39 Chapter 2 a Requiem for the Uk's Petroleum Fiscal

CHAPTER 2

A REQUIEM FOR THE UK’S PETROLEUM FISCAL REGIME

Juan Carlos Boué and Philip Wright

Introduction

If current newspaper headlines are anything to go by, thanks to the events of 2008/9 in world financial markets, free market fundamentalism is apparently now on life support, if not necessarily as an ideology, then certainly as a guide for government policy. Indeed, Joseph Stiglitz has gone so far as to assert that ‘the fall of Wall Street is to market fundamentalism what the fall of the Berlin Wall was to communism’ (Stiglitz, 2008). That said, the glacial pace at which financial reform is progressing suggests that, as of the time of writing, reports of the death of free market fundamentalism, even within the banking sector, might have been overoptimistic. Outside the financial sector, the penning of obituaries looks even more premature, as the sort of approach to government intervention, regulation, and taxation that is now routinely denounced by politicians as anathema in connection with banks and financial markets (albeit with decreasing vociferousness and conviction with the passage of time), is still presented as non-problematic – even desirable – in many other walks of life, where free market fundamentalism may nonetheless have wreaked a similar or even greater degree of damage (in relative, if not necessarily absolute, terms). The British policy towards oil and gas exploration and production activities can be used as an example. This policy, which we shall refer to as the UK North Sea Model, has been the standard-bearer for upstream liberalisation initiatives in the international oil industry for a long time, in much the same way as the British experience used to be a required reference point for anyone interested in pursuing the wholesale deregula- tion of financial markets. However, unlike financial liberalisation, the UK North Sea Model has lost none of its lustre, and is still consistently hailed as an all-too-rare example of enlightened governmental practice. This is remarkable, as the UK North Sea Model is a policy that embodies all the excesses of free market fundamentalism, and its consequences, as we shall show, have to be seen as resounding failures.

39 40 UK Energy Policy and the End of Market Fundamentalism

In popular perception, the application of free market fundamentalism to energy industries in the UK is seen as being restricted to a set of transformations of ownership and industrial structure, which applied in the main to downstream activities. Liberalisation, in other words, is seen to have been the stuff of electricity and downstream gas, much more than of upstream oil and gas. This viewpoint, however, is misconceived. For one thing, upstream oil and gas assets – the upstream interests of both the British National Oil Corporation (BNOC) and British Gas and, arguably, the government shareholding in British Petroleum – figured prominently in the privatisation wave that swept Great Britain during the 1980s and early 1990s.1 Furthermore, the genesis and expansion of forward and futures markets for Brent crude oil were also at the forefront of a marketisation and financialisation process that radically transformed the international oil trade, which has come to hang on the price signals emitted from a small set of paper and cash markets whose joint trading volume is a significant multiple of daily global crude oil production (Mabro, Bacon, Chadwick, Halliwell, and Long, 1986; Horsnell and Mabro, 1993). Finally, if laissez-faire is indeed one of the hallmarks of free market fundamentalism, then there can be no question that upstream oil and gas was one industry where its principles were applied most dogmatically. Consider that corporations involved in downstream energy activities had at least to take account of the presence, and views, of a variety of regulators, whatever their shortcomings. The situation in the UKCS (United Kingdom Continental Shelf) was different: starting with the dismantling of BNOC in 1985 and culminating in the abolition of the Department of Energy in 1992 (and its absorption by the Department of Trade and Industry), the UK government quite explicitly abdicated its upstream oil and gas policy role in favour of oil companies, retain- ing a say only in matters related to industrial safety, decommissioning, environmental protection, and, nominally at least, taxation. Thus, throughout most of the 1990s and up until very recently, the UK provided the unusual spectacle of being among the very few countries belonging to the OECD and the IEA that did not have a cabinet-level post for energy.2 In this respect, the UK also differed from every other major oil exporting country in the world, bar none. Quite apart from the above, the clearest confirmation of the fact that free market fundamentalism has held sway unopposed in the UKCS can be found in the realm of tax. One of the central tenets of free market fundamentalism is that action undertaken by the state in pursuit of the public purpose should be predicated on ensuring that the returns received by corporate capital are as attractive as possible, A Requiem for the UK’s Petroleum Fiscal Regime 41 and not necessarily limited to a risk-adjusted rate of return sufficient to allow for the reproduction of capital. Among the panoply of policy instruments that governments were supposed to deploy in pursuit of this objective, fiscal incentives and tax cuts occupied pride of place, as the cost to the public purse that they entailed would supposedly be more than compensated through an eventual increase in tax receipts derived from the higher level of economic activity that would be induced by the tax break (the supply-side argument at the core of Reaganomics). Therefore, an unjustifiably generous level of taxation constitutes an excellent diagnostic tool to ascertain the strength of the grip on an industry or activity taken by free market fundamentalism. If one ap- plies this yardstick to the case at hand, and analyses the relaxation of the UKCS fiscal regime, it is apparent that a particularly intense form of free market fundamentalism gradually came to prevail in the UK upstream sector from 1983 onwards. As can be appreciated from Appendix 2.1, a fundamental shift occurred in the tax stance of the UK between 1983 and 1993. This involved significant reductions in tax, in particular the dismantling of special taxes on the UK’s oil and gas resources – successive downward adjustments in, and more generous exemptions from, Petroleum Rev- enue Tax (PRT), as well as reductions in royalties. These relaxations in the UK’s petroleum fiscal regime ostensibly sought to stimulate exploration and development, first by providing targeted tax breaks (1983, 1987, 1989), and then more general tax relief (1993). However, Rutledge and Wright (1998) established that the resulting laxness in the UK’s petroleum fiscal regime did not produce the desired outcomes. In addition, the generosity of the UK fiscal regime was not a reflection of relatively poor UKCS profitability (either in relation to the rest of the UK corporate sector or to oil industry investments elsewhere in the world), and nor could it be justified by generic criteria such as historical and international comparisons, or the particular risk associated with oil and gas industry investments. More over, the conclusions of this analysis were echoed by the oil industry specialist Petroconsultants, which trenchantly characterised the UK’s petroleum fiscal regime in the mid-1990s as lacking the essential (and otherwise prevalent) correspondence between prospectivity and taxation: The regime which most notably does not fit into any of the general trends identified above is the UK. Geological prospectivity and the development of infrastructure in the UK is relatively good and recent exploration suc- cesses suggest that large profitable fields continue to be found. The potential returns from UKCS are, however, second only to Ireland [a country with very low prospectivity]. The State take comprises only Corporation Tax, having 42 UK Energy Policy and the End of Market Fundamentalism

gradually abolished all ‘special’ petroleum levies for new fields since 1993. The risk/reward balance for the investor is therefore highly favourable under current terms. (Petroconsultants 1995, 9). From Table 2.1, one can summarise the effect of the weakening in the UKCS regime at this time in terms of three indicators: 1. In 1987 (that is after the dramatic fall in oil prices of 1986), fiscal revenues per barrel were £3.80, but by 1999 they had fallen to £1.50. 2. As a proportion of unit sales revenue, fiscal revenues were 39.5 per cent in 1987, but only 15.9 per cent in 1999. 3. In 1987 the government was claiming 67.6 per cent of company Net Operating Surplus, but by 1999 this had fallen to 36.4 per cent. Thus, in 1987, UKCS production of oil and gas was 1,229 million barrels of oil equivalent (mboe), unit sales revenue was £9.70 per barrel of oil equivalent and fiscal revenues totalled £4,685 million. Twelve years later, in 1999, unit sales revenue was also between nine and ten pounds per barrel, production was almost 40 per cent higher at 1,710 million barrels, but fiscal revenues were only £2,551 million. This dramatic fall in fiscal revenue, of course, went completely against the grain of the supply-side argument that had been used to justify the tax cuts in the first place; namely, that a lower rate of tax would stimulate activity in such a way that tax revenue would actually grow. During the decade of the 1990s, that argument was conveniently forgotten, with the UK government increasingly taking the fallback position that fiscal revenue sacrifices were essential if companies with activities in the UKCS were to continue investing, and output was to continue growing. Indeed the government, time and time again, pointed to the increase in UK production of hydrocarbons (due in large part to the fact that gas production more than doubled) as a clear vindication of its low tax policy. However, this incremental production was not accompanied by any investment for the future. Apart from a brief spurt of mandatory investment derived from the companies’ need to comply with the improvements required by the Cullen report into the Piper Alpha disaster of 6 July 1988, the trend for real investment in the UKCS was one of decline: by 1999, for instance, it was well below what it had been in 1987, itself a year in which investment had stalled as a consequence of the 1986 fall in oil prices.3 Indeed, despite the Conservative government, oil companies, and certain academics relentlessly putting out the message in the media that a suspension of the downward trend (let alone an increase) in taxation would lead to an exodus of investment, companies were actually quite open about using A Requiem for the UK’s Petroleum Fiscal Regime 43 9,422 7,787 7,839 8,644 9,300 8,623 9,837 8,581 6,780 5,303 5,691 6,227 7,738 9,501 7,822 6,042 Total Total prices) 11,680 10,745 10,037 Investment (£m,2005 16.2 11.4 22.8 41.5 49.8 59.7 63.9 59.0 63.1 67.4 67.6 80.4 69.6 57.0 37.9 39.1 33.2 30.9 100.2 Fiscal Revenues as Surplus (%) Percentage of Net Operating 441 1,794 2,154 4,549 7,135 9,836 6,431 6,928 4,422 3,736 4,135 3,556 3,217 3,865 5,111 11,777 14,536 17,948 17,178 Net (of Operating Depreciation) Surplus (£m) 7.9 8.1 15.2 30.3 37.4 44.5 48.9 47.3 51.8 53.6 57.4 39.5 37.9 26.9 21.3 12.3 11.6 10.5 11.8 (%) Fiscal Revenues as Percentage of Unit Revenue 0.2 0.4 0.7 2.2 4.2 6.4 7.4 7.7 9.6 9.4 5.2 3.8 3.1 2.7 2.3 1.3 1.2 1.1 1.1 (£) Fiscal Barrel of Equivalent Oil & Gas Revenues per 71 205 492 1,886 3,553 5,870 7,528 8,580 6,446 4,685 3,556 2,599 2,358 1,348 1,258 1,284 1,579 basis) 11,333 11,571 Tax, £m, Tax, Total UKCS Total calendar year + Corporation (Special Taxes (Special Taxes Fiscal Revenues 86 245 574 2,323 3,963 6,506 7,868 8,817 4,804 4,645 3,193 2,401 2,343 1,016 1,338 1,266 1,683 12,171 11,371 beginning) Tax, £m, Tax, Total UKCS Total financialyear + Corporation (Special Taxes (Special Taxes Fiscal Revenues 2.7 4.7 4.9 7.4 9.0 9.7 8.2 9.9 9.5 11.1 14.4 15.1 16.3 18.5 17.6 11.0 10.5 10.1 10.1 Gas (£) Unit Sales Revenue for UKCS Oil & 331 539 659 840 852 917 975 1,021 1,112 1,185 1,231 1,242 1,229 1,149 1,004 1,038 1,068 1,202 1,398 Production equivalent) (millions of Hydrocarbon Total UKCS Total barrels of oil 32.0 33.6 33.9 34.2 33.1 32.8 32.9 33.3 32.9 36.5 38.5 40.5 38.7 38.3 42.3 47.1 48.1 60.1 59.5 Gas Production equivalent) (millions of tonnes of oil The Production,UKCS: Taxes,Prices, ReinvestmentandProfits, 1976–2008 12.2 38.3 54.0 77.8 80.5 89.5 91.7 91.6 91.3 94.3

