UK Electricity Market Reform and the Energy Transition: Emerging Lessons.

• Author: Grubb, Michael
• Position: Report - Statistical table

1. INTRODUCTION: 'MODEL OR WARNING?'

   The UK was widely seen as one of the world's leaders in electricity deregulation in the early 1990s. The move from a centrally dispatched Pool model to an energy-only market in 2001 seemed to embrace the trend to more decentralized market-determined pricing, so it came to some observers as a surprise when in 2010 the new UK Government embarked on a fundamental reform to the architecture of UK electricity markets. Some claimed it abandoned the principles of market competition seen as defining the UK approach (e.g. Timera Energy, 2011; Darwell, 2015), with widely divergent views as to whether it represents a potential model which others could follow, or a warning of the perils of--apparently--returning to greater state involvement in the market (Pollitt and Haney, 2013). Britain's electricity reform is therefore of central interest concerning electricity market design, and particularly in relation to the case for reforming the EU Target Electricity Model with its insistence on energy-only markets (Keay, 2016).

   The proximate causes of Electricity Market Reform (EMR) were the impending closure of old fossil and nuclear plant with a lack of willingness to invest in new gas-fired generation, and the need to decarbonize the electricity sector without raising consumer costs excessively. The analysis provided to the Government proved controversial, and the required legislation took most of the 5-year Parliamentary term to complete. The first auctions under the new system only took place in December 2014.

   This paper summarizes the background to and reasons for EMR, its structure and the results to mid-2018, commenting on the extent to which it has met the objectives of a secure, sustainable and affordable electricity system, and how it might be improved. Even in this relatively short period, substantial policy changes have been enacted, the regulator, Ofgem, has responded to criticisms of inefficient network tariff setting, and the auction outcomes have been substantially better than expected, so there is every reason to hope for further improvements, providing they can be effectively motivated.

   Simulation studies of the EMR (Franco, Castanedo and Dyner, 2015) have indicated that such a 'comprehensive intervention or a similar one that includes the promotion of low carbon electricity generation through the simultaneous implementation of various direct and indirect incentives, such as a carbon price floor, a Feed in Tariff (FIT) and a capacity mechanism' were needed to deliver the evolving objectives of UK policy. But while there are reports to Government evaluating EMR (e.g. Grant Thornton and Poyry, 2015), and studies of electricity market reforms driven by EU Directives (e.g. Pollitt, 2012), to our knowledge, there has been no academic empirical assessment of the emerging lessons from the reforms. Four years after its enactment, we aim to provide such an assessment.

2. UK ELECTRICITY IN CONTEXT

   2.1 The Evolution of the UK Electricity Supply Industry 1947-2001

   The UK's electricity industry was state-owned from 1947-1990, and until 1955, almost the entire output was generated from coal, supplied by the state-owned National Coal Board. Under pressure from the Treasury, oil-fired power stations were then built, and the first generation of gas-cooled Magnox nuclear power stations started producing (followed with a long delay by Advanced Gas-cooled Reactors).

   Figure 1 shows generation output by fuel with some of the key events. The share of oil peaked at 34% just before the oil shock in 1972, and thereafter coal and nuclear power gradually replaced oil, whilst the nuclear share rose to 20% by 1990.

   By 1989, just before restructuring for privatization, around 90% of the conventional thermal generation was from coal, and thereafter the share of oil fell from 7% to 1% in 2002 (the remainder of thermal generation is largely from industrial by-product gases). Shortly after privatization, the coal share rapidly declined as imported electricity and nuclear power increased. It continued declining with the 'dash for gas', which was all new entry despite the considerable spare capacity. At the end of the century, consumption fell with deindustrialization and increased demand efficiency, while renewables displaced gas and/or coal, whose shares depended on the very volatile clean (gas) and dark green (coal) spark spreads (the margins between the wholesale price and the gas or coal cost including the cost of C[O.sub.2]--see Figure 5).

