Australian Transport Fuel Energy Security of Supply
From MoxyWiki
Australia's transport fuel energy security of supply
Decision Situation
How can Australia's fuel security be ensured by domestic production of synthetic hydrocarbons?
A concern about Australia's energy security motivated an assessment of new energy resource development during the early 1980s.[1] The need to reduce Australia’s dependence on imported oil was recognised in the CSIRO's report[2] on research carried out in the 1980s to improve the efficiencies of synthetic fuel production.
Yet, under the pressure of increased demand for transportation fuels, decreasing rates of extraction of crude oil from domestic sources, and limitations in refining capacity, that dependence seemingly grows inexorably.
The 'make versus buy' decision situation has two closely linked parts.
At the macroeconomic level of the Australian economy as a whole, the question is: can synthetic hydrocarbon crudes, derived from indigenous resources such as coal and natural gas and biomass, augment the domestic production of crude oil and other refinery feedstocks at a scale that ensures Australia’s transportation fuel security, with minimum recourse to the importation of crude oil and other refinery feedstocks and of refined petroleum products?
At the level of the firms engaged in petroleum refining and sales, the question is: can the synthetic crudes be integrated into existing refining and supply infrastructure, in a way that strengthens the Relative Competitive Position (RCP) of Australia’s refiners in global markets for refinery feedstocks and refined petroleum products?
Strategic options available to Australia to mitigate the petroleum balance of trade deficit
In its report on the state of the Australia’s Oil and Gas industry in 2009[3], the Australian Petroleum Production and Exploration Association (APPEA), citing Australian Bureau of Resource Economics (ABARE)[4] data, puts the deficit in the petroleum balance of trade in 2007-08 at $13.1 billion. The 2007-08 deficit is reported to be $4.7 billion higher than it was in 2006-07.
APPEA submits that the liquids trade deficit, excluding LNG, could increase to $28 billion, or more, by 2017.
The final report of the Standing Committee on Rural and Regional Affairs and Transport on Australia’s future oil supply and alternative transport fuels calls for “a multifaceted approach to reduce dependence on imported oil”.
It is the intent of APPEA’s Upstream Oil and Gas Industry strategy to offset the deterioration in the petroleum balance of trade by the amount of $20 billion per annum by 2017[3]. A key tactic underlying the strategy is to increase LNG production capacity from 2008 levels of nominally 20 million tonnes per annum (mtpa) to 50 mtpa[3].
The deficit might also be reduced by increasing the domestic availability of refinery feedstock through future expansion of Australian crude oil and condensate production.
Australia’s sedimentary basins have been only lightly explored; it might be construed that Australia's overall petroleum endowment remains to be discovered. However, the rating of the hydrocarbon prospectivity of the basins is uncertain.
When new oil and other refinery feedstocks are discovered, the elapsed time between the release of new acreage and the commencement of production is substantial.
This paper examines strategic options for augmentation of imported crude petroleum feedstock and finished products with the domestic production of synthetic crudes from these two perspectives:
- the appropriate strategic scale at which to augment imported materials, and the distribution of that scale; and,
- how that augmentation is best integrated strategically into existing fuel refining and supply assets and infrastructure.
Australia's petroleum balance of trade
The structure of the petroleum industry upstream and downstream supply chains is shown shematically in Figure 1. The streams impacting on the petroleum balance of trade are numbered.
Figure 1: Schematic of the Australian upstream and downstream supply chains showing the streams impacting on the petroleum balance of trade
Note on Figure 1: LPG ≡ Liquefied Petroleum Gas
The values, volumes and energy flows associated with the streams affecting the petroleum balance of trade for the financial year 2007-08 are summarised in Table 1.
Table 1: Values, volumes and energy flows associated with the streams affecting the petroleum balance of trade for the financial year 2007-08
| Stream | AUD bn | GL | PJ | AUD/L | AUD/GJ | AUD/tonne |
| 1 - imported crude | 17.149 | 26.223 | 1019.0 | 0.654 | 16.83 | 818 |
| 2- imported refined | 13.454 | 17.982 | 658.7 | 0.748 | 20.43 | 935 |
| 3 - exported crude & ORF | 10.484 | 15.975 | 594.3 | 0.656 | 17.64 | 820 |
| 4 - exported LPG | 1.182 | 2.589 | 66.5 | 0.457 | 17.77 | 787 |
| 5 - exported refined | 2.78 | 3.974 | 146.9 | 0.700 | 36.98 | 875 |
| Imports - Exports | 16.157 | 21.667 | 870 |
Notes on Table 1:
- GL ≡ Gigalitres (billion 109 litres); PJ ≡ Petajoules (1015 Joules)
- The data is derived from ABARE tables.
