Balancing the Acts in the Power Sector: The Unfolding Story of Nigeria Independent Power Projects1

A. O. Adegbulugbe2, A. S. Momodu3, A. Adenikinju4, J-F. Akinbami5 & P. O. Onuvae6

AbstractThe Nigeria power sector has been faced with seemingly intractable problems for some decades. In resolving

these problems, the sector has been undergoing reforms since 1999. Presently, the major ‘discernible’ features of the reform process include: unbundling and corporatizing/privatizing the state utility; additions to capacity at all levels of the network; establishment of an independent regulator, and private sector participation. All of these aspects of the reform are in various stages and phases of advancement. It is planned that with the reforms in place, by 2010, Nigeria would have more than tripled its present installed capacity from 6,000 to about 23,000 MW. One of the responses to the reform program to facilitate the expansion targets is the involvement of power project developers in the form of independent power plants (IPP). Two IPPs are already operating in the country accounting for about 20% of the national monthly electricity generation and 25% of total revenue collected in the sector. Others are in various stages of development.

1 Acknowledgments: The authors thank Erik Woodhouse, David Victor and Thomas Heller, for insights into the research methodology and findings. Special thanks go to each of the organizations that provided interviews. Any errors and omissions are the responsibility of the authors. 2 Anthony Olusegun Adegbulugbe is a Professor of Energy Planning and Management. He holds a DSc degree from the Massachusetts Institute of Technology, Cambridge, USA. He also obtained a first class degree from the University of Ife (now Obafemi Awolowo University), Ile-Ife, Nigeria. He has contributed to well over sixty academic papers to various national and international journals. He also has served as lead author and coordinating lead author for the Intergovernmental Panel on Climate Change (IPCC). He was a member of the Expert Group on Technology Transfer of the UN Framework for Climate Change. Prof Adegbulugbe is also a member of various national and international organizations such as Nigeria Society of Engineers, International Association of Energy Economics, etc. He currently chairs various national and regional energy and energy-related agencies such as National Multi-sectoral Energy Access Committee, ECOWAS Regional Multi-sectoral Energy Access Committee, Gas to Power World Bank Assisted Project – etc. He is also the Alternate Chairman, Nigerian Nuclear Regulatory Authority (NNRA). Professor Adegbulugbe is presently the Special Adviser to the President on Energy Matters. Current contact address: Special Adviser to the President on Energy Matters, Floor 9, Block D, NNPC Towers, Abuja. Tel/Fax: +234-9-234-8025; Email: anthony_adegbulugbe@yahoo.co.uk3 Abiodun S. Momodu is currently a Research Assistant at the Centre for Energy Research and Development, Obafemi Awolowo University, Ile-Ife. He is the lead researcher in the study carried out on Nigeria IPP Experiences. He is a PhD candidate at the Technology Planning and Development Unit of the Obafemi Awolowo University, Ile-Ife, Nigeria. His studies and research interest focus on the reforms and regulations in the emerging electricity market of Nigeria. Abiodun has carried out studies related to bio-energy and environmental interactions, with emphasis on the forestry sector, as it affects greenhouse gas emissions in developing countries. Abiodun is currently serving as Technical Assistant to the Special Advisor to the President on Energy Matters. He holds a Master’s degree in Technology Management from Obafemi Awolowo University, Ile-Ife, Nigeria. He is a member of Nigerian Association of Energy Economics and an affiliate member of International Association of Energy Economics. Current contact address: Centre for Energy Research and Development, Obafemi Awolowo University, Ile-Ife, Nigeria. Mobile: +234-806-972-5417; Fax: + 234-9-234-8025; Email: cenedudev@yahoo.com4 Adeola Adenikinju is a holder of a Ph.D Degree in Economics from the University of Ibadan, Nigeria. Adeola is currently an Associate Professor in the same Department. He is also a Senior Research Fellow, at the Centre for Econometrics and Allied Research, Senior Research Fellow, Trade Policy, Research and Training Programme as well as Senior Research Fellow, Macroeconomic Study Group, all at the University of Ibadan. Adeola has consulted for such organizations as the European Union, United Nations, the Nigeria Liquefied Natural Gas Company, NLNG, The African Economic Research Consortium, OECD, UNIDO and the National Data Bank, among others. He was one of the Consultants that prepared the First Perspective Plan for Nigeria. He is also involved in the United Nations Project Link that makes economic projection for the Nigerian Economy. Adeola was a Visiting Scholar to the International Monetary Fund (IMF) in 1996 and 2005. His research interests include Petroleum and Energy Economics, Macroeconomic modeling, and Economic Development Issues. He is a member of Nigerian Association of Energy Economics and an affiliate member of International Association of Energy Economics. Adeola is presently on Leave of Absence from the University to serve as a Special Assistant to the Presidential Adviser on Energy Matters. Department of Economics, University of Ibadan, +234-802-344-0018, adeolaadenikinju@yahoo.com 5 J-F.K. Akinbami, PhD – is a Principal Research Fellow (Associate Professor) at the Centre for Energy Research and Development, Obafemi Awolowo University, Ile-Ife, Nigeria. Dr Akinbami’s research focus includes Energy and Environmental Management; Energy Systems Modeling, Energy Policy and Analysis, Electricity Sector Reform, Restructuring and Regulation, Alternative Energy Resources, Sustainable Development and Climate Change Study. He has published extensively in reputable local and international journals including amongst others International Journal of Global Energy Issues, Mitigation and Adaptation Strategies for Global Change, Renewable and Sustainable Energy Reviews, Applied Energy, Natural Resources Forum, Renewable Energy, Transport Policy, Environmental Management. He was also a resource person/consultant on various study projects for both national and international organizations including European Commission, African Development Bank, World Bank, Nigeria National Planning Commission, Energy Commission of Nigeria, Canadian International Development Agency (CIDA), and United Nations Industrial Development Organization (UNIDO). He was actively involved in the development and preparation of a Renewable Energy Master Plan for Nigeria and is also involved in the on-going development of a National Energy Master Plan for Nigeria. Dr Akinbami is presently consulting for the Power Holding Company of Nigeria (PHCN) on the Rural Access and Renewable Energy component of the World Bank funded project, National Energy Development Project (NEDP). He is a member of Nigerian Association of Energy Economics and an affiliate member of International Association of Energy Economics. Centre for Energy R and D, Obafemi Awolowo University, Ile-Ife, +234-803-719-5198, akinbami_jfk@yahoo.com 6 Precious Osamede Onuvae is a postgraduate student of Economics at the University of Abuja, Nigeria. She has previous work experience at the World Bank Country Office, Nigeria as a Research Assistant. She currently works as Administrative Assistant at the Gas-To-Power (G2P) World Bank Assisted Project. Precious’ study and research focus is in the area of public sector development with emphasis on power sector reform.Current contact address: World Bank Assisted Gas to Power Integrated Project, Plot 1393, Justice Mamman Nassir Street, Asokoro, Abuja. Tel: +234-9-3143646; Mobile: +234-806-336-1065; Fax: +234-9-3143647; Email: preciousiscrown@yahoo.com

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This study is therefore geared towards understanding IPP experiences so far in Nigeria. One of the aims of the study was to benchmark the performances of the IPPs against the publicly owned power plants; and to also note the lessons that can be learned from and possible challenges to their performance experiences. This will help to know the best practices to scaling up the IPP participation in both immediate and far future in the national electric power industry.

The methodology adopted for this analysis was developed primarily for the analysis of country and project performance in power development outcomes in developing countries and it has also been used for quite a number of developing countries. This involved analyzing the determining factors that influence outcomes referred to as Contributing Elements to Success (CES). The CES are a list of factors relating independent variables which inclusion/exclusion improves the probability of success of IPP projects. Results of the analysis revealed that the existing IPPs are: providing much needed electric power in the country; providing an important model and outlet for the Nigerian Natural Gas Strategy which seeks to eliminate gas flaring by 2008; paving the way for the private sector participation in the power sector especially the generation sub-sector; and accentuating the need for more robust PPAs that will take into consideration the desires and aspirations of all the stakeholders involved in the sector.

Keywords: Power sector, reform, IPP, PPA, gas flare, Nigeria

1. IntroductionAt the inception of the new civilian administration in 1999, Nigeria was confronted with issues

that could be narrowed down to four broad areas of control and management of available resources (both human and natural), governance and development. One of the subsets of these issues was the seeming intractable problem of providing adequate, affordable and reliable electricity supply to drive development. In other to respond to this problem, the administration embarked upon a program of reform in the power sector. To underscore the importance attached to the sector as it affects national economic development, a total of over N526 billion (about US$4.05 billion) was allocated to the sector in the past eight years. Currently, Nigeria has among the most ambitious power sector reform programs on the African continent, with full-scale privatization efforts for generation and distribution underway. The goal is greater efficiency, increased capacity and to achieve a better environmental track-record through reduction or elimination of wanton wastages of gas flare from the production terrain.

Independent Power Projects7 (IPPs) are part of the country’s reform program and an in depth understanding of the existing projects will help inform critical decisions about Nigeria’s electricity future. One of the core purposes of the reform was the need to introduce private sector participation into the power sector, particularly in generation through IPPs. The reasons for this are two-fold. On the one hand multilateral agencies, once among the largest sources of external financing to the sector prior to 1999, indicated their exit to pave the way for more private sector financing. On the other hand, the civilian government of Olusegun Obasanjo, which replaced a military dictatorship, at the end of the 1990s, prioritized both the expansion and the operational improvement of the electricity sector. At the time, less than 40% of the population had access to electricity, and those that did have access suffered from poor quality supply, with back-up generators owned by the majority of businesses. Furthermore, in 1990, it was recorded that only 37% of the total installed capacity was actually in operation (or just over 2,000 MW of the total 6,000 MW installed). Linked to these priorities to improve and increase supply has been a large-scale gas flaring reduction initiative, which requires oil companies operating in Nigeria to build power plants and use previously flared gas, as well as a specific effort to improve infrastructure in the communities of the Niger Delta, from which most of the country’s oil wealth originates.

Presently, two IPPs (referred to as IPP A and IPP B respectively) account for about 20% of the country’s capacity of the grid electricity. The first, which had an initial 9 units of 30 MW each (with total capacity of 270 MW), open cycle gas turbine, was initially invested into by an American energy company, which later sold its shares to another American owned energy company and a local Nigerian firm, is presently undergoing contract renegotiations. The second IPP, a 450 MW combined cycle gas turbine, built by a consortium comprised of international oil companies and the Nigeria national corporation in charge of oil and gas issues, has also encountered some difficulties, related to the escalation of its initial investment cost (IIC). Both plants have, however, made a significant contribution to supply. By 2010, Nigeria aims to nearly triple its installed capacity (from the present 6,700 MW to about 23,000 MW). Private sector

7 For proprietary and confidentiality reasons, the IPPs are not mentioned by names.

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involvement is currently being assessed at all levels and forms to help achieve these expansion targets, with IPPs among the most probable candidate for increasing capacity.

