GRONINGEN GAS: FROM ANCHOR POINT IN SWING ......04 ENERGY Groningen gas In order to diminish the risk of (heavier) earthquakes in the short term, SodM4 proposes to reduce the Groningen

GRONINGEN GAS: FROM ANCHOR POINT IN SWING SUPPLY TO WILD CARD IN THE FUTURE L-GAS MARKET

Author: Maroeska Boots, DNV GL1

ABSTRACTFollowing the intensified seismic activity and subsequent upheaval in the public domain, the decision to cap production of the Groningen field between 2014-2016 has stirred assumptions on gas market fundamentals and accelerated the discussion about the declining role of Groningen as swing provider in the Northwest European gas market. The recent decisions about the Groningen gas production scheme and future policies can have serious implications for the supply-demand balance (flexibility) in Northwest Europe. Furthermore, it will also have business consequences for companies active in the European gas (flexibility) market. The Loppersum cap could be extended after 2016, but the Dutch Government could also decide to substantially reduce production volumes further. In case these reduced volumes have to be produced at a flat rate, the gas market loses an important source of flexibility which consequently should be covered by other sources such as underground storages and gas quality conversion facilities. This affects the low-calorific gas market in particular.

1 We would like to thank Henk Kreuze and Floris van Foreest for their important contribution to the basis of this work.

SAFER, SMARTER, GREENER

In recent years, the Northwest European2 gas flexibility market has been oversupplied, with low summer-winter spreads and unfavorable outlooks for providers of flexibility. The UK is a special case in this context given its diverse range of gas supply options. During the cold spell of 2013, the country experienced very low storage levels and especially relied on Norwegian imports while LNG terminals were underutilized. Besides the Rough facility (4 bcm), storage capacity is limited. With the Groningen field as important swing provider in Northwest Europe, storage overcapacity in Germany, LNG as additional flexibility source in the UK and decreasing gas demand in general, the seasonal (and also peak) flexibility market has been more or less in a status quo.

Increased seismic activity in the Groningen area since 2000 and subsequent upheaval in the media and political debate, induced the Dutch government to restrict gas production from the Groningen field. As a consequence, the seasonal gas flexibility outlook in the Netherlands and broader Northwest Europe may change. In addition, the transition in Germany from low-calorific gas to high-calorific gas, future utilization of German storage capacity, and both storage and nitrogen capacity extensions in the Netherlands (Norg, Heiligerlee) can also alter the flexibility market’s status quo.

For gas shippers, traders and storage operators, the implications of the Dutch decision on the Groningen production scheme can be substantial.

02 ENERGY Groningen gas

INTRODUCTION1

2 The Netherlands, Germany, Belgium, France and the UK.

CHANGING OPERATION OF THEGRONINGEN FIELD

Groningen gas ENERGY 03

Statistical analysis by SodM3 show that the production of gas from the Dutch Groningen field has gradually increased from ca. 20 bcm in 2000 to more than 50 bcm in 2013. At the same time, the number of production-induced earthquakes in the north of the Netherlands has increased, just as the probability of higher magnitude earthquakes.

The graphs below are illustrative for SodM’s conclusion (supported by NAM and KNMI) that there is a linear relationship between the pace of gas production and the probability of earthquakes.

Annual production and the annual number of earthquakes with magnitude 1.5 or higher.

Cumulative seismic energy release and cumulative production through time. The higher magnitude earthquakes release the most energy, which causes the steps observed in the figure.

Figure 1 - Relationship between gas production and seismic activity [source: State Supervision of Mines, 16 January 2013. Reassessment of the probability of higher magnitude earthquakes in the Groningen gas field].

3 State Supervision of Mines, 16 January 2013. Reassessment of the probability of higher magnitude earthquakes in the Groningen gas field.

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In order to diminish the risk of (heavier) earthquakes in the short term, SodM4 proposes to reduce the Groningen gas production as fast as, and as much as reasonably possible. Following these analysis and propositions by SodM, on 29 November 2013, operator NAM5 submitted the revised production plan for the Groningen field to the Minister of Economic Affairs. After a review and evaluation (e.g. by SodM, Tcbb6 and the cabinet7) a decision on the Groningen production plan was reached and presented by the Minister on 17 January 2014 in the village of Loppersum, the heart of Dutch gas production induced earthquake area.