103.2 114.9 125.1 127.6 127.1 123.4 114.5 100.2 126.9 tonnes) Liquids Production (millions of Table 2.1: Table 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 44 UK Energy Policy and the End of Market Fundamentalism 6,948 6,725 6,543 6,750 4,041 3,516 4,433 4,301 3,918 3,773 4,831 6,254 6,048 5,580 Total Total prices) Investment (£m,2005 35.2 32.1 41.7 48.7 36.4 27.2 38.7 41.1 36.9 37.2 47.4 41.8 38.4 37.3 Fiscal Revenues as Surplus (%) Percentage of Net Operating 6,171 9,643 7,996 5,586 7,005 14,627 13,391 12,635 12,173 13,288 17,581 21,882 21,192 31,339 Net (of Operating Depreciation) Surplus (£m) 14.9 17.3 20.5 20.4 15.9 16.6 22.8 22.9 20.4 22.3 30.6 29.5 28.0 30.8 (%) Fiscal Revenues as Percentage of Unit Revenue 1.5 2.0 2.1 1.7 1.5 2.4 3.2 3.3 3.0 3.6 6.8 8.2 7.7 (£) 11.6 Fiscal Barrel of Equivalent Oil & Gas Revenues per 2,174 3,098 3,336 2,718 2,551 3,984 5,186 5,195 4,490 4,949 8,328 9,149 8,144 basis) 11,697 Tax, £m, Tax, Total UKCS Total calendar year + Corporation (Special Taxes (Special Taxes Fiscal Revenues 2,338 3,351 3,331 2,514 2,563 4,457 5,429 5,117 4,281 5,172 9,380 9,072 7,835 12,984 beginning) Tax, £m, Tax, Total UKCS Total financialyear + Corporation (Special Taxes (Special Taxes Fiscal Revenues 8.3 9.4 10.0 11.5 10.5 14.2 14.3 14.4 14.7 16.2 22.1 27.9 27.4 37.6 Gas (£) Unit Sales Revenue for UKCS Oil & 1,464 1,557 1,554 1,609 1,710 1,694 1,596 1,574 1,499 1,371 1,232 1,111 1,060 1,008 Production equivalent) (millions of Hydrocarbon Total UKCS Total barrels of oil 64.8 77.6 79.0 81.9 90.8 99.6 96.1 94.0 93.8 87.4 79.5 71.6 64.8 62.7 Gas Production equivalent) (millions of tonnes of oil continued 95.4 84.7 76.6 76.6 71.7

130.3 130.0 128.2 132.6 137.1 126.2 116.7 115.9 106.1 tonnes) Liquids DECC (2010a); DECC (2010b); ONS (series LRWY) Production

(millions of gas bcm converted to Mtoe at 0.92; tonnes converted to barrels at 7.5; unit sales revenue calculated astotal UKCS sales revenue from oil and gas divided by oil and gasfinancial production to ain calendarbarrelsyear of basisby addingoil e.g.January-March plus 2007-08financialoilyear revenues in financial orderequivalent to arrive yearat calendargas;revenues 2008 revenues; only to thefiscal calendaryear data revenues is April-December used in calculations.converted 2008-09 from a

Sources: Notes: Table 2.1: Table 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 A Requiem for the UK’s Petroleum Fiscal Regime 45 the cash flows generated by their UKCS activities to fund investments outside the UK, courtesy of the British taxpayer: The UK North Sea provides a strong stream of earnings and cash flow with relatively modest reinvestment needs. This is important for the funding of the Company’s plans in other strategic areas’. (Oryx Energy, 1996, 4) From the mid-1980s onwards, then, the UKCS fiscal regime was transformed into a vehicle to deliver a form of corporate welfare. Such was still the situation at the dawn of the twenty-first century, despite the arrival of New Labour in power in 1997. Initially, it seemed as if the new government intended to change the petroleum fiscal regime, but neither of the two options tabled as possible reforms – an increase in Petroleum Revenue Tax or the introduction of a Supplementary Corporation Tax (HM Treasury, 1998) – was taken up at that point. A depressed price environment and concerns about job losses in Scotland (and how these would play into the hands of the Scottish National Party, which was radically opposed to the increase in taxation because of its assumed effect on jobs) were the reasons most often cited for the lack of concrete action.4 If anything, the tax regime became even more favourable under New Labour, as a result of successive reductions in the standard rate of Corporation Tax: from 33 per cent to 31 per cent in 1997, and then down to 30 per cent in 1999. The New Labour policy on upstream oil and gas initially carried on where the Conservatives had left off. Then, on the face of it, upstream oil and gas policy represented one of the instances where the Labour government decided to part company with Conservative precedent. The rise in international oil prices from 2000 onwards seemingly prompted a rethink about whether the UKCS tax regime might indeed be too generous for investors. Thus, in 2002, and amidst a predictable outcry from the oil industry, a Supplementary Corporation Tax (SCT) of 10 percentage points was introduced.5 In 2006, SCT was further increased to 20 percentage points. At the time, much was made of the fact that these measures would allow the government to gain more from the increase in the oil price. In fact, though, the matter was not nearly as clear cut as that, since the introduction of SCT was accompanied by the abolition (from January 2003 onwards) of all remaining royalty obligations, as well as by an even more generous tax treatment of capital investment (see Appendix 2.1). However, in October 2008, the UK government took another step which could be interpreted as signalling unease with the outcomes derived from free market fundamentalism in the energy sector; namely, the creation of the Department of Energy and Climate Change (DECC) and thereby a cabinet-level post with responsibility for energy. 46 UK Energy Policy and the End of Market Fundamentalism

These developments beg a couple of obvious questions. Firstly, have the modifications to the UK’s petroleum fiscal regime since 2002 really resulted in a reversal of the long-term trends derived from its liberalisation? Secondly, if that is indeed the case, can they be seen as the harbingers of a radical change in direction for policy towards the UKCS?

A Reversal for the UK’s Petroleum Fiscal Regime Post-2001?

In order to answer these questions it is necessary to evaluate the performance of the UK’s petroleum fiscal regime after its alleged re-invigoration. This will be done by using the indicators deployed in the previous section (fiscal revenues per barrel, as a proportion of unit sales value and as a proportion of Net Operating Surplus); by estimating rent and its capture; by calculating the residual free cash flow available to companies; by comparing UKCS company profitability with non-UKCS company profitability; by calculating the rate of reinvestment in the UKCS, and by making a comparison with the performance of the petroleum fiscal regime deployed by near neighbours with North Sea oil and gas reserves. Estimates of fiscal revenues foregone will then be made and, finally, the arguments deployed to justify the current UK fiscal regime, or to advocate its further weakening, will be discussed.

Response of Fiscal Revenues to Rising Oil Prices 2002–9

Fiscal revenues in the UKCS since 1976 are shown in Figure 2.1 (oil production only started to become significant in 1976). The introduction of the 10 per cent SCT came in financial year (6 April to 31 March) 2002/3, while the increase to 20 per cent happened in financial year 2006/7. As can be appreciated in Figure 2.1 (based on financial years) and Table 2.1 (financial and calendar years), the impact of these changes on fiscal revenues was not straightforward. Between 2001 and 2003, for instance, when oil and gas unit sales revenue stayed more or less steady – £14.3 to £14.7 per barrel of oil equivalent – fiscal revenues fell (as the negative effect of the abolition of royalties and capital allowances, together with some issues related to timing of receipts, more than overshadowed receipts from the new tax). After 2003, prices rose, and so did tax receipts, to £9,380 million in financial year 2005/6 (Table 2.1). However, as prices continued on their upwards trend, fiscal revenues fell in the subsequent two fiscal A Requiem for the UK’s Petroleum Fiscal Regime 47 years (and after the increase in SCT rate), down to a level of £7,835 in financial year 2007/8. The official explanation for this sluggish response of the tax system to sharply rising prices involves transitional arrangements for payment (see HM Treasury, 2002), plus the later alignment with Corporation Tax payments, as well as increasing costs and lower overall production.6 An official government publication

14,000

12,000

10,000

8,000

£million 6,000

4,000

2,000

0 1968-69 1973-74 1978-79 1983-84 1988-89 1993-94 1998-99 2003-04 2008-09

Supplementary Charge (£m) Supplementary Petroleum Duty (£m)

Corporation Tax (£m) Oil Royalties £m

Petroleum Revenue Tax (£m) Licence Fees (£m)

Figure 2.1: UKCS Fiscal Revenues: A Breakdown 1964–2009 Source: DECC (2010a) Note: the UKCS fiscal revenue series do not include any dividends or other payments from the UKCS production operations of the formerly-nationalised or part-nationalised British National Oil Corporation, British Gas Corporation, and British Petroleum. The British National Oil Corporation (BNOC) was established in 1975, primarily as a security of supply trading organisation. However, it did have upstream operations which were privatised as Britoil when BNOC was shut down in 1982. Britoil was bought by BP in 1988. British Gas was privatised in 1986, while nearly all the government’s holding in BP was sold off in tranches between 1979 and 1987 (when most of the remaining 32 per cent holding was sold off, leaving just 1.8 per cent to be sold in 1995). Unfortunately it is impossible to isolate these possible sources of additional UKCS revenue. On the other hand, and as is the case with Statoil dividends for the Norwegian government, these sources of UKCS income are unlikely to emerge as very significant compared with the government’s tax and royalty sources 48 UK Energy Policy and the End of Market Fundamentalism summarises the erratic behaviour of fiscal revenues over the latter half of the decade thus:

The yield reached a high point in 2005/06 and 2006/07, boosted by a change in the instalment regime for North Sea companies and an increase in the rate of the supplementary charge to 20 per cent, but declined in 2007/08 as a result of lower production and high costs. However, there was a resurgence in receipts in 2008/09 in response to higher average oil and gas prices. (DECC, 2010a) In financial year 2008/9 (a period during which oil prices reached a record high of more than 140 dollars per barrel, in July 2008), fiscal receipts in the UKCS rose to £12,984 million. Observers well-disposed towards the UK North Sea Model saw, in this resurgence of fiscal revenues, conclusive evidence that the adoption of SCT has rendered the tax system both highly efficient and progressive. The default position of such observers appears to be that, given 100 per cent capital allowances, at least 50 per cent of the free cash can be safely assumed to be returning to the Government via SCT (Johnston, 2008, 45). However, ex post analyses of government data (such as this one) indicate that this particular threshold has never been reached. Indeed, the degree to which ex post statistics are studiously and systematically ignored in academic discussions about the merits of the UKCS fiscal regime (to the great convenience and benefit of the companies with activities there) is nothing short of remarkable.7 On the basis of the above exposition, the claims that the adoption of SCT heralded a significant change in the thrust of the UK’s petroleum fiscal regime, on the one hand, and that this tax has in effect reversed the tax liberalisation of the UK’s upstream, on the other, appear feeble. Quite apart from that, Figure 2.1 undeniably shows that the fiscal regime’s almost complete reliance on CT and SCT to capture rent has made it significantly less responsive in relation to price than the fiscal regime in place at the time of the previous spike in oil prices (early 1980s) – and which included Royalties, Supplementary Petroleum Duty, and a much higher rate and incidence of Petroleum Revenue Tax. Furthermore, the clearest indication that capturing windfall gains was never the real objective of the allegedly revamped UKCS fiscal regime is to be found in the fact that PRT, the instrument that is still officially highlighted as the UK’s main rent targeting device (HM Revenue and Customs, 2008, para 1.11), has in practice been allowed to wither away. Today, even in a very high price environment, only a minority of the fields potentially liable to pay PRT continue to do so (32 out of 93 fields in 2007; see Earp, 2008). A Requiem for the UK’s Petroleum Fiscal Regime 49

Fiscal Revenue Yield per Barrel and as Percentages of Unit Sales Value and Net Operating Surplus

Figure 2.2 (see Table 2.1 for the data) reveals three straightforward points about the changes in fiscal yield after 2002. Looking at the right- hand axis, which refers to the two series (fiscal revenues and unit sales) expressed in absolute values (as £ per barrel), it can be appreciated that as the unit value of UKCS oil and gas sales rises, the £/barrel fiscal yield increases three and a half times from £3.30 in 2002 to £11.60 in 2008. Looking to the left-hand axis, which provides relative values, the result of this increase in absolute yield was that in 2008 the yield per barrel amounted to 31 per cent of unit revenue and 37 per cent of net operating surplus. The modesty of these proportions is brought into sharp relief by a comparison with the 1980s, when yields were predominantly over 40 per cent of unit value and over 60 per cent of Net Operating Surplus.

