16/05/18 – The Prospects for Gas Storage

Speakers: Roddy Monroe, Independent Chair of the Gas Storage Operators Group; Nick Perry, Senior Advisor, Timera Energy; Will Webster, Energy Policy Manager, Oil and Gas UK

26th May 2018

All-Party Parliamentary Group on Energy Costs

 Prospects for Gas Storage

Chair: Lord Palmer

Speakers: Roddy Monroe, Independent Chair of the Gas Storage Operators Group; Nick Perry, Senior Advisor, Timera Energy; and Will Webster, Energy Policy Manager, Oil and Gas UK

Chair’s Opening Remarks:

I’d like to extend a warm welcome to you all to this, the 43rd meeting of the All-Party Parliamentary Group on Energy. I am Lord Palmer, co-Chair of this Group and an elected hereditary crossbench peer.

This afternoon we are examining the prospects for gas storage.

The closure of the Rough facility, imports of Russian LNG, and the Beast from The East have together raised concerns over security of gas supply.

The UK has relied upon supplies from the North Sea and imports across interconnectors and LNG facilities to meet peak demands.

Historically, those supplies were also backed up by the storage at Rough, which is no longer available. This winter National Grid indicated to the market that more supply was needed and some industrial customers and power stations were paid to reduce their loads.

Supplies were not interrupted, but concerns were raised. In future coal-fired generation will not be available to replace gas-fired capacity if there is a shortage of gas.

The spread between winter and summer gas prices has rarely been large enough for it to be economic to build new gas storage. Some have argued that the Government should require that new storage capacity is built and the costs should be paid from a levy on the gas market.

Many market participants argue that the market works perfectly well and no intervention is required. We expect to hear both sides of this argument at this meeting.  We have three excellent and very pertinent speakers I have asked them each for 5-7 minutes opening remarks after which we will go on to our normal Q&A.

Roddy Monroe, Independent Chair of the Gas Storage Operators Group

The answer to the question ‘what are the prospects for gas storage?’ can be helpfully summarised as ‘Not particularly good’

To provide some context around this I will look at 4 things:

  1. Why is gas storage important to energy costs?
  2. What are the challenges for existing storage facilities and for new investment?
  3. Why should policymakers care?
  4. Potential solutions


  1. Why is gas storage important to energy costs? There are two main reasons:
  • First, markets with plentiful gas storage are likely to see fewer gas price spikes in winter – flexible supply of gas is necessary to balance the market and manage supply and demand stresses)
  • Second, shifting summer priced gas to winter reducing average cost of gas

Providing Flexible Gas

  • Mid-range storage (or huff and puff storage) provides the market with a high degree of short term flexibility (inter day, intra day and inter week) It has capacity to fill (relatively) quickly when prices are low and empty quickly when prices rise.
  • Seasonal storage also provides the market with longer duration (or seasonal) flexibility to mitigate long term supply and demand stresses (Rough could provide 10% of peak demand for c 3 months)
  • Storage is one of a number of sources of flexible gas available to the market (to varying degrees includes LNG, interconnectors, Norwegian supplies and UKCS supplies)
  • BUT gas storage does not compete with other markets (unlike LNG, interconnectors and Norwegian supplies) and therefore responds to lower price signals.
  • Gas storage is local, fast-responding whereas LNG can take time to order or reschedule/divert sufficient cargoes
  • More supplies of flexible gas reduces price volatility and therefore results in lower and more stable prices

Providing summer priced gas in the winter

  • Seasonal gas storage i.e. Rough (and to a lesser extend mid-range storage) moves summer priced gas to winter reducing average cost of gas


  1. What are the challenges for existing storage facilities and for new investment?

Existing storage facilities

  • Revenues have been squeezed
    • Market currently has a good supply of flexible gas from LNG, interconnectors (importing EU storage flexibility) and from the UKCS (still supplying c50% of demand)
    • Volatility levels in the past ~7 years have thus been relatively low which is reflected in the value that can be captured. The current uptick is not pushing into the forward prices which hampers valuations
    • Decline in s/w spread


  • Cost of operation has increased
    • Costs have increased significantly: In the past 10 years Business Rates have increased by several 100% and now stand at circa 50% of costs. Transitional relief mechanism not helping (rate of adjustment too small)
    • Changes to Transmission Charging is set to increase costs significantly from Oct 2019
    • Some assets are aging therefore increase in cost to operate safety & re-investments shelved/abandoned given economic environment for operators (ie. Hornsea has mothballed 1/3 of its delivery capability, Rough has now closed)


  • Consequence
    • Significant write downs c75% of CAPEX. All now struggling to cover their costs

New build – Seasonal

  • Summer / Winter spreads less than 50% 2005 levels (currently below 10p/therm), Need to be north of 25p for a sustained period.

New build – fast cycle

  • More difficult to define but down from the 2008 levels when we last saw investment
  • Lead time from FID to first gas are typically 3-4 years for new build storage, which follows 2-3 year planning process.

