Deregulating the electricity industry in Nigeria: Lessons from the British reform

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Socio-Economic Planning Sciences 41 (2007) 291–304 www.elsevier.com/locate/seps

Deregulating the electricity industry in Nigeria: Lessons from the British reform Marilyn Chikaodili Amobi Faculty of Management, CASS Business School, City University, 106 Bunhill Row, London EC1Y 8TZ, UK Available online 22 August 2006

Abstract The Federal Republic of Nigeria has set out the modalities for launching a competition policy regime in its electricity industry in 2006. By analysing the factors that may inhibit a smooth transition to contestable regimes in generation (commodity and capacity) and in supply (metering, billing and customer services), this paper lays the foundation for the policy advisors to begin to re-think whether unbundling and deregulation is the best way for Nigeria to improve power supply. The paper concludes that, consistent with some of the other countries in sub-Saharan Africa, implementing a hastily convened competition policy will be a huge transaction cost, and one that will yield the country very little (if any) economic benefit. r 2006 Elsevier Ltd. All rights reserved. Keywords: Competition; Deregulation; Electricity; England and Wales’ Pool; National Electric Power Authority (NEPA); Nigeria

1. Introduction The Federal Government of Nigeria (FGN) has embarked on a rapid reform of its electricity sector and is set to launch full competition in October 2006; this will be roughly 18 months after the creation of the Power Holding Company of Nigeria (PHCN) formerly the sole vertically integrated public utility: the National Electric Power Authority (NEPA). The reform will bring the country into line with some of the other countries in sub-Saharan Africa who have unbundled and introduced competition policy into their electricity industry. Nigeria needs to improve its power supply to help many of the manufacturing, agricultural and service organisations to reduce their production costs by approximately 30% [1]. However, the timetable that the Government has set out for transition to full competition may not help to attract significant foreign investments that the country needs to enable it to expand its network capacity. Drawing on the England and Wales’ experience of deregulation of electricity, this paper highlights some of the factors that Nigeria needs to consider in the transition towards deregulation, to avoid structural as well as implementation problems. Until the year 2005, NEPA, which was set up in 1972 following a merger of the Electricity Company of Nigeria and the Niger Dams Authority (NDA), had the statutory monopoly to generate, transmit, distribute and supply power to all the sectors in the economy. Table 1 summarises the main variables in the Nigerian Tel.: +44 7958707602; fax: +44 2070408546.

E-mail address: [email protected]. 0038-0121/$ - see front matter r 2006 Elsevier Ltd. All rights reserved. doi:10.1016/j.seps.2006.06.003

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electricity system. In its early years, NEPA generated 69.3% of electricity from gas; 0.5% from coal and 30.2% from hydro plants located across the country; see NEPA & NEPA Profile (see www.bpeng.org). Nigerians felt that NEPA met its role during its early years. This seemed reasonable given that its customers enjoyed reliable power supply. Put differently persistent outages and/or load shedding were rare. Most of the generation stations across the country operated; this includes the coal station in Oji, in Enugu State, which provided significant quantity of the demand in the Eastern region. Also, during those early years, NEPA had the facility and capacity to expand the density of connections to its network both on the national transmission system (NTS) and on the local distribution zones (LDZ). Moreover, clear policies for rural electrification enhanced growth in the number of customers within the LDZs. The ‘Electricity Power Sector Reform’ (EPSR) Act 2005 is the statutory document that lays out the model and framework for privatising and deregulating the electricity industry in Nigeria. The Act presents a regime that is in many ways similar to the England and Wales 1990 privatisation model. By examining the evolution of the privatised British electricity industry, Nigeria should gain insight into some of the factors that may inhibit the country from achieving the Government’s goals for privatising and deregulating its power sector. The next section examines the motivations for competition policy in Nigeria’s electricity industry and the chosen model. This is followed by Section 3, which discusses the British reform, the initial policies for generation and transmission, distribution and in supply. Also it covers how the Regulator stimulated competition in the Pool. Finally in Section 4, by drawing on the British experience, the paper considers how Nigeria can facilitate a successful transition to full retail competition. Section 5 is the conclusion. 2. The reform of the Nigerian electricity sector Why unbundle and deregulate NEPA? In the past 20 years, the FGN has struggled to finance most of its public services. The Government believes that the country will have an added macro benefit by reducing its public sector borrowing requirement, if it removes the funding of the electricity sector from its budget [2–5]. Moreover and consistent with the experience in the UK, by privatising NEPA, the FGN expects to earn income (see e.g. [6]), which it can re-direct towards the development of other sectors in the country. NEPA was renowned for its inefficiency in both service delivery and management; for that, policy advisors saw its unbundling and deregulation as a way of overcoming organisational inertia [7]. Consistent with the experience in Asia, Nigerians believe that a privatised and deregulated power sector will set the tone for the country to attract significant foreign investment as well as private equity from domestic sources into its electricity network capacity expansion [8]. This will hasten the long awaited rapid growth and development in the country. Finally, as with the experience of some of the other sub-Saharan African countries that have deregulated their electricity system, it appears that globalisation and the pressure of market vagaries, combined with those from the international donor organisations such as the Bretton Woods Institution, continue to influence energy policies in Nigeria; see [9–12]. 2.1. The proposed model in Nigeria The generic pattern for unbundling and deregulating electricity systems around the world is usually designed to: create contestable commodity regimes in generation; least cost despatch, including congestion management/capacity regimes on the transmission system. Furthermore, for the Regulator to formulate policies that will encourage the system operator to use the cheapest source of energy and/or balancing services [spinning and non-spinning reserves, reactive power, black start and regulation] to maintain the network within its acceptable tolerances: voltages, frequency responses and energy. Also, in supply, for the Regulator to formulate policies that will promote competition in metering, billing and customer services. The overriding objective in most deregulated electricity markets is to encourage all the grid users to make appropriate longterm investments (LTI) because it is the only way to ensure that the system will have sufficient capacity to meet growth in demand [13,14].

