evaluation of the petroleum tax and licensing regime of new zealand

Evaluation of the Petroleum Tax and Licensing Regime of New Zealand Final Report to the Ministry of Economic Development July 2009

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Final Report – July 2009

STRICTLY CONFIDENTIAL

Contents

Executive Summary ................................................................................................. 5 1.0 Introduction ................................................................................................. 10 2.0 Evaluation of New Zealand‘s Permitting and Regulatory Framework for Exploration and Production of Petroleum Resources ............................................ 11

2.1 Approach in this Review ............................................................................... 11

2.2 The Policy Framework and Objectives ......................................................... 11 2.3 Land Available for Petroleum Permits .......................................................... 12 2.4 The Permitting Regime ................................................................................ 12 2.5 Allocation by Cash Bonus Bidding ............................................................... 12 2.6 Allocation of Prospecting Permits ................................................................ 13

2.7 Allocation of Petroleum Exploration Permits ................................................ 13

2.8 Priority in Time Applications ......................................................................... 14 2.9 Changes to Exploration Permits ................................................................... 14

2.10 Allocation of Mining Permits ....................................................................... 15

2.11 Good Mining Practice ................................................................................. 16 2.12 The Royalty Regime ................................................................................... 16

2.13 Need for Regulations on Decommissioning ............................................... 17 3.0 Evaluation of New Zealand‘s Petroleum Tax Regime ................................. 19

3.1 Approach and Methodology ......................................................................... 19 3.1.1 Characteristics of an Optimal Fiscal System .................................................... 19

3.2 Description of New Zealand‘s Fiscal Regime ............................................... 21 3.3 Production and Cost Assumptions ............................................................... 23

3.3.1 Offshore Great South Basin (GSB) - Oil ...................................................... 24 3.3.2 Offshore Great South Basin - Gas ............................................................... 25

3.4 Price Assumptions ....................................................................................... 27

4.0 Results of Evaluation of New Zealand Petroleum Tax Regime ................... 29 4.1 Oil Development Economics: Pre-Tax Results ............................................ 29

4.2 Oil Development Economics: Post-Tax Results ........................................... 32 4.3 Oil Exploration Economics: Pre-Tax Results ................................................ 41 4.4 Oil Exploration Economics: Post-Tax Results .............................................. 43

4.5 Gas Development Economics: Pre-Tax Results .......................................... 44 4.6 Gas Development Economics: Post-Tax Results ......................................... 47

4.7 Gas Exploration Economics: Pre-Tax Results ............................................. 56 4.8 Gas Exploration Economics: Post-Tax Results ............................................ 57 4.9 Combined Oil and Gas Exploration Economics: Pre-Tax Results ................ 58

4.10 Combined Oil and Gas Exploration Economics: Post-Tax Results ............ 59 5.0 Main Conclusions and Recommendations from Evaluation of the New Zealand Regime .................................................................................................... 61

5.1 General Observations .................................................................................. 61

5.2 Conclusions and Recommendations: Oil Projects ....................................... 61 5.3 Conclusions and Recommendations: Gas Projects ..................................... 63 5.4 Conclusions and Recommendations: Exploration ........................................ 64

6.0 Comparison with Other Petroleum Fiscal Regimes .................................... 66 6.1 Introduction .................................................................................................. 66 6.2 Description of the Australian Petroleum Fiscal Regime ............................... 66

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6.3 Description of Thailand‘s Petroleum Fiscal Regime ..................................... 69

6.4 Description of Chinese Petroleum Fiscal Regime ........................................ 70 6.5 Description of Papua New Guinea‘s Petroleum Fiscal Regime .................... 72

6.6 Description of India‘s Petroleum Fiscal Regime ........................................... 73 6.7 Oil Development Economics: Post-Tax Results ........................................... 76 6.8 Oil Exploration Economics: Post-Tax Results .............................................. 88 6.9 Gas Development Economics: Post-Tax Results ......................................... 92 6.10 Gas Exploration Economics: Post-Tax Results .......................................... 96

6.11 Overall Exploration Economics: Post-Tax Results ................................... 100 7.0 Main Conclusions from Evaluation of International Comparisons ............. 105

7.1 General Observations ................................................................................ 105 7.2 Conclusions and Recommendations: Gas Projects ................................... 105 7.3 Conclusions and Recommendations: Oil Projects ..................................... 106

8.0 Issues Regarding State Participation in Oil and Gas in New Zealand ...... 107 8.1 Introduction – Reasons for State Participation ........................................... 107

8.2 Public Sector Investment in Petroleum ...................................................... 107

8.3 Details of State Participation ...................................................................... 109 8.3.1 Time of Commencement of participation ........................................................ 109 8.3.2 Cost sharing and funding ............................................................................... 109 8.3.2.1 Analysis of the Effect of State Participation on Exploration Economics ....... 110 8.3.2.2 Analysis of the Effect of State Participation on Development Economics .... 112 8.3.3 Percentage of participation ............................................................................ 112 8.3.4 Amount of participation in the management of the project .............................. 113

8.4 Other considerations in State Participation ................................................ 113

8.5 International experience ............................................................................. 114 8.5.1. Comparison of regimes ................................................................................. 114 8.5.1.1. China ......................................................................................................... 114 8.5.1.2. Papua New Guinea .................................................................................... 115 8.5.1.3. Thailand ..................................................................................................... 115 8.5.1.4. India ........................................................................................................... 116 8.5.2 Other countries .............................................................................................. 116 8.5.2.1. Angola ....................................................................................................... 116 8.5.2.2. Tanzania .................................................................................................... 118 8.5.2.3. Nigeria ....................................................................................................... 119 8.5.2.4. Russia ........................................................................................................ 120

8.6 Conclusions ............................................................................................... 120 9.0 Economic Assessment of Gas Hydrates in New Zealand ......................... 121

9.1 Introduction ................................................................................................ 121

9.2 Economic Assessment of Gas Hydrates .................................................... 122 9.2.1 Resource and Cost Assumptions ................................................................... 122 9.2.2 Gas Price Assumptions .................................................................................. 125 9.2.3 Results........................................................................................................... 125

9.3 Conclusions and recommendations ........................................................... 128 10.0 Lessons from international experience on managing wealth created from the extraction of petroleum resources, with focus on establishing oil funds .............. 130

10.1 Introduction .............................................................................................. 130 10.2 The Purpose of an Oil Fund ..................................................................... 130 10.3 Some Operational Concerns .................................................................... 131 10.4 The International Experience on Oil Funds .............................................. 132

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10.4.1 Norway Government Pension Fund (NGPF) ................................................ 133 10.4.2 The Alaska Permanent Fund ....................................................................... 135 10.4.3 Alberta Heritage Savings Trust Fund ........................................................... 137 10.4.4 State Oil Fund of the Azerbaijan Republic (SOFAZ) ..................................... 138 10.4.5 The National Fund of the Republic of Kazakhstan (NFRK) ........................... 141 10.4.6 Oil Stabilization Fund (OSF) of the Russian Federation ............................... 142 10.4.7 The Reserve Fund for Future Generations (RFFG) of Kuwait ...................... 143

10.5 General Conclusions ................................................................................ 145 APPENDIX A: Terms of Reference ..................................................................... 146 APPENDIX B: Criteria for allocation of permits in the United Kingdom ............... 150

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Executive Summary

1. Introduction This Final Report presents the results of the activities performed in order to advise the Ministry of Economic Development of New Zealand on a number of policy matters relating to the petroleum regime of New Zealand, including:

A review of New Zealand‘s permitting and regulatory frameworks for exploration and production of petroleum resources

A review of New Zealand‘s specific taxation arrangements for revenues derived from sales of petroleum

Comparison with other jurisdictions regarding levels of government take relating to petroleum revenues

Comparison of other jurisdictions regarding how broader mechanisms are employed to achieve industry development objectives and economic benefits from petroleum estates.

This executive summary describes our main conclusions and our key recommendations, which are as follows:

Modification of certain provisions in the permitting and regulatory framework and the inclusion of further details with regards to decommissioning issues are desirable.

Consideration of special fiscal terms for non-associated gas is recommended, in order to minimise the number of marginal gas developments that are economic before tax but fail to be developed because they would be uneconomic after tax. Special terms would also address issues of perceived risk and of capital rationing.

The analysis of the economics of oil developments in New Zealand demonstrates

that the possible measures for gas are not required for oil unless there is a very strong desire to protect economically marginal oil developments. They would, however, improve the overall economics of exploration.

The New Zealand fiscal regime (i.e. those terms scheduled to apply after 31 December 2009) is highly competitive against all the comparator countries except Papua New Guinea when tested under Great South Basin conditions.

Based on the best information available, our review suggests that the potential economics of gas hydrate production are of a similar marginal status to those of conventional gasfields, at least in the lower half of the reserve range we have evaluated. Special fiscal terms extended from conventional gas to hydrates would have all the benefits described above, and in addition would help to combat the poorer economics of large hydrate developments.

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There are several reasons for governments wishing to participate side by side with oil companies in exploring and producing oil in their own countries. The motives for such participation vary from country to country and the importance of each of these to policy makers will depend on political as well as economic considerations and in the circumstances of the petroleum industry in each country. It is a matter for the judgement of the host Government to decide which, if any, are deemed to be sufficiently important to warrant state participation.

Petroleum reserves are part of the nation‘s capital stock and the depletion of hydrocarbons should be accompanied by measures to ensure that sufficient of the revenues is invested to at least keep the capital stock intact. On balance, for countries lucky enough to be endowed with large petroleum reserves, an oil fund is a sensible concept. But it is not a substitute for sound economic management. The rules of operation of the fund need to be very clearly specified and to be consistent with the objectives.

2. Main Conclusions and Recommendations from Evaluation of the New Zealand Permitting and Regulatory Regime While the current regulations are felt to be largely satisfactory we make several comments with regards to the permitting and regulatory framework existing in New Zealand. We provide specific comments on the details in the following policy areas:

Policy framework and objectives

Land available for petroleum permits

Permitting regime

Allocation by cash bonus bidding

Allocation of prospecting permits

Allocation of petroleum exploration permits

Priority in time applications Changes to exploration permits Allocation of mining permits Good mining practice

The royalty regime It is also judged that the current regulations do not discuss decommissioning issues adequately. If oil and gas exploitation becomes significant offshore the decommissioning problem will loom longer as the costs will be very substantial. The regulations adequately discuss how the costs can be relieved against accounting profits royalty, but there are several further issues which should be considered such as the ability of the investors to finance the work and the measures to protect the Government against default as well as the extent of the decommissioning obligation.

3. Main Conclusions and Recommendations from Evaluation of the Current Regime and International Comparisons Under the likely costs and base case hydrocarbon prices used in this study, petroleum exploration investments in New Zealand, as represented by the Great South Basin, are economically marginal at a cost of capital which is moderate and may not reflect all the risks and the effects of capital rationing.

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Although the exploration economics of the GSB are at breakeven, this position is founded on a probabilistic combination of economic oil developments and uneconomic gas ones. It would be preferable for all parties if everything possible could be done to move away from a position where the economic attraction of exploration hinges on finding oil rather than gas. It is crucial to improve the economics of New Zealand gas developments, and to minimise the number of marginal gas developments that are economic before tax but fail to be developed because they would be uneconomic after tax.

Being related to revenues and not to costs, the Ad Valorem royalty penalises marginal developments and is a candidate to have its rate significantly reduced, at least for new gas projects. Consideration should be given to deferring the planned increase in the Ad Valorem royalty.

An additional measure could be modification of the Accounting Profits royalty, converting it from a cumulative cashflow based royalty to a rate of return based one. The rate of return at which it begins to operate could be based on an analysis of the pre-tax internal rates of return in hypothetical gas fields that would currently be economic before tax but not after tax. While in general it is eminently reasonable that investments yielding high returns should be expected to contribute a higher share of the economic rents to the state the current situation in New Zealand hardly warrants any such increase, given the prime need to attract investment into the sector. In the event that very attractive discoveries are made and/or gas prices rise very substantially the notion of modifying the accounting profits royalty to a resource rent tax should be considered.

The analysis of the economics of oil developments in New Zealand demonstrates that the measures described above for gas are not required for oil unless there is a very strong desire to protect economically marginal oil developments. Fiscal changes for gas would result in a general improvement in exploration economics (general while the oil and gas proneness of individual New Zealand basins remains uncertain). Extending the same fiscal changes to oil, again while this uncertainty persists, would be an option if the impact of the gas taxation changes on exploration economics was judged to be inadequate.

The New Zealand fiscal regime (i.e. those terms scheduled to apply in New Zealand after 31 December 2009) is highly competitive against all the comparator countries except Papua New Guinea when tested under Great South Basin conditions. Moreover, the competitive advantage of the Papua New Guinea regime relies on a temporary reduction in the corporate income tax rate, a concession due to be withdrawn for development licenses granted after the year 2017. 4. Main Conclusions and Recommendations from the Economic Assessment of Gas Hydrates Given the level of scientific knowledge of gas hydrate production and the youth of this branch of the industry, there cannot be a definitive answer to the question of the likely commercial viability of gas hydrate production. Every field development must stand on its

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own merits and commercial drivers will differ according to market conditions and regional energy security issues.

Based on the best information currently available, the review undertaken by AUPEC suggests that the potential economics of hydrate production are marginal, but similar to those of conventional gas production when reserves are lower than about 3500 bcf. Above this level, conventional gas production becomes slightly more economic than gas hydrate exploitation. We have already recommended special fiscal terms for gas, and our review of gas hydrates suggests that fiscal terms improving the economics of conventional gasfields and protecting marginal ones will be adequate for hydrate gasfields, at least in the lower half of the reserve range we have evaluated.

We recommend monitoring the development of this branch of the industry via regular broad economic assessments which should be accompanied by an appropriate level of flexible framework review.

5. Main Conclusions and Recommendations from a Study on State Participation in Oil and Gas

Government investment to explore for and produce oil and gas is not uncommon in the industry and can take many forms, including the provision of infrastructure with and without user charges, equity participation in petroleum projects, and publicly financed exploration. There are several reasons for governments wishing to participate side by side with oil companies on exploring and producing oil in their own countries. The reasons vary among countries around the world. They may be summarised as follows:

To collect a further share of economic rents for the state above those obtained through royalties, taxes and profit-sharing.

To have indigenous (local) ownership of the activity.

For additional state control over the activity, through internal decision making.

To provide expert specialist advice to Government.

To serve as a vehicle for technology transfer. The importance of each of these motives to policy makers will depend on political as well as economic considerations and on the circumstances of the petroleum industry in each country. It is a matter for the judgement of the host Government to decide which, if any, objectives are deemed to be sufficiently important to warrant state participation. As a generalisation, in countries with sreious capital shortage the collection of economic rents is clearly better accomplished by royalties, taxes and profit-sharing arrangements. The view of most Western economists is generally that from an economic viewpoint state participation is unnecessary unless there are indications of market failures.

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6. Lessons from international experience of managing wealth created from the extraction of petroleum resources, with focus on establishing oil funds Oil funds can have various purposes, including long-term fiscal sustainability, inter-generational equity, macroeconomic stabilisation, efficient resource allocation within the economy, promoting industrial diversification, providing local benefits, and developing sustainable energy. The varied practice around the world reflects this variety of purposes. Thus oil funds can facilitate sound macroeconomic management in an environment of fluctuating revenues from oil production, which can destabilise an economy. They can ensure that the benefits of the revenues from the depletion of a non-renewable resource are not dissipated in consumption or used to reduce other taxes and thus all applied to normal budgetary purposes rather than strategic investment.

Petroleum reserves are part of the nation‘s capital stock and the depletion of hydrocarbons should be accompanied by measures to ensure that sufficient of the revenues is invested to at least keep the capital stock intact. An oil fund is not necessary to ensure that this outcome is achieved, but it can ensure that the revenues are not used for purposes inconsistent with this objective.

The issue of the extent to which the fund should be separated from the normal government budget procedures is thus a central one. On balance, for countries lucky enough to be endowed with large oil reserves, an oil fund is a sensible concept. But it is not a substitute for sound economic management. Another key conclusion is that the rules of operation of the fund need to be very clearly specified and to be consistent with the objectives. In general, discretionary access by a government is likely to endanger the objective of facilitating permanent benefits from the revenues. The notion of only utilising the permanent/sustainable income from the fund rests very uneasily with general government practice around the world.

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FINAL REPORT

Evaluation of New Zealand’s Petroleum Tax and Licensing Regime

1.0 Introduction

AUPEC Ltd was retained by the Government of New Zealand in March 2009 to carry out an evaluation of the country‘s petroleum tax and licensing regime. The following report describes our approach and methodology and presents our results and recommendations. The study has the following principal objectives.

1. Evaluation of New Zealand‘s permitting and regulatory frameworks for exploration and production of petroleum resources (focusing on permitting options for exploration, appraisal and mining)

2. Assessment of New Zealand‘s specific taxation arrangements for revenues derived

from sales of petroleum

3. Comparison with other jurisdictions regarding levels of government take relating to petroleum revenues

4. Comparison of other jurisdictions regarding how broader mechanisms are

employed to achieve industry development objectives and economic benefits from petroleum estates.

The work was carried out over a three month period between March and June 2009.

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2.0 Evaluation of New Zealand’s Permitting and Regulatory Framework for Exploration and Production of Petroleum Resources

2.1 Approach in this Review

We reviewed several items of legislation, focusing on permitting options for exploration and mining permits. The documents reviewed were the Crown Minerals Act 1991, the Minerals Programme for Petroleum 2005, the Crown Minerals (Petroleum) Regulations 2007, the Petroleum Digital Data Submission Standards and the Crown Minerals (Petroleum Fees) Regulations 2006. In recognition of the fact that relatively full details of the arrangements and the thinking behind them are shown in the Minerals Programme for Petroleum 2005 this review follows the format and sequence in that document and thus makes very frequent references to it. The paragraphs cited refer to this document unless otherwise stated.

2.2 The Policy Framework and Objectives

Acknowledgement that the process of allocating rights should be ―efficient‖ is laudable and par. 2.11 itemises sensibly the main considerations form the Government‘s viewpoint. Reference is made to the need to avoid ―unreasonable transaction costs‖. This is also laudable but further details of how this should be achieved could be given. The costs incurred by investors are relevant here. These include the time and effort required to conform to the procedures. These are national costs and can influence decisions on whether to apply for permits. This subject is developed below under the relevant specific headings. The interpretation of the phrase ―fair financial return‖ to the Crown is shown and itemised in par. 2.13. The items shown are arguably all relevant, but the central consideration is surely the size of the economic rents likely to be obtained from the oil and gas exploitation. This could be explicitly stated. A short definition would be the returns in excess of the supply price of the petroleum. If the economic rents are large the returns to the Crown can and should also be large. But if they are small or zero economic rents are in prospect the Crown‘s share should similarly be reduced. Otherwise investment will fall and other objectives jeopardised. In this context the concept of a minimum return to the Crown as owner needs particularly careful consideration. There would be widespread agreement that all investors should pay corporate income tax. But when projects are very marginal whether there should be royalties in addition to that can be debated. The summary of policies in par. 2.18 is generally clear and appropriate. It is noteworthy that some policy issues deemed to be important in other petroleum producing countries are not mentioned. Examples are (a) opportunities for indigenous suppliers and workers, (b) security of supply (which is noted elsewhere), (c) transfer of technology to New Zealand. It is not suggested that these should be highlighted in par. 2.18 but they might have been mentioned.

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The wording in par. 2.20 suggests (though does not say so explicitly) that state intervention further than has been mentioned explicitly in par. 2.18 is not contemplated. This will be of interest of investors.

2.3 Land Available for Petroleum Permits

Access to land and the terms and conditions of such access are clearly important issues for onshore petroleum exploitation. The rules should be made very clear to investors. A problem which sometimes arises after a permit has been awarded and a discovery has been made relates to the pipeline transportation of the gas/oil. The optimal route may well not have been anticipated at the time of the award of the permit. The optimal transportation route in the event may involve access to land outside the permit area. Landlords may object or demand very high fees for permitting access and laying pipelines. The rules regarding arbitration and the compensation/fees to landlords should be made clear to investors.

2.4 The Permitting Regime

The Priority in Time application concept as practised in New Zealand is a little unusual. The most conventional approach is to have a round of licensing whereby a number of blocks are put on offer by advertisement. In practice potential investors are usually canvassed first to ascertain their views on which areas are of potential interest. The basic case for this approach is that it encourages competitive bidding and the Government can on this basis determine which applicants best meet their award criteria. The Priority in Time concept may not allow full competitive bidding for an area sought by one investor. The concept does, however, deal with the situation where a perceived need for an area arises at relatively short notice. The ability to request an area which is otherwise available rather than wait for a round involving other blocks clearly has merit. But, in these circumstances, the area in question could be offered to the industry as a whole. This would enable the Government to choose the applicant which best meet the award criteria used in licence rounds. The time period given to submit bids could be relatively short. This procedure has been used in UK petroleum licensing.

2.5 Allocation by Cash Bonus Bidding

It is unusual, but certainly possible, to associate cash bonus bidding with a drilling obligation (even though it is a conditional obligation). Cash bonus bids are well known in the USA and Canada. There are variants, particularly royalty bids and net profit bidding. The case for these is that they do not put smaller companies with limited financial resources at a disadvantage compared to large companies. Generally banks do not lend funds for bonus biding purposes at the exploration stage. Royalty bids and net profit bids are payable out of production income. While the case for these rather than bonus bids has not been conclusively proven to attract more bids in the USA (because small companies can club together to form an effective bidding group), these alternatives could be considered. More fundamentally, however, it is arguable that, given the current position of the industry in New Zealand with only modest numbers of wells being drilled, the emphasis should be on encouraging exploration rather than on the receipt of early revenues from bonuses.

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2.6 Allocation of Prospecting Permits

Many of the terms are conventional. The general length of the permit at no more than one year is relatively short by international standards especially for offshore areas. The length of the time period should also be seen in the context of the size of the area in question. It is normal that the permit specifies that the Crown is given copies of all data gathered. It is also normal that a period of time be specified within which the licensee has exclusive rights to trade the data. It is now not uncommon that after this period the Government can make the data widely available.

2.7 Allocation of Petroleum Exploration Permits

A length of (up to) 5 years for the first term of an exploration permit is quite long by international standards for onshore exploration. In many countries the first term is less than 5 years for offshore situations. In the UK North Sea it has been 4 years in recent licence rounds and investor interest has not been reduced on this count. The length of the period should also be seen in the context of the size of the area awarded. The larger the area the stronger the case for a longer period. In the UK the size of a whole, standard block is c. 250 square kilometres. It is not clear why (at least for onshore situations) an extension of a further 5 years is necessary. This could be appropriate in large, deepwater blocks. This element in the licensing should be reconsidered at least as far as onshore and nearshore situations are concerned. It is stated (par. 5.4.13) that there is no fixed size of permit but that it ―should be such as to extend over known or potential exploration targets‖. This gives much discretion, and in practice could involve a negotiating situation. Investors will be keen to have large areas at their disposal and the result could be that the number of blocks awarded is less than optimal. The consequence of a possible 5+5 years total exploration period plus the possibility of relatively large sizes of blocks is that there is danger that the total exploration effort will be less than it could be. The phenomenon of ―fallow acreage‖ could result. The possibility of this is worthy of examination. The likelihood of it occurring is also a function of the size and structure of licence fees and the work obligations. If the fees are relatively low the holding costs of the acreage are correspondingly low. In some countries such as the UK the phenomenon of fallow acreage in earlier licence rounds was recognised to be a consequence of generous terms regarding relinquishment and low annual rental payments. In more recent rounds the fees rise annually fairly steeply to a maximum in order to encourage earlier activity. The need to surrender 50% of the initial acreage after 5 years is fairly conventional. Whether it is liberal or tough depends on the size of the initial area awarded. Consideration should be given to the question of whether fixed block sizes (and shapes), along with a re-examination of the length of the exploration period, would produce a greater exploration effort via more bids in aggregate and bigger work programmes in aggregate through time. Earlier relinquishment means that more acreage can be made available to new players. The condition that a work programme must provide for at least one well to be drilled during the first 5-year period is perhaps rather tough if the top priority is to attract and enhance the exploration effort. It is, of course, most desirable that investors commit to drill wells. In some prospective areas this will be the full intention from the outset. But normally there will also areas where the prospectivity is regarded as very risky. In such cases the investor may well wish to conduct further seismic work before committing to drill a well. If the terms oblige him to drill he may not bid for the high risk acreage. In this situation there can be merit in the concept of a conditional well. This means that the investor undertakes

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to conduct a specific minimum amount of seismic work, and, if the result is promising, to drill a well. This concept has been employed for some time in the UK North Sea. Consideration should be given as to whether it might be introduced in New Zealand. Thus a study could be undertaken to ascertain whether the drilling obligation as at a par. 5.4.17 is resulting in some acreage (with some prospects of oil or gas) not being sought. The criteria for determining the successful applicant in a bidding situation as shown in par. 5.4.24 are fairly conventional by international standards. In some countries (e.g. the UK) more detailed advice is given (see Appendix B). Interestingly, this includes details of the marking system which indicate the number of marks for each of the several categories listed. This gives useful information to bidders on which types of work are most sought after. In par. 5.4.25 it is indicated that bids may be ranked by the proposed expenditure on exploration. This is generally not recommended. It is the physical work programme which is best geared to exploration success which is relevant not the money expended as such.

2.8 Priority in Time Applications

The issue of whether Priority in Time application should be subject to competitive bidding has already been discussed. The wide discretion given to the Minister regarding relinquishment (par. 5.4.43) is rather unusual. It is not clear that this discretion is superior to fixed terms which the investor can clearly see. If the outcome depends on negotiation and results in different terms applying to different blocks and investors it is not clear that this discrimination has merit compared to uniform terms.

2.9 Changes to Exploration Permits

Explicit and detailed provisions for changes to permits are generally not encouraged. The provisions in Section 5.5 are thus comparatively unusual. But requests by investors for changes to licence terms do occur and thus having provisions to deal with this eventuality has some advantages. Reasons for requests for changes to exploration licences include the proposition that, on the bases of seismic work undertaken, drilling a well is not justified. (This forms the basis of the case for a contingent well obligation in some licences). Other requests are for a time extension to a drilling obligation because of inability to access a drilling rig within the agreed time period. Other requests can be to postpone or even cancel a drilling obligation because of an oil price fall or a tax increase. In the UK the Government has historically shown some sympathy to the technical (i.e. geological) arguments for not proceeding to drill on the basis of seismic work undertaken. In such cases attempts can be made to persuade the investor to transfer his drilling obligation to another block which that investor may have. Of course, this may not always be possible. Extensions to the time period within which a drilling obligation should be executed should be given only sparingly under quite exceptional circumstances. Historically the UK Government has not generally given approval to a reduction in a drilling commitment for economic reasons, such as a fall in oil/gas prices or a change in the tax system.

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To permit an extension of the permit to a land area beyond the then current permit area is very unusual by international standards. Normally when this is requested by the investor and the land in question is not under licence, the Government would put the acreage on offer and it would be awarded on a competitive basis. This would ensure that the acreage was awarded on the best terms from the Government‘s viewpoint. The only possible disadvantage of this approach would be in the circumstance when a discovery had been made on the edge of an existing permit area and it extended into other acreage. If this other acreage were awarded competitively an investor other than the one which had applied for the acreage extension might be the successful applicant. In turn this would subsequently entail an unitisation agreement. Apart from this possible complication the arguments in favour of competitive bidding for open acreage are strong. Provision for extension to the length of permits is relatively common, normally to deal with unforeseen events. As discussed above the initial terms for the exploration permit of up to 5 years is generous to the investor at least for onshore situations. Requests for extensions beyond the first term should be backed up by submitted work programmes which would be subject to approval by the Government. It is not obvious that the length of the second term should be as much as 5 years. The concept of ―an appraisal extension‖ (par. 5.5.17) has merit but it should not be thought of as an automatic right. Perhaps the wording could make this very clear. The investor should be encouraged to proceed expeditiously to the appraisal stage after a discovery has been made. The notion that the permit area could be reduced when the appraisal programme is proposed has merit because it should focus the attention of the investor and reduce the fallow acreage problem.

2.10 Allocation of Mining Permits

It is not entirely clear from reading pars. 5.6.1 – 5.6.3 whether the investor who acquires a mining permit relating to an existing exploration permit acquires all the acreage held under the exploration permit. This does happen in many licensing arrangements (and appears to be the case in New Zealand), but in others the mining permit would only apply to the field development area and the remaining part of the exploration permit acreage would be surrendered. There are arguments for both approaches. If the area of the exploration permit is large then there could be merit in restricting the mining permit to the development area. This would include a geologically sensible area around the discovery to permit exploration for and exploitation of satellites to the discovery. Government approval of all work programmes under a mining permit is recommended. It is conventional that the host Government will normally want to ensure that a field development plan is consistent with the objective of maximising field economic recovery. An investor who is anxious to emphasise early production and revenues may propose a development plan to that effect which then causes the reservoir pressure to fall to the detriment of overall economic recovery from the field. The Government as landlord will wish to check that the development plan is likely to achieve maximum economic recovery. In offshore situations it is possible that a development plan based on a fixed platform could achieve a higher economic recovery than one based on a subsea system. The Government should be satisfied that a subsea system does produce a satisfactory economic recovery. The Government will also have broader considerations than those often held by an investor. For example, an investor may propose a tanker loading scheme at an offshore field rather than a pipeline. The Government will have to consider the potential effects on other users of the sea such as fishermen and perhaps tourists. The

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chance of spills should come into the calculation. In general a field development plan is one of the most important issues in petroleum development and rights of Government approval of the plan will generally be in the national interest. To have discretion on the duration of the mining permit is unusual by international standards. The normal arrangement would be to specify a time period in the regulations but permit applications to be made for an extension. This procedure can focus the attention of the investor in proceeding expeditiously to a field development. It also gives the Government the authority to impose conditions on an extension to the permit. This procedure gives the Government the benefit of the knowledge over the original lifetime of the permit. When the investor receives the permit it can include a provision stating that an extension ―would not unreasonably be withheld‖ but is subject to an agreed work programme at the time. Staged development approval arrangements (par. 5.6.11) are possible but are generally unpopular with investors, especially if the Government has a history of being substantially ―interventionist‖ and that such interventions could act to the disadvantage of the investor. An example could be an interventionist depletion policy which suggested cuts in the production profile below that proposed by the investor. An alternative which can be effective from the Government‘s viewpoint is to require regular progress reports which would highlight any changes which had occurred to the original field development plan. The investor would have to justify these. Further, if the Government were dissatisfied with what was actually happening it would have the power to propose alternatives to what the investor was doing or planning. In the UK there is now an agreed initiative termed the stewardship initiative whereby investors have to justify their operations including incremental investments, and listen to suggestions made by the Government experts. They are given some time to implement the suggestions, but if these are not undertaken in a satisfactory manner, the investor can be obliged to trade his field. To date this has not happened.