Summary – given the squeeze on revenues and the increasing cost to operate:

  • More existing operators may reduce capacity or go out of business due to increasing costs and poor returns
  • New developments are highly unlike to get FID as investment in major infrastructure requires long term signals; markets provide (very) short term signals


  1. Why should policymakers care? So what if more storage closes and no more is built?
  • The market is not signalling that it needs gas storage because there is a current sufficient supply of flexible gas. However . . . things change
  • Tightness predicted for mid-2020s
  • Existing supplies of flexible gas are set to reduce:
    • Groningen: 2013 supplied 50 bcm (70% in the winter), by 2020 it is forecast to supply 12 bcm flat
    • Interconnectors: CAM is restricting product offerings, aging infrastructure may result in less EU storage being available
    • UKCS: on a continuous decline with aging assets / fields (FES predicts by 2030 fully depleted)
    • LNG: demand pull to Asia/China
    • NCS – offers some flex but production expected to start to decline in 2020s
    • Demand may increase
    • Coal to be phased out by 2025 to be replaced with gas generation
    • Large number of gas peakers being built – even if we have little new CCGT capacity coming on stream as yet. The point is that the peak electricity price setters are likely to be gas – so gas price spikes will often ‘knock on’ into electricity price spikes as well.


  • Relying solely on the market (which has a short term outlook) is likely to result in a tightness in the supply of gas flexibility which may not lead to lowest prices
    • Are there market failures? 3 potential market failures:
      • Limited liability companies tend to under insure especially when they operate in a competitive market
      • Locational benefits to the TSO not captured by storage operators
      • Neither are the social welfare benefits / societal benefits i.e. lower prices


  1. Potential solutions


  • Rates – need to be reduced quicker than the current transitional mechanism allows. BEIS/VOA/DCLG/Treasury workgroup
  • Transmission Charging Review
    • Gas storage is well-located near demand centres often helps to save on transmission investment – so this should be recognised in the charging regime
    • Gas pays to enter the transmission system and pays to leave it. It would be double-counting if the same gas had to pay full rate again to enter and leave a gas storage facility.
    • For this reason, EU legislation sets a normal minimum discount of 50% for network charges applicable to gas storage. Individual countries can offer greater discounts where justified and a number of GB charging proposals currently on the table would do just that (if Ofgem approves them).


  • Ofgem need to be made aware of wider consequences of increasing the costs to operate storage

Future investment:

  • Need to assess potential alternative regulatory frameworks


Nick Perry, Senior Advisor, Timera Energy

Timera is a commercial energy consultancy providing advice on value and risk in European energy markets. We are experts in the analysis of flexible energy assets, contracts and portfolios and the markets in which they operate. Our weekly blog is one of the most widely read in the energy sector worldwide: https://www.timera-energy.com/blog/.

Why is our speciality needed? Because inherent in the gas and power sectors there are significant volumetric uncertainties and the requirement for high levels of reliability in supply to end-users. This requires the extensive deployment of assets (and other measures) delivering flexibility, as a counter to the uncertainties.

Gas storage is a classic example of a flexible asset, especially for the protection of gas supplies to residential customers but also industrials and power generators, etc.

Some important background facts

Historically, gas flexibility – including storage – has been significantly oversupplied across Europe, for several reasons:

  • A preoccupation with national self-sufficiency in the period before liquid spot-gas trading and widespread interconnection
  • Recognition of producers’ inevitable occasional operational problems; and in some cases concern over strategic exposure to operators’ actions
  • In some countries, requirements by regulator that gas storage facilities be operated in a stylized seasonal manner which in the case of some facilities is sub-optimal o

These factors, coupled with what some term a ‘glut’ in the commodity itself, have resulted in declining seasonal spreads and levels of volatility. Some would identify a ‘low’ at around 2016; but the slight ‘recovery’ since then has not reached levels where prospective developers are immediately ready to invest in new storage capacity. (On the contrary: rationalisation is still taking place)

From the start of IUK interconnector operations in 1999, the UK has effectively accessed the surplus of continental seasonal storage by exporting gas in summer and importing in winter.

Material changes to the market dynamics of the past decade are not limited to the closure of Rough. The giant Groningen gas field (and traditional major provider of flexibility) is increasingly being spared this role; Troll likewise. Global flows of flexible LNG cargos tend to come to Europe in summer but China and other far-eastern destinations in winter. And as Russia actively seeks to reduce deliveries through the Ukraine, Europe’s access to the very large Ukrainian storage capacity is diminishing.

Since liberalization / market opening, the European gas market can be seen as working very effectively. As a good example: without any government direction or subvention, the industry identified the need for significant new import infrastructure to be constructed between 2000-2010 (LNG terminals and pipelines). Very significant (and adequate) new developments were made in this period, purely on a commercial basis.

  • Also the ongoing rationalization of surplus gas storage capacity across Europe, facilitated by liquid gas trading, improved interconnections, and reformed regulatory practices
  • The very cold snap last winter was effectively managed without Rough
  • Spot price spikes have proved very effective in pulling supply (albeit LNG cargos generally cannot respond within days)

Capacity mechanism?

Even for supporters of free markets, it is possible to be agnostic on whether capacity mechanisms are an appropriate tool (though some theorists favour energy-only markets). Capacity can be a traded ‘commodity’ just like the energy itself. Thus far, however, the system seems to have worked without a mandated UK capacity market of the kind introduced into electricity 4 years ago.

