11. Fiscal schemes for joint development of petroleum in disputed areas: A primer and an evaluation

Michael Keen, and Victor Thuronyi
Published Date:
September 2016
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1 Introduction

Significant amounts of petroleum lie in areas of disputed sovereignty or absence of agreed boundary delimitation.2 Many, but not all, such areas are maritime and lie beneath seas that countries can claim as their Exclusive Economic Zone (EEZ) (for exploitation of water column, seabed, and subsoil resources, though not for navigation) in terms of the United Nations Convention on the Law of the Sea (UNCLOS).3 UNCLOS came into force only in 1974, and techniques of exploring for and extracting petroleum in offshore areas have become efficient and widespread only in more recent times. Delineation of maritime boundaries in earlier times thus may not have seemed important or was made according to older legal principles.

UNCLOS itself provides for the adoption of “interim arrangements” where, for some reason the parties cannot delineate or agree a permanent maritime boundary (Article 33). In the case of petroleum areas, the most common form of arrangement has become the joint development zone (JDZ). JDZs also exist onshore, where UNCLOS is not relevant. Under a JDZ, the parties put aside the sovereignty issue, usually for a defined period, thus also putting aside the question of title to resources in the ground or under the seabed. Instead, they agree to attribute petroleum produced from the JDZ, or the revenues raised under a joint fiscal scheme, in percentages to each country. Prominent JDZ examples include Bahrain–Saudi Arabia, Malaysia–Thailand, Timor-Leste–Australia, and São Tomé e Príncipe–Nigeria.4

In a number of places, disputes over boundaries continue, as sometimes do negotiations over a possible JDZ. Contentious areas include the South China Sea, Venezuela–Trinidad and Tobago, Cameroon–Nigeria, Angola–DRC, the Caspian Sea, and Cambodia–Thailand. The new prospects in basins off the coasts of a number of West African countries have been identified, in some cases, before formal delimitation and agreement on maritime boundaries, raising the possibility of new sets of overlapping claims for EEZs. The Arctic Ocean – considered to hold a significant proportion of the world’s yet-to-be-discovered hydrocarbons – is subject to a series of overlapping claims.

The field of public international law on maritime claims, principles of delimitation of maritime boundaries and JDZs carries an enormous literature (see, for example, Becker-Weinberg, 2014; Hestermeyer et al., 2012; Nordquist and Moore, 2012, and the exposition in Crawford, 2012). That cannot be said for the economic and fiscal issues presented by interim solutions to unresolved maritime claims, despite the growing significance of these issues.5 Cameron in this volume explains the legal challenges involved in creating a JDZ and how a JDZ differs from a unitization scheme, even one that extends across maritime boundaries.

This chapter aims to document some key examples of the JDZ and evaluate the types of fiscal arrangements that occur. These fiscal arrangements consist, first, of the attribution of petroleum production or proceeds among the partner states and, second, as in any national scheme, of the tax, production sharing, state participation and pricing rules applied to companies operating in the JDZ; then third the “architecture” of the fiscal arrangements – meaning the specific ways in which each country’s regime and institutions blend with each other and with joint arrangements specially created, and, fourth and finally, the provisions for projects where resources either straddle the perimeter of the JDZ or require infrastructure extending beyond the JDZ to achieve export of petroleum (see also Le Leuch in this volume).

Fiscal terms in JDZs may differ from those in, say, neighbouring areas under exclusive jurisdiction. Do they differ in any systematic way – for example in average effective tax rates? And would a JDZ work differently on international oil companies’ (IOC) perceptions of risk from a sovereign national scheme?

This chapter presents in detail the specific example of the interim arrangements made between Australia and Timor-Leste. This is an especially complex case, one which illustrates virtually all the issues that need to be addressed and frictions that may arise in designing and implementing a JDZ.

The chapter outlines some practical lessons and policy conclusions, intended as helpful to those designing and negotiating interim arrangements, to those operating within them, and to civil society interests seeking to appraise the impact of these schemes.

2 Maritime disputes and joint development zones

According to data available in Pawlak (2012) by 2009 there were 170 formal agreements or treaties establishing maritime boundaries, but 365 known potential maritime boundaries were yet to be delineated and decided. (See also Cameron in this volume.) Only a minority of the parties to undecided or disputed maritime boundaries have entered agreements establishing joint development zones.

This simplest way to explain the characteristics of JDZs is by examples. After discussing the architecture of JDZs, we outline the arrangements in two of the best-known JDZs: Malaysia–Thailand and Nigeria–São Tomé e Príncipe. Then in section 3 we proceed with quantitative evaluation and in section 4 with detailed analysis of the case of Australia and Timor-Leste.

2.1 The fiscal architecture of joint development zones

2.1.1 The rationale for JDZs

A JDZ under UNCLOS applies to an offshore area6 subject to overlapping maritime boundary claims by the countries with adjacent or opposing coastlines where known deposits of or prospects for petroleum exist. (See also Cameron in this volume.) The countries cannot agree on a delimitation but also do not want to hold up the exploration and development of any petroleum resources, so for pragmatic reasons they agree to a joint approach and defer formal boundary delimitation for a defined period of time. The JDZ usually involves (1) shared jurisdiction; (2) an agreed regulatory architecture; (3) sharing of petroleum produced; or (4) sharing of revenues under a jointly administered fiscal regime.

2.1.2 Attribution of petroleum produced

JDZs differ from international unitisation agreements in that a JDZ may cover areas with no discoveries. Under unitisation, the boundary is usually not disputed; rather what is addressed is attribution of petroleum across an agreed boundary according to knowledge of location of reserves in discoveries.7 Redetermination of reserves and attribution occurs periodically under agreed rules, usually on the basis of technical analysis. Countries establish JDZs, on the other hand, in order to put aside competing claims and allow exploration or extraction (usually both) to go ahead in spite of the absence of a maritime boundary. The extent of the zone and the division of any petroleum discovered are determined by relative negotiating power.

Fifty–fifty sharing has proved appealing many cases in which no other basis exists for a different attribution. Nevertheless, examples of other attributions occur: the special area favouring Nigeria within the Nigeria–São Tomé e Príncipe JDZ or the zones B and C under the old “Timor Gap” treaty. Differences from 50% attribution might arise when the parties recognize that one party may have a stronger claim than the other over parts of the total area in dispute, but neither party wishes only a partial permanent delineation.

In principle, the rules of the zone might do no more than attribute any petroleum found and extracted. In practice, JDZs need a much more sophisticated architecture of rules and administrative structure governing activities and of fiscal terms to implement the attribution. Peter Cameron in this volume analyses the legal architecture. The parallel fiscal architecture covers the mechanisms for sharing physical petroleum, proceeds, or revenues earned under a joint fiscal regime, both between the states and with private parties engaged in petroleum activities. It must also cover the fiscal treatment of activities related to petroleum exploration or development, occurring whether or not production occurs, and those for exporting petroleum from the JDZ.

2.1.3 Concept of the fiscal scheme

The precedent from fiscal terms of the participating countries strongly influences the design of fiscal terms in a JDZ, but usually with an element of purpose-built fiscal terms for the zone. The detailed examples in this chapter all rely on a core fiscal mechanism (whether production sharing or otherwise) from which the countries then share proceeds. What remains to the private participants after this core mechanism may be taxed, either according to common rules or under each country’s national scheme with revenues and costs apportioned using the JDZ attribution percentages.

Thus even where one country operates a licensing system and the other does not, the JDZ might rely upon a single contractual scheme. A production sharing contract, for example, may determine the initial sharing of production between the JDZ governments collectively and any private investor, even where that PSC model does not reflect practice in either participating state. As with most such systems when used nationally, a hybrid emerges in which taxation applies to residual income of the “contractor” after production sharing.

Similarly, where the parties agree to a tax and royalty system – not contractual and not with production sharing – the core charge for the resource could be a combination of bonus, royalty or fees, charged collectively and distributed to the partner states. Again, tax would follow on the residual income. The Nigeria–São Tomé e Príncipe and Timor-Leste schemes reflect this approach.

By contrast, if the parties cannot agree a core fiscal scheme, jointly operated, then each country’s own fiscal system could apply to the gross proceeds of petroleum production in the attribution percentages. This would bring the JDZ closer to a unitisation scheme. Private investors face more challenges under this alternative because they lack the assurance of a common scheme agreed by the parties: the partner states have the usual incentives arising from time inconsistency to seek to secure a higher share of their own attribution percentages after production starts, though the JDZ architecture would usually place some constraint on any unilateral attempt to modify terms by one party.

2.1.4 National oil companies

Where the partner states have strong national oil companies with privileged positions in their own exclusive jurisdictions, these positions often carry over to the JDZ. An automatic role for the respective NOCs, for example, prevails in Malaysia–Thailand but not in Nigeria–São Tomé e Príncipe, or in Timor-Leste–Australia. In some respects, NOC dominance simplifies matters since the direct attraction of private investment by the JDZ regimes becomes irrelevant: the NOCs take full responsibility for the financing of exploration and development.

In a mixed system, the NOCs could function as recipient of production shares for the governments, obviating the need for a separate collection agency. Malaysia–Thailand, for example, contrasts with Timor-Leste–Australia in this respect. Many JDZs have a joint authority that functions not only as regulator but also as collector of significant revenues via fees or production sharing. In principle, the regulatory authority could deal with taxes designed specifically for the JDZ, though national tax authorities generally retain this role.

