Deregulated Electricity Market In The United Kingdom

Published Date: 02 Nov 2017

1. Select a deregulated electricity market of your choice and write a short summary of it’s principal features. In your description, try and cover the following items.

A. Compare and contrast how it operates in comparison to the deregulated electricity market in the United Kingdom. Consider aspects of trading and of certificates and the role of regulators.

The Public Power Corporation A.Ε is now the leading producer and supplier of electricity in Greece, with more than 7.5 million customers. D.E.I owns the national transmission systems and power distribution networks. D.E.I has very large infrastructure facilities for mining coal, manufacturing, transportation and distribution of electricity. It is also one of the largest industrial companies in the fixed assets of information, and is a leading utilities company in the electricity sector in Greece.

D.E.I renewable, is the only Greek company that operates in five main forms of renewable energy sources (wind, hydro, solar, geothermal and biomass). Along with the use of these five energies, D.E.I renewable study and develop solutions to other, alternative power generation sectors, such as hybrid systems.

On the other side the act of parliament (or utilities act 2000) was organized the independent economic regulator of UK electricity market, the Office of Gas and Electricity Markets (OFGEM), which main responsibilities are ensuring competition, enforcing regulations and achieving a sustainable development. These are a key contribution to achieve the energy goals. As an independent office, OFGEM ensures the freedom of regulatory process from political interference and avoids markets uncertainty, protecting in that way the interests of consumers [1]. The main functions of the regulator are related to the managing of licenses: the issuing, modifying, enforcing and revoking and also the setting of price controls.

The trading of electricity is made under BETTA, the British Electricity Trading and Transmission Arrangements, and cover UK electricity grid [1]. Bilateral contracts are the way in which electricity is traded between generators, electricity suppliers and customers, through a series of markets that operates on a rolling half hourly basis.

Currently, there are more than 18 energy companies in charge on UK supply. Furthermore, some companies have participated in the improving of vertical integration, which has contributed to market consolidation. Based on the experience to date in the England and Wales market, we make the following contrast for other countries looking to follow [2]:

1. Reject residential retail electricity market deregulation: In the UK the promise of competition and resulting improvements in service and decreases in price has not been kept. Restructured markets have not resulted in price savings for consumers.

2. Do not partially open markets: Pressure from large industrial and commercial consumers to open their retail markets can lead to dangers for residential consumers, even if the residential market remains regulated.

3. Increase Consumer Protection in those markets already deregulated.

Enact consumer safeguards on "door to door" and commission sales

Protect low-income consumers

Beware prepayment meters

The degree of price deregulation must be appropriate to the level of competition in the market

B. What checks and balances are present to avoid fraudulent practice, such as with ENRON in the United States?

The United Kingdom began deregulating its electric market years before the United States. Hence, the UK provides the best example of what can be expected in the deregulated residential retail electric market in the United States.

Generally there are 4 components of a consumer’s electricity bill [2]:

Generation: The production of electricity from fuel or renewable sources.

Transmission: The transport of electricity over long distances via high voltage wires.

Distribution: The final delivery of electricity after it has been stepped down in substations to household voltage levels.

Retail: Buying electricity from the wholesale market and reselling it to consumers. This includes the administrative overhead of customer care, billing, and advertising. In the UK, meter reading is considered part of the retail segment, but it is considered a distribution function in the US.

C. What are the advantages and disadvantages of each approach when viewed from the perspective of the utility customers?

Consumer complaints about cheat, abuse and billing errors have arisen, along with prepayment meters that enable price discrimination against lower income consumers. Consumers are better served by keeping retail supply under rate regulation with distribution and transmission networks [2].

If a partial opening is adopted, retail companies should not be allowed to allocate high cost generation contracts to residential consumers and low cost contracts to commercial and industrial users. Rules regarding conduct, disclosure and consumer remedies must be established beforehand to head off problems of fraud and abuse before they occur.

If retail competition is implemented, protections need to be built into the market structure to ensure that low-income and other vulnerable consumers have access to the market at fair and non-discriminatory prices. Provisions have to be made to supply (at a fair price) the consumers that no-one else wants.

Experience in the UK indicates that pre-payment meter technology can be used to charge higher prices to lower income consumers and to hide high disconnection rates. UK customers on prepayment meters have also paid higher prices than those paying by other means.

D. How does it accommodate Distributed Generation in general?

Under the UK’s monopoly cost structure prior to 2000, each component contributed to a typical consumer bill roughly as follows: Generation (63%), transmission (4%) distribution (27%), and retail (5%) [2]. Since restructuring, generation prices have fallen and retail prices have increased as a proportion of the bill. Under most deregulation schemes, transmission and distribution are maintained as regulated monopolies. Generation is opened to competition. Retail supply has been opened to competition in fewer markets, some of which have introduced competition only to large industrial and commercial users.