The study was geared towards understanding IPP experiences in Nigeria8. Of primary importance is how development outcomes, namely the extent to which quality, affordable power has been supplied, balance with investment outcomes, the degree to which IPP firms achieved expected returns and have been able to expand market share. This analysis involves determining the chief factors that influence outcomes (referred to as contributing elements to success, CES), such as the state of the general investment climate and the electricity market, the role of project partners and availability of project finance. The CES are a list of factors relating independent variables, whose inclusion/exclusion improves the probability of success of IPP projects. These elements have not been imposed uniformly or mechanistically on the data; instead they have emerged from in depth consultations to developed and on-going projects in the country. The elements have subsequently been grouped into two categories: with seven elements primarily under the purview of the host country stakeholders/government; and nine elements controlled by project sponsors. These elements are listed, in order of priority, in Table 1 and discussed further in Section 5.2.

Table 1: Contributing Elements to SuccessNo Host-country issues Project issues1 Favorable investment climate Favorable equity arrangements2 Clear policy framework Favorable debt arrangement3 Clear, consistent and fair regulatory oversight Secure and adequate revenue stream4 Coherent power sector planning Fuel type and agreement5 Competitive bidding practices Project management6 Abundant low cost fuel Positive political and public perception7 Part of a larger infrastructure development Smaller % of IPP/generation8 - Higher costs risks are borne by government9 - Hybrid firm

The study was based on an inductive research approach. Researchers began by culling all relevant policy documents and then engaged each of the key stakeholders in an in depth discussion to probe the question of outcomes and relevant factors. Information gathered from individual interviews9 was then confirmed across the range of stakeholders and secondary source data, before researchers reached conclusions.

2. ESI overview & power sector reform

Nigeria began the overhaul of its electricity supply industry (ESI) since 1999. Major objectives of the overhauling process include: unbundling the state utility National Electric Power Authority (NEPA) into six privately owned generation companies, one transmission company, and eleven distribution companies; additions to capacity at all levels of the network; and the establishment of an independent regulator. Of these objectives, the unbundling of the utility has been partially achieved.

Two months after the passage of Electric Power Sector Reform Act, EPSRA in March 2005 the assets of NEPA came under control of the Power Holding Company of Nigeria (PHCN). 10 PHCN was charged with preparing 18 successor companies for independent commercial operation and ultimately privatization. Even though it was expected that PHCN would complete its mandate within approximately one year, and on June 30 2006, ceases to exist going by the provision of the Electric Power Sector Reform Act 2005, due to developments within the industry, PHCN still exists, and is yet to be privatized. For this reason the 18 companies which came into existence as a result of the unbundling of NEPA are yet to be considered fully autonomous as should have been according to the EPSRA 2005. This not withstanding the Nigeria Electricity Liability Management Company (NELMCO), a publicly financed entity has been

8 The study analysis was based on methodology developed by the Program on Energy and Sustainable Development (PESD) at Stanford University on IPPs across developing countries: http://pesd.stanford.edu/ipps and the list of contributing elements to success developed by Gratwick, K.N. (2006) at Graduate School of Business, University of Cape Town, South Africa: accessed on March 29 2007 from www.gsb.uct..ac.za.9 Over a dozen interviews including written queries were conducted with more than 20 stakeholders throughout 2006 in Nigeria, Washington D.C., and London. Interviews were followed by email correspondence to clarify discussion points. Due to sensitivity of data, some major stakeholders have not been identified in this paper, where others are only mentioned by organizational affiliation.10 In November 2004, prior to the passage of EPSRA and the inauguration of the board of PHCN, the power-generating arm of NEPA was unbundled into six new semi-independent companies.

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formed to take over the functions of PHCN as the Special Purpose Entity (SPE) provided for in the Act guiding the operations of the ESI. This means that all the contractual obligations, chief among them the contracts with IPPs, go to NELMCO. Privatization, which is the next goal, is currently being stalled by lack of funds to prosecute the pension liabilities of PHCN. The privatization is to be done in a phased approach with generation and distribution privatization, targeted by end 2007. Finally, as provided for in EPSRA, on October 31 2005, the regulator, known as the Nigeria Electricity Regulatory Commission (NERC) was inaugurated to oversee the sector. The present organization and oversight of the sector, not including state owned utilities and self-generators, is depicted in Figure 1. It should be noted that legislation allowing for private participation in the generation sector dates back to 1998, just prior to the first IPP investment.

Expansion of the electrical power system is currently on-going. An eighty percent increase in transmission is targeted by the Transmission and System Operation Company (TransysCo) by 2007 as well as an increase of approximately 80% to the distribution network in the same year. By 2010, the distribution network was planned to be 100% greater than its 2006 capacity/size. As regards generation, among the most significant expansion to date has been 750 MW through the addition of independent power producers in 2001 and 2005, treated in detail in Sections 3 to 7. In addition, the Federal Government financed power plants are both in planning phase and under construction through the National Integrated Power Projects (NIPP) (the first such publicly financed capacity additions since 1990), and are expected to come online, starting in December 2007. Also, new power plants are planned to be built by some State Governments, some private initiatives and the international oil companies (IOCs) operating in the country. By 2010, it is anticipated that the country will have increased its operational capacity nearly three-fold through the following additions, depicted in Table 2. It is, however, important to note that this is a reduction on earlier targets of 25,000 MW by 2010, as initially specified in 2001.11

Table 2: Expected Total Generating Capacity by 2010Power Plants Capacity

MW2005 PHCN/ NELMCO Generating Capacity 3,213.4912

Refurbishable PHCN/NELMCO Capacity (presently not added to grid)

2,325.813

IPPs in Existence in Nigeria 750.8State Government IPP in operation 36Proposed State Government IPP 140Proposed PHCN/NELMCO operated power plants 5,412Proposed Niger Delta Power Plants 2,625Proposed IPP by IOCs in Nigeria 3,790Proposed IPPs by Private Investors 4,574Total 22,867.09Sources: Ministry of Petroleum Resources (2006) 2006 Ministerial Press Briefing; NERC, 2006, compiled by authorsNotes: International Oil Companies (IOCs).

Over 60% of PHCN’s present generation capacity is natural gas-fired, the remaining plant in operation being hydropower. In terms of new capacity, all additions will be natural gas-fired with the exception to four plants slated to be built by PHCN by 2010 (or approximately 2,950 MW of hydropower and 1,000 MW of coal).

11 Omiyi, B 2001, Shell Nigeria Corporate Strategy for Ending Gas Flaring, Seminar on Gas Flaring and Poverty Alleviation, Oslo, Norway, June 18-19 2001, p.9. 12 This represents available capacity from PHCN generation plants. Total available capacity including from the two IPPs for 2005 was 3,645.65 MW13 Total present installed capacity is 6621.6 MW (including IPPs). The capacity in service as at March 2006 was 2,698 MW (including IPPs). A total of 1,393.6 MW capacity has been scrapped, leaving the refurbishable capacity at 2,325.8 MW.

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Figure 1: Structure & oversight of Nigeria’s Electricity Supply Industry*

(Overall direction)

(Formulating electric power policy) (Regulatory oversight)

Note: *all grey boxes represent assets owned/managed by NEPA/PHCN until June 30, 2006, supposedly running as autonomous entities when a Special Purpose Entity, NELMCO, assumed management with BPE in charge of assets

2.1. Drivers for reformThere are various interrelated factors associated with Nigeria’s ESI reform. First is the retreat of

multilaterals from financing infrastructure projects, an issue which is common to that seen across Africa and many other developing regions. The second issue is related to the severe underperformance of the Nigerian ESI, at nearly every level, as well as the state of gas flaring and general neglect of the Niger Delta region.

In terms of transmission and distribution, poor performance has manifested itself in the form of high losses, with T&D losses between 1991-2000 averaging 38% (Federal Minister of Power and Steel, 2004). Technical losses have been estimated at about 15% with the remaining T&D losses attributed to unbilled consumption due to illegal connections, marketing constraints and internal inefficiencies. Finally, not all billed consumption is actually collected. It is estimated that tariffs are collected for only 40-50% of the power generated (ECN, 2004). In terms of the actual tariff charged, this has presented yet another challenge, and is also a contributing factor to the drive for reform in the sector. Average real retail tariffs between 1991 and 2000 were US¢2.8 /kWh. By 2001, weighted average tariffs reached US¢3.2/kWh, or about half the cost of supply and far below the long run marginal cost estimated at US¢6.5/kWh in 2001 14. Furthermore, a substantial cross-subsidy exists, with industry subsidizing residential consumers.

Total generation from installed capacity showed vigorous double-digit annual growth over the 1970s, with an average of 15.3% for the years 1973-1980. The growth slowed down in each of the next two decades to averages of 6.6% over 1981-1990 and 1.3% over 1991-2000. The low generation growth relative to the total installed generation capacity in the 1990s, reflects the poor state of the plants and lack of funding of the electric utility. For example, annual investment in the entire Nigeria’s ESI (see Figure 2) 14 World Bank 2001, Project Appraisal Document On a Proposed Credit to the Federal Republic of Nigeria for a Transmission Development Project, Report No. 22431-UNI, p.4. See also Adegbulugbe, A.O. (2005). Investments in Gas to Power Projects: The G2P World Bank Assisted Initiative being paper presented at the Special Presidential Retreat on Power Generation and Supply at the Presidential Hotel, Port Harcourt, Rivers State, December 2, 2005.

Transmission and System Operation Company of Nigeria

Enugu Ikeja Ibadan Jos Port-Harcourt

Eko Benin Kano

Customers

Kaduna

YolaAbuja

Distribution

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Jebba Hydro

Exports

2 IPPs Shiroro Hydro

Egbin Delta Afam Sapele

Federal Government of Nigeria

Federal Ministry of Power and Steel(now Federal Ministry of Energy) NERC

NELMCO

Generation

Transmission

Kainji Hydro

from 1990 to 1999 averaged US$13 million, less than 20% of the amount spent each year in the prior decade. The growth rate of grid electricity sales closely matches the growth rates in generation, at 13.6%, 6.0% and 0.8% over the decades 1971-1980, 1981-1990 and 1991-2000, signaling constraints within the electricity supply industry to meet demand.

