Resourcesand Energy

QuarterlyMarch Quarter 2014

AcknowledgementsIndividual commodity outlooks have identified BREE authors. Document design and production was undertaken by Tom Shael and Simon Cowling.Cover image source: Shutterstock.BREE 2014, Resources and Energy Quarterly, March Quarter 2014, BREE, Canberra, March 2014.© Commonwealth of Australia 2014

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ForewordThe Resources and Energy Quarterly provides data on the performance of Australia’s resources and energy sectors and analysis of key commodity markets. This edition of the Resources and Energy Quarterly contains an update to BREE’s medium-term commodity forecasts over the period to 2019. There are also two articles discussing the energy transition in Japan, South Korea and Chinese Taipei and developments in the Asia-Pacific LNG market.The outlook for the world economy is projected to be largely positive, which will continue to support growth in resources and energy demand. While slowing, China’s economy is expected to expand by more than 7 per cent a year over the medium term and there are indications that in the short term their capital investment will not abate. An expected recovery in economic activity in some OECD economies will provide further support to demand.In Australia, the resources boom is transitioning from the investment phase to the production phase as the large number of projects developed over the past few years start operation. This is expected to result in increased production and thus exports for a number of commodities. Lower prices for most commodities over the past year have put greater pressure on the profitability and competitiveness of some Australian producers. However, the Australian industry is expected to remain fairly resilient over the medium term.BREE projects Australia’s earnings from resources and energy commodities to increase at an average rate of 8 per cent a year from 2013–14 to total $284 billion in 2018–19. Higher export earnings will be driven by the substantial growth in volumes of a number of commodities despite near term softness in prices. In the short term, higher volumes of iron ore and coal will be the principal drivers of export growth. As new LNG production capacity comes online over the outlook period, LNG exports will increase to become one of Australia’s principal exports and support further growth in export earnings.The transition from the investment to production phase of the mining boom will provide substantial benefits to the Australian economy through higher export revenues. However, competitive pressures will be evident for Australian producers over the near to medium term, which will temper the contribution of the sector to economic growth. Nevertheless, the medium term outlook still remains positive with the energy and resources sector providing significant opportunities for Australia.Bruce WilsonExecutive DirectorBureau of Resources and Energy Economics

Macroeconomic outlookThe global economyIn overall terms the global economic outlook is significantly more positive and robust than this time last year. While the world economy grew more slowly in 2013 (2.9 per cent) compared to 2012 (3.2 per cent), signs of sustained recovery in key OCED economies combined with stronger overall growth in emerging economies, provide an encouraging picture of continued improvement over the next few years.Global economic growth is expected to rebound strongly to 3.4 per cent in 2014 with emerging economies continuing to provide the largest contribution, growing in aggregate terms by 4.7 per cent, up from 4.5 per cent in 2013. Importantly the stronger performance of OECD economies will begin to somewhat rebalance global economic patterns reducing to some extent the dominance of emerging economies in key markets that has been evident since the Global Financial Crisis (GFC). As key EU economies move further away from recession and US growth accelerates the OECD region is assumed to grow at 2.2 per cent in 2014, up from 1.2 per cent the previous year.Figure 1: World economic growthPlease refer to page 1 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 1: Key world macroeconomic assumptionsPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

Within this generally positive outlook there are several key swing factors that will be critical in shaping global outcomes in 2014 (and beyond). These include the degree to which the tapering of the US Federal Reserve’s quantitative easing (QE3) package affects the sustainability of US growth and/or induces flow-on capital or currency impacts in emerging markets. China’s reform agenda also remains critical for building a sustainable long-term foundation for its ongoing economic development although implementation is not without risks, including for its trade partners. These issues are discussed in greater detail in the key economic overviews below.Over the period to 2019 world economic growth is assumed to rise to around 4.0 per cent with growth in emerging and OECD economies to further recover rising to 5.5 per cent and 2.6 per cent, respectively. As shown in Table 1 emerging economy growth is expected to be driven by stronger growth in Asian economies while a strong US economy along with a steadily improving performance in key EU and Japanese economies underpin the OECD recovery. The ability of the US to pay down large accumulated debts and China’s ability to maintain economic momentum through a steady growth trajectory of between 7 to 8 per cent a year while also successfully implementing reforms will continue to be the largest sources of uncertainty in the longer term outlook.

Outlook for key economiesThe USDespite nervous beginnings in 2013 the US economy is now showing clear signs of sustained recovery which is expected to strengthen through 2014. US GDP grew by 1.9 per cent in 2013 despite the effects of the Government close down due to the budget sequester. Growth also picked up strongly in the second half of the year with annualised rates in the last two quarters at over 2.5 per cent.The Federal Reserve’s Open Market Committee (FOMC) announced the commencement of tapering of QE3 in December 2013, cutting monthly bond purchases from US$85 billion to US$75 billion. A second tapering was announced in January 2014 with a further US$10 billion reduction and a subsequent US$10 billion tapering in March 2014. FOMC statements following the announced March 2014 taper also indicated the timing cash rate increases may be sooner than previously expected.Most US macroeconomic indicators have remained positive since the first FOMC decision with solid employment growth and investment and construction activity holding up well allowing for the effects of the severe Northern winter. In the December quarter production of consumer durables rose 9 per cent year-on-year and exports were up 5.4 per cent. At the same time inflation has remained below FOMC targets at around 1.5 per cent in 2013 and gives plenty of room for QE3 to continue, albeit at lower rates, through 2014.

Over the outlook period to 2019, US GDP is projected to strengthen with average growth of around 3.0 per cent a year. The availability of low-cost energy and skilled labour combined with spare plant capacity is revitalising its manufacturing base. The US also has significant potential for further oil and gas exports in the future. Sustained low interest rates are supporting a recovery in housing construction. While still below inflated pre-GFC levels, this recovery is expected to remain positive through the outlook period.A key challenge for the US will be impasses between the Congress and Executive over the Federal budget. While the 2014 budget has been passed and removes the more immediate risk of program and agency closures the debt ceiling will need to be raised again in 2015 and may be the focal point for another political showdown. A rapidly shrinking budget deficit has removed some of the pressure in this debate with the deficit projected to fall from US$680 billion in 2013 to US$514 billion (or 3 per cent of GDP) in 2014. Lower increases in spending combined with a recovery in government revenues also point to a strengthening economy.

ChinaWhile the robustness of the Chinese economy continues to attract considerable media speculation, its national economic performance remains strong with annual GDP growth of 7.7 per cent in 2013, effectively matching the 7.8 per cent growth reported in 2012. It is notable that the small reduction in the annual rate of growth masked what was a larger absolute increase in GDP last year than was seen between 2011 and 2012. This expansion was roughly equivalent to two thirds of the entire Australian economy in 2013.The continued rapid expansion of the world’s second largest economy means that China is playing an increasingly important role in global commodity markets. For most resource and energy commodities, China now accounts for over 40 per cent of world consumption. For this reason prices in global and regional markets are expected to remain highly sensitive to variations in macroeconomic indicators relating to Chinese consumption and production.For example, given the usual disruptive impact of Chinese New Year, the market reactions to the large announced decreases in exports and industrial activity over January and February are perhaps a little overstated. It remains challenging to “look through” the impact of these short term market fluctuations and identify more significant changes in China’s economic development.In defining its blueprint for achieving an economic ‘pivot’ towards a more consumption based economy the new Chinese leadership have set several headline economic targets or goals, including the overall 7.5 per cent GDP growth target and a 17 per cent limit for growth in Fixed Asset Investment. Maintaining solid employment growth across China’s rapidly urbanisation economy completes the policy trifecta set down by the Central Government. Simultaneously achieving these goals will be challenging. Investment remained the principal source of economic growth in 2013, accounting for 4.2 per cent of GDP growth. Relatively lacklustre first quarter economic indicators appear to support the view that credit restrictions that have been the primary mechanism for implementing industrial rationalisation have also led to a down turn in investment activity.In the medium to longer term the wider financial reforms will have an important and positive impact on the economy. Proposed easing of capital and currency controls in particular will be a big step forward towards more liberalised markets that allocate resources more efficiently. However, in the short term, this may expose a number of loss-making enterprises with a resultant closure of inefficient capacity.China’s first corporate bond default occurred in March 2014 when solar-cell producer Shanghai Chaori Solar Energy missed a deadline to make an interest payment of 89.8 million Yuan. This has led a rapid change in market sentiment with the fear of further defaults in the wake of Government financial sector reforms reflected in sharp falls in commodity prices, particular those used as collateral in financing such as iron ore and copper. Given the small proportion of companies considered to be genuinely at risk this speculation is likely to be more de-stabilising than the impact of actual defaults and realised bad loans.Maintaining a GDP growth trajectory of around 7.5 per cent along with solid employment growth to promote the Government’s social objectives will likely require the eventual relaxation of credit constraining policies or additional targeted stimulus actions. Policies, such as the recently announced urbanisation package that will support a further 100 million people relocating to cities over the next few years, are expected to remain a key driver of economic growth in the medium term.Over the outlook period GDP growth is assumed to moderate further and average around 7.2 cent. While at the lower end of the growth target range this nonetheless continues to represent a substantial year-on-year increase in demand for resource and energy commodities with China’s GDP

tipped to exceed 10 trillion Yuan within the next two years.

IndiaEconomic growth in India during 2013 was below potential with GDP increasing by 3.8 per cent. The ripple effect of the US Federal Reserve’s QE3 tapering resulted in a depreciation of the Rupee and as a result Indian interest rates have been increased to avoid further currency debasement. First quarter GDP growth in calendar year 2014 has also remained subdued with minimal fiscal spending in the lead up to elections in May. Expectations for the remainder of the year are more positive with an anticipated jump in business and consumer confidence on the back of a clear election outcome. As a result GDP growth is assumed to recover to around 4.2 per cent for 2014.In the medium term India’s growing current account deficit is a challenge, particularly with the ongoing risk of currency depreciation. However a stronger economic performance will be supported by increasing investment particularly in infrastructure and energy, a decreasing rate of inflation and higher exports in line with an improving global economy. This should begin to reduce India’s current account deficit as a proportion of GDP. Over the outlook period India’s GDP growth rate is assumed to further strengthen over the outlook period to around 5 per cent.

JapanJapan’s return-to-growth strategy of monetary easing, flexible fiscal policy and structural reform was announced by the new Government in late 2012 (so called ‘Abenomics’). It is aimed at ending Japan’s record of chronic deflation and weak economic growth, and reversing the trend of rising public debt. So far the expansion of the monetary base has resulted in, what is for Japan over recent times, positive economic growth with GDP expanding by 1.5 per cent in 2013. A reduction in Japan’s trade deficit, which occurred as a positive effect of a weaker Yen on exports was more than offset by the rising cost of imports (driven in large part by fuel imports).The decision to progressively restart nuclear capacity as part of the new Basic Energy Plan will enable Japan to progressively reduce its energy imports and relieve some of the pressure on the trade deficit although the pace of the restart may build cautiously in line with public nervousness around nuclear power. While unpopular with parts of the community, Japan has few energy options in the short term to meet both its economic growth and carbon emission reduction targets.Growth in 2014 is assumed to moderate to 1.1 per cent as the effect of the fiscal stimulus is partially offset by the economic drag from an increase to the consumption tax in April 2013 However, there are ongoing concerns that continued deterioration of the current account will force Japan to draw on its domestic savings, increasing the need to manage its large public debt.In the longer run Japan’s economic growth is expected to marginally strengthen to around 2 per cent a year. However, limited public detail surrounding the Government’s plans for much needed fiscal and structural reforms are contributing to uncertainty about how seriously they will be implemented and their ultimate effect on economic growth.Japan’s longer term growth strategy remains focused on raising investment and employment and increasing productivity. However its ability to boost growth rates beyond current projections will continue to be constrained by an ageing labour force and the need for fiscal consolidation. There are also some risks for Japanese industry of slowing demand in key export markets, particularly China, which would be compounded if domestic demand was also to fall back to pre-Abe levels.

South KoreaThe South Korean assumed is projected to expand steadily through the outlook period rising from 2.8 per cent in 2013 to 3.5 per cent in 2014. The South Korean economy remains heavily reliant on exports, particularly consumer electronics, heavy engineering, ship-building and cars with China now being its largest market. However, increasing competition from Japan and China, as well as growing support in China for domestically produced goods, will challenge South Korea’s share in these markets.Government plans to stimulate growth in services sectors such as education, finance, software and tourism offer the prospect of a more diversified economy with additional sources of activity supporting a longer term average growth rate of 3.5 per cent a year from 2015 onwards.

The EUThe tentative economic recovery in Europe over the second half of 2013 increasingly appears to be strengthening; ensuring that the region retreats further from the possibility of sustained flat or negative growth. Overall the EU is expected to grow by 1.0 per cent in 2014, up from a stagnant 0.1

per cent in 2013. These positive assumptions are based on the expected faster recovery of the three main EU economies of the United Kingdom which is projected to grow by around 2.2 per cent in 2014, Germany which is expected to rebound up from 0.4 per cent in 2013 to 1.7 per cent in 2014 and France which will increase by 0.5 percentage points from 2013 to 0.8 per cent in 2014.Nevertheless, economic growth in several key economies, such as Italy and Spain, still lags with continuing austerity and public debt issues that continue to weigh down the overall performance of the region. However, the prospect of a possible return to recession in these economies is more remote than even four months ago.Over the outlook period, EU GDP growth is assumed to recover to 2.0 per cent in 2019, based on the expectation that fiscal reforms continue across the region. Exports from the EU are expected to pick up in line with an improvement in the world economy; however uncertainty over the management of internal challenges, particularly debt and fiscal policy, is assumed to moderate the prospects for higher economic growth over the next five years.Figure 2: Economic growth in select economiesPlease refer to page 8 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Economic outlook for AustraliaAccording to the Australian Bureau of Statistics, Australia’s GDP increased 0.7 per cent in the December quarter 2013, a modest increase from the 0.6 per cent increase in the September quarter. An increase in net exports, particularly resources commodities, and consumption expenditure were partially offset by lower gross fixed capital formation in the December quarter. For the full year 2013–14, Australia’s GDP growth is assumed at 2.8 per cent with low domestic interest rates expected to continue to stimulate housing construction and consumption expenditure. Higher resources and energy commodity export earnings as a result of both higher volumes and a more favourable Australian dollar exchange rate will also support GDP growth in 2013–14.Over the outlook period to 2018–19, Australia’s GDP growth rate is assumed to decline over the next two years, before recovering to trend growth in 2018–19. Capital expenditure, particularly in the mining and energy sectors, has been an important driver of economic growth in Australia since the GFC. While there are still several large resource and energy projects being developed in Australia, many of these are scheduled for completion over the next 18 months.The resulting decrease in construction activity, lower capital expenditure and its flow on effect on employment, will limit Australia’s economic growth in the short term. Forecast robust residential building activity in response to ongoing low interest rates, higher exports and increased infrastructure spending are expected to partially offset the decline in capital expenditure over the next two years. Unemployment will be a key risk in the short to medium term. Continued structural change in the Australian economy and the transition from the mining construction phase to the production phase has the potential to place sustained pressure on employment growth. In 2014–15, Australia’s GDP growth rate is assumed to decrease to 2.5 per cent but lower growth levels are possible in the event of higher unemployment rates.Over the medium term, growing resources and energy commodity exports and sustained high levels of residential construction activity are expected to support GDP growth rates returning to the long term trend level of around 3 per cent in 2018–19 (see Table 2).Table 2: Key macroeconomic assumptions for AustraliaPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

Although lower than the first quarter of 2013, the Australian dollar-US dollar exchange rate remains high by historical standards. Since depreciating in the second half of 2013, the Australian dollar-US dollar exchange rate has remained relatively stable through the first quarter of 2014 and traded at around 0.89 USD/AUD for most of the quarter. Through the remainder of 2014 the exchange rate is forecast decline in response to further tapering of the US’ QE3 bond purchases, lower commodity prices (and subsequently declining terms of trade) and more bearish sentiment over economic growth in China. For the financial year 2013–14 the exchange rate is forecast to average 0.90 USD and then depreciate to average around 0.85 USD over the remainder of the outlook period.

Australia’s resource and energy commodities, production and exportsAustralian producers of resource and energy commodities have been facing increasing commercial pressure due to the recent declines in world commodity prices. However, commodity prices have

generally not been declining in response to decreasing demand. In fact, consumption of resource and energy commodities has been increasing in most cases, often at quite robust rates. The decline in commodity prices can more accurately be attributed to the strong growth in world supply that is the product of substantial global investment in commodity production capacity since the GFC. Most commodity markets are now well supplied and in the case of refined materials, notably aluminium, there is a global surplus of production capacity as a result of the substantial expansion of China’s domestic industry. The resulting supply glut has caused most commodity prices to retreat already in the past 12–18 months, with a further falls forecast in most cases.For Australia, the period of falling commodity prices presents a considerable, but not insurmountable challenge. The emergence of new low cost competitors over the past decade and cost pressures in Australia has pushed many Australian producers to the wrong end of world cost curves. In the coming period of lower prices, cutting costs and enhancing productivity will be paramount to the continued success of Australia’s resource and energy producers. Cost structures are rarely stable and evidence from the corporate reports of a number of operators released in early 2014 indicate cost cutting activities have already been highly successful and many still expect further reductions in 2014. While cost cutting is generally associated with employment reductions, mining sector employment increased 2.6 per cent quarter-on-quarter in December following a 3.4 per cent increase in the September quarter (see Figure 3). While the downturn in mining capital expenditure will likely result in fewer construction jobs, the shift to the production phase of the ‘mining boom’ still holds substantial benefits for Australia, both in terms of revenue growth and employment opportunities.Figure 3: Quarterly Australian mining sector employmentPlease refer to page 10 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

In 2013–14, total export earnings for resources and energy commodities are forecast to increase 13 per cent, supported by robust growth in both resources and energy commodity export volumes and a lower Australian dollar exchange rate. Resources commodity export earnings are forecast to increase 17 per cent to total $125 billion, mainly due to substantial growth in the volume of iron ore exports. Export earnings from energy commodities are forecast to increase 7 per cent to total $74 billion, underpinned by higher earnings for LNG as well as thermal and metallurgical coal.The outlook for Australia’s resources and energy exports remains positive. Although prices for most commodities are expected to moderate over the outlook period, the projected growth in export volumes of Australia’s key commodities will support growth in export earnings. However, in real terms, export earnings from resources commodities are projected to peak in 2016–17 and energy commodity exports will become the principal driver of export earnings. In nominal terms, the value of LNG exports is projected to increase around 340 per cent over the outlook period as the large investments in new facilities over the past three years start production. Total export earnings are projected to increase at an average annual rate of 8 per cent to total $284 billion in 2018–19. Resources and energy export earnings are projected to total $151 billion and $133 billion in 2018–19, respectively (see Figure 4).Figure 4: Australia’s resources and energy export earningsPlease refer to page 11 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 3: Australia’s resources and energy commodity exports, by selected commoditiesPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

Table 4: Medium term outlook for Australia’s resources and energy commoditiesPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

Energy outlookOilPam Pham

PricesAfter a period of high prices in the September quarter 2013 relative to the June quarter, oil prices fell in the December quarter in response to increased production and easing of international sanctions imposed on Iran’s oil exports. For 2013 as a whole, the West Texas Intermediate (WTI) price averaged around US$98 a barrel while the Brent price averaged around US$109 a barrel. Prices are expected to stay at similar levels in 2014 amidst concerns about growing tension between Russia and Ukraine, and ongoing conflict over oil wealth in Libya.Prices are forecast to moderate in the medium term, supported by higher output from the US, Brazil, Saudi Arabia and Iraq, and a continued decline in oil consumption in OECD economies. The WTI–Brent price differential is also expected to widen due to robust growth in US production and continued political instability in the Middle East. World oil prices are projected to decline steadily, with real WTI prices expected to fall to US$83 a barrel and real Brent prices US$95 a barrel in 2019 (see Figure 1).Figure 1: Annual WTI and Brent oil pricesPlease refer to page 13 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Oil prices are subject to considerable volatility over the medium term due to changes in economic and political conditions. Geopolitical tensions and unexpected supply disruptions may put upward pressures on oil prices. Conversely, weaker-than-assumed world economic growth may put downward pressures on oil prices over the outlook period.

World oil consumptionRecent growth in world oil consumption has largely been driven by consumption growth in non-OECD economies which offset lower consumption in the OECD. In 2013, world oil consumption was about 91 million barrels a day, up by 1.8 per cent relative to 2012. This was underpinned by strong demand in non-OECD Asia and the Middle East. Meanwhile, oil consumption in the OECD has been declining in response to weak economic growth and improved fuel efficiency in the transport sector. This trend is expected to persist over the projection period.In 2014, world oil consumption is forecast to increase by 1.8 per cent to 92.6 million barrels a day. Strong growth in oil consumption in Asia and the Middle East is expected to contribute to non-OECD consumption exceeding OECD consumption for the first time. The gap is expected to widen over the projection period (see Figure 2). Over the period 2015 to 2019, world oil consumption is projected to grow by 1.3 per cent a year to 98.7 million barrels a day in 2019.Figure 2: Oil consumption in OECD and non-OECD economiesPlease refer to page 14 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Oil consumption in non-OECD countriesIn 2013, oil consumption in non-OECD economies averaged 45.2 million barrels a day. Increasing numbers of automobile users in non-OECD Asia and the development of new oil-fuelled electricity generation capacity in the Middle East will be significant sources of demand growth for oil in the medium term. In 2014, oil consumption in non-OECD economies is forecast to increase by 3.1 per cent to average 46.6 million barrels a day. Between 2015 and 2019, oil consumption in non-OECD economies is projected to increase by 2.9 per cent a year to average 53.8 million barrels a day in 2019.China is projected to lead the growth in non-OECD oil consumption, followed by India. China’s growing vehicle ownership as household income increases will drive oil consumption growth. Partially offsetting this growth will be the government target to improve fuel efficiency by 38 per cent by 2015. The adoption of commercial liquefied natural gas (LNG) trucks could also dampen growth in China’s oil demand over the medium term. In 2014, China’s oil consumption is forecast to increase by

3.8 per cent to average 10.5 million barrels a day. Over the period 2015–2019, China’s oil consumption is projected to increase by 3.7 per cent a year to average 12.6 million barrels a day in 2019.In India, oil consumption is forecast to average 3.5 million barrels a day in 2014, increasing by 3.2 per cent relative to 2013. Growing vehicle ownership will outweigh the negative impact of diesel price deregulation on oil demand. India’s oil consumption is expected to continue to grow robustly over the medium term, by 3.2 per cent a year to 4.1 million barrels a day in 2019.Additional demand for oil for electricity generation in the Middle East will further support growth in non-OECD oil consumption in the short to medium term. In 2014, oil consumption in the Middle East is forecast to increase by 3.3 per cent to average 8.1 million barrels a day as new oil-fuelled electricity generation capacity comes online. Between 2015 and 2019, oil consumption is projected to grow by 3.2 per cent a year to 9.5 million barrels a day in 2019. The promotion of more efficient use of electricity and alternative power generation sources may result in oil consumption being lower than forecast.

Oil consumption in OECD economiesIn 2013, oil demand in OECD economies remained at its 2012 level of around 46 million barrels a day. From 2014 onwards, oil demand is projected to fall steadily to 44.9 million barrels a day in 2019, underpinned by projected lower demand from Europe, North America and Japan.Weak economic growth, continued improvement in fuel efficiency in the transport sector and reduced use in electricity generation and heating applications have contributed to an ongoing decline in oil consumption in OECD-Europe. This trend is expected to continue over the medium term. In 2014, oil consumption in OECD-Europe is forecast to decrease by 0.7 per cent to average 13.6 million barrels a day. Over the outlook period, oil consumption in OECD-Europe is projected to decline by 0.7 per cent a year to 13.1 million barrels a day in 2019.Oil consumption in North America is forecast to average 24.1 million barrels a day in 2014 and is projected to remain relatively stable at around 24 million barrels a day throughout the outlook period. The effect of energy efficiency policies and fuel substitution due to high sustained oil prices will underpin a marginal decrease in the US’s oil consumption during 2015–2019 to average 19.5 million barrels a day in 2019.Lower oil consumption in Japan’s power generation sector will also contribute to the fall in OECD oil consumption. In 2014, Japan’s oil consumption is forecast to decrease by 1.8 per cent to average 4.5 million barrels a day. An assumed gradual restart of nuclear power generation capacity will contribute to lower oil consumption over the projection period. Japan’s oil consumption is projected to fall by 0.9 per cent a year to 4.3 million barrels a day in 2019.

World oil productionIn 2013, non-OPEC oil production increased, underpinned by higher unconventional oil production in the US and Canada and deep-water production in Brazil. Increased supply from OPEC countries will support further growth in world oil production in 2014, with Iraq expected to expand its production capacity and the prospect of production rebounding in Iran. In 2014, world oil production is forecast to increase by 2.4 per cent to average 93.6 million barrels a day (see Figure 3).Figure 3: World oil production in OPEC and non-OPEC economiesPlease refer to page 16 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Over the outlook period, world oil production is projected to increase by 1.1 per cent a year to average 98.8 million barrels a day in 2019, largely supported by projected increases in unconventional oil production in North America.

Non-OPEC oil productionUnconventional supplies from North America, in particular US light tight oil and Canadian oil sands, have largely driven the recent growth in non-OPEC oil production, and are expected to continue to expand. The development of deep-water production in Brazil will also contribute to non-OPEC production growth in the medium term.Production from the Kashagan field in Kazakhstan—the largest field outside of the Middle East—is not expected to be a major contributor to non-OPEC production growth over the outlook period. The field was closed due to safety concerns after just a month in operation. A production restart date remains unknown. Assuming that the field comes back online during the outlook period, continued technical

challenges and cost overruns will likely constrain its production in the medium term.In 2014 non-OPEC oil production is forecast to increase by 2.6 per cent to average 56.2 million barrels a day. Over the period 2015–2019, non-OPEC production is projected to increase by 1.4 per cent to average 60.3 million barrels a day in 2019.Unconventional oil production in the US and Canada will continue to grow. Commercially viable technologies associated with unconventional oil and gas extraction have driven US oil production growth. Improving drilling efficiencies, optimising fracking and reducing unit costs will continue to support US oil production in the medium term. In 2014, US oil production is forecast to average 10.9 million barrels a day, increasing by 5.8 per cent relative to 2013. In the medium term, US oil production growth is likely to moderate as demand weakens. Between 2015 and 2019, US oil production is projected to grow by 2.8 per cent a year to average 12.5 million barrels a day in 2019.Continued development of oil sands projects coupled with increased domestic and foreign investment in the petroleum sector will contribute to expanded oil production in Canada, although pipeline capacity may limit the pace of growth. In 2014, Canada’s oil production is forecast to increase by 2 per cent to average 4.1 million barrels a day. Over the period 2015–2019, Canada’s oil production is projected to grow at a rate of 4.5 per cent a year to average 5.1 million barrels a day in 2019.Outside North America, Brazil is projected to be the fastest-growing non-OPEC oil producer. In 2014, Brazil’s oil production is forecast to increase by 8.6 per cent, to average 2.3 million barrels a day, underpinned by increased deep-water production. The expansion of production at a number of offshore oil fields will continue to drive Brazil’s oil production over the medium term. Between 2015 and 2019, Brazil’s oil production is projected to grow by 6.8 per cent a year to average 3.2 million barrels a day in 2019.Partially offsetting non-OPEC oil production growth over the medium term will be a moderate decline in production in Europe and the Pacific due to lower production from maturing fields.

OPEC Oil production OPEC oil production fell by 2.1 per cent to 36.8 million barrels a day in 2013 due to lower output in Iran and Saudi Arabia and supply disruptions in Iraq. In 2014 OPEC oil production is forecast to increase by 1.6 per cent to average 37.4 million barrels a day, mainly driven by a rebound in Iraqi production. Over the period 2015–2019, OPEC production is projected to increase moderately by 0.6 per cent a year to 38.5 million barrels a day in 2019.Iraq will be the major source of OPEC production growth in the medium term. In early 2014, Iraq was reported to have produced more than its existing capacity. Iraq plans to triple its crude oil production capacity by 2020, although insufficient pipeline and port infrastructure may limit Iraqi production growth. In 2014 Iraqi production is forecast to increase by 16 per cent to average 3.6 million barrels a day. Between 2015 and 2019, oil production in Iraq is projected to grow by 5 per cent a year to around 4.6 million barrels a day in 2019.Recent easing of international sanctions imposed on Iran’s oil exports have contributed to a moderate growth in Iran’s oil production in early 2014. However, this growth will not be enough for production to rebound to the level prior to the sanctions. Iran’s oil production is projected to remain stable at around 2.8 million barrels a day over the outlook period, assuming the sanctions remain in place. A lift up of the international sanctions imposed on Iran’s exports may result in Iran’s oil production being higher than forecast.Increased production in Saudi Arabia will also contribute to OPEC production growth in 2014. Saudi Arabia’s oil production is forecast to increase by 2.1 per cent to 9.6 million barrels a day in 2014. Over the period 2015–2019, Saudi Arabia’s production is projected to remain relatively stable at around 9.5 million barrels a day, constrained by resource depletion.In the medium term, maturing fields, declining recovery rates and potential supply disruptions due to prolonged political instability in Libya and international sanctions on Iran could adversely affect OPEC production growth. Furthermore, production surges in the US could force OPEC producers to cut production to keep prices stable. These factors present downside risks to projected OPEC production over the medium term.

