UK: What’s In Store? Supply, Demand And Storage Issues In The UK Gas Market

Introduction

With declining North Sea gas production, the UK is now a net importer of gas, receiving supplies from an increasingly diverse set of countries. It is estimated that by 2016, 80% of gas consumed in the UK will have to be imported. Traditionally, the UK has relied heavily on the flexibility of its own offshore supplies in order to balance supply and demand, supplemented by offshore gas storage, some peak shaving LNG terminals (which supplement the normal amounts of gas delivered to customers during peak-use periods) and a very limited amount of salt cavity storage.

Major new import projects including the Langeled and BBL pipelines came on stream in October and December 2006 respectively and a number of large LNG terminals are being built. These new sources of supply are undoubtedly capable of providing substantial additional gas to the UK, but the question is whether they will be able to provide the flexibility required in the marketplace. Another related question is how these additional sources of gas supply might change the structure of the gas market in such a way as to affect the volatility of gas prices on a day-to-day and seasonal basis, and hence reduce the chances of attracting new capital into building additional storage capacity.

On 16th May 2006, the Secretary of State for Trade and Industry issued a ‘Statement on Need for Additional Gas Supply Infrastructure’, which affirmed "the clear national need for new gas storage infrastructure". This has created a great deal of interest in the issues surrounding development of new storage in the UK, and the potential financial returns available on such projects.

UK gas market

Gas demand

The UK is one of the largest gas markets in Europe with total gas demand of 99 bcm (billion cubic metres) in 2006. Despite the relative maturity of the market, total demand in the UK has risen by an average of 5.5% per annum over the past decade, driven especially by the large increase in gas fired power generation in the 1990s. In its Ten Year Statement, National Grid (NG) envisages a growth rate of 2.2% per annum in gas demand between 2005 and 2014/15. Gas demand growth in the following years will be influenced by Government policy regarding nuclear plant and renewables – continuation of existing policies will see further growth until 2030. The power generation sector is expected to continue to have the greatest impact on growth in UK gas demand over the next decade, and gas’s share of the generation market is likely to continue its rapid growth for environmental and commercial reasons. The onset of nuclear decommissioning beyond 2010 and the introduction of Phase II of the EU Emissions Trading Scheme will create a significant further requirement for new, low carbon, generating plant, much of which is expected to be gas-fired. The rate of growth of renewable energy and the Large Combustion Plant Directive are also likely to play a role. No new nuclear plant is expected to be on stream prior to 2018/2020. Modest gas demand growth is also expected in the industrial and residential sectors.

Gas demand is highly seasonal (for example, in the residential sector, on average, five times more gas is needed on a winter day than a summer day), and demand varies from day to day. To meet this varying demand, considerable flexibility is required in gas supply.

Gas supply

The rate of decline of UK Continental Shelf (UKCS) gas production is likely to depend mainly on the development of alternative sources of supply and the costs of extracting gas from remaining smaller fields, relative to the price of imported supplies.

NG has forecast that an increasing proportion of future supply is likely to come in the form of LNG imports. However, LNG demand in the UK will have to compete with demand from existing and new LNG terminals in the US and Europe, within the wider Atlantic Basin LNG market.

These peak day supply and demand forecasts indicate that LNG and storage will play an increasingly important peak day balancing role. If all projects go ahead as planned then not all projects will have to operate at full capacity.

However, while all of the gas supply projects are designed to be flexible, none will run at full capacity on an annual basis. For example:

  • Norway can divert gas from Langeled to Continental Europe via Zeepipe;
  • LNG can be diverted from the UK to the US (many LNG terminals around the world tend only to operate at about 60% of capacity); and
  • the Interconnector can flow both ways; however it does not operate as a regulated Third Party Access (TPA) system and, in the 2006 Budget, Ofgem was granted the power to investigate whether its operation is satisfactory. This was due to perceptions amongst large UK gas consumers that it does not always supply all the gas that it could on days of maximum demand in the UK.

The Government’s recent Energy Review (July 2006) noted the discrepancy between the amount of storage in the UK and that available in Continental Europe and the US – as a percentage of annual production the UK has a comparably very low storage capacity (Table 1). Having said that, some of the storage in other markets is maintained for strategic security of supply reasons, rather than purely as commercial, seasonal or daily storage.