Population

Demand

150,539,700 (August 2003) access +6000 MW to power supply 35%

4500 MW [1]

Equatorial in the south; Tropical in the centre

Transmission system (5 regions)

Fuel type

Location

Hydro Coal Thermal/gas

Kainji, Jebba, Shiroro Overhead Oji Overhead Egbin (Lagos), Ugheli, Sub-stations Afam, Sapele Calabar, Kadunna, Makurdi, Mubi Maiduguri, Minna and Suleja

Diesel (Isolated stations)

Climate

High voltage

Transformers

Source: wwwbpeng.org; www.nigeriahighcommission.org

Distribution System (10 Zones)

Type

KM of lines

Low voltage

Type

KM of lines

330 kV 132 kV Type

4534 5796 Number

Overhead Overhead Sub-stations

33 kV 11 kV Type

23,753 19,226 Number

330/132 Kv

19

33/11 Kv

679

132/33/11 Kv Type

91 Total capacity

132/33/11 kV 33/0.415 Kv or 11/0.415 Kv

91 Over 20,000

330 Kv 132 kV

5526 MVA 5780 MVA

Transformers

1790

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Energy balance

Generation

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Table 1 Summary information on the Nigerian electricity industry

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In many ways, Nigeria’s proposed reform is similar to the model that England and Wales adopted in 1990, when it unbundled and deregulated the Central Electricity Generating Board (CEGB). Nigeria has set out to divide its aggregate capacity between six-generation companies [the GENCOs]; and to introduce commodity trading in generation. Under this regime, parties will engage in independent and bilateral contracting and manage all the risks that arises from that. Power Exchanges will develop. The finance sector will support the energy market by developing and offering products that will help the utility companies to plan the best ways to reduce their operation risks. There will be a non-profit making and independent system operator (ISO) [a TRANSYSCO], who will perform the dual role as a transmission owner (TO) and a system operator (SO). The TRANSYSCO will LTI decisions and maintain the security and safety of the national transmission system (NTS). There will be 11 distribution companies [the DISCOs], who will transport electricity within the local distribution zones (LDZs). Finally, the sector regulator, the Nigerian Electricity Regulatory Commission (NERC), will regulate the monopoly cable and wires business and stimulate competition, wherever possible, in generation and supply. Also, the EPSR Act 2005 includes a framework for rural electrification and ways to encourage the development of renewable generation. This suggests that the Government recognises that private firms may be reluctant to serve unprofitable rural areas; and in particular, the need to expand the density of supply given that only 35% of the population [446 local government areas out of 774] is connected to the network (see www.bpeng.org). NERC will co-ordinate the roles of a sub-regulatory institution: the Rural Electrification Agency (REA), who will develop social action plans that covers but will not be limited to schemes for dealing with fuel poverty. Where appropriate and subject to a means testing criteria, REA will set in place modalities to help the customers who cannot pay for their demand. 3. The British reform In the rest of this paper, I will discuss some of the initial policies that England and Wales adopted and then say whether the proposed reform in Nigeria will achieve the Government’s objectives. Before March 1990, the CEGB was the public utility that owned and operated the power stations as well as the NTS and managed the electricity industry in England and Wales, which was then vertically integrated up to the distribution segment. It ‘also owned pumped storage stations at Dinorwig and Ffestiniog; [which] were later transferred to a separate company in November 1995, and [then] sold to Mission in December 1995’ [15–17]. The CEGB co-ordinated a centralised schedule and dispatched all the plants across the network that it used to meet demand. It sold approximately 95% of its production to the regional area boards; and the latter distributed and supplied power within their LDZs. The CEGB also used comparative efficiency techniques to monitor the quality of service and the performance between the area boards. Summarising, the CEGB carried out two broad roles: (1) the generation and transmission of power and (2) the maintenance of efficiency standards, which it achieved by using efficiency benchmarking to stimulate competition between the regional area boards. 3.1. What happened to the CEGB? Initial policies for reforming the British electricity industry The White Paper: ‘Privatising Electricity’ (1988) stipulated the regulatory reform, and the Electricity Act 1989 provided the framework upon which the industry was privatised. Generation and supply services were separated from transmission and distribution. The generation assets were privatised, whilst the transmission assets were vested in a new utility company, the National Grid Company (NGC). The Government set up a sector regulators office, to oversee the development of policies for the efficient economic regulation of the NTS and the stimulation of competition in generation and supply. The reform in the UK was designed to (1) promote competition in generation and supply. Government expected this would happen by the entry of independent power producers (IPPs). (2) Regulate the monopoly businesses in transmission and distribution; and (3) set up a compulsory power Pool. The following section discusses the initial policies that Britain made in each of the segments and summarises the benefits that the country earned.

