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Submission to the Review of Business Taxation
A Platform for Consultation - Discussion Paper No.2
Australian Petroleum Production & Exploration Association Ltd
Taxation & Industry Decision-Making
The Significance of the Petroleum Exploration & Production Industry
1. The Australian Petroleum Exploration and Production Industry
Australian Oil & Gas Production
Australian crude oil, condensate and LPG production averaged 620 thousand barrels per day (or 227 million barrels pa) in 1998. Gas production in 1998 was 997 billion cubic feet (bcf), up from 756 bcf in 1992. The Bureau of Resource Sciences has forecast a relatively optimistic production profile for liquids production over the next two to three years, however the prospects after this are less certain.
In the absence of new discoveries and future investment, Australias self sufficiency in petroleum liquids is expected to fall from around 75 per cent in 1998 to less than 50 per cent by the year 2005. Assuming an oil price of around $A25 per barrel, this implies a potential net import bill for crude oil and condensate of $4 billion per annum by the year 2005.
The Australian Bureau of Agricultural and Resource Economics (ABARE) estimates that natural gas production will grow by up to 5.5 per cent per annum until the end of the next decade. A large portion of this is associated with growth in south-east Australia. Assuming investment funds are available, this will meet both domestic demand and export opportunities. Domestic natural gas production also has the potential to replace coal for domestic power generation with associated greenhouse benefits.
Liquefied natural gas (LNG) has created an opportunity for Australia to market its substantial reserves of natural gas. Exports commenced from the North West Shelf project in 1989. Additional opportunities exist in terms of a number of potentially large new projects in the north-west region of Australia.
Petroleum exploration activity in Australia has fluctuated considerably over the last three decades. Exploration (and production) is affected by a range of factors, including access to acreage, prospectivity, prices, rig and seismic mobilisation costs, geographic location, perceptions of risk/rewards (eg potential field sizes), international competition for funds and the fiscal regime (including income, resource and indirect taxes).
In Australia, the above chart illustrates that the first 300 New Field Wildcat (NFW) wells discovered 80% of Australia's total offshore reserves; over 400 more NFW wells drilled since 1982 have only managed to add the remaining 20% of known reserves of gas and liquids.
The vast majority of reserves discovered since the 1960s have been gas which now accounts for over 60% of the total amount. While reserves coverage of ABARE's forecast production to 2010 appears comfortable on a total basis, the liquids position is rather more uncertain given the lower rate of discoveries of liquids.
While further discoveries are likely and have recently occurred in the Timor Gap, discoveries of the scale of those in the Gippsland Basin in the 1960s (whose original liquids reserves account for over half of total liquids discovered) and those in the Carnarvon Basin in the 1970s are not guaranteed.
The Economic Significance of the Industry
The petroleum exploration and production industry is crucial to Australias economic welfare. It provides the nation with a reliable and competitively priced source of energy which meets 53 per cent of Australias energy needs.
Its direct economic contributions include the following:
While the above contributions reflect direct benefits to the economy, it is important to recognise that companies that operate within the industry provide capital, infrastructure, expertise, technology diffusion and often facilitate the capturing of export market opportunities for related industries. It also supports a significant services sector. A strong and expanding industry will continue to make a significant long term contribution towards the Federal Governments economic growth targets.
A range of project specific benefits to the economy are outlined in section 2.
Federal Government Resources Policy
The Prime Minister and Minister for Resources and Energy released the Federal Governments Resources Policy Statement in February 1998. The Government recognised and highlighted the importance of this sector to the economy. The following observation was made about the sectors potential contribution:
The Governments vision for the industry seeks an outcome that "..offers high levels of certainty to all stakeholders..", "..provides a highly competitive operating environment..", "..supports the industrys efforts to achieve sustained wealth generation..", and "..allows the industry to respond confidently to international challenges and seize international trade and investment opportunities." This vision is fully supported by APPEA.
From a taxation perspective, settings must recognise the framework within which industry operates. Specifically, high risk exploration expenditure, long term investments and high capital intensity characterise investments in the industry. Taxation must be responsive to these features.