- Notwithstanding the limitations known to be associated with measures based on, or derived from, customs records, a reasonably sound estimate can be made of the relative contributions of the imbalances in upstream and downstream trading to the overall trade deficit.
- The unit value on a weight basis is estimated by assuming an average density of 0.80 kg/L for the feedstocks and refined products, and by using a value of 0.58 kg/L for LPG.
The data in Table 1 shows the macroeconomic impacts of the need to import crude oil and other refinery feedstocks, and refined petroleum products in financial year 2007-08 to be respectively of the order of:
- crude oil and other refinery feedstocks: AUD $5.5 bn
- refined petroleum products: AUD $10.7 bn
Assessing transport fuel energy security of supply
Given that LNG exports in 2007-08 amounted to AUD $5.84 bn, it might be construed from the above data and information that, at least in this instance, upstream trade in gas and oil commodities is somewhat in balance.
The security of Australia’s fuel energy infrastructure is properly assessed by reference to:
- the balance of trade in crude oil and other refinery feedstocks; and,
- the extent to which transport fuels are physically available in domestic markets.
The US Department of Energy’s metrics for assessing transport fuel energy security provide sound guidance. These are:
- Macroeconomic:
- on the supply side: annual and cumulative avoided oil imports;
- on the demand side: oil intensity reduction
- expressed as billion barrels of oil consumed per dollar of annual GDP.
- Microeconomic:
- on the supply side: fuel diversity improvement;
- on the demand side: fuel security economy
- expressed as light duty vehicle miles travelled per unit of gasoline, diesel and LPG consumption.
The measure of fuel diversity is based on the Shannon-Weiner Index, by means of which account is taken of the number of categories of fuels, and the ‘evenness’ of the distribution of the categories within the total fuel consumed. The index is at a maximum value when all categories are present in equal numbers.
The need to import crude oil and other refinery feedstock is imposed by limitations in Australia's domestic production, and by the refining capacities and configurations of its seven refineries. The task of ensuring domestic feedstock availability is made more complex by large shifts in the specific gravities of domestic production.
When fields within the Gippsland and Bonaparte basins dominated the upstream supply chains, the distribution of the °API gravity of Australia’s crude oils was relatively narrow.
Now that the fields within the Carnarvon basin provide the dominant proportion of domestic crude oil and condensate, the Shannon-Weiner index has increased appreciably. Increased production of heavy crudes (API less than 22.3°) from Enfield and Stybarrow fields, in particular, balances the increased production of condensates (API greater than 58°).
Trends in the crude oil production from three major Australian basins are shown in Figure 2.
Figure 2: Crude oil production from the Bonaparte, Carnarvon and Gippsland basins in the period from 200 to 2009
A reasonable facsimile of the changes in the distribution of the specific gravities of domestically produced crude oils, derived from data and information available in the public domain, is shown in Table 2.
Table 2: Schematic of the distribution of the API gravity of Australian crude oils, comparing 2004 with 2008
The capability to export condensates and crude oils under contract and to spot markets is essential to the financial performance of the upstream petroleum industry.
A supply side metric appropriate to assessing the fuel energy security of Australia’s upstream petroleum industry is: cummulative export revenues, subject to the constraint that cumulative import volumes are minimised over the same period.
Given refining capacity constraints, importation of refined petroleum products is essential to meeting domestic demand. The capability to export refined domestic products under contract and to spot markets is essential to the financial performance of the downstream petroleum industry.
A supply side metric appropriate to assessing the fuel energy security of Australia’s downstream petroleum industry is: cumulative import volumes, subject to meeting annual domestic demand for refined petroleum products.
Standards governing the freedom to operate the markets for fuels add further constraints. Externalities include: impacts on local air quality; life cycle greenhouse gas emissions; local environmental impacts on liquid and solid waste discharges; safety; consumption of corollary resources; and, the impact on the economic well-being of rural and remote communities of fuel energy costs.
The likely scale of augmentation of domestic production of crude oil and other refinery feedstocks to ensure domestic feedstock availability
The production profiles of each of the domestic producing fields, feedstock inventories, prices and yields, the 'crude diets' and configurations of the seven Australian refineries, and the profile of product demand, combine to determine the requirement for crude oil and other refinery feedstock imports at any time.