Australia’s production and exportsIn December 2013, oil production resumed at the Vincent and Pyrenees fields after temporarily closed for maintenance. Production at the Montara-Skua project in the Bonaparte basin and the Fletcher-Finucane project in the Carnarvon basin together added about 65 000 barrels a day to Australia’s oil production in the second half of 2013. These underpin a forecast 2.2 per cent increase

in Australia’s crude oil and condensate production to average 374 000 barrels a day in 2013–14 (see Figure 4). An expected commencement of the Coniston project (estimated capacity of 22 000 barrels a day) in the Carnarvon basin in the first half of 2014 will also support the production increase. The Surprise oil field in the Northern Territory—expected to be fully operational by mid-March 2014 with a capacity of 400 barrels a day—will also contribute to the expansion of Australia’s oil production in 2013–14.Figure 4: Australian crude oil, condensate and LPG production Please refer to page 19 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

In 2014–15 and 2015–16 Australia’s oil production is projected to fall as lower production at mature fields more than offset increases in new production capacity. In 2016–17 and 2017–18, production is expected to rebound, supported by additional condensate and liquefied petroleum gas production from the two gas projects in the Browse basin. Ichthys and Prelude that are expected to commence during 2017. However, the new production capacity will not be enough to offset the decline in oil production in the medium term. In 2018–19 Australia’s oil production is projected to average 354 000 barrels a day, its lowest level since 1972.

The closure of Caltex’s Kurnell refinery (capacity of 135 000 barrels a day) in the second half of 2014 will adversely affect Australia’s refinery production over the outlook period. In 2013–14 refinery production is forecast to fall by 6.9 per cent to average 592 000 barrels a day. Refinery production is projected to decline further by 3.5 per cent in 2014–15. Over the period 2016–19, Australia’s refinery production is projected to remain at around 575 000 barrels a day.Australia’s crude oil and condensate exports are forecast to fall by 5.6 per cent to 305 000 barrels a day in 2013–14 (see Figure 5). Despite this, higher prices and an assumed depreciation of the Australian dollar result in the export value increasing by 5.8 per cent to $13.2 billion.Over the projection period 2014–15 to 2018–19, Australia’s crude oil and condensate exports earnings are projected to decline by 2.9 per cent a year to $11.4 billion (in 2013–14 dollars) in 2018–19 given the projected lower export volumes and prices.Figure 5: Australian crude oil and condensate exports Please refer to page 20 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 1: Oil outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

GasTom Willcock and David Whitelaw

PricesAsian LNG prices Delivered LNG prices into North Asia were higher through the December quarter, mainly due to increased seasonal demand. Average Japanese LNG import prices increased steadily through the quarter to reach US$16.8 a gigajoule at the end of the year. South Korean prices were relatively flat, around US$15.4 a gigajoule, while Chinese prices rose strongly in December to reach US$14.6 a gigajoule. Higher realised prices largely reflect increased spot market purchases due to higher demand (above contracted volumes) and continued strong oil prices (to which most Asian LNG contracts are linked). The Japanese Crude Cocktail, for example, hovered around US$112–113 through the December quarter, well above prices in the US$105 range witnessed mid-year.Implied LNG values from Pluto were much higher in the December quarter (from US$7.4 a gigajoule in September to US$10.8 a gigajoule in December) largely because of contract adjustments (including bonus payments). The implied LNG prices received at the North West Shelf (NWS) project were flat (at US$12.6 a gigajoule, the same as September) due to lower spot market sales.

Domestic pricesDomestic gas prices were generally subdued over the December quarter. In the Eastern market, prices in the Adelaide, Brisbane and Sydney Short Term Trading Markets (STTMs) and Victorian wholesale market were largely unchanged. Relatively mild weather subdued electricity and hence gas demand (with little gas bought at spot prices) in those markets. Prices rose strongly in January at the Adelaide STTM, due to higher gas demand for electricity generation during a record heatwave. In the Western market, Woodside’s implied price for domestic sales gas was considerably higher in the December quarter ($5.0 a gigajoule) than in September ($4.2 a gigajoule), due to the completion of relatively low-priced industrial contract. Apache’s average realised price was relatively flat at $4.7 a gigajoule in December ($4.6 a gigajoule in September).

OutlookLooking forward, Australian domestic prices and Asian LNG prices are expected to converge to some degree, particularly on the East coast. Australian gas prices face considerable upward pressure over the medium term, and are widely expected to increase due to both demand competition (from LNG projects) and higher production costs. Netback pricing, in particular, will be a key determinant of future prices in the Eastern market. A number of new contracts, slated to start in coming years, were announced in the December quarter (including by Origin, AGL, and Strike). Prices have been quoted around $7 to $9 a gigajoule and comprise an oil-linked component (creating a gas price response as the oil price rises and falls). Prices in the Eastern market have historically been $4 a gigajoule or lower and been linked to an annual price escalator such as the CPI.In the Asian LNG market, the tight supply conditions prevailing in 2013 will be replaced by excess supply conditions later this decade (see Figure 2 in the following section). This is likely to place significant downward pressure on spot prices (currently at record highs in the order of $20 a gigajoule). By 2019, spot prices are likely to fall well below the high oil-linked contract prices expected to prevail in that market and should increasingly reflect the marginal producer’s cost of production.

Global outlookProduction and consumptionGlobal gas consumption is projected to grow by 12 per cent over the forecast period 2013 to 2019 to around 3930 billion cubic metres. The main regions of growth will be in Asia (predominantly China and India), followed by Africa and the Middle East. Coincident with this trend in consumption will be a shift in gas production, with a decline in European production more than offset by significant growth in Australia. Gas production in North America, growing rapidly from shale gas sources, is expected to result in the continent becoming a net exporter towards the end of this decade. These developments

represent a significant shift to the east in gas demand, and are likely to lead to some major re-alignments in world gas trade flows.Recent global LNG movements have been relatively subdued, hovering around 235 million tonnes in 2011, 2012 and 2013. This is due mainly to prevailing tight supply conditions as a result of lower production and liquefaction capacity in Africa and Indonesia. These tight conditions will persist until at least 2015 when new capacity will be commissioned in Australia, followed by projects in other countries in the Asia-Pacific, the US, Canada, Russia, and Africa. It is expected that booming supply will release the pent-up demand for LNG imports, leading to rapid growth in LNG trade over the remainder of the outlook period from 2015. By 2019, global LNG demand is forecast to have expanded by almost 50 per cent, to reach 350 million tonnes (see Figure 1).Figure 1: Global LNG tradePlease refer to page 24 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Figure 2 shows the forecast installed liquefaction capacity and LNG imports over the period 2013 to 2019. The major increases in capacity come from Australia after 2015, followed by the US and Canada and then Russia. In the US, the Sabine Pass project is currently under construction and another five plants have received non-FTA export approval from the US Government (a key gateway to making a final investment decision and beginning construction). The extent and speed of US developments will reshape global LNG trade (the US was a sizable LNG importer as recently as 2011). While consumption increases rapidly over the outlook period, it is vastly outweighed by the forecast increase in LNG supply, resulting in a significantly less tight global market by 2019.Figure 2: Global installed liquefaction capacity and LNG importsPlease refer to page 24 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Figure 3 shows existing and under construction liquefaction capacity. Overwhelmingly, those projects are located in Australia and will result in Australian liquefaction capacity more than tripling to become the largest in the world towards the end of the decade.Figure 3: Global nameplate liquefaction capacity, as of March 2014 Please refer to page 25 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Regional LNG tradeJapanJapan is currently the world’s largest LNG importer and is expected to remain so over the medium term. Large gas reserves in the East China Sea are unlikely to be developed until the territorial dispute with China is resolved, and proposals to develop methane hydrates off the west coast are high cost and are at best a long term option.In 2012, approximately two thirds of gas use was for power generation, a significant rise since the Fukushima incident in 2011 when the Japanese nuclear fleet was progressively closed. The prospects for increased LNG imports will be critically dependent on the fuel-sourcing strategies of the electricity generation industry in Japan over the coming decade (see the review section for further discussion of Japanese energy policy).

Japanese gas imports are projected to decline slightly over the outlook period, to 86 million tonnes in 2019, as a result of on-going energy efficiency measures and government reforms. If, as expected, the government permits between 12 and 20 nuclear reactors to restart over the next two years, the impact is likely to be predominantly on oil consumption currently used in power generation rather than on gas consumption.Figure 4 shows projected Japanese LNG demand by supplier. The LNG import mix is currently dominated by Middle Eastern supply but this is expected to shift towards Australia, with significant growth in North American supply late in the outlook period. Japanese companies are diversifying supply sources and investing in overseas gas production in Australia, Indonesia, North America and Russia.Figure 4: Japanese LNG imports outlook by supplierPlease refer to page 26 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

There is little potential upside to this forecast, but a significant downside. Japan is currently paying a

high price for oil and gas-fired power generation and restarting the majority of the nuclear fleet (i.e. around 40 or more reactors) would likely lead to a more sustainable long term solution for the country. This would result in a significant reduction in LNG imports and particularly spot market purchases.

South KoreaSouth Korea produces negligible gas domestically and is a major LNG importer. Around 22 per cent of power generation in 2012 was gas-fired, with the remainder sourced mainly from coal and nuclear power. However, South Korea is likely to expand nuclear power and renewable power generation, so there are limited growth prospects for further penetration of gas in the electricity generation sector.Gas consumption more than doubled between 2001 and 2011 and currently supplies the reticulated gas market and the power generation sectors in roughly equal proportions. Gas consumption spiked in 2013 due to the shutdown of a number of nuclear reactors for safety reasons. These reactors are expected to re-start by 2015, lowering gas consumption in that year, before moderate growth (supported by a recently announced reduction in the LNG import tax) sees imports return to around 39 million tonnes by 2019. With limited reserves, and no prospects of pipeline imports in the medium term, this consumption must be met with LNG imports. As Figure 5 shows, the majority of imports currently come from Indonesia, Malaysia and the Middle East, but it is expected that ASEAN imports will begin to be replaced by Australia and North America by 2017 and thereafter.Figure 5: South Korean LNG import outlook by supplierPlease refer to page 27 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

ChinaChina has a rapidly growing natural gas market that mainly serves the industrial sector. Gas consumption grew at 20 per cent a year between 2005 and 2013, and is expected to continue growing at a high rate, reaching around 287 billion cubic metres by 2019. This is largely driven by increasing gas use in power generation, although gas-powered vehicles also represent a growing market segment.China has large indigenous gas reserves which will support but not meet growing demand. By 2019, domestic production is projected to constitute only 55 per cent of consumption, from 75 per cent in 2012. The gap is filled by a combination of pipeline and LNG imports. The balance between these two import sources fluctuates as new pipeline and LNG contracts are brought online, but it is expected that there will be roughly equal imports from both sources over the outlook period. There is considerable uncertainty relating to the prospects for Chinese shale gas production. If these resources are found to be uneconomic to develop, there will be a significant long-term growth market for gas imports into China.Pipeline imports are expected to grow dramatically as new supplies are connected from Turkmenistan, Kazakhstan and Uzbekistan (via the Central Asia-China Pipeline) and later from the Russian Far East. These supplies will supplement existing pipeline volumes from Myanmar and have huge potential—the two largest gas fields in the world are located in Siberia and Turkmenistan. On current projections they will exceed LNG imports in the longer term. However, this will depend on a number of geopolitical considerations, including Russian gas pricing policies and their incentives to pivot gas production eastwards and Chinese companies’ willingness and ability to connect pipelines with gas-rich neighbouring countries.Chinese LNG imports are projected to reach 51 million tonnes by 2019, primarily met by ASEAN and Australian suppliers (see Figure 6). North America is not seen as a significant supplier to China over the outlook period due to saturation of the Asian LNG market by 2019 and the absence of contracted volumes.Figure 6: Chinese LNG imports outlook by supplierPlease refer to page 28 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

ASEANTotal ASEAN LNG imports are projected to grow rapidly to about 18 million tonnes by 2019, with most growth occurring in Indonesia and Malaysia (see Figure 7). Despite being large gas producers, Indonesia and Malaysia have a mismatch between the location of demand (generally in the West) and the sources of supply (in the East). Combined with a rapidly growing domestic gas demand base, this is leading to the development of LNG receiving terminals in parts of Malaysia and Indonesia while production is expanding in other areas (and therefore resulting in domestically traded LNG). At the

same time, gas production at existing LNG export facilities is falling due to reserve depletion. The Arun liquefaction plant in Aceh has been converted to a receiving terminal, and the large Bontang liquefaction plant in Borneo is expected to cease exports by 2020.Figure 7: ASEAN LNG import outlook by countryPlease refer to page 29 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Indonesia, Malaysia and Brunei currently represent the second largest LNG exporting region in the world after the Middle East and this transition to a more domestic focus will affect world LNG trade. This tension between local needs and export priorities has led to the proposed Donggi-Senori liquefaction plant in Sulawesi province being required to reserve one third of production for local needs. This forecast assumes that production expands to meet domestic demand growth but can only maintain a flat to declining export profile over the outlook period.The Philippines, Vietnam and Thailand will import small volumes starting in 2015 which are projected to grow over the outlook period. Vietnam and Thailand both have significant domestic production (Thailand also has access to pipeline imports) to meet strongly growing demand, while the Philippines has to meet all gas consumption via LNG (due to small indigenous reserves).Box 1: Floating LNG (FLNG)Historically, LNG has been produced at large plants located in close proximity to gas resources and a jetty capable of moving the liquefied gas to tankers for transport. For gas fields located offshore, this involves building offshore facilities to extract the gas, pipelines to transport it back to the land-based plant where it is liquefied and jetty infrastructure so it can be moved to ships for export. From 2015, LNG will be produced for the first time using floating LNG technology. For offshore fields, FLNG centralises the production process by co-locating the gas extraction, transport and liquefaction facilities on-board one enormous vessel. The world’s first two FLNG vessels are currently being built in South Korea. The first, Prelude, is being constructed for Shell. Its hull is almost half a kilometre long, and when complete, it will weigh around six times as much as an aircraft supercarrier. Capable of liquefying 3.6 million tonnes a year of natural gas, it will be one of the largest structures ever put to water. The second, PFLNG, is being constructed for Petronas. Slightly smaller than Prelude, it will be 365 metres long and be capable of liquefying 1.2 million tonnes a year of natural gas. On completion in 2016, Prelude will be towed from South Korea to the north west coast of Western Australia. It will then be moored in place for 25 years as it extracts gas, liquids and condensate from fields in the Browse Basin. The PFLNG, scheduled for completion in 2015, will operate in the Kanowit gas field off the coast of Malaysian Borneo. Petronas also recently announced that it had reached a final investment decision (FID) on a second FLNG which will begin construction soon (aiming for 2018 start-up).FLNG has a number of benefits compared with traditional LNG plants. It avoids the environmental impact associated with building an onshore plant and jetty and offshore platforms and pipelines. For certain fields it is considered a cheaper option than building onshore (as shown by Woodside’s decision to pursue FLNG over onshore LNG for their Browse basin resources). The first-of-its-kind Prelude project will cost $12.6 billion at $3.5 billion per million tonnes of liquefaction capacity. This is roughly equivalent to the per-unit cost of the conventional Pluto project ($15 billion at $3.5 billion per million tonnes of liquefaction capacity). The opportunities for savings are also considerable based on the repeatability of the design (i.e. future construction will be able to forego a considerable portion of front-end engineering and design costs). Finally, FLNG allows ‘stranded’ gas fields (those that are too far offshore to be accessed currently) to be economically exploited.While the underlying technology is well established, the scale creates uncertainty. As such, these projects are seen as bellwethers for the technology and its application. If successful, it will allow LNG plant construction to become a factory process rather than a series of individual one-off building projects, and could contribute to a wave of FLNG construction and deployment.

AustraliaAnnual and quarterly productionProduction in the December quarter was around 15.6 billion cubic metres, slightly lower than the September quarter (16.1 billion cubic metres). Production at some fields, such as Thylacine in the Otway basin, Reindeer and Pluto in the Carnarvon basin, and APLNG’s Queensland CSG operations increased following improvements in operating time and higher demand. These increases were more than offset by lower production elsewhere in Victoria (Gippsland JV, Yolla, Casino and Minerva) and Western Australia (where the cessation of a large industrial contract with NWS caused domestic production fall considerably).Australia is forecast to produce 62 billion cubic metres of gas in 2013–14, similar to 2012–13 production (see Table 1). The only major source of new gas production in the past six months was the Macedon gas processing plant in Western Australia which was largely offset by declines in other fields (mentioned above). The Tuna-Turrum project in the Gippsland basin, scheduled for completion in

early 2014, is expected to largely replace falling production at ageing fields in the area.

OutlookA number of large export projects underlie the massive projected growth in Australian gas production over the remainder of the outlook period (2014–15 to 2018–19). The seven LNG projects currently under construction in Australia will more than double gas production from 62 billion cubic metres in 2012–13 to 151 billion cubic metres in 2018–19.Western market production is projected to increase to around 73 billion cubic metres by 2018–19, from around 39 million cubic metres in 2012–13. Gorgon and Wheatstone domestic and LNG output is expected to contribute around 34 billion cubic metres of additional production a year by 2018–19, the majority of production growth over the outlook period.Northern market production is expected to remain stable until the Ichthys project begins operation in the Browse basin in 2016–17 and Prelude FLNG in early 2017–18. The commissioning of these projects is expected to underlie an increase in Northern market production from less than 1 billion cubic metres currently (Bayu-Undan production is excluded as it is in the Joint Petroleum Development Area) to more than 17 billion cubic metres in 2018–19.Eastern market production is projected to increase almost threefold: from around 22 billion cubic metres in 2012–13 to 61 billion cubic metres in 2018–19. This growth is associated almost entirely with Queensland LNG projects: Australia Pacific LNG (APLNG), Gladstone LNG (GLNG) and Queensland Curtis LNG (QCLNG). Gas production for domestic use faces considerable uncertainties over the outlook period. A number of projects such as Gloucester, Narrabri, and Ironbark may begin operation, but face environmental, economic and social hurdles. Eastern market demand is likely to be subdued by higher prices regardless of whether new projects go ahead or not.A key uncertainty over the projection period is the prospects for Arrow Energy’s LNG plant. Arrow, a joint venture between Shell and PetroChina, has sizable CSG resources of around 25 billion cubic metres. The company has been cautious in recent months about the prospects of developing their own LNG plant to draw on those resources (a FID was pushed back again in January). Arrow currently produces around a billion cubic metres of gas a year for domestic use but may consider selling into existing LNG projects in the future rather than developing their own LNG facilities.Table 1: Committed Australian LNG projects

Project Basin Ownership (%) Capacity (Mtpa)

Estimated start-up

Australia Pacific LNG (APLNG)

Surat-Bowen

Origin (37.5%), ConocoPhillips (37.5%) and Sinopec (25%)

9 T1 – H2 2015T2 – H1 2016

Gladstone LNG (GLNG)

Surat-Bowen

Santos (30%), Petronas (27.5%), Total (27.5%) and Kogas (15%)

7.8 T1 – H1 2015T2 – H2 2015

Queensland Curtis LNG (QCLNG)

Surat-Bowen

BG (73.75%), CNOOC (25%) and Tokyo Gas (1.25%)

8.5 T1 - H2 2014T2 – H2 2015

Gorgon Carnarvon Chevron (47.3%), ExxonMobil (25%), Shell (25%), Osaka Gas (1.25%), Tokyo Gas (1%) and Chubu Electric (.417%)

15.6 T1 – H1 2015T2 – H2 2015T3 – H1 2016

Wheatstone Carnarvon Chevron (64.14%), Apache (13%), KUFPEC (7%), Shell (6.4%) and Kyushu Electric (1.46%)

8.9 T1 – H2 2016T2 – H1 2017

Ichthys Browse Inpex (66%), Total (30%), Tokyo Gas (1.6%), Osaka Gas (1.2%) Chubu Electric (0.7%) and Toho Gas (0.4%)

8.4 T1 – H1 2017T2 – H2 2017

Prelude Browse Shell (67.5%), Inpex (17.5%), Kogas (10%) and CPC (5%)

3.6 T1 – H2 2017

Sources: BREE, Company reports; LNG Insight.

Box 2: Global gas market modellingBREE’s view of the Asia Pacific LNG market over the next five years has been informed by the use of a world gas model. This model calculates all inter-country pipeline and LNG trades within a least-cost framework, providing an integrated view of world gas supply and demand. The detailed database includes the costs of production from all gas fields in the world, and the costs of pipeline transportation, LNG liquefaction, shipping and regasification. The model also incorporates all existing and announced gas trading contracts. The model has provided more insights into the likely growth and sourcing of gas supplies in Australia’s LNG trading partners, both from competing LNG suppliers and pipeline sources. It also provides insights on the future liquidity of the global gas market and potential spot prices. BREE has assumed a lower LNG spot price later this decade, reflecting a more liquid and competitive Asian LNG market (due to strong growth in LNG and pipeline supply as discussed in the Global Outlook section earlier). This has contributed to lower projected export values compared with the September 2013 Resources and Energy Quarterly. The projected export volumes are also lower than in September, due to revised start-up assumptions for some projects, which has also contributed to the lower projected export value. The September REQ projected $67 billion worth of gas exports in 2017–18, which has been revised down to $61 billion in this REQ.

Annual and quarterly exportsAustralia is forecast to export 23.7 million tonnes of LNG in 2013–14, a slight decrease from 2012-13. This is mainly due to lower volumes from NWS (around 15.8 million tonnes in 2012–13 down to 15.4 million tonnes in 2013-14).LNG production in the December quarter was slightly lower than in September (from 6.1 million tonnes to 6.0 million tonnes) due to lower Darwin (higher downtime) and NWS (offshore maintenance and reliability improvements to a number of trains) production. In contrast, Pluto reported its highest ever quarterly production following maintenance through mid-2013.Construction progress at new LNG projects continued well over the December quarter. By the end of 2013, the upstream phase of APLNG was reportedly 58 per cent complete and downstream 62 per cent complete. The main pipeline connecting the two is close to being fully completed. Due to begin production in 2015 (see Table 1), GLNG is more than 72 per cent complete and announced a cooperation agreement with APLNG in late October to build connection points between their respective pipelines to allow gas swaps (expected to minimise gas transport and operational costs). QCLNG is the most advanced of the three Queensland projects at an estimated 75 per cent complete and is expected to begin production in late 2014.LNG projects in the West and North also made good progress through late 2013 and early 2014, but will be completed later than the three Eastern market projects. According to project operator Chevron, Gorgon and Wheatstone are now around 78 and 30 per cent complete, respectively. Ichthys (targeting 47 per cent completion by the end of 2014) is also progressing steadily and Prelude’s hull was completed in December, a key milestone (see Box 1 for more discussion on Prelude).Figure 8: Australian LNG export volume and valuesPlease refer to page 34 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

OutlookExport volumes are expected to more than triple over the outlook period (Figure 8). The seven projects under construction (Table 1) represent an additional 62 million tonnes of export capacity a year by 2018–19 and are expected to increase exports to 79 million tonnes by that year. While the majority of Australia’s gas will be traded under contract, the ability of Australian LNG operators to extend or re-sign expiring contracts (particularly at NWS), sign new contracts (particularly at Gorgon and QCLNG), or price their gas competitively in Asia–Pacific spot markets will be key determinants of export volumes later in the outlook period. Future Asia–Pacific LNG market conditions, which will have a significant bearing on those factors, are explored in the review section of this edition of Resources and Energy Quarterly.Australian LNG export values were $13.7 billion in 2012–13 and are forecast to continue growing in 2013–14, to $16.1 billion. The growth in values is almost entirely due to the depreciation of the Australian dollar as volumes and unit prices have been relatively flat. Values are projected to continue increasing from 2014–15 due to larger volumes, reaching $54 billion (in real terms) in 2018–

19. This is despite a forecast fall in the oil price and the likelihood of increased global supply driving down LNG spot prices later in the outlook period.Table 2: Gas outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

Thermal coalKate Penney

PricesNewcastle free on board spot prices for 6000 kilocalorie per kilogram (kcal/kg) coal averaged US$84 a tonne in 2013. Prices were around US$91 dollars a tonne at the start of the year and declined progressively to around US$77 a tonne by the end of September as new capacity developed over the past few years began production. Prices rallied toward the end of the year in response to seasonal buying by Chinese utilities ensuring sufficient supplies over the northern winter and Chinese New Year.Thermal coal prices continued the downward trajectory witnessed throughout most of 2013 in the first quarter of 2014, underpinned by increased world production, expected weaker demand growth in emerging economies and reduced activity around Chinese New Year. The Newcastle thermal coal price was around US$74 a tonne in mid-March. While lower prices have forced some marginal producers to close, others have increased production to reduce unit costs and remain viable. While consumption is forecast to increase, this extra supply is expected to continue to place downward pressure on prices throughout the remainder of 2014.Negotiations for the Japanese Fiscal Year 2014 (JFY, April 2014 to March 2015) benchmark contract price for Australian producers commenced in early March. Given the extended period of low Newcastle spot prices in the lead up to these negotiations, the benchmark contract price is forecast to decline by 15 per cent to be settled at US$81 a tonne.The global supply overhang is expected to persist in 2015, with contract prices forecast to decline by a further 3.7 per cent to US$78 a tonne in JFY 2015. From 2016, the market balance will tighten as import demand continues to increase and supply growth eases as price pressures in the preceding years force less competitive mines to close. The contract price is projected to rise to US$89 (in 2014 dollar terms) by 2019.There are two major risks to the price outlook. On the demand side, China’s efforts to reduce air pollution and associated measures to reduce coal-use may force the transition away from coal at a faster pace than expected. Should this occur, growth in China’s imports will be lower than projected, placing downward pressure on prices. On the supply side, if Indonesia’s plans to curb production growth are unsuccessful, exports will grow at a faster pace than projected, which could reduce the possibility of higher prices post-2016.Figure 1: JFY thermal coal pricesPlease refer to page 37 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Thermal coal consumption and tradeIncreased concern about the effect of coal-use on the environment has prompted governments around the world to reconsider their energy strategies and optimal energy mix. In line with their stage of economic development and the larger size of the service sector compared with manufacturing, growth in energy use in advanced economies will be relatively slow. As such, their energy strategies have a greater emphasis on environmental amenity, and a push to accelerate the transition away from coal into other, lower carbon options.Emerging economies have limited, if any, policies in place to limit carbon emissions, and are expected to expand their coal consumption to fuel economic expansion and improve their citizen’s standard of living. The relative abundance, low-cost and wide geographical dispersion of coal resources and the reliability of coal-fired technology will continue to support its use in these economies. Given that most of the forecast growth in world energy demand will come from emerging economies, coal is expected to continue to feature prominently in the world energy mix.In line with higher consumption, world coal trade is projected grow at an average rate of 2.1 per cent to around 1.15 billion tonnes in 2019.

World thermal coal importsChinaChina is the world’s largest coal producer, consumer and importer. As such, developments in China’s coal market will have important implications for world coal markets. In 2013, China’s thermal coal imports increased by 15 per cent to around 250 million tonnes. Imports of thermal coal increased considerably towards the end of the year following seasonal buying in the lead up to the northern winter and Chinese New Year. Further impetus was provided by relatively lower import prices.In response to heightened concerns about deteriorating air quality, the Chinese Government outlined its Airborne Pollution Prevention and Control Action Plan 2013–17 in mid-September 2013. Most of the measures contained in the plan directly target the use of coal, such as reducing the share of coal in the energy mix to less than 65 per cent by 2017 and a ban on the development of new coal-fired facilities in the Beijing-Tianjin-Hebei, Yangtze River Delta and Pearl River Delta areas. There is also greater interest in diversifying the energy mix to include more gas, wind, solar, hydro and nuclear.Plans to restrict the importation of lower grade coal are also gaining momentum. Details of the restrictions have not been confirmed and could target a combination of energy content, sulphur content, and ash content. If these plans are enacted, imports from Indonesia are expected to be the most affected. In 2013, China sourced almost half of its thermal coal imports from Indonesia. Depending on the final quality requirements for imported coal, it is likely that domestic production will need to fill the gap.While these plans are likely to slow the growth in coal-use, particularly toward the end of the projection period, China is likely to remain a large coal consumer given the expected expansion of coal-fired generation in other regions and the relatively low cost of imported coal. The China National Coal Association projects China’s coal consumption to increase at an average annual rate of more than 4 per cent to 4.8 billion tonnes in 2020.According to the IEA, China’s electricity generation is projected to increase by 55 per cent under the New Policies Scenario, with a third of this expected to be coal-fired. While the growth in new coal-fired plants is expected to be slower than other energy sources, it will still represent the largest absolute increase in capacity. China’s existing coal-fired generation fleet is relatively new. Coal-fired assets tend to have an operating life of 40–60 years and it will be 30–40 years before any significant closures of existing coal capacity in China is likely to occur.To allay environmental concerns associated with increased coal consumption, scrubbers that are already available in some plants could be used. Scrubbers capture the sulphur dioxide contained in waste gases from the plant. Because the scrubber’s water and energy requirements increase the cost of operation and reduces profitability, the current utilisation rate in China is low. For example, there are reports that a power company in Datong, near Beijing, turned off its scrubbers when Beijing’s air pollution was 30–40 times above recommended levels. While the government issues fines to plants caught turning off their scrubbers, the cost is typically less than the savings made by not running them. Improving efficiency at existing facilities and using the most modern technology will also reduce coal requirements for similar levels of generation.China is expected to remain the largest producer of coal over the projection period. In 2013, the construction of more than 100 million tonnes of new capacity was approved. There are further plans to consolidate the industry and create coal production bases with co-located mines, power plants and coal chemical plants, which will then export electricity to other regions. Most of the coal bases are expected to be in northwest China such as Inner Mongolia, Shaanxi and Ningxia.The cost of production is increasing in some of China’s more mature mining regions and the long distances between mining regions and consumption centres makes transportation infeasible or uneconomic. As such, imported coal is expected to remain competitive over the medium term. China’s imports of thermal coal are projected to increase at an average rate of 2.1 per cent to 290 million tonnes in 2019.Figure 2: Major thermal coal importersPlease refer to page 39 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

IndiaGrowth in India’s thermal coal imports is estimated to have moderated to 6 per cent in 2013, underpinned by lower economic growth and a relatively weak Indian Rupee that increased the relative cost of coal imports. Imports are estimated at around 130 million tonnes for the year.

