Fuel cost projections

Transcription

1 Updated natural gas and coal outlook for AEMO modelling Prepared for AEMO 28 June 2012

2 Reliance and Disclaimer The professional analysis and advice in this report has been prepared by ACIL Tasman for the exclusive use of the party or parties to whom it is addressed (the addressee) and for the purposes specified in it. This report is supplied in good faith and reflects the knowledge, expertise and experience of the consultants involved. The report must not be published, quoted or disseminated to any other party without ACIL Tasman s prior written consent. ACIL Tasman accepts no responsibility whatsoever for any loss occasioned by any person acting or refraining from action as a result of reliance on the report, other than the addressee. In conducting the analysis in this report ACIL Tasman has endeavoured to use what it considers is the best information available at the date of publication, including information supplied by the addressee. Unless stated otherwise, ACIL Tasman does not warrant the accuracy of any forecast or prediction in the report. Although ACIL Tasman exercises reasonable care when making forecasts or predictions, factors in the process, such as future market behaviour, are inherently uncertain and cannot be forecast or predicted reliably. ACIL Tasman shall not be liable in respect of any claim arising out of the failure of a client investment to perform to the advantage of the client or to the advantage of the client to the degree suggested or assumed in any advice or forecast given by ACIL Tasman. ACIL Tasman Pty Ltd ABN Internet Melbourne (Head Office) Level 4, 114 William Street Melbourne VIC 3000 Telephone (+61 3) Facsimile (+61 3) melbourne@aciltasman.com.au Brisbane Level 15, 127 Creek Street Brisbane QLD 4000 GPO Box 32 Brisbane QLD 4001 Telephone (+61 7) Facsimile (+61 7) brisbane@aciltasman.com.au Canberra Level 2, 33 Ainslie Place Canberra City ACT 2600 GPO Box 1322 Canberra ACT 2601 Telephone (+61 2) Facsimile (+61 2) canberra@aciltasman.com.au Perth Centa Building C2, 118 Railway Street West Perth WA 6005 Telephone (+61 8) Facsimile (+61 8) perth@aciltasman.com.au Sydney GPO Box 4670 Sydney NSW 2001 Telephone (+61 2) Facsimile (+61 2) sydney@aciltasman.com.au For information on this report Please contact: Owen Kelp Telephone (07) Mobile o.kelp@aciltasman.com.au Contributing team members Marc Randell

3 1 Introduction ACIL Tasman has been engaged by the Australian Energy Market Operator (AEMO) to provide updated fuel cost projections for use within its National Transmission Network Development Plan (NTNDP) modelling. This work represents an update of cost projections ACIL Tasman provided in December In early 2012 AEMO commissioned economic modelling to be undertaken on each of the five scenarios under evaluation. This work resulted in a range of macro-economic indicators being produced including foreign exchange rate projections. The update has been necessary to bring the exchange rate assumptions used in the development of the fuel cost projections in-line with those produced from AEMO s macroeconomic outputs. The natural gas projections have also used a more recent outlook for Asia-Pacific LNG pricing from the International Energy Agency s 2011 World Energy Outlook report. As with the previous iteration, the scope for this work covers fuel cost projections for natural gas; brown coal and bituminous (black) coal spanning the period to. Fuel costs are provided for new entrants on a financial year basis in real dollars. Costs projections have been made for 5 scenarios in each of the 16 NTNDP zones. This report examines the differences between the two datasets, but does not go into detail about the methodology employed, which remains unchanged from our previous report. This report is structured as follows: Section 2 outlines the projection results for natural gas Section 3 outlines the projection results for black and brown coal. 1.1 Exchange rates Projected exchange rates were provided by AEMO for each scenario as shown in Figure 1 and detailed in Table 1. The actual figures provided were at a quarterly resolution spanning the period March 2010 to June ACIL Tasman has created financial year averages for the purposes of this work. 1 1 Values were also provided for the Euro/AUD, but these have not been used. Introduction 1