Estimates can be made of aggregate requirements for augmentation under different scenarios, in the absence of detailed knowledge of these factors over a given period.
Supply chain system throughputs in the current period of interest, 2006 to 2009, were at a maximum in the financial year 2007-08. Data and information pertaining to that financial year thus provide a means of calibrating the minimum requirement of augmentation, at least in the immediate future.
From the data of Table 1:
- IF exported crude oil and other refinery feedstock were available to be refined domestically,
- THEN the minimum (‘baseline’) requirement is hypothetically 10 GL.
- IF feedstock exports were maintained at the 2007-08 level, AND IF no investment in new refining capacity were made,
- THEN the requirement is nominally 26 GL.
- IF feedstock exports were maintained at the 2007-08 level, AND IF investment in new refining capacity were made to the extent that no importation of refined product were required,
- THEN the requirment is nominally 40 GL.
The minimum-essential scale of additional refining capacity to ensure transportation fuel security
The unit quantity used to record trade in crude petroleum is litres. The material flows in the 2007-08 financial year through the upstream petroleum supply chain and the refining and supply segments of the downstream supply chain are shown in Figure 2. Energy flows can be conveyed schematically in a similar manner.
Figure 2: Material flows in the 2007-08 financial year through the Australian upstream petroleum supply chain and the refining and supply segments of the downstream supply chain
If account is taken of 0.845 GL of biproducts of downstream processing, the volume of products leaving the refinery gates amounts to 38.73 GL[5], accounting for approximately 75% of the 50.788 GL[5] of total marketable petroleum products consumed in 2007-08. A breakdown of these demand and supply volumes is presented in Table 2.
Table 2:Demand and supply volumes
| Total for 2007-08 | Marketable petroleum products | Refinery sales volumes | |
| Total petrol | GL | 19.23 | 17.08 |
| Total diesel | GL | 18.26 | 12.18 |
| Total other fuels | GL | 11.82 | 7.90 |
| Total other products | GL | 1.48 | 1.57 |
| Total | GL | 50.79 | 38.73 |
In addition to the 11.2 GL of imported refined petroleum products to fill the domestic supply - demand gap, it is estimated that nominally 5 GL was imported to support export opportunities.
Filling the supply - demand gap for automotive gasoline, diesel and aviation fuels and fuel oil would require an increase in total production capacity of these commodities of approximately 11 GL per annum. This corresponds to an increase of nominally 250,000 barrels per stream day (BPSD), at the average refinery utilisation rate in 2007-08 of 88%. A breakdown of the increased production is shown in Table 3.
Table 3: Supply demand gap for refined petroleum products in Australia 2008
| Estimated production rate to meet gaps: | ML per day | BPSD | |
| Automotive gasoline | 6.71 | 41.933 | |
| Total diesel | 18.92 | 118,229 | |
| Total other fuels | 12.36 | 77,249 |
A perspective of the financial performance of the Australian refining and supply industry segments based on estimates of gross margins
Indicative total revenues and cost of sales for the refining and supply industry segments in AUD bn are shown in Table 4[6].
Table 4: Indicative total revenues and cost of sales for the refining and supply industry segments in AUD bn
| Refining | Supply | Refining + Supply | |
| Revenues | 28.5 | 26.5 | 55.0 |
| Cost of Sales | 27.0 | 25.0 | 52.0 |
Indicative revenue streams in AUD bn are shown in Figure 3. The upstream export revenues are also displayed.
Figure 3: Indicative Refining and Supply segment revenue streams in AUD bn and upstream revenues
The figure of AUD3.6 bn assigned to refined petroleum exports is obtained from the Department of Foreign Affairs and Trade (DFAT) report[7] on merchandise trade.
Indicative values, volumes and energy flows of petrol and diesel at the refinery and terminal gates are shown in Table 5 on a full and unit basis[8][4][4].
