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Flexibility investment: New UK CCGTs

Posted on by David Duncan

New CCGTs have not fared well so far in the UK capacity market. Centrica’s repowering of the Kings Lynn plant (0.4GW) has been the only successful project to date. The gravestone raised over the 2.0 GW Trafford project stands as a warning to overly enthusiastic CCGT developers, after it failed to raise capital and reneged on its 2014 capacity agreement.

But it is too early to write off new CCGTs just yet given a policy landscape shifting in their favour. Ofgem has levelled the capacity market playing field by revoking the lucrative triad benefit that has underpinned distribution connected peaker economics to date. CCGT developers are also experiencing tailwinds from improving capital access, capex costs and unit efficiencies.  The recovery in forward sparkspreads over the last 12 months helps too.

There is a substantial pipeline of new CCGT project options waiting for the right capacity price. These sit across a range of developers, for example:

  • Utilities (e.g. Scottish Power’s Damhead Creek 2)
  • IPP generators (e.g. Drax & Eggborough coal to CCGT repowering options)
  • Fund backed (Macquarie backed Calon Energy’s Willington project)

But getting the numbers to line up is not easy. Today we take a look at drivers of the investment case for new CCGTs to illustrate the challenges involved.

Margin breakdown of new CCGTs

Chart 1 illustrates margin ranges for a generic new UK CCGT. The left hand column represents total asset margin required to earn a reasonable return on capital (i.e. a higher single digit unlevered IRR).

In the other chart columns we have broken margin components into three key buckets:

  1. Wholesale energy margin: Driven by margin capture in the wholesale energy market, a function of the evolution of clean spark spreads.
  2. Capacity margin: Driven by the evolution of pricing in the UK capacity market, adjusted for CCGT derating factors.
  3. BM & balancing services: Additional margin from bidding units into the Balancing Mechanism (BM) and providing other balancing/ancillary services.

Chart 1: Generic UK CCGT (@56% HHV) margin ranges

Source: Timera Energy

Wholesale margins

CCGT economics are underpinned by wholesale market margins. High unit efficiencies mean new CCGTs have a significant merit order dispatch advantage over existing coal & CCGT units, as well as gas peakers. This translates into higher load factors and the ability to earn margin rents when higher variable cost thermal units are setting wholesale market prices. This is weighed against a capex cost tradeoff, with new CCGT capex costs in the order of 550 £/kW (vs gas peaker capex of 350-400 £/kW).

The latest CCGTs (H-frame technology) are around 56% efficient (HHV). These units have a 3-10% efficiency advantage over existing CCGTs. Compare for example a 56% efficient new plant with a 52% efficient CCGT from the last wave of build in the late 2000s. The 4% efficiency advantage translates into an approximately 3 £/MWh increase in baseload clean spark spread.

The efficiency advantage of new CCGTs over OCGTs and reciprocating engines widens to 15%+. This translates into a ~15 £/MWh lower variable dispatch cost versus gas peakers.

The challenge in projecting CCGT wholesale market returns is understanding how margin and load factors erode over time. In other words, how a new CCGT asset transitions from relatively high load factors in the early 2020s to an increasing dependency on price shape and volatility by the 2030s.

The pace and scale of this transition depends strongly on evolution of the UK capacity mix and associated implications for pricing dynamics. A robust logic around capital cost recovery in the first 10 years of asset life is critical.

Capacity margin

Capacity margin is key from a financing perspective. A 15 year capacity agreement with a fixed price (indexed to inflation) acts to reduce margin risk. This is important downside protection for project equity. And it also impacts the ability of developers to raise debt financing (typically tested via a debt service coverage ratio against a downside scenario).

A significant part of the reason new CCGTs have not featured in the UK capacity market to date is capacity prices near 20 £/kW (around the level of CCGT fixed costs). Prices of 30 £/kW or higher are likely to be required to support significant volumes of new CCGT capacity development.

BM & balancing services

Margin from balancing and ancillary revenues can be a key component of peaking asset economics. But they are more like ‘icing on the cake’ for new CCGTs, at least in the first years of asset life. This is because relatively high load factor operation in the wholesale market typically constrains other revenue opportunities.

Despite the improved flexibility of new CCGTs, BM margins are typically limited to more opportunistic bidding by wholesale market operations e.g. bidding to ramp down volumes in the BM or pricing up smaller incremental volumes of additional output. Ancillary services can provide useful margin uplift, but tend to be strongly locationally dependent (e.g. higher in South West vs Northern UK).

Understanding competition, decarbonisation and downside risks

One of the biggest challenges facing a new CCGT developer is quantifying the risk/return impact of a range of credible threats. This is particularly key given the risks associated with a 20 year asset lifetime (+ 3-4 year development lead time) in a decarbonising world that is seeing rapid technology & cost innovation.

Some examples of important threats:

  • Cheaper capacity from alternative sources (e.g. peakers, batteries, life extensions of existing CCGTs)
  • Rapid deployment of offshore wind capacity, displacing thermal plants
  • Substantial build of other new CCGTs, eroding load factors & margins
  • Disruptive technology developments e.g. wide scale deployment of load-shifting batteries or technology induced changes in consumer behaviour.

Some CCGT value drivers can be complex and counterintuitive. For example:

  • The ramp up of electric vehicles may erode peak price shape, but also result in significantly higher system electricity demand, providing some support for load factors of more efficient CCGTs.
  • High volumes of gas peaker and short duration battery deployment may reduce the number of new CCGTs built, but at the same time increase wholesale margin rents in peak periods for those CCGTs that are developed.

Capital structure and route to market

One of the key factors bringing down the cost of new CCGT projects is the evolution of project capital structure. The traditional tolling contract model (tried by Trafford) is broken. But new sources of equity willing to bear market risk are emerging to underpin asset financing structures. This process is being helped by a strong willingness from turbine manufacturers to try and kick start a new generation of European CCGTs.

Route to market has also historically been a major hurdle for non-utility developers. Monetisation of CCGT value depends on access to sophisticated trading and optimisation expertise at a reasonable cost. The expense of developing this capability in-house has seen a growing ‘route to market’ service offering from established trading desks (e.g. Macquarie, Centrica, Gazprom Marketing & Trading). As services become more standardised, costs are also declining.

Ultimately a successful CCGT investment case is likely to be built around:

  1. A creative capital structure & competitive cost of capital
  2. An ability to quantify a robust breakdown of asset margin, recognising credible threats
  3. A capability to monetise that margin in the wholesale market and BM
  4. One or more specific value enhancing characteristics of the project

Specific project value sources are likely to be the difference between project FID and shelving. Capacity prices are unlikely to support substantial volumes of ‘generic’ CCGT projects. Instead successful projects need some competitive edge e.g. locational benefits, existing infrastructure, CHP revenue streams or short haul gas tariff benefits.