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3.1.1. Generation After publishing the White Paper, the Government realised that the sales valuation of the nuclear plants, which accounted for approximately 20% of the system capacity, was much lower than they were worth; consequently, it resolved in November 1989 to keep them under public ownership [18]. The Government rejected the initial proposals to create four or five generating companies from the CEGBs non-baseload capacity [19]. It decided to divide the CEGBs capacity between three private generating companies namely: National Power (NP), PowerGen (PG) and Nuclear Electric Power (NEP). The Government floated 60% of NP and PGs shares in March 1991 and sold the remaining 40% in February 1995. Scottish Power and Scottish Hydro Electric were privatised in May 1991. The two UK companies NEP and Scottish Nuclear remained in public ownership until part of it was privatised in July 1996 [15–17,20]. 3.1.2. The Pool ‘The Pool’, envisaged as a re-creation of the CEGBs computerised mechanism for centralised despatch, plant scheduling and price setting, was created in March 1990. It was an unincorporated association of all the agents’ licensed to use the Grid. These included the on-shore Generators and IPPs, plus the off-shore generators [imports from France and Scotland]. The NGC facilitated physical contracting and price setting, and no trade was done outside the Pool. A system settlement administrator (SSA) was set up to co-ordinate and process the settlements of the transactions between the Pool members. 3.1.3. Transmission, distribution and supply The NGC was the fourth company created at vesting; it was given the statutory right to serve as the nonprofit making ISO. It was the only utility licensed to operate the NTS with the 12 Regional Electricity Companies (RECs) serving as joint owners of the Grid. NGC transported power at high voltages from the Generators to the LDZs and also to the large consumers directly connected to the NTS. It also coordinated all the interconnector flows between England, Scotland and France. There was a Grid Code and a Master Connection Use of System Agreement (MCUSA). These documents plus the condition 12 of the NGCs licence set out its security standards. As well as that, all the parties to the MCUSA were compelled to adhere strictly to the provisions of the Grid Code [21]. In the LDZs, policy initiatives were focused on encouraging and developing entry of multiple but privately owned companies [22]. The RECs were allowed to diversify into other industry segments including generation. The RECs shares were floated on the Stock Exchange in December 1990, but they remained monopoly distribution companies within their LDZs. To enhance transparency whilst curtailing cross-subsidisation, they operated separate accounts for their monopoly and competitive businesses. The reform which was designed to enhance efficient competition provided for two types of supply licences: (1) Public Electricity Supply (PES), which allowed a supplier to ‘own and operate local distribution networks, as well as having an obligation to supply customers within an authorised area equal to their distribution network’. (2) ‘Second-tier’ licences, which allowed the authorised licensees to supply the premises that were located in the authorised area of a PES licence. ‘Suppliers of electricity to final consumers [were] exempt from licensing if they owned a generator and supplied customers [who] consumed less than 500 kW, or if all supply counted as ‘on-site’ [‘situated on the same site as the generation station’] [21]. The ‘White Paper’ provided for full retail competition to be phased; and it was structured over 8 years: in 1990, 1994 and 1998 [23]. The first phase occurred in 1990: approximately 50,000 customers who consumed more than 1 MW of power were allowed to choose a supplier from any of the RECs. These customers were usually metered sites that had load profiles. The second phase began in 1994 and customers who consumed approximately 100 kW of electricity got the right to choose their supplier. As the privatised industry evolved, Littlechild [22] pointed out that it became clear that a smooth transition to full competition could only be achieved by close surveillance of the market operations. Based on that, the Regulator modified some aspects of the rules that were adopted in 1990. These modifications covered issues such as setting Codes of Service; how utility firms dealt with customer complaints, metering, metre reading and profiling and guidelines on the separation and allocation of costs, particularly those that related to