Table 5: Indicative values, volumes and energy flows of petrol and diesel at the refinery and terminal gates on a full and unit basis
| Petrol | AUD bn | GL | PJ | MJ/L | AUD/L | AUD/GJ | AUD/tonne |
| Refinery gate | 12.64 | 17.079 | 584.10 | 34.2 | 0.74 | 21.64 | 925 |
| Terminal gate | 15.58 | 19.234 | 657.80 | 34.2 | 0.81 | 23.68 | 1013 |
| Diesel | |||||||
| Refinery gate | 10.23 | 12.180 | 470.15 | 38.6 | 0.84 | 21.76 | 1050 |
| Terminal gate | 16.61 | 18.256 | 704.68 | 38.6 | 0.91 | 23.58 | 1138 |
Notes on Table 5:
- The refinery gate unit values were obtained from the Australian Competition and Consumer Commission (ACCC) report[6]; terminal gate unit values are obtained by subtracting from the national average prices $0.50/L, in order to account for excise tax + GST less any state subsidies[9]
- MJ ≡ Megajoules
- Comparison of the revenues accruing due to differences in refinery and terminal gate prices for petrol and diesel (shown in the Table) with the total supply segment revenues associated with the sale of petrol and diesel (shown in Figure 2), indicates that there are a number of additional sources of revenue derived from the domestic supply of these fuels.
Some guidance as to the gross margins on imported and exported refined products can be obtained by comparing Table 4 with the indicative values, volumes and energy flows of the streams which impact on the petroleum balance of trade. These are shown in Table 6 on unit basis, along with the full basis data previously reported in Table 1.
Table 6: Indicative values, volumes and energy flows of the streams which impact on the petroleum balance of trade on a full and unit basis
| Stream | AUD bn | GL | PJ | MJ/L | AUD/L | AUD/GJ | AUD/tonne |
| 1 | 16,767 | 26.223 | 1,019 | 38.9 | 0.64 | 16.45 | 799 |
| 2 | 12,044 | 16.214 | 658.7 | 40.6 | 0.74 | 18.28 | 929 |
| 3 | 10,248 | 15.975 | 594.3 | 37.2 | 0.64 | 17.24 | 802 |
| 4 | 1,182 | 2.589 | 66.5 | 25.7 | 0.46 | 17.77 | 571 |
| 5 | 4,271 | 5.0 | 146.9 | 29.4 | 0.85 | 29.07 | 1,068 |
Note on Tables 5 and 6: Average unit values should be used with caution as a basis of comparison of prices of commodities subject to large variations over time.
The average refining margin in 2007-08 is estimated by the ACCC to be approximately 4 cents per litre (cpl). An average refinery gate price of diesel of $0.84/L is indicative of a cost of manufacture (COM) somewhere in the range of $0.75/L to $0.80/L. An estimated average cost of imported refined products of $0.74/L in turn indicates that the fuel was imported in 2007-08 at prices at, or below, the cost of its domestic manufacture.
An estimate of the gross margin on exported materials can be made by assigning five sixteenths of the imported refined products cost to the materials obtained to support the export business. On this basis, a gross margin of nominally AUD 0.5 bn is indicated.
In summary:
These inferences may be drawn from the data pertaining to the financial year 2007-08, regarding the gross margin performance of the refining and supply segments of the Australian downstream petroleum supply chain:
- gross margins were tight in both segments;
- the gross margins on imported and domestically produced diesel were roughly equivalent;
- while the exported refined products accounted for less than 10% of the material flowing through the supply segment, these materials are likely to have contributed better than 30% of the gross margin for the segment.
A perspective on the Relative Competitive Position (RCP) of the Australian petroleum industry
The financial performance of the downstream petroleum industry segment in 2008-09 brings into sharp focus the market risks confronting price takers in Asian markets for crude petroleum and refinery products, which are required to meet domestic market demand in excess of that which can be met with limited domestic feedstock availability and installed refining capacity.
High crude oil purchase price volatility, in combination with lower prices of refined products, caused costs to exceed revenues. Foreign exchange losses incurred by the industry amounted to more than $650 million.
Both the historical and the replacement cost of sales accounting bases reflect the steadily increasing competitve pressures exerted on the segment over the period from 2002-03 to 2008-09
Historical cost basis of accounting:
Estimated gross margins of petrol and diesel over the period covering financial years 2002-03 to 2008-09[6] are shown in Figure 4.
Figure 4: Estimated total downstream gross margins of petrol and diesel: 2002-03 to 2008-09
The ACCC estimates that the refining segment of the downstream petroleum supply chain operated at an annual average return (expressed as an ‘adjusted’ EBIT - Earnings Before Interest and Taxes) to sales ratio of just over 4% over the period from 2002-03 to 2008-09. And the segment is estimated to have operated at an annual average return to total asset ratio of just under 14.5%. Both indices of profitability were below that of the chemicals industry, which uses some products from the refining industry.