The decision entails a production volume reduction of 80% in Loppersum (consisting of the clusters ‘t Zandt, Overschild, De Paauwen, Ten Post and Leermens) for 2014, 2015 and 2016. Total annual production from these clusters is reduced to a maximum of 3 bcm compared to some 15 bcm on average in the period 2011-2013, while leaving the total Groningen production cap intact. The continued limited availability of Loppersum is required for security of supply reasons, since complete shutdown of the clusters would result in L-gas shortages when gas demand is very high8. The decision does not explicitly introduce production capacity restrictions, e.g. limiting the average or maximum production per day. However, in December 2014, the Dutch government decided to reduce the cap to 39.4 bcm for 2015 and 2016, with only 16.5 bcm in the first half of 2015 (as announced in the beginning of 2015). Despite increasing pressure from various stakeholders, there are no official further reductions. However, a scenario of reducing production to 30 bcm annually is becoming more probable, assuming increased attention to the safety of people and property in the Groningen province.

The relation between cumulative production volume (bcm) and production capacity (mcm/day) is quite linear. Therefore, as a general mechanism, due to cumulative production of Groningen over the years and decreasing remaining reserves, the daily production capacity from Groningen will decrease, resulting in declining annual volumes to be produced in the future. Since it is still unclear what will happen with production from Groningen after 2016, we take a look at three scenarios: business as usual (BAU), extended Loppersum and 30 bcm flat delivery.

4 SodM’s letter to the Minister of Economic Affairs, 22 January 2013. 5 “NAM dient herziene versie winningsplan in” http://www.namplatform.nl/actueel/nam-dient-herziene-versie-winningsplan-in.html6 Tcbb = Technische commissie bodembewegingen, see also www.tcbb.nl 7 “Besluitvorming over gaswinning Groningen” Letter of 28 October 2013 from the Minister of Economic Affairs.8 Consent by the Ministry of Economic Affairs. “Instemming gewijzigd winningsplan Groningenveld” http://www.rvo.nl/subsidies-regelingen/gaswinning-groningen-ontwerpbesluit9 See http://www.nlog.nl/nl/oilGas/oilGas.html, reference date 1 January 2013.

Figure 2 - Groningen annual production volume (left) and capacity (right) developments

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Business as usualAlthough the production gap has been lowered to 39.4 in the coming years, we still assume an overall cap of 425 bcm for the period 2011-2020 in the BAU scenario, resulting in 44 bcm annual production in 2017-2020 (based on the prognosis of nlog9. A continuation of the gas production after 2016 at the annual average level of before 2014 and assuming full use of the earlier production cap until 2020, the production volume decline of the Groningen field will only start in 2022, see the BAU curve in figure 2, left side.


Extended LoppersumAlthough the volume impact of the Loppersum and latest production cap (39.4-42.5 bcm per year) does not seem severe, the consequences of prolonged limited Groningen production after 2016 may be substantial. The main reason is that the five Loppersum clusters used to provide some 37% of total capacity.

The other Groningen clusters (non-Loppersum) need to make up for the production decline in Loppersum, i.e. they need to produce at higher levels and thus speeding up the process of production decline. If the cap on Loppersum of 3 bcm is continued after 2016, the cumulative effect is approximately 80 bcm less volume from Groningen, illustrated by the difference between the BAU curve and the blue bars in the left figure over the period 2017-2030. However, since the cumulative production from Groningen is lower than in BAU, the overall pressure in the field reduces less quickly and therefore the capacity from Groningen can be maintained (for security of supply reasons as indicated in the decision) and even remains higher when compared to BAU towards the end of the period analyzed. Capacity developments are depicted in the figure on the right.10

30 bcm flatFollowing the ongoing heated discussion in Groningen, the minister may very well decide to even further decrease production from the Groningen field. Therefore, we account for a more extreme scenario of 30 bcm (293 TWh) flat production as from 2017, i.e. not only limiting production volume but also limiting production capacity immediately. The green curves in figure 2 represent this scenario and shows the dramatic impact both on production volume and capacity delivery. The lower production level can be continued until 2025 and the decline will only start thereafter (due to lower cumulative production). Also capacity delivery decreases after 2025. The flat 30 bcm scenario will likely have severe consequences for security of supply, especially in the mid-term period 2017-2025. This will be further discussed in chapter 4.