Figure 2: Investment Profile of the entire Nigeria’s Electricity Supply Industry

0

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)

1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004

Source: THE POWER SECTOR: The Catalyst for Economic Growth & Development. Presented by the Hon. Minister Power & Steel and Chairman of the NEPA Technical Committee. At an interactive forum with Mr. President. March 2004

2.1.1 Generation conundrumPoor performance in generation deserves further detail given that it is among the prime motivators

for the IPP developments. Table 3 shows the performance indices as measured by factors of capacity, load and availability of the generation plants in the country in the period of 1999 to 2005. Average plant availability for the plants from 1999 to 2005 was less than 50% as against international best practice of over 95%. The capacity factor was even more dismal15. The capacity factor reflects average utilization of available generating capacity. It is calculated as the ratio of GWh generated annually to effective capacity in place (expressed as a percentage). A low capacity factor could indicate excessive plant failure, but it will also crucially depend on the shape of the demand load curve. If peak electricity demands differ greatly from average demand, the capacity factor will be low. The shape of the demand load curve will be partly influenced by factors beyond the control of the industry (such as weather patterns) but may also be significantly affected by electricity prices. The load factor reflects fluctuations in the use of capital due to seasonal and daily fluctuations in demand. It is measured as the ratio of annual generation to the peak generated load (that is, peak demand * 8760 hours per annum).

With diminished investment profile for the ESI throughout 1980s and 1990s as shown in Figure 2, it is little wonder that almost all the plants fell into disrepair as shown from the performances indicators in Table 3. It is estimated that in 1990, only 37.1% of installed capacity was in operation. Figure 3 shows energy generated and energy sent out over a period of 30 years (covering 1976 to 2005). Energy generated and energy available for sale has been on the increase. The losses, which incorporated distribution losses, however, had been on the increase ranging from as low as 8% in 1996 to the highest of a little over 44% in 1991 as shown in Figure 4. The average acceptable losses are between 5% and 10%. This statistics represents a huge loss of revenue in the country’s ESI. Figure 5 shows generation mix for the country between 1993 and 2005. From 1993 to 1999, hydro stations dominated the generation mix; from 2000 to 15 Due to low availability factor, almost all the plants in the country’s electricity supply industry operate as base-load plants. Industry best practice assumes a capacity factor for base-load plant to be in the range of 50-80+%. Coal-fired steam-cycle power plants, nuclear plants, and hydroelectric plants are examples of base-load generation capacity. Base-load plants may have high capital costs, but typically their fuel costs are low. The output of base-load-type plants cannot be rapidly decreased or increased to follow load,. i.e., adjusted to changes in the amount of power needed. Intermediate-load plants provide power during periods when demand is higher than minimal levels, such as during the day and evening (capacity factors about 15-50%). Technologies for intermediate-load plants include oil or gas-fired steam cycle plants, combined-cycle plants, some hydroelectric plants, and internal-combustion-engine generators. Peak-load plants provide power when demand is highest, and may operate only a few percent of the hours in the year. Types of peak-load power plants include combustion turbines (sometimes also used as intermediate load plants), internal combustion engine plants, and pumped-storage hydroelectric facilities.

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Period of poor funding & neglect of the Nigerian power sector

2005 thermal became dominant. Figure 6 highlights occurrence of forecast and actual peak demand on NEPA/PHCN system. The actual peak demand corresponds with how much the ESI supplies to the consumers. The forecast peak demand for electricity which represents how much the system was to have supplied is known to be quite higher than the actual demand. The gap in supply from the ESI is met by auto-generation in the country, which has been estimated to be at par with the current supply from the national grid. Even though the rehabilitation efforts of some existing PHCN power plants in 2001 raised capacity available for dispatch from 2,500 MW to 4,000 MW, current (2007) supply situation is abysmal due to vandalism and other technical problems.

Table 3: Performance Indicators for Nigeria’s Electricity Supply Industry: 1999 – 2005Year Average Plant Availability16

(%)Capacity Factor17

(%)Load Factor18

(%)2000 30.0 32.0 75.72001 27.7 32.5 68.32002 42.5 36.9 76.32003 46.2 39.8 92.02004 47.5 44.6 95.82005 44.4 41.5 90.6

Figure 3: Energy Generated compared to Energy Available for Sale in Nigeria’s ESI: 1976-2005

Source: NEPA various annual reports, extracted by authors

16 Average plant utilization factor is the average value of the ratio of the power generated in each available plant to the power that could be generated through installed capacity of each of the plants.17 Capacity factor is the ratio of the average load supplied during a year to the installed capacity computed as total load divided by installed capacity (MW) times 8760 hours.18 Load factor is the ratio of the average load supplied during a year to the annual peak demand computed as total load (MWh), divided by Peak demand (MW) times 8760 hours.

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0

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10000

15000

20000

25000

30000

1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004

GW

h

Energy Generated, GWh Energy Available for Sale, GWh

This area depicts losses in the system

Figure 4 Power Losses as percentage of generation

05

101520253035404550

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1976

1978

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1982

1984

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Figure 5: Plant Generation Mix from 1993 to 2005

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Hydro ThermalTot

Based on data from PHCN, between 1999 and 2005, the highest demand of 3,774.4 MW, including about 750MW from IPPs occurred in 2005 out of the almost 7,000 MW installed capacity as depicted in Figure 6. If uninterruptible power supply is assumed, the consumption and peak demand will be higher. Despite the fact that no universally accepted estimate of the actual demand is available, however, using the 1998 estimate by Shell Petroleum Development Company (ESMAP, 2004) of between 3000 and 4000 MW as the total private backup generator capacity in Nigeria could be taken as proxy for 2005, and using the more conservative of the two estimates, assuming the generators operate at 100 percent of installed capacity, and assuming that these private generators lose 20 percent in delivery, this gives a delivered capacity of 2,400 MW. Using this figure as backup generator capacity in the country added to PHCN 2005 delivered capacity of 3,774.4 MW and to the known capacity from other non-NEPA plants gives a total delivered power capacity of 6174.4 MW for all of Nigeria, which is approximately almost the total installed capacity for that year. This means that the excess of about 3000 MW of PHCN not deployed to meet demand could be a reflection of plant failures resulting from long period of low investment and poor electricity prices, and not necessarily due to excess capacity in the system.

The inability of the utility to meet the suppressed demand allow grid power outages due to system collapses and load shedding, so that those who do not have standby generators will not always have power supply as and when needed. This applies principally to the household sector and some services. In order to respond to the persistent shortfall in generation, the only reasonable and immediate response to the power supply/demand imbalance is load shedding. In implementing this strategy, the utility is normally sensitive to consumers who are critical to security and to the utility’s income. Consequently, urban residential and rural areas suffer load shedding the most. This situation has had a devastating effect on the national economy, while at the same time making the local manufacturing sector un-competitive

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internationally. Some studies19 have found that many small Nigerian firms have had to commit substantial portion of total capital expenditure in order to provide close to 50% of their electricity requirements, while some large firms are fully on self-generated electricity in order to have 100% reliability for their production processes. The implication of businesses with back-up generators in Nigeria represents credible latent demand for potential IPP developers as the cost of self-generation exceeds US$0.40/Kwh20 (WB, 2002).

Figure 6: Occurrence of Peak Power Demand in NEPA/PHCN System (1992-2005)

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urre

nce

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ax. P

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Forecast Actual

Source: PHCN, various annual reports

2.1.2 FlaringPoor performance of the ESI alone is not driving the reforms. Of significant importance is the role

of gas flaring in Nigeria, which at the start of reforms in the late 1990s contributed to more than 15% of global gas flaring (or approximately 1.6 Tcf per year). Due to limited gas distribution infrastructure, Nigeria today flares about 2.6 bcf/d of gas, representing 12.5% of all globally flared gas (ranking her as the highest gas-flare country in the world), representing 68% of the associated gas produced or 51% of the total gas production (CEE, ____). The commercial loss (estimated at US$2.5 billion annually) together with the environmental damage has motivated the country to target 2008 as the year to end all flaring. 21 A host of initiatives have been tabled including power generation, gas-to-liquids (GTL), pipelines (through the National Integrated Power Projects (NIPP22) funded by the government to the tune of N33 billion (approximately $264 million23), re-injection, liquefied natural gas (LNG) and petrochemicals--of which power generation is among the largest and most advanced in terms of gas application and implementation. International oil companies operating in Nigeria have been charged with building power plants to make use of gas from their fields, which would otherwise be flared. It is from this policy, enshrined in the Nigerian Natural Gas Strategy of 2002 that the IPP B emerged and that approximately additional 4,000 MW are expected by 2010 (highlighted in Table 2 above), including the IPP C, due online in 2007. Projects benefit largely from the same terms and conditions granted to upstream gas project investments, including a tax

19 International Monetary Fund 2005, Nigeria: Selected Issues and Statistical Appendix IMF Country Report No. 05/303 page 33 item #70; Ayodele, A. ‘Sesan 2001, Improving and Sustaining Power (Electricity) Supply for Socio-Economic Development in Nigeria – Unpublished work; Estache, 2005, pg 31.20 World Bank (2002) Nigeria Public and Private Electricity Provision as Barrier to Manufacturing Competitiveness accessed from www.worldbank.org/afr/findings on February 10 200721 Kupolokun, F 2002 “Issues in Natural Gas Utilization in Nigeria,” The Nigerian Natural Gas Strategy Stakeholders Workshop, Abuja, December 9, 2002, pp. 4-5. 22 The NIPP is an intervention project by the GoN to comprehensively address the state of electricity infrastructure in the country. NIPP is designed as fast-track approach to improving the nation’s electric power supply through implementation of generation, transmission, distribution and gas supply projects (Source: PHCN News – Official Journal of Power Holding Company of Nigeria plc ISSN:0331-3-85 January – April, 2005)23 At exchange rate of US$1 to N125

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rate of 30% (rather than 85% for all oil projects); tax holiday of five to seven years; and exemption on custom duties and VAT on gas related development equipment.24,25.

2.1.3 Niger Delta and neglectOne issue that could be attributed with major contribution to driving the electric power sector

reform is linked to the specific circumstances of the Niger Delta, where more than 90% of Nigeria’s oil and gas wealth is presently located. One of the major reasons for agitation in the Niger Delta region is the lack of physical and social infrastructure, which in recent times has caused serious uprising since oil was first discovered in the region in 1958. In an effort to address these major gaps, the GoN had awarded contract for the construction of integrated electricity infrastructure to include a generation facility of 2,625 MW to be added to the grid in the form of seven natural gas-fired plants (using combined cycle gas turbine technology) (see Table 4). The Federal Government of Nigeria (FGN) is facilitating the establishment of these Niger Delta plants with the intention of divesting its interest to the host communities of each plant. These projects, conceived as integrated power projects to comprehensively address the state of electricity in the country, would include generation, transmission, distribution and gas-supply projects26. The host communities (together with their state government where possible) are expected to pay back the cost of building to the FG at no interest over a period of time. IPPs per se are not a part of this development however, there will undoubtedly be a role for some level of private participation in the management of the plants. Federal Government finances the project to be built and operated by PHCN or its successor company. The overall improvement in performance expected from the execution of the integrated projects is highlighted in Table 5, with the expectation that gas flare would be reduced by as much as 748 mmscf/day.