Replacement cost of sales basis:
Replacement cost of sales operating profit (RCOP) of the Consolidated Group of Caltex Australia over the period from calendar year 2004 to 2009, and the return on invested capital (ROIC) at a company tax rate of 30%, reflect diminshing earning power. The trends are shown in Figure 5.
Figure 5: Caltex Australia’s replacement cost of sales operating profit (RCOP) and return on invested capital (ROIC) over the period from calendar year 2004 to 2009
Solid and gaseous forms of fossil and biologically sourced carbon as chemical energy resources
The solid and gaseous forms of fossil and biologically sourced carbon compete with crude petroleum as chemical energy resources for the production of transportation fuels, and of chemical commodities and material products.
The transformation of coal and gas to liquid fuels (CTL and GTL respectively) is illustrated in Figure 4. It involves a shift in the hydrogen to carbon (H/C) ratio: CTL requires the addition of hydrogen; GTL the removal of hydrogen and/or the addition of carbon.
Figure 4: Conceptual representation of the H/C shift in CTL and GTL transformations
This conceptual representation by John Marano [10] is cited in an April 2009 United States National Energy Technology Laboratory (NETL) presentation[11]. The schematic also applies to biomass to liquids (BTL) transformations.
The initiation of a number of large-scale gas extraction proposals, both conventional and from coal seams, creates opportunities for Australia to exploit the GTL option. And GTL may provide a means of monetization of stranded gas reserves.
The use of low and medium rank coals of suitable quality, existing in abundance in (for example) the Surat, Bowen, Gippsland, Arckaringa, Northern St. Vincent and Collie basins, provides Australia with the opportunity to continue to generate wealth from this valuable resource in the transition to a ‘low carbon’ global economy.
Alternative Fuels
In an engaging and informative article in the November 1978 issue of CHEMTECH, Reuel Shinnar wrote:
“... there are many potential uses in which liquid fuels have a great advantage. Peak power generation, home heating and transportation comprise these uses. There is a unifying feature for these cases: all concern applications which are distributed in time and space in such a way that convenient, transportable, energy-dense non-polluting fuel is needed. Most plans for synthetic fuels are aimed at convenient, storable, high-grade liquids, and it is this direction that long-range development should go. Present fuels of this kind include gasoline, jet fuel, home heating oil, diesel fuel, LPG and SNG, all of which have high hydrogen content. Since coal does not, the problem becomes immediately clear. Furthermore, synthetic fuel technology should be developed in such a way that low-grade coals are mainly used in their production, since they are less suitable for direct burning in large installations."
In June 1981, the Australian Environment Council launched an assessment of new energy resource development. Concurrently, the Commonwealth Department of Home Affairs and Environment commenced an evaluation of the environmental implications of coal liquefaction, shale oil production, and biomass conversion.
These three synthetic liquid fuel technologies were seen to have potential for “wide utilisation in Australia in the medium term”, towards achieving long-term environment protection, “while increasing the effectiveness and efficiency of economic processes.” [12]
Almost thirty years later: a number of coal to liquids projects are currently at early stages of commercial development in Australia; a decision by Queensland Energy Resources Limited (QER) to commit to the construction of an oil shale technology development facility in the Gladstone region, based on the Paraho technology, is pending in the first part of 2010; and, biomass conversion to liquid fuels amounts to approximately 300 Megalitres (ML) per annum of ethanol from three refineries, and approximately 100 ML per annum of biodiesel is produced from four refineries.
It is instructive to examine the penetration of alternative fuels into global markets, from the perspective of the current situation and the anticipated rates of growth of that penetration.
Current Situation Analysis (CSA) of the penetration of alternative fuels into global markets
Global consumption of liquids in transportation, and by households and industry in 2007 amounted to approximately 5,000 GL.
As Table 6 indicates, the three alternative fuels of interest to the Australian Government in the early 1980s have yet to penetrate global markets to any extent.
Table 6: Current nominal global production volumes from three chemical energy resources of interest to the Australian Government in the early 1980s
| Chemical energy resource | Fuel use | Global production (GL) | Year |
| Coal-derived liquids | transportation, households, industry | 10[13] | 2007 |
| Shale oil | all energy commodities | < 1[14] | 2005 |
| Biomass | ethanol | 66[15] | 2008 |
| diesel | 11[15] | 2008 |
Note on Table 6: ‘Energy commodities’ refers to stationary power, heating and transportation fuels, as per the International Energy Agency (IEA) definition.