2.1.5 Taxation

JDZs have adopted either a single tax system for the JDZ or application of each country’s tax system in attribution percentages. Common direct taxation by assessment with separate applications of indirect taxes or taxes by withholding represents a combination. The system of unified resource taxation (the resource charge or production sharing) with separate application of normal business and indirect taxation is common.

Application of national taxes, however, requires the equivalent specifically for the JDZ of an international double taxation agreement or code for the JDZ. The existence of the JDZ raises specific complications over source and residence for income tax purposes – commonly resolved by deeming the JDZ to be the tax territory of both countries but with rights to tax only in the attribution percentages. Limitations on withholding taxes on payments to nonresidents become part of the mechanisms to limit competitive appropriation of revenues beyond the attribution percentages.8

Most countries now specify a treatment for capital gains purposes of transfers of interest in petroleum rights and in assets associated with those rights. Again the harmonisation or integration of these rules in a JDZ presents significant challenges.9

2.1.6 Unitisation beyond a JDZ

The fact that perimeters of a JDZ are usually arbitrary means that discoveries are possible that lie across these perimeters. The parties then face, if willing, unitisation of fields applying a JDZ regime to one part and a national regime to another. Just as likely – and represented by Greater Sunrise between Timor-Leste and Australia – the JDZ itself may have temporarily settled only part of a dispute. If areas outside the JDZ also remain contested the parties may require still further “interim arrangements”, exactly as happened between Australia and Timor-Leste. This phenomenon serves only to emphasise the incompleteness and temporary nature of JDZ schemes.

2.1.7 Petroleum infrastructure

At the time of UNCLOS and then the first establishment of JDZs in disputed maritime areas the exploration target was oil (not natural gas) and the expectation was for infrastructure located within the JDZ close to any producing field. Upstream operations would terminate, and fiscal value would arise “at the point of tanker loading”. Subsequently, however, interest in gas raised the challenge of jurisdiction and taxation of transportation and processing facilities for JDZ products that might be located outside the JDZ (Calder, this volume). The Timor Sea Treaty, for example, provides that a pipeline commencing in the JDZ but landing in one of the contracting states comes under the jurisdiction of the destination state.10

Crude oil loaded onto a tanker at facilities within the JDZ has a specific value (when not sold at arm’s length) at the closest reference price adjusted for quality and transportation cost differentials. Oil and more especially gas transported out of a JDZ by pipeline requires valuation for upstream fiscal purposes after deduction of the transportation costs. How are those to be assessed? The answer requires transfer pricing rules that may benefit from no established point of reference and hence no comparable uncontrolled price. Similarly, natural gas transported by pipeline then processed into LNG outside the JDZ has an upstream “price” that may reflect a series of affiliate transactions with owners of transportation and processing infrastructure. This infrastructure requires planning, construction, and operation, all of which under a national jurisdiction would give rise to taxable income. Attribution of taxing rights for such income is far from straightforward in the case of a JDZ.

2.2 Malaysia–Thailand joint development zone

Malaysia and Thailand have no agreement on the continental shelf border in the Gulf of Thailand. The disputed border results from the two countries with adjacent coasts using different coastal baselines in calculating the equidistant line for a boundary. The two neighbours signed a memorandum of understanding in 1979 to create a joint development area where non-living natural resources can be explored. The Joint Authority established in 1990 issues licences and regulates the JDA.11 The JDA comprises three blocks (Figure 11.1). Blocks B-17 and C-19 are fully owned and operated by subsidiaries of Petronas and PTT. Block A-18 is a joint venture between Petronas’s subsidiary (50%) and Hess Company of Thailand (50%). Gas discoveries leading to production were made in the joint zone.

Figure 11.1Malaysia–Thailand JDZ

Source: Malaysia–Thailand Joint Authority

The discussion of each country’s national terms that follows illustrates how the JDZ regime derives from and compares with the partner countries’ national regimes.

2.2.1 Fiscal framework for petroleum activities in Malaysia

Malaysia has a long history of petroleum exploration and production. Shell made the first commercial discovery in 1909 in the state of Sarawak and started producing oil a year later. Companies that produced oil at the time assumed all risks and operating responsibilities from exploration to production, paying the Malaysian government royalty at fixed percentages and also income taxes. As commercial production accelerated in the early 1970s, the government sought to strengthen control over hydrocarbon activities in Malaysia. Petronas, the state-owned company, was thus established, endowed with the rights to explore and develop Malaysia’s hydrocarbon resources under the Petroleum Development Act of 1975. Contractors were no longer solely required to pay a royalty and income taxes but to operate under a production sharing contract (PSC), and to partner with Petronas in joint ventures. For marginal fields, the contractors have an option to operate under a risk service contract (RSC) and receive compensation for the services provided to Petronas instead of a share of production.

The PSC regime was first patterned after the Indonesian PSC until a new model PSC was developed in 1987. The model PSC went through several revisions up to 1997 with several agreements post-dating the model. Under this PSC regime, a contractor pays an explicit royalty of 10% of total production to the government and then recovers its costs from a share of remaining production. Profit petroleum remaining after royalty and cost recovery is shared according to a sliding scale determined by the revenue-to-cost (R/C) ratio. An export tax of 10% is imposed on any petroleum exported out of Malaysia.

Box 11.1The Malaysia–Thailand JDZ production sharing contract

Cost recovery is linked to project profitability as measured by the contractor’s revenue to cost ratio (R/C ratio) – commonly known as the R-factor. The higher the R/C ratio, the lower the cost recovery limit, which ranges from 30% to 70%. If in any quarter the cost recovery limit exceeds the actual cost eligible for recovery, the difference, known as excess cost recovery, is shared between the contractor and Petronas according to a specific scale.1 The R/C ratio and cumulative total hydrocarbon value (THV) determine the sharing of excess cost recovery and profit petroleum. THV is determined by individual field and equals the lesser of 300 MM Bbl for oil or 0.75 trillion cubic feet (TCF) for gas and the size of the field’s proved recoverable reserves. This amount is adjusted as more information about the field becomes known. Cumulative THV is the sum of all individual THVs from a contract area. If THV equals 300 MM Bbl, realised cumulative production from a contract area may exceed the cumulative regulatory THV, especially toward the final stage of production. Table 11.1 summarizes the sharing rates of excess cost recovery and profit petroleum as stipulated in the 1997 model PSC.

Table 11.1Cost recovery limits and shares of excess cost recovery and profit petroleum to contractors
R/C RatioCost Recovery LimitExcess Cost Recovery if cum. Production ≤ cum. THVExcess Cost Recovery if cum. Production > cum. THVProfit Petroleum if cum. Production ≤ cum. THVProfit Petroleum if cum. Production > cum. THV
0.0 ≤ R/C < 1.070%NANA80%40%
1.0 ≤ R/C < 1.460%80%40%70%30%
1.4 ≤ R/C < 2.050%70%40%60%30%
2.0 ≤ R/C < 2.530%60%40%50%30%
2.5 ≤ R/C < 3.030%50%40%40%30%
R/C ≥ 3.030%40%20%30%10%
1 This is a relatively unusual approach; in most PSCs unused cost recovery simply forms part of profit petroleum.

The contractor pays petroleum income tax of 38% on the revenues it derives from its share of cost recovery, excess cost recovery and profit petroleum, less eligible deductions. Losses from prior periods are carried forward indefinitely. When the oil price exceeds $25/Bbl, escalated by 4% from the date of contract, the contractor pays an additional profit tax. The government takes 70% of the profit arising from the difference between the base and actual prices. Petronas Carigali, an exploration and production company wholly owned by Petronas, can elect to take a minimum 15% participation interest carried through exploration. Past costs are not repaid but are cost recoverable. Participation in actual contracts has varied between 15% and 50%. Figure 11.2 graphically represents the revenue to the government of Malaysia from a stylized 900 million barrel oil project, the assumptions for which are set out in Figure 11.4. The average effective tax rate (AETR) is also shown as a measure of government share.

Figure 11.2Malaysia–Thailand project life revenues and AETR from a stylized 900 MMBbl field

Source: Authors’ calculations

Figure 11.3Nigeria–São Tomé e Príncipe project life revenues and AETR from a stylized 900 MMBbl field

Source: Authors’ calculations

Figure 11.4Project economics: stylized petroleum project examples

Source: Authors’ estimates

2.2.2 Fiscal framework for petroleum activities in Thailand

Petroleum exploration in Thailand commenced in the early 1920s in the northern part of the country. Government agencies exclusively undertook these activities, with no participation by the private sector. All that changed in 1954, when the government implemented a new policy that allowed the private sector to explore and develop petroleum resources. The Petroleum Act (PA) and Petroleum Income Tax Act (PITA) of 1971 were then enacted to regulate and tax petroleum activities in the kingdom.

The PA and PITA have gone through several amendments. Contracts awarded before 1982 were regulated and taxed by the Thailand I Regime. The Thailand II Regime took effect in 1982 during the hike of oil prices but was amended in 1989 to become Thailand III Regime. Legislation was revised again in 2007, PA (No. 6) and PITA (No. 6), for the bidding round of that year.12 A state-owned company PTT Public Company Limited (PTT), formerly known as the Petroleum Authority of Thailand, became one of the Fortune 500 Global Companies during the oil boom years. PTT Exploration and Production (PTTEP), a subsidiary of PTT, accounts for about 30% of total domestic oil and gas production, with operations overseas. In the private sector, Chevron remains the largest player, producing about 70% of oil and condensates from its offshore fields in the Gulf of Thailand in 2010.13

Thailand III is a royalty and tax regime. The contractor pays a royalty at rates on a sliding scale of monthly sales volume as summarized in Table 11.2. The royalty falls to 70% of the regular rates for deep-water blocks. After deducting royalty at the prescribed rate the contractor pays petroleum income tax at 50% but is not required to withhold tax when dividends are distributed to investors. A reduction of income tax to 35% is possible through a royal decree, but a remittance tax of 23.08% is then payable, making an effective tax rate of 55% on remitted profits.14 The contractor must withhold 15% on the payment of interest to lenders in either case. The legislation makes no explicit provision for state participation; however, the Invitation to Bid of May 23, 2007, included a provision for participation by a Thai national entity (usually the state company) in the petroleum concessions of at least 5%. The contractor carries the state entity through development but receives reimbursement for the state entity’s share of past costs.

