Energy Policy Issues (Excluding Taxation) PDF

Energy Policy Issues (Excluding Taxation) Professor Alex Kemp University of Aberdeen Business School High level overview of objectives of Host Governments and Investors and early licensing arrangements in the UK Concept of Deadweight Loss from...

Energy Policy Issues (Excluding Taxation) Professor Alex Kemp University of Aberdeen Business School High level overview of objectives of Host Governments and Investors and early licensing arrangements in the UK Concept of Deadweight Loss from Oil Price subsidy  Deadweight Loss from Oil Price Subsidy P P0 S C A B P0-s D 0 Q0 Q1 Loss of Gov./ export revenues from subsidisation = areas A+B+C Deadweight loss = area C Growth of Infrastructure End of Section Problems of Maturity Professor Alex Kemp University of Aberdeen Business School  21st Century: Maturity 1.Manifestations of maturity – (a) much lower average size of discovery and development , (b) lower E and A effort, and so smaller number of discoveries. 2.With lower size of field costs per barrel increase.  21st Century: Maturity 3. Smaller fields generally have faster decline rates from plateau than large fields. 4. Result is that, with decline in importance of early vintage large fields, aggregate production falls at brisk pace unless substantial number of new fields are regularly brought on stream. Offshore Field Approvals Offshore FDP Addenda Approvals  21st Century: Maturity 5. Various (PILOT) government- industry initiatives to enhance activity levels: a. Fallow block and field initiative. Problem unveiled in 1980’s when small companies complained that they could not obtain access to acreage tied up under existing licences but where no work had been undertaken for 10 years.  21st Century: Maturity In first few Licence Rounds second period of 40 years had no compulsory work obligations. Government acknowledged problem but slow to take effective action. Recent more proactive policy of insisting on acceptable work programme or trading/relinquishing acreage now bearing fruit.  21st Century: Maturity b. Promote licences. Encouraging very small companies to undertake geological / geophysical studies with 90% discount on licence fees for first two years. Many licences awarded with some positive outcomes. But blocks are by definition high risk.  21st Century: Maturity c. Stewardship initiative. To encourage maximum economic recovery on mature fields through incremental investments. If stewardship acceptable to DECC not forthcoming operator can be asked to trade the asset.  21st Century: Maturity d. Access to infrastructure. Historically third party access to transportation and processing infrastructure was encouraged but through independent negotiation. Result was local monopoly profits made by some asset owners, resulting in PRT being applied to tariff incomes in 1983.  21st Century: Maturity Problem of slow and sometimes expensive access was recognised by Government, but slowness to intervene, Revised Code of Practice in 2005 provides that, if after negotiation, no agreement on terms is reached, DECC can determine tariffs. Not clear how well scheme is working. PRT abolished on tariffs on new contracts. e. Problem of ageing infrastructure  Wood Review 2013-2014 Recommendations Recommendation 1: Government and Industry to develop and commit to a new strategy for Maximising Economic Recovery from the UKCS (MER UK) Recommendation 2: Create a new arm’s length regulatory body charged with effective stewardship and regulation of UKCS hydrocarbon recovery, and maximising collaboration in exploration, development and production across the Industry. Recommendation 3: The Regulator should take additional powers to facilitate implementation of MER UK. Recommendation 4: Develop and implement important Sector Strategies Exploration (including access to data) Asset Stewardship (including Production Efficiency and Improved Oil Recovery) Regulation Development (starting with the Southern North Sea) Infrastructure Technology (including Enhanced Oil Recovery and Carbon Capture and Storage) Decommissioning  Fostering MER UK 1. Oil and Gas Authority (OGA) - Well-resourced regulator as well as promoter 2. Oil and Gas Technology Centre (OGTC) - To facilitate developments of appropriate technology 3. Oil and Gas Innovation Centre (OGIC) - To facilitate appropriate innovation 4. Industry Technology Facilitator (ITF) - To facilitate technological developments (JIP basis) In 2020 modifications to central objectives of OGA from MER UK to include contribution to Energy Transition and reduction in CO 2 emissions. Concept of social license to operate by industry. Consultation by OGA.  Professor Kemp’s response to OGA Consultation 1. Form of Response This response to the OGA Consultation on Proposal to Revise the MER UK Strategy adheres to the request of the OGA to provide answers to the specific questions in the same order that they are posed. Further related suggestions and comments are provided at the end. 2. Answers to Specific Questions in Consultation Q1: Do you have any comments on the proposed changes to the Introduction? “The proposed changes are to add 3 further principles to the introduction of the revised Strategy, namely (1) to assist in meeting the Net Zero Emissions Target, (2) to consider the behaviour of the industry with respect to the operation and maintenance of good environmental, social and governance practices, and (3) compliance with licence and other regulatory obligations. “Both the UK and Scottish Governments now have legal commitments regarding Net Zero emissions. Given this they can legitimately expect that the oil and gas sector makes contributions to the achievement of this objective. But there is a need for policymakers to clarify to the industry the nature of that contribution and to specify the related incentives to procure the Net Zero Target. In turn, this requires a published integrated Energy Policy which would state the policy instruments which the industry would be required to follow. Similarly, the proposal that the industry should develop and maintain good environmental, social and governance practices is defensible, but the industry should be given clear guidance on what this means in practice. Compliance with established licence and other regulatory obligations is clearly desirable. Clear statements of these Q 2. Do you have any comments on the proposed changes to the Central Obligation? “The proposed changes to the Central Obligation are defensible in principle. To secure the maximum value of economically recoverable petroleum requires that a clear definition of this be given to the industry including the related environmental costs and the need for private sector investors to achieve a satisfactory expected return. Clarification on what constitutes reasonable reductions in emissions should be given. Support for CCS projects requires that policymakers clarify what incentive mechanisms are available to enable private sector companies to make informed investment decisions in such projects.” Q 3. Do you have any comments on the proposed changes to the Supporting Obligations to enable the proposed Net Zero limb of the Central Obligation? “With respect to the Asset Stewardship Supporting Obligation the proposed provisions are generally reasonable but clarification to the industry is needed on the meaning of the requirement to reduce greenhouse gas emissions “as far as reasonable”. There should be some limit on this such as where the costs incurred are disproportionate to the benefits. Guidance should be given on the circumstances where this would occur. The proposed requirement on the industry to consider all applicable options for existing and new developments and to seek out and apply relevant practices from other industrial sectors could be very wide-ranging in practice, and more specific guidance should be given to the industry. “The proposed requirement that infrastructure be maintained and operated to achieve optimal potential for future re-use or re-purposing in support of Net Zero Emissions is generally defensible. But the implementation of this in practice is by no means simple. Thus, the taxation issues relating to change of use of facilities need updating. For example, it is unclear what a “just and reasonable” allocation of costs between North Sea Ring Fence and non-North Sea activities means in practice. Also, the issues of for how long and in what circumstances the maintenance and operation of infrastructure can be required requires clarification. It is agreed that technological advances and their application are necessary to increase economic recovery from the UKCS and to facilitate reductions in emissions and the development of CCS and hydrogen projects. "The extent to which all this should be undertaken by the oil and gas sector needs to be clarified. What are reasonable expectations? It is to be expected that, oil and gas companies will respond to incentives. Thus, relevant incentives need to be indicated by policymakers. There are several possibilities. For example, funding through the OGTC could be extended. An effective carbon price either via a UK ETS or carbon tax could encourage CO2 capture and substitution of renewable electricity for power generated from diesel and gas. The most effective instruments are those which