120 40

35 100 30 80 25

60 20 £ Percent 15 40 10 20 5

0 0 1976 1980 1984 1988 1992 1996 2000 2004 2008

Fiscal Revenues as Percentage of Unit Revenue (%) Fiscal Revenues as Percentage of Net Operating Surplus (%) Unit Sales Revenue for UKCS Oil & Gas (£) Fiscal Revenues per Barrel of Oil & Gas Equivalent (£)

Figure 2.2: UK Petroleum Fiscal Regime: Absolute and Relative Performance Indicators Source: Table 2.1 50 UK Energy Policy and the End of Market Fundamentalism

Rent Capture

It is a widely held belief that petroleum fiscal regimes should necessarily be designed to capture rent – which in turn should necessarily accrue to the resource owner and not to company operators (as the latter are entitled to a fair return on their investment in relation to risk, but not to windfalls associated with either Ricardian differential rent or to large increases in the absolute level of oil prices which are unrelated to changes in the costs of production). In fact, this is a misconception. Pe- troleum fiscal regimes may be divided into two ‘ideal-typical’ categories, which are radically different in form and in their approach to targeting rents.8 On the one hand, there are proprietorial fiscal regimes, which aim to collect a significant rent for every single barrel extracted, with a strong preference for, and emphasis on, levies on gross income. On the other hand, there are non-proprietorial fiscal regimes, whose raison d’être is that no barrel of oil should be left in the ground as long as it is profitable to produce it, even if the rent such barrel attracts were to fall to zero (see Mommer, 2002a). Both types of fiscal regimes recognise the existence of Ricardian differential rents, or windfall profits. Proprietorial fiscal regimes tend to target such windfall gains aggressively, impelled by the notion that since such gains derive from the ‘original and indestructible powers of the land’ (to use the phraseology that Ricardo applied in an agricultural context), they should accrue to the owner of the land only, all the more so since, in the case of oil and gas, such powers are in fact transient rather than indestructible because natural resources are non-renewable.9 In contrast, non-proprietorial fiscal regimes tend to be lenient in this regard, as their rationale is not to collect rent on a truly marginal barrel, even by accident or oversight. Nevertheless, non-proprietorial regimes recognise that windfall gains may give rise to distortions (particularly where competition is concerned), and distributive justice issues (the incidence of taxation across industries). Thus, such rents might need to be taxed away in the interests of preserving a level playing field for capital in general, albeit in a manner that does not have an effect on the investment decisions of the firms exploiting the resources (that is the incidence of the tax should not lead to any reduction in the amount of capital that would otherwise have been invested by these firms). The UKCS fiscal regime falls squarely in the non-proprietorial camp, as do its analogues in Norway and Denmark (the most telling indication of this is that royalties have been phased out in all three). However, the advocates of the UK North Sea Model have always claimed that it strikes a balance between fostering investment on the one hand, and A Requiem for the UK’s Petroleum Fiscal Regime 51

Table 2.2: Rent and Rent Capture from the UKCS 1976–2008

Net (after Net Capital 15% Rate Estimate of Special Taxes on Rent Capture depreciation) Employed of Return on Rent: Net UKCS Oil & by Special Operating (£m) Net Capital Operating Gas (taxes other Taxes (%) Surplus Employed Surplus minus than standard (£m) (£m) 15% Rate of Corporation Return (£m) Tax,calendar year basis, £m) 1976 441 4,673 701 -260 63 -29.2 1977 1,794 7,119 1,068 726 195 32.4 1978 2,154 9,755 1,463 691 420 69.6 1979 4,549 12,956 1,943 2,606 1,675 79.6 1980 7,135 16,604 2,491 4,644 3,235 78.0 1981 9,836 19,663 2,949 6,887 5,274 84.6 1982 11,777 22,602 3,390 8,387 6,967 87.6 1983 14,536 25,127 3,769 10,767 7,792 73.7 1984 17,948 27,294 4,094 13,854 9,289 70.3 1985 17,178 29,876 4,481 12,697 8,776 66.6 1986 6,431 32,896 4,934 1,497 3,710 142.2 1987 6,928 35,256 5,288 1,640 3,042 204.1 1988 4,422 36,881 5,532 -1,110 2,335 -180.0 1989 3,736 39,284 5,893 -2,157 1,743 -76.9 1990 4,135 40,827 6,124 -1,989 1,537 -75.2 1991 3,556 41,552 6,233 -2,677 658 -14.1 1992 3,217 42,928 6,439 -3,222 587 -20.4 1993 3,865 44,924 6,739 -2,874 920 -35.1 1994 5,111 46,670 7,001 -1,890 1,229 -69.0 1995 6,171 48,443 7,266 -1,095 1,505 -143.5 1996 9,643 49,559 7,434 2,209 2,239 111.4 1997 7,996 49,583 7,437 559 1,779 277.9 1998 5,586 50,919 7,638 -2,052 1,070 -44.3 1999 7,005 52,008 7,801 -796 1,199 -162.6 2000 14,627 50,618 7,593 7,034 1,920 30.3 2001 13,391 48,833 7,325 6,066 1,968 31.6 2002 12,635 48,614 7,292 5,343 1,772 32.3 2003 12,173 49,199 7,380 4,793 1,904 41.0 2004 13,288 49,305 7,396 5,892 2,239 39.6 2005 17,581 48,459 7,269 10,312 3,548 38.3 2006 21,882 47,438 7,116 14,766 4,747 33.9 2007 21,192 47,314 7,097 14,095 4,426 30.0 2008 31,339 47,939 7,191 24,148 6,215 28.5

Source: ONS (series LRWY, LRXC) 52 UK Energy Policy and the End of Market Fundamentalism delivering good value for the Crown (the ultimate owner of the UKCS hydrocarbon resources) by going after Ricardian rents, on the other hand. In the light of the indicators that we have reviewed thus far, it makes sense to evaluate to what extent this claim is true. This requires a calculation of both the rent element in UKCS profits, and of the extent to which so-called ‘Special’ taxes have captured that rent (it is Special taxes on oil and gas production – taxes other than standard Corporation Tax – which are specifically directed at rent). These calculations are found in Table 2.2, in which the procedure was to use a generous 15 per cent as a standard (non-rent) rate of return on capital in order to calculate, on the basis of the official (Office for National Statistics) estimate of Net Capital Employed in the UKCS, the absolute amount of profit corresponding to this figure.10 The latter is then deducted from the official estimate of Net Operating Profit in order to arrive at an estimate of UKCS rent – defined as surplus generated by rates of return above 15 per cent. In Table 2.2, three points are evident. Firstly, up until about the year 2000, rent capture in the UK was subject to significant overshoot and undershoot (hardly surprising considering the volatility of oil markets and the many loopholes that corporations can exploit to ‘optimise’ their PRT and income tax obligations). Since then, however, it appears to be more stable: fluctuating between around 30 and 40 per cent. However, while there is evidence that the first 10 per cent tranche of the SCT did raise rent capture up to around the 40 per cent mark in 2003, 2004 and 2005, the second tranche appears to have been much less effective in the face of unit sales revenue rising to very high levels. Indeed, in 2008, rent capture was less than 30 per cent: UKCS companies were appropriating 70 per cent of rent. Thus, it is fair to conclude that the post–SCT UKCS fiscal regime (unlike, say, the Norwegian fiscal regime, analysed in greater detail below) has not delivered on its promise to capture windfall gains and Ricardian rents and, as a result, still has to be considered a vehicle for the delivery of corporate welfare on a grand scale. In a nutshell, the relative measures of tax incidence in the UKCS have declined as oil and gas prices (and profitability) have risen.

Free Cash Flow and UKCS Profitability

Table 2.3 introduces two further indicators to test the extent to which the introduction of SCT might have made the UKCS fiscal regime less lopsidedly generous for companies. The first of these is a calculation of the ‘free cash flow’ that UKCS companies were left with after deducting all investment and all taxes (both special and standard Corporation A Requiem for the UK’s Petroleum Fiscal Regime 53 55 97 99 101 113 141 146 134 102 123 151 140 174 157 124 149 170 169 207 Development Wells DrilledWells 30 42 27 15 23 28 48 56 84 63 43 70 79 84 67 79 56 61 38 Appraisal Wells DrilledWells 62 68 35 36 34 47 68 79 92 75 74 93 94 77 51 61 107 159 105 Exploration Wells DrilledWells 84.5 41.9 32.8 29.8 28.9 23.1 22.5 21.2 36.3 27.5 39.8 48.0 58.3 84.1 84.9 64.8 44.1 Total Total 286.0 105.8 Surplus Operating % of Gross Investment as (£m) 2,070 2,107 2,170 2,064 2,388 2,847 3,059 2,853 3,189 2,794 2,419 2,044 2,126 2,635 3,478 5,101 5,428 4,661 3,671 other than Investment Exploration Expenditure Expenditure 301 375 261 241 379 550 875 993 809 939 (£m) 1,395 1,445 1,039 1,129 1,182 1,637 1,955 1,508 1,213 Exploration Expenditure na na na na na na na na na na na na na 8.7 8.5 9.8 11.8 10.0 11.5 (Net, %) Tax Rate Tax of Return of Return Corporation Non-UKCS Non-Financial companies Pre- 9.2 8.7 7.3 8.1 6.9 5.9 7.8 25.1 21.3 33.5 41.1 47.0 49.6 54.7 58.3 48.1 11.2 15.0 10.2 Special (Net, %) Tax Rate Tax of Return of Return Taxes,Pre- Corporation UKCS Post 868 322 -381 -129 -102 Gross (£m) 1,706 1,512 1,798 4,013 3,649 4,354 1,276 2,893 1,731 1,733 1,317 1,931 4,161 -1,628 All Taxes All Taxes and Total and Total Operating Investment Surplus Less Free CashRatesFree Flow, of Return, and Reinvestment

Table 2.3: Table 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 54 UK Energy Policy and the End of Market Fundamentalism na 265 282 259 289 239 224 286 263 207 167 230 201 168 Development Wells DrilledWells 36 42 36 32 17 34 35 29 19 34 37 41 77 na Appraisal Wells DrilledWells 61 70 60 45 18 27 24 16 26 29 41 29 34 na Exploration Wells DrilledWells 46.0 35.5 39.7 49.9 27.0 15.1 20.8 21.8 21.0 19.4 20.7 23.3 23.8 16.3 Total Total Surplus Operating % of Gross Investment as (£m) 4,355 4,364 4,263 4,996 3,063 2,750 3,570 3,598 3,412 3,302 4,371 5,656 5,303 4,780 other than Investment Exploration Expenditure Expenditure 762 457 348 420 389 334 396 460 773 (£m) 1,085 1,097 1,194 1,090 1,274 Exploration Expenditure 11.8 12.3 13.3 13.4 12.7 11.5 11.0 11.2 12.0 12.6 12.3 13.1 13.0 12.1 (Net, %) Tax Rate Tax of Return of Return Corporation Non-UKCS Non-Financial companies Pre- 7.7 11.4 17.7 13.0 10.9 24.8 20.8 18.9 19.5 21.5 26.4 36.8 36.9 53.9 Special (Net, %) Tax Rate Tax of Return of Return Taxes,Pre- Corporation UKCS Post Gross (£m) 4,048 6,566 4,959 3,268 6,939 9,722 9,195 9,815 9,102 12,944 10,144 12,106 12,643 18,054 All Taxes All Taxes and Total and Total Operating Investment Surplus Less continued

DECC (2010a); ONS (series LRXC, LRWX, LRWY, LRXP)

(a) The UKCS post-Special Taxes net rate post-Specialof(a) The Taxes UKCS return was calculated deductingby all special taxes (that is all taxes other than basic Corporation away Tax) from net Operating Surplus and then calculating the residual as a percentage of net (b) Capital The Non-FinancialNon-UKCS, Employed. companies rate of return (ONS series LRXP) is not available prior to 1989.

