Wednesday, May 13, 2009


(Exploring the option of setting up a central purchasing agency.)

Mike Parker, John Rhys, Tony White

July 2009

This note is intended to explore further some of the issues associated with our earlier May 2009 proposal, set out below, for a new “agency” of government to act as a central purchasing agency and facilitate investment by:

inviting competitive tenders to build low carbon generating plant with quantum and timing consistent with carbon budgets and the advice of the CCC on time critical pathways or timelines

(ii) offering successful bidders long term contracts free of energy commodity and carbon price risks in the form of power purchase agreements (PPAs).

This note tries to put the proposal in the context of an incremental approach to changing market structure, starting from the need to achieve early implementation of investment in low carbon generation. It also seeks to retain the maximum of market and competitive features consistent with the need for a policy instrument that “drives” investment in low carbon. Our thinking the proposal for a purchasing agency continues to evolve, along with consideration of appropriate statutory and regulatory features for such an agency.

How contracts and competitive bidding would determine investor revenues and wholesale prices ?

The proposed agency would issue requests for X GW of low carbon generation for XX years for each of a range of technologies.

It is also possible to envisage circumstances where some existing owners of fossil generation assets, or investors meeting very short term needs for additional fossil capacity, would also wish to secure contracts with the new agency, particularly if it was perceived as creating market uncertainties under current market structures. It is possible that this would result in a more rapid expansion of the agency’s role.

Agency would pay generators according to the terms of the contract. We would expect these to include:

(i) a regular capacity payment, fixed or indexed, over a contract life sufficiently long to remunerate the capital investment for capital intensive projects with low marginal cost (wind, marine, nuclear); this payment would form the major part of revenues for many types of generation

(ii) payments per kWh of output for marginal fuel or other variable costs (CCS, biomass)

(iii) incentive payments to reward availability, structured to reflect the need for, or the market value of, output; these payments would reward operational performance and penalise failure, and be linked directly to availability, or to output, allowing a market element linked to an SRMC-based wholesale market price

(iv) other detailed and technology specific rules governing scheduling and dispatch arrangements, which would be specific to the type of plant or even to the individual plant

Special arrangements might be needed to avoid discrimination against small scale decentralised low carbon generation. For example small scale generation might form one of the tender categories, with its own procedures, or might simply be treated in the planning process as a negative demand.

The agency would sell its contracted power on a regular basis into wholesale markets with any imbalance between costs incurred and revenues received being cleared annually through network charges or a levy on all consumers. Such a levy may only be necessary if “market” prices are allowed to persist at levels below the “social cost” level that justifies agency intervention. Arguably, with fully priced emissions, the agency would generate a profit.

At some point the quantity of agency contracted wholesale generation would approach or exceed that of remaining non-agency existing plant so that it might be necessary or preferable to establish a bulk supply tariff.

What would be the interface with existing arrangements and CCS?

BETTA and wholesale market. This would continue to operate while the quantity of existing fossil fuel plant (without agency contracts) remained significant. The interaction between current arrangements for the scheduling and dispatch of plant and the operation of plant under agency contracts, would need to be considered carefully.

The wholesale market, whether in the form of a pool or the BETTA arrangements, has as a prime function the organisation of adjustments of output (and demand), and the scheduling and dispatch of plant, to accommodate variations in demand and the availability/ performance of different generating plant.

This feature would continue, certainly while there remained significant volumes of fossil plant, with the main fossil generators continuing to, in effect, bid into the market on the basis of their fuel costs.

One possible scenario would have the generators under contractual supply obligations to supply, but trading with each other in a “generators’ pool” in order to avoid penalties under the terms of their contracts with the agency, or to reduce costs by “buying in” from a cheaper source of supply. This retains the important feature of a competitive market in maintaining continuing pressures for efficient operation.

EU ETS. Existing generators, and any generators with CO2 emissions, would continue to include CO2 costs under ETS arrangements when bidding into wholesale markets.
If they entered into contracts with the agency they would need to take these costs, and their uncertainties, into account. Their contracts would probably specify prices for kWh output with a CO2 cost pass through, passing the market price risk to the agency.