produce the desired effect at lowest resource cost (i.e. including external/social costs) to the nation. Investors need clarification and an integrated Energy Policy framework. The UK Government should publish an Energy Policy statement to guide private sector investment decisions. “The OGA should then be better informed to effectively regulate the oil and gas sector. On the development of desired technologies, the OGA could use the licence system to advantage. Thus, when inviting applications for exploration licences the OGA could include in the list of criteria for making awards marks for the development of desired technologies as enunciated in the integrated Energy Policy. Similarly, when assessing field development plans the OGA could request the development and implementation of technologies consistent with the attainment of emission reductions and possibly CCS schemes and hydrogen projects consistent with the Government’s integrated Energy Policy statement. The Committee on Climate Change states that CCS “is a necessity not an option for reaching net-zero GHG emissions”. “This being the case it is even more incumbent on the UK Government to provide a policy framework indicating how this can be achieved. With respect to the OGA’s role as the licensing authority for CO2 storage, it is logical that the OGA should set out how the industry could support and collaborate on such projects, particularly on the extent to which the industry can reasonably be expected to investigate these projects. Energy policy decisions on the required incentives for investments in such projects are essentially a matter for the UK Government which should clarify the types of incentives in an Energy Policy statement. With respect to access to relevant infrastructure for CCS clarification on the terms, including the related taxation issues relating to inside and outside the North Sea ring fence is needed.” Q 4. Do you have any comments on the proposed clarifications to the Supporting Obligations to reflect stewardship and other changes in the UKCS? “The proposal that the OGA introduce a specific Supporting Obligation to promote good corporate governance represents a further extension of the role of the OGA. No doubt this reflects the current public interest in the concept of social licence to operate which, in turn, reflects the increased public interest in climate change issues and corporate attitudes and policies towards this subject. Given the UK Government’s commitment to a target of Net Zero emissions, this extension of the OGA’s role is acceptable. But clarity should be given to the industry on the definition of what constitutes sound social governance. The concept is rather vague and open to many interpretations. The industry is entitled to obtain clarification on the meaning of the concept in practical terms, and how a company is expected to meet the defined obligations. “The proposal that the OGA can require licensees to inform the OGA when they consider that they will be unable to make a satisfactory expected return is consistent with the overall objective of procuring Maximum Economic Recovery. But the OGA should appreciate that the attainment of a satisfactory return, especially at the exploration stage is subject to many uncertainties, and a very clear-cut answer can be difficult to make. The time at which a clear-cut answer can be given needs to be considered. With respect to access to infrastructure, there remain some uncertainties regarding the meaning of “fair and reasonable terms”. Thus, the concepts of marginal cost and average cost pricing in the short-run and long-run can both be employed in what may be defined as an equitable manner. Further clarification on what is “fair and reasonable” in different circumstances would be helpful. “With respect to decommissioning of infrastructure, the notion of considering re-use or re-purposing of such infrastructure is consistent with an integrated Energy Policy. But oil and gas licensees should be given clear guidance on what their obligations are, before submitting decommissioning plans. There can well be cost implications from re-purposing assets. The requirement that licensees must collaborate with their supply chain is consistent with the objective of attaining MER UK. But the meaning of such collaboration in practice is not clear, as experience over the past few months has demonstrated. “There are clear benefits to be gained from guidance being given to the respective parties on (a) what collaborative behaviour means, and (b) on what non- collaborative behaviour and its consequences entail. The OGA could play a constructive role in the facilitation of collaborative behaviour in areas such as the design of cost and reward sharing contracts when the result could be to enhance MER UK. Just as cooperation among licensees can enhance MER UK (for example, by facilitating field cluster developments) so can genuine cooperation between licensees and supply chain companies facilitate the viability of projects.” Q 5. Do you have any comments on the proposed changes to the Required Actions? “The proposal to revise the title of a required action from Cost Reduction to Cost Efficiency is sensible. Cost efficiency could even emanate from an increase in expenditure when the result is a (substantial) increase in productivity. The concept is also consistent with Net Zero considerations because it can include external or environmental costs.” Q 6. Do you have any comments on the proposed changes to the Definitions? Q 7. On what do you base your forecasts of future carbon prices? “The proposal to include in the definition of operating costs those associated with carbon emissions is conceptually sound, especially in the context of the Net Zero target. From an economic perspective, CO2 emissions are certainly a relevant cost. Clarification should be given to licensees and others. With respect to the definition of region, care should be taken to clarify what is a region and what is an area. Presumably, there can be several areas within one region. Forecasts of future carbon prices are difficult to make with any confidence just as forecasts of oil prices are difficult to make with confidence. The price depends “Thus, demand depends on the level of economic activity generating emissions. Thus, in 2008 after the financial crisis, economic activity which generated emissions fell substantially. The value of CO2 allowances in the EU ETS then fell substantially as a consequence. In 2020, the price also fell substantially in the light of the dramatic fall in economic activity following policies relating to the COVID-19 crisis. The price has recovered following hopes that there will be an economic recovery. On the supply side the number of EU ETS allowances issued is subject to the variability of Government policies reflecting (a) the extent to which the Governments are determined to raise the price to reduce emissions, and (b) the perceived need to safeguard the competitive interests of particular industries. The price also depends on the extent to which companies are able to reduce their own emissions and thus reduce their demand for allowances, and even sell allowances which they have received. The extent to which allowances under the EU ETS are issued free of charge or by auction also influence the price. “Forecasts of future carbon prices have to take into account the likely behaviour of all the above factors influencing the supply and demand. International organisations, such as the World Bank and IMF, published estimates of the carbon price necessary to achieve climate change targets. Recently, these prices have been in the $70 - $75 per tonne of CO2. All the above are taken into account in considering future carbon prices. Q 8. Do you have quantitative evidence of any specific impacts of the proposed revisions to the Strategy that you would like us to consider? Quantitative evidence of the potential effects of the proposed changes to the Strategy are not available. But it is clear that there will be compliance costs on the industry. These should be clarified and set against the value of the benefits in the form of enhanced MER UK taking into account the environmental benefits and the enhanced ESG benefits to the industry. The latter can mean that raising of capital (both debt and equity) becomes easier and less costly.” End of Section Depletion Policy and Related Issues Professor Alex Kemp University of Aberdeen A. Possible Lessons from Hotelling Framework If realised the Energy Transition to Net Zero Emissions by the middle of the century has profound implications for the oil and gas sector. In this section I discuss what these implications might be. To do so we need to have an appropriate framework to analyse the effects. A useful starting point is the framework which has developed from the famous Hotelling model. This dates back to 1931, but since then the framework of the model has been developed to enable useful insights to be gleaned regarding longer term trends.  