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common services as well as to those for the regulated and competitive businesses of the companies; see also [12,24]. All the initiatives discussed above influenced the evolution of price and capacity patterns plus the regulatory policies in the industry between April 1990 and June 1999, when full competition was implemented; and when over 26 million retail consumers—predominantly households that consumed less than 100 kW—were free to choose their own suppliers. 3.2. Result of the privatisation It is widely believed that England and Wales earned significant efficiency savings from privatising its electricity industry. Armstrong et al. [6] records that the British Government made over £13 billion (p. 301). Littlechild [22] reported that by the beginning of 2001, England and Wales had achieved most of the objectives that its Government had set out for privatising its industry: wholesale costs had decreased from 25% to 35%; there was an increase of approximately 50% in annual network investment and roughly a 50% decrease in the average minutes lost on the system. In addition, the number of complaints that customers made had been reduced by about 60%. In generation, the largest company share had decreased from 48% to 12%. The share of the market that NP and PG controlled had decreased from 78% to 26% and the number of times that they set the system marginal price (SMP) had been reduced from 90% to 41%. By the beginning of 2001, wholesale prices had decreased by approximately 40%; the quality of service had improved and the utility firms had begun to offer their consumers wider choices of products and services [20,25]. But it is worth noting that the industrial consumers benefited more from the privatisation than their retail counterparts [26]. This was because these large consumers, who were usually metered sites, could enjoy the economies of bulk purchasing. Nigeria can learn a number of things from the UK, which will enable it to deal with the challenges of a deregulated market. However, there are initial problems as well as ‘unique’ situations that are critical to Nigeria, which do not exist in the UK. For example, compared to Britain, macro economic policies in Nigeria are designed to reflect ‘federal character’ [equitable representation of all the geo-political zones in the country] Nigerians expect that Government will use federal character to decide, for example the location of plants, system operations, recruitment of human resources, governance and social action plans. It is not clear how policy advisors can develop robust federal character-underlying regimes; but the following section discusses both the lessons from the UK as well as the initial problems in Nigeria. 4. Lessons for Nigeria from the British experience The main objective for unbundling and deregulating the electricity industry in Nigeria is to increase network capacity and to reduce resource waste by making the managers more efficient. However, there are a number of issues and potential problems which the FGN needs to carefully examine and resolve to ensure that the country can have a smooth transition to a fully working market which can achieve most (if not all) of the Government’s objectives. In this section, I will in turn discuss some of these and where appropriate, draw comparisons with the British experience. 4.1. Lack of generation and transmission capacity Currently, Nigeria generates between 3500 MW and 4000 MW but needs approximately 6000 MW. The current transmission system can only support transportation of 3000 MW; whilst the distribution network is inadequate [27]. With regards to network capacity expansion, the country needs approximately $3.2bn for generation; $1.5bn for transmission and $4.5bn for distribution; that is, Nigeria needs a modest estimate of $9.2bn to revive its electricity system [28]. The Government is funding the construction of some gas-fired generating plants, most of which are located in the south western part of the country. These plants are scheduled to come on-line in 2007; but there may not be enough transmission infrastructure to take advantage of this additional generation capacity. Given this scenario, it is not clear what the Power Exchanges will trade, if full trading starts in October 2006. It is very unlikely that the market will be liquid anyway.

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Price

Relationship between Price & Reserve Margin

SRC 0

1

RM

(%) Fig. 1. Relationship between price and reserve margin.