10 We denote flexibility in terms of capacities, i.e. in GWh/day or GWh/hour (=GW).


FUNDAMENTAL DEVELOPMENTS IN THE NORTHWEST EUROPEAN MARKET FOR GAS FLEXIBILITY

Apart from Groningen production developments, several fundamentals affect the market for gas flexibility in Northwest Europe. Without pretending to give a complete overview, we will briefly discuss some fundamentals below, with an emphasis on specific L-gas market fundamentals.

Low-calorific gas11

The ‘quality’ of natural gas is mainly determined by the energy content of gas per cubic meter. The development and production of the Groningen gas field determined – and still determines – the typical Dutch gas quality. Groningen gas (G-gas) contains a significant amount of nitrogen (14%), which is non-combustible. End-user equipment was specifically designed to use this low-calorific G-gas. However, gas finds in other countries, but also Dutch small field gas, typically contain less nitrogen and more methane and higher hydrocarbons (ethane, propane, butane). These are therefore high-calorific gases, or H-gas.

As a result, the Dutch natural gas system roughly consists of two separate systems for G-gas and H-gas. G-gas is used by virtually all connected Dutch households and approximately two-third of industrial (including power generation) gas use is based on G-gas. G-gas is distributed via the regional gas grids. The H-gas system is mainly an import and export system, with a relatively small number of directly connected industrial customers and power generators. However, Dutch low-calorific gas is also exported to Germany, Belgium and France, via dedicated export stations.

The grid code (‘Regeling gaskwaliteit of 11 July 2014) specifies acceptable calorific values for transport and distribution of gas, usually in terms of Wobbe Index12 bandwidths. The Wobbe Index of G-gas normally varies between 43.46 and 44.41 MJ/m3, with Slochteren G-gas at the lower end and G+ gas (distributed to customers) at the higher end, although the acceptable range is wider. Typical low-calorific gas export to Germany and Belgium has a wider acceptable range (42.7-46.9 MJ/m3) that varies per export point. Finally, the Wobbe of H-gas in the Netherlands can be up to 55.7 MJ/m3.

Depleting reserves and import dependencyThe Netherlands, the UK and to a lesser extent Germany have been self-sufficient in gas supply. However, gas production from the UK Continental Shelf has rapidly declined since 2000, making the UK a net importer of gas. It forced the country to invest in alternative sources of gas and respective flexibility, resulting in the current diversified portfolio including imports from Norway via e.g. Langeled, LNG imports and imports from continental Europe via the IUK and BBL pipelines.

Where the UK gas market solely consists of H-gas, Germany is still producing some L-gas. German gas production covers less than 10% of gas demand and will further decline in the coming years. Germany therefore heavily depends on pipeline gas imports from the Netherlands (mainly L-gas), Norway and Russia.

11 H. Levinsky and M. van Rij. Gaskwaliteit voor de toekomst, deelrapport 1. KEMA and KIWA, 27 January 2011.12 The Wobbe Index is the gross calorific value divided by the square root of relative density of the gas. It is a measure of the amount of energy delivered to a burner via an injector. Then, with an average density of 0.645 G-gas has a heating value of 9.7 kWh/m3 whereas the heating value of H-gas can be 11.5 kWh/m3.

3


Gas storageAvailability of (underground) gas storage capacity is important in providing gas flexibility. Natural gas is a seasonal fuel with higher demand in the winter because gas is used for heating in the residential and commercial sector. Excess gas supplies from production and imports in summer are stored to meet the increased demand in winter. Base load storage capacity is used to meet seasonal demand increases. Typically, base load facilities have a storage cycle of one year, i.e. the facilities are filled during the summer and gas is withdrawn during the winter. Working gas capacities of those facilities are large while their delivery rates are relatively low. Alternatively, peak load storage facilities deliver at a relative high rate during short periods of time in order to meet sudden, short-term demand increases.

13 Underground gas storage in Germany. Erdöl Erdgas Kohle 128. Jg. 2012, Heft 11.14 In the analysis we focus on daily and seasonal volumes. As the gas market also has a strong intraday capacity demand a conservative storage send out load factor of 70% is assumed.

Figure 3 - Storage production capacity duration curve 2016

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Gas storage capacity in Europe has increased substantially over the last decade, especially in Germany and the Netherlands. Although storage additions have slowed down substantially, in the Netherlands, the new 4.1 bcm (45 TWh) Bergermeer gas storage started full operation in 2015, and by 2016 a doubling of Norg to 6 bcm (58 TWh) working gas will be realized. In Germany, on top of working gas additions in the past years (e.g. Etzel), the Jemgum (1.3 bcm) storage is expected as from 2016 onwards13.