The Hotelling model is essentially one of the long-term optimal depletion rate of a non-renewable natural resource. It is assumed that the owners of the resource will deplete the reserves to maximise their returns through time. The resource owners will have their discount rates which they will use to calculate their expected returns. Thus they will plan to maximise the present value of their returns. They will also take into account the externally-determined returns available elsewhere in the market. The essence of the optimal depletion rate of a fixed and known stock of reserves is shown in Chart 1. Chart 1  The key point is that the resource owners maximise their returns by equalising them in present value terms through time. Their returns cannot be increased by changing the depletion rate. With fixed and known reserves depletion reduces the remaining stock. Thus the price net of production costs rises at the interest (or discount) rate reflecting the increasing scarcity. The relationship between the externally determined interest rate and the rate of increase in the oil price is important in the model.  Let r = the interest rate and g = growth rate of the oil price. If r > g oil earns (via capital gain) less than the market rate of interest. The oil investor reacts by selling more oil now. Given the fixed stock the result is an increase in g over time. If g > r the resource owner sells less oil now. In equilibrium r = g and the resource rent or depletion premium grows at the same rate as the discount rate. The path of the oil price over time with a fixed cost per barrel is shown in Chart 2. Chart 2  The path of the oil price is shown in Chart 3. In the simplest model the price rises until the reserves are exhausted. The model can be simplified to incorporate the availability of a competing backstop technology such as renewable energy. In Chart 3 this is shown as Pb. Oil production becomes uneconomic at prices in excess of Pb and thus some deposits will remain in the ground. Chart 3  How does all this relate to the real world? In Chart 4 the long-run behaviour of the oil price is shown. At a glance it indicates no obvious consistency with the basic proposition of the Hotelling model. Changes in supply and demand are highlighted, neither of which received attention by Hotelling. Source: EI Statistical Review 2023  But the Hotelling framework can still be used to indicate the effects of the Energy Transition. There is every likelihood that this will result in decreases in the costs of alternative energy sources. This has already happened to offshore wind. In Chart 5 the effects of this on the price trajectory of oil are shown. With price trajectory starting at P0 and backstop technology price Pb oil production ceases at T. Following a decrease in the price of renewable energy to Pb’ the entire price trajectory falls with the decline in the initial period being from OPo to OPo’. This follows from the basic proposition of the Hotelling framework. The lifetime of the industry is reduced from OT to OT’. Chart 5  The history of the oil industry to date has been personified by increases in reserves, contrary to a basic assumption of Hotelling. Acknowledging this within the framework of the model the effect is to extend the life of the industry. In Chart 6 its life increases from OT to OT’. But the result is also to reduce the price trajectory throughout its life with price falling from OPo to Opo’ in the initial period.  Chart 6 O  Consistent with the above the history of the industry to date has exhibited many new discoveries. The effect of this within the Hotelling framework is shown in Chart 7 which shows the effects of periodic discoveries of different sizes on the price trajectory through time. It is seen that each significant discovery causes an initial price fall followed by an upward longer term movement consistent with the Hotelling framework. Chart 7  At this stage some empirical evidence is appropriate. In Charts 8 and 9 the evolution of world proven reserves is shown from the BP Statistical Review. Chart 8 Chart 9  The key point is that reserves have increased very substantially over the long-term to date. An empirical measure of scarcity is the reserves : production ratio (R:P ratio). These are shown in Charts 10 and 11 using data from BP Statistical Review. The reserves are proven. Chart 10 Source: BP Statistical Review of World Energy 202  It is clear from these charts that to date there is no scarcity of physical reserves. The present R:P ratio is around 50. Upward price behaviour has been due to above ground factors not below ground ones. Costs are clearly important in determining investment and production. There have been many occasions when unit costs have been reduced. The effect of this within the Hotelling framework is shown in Chart 12. Chart 12  It is seen that when costs fall from OC to OC’ per barrel, the price trajectory changes from an initial value of OPo to Opo’. The trajectory after the initial price fall becomes steeper than the original one and the ultimate end of production is earlier at OT’ compared to OT. There are no increases in reserves in this scenario. Demand is higher with the lower price, but, because there are no increases in reserves in this scenario, the scarcity phenomenon becomes more acute in subsequent years. An example of cost reductions is illustrated in Chart 13 which shows the evolution of unit costs in the UKCS. Chart 13  The effect of an increase in demand within the Hotelling framework is illustrated in Chart 14. Chart 14  This shows the effect of an increase in demand. The result is an upward movement of the price trajectory and an earlier termination date of production at OT’ compared to OT. There are no changes in reserves in this scenario. We now need to consider the effects of the Energy Transition to Net Zero. The IEA has recently produced a detailed study on this with Net Zero being achieved by 2050. The production/consumption figures emanating from this study are shown in Chart 15. Chart 15 Source: IEA: Net Zero by 2050  These are very dramatic figures in relation to the performance of the industry to date. The IEA states that no new field developments are required from now onwards! In terms of the Hotelling framework there is a major inward shift in the demand curve which produces a downward movement of the whole price trajectory. The IEA projects a dramatically lower price path which is shown in Table 1. Table 1 IEA: Oil Price Path for Net Zero by 2050 $US (2019 values) 20102020 2030 2040 2050 91 37 35 28 24  There are many uncertainties surrounding these projections. It is unclear to what extent oil and gas producing countries will conform to the perceived requirements of Net Zero. It is also unclear to what extent consuming countries will conform to the requirements to reduce their consumption to the major extent deemed necessary by the IEA. In terms of incentive effects producers who are influenced by the price scenario have an incentive to produce more sooner rather than later. By itself this would reduce prices in the nearer term. But long-term investment (and thus production) may also be reduced if the IEA price scenario is influential. By itself this would increase oil prices.  The IEA Net Zero scenario is certainly consistent with the view expressed by Sheikh Yamani that, just as the stone age did not end because of lack of stones, the oil age would not end because of lack of oil. The IEA Net Zero scenario will certainly accelerate the timing of this. There would clearly be very substantial oil (and gas) resources left unexploited. B. Alternative Use of Revenues and Depletion Policy It is certainly arguable that the design of depletion policies should consider the alternative use of the revenues. This has been highlighted in a paper by Paul Stevens and John Mitchell of the Royal Institute of International Affairs, Chatham House, London. They argue that trade-offs among (a) expected oil price increases, (b) returns from foreign investment of oil revenues, and (c) domestic investment, all in relation to operating costs, development costs, and exploration costs should be considered. Their thinking is indicated in the following charts. Chart 16  In Chart 16, the vertical axis shows expected rate of growth of the oil price. On the horizontal axis the expected returns from investing the oil revenues either abroad or domestically are shown. In this case it is assumed that higher returns can be achieved from domestic investment. In the simple case shown in Chart 16 the costs of oil production are assumed to be zero. The policy- maker will make the decision of either producing (depleting) now or leaving the reserves in the ground depending on which action gives the highest expected return. The higher the expected growth rate of oil price the greater has to be the returns from investing the revenues at home or abroad. The depletion rate thus depends upon this comparison. The case illustrated in Chart 16 is a great simplification. Chart 17  In Chart 17 the various costs are introduced as necessary elements in the calculations. The lowest cost oil comes from fields where the exploration and development costs have already been incurred. The returns from production are thus relatively high. Thus the expected oil price increase necessary to compensate for not producing oil and investing the revenues at home or abroad will have to be relatively high, but not so high as in the case where production costs are zero. Similarly, when field development costs have to be incurred, the oil price increase required to produce a higher expected return than that achieved from investing the proceeds at home or abroad will be rather less.  