The impact of LNG exposure on Australia s eastern gas market. Ross Lambie, LNG18

Transcription

1 The impact of LNG exposure on Australia s eastern gas market Ross Lambie, LNG18 April 2016

2 The impact of LNG exposure on Australia s eastern gas market Ross Lambie 13 April 2016, LNG18 Thank you to the organising committee of LNG18 for having me here today to present on the impact of LNG exposure on Australia s eastern gas market. There are a number of expectations about the potential effects of LNG production on the eastern Australian domestic gas market. My presentation today will hopefully provide clarity to the underlying economics and some insights into the implications. The presentation draws upon analysis recently undertaken by the Department of Industry Innovation and Science and published in the Office of the Chief Economist s Gas Market Report. 1.1 Australia s LNG exports are growing Global demand for LNG is projected to grow faster than overall gas demand, at 7 per cent a year from 2015 to The main destination for global LNG imports will continue to be in Asia, which will take over 70 per cent of global demand. Australia is well endowed with gas resources and has taken advantage of its location close to the centres of demand in Asia to service this market with LNG. Australia is experiencing a major expansion of LNG export capacity, and by 2019 is expected to supply about 20 per cent of the global LNG market, up from 9 per cent at present. The current expansion of LNG capacity, amounting to over 80 billion cubic metres, has involved a capital investment of over $200 billion dollars, and is in aggregate one of the largest resource developments in this country. By , LNG exports are projected to constitute 20 per cent of the value of total resource and energy exports from Australia. The impact of LNG exposure on Australia s eastern gas market 1

3 1.2 Price volatility and market uncertainty will characterise the LNG market in the medium term The most recent wave of investment in new LNG supply capacity in Australia was initiated at a time when LNG demand was forecast to grow rapidly particularly in the Asian region, and LNG prices in Asia were at historical highs. However, since final investment decisions were taken on these projects, the global LNG market has changed. We still expect strong demand growth to However, two major factors are affecting the market. Firstly, the United States is transitioning from a net LNG importer to a major exporter and when all the current investment in LNG capacity comes online it will have production levels roughly on par with Australia and Qatar. Secondly, this is coinciding with the collapse of oil prices, which determine Australian LNG contract prices. The expansion of US supply, on the back of the shale gas revolution, is expected to contribute to excess supply capacity for some time, which will maintain downward pressure on spot prices. This will make it difficult for obtaining investment approval for any new greenfield LNG plants no matter where they are located, at least in the medium term. And will reduce the incentive to expand production through brownfields investments, except where production costs are extremely low. As I ll explain later, this is not likely to favour any expansion of production levels from export plants in Gladstone. Under the current medium term outlook: prices and supplier profits are expected to remain low, there will be growing uncertainties regarding both price and demand volumes, and the LNG market will increasingly become a buyer s market. The impact of LNG exposure on Australia s eastern gas market 2

4 1.3 LNG exports are transforming Australia s eastern gas market Three LNG export projects have been constructed at Gladstone in Queensland, based on coal seam gas, or CSG, as a feedstock. Once complete, these plants will have a total nameplate capacity of 25 million tonnes per annum. The capital investment involved is around $70 billion, with many billions more required in sustaining gas production over time. All three projects have begun production and will constitute 30 per cent of Australia s total capacity by Gas reserves in Queensland to support these projects have grown rapidly over the last 10 years. Proved and probable (2P) CSG reserves in the Bowen and Surat basins were 3,400 PJ in 2005, and have grown to 35,200 PJ in 2011, and 42,700 PJ in The identified 2P reserves are sufficient to cover 20 years of LNG production, provided Arrow Energy s as yet undeveloped reserves are included. In the absence of Arrow s reserves, these projects will have to rely in aggregate on 3P and contingent reserves. A distinguishing feature of CSG production is that it requires continuous investment in new wells to sustain production over time, given the shorter life of CSG wells compared to conventional wells. In a sense, like the Red Queen in Alice in Wonderland, these projects must keep running just to stand still. This adds a new dimension of uncertainty to the projects, since CSG fields can be difficult to evaluate in respect of the complexity and the permeability of the underground coal seams. As a result, the future costs of gas production are uncertain. On the other hand, the operators are rapidly gaining experience and adapting to the local conditions, which, as we have seen in the United States, could contribute to increased productivity and thereby reduce costs. So, while these projects have been very successful in finding massive new CSG reserves in Queensland, in developing local production, processing and transmission facilities, and building the LNG plants on schedule, they face two types of uncertainty: the cost of feedstock gas over the life of the project; and total revenue, subject to the vagaries of oil prices. The impact of LNG exposure on Australia s eastern gas market 3