The UK government has tried to distance itself from picking winners. But it has created a policy and competitive landscape that has moved in favour of new CCGTs, despite the questionable logic of this given its emissions reduction goals. This may see several GW of new capacity developed by the mid 2020s. But the CCGT investment window is likely to be limited given the combined forces of decarbonisation and flexible technology innovation.

 

 

Barometers for LNG market tightness

Posted on by David Duncan

There seems to be an increasingly polarised debate about the state of LNG market balance.  This debate turns around use of the term ‘glut’.

In the red corner are the ‘supply glut’ crowd. Their view is that committed supply will outstrip demand for at least the next 5 years and that there is plenty of cheap gas beyond (e.g. from the US, Qatar & Russia) that should keep global gas prices subdued well into the 2020s.

In the blue corner are the ‘no glut’ crowd.  Their view is that robust Asian demand growth will absorb new supply, with gas prices set to rise imminently, in response to a requirement for new liquefaction in the next 3 or 4 years.

With any observed decline in spot LNG prices, plenty of noise can be heard from the red corner about the building glut.  On the other hand, any recovery in spot prices is a catalyst for the blue corner to embark on a bout of glut scepticism. It seems to us that there is a more constructive framework via which to track the evolution of the LNG supply & demand balance.

Regardless of market balance demand always equals supply.  What is important about current LNG market dynamics is that two key price responsive mechanisms are facilitating market balancing:

  1. Asian demand response – lower LNG spot prices triggering a pick-up in demand
  2. European power sector switching – gas hub price signals inducing higher CCGT load factors

It is these mechanisms that are worth focusing on rather than glut semantics.  In this context we set out two useful barometers for tracking LNG market balance.

Barometer 1: Asian vs European spot price spread

The first thing we watch for guidance on market tightness is the spread between Asian and European spot prices, illustrated in Chart 1.  This spread is a price signal for flexible LNG cargo flow to Asia vs Europe.

Chart 1: Spread between TTF and Singapore spot LNG marker

Source: Timera Energy (SGX for SLING data, ICE for TTF data)

This spread has been structurally converged since new supply started to outpace ‘business as usual’ demand growth back in summer 2014.  Since this time European hubs have been driving global LNG spot pricing given the role of the European gas market as swing provider. The resulting Asian vs European spread convergence sits within a range of tolerance, typically capped around the 1.50 $/mmbtu transport differential required to pull significant volumes of additional LNG supply from Europe to Asia.

Structural convergence does not preclude periods of temporary price divergence and volatility. The best example of this was the supply outage and cold weather driven events of Dec 16 – Jan 17 we described previously. This month Asian spot prices have again perked up, helped by pre-winter buying and hurricane damage at Sabine Pass, with the JKM spot marker now above 7.50 $/mmbtu in Nov/Dec.

The Asia vs European spot price spread is a better indicator of LNG market balance than absolute gas price levels.  This is because absolute gas price levels are strongly influenced by other commodity prices such as coal and oil.  For example a 20% rally in coal prices since June has been a key factor lifting the gas vs coal switching point in European power markets, in turn pulling up gas hub prices (as we set out in our Angle column last week).

Barometer 2: European LNG import volumes

The second indicator we are watching closely is the volume of LNG imports into Europe as shown in Chart 2.

Chart 2: European LNG import volumes by region

Source: Timera Energy

LNG cargoes that are surplus to Asian requirements typically flow to Europe. As a result, European import volumes are a useful indicator of how Asian demand growth is keeping pace with new supply.

European import volumes have been relatively strong over the last 12 months, particularly given robust Russian flows into Europe.  Power sector switching has enabled the European market to absorb this supply, helped by higher coal prices.

But LNG import volumes are yet to define a convincing trend back up toward pre-Fukushima levels.  Two factors have prevented a stronger growth in imports:

  1. Ramp up delays and outage issues with new production capacity (e.g. Gorgon, Sabine Pass)
  2. Robust Asian spot demand at lower prices, particularly from China this year

The LNG market has absorbed approximately 70 bcma (51 mtpa) of the current wave of new supply.  What remains uncertain going forward is whether Asian demand response & delays of new supply will continue to enable Asia to absorb the remaining 130 bcma (96 mtpa) of liquefaction capacity coming to market over the next 3 years.

To the extent that this is not the case then watch for European LNG import levels to rise.  If LNG flows to Europe do start to trend higher then the Asian vs European spot price spread will likely converge in a narrower range.  At that point convergence of the trans-Atlantic spread between NBP/TTF and Henry Hub also comes into focus as an important third barometer.

 

Power price analysis: focus on what matters

Posted on by David Duncan

We apply three simple rules when we analyse power prices:

  1. Confront the reality that the price forecast is going to be wrong
  2. Define the key market drivers likely to cause deviations from forecast
  3. Focus analysis on these drivers, rather than trying to capture spurious detail

This logic quickly points to the conclusion that fuel price assumptions are the primary driver of power price evolution. Taking the logic a step further, it makes sense to focus on the fuel price of the generation technology that dominates marginal price setting.

In the UK and Italy that is gas. In Germany it is coal. In markets such as France and Belgium it is a combination of the two.

There are of course other important drivers of power prices e.g. demand, capacity mix and cross border flows. But the impact of inputs such as half hourly wind profiles in 2032 are dwarfed by a 10% change in gas price assumption.

A UK power market case study

Let’s illustrate the importance of fuel prices using a practical case study from the UK power market. Chart 1 shows the monthly relationship between 2010 and 2017 of:

  1. UK month-ahead baselaod power prices (vertical axis)
  2. The fuel & carbon related variable costs of a CCGT asset @49% HHV efficiency (horizontal axis)

Chart 1: UK gas vs power price relationship

Source: Timera Energy

The strength of this relationship is pretty clear evidence of the fact that gas prices drive UK power prices. The carbon price is a second order driver, given it is a significantly smaller component of variable cost and carbon prices are currently relatively stable.

The deviations of power prices away from CCGT variable cost are predominantly explained by:

  1. Periods of CCGT margin rents (e.g. influence of coal units and start cost recovery in peak periods)
  2. System variable costs (e.g. Balancing Services Use of System (BSUoS) and flow based gas commodity costs)

It is only during periods of extreme market shocks that power prices materially diverge from CCGT variable costs e.g. during the French nuclear capacity closures in Q4 2016.Looking forward, the increasing penetration of renewables acts to erode the spark spread margin between CCGT variable cost and power prices. But gas prices are likely to remain a dominant driver of power prices well into the 2030s, given the influence of existing gas-fired capacity.