In the United Kingdom, prior to privatization, there were three main electricity transportation grids. The largest covered England and Wales (about 90% of demand), while there was a separate but interconnected system covering Scotland and a physically isolated system supplying Northern Ireland [2]. All of the segments of the market were state owned. At the time, there were was one main generation and Transmission Company and twelve regional distribution and retail companies in England and Wales. The Central Electricity Generating Board (CEGB) had an effective monopoly of generation and owned and operated the national high voltage transmission system. In 1990, it was split into 4 companies. The fossil fuel plants were given to two newly privatized companies, National Power and Powergen, while the nuclear plants remained in public ownership in a new company, Nuclear Electric. The transmission network was separated and was transferred to the new National Grid Company (NGC).

E. How are domestic micro-generators incorporated so that households are rewarded for KWH returned to the grid?

Electricity supply from micro generation is a big-market method of producing electricity with a product rather than a "betrothed" power project. Micro generation is energy efficient, well matched to demand and is environmentally friendly. Moreover micro generator electricity is produced and consumed on the premise, or very close electrically and geographically to the premise, where it is produced. These factors make micro generation unique.

Micro-generation is defined as a source of electrical energy and all associated equipment, rated up to and including [3]:

25A at low voltage [230V], when the DSO network connection is single-phase

16A at low voltage [230/400V], when the DSO network connection is three-phase, and designed to operate in parallel with the ESB Networks LV system.

Where multiple generating sources (of the same or varied technologies) are on the same site and share access to the same ESB Networks connection point, the aggregate rating must not exceed:

25A at low voltage, when the DSO network connection is single-phase

16A at low voltage, when the DSO network connection is three-phase.

2.

A. With reference to UK and Scottish Government policy and targets for renewable energy generation and the reduction of carbon emissions, describe how developments in offshore wind turbines and marine renewable energy devices are expected to grow in Scotland over the next 10 years.

The amount of renewable energy generated in Scotland is increasing day by day, with onshore-wind energy being the single largest contributor. The present trends in renewable energy generation indicate that it would technically be feasible to achieve the Scottish Executive’s target of 40% energy generation from a range of renewable resources by 2020. While renewable energy generation will undoubtedly help meet Scotland’s commitment to addressing climate change, it also places a lot of constraints on the existing grid and power distribution system due to the intermittent generation of electricity from wind-mills, which calls for adequate interconnectivity build-up of the Scottish grid with its neighboring grid systems besides necessitating the introduction and implementation of energy storage and demand side management technologies. In addition to onshore-wind, other renewable technologies such as offshore-wind, wave and tidal energy also hold out promises of energy generation though to lesser degrees.

According to [4] the government of UK has set a target to cut CO2 emissions by 60% by 2050 to achieve which 30-40% of electricity would have to be generated from renewable energy resources. This requires that Scotland generate 40% of its electricity from renewable sources by 2020 [4]. The Friends of the Earth Scotland [5] point out that demand scenarios can be either of demand growth or of demand reduction. In the Demand Growth scenario, demand is expected to grow again in 2011 as the present recession is about to be over and the projected demand will attain a steady growth of 12.2% corresponding to 45,900GWh annually by 2030. In the Demand Reduction scenario, the demand will start diminishing from 2012 resulting in an annual electricity consumption of only up to 35,180GWh by 2030. The projected values for demand growth and demand reduction in low renewable scenario and high renewable scenario are shown at table-1 while renewable energy generation as percentage of total consumption is shown at table-2.

Table 1 "Electricity Production Consumption & Export in 2030" [5]

Table 2 "Projected growth in Renewable Energy generation" [5]

The projected renewable electricity supply (such as onshore wind, offshore wind, wave, tidal and hydro) for 2030 in comparison with the projected demand which it is likely to exceed is shown at figure 1.

Figure 1 "Two Scenarios for 2030-RE Supply to exceed Demand"[5]

Both the UK committee on climate change and the Scottish Government has set demand reduction targets of 20% and 12% respectively to be achieved by 2020. Reducing electricity demand in general and peak demand in particular, is the cheapest way to cut greenhouse emissions.

B. How must such renewable energy be priced to be competitive with non-nuclear generation?

A balanced renewable energy generation mix with generation from onshore-wind, offshore-wind, wave and tidal-power in the ratio 5:2:2:1 is found to be the optimum ratio for renewable energy generation in Scotland and in UK.