Table 11.2Royalty rates for Thailand III
Monthly Sales VolumeRoyalty Rates
Up to 60 MMbbl5%
60–150 MMbbl6.25%
150–300 MMbbl10%
300–600 MMbbl12.5%
Over 600 MMbbl15%

Unique to the Thailand III fiscal regime is a form of additional profits tax known as “special remuneratory benefit” (SRB) introduced by the amendment to the Petroleum Act in 1989. The contractor’s income per metre of well drilled sets a scale for SRB rates. Income for this purpose is the revenue from the petroleum before royalty and other payments to the government, adjusted for inflation and exchange rates. Metres of wells drilled is the cumulative total metres of all wells drilled during the licence period, beginning at exploration, plus a geological constant which is intended to reflect the relative risks and difficulties associated with drilling the block. The geological constant varies from 300,000 metres for onshore blocks to 600,000 metres for deep offshore blocks in the Andaman Sea for the 19th and 20th bidding rounds: the higher the figure, of course, the lower the resulting income per metre of well. The rates of SRB are determined according to a sliding scale in Table 11.3, with a maximum rate of 75%.

Table 11.3Rates of special remuneratory benefit using Thai Baht
Income per metre of wellSRB
Up to THB 4,8000%
THB 4,800–14,4001% per each THB 240 increment
THB 14,400–33,6001% per each THB 960 increment
Over THB 33,6001% per each THB 3,840 increment (max. 75%)

The SRB rates are applied to the petroleum profit, calculated as revenue less capital expenditure with uplift, operating expense, and petroleum loss carried forward from prior years. Each contract specifies a rate of uplift. The Petroleum Regulation of 1989 stipulates the maximum rate of such uplift to be 35%. Negative petroleum profit (i.e., loss) is carried forward to the next period. The SRB is deductible for petroleum income tax purposes. Figure 11.2 presents the revenue streams to the government from a stylized petroleum project.15

2.2.3 Fiscal regime for the Malaysia–Thailand joint development area

The fiscal regime for the JDA is patterned largely on Malaysia’s PSC, but with a simpler profit sharing mechanism between the contractor and the Joint Authority. From total production, a royalty of 10% is payable to the Joint Authority. Petroleum exported outside of both Malaysia and Thailand incurs export tax at 10%. Customs authorities of both countries collect the export tax individually but reduce the amount due by the contractor by 50% in accordance with the percentage attribution to each state. Cost recovery is limited to 50% of petroleum produced, and unused cost recovery forms part of profit petroleum. Profit petroleum is split equally between the contractor and the Joint Authority. The contractor pays income tax on remaining petroleum income. An income tax exemption applies for the first 8 years of production, after which the contractor pays income tax at 10% for the next 8 years and 20% thereafter. The contractor pays income tax to the tax authorities of both countries, but the amount is reduced by 50% by each country. Tax losses can be carried forward indefinitely. The contractor pays additional profits tax of 50% (similar to the Malaysian device) where the petroleum price exceeds US$25 per barrel, escalated by 5% every year from 1994. No withholding tax applies to dividends or interest payments.

2.2.4 Discussion

For the assumed example the JDA regime emerges as significantly less tough on the contractor than either of the national fiscal regimes. The share to the states in aggregate, however, would include the proceeds to the national oil companies in each case. Assuming those are no different from cases under exclusive national jurisdiction, then the explanations for the more generous regime would include less favourable geological conditions and prospectivity in the zone, an intention of both countries to accelerate development in the joint zone relative to other areas, and an awareness that risk of future change in the JDA rules might add to investors’ perceptions of risk. Some combination of these probably applies.

2.3 Nigeria–São Tomé e Príncipe joint development zone

2.3.1 Fiscal framework for petroleum activities in Nigeria

Nigeria is the largest producer of petroleum in Africa and is a member of OPEC.

The first commercial discovery in Nigeria was made in the Niger Delta in 1956, where production commenced 2 years later. The oil industry has remained concentrated in the Niger Delta, with a daily production rate of about 2.5 MM Bbl. Nigeria also holds the largest reserve of natural gas in the continent, in addition to a vast amount of coal and renewable natural resources.16

Two separate fiscal regimes apply to oil in Nigeria – the joint venture (JV) regime, essentially a tax and royalty system applies onshore/in shallow water, and production sharing applies in deeper waters offshore.17 Both regimes, however, were to be modified under the terms of the new Petroleum Industry Bill (PIB), originally proposed in 2008 but not enacted by the National Assembly by the time of the change of government in 2015. The PIB has gone through several versions. This chapter illustrates the terms included in the July 2009 Memorandum on the PIB prepared by the Inter-Agency Committee (the Inter-Agency Memorandum, IAM), the last major revision prior to the 2015 election. Table 11.4 provides summaries of 1993 and 2005 PSCs and IAM terms for both fiscal regimes. The terms for the latest 2007 PSC are presented in Appendix 1, where they are compared with regimes of other countries.

Table 11.4Summary of Nigeria fiscal terms
Current terms – Oil projectsIAM terms
1993 PSC2005 PSCJVPSC (deep water)JV/onshore
Royalty on productionRoyalty on productionRoyalty on productionRoyalty on productionRoyalty on production
Royalty0–200m 16.67%,200–500m 12%,0–100m 18.50%,0–25Mbpd 5%5%/12.5%/25% varying with production rate and location (see Table 11.1)
200–500m 12%,500–800m 8%100–200m 16.5%,25–50Mbpd 12.5%Max. for existing 20% onshore
500–800m 8%,800–1000m 8%200–500m 12.5%,>50Mbpd 25%Max. for existing 18.5% shallow
800–1000m 4%, >1000m 0%> 1000m 8%800–1000m 4%, >1000m 0%Royalty on price $70 — $110; 0.4% per $1 $110–140; 16%+ 0.2% per$1Royalty on price $70 — $110; 0.4% per $1 $110–140; 16%+ 0.2% per$1
On shore: 20%$110–170; 22% + 0.1% per $1 >170; 25%$110–170; 22% + 0.1% per $1 >170; 25%
Valuation pointvolume of oil lifted/delivered to terminals (shipments)oil production (wellhead)
Valuation basisPosted price or actual price, whichever higherOfficial swelling price, as determined by Inspectorate and adjusted for quality and transportation costs
Production sharingCost recovery limit 100%Cost recovery limit 100%n/aCost recovery limit 80%n/a
Sharing using cumulative productionSharing using R-factorSharing basis unchanged
Govt. share 20%–60% Profit petroleum shared after PPTGovt. share 25%–75% Profit petroleum shared after PPTProfit petroleum before NHT
PPT/NHT1/PPT 50%PPT 85%NHT 30% (deep water and frontier)NHT 50% (on shore and shallow water)
Investment tax credit/allowance50% tax credit for PPT50% tax allowance for PPTTax allowance 5% on shore; 10–20% offshoren/an/a
Depreciation20% yr 1–4; 19% yr 5 from date incurred; intangible drilling expensed immediately20% yr 1–4; 19% yr 5 from commercial production; intangible drilling depreciated
Small field allowances (NHT)not applicableSeparate oil, condensate and gas allowance. Volume cap, $ per barrel/$ per MMBtu cap and proportion of realized price cap. Different limits for on shore, shallow water, off shore
CIT ratenot applicableCIT 30%, consolidated by company
CIT depreciation25% per year from production
Cost deductibilityWholly, Exclusively, Necessarily test for PPTBenchmarked, Verified, Approved test for NHT; Wholly, Exclusively, Necessarily and Reasonably for CIT

Non-deductible: non-Nigerian overhead, 20% other non-Nigerian costs; interest and certain other costs (demurrage)
Withholding taxnil for PPTnil for NHT; 10% for CIT (intention is to exempt)
Industry levynot applicable2% of revenues
NDDC levy3% of costs3% of costs
Education tax2% of assessable profit2% of assessable profit
Ring-fencePPT by companyNHT consolidated by company for upstream but separately for deep water and on shore/shallow. Midstream subject to CIT only. CIT consolidated by company

Petroleum Production Tax (PPT); National Hydrocarbon Tax (NHT)

Petroleum Production Tax (PPT); National Hydrocarbon Tax (NHT)

JV arrangements are between the holder(s) of an oil mining licence and the federal government as represented by the Nigerian National Petroleum Corporation (NNPC). In the first instance the JV partners are entitled to 100% of production. Each JV partner, including NNPC, then sells its share of production, pays its share of costs, and is separately liable for royalty and taxes. The JVs operate under a royalty/ tax system originally specified in legislation but modified since enactment by a memorandum of understanding (MOU) between the companies and the government, which has undergone several revisions. The government receives a royalty payment between 0% and 20% of total production depending on the location and water depth of the field. Petroleum profits tax applies to petroleum income at 85%.

