Fortescue Metals Group Western Australia gas sector analysis. Final report 16 May 2014

Fortescue Metals Group Western Australia gas sector analysis Final report 16 May 2014 20 March 2014

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Contents Executive summary 4 1 Introduction 20 1.1 Our approach 20 1.2 Structure of this report 20 2 Demand and supply analysis 22 2.1 Domestic demand in Western Australia 22 2.2 Domestic supply in Western Australia 23 2.3 Supply and Demand Assessment 26 3 Domestic gas reservation policy 30 3.1 Potential negative impacts of a domestic gas reservation policy 30 4 Retention leases 32 4.1 Commercial viability test 32 4.2 Grant and renewal of retention lease 33 4.3 Retention lease policy 33 4.4 International comparison of lease retention arrangements 38 5 Estimating whether undeveloped reserves are commercially viable 40 5.1 Identification of reserves 40 5.2 Results 42 6 The current link between LNG and domestic supply in Western Australia 44 6.1 Characteristic of players in the LNG and domestic gas industries 44 6.2 Two industries forced to operate as one 44 7 Modelling impact of more domestic gas production 46 7.1 Modelling approach 46 8 Findings 53 Appendix A The DAE-RGEM model 54 Households 56 Producers 57 Investors 58 International 58 Deloitte Access Economics: Western Australia gas sector analysis 3

Executive summary Fortescue Metals Group Limited has engaged Deloitte Access Economics to analyse the supply and demand dynamics in the Western Australian domestic gas market and to explore policy options to enhance the supply of gas to the domestic market in the medium term. Key Findings There are plentiful gas reserves in Western Australia to meet both projected domestic and LNG export demand for the foreseeable future. However, a significant number of gas reserves have been held under retention leases for a long period of time. Our modelling suggests that some of those reserves are presently commercially viable to be developed to supply the domestic market. If more commercially viable reserves were available to supply the domestic market, less reliance could be placed on the domestic gas reservation policy. Currently, the imposition of the domestic gas reservation policy links LNG export and domestic gas industries together. Consequently, domestic gas contracts are being priced at LNG netback prices. Phasing out the reservation policy and applying a more rigorous assessment of retention leases would allow the domestic gas industry to develop on its own accord. If sufficient reserves were developed to supply the domestic market and the conditions existed for new entry, we would expect domestic gas prices to reflect the cost of developing domestic reserves rather than the higher LNG netback price. We have estimated that the highest cost of domestic production is currently about A$7.2/GJ based on the Devils Creek project (all dollar values are expressed as real 2013-14 values unless otherwise specified). 1 Our modelling suggests that if the price of gas fell from an upper bound LNG netback price of A$10-$12/GJ to A$7.2/GJ, then the Western Australian economy would benefit from an annual increase to Gross State Product of around A$2.5 billion in 2020, increasing to A$4.8 billion by 2030. This is a significant increase in Western Australia s GSP, which was around A$243 billion in 2012-13. 2 The projected increase in economic activity is a combination of three main effects. First, additional activity due to the development of gas reserves for the domestic market which effectively brings forward economic development. Second, an improvement in the international competitiveness of the Western Australian economy through the availability of lower cost gas to downstream users (particularly in manufacturing). Third, over the longer term, an improvement in the energy efficiency of the Western Australian economy as gas is assumed to replace higher cost diesel in areas such as electricity generation. 1 Estimates of the domestic cost of gas are expressed as a point estimate, being the midpoint of our modelling range. 2 Western Australian Department of State Development, Western Australia Economic Profile, February 2014. Deloitte Access Economics: Western Australia gas sector analysis 4

There are likely to be other benefits that our model has not quantified that are associated with plentiful and lower priced gas such as: Encouraging innovation and early adoption of technology Environmental benefits associated with cleaner energy (for example from electricity generation and vehicle fuel conversion) As a sensitivity analysis we have modelled the impact on the Western Australian economy of the price of gas falling from LNG netback pricing to A$5.9 the highest cost of domestic gas production if the Devils Creek project can tap additional gas reserves. The benefits to the Western Australian economy would be more significant, with an annual increase to GSP of around A$2.8 billion in 2020, increasing to A$5.25 billion by 2030. The impact of a potentially lower gas price would alleviate cost pressures for major gas users, noting that gas is a key resource underpinning key sectors of the Western Australian economy. As our modelling shows, a lower gas price would not only generate higher productivity resulting in significant increases to overall GSP, but would also make the economy more resilient to external fuel and other commodity price shocks, and position the economy for future prosperity. It is therefore imperative that governments more rigorously apply the principles of the retention lease policy and enhance transparency of the process. Along with phasing out the domestic gas reservation policy, these changes will result in a more competitive and robust domestic gas market. Demand and supply analysis Western Australia has no shortage of gas reserves. Indeed, with an estimated 91,000 PJ of 2P conventional reserves, Western Australia is likely to have plentiful reserves to meet both projected domestic and LNG export demand for the foreseeable future. Despite the abundance of gas resources, Western Australia s local commercial gas users are finding it increasingly difficult to secure new long-term gas contracts. This is occurring despite domestic gas reservation arrangements, which require LNG producers to set aside certain amounts of gas for the domestic market. These arrangements have been operating in Western Australia for more than 30 years. The first and most significant of such arrangements was the 1979 North West Shelf State Agreement, which largely underwrote the development of both Western Australia s domestic and LNG export markets. Unfortunately, it also created the conditions by which the Western Australian domestic market now finds itself significantly exposed to the decisions and operations of a few major LNG producers. The North West Shelf commitment to supply the domestic market with 5,064 PJ of gas under the State Agreement is expected to be fulfilled in the near future, and as a result it is presently unknown whether the North West Shelf will recontract to supply the domestic market. If the North West Shelf continues to produce gas at the current estimated production rate (1,191 PJ/annum), it will have enough 2P reserves to supply both the domestic and LNG markets for at least another 12 years. However, the North West Shelf Deloitte Access Economics: Western Australia gas sector analysis 5

has currently not confirmed whether it intends to continue investing to supply the domestic market. 3 The Independent Market Operator s (IMO) supply and demand projections indicate that if the North West Shelf recontracts with domestic customers, domestic supply is projected to be approximately 30% greater than forecast domestic demand by 2023. However, if the North West Shelf elects not to supply domestic gas beyond its remaining contracts, the IMO projects very tight market conditions from 2021. This could even result in potential supply shortages. Given the long term nature of gas contracts, the effects of the potential future shortage are being felt now. Figure 1 illustrates these supply and demand dynamics. Figure 1 2014 domestic supply and demand forecasts PJ/year 600 500 Base demand NWS recontracts (Upper potential supply forecast) NWS does not recontract (Lower potential supply forecast) 400 300 200 100 0 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Source: IMO 2014 Gas Statement of Opportunities In order to capture the full market potential for gas demand, we have added a measure of consumers latent demand. We have defined latent demand as the existing diesel electricity generation that could be converted to gas, if gas supply was available and economically viable. Based on our approach, the inclusion of latent demand shows a 7.4% increase in domestic demand (27 PJ) by 2023. This represents a modest increase. However, in light of the precarious supply tightness projected if the North West Shelf does not recontract, even small increases in demand could result in potential supply shortages. 3 Western Australia Gas Statement of Opportunities, January 2014, p. 23. Deloitte Access Economics: Western Australia gas sector analysis 6

Figure 2-2014 domestic supply and demand forecasts including latent demand PJ/year 600 500 Latent demand Base demand NWS recontracts (Upper potential supply forecast) NWS does not recontract (Lower potential supply forecast) 400 300 200 100 0 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Source: IMO 2014 Gas Statement of Opportunities, Deloitte Access Economics Analysis If the North West Shelf does not recontract beyond its existing contracts and no new gas projects are developed, gas prices will rise as the scarce quantity of gas is allocated to areas where it is most highly valued within the domestic market. However, even if the North West Shelf chooses to recontract with the domestic market, it is likely that it would only be willing to contract at LNG netback prices, which reflects its opportunity cost of supplying LNG to the international market. The domestic reservation policy has therefore created the conditions in which LNG producers now dominate the domestic market which has linked the domestic price of gas to the LNG netback prices. Therefore, it is not surprising to see that gas contracts are currently being priced at A$10-$12/GJ. 4 Gas reservation policy Higher prices and the looming market tightness have spurred many market participants to champion the need for an expansion of the gas reservation policy. Domestic gas reservation may relieve supply shortages and potentially depress prices in the short term. However, we consider that in hindering the ability of markets to function effectively, domestic gas reservation policies are generally likely to create adverse economic outcomes in the longer term. Reservation policies generally result in: 5 Weak incentives to invest in new domestic supply infrastructure and develop new reserves Few (if any) new market entrants, resulting in limited competition between only a few major suppliers. 4 Based on our market knowledge. 5 Grattan Institute 2013, Getting Gas right: Australia s energy challenge. Deloitte Access Economics: Western Australia gas sector analysis 7

For these reasons we do not advocate domestic gas reservation policies. However, it is currently difficult to contract for gas in Western Australia and there may be tightness in the domestic market in the future. Our analysis suggests that these problems are best addressed by facilitating the development of new gas reserves for the domestic market by making changes to the implementation of the retention lease policy. Retention lease policy Retention leases provide security of title over gas reserves in the case that the reserve is not currently commercially viable, but is likely to be so within 15 years. 6 Whether or not a field is commercially viable is assessed by the Joint Authority an Authority comprising of a Commonwealth Minister (currently the Minister for Industry) and the relevant state or Northern Territory Minister. 7 Commercially viable gas is interpreted to mean that the gas could be developed: 8 Given existing knowledge of the field Having regard to prevailing market conditions Using proven technology readily available within the industry such that the commercial rates of return from recovery of the petroleum meet or exceed the minimum return considered acceptable typically the Joint Authority considers 12% to be the hurdle rate. The government s policy objectives through the Offshore Petroleum and Greenhouse Gas Storage Act are to promote development of commercial discoveries and that the lessee actively seeks to address those matters inhibiting the commercialisation of the discovery. 9 However, in some instances, retention leases may also provide companies with a mechanism to delay the exploitation of gas ( warehouse gas) if they can show to the Joint Authority that a reserve is uncommercial. The Domgas Alliance in its response to Queensland Government Consultation Paper on Domestic Gas Security noted that: 10 Major producers appear to be using offshore Retention Leases (which are jointly managed by the Commonwealth and State) to park gas reserves that might otherwise supply the domestic market on a commercial basis for increasingly ambitious LNG developments. While LNG producers initially claimed that resources were uneconomic for domestic gas development, such arguments appear no longer valid given the significant rise in domestic gas prices. LNG producers now claim that warehousing of resources is necessary to enable sequential field development of LNG projects. 6 Activities relating to the extraction of offshore gas outside of a three nautical mile zone are regulated by the Commonwealth Government and activities within this area are regulated by Western Australia. 7 NOPTA, <http://www.nopta.gov.au/joint_authority.html> 8 NOPTA, Offshore Petroleum Guideline for Grant and Administration of a Retention Lease, May 2012. 9 Department of Resources, Energy and Tourism, Offshore petroleum guideline for grant and administration of a retention lease, 12 May 2012. 10 Domgas Alliance, Queensland Government Consultation Paper on Domestic Gas Security, Submission by the Domgas Alliance, 20 October 2009. Deloitte Access Economics: Western Australia gas sector analysis 8

