Markets, Regulation and Coordination
Modern advanced economy power sectors are typically a complex mix of competitive markets, technical and commercial regulation, and natural monopoly elements, with the boundaries not always clear cut (as when a high voltage interconnection is an alternative source of power competing with new and existing generation). Technical regulation governs matters such as equipment standards, while economic regulation controls charges levied by the entities responsible for the networks (as natural monopolies), and, in the form of competition law, also seeks to limit abuse of market power by generating companies or suppliers. In addition, market structures have been introduced to electricity system in many countries in the last three decades; the aim has been to allow competitive forces to drive down energy users’ bills.
‘Ancillary service’ markets, which deal mainly in power capability rather than energy, are designed to ensure stability through the provision of services related to provision of reserves of power, voltage control and reactive power, and frequency control, and system protection, which are provided by means that include batteries, load management and spinning reserves. Typically the purchaser of these services is the network operator.
One of the biggest issues for our low carbon future, however, will be to find the combinations of markets, formal or informal regulation, direct interventions and other means to achieve coordination within the sector, that can both deliver the efficient operation of a power system (the balancing of supply and demand at least cost), and also provide the incentives for the necessary investments.
In this context price signals may either emanate from a competitive market or be offered by a system operator in order to help meet the objectives and challenges described above. But it is important to appreciate that reliance solely on prices in a properly functioning market should be able to meet two distinct criteria; first it should result in the most efficient use of the current capital stock, ie deliver the optimised equivalent of merit order scheduling and dispatch. Second, prices in that market, and expectations of their future course, should provide sufficient incentive for the levels and types of investment that the system requires. In other words the necessity for a market approach is to deliver price signals that both result in the most efficient operation of a system, and also provide the incentives for the right amounts and types of investment.
Avoiding market failure
It is useful to review these two requirements, for efficient operations and investment, through the perspectives of potential for market failure in the power sector. Market failureoccurs when individual incentives for rational behaviour do not lead to rational or acceptable outcomes for society as a whole, and can occur for a variety of reasons. In the worst cases it can result in systemic failure. Society can no more afford systemic failure in relation to energy and climate issues than it can in health and the financial sector.
- Failure to price in the carbon externality.
Failure to reflect the “externality” costs of the impact of emissions on climate is well established as the “greatest market failure of all time” (Stern). It has been partially addressed through the EU emissions trading scheme and UK carbon price support measures. However these have been partial in sector coverage, and, due to insufficient ambition or vested interest capture, have been quite inadequate in relation to serious estimates of the cost of the externality[JR1] , or to incentivise more than a small part of the investment required. There has been a rise in the carbon price anticipating and responding to more ambitious EU targets for zero carbon, but it remains the case that they are unlikely to reflect the “true” cost on any of the several bases for estimation, or to be sufficient to induce the changes required.
There are obvious reasons for the limited willingness of governments to see higher carbon prices, not least the impact on consumer prices, but very low prices, even under carbon pricing initiatives, have been a reality. That in turn means that governments cannot and will not “leave it to the market” to meet its climate objectives. However even in the absence of other considerations, that reluctance provides a prime basis for interventionist and non-market policies.
Inability to price emissions adequately means that market solutions cannot work on their own. The theory of the second best[JR2] implies that once we have one major failure in the market, we cannot assume that other policies, eg competition policy, normally thought of as good, will actually improve welfare rather than reduce it. In our context even the simplest type of energy market is likely to produce the wrong outcomes for both operations and investment if social cost is not properly priced in. For example the absence of an adequate carbon price will have been responsible for the substitution gas back to coal in 2012 and 2013; this was a 30% increase in coal use for generation. And the absence of domestic gas from the carbon pricing arrangements mitigates against substitution of electricity for gas in domestic heating[JR3] .
Potential Remedies. The remedies are either much higher carbon prices or major policy interventions. But any policy interventions by government or regulator will inevitably have their own major market impacts, and invalidate the assumption that investment can then realistically be based on a “pure” market assessment.