Under PSCs, the government, represented by NNPC, appoints the investor as “contractor” to assist the government in developing the resources. The parties agree that the contractor will meet the exploration and development costs in return for a share of any production to recover cost and a share of profit oil in excess of the cost. The contractor will have no right to be paid in the event that discovery and development do not occur. If production goes ahead, the government receives a royalty payment from the contractor at a rate that ranges from 0% to 16.67% depending on location and water depth of the block. The contractor is allowed to recover cost from a maximum 80% of total production after royalty. Profit petroleum is split between the government and the contractor according to a scale using the cumulative post-tax revenue-to-investment ratio – the R-factor.18 The contractor pays corporate income tax on its income at 50% and withholds 10% of dividends and interest payments before remitting them to shareholders and lenders. Figure 11.3 shows the revenue streams that make up the total government revenue from the 900 MMbbl field example.

2.4 Fiscal framework for petroleum activities in São Tomé e Príncipe

The presence of hydrocarbon in São Tomé e Príncipe (STP) was known from the middle of the 19th century. However, it was not until 1972 that Texas Pacific drilled the first exploration wells. At the end of 2015, no commercial discovery had been declared in the exclusive economic zone. Nevertheless, because of its location in a region where major oil plays have been found, the country has potential to become a large producer of hydrocarbons.

Hydrocarbon activities in STP’s exclusive economic zone would operate under either a production sharing (PSC) system or a risk service contract (RSC) system and be taxed according to the petroleum taxation legislation. If a development went ahead the government would receive 2% of total production in royalty payment under the PSC system. Up to 80% of total production (the cost oil or gas limit) after royalty can be taken to recover the costs of petroleum operation and development.19 The government and the contractor share profit petroleum according to a sliding scale of pre-tax nominal rates of return (Table 11.5). The contractor pays 30% on its profits to the government. Losses from prior periods can be carried forward indefinitely. The model PSC does not stipulate the level of state participation in the project. However, the first Licensing Round Presentation in 2010 indicated a 10% minimum participation by the state in the form of free venture interest in the contractor group.

Table 11.5Contractor profit share in STP PSC
Contractor’s Rate of ReturnContractor’s Profit Share
ROR < 16%100%
16 % ≤ ROR < 19%90%
19 % ≤ ROR < 23%80%
23 % ≤ ROR < 26%60%
ROR ≥ 26%50%

In the RSC system, instead of sharing production, the contractor would be compensated for its “service” with a portion of the revenues derived from petroleum production as agreed between the two parties. The government retains ownership of the resources under both PSC and RSC systems. The National Petroleum Agency (ANP) and Petroleum Oversight Commission together manage and oversee petroleum activities in the country. Figure 11.3 shows the government revenue breakdown from a stylized project example under the PSC system.

2.4.1 Fiscal framework for petroleum activities in Nigeria–São Tomé e Príncipe JDZ

Nigeria and São Tomé e Príncipe did not agree on the maritime boundary but acknowledged the importance of natural resources lying beneath the disputed area. The two countries established a joint development zone in February 2001, where Nigeria and STP have 60% and 40% of interests in the zone, respectively.20 The treaty will last for 45 years but will be reviewed 30 years after the date of signature. The JDZ Petroleum Regulations and the JDZ Tax Regulations, along with the model PSC, govern petroleum activities in the joint jurisdiction under the Nigeria–São Tomé e Príncipe Joint Authority. The first licensing round in the JDZ took place in 2004. A total of five blocks were available for licensing. All blocks were explored to some extent. In December 2011, the government of São Tomé e Príncipe confirmed the existence of commercial quantities of oil in the JDZ in Block 1, where the French oil company Total was the operator.21 Total relinquished Block 1 in 2013, however, while companies in Blocks 2, 3, and 4 had withdrawn in 2012. A new contract with a Hong Kong–based company for Block 1 was subsequently signed.

The fiscal regime for the JDZ has the overall structure of a Nigerian PSC, including R-factor production sharing, in contrast to STP’s internal rate of return (IRR) mechanism. If development is successful, the contractor pays a royalty to the Joint Authority at a rate that depends on the daily rate of production. The royalty rate is 0% if production is less than 20 Mbpd and 5% if production exceeds 70 Mbpd. When daily production falls between these two thresholds, the royalty rate is determined by the formula: 5% × (1 − [(70 − P)/ (70 – 20)]), where P is production in Mbpd. As in Nigeria’s and STP’s EEZs, the contractor recovers investment and cost of operations from a maximum of 80% of production after royalty. Petroleum after royalty and cost recovery divides between the contractor and the Joint Authority according to the post- tax R-factor as set out in Table 11.6. Profits to the contractor are subject to 50% tax, with indefinite loss carry-forward. Each country imposes its own rules with regards to dividend and interest withholding taxes, with Nigeria taxing 60% and STP taxing 40% of the total amounts. Where the imposition is joint, Nigeria takes 60% and STP 40%; where the imposition is according to national rules the effective base is reduced to each country’s attribution percentage. There is no requirement for the Joint Authority to have an equity interest in the projects.

Table 11.6Contractor profit share from PSC
R-FactorContractor Profit Share
R < 1.280%
1.2 ≤ R < 2.525% + ([(2.5 − R)/(2.5 − 1.2)] × (80% − 25%))
R ≥ 2.525%

3 Evaluation of fiscal regimes in JDZs

This section reports results from quantitative simulations of the fiscal regimes for exclusive economic and joint development zones.22 In practice, investment decisions depend on a variety of factors that go beyond the fiscal regime – such as perceived geological potential, stability of institutions, and companies’ diversification strategies. This analysis focuses exclusively on the characteristics of the fiscal regime and thus assumes all other factors constant and neutral with respect to the investment decision.

Appendix 1 presents a summary of fiscal terms for regimes simulated. JDZ fiscal regimes change in successive licensing rounds or offers of acreage. For the purpose of comparing exclusive and joint development zones and of detailed analysis, only one actual and recent fiscal regime is simulated for each JDZ scheme. For example, the fiscal terms for the 2007 PSC bidding round in Nigeria are simulated, but not the terms for 1993 and 2005 PSCs. Moreover, to simplify, minor taxes and levies are left out of the analysis unless they make up a material contribution to government revenues. Such additional items may include surface rentals, social development contributions, or local government taxes and levies.

The simulations employ two stylized project examples: a 300 million barrel (MM bbl) offshore field with a relatively high total cost per barrel of recoverable reserves, and a relatively larger 900 MM bbl offshore field with lower total cost per barrel. Figure 11.4 shows the project economics for the two fields. Note that these project examples do not reflect a particular field in a particular country but nevertheless represent fields that are broadly realistic in production profiles and costs. This is not to argue that these fields would have been viable or profitable in a low-price environment such as that prevailing early in 2016: in common with many other new prospects (and existing fields) their feasibility may depend on higher long run average prices. Moreover, measures such as the average effective tax rate (AETR) represent a division of rent – meaningful only where rent (as a surplus over minimum acceptable returns to capital) occurs – hence the use of high prices in our simulations to evaluate circumstances where there is material rent.

The evaluation uses simple economic assumptions. An oil price is assumed at US$90 per barrel in the base year, in order to demonstrate regime effects in above-average conditions of potential profitability, and the price escalates every year at a rate of 2%.23 For debt finance, the real risk-free interest rate is 1%, to which is added a margin of 3.5%. Government, and the oil company investor results are presented using a discount rate of 10%. Equity finance meets all exploration costs, with development costs 70% debt financed. Finally, both fields are assumed to be located in offshore areas at depths of 1,200 metres. The last assumption only affects the results for Nigeria and Thailand where royalty rates vary according to water depth and location of the fields.

The average effective tax rate (AETR) presents a project-specific measure of “government take” in a success case. The AETR consists of the government’s share of pre-tax net present value (NPV), usually measured at the government’s assumed discount rate. For alternative fiscal regimes, alternative prices, and other circumstances, the AETR provides a comparative benchmark. Figure 11.5 reports estimated AETRs for the regimes studied.

Figure 11.5Average effective tax Rates for EEZs and JDZs

Source: Authors’ estimates

Several observations emerge from the simulations. First, the ranking of fiscal regimes according to AETRs in this high-price case is consistent between both field examples (offshore 300 MM Bbl and offshore 900 MM Bbl), with Thailand on the top and Australia at the bottom of the charts. Second, no consistent pattern exists as to whether exclusive zone national regimes are “tougher” than joint regimes or vice versa. While exclusive zone regimes for Thailand and Malaysia yield higher AETRs than the joint regime, the opposite is true for Nigeria and São Tomé e Príncipe.24 The Australia–Timor-Leste joint regime is tougher than Australia’s exclusive zone regime but less tough than Timor-Leste’s under both scenarios. The rankings may well change with different oil price assumptions.

Thailand’s national regime is tougher than the joint regime as a result of the special remuneratory benefit (SRB, outlined earlier in this chapter) and a higher income tax rate (50% in the exclusive zone compared with a maximum of 20% for the JDZ). Recall that SRB is applied on profit petroleum at a rate that is progressive with income per metre of well. In the simulations, income per metre ranges between US$600 and US$3,000 for the 300 MM Bbl case and between US$900 and US$6,500 for the 900 MM Bbl case; thus SRB is imposed at or close to the maximum 75% rate for much of the project’s production period. Combined with royalty, profit tax, and other fiscal terms, the SRB makes the government take very high on the assumptions used here. The Malaysian EEZ regime is considerably tougher than the joint regime because of the higher corporate tax and supplementary tax rates and the presence of interest withholding tax and state participation in the projects.