Figure 3 shows the storage production capacity14 in GWh/d for Northwest Europe in 2016. As illustrated, dedicated L-gas storage capacity represents only a small part of total capacity. After the major extension of Norg, we assume there is some 105 TWh working gas available from L-gas storages in Northwest Europe (from 2016 and forward). Approximately 70% of this L-gas storage volume is located in the Netherlands (or directly linked to the Dutch gas system in case of the Epe storages), 18% in Germany and 12% in France.

In general, there is a large storage volume excess in the region, indicating that the main driver for storage demand is strategic volume to meet extreme winter demand, not year-to-year seasonal flexibility.


Gas quality conversionAs described in the explanatory textbox, the Northwest European gas market roughly distinguishes between low-calorific and high-calorific gas. This is however not a strict distinction, since various Wobbe ranges are applied at different locations in the gas system. Moreover, gas quality can be adapted, e.g. by blending H-gas and L-gas.

GTS applies several methods for gas quality conversion. Blending gasses of various qualities is relatively straightforward. This instrument can be used in various ways. For example, GTS is operating blending stations at Ommen and Puth-Schinnen where G-gas is injected into the H-gas stream to lower the calorific value of the stream. Figure 4 shows that the calorific value of actual Dutch (H-gas) exports has decreased in recent years, with e.g. Bocholtz often hitting the lower Wobbe level in recent years, indicating the use of blending stations. Alternatively, decreasing the G-gas injection at the blending stations would result in G-gas savings, while H-gas export still remains within the agreed Wobbe range.

Figure 4 - Estimated Wobbe index on GTS exits (monthly values)

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Also at L-gas exits, either export stations or domestic exits, there is room to play with the Wobbe index via blending. Increasing the Wobbe index of gas flows at those exits, within the required range, results in L-gas savings. The potential savings thus depend on the volumes of L-gas consumption and export, but at current normal consumption and export this may add up to some 10 to 13 GW.

In dedicated nitrogen stations, nitrogen (N2) is mixed with H-gas to lower the Wobbe of the gas15. In the Netherlands (Ommen and Wieringermeer), the assumed N2 base load capacity of GTS is 361,000 Nm3/h. This is equivalent to 223 TWh of natural gas per year or 25 GW, assuming non-restrictive supply of H-gas. At peak hours even more L-gas capacity is available through nitrogen. In addition, GTS has the availability of a nitrogen storage cavern and blending installation in Zuidbroek/Heiligerlee, with a peak capacity of 190,000 Nm3/h (for 11 consecutive days), equivalent to some 13 GW of natural gas. Also the installation in Pernis (45,000 Nm3/h of nitrogen) can be used as back-up.

15 Gasunie Transport Services. Mogelijkheden kwaliteitsconversie en gevolgen voor de leveringszekerheid. Resultaten onderzoek 7. October 2013.


3

Costs of quality conversion via nitrogen injection are generally higher than via blending or other flexibility options. Therefore, nitrogen would normally only be used when really required.

The quality conversion measures mentioned here add up to some 20 bcm of L-gas on an annual basis, or more than 50 GW in capacity units (indicative figures, in order of least costs):n Savings on G-gas injection at export flows: 2 GWn Higher Wobbe index at domestic G-gas exits and L-gas export stations: 13 GWn Injection of nitrogen at base load: 25 GWn Nitrogen at peak load: 13 GW

With further decreasing Dutch exports, enrichment of gas (the first two options) will gradually disappear in the future and GTS has to use the nitrogen facilities more often.

Market transition to H-gasIn the Netherlands, the composition of low calorific gas is guaranteed at least to 2021. It means that that gas using equipment in the G-gas segment can gradually be adapted to higher calorific gas. Research16 concluded that the transition period can even be extended until roughly 2030 for small gas users. Industrial G-gas users however will need to adapt their burners to H-gas in the coming years.

Developments in neighboring countries, notably Germany, Belgium and France, will also have an impact. Those countries depend on GasTerra exporting L-gas under long-term contracts, of which some run until 203017. An accelerated transition from L to H-gas in Germany and Belgium/France will provide the opportunity to extend the transition period in the Netherlands.

