset investors given a higher portion of asset margins are exposed to short term price fluctuations.

A new UK CCGT despite no price signal

Posted on June 4, 2018January 16, 2020 by David Duncan

The 8 £/kW clearing price in this year’s capacity auction presented a serious roadblock for new CCGT projects. But Scottish utility SSE has mounted the sidewalk and driven around it.

SSE announced it is about to commence construction of its Keadby 2 North Lincolnshire CCGT project. SSE will invest £350m in the 840MW plant with a headline efficiency of 57% (HHV). It is developing the project in partnership with Siemens.

There are three reasons why this decision is a big surprise:

There is currently no clear wholesale / capacity market price signal to support new CCGT economics
SSE is proceeding without the support of a 15 year capacity agreement
Scottish Power’s Damhead Creek 2 project looked to have a significant ‘first mover’ advantage over other new build CCGT options given a favourable location near London.

In today’s article we explore some of the potential drivers behind SSE’s decision.

Risk/return deconstruction

The market risk associated with the development of Keadby 2 sits firmly on the shoulders of project equity investors. Without a 15 year capacity agreement the project will struggle to gain any significant advantage through debt financing.

SSE’s is likely to require a significant recovery in wholesale and capacity prices versus current market conditions in order to make a return on capital invested.

Chart 1 illustrates the margin gap between current market price signals and what we estimate is required to pay back capex on a 57% efficient CCGT.

Chart 1: CCGT current vs required margin gap

Source: Timera Energy

Calculation of ‘current margin’ in the chart is based on:

Q1 2018 8.40 £/kW capacity clearing price
Current forward clean spark spreads for capacity year 2018-19
Assumptions on opex and ancillaries consistent with a generic new CCGT in North Lincolnshire

Calculation of ‘required margin’ in the chart is based on annual margin required to cover an 8% post tax nominal return on a latest generation CCGT plant in this location (estimated at 90 £/kW).

Chart 1 illustrates what we estimate to be a gap of at least 25-30 £/kW/year versus current market price signals. What factors could drive such a recovery?

Wholesale & BM margin:

There are structural drivers that are working in SSE’s favour to support a recovery in CCGT wholesale margins by early next decade. Lower variable cost coal and CCGT plants are retiring and being replaced by high variable cost engines, DSR & batteries. This is set to support peak prices, driving value into the top 20% of hours of the price duration curve.

Keadby 2 will be the most efficient CCGT in the market when it’s commissioned. This will help it to run at high load factors (avoiding start costs) and to pick up margin rents when other more expensive CCGT units are setting prices. The plant is also likely to be highly flexible, supporting margin capture in the Balancing Mechanism.

However, the plant also faces margin threats over its lifetime, likely to extend into the 2040s. These include the gradual erosion of load factors and margins due to penetration of renewables and the broader risks around a policy drive towards decarbonisation (e.g. possibility of emissions standards or higher carbon prices). Paying back a high proportion of capex in the first 5 years will be key to mitigating these risks.

Capacity margin:

The 2018 auction clearing price cleaned out the majority of the UK’s remaining coal plant. It also presented an existential threat to a number of older and less flexible CCGTs. Further exit of thermal capacity and competitive value erosion headwinds facing engines and batteries are likely to drive a recovery in capacity prices towards 20 £/kW over the next 2-3 years.

Ancillaries & other margin:

Ancillaries revenue is typically icing on the cake but there may be favourable factors in play for Keadby 2. From a TNUoS zoning perspective the plant may benefit from a transition to negative costs over the next few years, but there are more advantaged locations in Southern England.

In summary, SSE (& any other equity partners) are bearing substantial market risk and are likely to need a structural recovery in margin for the project to be a success. But behind the headline margin drivers there are likely to be a number of other considerations that have a tangible impact on project economics.

Other investment drivers

SSE have not announced details of their agreement with Siemens. But it is reasonable to assume that Siemens are providing substantial support (e.g. equity, efficiency /availability guarantees, favourable maintenance contract, risk sharing). Siemens and GE have been locked in a head to head battle for the last 5 years to try and deliver a bankable CCGT project that could be used as a template to support further turbine sales.