Fuel prices should be part of the analysis

We continue to be surprised how many power price forecasters avoid any detailed analysis of underlying fuel markets. Instead it is common to assume fuel curves are an exogenous input. In other words fuel prices only receive cursory consideration as assumptions, before the focus of modelling shifts to details of the supply stack.

What are your assumptions on Henry Hub gas price level, trans-Atlantic spread, Russian gas market share, Asian LNG demand and the cost structure of new LNG supply?  Different combinations of these gas market drivers determine whether European hub prices will be at 4 or 9 $/mmbtu (both numbers are quite plausible over a 10 year horizon).  In UK power market terms these gas price levels are broadly equivalent to power prices at 35 £/MWh or 65 £/MWh (an 85% range).

Fuel curves should be endogenous. In other words fuel price analysis should be just as much part of power market analysis as detailed stack modelling.

An even more dubious practice which is also common place is ‘borrowing’ public forecasts for commodity prices (e.g. from the IEA, EIA or other analysts). Or alternatively taking an average of multiple public sources to create a scenario soup.

Borrowing fuel prices may be convenient, but it ignores the fact that the assumptions behind these borrowed forecasts are almost certainly inconsistent with assumptions used for the rest of the power market scenario.

A robust understanding of power price evolution is built on an analysis of the fuel of the marginal price setting generators. Avoiding fuel market analysis is ignoring the crux of the problem. Outsourcing fuel curve assumptions is only a step away from outsourcing the power price forecast.

How Russia can balance the global gas market

Posted on by David Duncan

After the wild ride of 2014-16, a consensus is re-emerging as to the way forward for the LNG market. Across industry conferences, capital market presentations, analyst reports and bar stool discussions, you are likely to have heard a version of the following logic:

  1. Oversupply: There is a temporary oversupply due to committed global LNG liquefaction capacity, with 145 mtpa (200 bcma) coming online between 2015-2021.
  2. Demand growth: That oversupply will be eroded by LNG demand growth, particularly from emerging Asian buyers (e.g. China & India).
  3. Re-balance: Demand growth is likely absorb oversupply at some stage over the next 3-5 years, depending on the rate of Asian growth.
  4. New supply: At this stage, in the early to mid 2020s, new LNG liquefaction capacity will be required onstream to prevent a shortfall in the global gas market.

We agree with steps 1 to 3. But step 4 oversimplifies the dynamics around a requirement for new LNG supply. Why? In a word, Russia.

Russia can delay new LNG supply

By 2021 the global gas market will have 67 mtpa (90 bcma) of destination flexible, spot price responsive US LNG export capacity. This comes on top of substantial existing diversion flexibility in European LNG supply contracts (e.g. as was exercised to balance the global market across the 2011-13 post Fukushima period).

In this environment, it is difficult to define a credible scenario where Asian and European spot LNG prices diverge on a structural basis. There will be periods of short term price volatility, given delays in supply chain response time to spot price signals (e.g. 2 to 6 weeks). But any structural price divergence can be arbitraged by flexible supply.

In this new world, Russia can balance the Asian LNG market by increasing exports of pipeline gas to Europe and displacing flexible LNG supply. This puts Russia in a powerful position as the global market rebalances. We illustrate global rebalancing dynamics with a scenario of global supply and demand balance evolution in Chart 1.

Chart 1: Illustrative scenario of LNG and European gas market evolution to 2030

Source: Timera Energy

The chart shows liquid European hubs playing a key role in absorbing the temporary oversupply of LNG (primarily via gas for coal switching in the power sector). The bottom panel illustrates the global LNG market balance. Under the scenario shown (which assumes a lower Asian demand growth trajectory), oversupply is absorbed by 2022. But significant new volumes of LNG liquefaction capacity are not required until 2024.

The reason for this hiatus is Russia’s ability to flow up to 100+ bcma of existing ‘shut in’ gas production capacity (73+ mtpa equivalent).

Dynamics around shut in Russian gas

This shut in production capacity is located in West Siberian gas fields developed by Gazprom late last decade in anticipation of higher European demand growth. Loss of Russian domestic market share from Gazprom to other Russian ‘independents’ (mainly Rosneft, Lukoil and Novatek) has also contributed to the volume of shut in gas.

Gazprom has historically chosen not to flow this gas at price levels below existing long term oil-indexed contract prices. To do so would have acted as a catalyst for hub versus contract price divergence and development of hub liquidity, both of which Gazprom has considered to be against its strategic interests.

However over the last 12-18 months Russia has made a notable shift towards pursuing market share and adopting a more flexible stance on spot price indexation (e.g. via allowing TTF price corridor structures in a number of its long term supply contracts).

This may mean Gazprom defends a higher European market share (e.g. 160-170 bcma) than it has historically targeted (~150 bcma). But it still appears to be against Gazprom’s interests to push large volumes of new gas into Europe prior to global re-balancing. This would only induce a ‘bloody’ short run marginal cost driven price war e.g. by attempting to shut in US export capacity at sub 4.00 $/mmbtu European hub prices.

Instead, this surplus of ‘shut in’ gas puts Russia in a strong pricing position once the current LNG oversupply is absorbed. As long as Gazprom sells this gas into Europe at a sufficient discount to new gas supply project LRMC, it can delay marginal new LNG supply (e.g. in the form of ‘second wave’ US export projects).

Russian disruption is important but only temporary

This ability to delay new liquefaction projects is only a temporary situation. The extent to which Russia can exercise its power depends on the rate of global demand growth. It also depends on the volume of new LNG liquefaction capacity that is committed (i.e. progresses past FID) over the next 5 years. Once new liquefaction capacity is committed, Russia needs to compete with it on an SRMC rather than an LRMC basis (given sunk costs).

For these reasons it is unlikely that Gazprom manages to export the full 100 bcma of incremental production capacity to Europe. Russian influence is likely to be limited to a 3 or 4 year period. This may only be 1 or 2 years if you assume robust global demand growth and early FIDs of new liquefaction capacity.

But a production volume this large definitely has the potential to disrupt a smooth transition from oversupply to deficit in the LNG market (implied in step 4. of the logic in the first paragraph). And the threat of this disruption impacts FID decisions on new LNG projects today.

Beyond this temporary influence of Russia, the LRMC of new LNG supply is set to reassert its influence on global gas pricing.  But the capital structure and business model for delivering the next wave of new liquefaction capacity is likely to look very different to the current wave of supply. We will come back to explore this dynamic in more detail shortly.

Investment in flexibility: gas peakers

Posted on by David Duncan

A major transformation is underway in European power markets. Ageing coal, gas and nuclear plants are retiring and being replaced to a significant extent by renewable capacity. Loss of existing flexible plants and the inherent intermittency of wind and solar output is driving a requirement for substantial investment in new flexibility.