The planned market transition in Germany is described in documents related to the Netzentwicklungsplan18. These assume, amongst others, a consolidated supply of Dutch L-gas until 2020 of some 47.7 GW, subsequently declining gradually to 0 in 2029. At the same time, the sector will start to switch or adapt gas using equipment to accommodate H-gases. Technicians will have to be recruited and qualified in order to accommodate 400.000 to 450.000 appliances annually as from 2020. Without doubt, this is a challenging task for the German sector and grid operators.

16 Jepma, C. and N. Rop. EDGaR Transitiestudie G-gas. April 2013.17 Ministry of Economic Affairs – Directorate Energy Market. Groningengas op de Noordwest-Europese gasmarkt. Samenvattende rapportage bij de onderzoeken 7, 8 en 9. November 2013.18 Prognos. Szenariorahmen für den Netzentwicklungsplan Gas 2015 der Fernleitungsnetzbetreiber. September 2014.


An analysis of the firm available and booked capacities for L-gas at the Dutch borders with Germany and Belgium also gives an indication of the required timing of market transition. Moreover, for GTS the L-gas exit capacity is an important parameter for their need for quality conversion capacity. Although the physical transportation capacity, in terms of pipelines, may be constant, GTS restricts the bookable capacity.

Figure 5 illustrates that by 2020, the available and booked exit capacities to Germany reported by GTS match and dive below the firm entry capacity reported by German gas network operators. The difference between the firm L-gas entry capacity in Germany (dark blue line) and the firm exit from the Netherlands to Germany is an indication for the L to H-gas market transition in Germany. This transition will gradually evolve from 2020 onwards with a completion around 2029. For the cross-border capacity with Belgium, relevant for the L-gas deliveries to Belgium and France, we see that the transition from L-gas to H-gas will only start around 2024.

Gas-fired power generation In Northwest Europe, gas-fired power plants are being pushed out of the merit order by cheaper coal and increasing shares of renewable energy. The shale gas revolution in the US and subsequent low gas prices has driven global coal prices downward due to the surplus of produced coal as a result of the switch from coal to gas in the US power sector.

This development has lifted the competitiveness of coal over gas in European electricity markets. Secondly, the increasing capacity of renewable energy sources (wind and solar PV) with zero marginal costs reduces the load factor of much more expensive gas-fired generation. Consequently, gas demand has dropped significantly (next to the effect of the economic crisis) the past three years. Moreover, demand for flexible gas supply by power producers also decreases. Unless new market mechanisms are introduced for flexible gas plants, the decrease of gas demand in the power sector will be fundamental on at least the medium term.

Figure 5 - L-gas capacities at the Dutch border

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CONSEQUENCES OF GRONINGENPRODUCTION CHANGES FOR FLEXIBILITY

4

In Section 2 we described three scenarios for the development of gas production from the Groningen field as from 2017:n The business-as-usual (BAU) scenario, where production will return to ‘normal’ after the temporary three-year production reduction19.

n The extended Loppersum scenario, where the production reduction will be extended after 2016.n The flat 30 bcm scenario assuming maximum annual production of 30 bcm with flat delivery during the year.

In all scenarios, both the annual Groningen production volume and the production capacity will decrease, although at different rates, see figure 2.In this section, we will look at the impact of those developments on the market for gas flexibility, given the flexibility fundamentals as described in the previous chapter and with special emphasis on the L-gas market. Before discussing the longer term impacts of the production scenarios, we will first address the short-term until 2017.

Short-term implications Figure 6 illustrates the immediate (left) and 2016 (right) impact of the Loppersum production reduction on monthly production during the year. Monthly total production has been lower in 2014 when compared to average production over the previous four years, whereas the contribution of non-Loppersum (‘other’) production clusters has been higher than in previous years. This indicates the important contribution of Loppersum to delivering capacity in previous year, which can no longer be used.

As a consequence, capacity delivery of the other clusters will more rapidly decline. Given the assumed annual volume to be produced, the monthly volumes from the non-Loppersum clusters will be fairly constant (see picture for 2016 on the right). Loppersum may contribute in winter months and, as in the beginning of the year the temperatures at the end of the calendar year are not known, we assume that NAM and GasTerra will be cautious on the production in the first months of the year. Therefore we expect a relative high production from Loppersum in December20.Already in 2016 total monthly production capacity cannot meet the usual profile (picture on the right), resulting in an estimated lower volume of some 55 TWh (5.6 bcm, which is the sum of the difference between the red curve and the bars in winter months). Therefore, to bridge this gap, other flexibility provisions are required.