Keadby 2 is not a greenfield project. There are likely to be important ‘end of life economics’ considerations associated with the existing CCGT plant on the Keadby site (commissioned in 1996). SSE will also be able to re-use some existing infrastructure, reducing costs.

SSE may also attach value to the Keadby 2 project from a portfolio perspective. This is complicated by the proposed merger of the SSE and N-power retail operations.

SSE is set to lose most of its flexible generation capacity over the next few years (given closure of Keadby & Peterhead CCGTs and Fiddlers Ferry coal units). Keadby 2 helps maintain a footprint in the UK thermal generation sector. Depending on the nature of the retail merger, SSE may also see a new CCGT providing protection from price shape exposure from its retail customer book.

Time will tell if SSE (& Siemens) get paid for the risk they are taking in developing Keadby 2. But pulling the trigger first makes it even more difficult for other new CCGT projects to follow.

Belgium’s nuclear driven capacity crunch

Posted on May 29, 2018January 16, 2020 by David Duncan

Belgium’s nuclear driven capacity crunch

Nuclear power is not popular in Belgium. Belgium’s nukes are even more unpopular with Germany and the Netherlands, given their locations near these borders and chequered safety record.

Belgium’s reactors are ageing and have suffered several major safety and maintenance issues over the last 5 years. In response to these factors, the Belgium government agreed an energy plan on 30^th Mar 2018 that confirms the phase out of nuclear power by 2025.

In practice this means Belgium needs to replace half of its generation output in the next 7 years. This is clearly a major challenge. And Belgium’s newly approved strategic reserve mechanism is unlikely to incentivise adequate replacement capacity.

This means that Belgium is currently heading towards a mid 2020’s capacity crunch. It is doing so as key neighbouring markets (France, Netherlands & Germany) also face tightening capacity balances.

The hole created by nuclear closure

Belgium has 7 nuclear units:

4 units at the Doel site (on the Dutch border north of Antwerp)
3 units at Tihange (in Eastern Belgium, about 40km from the Dutch & German borders)

The Mar 30 plan schedules closures of 1GW in 2022, 1GW in 2023 and the remaining 3.9GW in 2025.

These units currently make up 27% of Belgian capacity (5.9GW of a total 22GW), but they account for approximately 50% of Belgium’s generation output.

The easiest solution for replacing lost generation output would be to import more power. But Belgium’s regulatory authorities and system operator have clearly stated they do not want to increase import dependency for security of supply reasons.

So it is clear Belgium needs replacement capacity. What is not clear is where that capacity will come from.

Can renewables plug the gap?

Belgium currently has approximately 3GW of wind and 3.5GW of solar capacity. Based on current policy support mechanisms, technology cost reduction curves and recent build rates, it is our view that Belgium can develop an additional:

~3GW of wind by 2025 (dominated by offshore)
~2GW solar by 2025.

In addition, we assume development of ~1GW of gas peaker capacity (dominated by distribution connected reciprocating engines) and ~0.5GW of battery storage by 2025.

This results in the nominal capacity mix scenario shown in Chart 1 (which also accounts for end of life retirements of some older thermal capacity). This scenario assumes no new large-scale gas build, consistent with a current lack of policy & market price signal support.

Chart 1: Scenario for evolution of Belgium capacity mix – assuming no large-scale gas build

Chart 1 however does not reflect the true security of supply problem Belgium faces replacing nuclear with wind and solar capacity. Wind and solar output needs to be derated to reflect the equivalent firm capacity that can be relied on given load factor fluctuations.

Once 3GW of wind and 2GW of solar build is derated, it yields only about 1GW of equivalent firm capacity. This leaves an almost 3GW capacity deficit in the Belgian market by 2025, with the derated system reserve margin plunging into negative territory as illustrated in Chart 2.

Chart 2: De-rated Belgium capacity mix

What if our renewable build assumptions in the scenario above are too conservative? Even with much more aggressive policy support, it is difficult for Belgium to develop more than 1.5GW of equivalent firm renewable capacity by 2025. This would still leave a ~2.5GW capacity deficit to be filled.

Where is the price signal for flexible capacity?

A 3GW capacity deficit is not a massive technical challenge. Two large CCGT plants would plug the gap. But this solution may be inconsistent with the backdrop of decarbonisation.