- The general investment problem.
In simple terms, investors in new generation facilities are typically dependent for their return on a revenue stream over 20 or more years, starting after commissioning of the new plant. In principle they can anticipate the projected revenues in an energy only market, possibly augmented by premium prices in periods of scarcity. Twenty year forecasts of power market spot prices may seem challenging or improbable. But the more important point of principle is that even if the investors could anticipate strong prices over many years ahead, that expectation would be undermined, not just by subsequent competitive entry, but by support for that entry from the regulator or from downstream utilities. Having sunk the costs of their capital investment they are exposed to opportunistic actions by other parties who may actually have an incentive to reduce the future revenue stream on which they depend.
That is why investors in fixed immobile assets typically require some form of long term contractual assurance. [Typical infrastructure investors like pension or sovereign wealth funds are most often seeking modest yield but very secure returns.] In other words reliance on a spot market dominated by short term factors, for so-called “merchant plant”, is a quite inadequate incentive for most investors in generation assets. Similar arguments apply to storage, and to transmission investment, although this may be in a slightly different regulatory framework, if that investment is made or underwritten by a regulated utility.
Potential remedies. There are two main options. One is inclusion of all major investment in a regulated utility framework (traditionally vertically integrated monopoly) in which reasonably incurred costs are passed to consumers. This is sometimes known as a regulated asset base (RAB) approach. The second is long term contracts with, or commitment from, a reliable counterparty. Typically the only plausible counterparty, apart from a RAB utility, is usually the government. In the UK network investments have in recent decades typically depended on the former, and generation on the latter (via CfDs, feed in tariffs etc[JR4] ).
Either remedy is feasible but both inevitably draw the monopoly utility or the government into strategic investment choices. This is a long way from the theoretical paradigm of the fully liberalised market, in which all decisions are taken in response only to price signals emanating from the operation of a competitive market. In addition we should note that successful resolution of the issue of long term investment and policy/contractual/regulatory commitment will be an essential pre-condition for financing infrastructure investments at the lowest possible cost of capital. This affects both investment choices and affordability.
- The missing money problem.
This is not market failure per se but just the simple observation that an “energy only” market built around a “bid at marginal fuel cost” merit order cannot be guaranteed to sufficiently reward capacity. This is demonstrated by the last peaking plant on the system which runs for a few hours a year in which it earns revenue exactly equal to its own expenditure on fuel, leaving nothing to pay for capital or other spending. The phenomenon is accentuated for systems dominated by renewables with zero marginal cost, or by nuclear plant which can have a negative SRMC, but the problem is intrinsic to an “energy only” market model.
In competitive “energy only” markets it is expected that spot prices will fall to the level of the short-run cost of the last generator needed to meet demand at any time. But when more than enough low marginal cost power is available to meet demand, which will be increasingly often as the roles of wind and solar increases, these prices will be very low (or even negative in situations with particular contractual terms or legacy subsidy arrangements). This will undermine generators’ confidence that they can recover their long-run costs, and thereby deter investment.
In essence an “energy only” market may be able to deliver spot prices that meet the necessary conditions to ensure efficient merit order operations, but will not normally provide prices that are sufficient to incentivise new investment, our second requirement of a market, particularly in the additional capacity necessary to ensure reliable supply. Sufficient capacity is critical to the maintenance of adequate reliability standards and security of supply.
Potential remedies. In principle this is remedied if prices in the simple energy market based on bid marginal costs are augmented in one of the following ways:
- An administered and precisely specified price supplement at times of capacity shortage. This was the route chosen in the UK 1990 privatisation, and was based on value of lost load (VOLL). This is potentially open to market abuse, if market participants withhold capacity in order to create price spikes.
- Allowing generators to exploit scarcity and bid scarcity prices. This tends to attract political criticism. It may also be seen as an abuse of market position, even if entirely legitimate and economically justified.