2.11 Good Mining Practice

With respect to data from mining operations (par. 6.2.4) it is important that the Government has the right to receive all well data. After a specified period such data should be made widely available to investors generally with the purpose of maximising the amount of public knowledge and enabling all potential investors to acquire the information. In the UK in recent licences well data now became widely available 3 years after the event.

2.12 The Royalty Regime

The detailed quantitative analysis of the effects of the royalty and tax regime is the subject of a separate chapter of this report. Thus the effects of the increase in the accounting profits royalty from 1st January 2010 and the increase in the ad valorem royalty on gas are discussed separately. Only qualitative comments are made here. The details of the two royalty schemes are generally clearly presented. From the investor‘s viewpoint it is the total Government take which is of most importance and the interaction of the royalties with the corporate income tax is very important.

17



The above requires clarification of some technical issues which can be economically important. In par. 7.16 the arrangements for the relief of decommissioning costs against accounting profit royalty are set out. The clawing back of decommissioning relief for accounting profits royalty is specified. This will have consequences for the corporate income tax payable which would also have to be recalculated as the accounting profits royalty paid is a deduction for income tax. There is a provision that head office costs are not allowable for accounting profits royalty. This is a notably tough provision if it is interpreted literally. It would be conventional for a scheme such as accounting profits royalty that head office costs clearly incurred in relation to activities under a mining permit would be deductible. Often a ceiling is placed on the amount which can be deductible. It should be noted that allowing some head office costs as cost recoverable is also very conventional in production sharing agreements. The list of non-allowable items reads very much like those employed in production sharing agreements.

2.13 Need for Regulations on Decommissioning

The current regulations do not discuss decommissioning issues adequately. If oil and gas exploitation becomes significant offshore the decommissioning problem will loom longer as the costs will be very substantial. The regulations discuss how the costs can be relieved against accounting profits royalty in an adequate manner, but there are several further issues which should be considered. These essentially result from the fact that the decommissioning activity occurs after field income has ceased. The issue of the ability of the investors to finance the work becomes an issue. The Government needs to protect itself and ensure that the work is undertaken to its satisfaction. To ensure that this happens the development plan produced by the investor should include a decommissioning plan for approval. If this is not already incorporated in existing development plans then the Government can insist that it is produced under the procedures for changing development plans. Policy decisions need to be made about the extent of the decommissioning obligation e.g. capping and sealing of wells, full removal of offshore installations or allowing footings to remain in place. To protect itself against default the Government has several options. It could insist on joint and several liability among all co-licensees. This would not be popular among licensees, but it is the policy in the UK. But all the licensees in group might not be sufficiently financially strong to give adequate comfort to the Government. In that event there are several further options. The Government could take powers to be able to require the provision of adequate financial security from permit holders. This could take the form of bank guarantees (letters of credit), surety bonds, or contributions into an alienated decommissioning fund. Letters of credit are expensive to investors and could cause premature cessation of production. The same applies to surety bonds. Investors would request tax relief and probably accounting royalty relief for the payments relating to letters of credit or surety bonds. Relief is given for the decommissioning costs directly and the result is a cost to the Government as well as the investors. Payments into an alienated decommissioning fund over at least part of the life of the field which accrue to meet the later decommissioning costs have attractions. They provide financial security to all relevant parties namely the Government, and all permit holders. But contributions made on a gross of tax basis are expensive and investors will ask for tax relief on the

18



contributions as they are made. This type of scheme is becoming more common around the world. Further details of the financial liability problem can be provided if necessary. Where no specific comments have been made on a subject this is because the current regulations are felt to be satisfactory and no comment required.

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3.0 Evaluation of New Zealand’s Petroleum Tax Regime

3.1 Approach and Methodology

AUPEC‘s approach to assessing the performance of fiscal regimes and, particularly, the efficacy of the fiscal instruments, is to first understand the key strategic objectives that most countries have regarding the exploitation of their petroleum resources. For example, most Governments are likely to have a set of objectives with regard to petroleum taxation, a typical list of which is summarised below:

To obtain a "reasonable" share of the revenues. More precisely Governments wish to collect an optimal share of the economic rents from oil and gas exploitation.

To avoid the introduction of disincentives on investors that might discourage them from developing new fields, continuing to explore for oil and gas, or maximising the recovery of oil and gas from the reservoir.

To ensure that the fiscal system does not encourage oil companies to overspend. In some circumstances the tax system may introduce incentives for investors to spend more than is necessary because the resulting tax saved is so great that the investor is better off. This is sometimes referred to as a "gold plating" incentive.

To receive part of the fiscal take comparatively early in the life of an oil or gas field.

To establish an "appropriate" degree of project risk-sharing with private investors.

To integrate the fiscal system levied on petroleum exploitation with the tax system applied across the economy generally.

AUPEC applies these, and other, fundamental Government objectives when reviewing fiscal regimes. The question we often pose is ‗do the economic and fiscal performance indicators (or yardsticks) match or exceed the objective criteria established by Government strategy with respect to oil and gas exploitation?‘

3.1.1 Characteristics of an Optimal Fiscal System

There are many ways that Governments can tax oil companies, and many different fiscal instruments that can be included in a fiscal regime. The impact of different fiscal instruments on after-tax (post-tax) returns can vary considerably. Governments need to take these effects into account when designing fiscal packages if they are to procure a "reasonable" share of revenues without introducing disincentives or distortions that prevent an efficient collection of taxes or that prevent new oil and gas fields being developed. Oil companies are concerned with several aspects of the fiscal burden, particularly the overall level of tax to be paid, the structure of the fiscal mechanism (i.e. what part of the system is based on gross revenues and what part is based on a share of the profits), and the timing of payments. In general companies prefer taxes to be based on profits rather

20



than volumes, and they prefer that the major burden of taxation is borne later rather than earlier in the life of an oil field. These objectives often conflict with those of Government (such as the sharing of risk, and the requirement by Government of early revenues), but not always, and there is often room to create terms that are in the interests of both parties in the long run. AUPEC generally conducts its assessment of fiscal regimes by comparison with the characteristics of an optimal fiscal system. These characteristics are summarised as follows:

The system should be targeted on economic rents. To do this the system should contain the following:

The system should be related to profits and allow the recovery of all costs plus an "adequate" return on the risk investment.

The system should be flexible to variations in oil and gas prices, production, development costs and operating costs

The system should automatically react progressively rather than regressively with respect to variations in oil and gas prices, production, development costs and operating costs.

This last bullet point means that the Government take should increase when the oil or gas price or production rises and exploitation costs fall. Equally the take should go down when oil or gas prices or production fall and costs increase. An optimal fiscal system should ensure that projects that are marginally acceptable before tax are viable after tax, and it should avoid the need for a company to abandon an oil field before all recoverable reserves have been produced. Finally, the system should not encourage oil companies to spend extravagantly in order to reduce their tax liability (this can occur when marginal tax rates are very high), it should not create a situation whereby the post-tax return on investment is greater than the pre-tax return, and it must have manageable administration and compliance costs. The following section concerns the objective of analysing and making recommendations on the fiscal regime of New Zealand. A key objective of the aspect of the study reported here was to assess the investment prospects of New Zealand under the current fiscal regime and in particular to consider the probability of discoveries, their likely size and profitability. Based on this work, the study team would make recommendations on the retention or modification of the terms of the fiscal regime in order to maximise both the attraction of New Zealand‘s oil and gas provinces to investors and the benefit of exploration and development to society in New Zealand. The project team employed computerised fiscal models of the fiscal regime. AUPEC uses macros that vary oil or gas price, reserves (field size) and unit development cost independently.

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In studies such as this AUPEC normally presents the results at three or four constant real terms oil prices, notionally including a central case and upper and lower sensitivities.

3.2 Description of New Zealand’s Fiscal Regime

The government of New Zealand has implemented a concessionary system where the Crown owns the subsurface petroleum resources and any company wanting to prospect, explore or mine petroleum in New Zealand must obtain a permit from Crown Minerals under the Crown Minerals Act 1991. Permits are regulated by a Minerals Programme for Petroleum which establishes the policies, procedures and provisions to be applied under the 1991 Act and which is updated at least once every 10 years. In addition, the Crown Minerals (Petroleum Fees) Regulations outline fees payable for matters specified under the 1991 Act for petroleum. The latest version of the (Petroleum Fees) Regulations is that of 2006, and relevant fees required as part of the permitting regime are summarised below (see Table 1). These were used in economic modelling of the regime. Table 1. Application and Annual Fees under the New Zealand Permitting Regime

Type of charge Amount

Application fee Prospecting permit – NZ$ 6,000a b

Exploration permit – NZ$ 6,000

Mining permit – NZ$ 25,000

Annual fee For each square kilometre or part thereof covered by the permit at the following rates

under prospecting permits - NZ$ 4

under exploration permits - NZ$ 10.50

under mining permits - NZ$ 100

Notes: a) 1.67 New Zealand dollars equal US$ 1 (assumption made for modelling purposes). b) The fees prescribed by these regulations are inclusive of goods and services tax (GST).

The latest version of the Minerals Programme for Petroleum is that of 2005 and it contains the details of the royalty regimes. The programme stipulates the payment of either an ad valorem royalty (AVR) or an accounting profits royalty (APR), whichever is the greater in any given year. As this study analyses future possible discoveries, the values for AVR and APR were assumed to be those applying after 31 December 2009 as specified in the above document. The AVR is essentially 5% of the revenues obtained from the sale of petroleum from a permit. The APR is specified as 20% of the ―accounting profit‖ of petroleum production. In calculating the accounting profit the same ―net‖ sales revenues are used as for the AVR and deductions that may include associated production costs, capital costs (exploration and appraisal costs, development costs, permit acquisition costs and feasibility cost),

22



indirect costs, abandonment costs, operating and capital overhead allowance, operating costs and capital costs carried forward and abandonment costs carried back. When there is a series of years, some with the Ad Valorem Royalty being higher and some with the Accounting Profits Royalty being higher, it was assumed that this does not perturb the Accounting Profits Royalty calculation. In other words, there is a genuine "shadow" calculation of the Accounting Profits Royalty calculation in periods where the Ad Valorem Royalty is higher. In periods when decommissioning is taking place, the Ad Valorem Royalty will be zero as there is no production, whereas subject to the level of the decommissioning costs the Accounting Profits Royalty will be negative, representing a carry-back of some or all of these costs. It was assumed that when decommissioning costs are carried back the corresponding allowance against APR cannot be curtailed by any AVR assessments that happened to be higher than the APR liabilities in any of the relevant years. It was assumed for modelling purposes that royalties are paid in the same calendar year as the corresponding income. Income tax is levied at a rate of 30%. Consolidation of income and expenses from different licenses is allowed within a company and within a group of New Zealand companies. Ad Valorem Royalty, Accounting Profits Royalty, and fees payable in respect of permits are allowable against Corporate Income Tax. Exploration and appraisal as well as operating expenditures are immediately deductible and development expenditure is generally depreciated on a straight line basis over 7 years, from the date it is incurred. There are several specific depreciation provisions and as such the investor must distinguish between development expenditure and other capital expenditure. The approach used in modelling was that all capital expenditure was development expenditure. Buildings may be depreciated using the method of diminishing value at 3% or the straight-line method at 2%. Depreciation on production plant, platforms and other installations including pipelines and related installations used in connection with acquiring income from the extraction and sale of hydrocarbons is provided on a straight line or diminishing value basis on the aggregate of all assets of this type. This excludes assets which are specific to a permit area and have a useful life dependent on that permit area: such assets are treated as development expenditure. Straight line depreciation rates range between 8 and 40% p.a.; alternatively diminishing value depreciation rates range between 2 and 67% p.a. For new assets an additional 20% loading on the depreciation rate is available, but it does not apply to development expenditure. There is a law change that will allow all development expenditure to be amortised from the date that it is incurred. A related law change will also allow development expenditure to be amortised on an units of production basis. In modelling, the relevant choice was given between straight line and unit of production amortisation, with the model selecting the most favourable discounted tax relief for the investor. Abandonment expenditure is deductible in the year in which it is incurred but only for petroleum mining depreciable property. Development expenditure can only be written-off if

23



the relevant permit is relinquished. Abandonment expenditure can be carried back 4 years. Interest deductions are allowable subject to a thin capitalisation limit of 75% of total assets. The Income Tax relief against finance costs was modelled as being based on 75% of the interest that would be paid on a fully loan funded project. The interest was based on all negative cumulative midyear project cash flows, i.e. the assumption is that the income tax authority expects each project to repay its notional funding as soon as possible. Trading losses may be set off against other taxable income. Tax losses can be carried forward, provided that shareholder continuity of 49% is maintained. Provisional income tax is paid using an instalment scheme that is based upon the investor‘s assessment of the preceding tax year (with estimated liabilities and to be adjusted later). Using a model with data input in calendar years, balance date of 31 December was assumed and that the Income Tax payments fall 2/3 in the current year calendar year and 1/3 in the following year under an instalment scheme. VAT (Goods and Services Tax, GST) is charged at the rate of 12.5% on any goods or a service supplied within New Zealand and is allowable against income tax. As GST is levied on final consumers, GST was not included in the Government take for the petroleum upstream sector when modelling. The rationale is as follows. GST levied on input costs for the upstream sector is allowed as a credit against the GST charged on the sale of the oil. If the buyer is a refinery in N.Z. the GST paid by him is allowed as a credit against the GST on the sales of the petroleum products. If the crude oil were to be exported it is zero rated for GST purposes and there would be a refund of the GST paid on the producer‘s input costs.

3.3 Production and Cost Assumptions

AUPEC was provided by the Ministry of Economic Development (henceforth referred to as ‖The Ministry‖) with hydrocarbon resource, production profile and cost assumptions for use in economic modelling. A series of email and telephone conversations resulted in refinement of the data, the result being described below. The data were based on the assumption that operations would be carried only in the gas prone Great South Basin as this is likely to be the most costly offshore basin from which to produce in New Zealand. It is important to note, however, that the reader can interpret the economic results by looking up lower or higher unit development costs in the charts than the ones currently assumed. The costs provided by the Ministry were given both in New Zealand and United States dollars. An exchange rate of US$0.6 per New Zealand dollar was assumed and we have adhered to this.

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3.3.1 Offshore Great South Basin (GSB) - Oil

For all offshore prospects a very aggressive development timetable was assumed while taking into consideration that the Great South Basin (GSB) has no infrastructure. It was assumed that

An exploration well will be drilled during 2011 (as required in the current GSB permits)

Three appraisal wells will be drilled during 2014, in order to minimise mobilisation/demobilisation costs

3D development seismic will be shot during 2016

In the case of successful appraisal, capital costs are represented to be incurred during 2015-2017

Production and injection well drilling will start during 2017

Production will start on 1 July 2017

Production will be via an FPSO The following assumptions were made when developing production profiles:

Water injection will be required for all developments

Gas re-injection will be required for all developments except the smallest field investigated

The reserve sizes modelled were 40, 80, 120, 260 and 400 mmb

The recovery factor was assumed to be 40%, based on gas re-injection The CAPEX phasing has a 50-55% spend in the year of first oil and only half a year's production was assumed in that year. This is based on the assumption that facilities/platform installation can be completed in the first half of the year and drilling commenced by end of the second quarter. It is also assumed that drilling will continue while production is ramped up. Not the all wells are required to meet design capacity at initial reservoir conditions. All costs were evaluated in mid 2009 US$. G&A costs were estimated at $3m per annum in the exploration/appraisal phase. An allowance of $8mm was included for shooting and processing 3D development seismic. On the basis of current rig rates each exploration and appraisal well was estimated to cost $24m. The cost of each production, water injection and gas injection well was estimated to be $26m. These costs include allowances for manifolds, flowlines and risers, plus an allowance for installation. It was assumed that an offshore oilfield would be developed using a purchased FPSO with facilities for oil and gas separation, gas compression, water and gas injection and with adequate oil storage capacity. In addition a number of subsea templates would be used, according to the size of the oil field.

25



It was estimated that the capital cost of such an FPSO with an oil processing capacity of 100,000 bbls/day would be $800m. In setting up the costs of the various reserve cases adjustment was made for higher and lower processing capacities. An allowance was made for the installation of a gas compressor (with a 30mmscf/d capacity) at a cost of $21m each. For the largest field size, and in the case of desiring to sell the associated gas to an onshore power plant rather than re-inject it, additional capital costs would be incurred. It was estimated that a gas production station with a gas processing capacity of 200mmscf/d would cost $90m. A 300km long subsea export pipeline would be required to transport the gas, at $0.5m per kilometre. The total of the development costs estimated for each field size was the basis of the most likely unit development cost mentioned in this report. Operating costs were estimated as follows:

General and Administration costs $3m per annum

FPSO with an oil processing capacity of 100,000 bbls/day, well operation and maintenance $90m per annum. In setting up the costs of the various reserve cases adjustment was made for higher and lower processing capacities.

Gas processing $0.3 per mscf

Condensate and oil processing $0.9 per bbl

Produced water treatment $0.3 per bbl

Injection water treatment $0.3 per bbl The total of the operating costs estimated for each field size in each year was represented as a percentage of the midyear cumulative development cost. When sensitivities are performed on the unit development cost, operating costs change proportionately. The cost of abandonment for each well was estimated at $3m. Abandonment costs were represented as 4.52% of cumulative real terms development expenditure, being the weighted average of the percentages for each field size case.

3.3.2 Offshore Great South Basin - Gas

For all offshore prospects, it was assumed that

An exploration well will be drilled during 2011

Three appraisal wells will be drilled during 2014

3D development seismic will be shot during 2016

In the case of successful appraisal, capital costs are represented to be incurred during 2019-2021 (the data provided assumed a slower development for gas than for oil)

Production and injection well drilling will start during 2020 for the largest three field sizes and 2021 for the smaller two

Production will start on 1 July 2021

Production will be through an offshore platform, of tension leg or wellhead type, according to field size

26



The output from the platform will be piped to North Island

The following assumptions were made when generating production profiles for the development of a gas discovery:

Production from the largest field would exceed local demand and would be converted to LNG.

The reserve sizes modelled were 250, 500, 1125, 2500 and 5000 bcf, based on recoverable volumes including fuel and flare (14.5% for the larger field and 5% for the others).

The recovery factor was assumed as 50%

The CAPEX phasing has a 47-62% spend in the year of first gas and only half a year's production was assumed in that year. This is based on the assumption that facilities/platform installation can be completed in the first half of the year and drilling commenced by end of the second quarter (one year earlier for the largest three fields). It is also assumed that drilling will continue while production is ramped up. Not all wells are required to meet design capacity at initial reservoir conditions. All costs were evaluated in mid 2009 US$. G&A costs were estimated at $3m per annum in the exploration/appraisal phase. On the basis of current rig rates each exploration and appraisal well was estimated to cost $24m. The cost of each production and water injection well was estimated to be $26m. These costs include allowances for manifolds, flowlines and risers, plus an allowance for installation. A gas discovery will be developed using production facilities that include separation and dehydration facilities for gas plus limited condensate handling and storage facilities. Produced water will be cleaned up in an API Separator prior to disposal into the sea or into a nearby aquifer. It was assumed that the two largest gasfields would be developed using a TLP with facilities for gas and condensate separation plus onshore processing. It was estimated that the capital cost of such a TLP would be $1250m for the largest reserve case and $900m for the second largest. For the smallest gas fields, a wellhead platform was assumed plus onshore processing. It was estimated that the capital cost of a 4 leg jacket with onboard dehydration for the 500 bcf case would be $300m. The capital cost for the 250 bcf case was assumed to be $80m, based on a simple wellhead platform. The 1125 bcf case had all its costs interpolated between the 500 and 2500 bcf cases. An export subsea pipeline would be required to transport the gas, costing $0.5m per kilometre. It was estimated that a gas production station with a gas processing capacity of 500mmscf/d would cost $168mm. In setting up the costs of the various reserve cases adjustment was made for lower processing capacities.

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The total of the development costs estimated for each field size was the basis of the most likely unit development cost mentioned in this report, using recoverable reserves including fuel and flare. Operating costs were estimated as follows:

General and Administration costs $3m per annum

TLP (5000 bcf), well operation and maintenance $120m per annum. TLP (2500 bcf), $90m per annum.

Advanced Wellhead platform (500 bcf), well operation and maintenance $75m per annum. For the smallest field size, using an unmanned wellhead platform, $30m per annum

Gas processing $0.3 per mscf

Condensate and oil processing $0.9 per bbl

Produced water treatment $0.3 per bbl

Injection water treatment $0.3 per bbl The total of the operating costs estimated for each field size in each year was represented as a percentage of the midyear cumulative development cost. When sensitivities are performed on the unit development cost, operating costs change proportionately. The cost of abandonment for each well was estimated at $3m, for a TLP $50m and for a wellhead platform $15m. Abandonment costs were represented as 7.185% of cumulative real terms development expenditure, being the weighted average of the percentages for each field size case.

3.4 Price Assumptions

AUPEC analysed data provided by the Ministry on the monthly average New Zealand crude prices and those of Brent and Tapis over the period 2000-2008. It was found that

there is a strong correlation between New Zealand crude prices, expressed in US$/barrel,

and both the Tapis and Brent blends. In recognition of this, and of the fact that the correlation was not perfect, we plotted the New Zealand/Brent crude price ration against the monthly average gravity pf new Zealand crude oil. A very strong correlation was found, but the reverse of the normal one. Low gravity here equals high condensate content rather than high normal light distillate yield. The gravity has been around 0.78 kg/l for the past 1 1/2 years. While New Zealand crude prices have risen relative to Brent at the end of this period, the plot against gravity suggests that parity with Brent is a reasonable assumption as long as this gravity is maintained. This approach was implemented in modelling. We considered US$ 60/bbl to be the most appropriate project screening value for the Brent blend. Upper and lower sensitivities of $80/bbl and $40/bbl were adopted and, as the template for the economic models could accommodate a fourth price, $100/bbl was also investigated. The Ministry had expressed an interest in results at this price, having recently used it in their own studies. To cover a range of possible gas prices consistent with our oil price assumptions we ran economic models at US$ 4, 7, 10 and 13/mscf (60%, 70%, 75% and 78% parity with crude

28



oil respectively) in 2009 terms. To the extent that high oil prices reflect pressure on oil reserves, it is reasonable to expect the market to look more to gas as a replacement fuel under those conditions and for gas prices to move towards thermal parity with oil. New Zealand gas prices are currently low, heavily influenced by abundant supply and by incremental gas production being used as a methanol feedstock. First gas from the notional projects analysed in this study, however, is assumed to occur on 1.7.2021, when production from the Maui field will have declined to the point where New Zealand gas prices should be close to the international levels we have assumed. The above prices (in 2009 US dollars) were applied in the economic models throughout the economic lifetimes of the notional oil and gas developments studied. Project screening values (even the base cases of US$60/bbl and US$7/mscf) are not price forecasts. We are attempting to shadow industry decision making behaviour and to run sensitivity appropriate to our fiscal analysis. Oil and gas companies tend to use real terms discount rates of 10-15% p.a. in evaluating upstream projects, representing their weighted average cost of capital plus a normal level of risk premium if they perceive the need for this. Conditions in New Zealand do not justify a special (higher) risk premium. We have used a discount rate of 10% p.a. in real terms to avoid the risk of recommending unnecessary concessions to the investor.

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4.0 Results of Evaluation of New Zealand Petroleum Tax Regime In this section the results of economic evaluation of potential New Zealand oil and gas fields under the New Zealand fiscal regime are presented, in terms of both development and exploration economics. Bearing in mind the uncertainty as to whether any hydrocarbon find will be oil or gas, it concludes with probabilistic exploration economics combining these two outcomes. The costs and production profiles used have been based on notional developments in the Great South Basin (GSB) because this is expected to have the highest development costs as a consequence of water depths and distance from markets. It is also the most gas prone basin, and gas project economics are poorer than oilfield ones as a result of higher operating costs and of prices below parity with oil. The Great South Basin is not, however, the most disadvantaged in terms of estimated oil and gas resource distributions or of the forecast probability of success for an exploration well (see Table 2, which summarises data provided by the Ministry). It may not therefore be the most conservative case in terms of economic attraction for an exploration company. Table 2. Comparison of New Zealand Basins

Basin Probability of Exploration

Well Success

Probability of Hydrocarbon

Find Being Gas

Average P50 Oil Resource

(million barrels)

Average P50 Gas Resource

(tcf)

Onshore Taranaki 0.28 0.50 26.3 0.322

Offshore Taranaki 0.10 0.48 127.6 0.592

Deepwater Taranaki 0.10 0.48 335.8 1.494

Northland 0.10 0.63 110.3 0.692

Raukumara 0.10 0.54 306 1.29

East Coast 0.05 0.64 83.6 0.489

Canterbury 0.20 0.65 183 0.67

Great South 0.15 0.67 295.8 1.594

Pegasus 0.10 0.47 230.5 1.37

Reinga 0.10 0.55 280.5 1.935

The average P50 resource data above are indicative only, as different resource cut-off points were employed across the basins in determining how many prospects should be included in the averages.

4.1 Oil Development Economics: Pre-Tax Results

Figures 1-4 show the pre-tax development economics for five oilfield sizes, at a range of oil prices and at a range of unit development costs. They indicate the pre-tax real terms net

30



present values (NPVs) in billions (thousand millions) of 2009 US dollars, discounted at 10% per annum in real terms to 1.7.2009. The plots correspond as indicated in the legends to reserve sizes of 40 million barrels, 80, 120, 260 and 400 mmb. In terms of conversion from resources to reserves, these cases assume gas reinjection and a recovery factor of 40%. Figure 1. Pre-Tax Real NPV at 10% p.a. (US$ Billions), GSB Oil at $40/bbl

0

2

4

6

8

10

12

3 5 7 9 11 13 15

Development Cost $/bbl 1.7.2009

40 mmb

80 mmb

120 mmb

260 mmb

400 mmb

Figure 2. Pre-Tax Real NPV at 10% p.a. (US$ Billions), GSB Oil at $60/bbl

0

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40 mmb

80 mmb

120 mmb

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31



At an oil price of $40/bbl, the NPV of the 260 mmb field becomes lower than that of the smaller fields at a unit development cost just above $13/bbl. Figure 3. Pre-Tax Real NPV at 10% p.a. (US$ Billions), GSB Oil at $80/bbl

0

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8

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3 5 7 9 11 13 15


40 mmb

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Figure 4. Pre-Tax Real NPV at 10% p.a. (US$ Billions), GSB Oil at $100/bbl

0

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40 mmb

80 mmb

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Table 3 shows the pre-tax NPVs of the five oilfields at the four oil prices considered and at the most likely unit development cost for each field size. Breakeven oil prices appear to be around $26/bbl for the 40 mmb field, $24/bbl at 80 mmb, $23/bbl for the 120 mmb case, $15/bbl at 260 mmb and $13/bbl for the 400 mmb field. Table 3 Pre-Tax RNPVs (US$ bn) at the Most Likely Unit Development Costs

40 mmb 80 mmb 120 mmb 260 mmb 400 mmb

$/bbl devex 12.45 10.15 8.94 4.72 4.39

$40/bbl 0.23 0.49 0.72 2.20 3.62

$60/bbl 0.55 1.11 1.59 3.94 6.27

$80/bbl 0.88 1.73 2.46 5.69 8.92

$100/bbl 1.21 2.35 3.34 7.44 11.57

At the selected oil prices and given all the other assumptions made, Figures 1-4 and Table 3 contain only positive NPVs before tax. Fiscal terms can therefore be designed that would make GSB oil developments attractive both for the Government and for an investor, as a Government take can be extracted and still leave positive NPVs after tax for the investor. The NPVs measure the potential value generation by fields of these sizes, which is also the economic rent they would provide, available for sharing between the Government and a contractor. At the base case oil price of $60/bbl and at the most likely unit development cost for each field size, the pre-tax NPV ranges from $0.55bn to $6.27bn for reserve sizes from 40 mmb to 400 mmb. Development NPVs are often discounted back to the date of a likely development decision rather than to 1.7.2009, which is nevertheless a suitable reference date for a current review of exploration economics. In this study, however, the situation is complicated by having different first oil and first gas dates, so oil and gas development NPVs and exploration expected monetary values (EMVs) have all been discounted back to 1.7.2009. A first oil date of 1.7.2017 is assumed, with development expenditure on oil projects from 1.1.2015 onwards. Discounting back to a latest decision date of, say, 1.7.2014 and expressing the result in 2014 US dollars would increase the above NPVs by a factor of 1.822 (multiplying by 1.131 in respect of 5 years inflation at 2.5% p.a. and by 1.611 to adjust for having 5 fewer years of discounting at 10% p.a. in real terms). This is based on maintaining the oil price assumptions as stated in 2009 US dollars.

4.2 Oil Development Economics: Post-Tax Results

Figures 5-8 show the post-tax development economics of the five GSB oilfield sizes under the New Zealand fiscal regime that will apply after 31 December 2009. They are based on the ranges of oil prices and of unit development costs used in Figures 1-4. Note that the Y axis scale now runs from -$2 to 8bn rather than from $0 to 12bn. Post-tax NPVs are positive throughout except at $40/bbl. At this oil price the 260 mmb reserve case is uneconomic above a unit development cost of $13.0/bbl, the 400 mmb field above $14.2/bbl and the 120 mmb development above $14.4/bbl. In the pre-tax analysis, the lowest breakeven unit development cost was just above $15/bbl.