4 $US/$AUD Figure 1 Projected USD/AUD exchange rate under each scenario Scenario 1 Fast rate of change Scenario 3 Planning Scenario 5 Slow rate of change Scenario 2 Fast world recovery Scenario 4 Decentralised world Data source: ACIL Tasman based on AEMO provided exchange rates Table 1 Projected USD/AUD exchange rate under each scenario Financial Year Planning and Decentralised World Fast World Recovery Fast Rate of Change Slow Rate of Change Euro USD Euro USD Euro USD Euro USD Data source: ACIL Tasman based on AEMO provided exchange rates Introduction 2

5 $US/$AUD Previously ACIL Tasman had utilised implied exchange rates from Commonwealth Treasury modeling of the Clean Energy Future package for Scenario 3. Exchange rate for other scenarios were set relative to Scenario 3 based on the scenario's commodity price assumptions. Figure 2 presents a comparison with the new exchange rates against the previous assumptions. In Scenario 1 the USD/AUD exchange rate is consistently higher compared with the previous figures, peaking at around 25 cents higher by. Scenario 2 oscillates between being higher and lower (within a ten cent band), with the average level being largely unchanged. Scenarios 3, 4 and 5 are all consistently lower, resulting in higher international commodity prices in Australia dollar terms. Figure 2 Changes from previous exchange rate assumptions Scenario 1 Fast rate of change Scenario 3 Planning Scenario 5 Slow rate of change Scenario 2 Fast world recovery Scenario 4 Decentralised world Data source: ACIL Tasman Introduction 3

6 2 Natural gas 2.1 International gas prices Table 2 details the assumed LNG import prices in the latest IEA World Energy Outlook 2011 under three future scenarios. As Japan is the dominant buyer of LNG, these prices have been used to represent the more general LNG prices available in the Asia-Pacific region. Table 2 Japan LNG import prices (Real 2010 US$/mmbtu) IEA scenario New Policies Current Policies ppm Data source: IEA World Energy Outlook 2011, Table 1.4, page 64 The New Policies has been used to represent the Planning scenario within this work (Scenario 3). The real 2010 figures above have been converted into real dollars by inflating at 6.3% (actual and anticipated US inflation over this period). LNG prices for other scenarios have been constructed around these values reflecting the combination of economic growth, commodity prices and international carbon abatement policies assumed under each of the NTNDP scenarios. The only difference in the relativities between the LNG prices under the NTNDP scenarios is Scenario 5 Slow rate of change in which the low economic growth variable had been given a larger weighting, resulting in it becoming the lowest LNG price scenario (previously it was in between scenarios 3 & 4). These prices have been translated back to equivalent prices at Gladstone, by deducting regasification and shipping costs of US.80/mmbtu and converting to A$/GJ based on the scenario's exchange rate assumption. These are shown in Figure 4 and represent the value at Gladstone once liquefied. Given the larger spread in exchange rates now being used, the resulting LNG price spread in Australian dollars is also wider, ranging between A/GJ to A0/GJ in real dollars. Natural gas 4

7 Real A$/GJ Real US$/mmbtu Figure 3 Assumed Asia-Pacific LNG prices under the NTNDP scenarios $18 Scenario 1 Fast rate of change Scenario 3 Planning Scenario 5 Slow rate of change Scenario 2 Fast world recovery Scenario 4 Decentralised world Data source: ACIL Tasman analysis Figure 4 LNG prices at Gladstone under the NTNDP scenarios 5 0 $15 $5 Scenario 1 Fast rate of change Scenario 3 Planning Scenario 5 Slow rate of change Scenario 2 Fast world recovery Scenario 4 Decentralised world Note: Implied value of LNG at Gladstone Data source: if outside data used and we have charted it These values are then converted back to an effective wellhead value for the purposes of estimating equivalent 'LNG netbacks' for additional LNG trains. 2 We estimate an equivalent tolling charge on pipeline and liquefaction capital of around A$3/GJ, with an additional A$1/GJ added to account for risk 2 Note that for existing or committed facilities, pipeline and liquefaction capital costs represent a sunk investment and hence operators would be seeking the full LNG value (cost of spot LNG cargoes) if required feedstock gas was to be redirected to the domestic market. Natural gas 5