Number of retention leases in WA Further, in 2011 the Western Australian Government concluded that: 11 The current process underpinning the application for a renewal of retention leases lacks sufficient rigour and enables the stockpiling of gas reserves by incumbent producers. These reserves may include fields that are suitable for the development of domestic supplies. For some time, Australian governments have outlined their intentions to apply the retention lease policy more rigorously to prevent warehousing of reserves. Most recently, in 2013, the Coalition outlined that it will verify that companies seeking to retain a lease over oil or gas fields have a legitimate need to secure gas for long-lived production projects and are not simply seeking to obtain a competitive commercial advantage by their retention. Additionally, it flagged the potential that at the end of a retention lease period the lease should be offered on a tender basis for a Production Licence. 12 However, there are still a number of retention leases that have been held for a long period of time. Figure 3 - Number of retention leases in Western Australia and time until expiry from initial grant 20 18 16 14 12 10 8 6 4 2 0 18 Retention leases renewed 11 3 2 1 0 0-5 5-10 10-15 15-20 20-25 25-30 Time to expiry from initial grant (years) Source: National Offshore Petroleum Titles Administrator, Deloitte Access Economics analysis In Western Australia there are currently 35 retention leases, 17 of which have been renewed more than once and hence have a duration of greater than five years. 13 For example, one retention lease was first granted in 1987 and is due to expire in 2015. This means that to date, 27 years have passed since the initial retention lease was granted and this field has not been developed. Retention leases are granted, however, with the expectation of reserves being developed within 15 years. This retention lease is not the only example of a retention lease that has been held for a substantial period of time. In total, six retention leases, or around 25% of the land area that 11 Economics and Industry Standing Committee, Inquiry into Domestic Gas prices, 2011. 12 The Coalition s Policy for Resources and Energy, September 2013. 13 There are also five retention leases held under State waters, however, information on the duration of these leases is not available. Deloitte Access Economics: Western Australia gas sector analysis 9

is held under retention leases, have been held for longer than 15 years. Moreover, the reasons for granting and renewing retention leases are not made publicly available. Retention lease transparency The process by which retention leases are granted does not include public consultation. 14 As a result of this and the absence of published information, the reasoning and details relied on by the Joint Authority to determine whether a gas reserve is commercially viable are not clear. The absence of public consultation means that other market participants are not provided with the opportunity to demonstrate that reserves are commercially viable and would be developed if released from retention. In turn it is possible that fewer reserves are developed. As noted by the DomGas Alliance in 2009: 15 This lack of transparency creates an asymmetry of information that exclusively benefits existing lease holders at the expense of prospective gas producers, or downstream gas customers. Stakeholders continue to express frustration at the current arrangements and their difficulties in being able to access information and engage in the process. Later in this paper we present analysis that suggests some gas reserves held under retention leases are potentially commercially viable to supply the domestic market. This highlights the need for the Joint Authority s assessment and reasoning used to determine the commercial viability to be made available for public scrutiny, and emphasises the need to provide other participants an opportunity to participate in the process. International comparison of retention lease arrangements Internationally, policies akin to the Australian retention lease policy exist. However, such international policies typically treat companies holding gas reserves less generously. As noted by Apache: 16 Tenure of exploration acreage in Australia is very long by worldwide standards By contrast in Egypt, another country in which Apache is an active explorer, the maximum duration of a petroleum title is 35 years and in this period the title holder must explore, appraise, develop and produce any discoveries it makes. The situation in the UK was comparable [to that in Australia]; it was felt that certain companies had made potentially commercial discoveries but that they were failing to develop them and that this failure was against the national interest A policy known as the Fallow Blocks / Discoveries Initiative was introduced which had the effect of moving both exploration acreage and discoveries into the hands of companies more motivated to commercialise these assets. It appears that Australia may be out of step with other countries and the application of the Australian retention lease policy potentially allows companies to warehouse gas possibly 14 DRET, Offshore Petroleum Guideline for Grant and Administration of a Retention Lease, May 2012. 15 DomGas Alliance Retention Lease Arrangements Response to the Department of Resources, Energy and Tourism Discussion Paper, 24 August 2009. 16 Apache Energy, Submission to the parliament inquiry on domestic gas prices, 25 June 2010. Deloitte Access Economics: Western Australia gas sector analysis 10

number of retetnion leases meaning companies allocate capital preferentially to those overseas discoveries in their worldwide portfolios which are subject to more stringent requirements by host governments to commercialise those reserves rapidly or to forfeit them. 17 Retention lease holders We have also examined the composition of the companies holding retention leases. Together, a few large operators account for a significant number of the total reserves held under retention in Western Australia. Figure 4 Number of retention leases held by operator in Western Australia 10 8 6 4 2 0 Chevron Australia Woodside Energy & Browse Apache Northwest Hydra Energy GDF SUEZ Bonaparte Esso Australia Resources Santos Offshore Source: National Offshore Petroleum Titles Administrator, Deloitte Access Economics analysis Eni Australia B.V. In the absence of reasons why retention leases are renewed and the lack of a transparent process, we are unable to confirm that the principles of renewing the retention leases are being applied robustly by the Joint Authority. Therefore it may be possible that existing reserves which could be developed commercially for the domestic market are being withheld by incumbents for future use. Estimating whether undeveloped reserves are commercially viable to supply the domestic market We have developed a model to assess whether known reserves that are held under retention leases are commercially viable to supply the domestic market. Our model estimates the gas price required by a developer to earn 12% return on investment. If the resultant gas price to deliver a return of 12% is below the LNG netback price, the field is likely to be commercially viable. We selected two actual gas reserves, which we have labelled Projects A and B. Based on the following factors we assessed these two reserves to be the most likely to meet the commercial viability test: Size of reserves and the potential revenue stream 17 Apache Energy, Submission to the parliament inquiry on domestic gas prices, 25 June 2010. Deloitte Access Economics: Western Australia gas sector analysis 11

Quality of the gas including the composition of the gas and potential revenue stream from condensate Location of the reserves, including sea water depth and proximity to land Likely cost of development and operation (capital and operational expenditure) Likely cost of decommissioning We have not identified these projects by name. This is because the purpose of this exercise is not to advocate for specific gas reserves to be released from retention leases. Rather, the purpose is to examine how rigorously the retention lease policy is being applied and to highlight the potential benefits to the Western Australian economy if more reserves that are suitable to supply the domestic gas market are developed. We also estimated the gas price required to deliver a 12% rate of return to the Macedon and Devils Creek projects the two projects that have been developed purely to supply the domestic gas market. With the development of Projects A and B, and the existing Devils Creek and Macedon projects, we estimate there would be sufficient domestic gas supply to meet the domestic gas demand without the need for supply from LNG producers. The resulting gas price of the most expensive domestic project would set the upper bound for the domestic gas price in contrast to the more expensive LNG netback price. We have developed the inputs to our model as follows: Estimated the gas and condensate (a by-product of extracting the gas) production from Project A and B by looking at the reported size of the reserves and the quality/makeup of the gas. 18 To estimate the gas and condensate production from Devils Creek and Macedon we used public sources on their production capabilities and reserve size. For all projects, we matched the gas production profile to the quoted reserves. Assumed that condensate can be sold at US$95 per barrel based on the world price of oil. 19 Estimated the project development cost by using specialist advice prepared by a large and reputable engineering consultancy firm specifically for developing an offshore platform for Project A. 20 Before adopting this estimate we benchmarked the cost with publicly available cost information of other similar projects. To be conservative, we then added an additional 25% to the estimated capital expenditure costs to develop the project. 21 We have used industry benchmarks for the cost of wells, pipelines and ongoing operational expenditure. Used the cost breakdown for each component of the engineering consultancy firm s cost estimate for project A, to estimate the cost of project B. Our adjustments included adjusting specific equipment costs to account for the different condensate and carbon dioxide makeup of the gas between the two 18 Gas quality/makeup information was sourced from: Department of Minerals and Petroleum, Well Report; and Geoscience Australia, Gas Report (geochemical summary sheet). 19 Average realised condensate price for Santos was $US 114.73/bbl in Q4 2013, $US 92.84/bbl in Q1 2014, and for Woodside $US 105.04/bbl in 2013. See: Santos, First quarter activities report, 17 April 2014; Woodside, Annual report, 2013. 20 We used the firm s P50 benchmark being the base estimate plus a contingency of 25%. 21 This contingency is additional to the contingency used in the engineering firm s P50 estimate. Deloitte Access Economics: Western Australia gas sector analysis 12

reserves. Using accepted industry benchmarks we also included the cost of an onshore pipeline required to deliver the gas to a point of sale. Estimated project closure/site cleanup costs. Modelled the impact of company tax, royalties and the Petroleum Rent Resources Tax. We have been conservative in undertaking our desktop production and cost estimates. Where possible we have directly relied on the engineering consultancy firm s analysis (adding an additional cost margin of 25%), have used industry benchmarks and have benchmarked our analysis against other projects. For the cost of Devils Creek and Macedon we used publicly available cost information. We have modelled a gas price range to make each reserve commercially viable, the midpoints of which are presented in the table below. 22 Table 1 - Gas price to make reserves commercially viable Project Midpoint gas price to achieve 12% return (A$/GJ, real) Assumed supply based on reserve characteristics (TJ per day) Project A 4.3 500 Project B 5.8 500 Macedon 23 5.9 211 Devils Creek 7.2 105 Source: Deloitte Access Economics analysis Devils Creek is the marginal cost project which results in a gas price of A$7.2/GJ. In contrast, Project A and B require a much lower gas price to achieve a 12% rate of return. Macedon requires a gas price of A$5.9/GJ to provide a return of 12%. On that basis, the upper bound for domestic gas prices would be based on the Devils Creek project, being A$7.2. 24 This is significantly lower than the upper bound LNG netback price A$10-$12/GJ. In our analysis for the Devils Creek project we have assumed it would be unable to tap additional reserves that are needed for it to sustain gas production near its nameplate capacity of 220 TJ per day for a period of 20 years. Given the sunk investment in gas processing facilities, Devils Creek would, however, have an incentive to continue operating 22 The prices presented are the midpoint of our model s upper and lower bounds. These prices are based on the assumptions that we have outlined above and our desktop analysis. Our upper and lower bound ranges reflect variances in capital and operating cost estimates, gas and condensate production rates, project closure costs, taxes including estimates of PRRT and corporate taxes. 23 We have assumed that Macedon can tie in a nearby gas field owned by BHP, which results in lowering the gas price required by Macedon to deliver a 12% return. We have included an estimate of the capital costs required to do so in our model. 24 This is a conservative assumption because it assumes the preservation of a 12% return whereas in fact this return may be squeezed with the advent of more domestic production. Thus, the actual marginal cost could be lower which could result in more positive benefits to the Western Australian economy than estimated by our modelling. Deloitte Access Economics: Western Australia gas sector analysis 13

its plant once the existing reserves are exhausted. Additionally, given the significant gas reserves in Western Australia, it is possible that Devils Creek could source more gas to process in its plant. If so, our model estimates that the gas price for Devils Creek to deliver a return of 12% would fall to A$5.7/GJ, meaning that the upper bound for domestic gas prices would be based on Macedon at A$5.9/GJ. 25 While this outcome is possible, we have not specifically identified a reserve that Devils Creek could tie into its existing operations. The LNG and domestic gas supply industries could be delinked by removing the reservation policy and by more rigorously applying the retention lease policy. If this occurred, it is likely that LNG suppliers would exit the domestic gas market. Gas reserves would be freed up and developed by domestic focussed suppliers. Additionally, the price of gas should tend towards the marginal cost of domestic production rather than the LNG netback price. Modelling the impact of more domestic gas production We have modelled two scenarios. The base scenario represents domestic gas prices based on LNG netback pricing. 26 In the alternative scenario sufficient gas reserves are developed (consistent with our earlier modelling), such that domestic gas prices are delinked from LNG netback pricing and represent the marginal cost of domestic supply being A$7.2/GJ based on the Devils Creek project. The following figure presents the gas price for the two scenarios. Figure 5 Average gas price under LNG netback and domestic supply scenario (A$, real 2013-14) $/GJ 16.00 Price set by LNG netback Price set by domestic supply 14.00 12.00 10.00 8.00 6.00 4.00 2.00 0.00 Source: Deloitte Access Economics analysis In determining the prices we have taken a weighted average of existing and new contracts. In the model, existing contracts are priced at A$4.0/GJ until their expiry in 2020-21 and new 25 The price of gas for Devils Creek assuming it can tap additional reserves assumes that additional capital expenditure is required to develop the project and that opex and closure costs also increase. 26 LNG netback prices are based on forecast of Brent and Henry Hub prices, sourced from Energy Information Administration (US). Deloitte Access Economics: Western Australia gas sector analysis 14

contracts are priced at either LNG netback pricing in the LNG netback scenario, or the upper bound of the domestic supply being A$7.2/GJ based on Devils Creek in the domestic supply scenario. 27 To all prices we have added an allowance for gas transportation. The average gas price in the domestic supply scenario is A$2.2/GJ lower by 2020 and A$4.4/GJ by 2025. We present the impact to the Western Australian economy of lowering the gas prices from its current LNG netback pricing to reaching an upper bound of A$7.2/GJ based on the Devils Creek project. We have presented the results of our model in a two staged approach; the first stage being a lower gas price to meet normal gas demand. The second stage incorporates latent demand being met by additional gas supplies at the lower price. Stage one - The impact on Western Australia of gas prices reflecting domestic marginal cost Stage one presents the impact on the Western Australian economy if gas prices were to be set by domestic supply instead of LNG netback pricing. A lower gas price would result in increased GSP as input costs are lowered to the economy and the economy becomes more productive, resulting in expanded output. It also incorporates the impact of higher capital and operating expenditure made as a result of developing Projects A and B. Figure 6 Additional Gross State Product from a fall in the domestic gas price (A$, real 2013-14) 3,500 Increase in GSP, $ million 3,000 2,500 2,000 1,500 1,000 500 - Source: Deloitte Access Economics analysis The impact to GSP is significant, increasing by around A$2.0 billion in 2020 and A$3.0 billion in 2030. 27 Based on our knowledge existing contracts priced around A$4 will expire in 2020-21. Deloitte Access Economics: Western Australia gas sector analysis 15