Fig. 1 illustrates the downward sloping relationship between Price and Reserve Margin. It shows that price decreases (increases) with increases (decreases) in reserve margin. Whenever the reserve margin is close to zero and possibly below, price can take astronomical values [29,30]. In the past 20 years, Nigeria has seen a rapid reduction in its network capacity and a huge growth in demand. Given the huge deviation between demand and available capacity in the country, it is reasonable to assume that the current level of Reserve Margin in Nigeria is zero; or rather negative. NERC must introduce price cap if it expects the population to be in a position to afford the market prices. 4.2. Emergence of efficient competition Once Nigeria vests the new market, the three factors that will influence the emergence of its price and capacity patterns are: (i) transitory arrangements, (ii) capacity mix and (iii) equitable entry along the load duration curve (LDC). 4.2.1. Transitory arrangements The first few years in any industry reform is usually a steep learning curve for all the players; see [31,32]. In the UK, the Government sold off NP and PG in fully contracted positions both for sales as well as coal input. They set up two-way, 3- and 5-year contracts called ‘initial portfolio’ (IP) between NP and PG and the RECs in 1990 and 1993. These contracts, which ‘were purely financial contracts, resembled options and cash-settled futures contracts’ [33, p. 445], and were structured as take-or-pay agreements against British Coal, with the strike prices based on an estimate of the Generators’ costs [34]. The IPs helped to reduce the utility firms’ exposure to the volatile spot market prices. Although this arrangement inhibited the assessment of the progress of competition during those early days [35,36]; it protected the coal industry which was undergoing a downturn at the time the market was vested. Nigeria must set in place initiatives that will enable the electricity firms to smoothly transit into the new regime. In doing so, policy advisors have to focus on formulating the strategies that will help the industry participants’ to reduce their risks. Electricity trading is all about strategy [37,38]. The industry participants: generators, suppliers and traders, are in business to maximise their profits. Given the industry structure plus the features of electricity that inhibits the application of the theoretical economics model of free market mechanism [7], one can conjecture at this stage that NERC will have tremendous difficulty steering forward contestable regimes in generation (see [10,19,22,36,38,42]). Government should consider finding a long term solution to the challenges that may inhibit the deregulation process. It is sensible to assume that the ways by which the electricity firms can remain in business to carry on their licence conditions should supersede the implementation of excessive ideology; see [39].

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4.2.2. Capacity mix and its distribution between the generators The vertical and horizontal structure that will emerge in Nigeria’s proposed electricity market will depend on (i) the ownership of the marginal plant and (ii) the rules that the country adopts for setting price and capacity. As well as these, the idea of reflecting ‘federal character’ in all aspects of system operations may mean that the TRANSYSCO may incur higher than normal costs to keep the network within its balanced tolerances. England and Wales did not handle the division of the marginal plants properly in its initial policy for vesting the market in 1990 [40]. Also, in 1991, when the Regulator identified that efficient competition might not be achieved within the duopoly structure created in 1990 [34], it delayed unduly the decision to divest NP and PGs mid-merit plants. In Nigeria, none of the six GENCOs should be allowed to own the whole of the marginal plant(s), instead it should be divided equally between them. Given the current huge deviation between demand and available capacity, this approach will ensure that no single GENCO will wield considerable monopoly power. It may therefore, be possible to restrain the otherwise higher prices that I have already shown in Fig. 1, which may dominate the market after October 2006 [41]. Most of the transactions in electricity markets are based on forward contracting. Market participants use forward and futures contracts to lock in their physical deliveries at specified [strike] prices. This helps them to curtail their operations and volumetric risks, and allows them to plan, based on the agreed prices. Nigeria can help to create contestable regimes in generation, if it sets up an effective bilateral financial market that will offer the utility firms very liquid instruments. The UK achieved this by having a bilateral contract market that complimented the Pool. The market offered two main products: long-term contracts for differences (CfDs) and short-term electricity futures agreements (EfAs). Compared to the EfAs, the Generators used the CfDs to hedge over 80% of their physical deliveries [42,43]. Newberry [44] finds that this market was the ‘contestable’ segment in the regime. For a discussion on the theory of contestable markets, see [45–48]. Apart from just setting up the bilateral financial market, NERC should create incentives that will encourage the Generators to lock in a significant proportion of their physical deliveries in long-term contracts. If this is achieved, the Generators will have no incentive to manipulate spot market prices [33]. If it is assumed that the foreign and private investor confidence will improve as the market evolves in Nigeria, then a strong threat of entry will also help to restrain high spot prices; see [44]. In the UK and in some of the other industrialised economies, the capital market restores the inefficiency that the product market creates [49]. The Regulator also uses comparative firms from the Stock Market to calculate the cost of capital for the regulated companies [6]. Nigeria has one of the most active and developed stock markets in West Africa. If this market is as efficient as economics theory postulates [17], information about the electricity companies will be incorporated instantaneously into their share prices. Furthermore, the threat of take-overs will encourage the managers’ to act in the best interest of their firms; in particular, they would always find ways to reduce the operating costs that they can control [49]. As long as the Nigerian Stock Exchange (NSE) has the right information technology, is sufficiently autonomous and its processes are transparent, it can wield great support to the electricity market. 4.2.3. Equitable entry along the load duration curve (LDC) Apart from Sizewell B and the capacity upgrade to the Scottish Interconnector, most of the new capacity that came on-line in the UK during the 1990s was combined cycle gas turbines (CCGTs) [A type of generating plant in which turbines, typically fuelled by gas-oil, are used to drive generators to produce electricity] [50]. Most of these plants were initially built to operate as baseloads. This was because the Generators had longterm take-or-pay gas contracts with associated ‘off-take’ agreements, which in some cases, lasted for more than 15 years [35]. In addition, institutions that financed the assets required the Generators to operate their plants at over 80% of their load factors [15,16,35]. By the mid 1990s, these lenders began to relax most of the conditions that they had placed on the gas-fired plants. It became possible for them to operate on a two-shift basis and at 50% of their load factors. This paved the way for them to move up the LDC into mid-merit [35]. But the rule for setting the commodity-clearing

