Energy Politics Summer 2005

Issue VI: Summer 2005 2

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Energy Politics

Issue VI: Summer 2005

Table of Contents

Can Another Oil Price Crash Be Avoided by Peter Odell 3 Using Tax Incentives to Compete for Foreign Investment: Do They Work? by Orighoye Rewane 7 Why Does OPEC Continue to Price Its Oil in Dollars? by A. F. Alhajji, Ph.D. 36 Pipeline Gas Introduction to the Korean Penninsula by Keun-Wook Paik, Ph.D. 41 Letter to the Editor: Angra III Brazils Third Nuclear Power Plant by Edmilson Moutinho dos Santos and Rafael Judar Vicchini 96 Country Assessment: India by Colin Campbell 102 Commentary: “Bank on It”:Economic Theory and Some Oil Markte Realities by Ferdinand E. Banks 104


Editorial Board Jennifer I. Considine, Canada Thomas Dawson, Canada Keun‐Wook Paik, United Kingdom Joy Dunkerley, United States of America Bob Ebel, United States of America Eugene Khartukov, Moscow Tony Reinsch, Canada Angela Tu Weissenberger, Canada Stephen O’Sullivan, Russia Alex Kemp, Scotland G. C. Watkins, Canada Alpheus Jessup, United States of America Gavin Longmuir, United Kingdom Mamdouh G. Salameh, United Kingdom Michael Lynch, United States of America Colin Campbell, Ireland William Kerr, Canada Jean Laherrere, France Roland George, Canada John Roberts, United Kingdom Richard Marshall, Canada Thomas Walde, United Kingdom Garth Renne, Canada May Yeung, Canada Peter Adams, United States of America Barbara Baker, Canada Len Coad, Canada Edmilson Moutinho dos Santos, Brazil Alli Marshall, Ca nada

Letter from the Editor

Can another Oil price Crash be Avoided?

Peter R. ODELL By pure chance the traumatic events in the international oil market over the past 12 months have coincided with research I was asked to undertake on the circumstances surrounding the 2nd oil price shock in 1979/80. The similarities between the two upheavals are disconcertingly similar: not only in terms of the more than doubling in the price of internationally traded crude, but also in the misrepresentation and misinterpretation of events. The latter can best be summed up as ‘panic’ amongst policy makers and experts who should have known better and, as an inevitable result, the imposition of self-inflicted wounds on the global economy in general, and on the OECD nations, in particular.


A “crisis” has thus been created – even though both OPEC’s and the IEA’s monthly statistics on oil supply and demand have revealed no evidence of a pending scarcity. Contrary to the reality of an oil surplus, western-world leaders castigated OPEC countries for under-production instead of recognising their 10% increase in 2004; while not even politely requesting the multi-national oil corporations to enhance their production and their investments in oil supply facilities in the rest of the world. OECD’s

The initial cause of the 1979/80 shock was the revolution in Iran and consequential fears for supply availability in the main oil importing countries. As the Iran revolution temporarily inhibited production (though in large part compensated by increased supplies from other OPEC countries and from the newly discovered North Sea oil province), scarcity fears were rampant amongst the analysts. These encouraged stockpiling by consumers – ranging from refineries, power plants and industrial users to the man-in-the-street motorist. Thus, 3 million b/d were added to oil consumption – and to the competitive upwards-bidding of prices by both real buyers of oil and by speculators in the spot markets. The initial cause of the present oil price shock, though superficially different from 25 years ago, is little different in principle. First, specious propaganda emanating from the so-called “peak oilers” and other Jeremiahs on prospective near-future oil scarcity has grabbed the headlines in the media: in which the presentation of potential supply problems are coupled with misinterpretations of demand growth, most notably in China. A “crisis” has thus been created – even though both OPEC’s and the IEA’s monthly statistics on oil supply and demand have revealed no evidence of a pending scarcity. Their recently published overall figures for 2004 now show that oil supply in 2004 comfortably exceeded demand – even when the latter incorporates the consequence of excessive stockpiling, to give a 6-year high in the volume of oil stocks. In 2004 global oil production at 83.2 million b/d was up by 3.34 million b/d over 2003. Demand, meanwhile, rose by only 2.7 million b/d to 82.5 million b/d – with about 25% of the increase accounted for by stock-building. Contrary to the reality of an oil surplus, western-world leaders castigated OPEC countries for under-production instead of recognising their 10% increase in 2004; while not even politely requesting the multi-national oil corporations to enhance their production and their investments in oil supply facilities in the rest of the world. OECD’s oil production – only one-third less than that of OPEC – was allowed to stagnate.


A curb – or even the temporary suspension of these nefarious speculative activities – would have eliminated not only the intense volatility of the markets, but would also have engendered price developments which reflected the innate stability of the market in real oil supply/demand relationships. In today’s “crisis”, the high oil price of about $50 per barrel hardly matches up to the 1980 level of over $80 (measured in 2005 dollar terms). Nevertheless, the current price is at a record-breaking high (except for 1979/80) since the 1870s.

Even more important from the broader economic standpoint, western governments – excluding that of Germany – have made no efforts to control the 2004/5 version of the spot-market speculators of 1979/80. Yet this most recent enterprise of the oil speculator’s virus is much more virulent and globally-wide in its activities; through the myriad of dealings in “paper” barrels (rather than in real oil) on the uncontrolled oil exchanges of New York, London and Singapore. A curb – or even the temporary suspension of these nefarious speculative activities – would have eliminated not only the intense volatility of the markets, but would also have engendered price developments which reflected the innate stability of the market in real oil supply/demand relationships. In the aftermath of the 1979/80 oil shock, the instability produced half-a-decade of severe problems for the oil producing and oil exporting countries. The consequential fall in the price of oil for six consecutive years ended up in 1986, with the price of oil (in real terms) down by about 65%: and demand by over 20%. The impact on the global economy was highly negative – with economic recession and accompanying social and political problems. In today’s “crisis”, the high oil price of about $50 per barrel hardly matches up to the 1980 level of over $80 (measured in 2005 dollar terms). Nevertheless, the current price is at a record-breaking high (except for 1979/80) since the 1870s. It is not, moreover, a sustainable price in what will inevitably become a more competitive market, as oil’s contribution to total energy supply continues to fall. As the long-run supply price does not exceed $25 per barrel, then, given the additional factor of relatively cheap money available for investment in the oil sector, today’s market price seems as unlikely as that of 1980 to remain so high. Competition from coal and gas – as well as the still improving efficiency in the use of oil (especially in aviation and for motor vehicles) will bring strong downward pressure to bear on present prices.


The failures of policy makers in the first five years of the 21st century to treat oil as anything other than just another commodity have quickly come home to roost. Let us hope that they quickly come to their senses…

The failures of policy makers in the first five years of the 21st century to treat oil as anything other than just another commodity have quickly come home to roost. Let us hope that they quickly come to their senses and then positively try to re-establish “order” in the market; first by curbing or even eliminating the interference of the speculators; and then, by securing the success of a meaningful dialogue with OPEC, plus Russia and China, so create conditions whereby long-term stability for both producers and consumers of oil can be achieved. If so, then a second mid-80’s style crash could be avoided. If not, then prepare for fireworks and the onset of economic doom and gloom. About the Author: Peter Odell is Professor Emeritus of International Energy Studies at Erasmus University Rotterdam. He recently published a two-volume study, 'Oil and Gas:Crises and Controversies,1961-2000' (Multi-Science Publishing Company, Brentwood, UK.


Put simply, although these governments own most of the world’s petroleum resources, they have neither the capacity to carry out such technical tasks as drilling wells and laying pipelines nor the financial stability or security necessary for such projects.

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Using Tax Incentives to Compete for Foreign Investment: Do They Work?

Orighoye Rewane

1 INTRODUCTION

In most of the countries that possess petroleum resources, these deposits are regarded as the crown jewels.1 This view is no more emphasised anywhere else than it is in developing countries, where the exploitation of these deposits is an important (and for some essential) source of revenue, representing a means for them to emulate the economic success of their industrialised counterparts.2 However, petroleum exploration and development projects are major long-term capital investments - requiring heavy front-end capital expenditure, detailed expertise, advanced technology and marketing outlets – characterised by long lead times and high risks of failure. Put simply, although these governments own most of the world’s petroleum resources,3 they have neither the capacity to carry out such technical tasks as drilling wells and laying pipelines4 nor the financial stability or security necessary for such projects.

1 Johnston D., International Petroleum Fiscal Systems and Production Sharing Contracts 1 (1994). 2 Cameron P., Lecture Notes on Petroleum Agreements, CEPMLP (October 2003). 3 Cameron P., Petroleum Licensing: a Comparative Study (1984). 4 Jok J., The Concession and the Licence as Oil Production Titles, 3 (Unpublished Dip. Pet. Law dissertation submitted to CEPMLP, University of Dundee, 1982).


The recognition of this need for foreign direct investment (FDI), coupled with the gradual elimination of barriers to foreign investment (FI) in other States with similar attractive features, has led to most host governments (HGs), over the past two decades, actively competing amongst themselves to promote their countries as investment locations.

Consequently, many governments are compelled to turn to international oil companies5 who hold most of the financial and technical wherewithal needed for the exploration and exploitation of petroleum resources.6 The recognition of this need for foreign direct investment (FDI), coupled with the gradual elimination of barriers to foreign investment (FI) in other States with similar attractive features, has led to most host governments (HGs), over the past two decades, actively competing amongst themselves to promote their countries as investment locations.7 They are increasingly striving to create a favourable and enabling climate to attract FDI as a policy priority by adopting such measures as liberalising the laws and regulations for the admission and establishment of FI projects; providing guarantees for repatriation of investment and profits; and establishing mechanisms for the settlement of investment disputes.8 Tax incentives (TIs), the subject of this paper, are also part of these promotional efforts.

The efficacy of these incentives as a determinant for attracting FDI is often debated, with some schools of thought arguing that the offering of tax incentives to foreign investors will (a) increase the aggregate amount of FI available to developing countries; and (b) affect the spatial distribution of investment9, even if the first argument does not fully stand up.10

5 These companies will be referred to as international oil companies (IOCs) or multinational oil companies (MNOCs) in an interchangeable manner throughout this paper. 6 Anenih O., The UK Petroleum Production Licence – Is it a Contract or Regulation and Does it Matter? 1 (2003). 7 UNCTAD, Tax Incentives and Foreign Direct Investment: A Global Survey, 11 (2000). 8 See id., 11. 9 That is to say that if governments of locales that are alternative locations for foreign investors offer incentives, then the govt eager to ensure that it gets the investment must match those incentives or face the prospect of losing investment to the competing countries. 10 Wells L.T. & Allen N.J., Tax Holidays to Attract Foreign Direct Investment: Lessons From Two Experiments, viii (2001).


In the case of foreign investors in developing nations, this transfer is primarily from a poor country to a richer one.

There has been a great deal of evidence, especially after the changes in the United States’ (US) tax laws during the late 1980s, that home country tax policy affects both the MNOC’s behaviour and the effectiveness of tax policy in the countries where these firms operate and invest.

However, other schools argue that TIs have little, if any effect on the total FI that is made world-wide, and thus in the aggregate, incentives create a net transfer from taxpayers to investors.11 In the case of foreign investors in developing nations, this transfer is primarily from a poor country to a richer one.

Despite the foregoing, developing countries have increasingly resorted to such measures in recent years,12 especially those that consider themselves to be alternative locations for FDI, as they are in close geographical proximity to other countries with similar attractive features, as it is thought that the importance of TIs may be more pronounced in these situations.13 In addition to this, there has been the emergence of a new issue, i.e. the recognition that the tax policies of the home and host countries are interconnected, breeding the view that this link influences the behaviour of MNOCs. There has been a great deal of evidence, especially after the changes in the United States’ (US) tax laws during the late 1980s, that home country tax policy affects both the MNOC’s behaviour and the effectiveness of tax policy in the countries where these firms operate and invest.14

These issues, which have added a considerable amount of fuel to the original debate generated about the efficacy of these TIs and whether governments have offered unreasonably large incentives to entice those firms to invest in their area, form the scope of this paper, which aims to establish whether using tax incentives to compete for FDI in oil and gas (O&G) projects actually work. The paper proceeds as follows. Chapter two is a brief, analytical excursion into the configuration of tax incentives, including their objectives and categories.

11 See id., viii. 12 Morisset J. & Pirnia N., How Tax Policy and Incentives Affect Foreign Direct Investment: A Review, 4 (2001). 13 This has a lot to do with investment experts, particularly from investment promotion agencies, viewing incentives as an important policy variable in their strategies to attract FDI for economic development – see UNCTAD, supra note 7, at 11. 14 See Morisset & Pirnia, supra note 12, at 4.


Chapter three explores the merits of the current debate on the efficacy of TIs in the context of Indonesia, as this country, having sporadically offered TIs to foreign investors over the past twenty-five years, offers a “natural experiment” for testing which of the arguments stand up andwhich do not.

This paper concludes that TIs attract some investors some of the time, as although chapters three and four have evinced that TIs are poor FDI-determinants for O&G projects in developing countries, it cannot be said that that they have absolutely no effect on FDI.

Chapter three explores the merits of the current debate on the efficacy of TIs in the context of Indonesia, as this country, having sporadically offered TIs to foreign investors over the past twenty-five years, offers a “natural experiment” for testing which of the arguments stand up andwhich do not. In addition to this, graphs showing the number and value of projects approved each year before and after the elimination of incentives will be analysed to compare growth rates and FDI inflows, as will tables showing the average shares of total FI in 5 Association of South East Asian Countries (ASEAN), including Indonesia, during these periods, in order to gauge whether the ending of incentives caused investors to shift their investments to neighbouring countries where HGs continued to offer incentives. A grouping and tabulation of investors is also done in order to examine the influence of home country tax policy on investment flows, with all the results mostly supporting the arguments made against incentives.

Next, chapter four presents the outcome of three sets of empirical research that are generally consistent with the findings of the research in Indonesia, notably that TIs neither affect significantly the amount of FDI that takes place nor usually determine the location to which investment is drawn.

This paper concludes that TIs attract some investors some of the time, as although chapters three and four have evinced that TIs are poor FDI-determinants for O&G projects in developing countries, it cannot be said that that they have absolutely no effect on FDI. It is, however, further suggested that instead of competing amongst themselves and blindly offering TIs, which this paper has shown to have minimal effect on FDI, to any MNOC that will have them, countries may want to harmonise their tax policies under regional or global agreements or consider whether some other sort of regional or global collective action might be in their better interests.


TIs, the subject of this paper, can be defined as any incentives that reduce the tax burden of an enterprise in order to induce them to invest in particular projects or sectors .

However, to be considered an investment incentive, a TI must not be available to all investors but, rather, must be tailored to specific investors or types of investors

2 TAX INCENTIVES This chapter makes a brief, analytical excursion into the definition, objectives and classification of the major tax incentives used in the international petroleum industry, with Table I on page 7 containing a description of these TIs, as well as definitions of all the technical terms used in this chapter.

2.1 What is a Tax Incentive? TIs, the subject of this paper, can be defined as any incentives that reduce the tax burden of an enterprise in order to induce them to invest in particular projects or sectors.15 Put simply, they are exceptions to the general tax regime. Specific to the international petroleum industry, they are those fiscal elements emplaced by HGs that make petroleum exploration and production (E&P) more economically attractive,16 and would include, for example, mechanisms such as tax or royalty holidays or tax abatement, etc.17 However, to be considered an investment incentive, a TI must not be available to all investors but, rather, must be tailored to specific investors or types of investors,18 this would explain why in developing countries, where TIs are especially common, they are aimed at FD investors and not available to domestic investors.19

15 See UNCTAD, supra note 7, at 12. 16 See Johnston, supra note 1, at 304. 17 There are also other mechanisms that HGs can use to try to influence investor behaviour, like lower government take, reduced government participation or widening of the ring fence. However, these mechanisms are more contractual in nature, and therefore, have not been included here. 18Thus, for example, accelerated depreciation offered to all investors would not be an investment incentive in the sense used here, even if accelerated depreciation might benefit certain specific investors – those operating in highly capital-intensive sectors – more than others. 19 The granting of incentives to desirable investors and not to others raises the issue of discriminatory treatment. Although such discrimination is opposed by the US on the ground that it distorts international trade, this is nothing more than an economic reason, for as long as the discrimination is not on racial grounds, there is nothing in international law against discrimination between foreign investors if the discrimination is based entirely on economic factors - Sornarajah M., The International Law on Foreign Investment, 99 (1994).


Because TIs are intended to encourage investment not just in E&P, but also in certain geographical areas, they are rarely provided without conditions attached. Very often countries design special incentive regimes that detail the tax benefits as well as the key restrictions.

Because TIs are intended to encourage investment not just in E&P, but also in certain geographical areas, they are rarely provided without conditions attached. Very often countries design special incentive regimes that detail the tax benefits as well as the key restrictions. For instance, these regimes may require that a project be established in a certain region(s), have a certain turnover, require the transfer of technology from abroad or employ a certain number of individuals.20 2.2 Objectives of Tax Incentives Apart from attracting desirable investment, TIs also have a number of other objectives, namely:

(a) Regional Investment: Countries with untested or/and unproven regions, wanting to attract E&P investment to these areas, often employ a mix of incentives to channel investment to these areas.21 (b) Performance Enhancement: TIs are a useful way of ensuring that the foreign investor enhances the performance of the industry in a manner desired by the HG, whereas a direct requirement may give the impression of hostility to foreign investors.22 (c) Transfer of technology: An important objective of using TIs to attract investment to oil and gas projects in developing countries is the transfer of technology. Certain types of tax incentives are designed specifically for this purpose.

20 For instance, China offers foreign-invested firms a tax refund of 40% on profits that are re-invested to increase the capital of the project or launch another firm. The profits must be re-invested for at least five years. If the re-invested amounts are withdrawn with five years, the firm has to pay the taxes. India, similarly, offers a tax exemption on profits of firms engaged in tourism or travel, provided their earnings are received in convertible foreign currency – see UNCTAD, supra note 7, at 12. 21 For example, Nigeria has a regional incentives scheme that gives allowances ranging from 5 to 100% to MNOCs that establish operations in areas where little or no exploration work has been carried out – see id. 22 In a non-petroleum example, Ghana taxes companies engaged in the export of non-traditional products at a reduced rate of 8% instead of the standard 35% - see id.


Some countries, such as Malaysia and Singapore, have introduced a specific set of incentives directed towards research and development (R&D) activities including tax-exempt technology funds and tax credits for expenditures on R&D

(d) Some countries, such as Malaysia and Singapore, have introduced a specific set of incentives directed towards research and development (R&D) activities including tax-exempt technology funds and tax credits for expenditures on R&D.23 For import of technology, tax incentives provided may take the form of allowing transfer costs of patent rights and import fees, etc to come under operating costs, thereby permitting them to be expensed.24 2.3 Classification of Tax Incentives Most of this paper focuses on the corporate income tax (CIT) and the different options used by HGs to relieve MNOCs. It is, however, worth underscoring at this point that unlike the actual tax instruments, e.g. royalties and income tax – which are fairly limited and more or less the same in most countries - the range of TIs available to HGs are quite vast. Andrews-Speed P., Lecture Notes on Mineral and Petroleum Taxation, 3.3 (2004). 1 This premium consists of an option where the investor purchases the right to maintain its corporate tax rate at a given level, even if the tax regime is modified in the future – see Morisset & Pirnia, supra note 12, at 13. 1 For example, a reduced CIT rate is a good incentive as it allows, inter alia, investors to keep a larger portion of profits, however, international linkages can undermine a country’s efforts to make its tax system relatively neutral. Similarly reduced taxes on dividends and interests paid abroad are also good TIs. But on the other hand, the lower the dividend tax, the lower the penalty for remitting dividends, and the lower the incentive to reinvest profits – see UNCTAD, supra note 7, at 21 1 For instance, the UNCTAD survey found that - in terms of the types of TIs granted - although there was clearly an increasing trend towards offering full or partial tax holidays or tax rate reduction for specific types of activities, with nearly 85% of the countries surveyed offering such incentives, another trend was the increasingprevalence of duty draw-backs, import duty exemptions and deductions for social security contributions - see id.

Andrews-Speed P., Lecture Notes on Mineral and Petroleum Taxation, 3.3 (2004). 1 This premium consists of an option where the investor purchases the right to maintain its corporate tax rate at a given level, even if the tax regime is modified in the future – see Morisset & Pirnia, supra note 12, at 13. Andrews-Speed P., Lecture Notes on Mineral and Petroleum Taxation, 3.3 (2004).


Therefore, it is worth noting that despite the classification given here, the variety of incentives that can be offered can be as far-reaching in range, from the “stability premium” that has been offered to investors by countries such as Chile and Colombia, relief from import duties or value-added taxes to flow-through shares, and there is no clear-cut answer in favour of one or the another mechanism, as each has its own inherent advantages and disadvantages , and ultimately the type of TI offered will depend on the HGs objectives.

This is because in order to make a fiscal regime more competitive, a HG has a number of options available to adapt a relatively standard set of taxes to suit its needs.25 Therefore, it is worth noting that despite the classification given here, the variety of incentives that can be offered can be as far-reaching in range, from the “stability premium” that has been offered to investors by countries such as Chile and Colombia,26 relief from import duties or value-added taxes to flow-through shares, and there is no clear-cut answer in favour of one or the another mechanism, as each has its own inherent advantages and disadvantages27, and ultimately the type of TI offered will depend on the HGs objectives.28 Bearing this in mind, one can therefore attempt to broadly categorise the main types of TIs found in the O&G industry into 2 groups:

1. Tax deductions: These are those incentives that serve to give a direct reduction of the actual tax base29, i.e. final tax base = (original tax base) – (tax deduction). Most TIs take the form of such “deductions,” for example expensing of costs, capitalisation of costs through depreciation and amortisation, loss carry forward, enhancement of allowable costs through “uplifts”, reduction of the tax base via tax “abatement”.

Andrews-Speed P., Lecture Notes on Mineral and Petroleum Taxation, 3.3 (2004). 26 This premium consists of an option where the investor purchases the right to maintain its corporate tax rate at a given level, even if the tax regime is modified in the future – see Morisset & Pirnia, supra note 12, at 13. 27 For example, a reduced CIT rate is a good incentive as it allows, inter alia, investors to keep a larger portion of profits, however, international linkages can undermine a country’s efforts to make its tax system relatively neutral. Similarly reduced taxes on dividends and interests paid abroad are also good TIs. But on the other hand, the lower the dividend tax, the lower the penalty for remitting dividends, and the lower the incentive to reinvest profits – see UNCTAD, supra note 7, at 21 28 For instance, the UNCTAD survey found that - in terms of the types of TIs granted - although there was clearly an increasing trend towards offering full or partial tax holidays or tax rate reduction for specific types of activities, with nearly 85% of the countries surveyed offering such incentives, another trend was the increasingprevalence of duty draw-backs, import duty exemptions and deductions for social security contributions - see id. 29 The tax base is that portion of the revenue, assets or expenditure, or some other feature of the business which is targeted by the tax in question – see Andrews-Speed, supra note 25, at 2.5.


(2)Tax Reductions: An alternative method would be to provide a TI which would serve to reduce or temporarily eliminate the tax rate, i.e. the amount of tax payable - i.e. a direct deduction from the amount of tax payable, rather than from the tax base – perhaps through a reduced CIT rate, tax credits, tax holidays or tax abatement.

Table I – Description of Tax Incentives Used in O&G industry

Term/ Incentive

Definition

Accelerated Depreciation (J)

Writing off an asset through depreciation or amortisation at a rate that is faster than normal accounting straight-line depreciation. There are a number of methods of accelerated depreciation, but they are usually characterised by higher rates of depreciation in the early years than the latter years in the life of the asset. Accelerated Depreciation allows for lower tax rates in the early years.

