May 7, 2008
NMA/DTe
Bedrijfsvoering en Informatiemanagement (B&I) Postbus 16326, 2500 BH
Den Haag
(DTe-CODATA_NG@nmanet.nl)
Re: Research into Gas Flexibility Services – Reference Number 102651
We would like to thank Mr. Erik Rakhou (NMa) for inviting Vermilion Resources Ltd. to provide feedback on the report by Frontier Economics Research on gas flexibility services, dated January 2008. Our views and comments are in the letter below. We hope you find our feedback useful. Since we are a relatively new player to the Dutch gas market and our expertise is mainly in the fully deregulated North American market, we hope that our views are not too unconventional.
Question 1
• Are you aware of additional possibilities for backhaul flows to be used to deliver flexibility to the Netherlands?
o We would view backhaul as a function of the Dutch gas price versus the export market price. An example would be: a BBL shipper is delivering gas to the UK. The NBP price is lower than the TTF price, such that the shipper can buy gas at the NBP to meet its UK market obligation and then sell their gas domestically at the higher TTF price. The price differential would only have to be greater than the variable costs of transport for the BBL firm service. The same principle can be used at the other export points. This would provide flexibility for the H-gas market, as well as for L-gas if enough quality conversion capacity exists.
o Export/import transportation capacity tends to be held by large companies (long term contracts and credit requirements), thus whether this would be efficient and available would depend on how much competition is in the domestic market. The lower the competition, the less likely a large company would divert gas into their domestic ‘dominant’ market, as it may lower the market price.
• Is it practical for backhaul flows to be used to deliver flexibility services to the Netherlands, for example, if export contracts delivered gas at a point located in a system adjacent to GTS’ system, backhaul flows into the Netherlands would require the payment of additional cross-border fees?
o The choice to charge fees is really up to the regulator, not a requirement. If no additional facilities or capital are required, then only an efficient nomination process would be required. If facilities are required, the regulator should determine if costs should be underpinned by firm contracts (limiting competition to large players?) or paid by the overall system users because of a public need. Public need for backhaul capacity could be in the form of creating competition for dominant players, by allowing free flow of gas across borders (flexibility). You may also want to provide cross-border capacity such that it could be used on an interruptible basis (open to all players).
o The pipeline should always have an efficient nomination and capacity allocation process. There should never be a situation where capacity goes unutilized when there are shippers willing to use that capacity. By having a use-it-or-lose-it firm service policy and deadlines for nominating firm service flows (or lose it for that day), then interruptible players can compete and utilize the spare firm capacity. This forces the holders of firm service to create and use a secondary market for firm service, leading to more flexibility and competition. If holders of firm service do not use the secondary market, then they incur the firm service cost. The fees collected by the pipeline for interruptible service can be allocated across all firm service shippers to lower the overall pipeline fees. We would recommend simplifying the tolling process. The toll for firm service should be based on a 100% demand charge (pay monthly Euro amount regardless of whether service actually used). Then have an interruptible toll (Euro per unit volume) that is set slightly higher (e.g., 10%) than the firm service toll (based on a Euro per unit volume at 100% utilization). This would help create an efficient secondary transportation market and also encourage shippers to hold firm service that would allow for more efficient pipeline design and planning.
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Confidential Page 2 of 4 Vermilion – February 20, 2008
o We were wondering if the shipper nominations and physical flows are managed somewhat independently by the pipelines? The physical flow between interconnecting pipelines is usually handled via an Operational Balancing Agreement. The two pipelines physically control the flows and pressures such that both systems are optimized and/or help each other via linepack variations. The shipper nominations (firm and interruptible service contracts) are used to allocate the gas deliveries between the pipelines. Operating the two separately could create more flexibility.
Question 2
• Please comment on the frequency and duration of interruptions assumed in Frontier’s 2008 Report.
o See answer in Question 1. We view GasTerra and other exporters to have considerable flexibility by varying their export flows. The ability to swing exports will increase as markets (e.g., TTF, BEB) become more mature and liquid.
o We believe the ability to swing small fields production will decrease significantly given the maturity of the fields. From our experience, the value small producers receive for providing swing capability to GasTerra is low. There should be a higher premium paid for providing swing flexibility.