The following figure shows the increase to employment as a result of higher GSP and the capital and operating expenditure to develop and operate Project A and B. Employment increases by around 2,000 FTEs in 2020, increasing to 2,100 FTEs in 2030. Figure 7 Additional employment from a fall in the gas price Increase in Full Time Equivalent 2,500 2,000 1,500 1,000 500 - Source: Deloitte Access Economics analysis Stage two - The impact on Western Australia of gas prices reflecting domestic marginal cost including latent demand In this scenario we have assumed that latent demand is met by the expanded domestic gas supply. Consistent with stage one, the domestic gas price is set by domestic supply instead of LNG netback pricing. The figure below presents the impact to GSP. Figure 8 Additional Gross State Product from a fall in the domestic gas price including latent demand (A$, real 2013-14) 6,000 Increase in GSP, $ million 5,000 4,000 3,000 2,000 1,000 - Source: Deloitte Access Economics analysis Deloitte Access Economics: Western Australia gas sector analysis 16

The impact to GSP is higher than in stage one. GSP increases by around A$2.5 billion in 2020 and A$4.8 billion in 2030. The following figure shows the increase to employment as a result of higher GSP and the capital and operation expenditure to develop and operate Project A and B. Employment increases by around 2,100 FTEs in 2020, increasing to 2,600 FTEs in 2030. Figure 9 Additional employment from Projects A and B including latent demand Increase in Full Time Equivalent 3,000 2,500 2,000 1,500 1,000 500 - Source: Deloitte Access Economics analysis The relative impact on increased FTEs is much smaller than the increase to GSP. This is because lower gas prices mainly improve the productivity of capital which results in large increases to GSP. Sensitivity analysis domestic gas price based on Macedon (A$5.9/GJ) We have also undertaken sensitivity analysis using a domestic gas price of A$5.9/GJ based on the price of the Macedon project. This sensitivity assumes that Devils Creek can tap additional gas reserves enabling it to produce near its nameplate capacity for another 20 years. If this occurred, Macedon would become the highest cost domestic producer at A$5.9/GJ. However because we have not specifically identified a reserve that Devils Creek would be likely to tap, we have modelled this as a sensitivity analysis rather than a scenario. Our baseline LNG gas price is the same as that used in earlier in our analysis. The domestic gas price is the upper bound of the domestic supply being A$5.9/GJ based on Macedon in the domestic supply scenario. To all prices we have added an allowance for gas transportation. The following figure presents the baseline and the average gas price for this sensitivity analysis. Deloitte Access Economics: Western Australia gas sector analysis 17

Figure 10 Average gas price under LNG netback and domestic supply scenario (A$, real 2013-14) $/GJ 16 14 12 Price set by LNG netback Price based on Devils Creek Sensitivity analysis - price based on Macedon 10 8 6 4 2 0 Source: Deloitte Access Economics analysis The average gas price in the domestic supply scenario is A$3.2/GJ lower by 2020 and A$5.7/GJ by 2025. We present the impact to the Western Australian economy of lowering the gas prices from its current LNG netback pricing to reaching an upper bound of $A5.9/GJ based on the Macedon project. We have presented the results of our model in only one stage, which incorporates latent demand being met by additional gas supplies at the lower price (that is, on the same basis as the latter set of scenario one results). The figure below presents the impact to GSP. Figure 11 Additional Gross State Product from a fall in the domestic gas price including latent demand (A$, real 2013-14) 6,000 Increase in GSP, $ million 5,000 4,000 3,000 2,000 1,000 - Source: Deloitte Access Economics analysis Deloitte Access Economics: Western Australia gas sector analysis 18

The impact to GSP is higher than in the scenario analysis. GSP increases by around A$2.8 billion in 2020 and A$5.25 billion in 2030. The following figure shows the increase to employment as a result of higher GSP and the capital and operation expenditure to develop and operate Project A and B. Employment increases by around 2,500 FTEs in 2020, increasing to 3,000 FTEs in 2030. Figure 12 Additional employment from Projects A and B including latent demand Increase in Full Time Equivalent 3,500 3,000 2,500 2,000 1,500 1,000 500 - Source: Deloitte Access Economics analysis The relative impact on increased FTEs is much smaller than the increase to GSP. This is because lower gas prices mainly improve the productivity of capital which results in large increases to GSP. Deloitte Access Economics: Western Australia gas sector analysis 19

1 Introduction Fortescue Metals Group Limited has engaged Deloitte Access Economics to analyse the supply and demand dynamics in the Western Australian domestic gas market and to explore policy options to enhance the supply of gas to the domestic market in the medium term. This need has arisen from a paucity of long term domestic gas contracts being made available. 1.1 Our approach In this report we have examined the supply and demand dynamics for gas in the Western Australian market to examine whether there is a shortage of domestic supply and whether there is likely to be one in the future. We have found that there is tightness in the market, which is exacerbated by the uncertainty of North West Shelf recontracting. While this tightness could potentially be alleviated by an expansion of Western Australia s domestic gas reservation policy, we do not believe that this is a desirable solution because of the problems associated with policies of this nature. Additionally, this policy links the domestic gas price to the LNG market price, which is likely to be higher than a pure domestic based price. Therefore, we have examined alternative methods to alleviate the possible shortfall of domestic gas. Anecdotal evidence suggests that the retention lease policy is not being rigorously applied and that LNG players can use the policy to warehouse gas reserves. We have also undertaken modelling which suggests that some of the gas reserves currently held under retention leases are commercially viable. As such, if released from retention, we believe that some of these reserves would be developed specifically for the domestic market given that currently the price of gas is close to LNG netback prices. If these fields were developed, our analysis suggests that the domestic gas price would tend more towards the marginal cost of producing domestic gas. We have modelled the effect of gas prices closer to marginal cost using our general equilibrium model. The results of this modelling demonstrate that there are significant potential gains to the Western Australian economy from developing additional gas reserves. 1.2 Structure of this report The remainder of this report is structured as follows: Deloitte Access Economics: Western Australia gas sector analysis 20

Chapter 2 provides background and context on Western Australia s gas demand and supply. It demonstrates that there is likely to be tightness in the market in the future. Chapter 3 looks at the problems with domestic gas reservation policies. Chapter 4 examines the purpose of retention leases and examines anecdotal evidence that the policy is not being rigorously applied. Chapter 5 models the gas price required to make two existing domestic gas projects and two hypothetical gas projects (based on actual reserves) commercially viable. Chapter 6 discusses how current policies have the effect of linking the LNG and domestic gas markets resulting in domestic gas prices being based on LNG netback pricing. Chapter 7 presents our CGE analysis of the economic benefits to Western Australia arising from additional domestic gas developments and a fall in gas prices. Chapter 8 presents our findings. Deloitte Access Economics: Western Australia gas sector analysis 21

2 Demand and supply analysis Western Australia has no shortage of gas reserves. Indeed, with an estimated 91,000 PJ of 2P conventional reserves, Western Australia is likely to have plentiful reserves to meet both projected domestic and LNG export demand for the foreseeable future. Despite the abundance of gas resources, Western Australia s local commercial gas users are finding it increasingly difficult to secure new long-term gas contracts. This is occurring despite domestic gas reservation arrangements, which require LNG producers to set aside certain amounts of gas for the domestic market. These arrangements have been operating in Western Australia for more than 30 years. This chapter outlines the current and projected future supply and demand dynamics within the Western Australian domestic gas market and highlights a number of issues that are creating uncertainty around future supply and placing upward pressure on domestic gas prices. 2.1 Domestic demand in Western Australia In 2012-13, domestic demand for gas in Western Australia totalled approximately 326 PJ. 28 As illustrated in figure 13, Western Australia s domestic gas consumption is dominated by three sectors. These are electricity generation, mining (where gas is mainly used for electricity generation), and manufacturing (which includes minerals and petroleum processing). 29 Figure 13 - Western Australia domestic gas demand 5% 1% 25% 37% Mining Manufacturing Electricity Generation Residential Others 32% Source: Western Australia Gas Statement of Opportunities, January 2014 28 Western Australia Gas Statement of Opportunities, January 2014, p. 67. 29 Western Australia Gas Statement of Opportunities, January 2014. Deloitte Access Economics: Western Australia gas sector analysis 22

2.2 Domestic supply in Western Australia Western Australia s domestic gas supply is highly concentrated and heavily reliant on a small number of major projects by large gas producers. We present a breakdown of average gas production and processing capacity by basin and by project in table 2 below. Table 2 - Gas supply projects Basin Project Operator Status Average production 1 Aug 30 Dec 2013 (TJ/day) Estimated Gas Processing capacity (TJ per day) Carnarvon North West Shelf Varanus Island Devils Creek Woodside Supplying 491.8 630 Apache Energy Apache Energy Supplying 293.8 390 Commenced Supplying Macedon BHP Billiton Commenced Supplying Gorgon Domestic Wheatstone Domestic Chevron Chevron Perth Dongara AWE Limited Beharra Springs Red Gully Origin Energy Empire Oil and Gas Expected 2015 Expected 2016 Almost depleted 109.5 220 135.9 200 NA 300 NA 200 2.1 7 Supplying 13.9 25 Supplying 5.9 10.6 Total 1052.9 1982.6 Source: Western Australia Gas Statement of Opportunities, January 2014 As can be seen, in Western Australia the majority of gas is sourced from the Carnarvon Basin and primarily controlled by two operators, Woodside Energy and Apache Energy. The dominance of only a few gas operators supplying the domestic gas market, combined with the fact that new supply has generally been available by producers only in comparatively large increments, means that end users face challenges when seeking to secure new long term gas supply contracts, especially where relatively small volumes are sought. Rather than being supplied in response to domestic market forces, a large proportion of Western Australia s domestic gas is provided on the basis of domestic gas reservation agreements with the Western Australian Government. As shown in figure 14, 57% of the total estimated gas processing capacity is pursuant to domestic gas reservation policies. Deloitte Access Economics: Western Australia gas sector analysis 23