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This shift in the breakeven unit development costs towards lower values when tax is taken into account shows that the New Zealand fiscal regime fails to protect the most economically marginal potential developments. Figure 5. Post-Tax Real NPV at 10% p.a. (US$ Billions), GSB Oil at $40/bbl

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Figure 6. Post-Tax Real NPV at 10% p.a. (US$ Billions), GSB Oil at $60/bbl

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The principal cause of this failure is the Ad Valorem royalty because when it is imposed (by virtue of being larger than the alternative Accounting Profits royalty in the relevant fiscal year) this element of the Government take is influenced only by revenues, taking no account of costs.


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The New Zealand fiscal regime is progressive in terms of the relationships between NPV and unit development cost, oil price and (with the minor exceptions noted at $40/bbl combined with high development costs) field size. This does not prove, however, that the tax take in percentage terms is progressive. Table 4 shows the post-tax NPVs of the five oilfields at the four oil prices considered and at the most likely unit development cost for each field size. Breakeven oil prices now appear to be around $29, 27, 26, 16 and 14/bbl in order of increasing field size. This shift of $1-3/bbl towards higher values has the same origin as the change in breakeven unit development costs observed in Figures 1-8. Table 4 Post-Tax RNPVs (US$ bn) at the Most Likely Unit Development Costs

40 mmb 80 mmb 120 mmb 260 mmb 400 mmb

$/bbl devex 12.45 10.15 8.94 4.72 4.39

$40/bbl 0.10 0.23 0.35 1.19 1.98

$60/bbl 0.29 0.59 0.85 2.19 3.49

$80/bbl 0.48 0.94 1.35 3.19 5.00

$100/bbl 0.66 1.30 1.85 4.20 6.53

At the base case oil price of $60/bbl and at the most likely unit development cost for each field size, the post-tax NPV (the potential value generation for the investor) ranges from $0.29bn to $3.49bn for reserve sizes from 40 mmb to 400 mmb. Based on all the assumptions made, development of GSB oilfields is economically attractive to an investor under the New Zealand fiscal regime. We still need, however, to consider the exploration economics and the possibility of finding gas rather than oil. Figures 9-12 show the nominal tax take in percentage terms, i.e. the share of the net cash flow taken by the Government in the form of fees and taxes, making no adjustment for inflation or for the timing of the tax take. Nominal tax take analysis highlights the fundamental structure of a fiscal regime. Note that in order to reveal subtly regressive behaviour the Y axis scales of these figures are highly expanded and run only from 42 to 46%, so that the value of the nominal tax take percentage at the origin is far from zero. At $40/bbl and high unit development costs the fact that 75% of project finance costs (calculated on the basis that these are all interest costs rather than shareholder remuneration) are allowable against income tax plays a significant role for the two largest fields. For the 260 mmb field at $15/bbl unit development cost, for example, total royalty payments are 34.85% of the pre-tax cashflow, and fees 0.05%. Thus if finance costs were not allowable income tax would add 30% of (100% minus 34.9%), i.e. 19.5%. The nominal tax take would then be 54.4% rather than the 42.4% observed in practice.

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Figure 9. Nominal Tax Take (%), GSB Oil at $40/bbl

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Aside from the impact of allowable interest charges at low oil prices, and aided by the very expanded Y axis scales, small regressive effects can be seen in Figures 9-12 whereby the nominal tax take percentage tends to be slightly higher for small fields, at low prices and at high unit development costs. That is, the Government takes a slightly higher percentage of the economic rents the smaller these become. In the hypothetical extreme case where the Accounting Profits royalty (APR) was higher than the Ad Valorem one, and therefore applied, in every fiscal year and interest charges

38



were negligible, cumulative Government take excluding fees would be exactly 44% of the cumulative cashflow (20% APR plus 30% income tax on the remaining 80%). In practice, however, the Ad Valorem royalty (AVR) is bound to apply before the project reaches payback (as the APR will be zero) and again as abandonment approaches (when the margin of revenues over costs is low). As long as a field pays APR at some point in its life, therefore, the nominal government take will be 44% plus the impact of any AVR payments. This effect is responsible for the regressive behaviour observed when it is not overruled by the impact of allowable interest. In the opposite extreme case where the margin of revenues over costs is so low in every year that AVR is charged throughout the field life, the nominal tax take could be very high because AVR takes no account of costs. In the 260 mmb case at $40/bbl and $15/bbl unit development cost analysed above, the overall royalty rate of 34.85% of cashflow was the result of 5 years paying AVR, 5 years of APR, 2 more years paying AVR and one year in which APR relief was obtained against decommissioning costs. Apart from the mild regressive and occasional progressive behaviours described above, arising from the AVR and from allowable interest respectively and both observed under conditions of low profitability, it is tempting to comment that the New Zealand fiscal regime is a very complex way to achieve an essentially proportional nominal tax take of 44%. While the nominal tax take percentage highlights the fundamental structure of a tax regime, it takes no account of the timing of tax payments, or of inflation or other aspects of the time value of money (such as the investor‘s or the Government‘s cost of capital or their potential returns from alternative uses of their funds). The impact of a fiscal regime on an investor‘s project economics is therefore best studied using the present value (PV), or discounted, real terms Government take percentage. This percentage also allows us directly to rationalise the difference between pre-tax and post-tax NPVs. Figures 13-16 show the real present value tax take (at 10% p.a. discount rate) as a percentage of the pre-tax real net present value (also at 10%). Note that the Y axis scale has been changed from the 42-46% of Figures 9-12 to 40-100%, and that once again it is not zero at the origin. These figures show that the mild regressive behaviour demonstrated, with the help of an expanded scale, in Figures 9-12 is significantly magnified in discounted terms. Indeed, there are cases at an oil price of $40/bbl where the discounted Government take exceeds 100%, corresponding to the negative post-tax NPVs in Figures 5-8. When there is a relatively high early Government share in a field‘s net cashflow, occasioned for example by AVR payments or to a lesser extent by depreciation of capital costs when calculating income tax liabilities, there is a relatively large impact on the investor‘s project economics through the operation of discounting in order to recognise the time value of money. Earlier tax payments are discounted for fewer years and are therefore larger in discounted terms than later tax payments of a similar magnitude.

39



Figure 13. Real Present Value Tax Take (%), GSB Oil at $40/bbl

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It should perhaps be highlighted at this point that a discount rate of 10% p.a. in real terms is used in this report. Oil and gas companies typically use 10-15% p.a. real terms for their upstream and perhaps for all their project evaluations. In comparison with 15% p.a., use of 10% p.a. is not conservative from the Government standpoint, in the sense that it could lead to an undue level of comfort when considering investor‘s perceptions. At 15% p.a., discounted Government takes of more than 100% would have been reached at lower unit development costs in Figures 13-16 and negative NPVs earlier in Figures 5-8.

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On the other hand, framing fiscal policies around project economics conducted at 15% p.a. would risk conceding too much to those investors who are happy to apply 10% p.a. in their economic evaluations. This is our principal motive in adopting 10%. As almost all fiscal regimes involve some element of accelerated Government take (that is, earlier than the component of the pre-tax cashflow from which it arises), a progressive fiscal regime is generally required in nominal percentage Government take terms in order to ensure even a proportional (neutral or ―flat‖) fiscal regime on the discounted basis.

4.3 Oil Exploration Economics: Pre-Tax Results

Figure 17 shows the decision tree used in the oil exploration economics conducted for the GSB. For the time being we have to maintain the fiction that an explorer there can be sure that any hydrocarbons found will be oil rather than gas. Then, when we have produced parallel results for gasfield development and gas exploration economics, we can combine the oil and gas results using the oil and gas probabilities from Table 2. The Ministry provided P10 and P50 resource distributions for both oil and gas in the GSB. These were power law distributions, so that if ranked, resources would be x, x/2, x/3, etc. In order that the P10 data could be utilised, P90 data were generated based on the clear pattern existing at the P10 and P50 levels. Weightings of 20% were then applied to the P10 data (representing the range P0 to P20) and to the P90 distribution (representing the range P80 to P100), and one of 60% to the P50 data (representing the range P20 to P80). Figure 17. Decision Tree for Oil Exploration in the Great South Basin

Shoot seismic

and drill one

exploration

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Failure

(dry well)

85%

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NPV(260)

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Appraisal drilling

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15%

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51.25%

Development

Great South Basin: Oil (33% prob.)

42



Development data (costs and production profiles) were also provided, for resource cases corresponding to reserves of 400, 260, 80 and 40 mmb at a 40% recovery factor. Adequate representation of the combined resource distribution (based on the P10, P50 and P90 weightings described above) required a fifth case at reserves of around 120 mmb so this was generated in a manner consistent with the other cases. Matching these cases to the resource distribution in as representative a way as possible resulted in the probabilities shown in Figure 17 against the NPVs that correspond to the individual reserve levels. Using the above decision tree, the pre-tax expected monetary values (EMVs) are as displayed in Figure 18. The scale is now in millions of 2009 US dollars. The EMVs are plotted against the unit development cost at the oil prices shown in the legend. The weighted average unit development cost of the five cases, using the weightings shown in Figure 17, is a little under $11/bbl. Thus, under the temporary fiction that we can be sure that any hydrocarbon found will be oil and under all the other assumptions made, exploration including the drilling of one well is economically attractive in pre-tax terms even at an oil price of $40/bbl. The EMV at a unit development cost of $11/bbl is $29m at an oil price of $40/bbl, $129m at the base case oil price of $60/bbl, $229m at $80/bbl and $330m at $100/bbl. It is therefore possible to construct a fiscal regime that will maintain a positive EMV after tax at oil prices down to about $34/bbl (where the pre-tax NPV at $11/bbl unit development cost is estimated to be zero).

Figure 18. Pre-Tax Expected Monetary Value (10%), US$ Millions, GSB Oil

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4.4 Oil Exploration Economics: Post-Tax Results

Figure 19 shows the post-tax EMVs under the New Zealand fiscal regime. Figure 19. Post-Tax Expected Monetary Value (10%), US$ Millions, GSB Oil

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Under the temporary fiction that we can be sure that any hydrocarbon found will be oil, and given all the other assumptions made, exploration including the drilling of one well is economically attractive under the New Zealand fiscal regime at oil prices down to $41/bbl (the post-tax EMV is -$3m at $40/bbl and $11/bbl unit development cost, and $54m at the base case oil price of $60/bbl). The increase in the breakeven oil price from $34/bbl to $41/bbl when tax is taken into account is the result of the New Zealand fiscal regime failing to protect the most marginally economic fields (marginal on the pre-tax basis). For companies operating under a licence that only requires seismic to be shot and processed, exploration is more attractive economically, as only the seismic costs would be a firm commitment under their version of the decision tree. A well must eventually be drilled, however, to determine the presence or otherwise of hydrocarbons, and if present whether they are oil or gas. Shooting and processing seismic cannot directly generate income. It must be stressed that the decision tree above and the resulting EMVs are based on a certainty of any hydrocarbon that is found being oil rather than non associated gas. This cannot be known before the first exploration well is drilled, so final conclusions on exploration economics must be left until the possibility of a gas find is considered below.

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4.5 Gas Development Economics: Pre-Tax Results

Figures 20-23 show the pre-tax development economics for five gasfield sizes, at a range of gas prices and at a range of unit development costs. They indicate the pre-tax real terms net present values (NPVs) in billions (thousand millions) of 2009 US dollars, discounted at 10% per annum in real terms to 1.7.2009. Note that the Y axis scale now runs from -4 to 6 billion dollars, whereas for oil it was $0 to 12bn. Gas economics suffer from prices below parity with oil on a heat content basis and from higher operating costs. Figure 20. Pre-Tax Real NPV at 10% p.a. (US$ Billions), GSB Gas at $4/mscf

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The plots correspond as indicated in the legends to reserve sizes of 250 billion cubic feet, 500, 1125, 2500 and 5000 bcf. In terms of conversion from resources to reserves, these cases assume a recovery factor of 50%. At a gas price of $4/mscf, the 250 bcf field is uneconomic in pre-tax terms at unit development costs above $1.20/mscf, the 500 bcf case above $1.23/mscf, the 1125 bcf field above $0.83/mscf, the 2500 bcf case above $0.76/mscf and the 5000 bcf field above $0.62/mscf. The bend in the plot for the 5000 bcf field at a gas price of $4/mscf is caused by the presence of cases that are so uneconomic in all years with potential production that no gas is produced. As the unit development cost is increased, so is the unit decommissioning cost as this is modelled proportionately, but there is no incremental operating cost in contrast to the steeper part of the plot, where there is production and therefore also opex. At the base case gas price of $7/mscf, the 250 and 500 bcf fields are economic before tax over the whole range of unit development costs modelled, the 1125 bcf case is uneconomic above $1.42/mscf, the 2500 bcf field above $1.30/mscf and the 5000 bcf case above $1.05/mscf.

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Figure 21. Pre-Tax Real NPV at 10% p.a. (US$ Billions), GSB Gas at $7/mscf

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At a gas price of $10/mscf, the 250, 500 and 1125 bcf fields are economic in pre-tax terms over the whole range of unit development costs modelled, the 2500 bcf case is uneconomic above $1.84/mscf, and the 5000 bcf field above $1.49/mscf.

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At a gas price of $13/mscf, all five field sizes are economic before tax over the whole range of unit development costs evaluated, though only just in the case of the largest field. Table 5 shows the pre-tax NPVs of the five gasfields at the four gas prices considered and at the most likely unit development cost for each field size. Breakeven gas prices are approximately $4.7, 5.4, 6.5, 3.5 and 4.5/mscf in increasing order of field size. Table 5 Pre-Tax RNPVs (US$ bn) at the Most Likely Unit Development Costs

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$/mscf devex 1.53 1.62 1.32 0.67 0.69

$4/mscf -0.03 -0.12 -0.34 0.13 -0.27

$7/mscf 0.10 0.14 0.07 0.88 1.42

$10/mscf 0.22 0.41 0.49 1.62 3.11

$13/mscf 0.35 0.68 0.91 2.37 4.80

At its most likely unit development cost, only the 2500 bcf field is economic before tax at a gas price of $4/mscf. The 5000 bcf field has a similar development cost per mscf of gas recovered at the wellhead (economies of scale being offset by the need for an LNG plant) but it has higher operating costs and an additional 9.5% consumption of recovered gas as fuel for the liquefaction process. The output of this field would be too large for the New Zealand gas market, even allowing for the rundown in Maui production. At the other gas prices modelled, all five field sizes are economic in pre-tax terms at their most likely unit development costs. Development NPVs are often discounted back to the date of a likely development decision rather than to 1.7.2009, which is nevertheless a suitable reference date for a current

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review of exploration economics. In this study, however, the situation is complicated by having different first oil and first gas dates. A first gas date of 1.7.2021 is assumed, with development expenditure on gas projects from 1.1.2019 onwards. Discounting back to a latest decision date of, say, 1.7.2018 and expressing the result in 2018 US dollars would increase the above NPVs by a factor of 2.945 (multiplying by 1.249 in respect of 9 years inflation at 2.5% p.a. and by 2.358 to adjust for having 9 fewer years of discounting at 10% p.a. in real terms). This is based on maintaining the gas price assumptions as stated in 2009 US dollars.

4.6 Gas Development Economics: Post-Tax Results

Figures 24-27 show the post-tax development economics of the five GSB gasfield sizes under the New Zealand fiscal regime that will apply after 31 December 2009. It is based on the ranges of gas prices and of unit development costs used in Figures 20-23. Note that the Y axis scale now runs from -$4 to 4bn rather than -$4 to 6bn. At a gas price of $4/mscf, the 250 bcf field is uneconomic in post-tax terms at unit development costs above $1.10/mscf, the 500 bcf case above $1.13/mscf, the 1125 bcf field above $0.77/mscf, the 2500 bcf case above $0.70/mscf and the 5000 bcf field above $0.58/mscf. Breakeven unit development costs have fallen by $0.04-0.1/mscf when tax is taken into account. Figure 24. Post-Tax Real NPV at 10% p.a. (US$ Billions), GSB Gas at $4/mscf

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At the base case gas price of $7/mscf, the 250 bcf field is uneconomic after tax at unit development costs above $1.88/mscf, the 500 bcf case is economic at all unit development costs evaluated, the 1125 bcf field is uneconomic above $1.32/mscf, the 2500 bcf case above $1.20/mscf and the 5000 bcf field above $0.99/mscf.

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Identified breakeven unit development costs have fallen by $0.06-0.1/mscf after taking account of tax. Figure 25. Post-Tax Real NPV at 10% p.a. (US$ Billions), GSB Gas at $7/mscf

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Figure 26. Post-Tax Real NPV at 10% p.a. (US$ Billions), GSB Gas at $10/mscf

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$1.39/mscf. Identified breakeven unit development costs have fallen by $0.1-0.15/mscf after tax. Figure 27. Post-Tax Real NPV at 10% p.a. (US$ Billions), GSB Gas at $13/mscf

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At a gas price of $13/mscf, the smallest four field sizes are economic after tax over the whole range of unit development costs evaluated but the 5000 bcf field is uneconomic above $1.80/mscf unit development cost. Before tax the breakeven was above $1.9/mscf, tax causing a reduction of at least $0.1/mscf. All the quantified economic break-even points have moved to lower unit development cost levels after accounting for tax, so given a sufficiently large number of potential projects more of them would fail to be developed following a rigorous post-tax analysis. This shows that the New Zealand fiscal regime fails to protect the most economically marginal potential developments. As was the case for oilfields, the principal cause is the Ad Valorem royalty. When this is imposed (by virtue of being larger than the alternative Accounting Profits royalty in the relevant fiscal year) this element of the Government take is influenced only by revenues, so takes no account of costs.

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Table 6 shows the post-tax NPVs of the five gasfields at the four gas prices considered and at the most likely unit development cost for each field size. Breakeven gas prices are approximately $5.3, 5.8, 7.0, 3.8 and 4.8/mscf in order of increasing field size. The shift of $0.3-0.6/mscf towards higher breakeven prices when tax is taken into account has the same origin as the changes in breakeven unit development cost in Figures 20-27. Table 6 Post-Tax RNPVs (US$ bn) at the Most Likely Unit Development Costs

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$/mscf devex 1.53 1.62 1.32 0.67 0.69

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$10/mscf 0.12 0.21 0.24 0.88 1.67

$13/mscf 0.19 0.36 0.48 1.30 2.63

At its most likely unit development cost, only the 2500 bcf field is economic after tax at a gas price of $4/mscf. At the base case gas price of $7/mscf, the 1125 bcf case is on the balance point with an NPV 10% of zero at its most likely unit development cost but the other four field sizes have positive NPVs. At $10 and $13/mscf all five cases are economic at their most likely unit development costs. The potential value generation for the investor ranges from $0 to 0.7bn for reserve sizes from 250 bcf to 5000 bcf, at the base case gas price of $7/mscf and at the most likely unit development costs. Comparable NPVs for the five oilfields were $0.29 to 3.49bn, almost five times greater at the high reserve end of the range, for reserves that are less than half as large in thermal equivalent terms. Even at $13/mscf and $100/bbl the NPV of the largest oilfield is 2.5 times that of the largest gasfield at their respective most likely unit development costs. While the distribution of negative and positive (or zero) NPVs is the same in Tables 5 and 6, which are based on the most likely unit development costs, there are instances in Figures 24-27 where NPVs that were positive in Figures 20-23 have become negative. This is the counterpart of the reductions in breakeven unit development costs and increases in breakeven prices already noted. Based on all the assumptions made, development of GSB gasfields at the base case price ranges from just acceptable to economic for an investor under the New Zealand fiscal regime, but the contrast in terms of value generated (NPVs) with the results for oilfields is instructive. At this stage in the basin‘s development, however, we still need to consider the exploration economics for gas and combine the results with those for oil in accordance with the relative probabilities of finding each. For gas as for oil, the New Zealand fiscal regime is progressive in terms of the relationships between NPV and unit development cost, hydrocarbon price and (except at high unit development cost) field size. This does not prove, however, that the tax take in percentage terms is progressive in the case of gasfields. Figures 28-31 show the nominal tax take in percentage terms, i.e. the share of the cash flow taken by the Government in the form of fees and taxes, making no adjustment for

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inflation or for the timing of the tax take. As the data for the 250 and 500 bcf fields are virtually identical, they are represented by a single plot in these figures. Nominal tax take analysis reveals the fundamental structure of a fiscal regime. In contrast to the case with oilfields, effects associated with very low profitability obscure the general tendency in the New Zealand fiscal regime towards very mild regressiveness.

Figure 28. Nominal Tax Take (%), GSB Gas at $4/mscf

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At $4/mscf and at unit development costs close to the economic breakeven point, the fact that 75% of interest charges are allowable against income tax plays a significant role, as it did for a few extreme oilfield cases. For the 2500 bcf field at $1.15/mscf unit development cost, for example, total royalty payments are 22.38% of the pre-tax cashflow, and fees 0.04%. Thus if interest charges were not allowable income tax would add 30% of (100% minus 22.42%), i.e. 23.27%. The nominal tax take would then be 45.65% rather than the 1.10% observed in practice. This particular case has very large interest costs, accumulating at the point of abandonment to more than twice the cumulative pre- tax cashflow. Note that interest costs do not appear in the pre-tax cashflow for economic evaluation purposes, because the investor‘s cost of capital (combining both interest costs and those of shareholder remuneration) is modelled within the discount rate rather than in the cashflow. When they are allowable against one or more of the relevant taxes, however, tax relief against interest costs appears in the after tax cashflow. We have assumed an interest rate of 7% p.a. While under normal economic conditions this might apply to a large, well established oil or gas company with a good track record and credit rating when base rate was, say, 5% p.a., consideration of the current difficulties in raising finance led us to maintain the 7% p.a. borrowing rate even though base rates are well below 5% p.a.

52



As the situation normalises, which should occur well within the exploration and appraisal phase of the notional oil and gas projects under review, inflation rates and base rates should rise and 2.5% p.a. inflation and a 7% p.a. interest rate should be reasonable long term assumptions. The internal rate of return of the extreme case in Figure 28 is only 4.9% p.a. in nominal terms, which is why it never repays borrowing at 7% p.a.


0

20

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60

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


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1125 bcf

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5000 bcf


0

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53




0

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


250 / 500

1125/2500

5000 bcf

At gas prices of $10 and 13/mscf, the plots for the 1125 and 2500 bcf gasfields become indistinguishable on the scale of Figures 30 and 31, so they too have been combined into one. While the nominal tax take percentage highlights the fundamental structure of a tax regime, it takes no account of the timing of tax payments, or of inflation or other aspects of the time value of money (such as the investor‘s or the Government‘s cost of capital, or potential returns from alternative uses of their funds). The impact of a fiscal regime on an investor‘s project economics is therefore best studied using the present value (PV), or discounted, real terms Government take percentage. This percentage also allows us directly to rationalise the difference between pre-tax and post-tax NPVs. Figures 32-35 show the real present value tax take (at 10% p.a. discount rate) as a percentage of the pre-tax real net present value (10%). Note that the Y axis scale is now 40-100% as for the oilfield cases, so that it is not zero at the origin. The generally very mild progressive behaviour demonstrated by gasfields, as a result of the impact of allowable interest costs overriding the Ad Valorem royalty effect seen in the oilfield cases with their greater profitability, is dramatically overturned when the percentage tax take calculation is performed in discounted terms. Indeed, there are cases at all the gas prices evaluated where over a greater or smaller range of unit development costs the discounted Government take exceeds 100%, corresponding to the negative post-tax NPVs in Figures 24-27.

54



Figure 32. Real Present Value Tax Take (%), GSB Gas at $4/mscf

40

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70

80

90

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


250 bcf

500 bcf

1125 bcf

2500 bcf

5000 bcf


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500 bcf

1125 bcf

2500 bcf

5000 bcf

55




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0.4 0.65 0.9 1.15 1.4 1.65 1.9


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When there is a relatively high early Government share in a field‘s net cashflow, occasioned for example by AVR payments or to a lesser extent by depreciation of capital costs when calculating income tax liabilities, there is a relatively large impact on the investor‘s project economics through the operation of discounting in order to recognise the time value of money. Earlier tax payments are discounted for fewer years and are therefore larger in discounted terms than later tax payments of a similar magnitude.

56



As almost all fiscal regimes involve some element of accelerated Government take (that is, earlier than the component of the cash flow giving rise to the tax), a progressive fiscal regime is generally required in nominal Government take percentage terms in order to ensure even a proportional (neutral or ―flat‖) fiscal regime on the discounted basis.

4.7 Gas Exploration Economics: Pre-Tax Results

Figure 36 shows the decision tree used in the gas exploration economics conducted for the GSB. We now have to temporarily maintain the fiction that an explorer there can be sure that any hydrocarbons found will be gas rather than oil. We can then combine the oil and gas results using the oil and gas probabilities from Table 2. The Ministry provided P10 and P50 resource distributions for both oil and gas in the GSB. These were power law distributions, so that if ranked, resources would be x, x/2, x/3, etc. In order that the P10 data could be utilised, P90 data were generated based on the clear pattern existing at the P10 and P50 levels. Weightings of 20% were then applied to the P10 data (representing the range P0 to P20) and to the P90 distribution (representing the range P80 to P100), and one of 60% to the P50 data (representing the range P20 to P80). Figure 36. Decision Tree for Gas Exploration in the Great South Basin

July 9, 2009 slide 3

Shoot seismic

and drill one

exploration

well

Failure

(dry well)

85%

NPV(5000)

NPV(2500)

NPV(1125)

NPV(500)

NPV(250)

Success

Appraisal drilling

(3 wells)

15%

$28.55m PV

@10% p.a.

(pre-tax)

$55.39m PV @10%

p.a. (pre-tax)

1.5%

1.5%

21%

16%

60%

Development

Great South Basin: Gas (67% prob.)

Development cases (costs and production profiles) were also provided, for resource cases corresponding to reserves of 250, 500, 2500 and 5000 bcf at a 50% recovery factor. Adequate representation of the combined resource distribution (based on the P10, P50 and P90 weightings described above) required a fifth case at reserves of around 1125 bcf so this was generated in a manner consistent with the other cases. Matching these cases to the resource distribution in as representative a way as possible resulted in the

57



probabilities shown in Figure 36 against the NPVs that correspond to the individual reserve levels. Using the above decision tree, the pre-tax Expected Monetary values (EMVs) are as displayed in Figure 37. Figure 37. Pre-Tax Expected Monetary Value (10%), US$ Millions, GSB Gas

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-50

0

50

100

150

0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/mscf

$7/mscf

$10/mscf

$13/mscf

The scale is now in millions of 2009 US dollars. The EMVs are plotted against the unit development cost at the gas prices shown in the legend. The weighted average unit development cost of the five cases, using the weightings shown in Figure 36, is approximately $1.4/mscf. Thus, under the temporary fiction that we can be sure that any hydrocarbon found will be gas and under all the other assumptions made, exploration including the drilling of one well is economically attractive in pre-tax terms at a gas price of $10 or $13/mscf but not at $4 or $7/mscf (the latter being the base case). The break-even gas price is approximately $9.1/mscf.

4.8 Gas Exploration Economics: Post-Tax Results

Figure 38 shows the post-tax EMV under the New Zealand fiscal regime. Under the temporary fiction that we can be sure that any hydrocarbon found will be gas and given all the other assumptions made, exploration including the drilling of one well is only economically attractive after tax under New Zealand‘s fiscal system at a gas price of $13/mscf and not at $4, 7 or 10/mscf. The breakeven point is now at approximately $11.2/mscf. The shift in the breakeven gas price from $9.1 to 11.2/mscf when tax is taken into account is the result of the failure of the New Zealand fiscal regime to protect the most marginally economic fields (marginally economic on the pre-tax basis).

58



Because we are assuming in this report that an investing company‘s income tax status will be that of an existing income tax payer in New Zealand, and because income tax is not ring fenced around fields in that jurisdiction, this is a rare example where a negative pre-tax EMV can become smaller after tax. Income tax relief against E&A costs is assumed to be available elsewhere in the investor‘s New Zealand operations without having to wait for an uncertain positive income (after brought forward losses) to arise in the prospect or potential field represented by one of our notional oil or gas cases. Figure 38. Post-Tax Expected Monetary Value (10%), US$ Millions, GSB Gas

-80

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/mscf

$7/mscf

$10/mscf

$13/mscf

For companies operating under a licence that only requires seismic to be shot and processed, exploration is more attractive economically, as only the seismic costs would be a firm commitment under their version of the decision tree. A well must eventually be drilled, however, to determine the presence or otherwise of hydrocarbons, and if present whether they are oil or gas. Shooting and processing seismic cannot directly generate income.

4.9 Combined Oil and Gas Exploration Economics: Pre-Tax Results

Figure 39 shows the combined pre-tax EMV for the GSB, using the assumed 67% probability of finding gas and 33% probability of finding oil in successful exploration wells. The EMVs are plotted against matched oil and gas unit development costs at the oil and gas prices shown in the legend. At the base case prices of $60/bbl and $7/mscf and at the weighted average most likely unit development costs of $11/bbl and $1.4/mscf the probabilistic combined oil and gas pre-tax EMV for exploration in the GSB including drilling one well is modestly attractive at $26m.