India’s electricity demand is expected to rise substantially over the medium term in response to greater electrification, rising household incomes and the expansion of the middle class. Coal-fired generation is a major component of India’s plans for new electricity generating capacity being developed under the twelfth Five-Year Plan (2012–17). The power ministry has forecast the development of 47 gigawatts of new coal-fired generating capacity by early 2017, and a further 66 gigawatts by 2022. Together, these increases will take India’s total coal-fired generating capacity to 247 gigawatts.Growth in India’s domestic coal production is not expected to keep pace with its requirements because of difficulties in obtaining relevant land access and environmental approvals for developing mines as well as transport infrastructure bottlenecks. Accordingly, India is expected to become more reliant on imported coal over the outlook period. Some of this coal is expected to be secured through the development of foreign assets, particularly in the Galilee Basin in Australia and South Africa. India’s thermal coal imports are projected to increase at an average rate of 6 per cent a year to 182 million tonnes in 2019.The majority of India’s coal imports are received at India’s ‘minor ports’. In order to accommodate the expected expansion in coal imports, the Indian Government has embarked on a program to increase handling capacity and modernise its major ports— Kolkata, Paradip, Visakhapatnam, Ennore, V.O. Chidambaranar, Haldia, Chennai, Tuticorin, Cochin, New Mangalore, Mormugao, J. L. Nehru, Mumbai and Kandla. The capacity of these ports to receive coal imports are limited by size, low berth productivity, limited stockyard capacity and poor interconnection with the regions. The program will seek to address these issues and increase handling capacity by 58 million tonnes a year over the next 3–4 years.

JapanFollowing the closure of the Ohi nuclear plant in Fukui at the end of 2013, Japan’s entire nuclear fleet has been shut down. Consequently, Japan has relied on thermal power (oil, coal and gas) to manage the lost capacity. Japan’s coal-fired power fleet has been running at close to capacity, contributing to greater coal use and coal imports, which increased by 4.1 per cent to 137 million tonnes in 2013. The increased imports required to operate these plants and relatively high prices for gas has contributed to Japan recording large trade deficits.Japan released a draft of its new Basic Energy Plan (BEP) in late February 2014, the first to be prepared post-Fukushima. The draft BEP indicates that nuclear power, along with renewables and fossil fuels will provide the most reliable energy mix for Japan. However, the existing fleet of nuclear reactors will need to pass a rigorous set of new safety requirements before they can resume operation. This has been a slow and uncertain process. It is assumed that only six reactors will be restarted toward the end of 2014. As a result, coal consumption is unlikely to be affected by nuclear restarts in 2014.As more reactors are restarted over the medium term, high-cost generation facilities will be progressively closed. Crude oil and fuel oil facilities are likely to be the first to close, followed by gas and coal. As facilities are closed, Japan’s coal imports are projected to decline at an average rate of 1.5 per cent to 127 million tonnes in 2019. If nuclear restarts and the uptake of renewable energy options are faster than expected, the decline in coal imports will accelerate, providing a downside risk to this assessment.

South KoreaIn 2013, South Korea imported an estimated 96 million tonnes of thermal coal, 1.8 per cent higher than in 2012. In an effort to reduce coal-use, a tax will be imposed on coal imports from mid-2014, while the tax on LNG will be reduced. Although this will increase the cost of coal imports, it is unlikely to result in any significant drop in volumes in the short term as coal will still be required to meet electricity demand.South Korea’s Second Energy Basic Plan was released in January 2014, which had a considerably reduced role for nuclear power compared with the previous plan released in 2008. While there is a larger role planned for gas and renewable energy, coal is likely to remain an important component of the energy mix to ensure system reliability. An expected moderation in electricity demand will contribute to a slower rate of growth in coal imports which are projected to increase at an average rate of 1.6 per cent to 105 million tonnes in 2019.

World thermal coal exportsAustraliaAustralia’s exports of thermal coal increased by 10 per cent in 2013 to 188 million tonnes, supported by continued strong demand for coal, particularly from China toward the end of the year, and increased production from recently completed expansions. In 2013, declining coal prices increased the financial pressure on higher-cost Australian producers. Many of these producers are locked into long-term take-or-pay contracts for infrastructure services, so it was more cost effective for them to increase output rather than shut down.In 2014, Australia’s exports of thermal coal are forecast to increase by 3.7 per cent to 195 million tonnes. Additional output will come from the completion of expansions at Glencore-Xstrata’s Rolleston mine (an extra 3 million tonnes a year) and Peabody Energy’s North Goonyella (an extra 5 million tonnes a year) and Middlemount (an extra 1.5 million tonnes a year) operations.There are still a number of producers that will face rising financial pressure with lower coal prices. As a result, some operations may be forced to close or scale back production over the coming years. For many producers, the take-or-pay contracts with infrastructure operators still make cutting production an even less commercially viable option and should continue to sustain current, or potentially higher, production levels. Over the projection period, Australian producers will continue to look for ways to improve efficiency and cut costs such as labour reductions and renegotiating service contracts. A merger of Rio Tinto and Glencore-Xstrata’s coal operations has also been mooted in an effort to achieve higher efficiencies and lower operating costs.The slowdown in investment in new coal projects in Australia over the past few years is expected to limit the pace of growth in Australia’s production and exports until 2016 when a number of new projects are scheduled to be commissioned. These will be partially offset by the closure of several mines over the projection horizon as their economic resources are exhausted.Over the medium term, Australia’s thermal coal exports are projected to increase at an average annual rate of 6 per cent to 257 million tonnes in 2019. This will be heavily influenced by the start of production from the large-scale projects being planned in Queensland’s Galilee Basin towards the end of the outlook period. These proposed mines include GVK Hancock’s Alpha mine (annual capacity of 30 million tonnes a year), Adani’s Carmichael mine (60 million tonnes) and Bandanna Energy’s South Galilee project (17 million tonnes). These are among the highest value coal projects being developed in Australia owing to both their size and the need to develop infrastructure to move the coal to export facilities. It is expected that the majority of this new capacity will be exported to India.Should China’s import ban target the ash content of coal, it is possible that this could affect the volume of imports from Australia. It is assessed that the import ban will more likely target coals with lower energy content and/or higher sulphur content. As such, it is not expected that exports from Australia will be significantly affected by this measure.Figure 3: Major thermal coal exportersPlease refer to page 43 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

IndonesiaIn 2013, Indonesia exported an estimated 411 million tonnes of thermal coal, 8 per cent higher than 2012. Indonesian producers increased output despite lower prices while looking to achieve cost reductions in order to remain profitable.The Indonesian Government has indicated plans to limit coal production to preserve resources and stabilise coal production to reduce downward pressure on prices. The Energy and Mineral Resources Ministry has outlined a coal production target of around 400 million tonnes for 2014. Under a longer term plan, the Ministry is only expecting production to increase by around 5 per cent from 2015. Larger companies are set targets through reviews of their company work plans and budget. Companies that breach the target will be sanctioned including suspensions and lower targets in subsequent years. However, to be effective the government will need to also curb output growth at small-scale operations and in unlawful mining.The Government plans to introduce a number of measures to achieve these targets. It is anticipated that Indonesia will review royalty payments arrangements over the medium term so that all producers pay 13.5 per cent of net sales. Currently, small to medium sized producers pay a royalty of between 3 to 7 per cent of net sales. This increase is likely to reduce the competitiveness of these suppliers and result in the closure of some of this capacity.

It is estimated that up to 74 million tonnes a year is produced at unregistered operations. In an effort to control unlawful mining, Indonesian coal exporters are required to provide evidence clearing them to produce coal before shipments will be allowed. As at late February an estimated 30–40 companies, or around 2500 mines, had obtained the required approvals.Concurrently, the Indonesian Government is promoting rapid growth in domestic coal consumption from 2014 by encouraging the expansion of coal-fired electricity generation and other uses such as coal liquefaction and gasification. Further, the ore export ban introduced in January 2014 requires minerals to be processed into a final product before export from Indonesia. These processing facilities will require large volumes of energy and are likely to be coal based.The expansion of Indonesia’s coal consumption will be met by domestic coal through the Domestic Market Obligation—the proportion of output that needs to be reserved for the domestic market. As such, Indonesia will have a lower capacity to export coal to world markets. A number of new coal-fired power plants in Asia have been designed to burn coal with lower heating values and were intending on importing the bulk of their requirements from Indonesia. These consumers will most likely need to explore other supply options over the medium term.If China proceeds with its plans to limit the importation of low quality coals, Indonesia is likely to be the hardest hit because of the low energy content of its coal. Lower demand for Indonesian coal from China may act to further limit their exports over the outlook period.Indonesia’s thermal coal exports are projected to decline at an average rate of 1.5 per cent to 390 million tonnes by 2019, underpinned by lower production and increased domestic use. There will be a number of challenges for the Indonesian Government in restraining production growth. Should the government fail to enforce these targets, exports from Indonesia are likely to be higher, providing an upside risk to this assessment.

The USThe US is attempting to achieve a sharp shift away from coal in its electricity system over a short timeframe through the planned introduction of new regulations. As part of the Climate Action Plan, the US Environmental Protection Authority has proposed new legislation that will limit emissions from new coal plants with a capacity of more than 25 megawatts to less than 1100 pounds (0.5 tonnes) per megawatt hour of electricity generated. This will effectively prevent the construction of new facilities as they would require the installation of technology that is currently considered uneconomic and not commercially proven. In addition, the Mercury and Air Toxics Standards for New Power Plants mandates reduced emissions of mercury, acid gases and toxic metals. These standards are scheduled to be introduced from 2015.The US coal-fired generation fleet is ageing and struggling to compete with relatively low gas prices. Around 17 per cent of the fleet is more than 50 years old and a further 24 per cent is more than 40 years old. These plants are likely to be retired over the medium term and are unlikely to be replaced with new capacity, especially in the presence of the proposed environmental standards.While lower domestic consumption would suggest that more coal will be available for export, low thermal coal prices, declining demand in key markets and infrastructure limitations are expected to contribute to exports declining at an average rate of 10 per cent a year to 24 million tonnes by 2019.In Europe, the largest export market for the US, the Industrial Emissions Directive and other climate related policies may encourage reduced use of coal-fired capacity from 2016. While coal consumption and import demand in Asia is expected to remain robust, the US will struggle to access this market without significant investment in infrastructure which is currently uneconomic to develop.

ColombiaColombia’s thermal coal exports declined by 7 per cent to around 76 million tonnes in 2013 as first exports from Glencore-Xstrata’s new Puerto Nuevo terminal (21 million tonnes a year) were more than offset by lower output following a series of labour disputes and disruptions owing to environmental regulation breaches. In addition, restrictions to coal transportation were imposed on the Feneco line (which is used for around 85 per cent of total exports) in an effort to reduce noise pollution.To prevent environmental damage associated with the use of barges, new transport rules requiring the use of enclosed transport systems were introduced in early 2014. After failing to meet this deadline, Drummond was banned from exporting coal until their facilities are completed. It is estimated that this will prevent up to 7 million tonnes of coal from being exported during the first quarter of 2014.

Over the medium term, Colombia is expected to increase its export volumes, underpinned by the development of new operations and new infrastructure. Given the expected slow growth in US and European imports, most of the new volumes will be directed to the Asia-Pacific market. Colombian exports are projected to increase at an average annual rate of 8 per cent to 117 million tonnes.

South AfricaSouth Africa sources the majority of its electricity from coal-fired facilities, accounting for more than half of its total coal production. A number of large-scale coal-fired generation facilities are scheduled to be developed over the next few years to ensure stable supply and are likely to reduce the volume of coal available for export.While the Richard’s Bay Coal Terminal has the capacity to handle up to 91 million tonnes of coal a year, South Africa’s coal exports have been limited by rail capacity. According to the Public Enterprises Minister, 6405 kilometres of rail will be replaced to increase freight capacity to around 150 million tonnes over the next five years. However, this is not expected to have a major effect on exports until toward the end of the projection period.Exports from South Africa are projected to increase at an average rate of 2.7 per cent to 87 million tonnes in 2019.

Australia’s export volumes and valuesAustralia’s thermal coal production is forecast to increase by 4.1 per cent in 2013–14 as recently completed projects increase output toward full capacity and a number of other producers expand output to reduce unit costs.In 2014–15, Australian thermal coal production is forecast to increase by 2.5 per cent to 255 million tonnes. Increased output will be supported by the completion of a number of expansion projects including Whitehaven Coal’s Werris Creek (an extra 0.5 million tonnes a year) and Peabody Energy’s Metropolitan mine (an extra 1.5 million tonnes a year) and the commencement of production at Whitehaven Coal’s Maules Creek (10.8 million tonnes a year). This will be partly offset by lower production at Anglo American’s Drayton operations because of delays in obtaining approval to proceed with developments to extend the life of the mine. Resources at the existing Drayton mine are expected to be exhausted in 2015.Over the medium term, Australia’s thermal coal production is projected to increase at an average rate of 3.6 per cent to 296 million tonnes. Growth in production is projected to accelerate from 2016–17 as a number of new projects are commissioned.In 2013–14, Australia’s exports of thermal coal are forecast to increase by 8 per cent to 195 million tonnes, supported by record volumes in response to seasonal buying from China at the end of 2013 and increased output at Australian operations. The value of these exports is forecast to increase by around 6 per cent to $17.1 billion, as higher export volumes more than offset expected lower prices. In 2015–16, export volumes are forecast to increase by 2.7 per cent to 201 million tonnes. Earnings are forecast to decline by 5.2 per cent to $16.2 billion, driven by expected lower prices.Over the remainder of the outlook period, Australia’s thermal coal exports are projected to increase at an average 4.6 per cent a year to 244 million tonnes in 2018–19. Export earnings are projected to increase by 4.5 per cent a year to around $21.2 billion (in 2013–14 dollar terms) in 2018–19.Figure 4: Australia’s thermal coal exportsPlease refer to page 47 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 1: Thermal coal outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

UraniumJohn Barber

PricesThe uranium spot price continued to decline in 2013 and averaged around US$38 a pound, 21 per cent lower than 2012 (see Figure 1). This price decrease was mostly observed in the first six months of 2013 with prices falling from around US$44 a pound in January to US$35 in July. Long term contract prices also declined in 2013, albeit at a lower rate of 10 per cent, and averaged US$54 a pound. While the price drop can be largely attributed to the demand shock associated with the idling of Japan’s nuclear industry since 2011, an 8 per cent increase in mined uranium production over the same period has also contributed to creating the supply surplus that has weighed heavily on uranium prices.In 2014, the uranium spot price is forecast to increase moderately from current levels, but remain essentially unchanged from 2013 at around US$38 a pound. The forecast price increase during 2014 is based on the assessment that the change in the market supply balance will not be significant enough to support higher prices in 2014. Although a small number of reactors in Japan are expected to resume operation, this is not expected to have any immediate impact on prices as Japanese nuclear power plants already have sufficient stocks of uranium to re-start and operate a small proportion of its industry. While the end of the US-Russian Highly Enriched Uranium (HEU) program in December 2013 will eventually lead to an increased reliance on primary uranium supplies, this is unlikely to affect the uranium price until late 2014, or potentially 2015, when the last shipments under the agreement are fully consumed. Similarly, many utilities around the world are understood to have already taken advantage of the lower prices in 2013 to cover their short term requirements. Purchases by utilities in China for the initial loading of new reactors is likely to be a principal source of demand growth in 2014, however, this is viewed as more likely to wind down the uranium inventories that have been accumulated over the past 12–18 months. A substantial increase in China’s reported uranium imports would suggest that these purchases have already started and had little effect on prices in 2013.Over the outlook period to 2019, the uranium market balance is projected to tighten substantially due to the rapid growth in China’s nuclear power industry, the eventual impact of the end of the US-Russian HEU program and delays in the development of major uranium mining projects around the world. Based on current projections of consumption and production, market deficits are not projected in the outlook period. Although consumption is projected to increase over the period, there are already a number of large mines under development that can meet the additional requirements. However, in the event that schedule risks delay the start of new mines, or their ramp up to full production, there is the potential for a supply shortfall that would support higher prices. Over the outlook period, the uranium spot price is projected to increase at an average annual rate of around 11 per cent to US$63 a pound (in 2014 dollars) in 2019.Figure 1: Quarterly uranium pricesPlease refer to page 50 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

ConsumptionUranium consumption for electricity generation is estimated at 76 700 tonnes in 2013, a 2.1 per cent increase relative to 2012 but still 3.8 per cent lower than consumption pre-Fukushima incident in 2010. This modest increase was supported by the commissioning of two new reactors in China and one in India as well as small increases in most uranium consuming countries. Japan’s uranium consumption remained very low relative to pre-Fukushima levels, with only two of its 48 reactors operational for part of the year.In 2014, world uranium consumption is forecast to increase by 3.4 per cent, relative to 2013, to 79 400 tonnes. This forecast growth will be supported by the initial fuelling requirements for new reactors in China which, after construction delays due to national energy policy reviews, are nearing completion and expected to connect to China’s electricity grid in 2014. Additional reactor starts are scheduled in Russia, South Korea and India but these will be partially offset by closures in Canada and the US.The idling of Japan’s nuclear industry has substantially reduced its uranium consumption over the

past three years. The Abe government of Japan released its draft Basic Energy Plan in February 2014 that indicated support for the country’s nuclear industry. Nuclear power plant operators have already lodged applications with the Nuclear Regulation Authority to restart 17 reactors. Based on the safety requirements and inspection times it is assessed that up to six of these could restart in the second half of 2014. Considerable political and social opposition to the reactor restarts still remains and there is the risk that further delays may occur. Over the outlook period it is expected that more of Japan’s nuclear reactors will recommence electricity production but that a number of older reactors will remain offline and be decommissioned. In 2019 Japan’s uranium consumption is projected to be around 70 per cent of its pre-Fukushima levels at 6500 tonnes of U3O8.Over the outlook period rapid growth in the number of operating nuclear power reactors is expected to result in substantial increases in demand for uranium. With around 70 new reactors currently under construction around the world (and more planned) world nuclear power production capacity is projected to increase by around 20 per cent over the next six years. As a result, world uranium consumption is projected to grow at an average annual rate of 4.7 per cent from 2013 to 2019 and to total 101 000 tonnes of U3O8 in 2019. This growth will come primarily from emerging economies that are including nuclear power in their energy mix as means of providing relatively cheap, low carbon emitting and reliable base load supplies of electricity to support their increasing energy requirements.China is currently the third largest consumer of uranium in the world and is estimated to have consumed around 7900 tonnes of U3O8 in 2013. With 30 nuclear reactors that have a combined capacity of around 32 GWe already under construction, China’s nuclear power industry is expected to triple over the next five years, making it the principal driver of the projected growth in uranium consumption over the outlook period. To fuel this increase in nuclear power output, China’s uranium consumption is projected to increase at an average annual rate of 14 per cent to total 17 300 tonnes of U3O8 in 2019. Chinese uranium buyers already appear to be managing this anticipated surge in consumption and China’s uranium imports surged in 2013 with buyers taking advantage of the lower prices.Uranium consumption in the Middle East is projected to grow substantially in the medium and longer term. While countries in this region have historically been heavily dependent on fossil fuels due to their large domestic reserves of oil and gas, their domestic energy policies are seeking to diversify their energy mix and reduce the rate of their resource depletion. The UAE has already commenced construction of its first nuclear power plant, the 4-unit Barakah power plant. Two of the plant’s reactors are already under construction and scheduled to come online from 2017. When complete the Barakah nuclear power plant will have a total capacity of around 5.6 GWe. In the longer term, Saudi Arabia is expected to become a key driver of higher uranium consumption. Its nuclear power program has plans to build up to 16 nuclear reactors with a combined capacity of 17 GWe, although the first reactor is not scheduled to come online until 2022.The US will remain the largest producer of nuclear power in the medium term. While five reactors have been closed over the last two years, this should be offset over the medium term by the five new reactors currently under construction. US uranium consumption is projected to increase at an average annual rate of 1.3 per cent to total around 25 500 tonnes of U3O8 in 2019. This is marginally higher than consumption before the recent reactor shutdowns as the new reactors under construction have higher power capacities. There are further new reactors being planned in the US, however given planning and construction times these are not expected to become operational within the outlook period. In the longer term, further expansions of the US’s nuclear power industry are far from guaranteed given the cost of construction, regulatory requirements and low gas prices. Nevertheless, recent comments by US Energy Secretary Ernest Moniz following the Department of Energy loan guarantee for Vogtle units 3 and 4 that ‘the construction of new nuclear power facilities like this one....is not only a major milestone in the administration’s commitment to jumpstart the U.S. nuclear power industry, it is also an important part of our all-of-the-above approach to American energy as we move toward a low-carbon energy future’ indicate nuclear power remains firmly in the long term energy plans of the US.India’s energy policy aims for a substantial increase in nuclear power generating capacity to provide energy to its growing economy. Six nuclear reactors are already under construction in India with an additional three being planned that could start operating by 2019. India’s uranium consumption is projected to increase at an average annual rate of 11 per cent to around 3000 tonnes in 2019. However, social opposition to India’s nuclear power program present further risks for completing reactors as scheduled and achieving nuclear power capacity targets.In Europe, nuclear power capacity is projected to grow over the outlook period to 2019. While OECD economies in Western Europe have energy policies that are moving away from nuclear power the growth in Eastern Europe will more than offset the scheduled reactor closures in countries such as

Germany and Belgium. France is expected to remain the largest consumer of uranium in Europe, but with consumption remaining stable at around 11 000 tonnes. Russia will be the principal driver of growth in terms of European uranium consumption with up to 10 reactors scheduled to start operating by 2019. As a result, uranium consumption in Russia is projected to increase at an annual average rate of 3 per cent from 2013 to around 7300 tonnes in 2019.

ProductionIn 2013, primary uranium production is estimated to have increased by 2.1 per cent to around 69 000 tonnes of U3O8 with production increases from existing mines in Kazakhstan being offset by disruptions at a number of mines and the end of ore extraction from the Ranger mine in Australia. At current uranium spot prices, around 20–30 per cent of world uranium production is estimated to be below cost, as evidenced by Paladin Energy’s decision to place the Kayalekera mine in Malawi on care and maintenance in early 2014. While long term contract prices still attract a premium on the spot prices and have remained over US$50 for some time, average sales values for a number of producers would suggest a decrease in the volume of sales completed at the long term contract price.In 2014 mined production is forecast to remain at around 69 000 tonnes with the start-up of Cameco’s Cigar Lake mine in Canada and incremental increases at existing mines around the world offsetting the loss of production from the Kayalekera mine in Malawi and Ranger mine in Australia. The end of the HEU program in December 2013 has removed the equivalent of around 10 000 tonnes of U3O8 from the market in 2014. However, with the last shipment occurring late in 2013 it will take a number of months for this supply disruption to work through the market as the lag between shipment and reactor loading will mean uranium sold through the HEU program will be used for a number of months to come. This overhang of secondary supplies, as well as the large inventories of U3O8 that have accumulated during the past two years and potential for continued ramp up in production from low cost mines in Kazakhstan, indicate there are limited prospects of a significant uranium price recovery in 2014.While the current price situation greatly benefits utilities, it is increasing the risk of a supply shortfall in the medium to long term. Most uranium mine developers have indicated that they require a uranium price over US$60 a pound to make new mines commercially viable. With current spot prices at around US$36 a pound there is a considerable risk that the new uranium mines required to support the expanding number of nuclear reactors around the world will not be developed in time. In the short to medium term this is not expected to be an issue as growing consumption over the next few years can be met by the uranium projects that are already in advanced stages of development (for example, Husab, Imouraren, Four Mile and Cigar Lake), the continued ramp up of recently completed mines or through brownfield expansions that have substantially shorter construction times. Subsequently, over the outlook period primary uranium production is projected to grow at an average annual rate of 5.9 per cent to around 97 000 tonnes. This projection is based on the expectation that a number of mines that are planned, but not yet sanctioned, are approved and start production. Given the growing importance of securing reliable uranium supplies to China further investment in new mines by Chinese companies, either as direct owners or equity partners, seems likely.Kazakhstan is expected to remain the world’s largest uranium producing country over the outlook period. Lower production growth rates are forecast over the next year or two in response to lower market prices but are projected to rebound later in the outlook period as consumption demand gathers pace. Production of U3O8 is projected to increase by 16 per cent over the outlook period, from 26 500 tonnes in 2013 to around 30 700 tonnes in 2019. The projected growth in Kazakhstan’s uranium production will be supported mainly by further expansions at existing mines where additional ISR wells can be created and processing mills expanded more economically than new greenfield mines.Uranium production in Canada is projected to increase by 52 per cent, relative to 2013, to 16 700 tonnes of U3O8 in 2019. This increase will be underpinned by Cameco’s Cigar Lake mine which is projected to reach full operating capacity by 2018, making it the second largest uranium mine in the world. Cameco’s McArthur River mine in Canada is expected to remain the largest uranium mine in the world over the outlook period and is projected to produce around 8500 tonnes in 2019. There are additional uranium deposits in Canada being explored and assessed, given the current market supply situation and time to develop a uranium mine it is not expected that any of this will enter production within the outlook period.Uranium mines in various countries in Africa are expected to play an increasingly important role in fuelling the expansion of nuclear power industries around the world. In 2013, the combined production from Niger, Namibia, Malawi and South Africa is estimated at around 12 000 tonnes, unchanged from 2012. Over the outlook period the start of several large uranium

mines in these countries is expected to support Africa’s uranium production almost doubling to around 22 400 tonnes of U3O8 in 2019. Although projects such as Areva’s Imouraren and Trekkopje mines as well as CGNPC’s Husab mine have reported higher production costs, these are the most advanced large scale projects under development and are well positioned to be the first to respond to any rebound in prices in the short to medium term. In addition to these mines, Bannerman Resources Etango and Forsys Metals’ Norasa projects in Namibia are at advanced planning stages and are expected to start production in the outlook period. Paladin Energy’s Kayalekera mine in Malawi is also expected to return to production later in the period when uranium prices recover.Chinese investment in African mines is expected to play an increasingly important role in the development of uranium resources. Chinese investment is already supporting the development of the Azelik and Husab mines in Niger and Namibia, respectively, and the China National Nuclear Corporation purchased a minority share in Paladin Energy’s Langer Heinrich mine in January 2014.Although smaller in terms of production, the US is projected to have the highest rate of increase in uranium production in the world during the outlook period. From a substantially lower base of around 2200 tonnes produced in 2013, production is projected to increase by around 170 per cent over the outlook period to total 5800 tonnes in 2019. This production increase will not completely offset the loss in supplies from the US-Russian HEU program and still implies the US will rely on imported uranium or secondary supplies to meet 85 per cent of the fuel needs for its nuclear power industry in 2019.

AustraliaProductionAustralia is forecast to produce around 6700 tonnes of U3O8 in 2013–14, down 26 per cent from 2012–13. The substantial drop in output is primarily attributable to the end of ore extraction ERA’s Ranger mine in the Northern Territory. While the facility is still producing U3O8 it is processing lower grade stockpiles that had been accumulated in previous years. After a strong production result in 2012–13, Ranger’s U3O8 production is forecast to be around 40–50 per cent lower in 2013–14. Production at BHP Billiton’s Olympic Dam mine in South Australia is expected to remain broadly consistent with previous years at around 4000 tonnes of U3O8 in 2013–14. Also in South Australia, the Honeymoon mine has been placed on care and maintenance in response to low uranium prices and production at the Beverley mine is estimated to be declining as resources are exhausted.In 2014–15, Australia’s production of U3O8 is forecast to decrease by a further 8 per cent to around 6150 tonnes. Production from Olympic Dam is to forecast to remain at around 4000 tonnes but lower production is forecast at the Ranger mine as the ore grades of processed material are expected to decline further. The Four Mile mine in South Australia is expected to start during this period, albeit at low production rates compared to its capacity.Over the outlook period Australia’s production of U3O8 is projected to rebound and increase at an average annual rate of 6 per cent after 2013–14 to around 8900 tonnes in 2018–19. This projected increase is underpinned by new production coming from the Ranger 3 Deeps project, Toro Energy’s Wiluna mine and the progression to full production at the Four Mile mine. In the second half of the outlook period higher prices are also expected to lead to the Honeymoon mine being restarted and the sanctioning of one of Cameco’s projects (Yeelirrie, Kintyre) in Western Australia. Nevertheless there is still considerable uncertainty as to the schedule of these projects and any production from them is likely to be small in the outlook period. In the event that the projected uranium price recovery happens earlier than expected, these projects may also start sooner. Uranium production in Queensland is not expected to occur within the outlook period based on the average time it takes to develop a greenfield uranium mine.

ExportsAustralia’s exports of uranium (U3O8) totalled 8391 tonnes in 2012–13, 21 per cent higher than 2011–12. Export volumes are forecast to decrease by 24 per cent in 2013–14 due to declining production. Export values in 2013–14 are forecast to decrease by 23 per cent in 2013–14 to $637 million with the lower value of the Australian dollar offsetting the lower prices received by Australian producers.Over the remainder of the outlook period to 2018–19, projected increases in Australia’s uranium production will support export volumes increasing at an average annual rate of 7 per cent to around 8890 tonnes in 2018–19. Combined with higher Australian dollar received prices, the value of uranium exports is projected to grow at an average annual rate of 11 per cent to around $1.1 billion (in 2013–14 dollars) in 2018–19.