8 Real A$/GJ premium (total discount of A/GJ). 3 The estimated effective netback prices are shown in Figure 5. In the period to 2020, netback prices range between A/GJ and A/GJ for new developments. This range increases to A/GJ to A$15/GJ in the second decade of the projection period. The primary reason for the larger netback range is the foreign exchange assumptions now in use. Figure 5 Effective LNG netback for domestic producers for new LNG Scenario 1 Fast rate of change Scenario 3 Planning Scenario 5 Slow rate of change Scenario 2 Fast world recovery Scenario 4 Decentralised world Data source: ACIL Tasman analysis 2.2 Scenario results The charts below show the price results for the Moomba hub which is a representative price for the East coast market. For each scenario, the chart on the left shows projected market clearing prices (akin to a spot price), whilst the chart on the right is a 10 year levelised price, which would be more reflective of long-term contract prices available. Levelised prices are calculated as a contract price (constant in real terms over a 10 year period) which would be equivalent in NPV terms (using 10% real discount rate) to the spot price projection over the same period. ACIL Tasman would recommend using this series for new entrant fuel costs as it better mimics the long-term fuel contracting approach associated with new generation developments. The spread sheet accompanying this report contains prices for each of the 16 NEM zones under each scenario/demand sensitivity on a spot and levelised 3 Part of this discount includes the gas losses within the liquefaction process itself. Natural gas 6

9 basis. These projected prices are based on 80% load factor loads (such as baseload-intermediate CCGT developments). A suggested 25% premium should be applied to low load factor loads such as OCGT developments. In some scenarios, LNG netback outcomes provide a floor price where excess domestic production is available to provide feedstock for additional LNG trains. If domestic production costs are significantly below this value, it is likely that additional LNG trains will be developed. Conversely, where large volumes of gas is required for domestic use typically sensitivities 5,6 and 7 prices are set by the long-run marginal cost of production from the marginal fields. As these are above the prevailing netback prices available from LNG, no additional LNG trains are built (above that assumed prior to 2020). Natural gas 7

10 Scenario 1 The settings for Scenario 1 (Fast rate of change) are characterised as follows: high domestic production costs which aligns with high commodity prices 5 committed LNG trains by 2020 low international LNG prices, driven by reduced primary demand for gas due to strong international commitment on greenhouse gas abatement despite strong economic growth high Australian dollar (which aligns with the high commodity price environment) and further reduces LNG netbacks in A$ terms. Projected prices at the Moomba hub for Scenario 1 are shown in Figure 6. This scenario has the lowest LNG prices and high domestic production costs. Netback prices for new LNG developments range between A$3/GJ and $5/GJ which is well below domestic production costs. As a result, no additional LNG trains are developed and domestic prices are strictly set by production costs throughout. The higher domestic demands under sensitivities 4 to 7 result in prices which actually exceed the LNG international spot price, indicating that feedstock gas on existing LNG plants may be redirected into local generation. If the high domestic demand was to be met under these sensitivities, it would imply that LNG proponents would be purchasing spot LNG cargoes from other projects to meet contractual commitments. Figure 6 $18 Scenario 1 results for Moomba hub (Left: spot price; Right: levelised series) Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 LNG netback LNG spot Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 Note: The LNG netback represents the risk-adjusted LNG price less liquefaction and pipeline tolling costs. The LNG spot price series represents the assumed Asia-Pacific LNG price FOB at Gladstone. Data source: ACIL Tasman, GMG Australia modelling Natural gas 8

11 Scenario 2 The settings for Scenario 2 (Fast world recovery) are characterised as follows: high domestic production costs which aligns with high commodity prices 8 committed LNG trains by 2020 reasonably high international LNG prices, driven by strong global economic growth and only moderate greenhouse gas abatement efforts reasonably high Australian dollar which remains above parity with the US dollar throughout (which aligns with the high commodity price environment). Scenario 2 has the highest price outcomes of the scenarios, driven by the large number of assumed LNG trains committed prior to 2020 and higher ex-field costs throughout. LNG netback prices reach around /GJ under this scenario by 2025 onwards, but remains well below domestic production costs in all demand sensitivities. As a result, no additional LNG is developed. Under some of the high demand sensitivities, some feedstock gas is redirected for domestic power generation. Figure 7 $18 Scenario 2 results for Moomba hub (Left: spot price; Right: levelised series) Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 LNG netback LNG spot Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 Note: The LNG netback represents the risk-adjusted LNG price less liquefaction and pipeline tolling costs. The LNG spot price series represents the assumed Asia-Pacific LNG price FOB at Gladstone. Data source: ACIL Tasman, GMG Australia modelling Natural gas 9