Table 4: National Integrated Power ProjectsS/n Name of power station Location/

StateNumber of units

Total output (MW)

Expected commissioning dates

1 Calabar Cross River 5 561 July 2007 Nov 20072 Egbema Imo 3 338 July 2007 Dec 20073 Ihovbor Edo 4 451 June 2007 Sept 20074 Gbarian/Ube Bayelsa 2 225 June 2007 Sept 20075 Sapele Delta 4 451 May 2007 Aug 20076 Omoku Rivers 3 230 Dec 2007 Dec 20077 Ikot Abasi (Ibom

Power)Akwa Ibom 3 188 Dec 2007 Dec 2007

8 Ikot Abasi (Alscon) Akwa Ibom 300 Yet to be awardedSource: PHCN News – Official Journal of Power Holding Company of Nigeria PLC ISSN: 0331-3085 January-April, 2006

Table 5: Overall Expected Performance Improvement from the NIPP ImplementationSector % Improvement

Generation 68Transmission 48Distribution 30Gas Flare 748 MMSCF/Day27

Source: PHCN News – Official Journal of Power Holding Company of Nigeria PLC ISSN: 0331-3085 January-April, 2006

24 Belguedj, M, 2002, “Strategic Gas Planning Policy for Nigeria,” The Nigerian Natural Gas Strategy, Stakeholders Workshop, Abuja, December 9, 2002, pp. 24, 13. 25 The package of incentives the government hoped to woo investors into the generation sector include tax holidays, exemption from duty taxes on imported equipment, capital and investment allowances, which can be carried forward and used after tax holiday period. Others include implementation of a tariff adjustment mechanism that will cover cost of production and provide adequate returns on investment, establishment of transmission infrastructure that would create a level playing field for private sector operators - Source: ThisDay August 18, 2004 through http://www.nigerianmuse.com/projects/EnergyDevelopmentProject/?u=Runningnewselectricity.htm accessed January 26 200726 The NIPP scope include construction of 8 new power stations with total capacity of 2,744 MW, distribution network expansion of 250 new projects comprising 4,367 km lines and 22,598 transformers, N15 billion gas pipeline/associated transmission infrastructure with first unit to be completed June 2007.27 This is the amount of gas flare that would be avoided daily once the NIPPs are completed.

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3. Development of IPPs in NigeriaAs discussed above, the failure of the utility plants to meet demand made proliferation of backup

generators in the country a success. This trend however had quite negative impact on the economic activities of most industries in the country. In order to address this gap, both the first and second IPP emerged to rectify the severe lack of generation, but in very different ways, which will be explored in this and subsequent sections. While the Electric Power Sector Reform Act, which has subsequently catalyzed the unbundling of the sector, was only passed in 2005, legislation allowing private participation in the generation sector was passed almost a decade earlier, just before the first IPP in 1998.

3.1. IPP AThe first IPP, which was originally intended to serve Nigeria’s industrial and commercial centre,

Lagos, emerged amidst the emergency power situation of 1999 when just over a third of total capacity was in operation and load shedding was becoming increasingly widespread. Two versions of the story exist according to stakeholders. In the first version, it was an America energy company that approached the FGN and the Lagos State Government with a proposal to build own and operate an emergency facility, namely a 90 MW barge-mounted diesel plant to be run on liquid fuel, followed by a permanent facility comprising a 560 MW gas-fired plant,-- both under a common PPA. In the second version of the story, the Lagos State Government appears to have been driving the process and have directly approached the American energy company for the two-part project. In both versions, it is important to note that international competitive bidding (ICB) practices were overlooked and the deal was negotiated within months. The original power purchase agreement was signed in 1999 among the project company, the Lagos State Government, the Federal Ministry of Power & Steel and NEPA, with the expectation that the first plant would be on-stream by December 1999. A local Nigerian firm was also involved at this stage as advisor to the American energy company, but not signatory to the PPA.

Due to subtle political pressure and other technical details that had to be cleared however, the initial deal had to go through renegotiations, that lasted for six months form January to June - 2000. Major objections were raised about: the lack of transparent and competitive bidding; the type of fuel to be used, the fact that the plant would not be penalized for poor performance; that the project company would receive excessive contract termination payments; and that payments would bankrupt the state and national utilities. Amidst the renegotiation, the original plan for the land-based 560 MW plant became sidetracked. The major items to be renegotiated involved increasing the initial plant from 90 MW to 270 MW (nominal capacity is presently put at 300.8MW) (9 units of 30 MW each gas-fired open cycle) and changing the fuel from liquid fuel to natural gas, both of which had the effect of reducing the capacity charge (with some reports of a reduction of up to ten times the original charge) to approximately US$19.00/kW/month, and a final investment cost28 of US$240 million29,30.

It was agreed that the capacity charge would be flat, indexed to OECD CPI, for the 13.25-year duration of the contract, which would be backed by a sovereign guarantee. Capacity charges would be payable in dollars. There was no separate fuel supply agreement; instead, fuel was to be provided by NEPA or its successor company, which would contract it directly from the Nigerian Gas Company. Although agreement was reached and the plant has been online since 2001, further negotiations are underway, over the following key terms.

Of critical importance is the availability deficiency payment. The PPA signed in 2000 allows for only 30% of the agreed unit cost of liquidated damages recoverable for shortfall in availability and was payable only at the end of the year. The current proposal tabled is 100% recovery of unit cost payable at the end of every month, the consequences of which will be discussed in greater detail in Section 4.

Of the US$240 million in investment costs, information is only publicly available on about half of the financing. Africa Merchant Bank and the Dutch Development Company (FMO) were the lead arrangers for US$120 million loan syndication. Co-arrangers were United Bank for Africa (UBA) and Afriexim. Participants were Rand Merchant Bank (RMB), Diamond Bank, Absa Bank and the German Investment & Development Corporation (DEG).31 No information is known about the equity contribution or further financing arrangements. To date, all loan payments have been made in a timely manner. 28 This actually represents the cost at which the present IPP A operator bought the interest from the initiator of the projector.29 Still very expensive, more than US$1000/kw30 This represents the cost at which the project of 9 barge-mounted units was purchased by the first American energy company to the second energy company. 31 Of RMB's USD 20 million participation in the USD 120 million facility, the bank sold down USD 5 million to ABSA about a year after close of the transaction.

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Table 6: Nigeria’s first IPP PPA present and proposed termsSIGNED IPP A PPA 2000 PROPOSED AMENDMENT IN THE PPA (2006)

PHCN pays full Capacity Payment each month without any regard to actual production. At the end of year IPP A reimburses any Availability Deficiency Payment for annual plant outages in excess of 10% of annual production capacity at the rate of $0.30 for each $1 paid by PHCN.

Commencing from 1st January, 2006 the Availability Deficiency Payment (for any shortfall in production from 90% level will be charged on 1:1 basis each month. PHCN will pay Availability Surplus payments for any production above 90% at the same rate;

Reconciliation for the Deficiency Payments is carried out annually on completion of the Contract year.

Reconciliation will be done on monthly basis

The PPA allow IPP A to install additional power capacity

IPP A will install additional power capacity of 65 MW as per PPA.

PPA term will expire on November 20th, 2014 The term of the PPA is extended. Following are the revised expire dates:

a. Contracted capacity of 365 MW up to November 20th, 2014.

b. Contracted capacity of 235 MW from November 21st, 2014 to December 31st, 2019;

c. Contracted capacity of 115 MW from January 1st, 2019 to date which is 20 years from the commissioning date of the additional capacity.

Barge Net Dependable capacity rates are as follows:

a. US$19.35/KW Month in respect of Net Dependable Capacity up to 290 MW

b. US$16.50/KW Month in respect of Net Dependable Capacity in excess of 290MW

This translates to an average rate of $19.255/KW – Month for 300MW Net Dependable Capacity.

With effect from the commissioning date of the additional capacity (65MW), the Net Dependable capacity Rate will be reduced to US$16.85/KW-Month till December 31st, 2019 and thereafter till expiry of the PPA will be $13.00/KW-Month.

This translates to an average (weighted for duration) rate of $15.12/KW-Month over the term of the PPA a reduction in tariff of about 21.5%

No penalty on excess usage of fuel gas Heat Rate Monitoring – IPP A will pay penalty at the rate c10/MMBTU on consuming fuel gas in excess of permitted allowance. AESNB will receive bonus at the same rate if the fuel gas usage is less than the permitted allowance.

Contract year ends on 26th April of each year. Contract year is aligned to Calendar year

Upon privatization the PPA will be assigned to Lagos State

Upon privatization the PPA will be assigned to special purpose entity (SPE), NELMCO contemplated in Electric Power Sector Reform Act 2005 which will assume all rights and obligations of PHCN.

Source: Office of the Special Adviser to the President on Energy Matters 2006.

While we have seen little change in terms of debt arrangers, equity has indeed changed hands. A little less than a year before the American energy company that initiated the project filed for bankruptcy, with its share price still meeting new heights,32 the firm sold its shares in two tranches. In September 2000, it sold 30% to the successor company, which happens to be another American energy company in the US. Then in December 2000, the firm sold the remaining 65% and 5% respectively to its successor and the Nigerian partner, which although present since project inception only became a shareholder in 2000, for an alleged US$240 million.33 The first American energy company did not complete construction, and the construction contract was transferred to the successor American energy company, with the plant coming

32 The first American energy company filed for bankruptcy protection on 2 December 2001. The firm’s stock price reached a high of US$90 per share in August 2000, prior to its demise and just prior to its sale to the second American energy company, starting in September 2000. Source: BBB, accessed on November 20 2006, http://news.bbc.co.uk/hi/english/static/in_depth/business/2002/enron/timeline/12.stm33 Enron filed chapter 11 in December 2001.

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online in May 2001.34 Since then the FGN has failed to issue the tax exemption certificate. A detailed discussion of operations, cost and outcomes is treated in Sections 4 and 6.

3.2. IPP BIPP B emerged from the country’s gas flaring elimination strategy. In 2001, NEPA invited bids for

a 450 MW combined cycle gas turbine plant along with the requisite gas infrastructure, via a Build Own Operate (BOO) structure, from a series of pre-qualified firms, namely oil firms active in the Nigerian petroleum sector, including major international oil companies. A consortium composed of the Nigerian national oil corporation (60%), two other international oil companies operating in the country holding (20%) each presented the winning bid. The factors upon which the winning bid was determined are not explicit.