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price [the system marginal price (SMP)], which enabled a Generator to earn a higher price that a marginal plant had set prevented them from changing the configuration of their plants. This confirms that price setting in the Pool was all about strategy, had absolutely nothing to do with the cost of production and strengthens the fact that efficient competition could never have materialised in the Pool. 4.2.4. What about the prospects for debt financing for electricity firms in Nigeria? One of the objectives of the proposed reform is to increase efficiency in service delivery in the industry and at affordable prices to the consumers. Investment in generating plants is one of the most expensive decisions that firms in the new market will make. On average, small combined cycle gas turbines of approximately 200 MW–300 MW can take up to 3 years to construct; and the repayment of the borrowed capital can be made over 20 or more years. However, past experience in the banking sector in Nigeria indicates that this kind of long-term money does not exist. Compared to Europe and indeed many of the other industrialised economies, the lending rates in Nigeria are very high. Loan syndication may be one way by which the large banks such as First Bank, Union Bank, and United Bank for Africa (UBA) may pool together the huge finance the industry will need. Apart from this, it will help them to diversify their portfolio risks [51]. Electricity companies in Nigeria will pass on all the added operational costs to the final consumers. If the cost of debt is high, it will worsen the high prices that I have suggested would dominate the new market. In which case, the possibility of the final consumers affording their demand in the new regime will be even worse. It is possible that policy advisors before contemplating the reform did not consider that the long-term existence of the utility firms will depend on the consumers’ ability to pay the post privatisation tariff [52]. Whatever the case, a way forward could be for the Government to plan a phased withdrawal of the subsidised rates that Nigerians currently pay for electricity. Under this initiative, the Government can make lump sum payments directly to the electricity companies. This arrangement should guarantee that the utilities remain in business to meet their licence conditions and meet all the reasonable demands that the different categories of customers may make. The FGN could also set in place concessionary sectoral lending policies for the electricity industry. It will also be very useful if the Government sets out a ‘pot’ of accessible funds for the electricity firms which the Central Bank of Nigeria (CBN) and/or any other designated financial institutions can administer. 4.3. Absence from the international bond market A country’s sovereign credit rating (SCR) in the international bond market influences the foreign investment that it attracts [53–55]. Nigeria is not an active participant in the international bond market. Currently, Nigeria has found no solution to its weak civil society, poor macro economic indices and unstable socio-political environment. Given that rating agencies all over the world use these variables to calculate countries SCR, investors may consider Nigeria a very high risk [56,57]. It may be difficult for the country to attract the level of foreign investment that it needs to develop its electricity network; in which case, the Government may not achieve one of the objectives that it had set out for reforming the industry. One option would be for the Government to follow a staged process to reinforce and extend parts of the present network. This project should include metering of all the consumers that are already connected to the network. A bottom-up approach that starts from the eleven designated LDZs in the country might be the way to begin. Combined Heat and Power (CHP) and renewable generation are best located in the distribution zones [58]. Strengthening the LDZs should include schemes to develop renewable generation and CHPs. The threshold that Nigeria has set for licensing may mean that some CHPs may be caught under the licensing regimes. Once the structure for developing capacity within the LDZs is set up, increases in demand will signal further extension and reinforcement of the distribution network [59]. The policy, which the Government adopts for LTI should not be based on the ‘federal character’ principle. For example, the best policy would be to locate generation plants closer to demand and if it is more economic to do so, then to locate them closer to the source of fuel. If the latter, to ensure that sufficient investments are made to provide appropriate infrastructure that will be required to transport electricity from the generation points to high demand areas. If this is achieved, reduction in thermal losses combined with increased efficiency in transmission and distribution will follow.