Amortisation (J)

Amortisation is an accounting convention designed to emulate the cost or expense associated with the reduction in value of an intangible asset (See depreciation infra) over a period of time. Amortisation is a non-cash expense, and the techniques for amortisation of intangible costs are similar to those of depreciation, see infra.


Capitalising Costs (AS)

Capitalisation allows certain costs - the most important of which are those associated with exploration and development - to be recovered later than they were incurred, possibly many years later, when the project starts to earn revenue. In order to calculate the tax base, the methods of depreciation or amortisation are used to calculate how these costs will be deducted from the revenue, with amortisation applying to intangible costs such as feasibility studies and depreciation applying to the costs of intangible assets.

Depreciation (AS)

Depreciation is an accounting convention designed to emulate the cost or expense associated with reduction in value of an asset due to wear and tear, deterioration, or obsolescence over a period of time. Depreciation is a non-cash expense. There are several techniques for depreciation, including (a) Straight-line depreciation: whereby the cost is depreciated in equal instalments over a defined period of time. For a tangible asset this period may be equivalent to the nominal life of the asset, e.g. a $1m cost depreciated over five years would result in a tax deduction of $200,000 per year for five years; (b) declining balance: The percentage rate of depreciation is derived from the total depreciation period. E.g., a 4-year period would have a 25% rate of depreciation. Each year that proportion (25%) of the remaining value of the asset is depreciated for the defined number of years (4). The balance is depreciated in the subsequent year; (c) double declining balance: is the same as the declining balance except that the rate of depreciation for a fixed period of depreciation is double. So a 4-yr double declining balance involves depreciation of 50% of the remaining value of the asset, not just 25%; (d) sum-of-the-year’s digits: is an alternative approach to providing the investor with earlier tax deductions than the straight-line method. A fraction is defined by an inverted scale of all the year’s digits. The depreciation for a particular year is calculated by multiplying the relevant fraction by the original value of the asset; (e) unit-of-production: this approach relates to the amount of depreciation each year to the ratio of annual production to the remaining reserve of the deposit.


1 Hong Kong (China), Indonesia, Ireland, the Lao People’s Democratic Republic, Cambodia and Estonia are a few countries that use this type of incentive. 1 Hong Kong (China), Indonesia, Ireland, the Lao People’s Democratic Republic, Cambodia and Estonia are a few countries that use this type of incentive

Employment based deductions (UN)

In many countries, governmental-mandated social security contributions can be a burden to enterprises, especially new ones. To encourage investment in O&G projects, governments may reduce social security contributions or provide tax credits or allowances based on the number of employees hired. Incidentally, Bulgaria, on the other hand, offers TIs to further its social goal of providing employment to persons with disabilities.

Expensing Costs (AS)

This is where a fiscal regime allows for certain costs - usually operating costs, and sometimes royalty - to be expensed, i.e. deducted from the tax base in the year that they are incurred.

Flow-through share(s) (AS)

Provide a mechanism for individual shareholders in a company to benefit from the tax allowance(s) of the company. The value of specified tax allowances is passed through to the shareholders.

Investment credit (UN)

A fiscal incentive where the HG allows a MNOC to recover an additional percentage of tangible capital expenditure. Investment credits (ICs) may be flat or incremental. A flat TC is earned as a fixed percentage of investment expenditures incurred in a year on qualifying (targeted) capital. In contrast, an incremental IC is earned as a fixed % of qualifying investment expenditure in a year in excess of some base that is typically a moving average base (e.g. the average investment expenditure by the taxpayer over the three previous years).


Loss carry forward or backward (UN)

This is a mechanism whereby losses incurred in one year can be carried forward (or backward – especially for oil field abandonment after production has ceased) for a specified number of years (usually three to five years) for tax accounting purposes. Usually only a fixed ratio of the loss with an upper limit is allowed to be carried forward (or backward). This measure is particularly valued by oil investors whose projects record losses both before production starts (when there are costs but no revenues) and after the deposit comes on production (if costs are too high or the price too low). Taken together, a low tax rate accompanied by loss carry forwards for tax purposes and accelerated depreciation – which also allows investors to reduce their tax burdens in the years immediately following investment when cash flow is important to pay off debt - is considered to be a major element in an effective tax system and one that is highly attractive to foreign investors.

Preferential treatment of long-term capital gains (UN)

Many countries accord preferential tax treatment for appreciation in value of capital (assets) held by enterprises if the capital (or assets) is held over a fixed period of time (usually six months to a year). Long-term capital gains (capital gains (capital retained for longer than the minimum period) are usually taxed at half the rate of short-term capital gains (capital retained for less than the minimum period). Short-term capital gains are usually taxed as ordinary income. Preferential tax treatment of long-term capital gains is intended to encourage investors to retain funds for longer periods.

Reduced taxes on dividends and interest paid abroad (UN)

These taxes, typically about 10%, may be reduced in order to attract FDI – the lower the dividend tax, the greater the TI. However, it is noteworthy that the lower the dividend tax, the lower the penalty for remitting dividends, and the lower the incentive to reinvest profits.


.

Reduced CIT Rate (UN)

HGs may set a lower CIT rate as an exception to the general tax regime in order to attract FDI into specific sectors or regions.30 It may be targeted at the income of foreign investors who meet specified criteria, or it may be applied for additional FDI, as was the case in Malaysia the mid-1980s when investment inflows were below expectations.

Reinvestment Credit (AS)

Operate in the same way as investment credits, discussed above, but are targeted at the companies’ re-investment in a country where they already have revenue.

Royalty Holiday (J)

This mechanism is similar to the tax holiday. It is a specified period of time in years or months, during which royalties are not payable to the government. After the holiday period, the standard royalty rates apply.

Tax Abatement (AS)

Is a mechanism for giving preferential treatment to a particular sector of the economy without changing the general income tax. It can act by either (a) reducing the tax base by a specified percentage or (b) the tax rate by a specified percentage. Tax abatement may be available for the whole life of the project or for a specified period only. Abatement may also be used by one level of govt in order to allow for a significant amount of tax to be taken by another level of government.

Tax Credit (AS)

A tax credit (TC) is an allowance, which is deducted from the amount of tax payable. In the petroleum industry, tax credits, if available are generally applied to either investments or re-investments.

Tax Holiday (UN)

A specified time period (usually 5-10 years) in the early stages of a project, when its exempt from paying a defined tax (usually CIT) or set of taxes. At the same time, tax holidays deny firms certain tax deductions over the holiday period or indefinitely (e.g. depreciation costs and interest expense), tending to offset at least in part any stimulative effect.


Sources: AS – Adapted from Andrews-Speed P., Lecture Notes on Mineral &

Petroleum Taxation (2004). J – Adapted from Johnston D., International Petroleum and Fiscal

Systems and Production Sharing Contracts (1994). UN – Culled from UNCTAD, Tax Incentives and Foreign

Investment: A Global Survey (2000).

Uplift (J)

Common terminology for a TI whereby the HG allows the contractor to recover some additional percentage of tangible capital expenditure. For example, if a contractor spent $10m on eligible expenditures and the HG allowed a 20% uplift then the contractor would be able to recover $12m. The uplift is similar to an investment credit. However, the term often implies that all costs are eligible where the investment credit applies to certain eligible costs. The term is also used at times to refer to the built-in rate of return element in a rate of return contract.


From 1967 - following the end of President Sukarno’s regime, which had kept Indonesia closed to FI in the first half of the 1960s - to the early 1980s, Indonesia, offered foreign investors tax holidays (THs) - that were similar to those granted by many other countries at the same time… The enacting law, Law I of 1967, was introduced exempting foreign investors from corporate income tax for a period of up to five years and from dividend withholding taxes on those profits even if they were remitted later .

2. THE INDONESIAN EXPERIENCE This chapter explores the issue of the impact of TIs on FI in the context of Indonesia, as the Indonesian government has offered TIs to foreign investors during some periods of recent history, but not during others. Thus, the country offers a “natural experiment” for testing which of the arguments, noted earlier, stand up and which do not.

3.1 The Natural Experiment From 1967 - following the end of President Sukarno’s regime, which had kept Indonesia closed to FI in the first half of the 1960s - to the early 1980s, Indonesia, offered foreign investors tax holidays (THs) - that were similar to those granted by many other countries at the same time, and today, as it was claimed that THs were important in light of the country’s high corporate income taxes (60%, under the 1925 Company Tax Ordinance) and dividend withholding taxes.31

The enacting law, Law I of 1967, was introduced exempting foreign investors from corporate income tax for a period of up to five years and from dividend withholding taxes on those profits even if they were remitted later. Once the basic tax holiday expired, the applicable tax rate for foreign firms could be reduced up to 50% for an additional five years.32 This law was later amended in 1970,33 enabling a project to receive tax exemptions – from corporate income tax and from withholding taxes on dividends34 - for up to six years. 31 The legislation added other incentives, such as guarantees against expropriation, guarantees on remittances abroad, exemptions from duties on capital equipment, and exemptions from duties on capital equipment for two years – Mohammad S., Recollections of My Career, 35 (1995). 32 World Bank, Managing Capital Flows in East Asia (1996). 33 Law II of 1970 concerning Amendment and Supplement to Law I of 1967 Concerning Foreign Investment. 34 It has been suggested that the exemption from dividend withholding tax applied only if the investor’s home country did not tax the income. This is unsubstantiated, as the basic laws show no evidence of a distinction by source of investment, however, practice may have done so.


The change, presenting a lower CIT rate of 35%, but leaving intact the other incentives (tariff exemptions, guarantees, and so on), set in motion the natural experiment, the results of which support the broad conclusions of this paper.

The clock on holidays started running when commercial production commenced (a date to be certified by the director general of taxation, in the ministry of finance).35 With only small adjustments, the system remained the same until 1984.In a dramatic turnaround in 1984, Indonesia became one of the very few developing countries to eliminate tax holidays,36 commencing with those investors approved after 1983. The change, presenting a lower CIT rate of 35%, but leaving intact the other incentives (tariff exemptions, guarantees, and so on),37 set in motion the natural experiment, the results of which support the broad conclusions of this paper: TIs are not the most influential factor for multinationals in selecting investment locations for O&G projects. 3.2 The Results from the Experiment 3.2.1 Impact on Foreign Investment

Figure 1, above, shows the number and value of projects approved each year from 1978 to 1993. As can be seen, although the first data available after tax holidays were dropped show that foreign investment approvals declined from those of the previous year, they also show that FI flows recovered soon afterwards.

35 See World Bank, supra note 32. 36 Due largely to the following three reasons. Firstly, their need to attract role model firms had disappeared as several name investors had established themselves in Indonesia. Secondly, the CIT rate in Indonesia had fallen to 45% and treaties for the avoidance of double taxation had lowered dividend withholding taxes for many foreign investors. Thirdly, empirical studies in Indonesia and elsewhere were showing reformers that tax holidays played only a relatively minor role in foreign company’s decisions about where to place new investment. These empirical studies also seemed to show that taxation of world-wide income and foreign tax credit systems in some home countries, meant that THs in Indonesia led to larger tax payments to investor’s home. It was also pointed out that the holiday system introduced distortions across sectors and classes of firms, favouring large investors, a class that policymakers were no longer so eager to encourage – see id. 37 See id.


Investors gained from 1983 approval dates, since the grandfathering of pre-1984 incentives meant they would receive tax holidays as well as enjoy the new lower tax rate.

Source: Culled from Wells L.T. & Allen N.J., Tax Holidays to Attract Foreign Direct Investment: Lessons from Two Experiments (2001)

Interestingly enough, as more encouraging data on FI began to come in, it emerged that the reason for the low FI figures in 1984 had been due to an upward blip in FI approvals for the year preceding reform, as a number of investors, widely expecting THs to be reduced, accelerated their applications for investment licenses.38

Also, there was some evidence that the investment agency, Badan Koordinasi Penanaman Modal (BKPM), responsible for drawing FI into the country, had been induced to predate some 1984 approvals to 1983.39

Investors gained from 1983 approval dates, since the grandfathering of pre-1984 incentives meant they would receive tax holidays as well as enjoy the new lower tax rate.

38 See Wells & Allen, supra note 10, at 10. 39 See id.


Figure 2, below - reporting the logs of the number and value of projects for the same period as Figure 1, to make it easier to compare growth rates before and after the elimination of incentives - shows that there was not a measurable change in the growth rate after the tax holidays were eliminated,

3.2.2 Impact on Growth Rate of Foreign Investment Figure 2, below - reporting the logs of the number and value of projects for the same period as Figure 1, to make it easier to compare growth rates before and after the elimination of incentives - shows that there was not a measurable change in the growth rate after the tax holidays were eliminated, although one might have expected some slowdown in this rapid growth simply from market.

Source: Culled from Wells L.T. & Allen N.J., Tax Holidays to Attract Foreign Direct Investment: Lessons from Two Experiments (2001)

Further confirming what the figures show graphically, are a series of statistical tests, carried out by Wells and Allen,40 of the differences between growth rates before and after 1984.

40 See id.


Considering the crudest of these tests first, Wells and Allen show that if one examines the values of FI, the rate of growth from 1978 through 1983 was slightly higher than that for 1984 to 1993, but the difference between the growth rates in the two periods was not significantly different from zero.

Table II, above, shows that despite the fact that other neighbouring countries continued offering, and in some case increased, TIs to attract FI, rather than losing long run share of FI in the region, by the period 5-10 years after it had eliminated THs, Indonesia had managed to almost double its share.

Considering the crudest of these tests first, Wells and Allen show that if one examines the values of FI, the rate of growth from 1978 through 1983 was slightly higher than that for 1984 to 1993, but the difference between the growth rates in the two periods was not significantly different from zero. On the other hand, if the comparison is based on the number of projects approved, the growth rate after the end of tax holidays was slightly higher than that before; again, the difference between the two growth rates was not significantly different from zero.

Secondly, to test the robustness of these findings, Wells and Allen41 adjusted the numbers in various ways, e.g., similar tests were made on the figures without including a very large refinery project that was never implemented. The handling of the transition years 1983 and 1984 was adjusted: first, by averaging the number of projects and the values for those two years and then, by eliminating the two years. Whatever the adjustments or combinations of adjustments, the conclusions held. The differences between growth rates in investment with tax holidays and those without tax holidays were not significantly different from zero.

3.2.3 Effect on Foreign Investment of Neighboring Countries Tax Incentives

Table II, above, shows that despite the fact that other neighbouring countries continued offering, and in some case increased, TIs to attract FI, rather than losing long run share of FI in the region, by the period 5-10 years after it had eliminated THs, Indonesia had managed to almost double its share. Further confirming the fact that if THs had been decisive factors in the location decisions of investors, Indonesia would have lagged behind investment in other countries that continued to offer tax holidays and tax rates comparable to the new Indonesian rates.

41 See id.


As a practical matter, such offsets result when the home country taxes income of its investors on a world-wide basis and rejects “tax sparing” provisions in treaties to avoid double taxation

3.2.4 Effect on Foreign Investment of Home Country Tax Policy It has been argued that one reason that TIs might be ineffective as a determinant of location of investment is that some home country policies offset the tax savings created by the incentive.42 As a practical matter, such offsets result when the home country taxes income of its investors on a world-wide basis and rejects “tax sparing” provisions in treaties to avoid double taxation.43 The US does so; hence, one might expect that US investors would be relatively indifferent to the offer of tax incentives when deciding whether to invest in a particular country. Some other countries, by contrast, tax only the domestic income of their residents or agree to tax sparing arrangements.44

42 Morisset J., Using Tax Incentives to Attract Foreign Direct Investment, 3 (2000). 43 Winters J.A., Power in Motion: Capital Mobility and the Indonesian State, 26 (1996). 44 See id.

Table II – Average Shares of Total Foreign Investment in 5 ASEAN Countries (Percent)

Country

Year Indonesia Philippines Thailand Singapore Malaysia Total

1970-84 10.8 2.6 7.7 46.4 32.5 100.0

1985-90 9.2 6.9 17.0 49.3 17.6 100.0

1991-96 19.8 6.5 11.7 3.8 28.1 100.0

Note: ASEAN is Association of Southeast Asian Nations. Source: Culled from Wells L.T. & Allen N.J., Tax Holidays to Attract Foreign Direct

f ( )


There is, in fact, some econometric evidence to suggest that in making FI location decisions, investors domiciled in countries with the latter practices do indeed respond more positively to tax incentives than do investors based in the US. On the other hand, the share of Dutch investors increased substantially, as did the share of investors from Singapore and Korea, contrary to predictions based on home country tax systems.

There is, in fact, some econometric evidence to suggest that in making FI location decisions, investors domiciled in countries with the latter practices do indeed respond more positively to tax incentives than do investors based in the US.45 However, it is difficult to identify any such influence of the home country in the investment flows set out in figures 1 and 2 above. Wells & Allen46, however, suggested grouping and examining the behaviour patterns of three groups of investors:

1. Those from the US, which taxes foreign-earned income but gives tax credits for taxes paid abroad;

2. Those from the industrialised countries of the Netherlands, France, the UK, and Japan, which do not tax foreign-earned income or give foreign tax credits under tax-sparing arrangements; and

3. Those from the emerging economies of Hong Kong, Singapore, Korea, and Taiwan, which probably pay no tax at home on foreign-earned income.

As can be seen from Table III above, the results of this test show that figures on shares of investment at the end of the tax holiday period and 10 years later show, at most, a very weak impact of the home country tax system. The share of US investors in total FI in Indonesia went up, as one might predict, since US investors benefited relatively little from tax holidays in the first place and would continue along their old path. The increase however, was quite small. The share of UK and Japanese investors fell somewhat, consistent with their having benefited from tax holidays. On the other hand, the share of Dutch investors increased substantially, as did the share of investors from Singapore and Korea, contrary to predictions based on home country tax systems. In sum, it is hard to find evidence in Indonesia that the home country tax system had a large and consistent impact on investors’ reactions to THs. 45 See Wells & Allen, supra note 10, at xiii. 46 See id.


In summary, the experiment in Indonesia provides strong evidence that a country can attract growing amounts of FI without offering tax holidays, at least if its general income tax rate differs little from that of its neighbours.

In summary, the experiment in Indonesia provides strong evidence that a country can attract growing amounts of FI without offering tax holidays, at least if its general income tax rate differs little from that of its neighbours.47 FDI in Indonesia increased over the 1978-93 period at a striking rate of 25% per year compounded (215 for number of projects; 28% for value), with even domestic investment showing a pattern almost identical to that of FI; it remained flat until 1982, spiked in 1983, declined in 1984, and climbed thereafter.48 Moreover, Indonesia’s experience suggests that with regards to the impact of TIs, home country policies matter less than one might expect. Although Japanese investors (whose Indonesian income was covered under tax sparing arrangements) complained regularly about the elimination of tax holidays, they still flocked to the country.49 In fact, 47 Anwar S., Fiscal Incentives for Investment and Innovation, 95 (1995). 48 See Wells & Allen, supra note 10, at 14. 49 See Morisset, supra note 42, at 4.

Table III – Shares in Total Foreign Investment in Indonesia, 1967 –95

1967-85 1967-95 Home Country $ million % $ million % United States 1,381 9.0 10,660 10.0 United Kingdom and Japan 5,249 34.1 30,472 28.8 Singapore and Korea 346 2.2 13,216 12.4 Netherlands 499 3.2 7,320 6.9 Other 7,9393 51.5 45,132 41.9 Total 15,414 100.0 106,800 100.0 Note: The end years in these sources are close to, but not identical to, those

used in Figures 1 and 2 and Table II. Source: Culled from Wells L.T. & Allen N.J., Tax Holidays to Attract Foreign

Direct Investment: Lessons from Two Experiments (2001).


One has to conclude that investors will go to a country – if its petroleum reserves, climate, and policies are attractive – whether the country offers THs or not. Not surprisingly, researchers using this approach find that, under assumptions that make calculations feasible, tax holidays will increase the returns to investors; therefore, researchers conclude, investors will invest more in countries offering them.

Indonesia gained over its neighbours in the competition for Japanese investment, even without TIs50. One has to conclude that investors will go to a country – if its petroleum reserves, climate, and policies are attractive – whether the country offers THs or not.

4 CONSISTENCY WITH OTHER FINDINGS To give strength to the conclusions made in the last chapter about the Indonesian experience, this chapter presents the outcome of three sets of empirical studies that show that the overall impact of TIs on the investment decisions of MNOCs is minimal.

4.1 Theoretical Research In a stream of conflicting theoretical research, scholars have calculated the financial impact of THs on the returns from hypothetical investment projects. They then assume that investors in the O&G industry, act in simple, profit-maximising ways, i.e. if THs increase the net present value of projects, they will attract more investors.51

Not surprisingly, researchers using this approach find that, under assumptions that make calculations feasible, tax holidays will increase the returns to investors; therefore, researchers conclude, investors will invest more in countries offering them. However, researchers following this approach usually do not address the question of whether the greater investment flow to a country offering incentives is a net addition to the flows to the developing world, or whether it simply represents a diversion from countries offering smaller incentives to those offering greater ones.52

In spite of the great care with which one is sure that some of this research has been done, the results remain unconvincing. First, the studies do not adequately account for the complexity of the tax situation

50 See id. 51 De Mooij R.A. & Ederveen S., Taxation and Foreign Direct Investment, 32 (2001). 52 See id.


In the real world of investors, the impact of tax systems such as that of the US is very complicated. The foreign tax credits that a firm can use to offset home country taxes can depend on the extent that earnings are retained in the operations in the HC, on tax rates in other countries in which the MNOC operates…

Recognising that investors may not always respond in ways assumed by calculations, a number of researchers have carried out selective surveys of investors to determine if tax policy was one of the key factors in the decision-making process of MNOCs.

facing multinational firms. Some home country tax codes, e.g., impose no tax on foreign-earned income.53 The tax systems of some other home countries result in a different outcome: the benefits of TIs in developing countries may be largely offset by increased liabilities of the parent enterprises to the tax authorities of the home governments (this can be the impact of the US foreign tax credit system).54

In the real world of investors, the impact of tax systems such as that of the US is very complicated. The foreign tax credits that a firm can use to offset home country taxes can depend on the extent that earnings are retained in the operations in the HC, on tax rates in other countries in which the MNOC operates, on how the investment is financed (in particular, the proportion declared as debt), and on administrative choices made by tax authorities.55 Second, to some extent, firms that operate under more than one tax regime have ways of allocating their profits within their networks; by assigning them to minimise taxes, they make any simple calculations suspect.56 These kinds of problems have led most theoretically oriented researchers simply to ignore the home country regime. Although the omission makes the calculations easier, it sharply reduces the plausibility of results.

(4.2)Survey of Investors

Recognising that investors may not always respond in ways assumed by calculations, a number of researchers have carried out selective surveys of investors to determine if tax policy was one of the key factors in the decision-making process of MNOCs.

Below is presented a brief summary of the major findings, which are generally consistent with the findings of the research in Indonesia, notably that TIs neither affect significantly the amount of direct

53 Edminston K.D., Mudd S., Valev N.T., Incentive Targeting, Influence Peddling and Foreign Direct Investment, 5 (2003). 54 See id. 55 See id. 56 See Wells & Allen, supra note 10, at 17.


In 1955, in one of the first type of these survey studies, Barlow and Wender interviewed 247 US companies about their strategies to invest abroad. Only 10% of the companies listed favourable foreign taxes as a condition for FDI, ranking these inducements fourth after currency convertibility, guarantee(s) against expropriation, and HC’s political stability.

“Tax exemption is like a dessert, it is good to have, but it does not help very much if the actual meal is not there!”

investment that takes place nor usually determine the location to which investment is drawn:57

In 1955, in one of the first type of these survey studies, Barlow and Wender58 interviewed 247 US companies about their strategies to invest abroad. Only 10% of the companies listed favourable foreign taxes as a condition for FDI, ranking these inducements fourth after currency convertibility, guarantee(s) against expropriation, and HC’s political stability.