The Federal Government is a cosignatory to The National Greenhouse Strategy. Part of the strategy covers the area of gas reform. Specifically, it is noted that:
The potential benefits associated with a growing gas sector from a greenhouse perspective are likely to be significant. In terms of electricity generation, the following table outlines the CO2 emissions per unit of produced energy.
Source : Australian Methodology for the Estimation of Greenhouse Gas Emissions and Sinks National Greenhouse Gas Inventory Committee (1994)
Policy settings should be directed towards ensuring that there are no distortions that would act to discourage investment in the gas industry. Only when this occurs can the full greenhouse benefits of natural gas be achieved.
One of the stated objectives of the Review of Business Taxation is that the taxation system should be neutral in its treatment of investment. While this objective may be desirable on an in-principle basis, it has the potential to create distortions based on current economic settings.
For example, the Industry Commission estimates that for 1996/97, total Federal budgetary assistance to industry was $3,390 million, which was allocated as follows:
Based on this data, the mining sector already receives the lowest rate of overall assistance. Changes to the taxation provisions that may disadvantage mining relative to other sectors of the economy may compound existing distortions.
2. The Impact of Taxation and General Principles
Taxation and Project Decision-Making
The petroleum exploration and production industry is confronted with multiple layers of taxes which are applied at both the federal and state levels, some of which are unique to the industry.
Overall, APPEA estimates that taxation, in one form or another, accounts for 36 per cent of total costs faced by the petroleum exploration and production industry. This equated to $A8.26 per barrel of oil equivalent production in 1997/98, which compares with an average price of petroleum during the same period of $A24.77. APPEA considers this is high relative to other sectors of the Australian economy. It is therefore essential from the petroleum industrys perspective that the Australian taxation framework be internationally competitive and that these costs are reduced.
At a time when the industry is becoming increasingly globalised, the flow of risk capital and investment funds responds to the overall risk/reward balances within individual countries. In addition, fiscal stability is also essential for large scale long-term investment projects.
Local and foreign based investors have significant roles to play in the growth of Australias petroleum exploration and production industry. In this context, the tax system must respond to the differing characteristics of local and foreign based companies.
Three broad layers of taxation confront investors in Australias oil and gas industry, namely income tax, resource taxes and indirect taxation (including tariffs). In terms of their relative importance, APPEAs Financial Survey data indicates the following weighting of significance (over a five year sample period):
In terms of the impact of taxation on industry profitability, resource and income taxes accounted for 63.3 per cent of pre-tax profit, the highest level recorded since 1991/92.
The Impact of Taxation on Investment Decisions
At a meeting of the Focus Group in respect of Wasting Assets that was held on 16 March 1999 in Canberra, representatives of the Review of Business Taxation suggested that the analysis of investment decisions should be undertaken on a pre-tax basis. In APPEAs experience, this is not the current practice of the majority of its members. Such an approach represents a fundamental misunderstanding of the importance of taxation in establishing the commercial viability of projects, in valuing projects and in establishing the international competitiveness and risk/reward profile of projects.
The analysis of investment decisions is generally conducted using discounted (real value) after tax cash flows. The timing and magnitude of cash flows resulting from tax is critical to the analysis and investment decision. The use of a pre-tax discount rate, adjusted to take into account the rate of tax, is not an accurate substitute for the impact of the timing of deductions on cash flows and project value.
If project analysis is done on a pre tax basis there would be no argument about the merits of an accelerated depreciation regime versus an effective life depreciation regime. These differences are only reflected in an after tax analysis. The fact that such an argument arises is evidence of the use of after tax analysis.
By way of example, after tax cash flows are important in the following scenarios.
The adoption of an entity approach to taxation that removed the bias of particular investment vehicles will still require the analysis on an after tax basis to reflect the timing of tax deductions.
Taxation Framework The Need to Correct Distortions
The taxation system, whether it be income, resource or indirect taxation, plays a fundamental role in shaping the framework within which investment decisions are made in the petroleum exploration and production industry. It also influences Australias ability to compete for limited international funds.
It is important from the outset that a clear distinction is made between tax concessions and the special taxation provisions which ameliorate or correct economic distortions which would otherwise be present. The accelerated depreciation provisions are an example of this corrective action. Specifically, the movement towards differential provisions in the tax laws in many cases are designed to address non-neutral outcomes that would arise if such provisions did not apply.