Table 2.3: Table 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 Sources: Notes: A Requiem for the UK’s Petroleum Fiscal Regime 55

Tax) from Gross Operating Surplus. Gross Operating Surplus is the relevant measure of surplus to use in this calculation because it includes depreciation, which is available to fund reinvestment – depreciation does not constitute a cash cost until it is used for reinvestment. The result is very revealing: after meeting all their UKCS costs, including investment and taxes, UKCS companies benefitted from a free cash flow which totalled £81 billion between 2002 and 2008. This figure is equivalent to five times the size of the stimulus package that the UK government adopted in November 2008 to counter the consequences of the financial meltdown (HM Treasury, 2008a, 20, clause 2.39). Reflecting the fact that UKCS companies benefitted very considerably from rising oil prices, despite the presence of Supplementary Corpora- tion Tax, the rates of return on capital achieved by these companies were very high indeed, when measured both in absolute terms and in comparison with non-UKCS companies. Table 2.3 shows that as unit sales revenues from oil and gas increased over two-and-a-half times between 2002 and 2008 (Table 2.1), UKCS company returns, which were already high in relation to non-UKCS companies, rose further, from 18.9 per cent to 53.9 per cent. Meanwhile, the returns for non- UKCS non-financial companies were between 12 and 13 per cent. This comparison between UKCS and non-UKCS company performance is made using a net (of Depreciation) pre-Corporation Tax rate of return for both sets of companies. To arrive at this indicator for UKCS companies, Special taxes had first of all to be deducted from Net Operating Surplus and the resulting (adjusted) Net Operating Surplus was then expressed as a percentage of UKCS Net Capital Employed. This rate of return, after Special UKCS taxes have been deducted, can then be compared with the non-UKCS corporations’ Pre-Tax rate of return (which is available directly from the Office for National Statistics database).

Reinvestment and Drilling Activity

The behaviour of investment since the introduction of Supplementary Corporation Tax may be said to show some reversal of the secular decline in UKCS investment, but only in ‘money-of-the-day’ terms (Table 2.3). As a result of the extraordinary impact of unprecedentedly high oil prices on industry costs, it is doubtful whether there has been any such reversal at all. Certainly, and apart from a sharp increase in appraisal drilling in 2007, there is so far no evidence of a major upturn in drilling activity in general, and development drilling in particular has continued down the path of secular decline (Table 2.3). Moreover, as a measure of the extent to which companies have been reinvesting their 56 UK Energy Policy and the End of Market Fundamentalism

UKCS profits in the UKCS, the highest proportion of Gross Operating Surplus to be reinvested between 2002 and 2008 was 23.8 per cent, and in 2008 this proportion fell to only 16.3 per cent. True to form (and most implausibly, given the evolution of corporate profits over this period), the UK North Sea Model admirers have laid the blame for this depression of capital investment at the door of the increase in tax brought about by SCT.11

Licence Awards

One telling characteristic of policies imbued with free market fundamentalism is that they betray remarkably little interest in, or understanding of, real market outcomes. Thus, for all their avowed admiration for the idea of the Market In General, in practice these policies have often been used to bypass, undermine, pre-empt, and even destroy well-functioning Markets in Particular. UKCS licensing policy provides an excellent illustration of this point. One might think that a government fixated by market fundamentalism would be keen to use market interactions to extract maximum value from the assignation of immensely valuable North Sea oil and gas production rights. However, with only three exceptions,12 the grant- ing of exploration and production licences in the UK North Sea has traditionally always involved a ‘beauty contest’ procedure, whereby firms submitted work plans to a committee which then awarded the licences to the submissions judged most meritorious. This can be seen as a reflection of the fact that ‘the United Kingdom embraced auctions later than the United States of America’ (Binmore and Klemperer, 2002, C-76), a country where the preferential use of this instrument stemmed from the need to pre-empt suspicion about potential impro- prieties in the assignation of public goods, However, as these authors go on to explain, ‘by the late 1990s, economists’ arguments for the use of auctions were beginning to make headway in Britain’, notably the fact that ‘an auction can ... extract and use information otherwise unavailable to the government’ in order to allocate resources to those who can use them most valuably, whereas ‘a beauty contest ... can give away valuable assets at a fraction of what they are worth’ (ibid.). This conversion of the British government to the merits of auctions allowed it to reap huge dividends in early 2000, when it assigned five third generation mobile spectrum licences. The auction, billed at the time as the biggest ever, raised £22.5 billion (2.5 per cent of GDP). In the light of this much vaunted success at ‘selling air’, and the considerable boost it gave to public finances, it would seem reasonable A Requiem for the UK’s Petroleum Fiscal Regime 57 to expect that the British government would turn its newfound enthusi- asm for auctions to the matter of ‘selling – ever more expensive – oil’, not least if there were any truth to the notion that the introduction of SCT in 2002 amounted to a relaxation of the hold of free market fundamentalism on British energy policy. In fact, the government reaf- firmed its market fundamentalist credentials by continuing to convey oil exploration and production rights to firms through administrative fiat, and even after the global financial crisis and a period of very high oil prices, the payment of a cash bonus was not contemplated in the conditions of the twenty-sixth Seaward Licensing Round, launched on 27 January 2010.

North Sea Comparisons

Given that companies operating in the same geological basin face similar physical conditions and challenges, it is appropriate to ask whether Norway and the UK have imposed similar fiscal conditions on companies operating in their respective sectors of the North Sea. Already, we have seen evidence in several indicators which suggests that the introduction of Supplementary Corporation Tax rates for UKCS companies has not prevented these companies benefitting very disproportionately as a result of the recent increases in oil prices. Has the same occurred in Norway?

Norway

The Norwegian fiscal regime has been ‘designed to be neutral, so that an investment project that is profitable before tax will also be profitable after tax ... [in order] to harmonise the requirement for significant revenues to the society with the requirement for sufficient post-tax profitability for the companies’ (MPE/NPD, 2009, 24). In this regard, it is superficially similar to that of the UK. However, the Norwegian petroleum fiscal regime is different from the UK’s in that the state receives income from two additional sources besides taxation. Firstly, the Norwegian State has a direct financial interest (SDFI) of varying size in 121 production licenses (MPE/NPD, 2009). These interests deliver income less participation in costs – and the income stream is therefore sensitive to investment requirements and prices. Secondly, the Norwegian state owns 67 per cent of Statoil. This ownership stake delivers dividends. Apart from this active presence of the state in Norwegian oil and gas production, the other main differences from 58 UK Energy Policy and the End of Market Fundamentalism the UK’s petroleum fiscal regime are that there is no PRT (but there is a higher rate of Special Tax: 50 per cent compared with the 20 per cent SCT in the UK), and that certain Environmental Taxes (carbon dioxide and nitrogen oxides) are levied. The flows of revenue from the Norwegian petroleum fiscal regime are shown in Figure 2.3. The profile is different from that of the UK in two important respects. Firstly, there is no major peak in the early 1980s, because Norwegian hydrocarbon production was, at that time, only just over a third of that of the UK. Secondly, there is a major positive effect delivered by the SDFI as oil prices rise after 2000, and a correspondingly negative one during the late 1980s/early 1990s, as investment requirements and low prices limited the flow of income to the Norwegian state.

500 Dividend Statoilhydro

400 Net cash flow SDFI

300 Environmental taxes

Area fee 200 Billion kroner Production fee

100 Special tax

Ordinary tax 0

1971 1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004 2007

Figure 2.3: Norwegian Government Revenues from Upstream Oil and Gas 1971–2008 Source: MPE/NPD (2009)

Figure 2.4 compares the relative behaviour of tax take per barrel in Norway and the UKCS. Since about 1990, Norwegian fiscal revenues per barrel of hydrocarbons produced have generally been above those in the UK, but after 2000, as oil prices rose, that difference became striking and large. By 2008, Norwegian take per barrel was $48.50, compared with $21.50 in the UK: the difference between the two countries ($27) was actually considerably greater than the actual amount being levied by the UK. Figure 2.5 shows correspondingly higher Norwegian state claims on unit sales value and Net Operating Surplus: A Requiem for the UK’s Petroleum Fiscal Regime 59

Norway Government Revenues per barrel of oil and oil 40 equivalent gas production (US$)

UK Government Revenues per barrel of oil and oil 30 equivalent gas production (US$)

Difference (US$ per barrel) 20 US$

-10 1976 1980 1984 1988 1992 1996 2000 2004 2008

Figure 2.4: UK and Norway Fiscal Revenues per Barrel Sources: derived from MPE/NPD (2009) and Table 2.1. Dollar exchange rates from the Bank of England and the Norwegian Central Bank (Norges Bank)

120

100

60 Percent

0 1976 1980 1984 1988 1992 1996 2000 2004 2008

Norway Revenues per Barrel as % of Unit Sales Value UK Revenues per Barrel as % of Unit Sales Value Norway Oil & Gas Revenues as % of Oil & Gas Net Operating Surplus UK Oil & Gas Revenues as % of Oil & Gas Net Operating Surplus

Figure 2.5: UK and Norway Fiscal Revenues in Relation to Prices and Profits Sources: Statistics Norway; MPE/NPD (2009); Table 2.1 Note: ‘per barrel’ refers to per barrel of oil plus oil equivalent gas production 60 UK Energy Policy and the End of Market Fundamentalism as the UK tax take edged upwards towards 30 per cent of unit sales value between 1999 and 2008, the Norwegian take (already at that level in 1999) shot up to over 60 per cent. Similarly, while the UK’s claim on company operating surpluses did not rise much above 40 per cent between 1999 and 2000, Norway’s started at 50 per cent and rose to between 78 per cent and more than 90 per cent after 2000 (the more than 100 per cent take in 2001 was an aberration caused by a spike in SDFI revenues). In summary, the Norwegian state’s claims on revenues from the country’s hydrocarbon production have been at much higher rates than the UK’s – making the Supplementary Corporation Tax rates appear as what they are: rather feeble gestures which are very vulnerable, like all corporation tax obligations, to – perfectly legal – manipulation by clever accountants and lawyers.13 To what extent this difference was entirely attributable to the Norwegian state’s ownership position as opposed to its tax position is discoverable from Figure 2.6, which compares the UK’s tax take per barrel in US$ with Norway’s fiscal revenues stripped of SDFI and dividend flows. This reveals that Norwegian taxation alone (that is without SDFI or state company dividend income) was similar to or above UK taxes in all but three years between 1976 and 1999. However, between 2000 and 2008, Norway claimed an average of $4/ barrel more than the UK. 30 Norway Taxation per barrel of oil and oil equivalent gas production (US$) 25 UK Taxation per barrel of oil and oil equivalent gas production (US$) 20

15 US$

0 1976 1980 1984 1988 1992 1996 2000 2004 2008

Figure 2.6: Comparing the Taxation Elements of the UK and Norway Petroleum Fiscal Regimes Sources: derived from MPE/NPD (2009) and Table 2.1. Dollar exchange rates from the Bank of England and the Norwegian Central Bank (Norges Bank) A Requiem for the UK’s Petroleum Fiscal Regime 61