Renewables obligation. Existing contracts under RO rules would continue to apply but new renewable generation would not receive ROCs and would not be included in the RO target for each year or the accredited generation.

Note. These observations reflect the inherently incremental nature of our agency proposal. While we believe that, in the interests of urgency, there is a strong case for its introduction as soon as possible for all new projects qualifying as low-carbon generation. But as the rate of implementation would reflect the number of projects coming forward there can be an orderly transition, with existing arrangements continuing to apply to declining existing generation assets.

How would intermittent and CCS plant be handled. All plant would be subject to scheduling and dispatch arrangements determined under the terms of the contract with the agency, which may allow for bidding into a generators’ pool.

Intermittent plant might normally be scheduled and dispatched by the agency/ system operator in such a way as to optimise its deployment taking into account its technical characteristics for intermittency and uncertain output parameters.

CCS retrofits would be an outcome of competitive tender, in one of the main categories to provide low carbon capacity, and would be competing in this category with new-build CCS. Subject to its technical characteristics of operation being a reasonable approximation to conventional fossil plant, CCS plant would operate in any wholesale or pooling arrangements in the same way as ordinary fossil plant.

Other alternatives

We believe our alternatives are better than:

(i) large increases in the value of ROCs since

  • whereas with enhanced ROCs customers would immediately pay on the assumption that low carbon capacity would be provided, with our proposal customers pay only after the capacity is built
  • current arrangements expose investors to price risk for fossil fuels and carbon price, as well as in the supply/demand balance in wholesale power and renewables markets. Agency contracts offer far lower revenue volatility and hence potentially lower costs of capital.

(ii) A “floor price” for EU ETS carbon price – a price level sufficiently high and certain to support early investment in large scale low carbon generation would be very difficult to negotiate for the foreseeable future. It could also generate excessive windfall profits.

The wider context

We would wish to emphasise that we regard our proposal as progressive, not retrograde. We have advocated open contestable competition in the bidding for contracts and would propose to maintain competition in supply, albeit this might de facto be confined to the supply functions such as metering and billing activities. However we would envisage that at least for some years the agency would seek bids based on a technology choice which is not based on market preference. In practice this is inevitable to make progress, in the light of existing policies on renewables, CCS and nuclear. The agency proposal is designed to make these policies effective.

More fundamentally our thinking is designed to be compatible with the most feasible rapid evolution of the electricity industry to full decarbonisation. While, as we have indicated above, the agency could continue to co-exist within the present market framework for some time, nevertheless the increasing importance of coordination issues arising from the cost and output profiles of low carbon technologies, the management of intermittency and storage, and changes in associated infrastructure, will raise, with increasing force, the question of the relationship between the agency and the system operator, and of both with the government and the CCC/ OFGEM.


Mike Parker, John Rhys and Tony White

on behalf of the BIEE Climate Change Policy Group

10 May2009


This paper arises from the concerns of the Group with the ability of markets to deliver a low carbon future, concentrating on the crucial electricity generation sector. We have drawn attention to many of these concerns before, in several of our earlier papers, and this paper is intended to bring together these earlier arguments with some ideas for a way forward. The importance of the issue has in our view been increased by the need to facilitate investment in a much more constrained and difficult financial environment.

The logic of our position is as follows:

· Meeting the Government’s 2050 target, and in particular the CCC’s requirement for substantial completion by 2030 of the decarbonisation of power sector, requires the earliest possible progress. The urgency would be even stronger if we were to adopt an equivalent cumulative emissions target rather than an end year focus, since it would recognise the higher value attaching to savings in the early years, more consistent both with the science and with the Stern and the Government’s own modelling results.

· Long lead times imply that there should be visible early signs of action on investment in the established front runners of nuclear, renewables and CCS; however many if not all of these are currently seen as marginal or barely viable in investment terms without major policy or financial interventions.

· This raises the issue of whether markets, in their current manifestation, can deliver a low carbon future. The additional factor of global financial turmoil, itself provoked by financial sector market failures, exacerbates the concerns.

This paper sets out the considered views of three members of the group on the question of what, if the current market arrangements can not deliver, should be done. We propose an approach, which we believe retains the most important benefits of competitive markets but provides a better assurance that the targets can be achieved.