A bias is already inherent in the current system in that the net present value of costs which can be expensed (eg operating costs), is greater than the net present value of plant and equipment costs which are often depreciated at historical cost. The result is that a dollar spent on operating costs is more tax effective than a dollar spent on capital. This treatment favours industries which are non-capital intensive. The current regime attempts to mitigate against this bias by allowing accelerated depreciation rates above the rate that would otherwise apply based on the assets effective life.
Without these provisions, distortions in the ranking of investments between alternative uses for funds would be considerably increased. From the petroleum exploration and production industrys perspective, this could adversely impact on the overall exploration and production effort and hence on Australias energy self sufficiency and balance of payments.
Economic distortions still exist under the current provisions. The inability under some circumstances to claim deductions until equipment is ready for use is an example. The lead times between investment expenditure and when equipment is installed ready for use for some large long term and Greenfields resource projects (which can be up to five years) can disadvantage such projects when compared with other investments due to the timing of tax payments.
The Treatment of Exploration Expenditures
APPEA strongly supports the immediate 100 per cent write-off of exploration expenditure. This is a vital component for maximising Australias exploration effort, particularly in an environment of low real oil prices and diminishing domestic reserves of petroleum liquids.
The nature of a number of the activities in the petroleum exploration and production industry differentiate it from many other sectors of the business community. One of the most unique elements is the need to identify a resource (or input) base, which is largely achieved through exploration. There are no direct comparisons between this category and those in other sectors of the economy.
Exploration arguably represents the most fundamental activity undertaken in the resource sector. In effect, it precedes all subsequent development and/or production decisions undertaken by an investor. It is important to recognise however that while a commercial discovery can be made, the ownership of the resource generally remains with the Crown. Therefore such expenditures, while a fundamental component of petroleum operations, do not create a physical asset.
Another unique feature of exploration activity is the creation of a public good. This effectively occurs on two levels. First, and unlike many other forms of activity, investors engaged in petroleum exploration operations are required to publicly release the data they collect. This is provided for under the terms of the respective federal and state/territory petroleum legislation. In addition, the provision of a reliable supply of oil and gas also represents a significant benefit to the on-going operation of the regional, state and national economies. Furthermore, such activities generally lead to the payment of considerable levels of resource taxation.
It is important to recognise that the discovery of hydrocarbons in itself does not mean commercial success. Many instances exist in Australia where oil and/or gas resources have been identified, but still remain undeveloped many years after their initial discovery. This is certainly the case for many gas reserves, where development opportunities may be constrained due to market, technical and/or economic factors.
The existing treatment whereby costs associated with exploration activity are immediately deductible for tax purposes is entirely appropriate and indeed essential if such an activity is to be maintained. It recognises the current policies of governments in Australia to encourage exploration and to acknowledge the risk of such activities.
A direct consequence of any change to the current arrangements would be to reduce the overall exploration effort (due to an effective reduction in the level of exploration budgets). There is likely to be a greater impact in frontier and greenfields regions where Australias largest discoveries can be expected to be made.
Support for the existing tax treatment of exploration costs has been extensive over the last two decades. In particular, the Industry Commission and its predecessors have strongly endorsed the continuation of the present provisions. Exploration costs are critical to the sector and any outcome other than immediate and full deductibility would be inequitable and distortionary.
In general, overseas jurisdictions provide treatments that have a similar overall impact, while the specific details can vary.
In summary, any change to the existing treatment would create a highly distortionary disincentive to risk-taking which would ultimately reduce the overall petroleum exploration effort in Australia.
The Special Nature of Gas Projects
Investments in gas projects are fundamentally different to investments in virtually any other type of business enterprise. Gas projects are often characterised by substantial time lags between discovery and commercialisation of the resource. In the case of Australia, reserves are also often located in geographically remote locations, with long distances to markets.
In addition to the above factors, gas projects often involve the expenditure of vast sums of capital over long periods, with considerable outlays prior to the commencement of initial production not being uncommon. This is particularly the case for LNG developments. Another factor that differentiates this type of project from many others is that the pay-back period for an investor to achieve a positive economic return is often quite lengthy, often in the order of 10 to 20 years.