Similarly, the current contribution of gas-derived liquids to meeting global demand is insignificant. As indicated in Table 7, global gas-to-liquids production capacity in place in 2006 amounted to 84,700 barrels per day (bpd), corresponding to an annual production of approximately 4.6 GL at 90% plant utilization.
Table 7: Capacity of global gas-to-liquids facilities in place in 2006[16]
| Project | Location | Investors | Capacity | Capacity | Start-up |
| (Barrels per day) | (GL per annum) | ||||
| Mossel Bay | South Africa | PetroSA | 36,000 | 1.89 | 1992 |
| Bintulu | Sarawak State | Shell, Petronas, Mitsubishi | 14,700 | 0.77 | 1993 |
| Sasolburg | South Africa | Sasol | 2,500 | 0.13 | 1993 |
| Oryx | Qatar | Qatar Petroleum, Sasol | 34,000 | 1.79 | 2006 |
| TOTAL | 84,700 | 4.58 |
Projections of near-term global alternative fuels production capacity
Growth in liquids production in the United States is seen by the Energy Information Administration (EIA) to follow the trends indicated in Figure 5, under a ‘reference’ set of drivers and impediments.
Figure 5: United States liquids production in thousands of barrels per day from coal, oil shale and biomass, projected by the EIA under a ‘reference’ set of drivers and impediments[17]
Compared with a projection of approximately 0.1 million bpd of US CTL production capacity by 2020, Chinese CTL production capacity is projected to grow to 2.75 million bpd, as shown in Figure 6.
Figure 6: China Coal Information Institute 2009 projection of Chinese CTL production capacity growth[13]
Similarly, shale oil production capacity is likely to grow at a faster pace in China than in the United States.
India appears to be acting as a ‘smart follower’ of China, in the case of both the commercialization of CTL and shale oil production technologies.
The review of biofuel production trends in 21 countries prompts the International Energy Agency’s (IEA’s) Bioenergy Task 39 to project that global bioethanol production capacity will grow to 90 GL per annum by 2012. Global biodiesel production is projected to grow to 20 GL per annum by that year.
When GTL production contributes to the US fuel mix is seen by the EIA to be influenced most strongly by oil price trends; commencement of production in Alaska before 2020 is foreseen under a 'high oil price' case.
If two plants come on-stream as projected, global GTL production capacity in 2011 will amount to 258,700 bpd, corresponding to an annual production capacity of approximately 14 GL.
From the data and information currently available in the public domain, a contribution of alternative fuels to meeting global demand for liquids consumed in transportation, and by households and industry in 2020 of the order of 500 GL per annum – corresponding to approximately 10% of the 2007 consumption levels - may be inferred.
The decision context regarding investment in assets and infrastructure to support large-scale deployment of alternative fuels
In its 2009 Annual Energy Outlook[17], the EIA cites these key drivers of increased rates of penetration of alternative fuels into US markets: changes in the fuel mix towards greater consumption of diesel; technology development; and, rising oil prices.
The EIA notes that growth in the rate of penetration may, on the other hand, be moderated by impedimentts such as: rising capital costs; more stringent environmental constraints governing the freedom-to-operate - with particular reference to water and land use; and, the introduction of Greenhouse Gas (GHG) emission intensity as a performance metric.
Small, open economies generally are confronted with additional impediments in the form of (for example) higher unit capital and operating expenditures (CAPEX and OPEX), and having to be price-takers in domestic and international energy commodity markets.
Developed economies tend also to face difficulties with strategic integration of new investment in assets and infrastructure into existing structures.
The IEA Bioenergy Task 39 notes a shift away from the promotion of growth in production capacity to a focus on economic and ecological sustainability in the formulation of public policy. The setting of carbon reduction targets in establishing the UK government’s Renewable Transport Fuel Obligations, instead of employing production volume targets, is cited as an example. And tighter environmental impact standards and concerns about management of the waste from energy crops drive the deployment of second generation technologies for biofuels production.
These paradigm shifts reflect the desire of the global community to move towards a low carbon economy, and to reduce the environmental impact of human activity, in general.
Decarbonisation of the energy system underlying the global economy is achieved through substitution of existing energy resources with less polluting ones.