Managing flexibility and security of supply

UK balancing

In order to keep gas supply and demand in balance on a daily basis, apart from buying and selling gas in the "On The Day" commodity market, the transmission and distribution system operators and individual licensed gas companies make use of a number of techniques to maintain the levels of security of supply within their licence conditions, essentially to be able to meet the coldest day in 20 years and the worst winter in 50 years. Base load is supplemented by:

  • "swing" from offshore fields (ie, the ratio of peak to annual average flows and requires oversized facilities and gas transmission systems);
  • peak shaving facilities, using excess delivery capacity. There are two main ways this can be done:

– using high swing offshore gas fields like Sean or Morecambe. Until quite recently Sean was used to supply gas on only a few days each year; and

– the use of LNG peak shaving facilities like Glenmavis: these facilities usually have much less storage capacity than large baseload LNG terminals and are designed typically to supply gas at high delivery rates for just five to eight days at a time. They are situated on the coast at the extremities of the gas market;

  • line pack in transmission lines (which would only last a matter of hours or days, depending on the circumstances, before parts of the transmission and distribution systems dropped to low pressures that are unsafe); and
  • interruption, both voluntarily, under supply contracts that have already allowed for some degree of interruption and where the gas is priced accordingly, or involuntarily, where the transmission system operator or supplier curtails the supply of gas unilaterally.

Swing can provide the equivalent of long-term storage and the day-ahead characteristics of short-term storage subject to nomination procedures. However, swing cannot provide the equivalent of the in-day characteristics of short-term storage without changes to nomination procedures or provide corresponding services to interruption, line pack or the local storage of LNG.

Regulation of gas storage in the UK

The commercial framework for storage services in the UK is determined by the Universal Network Code. In 1998 Rough (a depleted field) and Hornsea (a salt cavity facility) were moved out of regulation onto a commercial contract basis with capacity and prices set by auction. Capacity at Rough is sold subject to a number of conditions which were laid down by the Competition Commission in August 2003 following the acquisition of Rough by Centrica. This limits the maximum Rough storage capacity that Centrica can reserve for its own gas supply business.

The second European Gas Directive permitted gas storage to be operated on a negotiated or regulated access basis depending on the wishes of each member state. The European Gas Regulatory Forum (known as the Madrid Forum) has been pressing for new EU-wide rules on access to storage and implementation of the voluntary Guidelines for Good TPA Practice for Storage Operators (GGPSSO) (for example that unused capacity has to be released under a "use it or lose it" mechanism). So far this code has not been adopted in the UK for storage.

Until 2004 NG managed UK security of supply through "top up arrangements" to meet the 1 in 50 winter condition referred to above. In 2004 safety monitors were implemented, requiring NG to monitor gas levels in storage, to act if volumes fall below the prescribed levels for each facility, and to ensure adequate pressure throughout the network. The safety monitors take account of possible diversion of LNG supplies away from the UK. NG no longer has the right to interrupt end users when demand is above 85% of the peak day demand.

Types of storage system

There are broadly three types of gas storage: previously depleted gas and oil fields, salt cavities and aquifers. The two types described below are the most significant in the UK context.

Depleted gas and oil fields

One of the cheapest ways of storing gas (on a unit cost basis) is the usage of a partially depleted gas or oil field. To be suitable for this purpose, depleted reservoir formations must have high permeability and porosity. The porosity of the formation determines the amount of natural gas that it may hold, and the permeability determines the rate at which natural gas flows through the formation, which in turn determines the rate of injection and withdrawal of working gas. About 50 to 60% of gas initially in place must be retained as "cushion gas" to maintain reservoir pressure and cannot be extracted whilst the field is being used for storage. Depleted fields tend to be used for seasonal, rather than short-term, storage.

Salt cavities

There are two possible forms of salt cavity storage: salt domes and salt beds.

Salt domes are thick underground geological formations created from natural salt deposits that leach up through overlying sedimentary layers to form large dome-type structures. Salt beds tend to be shallower, thinner formations and are usually no more than 1,000 feet in height. As salt beds are wide and thin formations they are more prone to deterioration when used for storage, as compared with salt domes. In addition, they may also be more expensive to develop.

Salt cavity storage can be used to modulate gas much faster than depleted gas reservoirs or aquifers. Gas can be cycled a dozen or more times a year, catering for "needle peaks" in demand closer to end user markets. Hence the unit deliverability costs can be comparable to larger, depleted field storage, but bulk storage costs are usually higher. Salt cavity storage is commercially viable when there is high volatility of gas prices and where very sharp demand peaks need to be met in nearby demand centres.

