Energy and Climate Change Committee - Draft Energy Bill: Pre-legislitive ScrutinyWritten evidence submitted by Combined Heat & Power (CHPA)

1. Introduction

1.1 The Combined Heat and Power Association (CHPA) is the leading advocate of an integrated approach to delivering energy services using combined heat and power and district heating.

1.2 This memorandum sets out concerns that the Electricity Market Reform process has almost exclusively focused upon a narrow suite of low-carbon power generation technologies, which taken together have limited prospects for deployment at scale within the next ten years. This situation risks compromising prospects for development of a suite of technologies and approaches that are deliverable today and which offer the greatest prospects for maintaining the security and affordability of energy supplies without compromising climate change objectives. The memorandum addresses those “deliverable” approaches on the supply side of the market, identifies the current and emerging constraints on their development, and sets out simple recommendations for a remedy that could be pursued within the scope of the Energy Bill.

2. Limitations of Electricity Market Reform in Securing Policy Goals

The scope of EMR is wider than three low-carbon generation technologies

2.1 The scope of the UK’s Electricity Market Reform (EMR) is wider than consideration of what appears to be the three “key” technologies that Government wishes to encourage: Nuclear, Offshore Wind and Carbon Capture and Storage. The EMR process is going to have major impacts across all areas of the electricity market. Despite this, discussion of EMR focuses primarily around DECC’s three key generation technologies. The profound nature of the impacts of EMR presents both risks and opportunities.

2.2 Some of the potential risks of EMR include:

2.2.1Fundamental changes to the traded electricity market with new trading behaviours around the references prices possibly creating artificially low wholesale electricity prices and a fundamental reduction in market liquidity.

2.2.2Increased costs and risks for small scale generators due to greater market price volatility and the costs applied for offsetting that risk to a third party (through a Power Purchase Agreement).

2.2.3Security of supply risks as development of a capacity market causes new investors to delay investment until those rules have been established.

2.2.4Increased cost to consumers by creating “obligated sellers” in the market. Generators will need to generate electricity to receive FiT payments which could create a very powerful incentive to sell electricity at a low price to ensure payment under the CfD. The resulting increased payments under the CfD would fall on consumers.

The Electricity Market Reform process is increasingly unlikely to deliver on all key objectives

2.3 The stated aim of the EMR process is to achieve three key objectives: decarbonisation of electricity generation, maintaining security of electricity supply and ensuring affordable electricity prices for all consumers. A combination of evolving circumstances now suggest that the EMR process, as set out in the draft Energy Bill, is unlikely to address these objectives within the approximate timescale of the next ten years.

2.4 Carbon emissions reductions—the fundamentals of deliverability: A number of factors suggest that the original timescale for the commissioning of new nuclear power generation must be in doubt. These include the sale of the “Horizon” consortium, delays in the site preparation works for Hinkley Point B as well as a shift in the public statements made by EdF Energy, the principal investor in Hinkley Point.1 Secondly, delays over the carbon capture and storage (CCS) demonstration project means than CCS plant capturing emissions from all fuel inputs are unlikely to be delivered in the near term. Finally, the uncertainty over the EMR means that large scale renewables investments such as Round Three offshore wind projects are now on hold as they cannot be sure of commissioning before the 2017 date when the current support regime (the Renewables Obligation) will close to new entrants. For these projects the lack of certainty surrounding the CfD FiT combined with uncertainty over the timing of offshore transmission infrastructure development means that large developers and banks will not risk funding the development of a project, which, if not commissioned by 2017, has no certainty over its CfD revenue stream and its value. This combination of technical, commercial and regulatory factors that is resulting in major delays to the deployment of these three technologies means that their capability to deliver emissions reductions in the immediate decade will be severely impaired. Whilst this suite of technologies, as a whole, may be deployed in the following decade, an approach that maintains momentum in investment in technologies that are deliverable today and in the immediate decade appears to have been largely eclipsed in current energy policy.