Finally, in situation where exploration as well as development and operating costs have to be increase the oil price increase required to produce a higher return compared to domestic or foreign investment of the revenues will be still lower. It follows from the above that, if the oil price is not expected to increase but could well decrease, the incentive to deplete at a fast pace becomes greater. But incentives to explore and perhaps develop new fields could be reduced. C. Depletion Policy and Security of Supply: A Case Study of the UK Thinking on depletion policy of UK in 1970s and 1980s: a) Emphasis on Security of Supply and self-sufficiency b) Regulations to curtail production from existing producing fields and development of new fields to prolong self-sufficiency. On old fields no cut in production until 150% of field investment cost had been recovered. Maximum production cut of 20%. c) Difficult for licensees to obtain upward variation in production above that in field development plan. Chart 18 Chart 19  The historic behaviour of UK oil production and consumption is shown in Chart 18 and for gas in Chart 19. There was a vigorous debate about whether the UK Government should intervene to reduce the growth of oil production in the early 1980’s in order to prolong self- sufficiency and enhance security of supply. This was favoured by the Department of Energy. The Treasury was more sceptical particularly regarding reductions and postponement of production from fully developed fields. In the event the depletion intervention powers were generally not used because of the negative effect on near-term tax revenues at a time of large budget deficits.  The emergence of the Energy Transition and Net Zero Emissions as an objective in the UK has drawn renewed attention to the prospective degree of reliance on imports of oil and gas given the prospect that UK production may fall at a brisk pace. This might cause not only enhanced reliance on imports but on oil which may have come from sources where little attempts are made to reduce CO2 emissions in the production and transport of the oil to the UK. The possibilities with long-term UK oil and gas consumption being in line with the estimates of the Committee on Climate Change on what are required to meet the Net Zero target by 2050 are shown in Table 2. Table 2  The results in Table 2 show that oil import dependency was in the range 36%-27% in the period 2015-2019 but would exceed 40% annually from 2023 to 2035 and thereafter would exceed 30% annually to 2050. With natural gas import dependency has risen substantially to exceed 50% in recent years. This is set to increase to exceed 60% annually over the long period 2025 to 2050. The National Grid has undertaken a study on the possibilities in the UK gas market given the Net Zero UK obligations. The results are shown in Chart 20 under various assumptions regarding both production and consumption. Chart 20  The results in Chart 20 indicate the huge range of possibilities reflecting the wide range regarding gas demand in particular. The most recent UK oil and gas production estimates produced by the NSTA and the most recent UK oil and gas consumption estimates produced by the independent Climate Change Committee to be consistent with the achievement of Net Zero by 2050 are shown in Charts 20a and 20b. End of Section Third Party Access to Infrastructure Professor Alex Kemp University of Aberdeen Business School  Model from Kemp and Phimister, Economic Principles and Determination of Infrastructure Third Party Tariffs in the UK Continental Shelf (UKCS), North Sea Study Occasional Paper No. 116, University of Aberdeen Department of Economics, July 2010, pp.26 b) Model The initial model examines a situation where there are three potential user oil fields and a pipeline infrastructure with excess capacity is available. The marginal cost of using the infrastructure is less than the average cost. The three fields have different unit costs. Consider three oil fields with potential output levels q1 , q2 , q3. The marginal (incremental) cost of oil from each field is given by fixed values c1 , c2 , c3 where c1  c2  c3. Output from each field could be transported to market via a single pipeline (which has capacity of at least q1  q2  q3 ) and sold at an exogenously determined oil price, pm. Total costs for transporting oil are given by TCa F  ca q where q is the total output transported via the pipeline. The fixed cost F combined with the constant marginal cost ca means that the provision of the infrastructure service is a natural monopoly with falling Average Costs F  ca which here always remain above marginal cost ca. The fixed q cost F should be interpreted as covering any cost which is effectively independent of the quantity of oil transported. Hence clearly the capital costs of original investment are included but also it may include certain short run costs which are required to maintain the capacity of the infrastructure.  First, to characterize the effi cient outcome where overall profits would be maximized, consider the case where all three fields and infrastructure are operated by a single firm. If overall the fixed cost of the infrastructure is covered such that total revenues are at least as great as overall costs, the firm should operate any field where the marginal cost of transporting the oil ca is less than the net revenue from producing the oil. The thresholds, pm  c1 , pm  c2 , pm  c3 are therefore the maximum pipeline costs at which Fields 1,2, and 3 would be viable, and represent the usage of infrastructure services at different costs. Figure 1 illustrates an example case where the effi cient solution is that all three oil fields would operate. c) Potential Market Outcomes with No Regulation To illustrate the potential for ineffi ciency associated with a local monopoly in this context consider now the case where the fields are licensed to three separate operators, firms 1,2 and 3, and the ownership of the infrastructure is held by a private local monopoly. Each field licensee is assumed to profit maximize and therefore will only choose to operate from each field if marginal revenue is at least as large as the marginal cost from producing and transporting oil. Hence, Field 1 will operate if pm c1  pa , Field 2 if pm c2  pa and Field 3 if pm c3  pa. Setting these relations as equalities defines the maximum access price at which each field will operate. Hence, in Figure 1, demand (willingness to pay) for pipeline access is characterized by the step function line with thresholds, pm  c1 , pm  c2 , pm  c3. If the infrastructure owner is constrained to charge a single access price pa to the pipeline, the market solution may lead to an ineffi cient number of oil fields being exploited. In the example, to maximize profits the infrastructure owner would choose either pa  pm  c1 , or pa  pm  c2 , or pa  pm  c3. Whether the latter effi cient price is chosen depends on whether the loss in revenue from lowering the price for existing fields is less than the gain in revenue from pricing to ensure that there is effective demand for access from higher cost fields. In the example illustrated in Figure 1, the infrastructure owner would choose pm  c2 as the single access price, as the loss of profit from moving to the effi cient price pm  c3 (Area D) is greater than the profit gain (Area G). Hence, in this case the market outcome would lead to the ineffi cient under-exploitation of the oil resources.. As the local monopoly access price depends on the final market oil price pm , where this market price is particularly volatile one would expect access contracts to be written with terms which vary explicitly with the final market price. In this simple setting, the effi cient solution can obtained via the market by allowing the infrastructure owner to price discriminate and set individual access prices for each field. In this case with perfect information, the infrastructure owner could set access prices pm  c1 , pm  c2 , pm  c3 per unit transported for Fields 1, 2 and 3 respectively, and hence capturing all the rents from the three oil fields (but ensuring development of all fields). Alternatively, the infrastructure owner could set two-part tariffs, where each user pays an access fee (different across each user), and a separate charge equal to the marginal cost ca for each unit transported. In reality a number of factors undermine the ability of the price discriminating monopolist to generate the efficient solution via an unregulated market. Importantly, as the development of each oil field involves significant sunk costs, there is a potential hold-up problem which will reduce the licence holders’ incentives to invest. In principle field marginal costs c1 , c2 , c3 would include elements to cover the opportunity cost for capital in field developments. However, once licence holders have sunk capital in developing fields, the infrastructure owner would, with sufficient information, be able to extract any surplus above the short run marginal production cost, meaning that the licence owner would be better off if he did not invest On the other hand, asymmetric information means field licence owners will have significantly better information on costs than