- Scarcity prices set by consumer choices (eg setting price limits at which their load is cut), ie bringing the demand side much more into the market. This is prima facie attractive. However, as indicated[JR5] earlier, we are a very long way from this solution both in terms of technology and consumer education and acceptance.
Importantly the missing money problem can also be resolved as capacity payments within the long term contracts discussed in 2 above. In other words if we resolve the general investment problem through that route, the missing money issue becomes less relevant.
- Inconsistency of spot market with efficient operations
This is simply a reflection of the fact that traditional spot markets have been designed “by fossil for fossil”, ie mainly by fossil generation economists, managers and engineers, to suit the operation of fossil technology in which most plants are relatively flexible. They are not automatically suitable for or adaptable to new technologies with much more complex operating and intermittency constraints. Nuclear and tidal power are possibly the low carbon examples with the most complex operating constraints and cost structures currently, but CCS is likely to have some similar features, while other renewables add a stochastic dimension.
A theoretical approach to this is to examine the question of what conditions are necessary for an “optimised” most efficient dispatch (by a perfect central planner) to be replicated by a price mechanism and decentralised decision taking at plant level in response to those prices. The conditions are broadly satisfied in traditional merit order systems as these are approximated as simple linear optimisations. But complex constraints and indivisibilities create what are known technically as non-convex solution sets, which mean there is no set of prices that produces the optimal outcome.
It is quite easy to construct numerical examples which demonstrate the point, for example with any park of generators that have to operate in either full-on or full-off mode, ie indivisibility.
Remedy. There is no obvious way round this, since it essentially just reflects a mathematical logic, but one remedy would be centrally optimised scheduling and dispatch. The problem is likely to become more apparent as the complexities of managing low carbon systems grow (in the manner described earlier). At present these complexities, and those already associated with some fossil plant, can be dealt with through more or less arbitrary fudges in any particular system. (Insertion of must run conditions would be an example of a non-market driven fudge). While not an immediate problem in the UK it is appropriate to recognise that this is likely to become a serious issue as fossil plant progressively ceases to be the plant at the margin, and scheduling and dispatch decisions increasingly relate to nuclear and other more complex operating regimes (including storage) rather than simple merit order ranking.
It is apparent that serious problems are already being recognised. Most recently this has surfaced over the clear need to coordinate offshore wind development with the transmission investment necessary to bring it ashore[JR6] . But there are likely to be plenty of other instances. One useful illustration arises from the benefits of diversity in siting of wind facilities. An optimised least investment cost solution would attach significant weight to the benefits of location choice that provide a collection of sites with uncorrelated weather histories, which offer a more secure protection against wind droughts, rather than just the locations with least cost per kWh output on a levelized cost basis.
It has been suggested that energy wholesale market prices could incentivise a coordinated solution in this case. This seems fanciful, but it would perhaps be an easy enough proposition to submit to a first simple test. We already have wholesale market prices over several years that reflect weather variation, with lack of wind just one of a number of factors leading to price spikes. Can we use these with any confidence to say that particular sites, eg north-east versus south-west, would deliver output profiles that were significantly less or more correlated with those price spikes? This seems improbable, given the relatively low incidence of large spikes, other than with many years of both weather and price data. This implies very long response times to market signals further reducing the credibility of reliance on a market response.
The onus here should be on the need to show that the energy-only market can or does deliver signals that are strong enough to produce the right mix of all types of plant. But coordination issues are much broader than this example, and extend into investment plans for heat and transport..
Remedies. Various forms of informal coordination within the sector, or a central direction of what types of generation are the clear alternatives. Coordination needs to extend beyond simple calls for capacity, probably implying some form of system planning in the form of least cost expansion plans and models. Informal coordination raises issues under competition law unless there is a derogation or a legal basis for it, for example through the licensing regime.