It is also possible to be agnostic on whether interruption of industrial supply is an equally satisfactory flexibility tool. Some might characterize interruption as a failure: but it can be a very cost-effective balancing mechanism

Based on power market experience, and assuming DSR would be included in any gas capacity mechanism, it may be foreseen that clearing prices could be very low indeed

If not some kind of capacity mechanism, how will increasing future needs for gas flexibility be met? What is the “market mechanism”?

  • Increase in winter-summer spreads over time
  • Even more likely, increase in spot price volatility
  • Eventually, if reaching high enough levels, working though to an already-existing backlog of potential projects – new build, and incremental
  • The market dynamics of liquid trading, interconnection and reformed regulations are in place to facilitate market-based FIDs
  • There is plenty of money available, if the market conditions are right

Will Webster, Energy Policy Manager, Oil and Gas UK


  • Wood Review leading to Infrastructure Act 2015
  • Rebooting of regulatory regime -> independent regulator = OGA
  • Primary overarching objective of Maximising Economic Recovery


Recent Developments

  • UKCS has made significant adjustment to lower price environment. Significant reduction in costs (from around $30/boe to $15/boe). Or in gas terms to $3/MMBTU [25p/therm]
  • Prospects now reasonably good with production maintained over recent years.
  • Gas production from UKCS now roughly 50% of UK demand. So around 40bcm out of 80bcm demand. [Oil is nearer 2/3]
  • Some gas facilities are reaching the end of their life
    • Theddlethorpe terminal and associate production in 2018 in Southern North Sea
    • Also closure of Rough Storage.
  • These were discussed with OGA in the context of Cessation of Production arrangements.

Infrastructure Generally

  • Gas consumption overall has fallen by 20-25% since 2000. Mainly energy efficiency. Better isolation, condensing boilers etc.
  • Peak demand in winter something around 400mcm/day. It was nearer 500mcm.
  • Lots of new import infrastructure was built in 2005-10. Now situation of over capacity for both import and in the onshore NGC transmission network.
  • Also looking more widely than UK. Plenty of gas storage on continent.
  • Internal gas market rules encourage gas to flow efficiently to where it was needed. Rules exist to prevent undue government interference. And convergence of rules on balancing arrangements
  • UK effectively part of wider NW Europe market. Dutch TTF hub now more liquid than NBP.


  • Occasional winter prices are part and parcel of having a market for gas: we saw these in 2005, 2011-12 and also this year.
  • Variable prices encourage LNG cargos to be diverted and for gas to be injected and withdrawn from storage facilities.
  • Also encourages demand response: gas sold back into market if price goes high enough and interruptible contracts. Again, this all what we would expect to see.
  • Average NBP price for March 2018 was above the Japanese price [8dollars/MMBTU]. In these circumstances we are competing in a global market and Asia is the benchmark to some extent.
  • Upstream production also gives some flexibility. UKCS production can vary between 150 mcm to 200mcm in winter. But can be interrupted too: Forties interruption. Cold weather + wind. Issues with gas quality some contribution to situation in March.
  • Upstream producers lose out in these circumstances in that opportunity cost of lost production is higher if they are locked out in circumstances where prices are high.
  • Price spikes affect industrial gas users rather than SMEs or households who have suppliers to manage these risks.

Gas storage situation

  • Important to remember that not all storage is alike:
    • Seasonal storage (like Rough) can only be filled and emptied slowly. It is competing with swing from UKCS production, interconnection and continental storage. These are all things where there is overcapacity.
    • Closure of Rough storage has not had that big an impact on overall flexibility (it takes several weeks to empty it)
    • Would say that prospects for new Rough type storage are not that good.
    • Flexible short-term storage (mostly onshore). Important for managing more extreme market conditions. Can be filled and emptied several times over the winter as was the case in 2017-18.
    • Prospects for ST storage are probably improving as option value for investors and may help take the edge of price spikes if more is developed. Helps manage risks for suppliers too.
    • Discussion around transmission tariff regime ongoing. Storage may get a discount. Business rates also an issue.

Possible measures to encourage more storage:

  • Upstream producers relatively ambivalent. Most take the market as they find it.
  • Incentives are there to maximise production. Nobody wants to be locked out of market especially on days when prices are high.
  • In general, nervous about favouring one source of supply over another. Current discussions about gas entry charges. In tight situations we need everything we can get. A positive intervention in one area of ends up as a negative somewhere else.
  • Government’s prerogative to look for a different outcome and it has done this in electricity sector (capacity market) on grounds of a medium-long term signal. But even this is quite complex and may get something haven’t bargained for….[e.g. diesel farms]
  • Plenty of questions about how e.g. a regulator sponsored storage obligation would operate.
    • Minimum flexibility requirements?
    • When would gas be injected withdrawn
    • Who decides price offered into market
    • Interface with wholesale and balancing markets / impact on liquidity
    • Impact on interruptible contracts and price of these.


Questions and Comments

A discussion lasting 30 minutes followed the speakers and the meeting closed at 5.40 pm.