UK gas prices

Summer/winter UK gas price spreads

The value of storage capacity is driven by "within year" gas price differentials and not directly by the absolute levels of gas prices. The main commercial driver for seasonal storage is the differential between summer and winter gas prices. Forward spreads (taken here as the difference between average Q3 and Q1 prices) have varied significantly over the six year period 2001-2006. The following chart shows the forward spread as at January of each year for the following summer (Figure 2).

The eventual realised spreads have shown a similar pattern over this period, but have tended to be smaller than those in the forward curve.

Short-term gas price volatility

The volatility of gas market prices from day to day is the key factor in determining the economic viability of medium-term storage such as salt cavities. Access to storage creates a series of options to sell gas on a daily basis with varying delays. The option to sell creates value during periods of high prices, while the option to buy does so during periods of low prices. Historical gas prices show significant and highly variable levels of "within month" volatility (Figure 3).

Particularly volatile months were caused by cold winters in 2005 and 2006 coinciding with shortages in supply (see Box 1).

Box 1 Comments from Ofgem on winter 2005/06 prices:

November 2005
"Gas storage was used heavily because beach (UK and Norwegian offshore gas) supplies, Interconnector and Isle of Grain were not delivering the expected amount of gas. This combined with unseasonably cold weather."

February 2006
"Rough gas storage facility was closed following a fire on February 16. The market responded with increasing supplies, particularly from the Interconnector."

March 2006
"Low temperatures combined with the continued closure of Rough and lower than expected volumes of gas, particularly from beach supplies and the Interconnector."

New storage project opportunities

Opportunities

In response to increased demand for storage and the UK’s historically low level of storage compared with other markets of similar size, a number of new schemes have been proposed (Table 2).

Table 2. UK gas storage projects

An additional 7.6 bcm of UK storage capacity is being planned

Project

Type

Owner/Proposer

Size

(Storage capacity)

Commissioning date

Planning status

Aldbrough

Salt cavity

Statoil SSE

420 Mcm

Q3 2007

Approved

Byley

Salt cavity

E.ON (Scottish Power contracted)

170 Mcm

2008

Approved

Hole House Extension

Salt cavity

EdF

20 Mcm

2007-09

Under construction

Caythorpe

Depleted field

Warwick Energy

210 Mcm

Q3 2008

Planning application refused –appeal lodged

Saltfleetby

Depleted field

Wingas

715 Mcm

Q4 2008

Planning application submitted, January 2006 – awaiting outcome

Stublach

Salt cavity

INEOS Enterprises

540 Mcm

2009

Under construction

Albury Phase 1

Depleted field

Star Energy

160 Mcm

2009

Pre-planning

Albury Phase 2

Depleted field

Star Energy

Up To 715 Mcm

2010

Pre-planning

Bletchingley

Depleted field

Star Energy

900 Mcm

2010

Pre-planning

Gainsborough

Depleted field

Star Energy

220 Mcm

2010

Pre-planning

Welton

Depleted field

Star Energy

435 Mcm

2010

Local planning refused, 1965 Gas Act, application to be submitted

Preesall

Depleted field

Cantxx

1700 Mcm

2010

Pending outcome of public inquiry

Portland

Salt cavity

Portland

1000 Mcm

2010-2013

Pre-planning

Whitehall

Salt cavity

E.ON

420 Mcm

2010-2012

Planning submitted Jan 07

Total

7,626 Mcm


Source: Deloitte Petroleum Services

There are around a dozen storage projects under active discussion, including both salt cavity and depleted fields, and there are several other schemes on the drawing board that have not yet been publicly announced. The projects under construction (Aldbrough and Byley) will introduce incremental capacity of 0.5 bcm by 2009. If all proposed projects are completed then UK storage volumes could exceed 11 bcm by 2011/12, a level that might lead to some redundant capacity.

Several of the schemes have faced serious planning delays, a problem that may be addressed by the 2007 Energy White Paper and the prospective Energy Bill. Nevertheless, all schemes continue to face considerable planning, market and regulatory uncertainties.

There are several potential opportunities to re-develop UKCS gas fields as offshore storage as many that are severely depleted face imminent decommissioning. These include several of the original large Southern North Sea fields that have supplied the UK mainland with natural gas since the 1960s and 1970s. The possibility of staving off the huge costs of decommissioning by converting these fields to storage use might potentially be attractive to the owners/ operators of these facilities and the associated transportation systems, despite the cost of purchasing cushion gas. Not all gas-inplace can be extracted from a gas field economically; typically 10-15% of gas will remain in the reservoir and this becomes part of the cushion gas when the field is converted to storage.