Figure 14 - Provision of Western Australia s domestic gas processing capacity TJ/day 2000 1800 1600 1400 1200 1000 800 Reservation policies North West Shelf Wheatstone Domestic Gorgon Domestic Macedon Devils Creek Varanus Island Red Gully 600 400 200 Domestic focus Beharra Springs Dongara 0 Domestic supply Source: Western Australia Gas Statement of Opportunities January 2014, Deloitte Access Economics Analysis Domestic gas reservation arrangements, which require LNG producers to set aside certain amounts of gas for the domestic market, have been operating in Western Australia for more than 30 years. The first and most significant of such arrangements was the 1979 North West Shelf State Agreement, which largely underwrote the development of both Western Australia s domestic and LNG export markets. Under the North West Shelf State agreement, the Western Australia State Government contracted with the North West Shelf Joint Venture partnership (North West Shelf JV) to purchase 3,023 PJ of gas and reserve a further 2,041 PJ for domestic use. 30 This arrangement paved the way for the development of Western Australia s domestic gas processing facilities and pipeline infrastructure. However, it also created the conditions by which the Western Australian domestic market now finds itself significantly exposed to the decisions and operations of a few major LNG producers. 2.2.1 Uncertainty about the North West Shelf recontracting The North West Shelf commitment to supply the domestic market with 5,064 PJ of gas under the State Agreement is expected to be fulfilled in the near future. If the North West Shelf continues to produce gas at the current estimated production rate (1,191 PJ/annum), it will have enough 2P reserves to supply both the domestic and LNG markets for at least another 12 years. However, it is presently unknown whether the North West Shelf will recontract to supply the domestic market. 30 North West Gas Development (Woodside) Agreement Act 1979 Schedule 3. Deloitte Access Economics: Western Australia gas sector analysis 24

In 2011, the Economics and Standing Committee undertook an inquiry into domestic gas prices (the Inquiry) in Western Australia. During the Inquiry, North West Shelf representatives demonstrated some indication that they would be inclined to continue supplying the domestic market. In particular the General Manager of the North West Shelf Gas Pty Ltd stated to the Committee: 31 The 5,064 petajoules is under the state agreement and we very much see that as a lower limit, not an upper limit. There is no intent and there is no capacity to cut off supply once we hit that level. We are contractually obliged [with customers] to continue supplying gas beyond that point and we will continue to do so. However, the Department of Mines and Petroleum (DMP) noted that the North West Shelf did not have any obligation after the 5,064 PJ commitment was fulfilled. Consistent with the concerns raised by the DMP, our recent anecdotal experience with a number of domestic gas consumers in Western Australia suggests that domestic customers are facing significant difficulty recontracting with the North West Shelf post 2017. In its Inquiry, the Committee noted that under the State Agreement, the North West Shelf joint venture proponents are required to meet and reach agreement with the Minister on the requirements in the State and the manner in which they will be met 32 before entering into further commercial arrangements for the supply of natural gas between 2010 and 2025. Consequently, the Committee suggested that the government utilise this provision (and the declared intent of the North West Shelf joint venture to continue supplying domestic customers) to provide the domestic market with confidence that the North West Shelf will maintain full production capacity until 2025. However, as of April 2014, the Western Australian State Government and the North West Shelf JVs are yet to reach an agreement about the domestic supply of the remaining North West Shelf reserves. In response to a number of domestic market participants concerns about the uncertainty of the North West Shelf JV s intentions and ability to supply the domestic market once existing contracts expire, the latest Western Australian Gas Statement of Opportunities released on January 2014 undertook an investigation into the capability of the North West Shelf to continue to supply the domestic market. This analysis found that ongoing supply from the North West Shelf JVs beyond the terms of their existing contracts depends on a range of factors including: The outcomes of ongoing discussions between the WA Government and the North West Shelf JVs that relate to the status of remaining North West Shelf reserves; Investment decisions required by the North West Shelf JVs to access remaining undeveloped reserves; and Investment required to extend the life of the Karratha Gas Plant, which is the North West Shelf s ageing domestic gas production facility. 31 Economics and Industry Standing Committee 2011, Inquiry into domestic gas prices, Report No. 6 in the 38 th Parliament, p. 90. 32 North West Gas Development (Woodside) Agreement Act 1979 (Western Australia), Schedule 2, Clause 46(1a). Deloitte Access Economics: Western Australia gas sector analysis 25

Several domestic gas users have highlighted that a large proportion of the remaining North West Shelf gas reserves have already been committed to LNG customers, leaving inadequate reserves to serve the domestic market. 2.3 Supply and Demand Assessment In light of the uncertainty associated with the North West Shelf, the Independent Market Operator s (IMO) 2014 Gas Statement of Opportunities developed two supply scenarios for the 2014-2023 forecast period. These included: The Upper potential supply forecast, which assumes the North West Shelf will recontract to supply the domestic market. Under this scenario, the North West Shelf will continue to supply the domestic market at a maximum production quantity of 470 TJ/day for the 2014-20 period and 450 TJ/day for the 2021-23 period. The Lower potential supply forecast, which assumes that North West Shelf will only supply domestic gas under its remaining contracts (and not recontract with the domestic market). The supply and demand projections indicate that if the North West Shelf recontracts with domestic customers, domestic supply is projected to be approximately 30% greater than forecast domestic demand by 2023. However, if the North West Shelf elects not to supply domestic gas beyond its remaining contracts, the IMO projects very tight market conditions from 2021. This could even result in potential supply shortages. Given the long term nature of gas contracts, the effects of the potential future shortage are being felt now. Figure 15 illustrates these supply and demand dynamics. Figure 15-2014 domestic supply and demand forecasts PJ/year 600 500 400 Base demand NWS recontracts (Upper potential supply forecast) NWS does not recontract (Lower potential supply forecast) 300 200 100 0 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Source: IMO 2014 Gas Statement of Opportunities Deloitte Access Economics: Western Australia gas sector analysis 26

2.3.1 Latent demand modelling methodology In order to capture the full market potential for gas demand, we have added a measure of consumers latent demand to the IMO s demand forecast. For the purposes of this analysis, we defined latent demand as existing diesel electricity generation that could be converted to gas, if gas supply was available and economically viable. We sourced data for Western Australia s existing diesel electricity generation from the 2013 Australian Energy Statistics published by the Bureau of Resources and Energy Economics (BREE). To develop projections of this latent gas demand in Western Australia over the forecast period we undertook the following steps: We obtained the actual annual Automotive Diesel Oil (ADO) consumption for the purposes of Electricity Supply in Western Australia (in PJ) from 1983-84 through to 2011-12 (inclusive) from the 2013 Australian Energy Statistic published by BREE. 33 This represents the diesel consumption for the purposes of generating electricity in Western Australia which could potentially be substituted with gas (i.e. latent domestic gas demand) The average annual growth rate based on the 1983-84 to 2011-12 latent domestic gas demand in Western Australia was determined and used to project the 2011-12 latent domestic gas demand through to 2049-50. Based on this approach, the average annual increase in latent domestic gas demand was projected to grow at around 1% per annum. Having performed the projection, the impact of the diesel power generation at Fortescue s Solomon Mine (which came online in 2012-13) on the Western Australia latent gas demand was included as a step-change of an additional 10PJ per annum from 2012-13 onwards. An annual diesel to gas conversion rate of 10% per annum was applied to the latent domestic gas demand for each year from 2012-13 to 2021-22. This was done to account for the gradual conversion of diesel generation to gas-fired generation over an assumed 10 year period. So for 2012-13, the conversion-adjusted latent domestic gas demand is 10% of the unadjusted latent domestic gas demand projection for that year. In 2013-14, the conversion-adjusted latent domestic gas demand is 20% of the unadjusted latent domestic gas demand projection for that year. From 2021-22 onwards, the conversion-adjusted latent domestic gas demand is 100% of the unadjusted latent domestic gas demand projection for each year. Consideration was also given to including diesel fuel for road transport and for mining activities in the latent domestic gas demand projections. However, due to data inconsistencies we were unable to include these in the analysis. Based on our projections for gas demand and latent domestic gas demand in Western Australia: 33 BREE 2013 Australian Energy Statistics Data, Table F: Total final energy consumption and total net energy consumption in Australia, by fuel, energy units <http://www.bree.gov.au/node/114> Deloitte Access Economics: Western Australia gas sector analysis 27

Over the next 10 years, total domestic gas demand in Western Australia could total around 3,658 PJ Including the latent domestic gas demand, the total domestic gas demand over the next 10 years could total around 3,828 PJ The figure below provides a graphical depiction of the gas demand and latent domestic gas demand projections for Western Australia over the next 10 years. Figure 16 - Western Australian Domestic Gas Demand 2014-2023 PJ/year 420 Base demand + latent demand Base demand 400 380 360 340 320 300 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Source: Deloitte Access Economics analysis The figure shows that the inclusion of latent gas demand arising from diesel generation being converted to natural gas could result in only a modest (approximately 7.4%) increase in gas demand above business as usual levels by 2023. However, if other forms of latent demand were to be considered (i.e. for mining operations and road transport), the impact would be materially greater than the 7.4% suggested above. Based on our approach, the inclusion of latent demand shows a 7.4% increase in domestic demand (27 PJ) by 2023. This represents a modest increase. However, in light of the precarious supply tightness projected if the North West Shelf does not recontract, even small increases in demand could result in potential supply shortages. Deloitte Access Economics: Western Australia gas sector analysis 28

Figure 17-2014 domestic supply and demand forecasts including latent demand PJ/year 600 500 Latent demand Base demand NWS recontracts (Upper potential supply forecast) NWS does not recontract (Lower potential supply forecast) 400 300 200 100 0 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Source: IMO 2014 Gas Statement of Opportunities, Deloitte Access Economics analysis If the North West Shelf does not recontract beyond its existing contracts and no new gas projects are developed, gas prices will rise as the scarce quantity of gas is allocated to areas where it is most highly valued within the domestic market. However, even if the North West Shelf chooses to recontract with the domestic market, it is likely that it would only be willing to contract at LNG netback prices, which reflects its opportunity cost of supplying LNG to the international market. Such sentiment has also been expressed by the CEO of Woodside Petroleum: 34 Our target in [the domestic gas market] is to ensure that we get LNG netback prices or equivalent to that. So I would say to you, whether it goes to LNG or whether it goes to domgas, the focus here for us is to create additional value through ensuring that we get equivalent pricing mechanisms. The domestic reservation policy has therefore created the conditions in which LNG producers now dominate the domestic market which has linked the domestic price of gas to the LNG netback prices. Therefore, it is not surprising to see that gas contracts are currently being priced at A$10-$12/GJ. 35 This link is discussed further in Chapter 6. 34 Woodside Petroleum, Investor Update Conference Call transcript, 11 December 2013. 35 Based on our market knowledge. Deloitte Access Economics: Western Australia gas sector analysis 29

3 Domestic gas reservation policy Higher prices and potential market tightness have spurred many market participants to champion the need for an expansion of the gas reservation policy. Domestic gas reservation may relieve supply shortages and potentially depress prices in the short term. However, we consider that in hindering the ability of markets to function effectively, domestic gas reservation policies are generally likely to create adverse economic outcomes in the longer term. Western Australia s domestic gas reservation policy After imposing reservation agreements with the North West Shelf and the Gorgon LNG project, the WA Government formalised a policy to reserve gas for domestic use in 2006. In 2012, as part of its Strategic Energy Initiative s Energy 2031 final paper, the WA Government reaffirmed its commitment to a domestic gas reservation policy. In particular, the WA Government s policy statement stipulates that: Gas producers are required to demonstrate their ability to meet the Domestic Gas Reservation Policy as a condition of a project approval. The State will apply the policy in a flexible manner in accordance with the following requirements: LNG Producers will commit to make available domestic gas equivalent to 15% of LNG production from each LNG export by: Reserving domestic gas equivalent to 15% of LNG production from each LNG export project; Developing and obtaining access to, the necessary infrastructure (including a domgas plant, associated facilities and offshore pipelines) to meet their domestic gas commitments as part of the approvals process; and Showing diligence and good faith in marketing gas to the domestic market. 3.1 Potential negative impacts of a domestic gas reservation policy Under a reservation policy, rather than market forces influencing the quantities of gas available to the domestic market, supply is essentially imposed by the government. This intervention hampers the ability of the market to efficiently respond to dynamics and changing conditions facing market participants. Reservation policies generally result in: 36 Weak incentives to invest in new domestic supply infrastructure and develop new reserves 36 Grattan Institute 2013, Getting Gas right: Australia s energy challenge. Deloitte Access Economics: Western Australia gas sector analysis 30