The fiscal terms for the Nigeria–São Tomé e Príncipe JDZ produce a somewhat higher AETR than the assumed terms for the Nigerian EEZ. The deep- water assumption translates into 0% royalty rate for Nigeria but not for the JDZ. The Joint Authority also receives a higher share of profit petroleum. Similarly, the JDZ regime is tougher than the São Tomé e Príncipe regime because the JDZ guarantees a minimum 20% share of profit oil to the government while the national regime does not. The joint regime also imposes a higher rate of petroleum income tax (50% compared with 30%). However, the effects of these fiscal terms are offset in the national regime by a 10% free share in the contractor group.

Terms for the Timor-Leste–Australia JDZ are described in section 4. The government take for Timor-Leste is higher than those for the regimes applicable to Bayu-Undan and the new JPDA mainly because of the 15% state-carried interest assumed, given that other fiscal terms are broadly comparable. The first tranche petroleum in the Bayu-Undan regime acts as a pre-allocation of profit share, making an implicit royalty at the same rate as in the Timor-Leste national regime. Initial profit share to the government is less for the Bayu-Undan JDZ regime but would be higher for a large field. Australia does not impose royalty but has a resource rent tax in its national regime that is not applicable to profits from the JPDA since production sharing applies instead. The combined effect of the difference in fiscal terms results in a lower government share for the Australian jurisdiction than under either the joint regimes or the Timor-Leste national terms.

4 The case of Australia and Timor-Leste in the Timor Sea

4.1 Legal and fiscal framework for petroleum activities

Timor-Leste and Australia have no final maritime boundary in the Timor Sea. The two governments put in place a complex set of interim arrangements for the sharing of petroleum extracted from two overlapping joint development zones in the Timor Sea: (1) the Joint Petroleum Development Area (JPDA) under the Timor Sea Treaty (TST) and (2) the Greater Sunrise Unit Area (governed by the International Unitisation Agreement [IUA] and the Treaty Concerning Certain Maritime Areas in the Timor Sea [CMATS]). (See Figure 11.6.) These treaties result from long negotiations from 1999 to 2007 over replacements for arrangements made between Indonesia and Australia, during the period when Indonesia controlled East Timor. In sum, all these arrangements illustrate the full range of challenges in making interim arrangements in lieu of a full maritime boundary determination; hence the separate focus on this case in this chapter.25

Figure 11.6Timor Sea – joint petroleum development area

Indonesia and Australia ratified an agreement in 1972, establishing a frontal maritime seabed boundary between the two countries in the Timor Sea and beyond. Portugal then ruled Timor-Leste and declined to participate in negotiations over a maritime boundary in the area. As a result, Australia and Indonesia left a gap in the frontal line (the “Timor Gap”), pending future negotiations with Portugal.

Indonesia’s annexation of Timor-Leste as a province of Indonesia, following the occupation of late 1975, was not internationally recognized (UN Security Council Resolutions 384 [1975] and 389 [1976]). Australia, however, entered into negotiations with Indonesia about petroleum rights in the Timor Sea after Indonesia signalled unwillingness simply to “join the dots” across the gap in the 1972 frontal line. The “gap” lies between points A16 (east) and A12 (west) in the Australia–Indonesia maritime boundary (see Figure 11.6). The “Timor Gap Treaty” of 1989 resulted (ratified 1991), creating “Zone of Cooperation A” (ZOCA), where petroleum produced was attributed 50% to Australia and 50% to Indonesia. The ZOCA required the drawing of lateral lines intersecting the end-points that marked the Timor Gap in the 1972 treaty, and of further frontal lines to the north, and to the south at the median line between the opposing coasts.26 Exploration had commenced earlier under both Portuguese and Australian authorizations and accelerated within the ZOCA. By 1999 there were major discoveries at Bayu-Undan, and at Sunrise and Troubador (“Greater Sunrise”), where the fields extended beyond the eastern perimeter of the ZOCA. Other smaller discoveries resulted in oil production at Elang Kakatua-Kakatua North.

Following the UN–sponsored referendum of 1999, Indonesia withdrew from Timor-Leste, and the UN established a transitional administration in East Timor (UNTAET). UNTAET declined to adopt the Timor Gap Treaty on behalf of Timor-Leste, continuing the arrangement only by means of an Exchange of Notes with Australia enabling existing activities to continue. In July 2001, UNTAET and Australia agreed the text of a new Timor Sea Treaty (TST). The ZOCA was renamed the Joint Petroleum Development Area (JPDA), and the treaty once again created an interim arrangement without prejudice to any future maritime boundary delimitation.

The TST attributed 90% of JPDA petroleum produced to Timor-Leste and 10% to Australia. Annex E of the TST called for unitization of Greater Sunrise, attributing 20.1% of Sunrise petroleum to the JPDA and 79.9% to Australia, following available technical information at the time about the likely reserve proportions in each jurisdiction. The TST was ratified by Timor-Leste in 2002 and then by Australia in 2003 after completion of negotiations over the international unitization agreement (IUA) for Greater Sunrise and the approval of arrangements for gas production at Bayu-Undan.27 Australia ratified the IUA in 2003, but Timor-Leste declined to ratify pending a settlement of its wider maritime claims in the Timor Sea. A permanent maritime boundary was not delineated, but the dispute was resolved for the time being by a further interim arrangement, the Treaty on Certain Maritime Areas of the Timor Sea (CMATS): CMATS preserved the TST and IUA, but all the taxation and production- sharing revenue derived by both governments from the Sunrise unit area would be pooled and shared equally between the countries. CMATS and the IUA entered into force in 2007. If no development plan for Greater Sunrise had been approved by 2013, the parties were entitled to terminate CMATS. By 2016 neither Australia nor Timor-Leste had done so, though Timor-Leste had once again called for negotiations or arbitration under UNCLOS to delimit permanent maritime boundaries.28 CMATS contains a provision that, even if terminated, it returns to operation if and when a development plan for the Greater Sunrise fields is approved.29

A combination of production sharing and taxation generates revenue for Timor-Leste and Australia in the JPDA. As a result of the treaties, however, there are four variants of the production sharing contract (PSC) operation in the JPDA and areas outside it exclusively granted under contract by Timor-Leste. Further, the tax rules applied by Timor-Leste also differ among projects, mainly because certain rights for pre-existing PSC holders were preserved under the Timor Sea Treaty and because there are some differences in terms between the JPDA and areas of Timor-Leste exclusive jurisdiction. Australia applies its own oil and gas fiscal regime in areas it has licensed outside the JPDA but takes proceeds from production-sharing contracts within the JPDA in lieu of its own petroleum resource rent tax (PRRT). The implementation of these fiscal regimes therefore carries unavoidable administrative complications.

4.1.1 The JPDA general regime

The TST calls for agreement between Timor-Leste and Australia over a joint “fiscal scheme” for each petroleum project in the JPDA (Article 5), covering the sharing of petroleum between investors and the two governments. The contract incorporating the fiscal scheme is also the form of licence for petroleum activities. The two governments agreed a new Petroleum Mining Code (PMC)30 for the JPDA, and set out a model PSC as the general “fiscal scheme”; in addition, under the terms of the Treaty and the Tax Code,31 Timor-Leste and Australia impose national taxation on their respective shares of revenues from and relevant activities in the JPDA. Timor-Leste incorporated its Petroleum Taxation Act of 2005 into its Taxes and Duties Act of 2008. This overall scheme applies to PSCs granted following the first post-TST licensing round for the JPDA held in 2006.32

4.1.2 The Bayu-Undan regime

The TST (Annex F), however, preserved the pre-existing PSCs setting out the regulatory and fiscal terms for the Bayu-Undan area (extending across two PSCs) and the part of Sunrise located in the JPDA (also two PSCs). Timor-Leste also preserved the inherited taxation terms for these PSCs while Australian taxation applies in accordance with prevailing law. In the period prior to final ratification of the TST, the Bayu-Undan PSCs (and taxation terms) were renegotiated, so that the rules applying to the Bayu-Undan project consist of the original PSCs,33 as amended by “Appendix X”, the inherited Indonesian Law on Income Tax (as at October 25, 1999), UNTAET Regulation 2000/18 and the Taxation of Bayu-Undan Contractors Act (2003). The taxation terms for the Timor-Leste portion of Bayu-Undan were fixed under a Tax Stability Agreement – this is symmetrical, so that Bayu-Undan contractors do not benefit from general tax reductions.

4.1.3 The Sunrise regime

The PSC and tax rules for the Sunrise contract areas were not amended after the TST came into force – thus, in practice, creating a third regime. As of 2016, this was relevant only to the Sunrise joint venture partners and taxation of subcontractors working in the JPDA on Sunrise. It consists of the inherited PSCs, the inherited Indonesian Law on Income Tax, and UNTAET Regulation 2000/18.

The fourth PSC regime is that for areas outside the JPDA where TimorLeste applies its own exclusive jurisdiction. The PSC terms have been similar to those for the JPDA but included an option for a Timor-Leste national oil company to take up to 20% of a development at the time a commercial discovery is declared. Taxation of activities under these PSCs in Timor-Leste is set out in the Taxes and Duties Act (2008) but is not, of course, subject to the TST Taxation Code. For areas where Australia applies its exclusive jurisdiction the Australian offshore petroleum fiscal regime applies.

