Read Aloud the Text Content

This audio was created by Woord's Text to Speech service by content creators from all around the world.

Text Content or SSML code:

buyers will commit to ‘take or pay’, which forces the buyer to pay for the base volumes even in periods of low demand. The pricing formula will also normally include provisions for fluctuations in the final market prices, substitute fuels (such as fuel oil and coal), currency exchange rates and other inflation measures. In many LNG contracts, price ‘floors’ and ‘ceilings’ are also agreed. Prevailing market conditions and resulting bargaining power, will heavily influence the final terms agreed in any gas sales agreement. The government may own one or more links of the chain and dictate the level of economic rent to be captured by those links. For example, Algeria and Oman insist that most of the gas produced in the country, associated1 with oil, is taken by the government which reimburses only the producers’ costs. By contrast, the Indonesian government owns several LNG plants, which it operates on a tolling basis, recovering its own costs but enabling the remainder of the LNG price received to be passed to producers. 3 Natural gas taxation A Upstream vs midstream taxation The fiscal regimes for upstream and midstream operations are very different in most producing countries. Upstream production tends to be subject to more complex fiscal terms and can include bonuses, royalty, production sharing and windfall profits taxes, as well as corporate/petroleum income tax. Midstream operations, on the other hand, tend to be treated as general industrial projects and are subject only to standard corporate income tax. Major projects, such as greenfield LNG plants, may even receive fiscal incentives such as temporary tax holidays. The Malaysian LNG (MLNG) project highlights the differences between midstream and upstream taxation policies and the implications for other government policies, such as gas pricing and equity participation. Figure 6.6 illustrates the significant difference in the government take1 from Malaysian upstream and midstream operations, where the total fiscal take is 83 per cent of upstream profits but only 28 per cent of midstream profits. Petronas, the Malaysian national oil company (NOC), has a 50:50 joint venture with Shell in the upstream MLNG PSC. Petronas is also the purchaser of the gas at the plant gate, where it then sells the gas on to the LNG plant owners (at the same price as it pays for the gas). The price at the plant gate is usually referred to as the ‘gas transfer price’. Petronas owns 90 per cent of the plant, which sells LNG to markets in North Asia. The relationship between fiscal and gas pricing policies is critical. Figure 6.7 illustrates the difference between the total government take and investor profits from the project, under three different transfer pricing policies: • Transfer price is established at the maximum price the midstream can pay (i.e. the plant’s breakeven price). • Transfer price is established at the minimum price the upstream can receive (i.e. the producer’s breakeven price). • Transfer price is established at the midpoint between upstream and midstream breakeven prices. Figure 6.7 shows the distribution of the project’s total profit, i.e. LNG price less the upstream and midstream costs. The ‘midstream breakeven’ policy (which is comparable to the Indonesian policy of only reimbursing the LNG plant’s costs) ensures that the upstream transfer/netback price is as high as possible. Figure 6.7 shows that, under these assumptions, this policy generates the highest level of overall government take because of the higher fiscal take from upstream operations. The ‘upstream breakeven’ policy, which results in all of the economic rent residing in the midstream operation, is far less common. It is comparable to the Transfer price Percentage of profit 100 90 80 70 60 50 40 30 20 10 0 M/S breakeven U/S breakeven Shared M/S profit U/S profit M/S Govt take U/S Govt take Figure 6.7 Total government take under different transfer pricing policies (source: Wood Mackenzie). Natural gas 171 situation where upstream producers are deemed to have no rights to gas associated with oil production and deliver the gas to the government or midstream plant, with only costs reimbursed (e.g. Oman LNG) or recovered from oil revenues (e.g. Angola LNG). As a result of the lower tax rates applicable to the midstream operation, this generates the lowest overall government take of the different options. The third alternative is that the difference between the two breakeven prices is shared between the upstream and midstream operations, either as a result of negotiation between the two parties or by government regulation. This results in a government take from the total project somewhere between the two extremes. An example of this system is Australia’s residual price mechanism (RPM), which is established for integrated LNG projects. (See Figure 6.8.) Australia levies a Petroleum Resource Rent Tax (PRRT) on upstream profits, but not on midstream operations. If there is no arm’s-length agreement between the two operations, or a comparable local benchmark or price formula agreed in advance with government, then a proxy gas transfer price (GTP) needs to be established for purposes of calculating the PRRT payable by the upstream operation. Under the RPM, two prices are established: • Cost-plus price. • Netback price. The RPM involves taking the average of the gap (or economic rent) between the cost-plus and netback prices for that operation. The cost-plus price represents the lowest price the upstream phase of a gas to liquids operation would sell its sales gas for; that is, the lowest price at which that operation would fully recover its costs of producing the sales gas. A gas transfer price below the cost-plus price means that it would be uneconomic to produce sales gas. The netback price represents the highest price the midstream phase of a gas to liquids operation would pay for sales gas; that is, the highest price the operation