• Can you provide additional detailed information about the ability to interrupt long term contracts currently in place with power plants and large industrials?
o We have no information, as we are not a party to these types of agreements.
o In principle, to have a liquid and efficient market, the interruption of long term contracts should be left to the market players. Only under extreme emergencies (last resort) should curtailment of non-core markets be considered. The gas market and infrastructure should be robust enough to handle demand swings for its peak design (e.g., -17’C) without having to resort to curtailing markets. During cold weather, prices will increase significantly until demand destruction occurs (i.e., industrials curtail consumption). Curtailment should be handled by the market, driven by what makes economic sense between the parties involved. Security of supply for the core market would be provided for better by developing and utilizing gas storage.
o An example of an efficient market curtailment was a Canadian aluminum company where they had a long term low fixed price gas supply contract. When winter prices skyrocketed, the company decided to shut-down operations and re-sell the gas back in to the market. They made more money by re- selling the gas than if they had consumed the gas within their business operations. This is an extreme example, but companies may find it more economic to curtail their base business and re-sell their gas supply. Of course the market (nomination process and TTF market) must be efficient enough to allow for quick curtailments and diversions of gas.
Question 3
• Is the assumed total linepack volume available for flexibility services and the allocation of that volume to the L- gas and H-gas systems (see also Table 2) realistic?
o We would suggest segmenting the linepack between the two systems. H-gas is relatively stable throughout the year because the gas is mainly used for industrial purposes (page14 and Figure 2). H- gas is also the gas quality used by most European countries. The GTS tolerance and balancing rules for H-gas could be changed to a daily basis to match the UK market. This would enhance the TTF liquidity and its linkage to the NBP price. Those delivery points that have large hourly swings could be treated and balanced separately.
o As for L-gas, the hourly balancing could be maintained, as long as proper flexibility services are provided, as described in the report (quality conversion capacity). For the actual split between H-gas and L-gas, we would require more information to comment.
o We would recommend creating a GTS Shipper Taskforce to discuss, design, and implement new processes on the pipeline. This is common practice in North America, where pipelines and shippers jointly develop processes and rules (e.g., balancing, linepack allocation). This helps each party appreciate and understand the others business and corresponding physical limitations. Please consult the TransCanada Alberta (Nova) Pipeline website for examples of these taskforces and resulting processes and rules. http://www.transcanada.com/Alberta/
• Does the allocation of all linepack to non-GasTerra firms reflect the control of linepack?
o We would disagree with the assumption that non-GasTerra firms control or will control linepack.
GasTerra has a dominant position. They control the L-gas source (Groningen) and the majority of quality conversion and domestic sales. Even if end-users are able to buy all their supply on the TTF (GasTerra must provide supply), many will lack the ability/expertise to contract and balance their own supply.
Confidential Page 3 of 4 Vermilion – February 20, 2008
Question 4
• Can you comment on the assumption that GasTerra controls 85% of the capacity from the small fields?
o We do not have any firm data, but would have estimated this number to be even higher. The small fields contracts are for life of reserves. The producer is not allowed to sell excess production that GasTerra does not take on a given day on the Dutch market (TTF). This limits competition and provides GasTerra a very cheap source of flexibility. (see Question 2, first bullet). We recommend that the small fields producer be able to sell any excess gas that GasTerra does not take. This will increase competition and create a more liquid TTF market.
o If the percentage is based on production and certain production capability is restricted due to the contractual rate of take terms GasTerra has in their agreements, then the amount controlled would be much higher on a productive capability basis.
Question 5
• Please comment on the assumptions about forecast demand.
o No comment.
Question 6
• Which of the listed projects do you believe would become operational by 2011 (and if so, when)?
o The lower capital expenditure projects (i.e., salt caverns) and those in Germany where the storage regulations are easier to manage (fiscal/regulatory certainty) should become operational first. Large storage projects in Netherlands (e.g., Bergermeer) will likely be delayed.
• Do you expect other relevant projects in addition to those listed above to become operational by 2011, e.g.
German storages directly connected to the GTS system?
o Yes, we hope that there will be some gas storage projects initiated by small fields producers.
• Can you provide information about expansion plans of existing storage facilities (in particular the Norg facility)?
o No comment.