12 Scenario 3 The settings for Scenario 3 (Planning scenario) are designed to represent midline "best guess" values and are characterised as follows: moderate domestic production costs 7 committed LNG trains by 2020 moderate international LNG prices, stemming from moderate global economic growth (aligned with IEA projections under the New Policies scenario) moderate Australian dollar, averaging around US.75 in the last 10 years of the projection period. This scenario sees prices high LNG netback prices in Australian dollar terms, resulting in additional LNG development occurring in the post 2020 period under all demand sensitivities. Domestic loads are required to compete with new LNG proposals and as a result, domestic prices are set at netback levels throughout. Due to this there is little price variability between the demand sensitivities. Figure 8 $18 Scenario 3 results for Moomba hub (Left: spot price; Right: levelised series) Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 LNG netback LNG spot Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 Note: The LNG netback represents the risk-adjusted LNG price less liquefaction and pipeline tolling costs. The LNG spot price series represents the assumed Asia-Pacific LNG price FOB at Gladstone. Data source: ACIL Tasman, GMG Australia modelling Natural gas 10

13 Scenario 4 The settings for Scenario 4 (Decentralised world) are characterised as follows: moderate domestic production costs 6 committed LNG trains by 2020 moderate international LNG prices, stemming from moderate global economic growth, but slightly lower than Scenario 3 due to slower population growth moderate Australian dollar averaging US.75 in the last 10 years of the projection period (the same as Scenario 3). Prices under Scenario 4 are similar to Scenario 3, although with one less LNG train committed prior to 2020 and slightly lower LNG prices results in slightly lower price outcomes for the domestic market. Figure 9 $18 Scenario 4 results for Moomba hub (Left: spot price; Right: levelised series) Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 LNG netback LNG spot Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 Note: The LNG netback represents the risk-adjusted LNG price less liquefaction and pipeline tolling costs. The LNG spot price series represents the assumed Asia-Pacific LNG price FOB at Gladstone. Data source: ACIL Tasman, GMG Australia modelling Natural gas 11

14 Scenario 5 The settings for Scenario 5 are characterised as follows: low domestic production costs which aligns with low commodity prices 6 committed LNG trains by 2020 low international LNG prices, driven by lower economic growth but offset to some extent by increased primary demand for gas due to lack of any international commitment on greenhouse gas abatement high LNG prices in A$ terms due to low Australian dollar, averaging US.52 in the last 10 years of the projection (which aligns with the low commodity price environment). This scenario has the highest LNG prices in Australian dollar terms. The modelling sees continual development of additional LNG trains post 2020, with the domestic price under all sensitivities tracking the effective LNG netback, regardless of the level of domestic demand. Figure 10 $18 Scenario 5 results for Moomba hub (Left: spot price; Right: levelised series) Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 LNG netback LNG spot Sensitivity 1 Sensitivity 2 Sensitivity 3 Sensitivity 4 Sensitivity 5 Sensitivity 6 Sensitivity 7 Note: The LNG netback represents the risk-adjusted LNG price less liquefaction and pipeline tolling costs. The LNG spot price series represents the assumed Asia-Pacific LNG price FOB at Gladstone. Both LNG price series have had.85/gj deducted in order to present them at the Moomba hub. Data source: ACIL Tasman, GMG Australia modelling Comparing results across the scenarios Figure 11 shows a comparison of levelised price results for each demand sensitivity across the five NTNDP scenarios. For low levels of domestic demand (i.e. sensitivities 1 to 3) prices are strongly influenced by LNG netback prices. This is due to surplus low cost production capacity stimulating the development of additional LNG trains over the projection period. Domestic gas purchasers are therefore required to pay LNG netback-type prices in order to divert gas away from export markets. Natural gas 12