Comparison with the UKERC report
[1]. We find ourselves very much in sympathy with the fundamentals of the 2007 UKERC report. In particular, if policy goals depend on investment in particular technologies then policy must be designed to deal with investment risk, not just with technology costs.[2] Policy makers cannot necessarily determine which technologies get built, but they can provide incentives in the light of their understanding of the investment process.

UKERC place considerable emphasis on revenue risks which are not captured in assessments of costs (levelised or otherwise), and their analysis is very close to ours on the particular issues of capital intensity and the consequential bias towards existing fossil technologies

We also agree that a policy created market itself poses risks
[3], but the problem of investment is now so difficult and so urgent that the creation of a market environment geared to the CCC’s decarbonisation objective is an imperative, and needs to be realised as soon as possible.

However since the UKERC report was prepared two years ago:

  • Climate science has reinforced the warnings of urgency. xxxxxxxxxxxxxxxxxxxx xxxxxxxxxxxxxxxxxxxxx
  • Global financial turmoil has increased the financial “option value” to investors of delaying major spend, contrary to the true option value from a social or human perspective, and reinforced risk aversion in financing major long term projects. xxxxxxxxxxxxxx xxxxxxxx xxxxxxxxxxxx xxxxxxxxxxxx
  • The scale and severity of price variability (notably in fossil and carbon market prices) has greatly increased the price risk to major projects.

All this points to the need for strong incentive structures, and a high degree of assurance on regulatory and other risks, to support low carbon investment.


There are a number of serious prima facie concerns with electricity markets. These have been set out in some detail by one of our number in a recent Sussex Energy Electronic Working Paper
[4], but a few of the key factors are the following:

  • The rules and procedures associated with current UK wholesale markets were designed by and for fossil generators. They were intended to cope with the technical, operational and economic characteristics of fossil-fired plant. There is no a priori reason to suppose that they can cope with a future that must be based very largely on low or zero carbon plant, including nuclear and renewables, with completely different operational and economic characteristics. This applies both to the role of the market in organising the economic dispatch of generating plant, and to its role in setting prices as a signal for investment. xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
  • The absence of long term capacity payments, which potentially are an essential source of price signals for investment in new capacity, makes for a highly unpredictable and unreliable mechanism for safeguarding system security and for reducing carbon emissions. xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
  • The profitability of generation investment, and in particular, the relative economics of fossil fuels and “low carbon” is greatly influenced by the huge uncertainty/variability of future gas and coal prices, and of any EU ETS allowance prices. These outcomes are determined almost entirely by the interplay of different fossil fuel prices and generators, so that fossil fuel generation is comparatively less sensitive to these price volatilities, which bear much more heavily on the net present value of low carbon, but capital intensive, investment. In this context the short and medium term dominance of incumbent fossil fuel acts as a barrier to entry of the essential low carbon generation of the future. xxxxxxxxxxxxxx xxxxxxxxxxxxxx
  • Concerns that the centrepiece of current market arrangements in relation to low carbon, the EU ETS, is not currently, for whatever reasons, delivering prices that are compatible with the investments needed to achieve CO2 targets, and, by a wide margin, appears unlikely to deliver such prices in the foreseeable future. xxxxxxxxxxxxxx xxxxxxxxxxxxxxxxxxxxx
  • The absence of any obligation on individual firms to make low carbon investment, combined with more recent concerns over credit and financing issues, means that private firms would in the absence of intervention tend to choose new plant with low capital cost and short lead-times, typically CCGTs. xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
  • The general absence of long term contracts in the current market environment, the result of structural and regulatory factors, militates against long term capital intensive projects, such as large scale renewables, nuclear and carbon capture and storage (CCS), which must necessarily make up the greater part of the decarbonisation process. In the absence of effective long-term contracts these are exposed to huge risks within the present institutional structure.

The present policy framework is not capable of delivering effective price signals that would support, with assurance, long term capital investment in low carbon generation by risk averse private firms with no obligation to supply. The scale of the problem is demonstrated by the CCC’s own numbers in their December report; for example in extreme fossil fuel price uncertainty [5](p99) in 2015, with ranges of oil prices of $ 45-150 per barrel, UK wholesale gas at 30-92 pence per therm, and UK delivered coal at $ 45-130 per tonne; and carbon price forecasts that are “inherently uncertain” [6], with figures for 2020 ranging from € 39-105 per tonne[7] of CO2 – all largely determined by the relativity of coal and gas prices.