The fiscal terms that result from these four regimes are summarized in Table 11.7 for the PSCs and Table 11.8 for the tax regimes. The scheme of the PSC and tax is illustrated in Figures 11.7 for Bayu-Undan and 11.8 for Sunrise and the split by revenue type in Figure 11.10. Bayu-Undan and Greater Sunrise both allocate an initial tranche of petroleum, which is shared between the contractor and the designated authority (DA).34 This first tranche petroleum is, in effect, a limit on cost petroleum, as it ensures that some production will be shared between the contractor and the DA, as soon as production commences. In contrast, the PSCs not covered by Annex F (and PSCs in Timor-Leste’s exclusive jurisdiction) allocate 5% of production to the government, and this allocation is, in effect, a 5% royalty.

Table 11.7Timor-Leste: PSC fiscal terms and sharing between governments
JPDA PSCsPSCs in Timor-Leste’s Exclusive Jurisdiction
Bayu-Undan (Annex F Preserved PSCs)Sunrise (Annex F Preserved PSCs)PSCs not covered by Annex F
First tranche petroleum (FTP) or royalty10% of production; shared in same proportions as profit oil and gas between DA and contractor10% of production rising to 20% after 5 years; shared in the same proportions as profit oil and gas between DA and contractor5% of production to government (a royalty payment)5% of production to government (a royalty payment)
Cost petroleumPermits recovery of investment credit (equal to 127% of exploration costs + tangible capital) plus operating costs (includes current-year exploration costs, non-capital costs, depreciation and allowable operating costs in previous years that have not been recovered).Permits recovery of investment credit (equal to 127% of exploration costs + tangible capital) plus operating costs (includes current-year exploration costs, non-capital costs, depreciation and allowable operating costs in previous years that have not been recovered).Petroleum less royalty but not more than recoverable costs (exploration, appraisal, capital, and operating costs plus decommissioning reserve allowed that year). Unrecovered costs uplifted by the U.S. 30-year bond rate plus 11 percentage points.Petroleum less royalty but not more than recoverable costs (exploration, appraisal, capital, and operating costs plus decommissioning reserve allowed that year). Unrecovered costs uplifted by the U.S. 30-year bond rate plus 11 percentage points.
Government share of profit petroleumAny remaining petroleum after FTP and cost petroleum is split between the DA and contractor. For oil (inc. condensate): the government share increases from 50 to 70% as bpd increases; for gas, the government share is 40%.Any remaining petroleum after FTP and cost petroleum is split between the DA and contractor. For oil: the government share increases from 50 to 70% as bpd increases; for gas, the government share is 50%.Any petroleum remaining after the royalty and cost petroleum is split between the DA and the contractor. The DA’s share is 40%.Any petroleum remaining after the royalty and cost petroleum is split between the government and the contractor. The government’s share is 40%.
DecommissioningDetailed agreed provision (Appendix X) that permits a decommissioning cost reserve. Undiscounted costs recovered (UOP) over 15 years.No provisionDecommissioning reserve permitted, but costs discounted at the uplift rate.Decommissioning reserve permitted, but costs discounted at the uplift rate.
Ring-fencingBayu-Undan project ring-fenced by development areaBy contract areaBy contract areaBy contract area
Sharing between governments90% of DA’s FTP and profit petroleum to Timor-Leste; 10% to AustraliaUnder CMATS, 50:50 sharing of JPDA and non–JPDA upstream revenues (sharing and tax revenue)90% of DA’s royalty and profit petroleum to Timor-Leste; 10% to AustraliaNot applicable
State participationNoNoNoAt the time of a commercial discovery, election for participation (up to 20%) through a state-owned contractor, required to pay its share of future costs.
Table 11.8The tax regime applying to Timor-Leste’s PSCs
JPDA PSCsPSCs in Timor-Leste’s Exclusive Jurisdiction
Bayu-Undan (Annex F Preserved PSCs)Sunrise (Annex F Preserved PSCs)PSCs not covered by Annex F
Timor-Leste Income taxFrozen Indonesian law modified by TBUCA, with 30% fixed rate; no branch profits taxFrozen Indonesian law with 30% rate; 15% branch profits tax if Treaty tax code applies; (total tax 40.5%).Imposed by the Tax and Duties Act, petroleum rate 30%Imposed by the Tax and Duties Act, petroleum rate 30%
Depreciation and amortization for income tax purposesAll exploration and development expenditure, including tangible assets: Useful life 1–4 years: 25% SL Useful life >4 years: 20% SL Pro rata depreciation in first year of production EKKN residual losses on closure amortized against Bayu-Undan income over 5 years, SLFrozen Indonesian law rules: Tangible assets: Election of SL or DB methods over useful lives.

Asset classes: < 4, 8, 16, or 20 years.

Intangible assets: amortized by units of production method (includes exploration and intangible development expenditure).
Exploration expenditure – SL 5 years;

Development expenditure (other than depreciable tangible assets) — SL 10 years, or project life;

Depreciable assets other than buildings — SL (individually) or DB (pool) over useful life.

Asset classes: < 4, 8, 16, or 20 years.

Option for depreciation by units of production method for small fields.
Exploration expenditure — SL 5 years;

Development expenditure (other than depreciable tangible assets) — SL 10 years, or project life;

Depreciable assets other than buildings — SL (individually) or DB (pool) over useful life.

Asset classes: < 4, 8,16, or 20 years.

Option for depreciation by units of production method for small fields.
Ring-fencingBayu-Undan project ring-fenced by development areaBy contract areaBy contract areaBy contract area
Withholding tax on payments to non-residents20% withholding tax on interest and dividends, subject to reduction under the Timor Sea Tax Code if payee is Australian. 8% on services, with some special categories calculated under frozen Indonesian rules20% withholding tax on interest, dividends and services, subject to the Timor Sea Tax Code if payee is Australian, with some special categories calculated under frozen Indonesian rules.6% final withholding tax on all payments for services. 10% withholding tax on other payments to nonresidents (except where taxed as permanent establishment).6% final withholding tax on all payments for services.

10% withholding tax on other payments to non-residents (except where taxed as permanent establishment).
Additional profits taxImposed by TBUCA: net 22.5% after 16.5% rate of returnNoImposed by the Tax and Duties Act (as Bayu-Undan), termed Supplemental Petroleum Tax (SPT)Imposed by the Tax and Duties Act (as Bayu-Undan), termed Supplemental Petroleum Tax (SPT)
Fiscal stabilityYes – tax law frozen; contractors do not benefit from tax reductionsNoNoNo

Figure 11.7Fiscal regime for Bayu-Undan

Figure 11.8Sunrise fiscal regime

Figure 11.9Timor-Leste and JPDA PSCs

Figure 11.10Australia and Timor-Leste: fiscal regimes; 900 MMBbl field

Source: Authors’ calculations

All the PSCs allow generous recovery of costs, by permitting an uplift of certain costs. In the case of the preserved PSCs, the uplift is equal to 127% of exploration costs and tangible capital (the investment credit). This device was inherited from the old Indonesian PSC regime for “remote areas” but during the period of the “Timor Gap Treaty” was even more generous. In the case of the PSCs not covered by Annex F (or those in in Timor-Leste’s exclusive jurisdiction),35 unrecovered costs are uplifted annually by the U.S. 30-year bond rate plus 11 percentage points.

The split of profit petroleum is generally fixed percentages of remaining production. For oil production from the preserved PSCs, the fixed sharing varies within defined increments of the level of daily production, with three tranches: 0 to 50,000 bpd, DA share 50%, 50,000 to 150,000 bpd 60%, and greater than 150,000 bpd 70%. As JPDA PSCs cover the joint development area, the government’s share of petroleum production is shared between Timor-Leste and Australia. The sharing is 90% for Timor-Leste and 10% for Australia. The JPDA share of Greater Sunrise petroleum is first shared 90:10 in favour of Timor-Leste, but under CMATS the governments then share equally in total upstream revenues collected from the entire unitised field (both production and tax revenue) including the petroleum not attributed to the JPDA.

The preserved PSC contractors pay income tax to Timor-Leste under Indonesian law frozen at October 25, 1999. However, the Indonesian law for the Bayu-Undan PSC is modified by the Taxation of Bayu-Undan Contractors Act (TBUCA). Thus for Bayu-Undan there is no branch profits tax but there is an additional profits tax. In general, withholding tax on payments to nonresidents is higher under frozen Indonesian law than under the Tax and Duties Act. Except for Greater Sunrise, all the PSCs are subject to a supplemental petroleum tax (SPT) at a net rate of 22.5% of after-tax cash flows after the contractor has earned a 16.5% rate of return.36

The treatment of interest deductions for tax and PSC purposes also differs. Under the Annex F PSCs the use of interest-bearing debt to finance operations must be approved by the DA. The new JPDA and Timor-Leste PSCs do not permit cost recovery of interest on debt. Under frozen Indonesian income tax rules, interest deductions are restricted to interest on debt that does not exceed a debt–equity ratio of 3:1. Under the Timor-Leste Taxes and Duties Act (2008), interest is deductible but only to the extent of the taxpayer’s interest income plus 25% of the taxpayer’s non-interest income. Any excess interest expense can be carried forward for 5 years.

Box 11.2Petroleum exploration and development in treaty areas37

Following the closure of the small Elang Kakatua-Kakatua North (EKKN) oil fields in 2007, Timor-Leste’s sole producing projects were the Bayu-Undan gas and condensate38 project within the JPDA, operated by ConocoPhillips (with other venture partners) and the small Kitan field (35 million barrels), which started production in 2011 and was expected to stop in December 2015. Bayu-Undan consists of fields unitised from two PSC areas (Figure 11.9) and commenced commercial production of liquids (condensate and LPG) in July 2004 and of gas sales for LNG production in April 2006. Gas is piped to Darwin, Australia, through a pipeline owned by the same joint venturers and processed into LNG at Darwin LNG, a company again owned by the same parties. The LNG is sold under a long-term contract to Tokyo Gas and Tokyo Electric, who purchase it FOB Darwin and ship to Japan in their own LNG tankers. Condensate and LPG are essentially sold at spot prices, though under term contracts with selected buyers.