59



Figure 39. Overall Pre-Tax Expected Monetary Value (10%), US$ Millions, GSB

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250

3 5 7 9 11 13 15

0.4 0.65 0.9 1.15 1.4 1.65 1.9

Development Cost $/bbl, $/mscf 1.7.2009

$40 / $4

$60 / $7

$80 / $10

$100/$13

4.10 Combined Oil and Gas Exploration Economics: Post-Tax Results

Figure 40 shows the combined post-tax EMV under the New Zealand fiscal regime, using the assumed 67% probability of finding gas and 33% probability of finding oil in successful exploration wells in the GSB. At the base case prices of $60/bbl and $7/mscf and at the weighted average most likely unit development costs of $11/bbl and $1.4/mscf the probabilistic combined oil and gas EMV for the GSB is marginally uneconomic at -$1.5m after tax. The positive pre-tax EMV of $26m demonstrates that it would be possible to modify the New Zealand fiscal regime in the direction of reduced Government take and achieve a modest but positive post-tax EMV under base case assumptions for the GSB. Exploration including drilling one well would then be modestly attractive rather than marginally unattractive from the investor‘s economic standpoint. Any such change could be compensated for, on a probabilistic basis, by instituting a system that achieved a higher percentage government take when economic rents were particularly high. This would require a progressive rather than the current broadly proportional fiscal regime, such as maintaining the existing income tax arrangements together with a reduced level of AVR and an APR based on the pre- or post-AVR rate of return achieved by the investor within each individual oil or gasfield.

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Figure 40. Overall Post-Tax Expected Monetary Value (10%), US$ Millions, GSB

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-50

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150

3 5 7 9 11 13 15

0.4 0.65 0.9 1.15 1.4 1.65 1.9


$40 / $4

$60 / $7

$80 / $10

$100/$13

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5.0 Main Conclusions and Recommendations from Evaluation of the New Zealand Regime

This section is intended to summarise the conclusions and recommendations arising from the stand alone evaluation (in Section 4.0) of the New Zealand fiscal regime that will operate after 31 December 2009. That is, without any input at this point from the evaluation of comparator regimes that is to follow in Section 6.0 and be summarised in Section 7.0.

5.1 General Observations

The economic evaluation in Section 4.0 is based on exploration and development in the Great Southern Basin (GSB). AUPEC was provided by the Ministry with oil and gas resource, production profile and cost assumptions for use in economic modelling. A series of email and telephone discussions during the modelling process resulted in progressive refinement of the data. Basing the study on the GSB is a conservative approach in some respects (relatively high project costs and high gas proneness) but not in others (resource size distribution and probability of exploration drilling success). The position with regard to project costs suggests that the development economics may be conservative in the context of New Zealand basins as a whole, but taking all the situations together the way that those development economics have been utilised in generating the exploration economics may be relatively balanced. Oil and gas companies typically use real terms discount rates of 10-15% p.a. in their economic evaluations of potential upstream investments. We have used a discount rate of 10% p.a. in real terms in order to minimise the risk of advising the Ministry to make excessive concessions to the industry. This does have the consequence, however, that some potential investors may have a poorer perception of the attractiveness of New Zealand‘s basins than the one we have presented. We have assumed that a potential investor will already be an income tax payer in New Zealand, and we make a corresponding assumption when we come to evaluate the performance of selected regional fiscal regimes under New Zealand conditions. An investing organisation that is not an existing income tax payer will have less favourable timing of relief against some costs, and therefore lower NPVs and EMVs.

5.2 Conclusions and Recommendations: Oil Projects

Oilfield developments appear economically attractive over the whole range of assumptions employed in this study, except at an oil price below US$ 40 per barrel in 2009 terms. At this price, negative net present values (NPVs) at 10% p.a. real terms discount rate begin to appear at high unit development costs. This is true on both the pre-tax and the post-tax basis, but negative NPVs (10%) intrude at lower unit development costs post-tax. The pre-tax NPVs measure the potential value generation by fields of these sizes, which is also the economic rent they would provide, available for sharing between the Government

62



and a contractor. At the base case oil price of $60/bbl and at the most likely unit development cost for each field size, the pre-tax NPV ranges from $0.55bn to $6.27bn for reserve sizes from 40 mmb to 400 mmb. The potential post-tax value generation for the investor ranges from $0.29bn to $3.49bn the same range of reserve sizes at the base case oil price of $60/bbl and at the most likely unit development costs. The New Zealand fiscal regime fails to protect the most economically marginal oil projects, a fact evidenced by the shift towards lower break-even unit development costs when tax is accounted for. However, given the wide range of investigated assumptions that resulted in economic oilfields it is likely that only a small proportion of potential projects would as a result be left undeveloped at oil prices above $40/bbl. There is nevertheless a strategic argument in favour of protecting marginal fields even under these circumstances. Allowing fields that are economically marginal on a stand-alone basis to be developed in a timely fashion permits fields that are sub-economic using their own export facilities to be tied in to them. Fiscal changes to protect marginal oilfields could therefore be seen as a ―pump priming‖ or ―seed corn‖ measure in a frontier basin, which means virtually all of New Zealand except Onshore Taranaki. As seen through the evaluation of oilfields, the structure of the New Zealand fiscal regime is very mildly regressive in terms of the nominal Government take percentage at low oil prices, high unit development costs and small field sizes. This is largely due to the impact of the Ad Valorem royalty. Protection of some marginally economic oilfields (marginal on the pre-tax basis) could be achieved by a reduction in the rate of AVR. The comment about mildly regressive behaviour could, however, equally be expressed by the statement that the nominal Government take is virtually proportional at a little over 44%. In these circumstances we might normally advocate a progressive fiscal regime that permitted a higher government take from the most profitable oilfields (those with the highest economic rent) but in this case a better strategy may be to introduce measures aimed at protecting marginal fields first and at a later stage to introduce measures that target high economic rents (see our further conclusions in Section 7.0, following our evaluation of the comparator regional regimes). Also, the need to maintain significant positive NPVs in oil developments will become clearer when we combine oil and gas development economics via the discussion of exploration (Section 5.4 below). A possible route to introducing a progressive system without wholesale change would be to convert the APR into a rate of return based royalty, perhaps with two rate of return thresholds and two royalty rates. To avoid iterative calculations of the post-APR rate of return, a system based on the rate of return achieved up to and including the previous fiscal year would be sufficient. As income tax operates symmetrically on all components of the cashflow except depreciated capex, a simple system based on cashflows before income tax would probably also be adequate, but this should be tested by modelling. If a progressive fiscal regime were to be introduced, care should be taken to compensate potential investors with changes at the marginal end of oilfield economics, such as a reduction in the Ad Valorem royalty, or to have made such a change at an earlier date. New Zealand‘s average competitiveness would not then be damaged over the whole sequence of fiscal changes. The possibility of a two stage approach, starting with concessions for marginal fields, has already been mentioned. Maintaining the average

63



competitiveness could be expressed as maintaining the discounted Government take on an expectation (probabilistic) basis, but introducing such a progressive regime would not be entirely neutral in that it implies the Government taking a greater share in the project risk than it has to date. The discounted (present value) Government take percentage, which indicates the impact on investor economics rather than the fundamental structure of the fiscal regime, is significantly more regressive than the nominal one, especially when oil prices as low as $40/bbl are reached. Indeed, this percentage begins to exceed 100% at this price, which is responsible for the onset of negative NPVs. Relatively large Government takes early in the field life are the reason for discounted Government take percentages that are larger than the nominal ones. In New Zealand the Ad Valorem royalty is largely responsible, with a small contribution from the depreciation of capital costs for income tax purposes. To counter the effect of the investor‘s cost of capital, and hence the need to discount in order to reflect the time value of money, a progressive fiscal regime is generally required in nominal Government take terms in order to achieve even a proportional one in discounted terms. AUPEC recommends that the Government of New Zealand gives consideration to this, but this would only be urgent in the case of oilfields if and when a prolonged period of low oil prices were forecast. Given the current uncertainty as to whether oil or gas will be found by any successful exploration well, conclusions and recommendations arising from oil exploration economics can only usefully be discussed jointly with those for gas.

5.3 Conclusions and Recommendations: Gas Projects

In contrast to the situation with oilfields, gasfield developments only appear economically attractive on a pre-tax basis, over the whole range of field sizes and unit development costs employed in this study, at the very high gas price of $13/mscf. This price would be consistent with oil at $100/bbl and with New Zealand reaching current international levels of gas price parity by 2020. Relatively high operating costs in gasfields are largely to blame for this low profitability, compounded by their long production plateaux (which defer revenues in comparison with oilfields) and the lack of gas price parity with oil. The pre-tax profitability situation suggests that special fiscal terms for gas are desirable in order to minimise the number of potential developments made uneconomic by the tax system. The preferred route to encourage gas developments is reduction in the Ad Valorem royalty rate. Further modelling would be required in order to determine any need to modify the standard income tax regime for the benefit of gas projects or to change the Accounting Profits royalty, and both of these taxes have the advantage of being proportional, apart from the minor impact in discounted terms of depreciating capex for income tax purposes. The same shift to lower break-even unit development costs is observed on the post-tax basis as for oil, but as a smaller range of assumptions leads to gasfields being economic on the pre-tax basis, this may represent a much larger proportion of potentially economic marginal gasfields that fail to be developed even when they are acceptable before tax. Removal of regressive fiscal behaviour is the key to protecting economically marginal projects, and this is a major factor in the preference for reducing the Ad Valorem royalty for gas.

64



There is, however, evidence of progressive behaviour in the nominal Government take percentage at very low gas prices and high unit development costs, particularly affecting the larger gasfields. This may be a feature of vey low profitability in general and may accidentally not have been observed for oilfields, or it may be related to the difference in cost and production profiles between the two field types. As the only progressive element within the current New Zealand fiscal regime, this behaviour should be protected. The underlying mechanism is related to the fact that interest costs are allowable against income tax, subject to a thin capitalisation limit of 75%. For international taxation reasons it is very important that one New Zealand oil and gas tax should give relief against interest costs, but care should be exercised even if considering reducing the thin capitalisation limit in case this further damages the economics of gasfields and perhaps very marginal oilfields. While the argument that there is generally a virtually proportional nominal Government take could be used for gasfields, as for oil, in support of a progressive fiscal system, there are no high economic rents available to be exploited in the case of gas. The issue with gasfields is the protection of marginally economic prospects. The discounted (present value) Government take percentage, which indicates the impact on investor economics rather than the fundamental structure of the fiscal regime, is highly regressive for gasfields. Indeed, the chart for gas at the very high price of $13/mscf (Figure 35) looks very much like that for oil at the low price of $40/bbl (Figure 13). This may be why the allowable interest effect was not detected in our evaluation of oilfields, i.e. the range of profitability available for oil developments meant that we did not investigate them at sufficiently low profitability levels.

5.4 Conclusions and Recommendations: Exploration

At the base case hydrocarbon prices and the other assumptions adopted in this report, the economic attraction of exploration in the GSB, when it involves the drilling of a well in addition to seismic studies, is very modest in pre-tax terms and marginal on the wrong side of profitability in after tax terms. This suggests that corrective action needs to be taken unless there is a sustained increase in hydrocarbon prices such that $7/mscf and $60/bbl are no longer reasonable base cases, with particular emphasis on the gas price in the GSB and other gas prone basins. As the current oil/gas find uncertainty means that both types of development economics have to be included when calculating exploration economics, any special fiscal measures applied to gas developments will feed through to improving the attraction of exploration in general. Changes to the fiscal arrangements for oilfields may not therefore be a necessity in this context. However, the counterpart of fiscal changes for gas perhaps being sufficient is that any attempt to target the economic rents of highly profitable oilfields might have a very negative impact on the economic attraction of exploration. It is important that the Government should not be misled by activity levels under licences that only involve commitments to seismic work. A well has to be drilled at some point in order to prove the presence or otherwise of hydrocarbons and, if present, their nature. Seismic work generates potentially valuable information but only drilling offers the direct

65



prospect of income. The level of exploration drilling should therefore be the basis of any assessment of investor interest in a given New Zealand basin that is carried out in order to inform fiscal policy.

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6.0 Comparison with Other Petroleum Fiscal Regimes

6.1 Introduction

In order to rationalise the levels of exploration activity in New Zealand and the comparator countries AUPEC would need to have resource, chance of success, gas proneness, cost and production data for each country and then apply the local fiscal regimes. It is important to note that fiscal regimes are usually targeted on the particular costs and prospectivity conditions of the country in question. As data in the required level of detail is currently only available for New Zealand‘s Great South Basin (GSB), AUPEC‘s analysis tests each country‘s fiscal regime to see how appropriate it would be to GSB conditions. This may suggest positive directions for change in the New Zealand regime. In some countries, domestic gas prices are artificially reduced under price controls. For the purpose of this study AUPEC used gas prices consistent with the assumed oil prices (see section 3.4) and not any domestic prices specified in local fiscal terms. Given the objective to test the comparator regimes under New Zealand conditions, the same gas prices must in any case be applied to all the fiscal regimes concerned. Project economics have been modelled on the basis of an existing investor, already paying sufficient income tax to obtain early relief against exploration and development costs. In jurisdictions where income tax is ring fenced around fields, the distinction between existing and new investors makes no difference. AUPEC assumed a consistent treatment of decommissioning costs (relief for the purposes of cost recovery and income tax) for all countries, unless other provisions were specifically mentioned in legislation or regulations. The following fiscal terms were employed when modelling each of the comparison regimes.

6.2 Description of the Australian Petroleum Fiscal Regime

Australia operates a concessionary system. Beyond the coastal waters (i.e. seaward of the first three nautical miles of the territorial sea to the outer limits of Australia's continental shelf) petroleum rights are held by the Australian Government, and it collects taxes and royalties on petroleum produced. Onshore and in coastal waters, the States and Territories own and allocate petroleum rights, and collect royalties on petroleum produced. There are three exceptions to this arrangement: North West Shelf production licence (NWSP), Barrow Island and the Timor Sea Joint Petroleum Development Area (JPDA). The chosen regime is that applied in the Offshore Commonwealth. Under this regime there are no mandatory bonuses, royalty nor state participation. There are application fees of AUS$ 4040 (Exploration), AUS$ 1615 (Production/Retention). The annual exploration licence fee is AUS$ 1000 or AUS$ 50/block, whichever is greater; the annual production fee is AUS$ 18000 per block; the

67



annual retention fee is AUS$ 6000 per block and the renewal fee is AUS$ 1615 (note: AUS$ 1.39 equal US$ 1, March 2009). There is an income tax of 30%, on assessable profits. Deductible costs include capital assets, which are to be written-off over their effective life. For most depreciating assets, companies have a choice to either work out the effective life themselves or use an effective life determined by the Commissioner of Taxation. The Government has introduced statutory caps on the 'safe harbour' effective lives of certain assets. There is a statutory effective life cap of 15 years for oil and gas production assets, except for offshore platform assets where the 20 year life remained unchanged. There are two methods of calculating the deduction in value of depreciating assets over their effective lives; the prime cost (or straight line) method and the diminishing value (or reducing balance) method. Once one method of working out the deduction for the decline in value of a depreciating asset is adopted, the investor cannot change to the other method for that asset. The following special deductions are also available for companies involved in petroleum exploration and development activities:

immediate deduction of petroleum exploration and prospecting expenditures;

an immediate deduction for expenditure to the extent that it is incurred for the sole or dominant purpose of carrying on environmental protection activities (EPA, activities undertaken to prevent, fight or remedy pollution, or to treat, clean up, remove or store waste from an earning activity).

expenditure on EPA that is also an environmental impact assessment of a project is not deductible as expenditure on EPA

o instead, it could be deductible over the life of the project using a pool; and

immediate deduction of certain mine-site rehabilitation costs including, subject to meeting eligibility requirements, expenditure associated with the removal of offshore platforms incurred on or after 1 July 1991.

Operational expenditures, Research and Development costs and overall financial costs are allowed. PRRT (to be explained later on) payments are deductible for company income tax purposes The Petroleum Resource Rent Tax is the only resource charge payable on production arising out of the release of offshore petroleum exploration acreage. PRRT is a profit based project tax. It is applied at a rate of 40% to a project's taxable profit (that profit being calculated for PRRT purposes). Taxable profit is the project's income after all project and 'other' exploration expenditures transferred in from other related PRRT projects, including a compounded amount for carried forward expenditures, have been deducted from all assessable receipts. Eligible expenditures include exploration and all project development and operating expenditures. Closing-down expenditures, including offshore platform removal and environmental restoration, are also deductible in the year in which they are incurred. If receipts during the year the project is closed down are less than the closing down expenditures, a credit is available, depending on whether the project has previously paid PRRT, for offset against other liabilities owed to the Australian Government.

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In years where eligible deductions are greater than revenue, the undeducted amounts are compounded annually at set rates. The compounded amount is then deducted against assessable receipts in the following year. Petroleum projects are entitled to deduct exploration expenditure transferred from related projects when the following conditions are satisfied:

the exploration expenditure must have been incurred after 1 July 1990; the receiving project must be making a taxable profit; the company must have held an interest in the transferring project and the receiving

project from the time the expenditure was incurred until the time of the transfer (an interest is defined as the entitlement to receive receipts from the sale of petroleum recovered in relation to the project); and

the transfers must go to the project that has the most recent production licence. Exploration expenditures that are not deducted in the tax year in which they are incurred can be uplifted and carried forward to be used as deductions in subsequent years. This expenditure is uplifted at the following levels:

Expenditure incurred more than five years before the application for a project production licence is compounded at a rate based on the Implicit Price Deflator for Expenditure on Gross Domestic Product (GDP). New bases exist for the GDP factor rates in 1981, 1987, 1992 and 1998-2001 years. Changes in the reference bases occurred in those years.

Exploration expenditure incurred less than five years before the application for a project production licence is compounded at the Australian long-term bond rate (LTBR) plus 15% (currently about 20%).

General expenditure (such as capital and operating expenditures) incurred less than five years before the application for a project production licence is compounded at the LTBR plus 5% (currently about 10%).

A long term LTBR of 5% was assumed. Generally, projects cannot transfer general (non-exploration) expenditure between projects. General project expenditure is compounded in a given tax year to be an expense incurred on the first day of the next financial year. There is an order of deduction for different categories of expenditure. General project expenditure is deducted first, then exploration expenditure incurred within the project, closing down expenditure, and finally exploration expenditure that is transferred from another project. There are expenditures that are not deductible. These include financing costs, private override royalty payments, income tax, goods and services tax, cash bidding payments and certain indirect administrative costs. PRRT is paid in quarterly instalments. Assessment is made on the basis of an annual return.

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6.3 Description of Thailand’s Petroleum Fiscal Regime

Thailand operates a concessionary system. The fiscal regime used for modelling is that applicable for offshore operations in Thailand, that is Thailand III plus modifications implemented up to the 20th licensing round (started in 2007). There are neither mandatory bonuses nor state participation. There are application, surface reservation and permarcation fees which are small. Royalties offshore Thailand are levied on steps based on daily oil production (with similar terms for gas). For blocks located in deepwater, the royalty to pay is 70% of the rates shown in Table 7. Each royalty rate is operated on an ―incremental‖ basis, i.e. it is applied to the part of production where it applies. Royalties on petroleum are allowed against income. Table 7. Offshore Thailand Royalty Scheme

Daily oil production rate Royalty rate

< 2,000 5%

2,000-5,000 6.25%

5,000 – 10,000 10%

10,000 – 20,000 12.5%

Over 20,000 15%

There is an income tax of 50% on profits (or 35% on profits plus 23.08% remittance tax applied after tax). Revenues, deductions and taxes for all ―Thailand III‖ blocks of the same concessionaire may be consolidated. Intangible and exploration costs are deducted after the start of production. Operating costs, royalties and SRB are deducted on the year in which they are incurred. All other expenses are depreciated on a straight line basis, with 10% rate for intangible pre-production costs and 20% for tangible (development) costs (10% for deepwater). Tax losses can be carried forward for ten years but no carried back. VAT is not applicable to oil and gas projects. There is a Special Remuneratory Benefit (SRB), which can be deemed as a surplus profits tax, payable only in the years the concessionaire has ―petroleum profit‖. In calculating such petroleum profit for the year, the company is allow to deduct capital expenditure, operating costs, a special reduction (―expense uplift‖ of 35% on investments) for the year, royalties and ―petroleum loss‖ from prior years. SRB is calculated by exploration block at the rates shown in Table 8, subject to a ceiling of 75% of the petroleum profit. No SRB is levied when the ―income per metre of well‖ is below Baht 4800.

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Table 8. Rates for Thai SRB

Income per metre of well SRB rate

Up to Baht 4,800 0%

Baht 4,800 to 14,400 1% of per each Baht 240 increment

Baht 14,400 to 33,600 1% per each Baht 960 increment

Over 33,600 Baht 1% per each Baht 3,840 increment

Note: 35.5 Bahts equal US$ 1 (March 2009).

To determine the ―income per metre of well‖, it is needed to first calculate annual petroleum profit and adjust it for inflation and exchange rates; then calculate the accumulated total meters of all wells drilled during the concession period. The income per metre of well equals adjusted annual petroleum profit divided by total depth of all wells plus a geological stability factor, as seen in the following equation A = Rev / (M + K) where A is the Annual Petroleum Profit per one metre drilled, Rev is Price times Production Volume, M is the total depth of all wells and K is the Geological Stability Factor. The Geological Stability Factor is fixed for each geological region and is at least 150,000 metres. It is higher in difficult drilling areas (400,000 metres in the Gulf of Thailand 1995 terms; 1,400,000 metres for deepwater terms).

6.4 Description of Chinese Petroleum Fiscal Regime

The Chinese regime is a production sharing system using royalty, income tax and state participation. Licensing is based on bidding rounds where minimum exploration work and expenditures as well as the production sharing terms, which determine the percentage of production the company will receive as profit, are the major bidding variables. The chosen regime to model is that applicable for offshore situations as it is this acreage which attracts major oil companies to China and where significant discoveries have been made. A new round has been opened but a model PSC is not yet available (24-Apr-2009). Furthermore the terms could be modified without notice in the next months, depending on the world economy and the level of interest shown on the acreage (as it has happened in Algeria and Uruguay). As such we have chosen to use the terms known in the industry as ―Deepwater 1994-1995‖ and modified after consulting (Z. Gao, 1994) and Machmud (2000). The following are historical mandatory bonuses: US$0.25mm on signature; US$0.50mm upon selection of development area. There may be a bonus upon entry into the second part of the exploration phase or on a discovery but overall the bonus payment does not

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normally surpass US$1mm. The signature bonus is not cost recoverable and there are no production bonuses. There are no rentals or fees. Royalties are levied on a sliding scale based on tranches of daily production as shown below on Tables 9 and 10. The average cost oil limit is 62.5% of gross production. Exploration, operating and development costs are allowed. Deemed interest (9%) is added to the development costs and in effect becomes part of the development costs. There is a ring fence for cost recovery but not for income tax, around each contract area. Table 9. Oil royalty schedule for Chinese PSCs.

Oil Production (‗000‘s bbls/d approximate)

Royalty Rate (%)

0-20 0

20-30 4

30-40 6

40-60 8

60-80 10

>80 12.5 (BOPD converted from Tons/Year at 7:1)

Table 10. Gas royalty schedule for Chinese PSCs.

Gas Production (MMCFD)

Royalty Rate (%)

Up to 195 0

195-338 1

338-484 2

>484 3 (MMCFD converted from MM m3/year at 35.3:1)

Profit oil remaining after royalty, VAT and cost recovery is shared on a negotiable sliding scale, again on a tranche basis (see Table 11). Table 11. Profit oil sharing terms for sample Chinese PSCs

Oil Production (‗000‘s bbls/d approximate)

Govt. Share of Profit Oil (%)

0-20 0

20-40 10

40-60 20

60-100 30

100-150 40

>150 50

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There is an income tax on profits, levied at 33% (made of 30% income tax plus 3% local income tax). The contractor is deemed to have received income at the time that the crude oil is divided. The depreciation method used is 6 year straight line depreciation for development costs, with Exploration costs expensed and no Ring fence applied. There used to be a Consolidated Industry and Commercial Tax of 5% of gross revenues in lieu of VAT. This was replaced in a 1994 by a VAT at 5% which is payable in kind by foreign petroleum investors (effectively a being a production tax). The rate is 13% for Chinese companies.

State Participation is mandatory. All expenditures incurred during exploration are borne by the investor. CNOOC Ltd. is entitled to farm in for a stake of up to 51% in acreage once commercial finds are confirmed. The development costs required are to be shared by the partners in proportion to their participating interest, namely 51% for the CNOOC and 49% for the contractor.

6.5 Description of Papua New Guinea’s Petroleum Fiscal Regime

Papua New Guinea (PNG) operates a concessionary system. The terms below are based on the ―General Petroleum Fiscal Terms‖ existing regime and assuming it will be applied on new projects. Such regime incorporates the 2003 modifications, which abolished a resource rent tax called APT. There are no mandatory bonuses and permitting fees are small. There are application fees ranging K10,000-50,000 (c. US$ 3,450-17,250, 2.9 PNG Kina equal US$1 as of March 2009) and annual licence fees of K1000-100,000 (c. US$ 345-34,500) for petroleum, pipelines and processing facilities. Conventional royalties in Papua New Guinea are levied at a flat rate of 2% of the wellhead production value. There is also a Development Levy at 2% of the wellhead production value of all petroleum produced in a project and it is paid to the affected Provincial or Local-level Governments. The Development Levy is a normal deduction for income tax, while royalties are not allowed as deduction. The income tax to be applied on profits is 30%, as long as the Petroleum Development Licence is granted on or before 31st December 2017, otherwise it is levied at the rates of 45% for new projects and 50% for existing projects. The income tax is subject to ring fencing on a project basis. Taxable income is made of gross revenue less development levy (where applicable), allowances for the write off of past exploration and capital expenditure, interest deductions (with a limit), operating costs and previous tax losses (if any) carried forward. For existing projects, exploration costs in the 20 year period prior to project development are deductible. For new projects, all past exploration costs may be pooled for a 25% declining balance depreciation. Capital Expenditure in existing projects is depreciated on a diminishing balance basis with an 8 year divisor. For new projects, expenditure will be distinguished between long life (with expected life of ten years or more), to be depreciated on a 10% straight line basis) and short life (with expected life of less than ten years), to be depreciated on a 25% declining balance).

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The debt to equity ratio limit is 3:1 and interest during development is capitalised and written off as a deduction over the life of the project. Tax losses can be carried forward during 20 years. VAT is not applicable to oil and gas projects. The State has the right, but not the obligation, to acquire a 22.5% interest in any petroleum development project after paying the allocated sunk costs in the 20 years prior to the grant of the development licence, including exploration expenditure anywhere in the underlying petroleum prospecting licence. The State or its nominee becomes a full joint venture participant, and (subject to the carry provisions referred to below) is liable for its share of all development and operating expenses. There are provisions under which the State may mandate the licensees of a petroleum development licence to carry the State or its nominee for both the initial acquisition cost and all subsequent development and operating costs. This carry is repaid out of production from the State‘s interest (excluding the 2% landowner equity), which is foregone until the carry is repaid in full, with a commercial rate of interest.

6.6 Description of India’s Petroleum Fiscal Regime

Since 1997, the Government of India has awarded blocks under Production Sharing Contracts as part of its New Exploration Licensing Policy (NELP). The licensing and tax regime is composed of several laws updated at different times and of a Model PSC which tends to be updated before every NELP round. The NELP VIII round has been opened but a model PSC is not yet available (15-Apr-2009). Furthermore the terms sketched in the notice inviting offers could be modified without notice in the next months, depending on the world economy and the level of interest shown on the Indian acreage (as it has happened in Algeria and Uruguay this month). As such, the chosen regime to model will be NELP-VII, as of 2007. Signature and production bonuses are not mandatory under this regime as well as state participation. Securities are required as well as licence/lease fees and the dead rent (see Table 12). PSC Participants shall pay royalty at 10% for crude oil & natural gas in offshore areas. There is a special provision for deep water areas beyond 400m bathymetry, where the royalty will be charged at 5% for the first 7 years, commencing with the year in which Commercial Production is started. The Cost Petroleum limit is biddable up to 100% of total production and has reached average values lately of 90%. Costs of exploration in the Contract Area, development, production and royalty payments are recoverable on the year in which they are incurred. The unrecovered portions of Contract Costs are carried forward to the following year or years. Any Site Restoration fund scheme formulated by the Government and all costs incurred by the Contractor pursuant to environmental protection shall be cost recoverable.

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Table 12. Securities, licence/lease fees and rents under the Indian regime.

Type of charge Amount

Deposit as security for due observance of the terms of the licence/lease

For a exploration licence, Rs. 1,00,000 For a mining lease, Rs. 2,00,000 as well as a deposit for meeting the preliminary expenses, such sum not exceeding Rs. 30,000 as the Government may determine.

Initial petroleum exploration license or mining lease fee

(i) Rs.25,000 in the case of a license, and (ii) Rs.50,000 in the case of a lease

Advanced yearly licence fee

For each square kilometer or part thereof covered by the licence at the following rates a. Rs. 50 for the first year of the licence b. Rs. 100 for the second year of the licence c. Rs. 500 for the third year of the licence d. Rs. 700 for the fourth year of the licence e Rs. 1,000 for the first and second years of the renewal

Lease dead rent Rs. 25 per hectare or part thereof for the first 100 square kilometres and Rs. 50 per hectare or part thereof for area exceeding the first 100 sq. km., provided that the lessee shall be liable to pay only the dead rent or the royalty, whichever is higher in amount but not both.

49.8 Indian Rupee equal US$ 1 (April 2009)

The remaining Profit Petroleum is split based on a pre-tax investment multiple achieved by the investor at the end of the preceding Year for the Contract Area. The pre-tax investment multiple is in principle the same as an ‗R-factor‘ scheme, as profit oil relates incrementally to the investment multiple value (see Table 13). The investment multiple is calculated on the basis of the ‗net income‘. The ―net income‖ of the Contractor from their Petroleum Operations in any particular year is the aggregate value for the Year of the Cost Petroleum entitlement of the Contractor plus the Profit Petroleum entitlement of the Contractor plus the Contractor‘s all incidental income arising from Petroleum Operations; less the Contractor‘s Production Costs and royalty, the ―Investment‖ made by the Contractor in the Contract Area in any particular year (exploration costs plus development costs incurred). The investment multiple ratio of the Contractor as at the end of any year is calculated by dividing the aggregate value of the addition of each of the annual Net Incomes (accumulated, without interest, up to and including that year starting from the year in which production costs were first incurred or production first arose) by the aggregate value of the addition of each of the annual Investments (accumulated, without interest, up to and including that year starting from the year in which exploration and development costs were first incurred). The amount of Profit Petroleum to be shared between the Government and the Contractor shall be determined for each Quarter on an accumulative basis. Pending finalisation of accounts, Profit Petroleum shall be shared between the Government and the Contractor on the basis of provisional estimated figures.