From an economy wide perspective, such projects generate massive benefits for the economy. A summary of the potential benefits associated with an expansion of the North West Shelf LNG project is outlined in Section 4.
As a result of the characteristics of such projects (high capital expenditures, competitive prices and long pay-back periods), project viability is very sensitive to a number of key parameters, including the timing and nature of taxation. Because such projects can have lives that are in excess of 20 years, the ability to depreciate the capital cost over a shorter period for income tax purposes fundamentally influences project economics.
It is suggested in A Platform for Consultation Discussion Paper No.2, that provisions that allow for the accelerated write-off of capital costs represents some form of interest free loan to an investor. The truth of the matter however is that accelerated depreciation is offered to ameliorate the imbalance due to revenue being assessed in real terms (ie as it is derived), whilst capital deductions (through depreciation) are only obtained in nominal terms over the (often lengthy) life of the plant. The failure to treat both revenue and capital deductions on real terms represents a transfer of economic rent to the Government. Ultimately, it is essential that tax provisions do not distort an investors choice between assets used to produce income.
The negative impact of Australias company tax system on the economics of gas projects was demonstrated in a Petroleum Resource Rent Tax study that was prepared for the Department of Primary Industries and Energy by Aberdeen University Petroleum and Economic Consultants (AUPEC).
Specifically, the AUPEC study concluded that the Australian company taxation system introduced a significant element of regressiveness which leads to gas projects becoming less profitable due to the depreciation provisions. Indeed, under a range of representative scenarios, the net present value of company tax collections exceeded the entire pre-tax net present value of the project. In effect, the company tax system (even through the application of relatively low discount rates) can extract the entire economic rent from a gas project.
The study highlighted that even under a relatively modest set of development cost assumptions, the Australian company tax regime is uncompetitive with a range of other gas producing countries.
The following extract from the AUPEC report highlights the difficulty that the corporate tax system can cause to petroleum projects in Australia:
The Benefits of GST for the Petroleum Exploration and Production Industry
The Federal Governments paper Tax Reform: not a new tax, a new tax system (ANTS) suggested that the proposed introduction of a goods and service tax (GST) will favourably impact on the cost base of operations in the petroleum exploration and production industry on two levels. In APPEAs view, this is unlikely to be the case.
On the first level, and assuming that the GST does not impose an additional taxation burden on the industry, there is expected to be at best a very marginal reduction in the level of indirect taxation. Petroleum exploration and production activities are generally exempt from sales tax but pay high tariffs. As the relative share of indirect taxes is small (around 5% of the total value of tax payments), and recognising that the high cost indirect taxes that are incurred by the industry are to remain in place following the introduction of GST (ie tariffs), this first level of benefits is therefore expected to be very modest.
It also needs to be recognised that the nature of activities carried-out in the petroleum exploration and production operations are generally not transport fuel intensive (particularly when compared with the mainstream mining sector). The removal of diesel fuel excise, while potentially providing some avenue for cost reduction to the industry, again will only provide a relatively marginal benefit.
The second level of benefit associated with the introduction of a GST involves a possible reduction in the cost of business inputs as a result of a flow-through of lower taxes on supply activities. While it is recognised that some level of benefit may exist, the nature of activities in the industry may again dampen the overall impact. This is particularly the case due to the source of many of the inputs used in the industry, which are obtained from overseas supply points. In addition, the price of many inputs is supply and demand driven, rather than being tied to cost factors.
The full benefits associated with a reduction of business input costs can only be fully achieved for the petroleum exploration and production industry if there is a corresponding reduction in the level of customs and excise duties that currently apply to goods and services.
APPEAs judgement is also supported by the Department of Industry, Science and Resources in advice received in relation to the impact of the GST. In assessing the cost effects of the introduction of a GST, it was estimated in ANTS that the estimated savings to the coal, oil and gas sectors would average 4.7 per cent. In comparing the oil and gas sector benefit when compared with the coal industry, APPEA was advised that "..the upstream petroleum sector contribution to the figure (ie the net gain) is not as large as that of the coal industry where transport is likely to be a more significant component of costs."