Firstly from a policy standpoint, Belgium is likely to be wary of large scale new gas build from an emissions reduction perspective.

Secondly from an economic standpoint, it will be hard to find investment capital willing to commit to new CCGT projects (with 20 year economic lives) commissioning mid next decade. Investors face unpalatable margin risk relying on wholesale price signals alone, as well as the broader risk of stranded assets (as Dutch coal plant developers are painfully discovering).

If Belgium is going to plug its capacity gap with new gas plants, a clear price signal will be needed to secure investment. Belgium has no plans to implement a capacity market (as have the UK, France and Italy). Instead it gained EU state aid approval in Q1 2018 for a strategic reserve mechanism.

Belgium’s strategic reserve initially covers 5 winters from 2017-18. Reserve capacity sits outside the energy market and is called on only in periods of security of supply emergency. As such it can be used to prevent uneconomic older plants from closing. But it is unlikely to send a clear capacity price signal to support new build of flexible capacity.

CHPs may play a role in plugging the 3GW capacity deficit. This could either be smaller distribution connected CHPs (easier but lower volume) or large-scale grid connected assets (more challenging). But adequate policy support mechanisms to deliver significant volumes of CHP are not yet in place.

Where does this lead?

If nuclear plants are closed by 2025, it is difficult to see how Belgium can maintain (i) security of supply and (ii) similar levels of wholesale prices without 2-4GW of new gas-fired capacity. But it is not clear how this capacity will get built in the absence of new policy measures.

The capacity gap may be reduced somewhat by a combination of aggressive role out of renewables & storage as well as tolerance for higher import dependency. But these measures are unlikely to be enough.

There is recent evidence from 2014-15 of the impact of a rapid reduction in Belgium nuclear capacity. Prices separate from neighbouring markets and volatility jumps, with a focus in winters, peaks and periods of lower renewable output. Higher Belgium prices can also drag up French and Dutch prices as imports increase.

Belgian policy makers may be forced to confront the reality that the current path they are proceeding down is not going to work. But they are in good company.

Their biggest neighbour Germany is facing a similar, but much larger problem as it tries to close nuclear, coal and lignite capacity in parallel. We’ll come back soon to address the German problem and its implications for other European power markets.

Power sector switching is driving gas hub prices

Posted on May 21, 2018January 16, 2020 by David Duncan

“Everything comes back to gas prices”.

It is not only direct participants in the European gas market that are concerned about the path of hub prices. The direction of TTF and its satellite hubs has a much broader impact across energy markets. For example:

Thermal power: Power assets exposed to wholesale power prices have a strong indirect exposure to gas prices. This is the result of the important influence of hub prices in setting power prices across Europe (which is increasing as coal & nuclear plants close).
Renewables: Gas price influence on wholesale power prices also drives the relative competitiveness of renewables versus alternative capacity types (particularly important for the transition to standalone renewable investment).
LNG market: Europe’s role as swing provider to the LNG market means that European hubs underpin global LNG spot prices, with regional markets pricing off a basis to TTF.

In an article two weeks ago we set out the current state of supply and demand balance in the European gas market. Today we analyse in more detail the drivers of hub price evolution over the next few years with a particular focus on the importance of gas vs coal switching in the power sector.

Unusual uncertainty over next 3 years

The growing importance of gas prices for asset value sits against a backdrop of rising uncertainty as to hub price levels.

In our view, the distribution of potential hub price evolution across the next 3 years is an unusual shape. Rather than a classic ‘bell curve’ normal distribution, there appears to be an unusually broad and flat distribution of potential outcomes.

We also believe this distribution is asymmetrically skewed to the downside as the result of an oversupply of LNG over the next 3 years. In other words, the risk of lower prices is greater than that of higher prices.

Current TTF forward gas price levels are around the 6.5-7.5 $/mmbtu range across 2019-21 (18.8-21.7 €/MWh). To illustrate gas price uncertainty, it is relatively easy to define credible scenarios that deviate significantly from these price levels, e.g.