The standard industry response to the sort of statistics quoted above was most recently articulated in some of the evidence which Professor Kemp provided to the Energy and Climate Change Committee, a group of parliamentarians charged (along with a number of others linked to specific ministries), with keeping an eye on the executive arm of the UK government. According to Kemp: Around the world we are not the toughest because the toughest ones tend to be in countries with gigantic fields. I think the way to look at it is to relate the tax regime we have to the reserves and prospectivity and cost per barrel. We must remember that we now are a relatively mature province with the average size of field of 20 million barrels of oil equivalent. Norway is a bit tougher, but their average size of a new development is probably about 60 million barrels of oil equivalent and they also have a number of very big ones. They are in a rather different position (HC 2009b, Ev 20, Q113). The empirical evidence (historical investment cost per barrel) does not support Kemp’s argument, or a similar one made by Nakhle (2008, 111). If it was valid, then one would presumably encounter significantly lower investment costs per barrel for Norway, and this is not the case (Figure 2.7).14 In fact, in the 32 years between 1976 and 2008, Nor- wegian investment per barrel of hydrocarbons produced has only been less than the UK’s in seven years, and in two of those seven years the

20 Norway Investment per Barrel of Oil Equivalent (US$)

15 UK Investment per Barrel of Oil Equivalent (US$)

10 US$

0 1976 1980 1984 1988 1992 1996 2000 2004 2008

Figure 2.7: UK and Norway Investment per Barrel Produced Sources: derived from DECC (2010a); MPE/NPD (2009).Dollar exchange rates from the Bank of England and the Norwegian Central Bank (Norges Bank) 62 UK Energy Policy and the End of Market Fundamentalism effect of required investments post Piper Alpha can clearly be seen to have been the cause (in 1991 and 1992). These statistics, incidentally, also address the question of whether Norway’s greater share in the return from its oil and gas resources has led to an investment flight (which is, of course, a major issue in the UK whenever increased taxes are mentioned – as will be seen below). The answer, as Figure 2.7 demonstrates, is unequivocally ‘No’.

Other North Sea Producers

The aberrant nature of upstream taxation in the UK can be put into even starker perspective by broadening the scope of the fiscal comparison beyond Norway, to encompass the whole of the North Sea. Although all the data required to create the range of indicators in previous exercise are not available for this comparison, it is possible to compare usefully fiscal revenues as a proportion of the value of production (and sales). That this proportion, which is the effective tax ratio, is a useful analytical device is underlined by Gerking (2005, 3–4) because it makes the comparison between tax burdens straightforward, and also makes it unnecessary to track and itemise tax law over time. Thus effective tax ratios fully account for all exemptions, incentives, special features (and tax bases) granted against the various taxes faced by the oil and gas industry, thereby translating dynamic tax policy into a tractable form (Kunce, Gerking, Morgan, and Maddux, 2003). As can be appreciated from Figure 2.8, the UK effective tax ratio is the lowest, by some distance, of the four North Sea oil and gas producers.15 Some might argue that the lack of cost data undermines the usefulness of this comparison, since it makes it impossible to conclude beyond reasonable doubt that companies active in the UKCS have been on the receiving end of a bonanza financed by a succession of UK Chancellors of the Exchequer. However, the graph should still make uncomfortable viewing for UK fiscal authorities, and indeed for the devolved Scottish government, who perhaps ought to be asking themselves whether unit costs and prospectivity in the UK are so much higher and so much poorer than in Denmark – a country with a relatively small hydrocarbons endowment, a cumulative production that is but a fraction of the British one, and which, for all practical purposes, has one concessionaire (A.P. Møller-Maersk) – that they can justify the UK’s fiscal take being a full 20 percentage points lower than the Danish one in 2008. Yet what discussion there is on this topic in the British media – even in publications which presume themselves not to be beholden to corporate oil interests – astonishingly continues to A Requiem for the UK’s Petroleum Fiscal Regime 63

1 Netherlands Denmark UK Norway

0.8

0.6 Ratio 0.4

0.2

0 1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006

Figure 2.8: Effective Fiscal Take Ratio for Upstream Oil and Gas Activities in Countries around the North Sea 1966–2008 Sources: Central Bureau of Statistics (Statistics Netherlands); Danish Energy Agency (2009), DECC (2010a); Gasunie; Ministerie van Economische Zaken (2009); MPE/NPD (2009); Statistics Denmark; Statoil; Wieleman (1982) revolve around the ‘reality of a world-leading hydrocarbons industry that is being taxed into premature decline’ (Arnott, 2009).16

A Genuine Policy Debate?

The above evaluation demonstrates, from the perspectives of both UK and international indicators, that the introduction and later reinforce- ment of Supplementary Corporation Tax in the UK did not prevent UKCS companies from accruing a disproportionate share of the windfalls associated with rapidly-rising oil prices between 2002 and 2008. In other words, these measures have done nothing to reverse free market fundamentalism in the UK upstream, as reflected in tax statistics. In Table 2.4, the resulting size of windfall foregone by the UK government and UK citizens is calculated, in two different ways. The first of these assumes that all of the rent from UKCS oil and gas should have accrued to the Crown and resource owner, leaving UKCS companies with a 15 per cent rate of return (as was seen in Table 2.3, this is a generous rate compared to those achieved in the non-oil and 64 UK Energy Policy and the End of Market Fundamentalism 8,516 9,166 8,465 9,586 12,214 11,185 14,954 74,086 Windfall Foregone (2) (£m) Take at Take 13,711 13,656 13,414 17,914 21,363 19,329 26,650 UKCS Revenue Norwegian Rate (1) 2,931 2,336 3,395 6,558 9,201 9,074 17,674 51,170 Windfall Foregone 8,126 6,826 8,344 Capture 14,886 18,350 17,219 29,371 Standard + 100% Rent Corporation Tax Corporation Tax (£m) 2,784 2,033 2,452 4,574 3,584 3,124 5,223 Standard (annualised) Corporation Tax Corporation Tax 5,343 4,793 5,892 10,312 14,766 14,095 24,148 Return (£m) Net Operating 15% Rate of Surplus minus Estimate of Rent: 5,195 4,490 4,949 8,328 9,149 8,144 11,697 Total UKCS Total Fiscal Revenues £m, annualised) Corporation Tax, Corporation Tax, (Special Taxes (Special+ Taxes Estimates of Windfalls UKCS Foregone

DECC (2010a) (Government revenues from oil and gas production); Table 2.2 (Estimate of Rent); MPE/NPD (2009); Norwegian Central Bank (Norges Bank) for Kroner/Sterling exchange rate (a) Windfall (1) Foregone is calculated by subtracting the actual tax take (column 1) from the sum of Standard Corporation Tax (which is a tax on normal profit) plus the Estimate ofRent (column UKCS Foregone 4).Windfall (2) is calculatedby subtracting the actual tax take (column 1) from what the takeUKCS would have been at Norwegian rates (column 6). (b)calculate To what UK government oil and gas revenues would have been at the Norwegian rate, Norwegian Government oil and gas revenues per barrel of oil plus oil equivalent production gasof production were multiplied UKCS by oil plus oil equivalent gas production and then converted to sterling.

2002 2003 2004 2005 2006 2007 2008 TOTAL Table 2.4: Table Source: Notes: A Requiem for the UK’s Petroleum Fiscal Regime 65 non-financial sectors). On this basis, the windfall foregone between 2002 and 2008 was £51 billion. Alternatively, if the UK had managed to participate in the country’s oil and gas revenues to the same extent as Norway, revenues would have been £74 billion greater between 2002 and 2008. In this regard, it should be stressed again that, in common with the UK, Norway has also pursued an upstream policy that is predicated on facilitating the free and frictionless flow of investment into the oil sector, and preventing government claims for rent from becoming an obstacle to such flows. However, Norway has consistently sought to capture Ricardian rents and windfall gains, instead of turning its fiscal regime into a corporate giveaway, as happened in the UK. The end result of this is that, while cumulative production in the Norwegian and UK sectors of the North Sea looks quite similar (with both sectors having now entered a stage of irreversible decline), the Norwegian Crown has harvested oil and gas rent to the great benefit of its subjects and their public services. The British Crown, in contrast, has foregone an equally massive windfall for the benefit of a small sector of corporate Britain. This perverse outcome, and its concomitant public squalor, have often been justified with arguments as (dis)ingenious as they are monumentally absurd.17 The sums mentioned above are very substantial by any standard, but even more so in the context of the state of UK government finances in the wake of the 2008 financial crisis. It is fair to ask, then, whether this has been reflected in UK policy debates. The comparison of rates of return for UKCS versus non-UKCS companies has certainly cropped up in the debate, but only in informing the introduction of the second 10 per cent tranche of Supplementary Charge in 2006: The Government is committed to maintaining an active UK oil and gas industry and to promoting the future development of the nation’s gas and oil reserves. The Government introduced a package of reforms to North Sea oil taxation in Budget 2002. At that time prices were around US$25 per barrel. Since then world oil prices have risen to levels of around $55 per barrel over the last couple of months, having peaked at $67 per barrel in September. Since Budget 2002 prices have averaged $37; in the previous ten years they averaged $19. These increases have led to the pre-tax return on capital for North Sea oil producers rising to an average of over 30 per cent since 2002, and to around 40 per cent this year, compared with an average of 13 per cent for companies in other non-financial sectors of the economy. (HM Treasury 2005, para 5.127)18 It is also true that the announcement of the Supplementary Charge in the 2005 Pre-Budget Report was immediately followed by an announcement that discussions would be opened on the future of the UK’s 66 UK Energy Policy and the End of Market Fundamentalism petroleum fiscal regime. However, the outcome of these discussions was pre-empted by the specific proviso that any further increases in tax were out of the question: The Government intends to open discussions with industry to examine wider structural issues which have implications for the stability of the North Sea oil tax regime. The Government is clear that there will be no further increases in North Sea oil taxation during the life of this Parliament. (HM Treasury 2005, para 5.132) The results of these discussions were published by the Treasury in March 2007 (HM Treasury, 2007). This paper reiterated government objectives with respect to UKCS policy as follows (paras 1.3 and 1.4): The underlying geology and future oil and gas prices are the dominant drivers of investment and hence ultimate recovery levels. However Govern- ment has a crucial role to play in ensuring that the regulatory and fiscal regimes help deliver the best possible future for the UKCS. To achieve this the Government has twin objectives for the fiscal regime to promote investment and production whilst striking the right balance between producers and consumers and ensuring a fair return for the UK taxpayer from our national resources. These so-called objectives merely beg a number of questions. How is the ‘best possible future’ to be judged? What does striking a ‘right balance between producers and consumers’ actually mean? What criteria should be used to determine what is a ‘fair return for the UK taxpayer’. However, no answers to these questions are to be found in the subsequent pages of the paper. Likewise, no attempt is made to evaluate the performance of the UK’s petroleum fiscal regime in terms of its fairness for UK citizens, or with reference to the statistics published by the government itself. Instead of a government position, there is simply a description of the current regime. This leaves the way open for the industry itself to define the content and parameters of the policy debate (or, more accurately, non-debate). Again, this is an outcome entirely characteristic of free market fundamentalism. While the conclusions of the Treasury’s discussion paper were either negative or non-committal about changes to the fiscal regime, subsequent discussions led to a second paper (HM Treasury and HM Revenue and Customs, 2007), which provided the background to the changes introduced in the 2008 Budget, and then to a third paper (HM Treasury and HM Revenue and Customs, 2008), which did the same for changes introduced in the 2009 Budget. The changes to the UK’s petroleum fiscal regime introduced by the 2008 Budget (HM Treasury 2008b, para 3.15) were the extension of the A Requiem for the UK’s Petroleum Fiscal Regime 67