In summary, APPEA would be concerned if it was assumed that the losses that may result from changes to the company tax system are to be somehow offset by savings that are thought to accrue from the introduction of a GST. Indeed, APPEAs examination of the GST legislation that is currently before Parliament suggests that unless some clarity is provided to a number of key elements of the package, there may be adverse impacts on the industry.
In the context of any consideration of the taxation system, it is generally agreed that a set of principles should be established to evaluate the appropriateness of individual provisions. APPEA considers that the following criteria should be used:
Efficiency -The distortionary impact of taxes, or the likelihood that taxes may influence or alter the ranking of investment decisions should be minimised.
International Competitiveness The mobility of international investment funds dictates that tax settings should not act to discourage investing in Australia.
Equity - Those in relatively similar economic positions should be treated equally, while those in different circumstances should be treated in proportion with their ability to pay.
Administrative Simplicity -The cost of complying with, or collecting taxes, should be minimised. A tax system should also be as simple as possible.
Stability A stable taxation framework is particularly important for long term projects.
It is inevitable that by its very nature, the tax mix that is adopted across the various levels of government will lead to outcomes that conflict with the above principles. It is therefore important that outcomes are sought that attempt to minimise the breaching of the above criteria.
3. A Platform for Consultation APPEA Comments
There are many issues raised in A Platform for Consultation : Discussion Paper 2, that have potential to materially impact on companies with activities in Australias petroleum exploration and production industry. The comments which follow are, in general, limited to discussing issues that specifically impact on the industrys operations. Nonetheless, APPEA strongly recommends that careful consideration be given to the overall impact of changes, particularly where such changes and/or modifications may impact on the commercial framework that confronts the business community.
Company tax the goal of achieving a 30 per cent tax rate
The stated goal of the Federal Government of moving towards a 30 per cent rate of company tax will aid the competitiveness of the Australian economy and is generally supported by APPEA. For the economy wide benefits of such a rate to be maximised, it is essential that the Government also creates a taxation framework that encourages investments in a diverse range of activities. In meeting this objective, it is important that the tax system should not act to bias investments towards certain types of economic activities. In this context, the need to ensure that the taxation system gives appropriate treatment to the nature of long term capital assets (which in themselves provide significant economy-wide benefits) should be accorded a high priority. This is a critical aspect of this submission and is discussed in further detail in Section 4.
Who should be entitled to deductions? (p.83)
The discussion paper notes that "..the ownership basis for depreciation and other capital allowances has created difficulties and commercial uncertainties". This can be the case for companies in the petroleum exploration and production industry. Situations exist where technically, no tax deduction is available for expenditure incurred on items of plant pursuant to the depreciation provisions because they are owned by another joint venture. In addition, the item may also be located outside the prescribed petroleum operations thereby falling outside the scope of the allowable capital expenditure provisions in Section 330-80 on the Act (ie blackhole expenditure). Within the petroleum industry, there are also certain joint ventures which have entered into unitisation agreements which have complex redetermination clauses to overcome problems where assets are jointly paid for but legally owned by each individual joint venture.
APPEA would welcome a change to the current depreciation provisions particularly if it was in accordance with Option 1 that provides for the person who incurs the expenditure on the asset to claim the deduction.
How should the period of write-off be assessed? (p.91)
APPEA supports the retention of the current system that allows taxpayers to self-assess, or to select an appropriate effective life from the Commissioner's schedule. The flexibility this system provides is important to the upstream petroleum industry, where the effective life of assets is generally tied to the life of the relevant petroleum field.
This makes it impractical for the Commissioner's schedule to be able adequately to deal with the effective life of assets used in petroleum production. If Option 2 were adopted industry participants would be constantly seeking variations to the schedule where the life of the relevant field is less than that provided for in the schedule.
Should special rules apply to the resources sector? (p.95)
A discussion on the need for the taxation provisions to remain sensitive to the depreciation of long life capital assets in the petroleum exploration and production industry is outlined in Section 4.
Balancing charge offset (p.99)
Section 42-30 requires a balancing adjustment to be calculated for a unit of depreciable plant if it is lost or destroyed. Sections 42-190 and 42-195 provide for assessable or deductible balancing adjustments where the "Termination value" exceeds or is less than the written down value of the plant respectively. Section 42-205 defines "termination value" in the case of plant lost or destroyed to be the amount or value received or receivable under an insurance policy or otherwise for the loss or destruction.