Bayu-Undan production has reached up to 110,000 barrels per day (bpd) of liquids and one billion cubic feet of gas per day (half exported to Darwin LNG and half re-injected into the reservoir in order to maintain gas exports at LNG plant capacity). Lifetime recoverable reserves of the project are estimated at 4 trillion cubic feet of dry gas and 500 million barrels of liquids, permitting a project life that extends beyond 2020. Bayu-Undan accounted for the vast majority of Timor-Leste government revenues after production commenced.

The Greater Sunrise project consists of the Sunrise and Troubador fields, straddling the JPDA perimeter to the east. The fields lie partly in two JPDA PSC areas and partly in two license areas granted by Australia (Northern Territory). The operator is Woodside Energy (of Australia), in partnership with ConocoPhillips, Shell, and Osaka Gas.39 The joint venture has a commercial unitization agreement for the unit area, which is also the subject of the IUA and CMATS. A development concept for Greater Sunrise had not been decided, nor was a market for gas secured, by early 2016. The fields were estimated by Woodside to contain 5.1 tcf of dry gas and 226 million barrels of condensate.

4.2 Issues

The architecture of the Treaties constrains both Timor-Leste and Australia in making overall policy and legal changes in the JPDA and in the Sunrise area. In addition, Bayu-Undan has a stabilized tax regime under Timor-Leste law. If companies consider the geological prospects in the JPDA worthwhile, then past successful investment (Bayu-Undan) and the stable framework probably act positively to encourage investment.

This chapter does not address the boundary delimitation issues facing both countries. The preoccupations of both countries on those issues, however, have profoundly influenced the interim arrangements made in both the Timor Sea and CMATS treaties, since (understandably) neither country wished to set a precedent that might conceivably work to its disadvantage in any eventual determination of a maritime boundary. In addition, although the treaties establish joint development schemes, that does not mean the interests of both countries coincide with respect to individual petroleum development projects where the resource is located in a joint zone or is subject to a joint scheme.

Four circumstances make clear the extent to which interim arrangements of this kind present challenges that national jurisdiction does not face.

The first and most obvious is the existence of Greater Sunrise as a project that straddles the JPDA and areas outside it. Despite the TST, the Unitisation Agreement, and CMATS, the project had not progressed to development by 2015. The two governments, together with the private petroleum rights holders, had so far not found sufficient alignment of interests to reach a development concept and regulatory endorsements that they could agree and which would give buyers of gas sufficient confidence in security of supply.

The second is jurisdiction over pipelines and the associated transfer pricing questions. The TST provides, in effect, for extra-territorial jurisdiction in the control of the destination country for any pipeline.40 Because regulatory authority over the JPDA for petroleum matters remained joint and carried out by a joint institution, the possibility of confusion and disputes was inherent. Most of these were resolved, though only after skill-intensive and time-consuming negotiations over, for example, the tariff scheme for the Bayu-Undan pipeline, which, in turn, was critical to the upstream transfer price of gas at the delivery point in the JPDA. Others, notably over taxing rights, resulted in arbitration proceedings involving investing companies and the Timor-Leste authorities – not finally resolved by early 2016.

The third concerns commercial decisions over location of petroleum- processing and spin-off activities. The issue was exacerbated by Australia’s status as a mature petroleum-producing country with a substantial skills base in the industry, mature infrastructure, and a record of continuity of supply of oil and gas in export markets, while Timor-Leste had independence only newly restored in 2002 after more than a generation’s experience of invasion, occupation, and violence. The instinct of petroleum companies was not to source inputs from Timor-Leste or to locate processing facilities there. Taking the second and third together, therefore, provides a persistent basis for conflict of interest between the joint zone partners over, for example, the portion of overall revenue accruing in the JPDA and the possibility for each country to use the production to stimulate ancillary industries in Timor-Leste or in the Northern territory (in the case of Australia). This remained a key point of difference on the Sunrise project: Timor-Leste prefers development through an LNG plant onshore in Timor-Leste, while the investors prefer a floating LNG development.

The fourth is the complexity of the joint schemes that emerged in this case. Layers of joint schemes – the TST, the IUA, and CMATS – have to be read together and interpreted. The schemes also gave rise to multiple different regimes applicable to private companies, which proved especially demanding upon the limited regulatory and administrative capacities of Timor-Leste. Timor-Leste has both absolutely and relatively the most at stake in terms of upstream revenues.

In practice, the Timor Sea Treaty effectively became a joint scheme for the development of just one major project – Bayu-Undan. This was not wholly due to the complexity of the arrangements: significant exploration took place in the JPDA both before and after the implementation of the TST but with limited success. The existence of the layers of joint schemes had not, by early 2016, removed the obstacles to development of the Greater Sunrise fields. On the other hand, the TST regime overall (including the applicable domestic tax provisions in both countries) permitted the Bayu-Undan project to go ahead by affording regulatory and fiscal assurances to the investors. Although the agreements concerning Greater Sunrise became entwined with the implementation of the Treaty and the Bayu-Undan project, they were not in themselves essential to the progress of the Bayu-Undan project itself.

5 Conclusions

Joint Development Zones clearly work as pragmatic devices to enable offshore petroleum exploration and production where the relevant countries cannot agree a permanent maritime boundary. Leaving aside the long-standing joint zones in the Middle East, both the Malaysia–Thailand JDZ and the Timor-Leste–Australia JDZ have supported significant production. In Malaysia–Thailand the production consists of a diverse portfolio of fields; that, at 2016, seems less likely for Timor-Leste–Australia where the complex architecture in practice supports a single major project. The varying outcomes must to some degree reflect the underlying motivations of the parties and whether the JDZ is seen by all sides as a satisfactory long-term solution even if technically “interim”. Where both sides favour 50/50 and regard that as fair, the chances of success seem higher than when one party retains just a toehold for whatever reason.

Where there has been a maritime delimitation dispute, agreement on a JDZ with accompanying fiscal instruments does make a difference to private investor confidence. The JDZs do appear to have permitted exploration and development where it might not otherwise have occurred.

Fiscal devices in use in exclusive national jurisdictions also work in JDZs. They do, however, encounter added complications unless the parties decide to implement a single fiscal scheme throughout – whether production sharing or tax/royalty. The Timor Sea arrangements suggest that the implementation of national tax terms for a project, in the attribution percentages, carries unavoidable complications and potential for disputes. Nevertheless, the case for levying regular national taxes on income remaining after the charge for the resource (production sharing or royalty) stands up on grounds of ease of national administration.

We found no systematic differences between JDZ fiscal regimes and neighbouring national regimes in terms of the overall effective tax rates they are likely to imply. The JDZ regimes examined draw from international and local precedent but always with adaptations to the specifics of the joint area. Timing of when the JDZ regime was established relative to the domestic regimes – and hence consequently different perceptions of prospectivity and risk – are likely important determinants of relative fiscal take.

With the increasing importance of gas in world petroleum trade, pipeline and processing facilities have higher importance, together with their associated transfer pricing challenges (see, for example, the chapters by Calder and Le Leuch in this volume). In this area, JDZ architecture itself has so far been relatively weak, though the parties have in most cases developed practical solutions by negotiation. Similarly, the obstacles to development of “straddling fields” seem exacerbated if one part of the field is already in a JDZ. These experiences in the Timor-Leste–Australia case suggest that developing a purpose-built unit development approach for an individual project may prove more tractable, at least in fiscal terms, than the attempt to fit the special case within a much wider treaty or JDZ framework.

That observation leads to the final point. JDZ schemes arise because a dispute or disagreement has arisen in the first place. The effort to promote development while not prejudicing the parties’ pre-existing maritime claims can result in excessive complexity in the schemes, making them hard both to interpret and to administer. Such complexity may sometimes outweigh the incentive to invest in petroleum exploration and development underpinning the rationale for a JDZ.

Appendix 11.1

Petroleum fiscal terms in simulated countries and their joint development areas (JDAs)

Table 11A.1.Petroleum fiscal terms in simulated countries and their joint development areas (JDAs)
JurisdictionAUS-TMLJDA – Bayii-UndanAUS-TML New JPDAAustralia (AUS)Timor-Leste (TML)Nigeria - STP JDANigeria (Deep Water 2007)São Tomé e Príncipe (STP)Malaysia-Thailand JDAMalaysiaThailand
Signature/production bonusNilNilNilNilSB, PBSBSB, PBNilExempt in practiceNil
Royalty rate10% first tranche petroleum (FTP)5%Nil5%0%-5%; daily rate of production (DROP)-based0%-16.67% depending on onshore/offshore and water depth2%10% + 10% export duty2/10% + 10% export duty5%-15%; 70% of regular rates for deep water; sales volume-based
Cost recovery limit100%100%N/A100%80%80%80%50%30%-70%; Revenue/cost (R/C) ratio-basedN/A
Profit sharing (% profit oil to contractor)50%60%N/A60%25%-80%; post-tax R-Factor-based25%-70%; post-tax R-Factor-based50%-100%; ROR-based50%30%-80% if cumulative production < = CTHV; 10%-40%if cumulative production > CTHV4/; R/C ratio-based sliding scaleN/A
Corporate income tax30%30%30%30%50%50%30%0%/10%/20% (first 8 years of production; next 7 years; thereafter)38%50% (modelled) or 35% + dividend WT
Depreciation rule1/5 years (expl./ other capex); straight-line (SL)1/10 years (expl./dev.); SL1/15/5 years (expl./dev./ replacement); SL1/10 years (expl./dev.); SL5 years; SLOil: 5 years; Gas: 4 years; SL5 years; SL1/10/5 years (expl./dev./ replacement); SLVaried methods and rates for asset classes10 years (expl.&drilling cost shallow water); 5 years (other capex); SL
Loss carry-forwardIndefiniteIndefiniteIndefiniteIndefiniteIndefiniteIndefiniteIndefiniteIndefiniteIndefinite10 years
Supplementary profit tax22.5% once IRR reaches 16.5%22.5% once IRR reaches 16.5%40%; PRRT22.5% once IRR reaches 16.5%NilNilNil50% on profit oil when price >$25/ bbl, escalated by 5% from 199470% on profit when price exceeds $25/ bbl, escalated by 4% from date of contract0%–75% SRB progressive with income per meter of well5/
Dividend WTNilNil0% (franked)Nil6% (weighted avg. of both countries)10%NilNilNil23.08%
Interest WTNilNilNilNil14% (weighted avg.)10%20%Nil15%15%
State participationNilNilNil15% carried through exploration1/NilNil10% free equityNil3/15% carried through exploration1/5% carried through dev. with reimbursement6/
Source: FAD’s Fiscal Analysis of Resource Industries (FARI) database.