Interconnector investment and transmission upgrades can play a role in facilitating the more efficient integration of existing system flexibility. Batteries are emerging as a key provider of balancing services, although not yet load-shifting (as we set out last week). There is also a technology driven push towards more demand side flexibility. But there remains a key system requirement for flexible thermal generation capacity.

Investment in flexible thermal capacity over the last 3 decades has been dominated by large grid connected CCGTs. But investment in distribution connected peakers has surged over the last 3 years, particularly as a source of new capacity in the UK power market (with 3.5GW successful in UK capacity auctions to date).

Peaker investment is now focused on gas-fired technologies, particularly distribution connected reciprocating engines. These units represent a relatively cheap source of low load factor flexibility. However there are a number of different types of technology in play and an important trade-off between cost & efficiency.

Gas engines have a capital cost advantage over CCGTs (400-450 $/kW vs 650-700 $/kW). Fixed costs of CCGTs (around 25 $/kW) can be more than 50% higher than those of gas engines. Engines are significantly more flexible than CCGTs and have lower start costs. Peaker economic lives are also shorter than for CCGTs (e.g. 15 vs 25 years) which reduces the risk of assets becoming uneconomic or stranded in later life.

In today’s article we look at investment in UK gas engines as a case study of project economics and challenges.

Margin breakdown

There are two main reasons why the UK has so far led European peaker investment. Firstly the UK faces a serious deficit of flexible capacity as older coal and gas plants retire. And secondly the policy environment is relatively favourable in defining clear sources of ‘stackable’ peaker margin.

Margin can be broken down into 4 streams:

  1. Capacity margin: Driven by the evolution of pricing in the UK capacity market.
  2. Energy margin: Driven by margin capture in the wholesale energy market & balancing mechanism (BM), a function of the evolution of spark spreads, peak pricing dynamics, volatility & imbalance volumes.
  3. Balancing services: Focused on revenue from the Short Term Operating Reserve (STOR) market, with peaker revenue potential from other ancillary services limited by alternative sources of rapid flex (e.g. batteries & pump hydro dominating frequency response services).
  4. Embedded benefits: Available to distribution connected peakers, with revenue predominantly driven by helping suppliers avoid demand charges (e.g. triad benefits), but taking a bit hit from the recent Ofgem decision to scale back embedded benefits.

The challenge in quantifying risk & return across these margin streams is that they are neither mutually exclusive or independent. Margin can be ‘stacked’ across streams, but there is a strong co-dependence of returns. For example a peaker cannot provide committed STOR services at the same time it is operating in the wholesale market.

This means that the returns across margin streams depend strongly on the monetisation strategy of the peaker operator. Chart 1 gives some guidance on approximate ranges of:

  1. Margin by stream (note margin potential depends on monetisation strategy and margin streams are not simply additive given codependence).
  2. Total margin required to earn a low to mid double digit IRR (note this in part depends on capex variance across different gas engine technologies).

Chart 1: UK gas reciprocating engine margin ranges

Source: Timera Energy

Capacity margin is the foundation of peaker investment. Uncertainty around this margin stream is reduced by 15 year capacity agreements with a fixed price (indexed to inflation). Peaker developers require the capacity price to clear above a certain level to support the project (e.g. in the 25-35 £/kW range). But once this is achieved this margin stream is relatively secure and can be used to support debt financing.

The interaction between wholesale margin/BM and STOR/embedded benefits margin streams is much more challenging. Realistic quantification of margin capture in the wholesale market is the critical component of peaker economics. This requires robust probabilistic analysis of asset value capture from power price shape and volatility.

In quantifying these margin streams, an optimisation approach must be adopted that is consistent with the way a trading desk actually manages peaking units in practice.  Analysis of wholesale margin also depends on realistic assumptions about how peaking units can be optimised across codependent margin streams e.g. STOR, triads, wholesale energy & BM.

Revenue stacking is not magic.  In a post triad world it is tough to build a realistic margin case for gas engines that yields healthy double digit returns. The definition of realistic margin numbers has to be founded on a pragmatic analysis of how wholesale and BM margin can be captured in practice as the UK market evolves.

Business model & route to market

In building a viable investment case, there are a number of challenges a peaker developer faces. Securing advantaged sites. Sourcing competitively priced units. Access to financing. Site management. Unit operation and maintenance. Regulatory risk around revenue streams. But the toughest challenge is margin stream optimisation and market access.

Margin streams for flexible generation units have traditionally been optimised by the established trading desks of large utilities. Here, the significant overheads of operating a sophisticated trading desk and risk management function are spread across a large generation fleet.

Peaker developers can choose to outsource margin optimisation to an established trading desk. But this typically involves taking a significant margin haircut as well as giving away margin upside (via profit sharing). This can result in a major hit to project economics.

This has driven the more established peaker developers to develop in-house commercial capabilities to optimise margin across co-dependent streams. While an in-house capability sounds sensible in principle, it is challenging for a relatively small peaker developer to match the scale and sophistication of a large trading desk.

Good traders need practical experience and this means attracting them away from well paid jobs on established trading desks. Robust trading and risk management systems are expensive and typically require portfolio scale to support implementation. There are also a number of commercial and risk governance issues that require experienced headcount and processes. These functions are not the traditional domain of smaller scale asset developers.

Competition & scalability

Beyond the economics of an individual project, peaker developers face an important question of scalability. The UK market needs investment in new flexible capacity, particularly as coal and nuclear plants retire over the next decade. But peakers face competition from:

  1. New CCGTs: relative project economics have improved significantly over the last 12-18 months, as has access to capital. Watch out for new CCGTs if capacity prices start clearing above 30 £/kW.
  2. Existing CCGTs: The capacity market is also supporting life extensions of existing CCGTs e.g. via bypassing steam turbines and running GTs (as a number of owners have already done).
  3. Interconnectors: More than 4GW is already under construction with a pipeline of 8GW+ behind.
  4. Batteries: Currently have specific frequency response applications but may be deployed more broadly from the later 2020s (see last week’s article).
  5. DSR: Over time, technology driven innovation is set to increasingly boost demand side flexibility.

The growth potential of peaking units is a function of how these sources will compete in combination with renewable rollout, to drive the evolution of the UK capacity mix. Peakers are set to play an important role, but not necessarily a dominant role.

 

 

Investment in flexibility: battery storage

Posted on by David Duncan

Electricity flexibility investment

We are starting the second half of 2017 with a mini-series on investment in electricity system flexibility.  Today’s article looks at investment in grid scale battery storage.  We then return next week to contrast this with the investment economics of gas-fired peaking generators.  We will come back to investment in alternative sources of flexibility (e.g. CCGTs, interconnectors and DSR/distributed flex) as the year progresses.