A study of numerical results from six technology scenarios and five area scenarios indicate that less than 6GW of on-shore wind plant in Scotland can supply 40% of electricity demand [6]. This study found that 23% of electricity demand could be possibly met by off-shore wind plants. Another 20% of electricity could be supplied by wave energy plants generating 3GW of electricity [6].The study also found that 5% of the total demand could be met from tidal wave plants generating 750 MW of electricity. Furthermore, it was found that by opting for a mix of these different types of renewable energy plants, 5.5 GW of electricity could be produced which would account for 40% of electricity demand in Scotland. The amount of capacity that is required to be installed at these plants can be reduced by utilizing the capacities of presently operational hydro and biogas plants and of those in the anvil.

The above study has considered two mixed portfolio scenarios of renewable options arrived at from a combination of onshore-wind, offshore-wind, wave and tidal energy. In one option, the relative proportions of onshore-wind, offshore-wind, wave and tidal energy were held at 75-10-10-5% respectively, and the total renewable energy generating capacity was increased in four stages starting from 750MW, and ending at 6GW [6]. The graphs of this scenario are shown at Figure 2, (a), (b) and (c) respectively.

Figure 2"A mixed portfolio with a constant proportion of 75-10-10-5% held for onshore wind, offshore wind, wave and tidal respectively" [6]

In the other mixed portfolio scenario, the combined capacity of the above portfolios were held constant at 6GW, but the relative proportion of onshore-wind was increased starting from 0% to 100%, corresponding to 0GW,750MW,1.5GW,3GW and ending at 6GW, while the remaining part of renewable energy from offshore-wind, wave and tide was fixed in 2:2:1 ratio[6]. The graphs for the second option are shown at Figure 3 a), b), and c).

Figure 3"Available mix portfolio of onshore-wind, wave and tidal" [6]

The following pertinent conclusions have emerged from the above study [6]:

i) Based only on onshore-wind, offshore-wind wave and tidal power, electricity of up to 6GW, 3GW, 3GW and 1GW can be generated in Scotland.

ii) The annual plant capacity factors exceed 30%. There exists a seasonal variation for capacity factors due to variation in wind and tidal power with more potential for generation in the winter season.

iii) 3GW electricity generation from onshore-wind, offshore-wind and wave alone can meet at least 50% of the 40% target demand while a 6GW output can comfortably meet the target of 40% demand by 2020.

iv) There is no guarantee that the demand target would be met hour-by-hour at any time in a year by renewable resources alone. The renewable electricity generation would be characterized by shortfalls and excesses throughout its production due to the inherent variability which characterizes its generation.

v) Only for a fraction of hours during any given year will the value of 40% of the actual demand be actually met by renewable energy.

vi) A renewable energy capacity of 3GW will meet 40% of actual demand between 12-18% of the time while a renewable energy capacity of 6GW will meet 40% of the demand around 40% of the time.

The relationship between the cost of generating electrical power from various sources and the price that consumers pay is unclear by direct and indirect subsidies, market mechanisms, transmission and distribution costs. The true costs of generating electrical power are often covered by commercial sensitivities and competing claims that make the determination of sensible energy policy difficult and often imprecise [7].

The cost of generating electricity, is expressed in terms of a unit cost (pence per kWh) delivered at the boundary of the power station site. This cost value, therefore, includes the capital cost of the generating plant and equipment; the cost of fuel burned (if applicable); and the cost of operating and maintaining the plant in keeping with UK best practices.

The findings are summarized in Figure 4, which illustrates the present-day costs of generating electricity from different types of technology appropriate to the UK:

Figure 4 "Cost of generating electricity (pence per kWh) with no cost of CO2 emissions included" [7]

The following table includes the cost of generating electricity for the different ‘base-load’ plants considered by this study.

Table 3 Cost of generating electricity for base-load plant (pence per kWh) [7]

For peaking operation, i.e. generating for limited periods of high demand and providing standby capacity, open-cycle gas turbines (OCGT) fired on natural gas are the most appropriate new plant candidates. OCGT is ideally suited for the role of peaking duty, which requires flexibility, reliability and can be started quickly should the need arise. We estimate that the cost of a gas fired OCGT generation will be about 3.1 pence per kWh if operated continuously []. However, the average cost will rise to about 6.2 pence per kWh if only operated for limited periods of time consistent with peaking duty, i.e. for only 15 per cent of the time, say. Renewables are generally more expensive than conventional generation technologies. This is due in part to the immaturity of the technology and the more limited opportunity to take advantage of cost savings brought about by economies of scale usually associated with more traditional fossil-fuel types of generation. In addition, fluctuations in the energy source itself may limit the output of generation available from these technologies and, thus, raise the unit costs of the generator on two counts [7]:

• As capacity factor falls, unit costs of generation rise;

• Additional, fast response, standby generating plant may have to be provided to maintain

system security as the energy source fluctuates.