There is a further and related concern, that the market is ill-suited to the coordination role required in a low carbon future to deal with the intermittency, plant inflexibilities and demand/ storage issues that will operate. The problem arises from the issues of intermittency associated with renewable energy sources, and the parallel problems of scheduling nuclear or other outputs which do not follow load in a flexible way. In operational terms this implies system optimisation and control decisions that cannot be taken on a one day or less ahead basis, so that the maintenance of a secure and efficient system is not consistent with the current market and bidding framework. Similarly, at the investment and planning stage, it will imply the imposition of system parameters that determine the proportions of plant with different types of inflexibility or non-firm capacity that can be allowed to form part of the overall system. These factors (technically described as various forms of non-linearity) imply the need for some central intervention to secure a compatible overall balance of plant types.

This concern leads in to associated issues of infrastructure, where there is an increasingly fine dividing line with choice of generation technology. The integration of infrastructure and capacity planning is essential and the issue of coordination is becoming increasingly apparent. However this cannot be done without some view of the most appropriate time critical pathways, and of the means to deal with intermittency effects, standby plant investment, storage and demand management. These issues were recognised at several points in the CCC’s December report.


In the light of the above critique of the existing policy framework we conclude that there is an urgent need for a new approach based upon two main propositions, namely:-

Energy commodity and carbon price risks should be removed from the investment appraisal process of capital intensive, low-carbon projects, but with lowest cost bidding prior to construction, with risks arising from capital cost delays/over-runs, or “performance-related” loss of availability, falling to the investors; and with selected bidders being granted long term contracts.

As investors have no obligation to deliver capacity, let alone particular types of capacity, uncertainty on the quantum and timing of new capacity should be resolved centrally by means of indicative “time-critical pathways”, endorsed by Government, that take account of lead-times and interactions within the electricity system.

In addition explicit coordination is required with infrastructure issues: transmission and distribution investments, CO2 gathering pipelines, and demand infrastructure (notably in relation to use of electricity in the transport sector). Implementation also needs to take account of the range of technologies and their maturity, and of the question of who has to be incentivised, for what purpose, and how this is best achieved.

Our approach is predicated on the view that a greater burden of risk should be borne by consumers, directly or via government, since otherwise adequate investment will not be achieved and everyone loses

Finally we believe that such a new approach should result in a relatively permanent and stable structure, which will not rely on a series of ad hoc solutions to accommodate particular investment options or particular problems.

We recognise that there is room for further discussion on the institutional implications of following this new approach set out above. Accordingly we set out separately in the attached annex a proposal which could well be the most effective way to implement the principles of the new approach for capital intensive, low carbon projects.


The perceived urgency of meeting CCC objectives in the power sector has driven us to examine critically the assumptions, implicit in much of the thinking of the last few years, that unconstrained energy markets can and will deliver the low carbon future we require. We believe that any rigorous analysis of current energy market structures and mechanisms shows that we cannot rely with any confidence on markets, operating within current policy frameworks, to deliver, in particular due to an inherent failure to provide effective price signals for capital intensive investment. This analysis is merely reinforced by the turmoil in energy commodity and in financial markets, where it is clear that essential low carbon investments will not be made without additional support.

We therefore advocate new approaches which will require some significant central intervention, perhaps via a new agency, structures that use competitive tendering to derive long term contracts free of energy commodity and carbon price risks, significant coordination with infrastructure investment, and an indicative approach that we have previously characterised as “time-critical pathways”, to ensure compatibility with carbon budgets and government targets. We believe that this can be achieved while still retaining the essential efficiency gains that have resulted from a more competitive electricity generation sector.