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Table 13. Terms for an offshore block awarded on the Krishna Godavari Basin. Cost recovery ceiling was 90% of gross revenues.

Investment Multiple Profit Petroleum Split

Investor Government

<1.5 90% 10%

1.5 to less than 2.0 84% 16%

2.0 to less than 2.5 72% 28%

>= 2.5 15% 85%

PSC Participants who begin Commercial Production of Petroleum in any part of India on or after 1st April 1997 are entitled to claim deduction of 100% of their profits and gains derived from such business for the initial seven years after first commercial production. The Finance Ministry removed this holiday for gas production from blocks awarded from existing NELP VII contracts and made it clearer on the current licensing round. According to reports, officials from the petroleum ministry are in discussions with the finance ministry to work out a solution ―as oil and gas should have a level playing field‖. Income tax thereafter is levied at a rate of 35% for a domestic company and of 42.23% for a foreign company. Exploration and drilling operations are deductible in the year in which they are incurred. For any or all accumulated expenditures incurred in respect of exploration and drilling operations prior to the date of commercial production, PSC participants have the option to amortise such expenditures over a period of ten (10) years from the date of first commercial production. Development operations, other than drilling operations, and production operations will be allowed on a 25% declining balance basis. Any amount deposited in the Site Restoration Fund (to be discussed later on), in the year in which is deposited, can be deducted, up to a maximum of 20% of the profits. Interest reinvested in accordance with the Scheme shall also qualify for deduction within this limit. Interest payments are also deductible. Set off, or carry forward of losses is allowed for income tax purposes. There is a MAT (Minimum Alternative Tax), which is applied on the cases where there are ―book‖ profits but the assessable profits for income tax are zero or negative. The MAT will continue to be applicable in forthcoming PSC's signed and will be levied under the revised rate of 11.33%, if tax payable by the company on its total income, as computed under the normal income tax provisions, is less than 10 percent of its book profits. Due to the nature of the MAT regime, a company is liable to pay tax even during the 7 year income tax holiday period declared under NELP. The Site Restoration Fund Scheme applies to all contractors. PSC participants must deposit into an account yearly in one lump sum or in instalments. Such deposit has to be made out of profits derived from the business and carries interest at the highest rate as paid by the State Bank of India. The fund‘s aim is to meet any expenditure to be incurred by him on the expiry or termination of the agreement or relinquishment of part of the contract area, towards removal of all equipments and installations and towards meeting all other expenses necessary to prevent hazards to life or property or the environment. For the purpose of determining the annual contribution to be made to the Fund, the unit of production method i.e. Reserve to Production Ratio is used. Import of machinery, plant, equipment, materials and supplies by the PSC Participant or any of its subcontractors shall be exempt from customs duty.

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6.7 Oil Development Economics: Post-Tax Results

To aid comparison, Figure 41 repeats the post-tax real net present value at 10% p.a. real terms discount rate of GSB oil developments under the New Zealand fiscal regime at the base case oil price of $60/bbl. Figure 41. Post-Tax RNPV 10% (US$ bn), GSB Oil at $60/bbl, New Zealand Regime

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Other things being equal, the Papua New Guinea fiscal regime has increased attraction for the investor (higher NPVs). This arises from the special income tax rate of 30% which applies to Petroleum Development Licenses granted before 2018, when the rate reverts to 45%. Figure 43 shows the NPVs for GSB oil development under the Australian Offshore Commonwealth fiscal regime. Other things being equal, this does not compete with New Zealand‘s oil taxation system, the NPVs being lower than those in Figure 41. Figure 43. Post-Tax RNPV 10% (US$ bn) at $60/bbl, Offshore Commonwealth Regime

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Figure 44 shows the GSB oil development economics under a Chinese style production sharing contract. Other things being equal, this does not compete (lower NPVs) with New Zealand‘s oil taxation system. For the purposes of this study, mandatory state participation has been taken into account when calculating the post-tax RNPV for the investor.

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Figure 44. Post-Tax RNPV 10% (US$ bn), GSB Oil at $60/bbl, China Style PSC

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Figure 45 shows the NPVs for GSB oil development under Thailand‘s fiscal regime. Offshore royalty rates have been modelled, together with the most favourable values of the variable parameters (expense uplift and geological stability factor). Other things being equal, the Thai regime does not compete with New Zealand‘s oil taxation system, the NPVs being lower than those in Figure 41. Figure 45. Post-Tax RNPV 10% (US$ bn), GSB Oil at $60/bbl, Thai Fiscal Regime

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Figure 46 shows the GSB oil development economics under an Indian style production sharing contract. Other things being equal, this does not compete (lower NPVs) with New Zealand‘s oil taxation system. It also suffers from structural problems in the form of gold plating. Figure 46. Post-Tax RNPV 10% (US$ bn), GSB Oil at $60/bbl, India Style PSC

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The significant increase in NPV for the largest oilfield on moving from a unit development cost of $9/bbl to one of $11/bbl, for example, is the result of the large rise in the government share of profit oil, from 28 to 85%, on entering the highest Investment Multiple band. By spending an additional $800m on development in 2009 terms, plus a proportional increase in operating costs, and despite the consequent rise in cost oil and fall in profit oil volumes, the investor can increase the value of its share of profit oil by $2.2 billion (nominal). Two years of production at 15% contractor share of profit oil are converted into one year at 90% and one at 72%. Figures 41-46 show the economics of GSB oil developments over a very wide range of unit development costs bracketing the most likely values. Table 14 shows the NPVs under each of the six fiscal regimes at the most likely unit development cost for each field size. Table 14. Post-Tax RNPV (US$ bn) at $60/bbl, Most Likely Unit Development Costs 40 mmb 80 mmb 120 mmb 260 mmb 400 mmb

$/bbl devex 12.45 10.15 8.94 4.72 4.39

New Zealand 0.29 0.59 0.85 2.19 3.49

Papua New G. 0.32 0.66 0.96 2.53 4.04

Australia O.C. 0.20 0.42 0.60 1.56 2.50

China type PSC 0.15 0.29 0.41 0.96 1.40

Thailand 0.18 0.28 0.36 0.76 1.05

India type PSC 0.13 0.23 0.33 0.63 1.14

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The Papua New Guinea fiscal regime‘s relative advantage (other things being equal) over the New Zealand one increases with increasing field size, due to its fixed rate royalty system (2% plus 2% Development Levy).

To aid comparison, Figure 47 repeats the nominal percentage government take from GSB oil developments under the New Zealand fiscal regime at the base case oil price of $60/bbl. While the government take appears proportional when plotted on the Y axis scale required for a consistent international comparison, it is in fact very mildly regressive, rising from 44.0% at $3/bbl unit development cost to 44.3-44.9% at $15/bbl unit development cost. Figure 47. Nominal Percentage Government Take, Oil at $60/bbl, New Zealand Regime

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Figure 48 shows the nominal percentage government take from GSB oil developments under the Papua New Guinea fiscal regime at the base case oil price of $60/bbl. The government take is lower than for New Zealand at low unit development costs, in line with the lower overall tax rate which will apply for new development licenses until the end of 2017. The Papua New Guinea regime is slightly more regressive than the New Zealand one, particularly for the smaller fields.

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Figure 48. Nominal Percentage Government Take, $60/bbl, Papua New Guinea Regime

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Figure 49 shows the nominal percentage government take from GSB oil developments under the Australian Offshore Commonwealth fiscal regime at $60/bbl. Figure 49. Nominal Percentage Government Take, $60/bbl, Offshore Commonwealth

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While the government take is approximately proportional when plotted on the Y axis scale required for a consistent international comparison, it is mildly regressive for the smallest field, rising from 58.3% at $3/bbl unit development cost to 59.5% at $15/bbl unit development cost. For the remaining field sizes the regime is initially very slightly

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regressive but then becomes mildly progressive, rising from 58.1% at $3/bbl to a peak of up to 58.3% at $9/bbl and falling to a take of 57.5-58% at $15/bbl.

Although the Australian Offshore Commonwealth fiscal regime has the potential to be progressive because of the presence of the Petroleum Resource Rent Tax (PRRT), the five notional oilfields have pre-tax real terms internal rates of return at an oil price of $60/bbl and at $15/bbl unit development cost that range from 30% p.a. (260 mmb) to 63% p.a. (40 mmb). The PRRT targets nominal rates of return above about 10% p.a. in respect of development costs and above the inflation rate (2.5% p.a. assumed) in terms of operating costs, so the major part of the annual net cash flows analysed above over the lifetimes of the individual fields have been subject to PRRT, hence the general lack of observed progressive fiscal behaviour. Figure 50 shows the nominal percentage government take from GSB oil developments under a Chinese style production sharing contract at $60/bb (including participation by the state). The regime is slightly regressive in terms of unit development cost and, in contrast to the tax systems described above, slightly progressive in relation to field size.

Figure 50. Nominal Percentage Government Take, GSB Oil at $60/bbl, China Style PSC

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Figure 51 shows the nominal percentage government take from GSB oil developments under Thailand‘s fiscal regime at $60/bbl. It is a little erratic but essentially proportional with respect to unit development cost, and significantly progressive in terms of field size. There was no room for a legend in this case, but the key is the same as for all the other figures in this section (6.7).

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Figure 51. Nominal Percentage Government Take, Oil at $60/bbl, Thai Fiscal Regime

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The regime is highly progressive in terms of unit development cost, in fact too progressive, resulting in the lack of relatively high NPVs at low unit development costs in Figure 46. The erratic behaviour shown in the plots for individual field sizes is related to the finer detail of the gold plating present, that is, the design of the bands of government share of profit oil and of the Investment Multiple, as explained for one particular example when discussing Figure 46 above.

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Figures 47-52 show the nominal percentage government takes from GSB oil developments over a very wide range of unit development costs bracketing the most likely values. Table 15 shows the government takes under each of the six fiscal regimes at the most likely unit development cost for each field size.

Table 15. Nominal Percentage Gov. Take, $60/bbl, Most Likely Unit Development Costs 40 mmb 80 mmb 120 mmb 260 mmb 400 mmb

$/bbl devex 12.45 10.15 8.94 4.72 4.39

New Zealand 44.3 44.1 44.1 44.2 44.1

Papua New G. 37.4 35.1 34.2 33.7 33.4

Australia O.C. 59.1 58.2 58.2 58.2 58.2

China type PSC 71.0 71.9 72.4 74.1 75.6

Thailand 62.5 68.3 71.0 76.2 78.7

India type PSC 75.4 78.4 79.2 85.8 84.9

In terms of the five notional field sizes at their most likely unit development costs, the fundamental structure of the fiscal regimes can be classified as virtually proportional (New Zealand and Australia Offshore Commonwealth), regressive (Papua New Guinea) and progressive (China, Thailand and India). When considering the phenomenon of widespread gold plating as observed for India, the investor take (100% minus the above percentages) is the key factor. For this purpose, however, it is better investigated in net present value (discounted) investor take terms.

To aid comparison, Figure 53 repeats the real terms net present value (10% p.a.) percentage government take from GSB oil developments under the New Zealand fiscal regime at the base case oil price of $60/bbl. Figure 53. PV 10% Percentage Government Take, Oil at $60/bbl, New Zealand Regime

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In terms of its impact on an investor‘s project economics the New Zealand regime is mildly regressive with respect to unit development cost, and most so for the 260 mmb field size. Figure 54 shows the present value (10%) percentage government take from GSB oil developments under the Papua New Guinea fiscal regime at the base case oil price of $60/bbl. This regime is slightly more regressive than the New Zealand one in respect of unit development cost, and again the 260 mmb field is most affected by regressivity. Figure 54.PV 10% Percentage Government Take, $60/bbl, Papua New Guinea Regime

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Figure 55 shows the present value (10%) percentage government take from GSB oil developments under the Australian Offshore Commonwealth fiscal regime at $60/bbl.

Starting from a higher point, the increase in discounted government take for a given rise in unit development cost is intermediate between the results obtained for the New Zealand and Papua New Guinea regimes.

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Figure 55. PV 10% Percentage Government Take, $60/bbl, Offshore Commonwealth

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Figure 56 shows the present value (10%) percentage government take from GSB oil developments under a Chinese style production sharing contract at $60/bbl (including participation by the state). The rise in discounted government take is less than ten percentage points from left to right across the chart, more like the New Zealand regime than Papua New Guinea or the Australian Offshore Commonwealth system. Figure 56. PV 10% Percentage Government Take, GSB Oil at $60/bbl, China Style PSC

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Figure 57 shows the present value (10%) percentage government take from GSB oil developments under Thailand‘s fiscal regime at $60/bbl.

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The level of regressivity is similar to that under the Australian Offshore Commonwealth tax system, but starting from a much higher point the two largest fields are close to becoming uneconomic at $15/bbl unit development cost. Figure 57. PV 10% Percentage Government Take, Oil at $60/bbl, Thai Fiscal Regime

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Figure 58 shows the present value (10%) percentage government take from GSB oil developments under an Indian style production sharing contract at $60/bbl. Even after discounting, the regime remains progressive in terms of unit development cost. As already discussed, it is in fact too progressive as revealed by the lack of relatively high NPVs at low unit development costs in Figure 46. Once again the erratic behaviour shown in the plots for individual field sizes is related to the finer detail of the gold plating present, that is, the design of the bands of government share of profit oil and of the Investment Multiple, as explained for one particular example when discussing Figure 46 above.

The discounted investor take (100% minus the discounted government take) rises from approximately 15% at $3/bbl unit development cost to around 30% at $15/bbl unit development cost. The post-tax NPV is the pre-tax value multiplied by the discounted investor take. As the pre-tax NPVs at $60/bbl fall by 49% (40 mmb) to 65% (400 mmb) over the same range of unit development costs, the two rates of change cancel each other out for the smallest oil field. This is responsible for the very constant post-tax NPV shown by the 40 mmb field across Figure 46 and is the justification for describing the Indian fiscal regime as too progressive in terms of unit development cost.

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Figure 58. PV 10% Percentage Government Take, GSB Oil at $60/bbl, India Style PSC

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Figures 53-58 show the present value (10%) percentage government takes from GSB oil developments over a very wide range of unit development costs bracketing the most likely values. Table 16 shows the discounted government takes under each of the six fiscal regimes at the most likely unit development cost for each field size.

For the five notional field sizes at their most likely unit development costs, the structure of the fiscal regimes in terms of their impact on an investor‘s economics can be classified as regressive (New Zealand, Papua New Guinea and Australia Offshore Commonwealth, with Papua New Guinea standing out in terms of the increase in percentage government take from left to right across the table) and progressive (China, Thailand and India, with Thailand standing out).

Table 16. PV 10% Percentage Gov. Take, $60/bbl, Most Likely Unit Development Costs 40 mmb 80 mmb 120 mmb 260 mmb 400 mmb

$/bbl devex 12.45 10.15 8.94 4.72 4.39

New Zealand 47.5 46.6 46.3 44.5 44.3

Papua New G. 42.4 40.4 39.4 35.9 35.5

Australia O.C. 63.8 62.1 62.2 60.3 60.1

China type PSC 73.1 73.9 74.3 75.6 77.7

Thailand 67.7 74.4 77.0 80.7 83.3

India type PSC 76.4 79.3 79.1 84.0 81.8

6.8 Oil Exploration Economics: Post-Tax Results

To aid comparison, Figure 59 repeats the post-tax expected monetary value at 10% p.a. real terms discount rate of GSB oil exploration under the New Zealand fiscal regime and at the four oil prices evaluated. Until we have presented gas exploration results that can be

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combined with those for oil, we need to maintain the temporary fiction that an explorer in the GSB can be sure of finding oil rather than gas. Note that the units on the Y axis are now millions rather than billions of US dollars, but still with a reference date of 1.7.2009 as for the NPVs above. The weighted average unit development cost, using the same weights (see the resource distribution) adopted in the EMV calculation, is approximately $11/bbl. Figure 59. Post-Tax EMV 10% (US$ m), GSB Oil, New Zealand Fiscal Regime

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100

150

200

250

300

3 5 7 9 11 13 15


$40/bbl

$60/bbl

$80/bbl

$100/bbl

Figure 60 shows the GSB oil exploration economics under the Papua New Guinea regime. Figure 60. Post-Tax EMV 10% (US$ m), GSB Oil, Papua New Guinea Regime

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3 5 7 9 11 13 15


$40/bbl

$60/bbl

$80/bbl

$100/bbl

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Other things being equal, the Papua New Guinea fiscal regime has increased attraction for the explorer (higher EMVs), as would be expected from the higher NPVs observed above. At $40/bbl ($20/bbl below the base case oil price) and $11/bbl unit development cost, however, exploration on an oil-only basis becomes marginally uneconomic under both the New Zealand and the Papua New Guinea regimes. Figure 61 shows the EMVs for GSB oil exploration under the Australian Offshore Commonwealth fiscal regime. Other things being equal, this does not compete with New Zealand‘s oil taxation system, the EMVs being lower than those in Figure 59. Figure 61. Post-Tax EMV 10% (US$ m), GSB Oil, Offshore Commonwealth Regime

-50

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100

150

200

250

300

3 5 7 9 11 13 15


$40/bbl

$60/bbl

$80/bbl

$100/bbl

Figure 62 shows the GSB oil exploration economics under a Chinese style production sharing contract. Other things being equal, this does not compete (lower EMVs) with New Zealand‘s oil taxation system. For the purposes of this study, mandatory state participation has been taken into account when calculating the post-tax EMV for the investor.

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Figure 62. Post-Tax EMV 10% (US$ m), GSB Oil, China Style PSC

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0

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100

150

200

250

300

3 5 7 9 11 13 15


$40/bbl

$60/bbl

$80/bbl

$100/bbl

Figure 63 shows the EMVs for GSB oil exploration under Thailand‘s fiscal regime. Offshore royalty rates have been modelled, together with the most favourable values of the variable parameters (expense uplift and geological stability factor). Other things being equal, the Thai regime does not compete with New Zealand‘s oil taxation system, the EMVs being lower than those in Figure 59. Figure 63. Post-Tax EMV 10% (US$ m), GSB Oil, Thai Fiscal Regime

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100

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200

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300

3 5 7 9 11 13 15


$40/bbl

$60/bbl

$80/bbl

$100/bbl

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Figure 64 shows the GSB oil exploration economics under an Indian style production sharing contract. Figure 64. Post-Tax EMV 10% (US$ m), GSB Oil, India Style PSC

-50

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100

150

200

250

300

3 5 7 9 11 13 15


$40/bbl

$60/bbl

$80/bbl

$100/bbl

Other things being equal, this does not compete (lower EMVs) with New Zealand‘s oil taxation system. As for the analysis above of the underlying NPVs at $60/bbl, Figure 64 also displays some degree of structural problems in the form of gold plating at all four prices. Table 17 shows the EMVs under each of the six fiscal regimes at the base case oil price of $60/bbl.

Table 17. Post-Tax EMV (US$ m) at $60/bbl $/bbl devex 3 5 7 9 11 13 15

New Zealand 114 99 84 69 54 40 25

Papua New G. 136 117 99 81 62 44 26

Australia O.C. 68 57 46 35 24 14 3

China type PSC 39 31 23 16 8 1 -7

Thailand 27 22 14 7 0 -8 -16

India type PSC 13 11 12 17 17 15 8

6.9 Gas Development Economics: Post-Tax Results

To aid comparison, Figure 65 repeats the post-tax real net present value at 10% p.a. real terms discount rate of GSB gas developments under the New Zealand fiscal regime at the base case gas price of $7/mscf.

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Figure 65. Post-Tax RNPV 10% (US$ bn), GSB Gas at $7/mscf, New Zealand Regime

-4.0

-3.0

-2.0

-1.0

0.0

1.0

2.0

0.4 0.65 0.9 1.15 1.4 1.65 1.9


250 bcf

500 bcf

1125 bcf

2500 bcf

5000 bcf

Figure 66 shows the GSB gas development economics under the Papua New Guinea fiscal regime. Other things being equal this has somewhat increased attraction for the investor (slightly higher NPVs where these are positive) as long as unit development costs are relatively low. The largest field size becomes uneconomic at a slightly lower unit development cost under the Papua New Guinea than under the New Zealand fiscal regime. When the Papua New Guinea gas taxation regime is more attractive this arises from the special income tax rate of 30% which applies to Petroleum Development Licences granted before 2018, when the rate will revert to 45%. Figure 66. Post-Tax RNPV 10% (US$ bn), Gas at $7/mscf, Papua New Guinea Regime

-4.0

-3.0

-2.0

-1.0

0.0

1.0

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


250 bcf

500 bcf

1125 bcf

2500 bcf

5000 bcf

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Figure 67 shows the NPVs for GSB gas development under the Australian Offshore Commonwealth fiscal regime. Other things being equal, this does not compete with New Zealand‘s gas taxation system, positive NPVs being lower than those in Figure 65. Figure 67.Post-Tax RNPV 10% (US$ bn) at $7/mscf, Offshore Commonwealth Regime

-4.0

-3.0

-2.0

-1.0

0.0

1.0

2.0

0.4 0.65 0.9 1.15 1.4 1.65 1.9


250 bcf

500 bcf

1125 bcf

2500 bcf

5000 bcf

Figure 68 shows the GSB gas development economics under a Chinese style production sharing contract. Other things being equal, this does not compete (lower NPVs) with New Zealand‘s oil taxation system. Mandatory state participation has been taken into account when calculating the post-tax RNPV for the investor.

Figure 68. Post-Tax RNPV 10% (US$ bn), GSB Gas at $7/mscf, China Style PSC

-4.0

-3.0

-2.0

-1.0

0.0

1.0

2.0

0.4 0.65 0.9 1.15 1.4 1.65 1.9


250 bcf

500 bcf

1125 bcf

2500 bcf

5000 bcf

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Figure 69 shows the NPVs for GSB gas development under Thailand‘s fiscal regime. Offshore royalty rates have been modelled, together with the most favourable values of the variable parameters. Other things being equal, the Thai regime does not compete with New Zealand‘s oil taxation system, positive NPVs being lower than those in Figure 65. Figure 69. Post-Tax RNPV 10% (US$ bn), GSB Gas at $7/mscf, Thai Fiscal Regime

-4.0

-3.0

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-1.0

0.0

1.0

2.0

0.4 0.65 0.9 1.15 1.4 1.65 1.9


250 bcf

500 bcf

1125 bcf

2500 bcf

5000 bcf

Figure 70 shows the GSB gas development economics under an Indian style production sharing contract. Other things being equal, this does not compete (lower NPVs) with New Zealand‘s gas taxation system.

Figure 70. Post-Tax RNPV 10% (US$ bn), GSB Gas at $7/mscf, India Style PSC

-4.0

-3.0

-2.0

-1.0

0.0

1.0

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


250 bcf

500 bcf

1125 bcf

2500 bcf

5000 bcf

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The gas development economics are too poor to suffer from the potential structural problems, in the form of gold plating, that were observed for oilfields. The Investment Multiple may be in the lowest band throughout the gasfield lives. Figures 65-70 show the economics of GSB gas developments over a very wide range of unit development costs bracketing the most likely values. Table 18 shows the NPVs under each of the six fiscal regimes at the most likely unit development cost for each field size. Table 18. Post-Tax RNPV (US$ bn) at $7/mscf, Most Likely Unit Development Costs 250 bcf 500 bcf 1125 bcf 2500 bcf 5000 bcf

$/mscf devex 1.53 1.62 1.32 0.67 0.69

New Zealand 0.04 0.06 0.00 0.45 0.70

Papua New G 0.05 0.06 -0.02 0.51 0.77

Australia OC 0.02 0.02 -0.06 0.27 0.38

China type PSC 0.02 0.02 -0.02 0.22 0.24

Thailand 0.03 0.01 -0.09 0.20 0.08

India type PSC 0.01 0.01 -0.09 0.11 0.12

The Papua New Guinea fiscal regime‘s general relative advantage (other things being equal) over the New Zealand one is absent for the 500 bcf field size and reversed for the 1125 bcf field size.

As there are so few economic gas development cases in Figures 65-70, it is not worthwhile investigating the nominal and real terms present value government take percentages over the whole range of unit development costs studied. Many of the government takes would have to be plotted as 100%. The remaining economic cases would only give two or three data points for charts, and we can expect the fiscal regimes to have revealed the same behaviour for gas as for oil were it not for the fact that gas price parities with oil were so low and gasfield operating costs so high.

6.10 Gas Exploration Economics: Post-Tax Results

To aid comparison, Figure 71 repeats the post-tax expected monetary value at 10% p.a. real terms discount rate of GSB gas exploration under the New Zealand fiscal regime and at the four gas prices evaluated. Until we have established gas exploration results that can be combined with those for oil, we need to adopt the temporary fiction that an explorer in the GSB can be sure of finding gas rather than oil. Note that the units on the Y axis are now millions rather than billions of US dollars, but still with a reference date of 1.7.2009 as for the NPVs above. The weighted average unit development cost, using the same weights (based on the resource distribution) adopted in the EMV calculation, is approximately $1.4/mscf. At this unit development cost, a very high gas price of around $11.2/mscf is required to make GSB exploration economically attractive on a gas-only basis under the New Zealand fiscal regime.

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Figure 71. Post-Tax EMV 10% (US$ m), GSB Gas, New Zealand Fiscal Regime

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-100

-80

-60

-40

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0

20

40

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/mscf

$7/mscf

$10/mscf

$13/mscf

Figure 72 shows the GSB gas exploration economics under the Papua New Guinea fiscal regime. Other things being equal, the Papua New Guinea fiscal regime has increased attraction for the explorer (higher EMVs), as would be expected from the higher NPVs observed above. At a unit development cost of $1.4/mscf, however, GSB exploration on a gas-only basis is only economic above a gas price of around $11.0/mscf under the Papua New Guinea tax system.

Figure 72. Post-Tax EMV 10% (US$ m), GSB Gas, Papua New Guinea Regime

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-40

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/mscf

$7/mscf

$10/mscf

$13/mscf

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Figure 73 shows the EMVs for GSB gas exploration under the Australian Offshore Commonwealth fiscal regime. Other things being equal, this does not compete with New Zealand‘s taxation system, the EMVs being lower than those in Figure 71 and the gas-only breakeven hydrocarbon price being around $13/mscf at $1.4/mscf unit development cost. Figure 73. Post-Tax EMV 10% (US$ m), GSB Gas, Offshore Commonwealth Regime

-120

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-60

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0

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/mscf

$7/mscf

$10/mscf

$13/mscf

Figure 74 shows the GSB gas exploration economics under a Chinese style production sharing contract. Other things being equal, this does not compete (lower EMVs) with New Zealand‘s taxation system. Mandatory state participation has been taken into account. Figure 74. Post-Tax EMV 10% (US$ m), GSB Gas, China Style PSC

-120

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/mscf

$7/mscf

$10/mscf

$13/mscf

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Figure 75 shows the EMVs for GSB gas exploration under Thailand‘s fiscal regime. Offshore royalty rates have been modelled, together with the most favourable values of the variable parameters. Other things being equal, the Thai regime does not compete with New Zealand‘s gas taxation system, the EMVs being lower than those in Figure 71. Figure 75. Post-Tax EMV 10% (US$ m), GSB Gas, Thai Fiscal Regime

-120

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0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/mscf

$7/mscf

$10/mscf

$13/mscf

Figure 76 shows the GSB gas exploration economics under an Indian style PSC. Other things being equal, this does not compete with New Zealand‘s gas taxation system. The EMVs are negative under all the prices and unit development costs studied. Figure 76. Post-Tax EMV 10% (US$ m), GSB Gas, India Style PSC

-120

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$13/mscf

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Table 19 shows the EMVs under each of the six fiscal regimes at the base case gas price of $7/mscf. Table 19. Post-Tax EMV (US$ m) at $7/mscf $/mscf devex 0.4 0.65 0.9 1.15 1.4 1.65 1.9

New Zealand 5 -4 -12 -21 -29 -37 -46

Papua New G. 9 -2 -12 -22 -33 -44 -57

Australia O.C. 3 -7 -17 -28 -39 -52 -65

China type PSC -11 -17 -23 -30 -38 -46 -54

Thailand -5 -14 -23 -35 -48 -63 -77

India type PSC -18 -21 -27 -35 -47 -62 -79

6.11 Overall Exploration Economics: Post-Tax Results

To aid comparison, Figure 77 repeats the post-tax expected monetary value at 10% p.a. real terms discount rate of GSB exploration under the New Zealand fiscal regime and at the four pairs of consistent oil and gas prices studied. These are based on the assessed probability, 67%, of finding gas rather than oil in a successful exploration well in the GSB.

Figure 77. Post-Tax EMV 10% (US$ m), GSB, New Zealand Fiscal Regime

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3 5 7 9 11 13 15

0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/$40

$7/$60

$10/$80

$13/$100

The weighted average unit development costs, using the same weights (based on the resource distributions) adopted in the EMV calculations, of approximately $11/bbl and $1.4/mscf have been aligned in this chart, as have the full ranges of unit development costs studied. Exploration in the GSB is close to the economic breakeven point (an EMV of zero) under the New Zealand fiscal regime, at the base case hydrocarbon prices of $60/bbl and $7/mscf and at the most likely unit development costs. As revealed above, however, it is

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important to remember that this probabilistic breakeven situation is founded on economic oil development cases and uneconomic gas development ones. Figure 78 shows the overall GSB exploration economics under the Papua New Guinea fiscal regime. The EMV at the base case hydrocarbon prices and the most likely unit development costs is also close to zero (economic breakeven) under this taxation system. EMVs at higher hydrocarbon prices and at lower unit development costs are, however, larger than under the New Zealand fiscal regime. Figure 78. Post-Tax EMV 10% (US$ m), GSB, Papua New Guinea Regime

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3 5 7 9 11 13 15

0.4 0.65 0.9 1.15 1.4 1.65 1.9


Figure 79 shows the EMVs for GSB exploration under the Australian Offshore Commonwealth fiscal regime. Other things being equal, this does not compete with New Zealand‘s hydrocarbon taxation system, the EMVs being lower than those in Figure 77.