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Finally, the Government can put in place modalities to use benchmarking technique(s) to stimulate competition between the 11 LDZs [60]. The second phase in this staged process would be to reinforce the NTS. Assuming that the first phase of this staged process is successful, the country would have created the environment that should encourage foreign investment since investors may have confidence that they are buying into a system that works. 4.4. Corruption Corruption has inhibited economic growth and development in economies across the World. Mauro [61] finds that the effect of corruption is more severe in the developing than in the developed countries; see also [62–67]. Bribery and corruption are endemic in Nigeria. Moreover, the opulence with which highly placed citizens’ demand and take bribes make this the fourth factor of production [68–70]. Firms usually incur higher operating costs in Nigeria than in other developing countries, such as Asia and South America. So the threat of criminal prosecution against firms that give and/or accept bribes may prevent potential foreign energy utilities from entering the Nigerian market. This could mean that Nigeria may have difficulty in attracting the best electricity firms in the world. 4.5. The spot market Electricity trading is a two-stage game [71]. Traders set the capacity in stage 1 and price in stage 2; the latter occurs in the market and this is where demand is realised. Consistent with the theory of the behaviour of firms in oligopoly markets [72,73], the Generators in the Nigerian market will probably use their supply functions to manipulate price [45,74]. In the UK, NP and PG started to manipulate Pool prices right from the 1st year of the regime [36,40,75]. The Regulator conducted several inquiries and made reference to the Competition Commission (CC) [formerly the Monopolies and Mergers Commission] about the cause of high prices in the Pool [34,76]. The Regulator used limit pricing, close market surveillance; persuasive control [77] and the forced divestment of capacities [34,78] to restrain NP and PG from keeping prices above competitive levels. Finally, in 1998, having shown that efficient competition could not be achieved in the Pool [75], the Regulator published its initial thoughts on the possible model for trading outside the Pool and implemented the new electricity trading arrangement (NETA) in March 2001. In Nigeria, NERC should be aware that Betrand competition and therefore marginal cost (MC) pricing may not materialise in the new market. I have already discussed the price levels that might prevail in the new market. NERC should consider introducing price caps as it may be a way to ensure that the electricity firms will charge the consumers what they can afford. Furthermore, NERC should also be prepared to align commodity and capacity regimes to the challenges that the new market will face as it evolves. This means that consistent with the UK, the regulatory oversight on the new market should behave like a price mechanism. 4.5.1. What about the economic regulation of the monopoly cable and wires utilities? In the UK, economic regulation was focused on minimising the transportation costs. The Regulator used an incentive regulatory tool [the Retail Price Index (RPI) minus an ‘X’ efficiency rate], to control the transmission and distribution tariffs. Under this regime, the Regulator set an efficiency rate (‘X’); and the utilities kept the difference between this allowed benchmark and their actual costs. This approach encouraged the utility firms to use best practices to curtail the operating costs, which they could control [6,46,79]. The Regulator re-set the ‘X’ efficiency between periods. In doing this, the Regulator considered the estimates of the growth in demand and productivity levels; value of existing assets and the assessment of the progress that had been made in developing competition. The RECs were regional monopolies and they might have had differences in their cost structures. Nonetheless, Armstrong et al. [6] notes that the Regulator did not incorporate yardstick elements when setting the ‘X’; however, this issue might have been recognised during the price reviews. Merely setting ‘X’ was not sufficient to ensure that the regulated utilities maintained the quality of their services. This was where setting

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Table 2 Price controls in England and Wales (Oxera, 1999:71) Sector

Company

Period

Control

Transmission

NGC

1990–1993 1993–1997 1997–1998 1998–2001

RPI-0 RPI-3 RPI-20 RPI-4

Distribution

RECs

1990–1995 1995–1996 1996–1997 1997–2000

RPI+0–2.5 RPI-11; -14 or -17 RPI-10; -11 or -13 RPI-3

Supply

RECs

1990–1994 1994–1998 1998–1999 1999–2000

RPI-0+Y RPI-2+Y RPI-6 RPI-3

the service standards and the guidelines for enforcing breach of contractual agreements, which the Regulator put in place, became important. Table 2 shows that the Regulator increased the ‘X’ as competition developed. This suggests that utility firms were expected to do everything in their power to devise ways to reduce operating costs. The RECs were allowed to pass on 95% of the cost for wholesale purchases (transmission and distribution charges and fossil fuel levy), denoted by ‘Y’ in Table 2, to their captive consumers. This meant that the Regulator controlled only 5% of their costs [6]. Byatt [80] pointed out that the incentive regulation was a great success in the network utilities in Britain. In electricity, Green [81] notes that by 1998/1999, the incentive-based regulation had resulted in a 0.9% reduction in the cost of transmission and distribution from a 10% level in 1991/1992 (p. 10). 4.6. Human resource capacity In UK, the Regulator faced enormous challenges and devised ways to deal with issues such as crosssubsidisation, economic purchasing, monopoly power, price discrimination and refusal to supply [35]. Nigeria needs knowledgeable professionals who will formulate policies [technical, engineering and economics] for the successful interaction between the legislative, regulatory, contractual regimes and the related groups, in its proposed new electricity market. From discussion with senior managers and policy makers, it is clear that Nigeria will need to increase the number of experts who will contribute to the policies for the efficient performance of the deregulated electricity market. A significant proportion of the existing staff will be laid off once the private firms take over the industry. Some of these people are too young to retire; but too old to start new careers. They will need to be retrained to have the skills to work in the new market. But again, these people and in some cases the organisations they currently work for, have financial constraints, therefore, they cannot afford to finance the type of training that they will need to regain employment in the new market. It is likely that the Government and private firms may look to recruit management experts from abroad. The Government needs to address the increase in the rate of unemployment as well as the associated negative effects that will follow post deregulation. This should provoke policy initiatives that should guarantee a stable social structure in the new regime. This is important, given the cultural setting in the country, which is based on an extended social family structure. It is reasonable to make a modest assumption that an employed person is a proxy and a source of subsistence for an average of 10 others. This scenario suggests that the knock-on effect of the huge labour lay-offs will include an increase in the number of the population that will engage in anti-social behaviour. It is reasonable to expect a large erosion of the fragile social capital in the country; this situation will influence the success of the regulatory reform.