2.5 Security of supply—the problem of the Capacity Mechanism and the Carbon Price Support: The maintenance of secure electricity supplies is vital for the economy. The build time constraints for new low carbon plant highlighted above will exacerbate a recognised medium term risk to secure supplies. The Carbon Price Support policy in 2013, coupled with a low European carbon price, has incentivised coal plant to run as baseload rather than mid-merit plant. The result is that they are using up limited run hours (under the Industrial Emissions Directive) and, therefore, are likely to be legally obligated to close during 2013, rather than being able to run until 2016. In addition, the proposed capacity mechanism has created a hiatus on all new build of gas plant. The uncertainty as to how gas plant will be rewarded under the mechanism and how new and existing plant will be treated, effectively creates a high risk for new investment. Finally, the removal of Levy Exemption Certificates (LECs) from Combined Heat and Power (CHP) plants from 2013 discourages power export from CHP. As CHP accounts for 7% of UK power generation (and 13 million tonnes of CO₂ abatement per annum), the decision by Government to discourage operation of existing CHP plant at a time of concern over generation capacity is a surprising one.

2.6 Affordability for Consumers—the problem of the CfD FiT: The CHPA has fundamental concerns over the underlying analysis of the CfD FiT and the resultant belief that it reduces investor risk and reduces the cost to consumers. The fundamental concerns are:

2.6.1The Government’s assumptions for future energy market prices2 appear strongly at odds with commercial offerings3 for those same futures. Government energy modelling indicates persistent high electricity wholesale prices and relatively low wholesale gas prices. This model would lead to two assumptions:

That gas power plants would be attractive to build and operate now and in the future.

That the cost to consumers of the CfD FiT, which is based on the difference between the market electricity price and the agreed “strike-price”, will be relatively low.

2.6.2In reality, however, such wide differences between wholesale gas prices and wholesale electricity prices do not exist (gas plant are currently standing idle due to the high gas price relative to the electricity market price) and, even if they were to exist they would not persist as suggested by the Government models: in practice these circumstances would result in the commissioning of new plant would be commissioned and operate thus increasing electricity generation and reducing the wholesale electricity price. The result of such operations would be that the cost to consumers of the CfD FiT would be higher than modelled with the accompanying risk that the consumer would be locked in to those higher prices. Under the fixed value of the CfD, falling energy prices could not be passed on to the energy customer as lower electricity prices would lead to a higher pay out under the CfD. Given that Government modelling does not account for such a falling price scenario, the EMR analysis would never reveal this affordability risk for consumers.

2.6.3The creation of a counterparty other than the UK Government: By creating a Contract model for the FiT, the Government has created the need for a contractual counterparty, in contrast to the current small-scale FiT where contract law does not require a counterparty. Initially, it was widely assumed that the CfD counterparty would be the Government. This arrangement, however, appears to risk falling foul of EU state-aid rules if applied to nuclear generation. The Government’s response has been to seek to create a new counterparty which is currently expected to be a conceptual electricity “supplier base”. The Government, as counterparty would have had a top AAA credit rating, but a different counterparty may not have such a high rating. A lower than AAA rating would increase credit risk for investors and, therefore, the cost of capital. Given that the original justification for the selection of CfD FiT model was the effect of reducing the cost of capital for investors and therefore the cost to consumers, this change of counterparty has profound implications for the defence of the CfD model on cost grounds.

2.6.4Additionally, if the Government places an obligation on suppliers to be counterparty to an unknown number of new generation stations, each with an unknown credit rating delivering an unknown quantity of electricity on an unknown timescale against an unknown market price, and where such an obligation may be singularly or jointly met, this situation is likely to cause deep concern among Risk Managers and Risk Committees of those companies. If suppliers were obligated to remain in the market it is reasonable to expect that they would seek to increase their profit margin through the retail electricity price so as to manage the risk of any potential defaults and open ended obligations.

2.6.5The risk of creating obligated sellers in the electricity market and the resulting impact on price: The CfD FiT will only be paid out to an eligible generation station if that generation station were to generate power. The right to generate power is only granted once that power has been sold (in advance of generation). The result is that, to ensure revenues from the FiT (in addition to revenues for electricity) CfD FiT generators must ensure that their power has been sold onto the market. Unlike the current Renewables Obligation, the CfD provides no incentive for any of the major suppliers to purchase CfD electricity. By creating an effective obligation to generate on one side of the market with no corresponding incentive to buy on the other side of the market, generators risk becoming distressed sellers of power. Under these conditions purchasers will have the opportunity to dictate lower prices to CfD generators. This may have a twofold impact:

2.6.6Artificially reduce the electricity market price reducing the CfD reference price and increasing the payouts to CfD generators

2.6.7Causing developers of new CfD based plant to require a higher strike price under the CfD to compensate for the anticipated discount in the price secured for electricity generation and the corresponding loss of revenues. For market players with no supply-side business to operate as an effective hedge, this risk may put them off investing entirely.