Flexibility remains a central challenge in a decarbonising and decentralising energy system. Substantial cost reductions in wind and solar capacity are underpinning a robust pipeline of renewable capacity development across Europe. But this requires major investment in flexibility to facilitate swings from intermittent output.

Until recently, consensus was that this flexibility was going to be dominated by gas-fired generators and improvements in interconnection.  But rapid costs declines and deployment of battery storage is challenging this view.

The UK power market is leading European investment in the deployment of both battery storage and gas peaking assets. This is being driven by a tight UK reserve margin and a relatively supportive regulatory framework for investment in new flexible capacity.  So as we look at investment in batteries vs peakers, we use the UK market as a case study to illustrate the practical challenges facing asset investors.

Batteries: state of play

There is a dazzling array of potential battery storage applications.  But to date, the practical focus for commercial deployment has been investment in lithium-ion batteries to provide system services.

Growth in lithium-ion battery deployment is being driven by very rapid cost reductions. Only 2-3 years ago battery costs were in excess of 1000 $/kWh.  Tesla made headlines this year with a 250 $/kWh ‘pack level’ cost for 129 MWh battery system it is deploying in South Australia (the world’s largest to date).  This headline grabbing price tag excludes some important cost components.  But even accounting for these, grid scale battery costs may decline to under 200 $/kWh by the early 2020s.

The batteries currently being rolled out can provide very fast (sub-second) output response, but only over a short duration (e.g. 1 hour).  This means that they are well suited to servicing an increasing intermittency driven requirement for rapid frequency response services. Batteries can also be used to defer the costs of investment in grid upgrades. But short duration batteries are not designed to provide wholesale market arbitrage or ‘load shifting’ services.

That doesn’t mean that ‘load shifting’ batteries for wholesale market application should be written off.  There are already 4-6 hour duration batteries at the development stage. But the cost structure and cycling limitations of long duration batteries means that load shifting is not yet commercial.

The question looks to be when, rather than if, technology will progress to support broader commercial deployment of load shifting batteries (mid/late 2020s?).  But for now we focus on investment in short duration batteries.

UK focus for battery investment

Back in 2014 a 6MW, 10 MWh battery was developed at Leighton Buzzard in the UK. At the time it was the largest battery storage development in Europe.  Development relied heavily on support from the UK Low Carbon Networks Fund.

It was almost inconceivable that two years later, 500MW of batteries would be successful in the Dec 2016 UK capacity auction. A combination of technology cost declines and a constructive regulatory framework has catapulted the UK into global pole position for grid scale battery investment.

The rapid growth potential for batteries in the UK is illustrated by the system operator (National Grid’s) latest Future Energy Scenarios projections.  Grid projects more than 2GW of growth in UK electricity storage capacity over the next 5 years, in all four of its scenarios for capacity mix evolution.  The driving forces: declining battery costs and an increase in system requirement for rapid frequency response services as wind deployment grows.

UK battery investment case study

Commercial deployment of batteries in the UK is attracting a lot of investor attention. In a world of depressed infrastructure yields, battery developers are targeting double digit project returns.  There is also a compelling story around scalability, both within the UK market and in Continental Europe.

But project yields reflect risks. Battery investment is by no means a one-way bet.  In Table 1 we set out 5 key challenges facing battery investors.

Table 1: Challenges with UK battery investment

Consideration Getting comfortable
1. Investment model Scalability. Route to market. Contracting model. Integration with peakers or wind. Define business model & growth options. Benchmark contracting & 3rd party options.
2. Competitive dynamics Battery growth & risk/return vs e.g. CCGTs, peakers, ICs, pump hydro. Cost declines. Analyse (i) UK market rapid flex requirement (ii)  battery economics vs peakers/ CCGT/ICs.
3. Frequency Response FR revenue as capacity mix evolves. Grid ‘SNaPs’ review on buying FR services. Model evolution of FR market revenues & impact of wind, peaker, battery roll out.
4. Capacity Revenue Evolution of UK capacity prices. BEIS review of duration linked derating factors. Model evolution of pricing of 15 yr capacity contracts & overlay of duration derating.
5. Other margin & support Embedded benefit revenues. Impact of new battery policy support measures. Quantify stacked embedded benefit returns & risk/return impact of evolving policy.

Source: Timera Energy

The first challenge for investors is defining a viable business model to support asset risk/return and growth targets.  Most investors are currently looking at batteries as an integrated play with other assets.  There are revenue management and risk diversification synergies from building a portfolio of batteries and peakers (e.g. gas engines).  There are also potential co-locational benefits of integrating batteries with renewables. In all cases the battery business model relies on a route to market, to manage the interaction between stacked revenues (e.g. across balancing services, embedded benefits, wholesale market).

The policy framework to support batteries is more advanced in the UK than most other power markets.  This is underpinned by relatively well defined revenue streams for frequency response, capacity payments and demand charge avoidance.  But UK electricity storage policy is still evolving rapidly, causing inherent investment risks, for example:

  1. Frequency Response: Grid launched a comprehensive System Needs and Product Strategy (SNaPS) review of the way it procures balancing services in Jun 2016. This will likely result substantial changes to frequency response service procurement (e.g. replacement/aggregation of Firm Frequency Response and Enhanced Frequency Response services).
  2. Capacity Market: BEIS (UK Department for Business, Energy and Industrial Strategy) launched a consultation in Jul 2017, indicating its intention to scale battery capacity payments based on discharge duration. This may significantly reduce revenues under 15 year capacity agreements, particularly for the more cost effective short duration batteries.
  3. Broader policy support: BEIS also provided broad guidance in Jul 2017 of its intention to improve policy measures to support investment in battery technology. This includes cutting ‘double charging’ for system usage, facilitating colocation with renewables and smoothing the connections process, the investment impact of which depends on details yet to be announced.

Ultimately battery investment comes down to numbers.  Quantifying battery project risk/return involves a ‘revenue stacking’ problem.  In other words revenue is aggregated across co-dependent revenue streams.  In the UK there are three key components that make up battery returns (listed in order of importance):

  1. Frequency Response: The UK rapid FR market has historically been dominated by the 2GW First Hydro pump storage assets. This market currently presents a lucrative source of returns for batteries which can provide even faster response than pump hydro.  But the supply & demand dynamics in the FR market are complex and depend on the pace of roll out of batteries vs wind.  Returns are likely to be volatile and there is a risk that battery rollout outpaces system requirements, driving down FR returns.  The policy implications of the SNaPS review are also key.
  2. Capacity Payments: 15 year fixed price capacity agreements were very attractive in the 2016 capacity auction given battery storage derating factors of 96%. However the majority of successful batteries fall into the 0.5-1.5 hour duration categories that are most at risk from BEIS policy changes.  This impact may be partly offset however by rising capacity prices given negative policy impacts on peaker economics (e.g. reduction of the triad benefit).
  3. Other margin: Batteries can access a range of embedded benefits, focused on avoidance of demand side charges. But revenues depend on location and the key triad benefit is set to decline steeply by 2020. Batteries can also have specific opportunities from operation in the wholesale market, although this depends on duration and cycling costs.