15 Within sensitivities with higher domestic demand (i.e. sensitivities 5 to 7), low cost gas resources are fully exploited such that additional LNG trains do not appear commercially viable. Under these situations, LNG netbacks are less of an influence over domestic prices, with prices being driven more by incremental production costs. Across the sensitivities, it is clear that Scenario 3 and 5 have the higher prices throughout. Under Scenario 2 it is the combination of high economic growth, population and commodity prices which results in higher production costs and LNG prices. By comparison, Scenario 5 results in high price outcomes due to the lack of global greenhouse abatement efforts (which causes global primary natural gas demand to grow much faster) and the low Australian dollar which results in high LNG prices in Australian dollar terms. Across of sensitivities, Scenario 1 has the lowest price outcomes due to the assumed aggressive global greenhouse abatement efforts, which negatively affects primary gas demand, whilst the Australian dollar remains strong, resulting in low LNG netback prices in Australian dollar terms. Natural gas 13

16 Figure 11 Sensitivity results for Moomba hub (levelised prices) Sensitivity 1 Sensitivity 2 Scenario 1 Scenario 1 Scenario 2 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Scenario 3 Scenario 4 Scenario 5 Sensitivity 3 Sensitivity 4 Scenario 1 Scenario 1 Scenario 2 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Scenario 3 Scenario 4 Scenario 5 Sensitivity 5 Sensitivity 6 Scenario 1 Scenario 1 Scenario 2 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Scenario 3 Scenario 4 Scenario 5 Sensitivity 7 Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Note: Results presented are levelised prices Data source: ACIL Tasman, GMG Australia modelling Natural gas 14

17 Real A$/tonne 3 Coal The revised coal price projections for the various NTNDP zones are only marginally different to those provided previously. This is due to two factors: Prices being set by domestic production costs, rather than international thermal coal netbacks for many locations Australia s importance in the international traded thermal coal market, whereby fluctuations in the Australian dollar (which is more broadly closely linked with general commodity prices) are likely to influence the global price in US dollars. 3.1 Projected price for export thermal coal The projections of export thermal coal prices for each of the five scenarios are shown in Figure 12. Scenario 3 coal prices are based on the thermal coal price index published by Treasury in its report, "High Growth Low Pollution - Modelling a Carbon Price" a, released as part of the Australian Government's "Securing a clean energy future - The Australian Government's climate change plan" on 10 June 2011 adjusted for the lower assumed exchange rate. Figure 12 Price of export thermal coal (Real 2012/13 A$/t) Data source: ACIL Tasman analysis based on Treasury index and export thermal coal prices calculated from BREE mineral exports data Scenario 1 Fast rate of change Scenario 2 Fast world recovery Scenario 3 Planning Scenario 4 Decentralised world Scenario 5 Slow rate of change The coal prices for the remaining four scenarios have been linked to the price projection for Scenario 3 but adjusted to account for the different exchange rate, economic growth, commodity price and carbon price assumed in each of the scenarios. Scenario 2 has the highest coal price as it assumes strong economic growth and high commodity prices and moderate (550ppm) carbon price outlook. In this Coal 15

18 scenario the negative effect on coal prices of the carbon price is assumed to be more than offset by the strong world economic growth and high commodity prices. Scenario 5 with low economic growth and low commodity prices has the lowest coal price even though no carbon price is assumed and it has the lowest exchange rate. The prices are lower in Scenario 5 than all the other four scenarios which have carbon pricing because the influence of a depressed outlook for the world economy is assessed as reducing coal demand by more than a moderate carbon price. Furthermore with the lower economic growth the costs of production of coal are also lower. Coal prices for Scenario 1 where the carbon price is highest sit between Scenarios 2 and 3 with the high carbon price assumed to drive down the demand and price for coal even in a strongly growing world economy and higher exchange rate. Finally coal prices for Scenario 4 sit between Scenarios 3 and 5. Scenario 4 coal prices are below those in Scenario 3 because of lower economic growth and above those in Scenario 5 with the lower economic growth having a greater affect than the moderate carbon price. 3.2 Results for coal by Scenario The following graphs (Figure 13 to Figure 17) show the delivered black coal prices for each relevant NEM zone under each scenario taking into consideration the export price and production costs. Where the graphs initially fall and then flatten is because initially the high export coal prices are setting the price but after a time with real declines in the projected export coal price (see Figure 12) it is the cost of production which sets the domestic coal price as it exceeds the 80% of the export parity price. Coal 16

