SISTEMA DE ESTADÍSTICAS TURÍSTICAS EN ESPAÑA.

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.

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

(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

Macedon71 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.

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.

6

The current link between LNG