Unlike the first IPP, the initial negotiation process was not marked by a series of stops and starts, but a phased plan was agreed upon and negotiations have since been reopened. The 450 MW CCGT was to be built in two phases with 300 MW OCGT installed, which would then be upgraded with the addition of 150 MW to a CCGT. The dollar-denominated power purchase agreement with NEPA/PHCN would span 20 years, but would not be backed by a sovereign guarantee. Instead the security for the project lay in the fact that it was backed by oil revenues from the producing subsidiary of the country’s national oil corporation. The contract stipulated 80% minimum capacity availability, take-or-pay. Following from the gas strategy, fuel was to be supplied directly by one of the oil majors operating in the country with interest in the consortium. Ultimately, the Federal Ministry of Power and Steel signed the PPA together with Federal Ministry of Finance, project executor (one of the oil majors in the country) and NEPA, based on an agreed Final Investment Cost (FIC) of US$312 million, and an approximate flat capacity charge of US$13 per kW (at 80% capacity), tied OECD CPI35 with the energy charge at 2.2 UScents/kWh.

In a departure from most IPPs throughout the developing and developed world, IPP B was entirely equity financed, with the lead equity sponsor the state-owned oil company, providing 60% of total equity. According to government stakeholders, this is a common position by NNPC to provide equity rather than debt. Between the initial negotiations in 2001 and the plant coming on-stream (first 300 MW in April 2005, upgraded to 450 MW in November 2005), investment costs rose by US$150 million, to US$462 million36. Causes cited for the increase in costs are: vandalism as well as underestimating the cost of the transmission infrastructure required. Parties are presently seeking to resolve the dispute directly (i.e. out of court with sponsors directly) and meanwhile, the plant is producing power but, due to the dispute, full payment is not being made by PHCN. Therefore, as originally agreed to in the PPA, the plant will not amortize after five years.

3.3 IPP CAlthough recently hailed as “a beautiful bride”, with the President’s economic advisor urging that

“today not tomorrow” [is] the time to invest in Nigeria,”37 the country has a muddied track record when it comes to IPPs. Still, an additional IPP, born out of the gas-flaring reduction policy of 2001, is due online, in 2007. This is therefore analyzed only in part as performance data is not yet available. The project involves a Brownfield and Greenfield investment, namely: refurbishment of the existing 270 MW (Afam V) under Acquire, Operate Own (AOO) contract and the addition of 630MW (Afam VI) under a BOO arrangement.38 The companies invited to submit bids were the major international oil companies operating in Nigeria. Negotiations started like those for the country’s second IPP in 2001. The oil company controlling close to 40% of oil exploration in the country was selected as the Joint Venture

34 Van Meeteren, B 2005, Financing of AES Nigeria Barges Ltd, Presentation at Power Generation World 2005, FMO, April 19. 35 Okpai IPP PPA36 At about $1000/kW, raising questions about the negotiating process. This shows the problems with direct negotiation without competitive bidding.37 Games, D 2006, ‘Today, not tomorrow, the time to invest in Nigeria,’ South African Business Day Online, August 28. In January 2006, Nigeria received its first ever rating from Fitch Ratings, a BB- (3 notches below investment grade), followed by a comparable rating from Standard & Poor’s (‘Nigeria launches power privatization sales pitch’ 2006, Africa Electra, Issue 41, 14 February).38 It should be noted that the Afam project was initially conceived of as a Restore Own Transfer (ROT) for the existing Afam I-IV units and a Lease Own Transfer (LOT) for Afam V unit, however, after assessing conditions of the plant, the IOC involved proposed (and host country counterparts agreed) that Afam I-IV should instead be replaced with a new CCGT unit, which will be the new 630 MW in the form of Afam VI. Additional changes prompted by the transfer of security from NNPC to the Federal Ministry of Finance involved parties agreeing that Afam V should be negotiated on an Acquire Own Operate (AOO) rather than LOT basis and Afam VI be a Build Own Operate (BOO) rather than a Build Own Transfer (BOT).

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operator of a consortium composed of national oil corporation (55%), Shell (30%), Elf (Total) (10%) and Agip (5%).

Investor incentives, as noted previously in Section 2.1.2 are similar to those granted to upstream gas projects. As with the second IPP, a 20-year dollar-denominated PPA was negotiated, which will be backed by the Ministry of Finance Letter of Credit, which represents a change since the time of negotiations with IPP B. Initially, the only way that FGN could guarantee PHCN’s payment obligations was by pledging NPDC39 crude oil. Since then however, in January 2006, Nigeria received a BB- credit rating, which means that it no longer needs to pledge its crude oil or income stream as security against PHCN’s default. A Letter of Credit from the Ministry of Finance is now adequate security.

The terms of the agreement stipulate take or pay with minimum available capacity of 80%. Although the final investment cost has been set at US$540 million for the project, neither the energy charge nor the capacity charge have been made public. As is the practice in most of its transaction in the country, failure to disclose this information by the oil company could jeopardize the sustainability of the PPA in the long run. The IOC managing the JV is to provide fuel. And it is also expected that the plant will be 100% financed by equity, as with the second IPP.

More IPPs may be in the pipeline, including a suite of IPPs proposed by the international oil companies, featured in Table 7 below, particularly as the state aims to treble its capacity by the end of 2010 (from 5,198 MW at present to 22,867.09 MW). Table 8 shows private companies (not IOCs) that had been licensed by NERC to build IPPs in the country. The earliest date of commissioning for any of the IPPs being December 2007. Total capacity anticipated for addition to the system from the private initiatives once they are fully commissioned is 4,574 MW.

Table 7: Proposed IPP by International Oil Companies (IOCs) in NigeriaYear

Expected

Project/Location Project Sponsor Proposed Capacity

MW

2007/8 Kwale/Okpai IPP Phase II NNPC/NAOC JV 480

2007/8 Afam IPP (V and VI) NNPC/SPDC JV 930

2007/8 Afam II NNPC/SPDC 650

2007/8 Obite IPP NNPC/Total (EPNL) JV 450

2007/8 Ljede IPP NNPC/Chevron JV 780

2007/8 Bonny River Power LNG NNPC/ExxonMobil JV 500

Total 3,790

Source: Nigerian Ministry of Petroleum Resources (2006) 2006 Ministerial Press Briefing

39 Nigeria Petroleum Development Corporation, a subsidiary of Nigeria National Petroleum Corporation (NNPC)

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Table 8: Newly Issued Licenses40 by NERC for Development of IPPs in NigeriaS/N Project Location Licensed Capacity Expected

Commissioning DateTechnology

1 Farm Electric

Otta, Ogun State 150MW December 2007 OCGT

2 Ethiope Ogorede, Sapele, Delta State

2,800MW Phase 1 of 1390MW in September 2009

CCGT

3 ICS Alaoji, Abia State

624MW Phase 1 of 120MW in August 2008

CCGT

4 Supertek Akwete, Abia State

1,000MW Phase 1 of 480MW in July 2008

CCGT

  Total 4,574 MW    

Source: NERC, 2007

It is however to be noted that the fact that license had been issued to the various investors does not mean that they can operate in the country’s electricity industry. They have only been cleared by the regulatory body based on their legal, financial and technical capability to build and operate proposed generating plants. The second stage of the process involves the approval of their various PPAs detailing how they intend to operate in the industry.

4. Analysis of operations and costAs at 2005, IPP A and IPP B, supplies just above 14% of generation capacity, but however collects

more than 25% of the monthly revenue of the entire PHCN successor companies put together. This section seeks to unpack what is happening in terms of IPP costs and performance and begin to shed light on outcomes. Although previously mentioned in the context of IPP development, neither IPP C nor any of the other plants either under construction or planned will be discussed in detail in this evaluation of actual performance.

Figure 7: Composition of contribution to electricity generation, 2001 - 2005

0.0%

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70.0%

2001 2002 2003 2004 2005

Hydro ThermalU Thermal IPP

Figure 8: Performance Indicator based Declared versus Delivered Capacity of the IPPs, May 2005 – October 2006

40 If the Commission issues a generation license, it means that the Commission has concluded that the applicant has demonstrated that it has the legal, financial and technical capacity to build and operate the proposed generating plants. However, the granting of the license does not imply that the Commission has given approval to the terms of any PPA that will be used to sell the power produced from this generation facility. Nigerian Electricity Regulatory Commission (2006) Public Notice: Notice of Proposed Rulemaking on Power Purchase Agreements for Captive Customers. Point 7 - NERC/NOPR/CN04606

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0.00%

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IPP A 2005-2006 Performance % IPP B 2005-2006 Performance %

4.1 Performance: capacity declared and capacity deliveredTogether the two IPPs, which as at 2005 represent about 14% of installed dispatchable capacity,

are presently supplying a little over a fifth of generation. However (as indicated in Figure 9 above) the contribution of IPP B is greater than that of IPP A. In 2006, IPP A accounts about 4.5% of installed dispatchable capacity and 7.95% of total grid generation while IPP B accounts for 6.7% of installed capacity and 13.5% of total grid generation. This may be explained partly by the fact that IPP B has increased its capacity from 300 MW to 450 MW as of January 2006; however, there is a larger story behind the relative contribution of the plants.

The contract between operator of IPP A and PHCN, presently NELMCO, commits the sponsor to supplying 90% of declared capacity and 80% for IPP B. Since January 2005, AES has declared its capacity to be 300.8, i.e. 30.8 MW greater than the initial 270 MW contracted. Ninety percent of 300.8 is 270.7 MW; however, actual power delivered has averaged 222.5 MW, equivalent to 18% less than the agreed delivered amount. No explanation for this shortfall in production has been provided by the sponsor, however, it should be reiterated as detailed in Table 6 above: “PHCN pays full Capacity Payment each month without any regard to actual production. At the end of year the operator reimburses any Availability Deficiency Payment for annual plant outages in excess of 10% of annual production capacity at the rate of $0.30 for each $1 paid by PHCN,” hence the shortfall presently does not result in a significant penalty to AES.

Operator of IPP B has delivered on average (since May 2005) only 79% of its declared capacity. However, in contrast to operator of IPP A, the agreement with operator of IPP B only stipulates that the plant must deliver 80% of its declared capacity; hence the total shortfall for IPP B has been approximately 0.01%, (details in Appendix A). In sum, the operator of IPP A appears to be underperforming and IPP B, to be performing as contracted.