The shift from exploiting Australia’s thermal coals as fuels for stationary power generation, to their being used as chemical energy resources for the production of liquid and gaseous transportation fuels, and feedstocks for the manufacture of chemical commodities and material products, acts as an effective hedge against the risks of future loss of trade in the commodity, arising from substitution by natural gas and renewable power sources in existing target markets – on top of substitution by Indonesian thermal coals.
Formulating sound business cases for deployment of indigenous chemical energy resources
Sound business cases for making the investment in assets and infrastructure for the large-scale deployment of indigenous chemical energy resources are difficult to devise.
Participation at world scale is required to achieve a sound Relative Competitive Position (RCP) in domestic and international energy commodity markets.
At the small scale of 14,700 bpd, the investment in the Bintulu Shell Middle Distillate Synthesis (SMDS) facility was likely undertaken in 1993, more with the strategic intent of positioning Shell as a supplier of coal- and gas-to-liquids Science & Technology (S&T) and engineering, than it was to garner high return on assets (ROA).
Small, open economies, and business entities within them, generally face difficulties in assembling and applying the financial and human capital at the rate required to meet metrics associated with making sound business and societal investments.
The current approach to reducing the dependence on importation of crude oil and natural gas liquids and finished petroleum products
The CTL projects currently at early stages of commercial development in Australia have a full potential production capacity by the end of this decade (let us say) of the order of 7 GL per annum. The projected product mix is made up principally by diesel, naptha and dimethyl ether (DME). These are listed in Table 8.
Table 8: CTL projects currently at early stages of development in Australia
| Company | State | Liquids | Capacity (bpd) | Capacity (ML pa) | Stage of project as at Feb 2009 | |
| Linc Energy | SA | Middle distillates + Naphtha | 20,000 | 1056 | Demonstration plant | |
| Syngas Limited | SA | 80% as premium diesel | 16,000 | 845 | Bankable Feasibility Study | |
| Altona Energy plc | SA | mainly diesel | 30,000 | 1584 | JV Agreement | |
| Spitfire Oil Limited | WA | broad product mix | 20,000 | 1056 | Project reappraisal | |
| Ambre Energy Limited | QLD | Dimethyl ether (DME) | 26,000 | 1373 | Environmental Impact Study | |
| New Hope Corporation Limited | QLD | Diesel | 1,500 | 79 | 1 tonne per hour concept unit | |
| Blackham Resources Limited | WA | sulphur-free diesel | 15,000 | 768 | Development MOU | |
| Total | 6761 | |
Linc Energy’s proposal to scale-up to 20,000 barrels per day the production of refined diesel from coal gasified underground appears to be the most advanced; a contract to jointly develop the conceptual design was executed in August 2009. Most importantly, the sale of coal assets can finance the project.
The Clinton Coal-Biomass-to-Liquid (CBTL) project, in South Australia, perhaps offers the greatest promise of achieving a sound balance between environmental protection and economic performance. In late 2009, Syngas Limited engaged Rentech to provide Fischer-Tropsch preliminary engineering services for the production of a nominal 16,000 barrels per day of ‘premium’ clean diesel, employing Indirect Coal Liquefaction (ICL) technology. It is of concern that the company currently has a market capitalisation of the order of only $6 million.
The likelihood that 7 GL per annum of alternative fuels will be contributing to Australia’s transportation fuel security by the end of the decade is low. CTL projects in Australia face high strategic completion risks. The failure of the Monash Energy Project and the ‘Hydrogen Energy’ Joint Venture between BP and Rio Tinto to materialise is testimony to the difficulty in formulating sound business cases for exploiting low rank coals as chemical energy resources in a small, open economy.
Even if the projects currently under development were all to come to fruition, the effect would be that Australia’s alternative fuel production would be at the same competitive disadvantage as that experienced by a downstream petroleum industry, which is comprised of seven refineries, small in scale by Asian standards and distributed around the country, as illustrated in Figure 7.
Figure 7 Map of refineries and Coal to Liquids Projects in Australia
- Refineries 
- Coal to Liquids sites
The unit capital cost of refining capacity in new CTL facilities is likely to be some multiple of that associated with the augmentation of existing petroleum refining assets. The meshing of products supplied from a number of small-scale operations into the existing downstream petroleum supply chain will add complexity, and therefore cost. The large, integrated businesses, currently serving what is a fundamentally competitive domestic market, have little incentive to participate in the development of the small-scale enterprises undertaking to bring forward coal-derived finished fuel products.