100 per cent capital allowance to long-term assets and mid-life decommissioning, as well as reforms to Petroleum Revenue Tax and changes to the Corporation Tax treatment of decommissioning losses. The cost of these changes, driven by a concern to encourage investment, was an indexed £70 million over the three fiscal years 2009 to 2011. However, this loss was much more than offset by a projected £490 million gain (Table A.1(46)) from removing an egregious abuse of management expenses (the expenses of managing investment businesses – that is a form of overhead – were being offset against ring-fenced profits). The changes introduced in the 2009 Budget (HM Treasury, 2009, paras A.88, A.89, A.90) were as follows: With effect from 22 April 2009, a new ‘Field Allowance’, which will act to reduce the initial tax paid by qualifying new developments, will be introduced. With effect from 22 April 2009, chargeable gains will be removed from North Sea asset swaps and disposals where gains are reinvested in the North Sea. With effect from 30 June 2009, reforms will be made to the petroleum revenue tax (PRT) regime to ensure companies are still able to receive decommissioning relief even where licences have expired. The revenue effects of these changes were anticipated to be relatively trivial (just £15 million over 2010–12). While there is some sense from the government’s articulation of its position during this period that changes were not going to be conceded easily, unless the net cost to taxpayers was negative, the fact that any concessions were granted at all is symbolic of a government continuing to have the same reflexes which led to the enfeeblement of the fiscal regime in the first place, during the late 1980s and 1990s. After all, the government’s own data showed 2008 to have been a year in which the industry was left with £18 billion in free cash flow and a pre- Corporation Tax rate of return of 54 per cent, while only reinvesting 16.3 per cent of Gross Operating Surplus back into the UKCS. The last strand in the policy debate for us to consider is a report from the Energy and Climate Change Committee. Two key passages from its summary provide a flavour of its views (HC, 2009a, 3): When determining policy on UK oil and gas the Government’s priority should be security of supply, within the context of moving to a low carbon economy. However, proper account must also be taken of both the immense tax revenues paid by the industry and the 350,000 people whose employment rests upon it. Given that the sector predicts falling capital expenditure could destroy at least 14 per cent of those jobs over the next two years, the Government must find a way to support UK oil and gas production in the current difficult economic climate. The oil and gas industry operating on the UK continental shelf currently 68 UK Energy Policy and the End of Market Fundamentalism

faces a quadruple whammy of high costs, low prices, lack of affordable credit and a global recession. Unless the fiscal and regulatory regime is well designed and highly attractive then the likelihood is that the UK may not recover anything like as much of its reserve as would be desirable. The profoundly warped sense of economic perspective that underlies these passages (and the report as a whole) can be clearly appreciated in four points. Firstly, there is the reference to ‘immense tax revenues’, which is based on data from the company association Oil and Gas UK (see para 52 of HC, 2009a) and is not counterbalanced by any data on company profits and profitability. Secondly, the use of the term ‘quadruple whammy’ with respect to an industry which has been harvesting superprofits is simply bizarre, not least in the context of BP’s explicit recognition in its evidence about the highly attractive nature of the UK’s fiscal regime.19 Thirdly, even in the wake of the global financial crisis, the price environment that the oil and gas industry continues to face is extremely favourable when seen from a historical perspective. Finally, it is revealing that in the Committee’s report, Norway is only referred to in the context of carbon capture and storage. There is not one mention in relation to tax. The rest of the report reveals a Committee that has been captured by the company lobby to such an extent that it seems its members have entirely lost sight of who they are meant to represent, and of the elementary fact that the interests of the oil industry are not necessarily synonymous with those of UK plc. At one point, the astonishing observation is made that the fiscal regime is ‘unpopular with those subject to it’ (HC, 2009a, para 52). One is compelled to ask, rhe- torically, whether there has been a single instance in history of a tax actually being popular with those subject to it and, indeed, whether popularity is the point of taxation.20 In the light of the Committee’s supine stance, it is understandable that one company (BG plc) should have felt sufficiently emboldened to suggest in its memorandum of evidence that ‘one option HM Treasury may wish to consider over time is abolition of SCT, [thereby] bringing the oil and gas industry in line with the rest of industry. This would mean CT being payable at 28 per cent’ (HC, 2009b, Ev 53). According to BG, the viability of certain discoveries is a function of taxation (and taxation only), and the adoption of its suggestion ‘would be certain to release additional hydrocarbons from discoveries that are currently uncommercial because of the SCT regime’ (ibid.; emphasis ours). BG’s ‘disinterested’ recom- mendation is in line with Nakhle’s position that, in a mature province like the UKCS, taxation is a principal determinant of future levels of activity and profitability, which in her eyes makes the intellectual case A Requiem for the UK’s Petroleum Fiscal Regime 69 for additional special petroleum taxation unsustainable (Nakhle, 2005).21 Revealingly, however, Nakhle reached this conclusion on the basis of a survey conducted among industry and government actors, rather than from any empirical data! In contrast, investigators who have examined the relationship between taxation and activity through the medium of robust statistics have reached very different conclusions, even when very mature oil and gas provinces are concerned. For instance, in a landmark study carried out at the behest of the Wyoming state legislature, Gerking et al. established that production activities throughout the USA were inelastic with respect to changes in state severance taxes and other gross income levies like royalties. In Wyoming, for instance, a doubling of the 6 per cent severance tax rate in that state (where average well productivity in 2008 was merely 12.12 boe/day) was found to reduce production by 6 per cent over a 40 year period, while increasing tax revenue in present value terms by over 90 per cent.22 Conversely, a once-and-for-all drop of 2 percentage points in the severance tax rate was found to increase total oil recovery by less than one per cent (50 mboe) and employment by around 300 persons (that is 7.5 persons per year), while causing a 17 per cent reduction in the present value of severance tax collections (Gerking et al., 2001).23 As far as the additional relief measures introduced in explicit association with SCT, one would have thought that, if the latter were indeed to be phased out, then the former would be rendered surplus to requirements. BG, however, was having none of this and in its evidence indicated that it would expect the Government to give ‘certain safeguards in relation to capital expenditure relief’ (HC 2009b, Ev 53). In all, the Committee was highly receptive to the positions that the oil companies articulated, and it derived considerable support from the evidence that Professor Kemp gave before it (HC, 2009a, para 29): ... the way to maximise economic recovery from the North Sea is to get a very steady stream of investment going. My worry at the moment is if it falls down for two or more years then we could be on a slippery slope and there will not be enough incentive to maintain the infrastructure and then it will be too late. In view of the above, it is unsurprising that the Committee concluded by questioning the likely effectiveness of the new field allowance, and ventured the suggestion that further fiscal relaxation was necessary to stimulate UKCS investment and to assure greater security for future oil and gas supplies (HC, 2009a, 4), … the Government must reconsider the merits of more wide-ranging and generous reforms of the fiscal regime such as a capital uplift or a reduction 70 UK Energy Policy and the End of Market Fundamentalism

in the supplementary charge, calculating and setting out the predicted effects on tax revenues and on investment in the industry. For once, despite the concerns of the Committee, of oil companies, and of Professor Kemp, the government did politely refuse to reconsider its position (HC, 2009c). This negative response to the entreaties of the Committee notwithstanding, it would be grossly inaccurate to call this exchange of views a proper debate on oil and gas taxation in general, and on the UK North Sea Model, in particular. Such a debate has not yet taken place within Parliament, let alone within the wider British public arena. Furthermore, the omens that it will take place at all, even in the aftermath of the global financial crisis, do not look particularly auspicious, as evidenced by the speech that Prime Minister Gordon Brown delivered on 24 June 2008, on the occasion of the international oil summit convened by the kingdom of Saudi Arabia. On a day when the spot price of Brent crude oil was an unprecedented 135 US$/barrel, the prime minister incongruously pledged: ‘by examining incentives for greater recovery of oil and for smaller fields, we will do more to exploit the 25 billion barrels of reserves still in the North Sea’ (Brown, 2008). In other words, for Prime Minister Brown, high oil prices constituted proof that more fiscal incentives were required to secure additional investment in UKCS oil and gas. In order to appreciate the intellectual bankruptcy of the UK North Sea Model, one need only recall that, ten years to the day before the Prime Minister spoke in Jeddah, the spot price of Brent crude had been only 12.50 US$/barrel. These depressed price levels were instrumental in convincing the recently inaugurated Labour government’s decision to call off its review of the UKCS fiscal regime. As Kemp himself reported at the time: ‘the UK oil industry breathed a huge sigh of relief ... when the government said that for the moment it had no plans to change the ... fiscal regime in the North Sea ... Chancellor Gordon Brown said that ‘it would not be right at this stage’ to go ahead with reform, bearing in mind that oil prices in 1998 have plunged to 10 year lows’ (Kemp, 1998, 20). Indeed, the then-Chancellor Brown reached the conclusion that low oil prices would hurt UK production unless the government stepped in and granted fiscal incentives to promote more investment. From the above, it may be seen that the UK North Sea model can be encapsulated – not unfairly – by the following two prescriptions. In a low price environment, production will suffer unless investment is incentivised by reductions in taxes. Conversely, a high price environment is a sign that investment has been insufficient, and that it is therefore necessary to lighten the burden of taxation to stimulate it. In fiscal terms, then, the logic behind the UK North Sea Model as it A Requiem for the UK’s Petroleum Fiscal Regime 71 evolved under the sign of free market fundamentalism, is one that the Mad Hatter would both recognise and wholeheartedly approve of: jam tomorrow and jam yesterday, never jam today.

Is a Change in Direction Possible in the UK?

In late 2009, the US secretary of the Interior Ken Salazar addressed an audience of oil industry notables in the following terms:

Just as your shareholders expect you to get a fair rate of return on your investments and to be wise stewards of your balance sheets, the American people are asking the same of us as we manage their resources ... That means we are going to take another look at royalty rates. It means that tax breaks that are no longer needed, and which the American people can’t afford, will disappear. (Salazar, 2009) In making such a statement, secretary Salazar was reflecting a sense of outrage (stoked by the flames of the global financial crisis) at the spectacle afforded by oil companies’ visibly continuing to benefit from government largesse in an environment of high oil and gas prices.24 Granted, as a practical matter, Salazar’s statements are unlikely to be harbingers of a wholesale revision of the Reagan-era fiscal and institutional innovations that have turned the US Federal Outer Continental Shelf (OCS) into one of the most investor-friendly major petroleum provinces of the world (second only to the UKCS in this respect, in fact), not least because the secretary betrays no understanding of, or interest in, the mechanisms whereby this transformation was accom- plished.25 Nonetheless, his statement shows that, thanks to the perennial suspicion of the American public towards oil companies (to say nothing of its instinctive belief that collective goods should not be put at the disposal of private parties at fire sale values), the fiscal policy of the US Federal government towards upstream oil and gas still has to pass the proverbial red-face test, which it can only do by paying more than lip-service to the concept of ‘jam today’. Alas, the same has not been true in Britain for some time now and, as a result, the UKCS has become a place where certain concepts appear to have been eradicated from the political lexicon in an Orwellian fashion, and where the prime minister can consequently speak with no uncomfortable rise in under- collar temperatures about the pressing need to subsidise investment in oil at a time of very high oil prices and unprecedentedly wretched public finances.26 This chapter has focused on the unfortunate consequences that the 72 UK Energy Policy and the End of Market Fundamentalism internalisation of company arguments in the design of the UKCS petroleum fiscal regime has had for Britain as a whole. It has also debunked the notion that there might have been a meaningful reversal in long term UKCS fiscal policy trends. Such assertions beg the question: what are the necessary conditions for such a reversal to happen? This question can be answered in broad brush strokes, as opposed to granular specifics. Suffice it to say that, to be sound, any policy would have to incorporate a series of elementary commonsense maxims which are conspicuous by their absence in the current setup. Firstly, costs are essentially a company and industry problem, not a government problem. Secondly, it is the oil market and not the tax regime from whence the signals should originate as to whether higher-cost production can be brought to market. Thirdly, attempting to use the tax regime to make a difference at the margin is likely to risk large amounts of government revenue, to no discernible avail apart from swelling company coffers and depleting public ones. Fourthly, since the costs for new investments are prospective, and are based on projected production cycles of up to 25 years, no government can be expected to, or should assume the risk of, buying willy-nilly into such projections without any tangible reward. Moreover, neither the epithets ‘marginal’ nor ‘small’ automatically mean that such fields will be unprofitable over their lifetimes, as is so often simply assumed by both policy-makers and academics (for example, see Nakhle, 2008, 162).27 Fifthly, since costs are highly complex in ways related not just to the scale of production but also to the proximity of existing infrastructure, they are therefore likely to be project specific, and no petroleum fiscal regime can or ought to be tailored to individual projects. Sixthly, the current ahistorical approach to policy formulation has to be substituted by one that properly takes account of (and places in the public domain, for good measure) all relevant historical performance indicators – physical and financial – for both the UKCS as a whole and for individual operators. This leaves the question of how the UK should organise itself in future to capture oil and gas rents, and to prevent companies collecting unearned windfalls. The lesson from Norway is that a three-pronged approach is necessary: a special tax resistant to avoidance; major equity participation in oil and gas fields, and a state oil company. Each of these components of the Norwegian fiscal regime plays a distinct role: the special tax targets rent, the equity share means that the state shares risk but also rewards (which also serves as recompense if the special tax undershoots), and thirdly, the existence of Statoil provides bargaining leverage (both ‘inside information’ and the ability to go it alone) with respect to international oil companies. A Requiem for the UK’s Petroleum Fiscal Regime 73