Investors are running the numbers as developers raise capital for both existing and planned battery projects. The next UK capacity auction in Feb 2018 will be a key test for batteries under a rapidly evolving policy landscape. And while the UK may have a head start on battery deployment in Europe, other markets are rapidly catching up, particularly Germany.

The Timera Blog is about to evolve

Posted on by David Duncan

We have been publishing a weekly blog for 6 years now. Our regular readership has grown to more than 15,000 and the blog has evolved into one of the industry’s leading sources of views and analysis on the LNG and European gas & power markets.

The blog has been developed based on several key principles:

  1. Opinion: Publishing clear views based on our practical experience working in the energy industry
  2. Analysis: Supporting those views with thorough and transparent analysis
  3. Challenge: Aiming to challenge industry consensus where our views differ
  4. Independence: Ensuring objectivity and a clear separation from our client work
  5. Transparency: Maintaining an archive of all articles, whether our views prove to be accurate or otherwise

These principles remain core to the evolution of the blog.  But the time has come to grow and evolve.

So what’s new?

We will continue to publish our regular weekly analytical articles. But we are launching a new blog page after we return from a summer break.  A preview of the page can be seen below.

As well as providing access to the current and recent weekly articles (via the top panel shown in the picture), the blog page will have two new content columns.

Timera Angle column

The left hand ‘Timera Angle’ column will provide you with shorter, sharper written content than our regular blog articles.  A starter to compliment the main course.

Our focus here is the efficient delivery of views and opinions, backed by relevant facts and data.  Where it makes sense, we will also provide links to other useful sources of information (e.g. presentations, briefing papers, articles, data sources).

In terms of content our, aim is to keep a practical commercial focus. To provide you with information and views on investment, value management and markets that has a tangible application.

An example of ‘Timera Angle’ content is shown below.

Timera Snapshot column

The right hand ‘Timera Snapshot’ column is focused on fast dissemination of information using visual content e.g. charts and tables. You can digest the key messages from these ‘Snapshots’ in seconds.  If the material is relevant then you can examine the information provided in the charts/tables in greater detail via a pop out graphic.

As Timera has evolved we have developed large databases of market and commercial information.  We also have a range of analytical tools and models that draw on this data to provide us with a ‘dashboard’ view of the evolution of markets, asset value drivers and risks.  This generates a rich source of information that we intend to share via this column.

An example of ‘Timera Snapshot’ content is shown below.

Mining the archive

One of the weaknesses of our blog to date has been the categorisation and tagging of articles and the ability to search previous published content via the blog archive.  This is a shame given many of our blog articles contain information, analysis and charts that have a relatively long shelf life. We are addressing this by building a new Blog Archive page with enhanced search functionality.

Firstly we are re-categorising and re-tagging all our articles using a cleaner structure of keywords.  The new Blog Archive page will then allow you to bring up a list of articles by filtering with a specific chosen set of keywords.  Alternatively you can choose your own keywords by typing into a blog search box.

Expanding team, expanding content

Timera as a company is also evolving and growing. Our core focus is still Europe, but this is extending to a global reach, particularly due to our expanding presence in the LNG market.  This is reflected in the fact that a growing proportion of our clients are Asian and North American companies.

Our team is also expanding.  But the common theme across our team members is still senior ex-industry experience, in order to maintain our delivery of practical commercial advice.  As our blog content evolves, we intend to draw on wider input across our growing team to improve the depth and breadth of the views and analysis we publish.

This will be the last article before a summer break.  In the meantime we will be working to implement the changes described above. The blog will be launched in its new format in late August.  We will also be distributing content using Twitter and Linkedin.

Until then, we thank you all for your continued interest in the blog and wish you a relaxing summer break.

European gas supply sources: Norway

Posted on by David Duncan

Norway benefits from low sovereign risk, commercial flexibility and close proximity to key gas demand centres. Norwegian exports to Europe hit a record 108.56 bcm in 2016, more than 20% of total European gas demand. But this may well have marked the peak in Norwegian market share.

Norwegian gas production from existing fields is maturing and new gas is becoming more difficult to access. Norway is also cutting upstream investment expenditure, driven in part by a lower oil and gas price environment.

Chart 1 shows a projection of Norwegian production, plateauing this decade, then declining in the 2020s.

Chart 1: Monthly Norwegian exports to the UK & Continent

Source: Timera Energy

The chart also illustrates the pronounced Norwegian seasonal production pattern, which provides the European market with a key source of seasonal flexibility in addition to gas storage capacity.

Diagram 1 provides an overview of the Norwegian pipeline network, which allows access to UK, Germany, Belgium & France.

Diagram 1: Key Norwegian pipeline supply routes

Source: Timera Energy

On average about 75% of Norwegian gas flows to the Continent, predominantly via long term hub indexed contracts. There is ample capacity headroom into the UK, but there can be constraints on flows into the Continent.

However flow volumes to the UK versus the Continent can fluctuate significantly, driven by factors such as LNG import volumes, weather patterns and power sector gas demand. The loss of the UK’s Rough storage facility has also had a major impact on flows. Norwegian exports to the UK are becoming more seasonal in order to ‘backfill’ lost storage deliverability across winter, while making way for UKCS production no longer injected into Rough across the summer.

Hub indexation of long term contracts means Norwegian gas flows are driven by spot price signals. That is also true of the significant volume of uncontracted Norwegian production, which Statoil optimises against UK vs TTF/NCG/Zee hub price signals. This ability to optimise delivery across the multiple entry points shown in Diagram 1, provides important shorter term deliverability flexibility to the European gas market. The ability to arbitrage price differentials across hubs also underpins the structural price convergence across North West European hubs.

But is Norway a contender in the evolving battle for European gas market share? In a word no. Norwegian export volumes are driven by an annual government production mandate that is set to decline as production matures. Norway will continue to be a key exporter to Europe for many years to come. But it will watch the evolving battle between Russian and LNG imports as a price taker from the sideline.

Article written by Olly Spinks & David Stokes

 

Practical view of Brexit impact on UK gas market

Posted on by David Duncan

The uncertainty surrounding Brexit is a breeding ground for theories and threats. There are some genuine economic risks posed by Brexit that may have a knock on impact on energy markets. But some increasingly exaggerated claims are circulating as to the direct impact of Brexit on the UK gas market.