A 1961 Robinson Survey of 205 companies confirmed these findings.59Next came a 1966 field research by Aharoni60 on the way FI decisions were made by US manufacturing firms, in which, the conclusions were that HG concessions did not bring about the decisions to invest. Income tax stimulation was considered a very weak stimulant. Those investors, who did consider it, did it only marginally. In the words of one of the interviewed investors, “Tax exemption is like a dessert, it is good to have, but it does not help very much if the actual meal is not there!”In a 1984 survey of 31 oil companies (OCs), the Group of Thirty found that among 19 factors that were identified as influencing FDI flows, inducements offered by the host country rank seventh in importance for investment in developing countries and eighth in developed countries.61 In recent years, several investors’ surveys have explored the effectiveness of tax policies on FDI using alternative samples or asking 57 Indeed, in respect to the former, one striking finding reported in several surveys is that there is a large discrepancy between the way investors view tax incentives and the way government officials view the same incentives; surveys of investors tend to rank incentives quite low as determinants of investment. It should be noted, however, that studies using econometric tolls rank them high. 58 See Morisset & Pirnia, supra note 12, at 6. 59 Perhaps the most important result of the Robinson survey was the considerable difference of opinion between the business community and the governments, with regards the major factors influencing investment decisions: tax concessions headed the list of govt responses, while they were omitted from the list of private investor responses – see id. 60 Id. 61 See Morisset & Pirnia, supra note 12, at 6.


Last but not least, in 2000, the Oman Chamber of Commerce & Industry (OCCI) and Muscat Security Market (MSM) conducted a survey of 106 foreign equity ventures examining the factors that influence foreign investors to engage in projects in Oman.

These results support the view that political and economic stability are sine qua non for attracting FDI.

more detailed questions (for example, JETRO in 1995, Ernst & Young in1994 and Deloitte & Touche in 1997).62 In general, these surveys have confirmed the conclusions summarised above; that if tax policy matters it is not the most influential factor in the site selection of MNOCs.63

Last but not least, in 2000, the Oman Chamber of Commerce & Industry (OCCI) and Muscat Security Market (MSM) conducted a survey of 106 foreign equity ventures examining the factors that influence foreign investors to engage in projects in Oman. Analysis of the data revealed that political and economic stability are the two most important motives for investing in Oman.64

These results support the view that political and economic stability are sine qua non for attracting FDI. This is not to say that these two factors differentiate countries and make them more attractive for FDI. They are simply a threshold that all countries, and in particular developing countries, must achieve in order to be considered for FDI.65

62 Id. 63 In the Deloitte & Touche’s survey, TIs ranked at the 13th position out of 26 factors. 64 Mellahi K., Guermat C., Frynas G. & Al Bortamani H., Motives for Foreign Direct Investment In Gulf Co-operation Countries: The Case of Oman, 10 (2000). 65 Id.


But that does not mean that TIs have no effect on FDI, as there have been some spectacular successes as well as some notable failures in their role as facilitators of FDI

Econometric Analysis

Although an exhaustive evaluation of the available econometric evidence is beyond the expertise of this author, it is nonetheless, perhaps still worthwhile noting that most econometric studies have tended to confirm the results of surveys,66 i.e. that TIs appear to have little effect on the location of FDI. In summary, the overwhelming conclusion of the empirical research is, again, that tax incentives do not have a major impact on actual investment location decisions.

5 CONCLUSION Although at first glance the impact of TIs on FDI appears to be ambiguous, the results of the Indonesian experience, time-series econometric analysis and numerous surveys of international investors have all shown that TIs are not the most influential factor for multinationals in selecting investment locations for O&G projects.

66 In their article, How Tax Policy and Incentives Affect Foreign Direct Investment: A Review, Morisset & Pirnia evaluate a selective sample of studies – Root & Ahmed (1978), Agodo (1978), Shah and Toye (1978) and Lim (1983) - and conclude in that direction. With Root & Ahmed performing an econometric study with data for 41 developing countries during the period 1966-70. In which they classified countries into 3 categories of unattractive, moderately attractive according to their average per capita inflow of FDI. 44 variables were chosen as potentially significant discriminators of the 3 defined country groups. Among the six policy related discriminators were three relating to tax levels. Of these, CT rates proved to be an effective discriminator of the three defined country groups; however, TI laws and liberality were not found to be effective discriminators. Agodo analysed a sample of 23 US firms and tax concessions were found to be insignificant as a determinant of FDI in simple and multiple regressions – see Morisset & Pirnia, supra note 12, at 7.


Investors generally tend to adopt a two-stage process when evaluating countries as investment locations. In the first stage, they screen countries based on these and other fundamental determinants. Only those countries that pass these criteria go on to the next stage of evaluation where tax rates, grants and other incentives may become important. It is, therefore, suggested that instead of blindly offering TIs to any MNOC that will take them, which is just one method of attracting FDI, policy-makers may find it more beneficial to stick to the fundamentals,

The point to be made is that as a factor in attracting FDI, incentives are secondary to more fundamental determinants, such as size and prospectivity of reserves, political and macroeconomic stability, methods of foreign enterprise participation, attitudes and overall business environment.67 Investors generally tend to adopt a two-stage process when evaluating countries as investment locations. In the first stage, they screen countries based on these and other fundamental determinants. Only those countries that pass these criteria go on to the next stage of evaluation where tax rates, grants and other incentives may become important.68 Thus, more accurate would be to say that TIs affect the decisions of some investors some of the time. In conclusion, TIs seem to be neither necessary nor sufficient for a country to attract FDI in the first instance. Using them to compete for FDI carries the covert risk of “racing to the bottom” with competitive TIs,69 with countries either (a) ending up in a bidding war, favouring multinational companies at the expense of the State and the welfare of its citizens, or/and (b) facing reduced fiscal revenue and creating frequent opportunities for illicit behaviour by companies and tax administrators.70

It is, therefore, suggested that instead of blindly offering TIs to any MNOC that will take them, which is just one method of attracting FDI, policy-makers may find it more beneficial to stick to the fundamentals, realistically appraising their national FDI balance sheet with the strategic intelligence to target the right investors, while implementing macroeconomic and political reforms to ensure stability and predictability of policy measures, and then promote their countries as investment locations with a prowess that has been effectively and efficiently tailored. It may also be advisable for these governments to

67 Barrows G., A Survey of Incentives in Recent Petroleum Contracts, 227 (1988). 68 Ogutcu M., OECD: Attracting Foreign Direct Investment for Russia’s Modernisation – Battling Against the Odds, 5 (2002). 69 Such competition has already started in some regions, most notably in Asia 70 These issues have become crucial in developing countries, which face more severe budgetary constraints and corruption than do industrial countries – DPRU, What are the major trends and determinants of foreign direct investment in SADC countries? pp 4-10 (2000)


try to harmonise their tax policies under regional or international agreements71 or consider whether some other sort of regional or global collective action might be in their better interests: e.g. maybe a call for a World Trade Organisation obligation to limit selective incentives, as is done in the European Union, or ban them altogether.

About the Authors: Ms Orighoye Rewane is an attorney-at-law of the Federal Court of New York and recently completed an LL.M in Petroleum Law & Policy (with Distinctions) at the Centre for Energy, Petroleum Mineral Law and Policy.

71 Recent efforts to harmonise tax systems have been launched in both the industrial and the developing world. In the European Union, for example, member countries are discussing more stable, predictable, and transparent tax rules. As a first step, in December 1997, member states adopted a code of conduct for business taxation, agreeing not to introduce “harmful” tax measures and to roll back existing harmful measures. Similarly, several West African countries have been working to harmonise their tax incentives for FDI in one unified investment code within the Monetary Union of West African states – see id.


Why do OPEC members continue to price their oil in US dollar despite their hefty losses from the decline in the value of the dollar relative to other world currencies? Pricing oil in the euro instead of the dollar or even in a basket of currencies will not change the world price of oil. Exchange rates will determine the price of oil in other currencies.

GGoovveerrnnmmeenntt

Why Does OPEC Continue to Price Its Oil in Dollars?

A. F. Alhajji, PhD

Why do OPEC members continue to price their oil in US dollar despite their hefty losses from the decline in the value of the dollar relative to other world currencies? The answer is not as easy as some people think. OPEC has tackled dollar devaluation issues for more than 30 years, yet it still uses the dollar to price its oil. Several economic, technical, and political factors have in the past prevented OPEC from switching the pricing of oil to another currency or basket of currencies. These same factors prevent OPEC today from switching currencies. Economic Factors 1- Pricing oil in the euro instead of the dollar or even in a basket of currencies will not change the world price of oil. Exchange rates will determine the price of oil in other currencies. For example, if the price of oil is $50/b and the exchange rate is one euro to $1.30, the price of oil in euro would be €38.46/b. In this case, the producing country is indifferent to whether it gets $50/b or €38.46/b. The world price of oil would stay the same. Supporters of pricing oil in euro cite the success of Iraq when it asked the UN to receive euros instead of dollars for its oil exports under the UN oil-for-Food Program. Those supporters ignore the fact that as the euro started to appreciate the benefits to Iraq came from the money held in euro accounts, not from receiving euros for oil exports. In other words, Iraq did not "price" its oil in euros.


Pricing oil in a single currency other than the dollar, such as the euro, will not solve the problem of declining purchasing power, especially when the euro starts to decline relative to the dollar. Pricing oil in a basket of currencies will not benefit all members. OPEC members stretch from Latin America, to the Middle East, to Southeast Asia. Their trading partners are different, and the weight of each trading partner differs greatly.

Iraqi oil was still prices in dollars, but the Iraqi government insisted on payments in euros. The UN converted the dollar revenue from Iraq oil sales into euros and deposited them In Iraq’s accounts. Receiving euros did not change the price of Iraqi oil in the market. 2- Pricing oil in a single currency other than the dollar, such as the euro, will not solve the problem of declining purchasing power, especially when the euro starts to decline relative to the dollar. Once the euro starts to decline, those who have been calling on OPEC to switch to euro pricing instead of the dollar will then start calling on OPEC to return to dollar pricing. The use of any single currency in oil pricing will have the same effect, whether that currency is the dollar, the euro, or the yen. 3- Benefits from pricing oil in a basket of currencies are limited, especially in the long run. OPEC will not benefit greatly from adopting a basket of currencies to price its oil, especially if the objective is to stabilize the purchasing power of its oil exports. Given the share of the US trade in OPEC trade balances, the dollar will still have an influential role in such a basket. 4- Pricing oil in a basket of currencies will not benefit all members. OPEC members stretch from Latin America, to the Middle East, to Southeast Asia. Their trading partners are different, and the weight of each trading partner differs greatly. For example, the main trading partner for Venezuela is the US, for Indonesia is Japan, and for Algeria is the EU. When the dollar declines relative to the euro and the yen, Algeria and Indonesia stand to lose more purchasing power than Venezuela. 5- Some studies indicate that a switch to a non-dollar pricing might cause a shock in the US economy and reduce US economic growth. Regardless of the political reaction, a decline in US economic growth would lower the demand for oil, and consequently lower oil prices. The losses from lower oil prices could outweigh any benefits from switching to a new pricing mechanism.


The economic problems that the oil producing countries suffered from in the last three decades have nothing to do with the value of the dollar. However, these problems force governments to focus on short term rather than long term problems and solutions. Efforts to insure the success of the basket pricing are costly. They require a long period of time of research, negotiations, implementation, and monitoring.

6- The economic problems that the oil producing countries suffered from in the last three decades have nothing to do with the value of the dollar. However, these problems force governments to focus on short term rather than long term problems and solutions. Dollar devaluation causes problems in the short run. But in the long run, it appears that these countries benefited from several years of dollar appreciation. In fact, dollar appreciation and deprecation in the last 30 years even out. In other words, the disadvantages of a single-currency pricing are limited to the short run. These disadvantages do not exist in the long run. Technical Factors Which currencies should be included in the basket? What is the weight of each currency in the basket? What are the factors that determine the weight of each currency in the basket? How to monitor the basket and the price of each currency? How often should OPEC review the basket? How often should OPEC change the currencies in the basket or the weight of each currency? Should OPEC become the Grand Marshal of world central banks to monitor their moves so it can adjust the weight of currencies in the basket before it is too late? What is the cost of such consistent monitoring? Do benefits of a basket of currencies outweigh the cost of establishing such a basket and the consistent monitoring? These are some of the technical problems that OPEC will face if it decides to switch to a basket of currencies instead of the dollar to price its oil. Efforts to insure the success of the basket pricing are costly. They require a long period of time of research, negotiations, implementation, and monitoring. Such a shift would require highly skilled experts from around the world who are expensive to recruit. In addition, pricing oil in a basket would complicate world oil markets and will reduce transparency. Simply stated, the cost of using a basket of currency would outweigh its benefits.


However, these technical issues may have prevented OPEC from switching to a basket of currencies in the past, but they may not be as problematic nowadays We should not forget that even if the switch to non-dollar pricing does not affect the US economy, the US will not let OPEC members slap it in the face. It will not quietly accept such an insult in front the whole world. The dollar is a symbol of America's strength, and the US will not let others disregard this symbol.

However, these technical issues may have prevented OPEC from switching to a basket of currencies in the past, but they may not be as problematic nowadays. Most technical analyses are handled by advanced computer programs that reduce the cost substantially. The main issue that may not be solved by such programs is the choice of currencies, which subject to several economic and political factors. Political Factors Ultimately, the decision to price oil in a non-dollar currency or a basket of currencies is political. The decision of the deposed Iraqi president, Saddam Hussein, to receive euros instead of dollars for Iraqi oil exports under the UN Oil-for-Food Program was a political decision, not economic. Iraq lost a massive amount of revenues in the beginning. At the time, the euro was declining relative to the dollar. Pricing oil in another currency would carry a political price that OPEC members cannot handle, especially if the switch to non-dollar pricing hurts the US economy. We should not forget that even if the switch to non-dollar pricing does not affect the US economy, the US will not let OPEC members slap it in the face. It will not quietly accept such an insult in front the whole world. The dollar is a symbol of America's strength, and the US will not let others disregard this symbol. OPEC members are part of the world community. Its leaders fully understand the political ramifications of pricing oil in a currency other than the dollar. Conclusion The economic benefits from switching to non-dollar pricing are limited. Political costs would be very high. Technical factors, while costly, might be resolved, but OPEC members may not agree on the contents of the basket. Therefore, OPEC will not switch to a currency other than the dollar in the foreseeable future, even if the dollar continues to decline. The unexpected massive increase in oil revenues in the last two years provide another reason for OPEC members to do nothing.


The only way for OPEC members to reduce the negative effect of dollar devaluation is to diversify their imports. Import diversification will guarantee higher purchasing power than import concentration.

The only way for OPEC members to reduce the negative effect of dollar devaluation is to diversify their imports. Import diversification will guarantee higher purchasing power than import concentration. OPEC members can further improve their purchasing power by adopting flexible trade polices that will allow them to switch imports from one country to another as exchange rates change. Reprinted with the permission of the Gulf Research Center Copyright © Gulf Research Center 2005 All rights reserved www.gulfinthemedia.com. About the Author: A. F. Alhajji, PhD is an Associate Professor at theCollege of Business Administration Ohio Northern University.


When China’s energy self-reliance policy virtually ended in 1993, the trans-national pipeline concept was looked at afresh. PRC energy planners took the proposal seriously, and the concept was well thought of by Dr. Wang Tao (then president of China National Petroleum Corporation).

GGoovveerrnnmmeenntt Pipeline Gas Introduction to the Korean Peninsula

Dr Keun-Wook Paik 1.1.Pipeline Gas Supply Sources for the Korean Peninsula Until the end of the Cold War, the concept of developing a trans-national pipeline network in Northeast Asian region was a mere pipe-dream. It was inconceivable to have a long distance pipeline from Russia to Korea or Russia to Korea via China. However, the establishment of diplomatic relations between Former Soviet Union (FSU) and Korea in September 1990 and China and Korea in August 1992 opened a new chapter for energy cooperation in the region. When China’s energy self-reliance policy virtually ended in 1993, the trans-national pipeline concept was looked at afresh. PRC energy planners took the proposal seriously, and the concept was well thought of by Dr. Wang Tao (then president of China National Petroleum Corporation), particularly when it appeared in June 1996, as part of the proposal to establish a Pan-Asian oil and gas pipeline grid covering Russia, Japan, Korea and central Asian Republics.


In Northeast Asia there are currently six pipeline gas supply sources targeting mainly China, Korea and Japan. In recent years it has been China that has been driving the introduction of a transnational pipeline in Northeast Asian region. Despite ten years preparation and negotiations, agreements on the pipeline have been prevented by geopolitical tensions and the expense involved. In the meantime, the decision to supply LNG into both Guangdong and Fujian provinces introduced LNG to China.

During the first half of the 1990s, Japan carried out a comprehensive study of the potential for Russia’s oil and gas supply into Northeast Asia. The study identified a number of major oil and gas export sources, including the Yurubchonskoye oil field in the Krasnoyarsk region, Verkhechonskoye oil field in the Irkutsk region, Talakanskoye and Sredne-Botuobinskoye oil fields in Sakha Republic, Kovyktinskoye gas field in the Irkutsk region, and a cluster of gas fields in Sakha Republic (at that time the Chayandinskoye field reserves were only 200bcm).1 In Northeast Asia there are currently six pipeline gas supply sources targeting mainly China, Korea and Japan. As shown in Table 1, the Russian Federation has four gas supply sources for China, and in the central Asian Republic region there are two gas supply sources. There are three major pipeline gas supply sources for the Korean Peninsula. In recent years it has been China that has been driving the introduction of a transnational pipeline in Northeast Asian region. Despite ten years preparation and negotiations, agreements on the pipeline have been prevented by geopolitical tensions and the expense involved. In the meantime, the decision to supply LNG into both Guangdong and Fujian provinces introduced LNG to China. When the breakthrough comes, trans-national pipeline development will bring a new dimension to the Korean Peninsula and Northeast Asian region’s energy structure. The implications of a long distance pipeline development will be broad in scale, since they will not be confined to the Korean Peninsula.



The year 1992 witnessed two major initiatives by the China National Petroleum Corporation (CNPC) with regard to pipeline gas imports. The first involved East Siberian oil and gas development and their export to China. In July 1992, Professor Zhang Yongyi, then vice president of CNPC, proposed the export of oil from East Siberia to Russia and Japan. In September 1993, CNPC began to negotiate with the Russians for exploration rights for the Markovskoye and Yaraktinskoye oil and gas fields in the Irkutsk region.

Irkutsk gas export to the Korean Peninsula The year 1992 witnessed two major initiatives by the China National Petroleum Corporation (CNPC) with regard to pipeline gas imports. The first involved East Siberian oil and gas development and their export to China. In July 1992, Professor Zhang Yongyi, then vice president of CNPC, proposed the export of oil from East Siberia to Russia and Japan. Prof. Zhang added that the oil pipeline could be extended to Japan via Korea if Japan got involved in the project. The second initiative was the importation of Central Asian gas into China. This was proposed by CNPC together with Mitsubishi at the end of 1992. During 1993-1994, CNPC identified the Kovykta gas project in the Irkutsk region as the priority project for the trans-national pipeline development between Russia and China, and in November 1994 a memorandum of understanding (MOU) was signed between CNPC and Mintopenergo for the construction of a long distance pipeline to promote East Siberian oil and gas resources. The 1994 agreement was the first official expression of shared determination for the pipeline development. The trans-boundary pipeline, proposed by Sidanco, then the major Russian share holder, aims at transporting 20- 30bcm annually from the Irkutsk region in East Siberia to the coastal cities of East China, and possibly to Korea and Japan. In September 1993, CNPC began to negotiate with the Russians for exploration rights for the Markovskoye and Yaraktinskoye oil and gas fields in the Irkutsk region.2 CNPC’s Russian counterpart was Irkutsk's Petroleum and Gas Geological Company and Geophysical Research Institute, together with 14 other local companies and entities. CNPC’s two exploratory wells were drilled in two virgin fields.3 As a result of this initial investigation, CNPC understood the potential of Kovykta gas exports to China.


Under the deal, Russia would export 25bcm/y of gas over thirty years, from the Irkutsk. $1.5bn worth of electricity will be exported over 25 years, based on a supply of 20 billion KW/h of electricity from Irkutsk to either Shenyang, Liaoning province or to Beijing. Based on this 1999 agreement, a three-year study by the parties (CNPC, Korea Gas Corp and Russia Petroleum) was undertaken in November 2000 and the results were submitted in November 2003.

Another major agreement was made in late June 1997, when a Russian delegation led by Premier Viktor Chernormyrdin, visited Beijing and signed a governmental framework agreement between Russia and China to export natural gas and electricity from East Siberia to China. Under the deal, Russia would export 25bcm/y of gas over thirty years, from the Irkutsk. $1.5bn worth of electricity will be exported over 25 years, based on a supply of 20 billion KW/h of electricity from Irkutsk to either Shenyang, Liaoning province or to Beijing. This framework agreement is effectively a re-confirmation of the 1994 MOU. The most important agreements were signed in February 1999 after the fourth meeting between Premier Zhu Rongji and his counterpart Yevgeny Primakov. Both sides signed 11 agreements, of which three are related with oil and gas.4

• The first was for a preliminary feasibility study for crude oil exports from Angarsk to Daqing through a 20-30 mt/y capacity pipeline.

• The second was for a feasibility study on natural gas exports

from the Irkutsk region t north-eastern China through a long distance pipeline.

• The third was for a preliminary feasibility study on gas exports

from western Siberia` Shanghai by a trans-national pipeline passing through the Xinjiang region.

Based on this 1999 agreement, a three-year study by the parties (CNPC, Korea Gas Corp and Russia Petroleum) was undertaken in November 2000 and the results were submitted in November 2003.


Even though the official agreement for the feasibility study of the Irkutsk gas project was signed in November 2000, the negotiation was suspended for at least 7-8 months due to a number of unresolved issues since Autumn 2001

Kovykta Gas Development5 The ten years preparation period for the Kovykta gas project can be divided into five stages as Table 2 explains.

Table 2 – The Five Stages of the Kovykta Project

1994-1996 This period is characterized as ‘bilateral relationship development period’ between CNPC and Mintopenergo. 1996-1997 This is the first stage for the western investment, initiated by Korea’s Hanbo group and then by BP’s serious move. 1998 This is the negotiation period for ‘five country FS work’ (Had it hammered out a compromise, it would have opened the door for the genuine ‘multilateral cooperation era’ in Northeast Asia). The driving force of this negotiation was Japan, but its initiative to lend a major loan for the FS work was not supported due to its failure to open their gas market for the development. 1999-2000 The focus is once again on bilateral relationship between Russia and China until the three party FS work agreement is signed. 2000-2003 Both Russia and China agree to invite South Korea to the project, to minimize the risk of market availability in the early stage of the project. Even though the official agreement for the feasibility study of the Irkutsk gas project was signed in November 2000, the negotiation was suspended for at least 7-8 months due to a number of unresolved issues since Autumn 2001. The negotiation resumed in Summer 2002. The result of the FS was completed in November 2003. Source: Keun-Wook Paik, ‘Sino-Russian Oil and Gas Co-operative Relationship: Implications for Economic Development in Northeast Asia’, presented at Northeast Asia Cooperation Dialogue XIII: Infrastructure and Economic Development Workshop’, organised by Institute for Far Eastern Affairs, Russian Academy of Sciences, and Institute on Global Conflict and Cooperation, University of California, Moscow, 4 October, 2002.


When the project was initially introduced to the western world, the proven reserves of the field stood at 870 bcm, of which C1 was only 277 bcm. However, as of 2002 the figure became 1932 bcm, of which C1 was 1,000 bcm.