4.2 Evaluation of costsThe fact that the IPPs are eating up about 25% of PHCN’s revenues41 is highly significant because

it is taking so much cash out of PHCN’s inadequate resources that Government has to step in with huge subsidies to help out. Of course, these subsidies are not directly linked to the payments under the PPA. This problem would increase dramatically with new PPAs with large payment obligations. However, the consolation to this fact, as has already been noted, the ESI is not at present cost-reflective. Although cost data is scarce, what little this report could uncover relates to the relative price of the two IPPs as well as pressure to reduce costs for both plants.

41 From the 2005 records, the ESI expected revenue based on 23,695.3 GWh energy sent out of N140.3 billion ($1.08 billion). This would have meant that the IPPs were to have received 14% of the total revenue of PHCN.

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4.2.1 Current relative and absolute costs The capacity charge for IPP A is presently, as of November 2006, US$6.35 greater than that for

IPP B, with IPP A at US$19.35 per kilowatt per month and IPP B at US$13.00 per kilowatt per month. In terms of the energy charge, IPP A has no fuel cost as NEPA (later PHCN) contracted directly with the state-owned gas company, and there appears to be no separate energy charge. IPP B’s energy charge comes to 2.2 US cents per kWh, with its fuel, supplied directly from Agip, one of its sponsors.

While IPP A appears to be presently more expensive than IPP B, how does this compare to PHCN’s42 plants and those of IPPs in other African countries? With the ongoing disclaimer that publicly produced power is under-priced, PHCN’s average retail tariffs have been, since the inception of IPPs, approximately 4.0-4.5 UScents per kWh. Although the utility has not been able to provide wholesale tariffs for state-owned plants, IPP A’s wholesale tariff is 2.85 US cents per kWh (exclusive of fuel) and IPP B’s is 3.83 US cents per kWh (inclusive of fuel)43. Thus if we assume IPP B’s fuel costs for IPP A, simply for matter of argument, we arrive at a wholesale tariff for IPP A of approximately 5.1 US cents per kWh which is higher than the retail cost of PHCN’s plants and also noticeably higher than IPP B. In sum, IPP A appears to be more expensive than IPP B and both plants appear to be more expensive than PHCN’s plants. Ranking of African IPPs in Nigeria, Tanzania, Kenya, Egypt and Morocco organised based on $/kW with the lowest cost project ranked first and the highest cost ranked last. The two operating Nigeria IPP projects occupy 7th and 9th positions respectively at $889/kW and $1,027/kW. For the third IPP project which is yet to be operational, it is ranked 6 th in terms of $/kW cost of $600/kW. For the IPP A project, its relative high cost when compared to similar ones in other African countries could be attributed to the prevailing investment climate in the country as the time of its entry, and the IPP B though costlier than comparative ones in other African countries this relative increase was due to the restiveness in the Niger Delta where it is located44.

Table 9: Project Costs (organized by ranking based on unit project costs)Project (country) Cost (US$ million) Capacity (MW) $/kW Ranking45

Suez (Egypt) 338 683 495 1Port Said (Egypt) 340 683 498 2Carthage Power (Tunisia) 260.7 471 554 3Sidi Krir (Egypt) 413.9 683 606 4Westmont (Kenya) 35 80 435 5IPP C (Nigeria) 540 900 600 6IPP A (Nigeria) 240 270 889 7Tahaddart (Morocco) 365.9 385 950 8IPP B (Nigeria) 462 450 1,027 9Jorf Lasfar (Morocco) 1500 1360 1,103 10SEEB (Tanzania) 30 27 1,111 11Tsavo (Kenya) 85 75 1,133 12Iberafrica (Kenya) 65 56 1,161 13CED (Morocco) 58.2 50 1,170 14IPTL (Tanzania) 120 100 1,200 15Songas (Tanzania) 310 190 1,632 16OrPower4 (Kenya) 54 13 4,154 17

Total 4677.7Source: Adapted from Gratwick and Eberhard (2006)

42 Although as of June 2006, PHCN has ceased to exist and all generating companies are considered autonomous, we refer to PHCN (formerly NEPA) loosely in this section as the national utility for the sake of benchmarking. 43 Calculation done by authors.44 See footnote 4545 NOTE: due to technology differences, a per kW cost ranking/comparison may be misleading. A more revealing comparison is that of similar technologies, namely: CCGT (Carthage, Tahaddart & IPP B-Nigeria); OCGT (SEEB, IPP A-Nigeria and Songas); Steam cycle gas turbine (Sidi Krir, Port Said and Suez) and finally medium speed diesel engines (Iberafrica, Tsavo and IPTL). Those presently without any comparison are the two renewables: the geothermal plant OrPower4 and the wind plant CED.

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5. Analysis of outcomes: overview and analytic framework

5.1 Balancing actWhat are the main lessons to take to the next round? Our framework for evaluating results of the

IPP experience is based on determining investment and development outcomes. Broadly speaking, positive development outcomes are defined as reliable, affordable power provided to consumers; positive investment outcomes are where debt is serviced, equity rewarded as expected and there is a potential to increase investments. It is the premise of this study that in order for projects to be sustainable, development and investment outcomes must be roughly in balance.

Given the marked difference in cost and performance, a project-by-project review is called for in making any final judgments about outcomes. In terms of IPP A, the plant is undergoing its second renegotiation to adjust contract terms. The tax exemption certificate has still not been issued. A cursory glance might lead one to conclude that the state is squeezing the investor. However, at present, the present sponsors have given no indication of selling the plant. Furthermore, this study does have on record that stakeholders are generally content with the exception to the tax exemption certificate issue. Meanwhile government stakeholders have clearly indicated their discontent with the deal and the critical need to renegotiate on more favorable terms as proposed above in Table 6, leading the authors to conclude that the scale in the past has been tipping in favor of investment outcomes (at the expense of development outcomes). In terms of IPP B, less may be said; outcomes appear to be more balanced, however, the ongoing negotiation over investment costs may ultimately prove otherwise.

The analysis in Gratwick and Eberhard (2006) show a general tilt toward investment at the expense of development outcomes is common in sample of African projects evaluated to date. What becomes interesting is what determined these outcomes; what were the contributing elements to success (CES)?

5.2 Which CES? A matrix has been developed that depicts major elements that may contribute to both positive

development and investment outcomes (although exclusion of such elements does not portend failure, inclusion appears to impact favorably, based on IPP experiences evaluated across the continent). The elements have been grouped into two categories: elements primarily under the purview of the host country stakeholders/government; and elements primarily controlled by project sponsors, with related impacts on development and investment outcomes respectively. Countries may attract investment at lower cost and maximize development outcomes through establishing clear policy, regulatory and power planning frameworks. Successful outcomes are further enhanced through a favourable investment climate and the availability of competitively priced fuel. Project sponsors seek to maximize investment outcomes and mitigate risks through the equity and debt structures of the investment and through power purchase agreements, fuel and other contracts and through strategic management of relationships with relevant stakeholders. These elements are listed in the two tables below – Tables 10 and 11 respectively.

Although favourable equity and debt arrangements as well as risk mitigation measures with the off-taker, fuel supplier and other stakeholders have been classified below as project issues, these elements may relate to the host country as well, considering host country stakeholders are often involved in at least one if not several of these dynamics. Of the elements below, only one may seen be seen as exclusively within the purview of the project sponsor, namely positive technical performance. Nonetheless, these are all areas where the project sponsor seeks to mitigate risks, either through contracts, or the management of relationships, or both.

In the case of Nigeria, of the myriad elements listed in Table 11, few were in existence for either project. The following two sections take an element-by-element approach to understand the outcomes of each project.

6. The Outcomes and the ElementsFor IPP A, it was generally observed that outcomes tilted in favour of the investors at the expense

of the host country due to the public interest it had generated from inception, whereas, IPP B experience has generated less public interest than that of IPPA, with its analysis largely that of intervening in the gas flaring occurring in the Niger Delta region where most of the oil and gas related activities are taking place. IPP C is has not become fully operational. This section gives a summary of the outcomes and elements as

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they relate to each of the IPPs evaluated. They are examined based on host country and project factors as highlighted in Tables 1, 10 and 11 respectively.

Table 10: Contributing Elements to Success, host country issuesCES DetailsFavourable investment climate

-Stable macro-economic policies-Legal system allows contracts to be enforced, laws to be upheld, arbitration -Sound commercial practices, billing & collection and financial viability of off-taker-Requires less (costly) risk mitigation techniques to be employed which translate into lower cost of capital and hence lower projects costs and more competitive prices- Potentially more than one investment opportunity

Clear policy framework

-Framework clearly specifies roles and terms for private and public sector investments (generally for single buyer model, not, yet, wholesale competition in African context)-Reform-minded ‘champions’, concerned with long-run, lead and implement framework

Clear, consistent and fair regulatory oversight

-Transparent and predictable licensing and tariff framework improves investor confidence -Improves general performance of private and public sector assets-Cost-reflective tariffs ensure revenue sufficiency-Consumers protected – improves development outcomes

Coherent power sector planning

-Energy security standard in place; planning roles and functions clarified-Power planning vested with lead, appropriate (skilled, resourced & empowered) agency-Power sector planning takes into consideration the hybrid market (public and private stakeholders and their respective real costs of capital) and fairly allocates new build opportunities among stakeholders-Planning has built-in contingencies to avoid ‘emergency power’ or blackouts

Competitive bidding practices

-Procurement process is transparent and competition ultimately drives down prices

Abundant low cost fuel

-IPPs perceived as less costly and/or comparable to state power-Secure supplies of fuel

Part of a larger infrastructure development

-Projects that are part of a larger infrastructure development (e.g. developing upstream resource and downstream customer/market) are often more insulated from public pressure/scrutiny

6.1 The host country Issues for IPP A It was generally asserted in the last section that outcomes have tilted in favor of investors at the

expense of the host country. Why and how is this the case in terms of the IPP A? First the suite of elements chiefly related to the host country to make for more favorable development outcomes were absent. In 1999, when the first American energy company emerged on the scene, the country had not yet received an investment grade rating (as it did in 2006); instead, Nigeria had the features of a failed state, with all indicators of growth and development in the negative. The public debt burden, put at about USD 28.8 billion46, weighed heavily on the state. Internationally, Nigeria was not such a favoured nation for business transactions: loans and foreign aid had dried up and investors had abandoned the country47. Although a new elected government came into power in 1999 with a platform of reform, investors were not yet convinced of its staying power. Furthermore, the reforms laid out would take time to bear fruit. Amidst this change of power, there was also a fear of possible expropriation of private assets by the state. Hence, the general perception was one of high risk, and it is undisputed that the poor investment climate48 went a long way in determining outcomes.