the infrastructure owner. As a result, the infrastructure owner may be unable to extract all rents from licence holders with lower costs (Salanie, 1998). Partial vertical integration with a single firm being both infrastructure owner and operator of one of the fields can affect the market outcomes if there is a single access price for the other operators. Consider the case where the infrastructure owner also holds the licence to Field 1. Then, as before, the access price would be set at pm  c2 and Field 3 would not operate. However, if the infrastructure owner held the licence to the high cost Field 3, the access price would remain the same, but it would operate and transport the oil from Field 3 as the marginal cost of transport is below the marginal revenue from the field. d) Regulation in Model Framework The policy response to monopoly and in particular natural monopoly has been varied. For example, within UK utilities industries, the historic solution was to use vertically integrated state monopolies. More recently this approach has been replaced by the unbundling of such industries into segments containing markets which are potentially competitive, e.g. wholesale electricity and private monopolies controlling the network infrastructure but which are subject to price and other regulation (Newbury, 1999). In the simple local monopoly, if regulated prices can be set at marginal cost of transporting oil, regulation should in principle restore economic effi ciency. However, decreasing average costs in the natural monopoly case mean that the infrastructure owner will make a loss at marginal cost prices and the regulator would have to provide a subsidy to ensure that the service is provided. Figure 2 illustrates this with respect to the simple example model. Setting the regulated access price as paR c p then, as in the effi cient solution, all three fields will operate. At this price and quantity, average cost is greater than average revenue and the infrastructure owner makes a loss of area B + D + G. In contrast, all three field operators make profits of (A+B), (C+D), and (E+G) for Firms 1, 2 and 3 respectively. Hence, to ensure that the infrastructure owner operates the pipeline facility, the regulator must provide a subsidy of B + D + G. Such subsidies are diffi cult to achieve politically and ignore the wider economic ineffi ciencies induced arising from raising taxes to finance them (Laffont and Tirole, 1993). Partial vertical integration with a single firm being both infrastructure owner and operator of one of the fields, allows implicit profits from field operation to be set against the fixed cost of the common infrastructure. For example, if the infrastructure owner also holds the licence to Field 3, while the profit E+G remains above the fixed cost F, the infrastructure owner will operate both field and infrastructure. However, in the case where a single field operator bears the total fixed cost of the infrastructure, this will lead to premature (from an economic effi ciency perspective) abandonment of the field and infrastructure. In Figure 2 this would occur if the infrastructure owner holds the licence to Field 3 where profit E+G is less than the fixed cost, but the fixed cost is less that total profits across all fields ( (A+B)+ (C+D)+( E+G).  Where, as in the case of the UKCS, subsidy from the regulator is infeasible, the second best regulation prices are found by maximizing overall profit from the fields subject to the constraint that the infrastructure owner must not make a loss. In the case of a single homogenous service this leads to average cost or cost of service regulation, where the regulator sets the access price equal to the average cost of the operation of the infrastructure. In Figure 2 this implies par  AC q1  q2  q3 . At this price, by definition, the infrastructure average cost (which include opportunity costs of capital) and revenue are equal, and therefore the infrastructure will operate. A similar result holds under partial vertical integration where the infrastructure owner is also a user of the infrastructure operation (Armstrong, Cowan and Vickers, 1994). 1 1 Note this result does depend on the assumption that the product market is competitive. In other cases, the implications may be diff erent. For example, if the product market is regulated the best pricing rule in the presence of vertical integration is the effi cient component pricing rule which eff ectively states that the price of access should equal the incremental cost of access plus any opportunity cost in terms of lost profi t (see for example, Armstrong, Doyle and Vickers, 1996). It should be noted that second best average cost prices can lead to premature abandonment of higher cost fields. This would occur if average cost was sufficiently above marginal cost. For example, this would happen in Figure 2 if the average cost curve rose above pm  c3. The third field would not operate at average cost prices even if marginal cost was below this level. The simple model presented underlies the traditional approach to regulation. However it assumes that the regulator is able to accurately assess the firm’s costs and behaviour. Modern regulation theory emphasises the limitations of all pricing rules, including cost of service, due to the asymmetric nature of information between the regulator and the regulated firm. In particular, it explores the nature of the trade-off between preventing the regulated firm making excess profits and the firm’s effi ciency Joskow, 2005). The asymmetric information issues which arise can be simply illustrated using the cost of service/average cost pricing as an example. Assume the Regulator wishes to fix the price equal to average cost. Clearly the “correct” level depends on the regulated firm’s costs, information which the firm holds but may be imperfectly available to the regulator. In this case the regulated firm (infrastructure owner) has incentives to convince the regulator that their costs are as high as possible. In part what is known as the adverse selection problem can be addressed via auditing, and an important part of regulation has been defining transparent, common accounting procedures which regulated firms have to follow. Auditing, therefore, does reduce the ability of regulated firms to gain excess profits. However, it has no impact on the so-called moral hazard problem. If it is assumed that the firm’s costs (and therefore average costs) can be reduced by cost effort by the firm, e.g. via extra R&D, managerial effort, which cannot be perfectly observed by the regulator, the effect of average cost pricing is to eliminate any incentive that the regulated firm has to reduce costs. e) Long Run The model presented above focuses on outcomes for a given level of infrastructure, where therefore marginal costs cover short run incremental costs only. Nevertheless, it is clear from the model that where a given level of new investment (reinvestment) is required, regulation which prices access to the infrastructure at the short run marginal cost may not provide sufficient incentive for (re)-investment ( paR c p. in Figure 2) for infrastructure owners and developers. In long run decisions, the overall capacity of infrastructure available is also clearly variable. Decisions on overall capacity may arise either where new fields require new infrastructure or where reinvestment in existing capacity is needed due to depreciation of existing assets. In such circumstances, the effi cient access prices would include the marginal costs of providing capacity. The difference in the access price required for short run and long run effi ciency may be interpreted as analogous to the implications of peak load pricing (Joskow, 2005). In the short run, existing capacity does not constrain the outcome, and therefore if the infrastructure owner would operate at short run marginal cost prices, these are effi cient. Where investment in capacity is required, (i.e. it does constrain the outcome), the access price must cover marginal investment costs in order to ensure an effi cient level of infrastructure (re)investment. f) Regulation in Practice and Cost of Service Particularly in the US, average cost pricing or cost of service regulation has been the traditional method used by regulators to manage the trade off between trying to ensure private natural monopolies do not exploit their position while having sufficient incentive to provide the level of service demanded (Joskow, 2005). In the UK the private monopolies created via the process of privatisation and deregulation in the utility industries in the 1980’s and 1990s have been typically regulated via price caps (Newberry, 1999). This was an attempt to take more systematic account of the incentives which regulation gives to reduce costs (or not). In this system the regulator sets an initial Price po and x a target productivity factor and then prices for a fixed period are governed by a formula such as ptr  po 1  RPI  x  t. Hence, within the period the regulated firm gains any cost savings achieved. However, elements of cost of service pricing remain important within this system as the setting of initial price po depends in many cases on agreed profiles of capital and operating expenditure for regulated companies (see for example the regulation of UK