Price slump: where hub prices fall 40% by 2020-21 to around 4.0 $/mmbtu (11.6 €/MWh) e.g. if European LNG imports rise sharply and coal prices decline.
Price rise: where hub prices rise by 20%+ into the early 2020s e.g. if coal prices rise strongly and Asia comfortably absorbs new LNG supply coming to market.

Switching of gas for coal plants in the power sector is a key mechanism driving marginal hub price levels within this distribution.

Switching as a driver of gas prices

Switching is a relatively simple concept. As gas hub prices fall, gas-fired power plants become more competitive relative to coal plants, with load factors and gas burn increasing accordingly.

This creates additional gas demand and supports hub prices. The process works in reverse as hub prices rise.

This switching mechanism happens in real time based on spot gas, coal and carbon prices. It also influences relative movements in forward gas prices (based on future switching impact).

In order to analyse the role of switching in driving European hub price levels, it is useful to apply a three step framework:

LNG surplus: determine what volume of surplus LNG may flow into European hubs over the next 3 years
Switching: define how volumes of surplus LNG can be absorbed by power sector switching and at what combination of gas, coal (& carbon) prices
Gas price impact: determine the hub price levels required to balance the European gas market (& therefore the global LNG market given Europe’s role as swing provider)

We looked at the volume range of potential LNG surplus (1.) in last week’s article. In today’s article we put some numbers around 2. and 3. (switching potential & hub price impact).

Defining the switching range

Chart 1 illustrates the hub price range over which switching is important (shaded in blue). It shows this in the context of the current differential between TTF forward prices and US Henry Hub. Backwardation in the current forward curve can be seen in the relative price decline from 2019 to 2021.

Chart 1 Gas hub prices and the switching range

Source: Timera Energy

The top end of the switching range is defined by the point at which the UK power sector (with its carbon price floor) switches all its coal capacity back into merit (significantly above 8.0 $/mmbtu).

The lower end of the switching range is defined by the point at which US LNG export ‘shut ins’ transition to be the primary mechanism for absorbing surplus gas. Shut ins occur if the variable costs of exporting US LNG falls below netback spot prices. This is likely to happen if European hub prices fall below a 0.7-1.5 $/mmbtu variable LNG transport cost differential to Henry Hub (marked as the grey shaded area).

Switching continues in the grey ‘shut in’ range. It is just that shut ins are a much more dominant volume driver once gas prices fall to this level, given the ability for relatively large volumes of US export supply (80+ bcma) to be shut in over a relatively narrow price range.

Switching demand curves

It is one thing to understand the range over which switching is a dominant driver. It is another to define switching price & volume levels and their impact on hub prices.

In order to perform a robust analysis of aggregate gas vs coal switching potential in Europe, it is important to model the underlying dynamics of the individual power markets which drive switching. To enable this, we have set up a scenario in our pan-European power market model that reflects current forward market pricing for fuels. This provides a benchmark for aggregate power sector gas demand given current gas and coal market prices.

We then run multiple combinations of gas and coal prices through the power market model, in order to analyse aggregate pan-European gas vs coal switching potential. This allows us to produce gas switching demand curves for the different combinations of gas & coal prices shown in Chart 2.

Chart 2: Pan-European switching demand curves

Source: Timera Energy

Each line in the chart can be thought of as an aggregate gas demand curve for the European power sector. In other words, the lines show aggregate gas burn (bcma) as a function of gas price. Three different demand curves are shown for different coal prices.

The central line shows switching dynamics at current forward coal prices for European delivery (approximately 90 $/t). As you move from left to right down this line, gas switching volume increases as gas prices fall.

For example, a fall in gas prices from the 2019 forward price level (7.3 $/mmbtu, 21.2 €/MWh) to the ‘shut in’ range (4.2 $/mmbtu, 12.2 €/MWh) yields about 30 bcma of incremental switching demand, assuming coal (& carbon) prices are constant.

Coal prices typically move with gas prices (although not always in a correlated way). In order to understand the impact of changes in coal prices, we have also produced switching demand curves for coal prices 30 $/t above and below the 90 $/t central case (at 60 and 120 $/t).

As an example, if coal prices were to rise to 120 $/t, European hubs could support similar levels of power sector gas burn at prices around 1.7 $/mmbtu (4.9 €/MWh ) above current levels. This example illustrates why hub prices are currently rising with coal prices as switching levels increase accordingly.