Table 4 includes the cost of generating electricity, with and without the additional cost of standby generation, from the selection of renewable technologies considered by this study.

Table 4 Cost of generating electricity for selected renewables (pence per kWh) [7]

Although the fuel component of electricity may represent as much as 70 per cent of the total cost of production, deriving a detailed forecast of future fuel prices was out with the scope of this study. In order to compare the costs of different fuels used in electricity generation, we have taken a pragmatic view of historical prices and the key drivers affecting fuel prices moving forward to derive reasonable benchmarks from which to perform sensitivity analyses. Figure 2 illustrates the effect on the cost of generating electricity given a change of ±20 per cent in fuel price, where the base cost of coal is £30 per tone and natural gas is 23 pence per them [7].

Figure 5 "Effect of ± 20% change in fuel price on the cost of generating electricity" [7]

At the time of writing this report, no firm commitment has been given by the Government on how carbon dioxide (CO2) emission allowances will be allocated to new entrant generation plant for the period 2005 to 2007 [7]. In view of this uncertainty, a conservative approach has been adopted by the study to burden 100 per cent of the output from fossil fuelled generation with a notional cost, calculated in terms of £ per tonne of CO2 released. For the purposes of this study, a range of values between zero and £30 per tonne was used, where the upper limit reflects the reported cost of CO2 sequestration.

Figure 6 illustrates the potential increase in generating costs brought about by the introduction

of carbon emission allowances.

Figure 6 "Cost of generating electricity with respect to carbon dioxide emission cost" [7]

It is clear that CO2 costs will only affect those technologies burning fossil-fuels. The lower efficiency of steam plant, combined with the greater level of carbon found in coal compared with natural gas, means that the gap between CCGT plant and other coal-fired technologies will widen as the cost of CO2 increase. The cost of nuclear and other renewables (deemed to be carbon neutral) remain unchanged and, therefore, become more competitive as the specific cost of CO2 emissions increases.

C. What are the operations and maintenance (O&M) challenges for farms of such devices? What O&M strategies might be adopted to meet these?

The first years of a wind turbine (usually guaranteed by the manufacturer), there are no serious operational risks or serious maintenance needs. After this period, the first problems appear in control system and to sensors and after follow the other parts or accessories of a wind turbine. The costs of monitoring, maintenance, replacement and insurance costs, mainly by the dead time (when the wind turbine is out operation) increased over time, especially in the last years of the life of the wind turbine (20 years). The major problems come from the gearbox and can threaten

safety of any wind farm totally.

The wind turbines are scheduled to maintenance mode in accordance with a relevant annual plan drawn up properly. For each wind turbine is scheduled a specific period of maintenance (in hours) and time of entry (time of year).

The Monte-Carlo simulation is a stochastic method used to calculate the appropriate indicators of reliability and operational efficiency of any power system under realistic operating conditions. A series of random scenarios of the system can created by considering the operating state of each system component and the corresponding value of the load demand of the system.

After checking the functional status of renewable plants (operating, repair and maintenance), the process for selecting renewable plants that are in operation and the allocation process of the corresponding load demand on them. To this end, developed and implemented a suitable algorithm which takes into account the characteristics of autonomous power systems.

The plants are selected properly by considering the cost of production in accordance with a priority list. The selection of plants that are in working order and setting the corresponding power output of the mind that there are always be a sufficient quantity of force which is in a situation spinning reserve to meet emergencies caused by major forced the failures of production units. This total amount of power on the system by applying the criterion of greater output value generated by operating unit of production and the satisfaction of deterministic reliability criteria (safety criteria).

However, if the analyzed system applies a different criterion determining the level of spinning reserve for whatever reasons (eg financial), this criterion may be considered by determining the relative level (eg percentage load demand). Also taken into consideration that there should be a reverse spinning reserve as if it is possible to increase wind energy production (when wind speed increases) to the system can reduce the production of conventional operating units to exploit this growth.

Finally, it is considered that the charges of identical production units of the operating stations are equal to each other so as to achieve an improved response to the primary frequency regulation of systems to potential disruptions. A production cost of conventional generating units of the system is calculated by using the respective functions for fuel consumption in relation to the produced power output.