Where an insurance recovery exceeds the tax written down value, the excess is assessable to the extent of previously claimed deductions. If the insurance recovery exceeds the original cost, the excess over cost will be subject to the ordinary CGT provisions.
Sections 42-285 and 42-290 allow taxpayers to effectively defer any assessable balancing charge by reducing the cost, or written down value of replacement or other plant by the otherwise assessable balancing charge.
APPEA firmly believes that these provisions should be maintained in the event of involuntary disposals. To highlight the importance of this issue, we can look at the hypothetical situation of the total loss of an offshore facility. Under the current provisions, if the proceeds received are greater than the tax written down value, any such excess can, at the taxpayers election, be offset against the cost of the replacement facility. If the provisions allowing this election were removed, up to 36 per cent of the proceeds above the tax written down value of the facility would have to be paid in tax, potentially leaving insufficient funds to rebuild the offshore facility. This situation would be clearly unacceptable.
APPEA recommends that the balance charge provisions be maintained in the event of involuntary disposals.
How should blackhole expenditures be treated? (p.100)
APPEA generally supports the proposal to eliminate blackhole expenditure, however we do have some specific comments. In relation to the proposals for demolition and removal costs, we note that not always will the party paying for the demolition work be the owner of the land. This would suggest that demolition and removal costs should be treated as part of the cost of the new plant rather than being included in the cost base of the land. In the upstream petroleum industry, for example, plant is often constructed on leased property, meaning that the only way for the taxpayer to get the tax benefit of the costs is for them to be included in the cost of the new plant.
We also agree that there should be some loss carry back for closure costs. An upstream petroleum project, particularly if it is offshore, faces extensive closure costs (many of which relate to the protection of the environment) which in many cases may give rise to worthless tax deductions. A carry back against income from earlier years would help to alleviate this problem, and would also be consistent with the treatment for Petroleum Resource Rent Tax.
Excess deductions (p.111)
In Chapter 1, Appendix D, of A Platform for Consultation considers the issue of "excess deductions". This is expenditure that can be carried forward where a taxpayer incurs losses, unless otherwise elected. It is submitted that, in the absence of the purchasers of mining rights and information being entitled to write-off the full purchase price, the excess deduction rules should not be changed.
The rules do contain safeguarding measures. Deductions for exploration expenditure under section 330-10 of the Income Tax Assessment Act 1997 ("the Act") are not available unless the taxpayer continues to satisfy the deductibility tests set out in sub-section 330-15(2) of the Act.
Deductions for allowable capital expenditure in respect of a petroleum field are only available so long as prescribed petroleum operations are being conducted in respect of the field on which the deductions were incurred or transferred to under a section 330-235 agreement. The transfer of expenditure under section 330-235 of the Act also provide restrictions.
Sale of exploration results (p.113)
Paragraph D.13 states that "the current treatment of expenditure on, and income from exploitation of minerals, exploration and prospecting can be asymmetrical". The paragraph then goes on to note that whilst exploration and prospecting expenditure is immediately deductible, receipts from the sale of such expenditure are often not taxable. This statement is in accordance with the views expressed in Taxation Ruling 98/3. What is not noted in paragraph D.13 is that the purchaser of the information may not obtain any tax benefit from the cost of acquiring it. Further, there are significant concerns over the tax treatment of farm-outs and disposals of exploration and prospecting information following from the comments in TR 98/3.
Any amendments to the legislation dealing with the disposal of exploration or prospecting information must be symmetrical not just for the vendor but also between the vendor and purchaser of the information.
Consolidation by non-residents (p.545)
Paragraph 26.3 states that "groups choosing to enter a consolidation regime would be required to have a resident holding company at the head of the group in order to give practical meaning to the concept of a single Australian taxpayer". No justification or explanation is provided for the adoption of such a narrow eligibility requirement.
Many foreign owned companies in the industry have more than one resident holding company but are still part of a 100 per cent commonly owned group with an overseas parent. Under current legislation, tax loss transfers and rollovers can be made between all resident group companies. To move to a common Australian holding company could result in substantial tax costs in other jurisdictions as well as stamp duty costs in Australia. The alternative will be stand alone taxation in Australia for each Australian holding company or sub-group which could result in significant Australian tax costs for the foreign owned group.