The Kovyktinskoye gas/condensate field discovered by Vostsibneftegasgeologiya, a subdivision of the former Ministry of Geology of Russian Federation, is located in the Zhigalovsky region, 350 km to the north-northeast of Irkutsk.

When the project was initially introduced to the western world, the proven reserves of the field stood at 870 bcm, of which C1 was only 277 bcm. However, as of 2002 the figure became 1932 bcm, of which C1 was 1,000 bcm. The scale of the proven reserves was large enough to justify a major export scheme.


The project’s three-year feasibility study was completed in November 2003. The main objective of the study was to show whether gas supply to China and Korea would be effective and commercially viable. If the project was approved by all three governments, its value would soar. In 2003 the biggest share holder is BP-TNK, with a 62% controlling stake, as table 4 shows.

The turning point of the Kovykta project development was BP’s acquisition of a 45% equity stake in Russia Petroleum, achieved by providing $172m to the cost of appraising the Kovykta field. BP’s involvement helped accelerate the exploration, which confirmed the real scale of the proven reserves. The project’s three-year feasibility study was completed in November 2003. The main objective of the study was to show whether gas supply to China and Korea would be effective and commercially viable. The study assumed that Russia Petroleum would sell 600bcm of gas (20bcm/y) to CNPC and 300bcm (10bcm/y) to Korea Gas Corp (Kogas) over 30 years. The supply would start in 2008, reaching 30bcm/y by 2017. The study called for up to 4bcm/y of gas to be supplied to Irkutsk, Chita and Buryatia regions. The required investment for the project would total $17bn, much higher than the $12bn price tag suggested in 1995. About 400-500 wells with average depth of 3,000 meters would be needed to develop the Kovykta field. The project includes the construction of nine gas treatment plants, 20 compressor stations and 20 collection stations. Russia’s projected demand for the Kovykta gas was 4bcm, while that of north-eastern China and northern China was 12bcm and 8bcm respectively, and that of Korea were 10bcm per year.6 The next step was to obtain the approval of the governments involved. If the project was approved by all three governments, its value would soar. In 2003 the biggest share holder is BP-TNK, with a 62% controlling stake, as table 4 shows. It is worth noting that Interros Holdings Company’s 25.8% stake was put on sale for approximately $500m soon after the feasibility work was completed. However, the most important players that will decide the fate of the project – Gazprom and CNPC – did not make an offer.


There has been considerable confusion about the role of co-ordinator. Gazprom argues that it has a mandate from Russia’s central government to co-ordinate gas export projects.

A number of issues need to be resolved for this project to move forward: 1. Who should co-ordinate the negotiations? There has been considerable confusion about the role of co-ordinator. Gazprom argues that it has a mandate from Russia’s central government to co-ordinate gas export project.8 In fact, during a keynote speech at the 22nd International Gas Conference held in Tokyo in June 2003, Alexei Miller, CEO of Gazprom, confirmed that Gazprom had been authorised to co-ordinate the establishment of a united system for gas production and transportation.9 However, his talk did not give any details about how Gazprom would approach its coordinating role. TNK-BP understands that Gazprom’s commitment is vital for the project’s implementation. Industry officials have said recently that Russia is considering changing the source of the gas supply to China and South Korea, using gas from the Republic of Sakha instead of Kovykta. In January 2004, Gazprom said there were ‘numerous violations’ in the Kovykta’s exploration and development license that would have to be resolved before it would participate. Gazprom has an outstanding offer to join the project from all the shareholders. Vekselberg, TNK-BP managing director, said Gazprom "is a little afraid to lose its position (as the gas export monopoly), but we don’t want to change Pipeline Gas Introduction to the Korean Peninsula Page 8 Dr Keun-Wook Paik (January 2005) anything." He said it might be possible to find an arrangement that would allow Gazprom to participate without taking an equity stake. 10


Gazprom strongly indicated that the gas export source for China and Korea could be the Chayandinskoye field rather than Kovykta field.13 Gazprom knows too well that the Chayandagas project is not ready for immediate export, and a compromise betweenTNK-BP and Gazprom is a very likely possibility. The elimination of the Mongolia route was a serious blow to South Korea, since the cost of either eastern route meant that the pipeline could not be as competitive as LNG shipped into Guangdong and Fujian provinces.

‘We’re ready to organise gas exports through Gazprom,’ he said, noting that while Gazprom could have ‘operational control’ it would not have absolute control.11 Considering that Gazprom has agreed to make a swap deal with Shell for its positioning in Sakhalin II’s LNG project,12 there is a possibility that TNK-BP might do the similar deal with Gazprom to minimize the entry time of pipeline gas to Northeast Asian region. Gazprom strongly indicated that the gas export source for China and Korea could be the Chayandinskoye field rather than Kovykta field.13 Gazprom knows too well that the Chayandagas project is not ready for immediate export, and a compromise betweenTNK-BP and Gazprom is a very likely possibility. 2. The pipeline route. During the third meeting of the coordinating committee for managing the Kovykta feasibility study, China asked that the western route of the gas pipeline (the Mongolian line) should be rejected. China seems to prefer the eastern route because:

• China prefers to minimize the political risks involved in transiting through Mongolia.

• The economic benefits brought by the pipeline could make the

Mongolians suddenly richer than inhabitants in China’s Inner Mongolia.

• China would be able to channel some of the economic benefits of

the pipelines to its Northeast region, areas in desperate need of economic stimulus.The Mongolian route is the most economic for each of the parties due to the easy terrain and relatively short distance to the main gas market. However, the discovery of the Sulige-6 field in the Ordos Basin provided the opportunity for the Chinese planners to reconsider their stance towards the Mongolian route. Sulige gas was good enough to be the main gas supplier for Beijing and Tianjin areas in the short term. The elimination of the Mongolia route was a serious blow to South Korea, since the cost of either eastern route meant that the pipeline could not be as competitive as LNG shipped into Guangdong and Fujian provinces.


It is worth noting that Gazprom’s confirmation on the Asia-Pacific direction export route was made soon after China’s decision to terminate the negotiations with western energy firms – Shell, ExxonMobil and Gazprom consortium – for the WEP (West-East Pipeline) project. The Russians want a $100/1,000 cm price, but eventually a compromise price is likely to come down to the range of $70-80/1,000cm, considering that Russia’s Energy Strategy 2020 envisages the domestic gas price will reach to $ 40-41 / 1,000 cm by 2006, and $ 59-64 / 1,000 cm by 2010.

South Korea’s preference is the Manzhouli II route since it would bypass North Korea, and the construction and maintenance costs would be cheaper than Manzhouli route I. 14However, a recent report has suggested that Gazprom does not support this route. During a Moscow meeting with Kogas in early August, Gazprom confirmed that the route towards Nakhodka and then a sub-sea pipeline to South Korea is being seriously considered. This route would bypass China, and the project would target Korea as the main buyer.15 It is worth noting that Gazprom’s confirmation on the Asia-Pacific direction export route was made soon after China’s decision to terminate the negotiations with western energy firms – Shell, ExxonMobil and Gazprom consortium – for the WEP (West-East Pipeline) project.16 3. The price of the gas. It will be the city gate price of the imported gas that will decide the fate of this Kovykta project, and difficult negotiations are continuing. The Russians want a $100/1,000 cm price, but eventually a compromise price is likely to come down to the range of $70-80/1,000cm, considering that Russia’s Energy Strategy 2020 envisages the domestic gas price will reach to $ 40-41 / 1,000 cm by 2006, and $ 59-64 / 1,000 cm by 2010.17 The Chinese would like the gas to be priced at $20-25/1,000cm, since consumers in North-eastern China cannot afford to pay more. According to Gazprom’s calculations, the production cost alone is $30/1,000cm, while transportation will cost at least $30/1,000 cm, excluding tax and a profit margin. Gazprom is unsure whether China could accept even the price of $70/1,000cm.


The drop in LNG prices heralded a new era in which Northeast Asia did not have to pay more than other regions. LNG suppliers were very unhappy about this price discount that wiped out the premium which Japan and Korea have paid for a long period.


During the first of half of 2003, the Sakhalin II project announced that a total of 2.8 mt/y LNG would be supplied to Japanese utilities such as Tokyo Electricity, Tokyo Gas, and Kyushu Electricity, starting from 2007. Sakhalin Energy Investment Co (SEIL) refused to expose anything related to the delivered gas price, choosing only to highlight the short distance from Sakhalin Islands to Japan.

During the first of half of 2003, the Sakhalin II project announced that a total of 2.8 mt/y LNG would be supplied to Japanese utilities such as Tokyo Electricity, Tokyo Gas, and Kyushu Electricity, starting from 2007. Sakhalin Energy Investment Co (SEIL) refused to expose anything related to the delivered gas price, choosing only to highlight the short distance from Sakhalin Islands to Japan. However, industry sources confirm that the price is about $3.5/mmbtu. As shown in Table 8, the average LNG price paid by Japan in 2002 was $4.27/mmbtu. The figure indirectly confirms that less than 20% discount was made.18 In other words, Japan received some discount from the Sakhalin LNG price.

In August 2003 when Indonesia’s Tangguh project was chosen as the POSCO & SK’s 1.15 mt/y LNG supplier, price was the most important factor. The price reported to the Korean government was as good as the Guangdong and Fujian LNG price. (In August 2004, Kogas decided to invite a bidding for 5 mt/y of LNG for 20 years from 2008 and quite a number of potential suppliers expressed their interest in supplying the LNG. However, no supplier is willing to offer Guangdong and Fujian an LNG supply price due to the combination of strong LNG demand from the United States and high oil prices.) In the context of low LNG prices, securing a pipeline gas price that is 20-25% cheaper than LNG is


PetroChina announced that the average gas price for the West-East Pipeline (WEP) will be Rmb1.327/cm (US $4.332 / mmbtu). This is a guideline price prepared by the State Development Planning Commission (since renamed the National Development and Reform Commission) for the WEP’s 12bcm gas. If the Chinese authorities change their stance and agree to accept the Mongolian route, the pipeline gas price to the Bohai Bay areas could be lower than $3/mmbtu, and there is a very strong possibility of setting the city gate price in Inchon at $3.0-3.2/mmbtu

.

. simply not possible. Even to secure a pipeline gas price of $3.0/mmbtu is a very tough target to achieve. PetroChina announced that the average gas price for the West-East Pipeline (WEP) will be Rmb1.327/cm (US $4.332 / mmbtu). This is a guideline price prepared by the State Development Planning Commission (since renamed the National Development and Reform Commission) for the WEP’s 12bcm gas. The guideline price is composed of Rmb0.45/cm ($1.47) as the wellhead price and Rmb0.877/cm (US $2.87 / mmbtu) as the transportation tariff. Pipeline Gas Introduction to the Korean Peninsula Page 12 Dr Keun-Wook Paik (January 2005).

Due to this expensive domestic pipeline gas price, power producers are refusing to sign the take-or-pay contract with PetroChina. The producers are arguing that a price exceeding Rmb1.1/cm is not acceptable. If the Chinese authorities change their stance and agree to accept the Mongolian route, the pipeline gas price to the Bohai Bay areas could be lower than $3/mmbtu, and there is a very strong possibility of setting the city gate price in Inchon at $3.0-3.2/mmbtu. A pipeline passing through Manzhouli will not offer the kind of price that the Mongolian route can provide, and this pricing issue will present difficulties in the negotiations over the introduction of Kovykta gas into China and Korea. The meeting between Gazprom and Kogas in early August 2004 in Moscow confirmed that Gazprom does not like CNPC’s price negotiation strategy and would like to give priority to the Nakhodka export route.


The initiative to export gas from East Siberia to Northeast Asia came from the Sakha Republic. As early as the 1960s the possibility of Yakutian gas exports to Japan was explored and promoted, but activities were suspended in the wake of the Former Soviet Union’s Afghanistan invasion in late 1979. In the late 1980s Korea’s Hyundai group revived the forgotten project, and in 1995 the preliminary feasibility study on Sakha gas development, funded by Russia and South Korea at $10m each, was eventually implemented. However, the outcome of this study was not encouraging, and no further steps were taken.

Kovykta gas to Nakhodka will be too expensive and a big question will be who will buy the expensive pipeline gas. The most likely possibility is that Gazprom will make a compromise, in order to protect the entry timing of Russia’s pipeline gas to Northeast Asian region. 1.1.2. Sakha gas exports to the Korean Peninsula The initiative to export gas from East Siberia to Northeast Asia came from the Sakha Republic. As early as the 1960s the possibility of Yakutian gas exports to Japan was explored and promoted, but activities were suspended in the wake of the Former Soviet Union’s Afghanistan invasion in late 1979. In the late 1980s Korea’s Hyundai group revived the forgotten project, and in 1995 the preliminary feasibility study on Sakha gas development, funded by Russia and South Korea at $10m each, was eventually implemented. However, the outcome of this study was not encouraging, and no further steps were taken. The conclusion was that Sakha gas exports to Korea were not feasible because of the remote location, harsh environment and poor economic rationale. However, the Sakha Republic now boasts a relatively large proven gas reserve (over 1 tcm), and argues it has enough proven reserves to justify a long distance, trans-national pipeline. According to Vasiliy Moiseyevich Efimov, then president of Sakhaneftegas, as of 1998 the registered C1 category reserves in the Vilyuisk region (10 fields: 437.8bcm) and Pipeline Gas Introduction to the Korean Peninsula Page 13 Dr Keun-Wook Paik (January 2005) Botuobinsk region (21 fields: 586.3bcm) were 1,000bcm. Besides this, the reserves of Chayandinskoye field in Botuobinsk region were estimated at 755bcm (previously 208bcm), of which 535bcm is exploitable. Already 64 wells have been drilled in the field. Desperate to become the main gas export source in the region, Sakhaneftegas has proposed a East-Siberian consortium based in the Irkutsk region, Sakha Republic and Evenki Autonomous region of Krasnoyarsk Krai in 1998.


The proposal is supported by Rosneft, the administration of the Chita region, JSC UES of Russia, the administration of the Evenki Autonomous region and Russia Petroleum. Interestingly, Sakhaneftegas has signed an agreement with Russia Petroleum for the joint development of Kovyktinskoye and Chayandinskoye fields, although the priority will be given to Kovyktinskoye. As Kovykta’s gas reserves are large enough to pursue a level of exports of 30bcm/y for 30 years, there is actually no need to make the Chayandinskoye gas field the back-up supply source for the project.

The proposal is supported by Rosneft, the administration of the Chita region, JSC UES of Russia, the administration of the Evenki Autonomous region and Russia Petroleum. Interestingly, Sakhaneftegas has signed an agreement with Russia Petroleum for the joint development of Kovyktinskoye and Chayandinskoye fields, although the priority will be given to Kovyktinskoye. At that time, the only way to remove any suspicion on the reliability of the proven reserves scale was to combine both Kovykta gas and Chayandagas. The significance of the proposal lay in the fact that the combined development of the Kovyktinksoye and Chayandinskoye fields would provide proven gas reserves enough to justify a 4000kmlong pipeline development. The combined or hybrid export scheme has two options, even though there is no difference in the pipeline section within the Chinese territory. The first is a 4,961km pipeline, of which the Russian section is 1,960km in length, and the two pipelines from Kovykta and Chayanda fields meeting at Bodajbo (adjacent to the northern tip of the Baikal lake). The second option is a 5,626km pipeline of which 2,2625km is in Russian territory. This second option gives the absolute priority to the Kovykta project as the Chayanda is connected as a back-up supply source. As Kovykta’s gas reserves are large enough to pursue a level of exports of 30bcm/y for 30 years, there is actually no need to make the Chayandinskoye gas field the back-up supply source for the project. The Chayandgas project could be pursued on its own though in terms of preparation, it is far behind the Kovykta project. However, significant work has been carried out during the last few years. First, on July 26th 2002 Sakhaneftegaz completed a preliminary feasibility study for a gas pipeline that will export gas from Chayandgas to Shenyang.19 The initial export volume will be 12- 15bcm/y and the figure could expand to 20bcm/y later. Second, the Central Commission for Reserves of the Russian Federation’s Ministry of Natural Resources approved the revised figure of Chayandagas proven gas reserves as 1,240bcm as of 2002. Thirdly, in October 2002, Gazprom and the Sakha Republic Government signed a framework agreement on forming a joint venture to make a tender bid for a development license for the Chayandinkskoye and other fields in the Sakha Republic.


The Sakha Republic government’s response was to form a strategic partnership with Gazprom, which itself has neglected. If the figures in Table 10-15 are proved after exploration, Sakhalin offshore could produce enough gas to be exported not only to Japan, but also to other gas markets in Northeast Asia.

Gazprom’s strategic alliance with the Sakha Republic Government has special implications. In early 2002, the Sakha Government reported to the local legislative assembly that Yukos has secured a 47% controlling stake in Sakhaneftegas (which was originally controlled by Sakha Republic government). Yukos’ initiative forced the Sakha Republic Government to be a minor shareholder. The Sakha Republic government’s response was to form a strategic partnership with Gazprom, which itself has neglected. 1.1.1. Sakhalin Gas exports to the Korean Peninsula In 1991 the Development of Yakutian and Sakhalin Gas and Mineral Resources of Eastern Siberia and the USSR Far East, the so-called Vostok (East) Plan, was announced. The key element of the plan was the construction of a 3230km gas pipeline from Sakhalin across Russian territory through North Korea to South Korea, and a 3050km pipeline from Yakutsk to Khabarovsk. Like Sakha gas, Sakhalin offshore development has been discussed since the 1960s, but until the early 1990s no real development was made partly because of uneasy relations between the former Soviet Union and Japan, and partly because of the costbenefit analysis. As shown in Table 13-14, the gas reserves in Sakhalin I (owned by Exxon 30%, Sodeco 30%, Roseneft and Sakhalinmorneftegas 20%, and ONGC Videsh Ltd 20%), and Sakhalin II (Shell 55%, Mitsui 25%, and Mitsubishi 20%) stand at 485bcm and 460bcm respectively. Besides this, the ExxonMobil-Texaco consortium estimates the gas reserves of the Kirinskya prospect in Sakhalin Block III at 720bcm. If the figures in Table 10-15 are proved after exploration, Sakhalin offshore could produce enough gas to be exported not only to Japan, but also to other gas markets in Northeast Asia.24




The pipeline was composed of three sections: the first section, 625km from Katangli to Prigorodnoye, the second section, 1300km from Prigorodnye to Niigata via an offshore route, and the last section 300km from Niigata to Tokyo. The contracts with the Japanese utilities have eliminated the possibility of a pipeline gas supply from Sakhalin I to Japan until 2013-14. Thus, it is no co-incidence that Sakhalin I began to float the idea of gas supply to the north-eastern provinces of China soon after SEIC’s LNG deal with the Japanese utilities.

Japan is interested in the Sakhalin projects, despite long standing territorial disputes between Japan and the Russian Federation. Around 1998, Japex and four Japanese steel companies investigated the possibility of building a 2,225km pipeline connecting the Sakhalin Islands with mainland Japan. The pipeline was composed of three sections: the first section, 625km from Katangli to Prigorodnoye, the second section, 1300km from Prigorodnye to Niigata via an offshore route, and the last section 300km from Niigata to Tokyo. In May 1997, minister Shinji Sato of Japan’s Ministry of International Trade and Industry (MITI) announced that Japan was considering the Sakhalin offshore gas import pipeline. During April 1999 and Spring 2002, both Exxon Japan Pipeline and Japan Sakhalin Pipeline (JSPC) carried out a feasibility study at a cost of $40m.

The contracts with the Japanese utilities have eliminated the possibility of a pipeline gas supply from Sakhalin I to Japan until 2013-14. Thus, it is no co-incidence that Sakhalin I began to float the idea of gas supply to the north-eastern provinces of China soon after SEIC’s LNG deal with the Japanese utilities. The idea of a gas supply to China was 27 JSPC is composed of Japex 45%, Itochu 23.1%, Marubeni-Itochu Steel Inc. 18.7%, and Marubeni Corp 13.2% and was the operator in efforts to develop the FS.28 Russian Petroleum Investor, Nov/Dec 2002. On June 10, 2004, it was announced that the Sakhalin-1 Project signed Letters of Intent to sell natural gas from Sakhalin offshore fields with two buyers in Khabarovsk Krai, Russia. According to the operator for the Project, Exxon Neftegas Limited (ENL), the Sakhalin-1 Participants


Gas sales to buyers in Khabarovsk Krai could grow to up to 3 billion cubic meters of gas per year by 2009. The government of President Moo-Hyun Roh has shown a serious interest in the option of a Sakhalin gas supply to the Korean Peninsula by pipeline via North Korea.

will endeavor to begin gas deliveries to OAO Khabarovskenergo and OAO Khabarovskkraigas as early as the start of the 2005-2006 heating season. Gas sales to buyers in Khabarovsk Krai could grow to up to 3 billion cubic meters of gas per year by 2009. See, http://www.sakhalin1.com/en/index.htm & Interfax Petroleum Report, June 10-16, 2004. Author interviewed a number of Russian specialists and the suggested price hovers $60-65 plus VAT. Pipeline Gas Introduction to the Korean Peninsula Page 19 Dr Keun-Wook Paik (January 2005) originally promoted by Rosneft, a shareholder in the Sakhalin I project. The Sakhalin I consortium plans to resume the talk with the Chinese, which were halted in 2002 over disagreements on the gas price .

The government of President Moo-Hyun Roh has shown a serious interest in the option of a Sakhalin gas supply to the Korean Peninsula by pipeline via North Korea. The socalled ‘peace pipeline’ is also supported by the United Nations. Compared with the Kovykta gas project, the Sakhalin pipeline gas project is far behind in terms of a feasibility study and marketing, despite Sakhalin II’s LNG scheme being well advanced. Even if a political breakthrough is made with


In the wake of the collapse of the Cold War era, the energy relationships among the countries in Northeast Asian region have changed significantly. Korea’s interest in a trans-national pipeline gas dates back to the late 1980s when Hyundai Group founder Jung Ju-Young began to explore the possibility of Sakha gas development and a gas pipeline to the Korean Peninsula.

regard to the DPRK nuclear crisis, special efforts will be required to move the Sakhalin gas project to the same level of preparation as the Kovykta gas project. In a recent seminar held in Seoul, the Russian government confirmed that the following pipeline gas supply options are being reviewed:

• Sakhalin offshore gas to South Korea and Chayandagas to Northeast China

• Sakhalin offshore gas to both China and South Korea

• Kovykta gas and Chayandagas to Northeast China and South

Korea The details of these options will be reviewed by Russia’s Ministry of Industry and Energy and Gazprom until February 2005, and the development plan of Unified Gas Supply System in East Siberia and Russia’s Far East will be finalised in Spring 2005.32 1.2. North and South Korea’s approach to pipeline gas development 1.2.1. South Korea’s initiative In the wake of the collapse of the Cold War era, the energy relationships among the countries in Northeast Asian region have changed significantly. Based on the Northern Policy adopted by the Ro Tae-Woo government, South Korea established diplomatic relationships with the Former Soviet Union (FSU) in September 1990, and with China in August 1992 respectively. This altered political environment opened the door for South Korea to consider the options of energy cooperation with these two countries. Korea’s interest in a trans-national pipeline gas dates back to the late 1980s when Hyundai Group founder Jung Ju-Young began to explore the possibility of Sakha gas development and a gas pipeline to the Korean Peninsula. In July 1992, a Korean consortium led by Korea Petroleum Development Corporation (PEDCO, now Korea National Oil Corp: KNOC) was established, and Daewoo Corp became the driving


force from the private sector in pursuing this Russian gas import project. In November 1994, a preliminary feasibility study between Korea, Sakha Republic and Russia, was signed. The 12 month study cost $20m, consisting of $10m in the form of data provision from Russia and a $10m cash payment from Korea. The route was as follows – Gas fields in south-western part of Sakha Republic - Yakutsk - Tynda - Blagoveshensk - Khabarovsk - Vladivostok - DPRK – ROK, a 5,143km length, of which the Russian section was 4,383km. It is worth noting that in 1995, there were only five gas fields with over 100bcm (C1 reserves) in Sakha Republic. At that time, Chayandinskoye’s proven reserves were only 209.5bcm, and Chayandagas was the biggest gas field. It can be compared with the Tarim Basin’s Kela-2 field, with only around 250bcm proven reserves, which supplies China’s 4,000km west-east pipeline. However, Chayandinskoye’s reserves significantly increased to 755bcm in 1997 and eventually to 1240bcm in 2002.