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Figure 79. Post-Tax EMV 10% (US$ m), GSB, Offshore Commonwealth Regime

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0

50

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3 5 7 9 11 13 15

0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/$40

$7/$60

$10/$80

$13/$100

Figure 80 shows the GSB exploration economics under a Chinese style production sharing contract. Other things being equal, this does not compete (lower EMVs) with New Zealand‘s hydrocarbon taxation system. For the purposes of this study, mandatory state participation has been taken into account when calculating the post-tax EMV for the investor.

Figure 80. Post-Tax EMV 10% (US$ m), GSB, China Style PSC

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50

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3 5 7 9 11 13 15

0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/$40

$7/$60

$10/$80

$13/$100

Figure 81 shows the EMVs for GSB exploration under Thailand‘s fiscal regime. Offshore royalty rates have been modelled, together with the most favourable values of the variable parameters (expense uplift and geological stability factor). Other things being equal, the

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Thai regime does not compete with New Zealand‘s hydrocarbon taxation system, the EMVs being lower than those in Figure 77. Figure 81. Post-Tax EMV 10% (US$ m), GSB, Thai Fiscal Regime

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3 5 7 9 11 13 15

0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/$40

$7/$60

$10/$80

$13/$100

Figure 82 shows the GSB exploration economics under an Indian style production sharing contract. Other things being equal, this does not compete (lower EMVs) with New Zealand‘s hydrocarbon taxation system. Indeed, positive NPVs are only found at the highest hydrocarbon prices studied, and then only when these are combined with unit development costs below the most likely values.

Figure 82.Post-Tax EMV 10% (US$ m), GSB, India Style PSC

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3 5 7 9 11 13 15

0.4 0.65 0.9 1.15 1.4 1.65 1.9


$4/$40

$7/$60

$10/$80

$13/$100

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Table 20 shows the EMVs under each of the six fiscal regimes at the base case prices of $60/bbl and $7/mscf. Table 20. Post-Tax EMV (US$ m) at $60/bbl and $7/mscf $/bbl devex 3 5 7 9 11 13 15

$/mscf devex 0.4 0.65 0.9 1.15 1.4 1.65 1.9

New Zealand 41 30 20 9 -1 -12 -23

Papua New G. 51 38 24 12 -2 -15 -29

Australia O.C. 24 14 4 -7 -18 -31 -43

China type PSC 6 -1 -8 -15 -23 -30 -38

Thailand 5 -2 -11 -21 -32 -45 -57

India type PSC -8 -10 -14 -18 -26 -37 -50

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7.0 Main Conclusions from Evaluation of International Comparisons

7.1 General Observations

The New Zealand fiscal regime (i.e. those terms scheduled to apply in New Zealand after 31 December 2009) is highly competitive against all the comparator countries except Papua New Guinea when tested under Great South Basin conditions. Moreover, the competitive advantage of the Papua New Guinea regime relies on a temporary reduction in the corporate income tax rate, a concession due to be withdrawn for development licenses granted after the year 2017. The evaluation of the Indian type of production sharing contract clearly demonstrates that it is possible to construct a highly progressive fiscal system. In its detail it is too progressive, and can operate erratically because of large changes in government take between Investment Multiple (R factor) bands. As a result it can give rise to ―gold plating‖, removing a contractor‘s incentive to be cost conscious. Nevertheless, the achievement of a more than adequately progressive system is impressive. Under the likely costs and base case hydrocarbon prices used in this study, petroleum exploration investments in New Zealand, as represented by the Great South Basin, are economically marginal at a cost of capital which is moderate and may not reflect all the risks and the effects of capital rationing.

7.2 Conclusions and Recommendations: Gas Projects

Although the exploration economics of the GSB are at breakeven, this position is founded on a probabilistic combination of economic oil developments and uneconomic gas ones. It would be psychologically preferable for all parties if everything possible could be done to move away from a position where the economic attraction of exploration hinges on finding oil rather than gas. It is therefore crucial to improve the economics of New Zealand gas developments, and to minimise the number of marginal gas developments that are economic before tax but fail to be developed because they would be uneconomic after tax. Being related to revenues and not to costs, the Ad Valorem royalty is a candidate to have its rate significantly reduced, at least for new gas projects. Consideration should be given to deferring the planned increase in the Ad Valorem royalty. A justification for a specifically temporary measure applied to this royalty in the case of gas projects could be the current low gas prices in New Zealand, strongly influenced by use of gas at the margin as a methanol feedstock, and the prospective increase in gas prices as production from the Maui field declines. This increase would lead to a reduction in the prevalence of marginal gas projects. An additional measure could be modification of the Accounting Profits royalty, converting it from a cumulative cashflow based royalty to a rate of return based one. The rate of return at which it begins to operate could be based on an analysis of the pre-tax internal rates of

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return in hypothetical gas fields that would currently be economic before tax but not after tax. The observed behaviour of the Australian Offshore Commonwealth Petroleum Resource Rent tax suggests that a threshold rate of return for field development expenditures 5% p.a. above the long term government bond rate may be too low. While in general it is eminently reasonable that investments yielding high returns should be expected to contribute a higher share of the economic rents to the state the current situation in New Zealand hardly warrants any such increase, given the prime need to attract investment into the sector. The decision of Papua New Guinea to abolish its resource rent tax (which incorporated generous thresholds) was based on this thinking. In the event that very attractive discoveries are made and/or gas prices rise very substantially the notion of modifying the accounting profits royalty to a resource rent tax should be considered.

7.3 Conclusions and Recommendations: Oil Projects

The analysis of the economics of oil developments in New Zealand demonstrates that the measures described above for gas are not required for oil unless there is a very strong desire to protect economically marginal oil developments. Fiscal changes for gas would result in an improvement in exploration economics (while the oil and gas proneness of individual New Zealand basins remains uncertain). Extending the same fiscal changes to oil, again while this uncertainty persists, would be an option if the impact of the gas taxation changes on exploration economics was judged to be inadequate. Conversion of the Accounting Profits royalty into a rate of return based system with a high enough threshold would selectively assist New Zealand‘s (less economic) gas projects even if it were applied to both oil and gas developments.

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8.0 Issues Regarding State Participation in Oil and Gas in New Zealand

8.1 Introduction – Reasons for State Participation

Government investment to explore for and produce oil and gas is not uncommon in the industry and can take many forms, including the provision of infrastructure with and without user charges, equity participation in petroleum projects, and publicly financed exploration. An example of the last are the surveys carried out by the Government of New Zealand in 2007 and 2008. There are several reasons for governments wishing to participate side by side with oil companies in exploring and producing oil in their own countries. The reasons vary among countries around the world and it is a matter for the judgement of the host Government to decide which, if any, are deemed to be sufficiently important to warrant state participation. They may be summarised as follows:

a) To collect a further share of economic rents for the state above those obtained through royalties, taxes and profit-sharing. The extra which accrues to the state is the National Oil Company (NOC)‘s net cash flow after all taxes and other payments.

b) To have indigenous (local) ownership of the activity. State participation is one method of increasing the extent of local ownership. But it could also be done through local private sector oil companies.

c) For additional state control over the activity, through internal decision making. This

motive reflects the view that the oil industry is of such great strategic importance that it should be controlled by the state.

d) To provide expert specialist advice to Government. A Government may lack the

expertise to deal effectively with the oil companies and the experience of operations (even as a partner) may enhance the competence of the host Government.

e) To serve as a vehicle for technology transfer. Host Government may desire the

effective transfer of technology to their country. The provision of up-to-date knowhow and technology to a (state) partner company in a consortium is one way by which this can be achieved. It can be achieved in other ways through licence obligations regarding, for example, training obligations, but technology transfer is more difficult.

8.2 Public Sector Investment in Petroleum

The specific arrangements for public sector investment in petroleum will have an impact on the supply price of this resource. The supply price is the total economic cost required to find, develop, and produce the resource: to allocate capital and labour to resource exploitation, a sum must be paid sufficient to bid them away from their most highly valued alternative use.

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The supply price in turn will affect the economic rent available from petroleum activities. This is because the economic rent is made up of any revenues exceeding the supply price. The concept of economic rent has already been discussed in other parts of this report. Economic evaluation of projects uses discount rates, which are the interest or other cost of capital percentages used to represent the cost of capital/time value of money. Up to this point, it has been implicitly assumed that a resource will be exploited by private-sector organisations and thus that private-sector discount rates are appropriate to the determination of economic rents. It is sometimes argued that public-sector involvement is desirable because social discount rates are lower than private ones and because at least some forms of public-sector involvement can reduce discount rates and thus increase the economic rents available. Governments can generally borrow at lower interest rates than many companies, and Government shareholders may not demand such high dividends. With regard to investment in petroleum exploitation, the absence of the political risk factor (related to policy swings rather than political instability) that contributes to lower public discount rates. The larger potential investors can borrow at interest rates close to government levels but political risk assumes a noteworthy profile in the risk premium incorporated into discount rates in this industry. Government investment in petroleum exploitation can be direct, through equity stakes, or indirect. Indirect government investment would typically take the form of provision of infrastructure. The effect on the private-sector investor‘s supply price depends on whether direct charges are made for the services in question. With no charges, the investor‘s costs are clearly reduced and potential economic rents for the investor increased. If charges are made, the result depends on whether the government or the private investor can provide the service more cheaply, and on any element of profit margin or of subsidy in the charges. With respect to direct government investment, if the government is a full risk-sharing partner (more of this below), this approach could result in the overall supply price of investment being reduced. In addition to enjoying the conventional risk-sharing benefits from having a joint-venture partner, a private investor may feel that a partner in the form of a government corporation or other agency confers benefits in the form of enhanced security surrounding the operation. On the other hand, if the government corporation or agency participates on preferential terms, the result will normally be that the private investor perceives the risk/reward ratio to be altered adversely. The consequence could then be that the private discount rate would be increased. The investor‘s share of costs is reduced less than its share of rewards, increasing relative cost exposure. Direct government investment in exploration is sometimes argued for in circumstances where the risks are perceived to be especially high and where the private discount rate is correspondingly high. Some experts have put forward the additional argument that there are substantial economies of scale in basic geological mapping and so public investment is particularly suitable in this area. The benefits should accrue in the reduction of large risk premiums incorporated by private investors. Alternatively, charges are usually made for the resulting data and as for infrastructure provisions the level of charges affects the economic rent perceived by the investor.

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The governments of developing countries may sometimes be able to obtain loans in the form of aid on advantageous terms. These can contribute to lower discount rates being applied to petroleum investments. On the other hand governments may be highly risk averse in their attitudes to investment in petroleum, especially in situations where they have had no experience of this type of activity. Even when a government obtains funds on concessional terms it may feel that the risks of investing in exploration projects are too high, particularly if the government‘s overall international debt position is highly adverse. In general, government investment is justified if it takes place at an economic cost lower than private investment; the result may an increase in the available economic rents. There also non financial benefits of participation, discussed below.

8.3 Details of State Participation A frequent feature of petroleum exploitation arrangements or licences is equity participation by a national oil company (NOC) or other suitable government investment vehicle. State participation, while not a tax, represents a method by which the government can obtain a share of oil and gas revenues, often an additional share on top of taxation. Part of the government share substitutes for tax on the private sector companies, because participation reduces the tax base for taxation of the other investors. Government participation clauses usually stipulate that the NOC has the right to join in a development project. Key aspects to consider are the time at which the government joins, the costs that the government will bear, how the government will fund its portion of costs, the percentage participation, and the degree of participation in the management of the project. The introduction of state participation and the clarity of the arrangement around its introduction can influence incentives for exploration (see section 8.3.2.1 below).

8.3.1 Time of Commencement of participation

In some countries, the NOC joins the project from the beginning of an exploration contract, which represents the maximum sharing of risk at any given participation level. Some petroleum contracts or licences state that the NOC may indicate its intention to participate ―at any time‖. This is extremely vague and produces an undesirable degree of uncertainty. The provision is consistent with an election to participate on the day before first oil production from a field and as such is not recommended unless this is with repayment of all past costs, plus interest (ideally at the cost of capital). A common arrangement is that the NOC joins as soon as a commercial discovery has been made.

8.3.2 Cost sharing and funding

With regards to the costs that the NOC will pay, and how these will be paid, the following approaches have been used:

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Full risk sharing: the NOC pays its share of costs when required by partners from the commencement of the contract.

Carried interest: an arrangement whereby the other partners pay all or part of the NOC‘s costs of exploration, drilling, testing and completion in a field up to a specified point. The NOC contributes its share of all costs from that time forward. There are various permutations as follows:

o Carried interest with payment at the date of joining: the NOC reimburses the

investor for its share of any applicable past costs at the time of joining. o Carried interest with payment after the date of joining: the NOC reimburses

the investor after the time of joining, possibly out of its production revenues. o Carried interest without payment: the NOC does not pay its share of part

costs. Occasionally agreements have a further provision that the NOC could in effect require that ―the contractor shall advance by way of loan up to 100% of contract expenses‖, which is astonishing and out of line with normal practice in petroleum contracts. It is consistent with an outcome whereby the contractor carries all of the NOC‘s share of development costs. This would not only be very unusual but could even discourage an investor from signing such a contract. Joint operations in the petroleum industry are designed to share risks and costs between the parties. Carried interest at the development stage would generally be regarded by many investors as inconsistent with sharing the cost and (development) project completion risks. A statement that the loan to the NOC would be repaid –even with interest- from the latter‘s share of produced oil means that the risks attached to that, reflecting the behaviour of physical production, oil/gas prices and development/operating costs, are borne to a further degree by the investor. In order to cover its costs of participating in petroleum projects, the NOC or other government agency should have a dedicated source of funding. In some countries a major risk for investors has been the inability of national oil companies to meet their cash call obligations.

8.3.2.1 Analysis of the Effect of State Participation on Exploration Economics

At the exploration stage the investor‘s supply price of petroleum includes the predicted impact of any potential participation, and this impact depends on the terms under which participation may take place. Clearly, the net present value that the investor can expect from developing a discovered field is reduced by the participation of a state company. The effect of participation on the investor‘s incentive to explore can be quite strong, depending on the degree of participation and the rules governing carried interest. An example illustrates the possibilities. An investor contemplating an exploration programme will estimate his expected monetary value (EMV) as follows: EMV = P (NPV) – E

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where P is the probability of making a discovery, NPV is the net present value of the development excluding exploration costs and E is the cost of the exploration programme. Thus on a pre-tax basis, if the probability of success were 1 in 5, the NPV were US$100 million and the exploration costs were US$10 million, the EMV would be +US$10 million (0.2 * $100 million - $10 million). If the rate of state participation were 65% and if the state participated from the beginning as a full risk-sharing partner (i.e. no carried interest) the EMV would become EMV = P (NPV) (1 – SP) – E (1 – SP) where SP is the percentage of state participation. The EMV would be +US$3.5 million. In the case of carried interest participation, with the state company reimbursing the investor for its share of exploration costs only in the event of a commercial discovery the EMV formula would be as follows: EMV = P (NPV – E) (1 – SP) – (1 – P) E The EMV would be –US$1.7 million. In reality, as the reimbursement is delayed the factor SP as it applies to E should be discounted, further reducing the EMV. In the case where the investor was not reimbursed at all for bearing the state‘s share of past exploration costs the EMV would be as follows: EMV = P (NPV) (1 – SP) – E The EMV now becomes –US$3 million. These reductions in EMV occur because the NOC shares in the rewards of discoveries but not fully (if at all) in the costs and risk of exploration. The effect of participation on incentives is thus a function of the extent of the state‘s share taken and the terms of any carried interest provisions. In the example in Figure 83, the calculations are repeated but with a reduction in the percentage of state participation to 25%. All the EMVs have increased, and this lower level of participation on even the least attractive carried interest terms results in a positive EMV (in principle attractive to the investor). The simple examples have not included the complications of taxation. The investor does, of course, normally obtain tax relief on all his exploration outlays and such relief is in practice included in the EMV calculation, together with tax on revenues and tax relief against other costs.

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Figure 83. Effect of State Participation on Exploration (using US$).

Effect of State Participation on Exploration

E = $10 million

NPV of Discovery = $100 million

Chance of discovery (P) = 1 in 5 (20%)

EMV = P(NPV) – E = $10 million

State Participation = SP = 25%

(1) EMV = P(NPV)(1-SP)-E(1-SP)

= 0.2 x 100 x (0.75) - 10 x (0.75)

= + $7.5 million

(2) EMV = P(NPV-E)(1-SP)-(1-P)E

= 0.2 x (100-10) x (0.75) - (0.8) x 10

= + $5.5 million

(3) EMV = P(NPV)(1-SP)-E

= 0.2 x 100 x (0.75) - 10

= + $5 million

8.3.2.2 Analysis of the Effect of State Participation on Development Economics

At the development stage, investors will pay attention not only to NPV, a measure of the value generated by a project, but to an indicator of project profitability such as NPV/I or PI (profitability index). This is the NPV divided by the discounted project costs, normally capital costs alone but occasionally capital, operating and decommissioning costs. When budgets are allocated each year to worldwide exploration and projects, the latter will be ranked in order of decreasing PI. Carried interest, especially with a long reimbursement delay or non reimbursement, increases the discounted cost in this ratio. Thus in times of restricted capital and operating cost budgets, with investments being ―cut off‖ at a relatively high PI value, developments with carried interest may suffer delays. In times of noteworthy capital rationing (such as at present) this effect will be more prevalent.

8.3.3 Percentage of participation

It is not enough to indicate the possibility of state participation on a given licence or contract. In some licences or contracts, the expression ―not less than x%‖ is used, which is too vague. The investor will want to know the extent of his obligation to carry the NOC‘s interest. In other cases, a range with minimum and maximum values of state participation is specified. Contractors are likely to make the ―worst case‖ assumption that the NOC will

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participate to the maximum extent possible and with the optimum (for the NOC) timing, typically at the date of first oil or gas. Contractors may not be aware of the funding arrangements for the NOC, which may mean that it is unable to afford to participate. In some countries, consideration is given to making state participation progressive in a similar way as fiscal terms such as sliding scale royalty, or resource rent tax. It is thus good practice to specify precisely the size of the NOC‘s share on the licence or contract. Guidelines for specifying the percentage could include those set out in section 8.3.2

8.3.4 Amount of participation in the management of the project

Beyond increasing government revenues, state participation is seen as vehicle for transfer of technology and skills. Being a working interest partner usually means that the NOC has better access to data and information and that NOC personnel can attend Operating and Technical Committee Meetings. It is in such meetings where significant insight can be gained into other companies‘ decision making as well as industry standards and practices. Also, NOC personnel can gain experience. This can be especially powerful for governments with little experience in the oil industry. To facilitate the transfer of knowledge participation by the NOC in the management of projects should be encouraged while avoiding bureaucracy and bottlenecks. A possible issue is the additional personnel resource requirements on the NOC to take advantage of this participation. The transfer of technology and skills can also extend to other parts of the government in terms of capacity building, whereby government departments develop human resources well equipped to supervise the oil and gas industry and formulate policies for its future development. However, it has also to be weighted that in countries with limited technical human resources, the creation of a NOC would create additional strain for some government departments as they try to recruit and retain staff.

8.4 Other considerations in State Participation

In some countries the national oil company has several roles such as those of:

(a) A regulatory agency on behalf of the government, (b) an exploration and production investor (sometimes including operatorship),

and (c) a supplier of equipment and services.

There is evidence of conflicts of interest in some countries resulting from the above. Where the NOC is active in exploration & production, regulation is better undertaken by a separate Government body. An example of this is Norway, where Statoil and Petoro have NOC duties but not regulatory ones, which fall to the Norwegian Petroleum Directorate.

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When a state company is an operator or has a major share in a contract there may be conflicts of interest when the same company (or an affiliate) is involved in the supply of equipment and materials. Arms-length relationships are preferable.

8.5 International experience

Around the world there are many, varied schemes for state participation. State participation can take place irrespective of whether there is a concessionary fiscal or contractual petroleum regime with production sharing contracts.

8.5.1. Comparison of regimes

Of the countries selected for the comparative analysis of petroleum regimes (discussed in other parts of this report), Australia, Thailand and India do not currently pursue state participation in new petroleum projects and Australia has never done.

8.5.1.1. China

In China, foreign investment in petroleum exploitation can only take the form of ―cooperative development‖ with the state oil company, which in offshore contracts is CNOOC. With respect to the petroleum joint venture, the model contract provides that ―all exploration costs required for Exploration Operations shall be provided solely by the Contractor‖; and the contractor must bear the cost and risk of exploration if there is no commercial discovery. CNOOC is carried by the contractor throughout the exploration period. Upon a commercial discovery, the state company has the right to participate with a 51 percent working interest after the appraisal work has been completed and the decision for development has been made. The development costs required are to be shared by the partners in proportion to their participating interest, namely 51% for the CNOOC and 49% for the contractor. The provision of a majority interest for the state oil company has significant political implications. According to Chinese law officials, the 2 percent equity advantage is viewed as representative of China‘s permanent sovereignty over its petroleum resources. The joint venture is managed by a board of directors in the form of a Joint Management Committee (JMC), composed of one to three representatives from both CNOOC and the contractor and chaired by one of the members. The JMC holds regular meetings at least once a calendar quarter. The organisational structure of the Chinese contract is dominated by a joint venture format which makes day-to-day operational decisions as well as broader planning and budgeting decisions. Such an arrangement allows China greater control over petroleum operations while the oil company takes the exploration risks. The contractors are required to bear all primary responsibilities for carrying out the petroleum operations during the life of the contract, while CNOOC is required only to assist the contractor, ―at its request‖, in the performance of its tasks.

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In addition to regular obligations, the Chinese contracts provide that production operations are to be gradually assumed by CNOOC. The state oil company has the unilateral right to ―take over‖ production operations at any time after the development costs have been recovered in full by the contractor. The expenses incurred in the transfer and takeover are charged to the operating costs. This is the assumption of complete operational control, not nationalisation.

8.5.1.2. Papua New Guinea

In Papua New Guinea, and pursuant to the Oil and Gas Act, the State has the right, but not the obligation, to acquire from the licensees up to a 22.5% interest in any petroleum project. Petroleum Agreements provide that this option may be exercised at the time of grant of a petroleum development licence. As from the 1st of January 2003, if the State exercises its option, it is exercised immediately at the time of grant of a petroleum development licence. If the State chooses not to exercise its option, the option will lapse. The interest is acquired either directly by the State, a wholly owned company called the Mineral Resources Development Company Pty. Ltd. (MRDC) or a State nominee, such as Petromin. The price payable by the State is equal to the elected percentage (normally 22.5%, but may be smaller if the State elects to take a lesser interest) of the costs incurred in the 20 years prior to the grant of the petroleum development licence, including exploration expenditure anywhere in the underlying petroleum prospecting licence. The State or its nominee becomes a full joint venture participant, and (subject to the carry provisions referred to below) is liable for its share of all development and operating expenses. The Petroleum Agreements contain provisions which oblige the licensees of a petroleum development licence (other than the State or its nominee), in circumstances where the State has exercised its option to acquire an interest, to carry the State or its nominee for both the initial acquisition costs and all subsequent development and operating costs. This carry is repaid out of production from the State‘s interest (excluding the 2% landowner equity), which is foregone until the carry is repaid in full, with a commercial rate of interest. Out of the State‘s 22.5% equity entitlement, a 2% interest shall be provided to project area landowners without charge. This interest is held for the landowners by a trustee company, which becomes a full joint venture participant. This interest is unencumbered up to the commencement of commercial production, but thereafter the trustee is responsible for all capital and operating expenses attributable to the interest in question.

8.5.1.3. Thailand

Thailand eliminated in 1990 mandatory equity participation requirements for new concession agreements. When these already exist or have been negotiated, the concessionaire agrees to set aside up to a maximum of 20% working interest for participation by the Thai government and/or Thai nationals (collectively ―Thai participants‖) after a commercial discovery. Upon election to participate, all past, present and future exploration, development, operating, and production costs will be borne to the extent of 20% by Thai participants.

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8.5.1.4. India

India does not have mandatory state participation through state companies or any carried interest of the government under their New Exploration Licensing Policy (NELP). The 2007 model PSC shows that all members of a contractor group are to be treated equally. In the past, NOC‘s used to be carried up to 40% during the exploration phase.

8.5.2 Other countries

8.5.2.1. Angola

Following independence from Portugal the government of Angola set up a national oil company, the Sociedade Nacional de Combustíveis de Angola (Sonangol), in 1976, and in 1978 issued a law that made the government the sole owner of Angola‘s petroleum mineral resources and Sonangol the sole Concessionaire for their exploration and extraction. Sonangol was permitted to enter agreements with international oil companies to carry out oil operations in areas, or blocks, designated by the Ministry of Petroleum. Companies carrying on oil operations in Angola are therefore often described as companies associated with the National Concessionaire. As it will be described in the next paragraphs, in practice Sonangol entered into joint ventures with the oil companies already operating concessions in Angola since pre-independence times. Later agreements took the form of PSA‘s. In 1978 the government authorised Sonangol to acquire a 51% interest in the existing pre-independence on-shore (FS-FST) and off-shore (Block 0 - Cabinda) concessions. (Sonangol later reduced its interest in the Cabinda concession to 41%) Sonangol entered into traditional equity partnership joint ventures with the international oil companies operating these concessions. These equity partnerships are governed by Joint Operating Agreements. Under these agreements the international oil companies are considered to be owners of the oil installations and of the oil produced from them. In the early 1980s other shallow water offshore blocks began to be awarded through a competitive bidding process. The new concessions took the form of production sharing agreements (PSA‘s). Companies operating under PSA‘s function as contractors to the National Concessionaire Sonangol, which owns the installations and a share of the oil produced. The PSA governs the relations between the contractor companies and Sonangol. There is normally a separate Joint Operating Agreement (JOA) governing the relations of the contractor companies to each other. The PSA contains most of the same features as the JOA. But it allocates more extensive rights and responsibilities to Sonangol than are normally allocated to a joint venture partner under a commercial JOA. In particular the PSA provides for the determination of cost recovery, cost recovery oil and Sonangol profit oil.

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The Law of 13/78 also provides that Sonangol can become an equity participator in a block. Sonangol is a participator in the majority of blocks, mainly through its exploration and production subsidiary, Sonangol Pesquisa & Produção (Sonangol P & P). Where Sonangol becomes a member of a contractor group under a PSA, it in effect assumes the role of associate of the National Concessionaire. This means that is partly responsible for supervising its own activities as a contractor. Normally it would be Sonangol E.P. that was responsible for supervising Sonangol P & P. The Government is responsible for decisions on the extent of Sonangol‘s equity participation. For example the Government decided that it was in the nation‘s strategic interest that Sonangol should participate in the deepwater blocks. Typically Sonangol‘s share in these blocks is 20%. Sonangol‘s participation in some blocks has been on a carried interest basis at the exploration stage. The contractor group may typically recover these carried exploration costs from Sonangol‘s share of cost oil if a commercial discovery is made. Under the terms of the PSA‘s Sonangol is also entitled to carry out sole risk operations i.e. it can carry out, at its own expense and risk, operations that the operator does not wish to undertake. In the latest licensing round, initiated in 2007 and delayed due to elections and the current economic crisis, Sonangol has continued to include provisions for state participation, and these are intended to be non biddable or fixed. These provisions vary slightly depending on whether the block is onshore, on shallow offshore, deepwater or ultra-ultra deepwater. Table 21. State participation provisions in the latest Angolan licensing round. Types of acreage Terms Onshore Cabinda

Block Kwanza Onshore Blocks (2)

Offshore and deepwater

Ultra-ultra deepwater

Participation by Sonangol P&P

50% Not fixed 65% and will be the Operator.

Not fixed

Terms of participation – Bonus and Social Contribution

Signature bonus and the contribution for social projects are neither amortizable nor recoverable and to be paid by all members of the Contractor Group with the exception of Sonangol P&P. All Contractor Group companies, including Angolan Companies must pay their share on the Effective Date of the PSA.

Percentage participation carry

20% 20% 15% 20%

Terms of participation – Details of carry

Except in the Kwanza onshore blocks, carry occurs during the exploration phases and will be supported by all other members of the Contractor Group. Carry is recoverable for all other members of the Contractor Group from the Sonangol P&P share of the cost oil.

In the Kwanza onshore blocks there is also the requirement of 70% participation on the Contractor Group by Angolan companies. The definition of an Angolan Company to be considered is the one found on the Law nº 14/03, Law on the Promotion of the Angolan

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Private Businesses. The Angolan companies have preferential terms, such as paying their share of the Contribution for Social Projects on instalments (40% on the first Commercial Discovery Date and 60% on the date of the First Oil). The Angolan companies are not required to partake in the carry of Sonangol P&P costs. That is, the carry during the exploration phases will be supported by the non-Angolan Companies only. Carry is recoverable for all non-Angolan Companies of the Contractor Group from the Sonangol P&P share of the cost oil. The above terms are stricter than in the past. The terms sketched in the notice inviting offers could be modified without notice in the next months, depending on the world economy and the level of interest shown on the acreage (as it has happened in Algeria and Uruguay this month). However, given the high prospectivity found in Angola historically it could be expected that the state participation terms would be accepted by investors for deepwater acreage. It can be argued that this will not be the case for onshore acreage given the state and Angolan participation terms, unless foreign state companies or majors participate.