Figure 2: Australia’s uranium exportsPlease refer to page 56 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 1: Uranium outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

Resources outlookSteel and steel-making raw materialsTom Shael

World steel consumptionWorld steel consumption in 2013 is estimated to have increased by 2.9 per cent to total 1.59 billion tonnes. The chief driver of this growth was a 6 per cent increase in China’s consumption. For other major steel consuming economies, estimated lower rates of consumption growth can be attributable to lower investment growth in infrastructure and fixed assets. In 2014, world steel consumption is forecast to increase by 2.7 per cent, relative to 2013, to total 1.63 billion tonnes. The forecast growth is expected to be supported by investment in fixed capital and infrastructure in emerging economies, particularly in Asia.Over the period 2015 to 2019, world steel consumption is projected to increase at an average annual rate of 1.9 per cent to total 1.79 billion tonnes in 2019 (see Table 1). Continued economic growth, fixed capital formation and on-going urbanisation are expected to support projected robust growth in steel consumption in emerging economies. Steel consumption in most developed economies is projected to grow, albeit at a moderate rate as these economies already have higher levels of capital stock.Table 1: World steel consumption and production (Mt)Please refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

China was the world’s largest consumer of steel in 2013, accounting for around 46 per cent of world consumption. Steel consumption is estimated to have increased by 6 per cent, to total 729 million tonnes for the year. Credit restrictions that have tightened up housing investment and a decrease in investment in railway networks dampened growth in the latter part of 2013. The effects of this have continued over into the start of 2014; however, while credit controls are expected to remain in place, government spending programs are expected to result in a rebound in steel consumption throughout the remainder of 2014.The Chinese government has announced several fiscal spending programs for the period 2014 to 2020. The programs are aimed at expanding urbanisation, including improving the quality of urban housing stock and building more transportation infrastructure, both of which are steel intensive. The programs are expected to support forecast consumption growth of 3 per cent in 2014 and 2015. Over the remainder of the outlook period, China’s steel consumption growth rates are expected to moderate to a projected average annual rate of 1.8 per cent and total 832 million tonnes in 2019. Although these rates of growth are much lower than those seen during the preceding decade, they are starting from a much higher base and still result in robust additional volumes each year.In 2014, India’s steel consumption is forecast to increase 5 per cent, compared to 2013, to total 83 million tonnes. Consumption is forecast to increase as a result of government spending on infrastructure and higher consumption of consumer durables. Over the period 2015 to 2019, consumption growth is projected to increase at an average rate of 5 per cent a year to total 107 million tonnes in 2019. Increases in India’s steel consumption are expected to be supported by government efforts to improve the quality and coverage of the country’s infrastructure networks. This is expected to include: road networks and bridges, rail systems, electricity generation and other infrastructure. Rising income levels are expected to support a gradual increase in consumption of consumer durables that will also contribute higher levels of steel consumption.Steel consumption growth rates in OCED economies are projected to be more subdued compared to non-OECD economies. Steel consumption growth in the EU is projected to average around 1.4 per cent a year over the outlook period to total 167 million tonnes in 2019. Consumption levels in the US are projected to moderate down in the latter part of the outlook period, to total 101 million tonnes in 2019. The decrease in consumption levels in the US is expected as a result of lower investment in steel-intensive capital formation. Over the outlook period, competition from China in steel-intensive manufactures, such as cars and ships, is expected to put pressure on steel consumption rates in

South Korea and Japan. Steel consumption in South Korea is projected to grow at 1.3 per cent a year to total 60 million tonnes in 2019. Consumption rates in Japan are expected to be affected more strongly, and are projected to decrease by around 0.2 per cent a year to total 69 million tonnes in 2019.

World steel productionWorld steel production in 2013 was 4.2 per cent higher, relative to 2012, at a total of 1.6 billion tonnes. The large increase was driven mostly by a 66 million tonne increase in China’s steel production. In 2014, growth in world steel production is forecast to moderate to 2.1 per cent to total 1.64 billion tonnes. Over the remainder of the outlook period, steel production is projected to grow at an average annual rate of 1.8 per cent to reach 1.79 billion tonnes in 2019. Increases in China’s and India’s steel production are projected to be the leading contributors to the growth.Figure 1: Quarterly steel productionPlease refer to page 59 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

China’s crude steel production exceeded expectations in 2013 and increased by 9.3 per cent, relative to 2012, to total 775 million tonnes, according to monthly data from the World Steel Association. Steel production has started the year slower than at the end of 2013, and also year-on-year, to total around 120 million tonnes in the first two months of 2014. For 2014 overall, China’s steel production is forecast to increase by 3.5 per cent, relative to 2013, to total 802 million tonnes. The increase is expected as a result of robust consumption growth from recently announced government expenditure programs, and despite capacity closures.Around 30 million tonnes of China’s steel production capacity is expected to close in 2014. Out of an estimated 1 billion tonnes of current capacity this is a relatively small amount and as such, is not expected to disrupt production increasing in 2014. In 2014, 15 million tonnes of capacity closures are expected to occur in Hebei province, which accounts for around a quarter of China’s annual steel output. By 2017, Hebei province is expected to have reduced its steel production capacity by 60 million tonnes. Furthermore, the Governor of Hebei, Zhang Qingwei, has warned that any public official whom is found to be responsible for any additional tonnage of steel (or cement) making capacity will be fired.While closures of older and less efficient capacity in the traditional steel producing regions is expected, new capacity in the inland and western provinces is expected to open over the outlook period to meet the continued urban and economic expansion of these areas. These new steel plants are expected to be more efficient, produce less pollution and offset the loss in capacity from closures of older steel plants. Over the period 2015 to 2019, China’s steel production is projected to grow at an average rate of 1.8 per cent a year to total 875 million tonnes in 2019.Over the outlook period, India’s steel production is projected to increase at an average annual rate of 5 per cent and to total 109 million tonnes in 2019. The increase in steel production is expected to be bolstered by demand from both public producers, Steel Authority of India Limited (SAIL) and Rashtriya Ispat Nigam Limited (RINL), and private producers, Tata Steel, Essar Steel and Jindal Steel Power Limited (JSPL).In OECD economies, only a modest increase in steel production is projected to the end of 2019. Steel production in the US is projected to grow the strongest, at an average annual rate of 1.4 per cent a year to total 95 million tonnes in 2019, reducing its reliance on imports. Capacity utilisation rates at steel mills in the EU are expected to dip in the shorter term, before increases in consumption demand induces higher production. Steel production in the EU is projected to total 167 million tonnes in 2019.

Iron ore pricesIn 2013, iron ore spot prices FOB Australia averaged US$126 a tonne, an increase of 3.4 per cent relative to 2012. Spot prices have been declining through the first quarter of 2014, particularly in March due to a confluence of factors. These include: high inventories of ore at Chinese ports; a bearish sentiment emanating from declining construction and manufacturing activity in China; growing concerns over the use of iron ore as collateral for loans; the Haixin steel company loan repayment default; and kneejerk responses to a drop in imports in the oft-disrupted month in February (due to the timing of Chinese New Year). These factors culminated in the iron ore spot price falling 7 per cent in a single day in early March. The average FOB Australia spot price is still expected to average US$111 a tonne for the March quarter and recover later in 2014, led by increasing construction activity in the northern summer that should support a rebound in steel demand (particularly in light of recently announced government spending on urban development projects).

However, iron ore prices are not expected to recover to the high levels seen in 2013 due to the increased availability of supplies from new mines starting up in Australia in 2014. For the full year, the FOB Australia spot price is forecast to average $110 a tonne.The continued increase in seaborne supply through 2014 and 2015 is forecast to drive spot prices lower, to an average of US$103 a tonne in 2015. Price fluctuations are likely to lower prices at times through 2015, but the high cost of China’s domestic production is still expected to support a higher average price for the year. Any sustained period of CFR North China prices below US$100 a tonne should result in higher cost Chinese producers closing down mines if China’s announced market reforms extend to the iron ore industry.Over the remainder of the outlook period to 2019, continued growth in the availability of seaborne material, coming from large new developments in both Brazil and Australia, are projected to place further downward pressure on iron ore prices. In 2019 the average FOB Australia price is projected to be around US$87 a tonne (in 2014 US dollars).Figure 2: Iron ore prices, FOB AustraliaPlease refer to page 61 of the Resources and Energy Quarterly – March quarter 2014 PDF version.Sources: BREE; Bloomberg.

World trade in iron oreGlobal iron ore trade increased by 6 per cent in 2013 to total 1.23 billion tonnes. China imported an additional 75 million tonnes, while Australia supplied an additional 87 million tonnes. In 2014, world trade in iron ore is forecast to increase by 7 per cent, compared with 2013, to total 1.32 billion tonnes. Over the medium term, world iron ore trade is projected to increase at an annual average rate of 3.6 per cent to reach 1.57 billion tonnes in 2019 (see Table 2). The chief source of import demand is projected to originate in China; while additional exports are projected to come primarily from Australia and Brazil.Table 2: World iron ore trade (Mt)Please refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

Iron ore importsChina imported 86.8 million tonnes of iron ore in January, up 33 per cent year-on-year. Although imports were down to 61.2 million tonnes in February, a shorter month that contains Chinese New Year festivities, they were still up 9 per cent year-on-year. In 2014, China’s imports of iron ore are forecast to increase 6 per cent, relative to 2013, to total 872 million tonnes. Over the medium term, Chinese steel producers are expected to increase their reliance on imported ore. This is expected due to the projected increasingly abundant amount of high quality and comparatively cheap ores from international suppliers, particularly those in Australia and Brazil. As additional supply comes online in these countries and places downward pressure on traded prices, the low quality and high cost Chinese domestic ore is expected to be pushed out of the market. A North China delivered (real) price of US$100 a tonne is assessed as the price that higher cost Chinese producers will begin to exit the market. From 2015 to 2019, China’s imports are projected to grow at an average annual rate of 5 per cent, to total 1.12 billion tonnes—or around 70 per cent of world trade—in 2019.Imports into the EU are expected to dip in line with steel production before increasing in the latter part of the outlook period to total 128 million tonnes in 2019. Japan’s iron ore imports are projected to decrease by 0.3 per cent a year on average to total 134 million tonnes in 2019. South Korea’s imports are projected to increase at an average annual rate of 1.3 per cent a year over 2014 to 2019 to total 68 million tonnes in 2019. The moderation in import demand into these two economies is in proportion with changes in steel production.

Iron ore exportsIn 2014, Australia’s iron ore exports are forecast to increase by 19 per cent, compared with 2013, to total 687 million tonnes. The increase will be supported by forecast higher production from recently commissioned projects from Australia’s iron ore majors. This includes Rio Tinto’s recently completed Namuldi Expansion (26 million tonnes a year), Brockman 4 (stage 2; 18 million tonnes), Hope Downs 4 (15 million tonnes), Western Turner Syncline II (9 million tonnes); BHP Billiton’s Jimblebar project (35 million tonnes); and Fortescue’s Chichester (40 million tonnes) and Solomon hub expansions (60 million tonnes). These projects ramping up to full capacity, combined with CITIC Pacific’s Sino iron project (24 million tonnes) and Hancock Prospecting’s Roy Hill project (55 million tonnes), amongst

others, are projected to support continued growth in Australia’s iron ore exports. Over the remainder of the outlook period (2015 to 2019), Australia’s exports of iron ore are projected to grow at an average annual rate of 4.4 per cent, to reach 851 million tonnes in 2019 (see Figure 3).Brazil’s iron ore exports are forecast to increase by 9 per cent in 2014, relative to 2013, to total 361 million tonnes. Over the remainder of the outlook period, Brazil’s exports are projected to increase at an annual average rate of 6 per cent and to reach 486 million tonnes in 2019. The growth in exports is expected to be sourced primarily from expansions and new projects in the Carajas and South-East iron ore systems that are scheduled for completion over the medium term. The largest of these projects is Vale’s 90 million tonne annual capacity S11D, or Serra Sul, project that is scheduled to commence operation towards the end of the outlook period. A mining project of this size and technical complexity, however, can be susceptible to schedule delays.Figure 3: Major iron ore exportersPlease refer to page 63 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

In 2014, India’s net exports are forecast to total 11 million tonnes. Bans on mining in India’s key iron ore producing states are expected to continue to impact on production over the next few years. While the ban on exports from the Indian state of Karnataka has been lifted, production is still capped at 30 million tonnes a year. The Goan government expects iron ore mining in the state to resume around mid-2014. If mining does resume around this time, it is expected that production, and exports, will take some time to return to full capacity. The recently introduced 5 per cent export duty on iron ore pellets to discourage exports is also expected to limit India’s return to supplying seaborne markets.Over the remainder of the outlook period, India’s net exports of iron ore are projected to increase initially, as mining activity increases in response to relaxing and removal of mining bans. Later in the period, higher domestic requirements associated with higher domestic steel production are projected to reduce the quantities of ore available for export. In 2019, net exports are projected to total around 10 million tonnes. There is an upside risk to this projection which could occur if mining activity increases faster than expected.Exports from West Africa are not projected to have a significant impact on world markets within the outlook period. The large infrastructure investment required to enable large-scale exports of bulk commodities will be a limiting factor during a period likely to be characterised by more efficient allocation of capital, lower risk tolerances and higher expected returns on investment. Brownfield developments in established producing regions are assessed as a more commercially viable option for supplying the growing demand in key Asia-Pacific markets over the medium term.

Metallurgical coal pricesContract prices for high quality metallurgical coal for delivery in the March quarter 2014 settled at around US$143 a tonne, down from US$152 a tonne in the December quarter. Spot prices for the key steel making material have continued the slide that began in September 2013 and were trading as low as US$107 a tonne FOB Australia in mid-March. This is the closest to parity that the spot prices for 62 per cent iron ore and high quality metallurgical coal have been since they started trading on spot markets (see Figure 4). At these prices, a substantial portion of world metallurgical coal production is believed to be loss-making. As such, without marked decreases in mine cost structures, the prevailing price is not likely to be sustainable for current demand levels over the medium term. Nevertheless, for the remainder of 2014, contract prices are forecast to decrease further as loose market supply conditions continue. Contract prices are forecast to still trade at a premium on spot prices of around US$5–10 a tonne and to average US$128 a tonne for the year.Figure 4: Metallurgical coal premium to 62% iron ore spot price, FOB AustraliaPlease refer to page 65 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Metallurgical coal contract prices are forecast to rebound in 2015 as a protracted period of oversupply comes to an end through demand catching up and the closure of higher cost mines reducing world supply. Prices are forecast to average US$137 a tonne in 2015. Over the remainder of the outlook period, prices are projected to increase moderately, in 2014 US dollar terms, and to average around US$143 a tonne in 2019.Figure 5: Metallurgical coal benchmark prices, FOB AustraliaPlease refer to page 65 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

World trade in metallurgical coalIn 2013, world trade in metallurgical coal is estimated to have increased by 8 per cent to total 314 million tonnes. The large increase in supply is the result of the large amount of investment that occurred in the high-price post-GFC period. Australia contributed the most to additional supply (15 million tonnes), while China was the largest source of additional import demand (22 million tonnes).In 2014, world trade of metallurgical coal is forecast to grow by 2.2 per cent, relative to 2013, to total 321 million tonnes. Over the remainder of the outlook period, world trade is projected to increase at an average annual rate of 1.3 per cent to reach 343 million tonnes in 2019 (see Table 3). China is projected to have the largest growth in imports to 2019 while growth in exports is projected to be primarily sourced from Australia.Table 3: World metallurgical coal trade (Mt)Please refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

Metallurgical coal importsBetween 2014 and 2019, China’s imports of metallurgical coal are projected to increase at around 2.3 a year on average to reach 113 million tonnes in 2019. The most important factor driving import demand growth is that domestically produced coal in China is of lower quality and higher cost than imports. Furthermore, the Chinese Government has a metallurgical coal reservation policy that encourages the use of imports in an attempt to increase the longevity of its domestic reserves.India’s imports of metallurgical coal are projected to increase at an annual average rate of 1.2 per cent between 2014 and 2019 to reach 40 million tonnes in 2019. Imports into Brazil are projected to increase at an average annual rate of 2.4 per cent over the outlook period to total 15 million tonnes in 2018. Imports into the EU are projected to increase at an average of 1.7 per cent a year to total 44 million tonnes in 2019. The growth in imports into these economies is in line with projected increases in steel production, and in the case of the EU, flat indigenous metallurgical coal production.

Metallurgical coal exportsMetallurgical coal exports from Australia in 2014 are forecast to increase by 2.4 per cent to total 174 million tonnes. Over the period 2015 to 2019, Australia’s exports of metallurgical coal are projected to increase at an average annual rate of 2.2 per cent to reach 194 million tonnes in 2019 (see Figure 5). The growth will be supported by new and expanded mining projects such as BHP Billiton Mitsubishi Alliance’s (BMA) Caval Ridge (8 million tonnes a year) and Daunia projects (4.5 million tonnes); and Anglo American’s Grosvenor underground mine (5 million tonnes). Countervailing these increases will be the expected end of mine life at Vale and Sumitomo’s Issac Plains mine (around 3 million tonnes a year) from around 2018 and BMA’s West Cliff mine (2 million tonnes) from around 2016.Exports of metallurgical coal from Canada are projected to increase marginally over the medium term to total 36 million tonnes in 2019; while exports from Russia are projected to moderate to total 15 million tonnes in 2019. Exports from the US are projected to decline over the medium term to total 47 million tonnes in 2019. Lower prices, in response to a surplus of supply, over the past 18 months have largely removed the incentive to invest in new metallurgical coal projects worldwide. Accordingly, no new significant additions to world supply are expected to come from emerging suppliers in the short term.Figure 6: Major metallurgical coal exportersPlease refer to page 68 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Australian exportsIn 2013–14, Australia’s export volumes of iron ore are forecast to increase by 20 per cent, relative to 2012–13, to total 631 million tonnes. The surge in production will be supported by higher production from Rio Tinto, Fortescue and BHP Billiton. The value of Australia’s iron ore exports in 2013–14 is forecast to increase by 35 per cent to total $76.8 billion, underpinned by a trifecta of higher export volumes, stronger iron ore prices and a lower Australian dollar-US dollar exchange rate.Over the medium term, projected growth in export volumes from expansions to capacity at a number of mines, and the start-up of Hancock Prospecting’s Roy Hill project, will underpin growth in export volumes to 2018–19. Export volumes are projected to increase to 847 million tonnes in 2018–19 (see Figure 7), representing average growth of around 6 per cent a year over the outlook period. Iron ore

export values are projected to increase with volumes in the short term, before the price effect of lower projected prices bring down export values to $78.2 billion (in 2013–14 dollars) in 2018–19.Figure 7: Australia’s iron ore exportsPlease refer to page 69 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Australia’s metallurgical coal export volumes in 2013–14 are forecast to increase by 15 per cent to total 177 million tonnes. The large increase in volumes is expected to more than offset forecast lower received prices and result in export values increasing by 3.7 per cent to total $23.3 billion.Over the remainder of the outlook period export volumes of metallurgical coal are projected to increase at an average annual rate 1.8 per cent to total 193 million tonnes in 2018–19. Higher export volumes and projected higher prices are expected to result in export values from metallurgical coal increasing to $28 billion (in 2013–14 dollars) in 2018–19 (see Figure 8).Figure 8: Australia’s metallurgical coal exportsPlease refer to page 69 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 6: Steel, iron ore and metallurgical coal outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

GoldJohn Barber

PricesThe post GFC gold price bull run finally came to end in 2013 with the average gold price decreasing 15 per cent, relative to 2012, to US$1411 an ounce. Expectations for a tapering of the US Federal Reserve’s bond purchasing program (QE3) in May 2013 led many investors to reduce their gold holdings, particularly Exchange Traded Funds (ETF), and resulted in a substantial drop in prices through the remainder of the year. By the time the US Federal Reserve announced its planned tapering of bond purchases from US$85 billion a month to US$75 billion in December with a further $10 billion reduction announced in January, the gold market appeared to have already factored this in with prices relatively stable since November 2013. Lower gold prices appear to have stimulated a significant increase in gold purchases among non-institutional buyers, particularly jewellery purchases, which according to the World Gold Council increased substantially in the second half of 2013.Gold prices have rebounded by around 9 per cent since the start of 2014, from an initial price of US$1220 an ounce to around US$1330 an ounce in mid-March. The appeal of gold as a safe haven investment asset during periods of rising geopolitical tensions has been the principal supporter of prices over the past six months, first the civil war in Syria in the second half of 2013 and now tension in the Ukraine. For the remainder of 2014, the forecast continued improvement in economic conditions in the US is expected to strengthen the case for further easing of QE3 and lead to further declines in the price of gold. Despite forecast strong growth in jewellery purchases in China and other emerging markets, 2013 data indicates that this is highly price sensitive and is more likely to partially offset declining prices rather than support growth in prices.The US Federal Reserve’s bond purchases, which have supported higher gold prices since 2009, are expected to taper further over 2014 and 2015. This tapering, as well as the expectation of further net sales from institutional investors, is forecast to result in the average gold price decreasing by a further 10 per cent in 2014 to around US$1269 an ounce (see Figure 1). Prices are forecast to remain at similar levels in 2015, with the growth in jewellery purchases offsetting lower investment demand. After 2015 prices are projected to increase at an average annual rate of 0.5 per cent a year to an average of US$1304 (in 2014 US dollars) in 2019. Over this period, gold prices are expected to remain below the record high levels of the past four years (that were brought on by the distorting effects of QE3) and the gold market will start to be influenced more by demand and supply for real consumption (such as jewellery) instead of investment speculation. The net purchases of private investors as well as central banks will be a continuing risk over the outlook period. There remains considerable uncertainty in modelling the dynamics of swings in their net buying or selling patterns and these will continue to be both upside and downside risks to prices over the period.Figure 1: Quarterly gold pricesPlease refer to page 72 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

ConsumptionAccording to the World Gold Council, total world gold demand totalled 3756 tonnes in 2013, 15 per cent lower than 2012, as substantial increases in jewellery and physical bar purchases were more than offset by a decline in ETF purchases.Gold purchases for fabrication consumption increased considerably in the second half of 2013 in response to falling prices. Jewellery purchases were the main driver of this, increasing by 17 per cent to 2209 tonnes in 2013. China accounted for around half of the addition to world jewellery purchases in 2013, with consumption increasing by 29 per cent to 669 tonnes. This increase led to China overtaking India as the world’s largest consumer of gold. India’s jewellery purchases increased 11 per cent to total 613 tonnes in 2013. Together, China and India accounted for around 60 per cent of total world jewellery purchases in 2013.Private gold investment consumption was 51 per cent lower in 2013, relative to 2012, and totalled 773 tonnes. While bar and coin investment increased by 28 per cent to total 1654 tonnes, this was more than offset by the decline in ETF purchases. ETFs purchased around 279 tonnes of gold in 2012 but became a net seller of gold and reduced their gold holdings by 881 tonnes of gold in 2013 in

response to an anticipated tapering of the US QE3 bond purchasing program.Physical bar and coin investment increased in 2013, up 28 per cent to 1654 tonnes. This was underpinned by China increasing its bar and coin purchases by 38 per cent to 397 tonnes. Consumption of gold in electronics manufacturing, dentistry and other industrial applications proved to be less responsive to the drop in gold prices in 2013 and remained at similar levels to 2012.In 2014, world gold demand is forecast to rebound and increase by around 10 per cent to 4122 tonnes. Faced with the prospect of further tapering of QE3, ETFs are expected to remain a net seller in 2014 and place further downward pressure on gold prices. Growth in jewellery purchases is expected to moderate to 6 per cent and total around 2331 tonnes. This is underpinned by further growth in purchases by consumers in China in response to lower gold prices. However, it is expected to be mostly opportunistic buying and as such, highly price sensitive. While this will prevent prices from decreasing further, it is unlikely to support a recovery in gold prices to the high levels of the past five years. Gold purchases in India are forecast to increase, albeit at a lower rate than previous years. Factors working against higher gold demand growth in India are a rising domestic price due to a depreciating exchange rate offsetting the fall in international gold prices and a domestic tariff aimed at reducing gold imports to tackle India’s growing current account deficit.Over the period 2014 to 2019, world gold demand is projected to increase at an average annual rate of 4 per cent to total around 5119 tonnes. Based on forecast economic improvements in the US, QE3 is expected to taper further and eventually cease before the end of 2016. The resulting lower prices are projected to support continued growth in jewellery purchases, particularly in China and India. While incomes in these countries are projected to rise, the price sensitivity of gold purchasers is unlikely to change through the period.Investment demand for gold is expected to rebound over the outlook period in with lower prices making opportunistic buying appealing to investors that have positive expectations for a price rebound over the medium term. Proposed changes to gold trading regulations in China, if implemented will also lead to increased investment demand in the world’s largest purchaser of gold. Central banks are expected to remain net purchasers over the outlook period with the increase in emerging economies’ gold holdings more than offsetting the reductions in developed but remain below the high levels seen during the peaks of the US quantitative easing programs. ETFs are expected to return to being net purchasers of gold, though this will be a key risk affecting prices. A higher rate of purchases and subsequent higher prices will likely affect the jewellery purchases of consumers in India and China.

ProductionLower gold prices in the second half of 2013 increased the financial pressure on gold producers. The industry switch from reporting on C1 cash cost to an all-in sustaining cost has provided greater transparency about the commercial position of the world’s gold producers and shown that at the lower prevailing prices there is substantial commercial pressure on a number of mines. While some of the higher cost mines have been forced to close, more have embarked on cost cutting programs or focused on productivity improvements such as targeting higher ore grades. Several large mines began production during 2013 including the Pueblo Veijo mine in the Dominican Republic, the Tropicana mine Australia and Oyu Tolgoi mine in Mongolia. As a result, world gold mine production is estimated to have increased by 4.5 per cent to 2989 tonnes despite declining prices.While gold prices are forecast to decline further in 2014, increasing output at these new large mines as they approach full production and additional productivity gains at many existing mines are expected to offset any further mine closures. Accordingly, world gold production is forecast to increase by a further 2.7 per cent to around 3070 tonnes. China is expected to remain the world’s largest gold producer with its production increasing by 2.5 per cent to 448 tonnes in response to growing domestic demand for gold.Over the remainder of the outlook period, growth in world gold mine production is projected to slow in response to projected lower gold prices. Like many mineral commodities, attracting capital to large gold projects is expected to become increasingly difficult and limit the expansion of production capacity in the medium term. Gold producers are expected to focus their exploration and capital programs on lower cost brownfield expansions that extend or expand existing mines in an effort to reduce operating costs and provide a better return on investment. World gold mine production is projected to increase at an average annual rate of 0.8 per cent from 2014 to 2019 to total around 3194 tonnes.

AustraliaMine ProductionIn 2013–14 Australia’s gold production is forecast to increase by 6 per cent, relative to 2012–13, to 271 tonnes. Australian gold producers have not been immune to the changing commercial environment associated with the decline in gold prices in 2013. While some Australian mines have been placed on care and maintenance, most Australian gold companies have seen positive results from cost cutting initiatives and are reporting lower all-in sustaining costs for the fourth quarter of 2013 with most expecting further reductions. At these costs, most existing Australian producers are expected to continue producing at similar levels to 2013 or increase production by targeting higher grade ore. Higher production in 2013–14 will also be supported by the commissioning of the Anglogold Ashanti-Independence joint venture Tropicana gold mine in Western Australia in late 2013. Tropicana has annual capacity of around 14 tonnes and is one of the largest gold mines to open in Australia in recent years. Productivity gains and an increasing production profile at the Tropicana mine will underpin further production gains in 2014–15, with Australia’s total mined gold production forecast to increase by 1 per cent to 273 tonnes.Over the outlook period to 2018–19, few new major gold mines are expected to open in Australia. The development plans of domestic producers are instead expected to focus on exploring deposits around existing facilities to extend their operational life and minimise the requirement for further capital expenditure. Combined with further cost cutting programs, these brownfield expansions are expected to underpin further growth in Australian gold mine production, which is projected to increase at an average annual rate of 1.3 per cent (despite lower gold prices) to 288 tonnes in 2018–19.

ExportsIn 2013–14, Australia’s gold exports are forecast to decline by 0.4 per cent to around 279 tonnes as higher gold production is expected to be offset by a moderate decline in imports of gold dore for processing and re-export. Export values are forecast to decrease by 13 per cent, relative to 2012–13, to $13.1 billion due to the lower gold price.Over the outlook period to 2018–19, projected growth in domestic gold production will underpin Australia’s gold exports increasing at an average annual rate of 1.7 per cent to 303 tonnes in 2018–19. The combination of higher export volumes, a moderate rebound in gold prices and assumed lower Australian dollar exchange rate is expected to result in the value of Australia’s gold export values increasing at an average annual rate of 2.2 per cent to $14.6 billion (in 2013–14 dollars) in 2018–19.Figure 2: Australia’s gold exportsPlease refer to page 75 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 1: Gold outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

AluminiumSimon Cowling

PricesThe spot price of aluminium declined by 8 per cent to average US$1847 a tonne in 2013 as strong growth in production and moderate consumption growth resulted in rising stocks. At the end of 2013, world aluminium stocks were 7.2 million tonnes or 8.0 weeks of consumption. Prices declined progressively from a high of US$2123 a tonne during February 2013 to a low of US$1695 in early December (see Figure 1). Despite aluminium consumption increasing in 2013, aluminium prices were influenced by high London Metal Exchange (LME) stocks. When prices peaked during February, LME stocks equalled around 5.15 million tonnes. LME stocks totalled more than 5.47 million tonnes in December when prices fell below US$1700.Figure 1: Quarterly aluminium prices Please refer to page 77 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

In 2014, the aluminium spot price is forecast to decline by a further 2.9 per cent to average US$1794 a tonne (see Figure 2). The aluminium spot price averaged around US$1721 a tonne in the first quarter of 2014 due to weaker domestic prices in China, higher metal exchange stocks and record aluminium warehouse premiums. The aluminium spot price fell to US$1650 in early February, the lowest spot price in four and a half years, and LME stocks totalled around 5.42 million tonnes. Spot prices are expected to rise progressively over the remainder of 2014 as production curtailments implemented during 2013, such as in Russia, Canada, and the US, will limit production growth and contribute to declining stocks. Total stocks (including both LME and other bonded warehouses) are forecast to be 7.1 million tonnes or 7.7 weeks of consumption at the end of 2014.Over the remainder of the outlook period (2015 to 2019), the aluminium spot price is projected to increase at an average annual rate of 2.9 per cent to US$2071 (in 2014 dollars) in 2019 (see Figure 2). Consumption growth is projected to remain robust, driven by growing demand for automobiles and aluminium-intensive consumer products in response to rising incomes associated with the growing middle classes of key Asia-Pacific economies. This will be partly offset by the expected start-up of new, efficient smelters in Asia, which will contribute to production growth.Figure 2: Annual aluminium prices and stocksPlease refer to page 78 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

ConsumptionWorld aluminium consumption was 46.4 million tonnes in 2013, an increase of 2.0 per cent relative to 2012. Asian economies continue to be the largest consumers, offsetting falling consumption in Europe and the US because of reduced economic growth and challenging market conditions in aluminium-intensive industries. China’s aluminium consumption increased by around 8 per cent to 22 million tonnes, accounting for 47 per cent of total global consumption in 2013. Production of automobiles in China increased by 24 per cent to 23.9 million units in 2013.Substantial consumption decreases in Poland (45 per cent compared to 2012), Belgium (32 per cent) and Spain (25 per cent) underpinned total European consumption declining by 2.8 per cent to 7.7 million tonnes. US consumption was 4.7 million tonnes, a decrease of 3.4 per cent relative to 2012. Reduced automobile production and muted growth in sales of aluminium-intensive products drove the decrease.In 2014, world aluminium consumption is forecast to increase by around 4.0 per cent to 48.3 million tonnes, underpinned by continuing consumption growth in Asia and a recovery in demand in the US and Europe. China’s consumption is forecast to increase by 4.8 per cent to total 23 million tonnes. Expanding automobile production is being driven by increased consumer demand for vehicles as income rises. Ongoing infrastructure development and growth in household income are expected to contribute to India’s consumption increasing by around 7 per cent to 1.7 million tonnes. The US is forecast to increase consumption by around 4.6 per cent to total 4.9 million tonnes, supported by a recovery in automobile production and continuing construction industry growth. Total European consumption is forecast to total 7.8 million tonnes, an increase of around 1.2 per cent, driven by a gradual improvement in economic conditions.