In December 1995 the study was completed and, due to the poor economics of the long distance pipeline development, the verdict was not positive. No further steps were taken. While KNOC failed to take further steps for pipeline gas development, Kogas saw pipeline gas imports as an opportunity to expand its business domain. Since Irkutsk Oblast had asked Korean companies to develop its giant gas field in 1994, Kogas decided to take an initiative towards Irkutsk region’s Kovyktinskoye gas field development. A Korean Consortium composed of Kogas, PEDCO, Kohap, Halla, LG,Hyosung,


It was the Hanbo group that had made the initial running for this giant gas project. In early 1996, the Hanbo group (later declared bankrupt due to the financial strain from its ambitious steel plant building) set up the East Asia Gas Company (EAGC) as its sole subsidiary, with an initial capital of $12m, to act as a vehicle for its participation in Irkutsk region gas development. In July 1996, EAGC announced that the Hanbo group had bought 27.5% of equity of Russia Petroleum having exploration and development license in Kovyktinskoye and Verkhnechonskoye gas and oil fields in Irkutsk region

. Daewoo, and Yukong (which joined in April 1996 and the company name changed as SK) was established in mid-1995. Prior to this consortium, both Halla and Kohap were competing with each other to take the initiative for the Kovyktinskoye gas project.

It was the Hanbo group that had made the initial running for this giant gas project. In early 1996, the Hanbo group (later declared bankrupt due to the financial strain from its ambitious steel plant building) set up the East Asia Gas Company (EAGC) as its sole subsidiary, with an initial capital of $12m, to act as a vehicle for its participation in Irkutsk region gas development. In July 1996, EAGC announced that the Hanbo group had bought 27.5% of equity of Russia Petroleum having exploration and development license in Kovyktinskoye and Verkhnechonskoye gas and oil fields in Irkutsk region. A total of $44m, of which $25m was for the 27.5% equity stake and $19m for a three year loan to Sidanco, was invested.


Due to Hanbo group’s bankruptcy in early 1997, EAGC had difficulty in keeping the 27.5% equity stake. Consequently, the 20% was re-sold to Sidanco in November 1997 when BP decided to invest $571m in Sidanco.

Due to Hanbo group’s bankruptcy in early 1997, EAGC had difficulty in keeping the 27.5% equity stake. Consequently, the 20% was re-sold to Sidanco in November 1997 when BP decided to invest $571m in Sidanco.

• Kogas believed that the Korean gas market, with a capacity of 10 bcm pipeline gas import, would provide significant leverage at negotiations with Russian gas producers. The possibility of 10bcm gas market provision in the early stage of this trans-national pipeline development was the key point, and CNPC was respecting Kogas position as the gas market provider. It would have been ideal if the Kogas consortium and EAGC made a compromise by joining forces, but the opportunity was missed;

• The Kogas consortium was slow to grasp the importance of

securing an equity position in the giant Kovyktinskoye field as the consortium was suspicious of the real scale of the field’s proven gas reserves. Now it is clear that Kovyktinskoye gas field’s reserves are large enough to satisfy not only the Irktusk region itself but also both China and Korea’s gas demand;

• The Kogas consortium was reluctant to admit that EAGC’s

initiative was correct. When EAGC announced its equity positioning in Russia Petroleum, the Kogas consortium, together with the Ministry of Trade, Industry and Energy (MOTIE), lobbied strongly against approval being given. Kogas had virtually no experience in upstream business, and they argued that importing pipeline gas is solely a downstream business. This only confirms that at that time Kogas consortium did not have a clear picture of its equity positioning in the upstream sector in the major transnational pipeline development. Kogas consortium’s preference was to pursue the feasibility study first and to make a decision later. In 1998, a Japanese consortium led by Japan National Petroleum Corp (JNPC) and Sumitomo Corp took an initiative by proposing a five country feasibility study on a pipeline connecting the Kovykta gas field with China, Korea and Japan via Mongolia.


Neither the PRC authorities nor BP took the role of Japan as a coordinator of the study seriously since Japan was not offering any gas market for the development. In other words, two important players in the negotiations did not see the necessity for accepting the Japanese consortium’s(led by Sumitomo Corp and JNOC Corp) proposal to protect their carried interest in the project. A breakthrough of Kovykta gas project can be made if governmental approval is given by the Chinese and Korean governments in 2005, and this looks realistic due to the changing political environment.

However, due to the failure to reach consensus, negotiations collapsed at the end of 1998. Neither the PRC authorities nor BP took the role of Japan as a coordinator of the study seriously since Japan was not offering any gas market for the development. In other words, two important players in the negotiations did not see the necessity for accepting the Japanese consortium’s(led by Sumitomo Corp and JNOC Corp) proposal to protect their carried interest in the project. A unique opportunity to start a five-country project in Northeast Asia was missed. The collapse of the negotiations in 1998 meant that the region had little choice but to return to the formula of Sino-Russian cooperation. Without Korea’s participation, it would have been a bilateral project. In May 1999, Korea expressed its interest in the Sino- Russian feasibility study on the Kovykta gas project, and its participation laid the ground for a trilateral project. In November 2000, Kogas, CNPC and Russia Petroleum signed an agreement for a full feasibility study on Kovykta gas development. In January 2001, the Kogas Consortium was restructured, from seven to nine members.Dr Keun-Wook Paik (January 2005) present, Gazprom’s stance towards the project and the border price issue are the two major stumbling blocks for the project. A breakthrough of Kovykta gas project can be made if governmental approval is given by the Chinese and Korean governments in 2005, and this looks realistic due to the changing political environment. Even though Roh Moo-Hyun government has paid special attention to Sakhalin pipeline gas option for the settlement of the DPRK nuclear crisis during the first two years of his presidency, the US administration did not show its serious interest in accepting the formula of DPRK’s disposal of nuclear in return for economic and energy aid. The US administration’s rigid stance towards DPRK regime has prevented progress on the Sakhalin pipeline. This situation is forcing the Roh Moo- Hyun government to reconsider the Kovykta gas option despite Gazprom’s UGSS (Unified Gas Supply System) plan.


Korea’s Ministry of Commerce, Industry Energy (MOCIE) decided to allow Korea Electric Power Corp (KEPCO) to pursue its own 5.7 mt/y of LNG supply contract in November 2004. Assuming KEPCO pursue this 5.7 mt/y separately, there will be a real difficulty in finding a sizable gas market in South Korea. At present, the DPRK authorities are not willing to change their stance towards the KEDO project and to accept the pipeline gas option.

If South Korea’s commitment to the Kovykta gas project were to be made without delay, it could lead to an introduction of Russia-China- Korea energy alliance. The issue of energy supply to DPRK can be solved by a sideline pipeline from Dandong to DMZ via Pyongyang with a capacity of 1.5 bcm per year, and this compromise would also solve the problem of energy supply security once and for all. Korea’s Ministry of Commerce, Industry Energy (MOCIE) decided to allow Korea Electric Power Corp (KEPCO) to pursue its own 5.7 mt/y of LNG supply contract in November 2004. Assuming KEPCO pursue this 5.7 mt/y separately, there will be a real difficulty in finding a sizable gas market in South Korea. The Russian government has been very slow to understand this situation, and it remains to be seen how quickly the Russian authority will take steps to save this gas market in South Korea. If a quick response is made, it may still be possible to introduce pipeline gas to both China and Korea by around 2010-2012. If not, another ten years delay from 2010 will be inevitable. 37 UN’s Working Group on Energy for DPRK has been evaluating these pipeline introduction options. The group was established and is chaired by Mr. Maurice Strong, Special Envoy to Secretary General of the United Nations to DPRK. 38 China Daily, January, 1, 2005. 39 Nihon Keisai Shimbun, Dec 14th, 2004. 1.2.2. The DPRK’s stance towards pipeline gas The DPRK authorities have shown reluctance to express any interest towards the idea of pipeline gas despite the fact that they have been studying the import option since the mid-1990s. It took a while for DPRK authority to understand that the KEDO project, which aims at producing 2000 MW capacity electricity, cannot be completed without the transmission line development. At present, the DPRK authorities are not willing to change their stance towards the KEDO project and to accept the pipeline gas option.


Assuming that 1.5bcm/year of natural gas would be allocated to the DPRK as a transit fee plus subsidy, pipeline gas would deliver at least a minimum level of gas and power to a number of major cities.

However it is likely that they will take the pipeline gas option seriously once the nuclear crisis has been permanently settled. The scale of benefit in terms of DPRK’s economic development from the introduction of a long distance gas pipeline passing through its territory will be very different from that of the KEDO project. Assuming that 1.5bcm/year of natural gas would be allocated to the DPRK as a transit fee plus subsidy, pipeline gas would deliver at least a minimum level of gas and power to a number of major cities. Unlike the KEDO project, which did not allow any role for both Russia and China, this pipeline project envisages a major role for both countries. To observe the progress of trans-national natural gas pipeline projects in Northeast Asia, the DPRK established a Natural Gas Research Society, DPR Korea (NGRS DPRK), under the leadership of DPRK’s Asia Pacific Peace Committee in 1998. NGRS DPRK has sent its delegate to the 1998 Ulaan Baator (4th) and 1999 Yakutsk (5th) Northeast Asian Gas & Pipeline Forum conferences.


Later however, Kogas argued that the firm’s work on the DPRK section could not progress since the DPRK authorities had demanded Kogas’s preliminary commitment that the pipeline would pass through DPRK territory. Kogas could not take any further step due to this condition. The agreement gave FSI Energy exclusive transit rights with regard to the pipeline from Northern Sakhalin to the Korean Peninsula. Under this agreement, FSI Energy needed to identify the source of natural gas supply by 1 June 2003.

In February 2001 Kogas announced a joint study on pipeline gas, and in September 2001 South Korea announced that it had reached a preliminary agreement with the DPRK on a joint feasibility study for a pipeline passing through DPRK territory. Later however, Kogas argued that the firm’s work on the DPRK section could not progress since the DPRK authorities had demanded Kogas’s preliminary commitment that the pipeline would pass through DPRK territory. Kogas could not take any further step due to this condition. MOU with a Dutch Consortium On April 6, 2001, the NGRS DPRK signed an unpublished 18 point MOU with a consortium of three Dutch trading companies (HS International Trading, Tamalone International, and Boscalis International). The MOU gave the consortium exclusive rights to build the North Korean portion of the pipeline from the Russian border to the South Korean border. DPRK expected that the Dutch consortium would act as an intermediary in promoting the pipeline project with ExxonMobil, Japanese companies, and South Korean gas officials. The MOU envisaged the construction of three gas-fired power stations along the pipeline route with a total capacity of 500 MW (2 units of 200 MW + 1 unit of 100 MW).40 Agreement: KoRus Project41 On 3 August 2002, FSI Energy signed an agreement with Chairman Kyung-Bong Kim, NGRS DPRK. The agreement gave FSI Energy exclusive transit rights with regard to the pipeline from Northern Sakhalin to the Korean Peninsula. Under this agreement, FSI Energy needed to identify the source of natural gas supply by 1 June 2003. FSI Energy was seeking the support of Congressman Curt Weldon (Republican, Pennsylvania), chairman of the House Armed Services Committee. A Korea’s Weekly Sisa Journal has reported on this project comprehensively : 42 FSI Energy is the driving force behind the KoRus pipeline project which aims at supplying Sakhalin gas to North and South Korea by pipeline. In late May 2002, a US delegation composed of 12 congressman and led by Congressman Weldon planned to visit Pyongyang but the DPRK authorities refused to issue visas. On August 3rd, 2002, according to Dr. Roy Kim’s interview with the Sisa Journal,


The story claimed that US Department of Energy secretary Abraham had helped the introduction of US DOE officer to review the project, and FSI Energy had applied for a $10m grant for the feasibility work.This KoRus project was officially presented at the KIEP-KEI policy Forum on Northeast Asian Energy Cooperation conference held in Washington D.C. on 7 January 2003. It is worth noting that the North-South Korea dialogue in June 2000 offered an opportunity for both Koreas to discuss the pipeline routes from China and Russia. In early 2001 Kogas proposed that the DPRK authorities look into the possibility of laying a gas pipeline from the Kovykta gas field through North Korea.

FSI Energy signed a twelve clause-agreement with DRPK Natural Gas Research Society (led by Prof. Kyung-Bong Kim, former head of DPRK Academy of Science) with regard to the exclusive right of pipeline construction development for the DPRK section. This agreement is conditional on gas supply source securing until June 1st 2003 and approval from both governments. The story claimed that US Department of Energy secretary Abraham had helped the introduction of US DOE officer to review the project, and FSI Energy had applied for a $10m grant for the feasibility work.This KoRus project was officially presented at the KIEP-KEI policy Forum on Northeast Asian Energy Cooperation conference held in Washington D.C. on 7 January 2003. However, the project was not taken seriously by major institutions in the United States and South Korea. The KoRus project failed to identify and secure the gas supply until 1 June 1 2003. The project has no supply source and as a result cannot be implemented. Both the 2001 MOU and 2002 agreement indirectly confirmed that the DPRK authorities were interested in pipeline gas, but were very ignorant of the pipeline gas business. DPRK authorities were not ready to officially discuss the issues with Washington and Seoul since this would potentially signal willingness to compromise with respect to the settlement of the KEDO project. It is worth noting that the North-South Korea dialogue in June 2000 offered an opportunity for both Koreas to discuss the pipeline routes from China and Russia. In early 2001 Kogas proposed that the DPRK authorities look into the possibility of laying a gas pipeline from the Kovykta gas field through North Korea. The relevant document was sent to the DPRK government in early February 2001, and a Kogas delegation led by Jong-Sool Kim, then a senior vice president of Kogas, visited Pyongyang in September 2001. A proper feasibility study on the DPRK section was not possible as the DPRK authorities again demanded that the South Korean government make an advanced commitment that the pipeline would not bypass the DPRK’s territory, a demand which could not be accepted. 1.3. The Prospects of Energy cooperation between the two Koreas South Korea is ideally positioned to help revitalise the sluggish energy industry in North Korea. As of 2002, South Korea’s GNI scale is over


DPRK was contracted to receive a 0.5mt/y worth of heavy oil until the completion of the KEDO project, based on the 1994 Geneva Agreement. The DPRK remained at the amount until 2002, when the second DPRK nuclear crisis occurred. With this heavy oil supply, the operation of Seonbong Thermal Power Plant was possible during the 1990s. Fully fledged energy cooperation between the two Koreas seems unlikely until the settlement of the second DPRK nuclear crisis .

13 times of that of DPRK (See table 21), and as of 2000, South Korea’s crude oil import reached 894 million barrels, while DPRK imported only 2.9 million barrels (See table 22) In terms of primary energy supply, the ratio between South Korea and DPRK was only 3.9 in 1990 but this figure became 12.3 in 2000 (See table 23) Tables 24-26 show that DPRK’s energy supply and consumption structure could change significantly, with a significant decline of the role of coal, and a big increase in oil and gas. DPRK’s energy situation is currently extremely dire. Even a relatively small volume of oil supply to DPRK would make a big difference. DPRK was contracted to receive a 0.5mt/y worth of heavy oil until the completion of the KEDO project, based on the 1994 Geneva Agreement. The DPRK remained at the amount until 2002, when the second DPRK nuclear crisis occurred. With this heavy oil supply, the operation of Seonbong Thermal Power Plant was possible during the 1990s. However, even then, the plant could only be run at 30% capacity. Currently the power generation volume from this plant stands at 1,700GWh, less than 10% of DPRK’s total power generation volume. Fully fledged energy cooperation between the two Koreas seems unlikely until the settlement of the second DPRK nuclear crisis . Nonetheless, energy cooperation is moving from a remote possibility to a potential reality. Pipeline gas into the Korean peninsula, LNG and LPG supply to North Korea, electricity supply from either Russia or South Korea to North Korea, coal and mineral resources development cooperation; and joint exploration and development of North Korea’s offshore oil and gas resources are all potential areas for substantive cooperation. Table 26 is the projection made by Korea Energy Economics Institute for DPRK’s primary energy consumption until 2020. The projection envisages a significant growth of both oil and gas consumption.




Energy cooperation between South and North Korea is a very real possibility. When the option of Sakhalin gas supply to the Korean Peninsula was floated at the beginning of 2003, there was a very strong resistance from Kogas, the main market provider in South Korea, and the conservative Ministry of Commerce, Industry and Energy (MOCIE).

Pipeline gas cooperation Energy cooperation between South and North Korea is a very real possibility. Unlike the Kim Dae-Jung government which focused on East Siberian gas supply and Sakhalin LNG supply to South Korea, the Roh Moo-Hyun government has shown interest in a Sakhalin pipeline gas to the Korean peninsula. The ‘gas for peace’ formula has been laid out by National Security Advisor Jong-Il Ra. The FT reported that : …thermal power stations drawing from Russian gas would provide a peaceful alternative to Pyongyang’s nuclear programme… This is one of the possibilities we are looking at… Gas could be drawn from either Irkutsk or Sakhalin. Advisor Ra added that Seoul’s plans for a gas pipeline were at early stage and had not been discussed in detail with its allies or North Korea. Reportedly, during a recent visit to Pyongyang (May 2004), Mr. Strong met DPRK Military Commission Chairman Jong-Il Kim, and both sides agreed that the United Nations would study the options of long term energy and economic aid to DPRK. Mr. Strong made it clear that the DPRK authorities should provide the UN with economyrelated information if the DPRK wanted to win UN-led aid, and Chairman Kim unexpectedly agreed to provide this information. Energy specialists for the UN group will mainly come from Japan and Korea, while the economic specialists will come from the United States.Six party member countries will also be asked to send specialists..45 These reports suggest there is a strong chance that the inter-Korean cooperation on pipeline gas could be a reality. When the option of Sakhalin gas supply to the Korean Peninsula was floated at the beginning of 2003, there was a very strong resistance from Kogas, the main market provider in South Korea, and the conservative Ministry of Commerce, Industry and Energy (MOCIE). However, the adoption of a compromise route for Kovykta gas (Kovykta – northern line – Skovorodino – Heilongjiang and Liaoning province) and the delivery to Inchon via the Yellow Sea with a separate branch line constructed from Dandong to DPRK means the branch line development would not affect the main trunk pipeline development at all.


In April 2004, South Korea’s LPG firms decided to supply LPG to the Kaesung Industrial Complex. Although detailed plans are not available yet, the project is thought likely to handle a supply of 250 tonnes of LPG per day, 6,500 tonnes of LPG per month, and envisages a 200-500 tonne storage facility within the Kaesung Industrial Complex. The pipeline development would have cost in the region of 50-60 billion and Kogas suggested that some of the funding should come from the Inter-Korean Cooperation Fund..

LPG and LNG supply cooperation In South Korea, the completion of a natural gas trunk pipeline network was good news for natural gas expansion, but very bad news for LPG business. The LPG business in South Korea has already reached saturation stage and urgently needs to find a new market for the industry’s survival. LPG supply to North Korea offers a very attractive opportunity for market development. In April 2004, South Korea’s LPG firms decided to supply LPG to the Kaesung Industrial Complex. Although detailed plans are not available yet, the project is thought likely to handle a supply of 250 tonnes of LPG per day, 6,500 tonnes of LPG per month, and envisages a 200-500 tonne storage facility within the Kaesung Industrial Complex. The LPG industry projects that LPG sales will initially be 200tonnes per month, 1,000 tonnes per month once the project is on track, and in 2006 the scale will reach to 4,000 - 6,000 tonnes per month. It is also worth noting that Kogas explored the possibility of supplying LNG gas to the Kaesung Industrial Complex much earlier. In August 2001, the Chosun Ilbo reported that Kogas had lobbied to supply 18,000 tonnes of natural gas (5.9 billion Korean won or $4.6m) to North Korea from the beginning of 2003, gradually increasing the supply up to 0.71mt, worth 210 billion Korean won or $161.5m by 2009. Kogas had undertaken a 45 Joong-Ang Ilbo, 19 May, 2004 & June 20, 2004. The pipeline development would have cost in the region of 50-60 billion and Kogas suggested that some of the funding should come from the Inter-Korean Cooperation Fund. According to the feasibility study, the best supply network would involve a pipeline connecting the Grand Unification Bridge in the South with the Kaesong Industrial Complex across the DMZ. The two Koreas have been promoting the construction of a large-scale industrial estate in an area contiguous to Kaesong in their joint efforts to expand inter-Korean economic cooperation.


MOCIE said however, that it had never reviewed the option of supplying natural gas to the Kaesong Industrial Complex, and that the Kogas’s feasibility work would not necessarily be adopted as government policy. This was carried out by a local engineering firm. As a LNG supply option would require an extension of pipeline from South to the North, the LPG option would be somewhat easier to handle. In the short term perspective, LPG option is easier to be accepted by both North and South.

According to the Chosun Ilbo, in July 2001 the South Korean Ministry of Unification gave a green light to Kogas to contact the DPRK. In the same month the Ministry of Commerce, Industry and Energy (MOCIE) minister Jae-Shik Chang said that the government would be able to review the supply of electricity to North Korea if the North was positive about inter-Korean economic cooperation. However, the minister’s remarks invited criticism from the opposition party (GNP) and the United States. MOCIE said however, that it had never reviewed the option of supplying natural gas to the Kaesong Industrial Complex, and that the Kogas’s feasibility work would not necessarily be adopted as government policy. This was carried out by a local engineering firm. This news confirmed that, without a breakthrough in the political tensions, even LNG supply to the DPRK is not an easy option. At the beginning of 2003 when the concept of Sakhalin gas supply to the Korean Peninsula received coverage by the Korean media, both Kogas and MOCIE floated the concept of LNG supply to DPRK again. Both argued that a pipeline passing through DPRK territory would not be acceptable due to concerns over energy-supply security, but that LNG supply from ROK to the DPRK could be considered. As a LNG supply option would require an extension of pipeline from South to the North, the LPG option would be somewhat easier to handle. In the short term perspective, LPG option is easier to be accepted by both North and South. Electricity supply cooperation In early April 1999, KEPCO (Korea Electric Power Corp) president Chang Young–Shik announced that DPRK leader Jong-Il Kim had asked Hyundai Group founder Ju-Young Chung to build a 100MW capacity power plant nearby Pyongyang in late October 1998. Besides this, KEPCO was also planning to pursue another independent power plant development in a port city Haejoo (Hwanghae Namdo), once the Haejoo Industrial Complex (HIC) plan was agreed between Hyundai Group and the DPRK authorities.


After the historic summit meeting between President Dae-Jung Kim and Chairman Jong- Il Kim in June 2000, the issue of electricity was officially discussed during the 4th ministerial meeting held in Pyongyang. In this meeting, the DPRK authorities asked ROK to provide them with 2,000MW worth of electricity, of which the immediate provision of 500MW electricity was given priority.

Mr Chang added that the state firm was also considering the option of supplying electricity to HIC by constructing a 80km power transmission line between Moonsan and Haejoo, rather than developing an independent power plant in Haejoo After the historic summit meeting between President Dae-Jung Kim and Chairman Jong- Il Kim in June 2000, the issue of electricity was officially discussed during the 4th ministerial meeting held in Pyongyang. In this meeting, the DPRK authorities asked ROK to provide them with 2,000MW worth of electricity, of which the immediate provision of 500MW electricity was given priority.