8.5.2.2. Tanzania

While the United Republic of Tanzania has limited gas and condensate production, its model PSA incorporates a method of deciding the level of state participation that is worthy of analysis. The national oil company of Tanzania, TPDC, may elect to participate in Joint Operations and to contribute in the ―Specified Proportion‖ to Contract Expenses other than Exploration Expenses in a given development area. Joint Operations shall be conducted under the terms and conditions of an Operating Agreement to be concluded between TPDC and the Contractor, without changing the original operator of the area. A Joint Operating Committee shall be established on which all Contractor entities and TPDC shall be equally represented. Failure by any party to meet calls for funds within the time limits agreed shall result in liability for interest on the unpaid amounts for the period that such amounts remain unpaid at the going market rate. The ―Specified Proportion‖ means a proportion which does not exceed the maximum indicated below with respect to the daily total production rate in the entire Contract Area, which in turn depends on the type of acreage (see Tables 22 and 23). This method has been used in one signed PSA which is still in the exploration phase due to force majeure. Other recently signed PSA‘s have a fix percentage of possible state participation, in the range of 5 to 10%.

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Table 22. State participation provisions for onshore and shelf areas in the latest Tanzanian contracts.

Table 23. State participation provisions for onshore and shelf areas in the latest Tanzanian contracts.

Daily total production rates in Contract Area - deepwater areas

Maximum Specified Proportion

0 to 49,999 5%

50,000 74,999 7.5%

75,000 99,999 10%

100,000 124,999 12.5%

125,000 149,999 15%

150,000 199,999 17.5

200,000 and above 20%

8.5.2.3. Nigeria

The exploitation of petroleum in Nigeria is managed through legislation and two different contractual relationships. The most recent of those is the PSA. The other constitutes joint ventures between international oil companies and the Nigerian National Petroleum Company (NNPC) structured under a joint operating agreement (JOA) as set out in a memorandum of understanding (MOU). NNPC is supposed to partake in the financing of the joint ventures as any other partner. But NNPC does not have funds of its own and must rely on the state budget to finance its joint ventures with the likes of Royal Dutch Shell, Exxon, Total or Chevron.

Daily total production rates in Contract Area - onshore and shelf areas

Maximum Specified Proportion

0 to 12,499 5%

12,500 24,999 7.5%

25,000 49,999 10%

50,000 74,999 12.5%

75,000 99,999 15%

100,000 149,999 17.5%

150,000 and above 20%

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Oil companies often complain NNPC is unable to contribute its share of the funds required for projects and this complicates their execution. Most of the international oil companies have had to provide billions of dollars in bridge financing to NNPC to plug funding gaps. Earlier this year NNPC signed a $1.69 billion funding agreement with Shell to cover its share of investment in the Gbaran Ubie integrated oil and gas project. The government of Nigeria intends to reform its petroleum institutions, starting with NNPC. One of the aims is to change it into an entity able to turn to the capital markets for funding.

8.5.2.4. Russia

Some of the proposed Russian Joint Ventures (JV) are characterised by a 100% carry for the production association partner through development and operating costs as well. This is an extreme example of government participation. However, most of the Russian JVs deal with well-delineated reservoirs. The exploration risk aspect is greatly diminished.

8.6 Conclusions

State participation in petroleum exploitation is common in the Middle East, Asia, Africa and Latin America. The motives for such participation vary from country to country and were summarised in Section 8.1 where 5 common reasons were identified. The importance of each of these to policy makers will depend on political as well as economic considerations and on the circumstances of the petroleum industry in each country. Thus, for example, in cases where a host country already has well-established private sector oil companies there may not be a perceived pressing need to enhance the indigenous ownership of the activity. In countries where there is a clear capital shortage there will be a problem in financing the operations of the state company, and, if participation is denied for other reasons, the concept of carried interest will probably loom large. As a generalisation, in countries with serious capital shortage the collection of economic rents is clearly better accomplished by royalties, taxes and profit-sharing arrangements. The view of most Western economists is generally that from an economic viewpoint state participation is unnecessary unless there are indications of market failures.

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9.0 Economic Assessment of Gas Hydrates in New Zealand

9.1 Introduction

Gas hydrates are crystalline compounds containing mostly methane (>90%), the main component of natural gas, in an ―ice cage‖ structure. They can form when water or ice and suitably sized molecules are brought together at low temperatures and elevated pressures. Thus they tend to form in some marine and deep lake sediments as well as in the subsurface of arctic permafrost regions. The presence of large amounts of gas hydrates has been identified in several parts of the world. As gas hydrates are not chemical compounds, that is, the sequestered methane molecules are never bonded to the ―cage‖, it is possible to decompose them by collapsing the structure and secure a large release of gas. Once the methane has been extracted it can be further transported and processed using conventional natural gas technologies. Based on this, it is judged that these vast natural reserves could become a source of energy in the future. Both governments and the industry have been researching into the detection, characterisation and extraction of gas hydrates in recent decades. While no gas is commercially produced from gas hydrates anywhere in the world, considerable efforts are being made and knowledge developed. Advanced techniques to accelerate methane recovery are being developed and further production testing has been proposed in a number of geological provinces. New Zealand has one of the largest single gas hydrate provinces in the world. Gas hydrate deposits occur along the East Coast (Hikurangi) and Fordland margins in water depths of up to 1000m. Current estimates by New Zealand research bodies place the extent of the hydrate resource contained in the Hikurangi Margin area at around 840 trillion cubic feet (Tcf) of natural gas equivalent, 21 Tcf of which is identified as being in ‗sweet spots‘ or areas of potentially commercially viable development at depths around 300m below seabed. If fully developed, the hydrate in sweet spots could supply New Zealand‘s current natural gas requirements for more than 100 years. AUPEC was requested by the Ministry of Economic Development to make a broad assessment of the economics of producing natural gas hydrates in New Zealand. To assist us with this, we were provided with a series of studies undertaken on behalf of the Ministry, plus relevant presentations from past New Zealand Petroleum Conferences. The main study that AUPEC used was entitled ―An options analysis for the commercial and economic development of offshore methane hydrates as a future energy option for New Zealand‖ by the New Zealand Centre for Advanced Engineering (CAENZ). This study consolidated the available scientific knowledge and international learning with the intention of developing a possible road map for the commercial production of gas hydrates in New Zealand. The study also included an analysis of the potential of gas hydrates to provide an economically competitive alternative to or replacement for indigenous and imported fuels including gas. This was on a pre-tax basis and the assumed gas prices differed considerably from those in the data provided by the Ministry for conventional gas

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production, in some cases with national gas exports or imports at the margin being in the opposite direction. AUPEC used part of the study as the basis of a similar economic and fiscal examination to that presented in sections 4 to 7 of this report. This assessment permits AUPEC to provide comments on the applicability of the existing New Zealand fiscal regime to this energy source.

9.2 Economic Assessment of Gas Hydrates

The evaluation criteria and the modelled details of the New Zealand fiscal regime were as described in sections 3.1 and 3.2 of this report.

9.2.1 Resource and Cost Assumptions

Part of the CAENZ study involved producing a high level well development plan based on the premise that a gas hydrate ‗sweet spot‘ exists on the Wairarapa site on the East Coast of New Zealand‘s North Island. This site is expected to be a model candidate for the future development and production of methane from hydrates, due to hydrate concentration and proximity to land and to a major demand centre in Wellington. The cost estimates used for the scenarios in the CAENZ study were derived from S. Hancock‘s presentation to the 2008 New Zealand Petroleum Conference and independently corroborated by Transfield Worley Services, a local engineering and construction services company with experience in the development of the Taranaki exploration and production sector. As such, the costs assumed in the CAENZ study provide robust data on which to base an economic analysis. It is important to note, however, that the reader can interpret the economic results at the base case gas price of $7/mscf by looking up lower or higher unit development costs in the charts than the ones currently assumed. The costs provided by the Ministry were given both in New Zealand and United States dollars. An exchange rate of US$0.6 per New Zealand dollar was assumed and we have adhered to this. Developments with production rates of 10, 150 and 300PJ per annum (9.5, 142.5 and 285 bcf per annum respectively) were used to illustrate the impact of key assumptions and uncertainties on the economic analysis. Additionally, a ‗composite‘ or phased scenario, which envisaged the development of a 9.5 bcf p.a. ‗proving project‘ as a precursor to a major 285 bcf p.a. facility was used in order to illustrate a possible staged development pathway. For all offshore prospects, it was assumed that

Hydrates will be located at approximately 300m below the seabed at water depths of 1000m

There will be an assessment phase over a ten year period. This includes the development of the hydrate extraction technology and the characterisation of the hydrate resource. The second stage of the composite scenario includes an additional five year assessment phase

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After the assessment there will be a phase of front-end engineering design (FEED), conducted over a three year period for the larger reserve scenarios, two years for the smallest reserve scenario and two years for each stage of the composite scenario

The drilling and construction times will be a total of three years for the larger reserve scenarios and two years for the small scenario, after the end of the FEED phase. The composite scenario has an initial two year drilling/construction phase and a later three year one

The basic production process will be to reduce the pressure in each well by pumping out gas and liquids, thus causing more hydrate to dissociate into gas and free water. This process will be enhanced by chemical injection and the produced water will need to be separated, cleaned and disposed of

Production will start during 2023 or 2025 depending on the size of the (initial) project

Production will be through well clusters composed of six wells each, connected to a Tension Leg Platform (TLP)

The output from the platform will be piped to the North Island and additional connections to the grid will be required depending on the size of the field. If production volumes exceed local demand, liquefaction facilities will be required in order to permit export

The reserves to be produced will be 250, 3750 or 7500PJ (237.5, 3562.5 or 7125 bcf respectively) i.e. 25 year plateaux were assumed for all the single stage scenarios.

Key technical issues identified were the realities of having to operate gas hydrate fields below the typical abandonment pressure for conventional gas reservoir production, the much higher water production rates that will arise and flow assurance from wellhead to production facilities. This in turn will require a larger number of production wells than is needed in conventional gasfield development and will result in higher operating costs. It was assumed that, due to the characteristics of the hydrate reservoir, wells will need to be replaced every 10 years and this was included in the costs. All costs were evaluated in mid 2009 US$. Costs for 3 reserve cases were included in the analysis outlined in Table 24. In the composite case, the level of operating costs changes for the second, higher production rate, stage and if liquefaction is required the operating costs of the NGL plant commence at the same time. Capital costs for liquefaction were taken from the conventional gasfield data ($1500m for a 5000 bcf reserve) after applying a 0.6 power rule (capital cost proportional to capacity after raising it to the power 0.6). Operating costs were taken from the same source ($2/GJ, $2.105/mscf gas produced at the wellhead). A key economic issue is whether the gas from a hydrate development will need to be exported at any given production or reserve level. Current New Zealand gas demand is approximately 154 PJ/year (146 bcf/year). Hydrate gas production from a 237.5 bcf, 9.5 bcf/year development should therefore be easily absorbed within New Zealand if it starts up in 2023.

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Table 24. Cost Breakdown for Gas Hydrate Scenarios

US$ Million

Basic 237.5 bcf 3562.5 bcf 7125 bcf 7125 bcf

composite

Assessment 25 40 101 101

FEED 43 79 252 252

Other Capex 294 2181 5035 5035

Opex p.a. 16 168 199 49/199

Abandonment 5% of Other Capex

Incremental for Liquefaction

237.5 bcf 3562.5 bcf 7125 bcf 7125 bcf

composite

Capex n/a 1224 1855 1855

Opex p.a. n/a 300 600 0/600

Fuel and Flare n/a 10% of produced gas

Abandonment n/a 5% of Capex

In the conventional gas case it was assumed that liquefaction would be required for a 5000 bcf reserve. It will therefore be required for a 7125 bcf one. Indeed, even if Maui production ceased completely and no other gasfields were still producing in 2025, gas demand growth of 4.27% p.a. would be required to absorb the full 285 bcf/year of hydrate gas production when the field started up in that year. For the composite scenario, the situation is not so clear. On the same basis, a gas demand growth rate of at least 2.83% p.a. would be required to accommodate the production of the second stage when it started up in 2033. Even if the rate of economic growth in New Zealand were as high as 2.83% p.a. over the next 24 years, the incremental energy intensity might be less than 1, leading to a need to export incremental gas production as LNG, especially if gas were to decline in competitiveness relative to other energy sources in New Zealand. In 2025, output from a 3562.5 bcf reserve at 142.5 bcf/year would represent 97.6% of current demand. Both a carefully developed gas demand forecast and a similarly reliable supply projection from existing, planned and probable fields would be required in order to establish the need or otherwise for liquefaction of this incremental gas supply. Economic results have therefore been generated for the larger fields and for the composite scenario with and without export as LNG. Only the results for a 7125 bcf reserve without liquefaction are to be considered ―for information only‖, i.e. almost certain to be discounted in practice. It should be noted that the above discussion is for a single gas hydrate development. Any second or further hydrate gasfield other than a 237.5 bcf type development or a very carefully phased in ―composite‖ style one would require liquefaction.

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9.2.2 Gas Price Assumptions

To cover a range of possible gas prices consistent with our oil price assumptions made in section 3 of this study we ran economic models at US$ 4, 7, 10 and 13/mscf (60%, 70%, 75% and 78% parity with crude oil respectively) in 2009 terms. To the extent that high oil prices reflect pressure on oil reserves, it is reasonable to expect the market to look more to gas as a replacement fuel under those conditions and for gas prices to move towards thermal parity with oil. New Zealand gas prices are currently low, heavily influenced by abundant supply and by incremental gas production being used as a methanol feedstock. First gas from the notional projects analysed in this section, however, is assumed to occur in 14-16 years time, when production from the Maui field will have declined to the point where New Zealand gas prices should be close to the international levels we have assumed (unless, that is, there is significant oversupply from pre-existing hydrate or other non conventional sources, or an unexpectedly large volume of conventional gas discoveries). The above prices (in 2009 US dollars) were applied in the economic models throughout the economic lifetimes of the notional hydrate gas developments studied. We do not have cost estimates for LNG transport to likely markets for New Zealand LNG or for regasification in these locations. If New Zealand were exporting LNG to markets where wholesale gas prices were $4, 7, etc. per mscf the price netted back to a New Zealand gas hydrate field would be lower. Ideally the reader will attempt to adjust for this when interpreting our results.

9.2.3 Results

Table 25 shows the net present values at a real terms discount rate of 10% p.a. and under the New Zealand fiscal regime that will apply after the end of 2009 of the various notional hydrate developments at their most likely unit development costs and at the four gas prices adopted in this study. Selected results for conventional gasfields are included (in the bottom half of the table) for comparison purposes. The reference date for discounting is 1.7.2009. The results for reserves of 237.5 and 3562.5 bcf (as long as export as LNG is not required) are very similar to those for conventional gasfields in the Great South Basin (interpolate between 237.5 and 3562.5 bcf when comparing with 2500 bcf conventional). Having said this, the caveat discussed above over LNG prices netted back to New Zealand being lower than prices in end markets should be borne in mind. Above 3562.5 bcf the economic results are poorer (interpolate between the 3562.5 bcf LNG and the 7125 bcf LNG cases when comparing with 5000 bcf conventional exported as LNG). As for conventional gas, low profitability in comparison with oil developments stems from gas prices below parity with oil on a heat content basis, higher operating costs and long production plateaux. In addition to the caveat about netback pricing in the LNG cases, it is important when considering all the hydrate scenarios to remember that 10-15 years of assessment costs

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have had to be included in the economic evaluations. This is untried technology, with the possibility of failure and a greater probability than with conventional gas that production profile, cost and other assumptions will prove to be inaccurate. If lack of success becomes evident it may be possible to cease development during or near the end of the assessment phase with little economic regret, but failure at a late stage of a hydrate project would entail large losses. Given a successful track record, however, later developments will not incur the assessment costs we have included. Table 25. Real Terms Net Present Values (10% p.a.), US$ Billions

Reserves 237.5 bcf

3562.5 bcf

7125 bcf

7125 bcf composite

3562.5 bcf

LNG

7125 bcf

LNG

7125 bcf composite

LNG

US$/mscf devex

1.53 0.65 0.76 0.76 0.85 1.02 1.02

Gas Price

$4/mscf -0.06 0.06 0.16 -0.02 -0.48 -1.00 -0.56

$7/mscf -0.01 0.60 1.21 0.48 -0.01 -0.07 -0.11

$10/mscf 0.03 1.13 2.27 1.01 0.47 0.88 0.36

$13/mscf 0.07 1.66 3.34 1.53 0.95 1.84 0.83

Reserves 250 bcf

conventional 2500 bcf

conventional 5000 bcf conventional LNG

US$/mscf devex

1.53 0.67 0.69

Gas Price

$4/mscf -0.03 0.03 -0.26

$7/mscf 0.04 0.48 0.70

$10/mscf 0.12 0.88 1.67

$13/mscf 0.07 1.30 2.63

At least as much so as with conventional gas it is therefore crucial to improve the economics of New Zealand gas hydrate developments, and to minimise the number of marginal gas hydrate developments that are economic before tax but fail to be developed because they would be uneconomic after tax. The 7125 bcf ―composite‖ hydrate cases have results very similar to those for 3562.5 bcf, both with and without export as LNG. This is because the deferment of the date of attaining the second stage production rate of 285 bcf/year, and the deferment of the costs of stepping up production, when discounted at 10% p.a. in real terms happen to be more or less equivalent to producing at half that rate as soon as possible. At a higher discount rate, the results for the composite scenario (except for sub-economic, negative NPV cases) would be poorer than those for 3562.5 bcf because the impact of discounting the (positive) annual net cashflows would be larger.

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Figure 84 shows the unit development cost sensitivity of the non LNG cases at the base case gas price of $7/mscf. The Y axis shows NPVs in US$ billions, and it has been possible to use a narrower unit development range along the X axis than for conventional gas ($0.65-1.55/mscf instead of $0.4-1.9/mscf). As indicated above, the plot for the 7125 bcf composite scenario lies very close to that for the 3562.5 bcf case, only diverging at high unit development costs. Figure 84. Development Cost Sensitivity, Non LNG Cases at $7/mscf

-3

-2

-1

0

1

2

3

4

0.65 0.8 0.95 1.1 1.25 1.4 1.55


237.5 bcf

3562.5 bcf

7125 bcf

Composite

Figure 85 shows the unit development cost sensitivity of the LNG cases at the base case gas price of $7/mscf. The Y axis again shows NPVs in US$ billions, and it has been possible to use a narrower unit development range along the X axis than for conventional gas ($0.65-1.55/mscf instead of $0.4-1.9/mscf). Starting from a lower level because of their higher operating costs and the 10% gas consumption as fuel and flare, the LNG cases have about a one third greater sensitivity to unit development cost than the non LNG ones (the plot for 7125 bcf falls by $2bn from the left hand side to the right, in comparison with approximately $1.5bn in Figure 84).

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Figure 85. Development Cost Sensitivity, LNG Cases at $7/mscf

-3

-2

-1

0

1

2

3

4

0.65 0.8 0.95 1.1 1.25 1.4 1.55


3562.5 bcf NGL

7125 bcf NGL

Composite NGL

9.3 Conclusions and recommendations

Given the youth of this branch of the industry and the level of scientific knowledge of gas hydrate production, there cannot be a definitive answer to the question of the likely commercial viability of gas hydrate production. Every field development must stand on its own merits and commercial drivers will differ according to market conditions and regional energy security issues. We have identified that the changing pattern of New Zealand gas self sufficiency may produce large differences between individual hydrate developments, particularly if there is a need for LNG exports as hydrate fields are developed. Gas prices could rise considerably from current methanol feedstock values in response to declining production from existing conventional fields and then fall back again as hydrate fields are developed, albeit probably not down to today‘s levels. Technology for hydrate extraction and processing is in its infancy, with no development having been commercialised as yet, which places a high level of uncertainty on the cost and production estimates used in this analysis. Based on the best information currently available, the review undertaken by AUPEC suggests that the potential economics of hydrate production are marginal, but similar to those of conventional gas production when reserves are lower than about 3500 bcf. Above this level, conventional gas production becomes slightly more economic than gas hydrate exploitation. We have already recommended special fiscal terms for gas, and our review of gas hydrates suggests that fiscal terms improving the economics of conventional gasfields and protecting marginal ones will be adequate for hydrate gasfields, at least in the lower half of the reserve range we have evaluated.

Care should be taken to ensure that legislation, regulations and the Minerals Programme refer clearly to gas from hydrates as well as to conventional gas production. Several countries in the world use similar inclusive petroleum definitions as that used in the Crown Minerals Act 1991. However, in the spirit of clarification and to strengthen the regime we

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consider that there could be benefits in adding gas hydrates to the definition of petroleum in the Act or having them in a separate definition, which is a potential area for further study. An example of the latter is India, which in its Petroleum and Natural Gas (Amendment) Rules, 2003 included a definition of ‗gas hydrates‘ relating it to natural gas. In addition to this, the Government of India included this resource in the provisions dealing with royalty on petroleum, directive to prevent waste, restriction of production and prevention of escape of petroleum and water ingress. The government of New Zealand has the capacity to support and participate in research into hydrate gas production, perhaps taking part in international as well as national studies. In the short term, this may be a better strategy than introducing additional fiscal measures over and above those that should be introduced for conventional gas. Broad economic assessments of hydrate gas production, such as the one we report on here (and with increasing sophistication as more knowledge is gained) should be carried out at frequent intervals until uncertainty is considerably reduced. Depending on the developing relationships between conventional gas and oil economics, and between hydrate and conventional gas economics, it may become desirable to modify any special fiscal terms for conventional gas, to differentiate fiscally between conventional gas and hydrates and perhaps even to have a separate Minerals Programme for gas hydrates. None of this is clear at the moment, however, and monitoring via regular broad economic assessments should be accompanied by an appropriate level of flexible framework review as to whether it would be advisable to have a separate Minerals Programme for gas hydrates or simply gas hydrate specific provisions in the Mineral Programme for Petroleum existing at that time, or even provisions identical to those for conventional gas and eventually perhaps the same as those for oil.

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10.0 Lessons from international experience on managing wealth created from the extraction of petroleum resources, with focus on establishing oil funds

10.1 Introduction

The nature of oil revenues implies that they should be treated differently from other main sources of tax revenue such as personal income tax, VAT, profits tax on manufacturing industry, etc because they emanate from the depletion of a non-renewable natural resource. A significant number of countries (advanced and emerging) with major oil and gas reserves have created ‗wealth funds‘, sometimes known as ‗oil funds‘, into which they have invested their returns from oil and gas reserves. Oil depletion is comparable to depreciation of a nation‘s capital stock and the basic function of an oil fund is to facilitate sustainable financial resource management, allowing returns from non-renewable oil and gas revenues to be converted into a pool of renewable assets. These assets could then be used to generate wealth long after a country‘s oil and gas reserves have been exhausted thus compensating for the depletion effect. Thus, many oil- and gas-exporting countries consider the build-up of an oil fund more as a strategic objective than a by-product of surpluses generated by a combination of production policy and international market prices. This brief paper surveys oil funds and other related schemes internationally and identifies lessons relevant for New Zealand.

10.2 The Purpose of an Oil Fund

There has been a proliferation of oil funds in the last decade. Nevertheless, there are significant challenges to ensure that oil funds are effective. There is a consensus that oil-rich countries should save some of their oil revenues for future generations against a time when the oil would run out. This should be done in a transparent way and money should be managed prudently. Oil Funds can serve a variety of public policy objectives:

long-term fiscal sustainability;

inter-generational equity;

macroeconomic stabilisation;

efficient resource allocation within the economy;

promoting industrial diversification;

providing local benefits; and

developing sustainable energy. Oil funds can help to stabilise the macro-economy, limiting any inflationary effect on demand when oil and gas prices rise sharply, and helping to cushion demand when oil and

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gas prices fall. However, the stabilisation mechanism depends on a reliable forecast for the oil price—too high a forecast could deplete the fund, and then the sanctity of the savings fund could be questioned. If the price stays at a specified reference price, all revenue could go to the budget: however, this revenue, which would be expected to increase with the anticipated increases in production, might be inadequate for a number of reasons—for example, production might fail to keep up with the forecast, or needs might accelerate more rapidly as a result of some unforeseen circumstance. Oil funds can also be used as a mechanism to assist in economic diversification. Spending on diversification to strengthen the economy will serve for a time when the importance of oil and gas revenues decline. Local communities can benefit from the extraction of natural resources in their area. Ring-fencing a share of the revenues for local residents could potentially off-set social costs on local residents such as the rundown of construction yards. The fund in the Shetland Islands is partly designed to ensure that diversified economic activity is brought forward when the oil-related activities run down. One of the challenges to ensure that oil funds are effective is to clearly define and design with the established operational objectives of the oil fund. Operational rules cover specific principles for the accumulation and withdrawal of resources; asset management principles; and governance, transparency, and accountability provisions.

10.3 Some Operational Concerns

The size and growth of an oil fund should be determined on the basis of the overall macroeconomic policy. In some countries, the rules for paying in and withdrawal determine the size of the fund. Where countries have created an oil fund as an instrument of saving for future generations, the desired size of the fund is usually determined by reference to a policy of attempting to keep the wealth of the fund intact, by spending on average only the ―permanent‖ income from the oil wealth as part of its overall policy. Where the fund is created for stabilization purposes, the magnitude of the fund depends on the expected volatility of the revenues and the average spending needs of the government. Where governments have established a separate oil fund for the purposes of saving or stabilization, the accumulated sums should be invested to preserve or enhance its value over time. The choice of asset classes and asset managers, and the oversight of the performance of the fund are key issues in obtaining the best return from the country‘s mineral resources. In the case of savings funds, the main aims are spending in each period oil revenues of magnitudes such that the value of the wealth from oil—below the ground, invested in the oil fund, or both— remains at least constant, thus permitting the same level of incremental total government expenditure to be continued indefinitely. Two considerations may modify the desire to keep a constant level of incremental expenditure: a) early years of oil revenues may result in permanent income being greater than the revenue itself, so that the country would have to borrow to finance expenditures equal to permanent income; and b) immediate needs for spending may lead governments to spend more than the permanent income particularly in the early stages of oil revenues. These considerations may require the modification of rules designed to maintain a constant flow of income from the fund.

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For stabilization funds, rules are needed to determine when additions should be made to the funds and when there should be withdrawals. These amounts are linked to the budgetary process and revenue forecasting, because the sums involved are intended to allow the smoothing of expenditure. Generally, parliamentary or presidential approval is used to authorize such transfers. In certain cases, countries have actually formalized the rules governing the use of stabilization funds so that amounts added or withdrawn are automatic. Such rules require that long-term revenue forecasts, which are used to plan budget expenditures, be made, and then unanticipated revenues are adjusted through the use of the fund. Even in this approach, the parliament or president needs to authorize the planned budget expenditures around which the stabilization has to work. Another issue in the management of large resource revenue flows, whether through a separate fund or not, is that of transparency. The public at large is likely to be aware that the government receives large amounts of revenue, and there is a corresponding expectation that they will benefit from it. Transparency concerning the oil fund is often connected to and reinforces attitudes toward a wider transparency concerning a country‘s oil sector. Some oil funds, from their inception, have been established in an environment where published information on total oil revenue flows to the government is an integral part of the budget process, but in other cases, total oil revenues are not transparent. One way to provide such information is through use of the Extractive Industries Transparency Initiative (www.eitransparency.org.), in which governments, companies, and civil society form a voluntary partnership to collect and publish information about all resource revenues made to and received by the government. It may also be valuable to ensure that basic information is made available to the widest possible part of the population through information campaigns that provide a simple account of the revenues to be received and their planned use by the government.

10.4 The International Experience on Oil Funds

A number of resource rich countries and regions have established investment funds to manage the wealth generated from their natural resources (see Table 26). For example, Chile has run a stabilisation and pension fund for copper; the US States of New Mexico, Wyoming and Montana all have resource funds of some form, Norway has a very successful pension fund and other oil funds exist in many Asian and African oil producing countries with different degrees of success. In the next chapter we will discuss several examples of relevance to New Zealand. Most of these funds are well established and operate in political and economic systems where any lessons would be transferable to the case of New Zealand.

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Table 26. International experience on oil funds, in US$

Country Fund Name Assets

($ Million) Inception Year

UAE Abu Dhabi Investment Authoritya 875,000 1976

Norway Norway Government Pension Fund 373,000 1996

Saudi Arabia Saudi Arabian funds of various types 300,000 /

Kuwait Reserve Fund for Future Generations 250,000 1953

Russia Stabilisation Fundb 133,000 2003

Libya Oil Reserve Fund 50,000 2005

Algeria Fonds de régulations des recettes 42,600 2000

Qatar Qatar Investment Authority 40,000 /

United States Permanent Fund (Alaska) 38,000 1976

Brunei Brunei Investment Authority 30,000 1983

Kazakhstan Kazakhstan National Fund 17,600 2000

Canada Alberta Heritage Savings Fund 15,500 1976

Iran Oil Stabilisation Fund 15,000 1999

Nigeria Excess Crude Account 11,000 2003

Source: Stephen Jen (2007), "How Big Could Sovereign Wealth Funds be by 2015?" and Morgan Stanley Research

a: Estimate, September 2007

b: Split in February 2008 into Reserve Fund and National Welfare Fund

10.4.1 Norway Government Pension Fund (NGPF)

Petroleum was discovered in the Norwegian North Sea sector in 1969, with production beginning in 1971. Norway is currently the world‘s eleventh largest oil producer (and the fifth largest exporter) and fifth largest gas producer (and the third largest exporter). Despite this, it is estimated that approximately 40 percent of the discovered marketable oil and gas resources on the Norwegian continental shelf have yet to be extracted. The effective use of these resources has helped transform the Norwegian economy and made it one of the richest countries in the world. Norway‘s oil fund is officially known as ‗The Government Pension Fund – Global‘1. The

fund was established in 1990 however, the first net transfer to the fund was not made until 1996. Although the name of the fund captures its role in meeting future pension obligations, the fund‘s revenue is not specifically earmarked for pension expenditures. The Norwegian oil fund is the second largest wealth fund in the world. As at September 2008 it was valued at NOK 2,120bn, with a population of close to 5 million, this equates to approximately £40,000 per capita. The Norwegian Central Bank forecast that it will reach nearly NOK 4 trillion by 2015 (in 2008 prices).

1 The Government Pension Fund of Norway is made up of two elements: The Government Pension Fund –

Global (the oil fund) and The Government Pension Fund – Norway. The latter is a general National Insurance

scheme.