Question 7
• What capacities (in terms of maximum injection rate onto the GTS system in mcm/hour) do you expect for those projects in Table 6?
o No comment.
• Which firms will control those capacities (either physically or through long term contracts) or, in the case of multiple firms, in what proportion will they control the capacities?
o We would expect to see GasTerra involved in most of the projects since they are a dominant player.
Question 8
• Please comment on the assumed capacities and allocation of flexibility associated with interruptible contracts.
o From a supply perspective, the GasTerra small fields agreements do not provide the producer with the ability to provide interruptible gas. (see Question 4) GasTerra controls all the flexibility.
o For end-user agreements, we have no comment.
• On average, how often are contract interruptions used and how long could an interruption last?
o For small fields, the contract is confidential. Please contact GasTerra.
o For end-user agreements, we have no comment.
Question 9
• Please comment on any of the assumptions made by Frontier for the capacity share analysis.
o No comment.
Question 10
• Please comment on any other aspect of Frontier’s 2008 Report
o Some of these comments are related to DTe’s paper on the “Acceleration of the development of the TTF and the gas wholesale market”, dated September 2007.
o We were wondering how fast the Dutch government will want to convert to an open gas market if other countries are not proceeding as fast? This creates a competitive disadvantage for GasTerra and other Dutch marketers. This may change some of your assumptions and forecasts.
o How much foreign control of the L-gas market is the Dutch government comfortable with? As long as GasTerra controls the L-gas source (Groningen), this may not be an issue.
Confidential Page 4 of 4 Vermilion – February 20, 2008
o How will the price for ‘H-gas provided by a third party for an L-gas delivery’ be determined? GasTerra controls the source and the majority of quality conversion. There is not really a free market for L-gas to establish a price. Is there a type of ‘replacement value’ that would set the minimum price for L-gas on the TTF? An example would be the H-gas price plus conversion costs.
o If third parties are allowed to deliver H-gas at the TTF for L-gas, and this is a deemed conversion (GTS contracting with GasTerra for Groningen supply) instead of a physical conversion, where will all the H- gas at TTF go? Is the H-gas market large enough to absorb the deemed L-gas conversion volumes?
o Quality conversion should be first allocated to off-spec small fields production, then for the overall H- gas to L-gas market.
o An example of an item we would recommend for a GTS Shipper taskforce to handle is having no entry or exit tolls for storage interconnects. Our storage fields do not pay entry or exit tolls to the pipeline they are connected to. This is because the gas entering storage has already paid an entry fee to get on the pipeline. When storage gas is withdrawn, the gas pays an exit toll upon delivery off the system.
The pipeline is kept whole on fees. Storage is also a benefit to the pipeline, helping it maintain operational pressures and flows via shippers balancing their account (stable linepack).
o How will the expansion of NAM facilities (Groningen et al) under the Private Law Contract be handled with respect to competing with other parties? It appears NAM (gas storage) and GasTerra (Groningen, gas storage) are dominant in flexibility. Should there be some form of rules to ensure new storage entrants can compete?
o For cold weather events, most of NW Europe is cold at the same time, requiring flexibility services to be used at the same time, as opposed to shared. We believe there will be a higher need for flexibility services than currently forecasted due to the coincidence of cold weather.
o We strongly support holders of production licenses be given the first right (no public bid process) to convert their gas fields into gas storage. An appropriate time limit should be provided for non- producing gas fields where no plans for further activity (production, storage) are in place, before the MEA considers revoking a non-producing gas field. Our current understanding of the Dutch Bill on gas storage is that it supports our position.
Thank you again for allowing Vermilion to provide feedback on the Dutch gas flexibility services. If it is the Dutch government's intention to move toward an open competitive market place, we would like to assist in helping to remove barriers that discourage the development of efficient secondary markets. By encouraging efficient trading, more storage development, and more competitive pricing, the market would then be free to provide balancing &
flexibility services in the most efficient manner possible. These same features would also help create the Dutch Roundabout. This would in turn increase products and services, providing consumers with secure gas supplies at competitive prices.
If you have any questions, please contact Alan Sharp at 1-403-698-8845.
Sincerely,
Alan Sharp
Manager, Marketing Vermilion Resources Ltd.