• In October 2001 a memorandum was signed between Vostokenergo and a DPRK delegation led by Power and Coal Industry deputy minister Nam-Chil Park in Khabarovsk, after discussions over Russian electricity supply to the DPRK (based on available electricity (2-4%) from Primorskii Krai. Both parties also agreed to have a second DPRK-Russia working level meeting in Vladivostok to discuss technical issues, such as the development of a transmission line between Khasan and the DPRK, voltage conversion facility construction, and the electricity supply volume and price.

• In February 2002, Chairman Jong-Il Kim asked about Russia’s

electricity supply to DPRK during his meeting with the Russian Ambassador and then RFE region’s presidential representative (plenipotentiary) Constatin Fulikovsky when the later visited DPRK. Following this, Power and Coal Industry Minister Tae-Rok Shin met Vostokenergo director general Victor Minakov’s deputy to discuss the signing of an 49 Joong-Ang Ilno, Decemebr 19, 2000. 52 In July 2000, when President Putin visited Pyongyang, the DPRK-Russia Economic Cooperation Co-operation Committee discussed energy co-operation.


In August 2002, the third summit between Chairman Jong-Il Kim and President Putin was held in Vladivostok. Chairman Kim asked Russia to supply electricity. Both leaders also discussed the issue of nuclear power plant development in the border area of DRPK and Russia and the joint use of the electricity.

In September 2000, Power & Coal Industry Minister Tae-Rok Shin visited Russia and discussed the related projects. In August 2001 when Chairman Jong-Il Kim visited Russia, the countries adopted a Moscow Declaration including the refurbishment of DPRK’s thermal power plants and officially announced power sector co-operation between the two countries. In August 2002, the third summit between Chairman Jong-Il Kim and President Putin was held in Vladivostok. Chairman Kim asked Russia to supply electricity. Both leaders also discussed the issue of nuclear power plant development in the border area of DRPK and Russia and the joint use of the electricity.

• In April 2002, DPRK Cabinet Deputy Premier Chang-Deok Cho visited Russia and proposed the exchange of 400MW scale electricity in return for joint logging and construction manpower provision. He also discussed a power transmission line project linking southern Primorskii region with the DRPK.

• In September 2002, a memorandum among ACE Engineering Inc (S. Korea), Korea National Energy Committee (DPRK), and Vostokenergo and Energy System Institute (Russia) was signed for the preliminary FS on Northeast Asian region’s Electric Power Interconnection.

The concept of electricity supply from Primorskii Krai to the DPRK is as follows: The basic concept is Russia – DPRK Interconnection line Development

• Section: Vladivostok – Khasan – Chongjin • Transmission line capacity: AC 500 KV • Length: 375 km • Power Generation Installation Capacity: 500 MW & 3.0 billion

KWh • Capital Cost: $130-150m


On top of this pilot project, there is also a relatively big project - the so-called Podkovalnikov commissioned study which covers the inter-connection of Amur & Khabarovsk – Primorskii – DPRK and ROK. The core problem facing this power project lies in the financing. Who is going to finance it? The DPRK authorities may expect South Korea to be the main financier, but this will be difficult to achieve until a breakthrough in the North and South relationship is made.

Both Primorskii Krai Administration and DPRK authority are anxious to initiate this project development, but both parties do not have the financing source. On top of this pilot project, there is also a relatively big project - the so-called Podkovalnikov commissioned study which covers the inter-connection of Amur & Khabarovsk – Primorskii – DPRK and ROK. Transporting surplus electricity from Russia requires a large amount of investment, and the DPRK authorities are expecting the ROK to take part in the project. It is not surprising that Korea Energy National Committee Secretary General Park Seong-Hee argued during the Northeast Asia Power Network Connection Symposium held in Seoul in May 2004 that “the power network connection project among the six countries in Northeast Asian region should move to the implementation stage, and the project will not only help to ease the energy shortage problem but will also realise cooperation among the states in the region”. He added that “the above mentioned Russia-DPRK interconnection project reached the implementation stage”.55 The core problem facing this power project lies in the financing. Who is going to finance it? The DPRK authorities may expect South Korea to be the main financier, but this will be difficult to achieve until a breakthrough in the North and South relationship is made. It is worth noting that in early December 2004 both the North and South authority agreed that the method of electricity supply to Kaesung Industrial Complex. Korea Electric Power Corp has already completed the site investigation and expects to supply the electricity from late January 2005. The initial scale of power supply will be 15 MW but it will increase to 100 MW by 2007. Coal and mineral resource development cooperation In 2003, South Korea’s Mining Promotion Corporation and North Korea’s Samcheoli Company agreed a joint investment In the development of graphite deposits in Jeongchon, Hwanghae South Province in DPRK. At present, the two sides are also planning to pursue joint development of iron ore deposits in Moosan, Hamkyung North Province, gold deposits in Woonsan, Pyongan North Province, and Bookboo coal deposits in Eundeok, Hamkyung North Province. A total


Coal is a main energy source in the DPRK and its important role is unlikely to change in the foreseeable future. In the DPRK, there are quite significant coal reserves but the quality of coal is not high. Until the early 1990s, the DPRK used to receive 2 mt/y of crude oil from the FSU and China but this decreased to well below 1mt/y during the second half of 1990s. This was due to the fact that crude imports from the FSU were completely suspended and China cut its supply to only one third of the amount it provided during the 1980s.

of eight private companies from South Korea are interested in taking part, due to the large deposits in place. For example, the proven reserves of iron ore in Moosan are estimated to be 1bn tonnes (the projected production capacity is 8mt per year), and the proven reserves of gold in Woonsan are 1,000tonnes. Coal is a main energy source in the DPRK and its important role is unlikely to change in the foreseeable future. In the DPRK, there are quite significant coal reserves but the quality of coal is not high. This is the reason why less than 40% of coal production is allocated for power generation and the steel sector. DPRK’s coal production was 37.5mt in 1985 but production declined to as low as 18.6mt in 1998, even though the figure rose to 23.1mt in 2001. The production level could significantly increase if a new investment is made. Currently domestic coal supplies almost 90% of fuel for industry, 45% of energy for power generation, and 80% of the energy for household usage. Crude oil exploration cooperation Until the early 1990s, the DPRK used to receive 2 mt/y of crude oil from the FSU and China but this decreased to well below 1mt/y during the second half of 1990s. This was due to the fact that crude imports from the FSU were completely suspended and China cut its supply to only one third of the amount it provided during the 1980s. From the DPRK government’s viewpoint, the way to solve the energy shortage was to make an oil 56 Yonhap News, 3 December, 2004. On 19 May 2004 a Korean newspaper, Dong-Ah, reported that the DPRK’s Oil Industry Ministry has asked the Korea National Oil Corporation to take part in an oil and gas exploration project off North Korea’s west coast. The US Energy Information Administration said “West Korea Bay is geological analogous to China’s Bohai Bay”. There could be a chance to make a discovery if a comprehensive exploration is done in the West Korea Bay. North Korean sources give this site the potential of Nampo 5 to 40bn barrels of oil, but this is considered a highly speculative judgement.


A string of six party meetings have been held in Beijing in an attempt to resolve the crisis peacefully. If a breakthrough is made after the 2004 presidential election in the United States, the energy supply issue will be at the centre of any economic aid package to the DPRK. Energy cooperation between the two Koreas could then reach a significant level.

1.3. The implications of energy cooperation between the two Koreas Real progress in energy cooperation between the two Koreas depends upon the resolution of the second nuclear crisis. No party in the region is interested in being involved or witnessing another military confrontation. Even the DPRK authorities say that that they are willing to give up their nuclear programme as long their security is guaranteed. A string of six party meetings have been held in Beijing in an attempt to resolve the crisis peacefully. If a breakthrough is made after the 2004 presidential election in the United States, the energy supply issue will be at the centre of any economic aid package to the DPRK. Energy cooperation between the two Koreas could then reach a significant level. Energy cooperation is not an issue confined to the two Koreas, however, but extends to all parties in the Northeast Asian region. A successful settlement of the crisis will open the door for the systematic development of energy infrastructure not only in DPRK but also in Northeast Asia, cooperation leading to a Northeast Asian Energy Community.


In Russia, the development of oil and gas fields in East Siberia and Far East region and the related trunk oil and gas pipelines will require the big scale financing. In Northeast Asia, however, there is no regional co-operative framework that could protect the large scale of investment. Most of the cross-border energy trade and investment projects inevitably incur the problem of incompatibility between the laws and regulations among nations and different investment environments. Negotiations for cross border energy trade often means a long process of co-ordination between producers, transit countries, consumers, investors, central and local governments, etc.

According to IEA’s World Energy Investment Outlook 2003, the projected investment in Russia and China’s energy sector will reach to $1,050bn (of which $328bn is for oil and $332bn is for gas) and $2,253bn (of which $119bn is for oil and $98bn is for gas) respectively until 2030. Massive investment is needed to develop this type of energy infrastructure development. In China the development of a nation-wide pipeline network prepared by CNPC, and coastal pipeline network being planned by CNOOC, and a number of LNG terminals in the coastal areas will be the beneficiaries of these major investment. In Russia, the development of oil and gas fields in East Siberia and Far East region and the related trunk oil and gas pipelines will require the big scale financing. Korean Peninsula is very well located to have an extension of the major oil and gas pipeline infrastructure from Russia and China to be extended once the political settlement of current DPRK nuclear crisis opens the door for an active energy cooperation between North and South Korea. In Northeast Asia, however, there is no regional co-operative framework that could protect the large scale of investment. Most of the cross-border energy trade and investment projects inevitably incur the problem of incompatibility between the laws and regulations among nations and different investment environments. Negotiations for cross border energy trade often means a long process of co-ordination between producers, transit countries, consumers, investors, central and local governments, etc. This is why Northeast Asian region really needs to introduce regional co-operative framework. Multilateral cooperation in Northeast Asia is not a remote possibility but will be a reality in the foreseeable future. Reprinted with the permission of the Royal Institute of International Affairs (Chatham House About the Author: Dr. Keun-Wook Paik as an Associate Fellow at the Sustainable Development Programme Royal Institute of International Affairs (Chatham House). Endnotes: 1 Energy Research Institute of the Russian Academy of Sciences and Institute of Energy Economics, Japan, Study on Comprehensive Energy Plan in East Siberia and Far East of the Russian Federation: Second Phase Executive Summary, September 1995.


2 These two fields are located between Kovyktinskoye and Verkhnechonskoye fields. 3 Keun-Wook Paik, ‘Energy Cooperation in Sino-Russian Relations: The Importance of Oil and Gas’, The Pacific Review, vol. 9, no. 1 (1996), pp. 77-95. 4 Keun-Wook Paik, ‘Sino-Russian Oil and Gas Cooperative Relationship: Implications for Economic Development in Northeast Asia’, presented at Northeast Asia Co-operation Dialogue XIII: Infrastructure and Economic Development Workshop’, organised by Institute for Far Eastern Affairs, Russian Academy of Sciences, and Institute on Global Conflict and Co-operation, University of California, Moscow, October 4, 2002. 5 Some work had been done before 1994 when the memorandum was created for the development of East Siberian gas development between CNPC and Mintopenergo (the Russian Ministry of Fuel and Energy). In 1991 Baikalekogaz consortium and BP/Statoil alliance conducted a study on East Siberian oil and gas resources in East Siberia in the early 1990s, but BP/Statoil concluded that the study had no incentive for taking further steps, due to the lack of immediate market for East Siberian oil and gas export. In 1992 the Baikalekogaz consortium was converted into Russia Petroleum. The same year Canada’s SNC and Lavalin, under the sponsorship of Canadian Bitech Corp., carried out a pilot feasibility study on the Irkutsk region’s gas supply project based on Kovyktinskoye development. 6 Alastair Ferguson, ‘Kovykta Project’ presented at an International Seminar on Policies and Strategies toward Korea-Russia Energy Co-operation organised by Korea Energy Economics Institute, Vladivostok, October 7, 2003. 7 Whatever suggested or reported, author’s view is that Gazprom aims at securing a blocking stake, that is 25% plus one share eventually. 8 Interfax Petroleum Report, June 3-9, 2004. 9 Alexey B. Miller, ‘Eurosian Direction of the Russia’s Gas Strategy’ presented at 22nd World Gas Conference. 10 Gazprom could, for instance, buy shares in Russia Petroleum from the regional government and Interros, which own respectively 10.78% and 25.82% of the company. Interfax Petroleum Report, April 16-22, 2004. 11 Dow Jones China Energy Report, April 23rd 2004. 12 Moscow Times, Nov 29, 2004. 13 Alexey M. Mastepanov and Victor P. Timoshilov, ‘Perspectives of Development of Eurasian Gas Pipeline System and Energy Resources of Northeast Asia: Gazprom’s Point of View’, presented at International Conference on Northeast Asian Natural Gas


and Pipeline : Multilateral Co-operation, organised by Northeast Asian Gas and Pipeline Forum, and Asia Gas & Pipeline Co-operation Research Center of China, Shanghai, March 8-10, 2004. Pipeline Gas Introduction to the Korean Peninsula Page 9 Dr Keun-Wook Paik (January 2005) 14 At a parliamentary hearing in late September 2003, Kogas president Kang-Hyun Oh said that the cost of pipeline gas passing through the DPRK would be 1.8 times more expensive than that of the Yellow Sea line, assuming the gas supply period was 30 years. He added that the timing of pipeline gas supply could be delayed from 2008 to 2010-2013. ‘The Gas Industry News’, 30 September 2003. 15 Dong-Ah Ilbo, 5 August, 2004. Interestingly, the route that would bypass China is strongly supported by Prof. Tai-Yoo Kim, former advisor to the president. In fact he highlighted this point in the Korea Leader’s Forum on ‘Next Generation Growth Drive and Energy, What is the issue?’, held in Seoul on July 15, 2004. See, Choong-Ang Ilbo, July 16, 2004. 16 Hoyos, Carola and McGregor, Richard, ‘PetroChina ends talks on pipeline’ Financial Times, 4August, 2004. 17 In fact, the Russian side indicated that it was prepared to see gas for US$ 75 / 1000 cm as minimum. See Russian Petroleum Investor, March 2003, P. 52. Pipeline Gas Introduction to the Korean Peninsula Page 10 Dr Keun-Wook Paik (January 2005) The real pressure on the price comes from the Guangdong and Fujian LNG price secured by China in August 2002, a breakdown of which are shown in tables 6 and 7. CNOOC initially projected that China would pay an LNG price of $3.84/mmbtu. However, this figure is over $1.0/mmbtu higher than the price agreed for Tangguh in Indonesia. According to interviews with industry and financial sector specialists, the LNG price delivered to China will be as low as $2.5/mmbtu; even after regasification. 18 ABARE Economics and ERI’s joint research report pointed out the average real LNG import price to Japan over the period 1995-2001 ranged from $3.27 to $4.84/mmbtu, in 2001 prices. The average price over the period was $4.02/mmbtu. The report also argued that LNG import prices to eastern coastal China could be marginally ($0.10/mmbtu) lower than those to Japan. (See, ABARE Economics and Energy Research institute, Natural gas in eastern China: The role of LNG, ABARE Research Report 03.1, p. 7). It remains to be seen whether this projection is accurate. Pipeline Gas Introduction to the Korean Peninsula Page 11 Dr Keun-Wook Paik (January 2005) the scale of discount from the SEIL project is not as considerable as the discount for Australia’s Northwest Shelf and Indonesia’s Tangguh project for the Guangdong and Fujian LNG price. 19This work started based on the agreement signed between CNPC and Sakhaneftegas in April 1999, soon after the Feb 1999 agreement. Pipeline Gas Introduction to the Korean Peninsula Page 14 Dr Keun-Wook Paik (January 2005) the Kovykta project and became a dominant player in the solely Russian Federation government asset, Chayandagas. In February 2003, Gazprom chairman Alexei Miller and Rosneft president Sergei Bogdanchikov asked President Putin to instruct the Ministry of Natural Resources and other relevant ministries to consider developing the


Chayandinskoye, Talakanskoye, Sredne-Botuobinskoye, Kovyktinskoye and Verkhnechonskoye oil and gas fields under a single project and initiate an auction for it, in accordance with legislation. Putin accepted the proposal. 20 In March 2003, the Russian government held its first cabinet meeting to discuss the development of oil and gas reserves in Eastern Siberia and the Far East. During this meeting, the government adopted a draft entitled ‘Programme to Establish a Unified System of Production, Transportation and Supply of Gas in Eastern Siberia and the Far East’ which outlined possible exports to markets in China and other countries in the Asia Pacific region. Besides this, the government also decided to include the Gazpromdeveloped programme in the draft ‘Principal Provisions of the Energy Strategy of Russia for the Period until 2020’. 21Interfax reported in early 2004 that the proposals from the state energy firms, in particular Gazprom, Transneft and Rosneft were being taken very seriously byPresident Putin. 22In February 2004, Transneft revealed its revised pipeline plan and won the approval of the Amur region administration, as well as the governments of Khabarovsk and Primorye. Interestingly, the authors of this revised plan ignored the previous plan of Angarsk-Nakhodka line which had a branch line to Daqing. Transneft’s Semyon Vainshtok said it would take a year to draft a new feasibility study of the revised pipeline project, a further year to design it and about four years to build it. The new route begins much further west in Taishet and the distance from the pipeline to Lake Baikal has been doubled. Transneft is no longer considering routes that would send the pipeline south of Lake Baikal. The new pipeline will be 4,130km long, compared with 3,765km for the Angarsk-Nakhodka pipeline, and will be able to transport 56mt/y of oil. The project includes the construction of 32 pumping stations, of which 13 will have oil storage facilities. The route includes 48 river crossings and 115 road and railroad crossings. 23Besides Transneft’s revised plan, the government of the Sakha Republic (Yakutia) along with Gazprom, the Natural Resources Ministry, and Surgutneftegaz have drawn up an alternate route to the Pacific Ocean with oil and gas pipelines in a single corridor. This route would run from Nizhnyaya Poima (Transneft pipeline system) – Yurubcheno- Tokhomskoye field-Verkhnechonskoye field-Talakan field-Chayanda field-Lensk- Olekminsk-Aldan-Neryungri-Tynda-Skovorodino-Blagoveschensk-Khabarovsk Vladivostok-Nakhodka. Fields like Kovykta, Dulsimininskoye, and Yaraktinskoye would 20 Russian Petroleum Investor, April 2003. 21 Russian Petroleum Investor, April & September 2003. 22 Interfax Petroleum Report, March 26 – April 1, 2004. 23 Interfax Petroleum Report, June 17-23, 2004 ; Russian Petroleum Investor, May 2004. Pipeline Gas Introduction to the Korean Peninsula Page 15 Dr Keun-Wook Paik (January 2005) be linked in later. Thus, a single network would include all the major oil and gas fields in the Yakutia and Irkutsk regions, as well as the Krasnodar territory. The pipeline would stretch for 6,224km.


24 The project that combines the oil and gas pipelines was submitted to President Putin at a meeting on the development of Far East transport infrastructure on February 26th 2004 in Khabarovsk. Putin designated the pipeline as being of national strategic interest and told Sakha President Vyacheslav Shtyrov to continue work on the project. President Putin also said that all designs for the pipeline must be included in the documents to be submitted to the government. 25It is worth noting Gazprom’s intention to develop the Eurasian gas pipeline system. Prof. Alexey M. Mastepanov, Gazprom argued that “the export of Kovyktinskoye gas will lead to the temporary closure of the Chayandinksoye gas field for the long-term. This will complicate the organisation of gas supplies to the Far East region. As a result the gas fields of Yakutia will lose the market for a long period of time. It will involve a loss of profits for the Russian state. The Chayandinkoye gas field can satisfy the prospective demand of China and Korea, and Gazprom proposes to realise this project starting from 2009-2010”. 26 If this approach is accepted and supported by Russian authorities, then Kovykta gas export to China and Korea will have no choice but to consider a new route different from the one adopted by the feasibility study. 27 The study assumed a pipe diameter of 26-28 inch (65-70 cm) and delivery capacity of 8bcm/y. The distances from Sakhalin I to Tokyo and Niigata are 900 miles (1,400 km) and 700 miles (1,120 km) respectively. The FS concluded the project was technically and commercially viable. 28However, the Japanese utilities companies decided to back Sakhalin LNG rather than Sakhalin pipeline gas. A breakthrough was made with Sakhalin II’s LNG exports to Japan during the first half of 2003. Three firms, Tokyo Gas, Tokyo Electricity and Kyushu Electricity, agreed to import a total of 2.8mt of LNG from Sakhalin II from 2007. In 2004, SEIC announced that Toho Gas and Tokyo Electricity agreed to import 0.6mt/y of LNG from the Sakhalin Islands (see Table 16). 29 In terms of location, China’s north-eastern provincesare well positioned to be the beneficiaries of Sakhalin offshore gas development. According to the State Reform and Development Commission (SDPC), China is also considering importing Sakhalin offshore gas to the Heilongjiang province during 2011- 2020. China studied the possibility of Sakhalin gas imports to Heilongjiang, Jilin and Liaoning provinces in the late 1990s, but the suggested supply volume was not sufficient. During the first half of 2004, the issue was revisited, but this time it was the border price that has blocked the negotiation. Korea’s interest in Sakhalin gas dates back to early 1994 when the Korean government and companies considered the possibility of initiating LNG supplies from the Lunskoye gas field. Since 2000, the Sakhalin Islands authorities have intensified efforts to secure the LNG export market for Sakhalin II’s 9.6mt/y LNG scheme, but the administration’s 2005-2006 export timetable was ambitious. The administration was slow in understanding the difficulty in securing the commitment from the gas buyers. Sakhalin regional governor Igor Farkhutdinov has repeatedly announced that the Sakhalin region is interested in supplying gas to Korea, and that this supply could begin in 2005-2006. Shell, which has a 55% equity stake in Sakhalin Energy, has lobbied


hard to secure an early commitment from the Korean government. Due to the privatisation drive in Korea’s gas industry, however, Sakhalin Energy Investment Corp (SEIC) lobbying to penetrate Korea’s gas market has not yet been successful. 30In August 2004, Kogas announced a 5 mt/y of LNG long term supply bidding and SEIC’s proposal was included in the short list of the five potential supply sources. Very recently it was reported that Gazprom agreed to swap the asset for its entry in Sakhalin 2`project. 31 Industry sources are saying that Gazprom would take 25% equity in Sakhalin 2 project and in return Shell would take equity in the Zapolyarnoye oil field, which is located in west Siberia and is owned by Gazprom. This development would strengthen the chance of SEIC’s LNG supply contract (1.5 mt/y) with Kogas. 29 FT International Gas Report, August 1, 2003, p. 14. 30 In November 2000, Mr. Yong-Soo Kang, vice president of Kogas, delivered an interesting paper at an international conference. He said that “The most possible candidate in Russian gas project for the Northeast Asian gas market are the Irkutsk project and the Sakhalin project…..Kogas hopes to carry out the feasibility study on the Sakhalin project to see how much the Sakhalin project will contribute to the Korean gas market and to find possible ways to cooperate with each other in the region. Then he added that for the implementation of Sakhalin Project, two different options can be considered. One is the pipeline gas option which is to construct the pipeline through Khabarovsk, Vladivostok, and North Korea, and the other is the LNG option which is to construct the export terminal in the ice free southern port of the island.The length of pipeline from Sakhalin to Korean gas market is about 2,300 km and the day ofvoyage for LNG carrier is about 2.5 days compared with 7 days from Southeast Asian countries and 15 days from Middle East countries”. Yong-Soo Kang, ‘The Potential to supply Natural Gas from Sakhalin project to Korean market’ presented at the Fourth Annual Conference on Sakhalin Oil and Gas organised by IBC Gllobal Conferences Ltd in London, 20-21 November 2000. 31 Initially Nihon Keizai Report (Nov 27, 2004) covered this story and it was quoted by the Moscow Times, Nov 29th, 2004.Pipeline Gas Introduction to the Korean Peninsula Page 20 Dr Keun-Wook Paik (January 2005) However, the management of the Sakhalin I project has not shown any interest in the option of supplying gas to the Korean Peninsula by pipeline via North Korea. In addition, the Kovykta gas project cannot compete with the Sakhalin offshore gas project, as the latter is much more cost-effective if the sizeable gas markets of South Korea and southern Japan are to be supplied. In fact the distance from northern Sakhalin to Korea is around 2,700km and the majority of the Russian section terrain is flat. In terms of price, the Sakhalin pipeline option could be very competitive against Kovykta project if a sizable gas market (17 bcm/y) from South Korea and southern Japan were to be offered simultaneously. 32 The Gas Industry News, December 20, 2004. Pipeline Gas Introduction to the Korean Peninsula Page 22 Dr Keun-Wook Paik (January 2005)


33In the same year, through its 1995 energy plan, the Korean government made it clear for the first time that it intended to replace a substantial portion of LNG imports by long distance pipeline gas, and intended to balance the ratio between LNG and pipeline gas over the next decade. According to the report prepared by Kogas for the Korean parliament’s Trade and Industry Committee annual inspection in October 1997, pipeline gas introduction would take place in 2006 (see Table 19). At the core of the plan is the fact that the pipeline gas could be supplied to South Korea at a much cheaper price than LNG. 33 It is China National Petroleum Corp who have taken advantage of what KNOC has done. In1997, CNPC made a strategic alliance with Sakhaneftegas, and in 2001 a preliminary FS work on the giant Chayandinskoye was completed. Pipeline Gas Introduction to the Korean Peninsula Page 23 Dr Keun-Wook Paik (January 2005) reserves are added and a proper project structure is developed. 34 EAGC kept the remaining 7.5% for and the figure became 8.37% after the 4th emission during 1998-1999. However, it was diluted in 1999 to 7.1% due to its failure to join in the 5th emission. It was early in December 2000 that the remaining 7.1% was sold to BP-Amoco and Tyumen Oil Company (TNK). 35When the Korean press reported of the secret disposal of EAGC shares, the Korean government admitted that there was nothing the government could do to stop EAGC’s share disposal. It also argued that it would not affect its plan to join in the Kovykta gas development project. Kogas consortium did not want to take an equity stake in Russia Petroleum for the following reasons: 34 Soon after the November 2003 FS work completion, Interros announced that its 25.8% equity in Russia Petroleum is on sales. The estimated cost for the equity is at least $500 million. 35 Considering that the 12.88% of Irkutskenergo’s Russia Petroleum was sold at over $40 million in December 2000, the price of EAGC’s 7.1% shares is estimated to be around $20-30 million. 36 In June 2002, feasibility work was due to be completed but was postponed until June 2003. A total of $6.0m (of which 50% was supplied by the government, 50% by Korean consortium) was paid for the Korean portion of the study. Eventually, feasibility work was completed in November 2003. At 36 The members are Kogas 27.3%, LG Corp. 14.8%, KNOC 14.0%, Hyosung 12.8%, Daewoo Construction 7.7%, Daesung Industry 6.7%, Hyundai Corp 6.7%, Daewoo International 5.0%, and Hanwha 5.0%. 37 This pipeline gas alliance will be very different from the KEDO formula whose driving force was US-Japan-Korea alliance, and its implications towards Northeast Asian region’s power balance will not be small. At the end of 2004, the Russian Government decided to construct the crude oil pipeline to Nakhodka.