We are particularly sceptical about the ideas that:

  1. “Trade barriers will be imposed on gas”
  2. “A major shift in gas regulatory policy will take place”
  3. “The UK’s gas security of supply will be compromised”
  4. “UK hub liquidity will disappear”

We look at the potential implications of Brexit in these four areas in today’s article. This is also directly relevant to the UK electricity market, given the importance of the UK gas market as a driver.

UK gas trade barriers

In terms of the UK’s future trade & economic relationship with the EU, the two most likely outcomes appear to be either:

  1. A negotiated trade deal: which (from the EU side) would be inferior to the terms of EU Membership, and from the UK side would have to be more attractive than the WTO option
  2. The WTO default option: which provides a ‘floor’ above which an eventual negotiated settlement can be measured on the basis that ‘no deal is better than a bad deal’.

Several industry and media sources have raised the prospect of new tariffs being placed on gas flowing between the UK and EU Member States (Ireland, Netherlands, Belgium) and by extension Norway (an EEA/EFTA Member). Notwithstanding a possible political desire to ‘punish’ the UK (‘pour discourager les autres’), this is a poorly constructed argument on several levels.

The purpose of a tariff is to protect and incentivise ‘domestic’ production by making imports more expensive. But both the UK and continental Europe in aggregate are net importers of gas. Therefore it makes eminent sense for the UK and EU parties to encourage the efficient sharing of gas. In the case of the UK and North West European regions the same logic applies to gas flows. Given both regions have liquid gas trading hubs, flows should respond to price with minimal tariff barriers.

The UK is a large export market for Norwegian gas (supplying some around 37% of UK requirements in 2016). Furthermore the pipeline infrastructure from Norway to the European continent has insufficient capacity to take all Norway’s output. Norway would be unwilling to be penalised by having a tariff charged on its pipeline exports to the UK and lose out to LNG imports paying nothing.

But the situation is more complicated than this. With the closure of Rough storage, flows between the UK and NW Europe are set to become even more seasonal. This means higher exports from the UK in summer as LNG imports and Norwegian gas, surplus to the UK’s immediate requirements, seek storage capacity in onshore North West European facilities. In the winter, the UK will receive higher flows from NW Europe (storage withdrawals, Dutch production and Russian pipeline flows).

The imposition of tariffs on gas flows in both directions between the UK and the Continent would benefit the respective governments of Belgium, Holland and Norway (and the UK if it chose to retaliate with a tariff charge on imports from the EU and EEA). But tariffs would create periods of dislocation between TTF and NBP, probably partially ameliorated by LNG arbitrage. Norway would still need to send considerable volumes of gas to the UK as its pipeline delivery system to the Continent is close to capacity in winter months with high volumes to the UK.

Before going further down this road of speculative cause and effect, it is worth asking if this is really a likely outcome? We can shed light on this question by looking at the tariffs imposed by the EU to a range of non-EU member countries in Table 1.

Table 1: EU tariffs on non-EU member countries

Source: EU Tariff Tables (Code: 2711)

With the EU a long-time net importer of pipeline gas and LNG it is perhaps no surprise that it imposes zero tariff on imports.

So if there was to be a post-Brexit tariff imposed by the EU on imports/exports of gas with the UK, it would likely be in the context of a ‘punitive’ deal offered by the EU to the UK. In this outcome the UK may (as has been stated as its ‘negotiating position’) opt for ‘no deal’ and a default to WTO terms.

What does the WTO have to say about gas trade tariffs ? Inspecting the WTO database it is clear that the EU applies no tariffs to either natural gas or LNG under WTO terms.

Given the above it is reasonable to conclude that there is little if any prospect of post-Brexit tariffs being applied to gas flows between the UK and the EU/EEA.

Gas Regulatory Framework Development

The EU on the European continent lagged the UK in liberalising its gas markets by several years. Although the development of EU gas market regulation was based on a ‘from first principles’ approach, the active involvement of interested UK players ensured that ‘lessons learned’ from the UK experience were incorporated. This has led to the UK and EU being reasonably harmonised on gas regulation, with the exception of those continental member states who have been slow to adopt some regulatory packages in full.

UK interests and policy to date clearly support free unimpeded interflow of gas with the European continent in response to hub price signals. As a result it is reasonable to expect that UK regulatory authorities (and industry participants) will continue to broadly comply with future regulatory developments.

Gas Crisis/Security of Supply Management

A set of Draft Security of Supply Regulations published in 2016, shed some light on the EC’s approach to a major supply disruption. The key principle is that in the situation where a key European gas supply source is cut off, the allocation of supply would be taken over ‘by committee’. This approach might conceivably work in some specific cases, for example a group of East European markets with no trading hubs, state monopoly system operators and suppliers/distribution companies and one or two sources of cross border imports. But it seems inapplicable to the liberalised gas markets of NW Europe.

In a supply crisis a ‘committee of the great and good’ on the above model would have to:

  1. Suspend trading on TTF or other liquid hubs (and potentially compensate for losses/declare force majeure)
  2. Take over the control of flows into or out of the bloc of countries forced to share supply and optimise the distribution to customers on a merit order basis, as well as regulating a storage drawdown
  3. Presumably impose a wholesale and retail price controls to guard against speculation.

What seems more practical is the present system of national response, where the system operator intervenes to shed industrial demand in the face of a supply shortfall. The price signals between hubs in northwest Europe will perform a faster and more efficient job of allocating supply and storage withdrawals than any committee (as shown by the Russian gas supply crisis in February 2012). The exclusion of the UK from this framework post Brexit in practical terms is immaterial. Even if invoked it would be unworkable.

Nevertheless this leaves the EU member state of the Republic of Ireland in a seemingly vulnerable position. It has recently brought onstream the much-awaited Corrib offshore field which for a few years may cover some 60% of domestic demand. However the balance is imported from the UK.

Once the Irish Kinsale Head and Seven Heads gas fields commenced decline, imports from the UK met the balance of Ireland’s requirements from 1995 to the present day. Against the backdrop of UK taxpayers bailing out Irish banks after the financial crisis to the tune of £14bn with no popular dissent, it is inconceivable that the UK, post Brexit would fail to supply Ireland with gas (via pipeline interconnectors). Even without the Corrib Field, this is only 5 bcma, just 6% of UK consumption.

NBP vs TTF hub dynamics

The biggest practical impact of Brexit on the UK gas market may be its impact on relative pricing and liquidity of the UK NBP and Dutch TTF hubs.

The key differences between these two hubs are:

  1. NBP is sterling denominated; served by (declining) UK production, Norwegian imports and some 48 bcma of LNG import capacity.
  2. TTF is Euro denominated; served by (declining) Dutch production, Norwegian imports, Russian imports and 12 bcma of LNG capacity in the Netherlands (plus 9 bcma in Belgium).