We conclude that one effective way, and probably the most certain, to give effect to the principles in the paper would be the introduction of an agency of Government, established to:-

a) seek competitive tenders to build low carbon generation plant, with quantum and timing consistent with carbon budgets and the advice of the C.C.C., incorporating their time-critical pathways analysis.

b) offer successful bidders long term contracts in the form of Power Purchase Agreements-PPAs

c) sell the contracted power on a regular basis into the wholesale market; any difference between the costs incurred in (b) and the revenues received would be cleared via a consumer levy/reimbursement or an adjustment to network charges

Such a measure would give the following benefits not available from the present policy framework:

  • The introduction of new low carbon capacity would be explicitly linked to time critical pathways consistent with carbon budgets and government objectives. xxxxxxxxxxxxxxxxx
  • Long term contracts with PPAs without exposure to external price risk would encourage competitive bidding for low carbon generation; the revenue for investors however would necessarily be underpinned by long term contractual arrangements. xxxxxxxxxxxxxxxxxx
  • The Agency’s ability to secure remuneration for the generators over a long period, and to recover any losses arising from the wholesale market, would greatly ease the financing of low-carbon generating capacity on the back of the PPAs, providing lower risk and lower financing costs. xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
  • The Agency would, in principle, be able to offer long term contracts to other important categories, including:-
    xxxxFlexible stand-by plant/storage needed to offset intermittency and xxxx xxx xxx xxx safeguard system security of supply.
    xxxxFossil fuel plant retrofitted with CCS.
    xxxxPilot plants for emerging technologies.

The new system could also be used to encourage new entrants to bid for contracts for “decentralised”/smaller scale renewables. Integrated planning/co-ordination of new generating capacity, system management and infrastructure would be greatly facilitated.

Form of long term contract. Contracts would reward initial investment in new low carbon capacity through a fixed payment, as an outcome of the tendering process and contract negotiation, together with payments and incentive structures for availability and actual output linked to a measure of the market value of that electricity output. This is a familiar approach which has been discussed by the World Bank and other experts in the context of single buyer and other variants on the fully competitive models of an electricity market. The advantage of this contractual specification, compared to increasing ROC payments or a guaranteed floor price for carbon, is that it reduces the risk of windfall profits associated with setting such payments at an unnecessarily high level. At the same time it is possible to use this approach in a way that ensures that market based incentive structures continue to operate in relation to merit order related decisions and the operation of plant that has already been built.

CCS for retrofits. Under a competitive tendering approach, owners of existing coal-fired plant would be able to submit bids to run their stations with CCS retro-fitted on the same or a comparable basis as other sources of low carbon capacity. Whether this would be on a basis of direct competition between CCS retro-fitting and all other sources, or only within retro-fitted CCS, would be a significant policy issue for the agency to resolve, drawing on the analysis of the CCC.

Subsidy, public expenditure and competition considerations. This approach is free of formal subsidy arrangements, and avoids recourse to the taxpayer, since contracting costs can be passed on down the chain to the electricity supplier and final consumer. It may therefore represent a less subsidised structure than some of the proposed alternative interventions such as feed-in tariffs, or the subsidy implicit in continuing to allow fossil generation to be sold at prices that do not reflect in full its externalities and social costs. If our proposals represent the most effective means, then it is likely that the ultimate public expenditure burden will be less under our proposals than under alternatives.

It is open to the objection that the purchasing agency would de facto enjoy a monopoly position in selling to the wholesale market. This however would be subject to regulatory oversight in the way that the monopoly elements of the power sector are today. The crucial point however is that these departures from theoretically unconstrained competitive market structures appear almost inevitable, given that interventions are required because the existing pure market structure is not able to deliver.


The introduction of this new system would be incremental (as new investment came forward). As a result it would allow an orderly transition, with the existing regime continuing to apply to existing/committed generation assets.

Nevertheless, implementation would require prior resolution of some issues: notably how would the process of deciding the quantum, timing and technology choice be conducted;

  • Degree of disaggregation (how many auctions)
  • Linkage with time critical pathways compatible with carbon budgets
  • What consequential changes in the roles of DECC, CCC, OFGEM, National Grid ?


[1] Investment in electricity generation; the role of costs, incentives and risks. UKERC. May 2007
[2] UKERC Report, p. 67
[3] UKERC Report, p. 55
[4] SEWP 175. John Rhys. Will Markets Deliver Low Carbon Power Generation?. [ ]

[5] P. 99 of the CCC December report
[6] P. 158 of the CCC December report
[7] P. 165 of the CCC December report

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