However, if this model has been shown to be highly effective for Norway, this does not mean that it can or should be transplanted to the UK with immediate effect. For example, it is true that a state company can, in principle, assure that a steady stream of investment materialises, both by its own activity and by exercising leverage over the private sector companies. However, it is far from being the case that the existence of a state oil company is a guarantee that the public interest can be made to prevail over corporate interests. Indeed, the historical record in this regard is mixed, and some of the most spectacular oil policy triumphs were achieved by countries without a state oil company as in the main OPEC nations during the 1960s). Especially in more recent times, state oil companies have proven to be extremely vulnerable to capture by sectarian interests, with some of them being used to devastating effect as Trojan horses to destroy from within complex institutional frameworks and governance structures painstakingly built over the space of decades.28 This characteristic is worrisome in the light of the British knack of devising Byzantine power structures in which are enshrined the most naked conflicts of interest, and where accountability is conspicuous mainly by its absence. Indeed, in this regard, the Norwegian experience ought to be highly instructive to the UK as well. By the early 1980s, especially after the Second Oil Shock, it had become apparent to Norwegian politicians that ‘Statoil’s long-term plans [could] well be quite incompatible with the short-term and medium-term needs of the Norwegian state’ (Richardson, 1981, 45). Furthermore, given the magnitude of the cash flows going through Statoil, they also reached the conclusion that, in the not too distant future, there was an unacceptable risk that the political system might develop a clientelistic relationship with Statoil, and that Norway could become a variation on the Prussian theme of old: an oil company with a country attached to it. The solution (devised and implemented under a Conservative government of impeccable pro-market pedigree) was to hive off the bulk of the hydrocarbon revenues into a new entity, the SDFI, whose role was to behave like a passive financial investor in an enterprise (that is to provide investment funds for projects presented by officers of the operating part of the enterprise, after due diligence, and to collect the share of the proceeds proportional to its shareholding). In other words, when the Norwegian government took the decision that it needed to take preventive measures to safeguard both its freedom of manoeuvre and some of its preferred policy objectives, the way it went about securing these objectives was by reining back its national oil company, rather than expanding its scope of action. Thus far, the Norwegian government has successfully resisted all calls (some of the 74 UK Energy Policy and the End of Market Fundamentalism most strident coming from the part-privatised Statoil itself) to divest itself of its SDFI shares. Governments, then, do not necessarily need a state company to stand up to private oil companies (or to any other special interest group, for that matter). What they need, above all else, is strength of purpose, as well as a grasp of the far-from-revolutionary notion that the interests of the commonwealth need not necessarily be aligned with those of oil companies, whether they be foreign or native, private or state-owned. In this regard, the UK government could do a lot worse than learning from the salutary example of Wyoming, a US state which produces relatively modest amounts of oil and quite a bit of natural gas (140,000 b/day and 1.29 mboe/day in 2008, respectively, versus the UK’s 1.74 mb/day and 1.18 mboe/day, respectively), but whose oil and gas tax income receipts account for a proportion of government revenue that is second only to Alaska’s among the 50 states of the USA. As in many other oil states, the Wyoming political establishment developed a cosy relationship with oil companies, which often manifested itself in the form of tax incentives allegedly aimed at stimulating production and job creation. In 1999, in response to very low oil prices, the Wyoming legislature decided to enact a two-year tax break that would lower the severance rate on oil and gas by 33 per cent. Given the budget- ary implications of such tax breaks, a group of legislators who were sceptical about their benefits in general (led by Republican State Senator Cale Case) succeeded in amending the severance tax break bill to include funding for an econometric study that would ask whether past tax incentive schemes had indeed delivered as advertised. The study, which has already been referred to, materialised as Mineral Tax Incentives, Mineral Production and the Wyoming Economy (Gerking et al., 2001), and after its publication, the Wyoming legislature entrusted the Division of Economic Analysis of the state government with the administration of the model that constitutes its core, for the purpose of providing tax break simulations in response to requests put forward by the Wyoming Executive Branch, Legislators, and organisations and private citizens, as well as individuals, agencies or firms from other US states that also produce oil and gas. This arrangement presumably was intended to curb the munificence of legislators, by showing them in black and white (not to mention red) the tangible and rather asymmetrical results of their pet tax-cutting projects. As things have turned out, the existence and public availability of the MTI model has indeed translated into a markedly greater reluctance on the part of Wyoming legislators to grant oil and gas tax breaks. On a couple of occasions, the unpalatable results of simulations have raised the political stakes for state legislators A Requiem for the UK’s Petroleum Fiscal Regime 75

(chiefly through the dissemination of ‘hard’ numbers pointing out the fiscal costs of past – and pointless – incentive programmes), prompting the sponsors of the tax incentives to withdraw their proposals.29 The example of Wyoming shows that, if market fundamentalism in the UK upstream sector is to be reversed, the first step the government would have to take is to stop giving companies any further tax breaks. The logical follow-up to this would be to devise and introduce new ve- hicles for rent capture. Given the similarities between Norway’s Special Tax and the UK’s Supplementary Corporation Tax (the main difference being the rate) the UK could raise the rate of Supplementary Corpora- tion Tax. Secondly, and in order to create the kind of participation in risk and reward which the Norwegian SDFI provides, companies could be given the option to pay the additional tax in the form of equity. These would be steps in the right direction, and are certainly worth taking, given that the UK still has substantial hydrocarbon reserves which are likely to be worth more rather than less in the future. The alternative of continuing down the same path would be unnecessary additional strains on UK public finances, and investment crises in other oil producing countries. The latter would be the case because the UK North Sea Model or its underlying philosophy have been widely imitated outside the UK where, while it has tended to meet expectations in terms of a narrowly-defined yardstick of success (much enhanced investment flows in response to loosening of fiscal conditions), it has also led to calamitous economic and political consequences. In Nigeria, for instance, the output from deepwater fields (amounting to around 30 per cent of the country’s nominal production capacity), effectively makes no fiscal contribution whatsoever (NNPC, 2009). In Russia under the original Sakhalin 11 contract, the Russian government would only have started receiving its share of extracted oil revenues once the consortium of Shell, Mitsui, and Mitsubishi had recovered both its costs AND a 17.5 per cent real rate of return (see Rutledge, 2004, 3). In Kazakhstan, the calamitous cost overruns in the Kashagan project would have meant the government receiving a mere 2 per cent of a 1.5 mb/day production for at least the first decade after first oil (production was supposed to start in 2005 or 2006 but is now scheduled for the latter part of 2012), had it not renegotiated and restructured the production sharing-contract for the field (Kahale, 2010). Likewise, investment in Venezuela all but dried up as the Chávez government sought to reverse the fiscal consequences of the UK-inspired Apertura policy (oil fiscal income in Venezuela fell to its lowest level in 2002: 40 per cent lower than in 1998, even though prices were over 40 per cent higher) (MENPET, 2009). In other words, the economic consequences 76 UK Energy Policy and the End of Market Fundamentalism derived from the application of the North Sea Model (easily predictable, for the most part) have had a seriously negative effect on investment further down the line, for the simple reason that countries find that marshalling their scarce resources in order to restructure lopsided arrangements is an option that offers much better payouts than ne- gotiating and concluding new projects. Furthermore, this has led to a significant slowdown of investment in such countries (thereby damaging the interests of developed oil consuming countries who thought they stood to gain the most from the widespread adoption of the North Sea Model), and to the shutting out of oil companies from many highly prospective areas. Both from a UK, and arguably from an international perspective, the UK North Sea Model has ultimately turned out to be a ‘lose–lose’ proposition for all concerned: governments, oil companies, and oil consumers alike. A Requiem for the UK’s Petroleum Fiscal Regime 77

Appendix A2.1: The Evolution of the UK Oil and Gas Fiscal Regime

1964 12.5% Royalty + Corporation Tax but major loopholes for the avoidance of the latter, including the deductibility of losses made on non-UK operations. 1975 Additional to the 12.5% royalty, Petroleum Revenue Tax (PRT) introduced, initially at 45%, rising to 60% (1979-80) and then 70% (1980-82). PRT was ‘ring-fenced’ by field (losses from one field could not be set against the profits of another), but a series of deductions were allowed (Royalties, a tax-free Oil Production Allowance, ‘Uplift’ (an enhancement of actual capital expenditure) and smaller and less profitable fields were protected by a ‘Safeguard’ and ‘Tapering’. Corporation Tax was charged at 52% between 1972 and 1983 and ‘ring-fenced’ against non-UK losses, but not within the UK for individual fields. 1981 Supplementary Petroleum Duty introduced at a rate of 20% on Gross Revenue, but with a duty free allowance of 20,000 barrels per day. 1982 Supplementary Petroleum Duty replaced by Advance Petroleum Revenue Tax to accelerate PRT payment, plus PRT itself was increased to 75% (from January 1983). 1983 Advanced Petroleum Revenue Tax phased out. Royalties abolished on fields in Northern North Sea receiving development consent after April 1982. PRT Oil Production Allowance doubled for new oil fields outside Southern Basin of North Sea. Cross-Field Exploration Allowance introduced with respect to PRT, allowing a partial breach of the PRT ‘ring-fence’: exploration and appraisal expenditure incurred for one field could be offset against PRT liability on another. New Oil Taxation Act brought income and capital sums received for use or sale of North Sea infrastructure (e.g. pipeline) assets within scope of PRT and made PRT relief immediate for costs of most assets. 1984–86 Corporation Tax was progressively reduced from 52% to 50% in 1984, 45% in 1985 and 40% in 1986. As a compensating measure 100% first year capital allowances were abolished and replaced with a 25% depreciation allowance calculated on the declining balance method. 1987 Corporation Tax was reduced further to 35%. A Cross-Field Development Allowance was introduced: in a further breach of the ring-fence principle. Companies were allowed to offset 10% of their capital expenditure on certain new fields (fields with no PRT-liable profits against which such expenditure could be set) against the PRT liable profits of other fields. 1989 1983 Royalties exclusion extended: Royalties abolished for remaining offshore and onshore fields receiving development consent after April 1982. 1991 Corporation Tax reduced to 34%. 1992 Corporation Tax reduced to 33%. 78 UK Energy Policy and the End of Market Fundamentalism