Few (if any) new market entrants, resulting in limited competition between only a few major suppliers. Although not currently eventuating in Western Australia, domestic gas reservation policies also have the potential to create excess supply as governments, which are generally incentivised to avoid shortages, tend to reserve more gas than domestic consumers need. Policy-induced gas surpluses can artificially lower gas prices, which, as we have shown in our previous report, The economic impacts of a domestic gas reservation, 37 effectively place a simultaneous tax on domestic gas production and a subsidy on domestic gas consumption. Such distortions will impact on market participants economic decisions, resulting in the production and consumption of inefficient quantities and losses to the nation s overall welfare. Beyond creating distortions within the domestic gas market, burdensome compliance conditions associated with domestic gas reservation requirements could also deter potential investors away from undertaking further development in the Western Australian LNG industry. In addition to having to make specified quantities available to the domestic market, LNG producers are also required to incur additional capital costs in developing necessary infrastructure to supply the domestic market (such as a domestic gas plant, associated facilities and offshore pipelines). Such onerous conditions could reduce ongoing investment and also act as barriers to entry for new LNG players. For these reasons we do not advocate domestic gas reservation policies. However, it is currently difficult to contract for gas in Western Australia and there may be tightness in the domestic market in the future. Our analysis suggests that these problems are best addressed by facilitating the development of new gas reserves for the domestic market by making changes to the implementation of the retention lease policy. 37 Deloitte Access Economics 2013, The economic impacts of a domestic gas reservation, Report prepared for the Australian Petroleum Production and Exploration Association Ltd. Deloitte Access Economics: Western Australia gas sector analysis 31

4 Retention leases Once a gas reserve has been found, an explorer can apply for a production license to exploit the gas reserve. However, in some cases the gas reserve will not be commercially viable at that time. In such cases the explorer may instead apply for a retention lease enabling it to maintain security of title over the reserves. Activities relating to the extraction of offshore gas outside of a three nautical mile zone are regulated by the Commonwealth Government and activities within this area are regulated by Western Australia. 38 Thus there are several Acts which set out retention lease provisions. Specific provisions for retention leases in Commonwealth waters are set out in Part 2.3 of the Offshore Petroleum and Greenhouse Gas Storage Act (OPGGSA). 39 Provisions for retention leases in State waters are set out in the Petroleum (Submerged Lands) Act 1982 and the Petroleum and Geothermal Energy Resources Act 1967. While these Acts apply to different areas, the retention lease provisions are similar and operate in the same manner. 4.1 Commercial viability test Whether or not a field in Commonwealth waters is commercially viable is assessed by the Joint Authority an Authority comprising of a Commonwealth Minister (currently the Minister for Industry) and the relevant state or Northern Territory Minister. 40 In the case of retention leases in State waters, this is assessed by the Minister. Commercially viable gas is interpreted to mean that the gas could be developed: 41 Given existing knowledge of the field Having regard to prevailing market conditions Using proven technology readily available within the industry such that the commercial rates of return from recovery of the petroleum meet or exceed the minimum return considered acceptable typically the Joint Authority considers 12% to be the hurdle rate. The Joint Authority, however, may also agree that an otherwise commercially viable gas project (assuming current prices) is not commercially viable due to an inability to obtain offtake contracts at prevailing market terms and conditions. Additionally, the Joint Authority will give favourable consideration to an application for a lease if the applicant has demonstrated reasonable attempts in good faith to obtain gas supply contracts which were unsuccessful. 42 38 Government of Western Australia, Department of Mines and Petroleum, Western Australia s Petroleum and Geothermal Explorer s Guide, 2012. 39 NOPTA, Offshore Petroleum Guideline for Grant and Administration of a Retention Lease, May 2012. 40 NOPTA, <http://www.nopta.gov.au/joint_authority.html> 41 NOPTA, Offshore Petroleum Guideline for Grant and Administration of a Retention Lease, May 2012. 42 ibid. Deloitte Access Economics: Western Australia gas sector analysis 32

Unless the immediate commerciality of a reserve is outside the power of the lessee (for example if it is related to commodity price), the lease holder will need to provide a work program to the Joint Authority to address the constraints of commercial viability (this may include undertaking further studies/drilling if there is insufficient information on which to base decisions on commerciality). 4.2 Grant and renewal of retention lease The initial term of a retention lease is five years. Retention leases can be renewed for further five year periods if the commerciality tests continue to be met and previous lease conditions have been met. The Joint Authority can refuse to grant (or renew) a retention lease if it considers that a reserve is commercially viable (and hence should be developed), or if it considers a reserve will not be commercially viable within 15 years. 43 Where the Joint Authority refuses to grant a retention lease, the applicant has 12 months to apply for a production licence. The renewal process for retention leases is set out in the figure below. Figure 18 - Australian retention lease operation Source: NOPTA 4.3 Retention lease policy The government s policy objectives through the Offshore Petroleum and Greenhouse Gas Storage Act are to promote development of commercial discoveries and that the lessee actively seeks to address those matters inhibiting the commercialisation of the discovery. 44 However, in some instances retention leases may provide companies with a mechanism to delay the exploitation of gas ( warehouse gas) if they can show the Joint Authority that a reserve is uncommercial. For some time, Commonwealth governments have outlined their intentions to apply the retention lease policy more rigorously to prevent warehousing of reserves. In 2009 the 43 Offshore Petroleum and Greenhouse Gas Storage Act 2006, section 155. Petroleum (Submerged Lands) Act 1982, section 38B. Petroleum and Geothermal Energy Resources Act 1967, section 48B. 44 Department of Resources, Energy and Tourism, Offshore petroleum guideline for grant and administration of a retention lease, 12 May 2012. Deloitte Access Economics: Western Australia gas sector analysis 33

Minister for Resources and Energy confirmed that it would apply a use it or lose it principle to petroleum titles. More recently, in 2013, the Coalition outlined that it will verify that companies seeking to retain a lease over oil or gas fields have a legitimate need to secure gas for long-lived production projects and are not simply seeking to obtain a competitive commercial advantage by their retention. Additionally, it flagged the potential that at the end of a retention lease period the lease should be offered on a tender basis for a Production Licence. 45 Notwithstanding the Government s policy that commercially viable fields be developed, many players in the gas market have raised concern that the Joint Authority s assessment of whether gas reserves are commercially viable are too lenient and allow major companies to warehouse gas. In 2009 DRET released an options paper entitled Review of Policy relating to the Grant and Renewal of Retention Leases. 46 In this review, DRET noted that: 47 The commercial environment for offshore development has changed significantly from when retention leases were first implemented, and the rapid proliferation of retention leases at a time of unfulfilled domestic demand and increasing numbers of longer-term LNG customers suggests a prima facie case for changes to the status quo. The Western Australian Parliament s 2011 inquiry into domestic gas price observed that: 48 A common criticism of the current retention lease regime was that it was sufficiently lax as to enable producers to warehouse or hoard reserves, many of which could be commercially developed already for domestic markets. Other critics argued that the commercial viability parameters lacked transparency, were only reliant on the input of the producer and should be subject to greater independent scrutiny. Another concern was that the current approvals process creates significant barriers to entry for new players and protects larger incumbent producers. The Committee accepts that retention leases may play a role for prospective LNG producers who need to aggregate sufficient reserves to make a new project bankable The Committee is nonetheless persuaded by the argument that if the evaluation process underpinning the application for and renewal of retention leases lacks rigour, the potential exists for the excessive stockpiling of reserves for the LNG market. Managed efficiently, retention lease arrangements should be able to balance any competing objectives of the LNG and domestic markets. The Western Australian Government concluded that: The current process underpinning the application for a renewal of retention leases lacks sufficient rigour and enables the stockpiling of gas reserves by incumbent producers. These reserves may include fields that are suitable for the development of domestic supplies. 45 The Coalition s Policy for Resources and Energy, September 2013. 46 Allens <http://www.allens.com.au/pubs/ener/foenerapr11.htm> 47 Commonwealth Department of Resources, Energy and Tourism, Review of policy relating to the grant and renewal of retention leases Options Paper, 12 June 2009, p. 8. 48 Economics and Industry Standing Committee, Inquiry into Domestic Gas prices, 2011. Deloitte Access Economics: Western Australia gas sector analysis 34

In Apache s 2010 submission to the parliament Inquiry on domestic gas prices it outlined that: 49 This [retention lease] policy is a market distortion unique to Australia. Acreage prospective for gas fields suited to supply the domestic market in WA, in many cases containing gas discoveries, is being warehoused by companies to supply the LNG market many years in the future. In any other country in the world such acreage would be released to be licensed to companies which could more rapidly exploit it. Abolition of the retention lease policy and stringent application of the commerciality requirements on existing retention leases would result in acreage prospective for gasfields suited to supply the WA domestic market being released for exploitation by companies qualified and motivated to supply that market. This increased supply would result in downward pressure on gas prices to the consumer. Domgas Alliance in its response to DRET s Discussion Paper noted that: 50 Experience in other countries demonstrates that far from discouraging investment, a more stringent approach to retention lease management would in fact promote development of Australia s gas resources. It would significantly improve exploration and production cycle time, and reduce development costs. That Australia s existing arrangements are out of step with those in other gas producing countries has created a perception of Australia as a safe harbour. This has encouraged international oil and gas companies to warehouse resources in Australia as part of a global resource management strategy. Domgas Alliance in its response to Queensland Government Consultation Paper on Domestic Gas Security noted that: 51 Major producers appear to be using offshore Retention Leases (which are jointly managed by the Commonwealth and State) to park gas reserves that might otherwise supply the domestic market on a commercial basis for increasingly ambitious LNG developments. While LNG producers initially claimed that resources were uneconomic for domestic gas development, such arguments appear no longer valid given the significant rise in domestic gas prices. LNG producers now claim that warehousing of resources is necessary to enable sequential field development of LNG projects. 4.3.1 Indicators on the application of the retention lease policy There have been a small number of high profile cases in recent years in which a retention lease renewal application has been rejected by the Joint Authority including: In December 2009, the Department of Mines and Petroleum rejected Dixon s retention lease renewal application (WA-9-R) by the North West Shelf Venture. This meant that the joint ventures had 12 months in which to apply for a production 49 Apache Energy, Submission to the parliament inquiry on domestic gas prices, 25 June 2010. 50 Domgas Alliance, Retention Lease Arrangements Response to the Department of Resources, Energy and Tourism Discussion Paper, 24 August 2009. 51 Domgas Alliance, Queensland Government Consultation Paper on Domestic Gas Security, Submission by the Domgas Allliance, 20 October 2009. Deloitte Access Economics: Western Australia gas sector analysis 35