- An inadequate retail market, and other tariff issues
The UK retail market, in the decades after privatisation, never achieved the direct reflection of wholesale market price signals into retail price signals (especially for smaller consumers) that would be necessary to produce the efficient outcomes we are looking for. Most consumers are still charged on the basis of “load profiling” in which all domestic load, for example, may be assumed to have the same time of use profile. Although the sophistication of the retail market is now starting to increase, and there may be a significant impetus from smart metering, the reflection of system costs remains very limited. With an unbundled system such as that of the UK, the absence of formal system planning places even higher emphasis on cost reflective tariffs as a primary means of coordination through the sector. If this is defective, and there are major questions around network pricing as well as retail tariffs, then it cannot be assumed that sole reliance on markets will achieve efficient and effective inclusion of the consumer. This will matter more and more with future penetration into heat and transport.
Remedy. Analysis elsewhere suggests the need for more sophisticated retail pricing and tariffs, and redefinition of service requirements and the role of suppliers, perhaps involving aggregators or similar. It is clear that thinking is moving to recognise the importance of the consumer and the demand side in the future of the sector. But the importance of tariff issues, and the management of the demand side, deserves much more rigorous attention.
- Unfair practices
In most industries one of the commonest forms of market failure arises from inadequate degrees of competition, either through monopolies or abuse of market power. Electricity is not immune. Protection of consumers against unfair practices, e.g. by suppliers tempted to exploit temporary periods of shortage, in which they enjoy market power, or other means to raise prices and gain excess profits,  is likely to remain a source of potential concerns. Remedies through licence conditions, competition and consumer protection law will remain.
Any failure to meet acceptable standards of reliability will be regarded as a market failure. In principle there are two approaches to the management of this risk.
The first is a regulatory approach in which obligations are placed on suppliers to ensure that there is always sufficient capacity. This is difficult in a power system based on competing generators and suppliers, since it would be impossible to assign responsibility for an overall system wide lack of capacity. This responsibility can be placed on national or regional bodies charged[JR7] with commissioning capacity, which in turn must determine the right reserve margins, and balance security against cost. Historically this led to the development of the concept of the value of lost load (VOLL), or cost of supply failure, to value reliability. This approach, in effect, sets out a planning requirement to be placed on a central authority, or several more localised authorities in decentralised systems.
In the second approach, the value of lost load – the VOLL concept – is translated into a pricing or market-based approach. One option is a system of administered scarcity pricing, based on an estimate of VOLL, which the UK introduced in 1990. However this suggests in turn that the “scarcity price” could be determined in a market, in which consumers can effectively nominate their own “VOLL”. High scarcity prices could then limit demand to the available generation capacity available. It is not easy to put a value on the avoidance of very rare, high impact periods. In practice most consumers, especially smaller consumers, do not face real time pricing. Limitations of meters currently in use, and in technical means for consumers to respond, make this unrealistic in the immediate future. It is however likely that a low carbon future will require much more sophisticated tariffs[JR8] and will allow standards of reliability to be determined to a significant extent by consumer choices. Even so, conditions of severe shortage could result in price spikes at levels that consumers and governments find unacceptable, and provoke regulatory interventions. Reliability provision is one of the central, and difficult, issues in looking at market arrangements, and is discussed further below.
Regulation and Coordination
Regulation remains a basic requirement in terms of technical regulation and is still needed to cover the natural monopoly elements of the power sector, the wires businesses, and to include competition policy. There remain questions are as to how far formal regulation, or other policy interventions, need to address the issues of reliability and security of supply, or whether these can be met adequately through reliance on electricity markets. As argued earlier[JR9] the problem of ensuring security arises in conditions which are likely to become more common and more severe as the role of intermittent renewables grows.
International and UK experience indicates that “energy only” electricity markets, in which prices are driven by the variable short run marginal costs of generation, cannot generally be relied upon to deliver sufficient amounts of capacity, and to ensure that the system can always be operated in a stable manner and keep frequency, voltage, and power loads within acceptable limits[JR10] .