In recent years TTF has been in the ascendancy, overtaking NBP in terms of total trading volumes. TTF also now has a futures curve at least as liquid, and therefore useful for risk management, as the NBP. Brexit will likely support a continuation of that trend, particularly given the additional risk associated with GBP exchange rate volatility post Brexit.

But this does not mean that UK gas market liquidity is going to disappear. The recent move to merge the TTF hub and BBL pipeline to cut the cost of the Dutch-UK gas flow illustrates that both hub areas are deemed to be important. It also demonstrates that the view that the UK will be ‘cut off’ from the Continent post Brexit does not seem to be shared by key players. This is reinforced by the UK’s role as a desirable destination for LNG cargoes given substantial regas capacity and liquid market access.

Instead of disappearing, the UK NBP is evolving into a ‘satellite’ hub to TTF. European gas prices are anchored by the TTF hub in EUR terms. NBP prices then reflect any EUR-GBP exchange rate movements (which create additional NBP volatility) as well as the variable transport cost differential to TTF. Major NBP and TTF divergence typically only takes place during periods of interconnection constraints. It is market forces that will dominate the evolution of NBP and TTF, not Brexit related regulatory intervention.

Article written by David Stokes & Olly Spinks

European midstream gas infrastructure in focus

Posted on by David Duncan

Midstream gas assets are coming back into focus after a lull across the first half of this decade. A 20% decline in European gas demand between 2010 and 2015, caused a pronounced erosion of midstream asset utilisation and capacity value. But the sands are shifting as European gas supply dynamics change and demand continues to recover.

Midstream asset transaction momentum is starting to build again. Last year saw EPH sell a 30% stake in its key Slovakian transit pipeline & storage business, with Global Infrastructure Partners selling its 45% stake in the Transitgas pipeline into Italy. EDF, Uniper & Edison are currently in the process of selling equity stakes in French and Italian regas terminals. The gas storage market is also coming to life, particularly in the UK given the permanent closure of Rough.

In the more than 20 years we have been working in European energy markets we cannot remember a time of greater divergence in views on gas market evolution. This lack of consensus on supply mix, flow patterns, midstream asset utilisation and capacity value is an environment of opportunity for investors. But how do you think about midstream asset value?

Europe in a state of transition

The key force acting on the supply side of the European gas market is rising import dependency. This is reflected in increasing Russian import volumes in 2016-17, accompanied by an ongoing shift in flow patterns as Gazprom favours the Nordstream (Baltic) routing over Ukraine. European LNG imports and regas terminal utilisation have also risen to their highest level in five years.

The fact that Russian and LNG imports are rising together reflects growth in European gas demand, with a 27  bcma (5.4%) increase in 2016. 20 bcma of this was driven by higher power sector demand as coal plants were switched for CCGTs. The evidence so far in 2017 points to a continuation of that trend.

Even the substantial overhang of gas supply flexibility is starting to abate. Centrica Storage has now announced permanent closure of its large UK Rough storage facility (more than 70% of UK working gas volume). Further storage closures and capacity reductions are looming on the Continent. And European upstream flexibility is declining as field production matures (particularly given rapidly lowered volumes from the Dutch Groningen field).

Midstream infrastructure map

A map is a good place to start when considering the impact of this European gas market transition on  midstream gas infrastructure. Diagram 1 shows the key supply routes into the main European market hubs. Volumes of storage capacity and LNG regas terminal capacity are also shown.

Diagram 1: Summary of key European midstream infrastructure

The structural trend behind the transformation of the European gas market, is a terminal decline in production, which is projected to fall from 246 bcma in 2016 to 165 bcma by 2025 (volumes including Norway). This widening gap is driving an increase in European import dependency.

Europe’s sources of imported supply can be grouped into four categories:

  1. Russia: Europe’s dominant existing supplier with around 150 bcma of long term contracted ‘take or pay’ volumes, and a further 100 bcma of ‘shut in’ West Siberian gas production that could support additional sales to Europe.
  2. LNG: Europe has ample regas capacity headroom and there is more than 150 bcma of new global liquefaction capacity under construction, but European LNG import volumes will strongly depend on demand growth in Asia.
  3. Norway: Norwegian production is managed to an annual target (~110 bcma), which is set to decline into next decade as existing fields mature.
  4. Mediterranean: North African supply from Algeria and Libya is set to decline into next decade, partially offset by limited growth in imports of Azerbaijani gas into Italy via Southstream.

In a nutshell, the next stage of evolution of the European gas market comes down to a battle between Russian and LNG imports. In our briefing pack on midstream assets we set out two scenarios contrasting ‘LNG Dominance’ vs ‘Russian Dominance’. The volumes and routing of Russian vs LNG imports is set to be the key factor driving midstream asset utilisation and capacity value into next decade.

5 drivers of midstream asset value

One of Timera Energy’s key areas of engagement is advising ‘buy side’ investors on the value of pipelines, regas terminals and storage assets. In doing this we aim to understand and quantify the impact of 5 key drivers of asset value. These are summarised in the table below along with examples. Extrinsic value of UK regas & storage capacity set to rise with spot price volatility given Rough closure

Table 1: 5 drivers of European midstream asset value:

Driver Dynamics Example
1. Utilisation Evolution of supply volumes, routes and flow patterns drive capacity utilisation LNG import growth will drive regas utilisation and pipeline flow volumes in UK, Netherlands & France
2. Constraints Physical and contractual constraints drive capacity value premia Value premia from contractual pipe constraints into Italy and physical Spain/France pipe constraints
3. Flexibility value Interaction between physical asset flex and market price signals drives asset extrinsic value Extrinsic value of UK regas & storage capacity set to rise with spot price volatility given Rough closure
4. Liquidity access Access to liquid hub price signals drives ability to monetise capacity value Dutch & UK storage assets have clean access to liquid forward curves vs e.g. Czech & Slovak assets
5. Regulation Regulations on access, tariff structure and security of supply impact capacity value Regulated tariffs drive competitive variable cost dynamics impacting regas & pipeline utilisation

Source: Timera Energy

There are of course other important considerations driving midstream asset value, for example legacy long term contract position, expansion options, interaction with adjacent assets and commercial flexibility to monetise capacity value (e.g. via overselling). But if you can develop a structured view on the 5 drivers in the table and quantify their impact on asset risk/return it builds a strong investment case foundation.

Article written by David Stokes & Olly Spinks

Client briefing: European midstream gas

A Timera Energy client briefing pack on midstream assets can be downloaded here:

European midstream gas: Asset value drivers & market evolution