46 IMF (1999) Memorandum on Economic and Financial Policies of the Federal Government of Nigeria for 1999 accessed on Dec 7 2006 from http://www.imf.org/external/np/loi/1999/022299.htm47 See Ihonvbere, J.O. 2004 The Obasanjo Second Term in Office: Reinventing and Repositioning Nigeria for Growth, Stability and Democracy. West Africa Review, Issue 6.48 Taking GDP as proxy for country’s economic performance, then the climate of investment depicted in Figure 8 is that of unstable system at best.

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Table 11: Contributing elements to success, project issuesCES DetailsFavourable equity arrangements

-Local capital/partner contribution, where possible-Risk appetite for project-Experience with developing country project risk-Involvement of a multilateral partner (and/or host country government)-Reasonable, fair ROE

Favourable debt arrangements

-Low cost financing-Local capital/markets mitigate FX risk -Risk premium demanded by financiers or capped by off-taker matches country/project risk-Credit enhancements effectively lower risk premium -Some flexibility in terms and conditions (possible refinancing)

Secure and adequate revenue stream

-Assurances for timely and complete payment by utility- Robust PPA (stipulates capacity and payment as well as dispatch, fuel metering, interconnection, insurance, force majeure, transfer, termination, change of law provisions, refinancing arrangements, dispute resolution, etc.) - Security arrangements where necessary (sovereign guarantees, escrow accounts, letters of credit, stand-by debt facilities, hedging and other derivative instruments, committed public budget and/or taxes/levies, targeted subsidies and output-based aid, hard currency contracts, indexation in contracts)

Fuel arrangements Ensures reliable and cost-effective supply

Positive technical performance

-Technical performance high (availability)-Sponsors anticipate potential conflicts (esp related to O&M, and budgeting) and mitigate them

Strategic management and relationship building

Sponsors work to create good image in country through political relationships, development funds, effective communications and strategically manage their contracts, particularly in the face of exogenous shocks and other stresses

Figure 8: Nigeria’s GDP Growth Rate in percentage

13

-0.8

2.3

1.3

0.2

2.2

4.4

2.8 2.9

0.41

5.444.6

3.48

10.24

6

5

-2

0

2

4

6

8

10

12

14

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

GD

P G

row

th R

ate

%

Source: CBN various years, complied by authors

As at the time of entry of the first IPP, there was no general policy sector reform. However from 1999, before the inception of the second IPP, the government had initiated the process of general policy sector reform for the power sector. The first step involved the drafting of a power sector reform framework sent to the National Assembly for ratification in 2001. The reform generally included plans for unbundling and privatization. Due to the absence of an independent regulator which came into existence in 2005, regulation was vested in both the Ministry of Power and Steel and in NEPA. Among the most important elements, lay in the actual planning of the project and the delegation of powers to carry out the procurement. As had been previously noted the country was experiencing a severe power shortage and

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there was neither an energy security standard nor built in contingencies to help avert outages. With this backdrop, the Lagos State Government, which had the power (within Nigeria’s Federal System) to negotiate power deals, conducted an exclusive negotiation with Enron to procure up to 560 MW of power, i.e. ICB practices were not followed.

These three factors alone—namely the poor investment climate, the emergency power situation and the closed bidding procedures—may have influenced the terms of the PPAs which allow large and persistent increases in the charges over time that were not anticipated by the Nigerians because they did not understand properly the PPAs that they signed. One example of this is how the capacity charges and O&M charges for IPP B have increased substantially in US$ terms even during the first 2 or 3 years of operation. This is the real smoking gun. The point is that the Nigerians – through NERC - have to really understand their risk exposure to higher payments under PPAs before they enter into them. In addition, corruption has been alleged (but not proven) in terms of impacting on the deal49. NEPA, the then state utility, only became involved late in the game, after the initial agreement had been struck with the American energy company. The cause for NEPA’s involvement was to finalize the transmission agreement, however, due to mounting public pressure about the high tariffs, it was decided by the FGN that NEPA not Lagos State should take over the PPA. NEPA was made a co-party to the payment obligations in the original PPA at the last minute before signature of the PPA in December 1999. Government of Lagos State could not have taken on these obligations.

Several key points should be noted here. NEPA’s primary condition for assuming the PPA was that it would not pay more than US$14.00 per kW per month. With the deal already brokered and with Enron threatening to leave if it did not receive a minimum of US$19.35, the Lagos State Government agreed to make up the difference of US$5.35 per kW per month. NEPA subsequently made arrangements for fuel supply to help further reduce costs by negotiating fuel with the Nigerian Gas Company and Shell (which was significantly less than the price at which the American energy company would have been able to obtain the fuel). The final piece of this story is that when it became apparent that Lagos State would not be the beneficiary of all power delivered by the plant, Lagos State refused to pay the agreed upon US$5.35 per kW and left the full bill of US$19.35 with NEPA.

What is apparent through this analysis is that the investment climate in 1999 went a long way in impacting negatively on outcomes and that had a coherent power sector plan being in place, it could have helped the country avert the emergency predicament in which it found itself. Without doubt, the requisite checks and balances along with an ICB could have also helped to bring down costs and controversy, including alleged corruption. That said, the FGN did intervene and ultimately arrange a fuel contract that would limit its total exposure. Furthermore, the two renegotiations, that between January to June 2000 and the present one, ongoing in 2006, have shown the country’s ability to adjust outcomes.

6.2 The project: staying power?Much has already been written about the influences that impacted on the AES project at the

country level, including the overall investment climate, the policy and planning frameworks, together with the bidding practices and the fuel availability, concluding that of the myriad elements, it was planning (or the lack thereof) that was paramount in determining outcomes, followed by a poor investment environment. This section seeks to touch on the issues primarily under the purview of the investor that shed light on outcomes, including the securing of the revenue stream and the equity arrangements. Through the PPA and a suite of security arrangements, shareholders and debt holders alike were able to secure a revenue stream that by all accounts has been judged positive. As per the renegotiated PPA of 2000 (which presently holds, with negotiations ongoing), underperformance is not fully penalized, as discussed previously in relation to the Availability Deficiency Payment. Sponsors are paid monthly regardless of whether they meet performance targets and then at the end of the year only required to compensate the utility 30 UScents for every US$1.00 paid out. Furthermore, sponsors have benefited from having no fuel risk with the utility arranging fuel and assuming payment. The PPA was backed by a US$60 million Letter of Credit provided by the Federal Government. Furthermore, a US$200 million MIGA guarantee helped allay real and/or perceived country risk, together with the involvement of US Sponsors 49 In June 2001, Nigerian President (General) Olusegun Obasanjo railed against Enron on CNN. "Enron has played a dirty game on us. Dirty game in two ways: the price at which they have tried to sell power to us has been very exorbitant. Two, what they told us they would do, they have not done," he asserted. Ultimately, fearing Nigeria's standing among foreign investors, the government supported the barge project. Source: www.corpwatch.org/article.php?id=3328 - 27k accessed January 29, 2007

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were thus able to counter the perceived risky environment detailed in Section 6.1 above in part through provisions in the PPA.

It should be stated at the outset that minimal verifiable information is available in terms of either the equity or debt arrangements.50 What is known is that in terms of the equity arrangements, equity has changed hands, as previously indicated, in 2000, just after the renegotiation with Enron (which represented a reduction in capacity charges) and just months before the firm’s stock would start to lose the majority of its value. Given what little is known, it is hard to ascertain whether the turnover was primarily a function of: the renegotiation; the firm’s global strategy to exit the bricks and mortar energy business and concentrate exclusively on trading, including in non-energy commodities such as bandwidth capacity; or some other factor. One may conclude, however, that the first American energy company would not have opted out of the country if the circumstances were within its control as the investment was more favorable to it. With negotiations ongoing with the present operator and its Nigerian counterpart, it remains to be seen whether this behavior will be mimicked by the current investors. If PHCN’s proposed amendments are agreed upon, will the present operator/sponsor leave as did the first? With no indication as of yet of an imminent exit, it appears that investors are relatively satisfied with outcomes, with one major exception, namely the failure to issue the tax exemption certificate.

In sum, the PPA clinched the deals, but with renegotiation comes a change of hands. Each renegotiation has represented an attempt by the country to obtain a more favorable deal. This is not creeping expropriation per se but what may be seen as a balancing effort, to ensure continued private investment and ‘affordable’ power.

6.3 The host country: harnessing gasThe general framework and ultimately determining element in IPP B story is the gas flaring

reduction initiative. It was in this context that IPP B project and a series of other gas-to-power projects have been prioritized, including the IPP C project, due online in 2007.

While some improvements had been noted in the investment climate by 2000, investment indicators were still relatively bleak. It was on these grounds that the FGN offered gas investment incentives FGN offered to secure the agreement with national oil corporation’s revenues, which became the government’s primary risk mitigation strategy (later dropped with the IPP C project due to the improvement of the investment environment)—a costly, but ultimately necessary undertaking.

In contrast to the IPP A plant, there was greater certainty about the general policy framework, namely that Nigeria’s IOCs would be engaged in providing power as part of an effort to eliminate gas flaring by 2008. However, other than this general policy, little was spelled out in terms of a detailed policy and planning framework which specified the role and terms for public and private investors as well as any consideration of how a hybrid market might actually function. Also lacking was a detailed, transparent procurement policy. For IPP B, the then due process used in the oil sector was followed, which meant that there was a set procedure, but little transparency to the process. Furthermore, as with the IPP A plant, no independent regulator had been established, and the project was regulated as any oil and gas projects.

Perhaps the biggest boons in terms of the country level elements which contributed favorably to outcomes were the abundant low cost fuel and the fact that the project was part of a larger infrastructure project, which meant that it operated under a larger mandate.

6.4 The project: local presence and money Several features set IPP B project apart from the traditional IPP: the state was heavily involved, controlling 60% of the total equity; and the project was entirely financed by equity. According to stakeholders, this is common activity in Nigeria’s oil sector, again, not in IPPs. In essence, then we witness some new behaviors such as the tax incentives to encourage investment in gas as well as a set of old, established behaviors to ensure that the state ultimately is in control of the investment. More work needs to be done in this regard to understand these behaviors and how ultimately the IPP is a departure from state-owned and operated plants given such hefty state involvement. What may be asserted is that the state, as partner, may help to reduce project risk for foreign and local investors, however, not eliminate it entirely.

Although it has been relatively smooth sailing with IPP B, sponsors and the off-taker are in dispute about the final investment cost (FIC). Operators of IPP B assert that the FIC should be US$462 million.

50 Little has been disclosed about the debt holders, other than that previously mentioned in Section 3.1 related to the loan syndication and timely payment of loans.