In Great Britain[JR11] and many other countries, a centralised ‘capacity market’ has been introduced which can be used to guarantee, within affordable limits, that there is always enough power available to meet demand. However this is a separate market in which key decisions are necessarily taken by a central body that implicitly or explicitly lays down required standards of capacity adequacy, and may then decide how much and what types of capacity are required. Depending on the rules it sets (or fails to set) for capacity auctions, it will also have a major impact on technical characteristics as well as the quantity of generating capacity.
The advent of high levels of renewables, and the increasing importance of storage, will also add substantially to the policy and coordination challenges that capacity markets will need to handle. New challenges include creation of an efficient and well-functioning system of generation, transmission and storage assets which complement rather than conflict with each other.
Inter alia this means ensuring a mix of renewable resources that is optimal in terms of diversity, system compatibility and location. From the perspective of the whole system, for example, the sites of offshore wind sites should ideally be chosen to minimise the adverse effect of correlations in the time profiles of their power output, rather than just its anticipated cost. Theoretically the “energy only” part of the market would, if weather patterns were clearly reflected in spot prices, reward new supplies anticorrelated with existing resources. However[JR12] given the relative infrequency of extreme weather conditions and the multiple additional factors involved in price spikes, it seems unlikely that this would become apparent from prices sufficiently quickly to have a significant effect on investment choices.
investment decisions on the demand side (e.g. on how heat will be provided) are phased to allow timely decisions on the supply side investments needed to meet new demands.
Looking ahead, the design of power markets is becoming increasingly complex due to the challenges posed by disruptive technologies such as variable renewable energy, large-scale storage, and increasingly sophisticated demand side participation.
Delivering enough low carbon generation and storage capacity, at least cost, with the right mix of characteristics to meet a growing demand for electricity, and guiding its operation, are all huge challenges, and will require very large investments as well as the surmounting of increasingly complex operational challenges. The high-level framework for both investment and operational decisions can only be set by the Government, in the light of advice from parties such as Ofgem, the Committee on Climate Change and the National Infrastructure Commission. It is clear from our analysis that future arrangements must be i) capable of underpinning the necessary levels of investment with regulatory or contractual commitments, and ii) able to ensure greater coordination than can be provided solely by wholesale and retail markets on their own. This implies that, in the context of a firm high-level framework, existing institutions and markets should be strengthened or modified to deliver the coordinated investment and operational decisions that will be needed, and that some innovative approaches may be required. Some of these possibilities, and major issues requiring attention in future, are discussed below.
One proposed approach to the reliability issues raised by intermittency, in the context of the existing capacity market, would be to conduct reverse auctions of the obligation to provide dispatchable (‘firm’) power and/or peak power. In effect the central body assuming responsibility for reliability – in this case government – delegates its responsibility through a contractual obligation placed on the parties successful in the auction. In order to meet this obligation, owners of intermittent generation, who generally do not own (or have the expertise needed to provide) storage, would then have to form consortia with those who do, and/or form consortia with other suppliers. (Such consortia already exist: they provide the means to buy shortfalls or sell surpluses in day-ahead and intraday markets and help to hedge risks). The formation of large consortia would be a necessity for bidders to provide firm power, but would inevitably reduce competition, increase the potential for market abuse, and could raise a barrier to entry for smaller innovative firms. It would also fly in the face of many people’s belief that the system will or should become less centralised. Moreover it would lose some of the economy of scale that would result from the ability of the central body to exploit the diversity in a national system.
Future arrangements should allow investments in generation, transmission (including interconnectors) and storage to compete on a level playing field, and hence to be evaluated according to the same criteria. Currently, however, regulation prohibits the owners of transmission and distribution networks from owning storage, since this is treated as generation. As an illustration of this issue and the inconsistencies it raises, some DNOs have begun to consider contracts with owners of energy storage as an alternative to investing in new network assets. However, storage owners will not make large investments dependent on long term revenue streams without ultra-secure long-term guarantees provided by the regulatory framework or a long-term contract or both. Network owners have hitherto appeared reluctant to enter into such long-term contracts. In contrast, the network owners can recover the cost of network capacity over 40-60 years.
