Will shale gas be the “game changer” for world energy markets that many analysts predict? It’s certainly a revolution in the US with 20% of the nation’s natural gas supply already coming from shale. This is forecast to rise to 46% by 2035. Shale gas also presents a major opportunity in Australia with the discovery of large deposits. But it could easily fall victim to the same environmental and reputational issues that have stricken the CSG sector. How can these risks be overcome so that the industry can move towards becoming a viable alternative to conventional gas supplies?
Shale rock is situated deep below conventional gas deposits and is both a source and reservoir for natural gas. Horizontal drilling together with hydraulic fracturing (or “fracking”) is used to move natural gas deposits from the shale to the surface.
The United States has some of the largest reserves of shale gas in the world and is at the forefront of SGE developments. International companies like KOGAS, Sumitomo, Eni SPA and CNOOC have partnered with local US energy companies to develop SGE projects and global oil companies such as BP (United Kingdom), Statoil (Norway) and Total SA (France) have acquired significant acreage in key shale deposit areas.
It is forecast that shale gas will provide sufficient natural gas to supply the United States for the next century, effectively allowing the United States to become energy self-sufficient.
Australia’s shale gas resources are also substantial and while the sector lags the LNG and CSG industries, commercial arrangements have formed between international and local oil companies, Japanese trading houses, and Australian explorers to pursue SGE opportunities in the Cooper, Canning and Perth Basins.
The potential for a shale gas revolution in Australia is huge, however the risks are daunting. In addition to the usual risks for an oil and gas project like fugitive emissions, well blowouts, and access to pipelines and infrastructure, SGE has other risks that require careful management.
Fracking: The new “F word”
Fracking stimulates natural gas wells in the shale to enable gas to be removed and transported to the surface. Although its been used in mining since the 1940s, fracking can cause or exacerbate seismic activity. This has been a major concern in populated areas in the US and Europe, but is less of an issue in Australia due to the remote desert locations of many shale deposits. Infrastructure is also now built to withstand seismic activity which has further mitigated such risks.
Water, water everywhere: Use and contamination of water supplies
To frack a well requires millions of litres of water, which is mixed with “proppants” (like sand or mud) and a small percentage of chemicals. Accordingly, SGE companies need to manage: where they source their water supplies; how they protect any potable water aquifers; and how to dispose or, or treat, flowback or wastewater.
Advancements in water treatment technology have enabled SGE companies to take a lifecycle approach to water management, reducing the amount of potable water used in the fracking process and recycling flowback. Multiple cemented steel casings are also used to secure wells and protect shallow aquifers against the uncontrolled flow of contaminated fluids.
Domestic gas market
The Australian domestic gas market is one of continental contrast: the West has a shallow market and higher prices; the East has the reverse. There is a risk that a major shale play in WA will swamp the domestic gas market and hammer local prices. Curiously though, it is another part of the gas industry which could help ameliorate this risk.
Australian LNG projects themselves use substantial volumes of gas: approximately 220 petajoules (PJ) per year for each LNG train. To put this in context, the annual volume of gas required by the four trains already committed in Australia (two each by BG Group and Gladstone LNG) will equal the current eastern Australian demand. These volumes must be supported by proved and probable reserves equalling the volume of gas committed to buyers in offtake contracts, plus margins for risk management purposes.
Committed projects therefore require an enormous volume of gas, and additional trains for Inpex / Total’s Project Ichthys and Origin / ConocoPhillips / Sinopec’s Asia Pacific LNG will only add to this requirement.
Capital intensive and experimental nature of SGE
There is substantial upfront expense with SGE projects in the exploratory stage. Deposits are at significantly deeper than CSG. This depth increases the cost of drilling, and the risk that hydrocarbons are thermally over-matured so that the heat and pressure has converted the gas to carbon dioxide.
There is also a heavy reliance on 3D seismology and exploratory drilling to model each opportunity. This requires technology, rigs and crews to be imported from North America to help up-skill the local labour force. Accordingly, while skilled, well-equipped crews in the US can drill twice as cheaply and quickly as they could five years ago, it still costs five times as much to frack a well in Australia as it does in the US.
What remains in SGE’s favour is that multi-stage fracking, and multiple well orientation from single surface wellpads, means that only a fraction of surface wellpads are required when compared to a conventional gas or CSG project.
Most shale gas plays in Australia, as they move from exploration towards production, have been funded by way of equity raising or farm-in arrangements between the explorer and an international or national oil company.
As shale gas production in Australia is still in its infancy, it would be difficult to fund a shale gas development on a project finance basis (and impossible if there isn’t a bankable offtake agreement in place with a creditworthy offtaker). Project finance banks in Australia would need to be more confident with the extraction technology (both in terms of its cost and proven application), management of the environmental and reputational risks, as well as mitigation of other risks such as those set out above.
Lenders may draw comfort from parent guarantees from listed entities of strong credit-standing. However, if recourse to the parent is too great, it would be less expensive for the parent to finance the development on a corporate finance basis.
From a corporate finance perspective, bigger explorers that already have assets producing cash flow (e.g. from conventional gas fields) have been able to secure borrowing base facilities with major banks to fund shale gas exploration activities.
Borrowing base financing is a special type of working capital facility that is collateralised using a company’s current assets, such as 2P reserves. In contrast to standard, fixed-sum working capital financing, the maximum amount of credit that can be used is dependent on the amount of collateral provided, and is therefore aligned to the borrower’s liquidity requirements.
Until SGE gains more momentum in Australia and overcomes the environmental and reputational issues that have damaged some CSG projects, they will continue to be financed by way of farm-in arrangements with large national and international joint venturers. The capital cost involved means smaller players are effectively priced out of the market. However, the success of SGE projects in the United States and other countries suggests SGE projects in Australia will, over the medium to long term, present a viable alternative to conventional LNG projects.
 The principal amount a lender will loan to a borrower is based on the value of the collateral the company grants as security. The borrowing base is usually determined by way of “margining”, where the lender determines a discount factor that is multiplied by the value of the collateral; the result is the amount that will be loaned to the borrower.
Jeremy King is a partner in the Banking & Finance team of Corrs Chambers Westgarth, and also the author of the Project Finance chapter in the LexisNexis text Australian Corporate Finance Law.
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