Regional Electricity distribution companies RECs (Joskow, 2006; Pollit and Bialek, 2008). The implementation of a cost of service type of approach to regulation can be characterized by two steps. First, there is a determination of the regulated firm’s total allowable revenue or cost of service, and secondly the tariff structure. Total allowable revenue (or total revenue requirements) is estimated typically including allowance for “reasonable” operating expenditure, depreciation, an allowable rate of return on some defined capital base (regulatory asset value) plus other costs (Joskow, 2005). The tariff structure is then set so that the discounted value of predicted total revenue of the regulated firm’s activities covers this value. For example, in the regulation of UK Regional Electricity distribution companies, the values of x and po are chosen so that the present value of total predicted revenue for each firm equals the present value of total allowable revenue (Joskow, 2006; Pollit and Bialek, 2008). When regulated, access to network infrastructure does typically include cost of service elements. In the UK as discussed above access charges to the regional distribution electricity networks includes cost of service elements in setting initial prices for each regulator period. Similarly, although rather ad-hoc, the method of setting electricity transmission charges by National Grid aims to partially cover infrastructure cost (Pollit and Bialek, 2008). Although currently not regulated in the UK, in the US pipeline rates for interstate transport of oil have been controlled since the Hepburn Act in 1906. The methodology used here to set rates includes a cost of service element covering operating and capital expenditure or a market based rate where the pipeline operator can evidence suffi cient competition (FERC, 2010). 4. DECC Guidance Access: Tariff Determination As noted above the current DECC guidance on dispute resolution over Third Party Access to Oil and Gas Infrastructure (DECC, 2009) set out a number of principles which the Secretary of State will use to set access tariffs including supporting the principle of non-discriminatory access, which would appear to preclude price discrimination by infrastructure owners. The ICOP also states that tariffs should be non-discriminatory. Further, the principles of pricing access in the DECC Guidance (DECC, 2009, page 13) are discussed with reference to a number of different scenarios, which may be interpreted with respect to different cases in the simple model set out above. Firstly, for “infrastructure built as a part of an integrated field development”, terms would normally reflect incremental costs except where the field is near the end of its economic life in which case “third party access may need to be set above incremental costs to ensure it is maintained”. When this becomes insuffi cient due to the depletion of the field(s) owned by the operator, the fixed costs/access price will then be set at a cost of service level covering operating expenditure (DECC,2009, p13). In this scenario, the fixed costs F discussed in the model only cover operating expenditure with the initial investment cost deemed to be suffi ciently depreciated to be discounted. Hence, referring to Figure 2, this may be interpreted as implying that regulation would initially set the access price equal to marginal cost relying on partial vertical integration of infrastructure ownership with field operation to ensure that the fixed costs of the infrastructure are covered. When suffi cient field depletion has occurred in the field licensed by the infrastructure owner, the access tariff would then have to be reset to a cost of service level. In the second DECC scenario, where infrastructure operators can make a case that infrastructure was built or “maintained with a view to taking third party business”, a cost of service access price would be set covering both operating expenditure and return on capital. In terms of the model, this suggests that fixed costs F cover both operating and capital costs in this case due to the fact that this involves significant new or recent investment by infrastructure owners. While consistent with the traditional model of regulation (and the simple model presented above) i.e. assuming perfect information, the varying principles for access price setting suggested for different situations will pose challenges for the regulator when information is less than perfect. It is of course important to recognize, as modern regulation theory suggests, that it is not possible to ensure effi ciency and extract all possible excess profit from regulated firms. However, the different principles provided by DECC may provide potential perverse incentives for infrastructure owners. For example in certain circumstances, it may be in their interests to bring forward plans for the shutdown of its field(s) in order to ensure a move to cost of service access pricing. Similarly the distinction between infrastructure maintained (or not) for third part business would appear to provide some incentive to overinvest in infrastructure maintenance in order to move to a pricing regime which covers capital costs. 5. Taxation and Regulated Tariffs The prospect of the introduction of cost-related tariff determination in the UKCS raises the question of the appropriate tax treatment of tariff incomes. The historic situation was described in Section One above. This, of course, applied to a situation where the tariffs were determined purely by negotiation between the infrastructure owner and field developer. The abolition of PRT on tariff incomes relating to new contracts was introduced to enhance the competitiveness of the UKCS generally including the ability to contract for gas imports from Norway through infrastructure located in the UKCS. There was implicit recognition that the size of the tariff was influenced by the taxation applied to the related income. In the situation where tariffs are determined on a cost-related basis there has to be recognition of the tax payable on the income and the tax relief given for expenditures incurred in providing infrastructure service to third parties. Currently the tariff income is taxed at 50% (corporation tax (CT) at 30% and Supplementary Charge (SC) 20%) and the associated expenditures are relieved at the same rates. In general in a situation of infrastructure regulation the requirement to pay income taxes is taken into account by regulators in tariff determination. The size of the tax payments is a relevant consideration. The present situation in the UKCS should be seen in this context. There can be no doubt that corporation tax should apply to tariff incomes along with all other sources of corporate income, and that this should be acknowledged in tariff determination. But the application of SC to tariff incomes and its inclusion in cost-related tariff determination is very questionable. It could mean that tariffs are higher than they otherwise would be and result in economic recovery of oil and gas from potential user fields being reduced. The increased operating costs for user fields could accelerate the economic cut-off from such fields or even cause the non- development of marginal fields. In the above circumstances there is a case on economic effi ciency grounds for removing the SC on tariff incomes where the tariff is determined on a cost-related basis. It is arguably inconsistent to determine tariffs in this manner while levying SC on the income in question. Given that tariff determination on a cost-related basis is just starting the appropriate mechanism could be to remove SC from new third party contracts from a specified date. This should help to incentivise third party infrastructure agreements and encourage maximum economic recovery from the UKCS. 6. Conclusions In this paper an economic model has been developed to show the potential effects of third party tariffing of new oil/gas fields with an infrastructure owner who has some local monopoly powers. It has been demonstrated that, in the absence of any regulation at all, negotiations between the parties may not always lead to an economically efficient solution (which is the maximisation of economic recovery from the UKCS). An efficient solution could be procured by a scheme of discriminatory tariffs based on the willingness to pay of the users. This could ensure that even marginally attractive fields are developed. But this outcome depends on full knowledge by the infrastructure owner of the field owners’ costs. Further, if price discrimination by the infrastructure owner is not permitted (as is the case with the ICOP and DECC Guidance) the result can be that the costs of infrastructure operation are not covered. Non-discriminatory marginal cost tariff determination in a typical situation where the marginal cost of providing infrastructure services is below the average cost can be non-optimal and could lead to the premature closure of the infrastructure, and thus incomplete economic recovery. In these circumstances tariff determination by a regulator can lead to an economically more effi cient solution with enhanced oil and gas recovery. Average cost pricing ensures that all the infrastructure costs are covered. It should be recognised, however, that this is a second best solution and