World aluminium consumption is projected to increase at an average annual rate of around 3.7 per cent over the outlook period, to around 57.8 million tonnes in 2019. Consumption growth in China and other emerging Asian economies is expected to underpin the increase. Further supporting the increase will be consumption growth in the US, driven by an ongoing recovery in the automotive and construction industries. Moderate growth is projected in Europe, with gains predominantly coming from countries within the EU.Over the medium term, aluminium consumption in China is projected to increase at an average annual rate of around 4.9 per cent to 29.3 million tonnes. Growth in construction and automobile production, albeit at a moderated pace compared to 2013, are expected to be the principal factors driving the increase. Demand for automobiles is projected to increase in the medium term as household incomes continue to rise, with car ownership often perceived as a symbol of prestige by the middle class.US consumption is projected to increase at an average annual rate of 3.4 per cent to 5.7 million tonnes in 2019. While moderating compared with 2013, housing starts are projected to remain strong in the medium term as economic growth and conditions improve. US automobile production is expected to recover over the outlook period, with changes to environmental standards and consumer preferences encouraging manufacturers to increase fuel efficiency and reduce vehicle weight.Over the medium term, aluminium consumption in Europe is projected to increase at an average annual rate of 1.2 per cent to 8.3 million tonnes. The continuing impacts of austerity measures are expected to limit growth over the outlook period. Moderate improvement in economic conditions and slight recovery in automobile demand is projected to drive a consumption increase in Germany where consumption is projected to increase by an average annual rate of 1.2 per cent to 2.2 million tonnes in 2019.

ProductionIn 2013, world aluminium production increased by 4.0 per cent to 48.2 million tonnes despite production curtailments and closures aimed at correcting market oversupply. Production cuts within Europe, the US, and Australia were more than offset by the commissioning of new capacity in Asia and the Middle East.China was the largest contributor to growth, with production increasing 9 per cent relative to 2012 to 22 million tonnes. Higher output due to projects located in the northwest provinces near cheaper energy sources coming online and increasing production underpinned the increase. Combined production in the Xinjiang and Qinghai provinces increased from around 1.05 million tonnes in 2008 to 4.64 million tonnes in 2013, an absolute increase of 340 per cent (see Figure 3). If these two provinces were considered a separate country, its 2013 production would be the second highest in the world behind the rest of China, with Russia third (4.0 million tonnes). The large increases in production from these northwest provinces offset an estimated 2 million tonnes of capacity reductions at older, inefficient operations. These closures were driven by cost pressures, oversupply, and environmental targets outlined within China’s 12th Five-Year plan.Production curtailments and closures in response to rising costs, weaker prices and oversupply underpinned production decreases in Europe and the US. Total European aluminium production declined by 1.2 per cent to 8.4 million tonnes, while US production fell by 6 per cent to 1.9 million tonnes. Canada’s production increased 7 per cent to total 3.0 million tonnes despite production curtailments and closures, including Rio Tinto’s Shawinigan smelter (100 000 tonnes). Increased output from Rio Tinto Alcan’s Alma smelter (440 000 tonnes) supported the increase, as production returned to capacity following a seven month lockout at the smelter in 2012 over working conditions.Aluminium production is forecast to remain steady in 2014 as production increases in China are offset by further production curtailments and closures in the rest of the world. Aluminium production in China is forecast to increase by 6 per cent to 23.3 million tonnes, despite expected persistent market oversupply. Recently commissioned smelters and production increases in the northwest provinces, in addition to possible restarts at idled capacity will be the principal drivers of the growth. As at the end of 2013, China’s production capacity was estimated at around 31 million tonnes, indicating an utilisation rate of around 71% was achieved in 2013. Production capacity is forecast to total around 33 million tonnes by the end of 2014, offsetting further reductions and closures at out-dated operations within China.Figure 3: Chinese aluminium production by region, 2008 and 2013Please refer to page 81 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Production in the rest of the world is expected to decrease as curtailment programs by major

aluminium producing companies take effect. In May 2013, Alcoa placed around 460 000 tonnes of capacity under review as unfavourable market conditions and oversupply plagued the market. Following the February 2014 closure announcement of the Point Henry smelter in Australia (190 000 tonnes), Alcoa’s total announced capacity curtailments or closures amount to around 551 000 tonnes. In October 2013, Rusal announced that through already implemented and planned cuts, production capacity would decline by around 650 000 tonnes at the end of 2014, or 15 per cent of 2012 production volume. Additional unannounced capacity reductions of around 1.5 million tonnes are expected to occur in 2014. As a result of the capacity reductions, production in Europe (11 per cent to 7.4 million tonnes), the US (9 per cent to 1.8 million tonnes) and Canada (7 per cent to 2.8 million tonnes) is forecast to decrease.Over the outlook period production capacity expansions in China and Asia, where input costs are lower, are projected to support a 3.1 per cent annual average increase in world production to 57.9 million tonnes in 2019. Expected rises in energy and production costs are projected to mute potential growth in OECD economies in the medium term.Increased production in China’s northwest provinces will underpin projected production of 29.3 million tonnes in 2019, an average annual increase of 4.9 per cent. New projects coming online and increased production at existing smelters will be supported by access to low-cost coal-fired electricity over the outlook period. An additional 15–20 million tonnes of aluminium capacity is planned to be developed in Xinjiang by 2020. However this will be partially offset by efforts to curb production at inefficient and outdated smelters in heavily industrialised provinces over the outlook period. Production in India is projected to increase at an average annual rate of 17 per cent to 4.1 million tonnes in 2019, supported by the commissioning of a number of large-scale projects over the outlook period, headlined by Vedanta’s 1.25 million tonne Jharsuguda II project. Increased capital investment and comparatively cheaper energy costs will support increased production in the Middle East in the medium term which is projected to increase at an average annual rate of 9 per cent to 7.8 million tonnes.Over the outlook period, production in Canada and the US is projected to remain steady. Increased output from more efficient operations is projected to offset additional production closures at smelters operating at the higher end of the cost curve. Energy costs in the medium term are expected to rise, despite the emergence of shale gas as an input into electricity generation.Aluminium production in Europe is projected to decrease over the outlook period at an average annual rate of 1.1 per cent to 7.8 million tonnes. The decrease will be driven by higher production costs and subdued demand, leading to further production curtailments over the outlook period. Russia, the largest European producer, is projected to decrease production at an average annual rate of 0.8 per cent to 3.8 million tonnes. No significant production growth is projected in any European country in the medium term.

AustraliaProductionIn 2013–14, Australia’s aluminium production is forecast to decrease by 1.5 per cent to 1.8 million tonnes, driven by the closure of Alcoa’s Point Henry smelter and reduction in output at Rio Tinto’s Boyne Island smelter. In February 2014, Alcoa announced that the Point Henry aluminium smelter in Victoria (190 000 tonnes a year) would gradually reduce output before closing in August 2014 because it had become financially unviable. Production at Rio Tinto’s Boyne Island smelter (570 000 tonnes a year) is estimated to be 10 per cent lower in the March quarter as high electricity costs in Queensland have made production uneconomic. Production is expected to return to capacity in the following quarter.Over the outlook period (2013–14 to 2018–19), Australia’s aluminium production is projected to decrease at an average annual rate of 2.0 per cent to 1.6 million tonnes, underpinned by the full effect of the reduction in production capacity as a result of the Point Henry closure. Additional minor production curtailments over the outlook period are projected as the result of rising energy and supply costs. No new smelters are expected to be developed in Australia in the medium term.

ExportsAs a result of lower forecast production volumes in 2013–14, Australia’s aluminium exports are forecast to decrease by 0.8 per cent to 1.6 million tonnes. In line with reduced export volumes, export earnings are forecast to decrease by 0.9 per cent to $3.2 billion (see Figure 4). A forecast higher Australian dollar price for aluminium is expected to only marginally offset the volume decreases.

Australia’s aluminium export volumes are projected to decrease at an average annual rate of 1.9 per cent from 2013–14, to 1.4 million tonnes by the end of the outlook period. Export earnings are projected to remain stable at around $3.3 billion (in 2013–14 dollar terms) as lower export volumes are offset by projected higher Australian dollar prices.Figure 4: Australia’s aluminium exportsPlease refer to page 84 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

AluminaPricesCounter to the lead of its downstream product, aluminium, alumina spot prices increased by 2.6 per cent in 2013 to US$327 a tonne. Forecast ongoing global aluminium price falls and alumina market oversupply will continue to place downward pressure on alumina prices over the next year. As a result, alumina prices are forecast to decrease by 0.7 per cent to average US$325 a tonne in 2014 (see Figure 5). Increased alumina production in China is forecast to underpin the increase. China’s alumina capacity is expected to increase from around 60 million tonnes in 2013 to total around 66 million tonnes by the end of 2014. Over the remainder of the outlook period, prices are projected to increase at an average annual rate of 0.6 per cent to US$334 a tonne (in 2014 dollars), in line with projected moderate rebound in aluminium prices. Large scale production increases in China over the medium term to support additional aluminium capacity will limit additional price growth and exacerbate market oversupply. Production will be supported by recently commissioned projects in the province of Shanxi, including the Chiping Xinfa Group refinery (5 million tonnes a year), the new Chalco refinery (1 million tonnes) and Zhaofeng Aluminium’s new production lines (700 000 tonnes expansion), reaching full scale production.Figure 5: Annual alumina pricesPlease refer to page 85 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Australia’s alumina productionIn 2013–14, Australia’s alumina production is forecast to decrease by 0.9 per cent to 21.5 million tonnes driven by lower production at Rio Tinto’s Gove refinery in the Northern Territory ramping down output before the full suspension of operations at the refinery in June. Steady output at Rio Tinto’s Yarwun refinery in Queensland is expected partially offset lower production from Gove. As a result of the closure of Gove, Australia’s alumina production is projected to decrease at an average annual rate of 1.3 per to 20 million tonnes by 2018–19. Projected increases in operating costs and no new additional capacity coming online will support additional minor production reductions.

Australia’s alumina exportsLower production and subdued overseas demand are expected to support a forecast decrease in Australia’s alumina exports in 2013–14. Exports are forecast to decrease by 3.8 per cent to 18.2 million tonnes (see Figure 6). Over the outlook period, exports are forecast to decrease at an average annual rate of 1.9 per cent to 16.9 million tonnes in 2018–19, in line with lower production volumes.Australia’s alumina export values are forecast to increase by 5 per cent to total $5.6 billion dollars in 2013–14 as forecast higher Australian alumina prices more than offset the reduction in volumes. Export earnings are projected to increase at an average annual rate of 2.8 per cent to $6.5 billion (in 2013–14 dollars) in 2018–19. Reduced production is projected to be offset by further rises in the Australian dollar price for alumina.

Bauxite exportsAustralia’s bauxite export volumes are forecast to increase by 34 per cent in 2013–14, to 16.8 million tonnes. The January 2014 implementation of the Indonesian export ban on bauxite, and reduction in domestic consumption following the closure of alumina refining capacity will be the principal contributors to the increase.In January 2014, the Indonesian government implemented a ban on the export of ores and concentrates designed to boost domestic economic growth through value adding activities. Various conditions and timeframes for the ban apply across different ores and concentrates; however the ban on the export of bauxite and nickel ore is immediate. Assuming current arrangements remain in

place, the Indonesian export ban is projected to support an increase in demand for Australian bauxite over the remainder of the outlook period. This will be met by higher output from new mines, including Rio Tinto’s South of Embley project (22.5 million tonnes a year) in Queensland. As a result, Australia’s bauxite exports are projected to increase at an average annual rate of 6 per cent to total 22.4 million tonnes in 2018–19.In 2013–14, Australia’s bauxite export earnings are forecast to increase by around 56 per cent to $594 million dollars, driven by growth in export volumes. Australia’s export earnings are forecast to increase in line with export volumes over the outlook period to total $698 million (in 2013–14 dollars) in 2018–19.Figure 6: Australia’s alumina exportsPlease refer to page 86 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 1: Aluminium outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

CopperJohn Barber

PricesIn 2013 the average LME copper price decreased by 8 per cent, relative to 2012, to US$7326 a tonne (see Figure 1). The LME copper price peaked at US$8243 in February and then declined to a low of US$6637 in June before recovering to finish 2013 at around US$7395. A surplus of refined copper and growing bearish sentiment towards the economic outlook for China, the world’s largest consumer of copper, weighed on prices throughout 2013. While production exceeded consumption, world copper stocks decreased throughout the year to finish 2013 at around 908 000 tonnes, or 2.2 weeks of consumption. Reduced holdings at the Shanghai Futures Exchange were the major contributor to the decline in world copper stocks. Given the widespread practice of using copper as collateral on loans in China, the lower reported SHFE stocks may have potentially moved to an unreported stock holding rather than be consumed.Figure 1: Quarterly copper pricesPlease refer to page 88 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

The copper market is expected to remain in surplus in 2014, retaining downward pressure on copper prices. Although consumption is forecast to increase, continued expansion in China’s copper refining capacity should more than offset the mandated closures of older refineries and result in higher world refined copper production. Copper prices have become increasingly influenced by external macroeconomic factors in recent years due to the practice of Chinese companies using copper stocks as collateral to secure finance agreements. Finance sector and exchange rate reforms in China are likely to reduce this practice and result in weaker investment demand for copper. Increasing market pessimism over China’s economic growth and a forecast rebound in the US dollar are also expected to push copper prices lower in 2014. The LME copper price has already declined by 13 per cent since the start of the year to around US$6500 in mid-March. For the year as a whole, copper prices are forecast to average US$6826 a tonne in 2014, 7 per cent lower than 2013. Total world copper stocks are forecast to increase to around 1.2 million tonnes, or 2.9 weeks of consumption at the end of the year.A persistent surplus of refined copper production is expected to contribute to further price decreases in 2015. The average annual LME copper price is forecast to decline by 4.6 per cent to US$6643 a tonne. Total world copper stocks are forecast to increase to around 3.4 weeks of consumption at the end of 2015 (see Figure 2). Over the remainder of the outlook period, the combination of slower growth in refined copper production and stronger growth in copper consumption in emerging economies is expected bring a tighter market balance and lead to a moderate rebound in copper prices. From 2015 to 2019, copper prices are projected to increase at an average annual rate of 1.5 per cent to around US$6906 a tonne (in 2014 dollar terms).Figure 2: Annual copper prices and stocksPlease refer to page 89 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

ConsumptionTotal world copper consumption increased 4.7 per cent, relative to 2012, to total 21.0 million tonnes in 2013. China remained the world’s largest consumer of copper and increased its share of world consumption from 44 per cent in 2012 to 47 per cent in 2013. In fact, almost all growth in world copper consumption in 2013 can be attributed to China. Excluding China, the rest of the world’s copper consumption decreased 0.4 per cent in 2013. While moderate rebounds in copper consumption are forecast for the rest of the world as economic activity in OECD economies recovers in 2014, China is expected to remain the dominant driver of growth in copper consumption. World copper consumption is forecast to increase a further 4.0 per cent in 2014 to total 21.8 million tonnes, with China accounting for more than three quarters of this growth. Over the remainder of the outlook period, China and emerging economies are expected to remain the major sources of growth in world copper consumption. Between 2014 and 2019 world copper consumption is projected to increase at an average annual rate of 3.5 per cent to 25.9 million tonnes in 2019.China’s copper consumption is forecast to increase 5.8 per cent in 2014 to total 10.4 million tonnes and then grow at an average annual rate of 4.9 per cent from 2015 to total 13.2 million tonnes in

2019. Based on this projected growth rate, China will account for around 51 per cent of world copper consumption in 2019 and it will consume six times as much copper as the US and three times as much as all of Europe. Over the outlook period continued growth, albeit at slowing rates, in construction activity and the expansion of electricity networks associated with rising urbanisation will underpin higher copper consumption in China. Expected shifts in its industrial base towards producing more high value-add and technologically advanced products, such as cars and consumer electronics, will also support higher copper consumption. Financial sector reforms are expected to reduce the role of copper purchases for use as collateral in loans, but as these are a minor portion of China’s copper consumption the effect on consumption growth should be minimal.US copper consumption is still yet to fully rebound from the impacts of the global financial crisis (GFC). Although consumption in 2013 increased 0.3 per cent, compared to 2012, to total 1.84 million tonnes; it was still 13 per cent lower than the pre-GFC consumption in 2007. Over the outlook period, the projected improvements in the US economy, particularly increasing construction activity and to a lesser extent, manufacturing, are expected to support moderate growth in copper consumption. In 2014, US copper consumption is forecast to increase 1.7 per cent to total 1.87 million tonnes. Over the remainder of the outlook period, copper consumption is projected to grow at an average annual rate of 1.6 per cent to total 2 million tonnes in 2019.Copper consumption growth in other advanced economies had been declining prior to the GFC because their developed electrical and telecommunications networks and low population growth rates had stymied construction activity. As such, consumption in these economies is not expected to rebound significantly. Over the outlook period, Europe’s copper consumption is expected to increase at an average annual rate of 1.9 per cent, primarily as a result of growing industrial production in Germany and Eastern European nations. However, Europe’s copper consumption is projected to remain below its pre-GFC and Euro-zone debt crises levels for the outlook period. In Japan and South Korea, copper consumption is projected to remain at similar levels to 2013 with average annual growth rates of 0.1 per cent and 0.7 per cent, respectively. While these two economies have previously had higher consumption levels, increasing competition for their copper-intensive manufactured goods, particularly cars and electronics, is expected to increase and limit growth in their copper consumption.Over the outlook period India and other emerging economies are expected to have higher levels of copper consumption as they continue to develop communications and electricity infrastructure. In India, investment in its electricity distribution networks and growing industrial production will support higher copper consumption, which is projected to increase at an average annual rate of 5.1 per cent from 2013 to total 567 000 tonnes in 2019.

ProductionMine productionIn 2013, estimated world copper mine production had its largest year-on-year increase in a decade. Total production, in terms of metallic content, increased 7.4 per cent, relative to 2012, to total 18.3 million tonnes. Higher production at mines in Chile and China as well as the commissioning of new large mines in Mongolia, the Democratic Republic of Congo (DRC) and Zambia more than offset the lost production from incidents at the Grasberg mine in Indonesia and Bingham Canyon in the US. Chile remained the world’s largest copper producer in 2013 and accounted for 31 per cent of total mined production.World copper mine production is forecast to increase a further 4.4 per cent in 2014 to total 19.1 million tonnes. The continued increase in production towards capacity at recently started large mines such as the Oyu Tolgoi mine in Mongolia, Antapaccay mine in Peru and Konkola mine in Zambia as well as a return to full production at Freeport McMoran’s Grasberg mine are expected to underpin the increase. The stability of industrial relations at key South American producers will be a key risk to the 2014 production forecast and may result in lower production at large mines. Mined copper production is not forecast to fall in Indonesia in response to the policies implemented in January 2014 to encourage higher rates of onshore metals refining but remains a risk if negotiations with key producers to invest in new refineries break down.Over the outlook period to 2019, world copper mine production is projected to increase at an average annual rate of 4.6 per cent to total around 24 million tonnes in 2019. This will be driven mainly by substantial production growth in Peru, Zambia and the DRC. Chile is expected to remain the world’s principal supplier of copper, accounting for around 25 per cent of world production. With fewer large-scale projects expected to be completed in Chile over the outlook period, growth in is mined copper production will moderate. From 2014 to 2019, Chile’s mined copper production is forecast to increase

at an average annual rate of around 1 per cent to total 6.1 million tonnes in 2019.Mined copper production in Peru is projected to increase at an average annual rate of 13 per cent from 2014 to total 2.8 million tonnes in 2019. The opening of the Las Bambas mine will be the main driver of the projected increase and will add around 400 000 tonnes of production capacity following its expected start up in 2015. While Glencore-Xstrata is required to sell the project as part of the conditions of its 2013 merger, this is not expected to impact its opening or production over the outlook period. Higher production in Peru will also be supported by continued production increases from new mines such as Chinalco’s Toromocho mine (275 000 tonnes capacity) and Glencore-Xstrata’s Antapaccay mine (160 000 tonnes capacity), along with production expansions at a number of existing mines.In Zambia and the DRC, copper mine production is projected to grow at average annual rates of 10 per cent and 8 per cent, respectively. Production in Zambia is projected to total 1.5 million tonnes in 2019, underpinned by new production from the commissioning of First Quantum Minerals’ Sentinel mine (300 000 tonnes capacity) and higher production from existing mines such as Vedanta’s Konkola mine (250 000 tonne capacity). No new large scale mines are expected to be developed in the DRC during the outlook period and projected higher production is expected to come from the existing operations such as Glencore-Xstrata’s Kamoto (300 000 tonnes capacity) and Mutanda (200 000 tonnes capacity) mines as they increase output towards full capacity.

Refined productionWorld refined copper production totalled 21.4 million tonnes in 2013, 5.5 per cent higher than 2012. In 2014, refined copper production is forecast to increase by a further 3.4 per cent to 22.2 million tonnes. Continued growth in China’s copper refining capacity is forecast, with new refineries starting production more than offsetting the directed closures of older facilities under new environmental guidelines.As with other metal commodity markets, the rapid expansion of China’s domestic copper refining industry is expected to displace production in other parts of the world. Production curtailments and closures as witnessed in the aluminium industry are yet to occur in the copper market, but with further expansions planned in China it is anticipated that commercial pressure will increase and lead to closures in the future. Over the outlook period, world refined copper production is projected to increase at an average annual rate of 3.3 per cent to total 25.7 million tonnes in 2019. Around two-thirds of the projected increase in refined copper production will come from new refineries in emerging economies in Asia, particularly China.

AustraliaMine productionAustralia’s copper mine production is forecast to increase 1.6 per cent in 2013–14, relative to 2012–13, to 985 000 tonnes. This is mainly the result of marginally higher production rates at existing mines with no new large mines expected to start production during the year. Lower copper prices are not expected to significantly affect production in 2013–14, with most Australian producers still operating at costs below current prices. In 2014–15 Australia’s copper mine production is forecast to increase by 10 per cent to 1.1 million tonnes, underpinned by initial production at CuDeco’s Rocklands mine in Queensland and marginally higher production at most existing mines.Australian copper mine production is projected to total around 1.2 million tonnes by 2018–19, an average annual increase of 4.8 per cent over the outlook period. The expected development of Rex Resources’ Hillside (70 000 tonnes capacity) and Oz Minerals’ Carrapateena (100 000 tonnes capacity) projects over the outlook period, as well as moderate increases through improved efficiencies at a number of mines, are expected to offset planned closures and reduced production due to lower mineral grades. This production projection does not include higher output from the expansion of BHP Billiton’s Olympic Dam mine as the schedule and output for the project are still uncertain.

Refined productionAustralia’s refined copper production is forecast to increase by 5.1 per cent to total 477 000 tonnes in 2013–14 following the return to full production at BHP Billiton’s Olympic Dam and Glencore Xstrata’s Townsville refineries after production disruptions in 2012–13.The Townsville copper refinery’s scheduled closure in 2016 is projected to result in a decrease in Australian refined copper production over the outlook period. This is indicative of the emerging global

trend of metals refining shifting to emerging economies where production costs are lower and they aim to have the higher value adding activities located domestically to support their economic growth. Australia’s refined copper production is projected to decrease to 220 000 tonnes in 2018–19. No new Australian refined copper projects are expected to start in the medium term.

ExportsIn 2013–14, Australian copper exports (in metallic content) are forecast to increase by 1.4 per cent to 989 000 tonnes. Higher exports of refined copper, underpinned by a large spike in export volumes to China in December 2013, will offset lower exports of ores and concentrate. Australia’s copper export earnings are forecast to increase 4.8 per cent in 2013–14 to around $8.4 billion. Lower world copper prices are expected to be partially offset by a lower Australian dollar exchange rate.Over the remainder of the outlook period, higher mined copper production is expected to result in a commensurate increase in exports of ores and concentrates. The closure of the Townsville copper refinery will lead to lower exports of refined copper, with the feedstock expected to be exported as ores and concentrates. From 2014–15 to 2018–19, the volume of Australia’s copper exports (by metallic content) is projected to increase at an annual average rate of 4.8 per cent to 1.2 million tonnes in 2018–19. The combination of higher export volumes and a forecast increase in the Australian dollar price of copper will contribute to the value of Australia’s copper exports increasing at a projected annual average rate of 8 per cent to $12.8 billion (in 2013–14 dollars) in 2018–19 (see Figure 3).Figure 3: Australia’s copper exportsPlease refer to page 94 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 1: Copper outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

NickelTom Shael

WorldThe London Metal Exchange (LME) price for nickel averaged US$13 909 a tonne in the December quarter 2013, around the same level as in the September quarter. For 2013 as a whole, LME nickel prices averaged US$15 025 a tonne, down 14 per cent year-on-year. The substantial decrease in nickel prices in 2013 was a result of a surplus of refined production over consumption. Refined nickel production increased by 11 per cent, relative to 2012, to total 1.94 million tonnes; while consumption increased by 7 per cent to total 1.77 million tonnes. The excess supply resulted in stocks increasing to more than 10 weeks of consumption. The increase in stocks of refined nickel, as well as stockpiles of Indonesian nickel ore in China, can be largely attributed to pre-emptive activity leading up to the Indonesian Government’s ban the exportation of unprocessed raw materials that came into effect on 12 January 2014.The Indonesian government mandated ban, intended to increase the value adding that occurs domestically, imposes a minimum metal content on nickel products that must be met before exportation is permitted. It requires a nickel content of at least 70 per cent for nickel matte, 10 per cent for ferronickel, 4 per cent for nickel pig iron (NPI) and 93 per cent for nickel metal. As a result of this export ban, Indonesia’s nickel mine production is forecast to decrease to around 150 000 tonnes in 2014. This is around a third of 2013 and 2012 production levels (477 000 tonnes and 460 000 tonnes, respectively), and around a half of 2011 levels (297 000 tonnes).Indonesia has been the largest supplier of nickel ore to China’s NPI industry. Although there are large stockpiles of Indonesian nickel ore in China, it is not expected to be sufficient to support output levels comparable to 2013 throughout all of 2014. Some of the shortfall of required laterite ore is forecast to be met with increased exports from the Philippines. However, the size of the drop in Indonesia’s exports and the lower quality of Filipino ore is forecast to result in a 9 per cent drop in China’s refined nickel production to around 630 000 tonnes in 2014.Overall, world refined nickel production in 2014 is forecast to decrease by 7 per cent to total 1.81 million tonnes. Consumption is forecast to increase by 2.3 per cent to total 1.81 million tonnes, which is not expected to lead to a significant decline in stocks of refined nickel. Nickel prices are forecast to decline a further 2 per cent in 2014 to US$14 849 a tonne with stocks remaining high at around 10 weeks of consumption (see Figure 1).Figure 1: Annual nickel prices and stocksPlease refer to page 97 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

In 2015, continuing production curtailments at existing nickel refineries is forecast to offset new capacity due to come online resulting in a 4.7 per cent decrease in refined output to 1.72 million tonnes. Consumption, however, is forecast to grow at 1.6 per cent to total 1.84 million tonnes. The resulting market deficit is forecast to result in a drawdown of stocks to around 7 weeks of consumption (233 000 tonnes). As a result, prices are expected to increase to around US$16 600 a tonne in 2015.Over the remainder of the outlook period (2016 to 2019), consumption is projected to increase at an average annual rate of 1 per cent to reach 1.92 million tonnes in 2019. Growth in refined production is projected to grow at an average rate of 2.7 per cent a year to total 1.92 million tonnes by the end of the period. Higher mine output from the Philippines and an expected increase in production in Indonesia are projected to facilitate a return to growth in China’s NPI production. Stocks are projected to remain at around 5 weeks of consumption and annual average prices at around US$17 000 a tonne (in 2014 US dollars) over the period 2016–2019. This assumes the Indonesian export ban will remain in place as currently announced. If the ban is reduced in severity or removed, there is an upside risk to Indonesia’s mine output. Subsequently this would affect China’s NPI production rates and place further downward pressure on world nickel prices.