38 Before this official announcement, Transneft asked for priority to be given to the development of the Taishet-Skovorodino section - 2,000 km at a cost of US$ 6.0 billion, much less than the estimated total cost, US$ 11.5 billion - and to the development of the Skovorodino-Daqing section. 39 Since the government raised the possibility of a CNPC buy-out of 20% of Yugansk oil assets, there is a very strong possibility of a parallel crude oil and gas pipeline towards Skovorodino. The Kovykta gas pipeline can be constructed alongside this crude oil pipeline, which would save 30% of the pipeline construction cost. However, the difficulty would lie in the timing of this pipeline development. 40 Selig S. Harrison, ‘Toward Oil and Gas Co-operation in Northeast Asia : New Opportunities for Reducing Dependence on the Middle East’, Woodrow Wilson International Center for Schloars, Asia Porgram Special Report No. 106 (December 2002), and author’s interviews. 41 Author was told by a DPRK senior officer that the DPRK government believed the introduction of pipeline gas from Sakhalin Islands would be possible regardless of a sizable gas market provision from South Korea. The remarks confirmed that DPRK authority did not fully understand the fundamentals of natural gas development and related the gas trading. 42 Sisa Journal, February 6/ 13 & March 13, 2003. 43 If the six party talks finds a way of resolving the security issue, the option for gas for peace could be a real alternative for the KEDO project. At present both Kogas and MOCIE are not supportive of the pipeline gas passing through DPRK territory. They prefer East Siberian gas flowing to north China and then the Yellow Sea to South Korea, bypassing DPRK territory entirely. The United Nations is more open-minded to pipeline gas passing through DPRK territory. In an interview with a Korean newspaper Dong-Ah Ilbo, Mr. Maurice Strong, special envoy to the Secretary General of the United Nations with regard to the DPRK issue, said: ‘Energy is a humanitarian issue. DPRK urgently needs energy and it is only possible with the international community’s support. To tackle the DPRK’s long term energy shortage problem, Russia’s natural gas could be an option. In particular Sakhalin gas project is worth taking note of as it can be done with the shortest pipeline route with a short working period. For this project, an energy specialist group is being established and feasibility work is being studied.’44 43 Ward, Andrew, ‘Deal for gas pipeline could solve Korean nuclear crisis’, Financial Times, 31 March, 2003. 44 Dong-Ah Ilbo, 24 Nov, 2003. This remark was reconfirmed by his interview with NHK on 4 March 2004, that natural gas pipeline to the Korean peninsula passing through DPRK can be studied assuming that DPRK nuclear crisis would be resolved. See, JoongA-ng Ilbo, 5 March, 2004. 45 Joong-Ang Ilbo, 19 May, 2004 & June 20, 2004.


46In December 2003, the Korea Energy Economics Institute (KEEI) published a study on DPRK’s LPG demand and the potential for LPG cooperation between DPRK and ROK. The scale of LPG demand under the high growth scenario is predicted to reach 1.26mt in 2020 and the study confirmed that there is ample space for LPG development in the DPRK. 47 Meil Kyungje Economic Report (Weekly), October 2001, p. 10. 48 Dong-Ah Ilbo, April 3, 1999. 49 Considering that the cost of a 500MW power plant is around 600-700bn Korean won (roughly $0.5-0.6 billion), the ROK authorities could not give a positive response.During the 3rd six party meeting in Beijing in late June 2004, the DPRK authorities asked for 2,000MW worth of electricity supply in return for the suspension of their nuclear programme. If the electricity supply is calculated in terms of heavy oil supply, the volume would reach 2.7mt. 50 The total volume of heavy oil supply to DPRK during 1995 and 2002, based on the 1994 KEDO agreement, was 3.56mt and in money terms, the total cost was $511.3m, of which $347.5 was covered by the United States.51 Until the political situation has progressed, it is very difficult to make a positive response to such expensive requests. The DPRK authorities have also actively explored the option of importing power from Russia through power transmission lines. Chairman Jong-Il Kim has met President Putin three times since 2000, and the two leaders discussed power cooperation at each of these meetings. 51 Of which 0.15mt in 1995, 0.5 mt during 1996/2001 annually, and 0.411 mt in 2002. Ahn Choong-Young and Lee Chang-Jae, ed., Northeast Asia Economic Co-operation : First Step towards Unification ( Seoul : Pakyoungsa, 2004), p. 183 (written in Korean) 52 In parallel with the summit meetings between the two leaders, a number of working level meetings have taken place. 53 In 1997, Kap-Koo Yoon, head of ACE Engineering Inc made the presentation on ‘Peac Network Project’ for the first time during the Autumn Seminar organised by Korea Electricity Society. 54 Victor Kalashnikov, ‘Electric Power Interconnections in NEA : Perspectives from the Russian Far East’ presented at an International Workshop on Upgrading and Integration of Energy Systems in the Korean Peninsula : Energy Scenarios for the DPR of Korea, organised by Landau Network – Centro Volta, Como, Italy, 19-21 Sep, 2002. 55 Dong-Ah Ilobo, 18 May, 2004. Primorskii Krai governor Darkin confirmed the export scheme of Russian Far East surplus electricity export to South Korea via North Korea is almost completed.See, Jong-Ang Ilbo, 5 July, 2004. 56 The project scale is small but it is a very significant development in energy cooperation between the two Koreas.


57 Meil Kyungje Shinmoon, 29 June, 2004. 58 The share of coal in energy consumption is electricity generation 39%, household 15%, railway 2%, metallurgy 8%, industry 33%, and other 3%. Coal production share between anthracite and brown coal is divided into 80 vs 20 ratio.See, Jong Jin-Chang, ‘Clean Coal Technology in DPR Korea’, presented at an international workshop on Upgrading and Integration of Energy Systems in the Korean Peninsula : Energy Scenarios for the DPRK of Korea, organised by Italian Ministry of Foreign Affairs, Landau Network-Centro Volta, World Information Service on Energy, and Fondazione Opera Campana dei Caduti, , Como, 19-21 September, 2002.discovery offshore. Since the 1960s, Pyongayng authority has made a huge effort to explore its offshore. 58 In the DRPK there are over 100 centrally-controlled mines, of which 70 are anthracite mines, the remainding 30 being bituminous mines. Besides this, there are regional based 500 minor mines. 59North Korea achieved its dream of becoming an oil producer in 1998. Even though the scale of annual crude oil production from the Sook-Cheong County’s Anju Basin is very small (0.3 mt/y), to the North Korean authorities it is a significant volume. 60 Besides the West Korea Bay exploration, the authorities have initiated the exploration in Anju Basin by inviting Russian specialists with experience in West Siberian oil development.The Chosun Ilbo reported that overall supervision of oil development is being led byDPRK premier Sung-Nam Hong. Under his leadership, both the Oil Bureau (headed byMr. Jung-Shik Ko) and KOEC (headed by Mr. Jung-Shik Ko) are responsible for the oilexploration and development. 61In 2000, reportedly both UK’s Soco International and Sweden’s Taurus Petroleum proposed to Hyundai Corporation and Korea National Oil Corporation (KNOC) to form a consortium for oil and gas exploration in the Yellow Sea. 62 Hyundai estimated the Block B and C’s reserves at around 100m – 1bn barrels, the estimate being based on two discoveries from the ten drilling wells. The firm believed that the economics of exploration in the west Korean Bay would be justified given a minimum discovery of 40- 50m barrels worth of reserves. The firm wanted to apply to the Korean government for exploration rights. No significant step was taken after the summit. In late August 2002, Singapore-based Sovereign Venture Pte Ltd. announced that it had found oil and gas reserves from the contracted area in northern Hamkyung province and expected to be able to recover a minimum of 1tcf of natural gas and 10m barrels of oil reserves from the concession area. 63In South Korea, KNOC is responsible for continental shelf exploration and development.In the DPRK, its counterpart is KOEC, which has responsibility for oil development and oil concession matters.64 KNOC and KOEC have never discussed the Yellow Sea boundary issue of the question of West Korea Bay exploration. Ideally, KOEC, KNOC and CNOOC should discuss together the Yellow Sea boundary issue and the question of joint exploration (regardless of the settlement of the boundary issue). In particular, joint exploration in the Yellow Sea and any discoveries would offer a unique opportunity to settle the boundary issue.


59 For the details of DPRK’s exploration effort, see Keun-Wook Paik, ‘North Korea’s Approach for Oil Exploration & Production’ presented at an International Workshop on ‘Seabed Petroleum in the Yellow Sea : Geological Prospects, Jurisdictional Issues, and Paths to Cooperative Development’, co-organised by Woodrow Wilson International Center for Scholars and China Institute of International Studies, April 16-17, 2004. 60 In 1991 the import volume of crude oil was 1.89 mt but the volume recorded only 0.61 mt in 1998. 61 Chosun Ilbo, May 26, 2001. 62 Meil Kyungje Shinmoon, May 13, 2000. 63 http://www.rmfdevelopment.com/political/NorthKoreaOil.htm For an interesting article on DPRK’s potential oil reserves, see http://www.hartford-hwp.com/archives/55a/161.htmlandhttp://210.145.168.243/pk/073rd_issue/98120902.htm 64 Until the beginning of 2004 there was no organization representing the oil developing issueswithin the Cabinet, except some of the energy specialists working within the advisory committeewithin the governmental structure. Now KOEC is converted into Ministry of Oil Industry. 65 An officer from the Ministry of Commerce, Industry and Energy (MOCIE) said that DPRKauthority proposed a working group meeting in Kumkang mountain to review the proposal. A KNOC official was quoted as saying that the company was seeking talks with North Korean officials in June or July. 65Global GeoServices of Norway reported in October 2003 that it planned to do seismic surveys in DPRK’s offshore, but KNOC said its contract has expired on 30 April. Concessions previously held by Taurus Petroleum of Sweden, Soco International of the UK, and Beach Petroleum of Australia have lapsed. Petronas of Malaysia took over Block A, previously held by Soco. 66 Dong-Ah Ilbo, May 19. 2004 ; Oil and Gas Journal, ‘Exploration off N. Korea might include S.Korean participation’, June 7, 2004, P. 42 66 A rumour is that Petronas decided to withdraw from the project due to the invisible pressure from the Chinese authority. In mid-May 2004 KNOC was considering participation in an exploration project off North Korea’s west coast. 67 North Korean sources placed potential off Nampo 5 to 40 billion bbl of oil, but this is considered highly speculative. In October 2003 Global GeoServices of Norway reported that it planned to acquire seismic surveys offshore, but KNOC said its contract has expired. A KNOC official was quoted as saying the company was seeking talks with North Korean officials in June or July. See, Dong-Ah Ilbo, May 18, 2004 : Oil and


Gas Journal, “Exploration off N. Korea might include S. Korean participation”, June 7, 2004. 67 However, the behind-the-screen approach backfired when the on unexpected media coverage of communications between KNOC and KOEC, hindering further progress on cooperation between the two parties. DPRK authority stance towards the collaboration between KNOC and KOEC was indirectly explained by the British Newspaper report. The Observer reported that “Aminex Plc clinched a deal with the government of North Korea to explore and develop all the country’s potentially oil-bearing territory, with a decisive say in production…. The deal – signed secretly in Pyongyang during the summer in the presence of the British ambassador – gives Aminex 20- year rights over the industry, via a joint venture with the government. It has also negotiated the right to receive royalties, revenues and the pick of the best acreage should it prove productive” 68 The Observer, “British company strikes first deal for oil prospecting in North Korea”, September 19, 2004. 68A more detailed interview story by the Financial Times exposed the characteristics of the deal Aminex has signed with Pyongyang authority. “The North Koreans proposed to draw the contract up under Swiss commercial law. It was finally signed in Pyongyang in June in the presence of the British. ambassador… Under the agreement, Aminex will provide technical assistance such as analyzing seismic data and introducing foreign investment in return for a share of future production and royalties. The company also has the right to cherry-pick and drill wherever it considers promising and is eyeing an area off the western coast”. 69If these reports are the case, the deal is extremely good for Aminex but terribly bad for Pyongyang authority. This Aminex deal indirectly confirms that Pyongyang authority’s frustration in attracting a reliable western energy firm for its offshore exploration. Unfortunately Aminex deal will serve as obstacle rather than facilitator for DPRK’s offshore exploration. Until comprehensive exploration work is done the real scale of the DPRK’s offshore oil and gas reserves will remain unknown. However significant investment from the West, which is needed for effective exploration work, is very unlikely until the nuclear crisis is resolved. 69 Friederike Tiesenhausen Cave, “Aminex makes rare foray deep into the ‘axis of evil’”, Financial Times, October 6, 2004. 70 Through Khabarovsk Communique (2001 October) and Vladivvostok Statement (2003 April), Korean government was the most active in this initiative. Japan has promoted the so-called ASEAN + 3 (Japan, Korea and China) initiative (Hiranuma Initiative). Japan’s initiative is not extended to the Russian Federation.


70At the beginning of 1990s, Professor Masaru Hirata, the driving force of North Asian Gas and Pipeline Forum proposed a large-scale Pan Asia-Pacific Natural Gas Network. 71 After reviewing Prof. Hirata’s proposal, author touched the issue of Northeast Asian Energy Charter Treaty for the first time. See, Paik Keun-Wook, ‘Towards a northeast Asian energy charter’, Energy Policy, Vol. 20, No. 5 (May 1992), pp. 433-443. 71 The current behind-the-scenes competition between Japan and China with regard to crude oil pipeline development from East Siberia to Northeast Asia is only one small part of a regional energy infrastructure. South Korea has already established a 2,440km nation-wide trunk pipeline network and this domestic trunk pipeline played a pivotal role in natural gas expansion in Korea. In China, China National Petroleum Corp (CNPC) is planning to complete a 20,000km onshore trunk pipeline by 2020, and China National Offshore Oil Corp (CNOOC) is planning to build a 3,759km coastal pipeline network (of which 2,259km onshore and 1,500km offshore) before 2010. If the CNPC trunk and the CNOOC network are connected, China will have a nation-wide gas pipeline network in place by 2020. In 2003 Russia announced a blueprint for energy infrastructure development in the western part of the Federation. In addition to this ‘Energy Strategy of Russia up to 2020’, a federal programme, ‘Economic Development of the Far East and Zabaikal up to 2010’ has also been written. The intention is to establish a trunk oil and gas pipeline network in East Siberia and the Far East. The only issue being that although Japan has spent almost 15 years feasibility study on a trunk pipeline introduction to Honshu, the main island of Japan, no action has been yet taken. 72 Keun-Wook Paik, ‘Geopolitics of Pipeline Development in Northeast Asia : The Reality and the Implications’ presented at 11th LawAsia Energy Law International Conference on Towards Energy Co-operation in the Asia Pacific Region’, organised by LawAsia Energy Section, Seoul, June 22- 25, 2004 ; Victor D. Kalashnikov, Russian Far East Energy Sector Development and Cooperation Strategies towards Northeast Asia, presented at 2004 COE Summer International Symposium on Siberia and the Russian Far East in the 21st Century : Partners in the Community of Asia’ organised by Slavic Research Centre, Hokkaido University, Sapporo, July 14-16, 2004. 72Even if the trunk pipeline is not built in Japan, pipeline development in the Korean peninsula, China and Russia will form the basis of a Northeast Asian Natural Gas Pipeline Grid in the future. Ideally, the network should be comprised of Russia, China, Korean Peninsula, and Japan, as shown in the map. Such a larger circular pipeline could also include two inner circular pipelines to ensure minimal disruption to gas flow. However, without Japan’s trunk pipeline, the greater circular pipeline will not be completed. 73 The concept of this pipeline was initially suggested by author’s paper ‘Sakhalin


Hokkaido Gas Pipeline Introductions and Its Implications towards Circular Pipeline Development in Northeast Asia’, presented an international conference on Advancing the Japan Pipeline Project for Introducing Sakhalin Natural Gas, organised by Hokkaido Sakhalin Natural Gas Pipeline Study Committee, 2nd April 1999. However, the concept was drawn as a map by Mitsubishi Research Corp in early 2000, and Dr. Kengo Asakura introduced this map in his article on Trans-Korean gas pipeline could help Asia energy security, environmental problems (Oil & Gas Journal, May 15th, 2000), p. 75. Author used the map without this clarification in his paper titled “Revitalising North Korea’s Energy : Based on Pipeline gas option”, presented at LNCV’s conference on Korean Peninsula : Enhancing Stability and International Dialogue, 1-2 June, Rome (http://www.mi.infn.it/~landnet/corea/proc/033.pdf). To prevent any further confusion, author decided to clarify this issue in this paper.


In the interests of their energy security, countries such as China, Korea Taiwan, Japan and Russia continued to move towards energy diversification, including some nuclear capacity. Now, primarily due to climate change and energy security concerns, even western governments are increasingly looking anew at nuclear energy.

Letter to the Editor

ANGRA III Brazil’s Third Nuclear Power Plant

Edmilson Moutinho dos Santos Rafael Judar Vicchini

Dear Sirs, We have been following the likely revival of the nuclear industry in the world. Due to safety concerns and financial troubles, things have not gone well for the nuclear energy since the Three Mile Island accident in America in 1979. But lately, things are changing again and Nuke’s social, political and economic pictures seem much improved. In Asia, nuclear energy was never ruled out. In the interests of their energy security, countries such as China, Korea Taiwan, Japan and Russia continued to move towards energy diversification, including some nuclear capacity. Now, primarily due to climate change and energy security concerns, even western governments are increasingly looking anew at nuclear energy. The debate is still opened worldwide. Clearly, as climate change rises up the political agenda, the nuclear lobbyists can make the case that nuclear energy is the leading and most cost-effective carbon free energy alternative for the world. Better management is allowing nuclear power plants to run more efficiently and to perform much better environmentally. In many countries, nuclear electricity has become the cheapest in the market. However, many uncertainties are present and studies still indicate that new nuclear power plants are not economic and can not be built without subsidies. The impetus of this discussion internationally has also helped to revive the nuclear debate in Brazil. The nuclear lobbyists have grown their


The Nuclear Program with Germany also failed and only one power station, Angra II, was built, coming on service by the end of 1990s. Both Angra I and II have never performed greatly during reasonable period of time. From 1985 to 1995, the average utilization factor was lower than 40%. Then, it grew gradually up to 70%.

pressure on government to retake the construction of Angra III, which is supposed to become Brazil’s third nuclear power plant. It is interesting and somehow amazing to follow up the current domestic discussion on whether or not the government should pursue the construction of this nuclear plant. Nuclear power is a historic project in Brazil. The first reactor, the Westinghouse PWR Angra I, was launched in the middle 1960s and only begun to operate in the early 1980s. Then, disappointed with its partnership with the USA, Brazil decided to co-work with the former West Germany in the 1970s. A broad Nuclear Program previewed the construction of up to 8 major KWU PWR reactors plus the full technology transferring to allow the command of the uranium cycle, from mining, processing and enrichment. The Nuclear Program with Germany also failed and only one power station, Angra II, was built, coming on service by the end of 1990s. Both Angra I and II have never performed greatly during reasonable period of time. From 1985 to 1995, the average utilization factor was lower than 40%. Then, it grew gradually up to 70%. In 2001, the role of nuclear power turned very positive. From its historical “lower than 2%”, nuclear energy increased its share in the national energy mix to 4.8% in 2001. The electricity generated by Angra I and II increased from 1,806 toe (tons of oil equivalent), in 2000, to 3,783 toe in 2001, with the average utilization factor growing to 80%. Therefore, the nuclear reactors were useful for the country to overcome its electricity shortage when the hydro system failed to deliver enough energy and the government was obliged to impose a major electricity rationing. The searching for alternative forms to generate power rose up the political agenda. Thermal generation was seen as essential strategy for Brazil to reduce its dependence on the “humors of water”. Beyond Angra I and II, the Federal government, supported primarily by the state-owned Petrobras, built up many oil-and-gas-fired power plants. On the other hand, the discussion about resuming the construction of Agra III heated up again. By mid-2002, having rained substantially and created over supply of hydro power (also resulting by many rationalization initiatives taken in 2001, which reduced the Brazilian electricity consumption by almost 20%), the thermal power plants started running into financial difficulties. Thermal power could no longer co-exist in a market dominated by low-cost hydroelectricity.