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NEPA/PHCN asserts a FIC of US$312 million. The difference of US$150 million is attributed to vandalism as well as underestimating the cost of the transmission infrastructure required. With the negotiation being brokered by National Petroleum Investment Management Services (NAPIMS - the upstream arm of NNPC that oversees Nigeria’s interest in Joint Venture investments with international oil companies) an amicable settlement (compromise) is expected with the FIC adjusted upwards from the earlier agreed figure of US$312 million.

Despite the fact that the state makes up 60% of the equity and that the plant is exclusively equity financed, capacity charges are still denominated in US dollars, exposing the project to foreign exchange exposure risk, but providing a safeguard to foreign investors. This agreement, enshrined in a 20-year PPA, has not been challenged. Thus, unlike the AES plant, no attempts have been made to renegotiate the contract, other than as it relates to the FIC, which would seem to indicate relative satisfaction on the part of both sponsors and off-taker. This contract, as previously mentioned, has been further secured by the national oil corporation’s oil revenues, which mean an even larger commitment on behalf of the state.

Although power is being produced, as highlighted in Section 4, and the investor appears to be satisfied (pending swift resolution of FIC dispute), this analysis sheds light on the extensive involvement and associated cost of the host country government. It is not entirely clear given the mixed involvement of the state, but one might wager that development outcomes have been somewhat compromised in the name of gas flaring reduction, particularly given the final detail of dollar denominated payments.

In terms of development outcomes, the projects had contributed to increasing reliability of supply as seen from Table 3. All performance indices showed increase from pre-IPP period of 1999 to the era of IPPs contributing to the capacity being dispatched to the grid, even though the overall performance of the entire industry is till below internationally accepted standard.

7. Conclusion & next stepsNigeria has developed two IPPs to date, with plans for additional projects in the pipeline. The

projects provide much needed power (presently accounting for a little over 20% of generation). They also offer an important benchmark against the publicly owned plants (previously NEPA/PHCN, now successor companies). The second of the two IPPs also provides an important model and outlet for the Nigerian Natural Gas Strategy which seeks to eliminate gas flaring by 2008, in part by harnessing gas for power generation. Finally the IPPs are part of a transition to privatization and are therefore inherently helpful in paving the way for Nigeria’s proposed future.

The projects are not, however, without controversy. The IIP A plant is presently undergoing its second renegotiation and appears to be underperforming. Meanwhile, stakeholders in Okpai have yet to agree on the final investment cost of the project, which could impact how the scale tilts (i.e. in favor of investment or development outcomes as well as whether existing sponsors stay on).

Outcomes appear to tilt in favor of investors at the expense of the host country, with issues related to planning and the investment climate having made the most significant contribution to outcomes. The fact, however, that the state is so heavily involved, particularly in IPP B, means that a final judgment about development outcomes must distinguish between host country as investor and host country as the consumers of power. This ultimately calls for further research and analysis into the area, namely the extent to which the state as investor leads to enhanced development outcomes.

Even with analysis outstanding, lessons emerge, which largely reinforce the contributing elements to success already enumerated. Chief among these lessons is the need for coherent power sector planning as well as competitive bidding practices. At the project level, the need for more robust PPAs, which ultimately balance investor and development outcomes, has been signaled by the ongoing debate about the terms and conditions of the contracts. Although not raised by stakeholders, the potential for local capital involvement could potentially help balance outcomes as well.

Meanwhile, the ambitious plans for overhauling the Nigerian ESI continue, however, with some delays noted. This has been affected by labour issues, sales of power plants, vandalism of gas pipelines, inadequate gas infrastructure, maintenance and funding, tariff regimes and revenue collection. For the entire power sector, privatization has not proven to be the silver bullet, but viable alternatives are few and far between. The same could be said for the country’s IPPs.

References:

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Adegbulugbe, A.O. (2005) Investments in Gas to Power Projects: The G2P World Bank Assisted Initiative. Paper presented at the Special Presidential Retreat on Power Generation and Supply, Hotel Presidential, Port Harcourt. December 2nd, 2005. Working Paper #2

Belguedj, M, (2002) “Strategic Gas Planning Policy for Nigeria,” The Nigerian Natural Gas Strategy, Stakeholders Workshop, Abuja, December 9, 2002.

Centre for Energy Economics (____), Gas Monetization in Nigeria accessed http://www.beg.utexas.edu/energyecon/publications.php on 14 June 2007

Chao, H., Oren, S. and Wilson, R. 2005, “Alternative Pathway to Electricity Reform: A Risk Management Approach”. EPRI Technical Paper, September.

Energy Commission of Nigeria, ECN (2004), Nigeria Energy Demand and Power Planning Study for the period 2000-2030. Part 1: Energy Demand Projections. Technical Report No ECN/EPA/04/01 Energy Commission of Nigeria, Abuja

ESMAP (2004) Strategic Gas Plan for Nigeria. Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) accessed from http://wbln0018.worldbank.org/esmap/site.nsf/files/ESM27910paper.pdf/$FILE/ESM27910paper.pdf on 14 June 2007

Gratwick, K and Eberhard, A (2006) An Analysis of Independent Power Projects in Africa: understanding development and investment outcomes, MIR Working Paper.

Ihonvbere, J.O. (2004) The Obasanjo Second Term in Office: Reinventing and Repositioning Nigeria for Growth, Stability and Democracy. West Africa Review. Issue 6.

IMF (1999) Memorandum on Economic and Financial Policies of the Federal Government of Nigeria for 1999 accessed on Dec 7 2006 from http://www.imf.org/external/np/loi/1999/022299.htm

Imoke L. (2004) THE POWER SECTOR: The Catalyst for Economic Growth & Development. Presented by the Hon. Minister Power & Steel and Chairman of the NEPA Technical Committee. At an interactive forum with Mr. President. March 2004

Kupolokun, F. (2002) “Issues in Natural Gas Utilization in Nigeria,” The Nigerian Natural Gas Strategy Stakeholders Workshop, Abuja, December 9, 2002.

‘Nigerian Ministry of Petroleum Resources,’ (2006) 2006 Ministerial Press Briefing ‘Nigeria: Abuja re-offers small generating plant,’ (2006) Africa Electra, Issue 59, 21 November.‘Nigeria launches power privatization sales pitch’ (2006) Africa Electra, Issue 41, 14 February.O’Neill, J.,Wilson, D., Purushothaman, R and Stupnytska, A. (2005) How Solid are the BRICS? Global Economics

Paper No: 134. https://portal.gs.com May 14 2006 Okpai PPA (2001) Power Purchase Agreement by and among Federal Government of the Federal Republic of Nigeria,

National Electric Power Authority (NEPA) and Nigerian National Petroleum Corporation (NNPC), Nigerian Agip Oil Company (NAOC) Limited, Phillips Oil Company (Nigeria) Limited - relating to - a 450 MW Power Generation Facility at Okpai, near Kwale, in the Delta State of Nigeria

Omiyi, B (2001) Shell Nigeria Corporate Strategy for Ending Gas Flaring, Seminar on Gas Flaring and Poverty Alleviation, Oslo, Norway, June 18-19.

Plunkett, D 2004, West African Electricity Sector Integration State of Progress and Future Challenges for the West African Power Pool www.aird.com Accessed May 14 2006

Shell MOU (2001) Memorandum of Understanding (MoU) between the Government of the Federal Republic of Nigeria (FGN), National Electric Power Authority (NEPA), Nigerian National Petroleum Corporation (NNPC) and the Shell Petroleum Development Company (SPDC) of Nigeria Limited

Van Meeteren, B (2005) Financing of AES Nigeria Barges Ltd, Presentation at Power Generation World 2005, FMO, April 19.

World Bank (2001) Project Appraisal Document On a Proposed Credit to the Federal Republic of Nigeria for a Transmission Development Project, Report No. 22431-UNI.

World Bank (2002) Nigeria Public and Private Electricity Provision as Barrier to Manufacturing Competitiveness accessed from www.worldbank.org/afr/findings on February 10 2007

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Appendix 1

Table A: Declared versus Delivered Capacity - IPP A 2001 - 2006

Year Month Declared CapacityMW

Delivered CapacityMW

Performance%

2001 Average for the year 157 108.126 68.87%2002 Average for the year 270 187.272 69.36%2003 Average for the year 270 203.256 75.28%2004 Average for the year 270 203.256 75.28%2005 January 300.87 236.67 78.66%

February 300.87 248.68 82.65%March 300.87 243.34 80.88%April 300.87 238.03 79.11%May 300.87 212.11 70.50%June 300.87 218.49 72.62%July 300.87 206.70 68.70%August 300.87 235.37 78.23%September 300.87 211.50 70.30%October 300.87 237.50 78.94%November 300.87 232.27 77.20%December 300.87 230.97 76.77%Average 300.87 229.30 76.21%

2006 January 300.87 186.31 61.92%February 300.87 205.19 68.20%March 300.87 226.27 75.21%April 300.87 240.41 79.90%May 300.87 244.40 81.23%June 300.87 210.22 69.87%July 300.87 219.04 72.80%August 300.87 206.70 68.70%September 300.87 197.71 65.71%October 300.87 208.88 69.43%Average 300.87 214.51 71.30%

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Table B: Declared versus Delivered Capacity – IPP B May 2005 – October 2006

Year Month Declared Capacity Delivered Capacity

Performance%

2005 May 150 117.00 78.00%June 300 272.52 90.84%July 300 146.96 48.99%August 300 227.54 75.85%September 300 224.25 74.75%October 300 204.00 68.00%November 300 229.45 76.48%December 300 325.54 108.51%Average 281.25 218.41 77.68%

2006 January 450 377.55 83.90%February 450 241.08 53.57%March 450 408.07 90.68%April 450 400.64 89.03%May 450 327.66 72.81%June 450 384.82 85.52%July 450 352.26 78.28%August 457 305.37 66.82%September 457 415.35 90.89%October 457 423.51 92.67%Average 452.1 363.63 80.42%

Observations/Comments:

1. Based on the performance data above, IPP A did not meet up with the contract agreed level of 90% as they delivered an average performance of 72.72% for the years reviewed.a. This means that the plant had not been reliable in terms of development outcomeb. Based on the ‘agreed’ high capacity payment, the plant is also not affordable for development

outcomec. In terms of investment outcome, IPP A is guaranteed 70% payment, if the 30% (max) of liquidated

damages payable to PHCN after yearly reconciliation of accounts is put into consideration. Reconciliation is done due to the fact that IPP A is unable to deliver agreed utilized capacity of 90% of declared capacity. In other words, take-or-pay terms in the contract guarantees a revenue stream of 70% capacity charge yearly. To this NEPA/PHCN had not defaulted even though there had been delays in some instances. The investment outcome is therefore positive

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