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The FGN should focus on doing much more than just agreeing higher severance benefits for the staff that they will lay off from PHCN. Instead, they should set up a rapid programme to re-train these personnel, so that they can be reabsorbed into the new market. This is sensible given that whatever severance benefits they will receive will be exhausted over time. Once this happens, some of them may resort to criminal activities to enable then meet their daily needs. 5. Conclusion This paper has shown that consistent with the experience in some of the other countries in sub-Saharan Africa [82,83] merely launching a fully competitive market with commodity trading in Nigeria in 2006 may not significantly improve power supply or increase efficiency. NEPA delivered services inefficiently in the past, and it is unlikely that a deregulation on its own will create a more efficient electricity system. Nigeria may face similar challenges that England and Wales encountered in the evolution of its electricity market. Unfortunately, the problems in Nigeria could be much worse than the problems that the UK encountered. Nigeria has a number of other factors which are likely to amplify some of the previous problems in the British deregulation; that is, amongst other socio-political and macroeconomics issues, the lack of sufficient generation and transmission capacity and human resource experts, as well as a relatively weak institutional environment may have a negative impact on the success of its market reform. The Nigerian electricity market, just like the others in most economies, was not built as a market place. Policy advisors should not expect the type of competition policy that they think has worked in the Nigerian telecommunications industry to deliver comparable gains when applied to the electricity system [84,85]. They should understand that some of the peculiar characteristics of electricity make it difficult to trade it like other commodities. This makes efficient competition impossible to achieve in electricity markets. The underlying structural problem with insufficient generation and transmission capacity, will most likely persist for a long time after deregulation, and would make the efficient operation of a market-based system very difficult. Finally, one might raise the issue of what the ‘optimal’ time for deregulation and privatisation may be for the Nigerian electricity sector and what should determine this. Given the potential problems and issues that this paper has discussed, which are common in sub-Saharan Africa (see [86]), many of the underlying problems that would inhibit a successful competition policy regime, will need to be resolved before Nigeria implements an efficient deregulation model. It may be easier to resolve some of these problems whilst the sector is still under Government control. This suggests that there could be a potential conflict between the political desire for a speedy deregulation and the need to solve fundamental problems in the sector; the latter of which is likely to take much longer. It should also be clear that the state of the sector will clearly influence the Governments sale price for the unbundled segments, as well as the likelihood that private investors will find it attractive to invest. Acknowledgements The author acknowledges the support and guidance of Erik Larsen; the comments from an anonymous referee; Emeka Okongwu; Ann van Ackere; Margaret Busgith and the participants at the Energy Workshop: Deregulation and Competition in the Electricity Sector: Learning from the past and looking into the future, which was held at CASS Business School, London in July 2004. Any errors remain her own. References [1] Peel M. Reviving industry: power to the people in Nigeria. Financial Times 2005:14. [2] Due J. Privatisation in Tanzania and Zambia. World Development 1993;21(12):1981–8. [3] Gibbon P, Bangura Y, Obstad A, editors. Authoritarianism, democracy and adjustment. Uppsala: Scandinavian Institute of African Studies; 1992. [4] Harrigan J, Mosley P, Toye J. Aid and power: the World Bank and policy-based lending. London: Routledge; 1991. [5] Plane P. Productive efficiency of public enterprises; a macroeconomic analysis based on cross-section estimation of a neo-classical production function. Applied Economics 1992;24:833–44.

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Marilyn C. Amobi is Visiting Lecturer at the Faculty of Management, CASS Business School, City University, London, UK; and Managing Partner, Emergent Solutions Limited (ESL), a multi-national economics, management and consulting network. She earned her B.Sc., in Economics from the University of Nigeria Nsukka, M.Sc., in Economic Regulation and Competition from the Department of Economics, City University, London, and Ph.D. in Economics from CASS Business School, London. Following the award of her M.Sc., she worked in the Competition and Trading Arrangements Directorate at the energy regulators office: Office of Gas and Electricity Markets (OFGEM). Dr. Amobi focuses on empirical research that have relevance to policy development in deregulated energy markets.