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Gas storage - an opportunity to optimise revenues for pipeline operators?

Gas storage comes in a sliding scale of complexity and associated volume requirements. Depending on the duration of gas storage and the rate at which the gas has to be withdrawn, there are a number of options available.

Kai Eberspaecher Senior Associate

by Kai Eberspaecher

Senior Associate, Brisbane

18 August 2017
twilight view of gas plant and storage tanks

Gas storage can provide flexibility in a market where demand exceeds ‘online’ supply through current production from upstream gas operators. Depending on how prolonged the excess demand continues, a range of storage options could be applicable to supply gas for power generation.  

Gas Storage

bubble graphicFigure 1: Complexity vs. Time Horizon for Storage Options 

In Figure 1, the ‘bubble’ size is proportional to the relative cost of establishing any of the storage alternatives from a storage operator’s perspective. The ranges for both complexity and time horizon are low, medium and high.

In general, the economic drivers for storage are based on the following fundamental requirements2:

  • Supply security enhancement as supply backup in case of emergency
  • Daily volatility
  • Seasonal volatility
  • System efficiency enhancement

The storage alternatives available to address some or all of these requirements include:

Short-term commercial instruments - Most of the capacities are traded under long-term Gas Transportation Agreements (GTAs) and Gas Sales Agreements (GSAs). Trading variations for these are managed by bilateral agreements through nomination services provided by pipeline operators

In pipe storage – line pack - Building line pack is to inject gas within the operating envelope of a pipeline above the required delivery pressure. A surplus inventory is maintained over and above what is required to be delivered to the off-takers.

Liquefaction and regasification - A liquefaction facility cools gas and reduce its pressure to be stored as a liquid in tanks. When gas is required, it is vaporised and injected into the pipeline. Liquefaction facilities offer limited storage capacity which allow for support during peak usage. The operating costs of such facilities are significant given the energy required to refrigerate, regasify and compress the gas.

Underground storage3 - A number of different options are available depending on the geological setting and proximity to potential markets. Typically underground reservoir storage falls into one of three categories - depleted hydrocarbon reservoirs, aquifers or salt domes.

Regulatory supply management - State or Federal governments introduce regulation limiting gas production through incentives, subsidies, production allocation to market participants and stipulating minimum storage requirements for the region or country.

Australian Gas Market

Trading

In Australia only physical trading is implemented, and there are no financial derivative instruments available. The only ‘derivatives’ are forward contracts for gas delivery which are listed for the Wallumbilla Gas Supply Hub and Victorian Declared Wholesale Gas Market. Furthermore, a comparatively modest (on an international scale) spot market exists in Western Australia with a daily volume of around 10 to 15 TJ/d.

The Australian Gas Market4 does not have a national wholesale presence like electricity. Gas producers sell gas to energy retailers or large industrial gas users, and are linked by a network of high-pressure pipelines. Pipeline operators sell capacity in their pipelines.

In Australia certain regulations2 apply to setting gas prices. In practice, these are only for small domestic users - wholesale pricing is not regulated.

However, the Australian regulatory regime1 for the transportation of gas described in the National Gas Law and National Gas Rules provides two forms of regulation based on a pipeline’s relative economic market power – full regulation and light regulation. The regime applies to most gas distribution networks and a number of gas transmission pipelines in Australia and sets transportation tariffs.

For assets under full regulation, the Australian Energy Regulator (AER) approves price and other terms of access as part of an access arrangement process. The process allows the asset owner to recover at least the efficient costs of owning and operating the asset. For assets under light regulation, contractual terms are negotiated between the service provider and customer with an option for arbitration by the regulator.

According to the Australian Energy Market Operator (AEMO)’s website4, the Eastern Gas Region (interconnected gas grid connecting all of Australia’s Southern and Eastern States) has some wholesale markets for gas, which allow retailers or large customers to purchase gas without entering into long-term contracts. These markets are utilised to manage short-term imbalances between supply and demand by the producers or customers. AEMO operates these markets:

Short-term Trading Market - AEMO operates the Short-term Trading Market at demand hubs in Adelaide, Sydney and Brisbane. A gas supply hub has also been established at Wallumbilla. The idea of a hub is to establish a price reference for physical trading purposes. Forward contracts are available at Wallumbila.