In April 2019, the Electricity System Operator (ESO) function of National Grid was split away from its network owner function and given not just responsibility for balancing the system in real time but also for coordination of investments to enhance the capacity of the main interconnected transmission network. However, the coordinating role of the ESO has been controversial. While National Grid’s CEO has been quoted as saying that the ESO is the ‘obvious’ body to carry out a network planning and coordinating role, Dermot Nolan (the former CEO of Ofgem) has been reported as saying that planning and management of the grid[JR13] , on- and offshore, should be taken away from the National Grid and handed to an independent body with new powers.
It is in our view clear, for the reasons set out earlier, that new arrangements, or expansion of existing arrangements, will be needed both to ensure sufficient investment in low carbon generation and to ensure that adequate security of supply will be achieved. Measures might include development of the existing capacity market, the continued use of contracts for difference in long term contracts, and more aggressive use on carbon pricing. There is also huge scope for the better reflection of costs related to time of use or reliability standards. Suppliers should have much more incentives to innovate in respect of contractual agreements with their customers for a choice of levels of reliability of supply or type of service delivery. This would enable much more effective exploitation of the potential for demand side measures and its coordination with decisions in respect of generation and storage.
It may however be necessary to move beyond this, to more formal recognition of the growing need for some degree of centralised and coordinated procurement of generating and storage capacity with different capabilities, along with operational coordination between the players. This could have features similar to the existing capacity market or an extension of it, and to the institution of a central buyer and seller of power at the centre of the system. This, and closely similar concepts which rely on informal[JR14] coordination within the sector, are not uncommon internationally, but are a very substantial move from the original conception of the fully unbundled and liberalised UK market. However that move has already occurred with the increasing dependence on central government to formulate sector policy and underwrite new investment, for example through long term contracts.
We note that many of these issues, and alternatives, were explored extensively in a set of four perspectives commissioned by the Energy Technologies[JR15] Institute (forerunner of Catapult) in 2016.
It is clear from our analysis that progress to a low carbon economy poses multiple new challenges for the market, regulatory and governance structures on which we have relied for the last three decades. To some extent the new questions posed by low carbon technologies have merely amplified flaws and weaknesses in existing structures, but our analysis of the potential sources of market failure indicates a systemic risk to the objectives of low or zero carbon, and to the future efficient and reliable operation of the power sector, which it is impossible to ignore. The most important systemic risks relate to securing investment of the nature and scale required, and to very broad issues of coordination both within the power sector and across the larger decarbonisation agenda of heat and transport.
Private investment in transmission, generation and storage is already recognised to be largely dependent on forms of long term contractual and regulatory commitment, which can ultimately only be provided through government, sometimes directly, as with nuclear, or through obligations placed on bodies which are themselves regulated monopolies (such as the ESO or network owners). Given the high capital cost of the technologies needed to move to net-zero, uncertainty in future revenue, and the need to move quickly to reduce emissions while ensuring security of supply, it will be necessary to strengthen such commitments in order to ensure a relatively low cost of capital. This can happen through regulated asset base (RAB) models in which, in effect, risk is shared with consumers; CfD-like instruments; or through part, or even full, public ownership (which would be one way to allow whole system benefits to be properly taken into account in investment decisions) in which case a part of the risk is borne by taxpayers[JR16] .
It is also abundantly clear that progression to a low carbon power sector is intimately linked in terms of policy, investment requirement to decisions on how the transport and heat sectors are decarbonised. The approaches taken to these sectors will have a profound effect on both the scale and shape of the power sector. This can only be done at government level, whether central or local/regional or both. Within the power sector itself, similar considerations suggest the need for increased reliance on a degree of coordination which is unlikely to be delivered solely by reliance on current market and regulatory structures.
The transition to a net-zero power sector will require increased central coordination of planning (extending into closely related sectors such as heat and transport), investment and operational decisions. How much this can be delivered by strengthening or modifying existing bodies and market structures, and how much requires more radical change is a more open question. A starting point for developing future commercial and regulatory arrangements, however, must be a clear recognition of the challenges; and then how, and by whom, investments in generation, storage and networks are compared and evaluated.