Number of retention leases in WA licence and then five years to start recovering petroleum or lose the petroleum title completely. 52 On 25 March 2011, Nexus Energy Limited lost one of its petroleum titles when it applied for a retention lease renewal. It is understood that Nexus failed to drill an exploration well by a specified date (after being specifically notified to do so). The Department of Resources, Energy and Tourism subsequently stripped Nexus of its exploration permit (WA-368-P) in the offshore Perth Basin that was granted in 2005 and which contains the 90 million barrel Yngling prospect. However, the number of instances where retention lease renewal applications have been rejected by the Joint Authority is not known. It is therefore not clear from these small number of instances alone whether the retention lease policy is being rigorously applied. 4.3.1.1 Duration of retention leases To further examine the application and effect of the retention lease policy, we have looked at the number of retention leases held and the time from when the retention lease was granted to the time it expires (including renewals) in Western Australia. In 1990, less than 4% of the Commonwealth s offshore gas titles were held under retention leases but by 2000, this figure had grown to 29%. As at December 2009, more than 40% of the titles were held in retention lease. 53 Figure 19 outlines the number of retention leases held in Commonwealth waters in Western Australia and the time that they have been held. Figure 19 - Number of retention leases in Western Australia and time until expiry from initial grant 20 18 16 14 12 10 8 6 4 2 0 18 Retention leases renewed 11 3 2 1 0 0-5 5-10 10-15 15-20 20-25 25-30 Time to expiry from initial grant (years) Source: National Offshore Petroleum Titles Administrator, Deloitte analysis In Western Australia there are currently 35 retention leases held in Commonwealth waters, 17 of which have been renewed more than once and hence have a duration of greater than 52 Norton Rose <http://www.nortonrosefulbright.com/knowledge/publications/52263/petroleum-permits-useit-or-lose-it> 53 The Liberal party of Australia Western Australian Division, Joint authority announces decisions on Dixon and Browse retention leases <http://www.wa.liberal.org.au/article/joint-authority-announces-decisions-dixon-andbrowse-retention-leases> Deloitte Access Economics: Western Australia gas sector analysis 36

number of retetnion leases five years. One of these retention leases was first granted in 1987 and is due to expire in 2015. This means that to date, 27 years have passed since the initial retention lease was granted and this field has not been developed. Retention leases are granted, however, with the expectation of reserves being developed within 15 years. This retention lease is not the only example of a retention lease that has been held for a substantial period of time. In total, six retention leases, or around 25% of the land area that is held under retention leases, have been held for longer than 15 years. There are also five retention leases held in State waters, however, information on the duration of these leases is not available. 54 4.3.1.2 Retention lease holders We have also examined the composition of the companies holding Commonwealth retention leases. Together, a few large operators account for a significant number of the total reserves held under retention in Western Australia. Figure 20 Number of retention leases held by operator in Western Australia 10 8 6 4 2 0 Chevron Australia Woodside Energy & Browse Apache Northwest Hydra Energy GDF SUEZ Bonaparte Source: National Offshore Petroleum Titles Administrator, Deloitte analysis Esso Australia Resources Santos Offshore Eni Australia B.V. 4.3.1.3 Retention lease process transparency The process by which retention leases are granted does not include a public consultation stage. 55 As a result of this and the absence of published information, the reasoning and details relied on by the Joint Authority to determine whether a gas reserve is commercially viable are not clear. The absence of public consultation means that other market participants are not provided with the opportunity to demonstrate that reserves are commercially viable and would be developed if released from retention. In turn it is possible that fewer reserves are developed. 54 Government of Western Australia, tenements in Force <http://www.dmp.wa.gov.au/1521.aspx#1592> 55 DRET, Offshore Petroleum Guideline for Grant and Administration of a Retention Lease, May 2012. Deloitte Access Economics: Western Australia gas sector analysis 37

As noted by the DomGas Alliance in 2009: 56 This lack of transparency creates an asymmetry of information that exclusively benefits existing lease holders at the expense of prospective gas producers, or downstream gas customers. Stakeholders continue to express frustration at the current arrangements and their difficulties in being able to access information and engage in the process. This lack of transparency was also recognised in the Australian Government s Energy White Paper which outlined: 57 While the introduction of the retention lease framework has served the offshore sector well, the Australian Government believes that its implementation can be improved. Consultation undertaken as part of the review of the retention lease framework supported greater transparency Improving transparency will benefit titleholders and assist third parties to comment on retention lease awards or renewals and offer alternative development options. However, legitimate commercial data and information will remain protected. In the absence of reasons why retention leases are renewed and the lack of a transparent process, we are unable to confirm that the tests for renewing retention leases are being applied robustly by the Joint Authority. Therefore it may be possible that existing reserves which could be developed commercially for the domestic market are being withheld by incumbents for future use. We explore this further in the next chapter. 4.4 International comparison of lease retention arrangements Internationally, policies akin to the Australian retention lease policy exist. However, such international policies typically treat companies holding gas reserves less generously. As noted by Apache: 58 Tenure of exploration acreage in Australia is very long by worldwide standards By contrast in Egypt, another country in which Apache is an active explorer, the maximum duration of a petroleum title is 35 years and in this period the title holder must explore, appraise, develop and produce any discoveries it makes. The situation in the UK was comparable [to that in Australia]; it was felt that certain companies had made potentially commercial discoveries but that they were failing to develop them and that this failure was against the national interest A policy known as the Fallow Blocks / Discoveries Initiative was introduced which had the effect of moving both exploration acreage and discoveries into the hands of companies more motivated to commercialise these assets. It appears that Australia may be out of step with other countries and the application of Australian retention lease policy potentially allows companies to warehouse gas possibly meaning companies allocate capital preferentially to those overseas discoveries in their 56 DomGas Alliance Retention Lease Arrangements Response to the Department of Resources, Energy and Tourism Discussion Paper, 24 August 2009. 57 Australian Government, Energy White Paper 2012, Australia s energy transformation, p. 75. 58 Apache Energy, Submission to the parliament inquiry on domestic gas prices, 25 June 2010. Deloitte Access Economics: Western Australia gas sector analysis 38

worldwide portfolios which are subject to more stringent requirements by host governments to commercialise those reserves rapidly or to forfeit them. 59 4.4.1 UK precedent The Fallow Block Process and a Fallow Discovery Process in the UK are akin to use it or lose it arrangements whereby blocks and discoveries are considered fallow after three years without significant activity. These processes apply to blocks and discoveries under older licences to stimulate prudent activity in currently fallow blocks in order to enhance development of the UK s oil and gas resources. 60 Prior to the introduction of these processes, for gas licences issued between 1964 and 1972, if development had occurred anywhere on the license, companies could retain the acreage for up to 46 years without any further activity. 61 Up until 2011, there had been 122 exploration and appraisal wells drilled targeting prospects on Fallow Blocks since the process began in 2002. 62 This represented 25% of the 489 exploration and appraisal wells drilled from 2002-11. 63 Five field development plans on previously fallow discoveries have been approved. As of 2011, most acreage that was licensed under older licences has been reviewed and, where appropriate, re-licensed, with the terms of newer licences ensuring that unused acreage is relinquished. 64 4.4.2 US lease arrangements The lease arrangements in the US to some extent give effect to strict retention lease provisions in that: 65 Oil and gas companies are required to develop their properties within specific timeframes as set out in lease terms. Rents on the leases increase in later years to encourage faster development. In general, leases not producing by the end of their term are relinquished back to the government, which can then re-lease them. Companies pay a bonus bid to the federal government to acquire a lease, which can last anywhere from 5 to 10 years. This is in addition to annual rent paid to the government to maintain the leases, regardless of whether gas is found or not. Coupled with their investment in seismic surveys, environmental studies, technology development and exploratory drilling to find the oil and gas, this level of investment means that oil and gas companies already have a financial incentive to develop leases. 59 Apache Energy, Submission to the parliament inquiry on domestic gas prices, 25 June 2010. 60 Department of Energy & Climate Change, Revised guidelines for the Fallow Blocks process, 2005. 61 Domgas Alliance, Retention Lease Arrangements - Response to the Department of Resources, Energy and Tourism Discussion Paper, 21 August 2009. 62 Oil & Gas UK, Economic report 2012, p. 16. <http://www.oilandgasuk.co.uk/cmsfiles/modules/publications/pdfs/ec030.pdf> 63 Business Wire, UK North Sea Exploration Slows; Drilling Inventories at Record High, 26 November 2013 <http://www.businesswire.com/news/home/20131125005665/en/1derrick-research-uk-north-sea- Exploration-Slows> 64 Oil & Gas UK, Economic report 2012, p. 16. <http://www.oilandgasuk.co.uk/cmsfiles/modules/publications/pdfs/ec030.pdf> 65 US Code of Federal Regulations. Deloitte Access Economics: Western Australia gas sector analysis 39

5 Estimating whether undeveloped reserves are commercially viable We have developed a model to assess whether known reserves that are held under retention leases are commercially viable to supply the domestic market. Our model estimates the gas price required by a developer to earn 12% return on investment. If the resultant gas price to deliver a return of 12% is below the LNG netback price, the field is likely to be commercially viable. 5.1 Identification of reserves We selected two actual gas reserves, which we have labelled Projects A and B. Based on the following factors we assessed these two reserves to be the most likely to meet the commercial viability test: Size of reserves and the potential revenue stream Quality of the gas including the composition of the gas and potential revenue stream from condensate Location of the reserves, including sea water depth and proximity to land Estimated cost of development and operation (capital and operational expenditure) Estimated cost of decommissioning We have not identified these projects by name. This is because the purpose of this exercise is not to advocate for specific gas reserves to be released from retention leases. Rather, the purpose is to examine how rigorously the retention lease policy is being applied and to highlight the potential benefits to the Western Australian economy if more reserves that are suitable to supply the domestic gas market are developed. We also estimated the gas price required to deliver a 12% rate of return to the Macedon and Devils Creek projects the two projects that have been developed purely to supply the domestic gas market. With the development of Projects A and B, and the existing Devils Creek and Macedon projects, we estimate there would be sufficient domestic gas supply to meet the domestic gas demand without the need for supply from LNG producers. The resulting gas price of the most expensive domestic project would set the upper bound for the domestic gas price in contrast to the more expensive LNG netback price. Deloitte Access Economics: Western Australia gas sector analysis 40

5.1.1 Estimating commercial viability We have developed the inputs to our model as follows: Estimated the gas and condensate (a by-product of extracting the gas) production from Project A and B by looking at the reported size of the reserves and the quality/makeup of the gas. 66 To estimate the gas and condensate production from Devils Creek and Macedon we used public sources on their production capabilities and reserves. For all projects, we matched the gas production profile in our model to the quoted reserves. Assumed that condensate can be sold at US$95 per barrel based on the world price of oil. 67 Estimated the project development cost by using specialist advice prepared by a large and reputable engineering consultancy firm specifically for developing an offshore platform for Project A. 68 Before adopting this estimate we benchmarked the cost with publicly available cost information of other similar projects. To be conservative, we then added an additional 25% to the estimated capital expenditure costs to develop the project. 69 We have used industry benchmarks for the cost of wells, pipelines and ongoing operational expenditure (5% per annum of total capital expenditure). Used the cost breakdown for each component of the engineering consultancy firm s cost estimate for project A (plus an additional 25% contingency), to estimate the cost of project B. Our adjustments included adjusting specific equipment costs to account for the different condensate and carbon dioxide makeup of the gas between the two reserves. Estimated project closure/site cleanup costs based on the size of the onshore and offshore plant and the number of wells. Modelled the impact of company tax, royalties and the Petroleum Rent Resources Tax. Used an exchange rate of 0.8 to convert USD to AUD. Used an inflation rate of 2.5% per annum in line with the middle of the Reserve Bank of Australia s target. For the cost of Devils Creek and Macedon we used publicly available cost information. Modelled three years of capital expenditure during the project development phase and an additional 20 years of gas production. We have been conservative in undertaking our desktop production and cost estimates. Where possible we have relied directly on the engineering consultancy firm s analysis 66 Gas quality/makeup information was sourced from: Department of Minerals and Petroleum, Well Report for and Geoscience Australia, Gas Report (geochemical summary sheet). 67 Average realised condensate price for Santos was $US 114.73/bbl in Q4 2013, $US 92.84/bbl in Q1 2014, and for Woodside $US 105.04/bbl in 2013. See: Santos, First quarter activities report, 17 April 2014; Woodside, Annual report, 2013. 68 We used the firm s P50 benchmark being the base estimate plus a contingency of 25%. 69 This contingency is additional to the contingency used in the engineering firm s P50 estimate. Deloitte Access Economics: Western Australia gas sector analysis 41