Angra I and II can only survive on subsidies. In 2004, Brazil generated about 11,550 GWh of nuclear power, representing something like 3% of the total national energy mix. While Angra I struck its production record, generating 4,125 GWh, Angra II presented new major operational troubles, resulting in interruptions and load reductions.

Angra I and II can only survive on subsidies. In 2004, Brazil generated about 11,550 GWh of nuclear power, representing something like 3% of the total national energy mix. While Angra I struck its production record, generating 4,125 GWh, Angra II presented new major operational troubles, resulting in interruptions and load reductions. Both plants are operated by Eletronuclear, a state-owned enterprise, which sells all the generated energy to Furnas, another state-owned enterprise. Furnas is a major hydroelectric generator. After tough negotiation, the two companies agreed on a tariff of 91.52 R$/MWh (about 37 US$/MWh), applied since December 2004. This tariff does not reflect the full cost of nuclear power in Angra I and II. It resulted from an adjustment mechanism by which Eletronuclear sells its energy at a price compatible to Furnas hydroelectric plants and the difference is balanced by the Federal government. Yet the debate regarding the construction of Angra III was not frozen. Actually, it became a political issue, engendering controversies and divisions within the Federal government and also outside. More and more, respected voices have been making the case that nuclear energy is essential for Brazil. As a result, also here there is a growing and unlikely alliance between the nuclear industry, the academic community and many environmentalists. Important scientists are lending their support based on the argument that Brazil must keep developing the nuclear technology for tomorrow needs. Others just argue on practical topics such as the fact that Brazil has already invested about US$700 million buying Agra III equipments, which, in addition, represent annual maintenance cost of up to US$50 million. The political splitting within the Federal government has caused special consternation among energy specialists and the whole nuclear community. Initially, on one side, the Ministries of Mines and Energy (MME) and Environment (MMA) have sat as the environment and energy's long-standing opponents of Angra III. On the other side, the Ministries of Internal Affairs (or Casa Civil – Civil House), Defense, and Science & Technology (MCT) supported Angra III rather as a political (non energetic) issue, raising primarily the technological aspect of keeping developing a domestic nuclear expertise. Before we give our opinion on this theme, let’s position ourselves immediately. We are not Anti-NUKE per se nor believe any energy technology should be ruled out on ideological basis. Yet, we are totally


However, a country like Brazil, with lots of hydropower and important natural gas reserves (particularly considering those on neighboring countries such as Bolivia). does not need to lead the nuclear technology challenge. Brazil can in fact benefit substantially from letting others make the inevitable expensive mistakes in developing a new nuclear reactor generation (more safety and cost-effective). But, it is a misunderstanding to think that Angra III or Eletronuclear will guarantee the domain of nuclear technology in Brazil.

against the construction of Angra III. Personally, we are convinced that the energy future of the human race may firmly need more nuclear power, especially if the world will decide to speed up the efforts to stabilize CO2 concentrations in the atmosphere. However, a country like Brazil, with lots of hydropower and important natural gas reserves (particularly considering those on neighboring countries such as Bolivia). does not need to lead the nuclear technology challenge. Brazil can in fact benefit substantially from letting others make the inevitable expensive mistakes in developing a new nuclear reactor generation (more safety and cost-effective). The Brazilian Environment Ministry (MMA) alleges that the nuclear energy still involves high risks and not yet solved environmental issues. Many scientists would not completely agree with that argument, saying that technologies are available and current reactors operate with acceptable safety levels. However, why should Brazil accept to subsidize Angra III, which is from old generation, rather than invest on future and much better technological possibilities? Moreover, Eletronuclear must still achieve long-term adequate performance on Angra I and II, before the company can convince the society about its competence in managing well and holding high safety standards in a larger nuclear program. The Science and Technology Ministry (MCT) suggests that building up Angra III is necessary to allow Brazil to keep pursuing the development of nuclear technology and the full command of the uranium cycle. Angra III should allow the country to construct its first commercial uranium enrichment plant. But, it is a misunderstanding to think that Angra III or Eletronuclear will guarantee the domain of nuclear technology in Brazil. Actually, the domestic excellence centers are located at IPEN (Institute for Energy and Nuclear Researches in Sao Paulo) and CTM/SP (the Navy’s Center for Nuclear Technology in Aramar, Sao Paulo). Those institutions developed domestic technology outside the former Nuclear Program with Germany, which Eletronuclear came from. If the country’s objective is to build up competence on enriching uranium and developing the full uranium cycle at industrial level (which is questionable), then those activities, rather than Angra III, should receive investment and eventual subsidies. The uranium market and particularly the enriching activity are far from being competitive businesses. Therefore, Brazil should not really care whether its enrichment plant will be poorly economical. But there should


Whenever something appears more complex, Eletronuclear will contract out with foreigners or - for simpler cases – with small Brazilian firms. The state company counts upon a small group of high skilled operational professionals. How can we possibly imagine that Angra III is necessary in the next 10 or even 20 years in a country where much cheaper hydro possibilities are still available?

be an open and democratic debate whether enriching uranium for domestic uses (eventually for exporting) is the most strategic decision to prioritize the public investments. It is unacceptable the argument that Angra III, which still requires minimum investments up to US$ 2 billion, is necessary to justify the enrichment plant. According to the Brazilian Navy, expending about US$ 200 million in the research centers, Brazil could have the access to the full uranium cycle by 2010. But the government keeps reducing the Navy’s budget due to macroeconomic instabilities and the country’s major nuclear research centers find themselves in an almost calamity. So, it is hard to believe that Angra III is the best strategy for Brazil to keep pace with the development of nuclear technology. The country should rather rescue those nuclear institutes and maintain its nuclear intelligence for the future through credible and feasible projects. Eletronuclear actually lost its expertise in managing large nuclear works. As far as engineering knowledge is concerned, Eletronuclear is no longer independent to solve more intricate problems. Often, the company is obliged to join together with the Brazilian research centers to find specific expertise and this improves synergies. Whenever something appears more complex, Eletronuclear will contract out with foreigners or - for simpler cases – with small Brazilian firms. The state company counts upon a small group of high skilled operational professionals. The more seniors have been retiring and transferring operational experience to the juniors, who are entering the company. It is not necessary to build up Angra III to keep this process going. Finally, the last relevant point is raised by the Energy Ministry (MME) and regards energy costs. Angra I and II´s total costs were greater than US$ 10 billion. Long delays led to uncontrollable additional financial costs. Now, imaging that Angra III might cost significantly lower sounds like a fantasy still to be proved. How can we possibly imagine that Angra III is necessary in the next 10 or even 20 years in a country where much cheaper hydro possibilities are still available? Moreover, with so many natural gas resources in place, nuclear power does not seem the most cost-effective thermal option either. Since 2001, Brazil invested from 7 to 10 billion US dollars in gas-fired power plants. Those units are not working or receive strong subsidies to cover losses, since they are not competitive with hydro. Now, firstly, Brazil should give any economic sense for those plants before even starting thinking about Angra III. Then, considering gas prices usually found in Brazil, even


In the 1970s, Brazil made two serious mistakes: (i) it invested excessively in energy infrastructure instead of investing in human capital, i.e., education for its people; and (ii) it opted for thermal power stations, which must operate with high load factor, more than 80%, to complement its hydro plants. Those thermal plants are not consistent with a huge and strongly liked hydro system. Are we planning to repeat the same mistakes again?

new gas-fired power plants would be cheaper than new nuclear facilities (both are more expensive than several other hydro plants though). And even more important, the direct use of natural gas to substitute thermal uses of electricity would certainly be the most rational and cost-effective energy strategy for the country. Angra III will not help Brazil to improve the final use of electricity. By creating additional excess of electricity supply, energy rationalization will be postponed again. In the 1970s, Brazil made two serious mistakes: (i) it invested excessively in energy infrastructure instead of investing in human capital, i.e., education for its people; and (ii) it opted for thermal power stations, which must operate with high load factor, more than 80%, to complement its hydro plants. Those thermal plants are not consistent with a huge and strongly liked hydro system. Are we planning to repeat the same mistakes again? In 2001, when the country was running out of water, creating an energy shortage, for despair of the government, the Civil House, on behalf of the President, took over all the power on Energy Affairs. The result was a billion dollar gas-fired power program, which made little or no economic sense. Unbelievably, the Civil House is still trying to move back into the energy forum. After major changes in government, the former Energy Minister took power at the Civil House and, surprisingly, became to be more favorable to Angra III. Will the Civil House continue on its present course, even at the risk of driving the country to another mistaken energy policy? About the Authors: Edmilson Moutinho dos Santos is an Associate Professor at the Graduate Energy Program of the University of Sao Paulo, Brazil, specializing in energy economics and policy. He is a member of the editorial committee for Energy Politics. Rafael Judar Vicchini is graduate student in economics at the University of Sao Paulo, researching in energy economics and policy. He holds a scholarship from the Brazilian government - The Human Resource Program from the National Petroleum Agency (PRH-04/ANP).


Country Assessment – India

Colin Campbell

The Republic of India covers an area of some 3M km2, making it the seventh largest country in the World. Topographically, it is divided into a mountainous north, flanking the Himalayan Range; the North Indian Plain, drained by the Indus and Ganges Rivers; and the Deccan Plateau in the south, which itself is flanked by the Western and East Ghat mountain ranges, locally rising to around 3000m. Its climate is characterised by three seasons: hot and wet from June to September; cool and dry from October to February; and hot and dry from February to June. But they are subject to marked annual variations, spelling famine if the rains are late or weak, or flooding in the opposite case. Much of the country is forested. In geological terms, India forms a segment of the ancient southern continent of Gondwanaland that moved northwards to collide with the Eurasian Plate some 50 million years ago. In regional terms, this continent was deficient in oil prospects, primarily because the conditions for oil generation were restricted in high southern latitudes. It is not surprising, therefore, that India is not rich oil territory, although some marginal basins have delivered modest results. The largest of these, with some 2.5 Gb, is the Bombay High, off the west coast, which was found in 1974. The industry is dominated by the State Company, ONGC, although some small foreign private firms are also active. About 1300 wildcats have been drilled, finding 10.5 Gb of oil, of which 6 Gb have been produced. Exploration drilling peaked in 1991 when 88

INDIA Regular Oil

Population M 1000

Rates Mb/d

Consumption 2004

2.4

per person b/a 0.9

Production 2004

0.685

Forecast 2010 0.52

Forecast 2020 0.33

Discovery 5-yr average Gb

0.01

Amounts Gb

Past Production 6.1

Reported Proved Reserves*

5.37

Future Production - total

5.4

From Known Fields 4.5

From New Fields 1.0

Past and Future Production

11.5

Current Depletion Rate 4.4%

Depletion Midpoint Date

2003

Source: Oil and Gas Journal

EP Regular Features


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wildcats were drilled, but is now down to about half that number. A fairly high level of activity is likely to continue, as the country is in desperate need of oil, but is unlikely to be rewarded by more than perhaps another billion barrels, mainly in small fields. Some interest is now being devoted to deepwater possibilities, but the outcome is far from assured. Production stands at 685 kb/d, which is likely to be the peak, the midpoint of depletion having been passed in 2002. At the current Depletion Rate of 4.4%, production is set to fall to about 500 kb/d by 2010 and 330 kb/s by 2020. Consumption stands at 2.4 Mb/d, giving the country a large and growing need of imports, which will be increasingly difficult to obtain. This readily explains why State-backed Indian companies are taking up rights overseas in for example the Sudan, Libya, Iran and Venezuela (see also Items 511 and 513). The country’s gas potential is also limited. Only 42 Tcf have been discovered, of which 13 Tcf have been produced. Production stands at about 2 Tcf/a. The country has substantial coal deposits, although some have a high arsenic content which has caused serious environmental damage in the past.

About the Author: Colin Campbell is the Chairman of the Association for the Study of Peak Oil and Gas.


The major dilemma is simple and widespread, and cannot be referred to often enough: Mr and Ms consumer are still unable to comprehend that are moving toward a world in which we are not going to have access to the inexpensive oil to which we believe we are entitled.

.

Bank on It Commentary by Ferdinand E. Banks

Economic Theory and Some Oil Market Realities

Not too long ago I had the great pleasure of giving a long lecture on oil at the Royal Institute of Technology in Stockholm, where I once studied mathematics in a building that is still known as ‘Sing-Sing’ (after the US prison of the same name.) And once again I discovered, to my great surprise, that even at this late date the realities of the present world oil market have not been absorbed by the future engineering elite to a desirable extent.

The major dilemma is simple and widespread, and cannot be referred to often enough: Mr and Ms consumer are still unable to comprehend that are moving toward a world in which we are not going to have access to the inexpensive oil to which we believe we are entitled. Eleven years ago the Energy Journal presented a special issue called ‘The Changing World Petroleum Market’ (1994) in which the future oil and gas scene was systematically misrepresented by a number of prestigious energy economists. In their vision of the 21st century, not only was oil “plentiful”, but OPEC was a fragile construction due to the enormous amount of oil and gas that could or would eventually be discovered in the unexplored or only partially explored regions of the globe. In terms of mainstream geology, this kind of thinking hardly deserved to be labeled bizarre, but even so it attracted a sympathetic audience.

A basic difficulty was and is the inability of many observers to accept that technology cannot discover or produce oil that does not exist; and where it does exist, it may not be what many students of this subject think that it is. A perfect example here is the tar sands of Northern


Professor Maureen S. Crandall of the United States National Defense University, in a discussion of the huge resources that ostensibly will be made available by extensive exploitation of the Caspian region (2005), makes the following unwelcome observation: “But this producing region as a whole, while accounting for billions of dollars in investments, is unlikely to be a large and sustained future producer and contributor to the world’s energy supplies, and cannot be considered of strategic energy importance to the US.”

This decline is not certain, but it might be useful to remember that the major part of today’s oil production – at least 70% – comes from deposits discovered before 1970. This is hardly worth pondering, given that global oil discovery peaked about 1965.

Canada, whose resources have now been officially added to proved Canadian reserves of oil, thereby turning that country into a rival to Saudi Arabia in the oil reserves league.

Professor Douglas Reynolds has examined the realities of Canadian tar sands in the latest issue of the OPEC Review (2005). As he makes clear, “Physics, economics and engineering management all point to one thing – oil sand is not the same as crude oil. By defining oil sand bitumen as proven reserved of crude oil, we are setting up the oil and energy markets for a large price spike – a shock.” A version of this comment could probably be applied to the heavy oil of Venezuela, along with a reminder that from a thermodynamic point of view, both heavy oil and oil from tar sands do not have a great deal to offer.

Another important issue in these matters concerns attracting investment dollars to non-profitable undertakings, which is something that I touched on in my energy economics textbook (2000) and several recent papers, but which apparently was not appreciated by a number of influential readers. However Professor Maureen S. Crandall of the United States National Defense University, in a discussion of the huge resources that ostensibly will be made available by extensive exploitation of the Caspian region (2005), makes the following unwelcome observation: “But this producing region as a whole, while accounting for billions of dollars in investments, is unlikely to be a large and sustained future producer and contributor to the world’s energy supplies, and cannot be considered of strategic energy importance to the US.”

The same judgement applies to other ‘oil producing regions of great promise’, but it is best at this time to sum up the situation introduced above with a quote from Craig Bond Hatfield (1997). “The coming era of permanent decline in oil-production rate and the economic and social implications of this phenomenon demand serious planning by the world’s governments.” This decline is not certain, but it might be useful to remember that the major part of today’s oil production – at least 70% – comes from deposits discovered before 1970. This is hardly worth pondering, given that global oil discovery peaked about 1965. Similarly, rumors have started making the rounds that the


At the present time Saudi Arabia supplies almost a third of OPEC oil, and given their reserve situation relative to the other OPEC (and non-OPEC) countries, this fraction will hardly decrease. (Saudi Arabia has proven reserves of 260 billion barrels, while second place Iraq has 120 billion barrels.) Accordingly, it seems that IEA experts believe that Saudi Arabia will supply about 20 mb/d in 2030.

It will not be easy for Saudi Arabia to supply 20 mb/d in 2030, or at any other time in the near or distant future. A high-ranking Saudi official recently stated that 15 mb/d should be possible, which undoubtedly sounded lovely to motorists in the large oil importing countries – if they were listening.

relatively new discoveries in Russia and West Africa may not live up to expectations.

SOME BASIC ECONOMICS

Recently the International Energy Agency (IEA) published its latest ‘World Energy Outlook’, in which the conclusion was advanced that the availability of oil in terms of reserves and production will not be a problem as long as a few trillion dollars can be mobilized to finance new wells and pipelines, as well as capital intensive items such as refineries and tankers.

In addition, that organization has postulated an increase in the world oil demand from the present 84 mb/d to 121 mb/d in 2030. Normally, I would express some curiosity as to the scientific background for that estimate, however I have heard it a number of times, and it is almost the same as a recent estimate of the United States Department of Energy (USDOE). At the time when this 121 mb/d is supposed to be produced, OPEC is pictured as being responsible for about one-half (as compared to approximately 38% just now). This suggests an OPEC production of approximately 60 mb/d. At the present time Saudi Arabia supplies almost a third of OPEC oil, and given their reserve situation relative to the other OPEC (and non-OPEC) countries, this fraction will hardly decrease. (Saudi Arabia has proven reserves of 260 billion barrels, while second place Iraq has 120 billion barrels.) Accordingly, it seems that IEA experts believe that Saudi Arabia will supply about 20 mb/d in 2030.

It will not be easy for Saudi Arabia to supply 20 mb/d in 2030, or at any other time in the near or distant future. A high-ranking Saudi official recently stated that 15 mb/d should be possible, which undoubtedly sounded lovely to motorists in the large oil importing countries – if they were listening; but although my knowledge of geology is limited, the energy economics that I have taught left me with the belief that the 12.5 mb/d recently promised by the Saudi Arabian king to President George Bush is a more realistic goal. This particular output is supposed to become available by 2010.


A report from the consulting firm PFC Energy (as mentioned in the Petroleum Economist, October 2004) states that OPEC is producing about 8 billion barrels a year more than it has been finding.

This situation might change if e.g. Libya and Iraq intensify their exploration activities, however there is little or no reason to believe that this will be of other than marginal significance for the IEA and DOE targets mentioned above.

There is also some question as to what OPEC as a whole will be able to achieve. A report from the consulting firm PFC Energy (as mentioned in the Petroleum Economist, October 2004) states that OPEC is producing about 8 billion barrels a year more than it has been finding. This situation might change if e.g. Libya and Iraq intensify their exploration activities, however there is little or no reason to believe that this will be of other than marginal significance for the IEA and DOE targets mentioned above.

During the question and comment phase of the lecture mentioned in the first paragraph of this paper, I was cheerfully informed that OPEC producers are increasingly aware that erratic behavior on their part might result in their being confronted by a deluge of synthetic liquids, with natural gas being the most popular input. This kind of situation sounds consistent with the approach taken in a mainstream intermediate microeconomics textbook – assuming that you and your teacher did not confine your reading to the first few chapters – but even so it has no basis in reality: there is not enough natural gas to bring this about except in the fantasies of journalists, and for various reasons coal is no longer a contender. Of course, even if it were possible, the producers of onventional oil might – in theory – merely dump their prices when the new oil comes on the market, and therefore wipe out the profit of the intruders.

Almost thirty years ago Crown Prince Fahd of Saudi Arabia informed the large oil importing countries that their best strategy was to moderate their consumption of oil, while introducing as rapidly as possible alternative sources of energy. (Similar thoughts were expressed by the very visible and highly respected oil minister of Saudi Arabia, Sheikh Zaki Yamani.) Prince Fahd also emphasized the need to preserve his country’s petroleum wealth for future generations, and made it clear – by actions as well as words – that Saudi Arabia recognized its position as a critical component in the global oil supply nexus – both present and future – and would do everything possible to maintain an adequate margin of spare capacity that could be used in


the event of an unforseen escalation in global demand. A large part of this is forgotten or overlooked by many journalists and pseudo-scholars in the consuming countries, however it is an undeniable part of the history of the past thirty or forty years.

CONCLUSION: GENIUS AT WORK

Given the actual and potential economic growth in the world economy, there is no such thing as an enormous reserve base! There is instead a limited amount of oil in the crust of the earth that it is in the interest of both buyers and sellers to preserve for many more years in both the stock and flow sense – that is, not just as petroleum in the ground, but available as inputs for the durable items that were purchased by consumers and producers in the belief that they would not be kept from using them because of the lack of a critical input, where by by “critical input” I mean what George Monbiot calls “the resource on which our lives are built”.

REFERENCES

Adelman, M.A. (1994). ‘The world oil market: past and future’. The Energy Journal.

Banks, Ferdinand E. (2005). ‘Logic and the Oil Future’. (Forthcoming)

______. (2004). ‘A new world oil market’. Geopolitics of Energy (December).

______. (2000). Energy Economics: A Modern Introduction. Dordrecht and Boston: Kluwer.


______. (1998). ‘World energy and the 21st Century’. The OPEC Bulletin (July).

Carr, Donald E. (1978). Energy and the Earth Machine. London: Abacus.

Crandall, Maureen (2005). ‘Realism on Caspian Energy’. IAEE Newsletter (Spring).

Griffin, James M. and Lawrence Vielhaber (1994). ‘OPEC production’. The Energy Journal.

Hatfield, Craig Bond (1997). ‘Oil back on the global agenda’. Nature (May).

Odell, Peter R. (1994). ’World oil resources: reserves and production.’ The Energy Journal.

Reynolds, Douglas (1995). ‘The economics of oil definitions’. OPEC Review (March).

About the Author:

Ferdinand E. Banks is an Occasional Lecturer in Industrial Organization at the Nationalekonomiska Inst., Uppsala University and a Visiting Professor at the ENI Corporate University, Milan Italy. e-mail: [email protected]


Editorial Committee – Moscow

Office EUGENE (YEVGENY)

KHARTUKOV Editorial Committee – Calgary

Office Western Division Alli Marshall

The Energy Politics Editorial Committee Prof. Khartukov is a leading international expert on Russian and ex-Soviet oil and gas issues. During 1970-82, he worked in various research centers, departments and enterprises of the USSR ministries of geology, of oil and gas industry, of foreign trade and of foreign affairs. Since 1980, teaches world oil and energy markets research at the Moscow State University for International Relations (MGIMO), USSR/RF Ministry of Foreign Affairs. Since 1984, heads the Moscow-based World Energy Analysis & Forecasting Group (GAPMER), advises and consults on oil and gas economics and policies and energy pricing to various Soviet/Russian ministries, international agencies, foreign governments, private oil and gas companies, consulting firms and financial institutions, as well as to Gorbachev, Yeltsin and Putin administrations. In 1994-95 – Head of Russia Energy Project, East-West Center, Hawaii, USA. Since 1995 – Vice President (for Eurasia) of Petro-Logistics Ltd, Switzerland. Since 1996 – General Director of (International) Center for Petroleum Business Studies (ICPBS/CPBS), Moscow, and Professor of Marketing & Management at MGIMO. Since 2003 – Director (for International Affairs) of PetroMarket Research Group, Moscow. Prof. Khartukov has authored and co authored over 250 articles, brochures and books on petroleum and energy economics, politics, management, and Russia’s Far East. Participated as a speaker and/or a session chairman in more than 150 international energy, oil and gas and economic fora.

Alli Marshall is a Fundamentals Analyst with EnCana Corporation's Gas Marketing group in Calgary, Alberta. She began her current role in Sept, 2004 after 5 years of work as a geophysicist. Her geophysics background includes several years of seismic processing and new technologies such as inversions and attribute analysis and 2 years of exploration in the Deepwater Gulf of Mexico with a focus on salt tectonics. She graduated from the U of C in 1999 with an H.B.Sc. in geology and geophysics and a minor in philosophy. Alli's current work responsibilities include country-specific gas market analysis (regulatory environment, supply, demand, pricing, and market risks), LNG, and global natural gas and oil production forecasting.

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Energy Politics Summer 2005