5 1.4 Long run LNG netback prices have pushed up the domestic gas price The construction of these projects has given rise to concerns about gas prices and gas availability in the eastern market, as a result of the sheer scale of LNG production compared to the size of the domestic market. Once the projects reach maximum production, LNG demand in the eastern market is expected to be almost three times greater than domestic demand. During the investment and construction phase, there has been strong pressure on domestic reserves as LNG producers develop their supply portfolios, with some domestic gas diverted to the LNG projects. This pressure was heightened by uncertainty about the number of LNG plants likely to be constructed. Over this period, it was thought that the linking of the eastern domestic gas market to the LNG market would cause domestic gas prices to rise to the LNG netback price in each state. This is on the basis that the LNG producers would be willing to pay up to LNG netback for third-party gas supplies. A typical long-run netback at Wallumbilla in Queensland two years ago was about $8.40/GJ, more than twice the rate of domestic legacy contracts. We would agree that during the investment phase, the long-run LNG netback was an important driver of prices in the domestic market. The actual price would also be determined by the level of competition between third-party suppliers in the domestic market, and the LNG producers own gas production capacity (which vastly exceeds the domestic production capacity). Gas prices for new domestic contracts have indeed risen. A study for the department by Oakley Greenwood found that although new contract prices had increased significantly, average prices had not risen much because of legacy contracts. Changes in gas supply and price are affecting demand. Gas powered generation (or GPG) demand spiked in 2014 as very cheap ramp gas flooded the domestic market and local prices fell. This highlights the close connection between LNG demand and the domestic market, and the substitutability between gas for LNG and GPG. The impact of LNG exposure on Australia s eastern gas market 4

6 1.5 The drivers of domestic gas prices will change in the production phase Now we are entering the production phase, the dynamics of demand and price will change. The questions we are seeking insights on are: how prices and supply in the domestic market will evolve over time; and the factors that will influence the market as the linkage between the domestic and the global LNG market matures. Since 2013, the department has invested in developing its gas markets expertise, including building its own model of the eastern Australian gas market the Gas Market Model. This capability has allowed us to explore the physical and economic issues affecting the domestic market. In the production phase, LNG supply will be determined by short-run profit maximisation, since the capital investment is now a sunk cost. LNG producers will seek to maximise their profits by choosing a level of production between a maximum which is at, or just above, the nameplate capacity and a minimum which is the take-or-pay obligation of contracted buyers. Profits will depend on the price that either uncontracted LNG or volumes above take-or-pay levels can command in the spot market. The relevant price for these volumes is the Asian LNG spot price. Therefore, the LNG spot price relative to the short-run variable costs of LNG production is a key determinant of LNG production at the margin. When the Queensland plants are all producing, the short-run netback price should be a determinant of domestic prices, rather than the long-run netback. Short-run netbacks are based on Asian spot LNG prices, minus variable transport and liquefaction costs. At present these are very low, in the order of AUD$3.80/GJ (based on a spot price of US$4.4/mmbtu in Asia). If spot prices reach US$8/mmbtu, the netback is much higher at AUD$8.60/GJ. However, as is the case with the long-run netback, the short-run netback is not the only determinant of domestic prices. The actual price negotiated between buyer and seller will be determined by a range of factors, including the cost of production from domestic suppliers, the level of competition between these suppliers, and the price elasticity of the demand in the domestic market. The figure shows how some of these factors could interact over the next 5 years. The long-run netback price is determined by our forecast of oil prices and the US/Australian dollar exchange rate. It shows that the very high long run netbacks of 2 years ago have fallen well below the price of gas in the domestic market, and how they would recover if oil prices rise to about US$60/bbl (in 2015 dollars). We assessed the likely range of Queensland prices, based on modelling of the level of oligopolistic competition amongst gas supplies in the eastern Australian gas market, and assumptions about new investment in gas production capacity. While prices are higher than legacy contracts, they are unrelated to the prices that long-run netbacks would imply. The impact of LNG exposure on Australia s eastern gas market 5