Declared Wholesale Gas Market - AEMO operates the Declared Wholesale Gas Market in Victoria.

Storage Differences

Most Australian5 storage capacity is limited to serving the Eastern seaboard where the majority of the population lives. There are also no minimum regulated storage requirements. The current storage facilities are owned by producers, shippers and wholesale generators alike. In Australia, only depleted hydrocarbon reservoirs are currently utilised for underground reservoir storage. It is unlikely that suitable aquifer injection will be available from a technical or a societal acceptance perspective. Current salt dome structures are sparse and remotely located. Short-term contractual vehicles, including a spot market in the West, line pack and LNG facilities are currently used as well.

The following gas storage facilities are in operation in Australia:

table graphic

Table 1: Overview of current Gas Storage facilities in Australia

Economic Considerations

Before investing in gas storage, some economic considerations should be given to the capital and operating cost of the storage facilities versus the potential revenue which ideally should generate a profit for the storage owner and operator.

In any market, it is always good to ‘buy at low prices and sell at higher prices’ to cover costs and make a profit. For gas storage, this is not that different. It is however essential to have a good view on the cost of capital and operating costs such as injection rate, blanket gas, storage, withdrawal rate, treatment for export and reinjection. Typically for reservoir storage options as well as LNG, this requires rotating equipment that is complex to maintain and operate. A storage operator needs to form a skilled workforce and specialist contractors to be able to have sustainable operations. Given that some of the storage assets might be depleted reservoirs, aging facilities, wells and infrastructure might impose a higher burden to maintain its asset integrity. For LNG storage, the process of liquefaction is complex and requires a high degree of dedicated maintenance. Specifically for LNG, there is also a limitation to the size of the storage tanks.

Key to operating storage facilities is the ability to seize opportunities (e.g. buying distressed gas from shippers who have to produce but cannot deliver due to an outage at the consumer end). Line pack is the first mechanism that provides a buffer, but for more sustained outages, reservoir or LNG storage would become applicable. This requires the facilities to be in an operations ready mode, ready to receive, inject or chill gas and store at low prices.

On the revenue side, opportunities to sell at high prices arise in times of peak demand which might only last a few hours to a few days depending on the circumstances. These could be a cold chill leading to higher than usual demand or spikes in electricity requirements. Some predictions can be made by following the market demand trends on the electricity market, for example the baseload is provided by coal-fired plants, so any demand above a certain threshold requires gas-fired ‘peak’ power plants to come online.

Gas Storage – An opportunity for Australian Pipeline Operators?

The decision to make an investment in gas storage for Australian Pipeline operators in the coming years will be based on a combination of the following factors:

Domestic demand patterns: With the onset of large-scale gas export on the East Coast by LNG producers, the demand pattern for peak usage might experience sharper increases due to a higher base load for export as has been recently experienced. Addressing seasonal volatility / peak shaving is a potential value driver in the highly populated East Coast. Furthermore, LNG proponents might be willing to pay a premium for stored volumes in order make their contracted volume nominations. Maintaining or increasing the system utilisation of the LNG trains is a key potential value driver for storage solutions. It is in these circumstances that stored capacity is most valuable. This requires agile response to changing market conditions or calls by customers and storage installations that can respond quickly. Once all six LNG trains are operating on Curtis Island, the ability to meet shortfalls by using other proponents’ gas will diminish unless new sources of gas are developed within the Bowen, Surat, and other adjacent basins to allow for an excess in supply.

Storage location: The physical location of a reservoir or LNG storage facility is important in order to minimise transportation cost and respond quickly to changing demand.