19 Although we call it business as usual, it doesn’t seem to be the most likely scenario after the recent discussions. This scenario should be interpreted as business as usual before the earthquakes.20 In the meantime, the minister acknowledged this risk and decided that the production cap refers to the gas year instead of the calendar year.

Figure 6 - Impact of Loppersum production reduction on working volume

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The Groningen production decline is one of the reasons for NAM/GasTerra to expand the capacity of the underground L-gas storage capacity in Norg21, assumed to come online in 2016. Norg will be used to cover gaps in working volumes as a result of Groningen production changes. Presumably, capacities of Norg will be more than sufficient to provide the required volumes in the coming years.

Even in worst case circumstances with extremely low temperatures for an extended period of time22, available base load (Norg, Epe, Huntorf & Nüttermoor, Sediane B) and peak load (PGI Alkmaar) storage capacities in combination with gas quality conversion capacities will be able to address L-gas demand in the Netherlands and Northwest Europe, given BAU and the extended Loppersum scenarios. This is shown in figure 7 for the year 2017. However, the figure also illustrates that restricted flat production from the Groningen field leads to a shortage of L-gas working volume of approximately 50 TWh in 2017 (this is the area between the curve and the storage provision).

21 Norg is to be regarded as a facility integrated with the Groningen production system. No access regime applies to Norg. Source: GSE Storage Map, July 2014.22 The temperature profile of the winter 1962/63 defines a cold year.

Long-term implicationsApplying the Groningen production scenarios, including minor amounts of L-gas production from Dutch small fields and Germany, and quantifying the supply-demand balance of the Northwest European L-gas market towards 2030 reveals that there probably will be sufficient working gas volume to meet the declining Groningen volume and capacity, even if we assume relative cold years with higher than average gas demand.

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Figure 7 - L-gas storage contribution to working gas in 2017 assuming a cold winter


Figure 8 - Development of L-gas supply and demand in Northwest Europe

Figure 8 depicts the development of L-gas volume from 2019 to 2027 in Northwest Europe for the Groningen production scenarios. The demand shown is for a cold year and already accounts for market transition from L to H-gas in Germany and Belgium/France. The graph clearly shows the opposite developments in the BAU and the flat 30 bcm scenarios over the years. After optimized use of Groningen production, the resulting gap between demand and supply requires the use of L-gas storages (105 TWh) and quality conversion through nitrogen (223 TWh base load). The gaps between supply and demand in figure 8 are never higher than 300 TWh, therefore, on an annual basis storage and base load quality conversion (together >300 TWh) are sufficient to meet demand.

However, doing the same analysis while looking at daily capacities during the year, provides a more nuanced picture. Zooming in on the year 2023, figure 9 shows the load duration curves depicting the resulting shortage in working volume over the year after optimization of Groningen production, while assuming23:

n Higher than average demand due to a cold wintern Market transition from L to H-gas in Belgium, France and Germanyn Some L-gas production in Germany n Maximum use of enrichment at Dutch exits (domestic and export)n Groningen production within the given scenario constraints

We have assumed that, apart from L to H-gas market transition, the annual L-gas demand remains constant up to 2030. L-gas is predominantly supplied to the residential market where increased insulation is compensated by additional homes build and fuel switching (coal and heating oil to gas) in Belgium and France. Since the L-gas market is dominated by residential and commercial customers, the options for interrupting demand in severe winters are limited. In addition, the L-gas demand is assumed insensitive to price hikes during severe winters.

23 The same assumptions apply to figure 8.

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The load duration curves (working volume required) of the scenarios are compared with assumed available L-gas storage and base load nitrogen capacity during the year. It shows that these options provide sufficient working volume to cover peak L-gas demand in Northwest Europe. However at some days/intervals storage and base load nitrogen capacity cannot meet the requirements, as indicated by the white areas below the load duration curves. In those intervals, GTS will need to use back-up nitrogen capacities in Heiligerlee and Pernis to meet the peak requirements.