Conclusions on gas price levels

In last week’s article we set out the potential volume range of LNG that may be surplus to ‘business as usual’ requirements in Asia & Latin America (15-70 bcma in 2020). Not all of that surplus LNG will flow to Europe.

There is likely to be some incremental demand response in Asian markets at lower spot prices (e.g. 10-20 bcma of additional demand if prices fall below 5.0 $/mmbtu). But there is certainly a credible risk in our view that 40+ bcma of surplus LNG could flow to Europe by 2020-21 in a scenario of weaker Asian demand growth.

Our switching analysis shows 20-30 bcma of accessible incremental switching potential in Europe, before hub prices fall to US shut in levels. This switching volume would rise if coal and/or carbon prices continue to increase.

If surplus LNG flows to Europe remain below this 20-30 bcma level, then switching should allow hubs to absorb extra cargoes (e.g. in a 5-7 $/mmbtu price range based on current coal/carbon prices).

But if surplus LNG imports into Europe rise above 40 bcma, it is hard to construct a scenario where US shut ins are not required. That would likely mean European hub prices at levels below 4.5 $/mmbtu (13.0 €/MWh), maybe as low as 3.5 $/mmbtu (10.1 €/MWh).

We are not predicting this low price scenario, but it is a credible downside risk flashing on the radar screen. And it represents a substantial deviation from current forward price levels.

LNG oversupply setting up 2020s squeeze

Posted on May 14, 2018January 16, 2020 by David Duncan

‘There is an LNG glut’. ‘No, the market is tight’. Two tribes have emerged within the LNG market and their views are polar.

The glut tribe argues that LNG supply will outpace demand growth over 2018-21, forcing spot prices lower, potentially towards 4 $/mmbtu in order to shut in US exports.

The tight market tribe sees little evidence of oversupply, given demand growth is broadly keeping pace with new liquefaction projects coming online. It also points to a shortage of gas in the early 2020s due to a lack of investment now.

The key element that is often missing within this polarised debate is timing. If appropriate time horizons are defined, it is quite possible both tribes will be proven right. In fact oversupply over the next three years may be a powerful catalyst for a tightening market in the early-mid 2020s, as it chokes off liquefaction investment decisions.

New investment has dried up

Significant uncertainty around the level of Asian LNG demand has fueled the polarisation of industry views. It is generally accepted that cargoes which are surplus to Asian & Latin American requirements will flow to Europe. But the level of this surplus could quite credibly be anywhere from 15 – 70 bcma (10-50 mtpa).

Chart 1 shows the global LNG market balance under an illustrative high and a low Asian demand scenario. The global surplus of LNG (vs business as usual demand) is shown by the hashed red area above the balance line. Beyond this, the global deficit of LNG is shown by the red shaded area below the line. The period in between surplus and deficit reflects the ability of Russian pipeline exports to temporarily meet incremental demand growth requirements with shut in West Siberian gas production.

The scenarios in Chart 1 illustrate both the time & volume range of global surplus LNG volumes that could flow to Europe depending on Asian demand growth:

The top panel shows a more aggressive Asian demand scenario with only 16 bcma surplus flow in 2020 and new supply required by 2022
The bottom panel shows a slower Asian demand scenario with 61 bcma of LNG surplus in 2020 and a requirement for new supply from 2024.

Chart 1: Illustrative range of surplus LNG flows into Europe depending on Asian demand

Source: Timera Energy

Volumes towards the lower end of this surplus range can be absorbed at European hubs in a relatively orderly fashion via power sector switching. Volumes at the upper end of the range are likely to force European hubs down from current levels (~ 7 $/mmbtu) to levels that shut in US export flows (~ 4.0-4.5 $/mmbtu assuming Henry Hub prices remain ~ 3.0 $/mmbtu).

This uncertainty is causing Financial Investment Decisions (FIDs) in new liquefaction capacity to dry up. There was only one liquefaction FID in 2017 – ENI’s Coral South FLNG project.

The next wave of investment looks to be some way off

Market uncertainty also means there are few credible prospects for FID in 2018. The winter surge in Asian spot prices supported some optimism in late 2017. But this was largely the result of a lack of seasonal storage in Asia, with prices quickly re-converging with European hubs in Q1 2018.