2.6.8In either case, these circumstances suggest that society faces a risk of a greater cost of the CfD policy than has been assumed. Any assumption that the competitiveness of the supply market will ensure that any fall in CfD traded power prices will be translated into a lower cost for the traded electricity component in consumers bills must be tempered by the reality that a major proportion of electricity will continue to be sold bilaterally. Under these circumstances there may be a lack of transparency that affords the Government or regulator little visibility to assess the efficient functioning of the market in the interest of consumers.

3. Developing a Solution—a Phased Approach to EMR

Overview

3.1 As circumstances surrounding the EMR have evolved, it appears increasingly unlikely that the EMR will achieve the energy policy objectives for the coming ten years. This situation determines that a more comprehensive approach to market will be required. The factors outlined in Section 2 suggest that whilst the principal elements of EMR are seeking to create conditions that will yield outcomes in the mid 2020s they are likely to fail to address issues facing the energy system in the critical period prior to this. Hence, whilst there may be substantive value in retaining the existing EMR work streams there is also a clear need for a focus on what can be done now to ensure that the energy system is affordable, secure and reducing in carbon intensity whilst longer term solutions are in development.

3.2 Intervention is needed to ensure that the market will deliver for the shorter term. To meet this shorter term need, the CHPA recommends that DECC needs to develop a focus on deliverable pathways to achieve affordability, emissions reduction and security of supply. The current electricity market will not however deliver these aims without intervention: since the formation of the current electricity market system which operates on a short run marginal cost basis, an absence of intervention policy will lead to the construction of the lowest cost, lowest risk generation assets. In the current situation, that plant is a combined cycle gas turbine (CCGT) power station. Hence, if the Government does not want an electricity market almost entirely reliant on default investment in CCGTs then some intervention is likely to be required. The interventions may be for reasons of security of supply, carbon emissions or other concerns. To deliver government intentions, therefore, necessitates the development of either subsidies or regulation. As creating a low carbon and secure electricity system requires regulation and/or subsidy, it is vital that DECC develops a considered approach to these three key areas identified above. Without such a strategic approach, the Government is likely to see a new dash for gas which, whilst addressing security of supply concerns, will fail on sufficient emissions reduction and renewable energy deployment.

3.3 Recognising that neither the current market nor the current EMR proposals will deliver on the key aims of energy policy in the appropriate timescale, DECC needs to develop a focus on three areas of progress for the shorter term:

(1)Renewable electricity generation.

(2)Energy efficiency.

(3)Optimum deployment of new gas generation.

3.4 Correctly approached, this combination of technologies could continue to see emissions reductions and increased renewables whilst the EMR process for larger-scale, low-carbon generation technologies persists.

3.5 Combining delivery of gas generation, renewables and energy efficiency. There are two key actions that need to occur to deliver gas, renewables and energy efficiency:

Drive the development of the most efficient gas generation possible.

Maintain simple and accessible support for renewable generation past 2017.

Drive the development of the most efficient gas generation possible

3.6 Ensure the most efficient gas plants are built and operate. With government recognition that there is a need for more gas generation on the system, the lead option to continue to reduce carbon emissions whilst facilitating new gas build should be the development of new gas fired combined heat and power (CHP) generation, whilst securing the operation of the existing fleet of plant.

3.7 CHP represents the optimal use of any input fuel and will reduce emissions by up to 30% compared to separate generation. The UK currently obtains 7% of electricity supplies from CHP, reducing emissions by some 13 million tonnes of CO₂ per annum4 and reducing UK gas imports by 5%. Despite the benefits of CHP the chancellor saw fit to remove the operational subsidy for CHP from 2013 and the industry anticipates a reduction on CHP outputs (and a consequential increase in CO₂ emissions and gas imports) from 2013. In addition, the removal of support has all but halted new CHP development. The timing of the confirmation of removal of support for CHP came days after the announcement of the new Gas Generation Strategy in which Edward Davey the Secretary of State stated “we can’t take our foot off the gas for some time yet”.5 The removal of support for CHP works directly counter to both the UK’s security of supply and carbon commitments.

3.8 CHP is a proven, reliable, cost-effective energy-saving approach, capable of delivering a step-change reduction in an industrial site’s primary energy demand of up to 30%. Investing businesses benefit from enhanced competitiveness through improved efficiency, whilst Government (which foresees a potential doubling of CHP capacity to 2020) reaps the benefits of cost-effective CO₂ abatement and greater energy security.