(adding an additional cost margin of 25%), have used industry benchmarks and have benchmarked our analysis against other projects. 5.2 Results We have modelled a gas price range to make each reserve commercially viable, the midpoints of which are presented in the table below. 70 Table 3 - Gas price to make reserves commercially viable Project Midpoint gas price to achieve 12% return (A$/GJ, real) Assumed supply based on reserve characteristics (TJ per day) Project A 4.3 500 Project B 5.8 500 Macedon 71 5.9 211 Devils Creek 7.2 105 Source: Deloitte Access Economics analysis Devils Creek is the marginal cost project which results in a gas price of A$7.2/GJ. In contrast, Project A and B require a much lower gas price to achieve a 12% rate of return. Macedon requires a gas price of A$5.9/GJ to provide a return of 12%. On that basis, the upper bound for domestic gas prices would be based on the Devils Creek project, being A$7.2. 72 This is significantly lower than the upper bound LNG netback price A$10-$12/GJ. In our analysis for the Devils Creek project we have assumed it would be unable to tap additional reserves that are needed for it to sustain gas production near its nameplate capacity of 220 TJ per day for a period of 20 years. Given the sunk investment in gas processing facilities, Devils Creek would, however, have an incentive to continue operating its plant once the existing reserves are exhausted. 73 Additionally, given the significant gas reserves in Western Australia, it is possible that Devils Creek could source more gas to process in its plant. If so, and based on its production capacity, our model estimates that the gas price for Devils Creek to deliver a return of 12% would fall to A$5.7/GJ meaning that 70 The prices presented are the midpoint of our model s upper and lower bounds. These prices are based on the assumptions that we have outlined above and our desktop analysis. Our upper and lower bound ranges reflect variances in capital and operating cost estimates, gas and condensate production rates, project closure costs, taxes including estimates of PRRT and corporate taxes. 71 We have assumed that Macedon can tie in a nearby gas field owned by BHP, which results in lowering the gas price required by Macedon to deliver a 12% return. We have included an estimate of the capital costs required to do so in our model. 72 This is a conservative assumption because it assumes the preservation of a 12% return whereas in fact this return may be squeezed with the advent of more domestic production. Thus, the actual marginal cost could be lower which could result in more positive benefits to the Western Australian economy than estimated by our modelling. 73 An LNG producer with domestic supply capabilities, however, may not have a strong incentive to continue to supply to the domestic even though it has made a sunk investment because it could generate revenue from an alternative source the LNG market. Deloitte Access Economics: Western Australia gas sector analysis 42

the upper bound for domestic gas prices would be based on Macedon at A$5.9/GJ. 74 While this outcome is possible, we have not specifically identified a reserve that Devils Creek could tie into its existing operations. If the government was to apply the retention lease policy more rigorously then we would expect more domestic supply to come online to meet domestic demand, thereby delinking the domestic supply and pricing from the LNG market. Such conditions would make the current domestic gas reservation policy redundant. This is discussed further in the next chapter. 74 The price of gas for Devils Creek assuming it can tap additional reserves assumes that additional capital expenditure is required to develop the project and that opex and closure costs also increase. Deloitte Access Economics: Western Australia gas sector analysis 43

6 The current link between LNG and domestic supply in Western Australia The supply of domestic gas and the supply of LNG are separate industries that have been forced to operate as one because of the reservation policy and the current implementation of the retention lease policy. Allowing these industries to operate separately is likely to increase the production of gas made available for the domestic market and delink the domestic price from the international LNG price. 6.1 Characteristic of players in the LNG and domestic gas industries The Western Australian LNG supply industry is occupied by very large companies that operate large gas reserves such as those found in the North West Shelf. To attract financing these projects typically contract 80% of their gas production to international buyers. Such contracts typically have a 20 year duration and are negotiated prior to undertaking the final investment decision to develop LNG plants. Further, LNG customers often take equity stakes in LNG plants, partly to share in price upside, partly to ensure supply visibility and partly to lock in supply. In addition to these company characteristics, LNG sites require different infrastructure to domestic focussed production. For example they require LNG storage tanks, dredging, jetty construction and they may not have the infrastructure in place to transport gas to the domestic market. On the other hand, gas projects focused for the domestic market can typically be undertaken by smaller gas players. While small/mid-tier gas players usually initiate LNG projects from the exploration end they rarely have the financial or technical resources to complete an LNG project alone. While still substantial, the capital expenditure to serve the domestic market is often lower (for example no dredging or jetty construction costs). Given that the Australian market is smaller than the world market and that contract sizes are likely to be smaller, arranging these contracts requires less specialist skills. 6.2 Two industries forced to operate as one As a result of the differences between the two industries, it is likely that LNG players would prefer not to be required to supply to the domestic market. This may be driving the apparent unwillingness of the North West Shelf to recontract with domestic gas users. However, in Western Australia: Deloitte Access Economics: Western Australia gas sector analysis 44

The reservation policy has forced LNG focussed producers to supply the domestic market meaning that the domestic focussed supply is underdeveloped there are only six domestic plants currently producing 561 TJ/day per annum focussed on serving the domestic market. 75 The price at which domestic gas users can execute long term contracts is close to the LNG netback price. This is unsurprising given the netback price is available to LNG focussed producers in the LNG market, and hence will be the price that they are willing to sell to domestic users under the reservation policy. In combination with the reservation policy, the development of the domestic supply has been hampered by the current implementation of the retention lease policy. Gas reserves, which our modelling suggests may be commercially viable to develop for the domestic market, remain under retention leases held by the major LNG players. The lack of domestic focussed supply means that the LNG producer s supply under the reservation policy becomes the marginal supply and influences the domestic price. The LNG and domestic gas supply industries could be delinked by removing the reservation policy and by more rigorously applying the retention lease policy. If this occurred, it is likely that LNG suppliers would exit the domestic gas market. Gas reserves would be freed up and developed by domestic focussed suppliers. Additionally, the price of gas should tend towards the marginal cost of domestic production rather than the LNG netback price. While we would not recommend that the domestic reservation policy be abolished immediately, we believe that there is a case for it to be wound back while simultaneously applying the retention lease policy more rigorously, thus giving the market time to adjust. 75 Whereas in 2012-13 domestic demand was around 893 TJ/day. See section 2.1, Table 2 and Figure 14. Deloitte Access Economics: Western Australia gas sector analysis 45

7 Modelling impact of more domestic gas production We have modelled the effects on the Western Australian economy of the price of gas tending to its marginal cost of A$7.2 based on the Devils Creek development. Modelling the economy wide impacts of a reduction in domestic gas prices has been undertaken using the DAE-RGEM model, Deloitte Access Economics in house computable general equilibrium (CGE) model. This model provides the necessary industry and sectoral detail along with a national accounting treatment of the national economy needed to translate the immediate impacts of changes to the structure of the gas market and fuel switching estimates to economy wide macroeconomic impacts. The widespread use of CGE models to undertake this style of analysis is underpinned both by the resolution available in the underlying data and the inclusion of important drivers such as potential crowding-out in labour and capital markets. Further details of the DAE-RGEM model are provided in Appendix A. 7.1 Modelling approach We have modelled two scenarios. The base scenario represents domestic gas prices based on LNG netback pricing. 76 In the alternative scenario sufficient gas reserves are developed (consistent with our earlier modelling), such that domestic gas prices are delinked from LNG netback pricing and represent the marginal cost of domestic supply being A$7.2/GJ based on the Devils Creek project. The following figure presents the gas price for the two scenarios. 76 LNG netback prices are based on forecast of Brent and Henry Hub prices, sourced from Energy Information Administration (US). Deloitte Access Economics: Western Australia gas sector analysis 46

Figure 21 Average gas price under LNG netback and domestic supply scenario (A$, real 2013-14) $/GJ 16.00 Price set by LNG netback Price set by domestic supply 14.00 12.00 10.00 8.00 6.00 4.00 2.00 0.00 Source: Deloitte Access Economics analysis In determining the prices we have taken a weighted average of existing and new contracts. In the model, existing contracts are priced at A$4.0/GJ until their expiry (2020-21) and new contracts are priced at either LNG netback pricing in the LNG netback scenario, or the upper bound of the domestic supply being A$7.2/GJ based on Devils Creek in the domestic supply scenario. 77 To all prices we have added an allowance for gas transportation. The average gas price in the domestic supply scenario is A$2.2/GJ lower by 2020 and A$4.4/GJ by 2025. We present the impact to the Western Australian economy of lowering the gas prices from its current LNG netback pricing to reaching an upper bound of A$7.2/GJ based on the Devils Creek project. We have presented the results of our model in a two staged approach; the first stage being a lower gas price to meet normal gas demand. The second stage incorporates latent demand being met by additional gas supplies at the lower price. Stage one - The impact on Western Australia of gas prices reflecting domestic marginal cost Stage one presents the impact on the Western Australian economy if the gas price is set by domestic supply instead of LNG netback pricing. A lower gas price would result in increased Gross State Product (GSP) as input costs are lowered to the economy and the economy becomes more productive, resulting in expanded output. It also incorporates the impact of higher capital and operating expenditure made as a result of developing Projects A and B. 77 Based on our knowledge existing contracts priced around A$4 will expire in 2020-21. Deloitte Access Economics: Western Australia gas sector analysis 47

Figure 22 Additional Gross State Product from a fall in the domestic gas price ($A, real 2013-14) 3,500 Increase in GSP, $ million 3,000 2,500 2,000 1,500 1,000 500 - Source: Deloitte Access Economics analysis The impact to GSP is significant. It increases by around A$2.0 billion in 2020 and A$3.0 billion in 2030. The projected increase in economic activity is a combination of three main effects. First, additional activity due to the development of gas reserves for the domestic market which effectively brings forward economic development. Second, an improvement in the international competitiveness of the Western Australian economy through the availability of lower cost gas to downstream users (particularly in manufacturing). Third, over the longer term, an improvement in the energy efficiency of the Western Australian economy as gas is assumed to replace higher cost diesel in areas such as electricity. The following figure shows the increase to employment as a result of higher GSP and the capital and operating expenditure to develop and operate Project A and B. Employment increases by around 2,000 FTEs in 2020, increasing to 2,100 FTEs in 2030. Deloitte Access Economics: Western Australia gas sector analysis 48

Figure 23 Additional employment from a fall in the gas price Increase in Full Time Equivalent 2,500 2,000 1,500 1,000 500 - Source: Deloitte Access Economics analysis The relative impact on increased FTEs is much smaller than the increase to GSP. This is because lower gas prices mainly improve the productivity of capital which results in large increases to GSP. There are likely to be other benefits that our model has not quantified that are associated with plentiful and lower priced gas such as: Encouraging innovation and early adoption of technology Environmental benefits associated with cleaner energy (for example from electricity generation and vehicle fuel conversion) Additionally, our model does not capture the full effect of large step changes in industry. In Western Australia there are a small number of significant gas users, such as alumina refineries. A lower gas price may encourage significant users to enter the market or may prevent existing users from leaving. Our model, however, would not capture the benefit of such step changes and so in this respect, our GSP and employment benefits are likely to be conservative. Stage two - The impact on Western Australia of gas prices reflecting domestic marginal cost including latent demand In this scenario we have assumed that latent demand is met by the expanded domestic gas supply. Consistent with stage one, the domestic gas price is set by domestic supply instead of LNG netback pricing. The figure below presents the impact to GSP. Deloitte Access Economics: Western Australia gas sector analysis 49

Figure 24 Additional Gross State Product from a fall in the domestic gas price including latent demand (A$, real 2013-14) 6,000 Increase in GSP, $ million 5,000 4,000 3,000 2,000 1,000 - Source: Deloitte Access Economics analysis The impact to GSP is higher than in stage one. GSP increases by around A$2.5 billion in 2020 and A$4.8 billion in 2030. The following figure shows the increase to employment as a result of higher GSP and the capital and operation expenditure to develop and operate Project A and B. Employment increases by around 2,100 FTEs in 2020, increasing to 2,600 FTEs in 2030. Figure 25 Additional employment from Projects A and B including latent demand Increase in Full Time Equivalent 3,000 2,500 2,000 1,500 1,000 500 - Source: Deloitte Access Economics analysis Sensitivity analysis domestic gas price based on Macedon (A$5.9/GJ) We have also undertaken sensitivity analysis using a domestic gas price of A$5.9/GJ based on the price of the Macedon project. This sensitivity assumes that Devils Creek can tap additional gas reserves enabling it to produce near its nameplate capacity for another 20 years. If this occurred, Macedon would become the highest cost domestic producer at Deloitte Access Economics: Western Australia gas sector analysis 50