the resulting tariffs could still render a field uneconomic compared to marginal cost pricing. But in the absence of discriminatory pricing or subsidies this second best solution is the best that can be obtained. In the longer term where further investment in the infrastructure is required to maintain or enhance its integrity for use by third parties the necessary costs need to be reflected in the tariffs. In a situation where tariffs are determined on a cost-related basis the requirement to pay corporation tax on tariff income has to be acknowledged. But the payment of Supplementary Charge on tariff incomes and the associated reflection of that in tariffs charged is inconsistent and non-optimal, and could lead to incomplete economic recovery from the UKCS. There is thus a case for abolishing the application of SC to new third party tariff contracts in the UKCS. End of Section  Economics of Natural Gas (with special reference to the UK) Professor Alex Kemp University of Aberdeen Business School Significance of differences in types of gas finds 1. Southern North Sea: Dry gas Contracts can have substantial seasonal variations (swing factor) 2. Central & Northern North Sea: Gas associate with oil Less scope for seasonal variations. But: a) Field maintenance work in summer b) Substantial share of field costs and risks effectively borne by oil Field costs and risks effectively borne by oil Costs of Handling Seasonal Gas Demand Problem Supply 1.67 1. Swing factor in gas contracts: 2. Storage in (a) salt cavity, (b) depleted gas field 3. LNG storage: relatively high cost Demand – Interruptible contracts Gas sales & purchase agreements 1. Depletion contracts a) Dedicated source b) Volume linked to field performance c) Termination determined by economic limit 2. Supply contracts a) No dedicated field b) Fixed quantities c) Fixed contract life 3. Non price terms a) Daily contract quantity b) Delivery capacity (swing factor) c) Plateau DCQ d) Obligation to deliver e) Take or pay Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Obligation 100 100 100 100 100 100 f) Make up/carry Actual Take Take or pay 90 10 100 - 105 (5) 105 (5) 120 - 80 - forward payment Make-up - 10 10 5 - - Balance B/F Carry-forward - - - - - 20 Balance B/F 4. Price a) Different perspectives of seller and buyer b) Base price at start of supply c) Price escalators – several possibilities: i) crude oil price ii) oil products competing with gas, e.g. gas oil, fuel oil iii) recognised gas market price, e.g. Henry Hub in USA, NBP in UK. Spot and forward/future prices iv) electricity price v) coal price vi) inflation factor  vii) example: +0.1) viii) frequency of calculation (quarterly/monthly) ix) top stop: a) buyer concern – may compete against oil in one market and electricity in a second market Solution could be 2 Formulae (P1 and P2) where P1=x [ (0.3 x ) + (0.2 x ) + (0.4 x ) + (0.1 x ) P2= x [ (0.5) + (0.5) ] The lesser of P1 and P2 is used. Thus if oil prices fall P2 is used.  x) bottom stop: a) problem for seller i) guaranteed minimum price ii) price greater of two formulae xi) price break clause xii) most favoured nation clause. Can be used with advantage by both buyers and seller. Key features of UK gas policies, 1964-1986 1. BGC given monopsony buying rights & monopoly selling rights 2. Cost-related pricing to producers in UKCS 3. Negotiate4d prices with Norwegian sector producers. Higher than in UKCS, e.g. Frigg 4. Prices to gas consumers to reflect agreed rate of return for BGC 5. Price indexation to UK producers to reflet very limited cost inflation only. No indexation to oil price. 6. Long term take or pay contracts between producers and BGC 7. Large swing factor in contracts in Southern North Sea (1.67). 8. Landing obligation in UK by UK producers. Privatisation of BGC 1986 Structure in 1986: Role of BGC a. Producer (BG one of many) b. Transmission (BG natural monopoly) c. Supplier to Consumer (BG monopoly. 12 regional suppliers (e.g. Scottish Gas) Privatisation of BGC (How NOT to do it) 1. BGC integrated company with monopsony and monopoly powers 2. BGC could have been split into (a) production, (b) transportation, and (c) supply. Also 12 regional supply subsidiaries already existed. 3. 1986 ACT conferred monopoly to BGC on sales to domestic market for 25 years. Prices regulated by RPI- x formula. No evidence of underlying ROR. 4. 1986 ACT did not discuss terms of access to BGC pipelines by competitors who were encouraged to enter industrial market. 5. 1988 MMC Inquiry found that BGC had practised price discrimination in industrial market depending on whether customer had access to alternative fuel. 6. Competitors in industrial market had no gas because BGC bought it all under Long-Term TOP contracts. 7. Competitors had no clear knowledge of tariffs to be paid for access to BGC’s pipelines 8. (possible) Conflict of interest with (1) BG providing gas to competitors and (2) allowing access to its pipelines 9. Major disagreement over terms of access to BG pipelines. What ROR on (1) existing and (2) new pipelines? What WACC? CAPM used by OFGAS and BG with different results. 10. 1992-93 MMC Inquiry recommends (a) separation of BG trading from transport (and production) (b) ROR of 4%-4.5% on existing pipelines and 6.5%-7.5% on new pipelines. 11. 1995. Emergence of competition in production and supply to industrial market. 12. 1996 onwards. Introduction of competition in domestic market. Generally successful. Why so late? Fully achieved 1998. 13. 1996-97. MMC inquiry into BG transportation charges: (a) cost of capital 7% (b) regulatory value based on historic costs and market value of assets NOT CCA value, (c) RPI-x formula for tariffs. 14. (a) Transportation split from supply. BG Transco. Now national grid gas. (b) Marketing now Centrica with trade names (e.g. Scottish Gas). (c) Production became BG Group (now taken over by Shell) Evolution of UK gas market Source: BG Transco, Department of Trade & Industry Source: Ofgem Source: OEUK Economic Report 2022 Trends in Annual Gas Demand, 2007-2015 Source: BEIS Energy Trends UK Demand for Natural Gas Source: BEIS UK Imports and Exports of Gas Q1 2018 Source: BEIS Long-Term Gas Import Contract Volumes, by Contract Type, as of 1 November 2015 Source: Ofgem information request to shippers End of Section Security of Oil and Gas supply Issues Professor Alex Kemp University of Aberdeen Business School Measures of concentration and diversity  HERFINDAHL-HIRSCHMAN INDEX (HHI) A measure of market concentration. To find the index the individual market share of each firm is squared. The HHI Index is given by sum of these squired terms: HHI = Where is market share of firm.  SHANNON-WEIMER MEASURE OF DIVERSITY =( It is sum of product of market share multiplied by natural log of market share for each fuel in the market. In formula is proportion of total market supplied by fuel i. Minimum value of S.-W. Measure is zero when only one fuel (or source) is available. NO diversity of supply. If there were 5 sources of supply (or 5 fuels) and they were available in equal proportions then the maximum value of S.-W. Measure, showing total equality is 1.61.  Oil Export Dependence =xxx OER = Oil Export Revenues GDP = Gros Domestic Product OEV = Oil Export Volume POS = Primary Oil Supply PEC = Primary Oil Consumption 4 drivers of oil export dependence rations as follows:  Oil Export Dependence 1. Oil Export Revenue to Oil Export Volume – Captures Oil Export Price 2. Oil Export Volume to Primary Oil Supply – Importance of Oil Export c/f Domestic Use 3. Primary Oil Supply to Primary Energy Supply – Captures Oil Dependency of Economy 4. Primary Energy Supply to GDP – Captures Energy Intensity of Economy Tax on Imports No Imports: Q1 and P1 Free Trade: P2 with 0Q3 domestic production and Q3-Q2 imports Tax on Imports: P2+t with0Q5 Domestic production and Q5-Q4 imports  Energy Security of Supply with Special Reference to Oil and Gas in the UK Professor Alex Kemp University of Aberdeen Business School  Security of Energy Supply 1. Likelihood of meeting expected demand without major price or other disruption. 2. Emphasis on sources and dimensions of the risks, the measurement/probabilities attached to the different risks, and the repercussions of a supply disruption. Diversity of supplies likely to reduce risks. 199  UK Oil and Gas Context 1. UK relies on indigenous production and increasingly on imports. Imports not more risky per se. 2. Importance of supply diversity/concentration: (a) Diversity/concentration of indigenous production and sources of imports. (b) Degree of dependence on individual elements of infrastructure. (c) Degree of interdependence of supply sources. (d) Examples: 200 201 202 203  UK Oil and Gas Context (cont.) (e) In UKCS over 300 producing fields including over 100 for gas. No single field (oil or gas) constitutes a major share of total. 204  Sources of risks 1. Disruption to producing fields– technical problems. Age. 2. Disruption to pipelines – technical problems. Age. 3. Disruption to NTS. 4. Disruption to imports: (i) technical problems e.g. Ormen Lange (ii) political (iii) secondary effects from gas interconnection with Europe 5. Weather/temperature – especially with gas and importance of heating demand. 205 206 207  Policy Issues 1. What is “adequate” security of supply? 