3.9 As an energy efficiency technology, CHP reconciles major issues including: the apparent tension between emissions reductions and industrial competitiveness; the need for gas to maintain security without compromising emissions reductions goals; and the need to minimise the risk of rising energy prices.

Ensure bankable support for renewables to prevent a hiatus in investment

3.10 Substantial deployment of renewable energy is needed but the lack of bankable support for renewable generation commissioning after 2017 and for renewable CHP post 2015 means that large scale projects are on hold as developers cannot be sure that they will be commissioned and operating in time to secure eligibility for the present subsidy regime.

4. Understanding the Market Limitations

4.1 As noted above, an unconstrained electricity market will tend to bring forward only CCGT plant. Interventions are needed to move away from the default. Under these circumstances any interventions should be targeted to address the specific factors that act to constrain development and operation of efficient gas fired CHP does and which may also constrain new renewable generation during the period when Government is developing a new incentive scheme. These are both addressed below.

Constraints on CHP development

4.2 As an energy efficiency technology that makes optimum use of expensive fuels, CHP might be expected to be the default choice for consumers with a heat and power demand; often reflected in the query “if CHP is so efficient why does it not get built?” Recent experience demonstrates that this truism is evidently not the case: heat users often preferentially choose simple boilers and the power industry routinely develops power-only generating stations. The case for policy support reflects the need to bridge this gap between opportunity and practice.

4.3 The principal reason for CHP remaining outside of the mainstream of energy investments lies in a combination of market failures and market distortions. The Government’s Electricity Market Reform proposals introduce a complex set of changes that will add further layers of intervention and distortion onto a market which already suffers from a lack of transparency and liquidity. Any support for CHP must be targeted to address these market distortions and recompense the CHP operator or developer to ensure that CHP is a viable commercial proposition for investment and continuing operation. There are four key areas where the market today does not function effectively:

4.3.1Existing sites for power generation have a competitive advantage over new sites. New power generation stations are generally proposed on existing or legacy sites where power stations have previously operated. These sites, generally in place before privatisation, have existing infrastructure in place (power lines, fuel supply routes etc) thereby minimising development costs. In addition, the existence of a power station ensures that the likelihood of planning barriers and costs being an issue are minimised. By contrast, new CHP plants are sited based on heat demand not electricity infrastructure. Sites of new CHP plant are often in areas where the electricity grid—configured to meet the needs of mid-C20th Britain—is limited in its ability to accommodate new generation assets, further increasing project complexity and costs. In addition, the prospect of a new power station at an industrial site may be subject to greater planning challenges, adding both cost and risk to the development.

4.3.2The balance of cost and risk is weighted against CHP developers. This cost and risk balance arises in two areas: electricity market interaction and heat off-take.

4.4 Developers of new power plant do so purely to supply electricity to the market or sell bilaterally to energy suppliers. The electricity market and its regulations are central to their business model. Unlike the developer of a power station, a CHP plant primarily operates to meet the heat and power demand of manufacturing a product such as paper, soda ash, sugar or petrol. To ensure maximum CHP efficiency and emissions reductions, plant design will usually result in the export of excess power generation to the electricity grid: a major step that requires active engagement with the electricity market rather than simply passive consumption. For a CHP operator, therefore, electricity market interaction is a secondary activity and the electricity market viewed as inherently risky and “foreign” to business-as-usual. By contrast, the electricity market is fundamental to the business of large-scale centralised plant and vertically integrated companies (with generation and supply businesses). The vast majority of smaller market operators are only present due the incentives such as the Renewables Obligation. Without incentives, smaller generators simply cannot compete in the market as structured currently.

4.5 Where a CHP plant is developed by a 3rd party ESCO, heat supply represents a major revenue line. The credit risk of the industrial site, and ultimately the risk that the industrial consumer may cease operations, present costs and constraints for new projects.

4.5.1The additional capital cost of investing in CHP and the substantial risk of selling a secondary product into an unknown, complex and illiquid market discourages many potential CHP operators from investing.

4.5.2Emissions reductions benefits do not accrue to CHP operators. CHP reduces emissions compared to separate generation by at least 10% and commonly up to 30%. The practical effect of CHP operation is to displace the emissions from grid electricity—emissions which arise at a central power station, far away from the industrial site. Whilst UK net emissions fall as a result of CHP installation, gross emissions at the CHP site will rise as a new process (electricity generation) now occurs on-site. The emissions reductions of CHP are recorded in Government statistics but, without express support, the value of these reductions accrue to the wider UK economy not the CHP operator.