AustraliaProductionNickel mine production in Australia in 2013–14 is forecast to fall by 11 per cent to total 215 000

tonnes. Australia’s refined nickel production is forecast to increase by 2.2 per cent in 2013–14 to total 138 000 tonnes as a result of a higher proportion of nickel class 1 production relative to nickel ores and concentrates.Over the remainder of the outlook period Australia’s nickel mine production is projected to moderate down to total 209 000 tonnes in 2019. Mine production is projected to trough in 2014–15 at around 203 000 tonnes before higher world nickel prices and the expected start-up of new nickel mines in Western Australia, Queensland and Tasmania lead to higher mine production. Refined nickel production is projected to moderate down to total 134 000 tonnes in 2018–19.

ExportsIn line with lower nickel production, Australia’s exports of nickel in 2013–14 are forecast to decrease 13 per cent to total 221 000 tonnes. Export values are forecast to decrease by 21 per cent, relative to 2012–13, to $2.88 billion as a result of lower volumes and a lower Australian dollar nickel price.Export volumes are projected to decrease further in 2014–15 to total 215 000 tonnes before higher mine production boosts exports of ores and concentrates resulting in export volumes increasing to 219 000 tonnes in 2018–19. Following the upward trend in world nickel prices, and given the assumed exchange rate of US$0.85, export values are forecast to increase at an average rate of 3.9 per cent a year to total $3.61 billion (in 2013–14 Australian dollars) in 2018–19 (see Figure 2).Figure 2: Australia’s nickel exportsPlease refer to page 98 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 1: Nickel outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

ZincSimon Cowling

Zinc prices and stocksIn 2013, world zinc consumption increased 7 per cent, relative to 2012, to 13.2 million tonnes. Continued growth in China’s consumption was the main driver of this increase and totalled 6 million tonnes, 14 per cent higher than 2012. As a result of this increase, China accounted for around 45 per cent of global zinc consumption in 2013. World refined zinc production increased 4.9 per cent, relative to 2012, to total 13.1 million tonnes in 2013. China’s production increased 11 per cent to total 5.3 million tonnes, underpinned by production restarts and the commissioning of Chihong Zinc and Germanium’s new refinery (100 000 tonnes) in Yunan. The continued accumulation of stocks placed downward pressure on prices throughout the year until December, when a draw down on stocks coincided with daily prices increasing to over US$2100. For 2013 as a whole, zinc prices averaged US$1910 a tonne, 1.9 per cent lower than 2012 (see Figure 1). Total commercial stocks decreased by 14 per cent to total 1.9 million tonnes or 7.5 weeks consumption at the end of 2013.Figure 1: Quarterly zinc prices Please refer to page 100 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

World zinc prices are forecast to increase by 9 per cent to average US$2089 a tonne in 2014, supported by lower production and further stock drawdowns (see Figure 2). In the absence of any major new capacity, which is typically uneconomic at prices below US$2200, mine production growth is expected to be limited to efficiency improvements. Consumption is forecast to increase by 3.5 per cent to 13.7 million tonnes, supported by growing demand for galvanised steel for use in infrastructure development in emerging and Asia-Pacific economies.Over the outlook period (2014 to 2019), zinc prices are projected to increase at an average annual rate of around 3.2 per cent to US$2343 a tonne (in 2014 dollars) in 2019. The increased use of galvanised steel, for which zinc is an input, is projected to support zinc consumption growing at an average annual rate of 3.7 per cent to total 16.5 million tonnes in 2019. Mine production is projected to decline over the next two years due to the scheduled closures of mines such as MMG’s Century and Vendata’s Skorpion and Lisheen mines. These closures are not likely to be fully offset until later in the outlook period when higher prices make projects under development, which generally have higher operating costs, seem less risky to investors. Refined zinc production is projected to increase at an average annual rate of around 3.9 per cent to 16.5 million tonnes; similar levels to zinc consumption.Figure 2: Annual zinc prices and stocksPlease refer to page 101 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

AustraliaProductionIn 2013–14, Australia’s mined production of zinc (total metallic content) is forecast to increase by 4.7 per cent to 1.6 million tonnes. Increased production at recently commissioned projects including Glencore-Xstrata’s Lady Loretta mine (126 000 tonnes) and the George Fisher expansion, in addition to the expected start-up of Glencore-Xstrata’s McArthur River project (200 000 tonnes) will underpin the increase. Terramin’s Angus Zinc mine being placed on care and maintenance will remove around 25 000 tonnes (metallic content) from Australia’s mine production capacity.Australia’s zinc mine production over the outlook period is projected to fluctuate. Increased output from the Glencore-Xstrata’s projects as they approach capacity is forecast to result in production increasing by 7 per cent in 2014–15 to 1.7 million tonnes. Offsetting this increase will be reduced production from MMG’s Century zinc mine (500 000 tonnes) as it starts to exhaust its resources around the start of 2015–16. As a result, mine production in 2015–16 is projected to decrease by 16 per cent to 1.4 million tonnes. MMG’s Dugald River mine in Queensland (200 000 tonnes) is projected to be completed during 2017–18, supporting production increases of 7 per cent in 2017–18 and in 2018–19, respectively to total 1.7 million tonnes in 2018–19.Australia’s refined zinc production in 2013–14 is forecast to increase by around 2.2 per cent in 2013–

14 to 507 000 tonnes. Over the outlook period, minor refinery curtailments are projected to occur in response to inconsistent domestic mine production. Refined production is projected to decrease at an average annual rate of 0.5 per cent to 482 000 tonnes in 2018–19.

ExportsAustralia’s zinc exports (total metallic content) are forecast to increase by 1.8 per cent to 1.6 million tonnes 2013–14, supported by growth in ores and concentrates exports. Export values in 2013–14 are forecast to increase by 16 per cent to $2.5 billion underpinned by higher global zinc prices in conjunction with a depreciating Australian dollar.Australian zinc exports are projected to reflect movements in production volumes over the outlook period. In 2014–15, export volumes are forecast to increase by 7 per cent to 1.7 million tonnes (see Figure 3). Reduced mine production in 2015–16 will decrease Australia’s zinc export volumes by 15 per cent to 1.5 million tonnes. From 2016–17 to 2018–19, exports volumes are projected to progressively increase to 1.8 million tonnes in 2018–19. Projected higher zinc prices and an assumed depreciating Australian dollar are expected to contribute to Australia’s export earnings from zinc increasing at 7 per cent a year to $3.4 billion (in 2013–14 dollars) in 2018–19.Figure 3: Australia’s zinc exportsPlease refer to page 102 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Table 1: Zinc outlookPlease refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.

Resourcesand Energy

QuarterlyReviews

Japan, South Korea and Chinese Taipei: energy markets in transitionKate Penney1

With most discussion about world energy markets focusing on developments in China and the US, energy developments in Japan, South Korea and Chinese Taipei have received less attention. Unlike China and the US, these three markets have limited indigenous resources and are heavily dependent on imports to meet their energy needs. In 2011, they accounted for around 17 per cent of world energy imports and are key markets for Australian producers of coal, liquefied natural gas (LNG) and uranium. This review article will provide an overview of the energy policies of Japan, South Korea and Chinese Taipei and consider the key issues shaping their evolving energy policies.

IntroductionThe incident at the Fukushima Daiichi nuclear power plant in Japan in March 2011 has been a defining point in world energy markets. Confidence in the safety of nuclear power has been shaken and in the short-term resulted in key advanced economies resorting to increased consumption of fossil fuels while their governments reviewed their energy policies. Japan, South Korea and Chinese Taipei have each relied on nuclear power to support their industrial expansions over the past 40 years. Following the Fukushima incident, each has undertaken a lengthy review of its energy policy. The depth and scope of these reviews and the growing public opposition to nuclear power has resulted in delays in their release. While Chinese Taipei announced its revised energy policy in 2011, new policies in Japan and South Korea were only announced in early 2014.Because of their importance to world energy trade, developments in the energy sectors of Japan, South Korea and Chinese Taipei will have consequences for energy import requirements. As such, it is useful to understand what has changed in their energy policies, what it means for their future energy mix and some of the challenges they may encounter in the transition. This is particularly relevant to Australia because Japan, South Korea and Chinese Taipei together account for around 60 per cent of earnings from energy exports and have been major sources of investment in Australia’s resources sector.

An energy transition is underwayJapan, South Korea and Chinese Taipei: energy intensive and import dependentJapan, South Korea and Chinese Taipei are three of Asia’s most advanced economies. They have relied on the availability of low-cost energy to support economic growth and maintain the competitiveness of their export industries. While all three have large installed oil refining capability, none are endowed with substantial energy resources or have pipeline/transmission infrastructure linking them to other energy systems.Japan, South Korea and Chinese Taipei all source the majority of their energy needs through world markets. Japan’s net imports account for around 96 per cent of their energy use, Chinese Taipei 90 per cent and South Korea 87 per cent. To ensure a stable energy supply and minimise the risk of disruption, all three economies have an energy mix that draws on all available sources of energy including nuclear, coal, gas, oil and renewable energy.

Fukushima prompted a change in policyGiven their similar situation, the energy policies of Japan, South Korea and Chinese Taipei have traditionally had the common goal of securing reliable and affordable energy supplies. This has been achieved through a number of means including diversification of energy type; and investment in foreign energy assets.Following the Fukushima Daiichi incident, all three economies reviewed their energy policies, particularly the role of nuclear power. Nuclear power played a large role in the energy mix in these economies, and was expected to expand considerably to simultaneously meet energy demand and carbon emissions commitments. While these reviews were conducted the construction of new nuclear

1 The author would like to acknowledge the valuable information and insights provided by Carolyn Barton at the Australian Embassy in Tokyo and Mike Wight at the Australian Embassy in Seoul.

facilities was delayed, some reactors were closed and more stringent safety standards were imposed (Ford 2014). In Japan, all nuclear reactors were shut down and now need to pass revised safety standards by the new independent nuclear regulator before they are allowed to restart. As at March 2014, all reactors remain shut, which used to provide around 30 per cent of Japan’s electricity.Following the completion of their reviews, the position on nuclear power varied across the three economies. Chinese Taipei will progressively decommission its three existing reactors by 2025. Japan will restart nuclear capacity from 2014, with a view to reducing dependence over the longer term. South Korea will maintain its nuclear industry, but plans for expansion have been significantly curbed. To accommodate the reduced role of nuclear power, all three will shift their focus to the development of renewable energy, energy efficiency and market reforms.Details of the energy policies and a discussion on some of the major challenges are contained in the section: The energy situation in Japan, South Korea and Chinese Taipei below.

The energy mix and procurement strategies are changing The energy policies and projections for Japan, South Korea and Chinese Taipei suggest that they will require various sources to meet their energy requirements over the medium to longer term. Under the revised energy policies, nuclear power will have a reduced role in the energy system than previously planned. Subsequently, the use of other energy sources will need to increase, with current plans favouring expansions in gas consumption and a greater use of renewable energy sources. While oil will remain the largest component of primary energy supply, growth in its use will slow dramatically as improved efficiency and the use of alternative fuels in the transportation sector reduce demand. There is considerable variation in the expectations for coal consumption in these economies. The volume of coal consumed will be highly dependent on environmental and climate change policies and the relative cost of alternative options.Rising global energy prices have contributed to deterioration in the current account balances of these economies and reduced the profitability of their domestic utilities. As such, there has been a greater focus on reducing the cost of imports, particularly LNG. For example, Japanese and South Korean utilities have signed contracts for LNG delivered from the United States based on the more favourable Henry Hub pricing method. Depending on the eventual Henry Hub price, some projections suggest that the price differential with Asia-Pacific LNG will be minimal. They are also looking at options for joint purchasing to improve bargaining power and reduce the cost of gas imports, as well as more flexibility in contract terms.The three economies source the majority of their energy needs from few suppliers, particularly oil, which is mostly sourced from the Middle East. There is an increased focus to diversify suppliers to ensure secure supply and to potentially reduce the cost of energy imports.

The push for alternative forms of energyIn an effort to improve their energy self-sufficiency and meet environmental objectives, all three are advocating a greater role for renewable energy in their energy mix. However, they face a number of challenges in achieving these goals including suitable resources, land availability, costs and regulations. Furthermore, the current structure of their electricity markets and existing infrastructure will restrict the ability to integrate new renewable projects to the grid. As with most electricity systems, their infrastructure was developed around large plants generating electricity to be transmitted over long distances. The variability of some renewable energy sources will create some challenges in maintaining system stability. As such, there will be a limit the volume of new capacity developed over the period to 2035.

Energy efficiency and market reformDemand-side management has been used as a strategy to reduce growth in energy use and the need to import energy. All three economies have implemented measures to improve energy efficiency and encourage conservation including performance standards, labelling and raising awareness.Major disruptions to electricity supply, rising input prices and the push to increase the use of renewable energy have highlighted inadequacies in the electricity market and/or pricing mechanisms in Japan, South Korea and Chinese Taipei. Efforts are now being directed towards promoting greater competition or increasing prices to more accurately represent the cost of supply.

A relationship of mutual dependenceAustralia is a major source of importsJapan, South Korea and Chinese Taipei source a large proportion of their energy needs from Australia. Australia is the largest supplier of coal to Japan and South Korea and the second largest supplier to Chinese Taipei, after Indonesia. By coal type, Australia is the largest supplier of metallurgical coal to all three markets, the largest supplier of thermal coal to Japan and second largest supplier of thermal coal to South Korea and Chinese Taipei. Australia became the largest supplier of LNG to Japan for the first time in 2012 (Figure 1). Changes in the energy policies of these markets will therefore have far-reaching effects on Australian producers.Figure 1: Australian share of total imports, 2012Please refer to page 108 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Contribution to Australia’s export earningsAustralia is the world’s second largest exporter of coal, the third largest exporter of LNG and is a major exporter of uranium. Exports of resources and energy commodities have been a key contributor to economic growth in Australia over the past few years. Just as Australia is major source of energy imports for each of these economies, they also account for a large proportion of Australia’s energy exports.Japan is by far Australia’s largest energy trading partner, accounting for around 78 per cent of LNG exports and 36 per cent of coal exports in 2012. South Korea is the third largest destination for Australian coal, accounting for 15 per cent of export volumes, and second largest destination for LNG (4 per cent). Chinese Taipei is the fifth largest destination for coal (9 per cent) and fourth largest destination for LNG (1 per cent). Together, these three markets account for 60 per cent of Australia’s total coal exports and 83 per cent of LNG exports (Figure 2; IEA 2013a, BP 2013).In 2012–13, the value of energy exports to these markets was an estimated $40.3 billion (in 2013–14 dollar terms), almost 60 per cent of the total (Figure 3).Figure 2: Australian energy exports by destination, 2012Please refer to page 109 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Figure 3: Australian energy export earningsPlease refer to page 110 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

A source of investmentIn an effort to ensure supply security, companies in Japan have invested in the Australian resources and energy sector for many decades, with South Korean companies also investing over the past few decades. This investment provided financial resources to assist in the development of the Australian mining industry. For instance, Japanese investment and long term contracts with Japanese customers underpinned the development of the North West Shelf LNG project in the late 1980s, which started Australia’s participation in the LNG industry. Starting in the 1960s, much of Australia’s coal export industry has been developed in partnership with Japanese investors.A number of Japanese trading companies and electricity and gas utilities have small equity shares in nearly all Australian LNG projects. For example, Mitsui and Mitsubishi have a 15 per cent equity stake in the Browse LNG project. Other LNG projects that have Japanese participation are the North West Shelf, Pluto, Gorgon, Bayu-Undan, Darwin, Wheatstone, Queensland Curtis and Prelude (EIA 2013a). In addition, the Ichthys project is operated by INPEX, the first Japanese operated LNG project in the world. The Korea Gas Corporation (KOGAS) have a stake in the Prelude and Gladstone LNG projects.Japanese companies have a larger presence in the coal industry to facilitate a secure and stable stream of supply. These include the BHP Billiton Mitsubishi Alliance (BMA), Idemitsu Kosan, Mitsui, JFE Steel Corporation, Marubeni Corporation, Sojitz Corporation, Sumisho coal and Itochu. The Korea Resources Corporation (KORES) and Daewoo International Corporation are also involved in coal project development in Australia.

Implications for Australia’s exportsWith gas expected to account for a larger share of the energy mix, and the continued importance of coal as a low-cost, stable supply of energy in Japan, South Korea and Chinese Taipei, implies that

demand for Australia’s key energy exports is likely to remain robust for the foreseeable future. The energy policies of Japan and South Korea emphasise continued involvement in the development of foreign energy assets and may result in further investment in the Australian resources sector.While Australia has a large resource base and a geographic advantage relative to other major suppliers, it is not guaranteed that it will continue to retain a large export or investment share with these economies. For example, as part of a diversification strategy, Japanese utilities have indicated that they intend to reduce their reliance on Australian coal, and have begun to source imports from the United States and Canada. It is anticipated that this strategy will improve their bargaining power and assist in reducing costs (Inajima & Okada 2014). Similarly, a number of new gas suppliers are entering the market and are competing directly with Australia to supply LNG to these key consumers.As the consumption profiles in Australia’s major export markets are changing and new sources of supply emerge, Australia will need to remain competitive and a favourable investment destination to ensure that it can continue to take advantage of market opportunities.

Table 1: Summary of the energy situation in Japan, South Korea and Chinese TaipeiCh

ines

e Ta

ipei

Stab

le e

nerg

y su

pply

Impr

oved

nuc

lear

saf

ety

Redu

ce e

lect

ricity

de

man

dEn

ergy

effi

cien

cyEn

ergy

pric

ing

Rene

wab

les

Coal

: 25–

28%

Oil:

41–4

2%Ga

s: 2

2–23

%Nu

clea

r: 4–

5%Hy

dro:

0–1

%Ot

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Source: BREE

The energy situation in Japan, South Korea and Chinese Taipei

JapanUntil recently, Japan had a balanced energy mix that used all forms of energy. Since the Great East Japan Earthquake in 2011 and the progressive shutdown of nuclear capacity, it has relied more on thermal power (oil and gas in particular). Japan has limited natural resources and must import large volumes of energy. It is the world’s largest importer of LNG, second largest coal importer and the third largest net importer of oil. Japan’s energy imports are sourced from relatively few suppliers, particularly oil, although the government is using a resources diplomacy strategy to diversify supplies. Around 83 per cent of Japan’s oil imports are sourced from the Middle East—Saudi Arabia, United Arab Emirates, Qatar, Kuwait, and Iran (EIA 2013a).To ensure supply security, Japanese companies, with government support, engage in foreign oil, gas, coal and uranium project development, providing finance and engineering, construction and project management expertise. Energy research and development is supported by the government and has

enabled Japan to become a major exporter of energy-related capital equipment (EIA 2013a).Japan has no international pipeline or transmission connections. It also has limited domestic pipeline capability so oil is typically delivered by coastal tankers, tank trucks, and railroad tankers and gas is received at LNG terminals close to point of use (EIA 2013a). As part of its energy market reforms, the government is looking at options to expand infrastructure, particularly for gas and electricity transmission.Table 2: Key energy data, 2012

Population (millions) 127.6

GDP per capita (USD PPP) 35 855

Total primary energy supply (Mtoe) 452

World rank 5

Electricity generation (TWh) 1026

coal 28

oil 17

gas 42

nuclear 1

hydro 8

other 5

Energy production (Mtoe) 27

Net Imports (Mtoe) 436

Energy intensity (toe per thousand 2005 USD PPP)

0.11

Sources: IEA 2013b; IMF 2013.toe is tonne of oil equivalent.

At a glance• High fossil fuel dependency and low source diversification, particularly for oil• Low self sufficiency• Exposure to volatile world prices• Still considerable uncertainty on future share of nuclear• Renewable potential, but some constraints

Energy policyJapan’s energy policy has traditionally been based around achieving the 3Es (energy security, economic efficiency and environment) at an affordable price. This was realised through a combination of supply and demand measures that diversified the energy mix and curbed consumption growth.The Great East Japan Earthquake and incident at the Fukushima Daiichi nuclear power plant in March 2011 exposed some vulnerability in Japan’s energy system, namely the ability to cope with a major disruption. Consequently, following a change in government, the Ministry of Economy, Trade and Industry (METI) was directed to conduct a review and re-evaluation of Japan’s energy and environmental strategies from early 2013. In late February 2014, a draft Basic Energy Plan (BEP) was submitted to cabinet for expected approval in late March. This is the first BEP to be prepared post-Fukushima.The key outcome of the draft BEP was the Government’s position on nuclear power, stating that it would remain a vital source of baseload electricity (the previous government had advocated to cease the use of nuclear power). Although Japan intends to reduce its reliance on nuclear, it will begin to restart nuclear capacity, subject to stringent safety regulations, during 2014. While the draft energy policy suggested that the most reliable energy mix for Japan would contain a combination of nuclear, renewable energy and fossil fuels, it did not define targeted shares because of uncertainties about

the number of nuclear restarts and the pace of renewable development. Other priority areas include accelerated uptake of renewable energy; electricity market deregulation; and energy efficiency and conservation. In addition to the 3Es that underpinned previous policy, safety has been added to the mix (Toyoda 2013).The new BEP will aim to create ‘more tenacious resource procurement and energy supply networks’ through increased consumer choice and reforms to the supply structure (Figure 4).Figure 4: Key priorities of Japan’s energy policyPlease refer to page 115 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Japan passed legislated reforms to the electricity system (Amended Electricity Business Act) in November 2013. The aim of the reforms is to ensure stable electricity supply, reduce electricity prices and increase consumer choice. This will be achieved through greater cross-regional cooperation (including the creation of a national grid company), the introduction of full retail competition and the unbundling of transmission and distribution services (METI 2013a). The Japanese Government has previously introduced electricity reforms in the industrial sector, but to date supply diversification remains low. The current reforms are intended to break up the ten regional monopolies which own generation, transmission and retail operations.While renewable energy currently accounts for a small proportion of Japan’s energy mix (around 1 per cent excluding hydro), the government has implemented a number of measures to increase the use of renewable energy sources. The introduction of a feed-in tariff scheme in 2012 has contributed to a strong increase in renewable generation capacity.Japanese energy consumption is covered by the Energy Conservation Law. The law was amended in May 2013 to ensure continued efforts to conserve energy. The changes include an expansion to the products covered by the Top Runner program and the promotion of energy management.

Energy outlookThe projections for energy consumption in Japan vary considerably, largely because of uncertainty about the future of nuclear power. The selected projections were compiled at different times and have varying assumptions on the role of nuclear based on available information at the time of preparation.Japan’s energy consumption has been declining steadily since 2004, driven by a number of different factors including energy efficiency improvements, technological change, slowing economic growth and the Great East Japan Earthquake (ADB 2013). This trend is expected to persist into the future, with primary energy consumption projected to decrease to between 468 and 397 million tonnes of oil equivalent in 2035 under business as usual conditions, underpinned by improved efficiency and slower economic growth. Economic growth will be slower as a result of an ageing population and contracting workforce; mature social infrastructure; and the relocation of industry abroad (APERC 2013; ADB 2013; IEA 2013d).

Table 3: Energy projections for Japan

Actual

ADB APERC IEA (new policies)

2010 2035 aag share

2035 aag share

2035 aag share

% % % % % %

TPES (Mtoe) 482.0

467.5 -0.12 100 397.

2 -0.77 100 443 -0.34 100

coal 102.7

128.5 0.90 27 102.

0 -0.03 26 98 -0.19 22

oil 196.9

151.6 -1.04 32 139.

9 -1.36 35 131 -1.62 30

gas 88.8 129.1 1.51 28 106.

5 0.73 27 103 0.59 23

nuclear 75.3 14.9 -6.28 3 14.9 -6.27 4 45 -2.04 10

hydro 7.5 9.6 1.00 2 9.6 1.00 2 9 0.74 2

other 10.9 33.7 4.63 7 24.3 3.27 6 57 6.85 13

Generation (TWh)

1071.5

1257.9 0.64 100 1009

.8 -0.24 100 1217 0.51 100

coal 281.7

420.3 1.61 33 311.

4 0.40 31 276 -0.08 23

oil 77.9 13.5 -6.77 1 10.0 -7.88 1 26 -4.29 2

gas 302.5

523.9 2.22 42 388.

2 1.00 38 398 1.10 33

nuclear 289.0 57.3 -6.27 5 57.3 -6.27 6 174 -2.01 14

hydro 87.0 111.7 1.00 9 111.

7 1.00 11 108 0.87 9

other 33.4 131.2 5.63 10 131.

2 5.63 13 235.0 8.12 19

Sources: ADB 2013, APERC 2013, IEA 2013d.TPES is total primary energy supply.

While policy efforts are being directed towards the development of renewable energy, fossil fuels will remain the dominant source of energy. Oil is projected to retain the largest share of total primary energy supply. Despite this, growth in oil consumption is projected to decline as vehicle fuel efficiency improves and manufacturing production is progressively moved offshore.Projections for coal use vary significantly, ranging from 98 to 129 million tonnes of oil equivalent in 2035. While coal use will receive some support in the short term following the closure of nuclear capacity, the longer term outlook for coal will depend on the eventual share of nuclear, the speed of renewable uptake, fuel prices and government policies. The government is currently promoting coal-fired technology to improve domestic efficiency and as a key export under ‘Abenomics’.Gas is projected to account for a larger share in the energy mix by 2035. Like coal, gas utilisation will increase in the short term with the closure of nuclear capacity but will have a longer term role in the energy mix. The ability to secure low cost gas will be important.The strongest growth is projected to occur in renewable energy, particularly solar and wind, but from a very low base. Supportive policy measures for the development of renewable energy have been designed to increase energy security and limit the effect of fuel price increases post-Fukushima. However, it is debatable how far renewables can be expanded in Japan (and at what cost) without regulatory changes including to land-use (discussed below).

The road aheadNuclearSince the Great East Japan Earthquake, the greatest uncertainty in Japan’s energy policy has been surrounding the future of nuclear power. With the appropriate safety measures, the Abe Government views nuclear as an essential component of the energy mix to ensure stable supply, and reduce costs and reliance on expensive imported fuels. Access to low-cost energy is an important part of the ‘Abenomics’ growth strategy.Following the scheduled maintenance shutdown at the Ohi nuclear power plant in September 2013, Japan’s entire nuclear fleet is out of service. Nuclear power plants will only be allowed to recommence operation after the Nuclear Regulation Authority (NRA) has assured their safety. Around 17 reactors (a third of the nuclear fleet) have applied to restart.Under the new regulations, power companies need to demonstrate they have plans for dealing with a range of disruptions, have installed venting systems to limit the release of radioactive substances during emergencies, and provide assessments of seismic and tsunami risk around the reactor. The inspection team is taking longer than anticipated to work through the assessments, largely because of the delay in receiving required paperwork from the power companies. The NRA has not announced a firm schedule for the completion of these assessments and it is uncertain when any plants will be restarted, although Japanese summer 2014 is looking most likely for the first plant/s to restart (Japan Times 2014). Japanese utilities are keen to restart their nuclear capacity to reduce the financial pressure from importing fuel while their nuclear facilities are idled.Japan plans to export its nuclear technology and know-how, particularly to Asia and the Middle East, with the government signing a number of agreements to this effect.

Renewable energyJapanese energy policy strongly promotes the uptake and utilisation of renewable energy sources. The renewable sources with the best potential are solar photovoltaic using a combination of residential and office/building installations, unused land and abandoned rice paddies; offshore wind; small and medium-scale hydropower; geothermal and biomass (APERC 2013).The plans to rapidly increase the penetration of renewable energy in the mix may encounter some difficulties, particularly land availability. The islands are mountainous with dense forest, much of which are in national parks that restrict development and thus limit site options. The development of high-potential geothermal sources faces concerns from the hot spring (onsen) industry, which forms an important component of regional tourism. There are also alternative land use considerations such as food cultivation and fishing rights in prospective offshore wind areas (APERC 2013; Jones & Kim 2013).The current structure of the electricity market will also provide a challenge to the large-scale development of the renewable industry. Because of the isolation of the Japanese electricity system, alternative energy options will need to be available to account for the potential variability in renewable energy output (Jones & Kim 2013). For instance, the largest wind resources are in the most northern part of Japan, northern Hokkaido, which is a long distance from demand centres and has limited transmission capacity. However, the government is investing in expanding transmission infrastructure in an attempt to overcome this issue.

GasGas is projected to play an important role in Japan’s energy future, particularly with the likelihood of reduced nuclear power utilisation. Japan’s current import capacity is constrained by infrastructure, berthing, and ship size. To meet its growing import requirements, five LNG import terminals are under construction with a combined capacity of 350 billion cubic feet a year (EIA 2013a).LNG imports increased dramatically following the closure of nuclear capacity. Furthermore, rising oil prices increased the cost of imported LNG, contributing to a near doubling of Japan’s annual LNG bill and rising trade deficit (METI 2013b). As such, reducing the cost of gas imports has been a prime focus of the government, and they have been pushing for greater diversity in contracts, including moving away from oil-linked pricing and the removal of destination clauses (Barton 2013).They have also compiled a strategy for securing lower-cost gas, with shale gas in the United States seen as a key way to reduce prices. On the supply side, Japan is keen to diversify its supply sources and is looking at options in a range of countries including the United States, Canada, Russia and Mozambique. They have already signed a contract for LNG supplied from the United States based on

Henry Hub pricing. Japan is also investing in new gas developments and accelerating their completion where possible (METI 2013b; Barton 2013; Okamoto 2013).Japan is encouraging joint purchasing, both between Japanese buyers and with purchasers from other countries, such as South Korea and India. Joint purchasing is seen as a means to achieve discounted prices and increase buyers’ bargaining power. Other work is underway to encourage the development of an Asian LNG trading hub, encouraging a more liquid market, greater flexibility and lower prices.On the demand side, Japan will look for ways to stem the growth in gas use, including restarting nuclear capacity, re-evaluating the development of coal-fired capacity and expanding renewables. They are also looking for more flexibility in their supply contracts (METI 2013b).In an effort to become more self-sufficient in gas, Japan is trying to develop its gas hydrate resources. There is an experimental project that has produced gas hydrate offshore Japan at a small-scale. It is intended that they can improve the technology so that it can become commercial by 2018, but this may require a technological breakthrough (METI 2013b).