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Figure 86. Value of Norwegian Oil Fund (At Start of Year) on NOKbn, 1997 – 2015 (2008 Prices)

NOK 0

NOK 500

NOK 1,000

NOK 1,500

NOK 2,000

NOK 2,500

NOK 3,000

NOK 3,500

NOK 4,000

NOK 4,500

1997 2002 2007 2012

Co

nst

ant

20

08

Pri

ces

Figures for 2009 onwards are from the National Budget 2009

Source: Norges Bank - Government Pension Fund - Key Figures

Note: Figures were deflated using OECD GDP Deflators, OECD Economic Outlook and Scottish Government calculations. Exchange Rate: 6.51 NOK = US$1, May 2009.

The distinctive feature of the NGPF is that it is, by law, part of the general budget process, because the only explicit use of the fund is to support non-oil budget deficits, and the status of the fund is such that at any time the parliament can withdraw as much as it wishes from the fund to support the non-oil budget deficit. Therefore, the decision to invest the entire fund abroad was an effective method of sterilizing the impacts of the oil boom. If there is a need to support domestic investment, then the non-oil deficit can be increased and transfers to the fund decreased. This flexibility is due to the fact that there are no rigid accumulation or withdrawal rules. In practice, during its short operational life since 1996, it has been used largely as a savings fund, although there have been substantial year-to-year variations in the proportion of oil revenues saved. The other key feature of the NGPF arrangement is linked to the limitations on the investment universe—the almost absolute control of the policies for the management of the fund by the Ministry of Finance, determined by the Foundation Act. Because the single overarching constraint of the fund is to maximize its return subject to a risk cap, the management focuses on delegation to a competent authority and the establishment of adequate auditing procedures, which are particularly straightforward for the classes of assets permitted by the ministry. Overall, the operation and management of the NGPF has proved very successful in accumulating funds for the Norwegian state. It remains to be seen whether the aggressive saving of oil funds and sophisticated investment policies followed by the government will

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be able to accumulate sufficient funds to finance future spending needs at a time when oil production will be in decline.

10.4.2 The Alaska Permanent Fund

Oil was discovered along the north coast of Alaska in the late 1960s and has made a significant contribution to the state‘s economy. In 2007, Alaskan GDP per capita was US$44,000, 18% higher than the national average. Alaska‘s oil fields are estimated to be large, with the Prudhoe Bay field the largest field ever discovered in North America with estimated original reserves in place of approximately 25bn barrels of oil. Alaska‘s oil fund, established in 1976, is officially known as ‗The Alaska Permanent Fund‘. It is a dedicated investment fund owned by the State and is enshrined in the Alaskan constitution. Twenty-five per cent of all lease bonus bids and royalties are paid into the Fund. The Alaskan Government does not have ready access to the Fund for normal budgetary purposes. The fund attracts widespread public support and the relevant constitutional amendment to establish the fund was passed by an almost two to one majority. From an initial deposit of US$734,000 in 1977, the fund is now worth over US$29bn. Figure 87. Alaska Permanent Fund Value (1978 to 2008, US$ 2008 Prices)

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

$45,000

1978 1983 1988 1993 1998 2003 2008

$ M

illio

ns

(20

08

Pri

ces)

Source: Alaska Permanent Fund Corporation

Note: Figures were deflated using OECD GDP Deflators, OECD Economic Outlook

In 1996 realized net income from the Permanent Fund surpassed state oil revenues for the first time meaning that the renewable wealth created by the fund exceeded the returns from the non-renewable source of wealth. This is therefore a good example of a successful sustainable investment programme.

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Figure 88. Alaska Petroleum Revenue and Permanent Fund Income (1978 to 2008, US$ 2008 Prices)

-$2,000

-$1,000

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

1978 1983 1988 1993 1998 2003 2008

USD

Mill

ion

s (2

00

8 P

rice

s)

Permanent Fund Net Income Petroleum Revenue

Source: Alaska Permanent Fund Corporation

Note: Petroleum Revenue is net of transfers into the permanent fund. Fund net income is statutory net income plus the net change in unrealized gains (losses) and settlement earnings.

Figures were deflated using OECD GDP Deflators, OECD Economic Outlook

The aim is for the fund to generate a real return of 5%. Over the past 25 years the fund has achieved a real annual return of 6.7%. In recent years returns have fallen with a real annual return of just under 4% achieved between 1998 and 2008. Income of the fund is used solely for inflation-proofing the capital and paying a dividend to the citizens of the state. Although it is legally possible to transfer some income from the fund to the general budget, this has not yet happened. The operation of the fund can then be seen to ensure that the fund‘s principal increases with the dedicated share of revenues, and that these are held constant in real terms. The balance is devoted to whatever citizens decide to spend their dividend on. Of course, the oil revenues dedicated to the fund can be indirectly spent if the government runs a deficit and borrows. The obverse of the success of the Alaska model is that its rigidity, which protects it from unwise or politically motivated spending decisions by the legislature, threatens to be a handicap as oil production declines and the state continues to face budget deficits. The inability to respond to changing state needs is related to the inviolability of the principal plus the lengthy tradition of distributing earnings in the form of dividends to all citizens of the state. The direct benefits of the citizens from such a program, and the effectively ―permanent‖ nature of this arrangement, mean that citizens have an enormous interest in the operation and use of the fund. Remarkably, even though the legislature has the power, without a constitutional amendment, to transfer part of the income of the fund to support the general fund, popular resistance to this has so far blocked this option. This raises the possibility that the state of

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Alaska, unable to print money, reluctant to increase local taxes because of public opposition, and constrained on how much debt it can accumulate, will have to cut social spending. In the long run, the effects of this may force a reconsideration of the original purpose of the fund, but this correction is likely to be slow to come into being, as current experience in Alaska has demonstrated.

The model set up in Alaska has resulted in net public saving, but the only use to date for these savings is to distribute them directly to individuals, thus intergenerational transfers are made at a rate dependent on the share of total oil revenues paid into the fund. Alaskans receiving dividends each year have the option to spend or save their share of the fund earnings.

10.4.3 Alberta Heritage Savings Trust Fund

Alberta is the largest oil and gas province in Canada. In fact, it is estimated that Alberta contains the second largest proven concentration of oil in the world, approximately 180bn barrels. This has helped make Alberta one of the richest provinces in Canada with GDP per capita of US$75,000 in 2007, 61% higher than the Canadian average. Alberta‘s oil fund is officially known as the ‗Alberta Heritage Savings Trust Fund‘. The fund was established in 1976 and is currently valued at US$15.8bn (September 30, 2008). It is the only Province in Canada to have established an oil fund. The Government has full access to the revenues in the fund and can decide how much to put into the fund each year. The Fund was started with a special contribution of CAN$1.5bn in 1976. Payments were made on an annual basis into the fund until 1986/87. From 1987 – 2006, no new payments were made into the fund. As a result of the lack of additional investment and continued withdrawals, the fund‘s real value declined over time – see Figure 89. Since 2006, investments have recommenced with approximately CAN$3bn invested. The experience of the AHSTF illustrates many of the issues that have been raised in general discussions of the desirability of establishing oil revenue management funds, in particular whether the aims of the fund should be distinct and separate from those of the general budget, how the fund was to be governed, and its relation to the population of Alberta. By the mid-1990s, the government of Alberta was willing to engage the public in a debate over the future of the fund, reflecting unease over the performance of the nonfinancial assets and the impact of the democratic process. A series of surveys resulted in a major formal change in the act and the fund, restricting its role to that of a savings fund with financial objectives tied to ―prudent‖ investing. Although the possibility of increasing total savings by making further transfers into the fund was left open, this has not happened during the past seven years, indicating the higher priority of paying off the province‘s debt. The crucial aspect of the fund that emerged from a series of decisions is that it no longer reflects changes in the oil price and oil revenues and so has no stabilization function. Even following the enormous rises in oil prices in 2004, the general budget of the province benefited but the fund did not. Its contribution to the province‘s finances is presently limited

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by movements in stock exchange values and by financial management policies of the portfolio. Figure 89. Alberta Heritage Savings Fund Value (1976-77 to 2007-08, CAN$ 2008 Prices)

$0

$5,000

$10,000

$15,000

$20,000

$25,000

1976-77 1981-82 1986-87 1991-92 1996-97 2001-02 2006-07

$ M

illio

n C

AD

(2

00

8 P

rice

s)

Source: Alberta Heritage Savings Trust Fund - 2007-08 Annual Report.

Note: Figures were deflated using OECD GDP Deflators, OECD Economic Outlook

The other major change that was made was to improve the governance of the fund by introducing a number of checks and balances and improved transparency. The publication of quarterly and annual reports (now available on the Internet) and a business plan, together with the need for legislative approval an the establishment of a formal committee of external advisers on investment policy, have removed control from the executive. There is little direct evidence that the initial goals of the fund to diversify the economy and improve social infrastructure were very successful. This lack of evidence comes from the failure of the government to carry out cost-benefit studies, or even consumer satisfaction surveys, so that although the policies may have achieved their goals, the evidence was not collected. The responses of the citizens to the surveys of the 1990s on the possible uses of the fund, which showed that the overwhelming support was for a savings function alone, suggest that there was no public perception that the other goals had been achieved and were worthwhile. Again, this may have been due to a lack of information and publicity, but it illustrates the dangers of this approach.

10.4.4 State Oil Fund of the Azerbaijan Republic (SOFAZ)

Azerbaijan has been an oil-producing region since the late 19th century, and production subsequently grew to substantial levels. However, starting in the mid-1960s, production gradually declined because of lack of investment when the Soviet Union directed its

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attention to other producing regions. By the time of independence and the creation of the Republic of Azerbaijan, production was about 200,000 barrels a day. However, in 1994, a dramatic turnaround in the financial and fiscal strength of the economy occurred by the signature of a US$10 billion deal for the development of the Azeri-Chirag-Gunashli (ACG) oil fields. Since that time, there has been further investment in oil and gas, resulting in oil revenues accounting for 30 percent of total government revenue by 2001 – the share of oil in total exports had risen to 91 percent. The oil fund, with explicit operating, investment, and expenditure rules, was launched in July 2001, by presidential decree. The fund was designed explicitly to take account of the problems of managing a large and temporary inflow, and the rules of operation were designed to be sufficiently flexible for use as either a savings or stabilization function, as well as supplying budget-type support for specific projects. Subsequently, the International Monetary Fund (IMF) and World Bank have supported a program to improve the design of the fund through technical assistance and program conditionality. The basic principles of SOFAZ suggested that expenditures from it would be used for human development and the promotion of the non-oil sector, as well as for budget support. In particular, it has been used also for assistance to refugees and funding the share in the Baku-Tbilisi-Ceyhan (BTC) oil pipeline of the State Oil Company of the Azerbaijan Republic (SOCAR). Revenues from bonuses, the sale of profit oil from the production-sharing agreements, rental fees, and acreage fees, as well as revenues from the investments of its own assets, are all paid into SOFAZ; profit tax payments from SOCAR and the ACG partners are all paid directly into the budget. At the end of 2004, the net assets of SOFAZ were US$964 million, and over the period 2004 to 2024, about US$50 billion is estimated as being paid to SOFAZ, with another US$20 billion being paid directly to the budget. Currently, use of the fund‘s resources in any year are limited to an amount equal to the revenues of the fund in the same year, ensuring that the nominal value of the fund does not decrease over time. Expenditures from the fund itself, whether as budget support or project-specific outlays, have to be approved by the president. Since 2003, oil revenues paid directly to the budget, which have been inflated beyond expectations by high oil prices, have created an excess for the budget and so have been placed into a separate stabilization account created by the ministry of finance. These are held in domestic banks and can be drawn down when required, according to a principle that they are to be used for stabilization only if the price of oil drops below that in the current budget estimate. By mid-2004, another US$82 million had been accumulated in this way, which reduces the need for SOFAZ to be regarded as providing a stabilization role and lessens the need for its assets to be held in the short term. This arrangement is rather informal and raises a number of questions about its operation and use—in particular, whether the stabilization account should be amalgamated with SOFAZ, which is acquiring investment management expertise in both short-term and longer-term securities.

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Figure 90. Contributions Received into the State Oil Fund in Current Billion Manats (2001-2004)

0

200

400

600

800

1000

1200

1400

1600

Initial Transfer 2001 2002 2003 2004

Bil

lio

n M

an

ats

(C

urr

en

t P

rices)

Source: World Bank/ESMAP Report 321/06.

Note: a. 4,593 Manats = US$1, December 2004.

The distinctive feature of SOFAZ is its ultimate subordination to a single agent, in the person of the president, in that the establishment, regulatory, and asset management decrees were all determined by the president. Also, the president appoints the executive director of the fund and approves the membership of the supervisory board. This arrangement had the advantage of allowing rapid establishment of the fund and giving time to understand what legislation would be needed for the best long-run interest of the country. Currently, discussions are under way with respect to passing a parliamentary act concerning the nature and operations of the fund because, as with other funds where the laws concerning them have not been entrenched in the constitution, thus requiring a major political debate on any changes to be made, changes of direction could easily be made and short-term needs could come to dominate the longer-term purposes of the original ideas behind the creation of a savings-type fund. The actual control of the fund and oversight are more limited than in the case of the funds in Norway, Alberta, and Alaska. The executive director is aided by an investment committee drawn from senior staff within SOFAZ. Outsiders and technical experts can be invited to attend, but this is discretionary, and actual use made of this provision is unclear. In contrast to other funds, there is no formal role within SOFAZ for external investment advisers with specialist knowledge of financial markets. The supervisory board, which comments on the current investment strategy presented to the president, consists almost entirely of ministers and also has no current representative from the business community. The transparency of the fund itself is well established, with a very detailed Web site and the publication of all relevant legal material, as well as the annual reports and the external audit. As the investment strategy becomes more complex, these will need to provide more

141



detail on the actual holdings of the fund to permit debate on whether appropriate investment decisions are being made.

10.4.5 The National Fund of the Republic of Kazakhstan (NFRK)

In the early 1990s, after the creation of the Republic of Kazakhstan in 1990, oil production was about 500,000 barrels a day. A series of large investments took this to 1.1 million barrels a day by 2003. Domestic demand for oil declined throughout the 1990s, so that net exports were able to rise even faster than production. Further investment in the sector indicates that production may reach 2 million barrels a day by 2010 and even 3 million barrels a day by 2015 (Tsalik 2003, International Monetary Fund 2004c), making Kazakhstan one of the world‘s largest producers and exporters of oil. Oil is the dominant export of Kazakhstan, and fluctuations in its price have a very large impact on the budget. Earnings from oil exports accounted for 5 percent of government revenues in 1999, 20 percent in 2002, and reached more than 50 percent in 2004 (United States Energy Information Agency 2004). The recovery of oil prices in 2000 gave renewed impetus to the problem of revenue management, and the NFRK was created by presidential decree to prevent overspending on low-priority projects. The NFRK is not a separate entity but rather an account of the government held at the national bank. Oil and mining revenues due to the government are first paid to the ministry of finance, which then pays a portion into the fund according to a strict formula.

The fund is designed to have both a savings and a stabilization function, and payments are made into two separate portfolios to reflect this (International Monetary Fund 2004c). A reference price for oil is determined for a five-year period (currently US$19 a barrel) and this determines baseline budgeted oil revenues. Of these revenues, 10 percent are paid quarterly into the savings account, and 90 percent are retained for the budget. Excess revenues above the budgeted amount are paid into the stabilization account, and deficits (when the actual price is below US$19 a barrel) are withdrawn from the stabilization account. Mining payments had a separate reference price. This scheme has a number of weaknesses, and the IMF has argued for a simplification that would bring the rules nearer to those of the Norwegian model, where flows into and withdrawals from the fund depend on the budget approved by parliament. Net payments into the NFRK have rapidly increased its size – see Figure 91 – and the latest figures for 2005 reveal that by December, the fund‘s had increased to US$8.0 billion. The fund currently has a value equal to about 5 percent of Kazakhstan‘s GDP. The national bank produces daily, monthly, quarterly, and annual reports for the finance ministry on the investments, but these are not made public. Periodic statements on accumulation in the fund are published in the press. The annual report and audit are not published in full, but a truncated summary is publicly available.

The NFRK has clearly articulated rules for accumulation or withdrawal, but these rules are not presently formally linked to overall fiscal policy. The procedures for managing the investments mirror those used in other well-established funds.

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Several aspects of the NFRK have attracted criticism:

Excessive control exercised by the president,

Rigidity of the rules for accumulation,

Lack of full public disclosure of the fund‘s performance,

Lack of integration with the overall fiscal policy. Figure 91. Budget Revenues and NFRK Assets in Current Million US$ (2001-2004)

$0

$1.000

$2.000

$3.000

$4.000

$5.000

$6.000

1999 2000 2001 2002 2003 2004

US

$ M

illi

on

(cu

rren

t)

NFRK Assests Revenue From Oil

Note: a. Excludes bonuses, privatization receipts, and other exceptional payments. Data on Revenue From Oil not available for 2004

10.4.6 Oil Stabilization Fund (OSF) of the Russian Federation

Russia is the world‘s second largest oil producer, currently at about 9 million barrels a day, which marks a steady recovery from about 6 million barrels a day in the mid-1990s. This country of 140 million people has a per capita income of about US$10,000, but it is still heavily dependent on oil and gas. It is estimated that these accounted for 25 percent of GDP, at least 40 percent of budget revenues, and 50 percent of exports in 2003. The rapid increase in oil prices since then will have increased these ratios further. As oil revenues recovered in the late 1990s, there was debate within Russia on the need to set up a formal oil fund to help stabilize budgetary revenues. Initially, the Duma proposed its version of a stabilization fund law in 2002, and this was countered by the government proposing its own version of the law, which came into effect at the beginning of 2004 (The Moscow News 2003). There were to be three sources of revenues for the OSF: first, any end-year surplus from the budget; second, if world oil prices exceed a benchmark price for Russian export oil, export duties and tax on oil beyond the benchmark price will be paid monthly into the fund; and third, yields on the assets of the OSF will be paid back into the fund. The assets of the fund may be placed only in foreign debt

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instruments from a government list of approved items. Withdrawals from the fund will take place if the actual price falls below the benchmark price (then US$20 a barrel), because the budget is prepared on the basis of this price. In addition, once the fund has accumulated 500 billion rubles (Rub), it may be used to finance certain strategic objectives. The ministry of finance had proposed a higher threshold of 9 percent of GDP before non-stabilization withdrawals could occur, but in the event, the lower threshold of about 3.8 percent of GDP was implemented. The designers of the OSF had expected that it might take three to four years before such disbursements would occur, but the steep rise in oil prices has already taken the fund to more than Rub 1.46 trillion by November 2005 (which is almost equal to the estimate of GDP for the year), so that calls for disbursement on a range of projects are occurring (such as reducing the rate of VAT or granting development loans to businesses) that could create risks of Dutch disease effects. Early plans for uses of the fund‘s revenues included paying back external debt and financing the pension deficit. The cautious estimate of the oil reference price has in fact meant that the OSF has very rapidly accumulated reserves, and this has put the government in a strong position to stabilize budget revenues if and when oil prices turn down. Faced with the unexpected developments in the world oil market, the authorities raised the benchmark price to US$40 a barrel for the 2006 budget. The OSF is held as a sub-account of the treasury at the central bank, and the bank is responsible for investing these sums. Each month, the press publishes details of the balance of the fund, transfers into it, and its uses. At present, the balance of the fund is entirely invested in U.S. high-grade income securities. There is at present no official dedicated source of information for the fund, and its investment performance is at present not published. Also, if an external audit of the fund has been carried out, this has not been made public. Russia chose a particularly fortuitous time to establish the OSF, just as the world oil price rise started its rapid climb. This meant that its modest accumulation target was achieved within one year, so that the country has some time to consider the long term use of the funds before they become essential for budget revenue stabilization. The fund as yet does not conform to international best practice for transparency in terms of information.

10.4.7 The Reserve Fund for Future Generations (RFFG) of Kuwait

Although geographically small, Kuwait is one of the world‘s major oil producers. Oil production is currently about 2.4 million barrels a day, and its reserves are the fourth largest in the world, giving it an extraordinarily high reserve to production ratio (British Petroleum 2005). With a population of 2.3 million, of which only 1 million are Kuwaiti, GDP per capita is high at more than US$20,000. Oil accounts for nearly 50 percent of GDP, 80 percent of government revenue, and 95 percent of exports. Faced with oil revenues that are huge in relation to the size of the country, and which will last for an extremely long period, there is only a weak case at present for a substantial intergenerational fund. However, a fund for future generations has to be interpreted not in terms of intergenerational preferences, but more in terms of precautionary saving against falls in the world oil price (caused by technological and demand shifts over the longer run) and against geopolitical uncertainties. In addition, concerns about the effects of excessive domestic spending have led to the withdrawal of some funds from circulation and their

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sterilization through being invested abroad. Kuwait, unlike some other oil producers, does not face the immediate re-entry problem of how to restructure the economy for when the oil runs out, but by the same token, it needs to avoid embedding the creation of negative incentives for entrepreneurship and employment that have occurred elsewhere with the presence of huge revenue flows. Faced with the extreme dominance of the oil sector, the government has for a long time sought to diversify through investing some of the oil revenues abroad. In 1952, the Kuwait Investment Board, based in London, was established to manage the portfolio of foreign investments, and in 1958, this became the Kuwait Investment Office (KIO). In 1960, the government created the General Reserve Fund, financed from budget surpluses; in 1976, it also created the RFFG, allocating to it 50 percent of the General Reserve Fund at that time, plus 10 percent of future budgetary revenues and the profits on the assets of the RFFG. The Kuwait Investment Authority (KIA) was created in 1982 to take over from ministry of finance the management of both of these funds. The KIA board has as its main tasks to draw up strategy, supervise implementation, and set up rules and regulations for the operation of the KIA. The KIA also encourages the local private sector by participating in financing of the establishment of companies, and it has provided liquidity to the treasury. Provision of public information on the fund‘s assets is prohibited by law, partly in an attempt to insulate the fund from pressures for it to be spent. The rules for payments into the RFFG are clear, but conditions for withdrawals are not made public. However, all withdrawals from the fund must be approved by the national assembly. At the outbreak of the Gulf War, the fund was estimated to be worth between US$90 and $100 billion, equivalent to a multiple of approximately five times per capita income for each citizen. The Gulf War did a great deal of damage to the Kuwaiti economy, not least in shutting down its oil production completely. The deficits were met out of the assets of the RFFG, although the exact amount drawn down has not been published. Estimates range from between one-third to one-half of the then assets of the fund. One result of this drawdown was that investment income declined, reducing the ability of the fund to provide stabilization so that the economy became more vulnerable to swings in the world oil price. Kuwait has very large oil revenues in relation to the size of the budget and has also been able to run fiscal surpluses, so that the rule of depositing 10 percent of revenues into the RFFG has been easier than it is in some other economies. The accumulated saving of the RFFG was apparently valuable in providing the short-term financing required by the heavy strain placed on the economy by the Gulf War. The deliberate lack of transparency concerning the fund, in terms of revenue and expenditure flows, assets held, and investment performance, has been justified by the authorities in terms of preventing calls for the immediate spending of the fund, with its likely consequences of further distorting the economy. However, this lack of transparency, in a situation where all citizens have an interest in the management of the economy, is not a model that is to be recommended, and indeed it may not be sustainable under increasing pressure for accountability.

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10.5 General Conclusions

As noted in par. 10.2 oil funds can have various purposes, including long-term fiscal sustainability, inter-generational equity, macroeconomic stabilisation, efficient resource allocation within the economy, promoting industrial diversification, providing local benefits, and developing sustainable energy. The varied practice around the world reflects this variety of purposes. Thus they can facilitate sound macroeconomic management in an environment of fluctuating revenues from oil production, which can destabilise an economy. They can ensure that the benefits of the revenues from the depletion of a non-renewable resource are not dissipated in consumption or used to reduce other taxes and thus all used for normal budgetary purposes rather than strategic investment. Petroleum reserves are part of the nation‘s capital stock and the depletion of hydrocarbons should be accompanied by measures to ensure that sufficient of the revenues is invested to at least keep the capital stock intact. An oil fund is not necessary to ensure that this outcome is achieved, but it can ensure that the revenues are not used for purposes inconsistent with this objective. The issue of the extent to which the fund should be separated from the normal government budget procedures is thus a central one. On balance, for countries lucky enough to be endowed with large petroleum reserves, an oil fund is a sensible concept. But it is not a substitute for sound economic management. Another key conclusion is that the rules of operation of the fund need to be very clearly specified and to be consistent with the objectives. In general discretionary access by a government is likely to endanger the objective of facilitating permanent benefits from the revenues. The notion of only utilising the permanent/sustainable income from the fund rests very uneasily with general government practice around the world.

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APPENDIX A: Terms of Reference

EVALUATION OF NEW ZEALAND’S PETROLEUM

TAX AND LICENSING REGIME

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148



149



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APPENDIX B: Criteria for allocation of permits in the United Kingdom

In the United Kingdom, licences are issued by the Department of Energy and Climate Change (DECC) through competitive Licensing Rounds. DECC assesses the Applicant‘s operating competence, technical and environmental, and its financial capacity to carry out the Work Programme offered. DECC accepts that some elements of the Applicant‘s competence may not be in place at the application stage. For example, some posts may not be filled at the moment of application, which may occur months or even years ahead of any need for them. Nevertheless the Applicant will have to convince DECC that it knows what structure and skills are needed and that it has a management team capable of delivering it. On the other hand, the financial capacity must be clearly available to the Applicant at the time of application, and not be subject to uncertain future events like share issues. Additional to the application form, oil and gas companies have to submit four appendices with supporting information:

Appendix A: It contains the ―Financial capacity form‖ for each individual company. It is composed of the ―Financial Capacity Questionnaire‖, ―Existing UKCS Capital Commitments‖, ―Existing non-UKCS Capital Commitments‖ and ―Planned Expenditure Profile‖.

Appendix B: It sets out the Applicant‘s technical understanding of the acreage and its plans to exploit it. The most important information is contained in Parts B4 and B5.

o Part B4: The ―Lead/Prospect summary sheet‖ (there must be one Part B4 for each prospect, lead or new play/discovery on the acreage being applied for).

o Part B5: The ―Work programme summary sheet‖ (one or more required).

Appendix C: It describes the environmental competence of the prospective operator (―Environmental Information‖).

Appendix D: It contains the ―Company information form‖ and the company‘s most recent published accounts (and most recent consolidated accounts of its parent if there is one).

Following receipt of the applications, it is normal practice for DECC to interview every applicant (or consortium) for each block or part-block being applied for. The main purpose of the interview is to enable the Applicant to present the technical rationale for the application (that is, their technical understanding of the acreage and the Work Programme offered) and for DECC to ask questions and seek clarifications. The interview is likely to focus on:

the Applicant‘s geotechnical data coverage and work done to date;

identified prospectivity;

the potential for appraisal or development of existing discoveries and/or redevelopment of decommissioned fields that the Applicant has identified;

how these relate to the Work Programme offered;

and additionally, for Promote Applicants, its plans for and approach to securing resources necessary to complete the Work Programme.

After the interview, DECC marks each application against a relevant Marks Scheme, Landward or Seaward. The latter is shown on Table 27 and as well as the details above

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this information is freely available from DECC. Applicants who fall short of the criteria cannot be considered for the award of a licence. Table 27. Summary of the British Seaward marks scheme summary

Geotechnical database used

3D Seismic: ............................................................................................................................................. 30 (max) 2D Seismic: .............................................................................................................................................. 20 (max) Seismic reprocessing: .............................................................................................................................. 15 (max) Well data: ................................................................................................................................................... 6 (max) Other: ...................................................................................................................................................... 10 (max)

Geotechnical evaluation already performed over block

Well interpretation/ties: .............................................................................................................................. 6 (max) Stratigraphic interpretation: ........................................................................................................................ 6 (max) Structural interpretation: ............................................................................................................................. 6 (max) Seismic interpretation: ............................................................................................................................... 6 (max) Hydrocarbon system: ................................................................................................................................. 6 (max) Depth interpretation: .................................................................................................................................. 6 (max) Other: ..................................................................................................................................................... 10 (max)

Specific prospectivity identified

Leads: ............................................................................................................................................ 10 each (max) Prospects not fully evaluated: .............................................................................................................. 11-20 each Fully evaluated prospects: ................................................................................................................... 21-30 each

New plays .......................................................................................................................................... 5 each (max)

Geotechnical Work Programme 3D seismic ................................................................................................................................................ 25 (max) 2D seismic ............................................................................................................................................... 15 (max) Seismic reprocessing: ............................................................................................................................. 10 (max) Geotechnical studies/new data acquisition e.g. seabed electromagnetic logging: ................................... 25 (max)

Drilling Work Programme (marks only for Trad and Frontier applications)

Firm well: ................................................................................................................................... 60 (+0-20 if deep) Contingent well: ......................................................................................................................... 30 (+0-10 if deep) Drill-or-drop with early decision point (marks for Traditional only): .................................. 0-20 (timing-dependent)

Promote assessment

Future resourcing: Immediate technical Work Programme ...................................................................................................... 7 (max) Later phase Work Programme ................................................................................................................... 7 (max) Marketing/potential customers .................................................................................................................... 7 (max)

Existing discoveries & Re-developments

Technical assessment: ............................................................................................................................... 5 (max) Economics: ............................................................................................................................................... 5 (max) Commercial: ............................................................................................................................................. 5 (max) Infrastructure: ........................................................................................................................................... 5 (max) Plans and timing: ....................................................................................................................................... 5 (max)

The technical work done and the Work Programme are the main deciding factors between competing applicants (assuming they meet such financial, technical and environmental criteria as are appropriate). There is limited discretion in deciding whether or not to issue a licence; and if so, to whom and on what conditions. Usually a licence will be awarded to the Applicant with the highest

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marks. The guiding principle in reaching a decision will be the policy of maximising successful and expeditious exploration and exploitation of the UK‘s oil and gas resources. For the 25th Seaward Licensing Round, DECC published a list of winning marks by block.

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evaluation of the petroleum tax and licensing regime of new zealand

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