This is the minimum rate. Carried costs are not reimbursable but are cost recoverable.

Malaysia and the Kingdom of Thailand collect export duties under their respective legislation but reduce the applicable rates by 50%.

There is no provision for state participation in the JDA. However, Petronas’s wholly-owned subsidiary has 50% working interest in all of the three blocks. Thailand’s state-owned PTTEP has 50% in two of the three blocks.

Cumulative total hydrocarbon volume (CTHV): the sum of the individual THVs from a contract area. An individual THV is the lesser of 30 MMBBL or 0.75 TCF or the size of the individual field’s approved proved ultimate recoverable reserves, as adjusted or redetermined from time to time. 30 MMBBL is used in the modelling.

Special remunerator benefit (SRB).

After a production area has been first correctly defined in the concession block, the applicant must propose in its special advantages to have a Thai legal person (established under the laws of Thailand with Thai nationals holding more than 50% in it), with the approval of the Petroleum Committee, to acquire an undivided participating interest of not less than 5% under the concession. Such juristic person shall reimburse the applicant the expenditures incurred from the block prior to the date of its participation according to its participating interest share and bear its participating interest share of all the expenditure incurred in the block from the date of its participation.

Source: FAD’s Fiscal Analysis of Resource Industries (FARI) database.

This is the minimum rate. Carried costs are not reimbursable but are cost recoverable.

Malaysia and the Kingdom of Thailand collect export duties under their respective legislation but reduce the applicable rates by 50%.

There is no provision for state participation in the JDA. However, Petronas’s wholly-owned subsidiary has 50% working interest in all of the three blocks. Thailand’s state-owned PTTEP has 50% in two of the three blocks.

Cumulative total hydrocarbon volume (CTHV): the sum of the individual THVs from a contract area. An individual THV is the lesser of 30 MMBBL or 0.75 TCF or the size of the individual field’s approved proved ultimate recoverable reserves, as adjusted or redetermined from time to time. 30 MMBBL is used in the modelling.

Special remunerator benefit (SRB).

After a production area has been first correctly defined in the concession block, the applicant must propose in its special advantages to have a Thai legal person (established under the laws of Thailand with Thai nationals holding more than 50% in it), with the approval of the Petroleum Committee, to acquire an undivided participating interest of not less than 5% under the concession. Such juristic person shall reimburse the applicant the expenditures incurred from the block prior to the date of its participation according to its participating interest share and bear its participating interest share of all the expenditure incurred in the block from the date of its participation.


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The authors are grateful to Michael Keen for comments on an earlier draft and to Nate Vernon for assistance with checking of calculations.

This chapter addresses the mechanics of joint development zones; nothing in the chapter should be taken to imply any view on the part of IMF staff or the present authors concerning the positions of any states that are partners to a JDZ on ultimate delimitation of maritime boundaries.

Crawford (2012) pp. 255–280 succinctly explains the rights of states in their territorial sea and other maritime zones.

For further explanation of the legal principles, with examples, see Cameron in this volume, Hestermeyer et al. (2012), Nordquist and Moore (2012), Becker-Weinberg (2014).

Pawlak (2012) p. 242 comments that “the newest maritime treaties concentrate more on economic cooperation than on the dispute-solving procedure.”

The authors know only of one joint development scheme on land: that is the Saudi Arabia–Kuwait “neutral zone”, which includes both jointly managed on-shore and offshore areas.

The case of Timor-Leste and Australia, discussed in what follows, is exceptional in that unitisation took place across the perimeter of a JDZ rather than an agreed maritime boundary.

At early 2016, imposition of withholding taxes on charges for a pipeline that takes gas out of the JDZ was the subject of an unresolved dispute between Timor-Leste and petroleum contractors in the Bayu-Undan gas project.

The capital gains issue on assets had specifically to be addressed in unitisation schemes for fields straddling the UK–Norway boundary in the North Sea, where no JDZ was involved.

Some fiscal implications of this provision were the subject of arbitration proceedings involving private contractors and one of the governments, still not determined by the end of 2015.

Many treaties use the term “joint development area” or similar, whereas the usual generic term is “joint development zone”; this chapter uses each where relevant.

Balance of 65 out of 100 of after-tax profits multiplied by 23.08% equals 20% remittance tax on the original 100.

Given the materiality of SRB, the assumption of meters drilled for the project example is critical. Very deep wells significantly reduce the SRB payment.

As stipulated in the Petroleum Decree No. 51 of 1969, as amended, Petroleum (Drilling and Production) Regulations of 1969, as amended, and Petroleum Profits Tax Act of 2004, as amended by subsequent Finance Decrees.

Earlier PSCs used cumulative production as the scale for determining profit shares.

The contractor, however, takes 100% of profit oil when IRR < 16%, so the cost recovery limit would have little impact early in the life of the field

Batista, Unitization, and JDZ.

Using the Fiscal Analysis of Resource Industries (FARI) modeling system and database developed in the Fiscal Affairs Department of the IMF. For a detailed exposition of the FARI modeling framework and evaluation criteria for fiscal regimes, see Daniel, P. and others (2010). Luca and Mesa Puyo (2016) Excel based, FARI enables detailed design, modeling, and comparison of fiscal regimes across the entire life cycle of petroleum or mining projects. It is now widely employed by staff in country and TA work and is increasingly used as a forecasting tool linked to the macro-economic framework for resource-rich countries.

The average effective tax rate (AETR) only becomes a meaningful in cases above marginal levels of profitability, since a case yielding zero NPV at the chosen discount rate has no surplus to divide.

We note that the outcome in the national Nigeria and STP case could be weighted 60/40 to reflect the attribution percentages in the JDZ.

For discussion of the relationship between JDZs and unitisation, see Cameron in this volume and Duval et al. (2009); for the case of Timor-Leste and Australia the literature is substantial; see, for example, Khamsi (2005) or Pereira Coutinho and Briosa e Gala (2015).

The Timor Gap Treaty also created zone B to the north and zone C to the south; in ZOCB the split was 90/10 in favor of Indonesia, in ZOCC 90/10 in favor of Australia. No petroleum activities took place in areas B or C, and they did not feature in the Timor Sea Treaty.

Procedures for technical redetermination of the reserve attributions were incorporated in the IUA for Greater Sunrise.

CMATS became the subject of a legal challenge by Timor-Leste at the International Court of Justice contested by Australia and unresolved by early 2016.

The Petroleum Mining Code for the JPDA, taken together with provisions of the TST, is equivalent to a petroleum law concerning the grant of rights and regulation of activities in a single jurisdiction.

Annex G in Schedule 1 of the TST (under Article 13(b)) is the Taxation Code for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion in respect of Activities Connected with the JPDA.

It also applies to PSC 06–105, in which previous exploration identified the small Jahal and Kuda Tasi oil discoveries. Exploration expenditure and investment credits under a previous PSC were brought forward as an opening balance under the new PSC but excluded from further uplift under the new scheme.

The new PMC is not applied to Bayu-Undan and Sunrise either. These PSCs are subject to the Interim PMC (adapted from the PMC under the Timor Gap Treaty), since their PSCs were made under that version of the PMC.

The TST ascribes rights to the DA on behalf of the two governments; the Timor-Leste Petroleum Authority (ANP) now exercises the powers of the DA. We refer to the DA when describing powers under the TST and associated PSCs.

The PSCs in Timor-Leste’s exclusive jurisdiction allow the government, on the announcement of a commercial discovery, to elect state participation up to 20% through a state-owned contractor. The government pays no compensation for past costs but would pay its proportionate share of future costs.

The Bayu-Undan additional profits tax and the general SPT are identical in design and rates. The net rate of 22.5% is achieved by charging a grossed-up rate of 22.5/(1−t), where t is the corporate income tax rate (30%), and allowing the resulting grossed-up rate of 32.143 percent as a deduction for income tax.

Condensate is defined as crude oil in the PSC applying to Bayu-Undan.

The percentage ownership interests in the Sunrise JV were Woodside 33, ConocoPhillips 30, Shell 27, and Osaka Gas 10.

The reverse of the extra-territorial jurisdiction secured by Norway over pipelines from its continental shelf exporting gas to other European countries.

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