Electricity market reformLiberalisation of the Japanese electricity market began in 1995. However, progress has been slow and the sector remains dominated by ten vertically integrated regional utilities. Until the Great East Japan Earthquake the system provided stable supply and encouraged sufficient investment to keep pace with demand (Jones & Kim 2013). However, it remains one of the most expensive electricity markets in the world.The incident at the Fukushima Daiichi power plant highlighted the electricity system’s inability to deal with a major disruption. For example, electricity could not be transferred from regions with surplus to those with shortage because of inadequate interconnection. In addition, the flow of electricity between regions is restricted by the electricity network, which is based on two different frequencies. The east runs at 50 Hertz and the west at 60 Hertz and there are only three conversion facilities connecting the systems. When the east lost generation capacity, it was effectively cut off from supply in the west as there was insufficient capacity to cope with the required flow of electricity (Figure 5, Jones & Kim 2013). It also revealed the lack of competition in the market and a limited ability to integrate renewable energy (METI 2013a).In response to these inadequacies, the Japanese government has embarked on a new series of reforms to the electricity market. The three steps outlined in the policy section will be carried out systematically over a prescribed schedule. The first agenda item is the creation of a national grid company by 2015 that will coordinate the activities of the generators. The second agenda item is to move towards full retail competition in the residential sector from around 2016. Retail competition was introduced in 1999, with power producers allowed to deliver electricity directly to eligible industrial customers using the utilities’ transmission networks. The third item on the agenda is unbundling the generation, transmission and distribution activities of the ten regional monopolies from around 2018.Unlike previous attempts at electricity market reform, the government appears to be more likely to be successful this time, particularly in light of public criticism of the sector post-Fukushima. The utilities are also in a much weaker financial position. The biggest factor that will support the reforms is the nationalisation of the Tokyo Electric Power Company (TEPCO) following the Fukushima Daiichi incident—the largest Japanese utility and one of the largest in the world. Under the oversight of the government, TEPCO is being split into separate generation, transmission and retail holding companies. Other power providers are also being allowed to enter its monopoly area. It is expected that this will result in a radical change to the electricity market in TEPCO’s region, which serves around 45 million customers.Figure 5. Japan’s electricity networkPlease refer to page 121 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Electricity pricesFollowing the closure of the nuclear power fleet, Japan has relied on fossil fuel imports to bridge the gap in generating capacity. Increased energy imports, particularly oil and LNG, combined with relatively high prices for these commodities, increased the cost of electricity generation, increased the financial pressure on utilities and contributed to a rising Japanese trade deficit. In an effort to limit the burden passed on to consumers through higher electricity prices, the Japanese government has scrutinised all applications for electricity price increases, approving rises of between 6 and 9 per cent for households. Industrial prices, which don’t have to be approved by government, have risen by

11 to 17 per cent from a high base. The average household in Japan now pays US$1200 more a year for their electricity than before Fukushima (METI 2013a).Renewable energy options are currently more expensive than existing technologies. For generators to make an acceptable return on their investment and remain profitable, electricity prices may need to remain high. Research undertaken by the National Policy Unit suggests that using renewable energy to replace nuclear power capacity will increase household electricity prices by 90 to 110 per cent. However, an estimated 10 to 65 per cent of the effect would be offset by reduced consumption (Jones & Kim 2013).

South KoreaBecause of its energy-intensive manufacturing sector, South Korea is the world’s eighth largest energy consumer. South Korea has limited domestic energy resources and so has developed a diverse energy mix which includes coal, oil, gas, nuclear and renewables to ensure supply security and stability. However, the penetration of renewable energy is among the lowest within the Organisation for Economic Cooperation and Development (OECD). Although it does not have large oil deposits, South Korea has three of the ten largest oil refineries in the world (IEA 2012; EIA 2013b).Given its limited domestic energy sources, South Korea is the world’s fourth largest energy importer—oil (fifth), LNG (second), coal (third). South Korea has no international gas pipelines, relying solely on LNG imports for its gas requirements. As such, even though they are not a large overall consumer of gas, they are among the world’s largest importers and the Korea Gas Corporation (KOGAS) is the largest single purchaser of LNG in the world. South Korea has a high dependence on the Middle East for its oil and gas imports, which potentially exposes it to supply risk (EIA 2013b; IEA 2012).Table 4: Key energy data, 2012

Population (millions) 50.0

GDP per capita (USD PPP) 31 950

Total primary energy supply (Mtoe) 263

World rank 8

Electricity generation (TWh) 528

coal 42

oil 4

gas 23

nuclear 29

hydro 1

other 1

Energy production (Mtoe) 47

Net Imports (Mtoe) 228

Energy intensity (toe per thousand 2005 USD PPP)

0.19

Sources: IEA 2013b; IMF 2013. toe is tonne of oil equivalent.

At a glance• Energy intensive economy• Major energy importer• Regulated pricing has contributed to mismatch between supply and demand• Increasing public resistance to nuclear• Heavy reliance on fossil fuels

Energy policyThe direction of South Korea’s energy policy is set out in its Energy Basic Plan, which is reviewed every five years. The Energy Basic Plan forms the basis of more detailed sectoral plans such as power and gas markets. In mid-January 2014, the Government finalised its Second Energy Basic Plan (SEBP), which covers the period 2013–2035. A working group containing a mix of representatives from industry, academia and civil society were consulted in the development of the SEBP.The key change to the SBEP is the expected role of nuclear power. After the incident at the Fukushima Daiichi power plant and a series of incidents in the domestic nuclear industry (including poor quality components and falsified safety certificates), public opposition to nuclear power has grown. The working group suggested that the targeted share of energy derived from nuclear power should be reduced to 22–29 per cent (from a previous target of 41 per cent by 2030). The Government recognised the need to maintain a nuclear industry for energy security, while acknowledging the change in circumstances from the creation of the previous target. As such, when passed, the upper limit of the proposed range (29 per cent) was set as the new target (Ford 2014).The SEBP outlines five major policy tasks (see Figure 6) to be undertaken during the period of the plan:

1. Reduce energy consumption by 13.3 per cent in 2035 relative to the forecast (254 million tonnes of oil equivalent) through energy management systems and adjusted energy prices. As part of these efforts, the tax on LNG and kerosene will be reduced to encourage a shift in consumption to these commodities. Simultaneously, a tax on coal (excluding coking coal) will be introduced (Ford 2014).

2. Development of a distributed energy system to improve system stability and reduce disputes over the construction of transmission and power infrastructure. By 2035, it is intended that 15 per cent of electricity supply will be generated in a distributed form.

3. Improve energy sustainability, including environmental protection and safety. A targeted 20 per cent reduction in greenhouse gases by 2035 through the use of the best carbon reduction technology available, particularly in coal-fired plants, has been set.

4. Strengthen energy security through the development of resources abroad (targeting 40 per cent ratio) and increasing the use of renewable energy (target 11 per cent share of mix by 2035). South Korea’s energy supply has been developed through a combination of long-term contracts, spot market purchases and foreign resource development, supported through tax incentives and easier access to credit (APERC 2013; EIA 2013b).

5. Ensuring energy affordability for Korean citizens. There are plans to introduce a voucher system for poor households from 2015 to offset anticipated price increases.

Figure 6: Energy policy tasks outlined in Second Energy Basic PlanPlease refer to page 125 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

In November 2012, the Government passed The Enforcement Decree of Allocation of Trading of Greenhouse Gas Emissions Allowances Act, establishing its emissions trading scheme. The scheme will cover six greenhouse gases and be phased in from 2015. The Ministry of Environment will have primary responsibility for managing the scheme (Patel 2013; Jones & Yoo 2012).

Energy outlookBased on the First Energy Basic Plan, South Korea’s primary energy consumption is projected to increase to between 270 and 284 million tonnes of oil equivalent in 2035 under business as usual conditions. Growth in energy consumption is projected to moderate over the period to 2035 because of slower anticipated economic growth, structural change away from energy intensive industries and improved energy efficiency (ADB 2013; APERC 2013).Oil is projected to remain the largest contributor to total primary energy supply. However, growth in consumption is projected to be moderate or negative as growth in personal motor vehicle ownership in South Korea is expected to be modest, reflecting limited population expansion and well-developed public transportation. The use of oil in the power sector is also projected to decline dramatically as South Korea increasingly uses other energy sources for electricity generation.Projections for coal use vary significantly. Despite efforts to reduce the use of coal, it will likely remain a large component of the energy mix, especially if the nuclear industry does not expand rapidly under the SBEP and LNG prices remain high.In line with its efforts to utilise energy supply that has a lower environmental footprint, the use of gas is projected to increase. Like coal, the projections for gas use vary considerably, with APERC

expecting strong growth in gas use at the expense of coal, while the ADB expect more subdued growth based on infrastructure limitations.

Table 5: Energy projections for South Korea

Actual ADB APERC

2010 2035 aag share 2035 aag share

% % % %

TPES (Mtoe) 239.0 284 0.69 100 269.5 0.48 100

coal 68.0 76.1 0.45 27 27.7 -3.53 10

oil 92.9 93.4 0.02 33 91.7 -0.05 34

gas 36.0 39.4 0.36 14 61.9 2.19 23

nuclear 38.5 67.2 2.25 24 79.0 2.92 29

hydro 0.2 0.2 -0.74 0 0.1 -2.21 0

other 3.4 7.7 3.36 3 9.1 4.05 3

Generation (TWh) 469.4 615.7 1.09 100 622.3 1.13 100

coal 211.7 275.1 1.05 45 81.5 -3.75 13

oil 19.1 1.2 –10.48 0 1.4 -9.93 0

gas 86.0 71.6 –0.73 12 215.7 3.75 35

nuclear 147.7 258 2.26 42 303.1 2.92 49

hydro 2.8 1.8 -1.75 0 1.6 -2.21 0

other 2.1 8.0 5.50 1 19.0 9.21 3

Sources: ADB 2013; APERC 2013.TPES is total primary energy supply.

In both cases nuclear power generation is projected to grow at an average annual rate of more than 2 per cent. The First Energy Basic Plan outlined a strong role for nuclear power as part of South Korea’s efforts to increase its energy independence and reduce its carbon emissions. However, given the change in sentiment towards nuclear power and the lower target outlined in the SEBP, the outlook for nuclear is likely to be weaker than projected.Renewable energy is projected to exhibit the fastest growth in total primary energy supply, reinforced by policy measures to ensure energy security and environmental protection. There are no suitable sites for further hydropower development, so growth is likely to come from solar and wind energy. However, the overall share of renewables in the energy mix will remain small.With increasing energy consumption, South Korea will remain a large energy importer. Projected increases in the utilisation of nuclear power and renewable energy sources will reduce their import dependence.

Road aheadSouth Korea’s aim to reduce emissions and alter the configuration of the energy system (such as reducing the role of nuclear and coal) will require adjustments to production processes, energy use and the structure of the economy. These changes are unlikely to occur without enduring large transition costs (Jones & Yoo 2012).

NuclearThe position on nuclear outlined in the SEBP will result in a considerably different energy mix than envisioned in the preparation of the First Energy Basic Plan in 2008. Under the SEBP, nuclear will account for around 29 per cent of the energy mix in 2035. This target will allow existing power plants to continue to operate and those under construction to be completed. However, the future for planned reactors is uncertain. There are currently five reactors under construction with a combined capacity of almost 6900 megawatts that are expected to be completed by 2018. Plans for a further two reactors with a combined capacity of 2800 megawatts were approved in late January 2014 and are expected to be completed by 2020.

The utilisation of nuclear power has allowed South Korea to continue to increase its energy use as it expanded its manufacturing capabilities without a corresponding large increase in emissions (Jones & Yoo 2012). Because nuclear power has zero emissions, the reduced role of nuclear in the energy mix under the SEBP will affect South Korea’s ability to meet its green growth targets, particularly if coal-fired generation is required to fill some of the gap. While the Government is pushing for more efficient coal-fired generation technology to be utilised in the future, emissions from this source will remain higher than nuclear.In addition to using nuclear power, South Korea aims to become a large exporter of nuclear technology. They intend to export to countries that are starting to develop a nuclear industry such as India, Vietnam, Poland, Saudi Arabia, and South Africa and larger, more established nuclear industries such as in China and the United States (Kane & Pomper 2013). Their ability to achieve this goal will depend, to some extent, on developments in the domestic industry and the cost competitiveness of Korean technology. With a slower expansion of the South Korean nuclear industry, more financial and personnel resources will be available to assist in the expansion of the export industry (Kane & Pomper 2013).

Energy pricingBecause the electricity network is a monopoly, energy prices are regulated to ensure affordability and the competitiveness of its manufacturing export industry. As a result, South Korea has one of the lowest electricity prices among OECD countries (Jones & Yoo 2012).South Korea’s electricity consumption has been increasing, underpinned by rising household incomes and the expansion of energy-intensive manufacturing. Since prices have been kept relatively stable and do not reflect the cost of generation, consumers have not been provided with any incentive to change their consumption patterns, despite efforts to stem growth in energy use.Low electricity prices and overambitious expectations for energy savings have discouraged investment in new generating capacity, particularly renewables. The development of new electricity generating capacity has also been mired by environmental concerns and public opposition, contributing to a progressive reduction in South Korea’s reserve margins. Consequently, there has been a mismatch between supply and demand, which has contributed to a number of electricity blackouts over the past five years (Patel 2013; Jones & Yoo 2012).South Korean power generators have struggled with rising production costs while retail prices have remained relatively constant (Patel 2013). Existing electricity prices are estimated to only cover around 90 per cent of generation costs—80 per cent for industrial users. Regulated prices contributed to KEPCO losing around 11 trillion Won (around US$9.5 billion) over five years (Ford 2014). The Korean Government are starting to increase electricity prices, with announced increases in tariff rates during 2013. Since the economy’s competitiveness has been based around access to low-cost energy, there will be reluctance toward any rapid or large-scale change.

GasCoal and nuclear power have been the dominant sources of energy in South Korea. With the shift in policy away from these sources, there will be increasing pressure on gas to fill this gap. All of South Korea’s existing gas-fired power plants are being utilised. As such, new capacity will need to be built to enable gas use in the generation sector to expand (Ford 2014).South Korea will need to explore options to source gas. KOGAS is already the largest single buyer of LNG in the world. It currently has long term contract arrangements with suppliers in Qatar, Indonesia, Malaysia and Oman and procures a large volume of gas from the spot market. South Korea will need to compete with Japan and China for gas supplies. This has contributed to rising prices in the region and escalating costs for electricity generation (Ford 2014).The option of developing a pipeline to transport gas from Russia via North Korea has been explored. However, Gazprom, the Russian gas company, has assessed the project as uneconomic. In addition, having important infrastructure run through North Korea is considered too high risk. As such, it is unlikely that a pipeline will be developed over the horizon of the SBEP (Ford 2014).

Renewable energySouth Korea has relatively low renewable energy resource potential because of its location and climate (IEA 2012). It has some potential in solar photovoltaic and offshore wind energy, and has recently developed the world’s largest tidal energy facility—the 254 megawatt Sihwa plant (Jones & Yoo 2012, Patel 2013, Ford 2014).The government is attempting to accelerate the development of renewable energy through the

introduction of a number of policy measures. For example, a renewable energy portfolio standard, much like the Australian Renewable Energy Target, was announced in 2012. The standard requires electricity generators to either produce or purchase 10 per cent of their electricity from renewable sources by 2022, from 1.3 per cent in 2010 (Jones & Yoo 2012).Renewable energy accounts for a relatively small proportion of South Korea’s energy mix. In order to meet these targets, considerable investment in new capacity is required (Patel 2013). Aside from resource potential, there are various challenges to the wide-scale adoption of renewable energy in South Korea. It remains relatively expensive compared with other forms of energy, particularly in the presence of low regulated electricity prices. Further, the intermittent nature of some renewable technology options will have implications for system reliability, which is already an issue for the sector (IEA 2012).

Chinese TaipeiChinese Taipei’s economic development has been energy intensive, supported by the production of intermediate manufactured products for export. Accordingly, its energy demand increased rapidly in line with growth in exports. Around three decades ago, indigenous energy sources accounted for around 15–20 per cent of Chinese Taipei’s energy supply. However, these resources have since been exhausted and its geographical isolation prevents electricity imports. As a result, Chinese Taipei now relies almost entirely on imported energy, which has prompted energy security concerns (Wakefield 2012).Table 6: Key energy data, 2011

Population (millions) 23.2

GDP per capita (USD PPP) 37 351

Total primary energy supply (Mtoe) 109

World rank 24

Electricity generation (TWh) 249

coal 51

oil 4

gas 25

nuclear 17

hydro 2

other 2

Energy production (Mtoe) 14

Net Imports (Mtoe) 97

Energy intensity (toe per thousand 2005 USD PPP)

0.14

Sources: IEA 2013c; IMF 2013.toe is tonne of oil equivalent.

At a glance• Energy intensive economy• Limited indigenous energy resources• Low energy type and source diversification• Renewable potential but limited by cost, stability and land considerations• Nuclear being phased out• Regulated energy prices do not promote conservation

Energy policyChinese Taipei’s ‘Framework of Sustainable Energy Policy’ was introduced by the Executive Yuan in 2008. It is based around achieving energy security and environmental protection while considering intergenerational equity, scarce natural resources and limited environmental capacity. Policies implemented under the framework are intended to create four trends: (1) more efficient consumption and transformation; (2) higher value added from energy used; (3) reduced carbon intensity and (4) reduced dependence on fossil fuels and imports.In light of this, the policy focuses on the efficient use of energy resources, development and uptake of clean energy technologies and ensuring energy security. Within the policy a number of targets were set including:

Improving energy efficiency by 2 per cent a year so that energy intensity in 2015 is 20 per cent lower than in 2005. In the presence of technological breakthrough and appropriate policy measures and support, a targeted 50 per cent reduction in 2025 compared with 2005 has also been set.

Reducing CO2 emissions to 2008 levels between 2016 and 2020 and 2000 levels by 2025. Increasing the share of low carbon energy (which includes nuclear and gas) from 40 per

cent to 55 per cent by 2025. Developing a stable energy system that supports economic development goals such as

increasing per capita income to US$30 000 by 2015.The Fukushima Daiichi incident in Japan prompted the Executive Yuan to revisit its energy situation, forming the ‘New energy policy’. This effectively built on the 2008 framework and extended it to include plans for nuclear development. The New energy policy looks to ensure nuclear safety and steadily reduce the dependence on nuclear energy, eventually transitioning to zero nuclear power. As part of this policy, existing reactors will be progressively decommissioned following the completion of the fourth nuclear power plant. It is anticipated that the three existing reactors will be closed by 2025 (APERC 2013).To ensure nuclear safety, the Atomic Energy Council (AEC) undertook a comprehensive safety review of the nuclear fleet. As part of this, the AEC increased the required capacity to withstand damage from earthquakes, landslides, floods and tsunamis given the seismic activity in the region. They also ensured that all facilities have established emergency procedures and periodic drills. Any new reactors to be developed must be assessed by the AEC, who will be supported by the World Association of Nuclear Operators and experts from international organisations. Chinese Taipei intends to reduce its nuclear dependence through a combination of reduced electricity demand, a lower peak load and the development of alternative energy sources.Chinese Taipei’s energy policy framework is supported by a number of legislative instruments to achieve these targets. These include the Energy Management Act, Petroleum Administration Act, Natural Gas Business Act, Electricity Act and Renewable Energy Development Act.Figure 7: Energy policy principles and actions—Chinese TaipeiPlease refer to page 132 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Energy outlookUnder reference case scenarios, primary energy consumption in Chinese Taipei is projected to increase from 114 million tonnes of oil equivalent in 2010 to around 125–127 million tonnes of oil equivalent in 2035. The rate of growth is expected to moderate over the projection period, reflecting assumed slower economic and population growth, structural change and energy conservation efforts.

Table 7: Energy projections for Chinese Taipei

Actual ADB APERC

2010 2035 aag share 2035 aag share

% % % %

TPES (Mtoe) 114.0 124.5 0.35 100 127.1 0.44 100

coal 39.9 34.4 -0.60 28 32.1 -0.87 25

oil 48.1 51.6 0.28 41 53.1 0.40 42

gas 12.3 27.3 3.24 22 28.6 3.43 23

nuclear 11.3 5.1 -3.14 4 6.1 -2.47 5

hydro 0.6 0.6 -0.07 0 1.1 2.32 1

other 1.7 5.4 4.69 4 6.1 5.17 5

Generation (TWh) 247.5 335.9 1.23 100 335.9 1.23 100

coal 128.3 117.9 -0.34 35 114.5 -0.45 34

oil 9.1 12.1 1.15 4 12.2 1.18 4

gas 54.7 149.3 4.10 44 145.4 3.99 43

nuclear 43.4 23.2 -2.47 7 23.2 -2.47 7

hydro 7.1 12.5 2.29 4 12.6 2.32 4

other 4.9 20.9 5.97 6 28.0 7.22 8

Sources: ADB 2013; APERC 2013.TPES is total primary energy supply

It is expected that Chinese Taipei will continue its efforts to shift the structure of the economy away from heavy industry, which is energy intensive, towards higher value added manufacturing, services and information technology and communications (APERC 2013).Oil is projected to remain the dominant fuel in the energy mix, accounting for around 42 per cent of total primary energy supply in 2035. While oil will retain its share in the energy mix, consumption is projected to grow at an average rate of between 0.3–0.4 per cent a year to 2035 as use in the transportation sector eases supported by slow population growth, the development of mass public transportation and improved energy efficiency.In order to meet environmental objectives, coal-fired power plants will be decommissioned over the projection period. Chinese Taipei’s coal use is projected to decline at an average annual rate of between 0.6 and 0.9 per cent. While its share in the electricity mix will decline from 52 per cent in 2010 to around 35 per cent in 2035, coal will still be the second largest input for electricity generation.Given the policy directive to phase out nuclear power, the growth and share of nuclear generation will decline considerably. The reduced use of coal and nuclear will require increased gas use and a greater penetration of renewable energy.Gas is projected to exhibit the fastest growth among the energy types to meet increased demand for electricity, and replace decommissioned coal-fired and nuclear generation capacity. Gas-use is projected to grow at more than 3 per cent a year and will increase its share of the primary energy mix from 12 per cent in 2010 to 23 per cent in 2035. Accordingly, the government is planning to develop more LNG terminals to cope with the expected increase in gas use.The development and use of renewable energy sources is projected to increase substantially, underpinned by legislation and policies promoting their uptake. Under the Renewable Energy Development Act passed in July 2009, Chinese Taipei has set a target to increase renewable electricity generating capacity. The Act introduced feed-in tariffs and compels utilities to purchase this energy. It also established a fund for renewable energy development funded by fossil-fuel and nuclear based generators (Fox 2011).

Chinese Taipei has strong potential for solar energy, with some areas in the south receiving around 300 days of sunlight a year, wind and ocean energy (Wakefield 2012). The installed renewable targets are outlined in table 8.Table 8. Chinese Taipei renewable energy installation targets

2025 2030

Total 9 952 12 502

wind 4 200

solar photovoltaic 3 100

hydro 2 502

waste 1 369

ocean 600

fuel cell 500

geothermal/biogas 231

Source: Wakefield 2012.

The road aheadTo achieve these projections for energy use, Chinese Taipei will need to make some considerable changes to its energy system. These changes will bring with it a number of challenges and opportunities.

Demand side managementThe government in Chinese Taipei has demonstrated a strong commitment to encouraging energy efficiency and conservation through the implementation of numerous policy measures across multiple sectors (APEC 2010). While the energy intensity of the economy has improved, the continuous tightening of minimum energy performance standards (MEPS), labelling requirements and building standards will help achieve further energy savings (Liang 2012).The largest hurdle to reducing energy requirements in Chinese Taipei is regulated gas and electricity pricing, which is controlled by the government to maintain competitiveness and access to affordable energy (Chang 2012). Regulated prices do not provide the appropriate incentives for consumers to alter their energy use; for the economy to restructure away from energy-intensive manufacturing; or for the development of relatively higher cost alternative energy sources (Liang 2012; Chang 2012). Further, regulated prices have contributed to increased financial pressure for state-owned Taipower and CPC Corporation. As a result, neither company has had surplus capital to reinvest into alternative energy sources (Chang 2012).

Diversification of fuel types and sourcesChinese Taipei has high import dependency and low source diversification. Energy imports accounted for 3.9 per cent of Chinese Taipei’s GDP in 2002, increasing to 14.6 per cent in 2012 (Liao & Jhou 2013). The majority of petroleum imports are sourced from the Middle East and coal from Indonesia, Australia and China (Chang 2012). Chinese Taipei has an isolated electricity grid and cannot import electricity from neighbouring countries, which requires greater reserve margins to ensure system safety and stability (Chang 2012).As outlined above, gas will play an increasingly important role in the energy mix. This will need to be imported as LNG. It is expected that Chinese Taipei’s LNG imports will increase to 20 million tonnes by 2030 from around 12.5 million tonnes in 2012. Chinese Taipei intends to import LNG from stable and reliable sources and to have a portfolio approach to pricing arrangements to reduce price risk. To diversify its import sources, Chinese Taipei is considering providers in Australia, the United States and Canada (Lin 2012).CPC Corporation has determined the location for the development of a third LNG terminal near Taipei. The new terminal is expected have a capacity of up to 6 million tonnes a year (Lin 2012). The development of additional regasification terminals will be constrained by land availability (Chang

2012).

Nuclear Nuclear power reduces the risk of price volatility in electricity supply, as it is largely used as a substitute for LNG and coal (Chang 2012). Chinese Taipei has three nuclear power plants (six units) with a combined capacity of 4.9 gigawatts (WNA 2014). The first two of these plants have been operating for more than 20 years and are approaching the end of their designed lifespan (Hwang 2012). A fourth power plant is under development.Despite the presence of nuclear power since the 1970s, there is a long history of strong public resistance. This was reinvigorated post-Fukushima, spurring a change in energy policy (Wakefield 2012; Hwang 2012). While nuclear power would help in achieving Chinese Taipei’s carbon reduction goals, political and technical issues are likely to halt the expansion of nuclear capacity (Hwang 2012).The fourth power plant has been under development since 1999, but has faced a number of hurdles (WNA 2014). There is increasing public pressure to stop the forth nuclear power plant and there may be a public referendum on the development. It is possible that the forth nuclear power plant will be abandoned. Around US$9.5 billion (NT$238 billion) has already been spent on the plant, and the suspension of development will likely bankrupt Taipower (Liao & Jhou 2013).Even if Chinese Taipei were to pursue further development of its nuclear industry, high population density between cities and existing capacity limits the space available for development. This has safety implications for the storage of spent fuel (Hwang 2012).

Renewable energyAfter making a voluntary commitment to the Kyoto Protocol in 2005, a number of renewable energy projects were initiated to meet announced targets. However, a change in government with a focus on nuclear power in 2008 resulted in the budgets for these projects being reduced or eliminated and their progress stalled. This delayed the development of a renewable energy industry in Chinese Taipei (Hwang 2012).Chinese Taipei has a number of renewable energy sources that could be developed including solar (particularly in the south), wind (especially on the west coast and in the Taiwan Strait), ocean (using the Pacific Ocean currents) and geothermal. The main issues that Chinese Taipei faces in developing renewable energy include:

the cost relative to traditional fuels concerns about supply stability limited resources—hydro is scarce land availability and terrain (Liang 2012).

The large-scale uptake of renewable technologies will be limited by land availability and suitable sites (Chang 2012). Chinese Taipei’s size and mountainous terrain will obstruct the widespread adoption of renewable technologies (Liao & Jhou 2013).Chinese Taipei has already developed most of its suitable hydro power sites so there is not much scope for future expansion (Fox 2011). Accordingly, the government is currently prioritising the development of wind and solar energy. However, both technologies face problems with implementation (Liao & Jhou 2013). The cost of renewable energy is still too high to be competitive, especially with regulated prices (Hwang 2012). It is unlikely that consumers will accept higher electricity prices required for generators to remain profitable, particularly if regulated pricing is removed prior to large-scale rollout of renewable energy and prices increase (Liao & Jhou 2013).Both wind and solar technologies are intermittent and weather dependent. Given its geographical isolation and high reserve margin requirements, intermittency will reduce reliability and certainty of supply. As such, generation from renewable sources will need to be periodically supplemented to ensure stability in the energy system. Most of Chinese Taipei’s back-up capacity is fossil-fuel based (Chang 2012; Liao & Jhou 2013).Other renewable energy technologies in Chinese Taipei are at the development and demonstration stage. Consequently, it could be a long time before they are deployed (Liao & Jhou 2013). Given Chinese Taipei’s technological expertise, they could potentially become a leader in renewable technology development (Wakefield 2012).Chinese Taipei has research and development and information communications technology capacity, with a history of innovation to reduce costs that will assist in the development of its renewable

energy industry (Liang 2012). However, technology development remains behind many other countries. Progress could be assisted through international cooperation but Chinese Taipei’s special economic status precludes it from actively participating in many fora (Liao & Jhou 2013).