Figure 10 illustrates the sizes of the white areas, i.e. the sum of daily shortages in capacity in the winter period, for the three scenarios and for several years. It shows that the extended Loppersum scenario provides the least trouble with respect to peak load provisions, which is mainly due to the fact that Groningen production capacity is preserved for the long run with immediate near-term production volume reductions.

In the BAU scenario production capacity can be maintained in the near-term. However in the long run towards 2025 shortage in peak capacity accelerates. This scenario would however provide time to find solutions to the foreseen capacity problem. The flat 30 bcm scenario works in the complete opposite direction. Capacity problems arise immediately and will gradually fade in the long run. In this scenario there is no time to find or invest in additional peak capacity.

Given the above, we conclude that L-gas storage facilities in combination with nitrogen base load facilities in the Netherlands in general are able to meet the required working volume in the long run. However, depending on the chosen production scenario, shortages in peak capacity may arise. In particular the assumptions on the market transition from L-gas to H-gas in Germany, Belgium and France, and gas quality conversion capacity have a large impact on this outlook. In the long run the supply-demand issues in the L-gas market will subside due to the planned L to H-gas market transition in Germany, and as we have seen, at a later stage in Belgium and France. Any delay in such market transition will have a direct impact on the L-gas flexibility market. Other uncertainties are the availability of H-gas required for quality conversion and the availability of L-gas in summer to fill the storages.

Figure 9 - Working volume requirements in 2023

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Figure 10 - Development of working volume shortages

However, the main uncertainty remains what will happen with the Groningen production for 2017 onwards. If the minister decides to further lower the Groningen production, e.g. towards 30 bcm per year with a flat delivery schedule within the year, security of supply problems related to peak delivery in the winter arise. Also the further details of such production decision are important. For example, the decision may include some ‘force majeure’ clause for emergency volumes delivered by Groningen, assuming an agreement between the government and NAM that allows NAM to produce extra Groningen volumes when temperatures drop below certain limits (whether or not within the limits required to prevent further seismic activity).

If additional Groningen production limits are applied, we expect an issue for gas quality conversion during peak situations, especially in the period 2020-2025. GTS recognized and anticipated on possible L-gas capacity shortages by investing in nitrogen peak capacity around 202024. However, in the long run, L-gas demand, both in terms of volume and peak demand, is likely to decrease. Current investments in quality conversion assets – or in L-gas storage for that matter - may prove to be stranded by e.g. 2030. Structurally reducing gas demand peaks and measures that do not require major investments, may be more cost-effective.

24 Gasunie Transport Services. Mogelijkheden kwaliteitsconversie en gevolgen voor de leveringszekerheid. Resultaten onderzoek 7. October 2013.

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SAFER, SMARTER, GREENER

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The analysis in this paper gives a flavor of the impact of limiting gas production from the Dutch Groningen field and the physical measures present in the market to mitigate the impact.

The subsequent decisions by Minister Kamp on Groningen production limitations do not drastically affect the Northwest European market in the short run. The production reductions can be handled by the market in the coming years (2015-2016). With the Loppersum restrictions, total monthly production capacity cannot meet the usual profile, resulting in an estimated lower volume of some 55 TWh (5.6 bcm) in 2016. The expansion of the underground L-gas storage capacity in Norg will be used to cover gaps in working volumes as a result of Groningen production changes. In combination with other storage capacities and with gas quality conversion capacities, the market will be able to address L-gas demand requirements.

In the longer run, if the Loppersum production cap is extended after 2016, the cumulative Groningen volume produced until 2030 will be some 600 TWh lower than compared to business as usual. However, capacity from Groningen will then be preserved and up to some 8 GW higher than with business as usual in the long run.

Further lowering the Groningen production after 2016, e.g. towards 30 bcm flat delivery, would imply security of supply issues, with both L-gas working volume and capacity problems already in the short term. For example, the gap would be some 30 TWh or a maximum of 467 GWh/day in 2019 with flat production at 30 bcm. The availability of quality conversion capacity by GTS is then important, especially in the period 2021-2025 when looking at the various production scenarios. But this will also provide an opportunity for Dutch and German L-gas storage facilities. The market transition from L to H-gas in Germany is crucial here. Any delays in this transition have an immediate impact on the market.

For a more detailed analysis of gas quality conversion capacity in peak situations, a within-day analysis would be required, but is not part of this paper. Moreover, costs of the various flexibility options have been disregarded here.

CONCLUSION5

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