Cheniere is expected to make a decision this year on Corpus Christi Train 3 (cost advantage given existing infrastructure). Ophir’s Fortuna FLNG project FID was expected this quarter but appears to have been delayed by issues with financing. It is slim pickings for imminent FIDs beyond these projects.

Liquefaction projects typically have a 4 to 5 year lead time to full production. That means FIDs taken in 2018 are unlikely to impact global supply until 2022-23. Glut or no glut, the pace of new supply entering the market is set to accelerate over the 2019-20 period. This will likely keep a cap on LNG prices and new project FIDs.

So it may not be until the early 2020s that significant volumes of new investment are forthcoming. That is likely to be too late. The timing of Qatar’s decision to bring 20+ mtpa of low cost new supply to market will be key. But as things look today, the LNG market may be marching towards a major squeeze in the early-mid 2020s.

Winners & losers from an LNG price surge

The key losers from higher gas prices are consumers (residential, commercial and industrial). Retailers may also be hurt, to the extent they cannot pass through price rises e.g. for contractual, competitive or policy reasons. Gas-fired power plants would also likely suffer from an erosion of competitiveness versus coal plants.

A gas price surge would clearly benefit gas producers (although this is dependent on timing & offtake contract structures). A tighter market would also likely mean greater gas price volatility, paying dividends to owners of flexible midstream assets e.g. LNG portfolio players.

There would also be important knock-on impacts for European power markets. By the early 2020s, gas-fired plants will dominate marginal setting of wholesale power prices. That means higher gas prices translate directly into higher power prices (via CCGT pass through). That is good news for the prospects of standalone renewable development. But it may also prolong the economic lives of coal plants (depending on coal & carbon prices).

European gas balance: drivers & prognosis

Posted on May 7, 2018January 16, 2020 by David Duncan

European gas demand hit its ‘high-water’ level of 586 bcm in 2010. From 2010 to 2014 demand then reversed sharply, falling 19% (111 bcm), and commencing what many perceived to be an irreversible downward trend.

This trend was generally accepted to be in line with the growth of renewables in the power sector (at the expense of gas) and the slow demise of energy intensive industries in Europe as these were ‘offshored’ to developing Asia.

This script conveniently aligned with EU policy. It was consistent with reduced reliance on Russia as the largest source of natural gas imports. This was important given several points of disagreement between the EU and Russia. For example, territorial infringement in Ukraine, the issue of Nordstream 2 versus maintenance of transit flows (and revenues) through Ukraine, and squabbles over the use of downstream pipeline capacity related to Nordstream 1.

If reduced natural gas consumption was the EU policy ‘game plan’, the reality from 2016 onwards makes for uncomfortable reading. European gas demand has rebounded almost as quickly as it fell. And overwhelmingly, Russia has been the supplier benefitting from this.

What is driving demand growth

European gas demand has recovered 16% (77bcm) across 2014-17. This rebound has been surprisingly consistent across countries: UK 4.1%, Germany 6.0%, Italy 6.7%, France 5.5%, Netherlands 4.9%, Spain 4.8%, Turkey 3.2%, Belgium 4.3%, Others 5.5%.

A recovery in economic & manufacturing growth has played an important role, particularly in 2016-17. Lower wholesale gas prices since 2014 (relative to earlier in the decade) have also helped support demand. But Chart 1 illustrates that one of the pillars of gas demand recovery has been power sector consumption.

Chart 1: Power sector gas demand across 5 largest markets

Source: Timera Energy

Gas demand from power generators across these five markets accounts for ~30 bcma of the gas demand rebound since 2014. This is partly the result of gas for coal switching that has taken place given:

Coal prices strengthening relative to gas prices
A step up in the UK carbon price floor (to 18 £/t in Apr 2015)

However there are also some ‘one-off’ factors that have supported power sector demand e.g. the French nuclear outages in Winter 16/17 and low Spanish hydro availability in 2017.

The extent of power sector gas for coal switching over the next 3 years will be a key factor determining whether European gas demand continues to recover or stalls.

Where is new supply coming from?