A preferred alternative would be to allow consolidation by reference to a common resident or non-resident entity.
Same Business Test
Chapter 28 of the Discussion Paper raises a number or proposals to prevent the perceived problem of loss duplication. One of the suggestions is the removal of the same business test. APPEA strongly supports retention of the same business test.
In the petroleum exploration business it is not uncommon for a special purpose company ("Exco") to be established to undertake exploration in a particular area. If the exploration is successful Exco may be sold to a company that is prepared to undertake the development work necessary to produce petroleum from the discovery. In situations like this Exco, although being of significant value (based on the potential of the discovery), will still be in a tax loss situation because at the time of transfer no income would have been derived.
If the same business test were removed, the transferor(s) of Exco would be subject to capital gains tax on any gain from the sale of Exco, but the transferee(s) would be precluded from obtaining the benefit of the losses that have been legitimately incurred by Exco. In this situation, the removal of the same business test would not prevent the duplication of losses. Rather it would prevent legitimate costs from being deducted against income derived from the subsequent petroleum development. This could act as a significant deterrent for future petroleum exploration.
Taxation of Entities Treatment of Entity Distributions
A number of elements of the proposal to change the existing provisions are of concern to APPEA. The deferred company tax proposal in effect brings forward the taxation point to the extent that it must be fully borne by the company, rather than the shareholder. The direct consequence of this is a potential reduction in after tax profit at the company level. This proposal is not supported by APPEA.
Also at the company level, there will be a change in the nature of tax preferred income tax that is currently distributed. Specifically, the full level of taxation, which at the present time can be shared between the company and shareholder, must be paid at the company level. The flexibility of determining where (as opposed to the amount) the tax must be borne is lost. For a company, this will potentially impact on the after-tax ranking of individual projects as well as the overall competitiveness of some categories of companies.
4. Taxation Settings and Long Term Capital Investments in the Petroleum Exploration and Production Industry
This section of the submission argues the case for maintaining the current depreciation schedules (or similar value enhancing measures) for long life petroleum projects whilst moving to a company tax rate of 30%. The increased level of investment attracted by maintaining accelerated depreciation in a low tax environment will generate superior community benefits to an outcome that simply acts to trade-off accelerated depreciation against a lower company tax rate.
The total benefits flowing to the Australian community from the go-ahead of large petroleum projects include employment growth, stimulation of service industries, additional tax and royalty payments, the generation of substantial export income, the import replacement of external energy sources and greenhouse advantages. The results of a case study, based on a typical large scale LNG project, are presented below. The enormous benefits flowing to the community highlight the importance for such projects to be encouraged.
Details of international competitiveness for the LNG industry show that Australia's depreciation regime in relation to LNG type projects is already uncompetitive with those applying to our competitors. Such activities and their benefits may well be lost to Australia if the projects cannot offer attractive after-tax rates of return to international investment capital.
Some $190 billion of resource sector mining and processing projects are proposed in the period 2001 - 2011 according to information complied by Access Economics. The impact of depreciation rate changes on hypothetical projects and how changes to depreciation rates may impact on project viability is also outlined below. APPEA contends that there is a strong case for maintaining accelerated depreciation for long term petroleum projects while at the same time moving towards a lower company tax rate.
Indeed, the diminution of income tax streams as a result of maintaining accelerated depreciation for such projects in a low tax environment are likely to be more than offset by the additional revenues (both income and resource taxes) flowing from projects otherwise rendered uneconomic by a simple depreciation/tax rate trade-off.
North West Shelf Expansion Project A Case Study of Economic and Fiscal Impacts
This section draws on results contained in a report prepared by Access Economics produced in October 1997 for Woodside Energy Ltd. The assumptions in the report reflected the then current conditions of market demand and energy prices, which have now changed. Nonetheless, the analysis still reflects the benefits of a large-scale long life petroleum project, albeit that the profitability to the proponents is lower than implicit in the case study. Community benefits will naturally be delayed to the extent that the project timetable slips beyond that envisaged in the report.