7 Australian LNG exporters are currently producing at full capacity, despite the low spot LNG price. This is maintaining a tight domestic market and high domestic prices in eastern Australia. Based on projections of these high domestic prices continuing, the Australian Energy Market Operator has forecast large falls in demand in the GPG sector, of around 70 per cent in Queensland and 50 per cent in other States, and a smaller fall of around 13 per cent in the industrial market. However, we believe that if low LNG spot prices continue there is likely to be a reduction in gas demand by LNG producers as a result of lower LNG production and, therefore, less supply pressure on the domestic market. Given the relative flexibility of GPG demand for gas, any reduction in LNG demand is likely to reduce the size of potential falls in GPG gas demand. 1.6 Investment in gas production will be a key driver of gas prices Over the medium term, LNG production is expected to continue to place pressure on Australia s domestic gas prices. While the interaction between LNG spot prices and the domestic market will be important, and will contribute to volatility in domestic prices, the most critical determinant of prices will be gas production capacity, which in turn depends on the level of investment. There are many factors which influence the adequacy of production capacity, including the physical capability of the fields, the costs of supply, and the incentives to invest in new supply. The figures illustrate the supply and demand situation in eastern Australia, which is best understood as two distinct markets the north and the south. The current production capacity is adequate to supply both markets in the short term, but modelling suggests that in the medium to long term the physical production of gas in the south will decline, which in the absence of new supply may expose the market to shortfalls. The southern market will soon have to rely almost totally on Victorian offshore fields and NSW CSG, unless gas is imported from the north, or new discoveries are made in the south. This will make the south more reliant on the Gippsland Basin Joint Venture. The problem here is not so much production capacity, but the depletion of existing fields and the need for greater exploration and development of new gas reserves. In Queensland, the problem is almost the reverse. The figure shows the forecast of production capacity available to the domestic market, after supplying the LNG plants. The amount of gas production supplied to the LNG plants is not fixed, but depends on the level of LNG production, which in turn depends on LNG prices. The impact of LNG exposure on Australia s eastern gas market 6

8 While Queensland has sufficient gas reserves available for both the LNG producers and the domestic market provided no new trains are developed, the issue is whether gas suppliers are willing to invest in production capacity to service a potentially highly variable demand. To the extent that only enough capacity is developed for an average level of LNG exports, then the domestic market will experience periods of market tightness and looseness depending on the level of LNG production. We expect the available gas production to switch between supplying LNG producers and GPG, as we saw when ramp gas was available in To avoid this situation giving rise to excessive price volatility, new investment is required in both gas reserves and gas production capacity. However, the current investment climate is very poor, for three reasons: Firstly, poor returns in the global LNG market have reduced the capital available for gas exploration and development activities, which in turn flow through to investment in domestic gas production. Secondly, the ability to develop CSG and shale gas in NSW, Victoria and the Northern Territory is facing barriers from communities and other groups opposing development. Even in Queensland where the industry is progressing successfully, the social licence to operate is not guaranteed, and community engagement efforts take time and are costly, which can deter investment decisions. Thirdly, the level of uncertainty in the domestic and global gas market is such that there is a significant option value to delaying investment. Companies may assess that it is better to wait and see what happens, thereby putting off the decision to commit funds. The Australian Government has responded to these issues in a number of ways. These include an inquiry by the Australian Competition and Consumer Commission into upstream competition, which is expected to report its findings this month; and a review of gas market trading and pipeline access by the Australian Energy Market Commission, with the intention of improving market efficiency, responsiveness, and transparency. In addition, the Council of Australian Governments has agreed to a Gas Supply Strategy, with a commitment to collaborate on the responsible development of onshore gas resources. The impact of LNG exposure on Australia s eastern gas market 7

9 1.7 Conclusion I hope I have left you with a few key messages. The eastern Australian domestic gas market is now exposed to the international market, which we expect will become increasingly volatile in the medium term. Wholesale gas prices have increased, and are unlikely to return to legacy levels. We believe that long-run netback pricing will be less relevant to price formation in the east coast as LNG enters the production phase. The drivers of price will be short-run profit maximisation based on international spot prices, weighed against the costs of production from new and existing fields and the level of competition in the upstream market. Despite low LNG prices, increasing costs of production and limited upstream competition are keeping prices high. Investment in new supply and production capacity is essential to the future of the eastern Australian gas industry. However, the current investment climate is poor due to low LNG prices and barriers to the development of our gas resources, particularly onshore. Finally, the Australian Government is endeavouring to help address these challenging circumstances by improving the efficiency of market operations, and coordinating with the states to support the responsible development of our gas resources. 1.8 Contact page Thank you for your time. If you are interested in seeing more analysis of the LNG sector and Australia s energy markets I encourage you all to visit our website and keep up to date on new releases through our twitter account. The impact of LNG exposure on Australia s eastern gas market 8