Storage mechanism: Interested parties should consider options including complexity and operating cost. These should match the internal technical and commercial capabilities of the pipeline operators. It is also beneficial to think of the storage mechanisms in a spectrum ranging from commercial contracts to reservoir injection and develop a portfolio view on how to optimise their utilisation. The selection of withdrawal rates and associated recharge rates as well as the volume required will determine the choice of storage mechanism.

Vertical integration: Pipeline operators could also consider expanding their field of operations to manage gas supply and couple this with a portfolio of storage options. This vertical integration could allow Pipeline Operators to optimise pipeline utilisation and respond quickly to customer demands. The investment angle under this consideration would be to maximise opportunities in a peak supply scenario as well as offering physical hedging services to market participants on the supply and demand side.

Regulatory environment: A stable regulatory environment is required in underpinning any investment. Such an environment permits market forces to operate and optimise price as a function of supply and demand.

Conclusion

Gas storage in Australia has the potential to address three elements that typically exceed baseload and lead to peak demands and high gas prices. These include:

  • Seasonal volatility
  • System utilisation for East Coast based LNG projects
  • Emergency Supply of peak loads

Elements 1 and 2 are naturally suited due to the potential volume requirements to large-scale underground storage that could be recharged over longer periods of time and withdrawn over a shorter window of opportunity. Element 3 lends itself to LNG facilities to protect against loss of supply for a very short peak demand. Addressing daily volatility can be achieved through short-term trading instruments, an active spot market like in Western Australia or line pack.

Enabling Framework

In order to promote a more competitive environment for setting gas prices, it seems that less regulation and more negotiation stimulate the market laws of supply and demand to settle on fair prices. A competitive market benefits from a sufficient number of participants on the sell, buy and transportation side. In the US, prices are set at trading hubs such as Henry Hub. Australia could benefit if, for example, Wallumbilla would become a trading hub of a similar standing. The associated business case with peak shaving for storage would create a physical and natural hedge against excessive short-term price hikes.

Furthermore, over and above the storage requirements, physical interconnection of gas markets like the Northern Gas Interconnector assists in developing a diversity of supply. Maturing further upstream supply streams and connecting these to the existing transportation infrastructure will aid in reducing gas prices at current demand levels.

Emerging Opportunities

For pipeline operators looking to extend their current operations into upstream gas supply and gas storage and respond to the three elements above, the following opportunities arise:

  • Identify underground storage options near existing and future markets
  • Identify potential peak / emergency supply options to cover for outages
  • Identify upstream gas sources that can be integrated with pipeline operators
  • Promote an open market approach with less regulation and more freedom for trading and investments

Given recent gas price hikes, the question is not if pipeline operators are considering making further investments in storage options and other vertical integration opportunities such as upstream production, the question really is when?

References

  1. European Commission, Directorate-General for Energy Internal Energy Market, “The role of gas storage in internal market and in ensuring security of supply”, 2015, EUR 2015.1391

  2. Lauer, Mike, Project Consultancy Services Pty Ltd, University of Western Australia, Faculty of Law, Session 9: Gas Storage and Transportation, Oil and Gas Agreements, 2016

  3. INGAA Foundation, “Profile of Underground Natural Gas Storage Facilities and Market Hubs”, 1995

  4. www.aemo.org, 2016

  5. Core Energy Group, “Gas Storage Facilities Eastern and South Eastern Australia”, February 2015

 

Topics

Kai Eberspaecher Senior Associate

Kai Eberspaecher

Senior Associate

Kai brings a broad skill set in evaluating, designing, operating and improving conventional and unconventional oil, and gas assets, in multi-disciplinary environments in a variety of geographic locations. During his time working offshore in the North Sea, Kai gained valuable production engineering experience. In Kazakhstan, Kai delivered brownfield capital projects in a remote complex joint venture environment. In Australia, Kai worked in the front end upstream design and later in the commissioning and start of the world’s first coal seam gas to LNG development. Kai’s unique blend of international project management, engineering, production and operations experience allows him to quickly integrate into client teams implementing long-term solutions to challenges in the hydrocarbon industry.

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