2. Is free market likely to provide “adequate” security? 3. What insurance premium is appropriate and who pays it? Should policy for gas be the same as for oil? 4. What requirement for stocks? 209  Oil Storage Reserve 1. Context is UK’s oil stocking obligations under EU and IEA commitments 2. Key EU requirement to maintain stocks equal to 90 days average consumption of preceding year. Obligation relates to (1) motor gasoline and gasoline-based aviation fuels, (2) gas oil, diesel, kerosene and kerosene-based aviation fuels, and (3) fuel oil. The Directive permits crude oil to be held as part of the3 obligation, taking account of refining yield of the crude. 3. As a major oil producer UK receives a derogation of 25%, with resulting obligation of 67.5 days consumption. With declining production the obligation will gradually increase to 90 days. BERR estimates that increases from 67.5 days will start around 2014 210  Changes in Detailed arrangements 1. Current system not delivering compliance with obligations. Designed when oil companies dominated wholesale and retail markets. Supermarkets and other smaller companies now important at retail stage. Difficult for government to monitor the market as companies with deliveries to consumers of less than 100,000 tonnes per year are exempt. Also lower obligation on non-refiners (48.5 days) compared to refiners (67.5 days). 211 2. New arrangements based on obligations on (a) refineries (67.5 days of consumption) and (b) importers (58 days of consumption). After transitional arrangements supermarkets will have no obligations, refiners will have enhanced obligations, and other importers will have obligations for first time. 3. Costs of operating the scheme have increased enormously with oil price increases, perhaps £1.5 billion for 2007. 212 4. UK industry has proposed that the scheme be run collectively by companies via an agency. Government is considering alternative schemes including an agency arrangement so long as it is not classified as a public body with PSBR implications 213  IEA Obligations 1. Maintain oil reserves equal to minimum of 90 days of net oil imports 2. Introduce measures to restrain oil demand 3. Participate in oil allocation scheme among IEA member when severe supply disruption occurs 4. UK became oil importer in 2006 and now has IEA stocking obligation 214 5. In a few years time IEA obligation will exceed EU one (Stocks count towards both obligations) 6. IEA rules not specify whether stocks to be held in crude oil or refined products. Proportions vary across member states. At late 2006 average for all members was 59% crude, 41% products. For UK it was 46% crude, 54% products. Countries which have substantial refineries with associated storage tanks tend to have high proportion in crude. Also costs of holding products are much higher. A noteworthy feature is that one IEA member state can hold stocks on behalf of another member. This is quite common 215  Gas Security of Supply 1. No comparable security of supply measure for natural gas despite its importance in energy market. Gas imports now around 50% of UK consumption. 2. Investigation of subject conducted by consultants for UK Government who concluded that (costly) intervention not necessary. 216 End of section Oil Funds and Related Issues Professor Alex Kemp University of Aberdeen Business School Two purposes of Oil Funds: 1. Budget stabilisation 2. Provision for intertemporal equity  Intergenerational Equity Solow (1974): Investment all economic rents from oil depletion into reproducible capital to obtain intergenerational equity Hartwick (1977): To sustainably extract oil every unit extracted should be equal to unit R.O.R. on capital invested. Solow (1986): Extends model to complex economy models. Permit achievement of constant consumption  Oil Funds 1. Stabilisation Funds: Reduce exposure of budget to volatile revenues. Does not achieve constant consumption 2. Saving Funds: Goal to accumulate wealth for future generations. Specified % of revenues put into funds. BUT does not necessarily equate with higher savings. Government could borrow more. 3. Oil Fund can be (a) integrated into budget, or (b) extra- budgetary. In (a) fund is a virtual one with no earmarking. In (b) separate management of Fund. 4. Fund can mute resource curse and Dutch disease but this not guaranteed. Sound budget and macro policy necessary.  Social Time Preference Rate (r) 1. Rate at which future consumption is discounted compared to present (ρ) 2. Future consumption likely to be more plentiful than present and thus have lower utility. This found by product of growth rate of per capita consumption (g) and the elasticity of marginal utility of consumption (μ) with respect to utility.  r = ρ + μg HMT take ρ = 1.5% ρ has 2 elements: HMT take μ = 1 (a) catastrophe risk (L) HMT take g = 2% p.a. (b) pure time preference (δ) ‫؞‬STPR = 0.015 + 1.0 x 0.02 = 3.5% This is in Real Terms Source: HMT, The Green Book, July 2011 (My Aberdeen)  Oil Funds 1. Oil Revenues are conceptually different from other main sources of tax revenue such as personal income tax, VAT, profits tax on manufacturing industry etc. Unlike these oil revenues emanate from the depletion of a non-renewable natural resource. They should accordingly be treated differently. 2. Oil reserves are part of a nation’s capital stock akin to other capital equipment. Oil depletion is comparable depreciation of capital equipment and should be treated accordingly. Prudent behaviour is to maintain/grow a nation’s capital stock and thus a sufficient share of the oil revenues should be invested to the extent necessary to compensate for the depletion effect. Consumption from oil revenues should be constrained to the permanent increase made possible by these revenues. 3. It is possible to argue that oil revenues improve the Government’s budget and permit reductions in interest rates and other taxation which facilitate increased investment. But results may be increased consumption rather than investment. 4. An Oil Fund is a mechanism which can ensure that any specified share of the revenues received is invested. It can also ensure that inter-generational equity is maintained. To produce permanent benefits through time only the income from the fund could be spent.  Deriving Permanent Income from Petroleum Exploitation Petroleum is a non-renewable resource. A Petroleum Fund may be established to provide a stream of permanent income from its exploitation. The principle is explained with a simple example.  An oil field yields economic rents of $100 million per year for 10 years. By investing a share of the rent a fund can be built up which would produce an income of $x per year in perpetuity, i.e. long after the field is depleted, provided the fund is maintained. How much of the petroleum rent has to be saved? Each year $x is spent and $(100-x) is put into the fund. Let the rate of return on the investment fund be r%. After 10 years the fund would have grown as follows:  From then on r% of the fund could be spent annually without dipping into the fund. This is x noted above, namely the amount which could be consumed in perpetuity. Setting x = r F gives: If r =.05 then x = $38.61 million. Thus saving just over 60% of the petroleum rent would generate permanent wealth which would make possible permanent annual spending = just less than 40% of the annual petroleum rent. The general formula from the above example where T is the total length of the oil production period is:  The return on the investment and the length of the oil production period are very important in determining the size of the permanent income. Illustrative examples are as follows:  Examples of Oil Funds a) Alaska Permanent Fund Founded 1976. Each year 25% of royalties and bonus bids are paid into Permanent Fund. These funds are not available for normal Government budget purposes. The Fund invests in stocks are bonds. A dividend is paid annually to permanent residents of Alaska. b) Alberta Heritage Fund Founded in 1976. Under control of Alberta Government. Initially 30% of total revenues from bonus bids, royalties and tax paid into Fund. This was reduced to 15% in 1980s when oil prices well and became zero in 1986. Monies invested in various projects in Alberta (pet projects). Low return obtained. Income reinvested until 1982. After that used for general Government purposes. In 1997 Fund reorganised and now invested in stocks and bonds. But no further oil revenues have been paid into Fund. c) Norwegian Petroleum Fund Established in 1990. Payments into it commenced in 1995. Amount invested not specified. It is all oil revenues minus those required for normal budget purposes. Fund monies invested overseas in stocks and bonds. Recently restyled as Pension Fund. End of Section  Further reading (in addition to textbooks in course brochure) Wood Review (Final) (My Aberdeen) A. G. Kemp, Key Issues Affecting the UK Gas Market from 1986 (My Aberdeen) Walter Mead, Towards An Optimal Oil and Gas Leasing System (My Aberdeen) P. Stevens & J.V. Mitchell, Resource Depletion, Dependence and Development. Can Theory Help? (My Aberdeen) HM Treasury, The Green Book, July, 2011 (My Aberdeen) N. Trimble, Gas Sales Agreements (My Aberdeen) A. G. Kemp, Mitigating the Resource Curse (My Aberdeen) ≈ There are very many relevant papers in the OGA website ≈