19 real 2012/13 A$/GJ real 2012/13 A$/GJ Figure 13 Scenario 1 Domestic black coal prices by NEM zone $3.50 $ $1.50 $1.00 Scenario NQ CQ $1.92 $1.80 $1.72 $1.67 $1.65 $1.63 $1.61 $1.60 $1.58 $1.57 $1.55 $1.53 $1.55 $1.56 $1.58 $1.60 SWQ $1.92 $1.87 $1.82 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 NNS $1.95 $1.92 $1.90 $1.87 $1.85 $1.83 $1.80 $1.78 $1.78 $1.79 $1.80 $1.82 $1.85 NCEN $1.95 $1.86 $1.76 $1.69 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 SWNSW $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 Data source: ACIL Tasman, coal price modelling and analysis Figure 14 Scenario 2 Domestic black coal prices by NEM zone $3.50 $ $1.50 $1.00 Scenario NQ CQ $1.97 $1.90 $1.86 $1.83 $1.79 $1.76 $1.72 $1.69 $1.66 $1.64 $1.67 $1.68 $1.72 $1.76 SWQ $1.94 $1.89 $1.86 $1.84 $1.83 $1.82 $1.81 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.81 NNS $3.20 $ $1.99 $1.95 $1.92 $1.96 $ NCEN $1.99 $1.91 $1.85 $1.81 $1.78 $1.75 $1.72 $1.69 $1.68 $1.68 $1.68 $1.68 $1.68 $1.69 $1.73 SWNSW $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 Data source: ACIL Tasman, coal price modelling and analysis Coal 17

20 real 2012/13 A$/GJ real 2012/13 A$/GJ Figure 15 Scenario 3 Domestic black coal prices by NEM zone $3.50 $ $1.50 $1.00 Scenario NQ CQ $1.92 $1.77 $1.67 $1.61 $1.57 $1.54 $1.52 $1.50 $1.49 $1.48 $1.47 $1.47 $1.46 $1.46 $1.46 $1.45 $1.45 $1.46 SWQ.07 $1.95 $1.87 $1.80 $1.78 $1.78 $1.78 $1.77 $1.77 $1.76 $1.76 $1.75 $1.75 $1.75 $1.74 $1.74 $1.73 $1.73 $1.72 $1.72 NNS $1.98 $1.88 $1.82 $1.77 $1.75 $1.75 $1.74 $1.74 $1.73 $1.73 $1.72 $1.72 $1.71 $1.71 $1.71 $1.70 NCEN $1.87 $1.73 $1.66 $1.66 $1.65 $1.65 $1.65 $1.64 $1.64 $1.63 $1.63 $1.63 $1.62 $1.62 $1.61 $1.61 $1.61 $1.60 SWNSW $1.80 $1.80 $1.79 $1.79 $1.78 $1.78 $1.78 $1.77 $1.77 $1.76 $1.76 $1.75 $1.75 $1.75 $1.74 $1.74 $1.73 $1.73 $1.72 $1.72 Data source: ACIL Tasman, coal price modelling and analysis Figure 16 Scenario 4 Domestic black coal prices by NEM zone $3.50 $ $1.50 $1.00 Scenario NQ CQ.02 $1.87 $1.72 $1.62 $1.57 $1.52 $1.48 $1.48 $1.47 $1.46 $1.46 $1.45 $1.45 $1.44 $1.44 $1.43 $1.43 $1.42 $1.41 $1.41 SWQ $1.92 $1.84 $1.79 $1.78 $1.78 $1.77 $1.76 $1.76 $1.75 $1.74 $1.74 $1.73 $1.72 $1.72 $1.71 $1.70 $1.70 $1.69 $1.69 $1.68 NNS $1.89 $1.82 $1.75 $1.74 $1.74 $1.73 $1.73 $1.72 $1.71 $1.71 $1.70 $1.69 $1.69 $1.68 $1.67 $1.67 $1.66 NCEN $1.90 $1.82 $1.69 $1.66 $1.65 $1.65 $1.64 $1.64 $1.63 $1.62 $1.62 $1.61 $1.61 $1.60 $1.59 $1.59 $1.58 $1.58 $1.57 $1.56 SWNSW $1.80 $1.80 $1.79 $1.78 $1.78 $1.77 $1.76 $1.76 $1.75 $1.74 $1.74 $1.73 $1.72 $1.72 $1.71 $1.71 $1.70 $1.69 $1.69 $1.68 Data source: ACIL Tasman, coal price modelling and analysis Coal 18