A$5.9/GJ. However because we have not specifically identified a reserve that Devils Creek would be likely to tap, we have modelled this as a sensitivity analysis rather than a scenario. Our baseline LNG gas price is the same as that used in earlier in our analysis. The domestic gas price is the upper bound of the domestic supply being A$5.9/GJ based on Macedon in the domestic supply scenario. To all prices we have added an allowance for gas transportation. The following figure presents the baseline and the average gas price for this sensitivity analysis. Figure 26 Average gas price under LNG netback and domestic supply scenario (A$, real 2013-14) $/GJ 16 14 12 Price set by LNG netback Price based on Devils Creek Sensitivity analysis - price based on Macedon 10 8 6 4 2 0 Source: Deloitte Access Economics analysis The average gas price in the domestic supply scenario is A$3.2/GJ lower by 2020 and A$5.7/GJ by 2025. We present the impact to the Western Australian economy of lowering the gas prices from its current LNG netback pricing to reaching an upper bound of A$5.9/GJ based on the Macedon project. We have presented the results of our model in only one stage, which incorporates latent demand being met by additional gas supplies at the lower price (that is, on the same basis as the latter set of results from scenario one). The figure below presents the impact to GSP. Deloitte Access Economics: Western Australia gas sector analysis 51

Figure 27 Additional Gross State Product from a fall in the domestic gas price including latent demand (A$, real 2013-14) 6,000 Increase in GSP, $ million 5,000 4,000 3,000 2,000 1,000 - Source: Deloitte Access Economics analysis The impact to GSP is higher than in the scenario analysis. GSP increases by around A$2.8 billion in 2020 and A$5.25 billion in 2030. The following figure shows the increase to employment as a result of higher GSP and the capital and operation expenditure to develop and operate Project A and B. Employment increases by around 2,500 FTEs in 2020, increasing to 3,000 FTEs in 2030. Figure 28 Additional employment from Projects A and B including latent demand Increase in Full Time Equivalent 3,500 3,000 2,500 2,000 1,500 1,000 500 - Source: Deloitte Access Economics analysis As per scenario one, the relative impact on increased FTEs is much smaller than the increase to GSP. This is because lower gas prices mainly improve the productivity of capital which results in large increases to GSP. Deloitte Access Economics: Western Australia gas sector analysis 52

8 Findings There is currently tightness in the Western Australian domestic gas market because its proponents are uncertain as to whether the North West Shelf will recontract with domestic consumers. This tightness will continue if the North West Shelf does not recontract, possibly resulting in a shortfall of domestic gas supply. Notwithstanding the supply tightness, the price of domestic gas in Western Australia is around A$10-$12/GJ, which is based on the LNG netback price. This is because the price of domestic gas is linked to the price of LNG via the domestic gas reservation policy which requires LNG producers to reserve gas for the domestic market. If more gas reserves were developed for the domestic market then the domestic gas reservation policy could be phased out and the price of domestic gas would tend towards the cost of developing domestic reserves. However, our modelling suggests that gas reserves, which are commercially viable to be developed for domestic supply, are being held under retention leases. Thus we believe that there is a case for more rigorously applying the retention lease policy. If additional gas reserves were developed for the domestic market, our analysis suggests that the domestic gas price would fall to around A$7.2/GJ which is the gas price of the most expensive domestic project, Devils Creek. This price would set the upper bound for the domestic gas price in contrast to the more expensive LNG netback price. Our modelling suggests that if the price of gas fell from an upper bound LNG netback price of A$10-$12/GJ to A$7.2/GJ, then the Western Australian economy would benefit from an annual increase to Gross State Product of around A$2.5 billion in 2020, increasing to A$4.8 billion by 2030. This is a significant increase in Western Australia s GSP, which was around A$243 billion in 2012-13. 78 It is therefore imperative that governments more rigorously apply the principles of the retention lease policy and enhance transparency of the process. Along with phasing out the domestic gas reservation policy, these changes will result in a more competitive and robust domestic gas market. 78 Western Australian Department of State Development, Western Australia Economic Profile, February 2014. Deloitte Access Economics: Western Australia gas sector analysis 53

Appendix A The DAE-RGEM model The Deloitte Access Economics Regional General Equilibrium Model (DAE-RGEM) is a large scale, dynamic, multi-region, multi-commodity computable general equilibrium model of the world economy. The model allows policy analysis in a single, robust, integrated economic framework. This model projects changes in macroeconomic aggregates such as GDP, employment, export volumes, investment and private consumption. At the sectoral level, detailed results such as output, exports, imports and employment are also produced. The model is based upon a set of key underlying relationships between the various components of the model, each which represent a different group of agents in the economy. These relationships are solved simultaneously, and so there is no logical start or end point for describing how the model actually works. Figure A.1 shows the key components of the model for an individual region. The components include a representative household, producers, investors and international (or linkages with the other regions in the model, including other Australian States and foreign regions). Below is a description of each component of the model and key linkages between components. Some additional, somewhat technical, detail is also provided. Figure A.1: Key components of DAE-RGEM DAE-RGEM is based on a substantial body of accepted microeconomic theory. Key assumptions underpinning the model are: Deloitte Access Economics: Western Australia gas sector analysis 54

The model contains a regional consumer that receives income from factor payments (labour, capital, land and natural resources), taxes and net foreign income from borrowing (lending). Income is allocated across household consumption, government consumption and savings so as to maximise a Cobb-Douglas (C-D) utility function. Household consumption for composite goods is determined by minimising expenditure via a CDE (Constant Differences of Elasticities) expenditure function. For most regions, households can source consumption goods only from domestic and imported sources. In the Australian regions, households can also source goods from interstate. In all cases, the choice of commodities by source is determined by a CRESH (Constant Ratios of Elasticities Substitution, Homothetic) utility function. Government consumption for composite goods, and goods from different sources (domestic, imported and interstate), is determined by maximising utility via a C-D utility function. Savings generated in each region are used to purchase bonds whose price movements reflect movements in the price of creating capital. Producers supply goods by combining aggregate intermediate inputs and primary factors in fixed proportions (the Leontief assumption). Composite intermediate inputs are also combined in fixed proportions, whereas individual primary factors are combined using a CES production function. Producers are cost minimisers, and in doing so, choose between domestic, imported and interstate intermediate inputs via a CRESH production function. The model contains a more detailed treatment of the electricity sector that is based on the technology bundle approach for general equilibrium modelling developed by ABARE (1996). The supply of labour is positively influenced by movements in the real wage rate governed by an elasticity of supply. Investment takes place in a global market and allows for different regions to have different rates of return that reflect different risk profiles and policy impediments to investment. A global investor ranks countries as investment destinations based on two factors: global investment and rates of return in a given region compared with global rates of return. Once the aggregate investment has been determined for Australia, aggregate investment in each Australian sub-region is determined by an Australian investor based on: Australian investment and rates of return in a given sub-region compared with the national rate of return. Once aggregate investment is determined in each region, the regional investor constructs capital goods by combining composite investment goods in fixed proportions, and minimises costs by choosing between domestic, imported and interstate sources for these goods via a CRESH production function. Deloitte Access Economics: Western Australia gas sector analysis 55

Prices are determined via market-clearing conditions that require sectoral output (supply) to equal the amount sold (demand) to final users (households and government), intermediate users (firms and investors), foreigners (international exports), and other Australian regions (interstate exports). For internationally-traded goods (imports and exports), the Armington assumption is applied whereby the same goods produced in different countries are treated as imperfect substitutes. But, in relative terms, imported goods from different regions are treated as closer substitutes than domestically-produced goods and imported composites. Goods traded interstate within the Australian regions are assumed to be closer substitutes again. The model accounts for greenhouse gas emissions from fossil fuel combustion. Taxes can be applied to emissions, which are converted to good-specific sales taxes that impact on demand. Emission quotas can be set by region and these can be traded, at a value equal to the carbon tax avoided, where a region s emissions fall below or exceed their quota. Households Each region in the model has a so-called representative household that receives and spends income. The representative household allocates income across three different expenditure areas: private household consumption; government consumption; and savings. Going clockwise around Figure A.1, the representative household interacts with producers in two ways. First, in allocating expenditure across household and government consumption, this sustains demand for production. Second, the representative household owns and receives income from factor payments (labour, capital, land and natural resources) as well as net taxes. Factors of production are used by producers as inputs into production along with intermediate inputs. The level of production, as well as supply of factors, determines the amount of income generated in each region. The representative household s relationship with investors is through the supply of investable funds savings. The relationship between the representative household and the international sector is twofold. First, importers compete with domestic producers in consumption markets. Second, other regions in the model can lend (borrow) money from each other. The representative household allocates income across three different expenditure areas private household consumption, government consumption and savings to maximise a Cobb-Douglas utility function. Private household consumption on composite goods is determined by minimising a CDE (Constant Differences of Elasticities) expenditure function. Private household consumption on composite goods from different sources is determined by a CRESH (Constant Ratios of Elasticities Substitution, Homothetic) utility function. Government consumption on composite goods, and composite goods from different sources, is determined by maximising a Cobb-Douglas utility function. Deloitte Access Economics: Western Australia gas sector analysis 56

Savings generated in each region are used to purchase bonds whose price movements reflect movements in the price of generating capital. Producers Apart from selling goods and services to households and government, producers sell products to each other (intermediate usage) and to investors. Intermediate usage is where one producer supplies inputs to another s production. For example, coal producers supply inputs to the electricity sector. Capital is an input into production. Investors react to the conditions facing producers in a region to determine the amount of investment. Generally, increases in production are accompanied by increased investment. In addition, the production of machinery, construction of buildings and the like that forms the basis of a region s capital stock, is undertaken by producers. In other words, investment demand adds to household and government expenditure from the representative household, to determine the demand for goods and services in a region. Producers interact with international markets in two main ways. First, they compete with producers in overseas regions for export markets, as well as in their own region. Second, they use inputs from overseas in their production. Sectoral output equals the amount demanded by consumers (households and government) and intermediate users (firms and investors) as well as exports. Intermediate inputs are assumed to be combined in fixed proportions at the composite level. As mentioned above, the exception to this is the electricity sector that is able to substitute different technologies (brown coal, black coal, oil, gas, hydropower and other renewables) using the technology bundle approach developed by ABARE (1996). To minimise costs, producers substitute between domestic and imported intermediate inputs is governed by the Armington assumption as well as between primary factors of production (through a CES aggregator). Substitution between skilled and unskilled labour is also allowed (again via a CES function). The supply of labour is positively influenced by movements in the wage rate governed by an elasticity of supply is (assumed to be 0.2).This implies that changes influencing the demand for labour, positively or negatively, will impact both the level of employment and the wage rate. This is a typical labour market specification for a dynamic model such as DAE-RGEM. There are other labour market settings that can be used. First, the labour market could take on long-run characteristics with aggregate employment being fixed and changes to labour demand changes being absorbed through movements in the wage rate. Second, the labour market could take on short-run characteristics with fixed wages and flexible employment levels. Deloitte Access Economics: Western Australia gas sector analysis 57

Investors Investment takes place in a global market and allows for different regions to have different rates of return that reflect different risk profiles and policy impediments to investment. The global investor ranks countries as investment destination based on two factors: current economic growth and rates of return in a given region compared with global rates of return. Once aggregate investment is determined in each region, the regional investor constructs capital goods by combining composite investment goods in fixed proportions, and minimises costs by choosing between domestic, imported and interstate sources for these goods via a CRESH production function. International Each of the components outlined above operate, simultaneously, in each region of the model. That is, for a simulation the model forecast changes to trade and investment flows within, and between, regions subject to optimising behaviour by producers, consumers and investors. Of course, this implies some global conditions that must be met, such as global exports and global imports, are the same and that global debt repayment equals global debt receipts each year. Deloitte Access Economics: Western Australia gas sector analysis 58

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