A strategic approach to eliminating the importation of petroleum feedstock and finished products
Elimination of imports of crude oil and NGL feedstock and finished petroleum products involves the integration of synthetic hydrocarbon crude, derived from indigenous solid and gaseous fossil resources, into the structure of Australia’s Upstream Oil and Gas industry.
The upstream supply chain would be required to deliver in the order of 25 GL per annum of a synthetic hydrocarbon crude feedstock with a H/C ratio of nominally 1.6, at costs of less than - or equal to - $0.60/litre.
Preliminary Feasibility Assessment of the strategic scale
'Rough cut' estimation of the coal feedstock and hydrogen requirements provide a useful first test of whether 25 GL per annum of domestic synthetic crude production is an appropriate strategic scale.
A thermal coal with the Ultimate Analysis (as received) shown in Table 9 may be represented on a N- and S-free, dry mineral matter-free (dmmf) basis as CH0.65.
Table 9: Ultimate Analysis thermal coal (as received)
| C | 65.93% |
| Available H2 | 3.50% |
| N2 | 1.30% |
| S | 0.00% |
| Combined water | 6.31% |
| Free moisture | 4.38% |
| Ash (as weighed) | 18.58% |
The theoretical feedstock requirement to produce 25 GL of a nominal synthetic crude with the hydrocarbon formula CH1.6 from coal with this analysis is approximately 27 million tonnes per annum.
The shift in H/C ratio from 0.65 to 1.6 requires a theoretical amount of hydrogen of approximately 1.4 million tonnes, corresponding to approximately 15.60 billion cubic metres at Standard Conditions of Temperature and Pressure (STP). (This corresponds to about 3% of the global production in 2004.)
Whether realistic synthetic feedstock costs can be achieved is dependent on the full cost of this hydrogen.
Strategic integration of additional refining capacity to meet total domestic demand
On the other hand, the financial productivity of the refining assets is high. Over the period from 2002-03 to 2008-09, the asset turnover ratio - the ratio of sales to assets - was approximately 3.5, compared with a Chemicals industry ratio over the same period of approximately 1.1.
New funding required to put in place the additional refining capacity to meet total domestic demand would amount to approximately $3 billion, with the existing degree of asset productivity (refer to Figure 8). The existing investment in other assets along the downstream petroleum supply chain would not need to be augmented.
Figure 8: Increase in refining asset investment to meet Australia's current importation of finished product.
Augmentation of the domestic crude petroleum feedstock supply chain system with one delivering a synthetic hydrocarbon crude, coupled with expansion of existing petroleum refining capacity to meet total domestic demand and support export opportunities, may therefore be the appropriate tactics to deploy, in order to ensure Australia’s long-term transportation fuel security.
Export opportunities for Australian synthetic hydrocarbon crude and consequent impact on scale and costs should also be considered.
References
- ↑ The environmental implications of three synthetic liquid fuel technologies: coal liquefaction, shale oil production and biomass conversion: Parliamentary Paper No. 343
- ↑ Fill 'er up...on shale oil?
- ↑ 3.0 3.1 3.2 State of the industry 2009: A status report on Platform for Prosperity - a strategy for maximising the value of Australia's oil and gas resources
- ↑ 4.0 4.1 4.2 ABARE Mineral Statistics, Table L
- ↑ 5.0 5.1 ABARE Australian Energy Statistics
- ↑ 6.0 6.1 6.2 Monitoring of the Australian petroleum industry
- ↑ Composition of trade Australia 2008-09pg 40
- ↑ Australian Institute of Petroleum: Terminal Gate Prices (Wholesale)
- ↑ Australian Institute of Petroleum: Weekly Petrol Prices Report
- ↑ Marano, J J, Overview of Coal to Liquids 2006 Presented to NETL
- ↑ Direct Coal Liquefaction Overview: Presented to NETL
- ↑ The environmental implications of three synthetic liquid fuel technologies: coal liquefaction, shale oil production and biomass conversion: Parliamentary Paper No. 343
- ↑ 13.0 13.1 CTL and Lignite based CTL
- ↑ Survey of energy resourcespg 96
- ↑ 15.0 15.1 IEA Task 39 'Update on Implementation Agendas 2009: A review of key biofuel producing countries’, 2009
- ↑ World Petroleum Councilslide 8
- ↑ 17.0 17.1 Energy Information Administration: Annual Energy Outlook 2009: Extract - synthetic fuels pg 80
| DecisionSituation | How can Australia's fuel security be ensured by domestic production of synthetic hydrocarbons? + |