   Privatization replaced the state-owned companies in England and Wales with two fossil and one nuclear (initially state-owned) generation companies, with an unbundled National Grid (initially collectively owned by the privatized distribution and supply Regional Electricity Companies, RECs). In Scotland the two vertically integrated companies were sold bundled, while in Northern Ireland three generation companies were sold with long-term power purchase agreements. The network companies were subject to price-cap regulation with the basket of tariffs changing in line with the Retail Price Index, minus an annual efficiency factor X (the "RPI-X" incentive regulation).

   The wholesale market took the form of the mandatory gross Electricity Pool, into which all plant had to be offered (with sub-50 MW exceptions). This was centrally dispatched with a System Marginal Price (SMP) set by the marginal price offered by the most expensive unconstrained generator required. To this price was added a capacity payment, equal to LoLP*(VoLL--SMP), where LoLP is the Loss of Load Probability in that half-hour and VoLL is the Value of Lost Load ([pounds sterling]5,000/MWh in 2016[pounds sterling]). This would have been the efficient price if the SMP were equal to the System Marginal Cost (SMC), but the restructuring had left two large fossil companies (National Power and PowerGen) setting the price in the Pool with the ability to raise the wholesale price above the SMC.

   Figure 1 shows the dramatic 'dash for gas' with its share growing from next to nothing in 1992 to almost a third of generation by 2000; a result of a combination of reasons. A legal ban on using gas for power generation had been lifted and the newly developed Combined Cycle Gas Turbines (CCGTs) were cheap, quick to build and offered high efficiencies, which, with falling gas prices, offered low average costs. The Pool allowed new entrants to sell at the same price as incumbents and the transparent system-wide price facilitated contracts. With energy policy leaving the market to guide choices, political risk was considered low and substantial entry by 'Independent' Power Producers (IPPs) occurred. These entered on the back of long-term fixed-price contracts (and often share ownership) with the RECs, who could pass on their costs to the captive franchise domestic market.

   The combination of long-term gas contracts, long-term IPP contracts, regulated pass-through and performance guarantees on the CCGTs all reduced risk, whilst an added incentive for the RECs to sign such contracts was to exploit their new independence from centralized generation. The two fossil generators dominated the England & Wales Pool and clearly had considerable market power (Newbery, 1995; Tashpulatov, 2015), which the regulator negotiated down by encouraging them to divest 6 GW of coal plants to a third generator in 1996. The resulting triopoly was subject to less regulatory constraint in exercising market power, with an incentive to do so as they wished to divest coal plant before the "dash for gas" eroded their market share too drastically (Sweeting, 2007). Indeed, by 2000, coal-based generation had shrunk by more than a third (and increasing amounts of coal were imported rather than domestically produced).

   1.2 The Electricity Industry Structure after 2001

   Once they had divested enough plants, the generation companies were free to buy the supply (retailing) businesses originally integrated with distribution in the RECs. The market evolved towards the current Big Six generators plus retailers. (1) The market power of the original triopoly led to an increasing gap between cost and price in the Pool between 1996-2000, and encouraged the Government to replace the Pool with New Electricity Trading Arrangements (NETA)--just at the date (2001) when the price-cost margin collapsed under the weight of competition and excess capacity (Newbery, 1998; 2005).

   NETA replaced central dispatch and the Pool with a self-dispatched energy-only market (abolishing capacity payments). The argument put forward was that getting rid of the Pool in favour of direct bilateral trading would encourage competition. To meet the physical need to balance supply and demand, NETA created a two-priced Balancing Mechanism which penalized under-delivery of promised power with a high penalty. The claimed logic for the reform was that self-dispatch required generators to submit a balanced offer (output matched by contracts to purchase), requiring them to contract all output, thus removing the incentive to manipulate the spot market (under-contracting encourages sellers to increase the spot price above the marginal cost, over-contracting to reduce the price below marginal cost, Newbery, 1995).

   In practice, the balancing mechanism was so flawed that it required numerous painfully negotiated modifications to approximate an efficient balancing market. In addition, the risk of incentives to manipulate the spot market was replaced by a clear incentive to vertical integration: the merger of retailing and generation companies ensured that they were automatically hedged against electricity price uncertainties, since they would then be selling wholesale to themselves. However, this in turn created major barriers to entry, and a perception of the electricity system as an oligopoly of major power companies controlling the entire system from generation to consumption.

   Despite evidence that...