However, the suitability of the infrastructure to which these fields are connected to act as part of a storage system is more problematic. Whilst the fields may have started out with dedicated infrastructure, to avoid proliferation of pipelines many joint facilities have typically been used to transport the gas from nearby fields to shore. In some cases they have developed into major gas gathering systems. These facilities and the associated compressors are not in general set up to pump gas back into depleted field storage during the summer, (ie, against the flow of other gas in the system), or necessarily to release the stored gas to shore in much larger flows during the winter. Gas storage also requires different processing and compression facilities.

There is yet another level of complexity as third party gas on joint infrastructure systems is transported according to strict commercial rules, with capacity dedicated to individual shippers under long-term transportation agreements. This means that pipeline capacity cannot readily be made available for storage use, if so doing would adversely affect other shippers.

Long-term investment signals

The largest storage scheme in the UK is the offshore Rough field, which can deliver 10% of peak gas demand and represents 80% of storage capacity. When the original gas field was converted, new wells were required, expensive offshore compression was installed and capacity increased to offer much greater deliverability. It is estimated that it would cost £1-1.5b to develop an equivalent storage field nowadays. For a scheme as large as Rough, it might cost a further £1-1.5b to fill the reservoir with cushion gas if it were wholly depleted. If producible gas is still in the reservoir, then it could become cushion gas, but its market value would have to be deferred as it could not be produced until the gas storage system is eventually closed down and emptied.

It can be difficult to extract reliable investment signals for new long-term investment in storage infrastructure from a liberalised market, like that for UK gas. This was the subject of much debate when the new gas trading rules were introduced by Ofgem in 1999.

Our calculations indicate that a new large "Rough" type storage scheme would require a market price of at least 45p/standard bundled unit (SBU – each SBU comprises 1 kWh of deliverability, 0.110769 kWh of injectability and 17.948718 kWh of capacity), excluding the cost of cushion gas, to break even economically. But, prices dropped from 51p/SBU for 2007 to below 40p/SBU in mid-2006. Accordingly, if these SBU price levels persist, investment in strategic storage might not be economically justified as a worthwhile use of incremental capital.

Summary and conclusions

At least a dozen new storage project proposals are under discussion, and several more are at an early planning stage. Many of these schemes are situated onshore and some have been subject to extended planning approval delays because of local concerns about environmental impact. If all the projects go ahead then the UK could have up to 11 bcm of storage, potentially creating an oversupply. New storage projects face planning, market and regulatory risks and it is expected that these issues will be addressed in the Government’s Energy White Paper and Energy Bill.

At a time when there is increasing concern about long-term security of energy supply to the UK, it is apparent that the costs of developing a new strategic storage system, such as another Rough, that is capable of coping with a major imported gas disruption are huge, £2-3b including the cost of filling the storage system with cushion gas. The market risk could also be considerable, given the potential for an oversupply of peak day gas storage in the UK if all the planned import and storage schemes were to operate at, or near, design capacity.

Although there is likely to be increasing geographical diversity of supply of gas to the UK, the gas supplied through import pipelines will be concentrated in very few large players. LNG supply is no longer all locked into specific trade routes in the way it used to be, and at least some LNG can be diverted at short notice to other markets if they are prepared to pay higher prices. Moreover, whatever progress there may be in the future towards establishing a more harmonised gas market across Europe, if supply were to become tight, Continental European gas companies may not be prepared (or permitted) to send gas to the UK market if there is a risk of supply shortfall to customers on the Continent.

Having said that, the ability to switch from gas to coal or oil does provide some insurance against long-term gas supply disruptions, and also exposure to unduly high gas prices; and there is some additional short-term buffering against interruptions in supply due to the storage inherent in LNG supply chains.

Nevertheless, to ensure the UK has satisfactory long-term gas supply capacities in place, now may be the time for Government to reassess, and gain consensus on, the gas industry’s contingency plans and the fundamentals of the future shape of the UK gas supply system. If private sector storage schemes do not come forward on a sufficient scale, then Government may need to provide greater fiscal or other incentives to attract the necessary investment into strategic storage. Consideration should also be given to adjusting the regulatory system to make sure that sufficient commercial and strategic storage and LNG import capacity is made available to serve the needs of the growing UK gas market. Without strategic storage, the UK’s gas supply system will remain vulnerable to problems at a major gas terminal and to supply problems with major gas fields or pipelines – we have already experienced the costs of outages in the Rough storage facility.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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