Appendix A2.1: continued

1993 PRT reduced to 50% for existing fields and abolished altogether for new fields given development consent after April 1993. Cross-Field Exploration and Development Allowances abolished for future exploration and development (under transitional arrangements to cover committed expenditures). 1997 New Labour government announces a review of the North Sea Fiscal regime, involving two alternatives: a Supplementary Corporation Tax or a Broader Petroleum Revenue Tax. Either of these alternatives would be accompanied by the abolition of Royalties. However neither alternative was implemented, with the 1998 drop in oil prices being used as the pretext. Moreover, oil companies benefited from a further reduction in Corporation Tax to 31%. 1999 Corporation Tax reduced to 30% 2002 Remaining Royalty obligations abolished from January 2003 for the 30 fields which still paid them. An additional ‘Supplementary Charge’ of 10% of ‘ring-fenced’ profits introduced, without any decuction for financing costs. At the same time expenditure which qualified for a 25% writing-down allowance under the plant and machinery and mineral extraction capital allowance codes now allowed a 100% first year allowance. Long life assets which currently receive a 6% writing down allowance now eligible for a 24% first year allowance. 2006 Jannuary 2006: Supplementary Charge raised from 10% to 20% 2008 March 2008: changes to the treatment of CT losses created by decommissioning, extension of 100 per cent capital allowances to long-life assets and mid-life decommissioning, and reforms to Petroleum Revenue Tax; Main rate of Corporation Tax reduced to 28% but not applied to UKCS which remained at 30% 2009 March 2009 (effective April 22nd): New Field Allowance reducing the tax payable on qualifying new developments; Gains from asset swaps and disposals not to be charged if reinvested in UKCS; Petroleum Revenue Tax decommissioning relief to continue after licences have expired.

A Requiem for the UK’s Petroleum Fiscal Regime 79

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Notes

1 Given that it was the privatisation of a diversified international oil company, it could be argued that the sale of the UK government’s shareholding in BP does not qualify as a UK upstream privatisation initiative. 2 Oddly enough, the Netherlands, a major gas exporter, was another. Re- sponsibility for the Dutch upstream gas industry falls within the purview of the Ministry of Economic Affairs, through the Staatstoezicht op de Mijnen. However, this institutional arrangement dates from the very beginning of the Dutch gas industry, and therefore cannot be seen as symptomatic of A Requiem for the UK’s Petroleum Fiscal Regime 83

a change in approach to government intervention in the industry, like the one which underlies the abolition of the UK Department of Energy. 3 The Cullen report was published in November 1990 4 While this concern about jobs played extensively in the Scottish Press at the time, one of the authors had direct experience of it, as a presentation of the research in Rutledge and Wright (1998) which was due to take place in the House of Commons was cancelled. The presentation was sponsored by Norman Godman, a former Glasgow MP and close ally of Gordon Brown. Godman explained that this was because Brown did not want the petroleum fiscal regime under the spotlight while oil prices were low and Scottish jobs at risk. 5 The Supplementary rate of Corporation Tax is officially referred to as the ‘Supplementary Charge’. 6 Companies were allowed to carry forward capital allowances from FY 2005/6 into FY 2006/7, which accelerated tax paid in 2005 and depressed the tax paid in 2007. Similar optimisation considerations affected the timing of SCT tax payments, which further compounded the effect of depressing 2007 receipts relative to 2005 receipts. 7 Nakhle and Hawdon (2004) provide a striking example of this. In an account of the evolution of the UK petroleum fiscal regime over the previous 27 years, these authors resorted to calculating profitability and Government revenue for a representative sample of post-1993 fields, instead of just using the very detailed statistical data published by the DECC. Moreover, their calculations were bizarre, as they involved the retrospective application of methodologies which are meant to be applied prospectively: discounted cash flow (DCF), modern asset pricing (MAP) and real options theory (ROT). Small surprise, then, that they could reach conclusions such as this one: ‘the abolition of Royalty [did] not significantly reduce Government take’ (Nakhle and Hawdon, 2004, 18). 8 An ideal type, according to Weber, is a heuristic device ‘formed by the one-sided accentuation of one or more points of view and by the synthesis of a great many diffuse, discrete, more or less present and occasionally absent concrete individual phenomena, which are arranged according to those one-sidedly emphasized viewpoints into a unified analytical construct’ (1997, 88). 9 Ricardo (1821, 67). 10 A 15 per cent rate of return is appropriate because it is often the default rate used in evaluating oil industry investments and is also the threshold value used to calculate PRT liabilities (see HM Revenue and Customs, 2008, para 4.18). However, it should be seen as generous, particularly in relation to non-oil industry rates of return (see Table 2.3), and should not therefore be seen as representing a minimum acceptable level of profitability. 11 For instance, Nakhle (2007), mimicking a BP presentation (Hall, 2006), blames the UK Government’s fiscal policies for presiding over one of the highest basin decline rates ever recorded. Of course, the decline rate of a basin is a physical variable that has nothing whatsoever to do with taxes 84 UK Energy Policy and the End of Market Fundamentalism

(production declines in Norway and the UK are quite similar, despite the differences in their respective fiscal regimes). Moreover, Fugro Robertson’s International New Ventures Survey has, since 2004, placed the UK either first or second as the oil region most attractive to new ventures. In 2007, for example, the UK was number one (Fugro Robertson, 2007). 12 15 blocks were allocated in sealed bid auctions as part of the fourth (1971–2), eighth (1982–3) and ninth (1984–5) Licensing Rounds, bringing in small but tangible increases in income (see DECC 2010a, Government revenues from oil and gas production). 13 The effective corporate tax rate for the 20 largest firms in the USA, for instance, is under 2 per cent (Galbraith, 2009). 14 Indeed, the opposite was true in the days of Norway’s elephant-sized finds. As Richardson (1981: 46) quips, cost overruns and delays were so com- monplace that one could think that ‘there seemed to be two immutable laws operating on the Norwegian continental shelf. One: regardless of how much has been invested, the amount still to be invested remains constant. Two: Regardless of how far the project has advanced, completion is still six months ahead’. 15 The German Länder of Schleswig-Holstein and Niedersachsen also produce oil and natural gas, respectively, from the North Sea. The volumes involved are, however, relatively minor: in 2008, crude oil output from the Mittelplatte offshore field in Schleswig-Holstein (Germany’s largest) amounted to less than 20 mbd. Nevertheless, in 2008 Schleswig-Holstein still collected a 15 per cent royalty on production from this field (mineral taxation in Germany falls within the attributions of the federal states). Information on oil and gas royalty payments to Länder governments is available, but there is no information readily available on other taxes or the gross income of the oil and gas industry. 16 This particular article went so far as to contrast the languishing drilling activity in the UK with the vibrant drilling scene ‘just over the border into the less heavily-taxed Norwegian North Sea’[sic.!]. In a similar vein, see ‘Crude Britannia: The Story of North Sea Oil’, first broadcast on the BBC in June 2009. 17 Like the argument that low North Sea taxation is actually good for the people of Britain as a whole because of the sizeable proportion of private pension fund money invested in BP stock. According to John Browne’s calculations (2010, 223), BP accounted on average for £1 out of every £6 received in dividends by UK pension funds. 18 Here it seems the government was using the Pre-Tax rate of return for UKCS companies, rather than the post-Special Taxes, pre-Corporation Tax rate of return which we have used in order to make the appropriate comparison with non-UKCS companies. 19 ‘This is not to imply that, in recent years, the UKCS Fiscal Regime has been draconian or uncompetitive in global terms.’ (House of Commons Energy and Climate Change Committee, 2009b, Ev 55). 20 ‘Less bread, more taxes!’ is a political slogan unlikely to catch on outside A Requiem for the UK’s Petroleum Fiscal Regime 85

Sylvie and Bruno, Lewis Carroll’s whimsical fairy tale. 21 Nakhle suggests that an application of CT only will ‘ensure that the upstream industry is treated in the same way as any other industry in the UK’. This statement rather misses the point that NOT treating the oil industry as any other one is (or should be) the central tenet of a sensible upstream tax policy, even one run on non-proprietorial lines. 22 Wyoming data from the Distribution of Oil and Gas Wells and Production Project, undertaken by the Reserves and Production Division, Office of Oil and Gas of the Energy Information Agency (www.eia.doe.gov/pub/oil_gas/ petrosystem/petrosysog.html). 23 These findings are in line with Mitchell’s general observation that ‘fiscal terms affect supply only marginally ... They do not affect the general level of activity, which is more influenced by overall price levels and exploration attractiveness’ (Mitchell et al., 2001: 49–50) 24 ‘When the price of oil is above $80 per barrel, subsidizing oil companies to drill through royalty-free drilling is like subsidizing fish to swim – you don’t need to do it (NYT, 2010).’ 25 Royalty relief measures have come under intense press and legal scrutiny (see Andrews 2007a, 2007b, 2007c and 2007d), and their visibility and cost probably mean that royalty holidays in the US Federal OCS will come to an end. However, royalty relief was not the element that turned the areas in the Gulf of Mexico under Federal jurisdiction into one of lowest-taxed petroleum provinces in the world. Rather, it was the Reagan-era reform known as Area Wide Leasing. Due to the idiosyncratic fiscal regime in the US Federal OCS (explained in more detail in Boué and Jones 2006), and the role that cash bidding bonuses in it play, the changes in the auction procedures for leasing offshore tracts gave rise to a brutal contraction in OCS fiscal revenues (ibid.) 26 One should also highlight, en passant, the remarkable parallels between Kemp’s argument for laxer tax on high-cost oil fields on the one hand, with the ferociously denounced prescriptions of Arthur Scargill (who essentially advocated keeping uneconomic pits open by not dissimilar means) on the other. 27 In fact, research evidence about the profitability of small fields, a critical support for government policy, is notable by its absence, and where it does exist suggests the opposite of conventional wisdom because small fields may be developed very profitably by taking advantage of existing infrastructure in mature basins, for example Bond, Devereux, and Saunders (1987, 51) state that ‘There is only a weak correlation between small fields … and fields with low profitability.’ 28 See Mommer (2002b) for the emblematic case of Petróleos de Venezuela (PDVSA). The discussion surrounding changes in Mexican institutional arrangements to permit incentivised service contracts strongly suggests that PEMEX is now playing a similar role to that played by PDVSA in Venezuela during the 1990s, and without any awareness of the part played by the Venezuelan Apertura policy in the decomposition of the political system in 86 UK Energy Policy and the End of Market Fundamentalism

the country, and the subsequent rise to power of Hugo Chávez. Interestingly, the issue of the potentially divided loyalties of the large state oil companies in oil exporting countries would appear to have reared its head soon after the establishment of the first of these, the National Iranian Oil Company, in the wake of Mossadegh’s nationalisation of the oil industry in Iran (see Farmanfarmaian, M. and Farmanfarmaian, R. (2005, 342), for a trenchant account of NIOC’s repeated attempts to sabotage OPEC, which started soon after the latter’s foundation and would continue throughout the Shah’s reign, as related in Bamberg (2000). 29 Despite the fact that this study proved to be among the most cost-effective initiatives ever undertaken by the Wyoming legislature, vigorous lobbying by oil and gas interests has meant that it has not been updated and has been somewhat relegated to oblivion. During an 8 December 2004, meeting of the Legislative Management Council, former Wyoming state Rep. Fred Parady proposed that further funding of this study ‘be deferred’ and left for consideration in the next session. The result, according to Mark Quiner of the Legislative Service Office, was that ‘it was never brought up again ... They defunded it.’ (WyoFile Newsletter, 8 February 2008 (http:// wyomingreview.com/?p=272))