21 real 2012/13 A$/GJ real 2012/13 A$/GJ Figure 17 Scenario 5 Domestic black coal prices by NEM zone $3.50 $ $1.50 $1.00 Scenario NQ CQ $1.79 $1.66 $1.59 $1.52 $1.49 $1.48 $1.47 $1.46 $1.46 $1.45 $1.44 $1.44 $1.43 $1.42 $1.42 $1.41 $1.40 $1.40 $1.39 $1.38 SWQ $1.82 $1.79 $1.79 $1.78 $1.77 $1.76 $1.75 $1.74 $1.73 $1.72 $1.72 $1.71 $1.70 $1.69 $1.68 $1.67 $1.67 $1.66 $1.65 $1.64 NNS.03 $1.95 $1.84 $1.76 $1.75 $1.74 $1.73 $1.72 $1.72 $1.71 $1.70 $1.69 $1.68 $1.67 $1.67 $1.66 $1.65 $1.64 $1.63 $1.63 NCEN $1.70 $1.67 $1.66 $1.65 $1.65 $1.64 $1.63 $1.62 $1.61 $1.61 $1.60 $1.59 $1.58 $1.57 $1.57 $1.56 $1.55 $1.54 $1.54 $1.53 SWNSW $1.80 $1.79 $1.78 $1.78 $1.77 $1.76 $1.75 $1.74 $1.73 $1.72 $1.72 $1.71 $1.70 $1.69 $1.68 $1.67 $1.67 $1.66 $1.65 $1.64 Data source: ACIL Tasman, coal price modelling and analysis 3.3 Results for coal by zone The following set of graphs (Figure 19 to Figure 23) shows the black coal prices for each Scenario in each region. The cost of coal from brown coal deposits in the Latrobe Valley are estimated to be around $5.00/tonne (equivalent to approximately.50/gj), held constant in real terms throughout. This cost would be the same across all scenarios. Figure 18 $3.50 $ $1.50 $1.00 NQ: Domestic black coal prices for each Scenario Data source: ACIL Tasman, coal price modelling and analysis NQ Scenario Scenario Scenario Scenario Scenario Coal 19

22 real 2012/13 A$/GJ real 2012/13 A$/GJ Figure 19 $3.50 $ $1.50 $1.00 CQ: Domestic black coal prices for each Scenario Data source: ACIL Tasman, coal price modelling and analysis CQ Scenario $1.92 $1.80 $1.72 $1.67 $1.65 $1.63 $1.61 $1.60 $1.58 $1.57 $1.55 $1.53 $1.55 $1.56 $1.58 $1.60 Scenario $1.97 $1.90 $1.86 $1.83 $1.79 $1.76 $1.72 $1.69 $1.66 $1.64 $1.67 $1.68 $1.72 $1.76 Scenario $1.92 $1.77 $1.67 $1.61 $1.57 $1.54 $1.52 $1.50 $1.49 $1.48 $1.47 $1.47 $1.46 $1.46 $1.46 $1.45 $1.45 $1.46 Scenario 4.02 $1.87 $1.72 $1.62 $1.57 $1.52 $1.48 $1.48 $1.47 $1.46 $1.46 $1.45 $1.45 $1.44 $1.44 $1.43 $1.43 $1.42 $1.41 $1.41 Scenario 5 $1.79 $1.66 $1.59 $1.52 $1.49 $1.48 $1.47 $1.46 $1.46 $1.45 $1.44 $1.44 $1.43 $1.42 $1.42 $1.41 $1.40 $1.40 $1.39 $ Figure 20 $3.50 $ $1.50 $1.00 SWQ: Domestic black coal prices for each Scenario Data source: ACIL Tasman, coal price modelling and analysis SWQ Scenario $1.92 $1.87 $1.82 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 Scenario $1.94 $1.89 $1.86 $1.84 $1.83 $1.82 $1.81 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.81 Scenario 3.07 $1.95 $1.87 $1.80 $1.78 $1.78 $1.78 $1.77 $1.77 $1.76 $1.76 $1.75 $1.75 $1.75 $1.74 $1.74 $1.73 $1.73 $1.72 $1.72 Scenario 4 $1.92 $1.84 $1.79 $1.78 $1.78 $1.77 $1.76 $1.76 $1.75 $1.74 $1.74 $1.73 $1.72 $1.72 $1.71 $1.70 $1.70 $1.69 $1.69 $1.68 Scenario 5 $1.82 $1.79 $1.79 $1.78 $1.77 $1.76 $1.75 $1.74 $1.73 $1.72 $1.72 $1.71 $1.70 $1.69 $1.68 $1.67 $1.67 $1.66 $1.65 $ Coal 20