 Failure in the financial and banking system is perhaps the most familiar example but Mark Carney, in his recent Reith lecture, drew attention to finance, health and climate as the three most egregious examples of market failure leading to systemic failure with massive social and economic consequences.
 Domestic gas use, for example, does not form part of the scheme.
 This is an issue for peaking plants (such as OCGTs) which only operate for a few hours a year, during which the price is set by their own managed costs.
 Enron in California provided merely one of the most egregious examples. See e.g. Weare, Christopher (2003) The California Electricity Crisis: Causes and Policy Options ISBN 1-58213-064-7;
 See the Appendix for a fuller description of the present uses of, and revenue streams that support, storage.
 The spot-market was designed (in the era when fossil-fuels dominated) on the implicit assumption that plant is flexible and electricity dispatch could be optimised day by day, independently of both past and future. In an era dominated by variable renewables and (perhaps) inflexible nuclear, with an increased emphasis on storage and time management, it would seem unlikely that an energy-only spot market can deliver efficient choices on scheduling and dispatch of generation, flexible demand and storage over sufficiently long periods.
 See report on phase 1 of the National Grid ESO led ‘Offshore Coordination Project”
 World Bank Policy Research Working Paper 8519, 2018
 The Times, November 8th, 2020
 At the time of legal separation of the Electricity System Operator function of National Grid from the rest, Ofgem committed to a review during the course of 2020/21 of the effectiveness of legal separation and “a full assessment of both gas and electricity System Operation”. At the time of writing (November 2020), the report had not yet been published. https://www.ofgem.gov.uk/publications-and-updates/ofgem-review-gb-system-operation-terms-reference
 In the UK the National Grid as Electricity System Operator (ESO) would be one of the candidates for that role.
[JR1]There are several possible approaches in principle to putting a value on emissions: estimating cost of climate change, estimating implied cost of an emissions target, and estimating the future cost of extraction from the atmosphere. While there may be no definitive estimate, it is generally supposed that the value should be at least $ 75 per tonne of CO2 and possibly much higher. This compares with typical prices of around $30 (December 2020) and a low of around $ 4 in 2017. Informal estimates of the future cost of extraction from the atmosphere have been set as low as $100 compared to a current “best available technology” of about $600.
[JR3]Another policy related example was the prohibition on anti-cartel grounds, of Netherlands generators from a mutual agreement to substitute gas for coal.
[JR4]For completeness we should perhaps add state ownership to the list of remedies, but for formal analytical purposes this equates to vertically integrated monopoly in this context.
[JR5]Refer back to page 2
[JR6]Refer recent Times article Nolan et al
[JR7]This can in principle then be delegated by contracting for firm capacity from several sources, an option which is considered in more depth later.
[JR10]Occasional counterexamples are sometimes offered such as the ERCOT approach in Texas. However ERCOT's members include consumers, electric cooperatives, generators, power marketers, retail electric providers, investor-owned electric utilities (transmission and distribution providers), and municipally owned electric utilities, prima facie providing a collaborative vehicle for informal coordination and the implicit underwriting of long term investments akin to a vertically integrated utility.
[JR11]Do we mean GB or UK?
[JR12]Refer back to p.8.
[JR13]“Back in the day”in 1990 when we were trying to define structures that would actually work in a competitive market, separating operations and investment would have been regarded as almost insane Imagine this dictum being applied in almost any other business. The offshore issue is about or ought to be about coordination of generation and transmission investment, for very obvious reasons.
[JR14]ERCOT the regulatory body for Texas has as its membership the main utilities, while Ontario Hydro operates the single buyer model.
[JR15]The additional full reports from each author can be viewed via the links below:
[JR16]It might be worth referring to the series of papers produced for ETI in 2016, as a reference for both this and the next para