Chart 2 shows the dominance of Russia in meeting demand growth since 2014, with Russia providing 45bcm of the 77 bcm European growth.

Chart 2: Evolution of key sources of European gas supply (2010-17)

Source: Timera Energy

Domestic European production has been in general decline since 2010, although this decline has stabilised somewhat over the last two years. This is partly due to strong Norwegian flows. But some UK production, which achieved FID during the high oil/gas price conditions of 2011–14, has also come onstream.

Non-Russian pipeline imports have been variable. It is thought that Algeria’s 2016 increase was achieved by ‘borrowing’ Hassi R’Mel recycle gas in advance of new fields coming onstream. Apart from the anticipated boost from Azerbaijan’s Shah Deniz 2 around the end of this decade – there is little prospect of an increase in non-Russian European pipeline gas imports.

LNG imports were around 90 bcma in 2010 and 2011, when new LNG supply projects hoping to target the US ended up in Europe by default (as a consequence of the US shale gas revolution). As Asian LNG demand has grown since then, it has drawn LNG away from Europe. 2017 saw a break in this trend. Growing global LNG supply caused European imports to increase by 20% over 2016 levels, though this was mainly confined to Southern Europe.

Higher LNG imports are the only substantial threat to Russia dominating incremental supply volumes into Europe. Surplus LNG cargoes flow into Europe as ‘price taking’ gas (i.e. insensitive to price while prices remain above US export shut in levels). But so far the volumes of surplus LNG imports into Europe have been well below demand growth, allowing Russia to step into the gap.

What next?

Some of the factors behind the rebound in European gas demand are unlikely to support further consistent demand growth. For example:

UK has limited additional coal switch-out potential
French nuclear capacity has returned to higher availability (at least for now)
Drought/hydro issues revert to mean (which may be negative for gas demand)

But there are 5 structural drivers of the European gas market supply & demand balance we are keeping a close eye for guidance on what may happen next:

Switching: Relative coal vs gas prices and associated power sector switching volumes
Capacity mix: Pace of retirement of (i) coal, lignite & nuclear capacity & (ii) growth in renewables capacity
Economic growth: Extent to which non-power sector gas demand continues to rise
Domestic production: Pace of production decline (e.g. across Groningen, UKCS)
LNG imports: Volume of surplus ‘price taking’ LNG flow into Europe

We will return to look at some of these drivers in more detail as the year progresses.

At the flicks: gas curve animation

Posted on April 30, 2018January 16, 2020 by David Duncan

Energy markets are awash with charts. We work in a data intensive industry and a good chart can be worth a thousand words. But charts by nature provide a static view of factors such as price, volume, value & risk.

Chart animation adds an additional dimension: time. That can help a lot with interpreting the dynamic evolution of market prices and let’s face it, everyone likes a trip to the movies.

Today we animate the evolution of NBP gas prices. We’re no threat to Pixar, but the animation supports some interesting takeaways on current gas pricing dynamics.

The NBP snake

Chart 1 shows the simultaneous evolution of NBP spot and forward gas prices. The strong arbitrage driven relationship between NBP and TTF means that many of the characteristics of this animation apply for TTF also. But we’ve chosen NBP rather than TTF to focus on some recent pricing dynamics that are specific to the UK.

Chart 1: NBP gas curve animation (2010-18)

Source: Timera Energy (based on ICE data)

Some takeaways to consider

1. Spot vs forward: there is a very strong relationship between spot prices (we’ve used month-ahead prices in Chart 1) and shifts in the forward curve (‘spot wagging the curve’), although this can break down in periods of more extreme spot price stress.
2. Winter 17/18: NBP month-ahead prices took off in Dec 17 due to a combination of supply outages and uplift from high spot LNG prices given strong Chinese demand for spot cargoes. However the ‘beast from the east’ day-ahead and within-day spikes in Feb 18 had very little impact on forward prices (given short term weather driven nature of the shock).
3. Seasonal spreads: UK seasonal spreads can be seen roughly doubling from 2016-18 (4 to 8 p/th) to induce more supply flex since the closure of Rough. Front year spreads can be very volatile as spot prices move.
4. Recent spot price ramp: European near term gas prices are again being pulled higher by rising coal prices in Q2 2018. Higher coal prices lifts gas for coal plant switching levels in the power sector which provides support for gas prices.
5. Current backwardation: European gas curves (like the Brent crude curve) are also moving into strong backwardation which is relatively unusual for gas. This is due to a combination of (i) rising spot prices and (ii) the looming ramp up in surplus LNG acting to dampen forward prices across 2019-21.