4.5.3Security of supply benefit does not accrue to CHP operators. As with emissions reductions, the more efficient use of fuel to meet heat and power demand reduces primary energy demand. Reducing primary energy demand directly improves security of energy supply but, once again, the benefits accrue to the wider UK economy. CHP utilisation currently reduces gas demand by around 3.5bcm, equivalent to 5% of net imports. As noted above fuel consumption will rise at a site that installs CHP and, therefore, it is vital that the security of supply benefit is credited to the CHP operator to ensure a fair market.

4.6 There is now a pressing requirement to address these market failures. If these failures are not addressed then the pattern of generation that we can expect to see in the period of the next 10 years will compromise emission and security (efficient use of resources) goals; EMR presents the only timely opportunity to do this. Furthermore, gas CHP on industrial sites can, subject to design, offer highly flexible capacity services at far higher efficiencies than other peaking plant.

4.7 A simple incentive for both new and existing CHP today can also ensure efficient flexible generation for the future. Countries such as Germany and Belgium have substantive support in place for CHP and this is leading to a major deployment. In the case of Germany a time limited feed in tariff for CHP is in place to achieve a target of 25% of total electricity generation by 2020.

4.8 It is important to note that the Government’s modelling of CHP uptake is consistently over-optimistic as is borne out by the actual CHP data in the Government’s statistics. Whilst there may be a number of causes for this, a key factor may be the same concerns raised previously in this submission regarding the energy price assumptions used by the Government in their modelling in Section 2 of this paper.

Why there is a risk that new renewable will not be built

4.9 The Government needs to ensure bankable support for renewables to prevent a hiatus in investment whilst the CfD is developed. Substantial deployment of renewable energy is needed but the lack of bankable support for renewable generation commissioning after 2017 and for renewable CHP post 2015 means that large scale projects are on hold as developers cannot be sure that they will be operating in time.

4.10 The development of the CfD is complex making it both slow and of significant concern to smaller scale developers of renewable generation projects. Working in collaboration with other parties as part of the Ministerial Distributed Energy Contact Group, the CHPA has identified a number of concerns facing the development of smaller scale renewables under the CfD FiT proposals. The overriding concern is that the substantial additional risks associated with operating within a CfD FiT will need to be transferred to a third party better able to manage that risk. The result of the transfer of risk will be an increase in cost (or reduction in revenues) to the developer and reduction of project viability.

4.11 The combination of challenges for larger renewable projects commissioning before the RO expires and for smaller developers having concerns over the CfD mechanism, creates a strong case for ensuring simple support is available whilst the CfD is developed and implemented. The Government’s proposed overlap of three years (2014–2017) is insufficient as this will reduce if there were delays to the CfD development and because it will take time for developers to become accustomed to the CfD following its implementation. The current proposals will cause a hiatus in development when deployment is needed.

5. Recommendations

5.1 As already noted the circumstances surrounding the EMR have evolved so that the what had been envisaged at the start of the EMR process, in terms of build times and the cost effectiveness of the proposals are not necessarily the case now. As a direct result, the present EMR proposals are not addressing the immediate challenges facing the energy system and may risk creating a hiatus in low carbon and renewable investment over the coming ten years. To address this risk an alternative approach is needed to deliver the near-term goals in a coordinated and efficient manner that is nonetheless consistent with longer-term policy goals.

5.2 The urgency of the situation demands that whatever is proposed be a simple and workable solution. To achieve Government’s aims any solution needs to specifically incorporate both renewable and gas fired CHP. The CHPA, therefore, recommends that Government gives urgent consideration to a proposal for extending the current small scale FiT, as the most effective means of achieving these criteria.

5.3 The current small-scale feed in tariff already has provisions for supporting gas-CHP and renewables but these both have capacity limits of 5W and 5MW respectively. A very simple change to primary legislation could remove these capacity limits. The procedures for funding the FiT are already in place and so little, if any change would be required there. In terms of levels of support, the Government already has support levels for renewables determined under the RO and is in the process of reviewing support for CHP ensuring that support should be relatively simple to determine.

5.4 Such a change for the current Feed-in-Tariff need not distract from other elements of the EMR process. The change would, however, provide the framework needed to ensure that energy security, affordability and emissions reductions were all pursued during the 2010s and early 2020s rather than creating a hiatus.

6. Concluding Remarks

6.1 The CHPA would welcome the opportunity to explore these ideas at an oral evidence session to the committee.

June 2012