23 real 2012/13 A$/GJ real 2012/13 A$/GJ Figure 21 $3.50 $ $1.50 $1.00 NNS: Domestic black coal prices for each Scenario Data source: ACIL Tasman, coal price modelling and analysis NNS Scenario $1.95 $1.92 $1.90 $1.87 $1.85 $1.83 $1.80 $1.78 $1.78 $1.79 $1.80 $1.82 $1.85 Scenario 2 $3.20 $ $1.99 $1.95 $1.92 $1.96 $ Scenario $1.98 $1.88 $1.82 $1.77 $1.75 $1.75 $1.74 $1.74 $1.73 $1.73 $1.72 $1.72 $1.71 $1.71 $1.71 $1.70 Scenario $1.89 $1.82 $1.75 $1.74 $1.74 $1.73 $1.73 $1.72 $1.71 $1.71 $1.70 $1.69 $1.69 $1.68 $1.67 $1.67 $1.66 Scenario 5.03 $1.95 $1.84 $1.76 $1.75 $1.74 $1.73 $1.72 $1.72 $1.71 $1.70 $1.69 $1.68 $1.67 $1.67 $1.66 $1.65 $1.64 $1.63 $ Figure 22 $3.50 $ $1.50 $1.00 NCEN: Domestic black coal prices for each Scenario Data source: ACIL Tasman, coal price modelling and analysis NCEN Scenario $1.95 $1.86 $1.76 $1.69 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 $1.68 Scenario $1.99 $1.91 $1.85 $1.81 $1.78 $1.75 $1.72 $1.69 $1.68 $1.68 $1.68 $1.68 $1.68 $1.69 $1.73 Scenario $1.87 $1.73 $1.66 $1.66 $1.65 $1.65 $1.65 $1.64 $1.64 $1.63 $1.63 $1.63 $1.62 $1.62 $1.61 $1.61 $1.61 $1.60 Scenario 4 $1.90 $1.82 $1.69 $1.66 $1.65 $1.65 $1.64 $1.64 $1.63 $1.62 $1.62 $1.61 $1.61 $1.60 $1.59 $1.59 $1.58 $1.58 $1.57 $1.56 Scenario 5 $1.70 $1.67 $1.66 $1.65 $1.65 $1.64 $1.63 $1.62 $1.61 $1.61 $1.60 $1.59 $1.58 $1.57 $1.57 $1.56 $1.55 $1.54 $1.54 $ Coal 21

24 real 2012/13 A$/GJ Figure 23 $3.50 $ $1.50 $1.00 SWNSW: Domestic black coal prices for each Scenario Data source: ACIL Tasman, coal price modelling and analysis SWNSW Scenario 1 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 Scenario 2 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 $1.80 Scenario 3 $1.80 $1.80 $1.79 $1.79 $1.78 $1.78 $1.78 $1.77 $1.77 $1.76 $1.76 $1.75 $1.75 $1.75 $1.74 $1.74 $1.73 $1.73 $1.72 $1.72 Scenario 4 $1.80 $1.80 $1.79 $1.78 $1.78 $1.77 $1.76 $1.76 $1.75 $1.74 $1.74 $1.73 $1.72 $1.72 $1.71 $1.71 $1.70 $1.69 $1.69 $1.68 Scenario 5 $1.80 $1.79 $1.78 $1.78 $1.77 $1.76 $1.75 $1.74 $1.73 $1.72 $1.72 $1.71 $1.70 $1.69 $1.68 $1.67 $1.67 $1.66 $1.65 $ Coal 22