Base assumptions in the analysis are the construction of a two LNG train export facility on the Burrup Peninsula in north-west Australia with some $6.5 billion of capital (1998 prices) being expended over the period from present to 2007. Capital is supplied largely (some 75%) by foreign investors and (for the purposes of conservatively modelling the community benefits) is assumed to be 100% debt financed. Additional revenues associated with 7 million tonnes p.a. LNG export are some $2 billion p.a.
Key economic results:
The report also makes the following points:
A key measure of project viability is the after-tax rate of return expected by project owners. This is strongly influenced by both the company tax rate and the rules governing depreciation of capital. Depreciation rules are especially important for capital intensive long-life activities such as LNG and long life domestic gas projects.
As an example, the chart below provides a simple comparison between company tax rates and depreciation write-off periods applying to LNG projects currently operating or planned for development. It shows the relative competitive position of Australia against overseas LNG projects able to compete in markets accessible to Australian LNG. It is recognised that this is one of a number of factors that must be used in determining the relative competitiveness of projects.
The chart shows that most competitors to Australian LNG enjoy low effective company tax rates and are allowed to depreciate capital over a 4 - 5 year period. In each competitor country, accelerated depreciation is recognised as an important provision to improve the viability of long-life capital intensive projects such as LNG. While Alaska is in the process of renegotiating applicable depreciation schedules for LNG (from 8 year to 5 year write-off), Australia is in danger of further disadvantaging its competitive position by changing the accelerated depreciation provisions for long term assets.
The tax rate in the above chart is averaged over project life to account for tax holidays of up to 10 years offered in some jurisdictions.
Impact of Effective Life Depreciation on a Marginal Gas Project
Two measures of project profitability are routinely used to gauge the viability of long-life projects; net present value (at the investor's hurdle rate) and internal rate of return. Both measures are calculated on the after-tax cash flows from a project, before financing costs. The hurdle rate is necessarily higher than the investor's weighted cost of capital to account for unquantified risk, and to some extent is dependent on prevailing market conditions and the scarcity of capital.
With investor weighted cost of capital in the range of 8 - 10% real, a hurdle rate of 10% real is generally used as a minimum hurdle rate for LNG projects. LNG projects expected to return less than this hurdle rate are unlikely to be supported.
An analysis conducted by Woodside Energy shows that marginal LNG projects (IRR close to 10% real) are adversely impacted by a loss of accelerated depreciation and that a company tax rate of 30% does not fully compensate for the reduction in NPV. In other words, a loss of accelerated depreciation, even with a lower company tax rate, would tend to discourage investment in long-life marginal projects such as LNG by reducing the investment returns earned from those projects. It is expected that similar conclusions could be drawn for long term domestic gas projects.
The chart below shows how NPV at a 10% real discount rate is reduced by the order of $100mand rate of return reduced by some 0.25% by moving from current tax arrangements to a 30% tax rate combined with an assumed20 year effective life for depreciation.
Viability of Marginal Projects Potential Economy Wide Implications
It is estimated that some $190 billion of mining and resource-processing investment is forecast for the period 2001 - 2011. Some of this pool of investment will represent marginal projects, which may not proceed if overall taxation conditions change from those currently available.
Applying a simple revenue-neutral trade-off of the tax rate with effective life depreciation could put significant levels of Government revenue at risk. Conversely, by maintaining existing depreciation rates for long life petroleum projects in a lower tax environment could realistically create additional government revenue NPV of tens of billions of dollars.
The balance of trade implications of large scale investment projects needs careful consideration. With Australia's current account deficit heading towards record highs, it is important to consider the implications of discouraging trade enhancing investments through adverse changes to the taxation provisions.
Other things being equal, an unsustainably high current account deficit reduces national wealth by lowering the exchange rate, putting upward pressure on interest rates thereby dampening economic growth. These threats to economic welfare can be reduced by appropriate policy settings which encourage export industry, namely a lower company tax rate whilst maintaining accelerated depreciation for a limited range of activities.
APPEA recommends that the competitiveness of Australias taxation system could be best improved by both lowering the company tax rate to 30% whilst maintaining the current depreciation schedules (or similar value enhancing measures) for long-life projects. The increased level of petroleum sector investment attracted by maintaining a responsive depreciation regime in a lower tax environment will generate a win-win outcome for the economy and investors.