The other important thing to note is that current NBP/TTF forward curves are consistent with Europe comfortably digesting surplus LNG this decade (at annual prices above 6 $/mmbtu). European hub spreads vs US Henry Hub (3-3.50 $/mmbtu) are well above the variable costs of flowing US exports to Europe. The Q1 2016 price slump has so far been the only time when the trans-Atlantic spread declined to levels that threaten US shut ins.

We will be back soon to revisit how Europe can digest surplus LNG via gas vs coal switching and the associated impact on hub pricing dynamics.

Plant closure: Valuing closure option vs alternatives

Posted on April 23, 2018January 16, 2020 by David Duncan

Plant closure decisions are usually driven by expected profit. But a simple assessment of plant profitability is usually an inadequate approach to inform a plant closure decision.

This needs to be couched within a structured investment decision framework that maps out:

Alternative options (e.g. cost restructuring, refurb, conversion, mothball, repower, reserve contracts)
Timing of exercise (often driven by external factors e.g. technical, policy or market related)
Cost of exercise & in some case cost of carrying options
Risk adjusted value of exercise (using a probabilistic approach)

A robust investment decision framework allows a plant owner to quantify and assess the risk/return distributions of alternative options as the plant progresses towards closure.

Today we follow on from last week’s article on drivers of plant closure by exploring a practical case study of CCGT end of life investment decisions.

CCGT closure vs life extension

CCGT plants usually face a key investment decision around 25 years of age. The exact timing depends on technology, run hours and operation profiles. But life extension beyond this point typically requires major capex spend e.g. relating to replacement of steam generator components.

This life renewal capex hurdle may trigger plant closure if analysed in isolation, but there are usually several other options available to plant owners, for example:

GT conversion: Bypassing the steam generator to run the gas turbines alone (lower efficiency but often with associated fixed cost reductions)
Refurb: capex spend to extend plant life and increase flexibility e.g. reducing minimum stable generation levels and start costs to enable greater capture of prompt, balancing & ancillary revenues
Repower: Replacement of existing generators with new equipment, but re-using site infrastructure
Mothball: Substantially reducing fixed costs to retain the option of reopening the plant in the future (this only makes sense for certain assets and market conditions e.g. Netherlands and Germany both have significant mothballed CCGT capacity in anticipation of a tightening capacity balance).

A structured approach is required to properly quantify and compare the relative risk/return of these different options. This requires a robust probabilistic plant modelling framework that generates realistic distributions of asset margin under each of the alternative options.

A nodal decision tree can then be constructed to estimate risk adjusted values for different investment options as illustrated in Chart 1.

Chart 1: CCGT closure vs life extension option decision tree

Source: Timera Energy

This framework can be assessed for example on an annual basis as the plant ages and market & operational conditions change. But it is important to note that options are impacted by decisions taken i.e. there is a ‘path dependence’ problem that needs to be properly analysed and accounted for.

DCF / NPV calculations to support investment decisions may require use of multiple discount rates, depending on the nature of the uncertainties associated with the various options (which can be very different).

Mid-life asset ownership is becoming a specialist game

It is no coincidence that commodity traders and private equity firms are buying mid-life thermal power assets across Europe (e.g. KKR French CCGTs, Vitol Immingham CCGT, Castleton Rotterdam CCGT, ECP Saltend & Deeside CCGTs).

The changing ownership of thermal assets reflects:

More challenging risk/return profiles of assets as they age, load factors decline and value becomes more focused in the prompt horizon
More complex investment optionality as assets enter later life (as per case study above)

The first of these factors requires a strong trading capability (either in-house or via route to market contract). The second factor requires strong expertise on plant investment optionality & cost structuring.

Applying the investment approach we describe above can unlock significant upside value from ageing assets. This is a key factor behind the increasing trend in change of ownership of mid-life thermal assets, as traditional utility owners sell to specialist investors.