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The Asia-Pacific LNG market: recent past and medium term outlookRoss Lambie

IntroductionAustralia has seven new LNG liquefaction facilities at various stages of construction with a combined capacity of 61.8 million tonnes a year that are due to enter the export market by 2022. An additional eight projects with a combined capacity of about 60 million tonnes a year are proposed but remain uncommitted awaiting, final investment decision. Currently, more than two-thirds of the global investment in LNG liquefaction is occurring in Australia (IEA 2013a).The IEA (2013a, pp.124–125) have recently stated that “[t]he Asia-Pacific region is the arena in which the most profound changes in global gas markets are set to play out over the coming decades, though the speed and extent of these changes is subject to a high degree of uncertainty”. This situation will occur at a time when Australia is projected to soon become the world’s largest exporter of LNG. To understand the likely implications for Australian LNG over the medium-term, it is necessary to identify the main factors likely to affect demand and supply conditions in the Asia-Pacific market.This review examines the significant factors that may impact on the Asia-Pacific LNG market’s supply and demand conditions over the medium term and Australia’s role in it as a major LNG producer. It is presented in two parts, with the first part providing a historical context through a snapshot of the most recent five year period (2008–2012) for which there is comprehensive data, and then focusing on Australia’s LNG exports to the Asia-Pacific region up to 2013. The second part looks forward over the medium-term, highlighting potentially key factors that may affect supply and demand for LNG in the region.

A five year review of LNG trade in the Asia-Pacific, 2008 to 2012In 2012, global natural gas consumption grew to an estimated 3 427 billion cubic metres, representing 21 per cent of global primary energy, and ranking natural gas third behind oil and coal in the primary energy mix. In that year the Asia-Pacific region’s share of natural gas use was a relatively low at 11 per cent of total energy consumption compared to 30 per cent in the rest of the world. Of particular note was China’s use of natural gas, which in 2012 represented only 5 per cent of their total energy consumption.

The Asia-Pacific region’s demand for LNG has grownLNG’s share of global gas demand reached 9 per cent (320 billion cubic metres) in 2012, which is equivalent to about 235 million tonnes a year. This is a 32 per cent increase on the 172 million tonnes a year of LNG traded in 2008 (GIIGNL 2013). Figure 1 shows the regional breakdown of LNG imports over the five year period from 2008 to 2012. The Asia-Pacific region has made the largest contribution to the growth in total global LNG imports, increasing by about 40 per cent over the period. In 2012, economies in the Asia-Pacific region imported just over 167 million tonnes a year of LNG, which is two and a half times the volume of the next largest importing region, Europe.Figure 1: World LNG imports by region, 2008–2012Please refer to page 142 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

As shown in figure 2, over the five year period Japan was by far the largest LNG importer in the Asia-Pacific region, with its imports increasing at a compound yearly rate of 5 per cent. Japan and South Korea’s imports combined account for about half of global LNG imports each year. Both countries rely heavily on LNG imports to meet their natural gas demand as neither is connected to any international gas pipelines. In 2012, Japan imported 88 million tonnes of LNG, which is just over 36 per cent of the global LNG market for that year. A large share of Japan’s LNG is consumed in electricity generation, which has increased significantly since the Great East Japan Earthquake in 2011 due to the shut-down of the nuclear generation fleet – 30 per cent of the country’s electricity generation capacity. South Korea’s LNG imports reached about 38 million tonnes a in 2012 and increased at a 5 per cent compound yearly growth rate over the five years, mostly driven by residential and commercial demand.

Figure 2: Asia-Pacific LNG imports by country, 2008–2012Please refer to page 143 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Although not shown in figure 2 due to the relatively insignificant amount, Indonesia imported 0.7 million tonnes of LNG in 2012. While China imported only 14.7 million tonnes a year in 2012, or about 17 per cent of Japan’s imports, its LNG imports grew at a compound yearly growth rate of 34 per cent over the five years. The two consumers with the next highest annual growth rates are India and Chinese Taipei, at 10 percent and 7 per cent, respectively.

A mixed response by LNG exportersThe increased demand for LNG in the Asia-Pacific over 2008–2012 resulted in some exporting countries becoming increasingly attracted to the region (Figure 3). Traditionally, the large exporters to the Asia-Pacific have been Qatar, Malaysia, Australia and Indonesia. Of these countries, Qatar’s exports increased at a 15 per cent compound yearly growth rate over the period, followed by Australia at 6 per cent, Malaysia at 1 per cent and Indonesia declining by 1 per cent. Indonesia’s poor export performance is part of a longer term deterioration that began in 2003 (Rogers and Stern 2014).Figure 3: Exports of LNG to Asia-Pacific by country, 2008–2012Please refer to page 144 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

As shown in figure 3, with the exception of the Russia, Nigeria and ‘other’, there were declines in LNG exported from the remaining relatively smaller suppliers to the region (Oman, Brunei, and Abu Dhabi). Nigeria and Russia increased their exports to the Asia-Pacific by two and one third times over the periods 2008–2012 and 2009–2012, respectively, representing a compound yearly growth rate of 18 per cent for both countries. As shown in figure 4, there was a relatively stronger growth in exports from both Qatar and Nigeria than the other exporting countries from 2010 to 2012. This reflects the increase in liquefaction capacity that became available in both countries over the period, especially Qatar, which allowed them to respond to the increase in demand in the region.Figure 4: Exports of LNG to Asia-Pacific from selected countries, 2008–2012Please refer to page 144 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Tighter conditions bring changes to the marketA general feature of global LNG trade during the 2000s is the increasing flexibility of LNG contractual arrangements, particularly with respect to cargo destination, and the interconnectedness of regional markets (IEAb 2013). At the end of 2012, global liquefaction capacity had grown to about 282 million tonnes a year located in 18 countries, from about 202 million tonnes a year in 15 countries in 2008 (GIIGNL 2009). Over the same period regasification capacity had grown from 471 to 668 million tonnes (GIIGNL 2009, 2013). At the end of 2012, half of the world’s regasification capacity was located in the Asia-Pacific region (GIIGNL 2013).Growing natural gas demand in the Asia-Pacific over the period, in particular Japan’s increased reliance on gas-fired electricity generation, along with delays in the commissioning of new LNG liquefaction facilities contributed to a tightening of the Asia-Pacific LNG market (IEA 2013). The increase in LNG demand in the region was not only attributable to the ’traditional’ importing countries, but also to Thailand and to a lesser extent Indonesia entering the demand-side of market. As shown in figure 5, the region’s market tightness is reflected in the higher annual price of LNG imported by Japan compared to the other regional gas prices. These price differences increase significantly over the period reviewed, particularly with respect to North America.As a consequence of the large price differentials between Asia-Pacific LNG and gas in other regions, Japan has strongly expressed its desire to move away from long-term contracts linked to the crude oil price, to an alternative pricing arrangement based on the United States Henry Hub gas price or an Asia-Pacific regional gas hub price index. This year Singapore officially opened a three storage tank LNG terminal – capacity of 6 million tonnes a year – with the aim of becoming a regional LNG hub for supplying short-term LNG to the region, and intends to expand the facility to 9 million tonnes a year. The growing interest by importers for a new basis for pricing LNG is a significant development, as long-term contracts linked to the oil price have been the main pricing mechanism in the Asia-Pacific region for nearly three decades.Figure 5: LNG, natural gas and crude oil average annual prices, 2008–2012Please refer to page 145 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

With the exception of North American gas prices, other regional gas prices increased from either 2009 or 2010. As shown in figure 6, these price increases correspond with an increase in the quantity of LNG delivered through spot market and short-term contracts (up to four years) globally. Estimates of the spot/short-term LNG market’s share of global LNG imports in 2012 range from 25 per cent (GIIGNL 2013) to 31 per cent (IGU 2013). It is estimated that in 2012 about 19 per cent of Asia-Pacific’s LNG imports was on a spot delivery basis (Rogers and Stern 2014). In that year Japan was the largest buyer of spot/short-term LNG taking delivery of just over 19.4 million tonnes, followed by South Korea (9.3 million tonnes), India (5.7 million tonnes), China (3.3 million tonnes), Chinese Taipei (2.8 million tonnes) and Thailand (1.0 million tonnes). Japan was also the largest buyer of spot/short-term contracts over the whole five years, increasing the amount of LNG purchased under these contracts by 46 per cent compared to a 27 per cent increase in total LNG imports. In 2012, the three largest exporters of spot/short-term LNG to Asia-Pacific in terms of millions of tonnes were in descending order, Qatar (11.8), Nigeria (7.9) and Indonesia (3.6).Figure 6: Spot/short-term LNG imports compared to global LNG imports, 2008–2012 million tonnes a

year (mtpa)Please refer to page 146 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

In 2013, Australian LNG exporters continue to consolidate their position in the Asia-Pacific regionMore recently in 2013, a total of 164.5 million tonnes of LNG was imported by Asian-Pacific countries (Argus 2014). Just over half of this amount (53 per cent) was to Japan, followed by South Korea (24 per cent), China (11 per cent), Chinese Taipei (7 per cent), India (4 per cent) and Thailand (1 per cent). Australia’s share of LNG exported to the region in 2013 was 13.5 percent, or just over 22.2 million tonnes. This is lower than Australia’s total LNG export capacity of 24.2 million tonnes a year at the end of 2013, consisting of the North West Shelf with 16.3 million tonnes a year, Darwin LNG with 3.6 million tonnes a year and Pluto LNG with 4.3 million tonnes a year, due to the Pluto LNG plant only commencing operation in 2012.Australia exported LNG to five countries in the Asia-Pacific region during 2008 to 2013 (Chinese Taipei, India, China, South Korea and Japan). Figure 7 shows the variability of annual LNG exports from Australia to the three smallest importing countries (Chinese Taipei, South Korea and India), and the comparative stability of exports to Australia’s second largest export destination, China, since 2009. Of particular note, is the response by Australian LNG producers to Japan’s need for larger volumes from 2011 following the shut-down of its nuclear electricity generation plants. Japan was by far Australia’s largest export destination for LNG over the 2008 to 2013 period, taking delivery of just under 80 per cent of LNG exported in 2013 (17.9 million tonnes), which represents a 49 per cent increase over the six years.Figure 7: Australia’s LNG exports to Asia-Pacific, 2008–2013Please refer to page 147 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Figure 8 illustrates the relative significance of each of the importing countries in 2013 in terms of their percentage share of Australia’s total LNG exports.Figure 8: Share of Australia’s total Asia-Pacific LNG exports by country, 2013Please refer to page 148 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Although growing in absolute terms, Australia’s share of total LNG exports to the Asia-Pacific varied between a high of 16 per cent in 2009 and a low of 12 per cent in 2012, and was about 14 per cent in 2013. Figure 9 provides a breakdown of Australia’s share of total LNG exports to each of the five LNG importing countries in the region during the period.Figure 9: Australia’s share of LNG exports to Asia-Pacific countries, 2008–2013Please refer to page 148 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

The decline in Australia’s share of exports to China and the relative stability of its share of exports to Japan during this period of rapid growth in the region’s LNG demand, highlight the inertia suppliers may face in responding in the short-term to significant increases in consumption (such as the Fukushima incident). In Australia’s case, this inertia is mostly due to a large share of LNG production being tied to existing contracts, and new liquefaction capacity still being constructed. The significance of the capacity constraint is highlighted by Australia’s three operating LNG plants currently having only 1.6 million tonnes a year, or just over 6.5 per cent, of their total capacity uncontracted.

Medium-term outlook for Asia-Pacific LNG tradeBP (2014) and the IEA (2013a) show in their long-term projections to 2035 that natural gas continues to substitute for coal and oil in the global energy mix, and that the Asia-Pacific increasingly becomes the major region for international trade in gas. The general outlook scenario from these projections provides the context for a medium-term outlook. Ongoing demand in the region is driven by a range of factors relating to total energy demand and energy intensity as countries undergo various stages of economic development (industrialisation and urbanisation) and address issues concerning energy security and environmental objectives. While gas is supplied from an array of indigenous gas and pipeline import options to meet demand, LNG imports from an increasingly diverse range of suppliers continues to be an important and growing source of gas in the region. By the end of the projection period, China and India become the two largest LNG importers in the Asia-Pacific. In terms of supply, Australia is joined by the United States, Canada and East Africa, in competing with Qatar for LNG exports to the region.The following medium-term outlook for demand and supply focuses on some of the key countries and factors that may affect market conditions in the region, to around the end of this decade and early into the next. For a more detailed assessment of demand conditions to 2019 see the gas section of this edition of Resources and Energy Quarterly.

Outlook for LNG demand largely depends on China and IndiaAs stated above, Japan, China, South Korea, Chinese Taipei and India are currently the five largest LNG importing countries in the region. Over the medium-term, demand for LNG in South Korea, Chinese Taipei and Japan are expected to continue to be driven by the growing consumption of gas in the residential and commercial sectors, but the rate of growth in consumption is expected to moderate. Japan, China and India are the three countries that are likely to have the largest impact on LNG demand.

JapanJapan’s demand will depend on how many of its nuclear power plants that were shut down as a result of the Fukushima incident are approved for restart and the timing of the restarts. The Japanese Government has reaffirmed the role of nuclear generation as a component of base load electricity generation. Although the impact of this decision on gas use remains uncertain, the restarting of nuclear plants may have only a small impact on LNG demand if the price relativity between imported oil and LNG favours gas-fired generation as a substitute for oil-fired generation. Japan’s LNG imports are projected to decline from its 2012 level (around 88 million tonnes a year) until 2015, and then only return to the 2012 level in 2025 (Rogers and Stern 2014).

ChinaChina’s demand for LNG is the key factor for the region’s overall demand over the medium-term, as it is both potentially large and highly uncertain. It is expected that per capita energy consumption in China will expand at a high growth rate over the medium term due to the pace of industrialisation and an ongoing expansion of the middle class. A consequence of this is that total natural gas consumption is expected to increase to about 221 billion cubic metres in 2020 from about 147 billion cubic metres in 2012 (EIA 2014). Current five-year plans aim to increase the share of gas-fired electricity generation to address air quality issues, develop city gas infrastructure, and move the natural gas sector to market-based pricing to incentivise upstream and infrastructure investment. It is projected that by 2025 China’s LNG imports may reach the levels imported by Japan in 2012 (Rogers and Stern 2014). However, China’s need for LNG to meet gas demand will depend on several factors:

the extent and timing of additional imported pipeline gas from Central Asia (Turkmenistan, Kazakhstan and Uzbekistan) and Myanmar, and possibly Russia

the scale and speed of domestic coal seam gas and shale gas production the development of storage capacity government policy and regulations affecting gas consumption.

Over the medium-term, pipeline gas from Central Asia in particular is a factor that could have a major impact on China’s LNG demand. China has significant investment in the development of Turkmenistan’s Galkynysh gas field. This field has the second largest reserves in the world, estimated between 13.1 and 21.2 trillion cubic metres, and is due to reach peak production in 2014. Gas from the Galkynysh field will flow to China through the Central Asia-China Gas Pipeline (CACGP). The

CACGP is being expanded from two existing pipelines, Lines A and B transporting 30 billion cubic metres a year, to a third pipeline (Line C ) which will be operational later this year and add a further 25 billion cubic metres a year. Construction on a fourth artery (Line D) is expected to start in late 2014 and increase the total amount of gas delivered to China through the CACGP to 80 billion cubic metres a year by 2020.

IndiaIndia is expected to continue to have significant growth in energy consumption over the medium term due to rapid economic growth and population growth. In recent years natural gas consumption has been around 10 per cent of total energy consumption. In 2011–12, electricity generation and fertilizer production together accounted for just over 69 per cent of India’s gas consumption (44 per cent and 25 per cent, respectively), while residential consumption was 6 per cent. Although India has 1.3 trillion cubic metres of gas reserves (CSO 2013), domestic gas production is unable to satisfy demand largely because of supply constraints (ageing off-shore fields, poorly performing new discoveries and lack of infrastructure). There are no pipeline connections with another country and, therefore, India is totally reliant on LNG to meet its imported gas requirements. The Indian Government is attempting to implement a range of measures to incentivise investment in the domestic upstream and downstream gas sectors and LNG import infrastructure, and reduce gas price distortions and competing fuel price subsidies. Given India’s reliance on imported LNG, further government initiatives relating to these areas are expected over the medium-term. Several uncertainties affecting India’s future demand for LNG remain:

the share of India’s gas demand that can be supplied domestically, including the potential for production from shale resources

whether the price of gas is based on LNG imports or possibly cheaper domestic gas supply the speed and effectiveness of reform to remove price distortions for domestic suppliers and

gas consumers the role of gas in the electricity generation mix.

Over the medium term LNG imports are expected to continue to grow, although the amount of growth will depend heavily on the successful implementation of government initiatives. India has substantial capacity to increase the volume of LNG imported through its four regasification import terminals on the west coast (three fully operational and one operating six months each year).

Outlook for LNG supply depends on more than Australia and North AmericaAustraliaAbout 80 per cent of the 61.8 million tonnes a year of liquefaction projects under construction in Australia is already contracted to customers in the Asia-Pacific region. While there are proposals for investment in another 60 million tonnes a year of liquefaction capacity, it remains unclear whether these projects will proceed. The IEA (2013a) highlight the main factors affecting these investment decisions as:

the outlook for development costs (taxation, regulatory, construction and engineering), which have been substantially higher than originally expected for current projects

the viability of alternative technologies that may lower costs, such as floating LNG the degree of competition from other export countries, mainly from North America.

Of these factors, development costs is the most significant as it also determines the other two. For some of the current Australia liquefaction projects construction and engineering costs are as high as 50–60 per cent of total project costs, which is considerably higher than the 30 per cent share typically incurred by projects elsewhere (Songhurst 2014).An additional factor confronting Australian LNG production is the cost of producing gas from unconventional gas reserves. Recent experience indicates that coal seam gas production on the east coast in Queensland is more costly and uncertain than originally estimated by LNG proponents. Over the medium term there is expected to be increased interest in shale and tight gas production as potential sources of supply for future LNG projects. Whether or not this gas would underpin further investment in LNG projects in Australia will depend on its cost, which is also likely to be subject to considerable uncertainty.

North AmericaThere is also significant potential for LNG exports from North America to the Asia-Pacific region. The United States is expected to become a net exporter of LNG around the middle of this decade (EIA 2013). All exports of LNG from the United States must be authorised by the Department of Energy (DOE). However, unlike exports to free trade agreement (FTA) countries (South Korea and Singapore are two in the region) applications for the authorisation of exports to non-FTA countries must pass a public interest test. Authorisations are conditional until they are reviewed and approved by the Federal Energy Regulatory Commission (FERC). To date DOE has authorised six applications for LNG exports to non-FTA countries consisting of five major projects (Sabine Pass at 16 million tonnes a year, Freeport at 13.2 million tonnes a year, Lake Charles at 15 million tonnes a year, Dominion Cove Point at 5.25 million tonnes a year and Cameron at 12 million tonnes a year). Only one of these authorisations, the 7.7 million tonnes a year from Sabine Pass, has unconditional approval from FERC for the export of LNG, which is expected to begin in 2015–2016. The total volume of both conditional and unconditional authorized non-FTA LNG exports is now equivalent to about 61.5 million tonnes a year. This creates the potential for significant amounts of LNG to be exported to Asia-Pacific countries over the medium-term. There remain 22 pending applications for a further 20 facilities totalling about 200 million tonnes a year of export capacity seeking non-FTA LNG export authorisations.Liquefaction projects that have so far been granted authorization from the DOE have benefited from being brownfield developments of regasification facilities with existing shipping and storage infrastructure, resulting in relatively lower costs and shorter construction times compared to proposed greenfield facilities and the Australian projects. A brownfield base liquefaction project may be 50 per cent of the cost of a comparable greenfield project (Songhurst 2014). Most of the projects that are now waiting for a non-FTE export authorisation are greenfield projects. Through the amount of liquefaction capacity authorised and their relative cost competitiveness, the United States has the potential to gain a large share of the Asia-Pacific market over the medium term.Canada’s National Energy Board has to date granted export licences to three proposals for greenfield LNG projects totalling 36.8 million tonnes a year (Kitimat LNG at 11 million tonnes a year, BC LNG at 1.8 million tonnes a year and LNG Canada at 24 million tonnes a year) and there are proposals for a further seven projects all located on the west coast in British Columbia. These projects have a combined capacity of about 160 million tonnes a year (FERC 2014). Although none of the licensed projects has passed a final investment decision, if they were to proceed the LNG produced is destined for the Asia-Pacific market. Although Canadian LNG greenfield projects are more costly to develop than the United States brownfield projects, the shipping cost from the west coast of Canada is significantly lower than from the Gulf of Mexico and eastern United States.There is potentially a wall of LNG supply from Australia and North America that could hit the Asia-Pacific market over the medium term to take advantage of expected high prices. This supply has largely arisen from the discovery of and ability to commercialise huge reserves of gas in shale formations and coal seams. Many speculations on medium term conditions for LNG supply to the Asia-Pacific region frame the dynamics as a contest between Australia and North America. There are relative advantages associated with each source of supply. While Australia’s costs for developing export capacity is estimated to be 20 to 30 per cent higher than North America (McKinsey 2013), Australian projects benefit from being more advanced in their completion and located closer to the region’s customers. While North American liquefaction facilities are further away from the region and, therefore, LNG shipping costs are higher, the pricing arrangements adopted by the United States projects are based on Henry Hub gas prices, liquefaction tolling fees and unrestricted destination clauses. Such arrangements provide customers with more flexibility compared to traditional long-term contracts linked to oil, as are used by Australian LNG producers.

Other factors affecting LNG supplyAlthough Australian and North American LNG projects dominate the supply outlook, there are three other significant factors that, although very uncertain, may have a large bearing on LNG supply conditions to Asia-Pacific over the medium-term:

Russia’s gas market liberalisation China’s response to growing gas demand New sources of LNG supply from Papua New Guinea and East Africa.

Russia’s liberalisation of its gas market and the recent granting of export licences to privately owned producers Rosneft and Novatek has brought to an end Gazprom’s monopoly on LNG exports from its 9.6 million tonnes a year Sakhalin 2 facility in the far east. This is part of a broader energy strategy that aims to increase Russia’s share of both pipeline gas and LNG exports to the Asia-Pacific region

by 2020 (Bradshaw 2013). LNG is projected to make up the major share of gas exports, and is likely to include supply from new liquefaction plants, including Novatek’s Yamal LNG facility to be located in the Arctic (5.5 million tonnes a year initially, increasing to 16.5) and due for first LNG in 2017, and two proposed projects located in Russia’s Far East, Rosneft’s Sakhalin LNG (5 million tonnes a year) and Gazprom’s Vladivostok LNG (10 to 15 million tonnes a year). In addition to the potential for increased LNG exports, there is a proposal for a substantial amount of pipeline gas (equivalent to about 28 million tonnes a year) to be supplied to China by 2025.China’s strategy for meeting its gas demand will also impact on the demand for LNG in the region and, therefore, the tightness of the market as new LNG supply comes online. LNG imports are only one supply option for China. As mentioned in the demand outlook, in addition to importing gas from Russia, China could increase its domestic production of gas and source more pipeline gas from Central Asia and Myanmar to the south. It is important to appreciate that how China responds through its choice of supply options to its significant growth in gas demand driven by economic activity and population growth, and objectives with respect to energy security and environmental objectives over the medium term is very uncertain, but may have significant implications for LNG demand in the region.The third factor is the projected supply of LNG to the region from new exporting countries: Papua New Guinea, Mozambique and Tanzania. Papua New Guinea’s Elk and Antelope gas fields are being developed for the purpose of producing LNG. First LNG is scheduled in the second half of 2014 from the 6.9 million tonnes a year, two train PNG LNG joint venture plant constructed and operated by ExxonMobil. The LNG from this plant is contracted to China, Japan and Chinese Taipei. There are also proposals for additional LNG trains located on the Gulf of Papua, either through an expansion of the PNG LNG facility to three or more trains and/or the development of a separate Gulf LNG project (3.8 million tonnes a year). Final investment decision on the Gulf LNG project is expected in 2016 and, therefore, if it did proceed it is unlikely that it would be operational until around 2020 at the earliest.The entry of East Africa into the Asia-Pacific market is not expected to occur until after 2020 (Herberg 2013). Both Mozambique and Tanzania have sufficient off-shore gas reserves (estimated at 3.4–4.0 trillion cubic metres and 630 billion cubic metres, respectively) for the development of LNG production and export, although Mozambique is better placed to enter the market first. Preliminary calculations suggest that LNG from East Africa may be exported to Japan at costs competitive with LNG production on the west coast of Australia and the Gulf of Mexico in the United States (Ledesma 2013). The key uncertainty for East African LNG is the timing of its entry into the Asia-Pacific market. Anadarko and ENI East Africa are due to begin early stage work in 2014 on a 20 million tonnes a year liquefaction plant on the Afungi peninsula area in Mozambique. The project includes options to expand the capacity of the facility to 50 million tonnes a year. Details on a proposed Tanzanian LNG project to be developed by Statoil and BG Group, who have each discovered significant recoverable volumes of offshore gas, are expected in April 2014. Although there are several major challenges facing East African projects such as lack of infrastructure, poorly developed regulatory settings and fiscal regimes, and sovereign risk, East Africa is expected to play an increasing role in supplying the Asia-Pacific LNG market.

ConclusionAustralia has a relatively long and reliable past in exporting LNG to the Asia-Pacific region. Australian LNG producers have, and are, responding to large increases in demand for gas in many of the region’s countries, and this expanding demand is projected to continue well into the future. Substantial liquefaction capacity is due to come online over the medium term. Recent developments in the market, such as Japan’s reliance on gas-fired electricity generation following the Fukushima incident and large growth rates in LNG demand from China, India and Chinese Taipei have seen Qatar, Russia and Nigeria increase their share of exports to the region.Demand and supply conditions over the medium term are expected to reduce the market’s present tightness. LNG demand in the region will depend on Japan, China and India and, therefore, the specific policies adopted by each country regarding gas demand and options for gas supply. There is potentially a huge amount of LNG supply that could enter the Asia-Pacific market over the medium term. Australia and the United States are presently in a race to develop liquefaction projects and bring on supply. Papua New Guinea is due to start supplying LNG as early as this year. While projects proposed in Canada, Russia and East Africa (Mozambique and Tanzania) are not as progressed, they have the potential to substantially add to the competition for supply. In addition, to these LNG supply factors is a major wildcard in the form of China’s ability and desire to meet its gas demand through pipeline imports and domestic production.This highlights that LNG demand projections need to be considered in light of expectations regarding

the costs of alternative energies, domestic gas and imported pipeline gas, and government policies and regulations. LNG is the balancing item for consumption and, hence, subject to the combined effect of the uncertainties surrounding all these expectations. Forecasting LNG demand is, therefore, inherently difficult.How the demand and supply conditions will play out over the medium term is very uncertain. While Australia is soon to be the world’s largest exporter of LNG, this will occur in a period of increasing competition from new entrants into the Asia-Pacific market. This situation is likely to have implications for future investment in LNG projects in Australia. Project proponents seeking to enter the Asia-Pacific market now have several options regarding where to develop LNG liquefaction facilities, and if demand uncertainty persists the option on when to invest in projects may also become a significant decision affecting investment. The expansion of LNG production capacity in Australia over the medium term will, therefore, depend on it remaining a competitive destination for this investment given the large uncertainties facing the Asia-Pacific LNG market and alternative opportunities for developing supply in North America and East Africa.

ReferencesAgrus, 2014, Global LNG Monthly. March.BP, 2014, BP energy outlook 2035. http://www.bp.com/energyoutlook——2013, Statistical Review of World Energy. June 2013.

http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy-2013.html

Bradshaw, M., 2013, Russian LNG exports to Asia: Current status and future prospects, in Asia’s uncertain future, The National Bureau of Asian Research, Special Report 44, November 2013, pp.37-50.

CSO (Central Statistics Office), 2013, Energy statistics 2013. Ministry of Statistics and Programme Implementation, Government of India, New Delhi.

EIA (U. S. Energy Information Agency), 2014, China. Washington D.C. http://www.eia.gov/countries/cab.cfm?fips=ch

—— 2013, AEO2014 Early release overview. Washington D.C. http://www.eia.gov/forecasts/aeo/er/index.cfm

FERC (Federal Energy Regulatory Commission), 2014, LNG. http://www.ferc.gov/industries/gas/indus-act/lng.asp

GIIGNL , 2013, The LNG industry 2012. International Group of Liquefied Natural Gas Importers.—— 2012, The LNG industry 2011.——2011, The LNG industry 2010.—— 2010, The LNG industry 2009.——2009, The LNG industry 2008.Herbeg, M.E., 2013, Asia’s uncertain LNG future: Conclusions and implications for the United States

and Asia. In Asia’s uncertain future, The National Bureau of Asian Research, Special Report 44, November 2013, pp. 61–65.

IEA (International Energy Agency), 2013a, World energy outlook 2013. France, Paris.--2013b, Gas medium-term market report 2013.IGU (International Gas Union), 2013, World LNG report – 2013 Edition. Norway.Ledesma, 2013, East Africa gas – potential for export, NG 74, The Oxford Institute for Energy Studies,

March 2013.

McKinsey, 2013, Extending the LNG boom: improving Australian LNG productivity and competitiveness. McKinsey & Company, May 2013.

Rogers, H. V. And Stern, J., 2014, Challenges to JCC pricing ain Asian LNG markets. OIES Paper, NG 81, Oxford Institute for Energy Studies.

Songhurst, B., 2014, LNG plant cost escalation. OIES Paper, NG 83, Oxford Institute for Energy Studies.

Resourcesand Energy

QuarterlyStatistical tables

Contribution to GDPPlease refer to page 160 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Principal markets for Australian importsPlease refer to page 160 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Principal markets for Australian exportsPlease refer to page 161 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Principal markets for resources and energy exportsPlease refer to page 162 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Tables 1–2:Please refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 statistical data Excel workbook.

Table 3: Contribution to exports by sector, balance of payments basis, AustraliaPlease refer to page 52 of the Resources and Energy Quarterly – March quarter 2014 PDF version.

Tables 4–41:Please refer to the associated Excel sheet of the Resources and Energy Quarterly – March quarter 2014 commodity data Excel workbook.