Domestic Supply Obligation and Gas Pricing Policy

Transcription

1 Domestic Supply Obligation and Gas Pricing Policy Under the DSO, every gas producer must allocate a portion of their production to the DSO before they can allocate any gas to other commercial obligations. Non-compliance would result in significant penalties. Once the gas producer has satisfied its DSO quota, any amount of gas produced in excess of that can be sold on a willing buyer/willing seller basis. The amount each supplier must allocate is not fixed but is determined each year based on domestic demand and the number of gas suppliers. Allocation to each supplier is done on an equitable basis determined by the Minister for Energy. Before the DSO was introduced and became operational in 2010, practically all gas produced was exported because the price the PHCN GenCos were willing (and able) to pay was too low to make it commercially viable to supply gas to local GenCos. The situation could not persist if the Nigerian government wanted to attract investment not only to the power sector but also to the gas sector. It was accepted that the age of effectively financially and structurally subsidising the power industry had passed. However in order to ensure, as far as possible, a smooth transition to a free-market system in the gas industry and in other strategic industries, price increases would have to be managed rather than left to the market to set the level. The regulated pricing regime for the DSO (bulk of which is for power) is based on determining the lowest cost of supply that will allow a 15% return to the supplier. This floor price has been set at US$0.10 per Mcf 31. The actual price paid for gas includes an escalation for inflation and an indexation to the real time product price and/or any other indices that the buyer and seller agree upon. The Ministry of Energy determined that the cost reflective baseline was c.us$1.00 per Mcf by This was later reviewed to US$1.50 per Mcf. The main sticking point with the DSO has been on the issue of pricing because the baseline price paid to the producers for DSO gas to power has been below the market price (now US$ per Mcf). On 2 August 2014 the FGN announced a revision in the DSO gas-to-power price for 2014 to US$2.50 from US$2.00 per Mcf as part of measures to bridge this pricing issue. This brings the DSO price closer to, but still well short of the market spot price of US$ per Mcf. The DSO price is expected to reach export-parity in 2016, thereby doing away with the need for price regulation. MYTO II factors in a gas price of US$2.19 per Mcf by Thousand Cubic Feet Page 101

2 US$ per Mcf US $ per Mcf Nigerian Power Sector Chart 21: DSO Gas Price to Power Profile ( ), US$/Mcf Chart 22: Old Gas Price to Power vs Annual Price of US LNG Imports from Nigeria, US$/Mcf Current Market (Spot) Price Range On 2 August 2014 the FGN revised the 2014 DSO gas-to-power price to US$2.50 per Mcf Annual Price of US LNG Imports from Nigeria Old Gas Price to Power Est Est Source: NERC, CSL Research Source: NERC, US EIA, CSL Research Figure 30: Operation of the Domestic Supply Obligation Domestic Buyers Other Exports Power Plants Fertiliser Plants Methanol Plants Regional Pipelines Pure Liquefaction LNG Plants Gas Transmission Line Central Gas Processing Facility (CGPF) Excess Gas Over DSO Bilateral Contracts Integrated LNG Plant With Own CGPF Gas for Own Export Projects Domestic Supply Obligation (DSO) Wet Gas Gas Suppliers (International Oil Companies & Independents) Source: CSL Research Page 102

3 Aggregate Price Nigerian Power Sector Gas Aggregation Company The Gas Aggregation Company Nigeria Limited (GACN) is the aggregator of natural gas produced for domestic use in Nigeria. It acts as an intermediary between suppliers and buyers of natural gas in the Nigerian domestic gas market and ensures that the Strategic Sectors are supplied with gas under the appropriate pricing schedule. Its responsibilities also include managing receipts of payments and disbursement of an aggregate gas price to suppliers and facilitating the execution of necessary securities in respect of default of gas payments. The only three entities permitted to buy gas through the GACN are: GenCos whose sole business is to generate power to the national grid; companies that use gas as feedstock for their end products; and local distribution companies which sell gas to commercial and manufacturing companies in the domestic market. A Gas Supply and Aggregation Agreement (GSAA) between the buyer, seller and the GACN governs terms of gas supply and purchase. While the GACN is not itself a regulator, it interfaces with the Department of Petroleum Resources (DPR) 32 on the due diligence process it conducts on buyers, demand rationing criteria and DSO management. The gas market lacks a clear regulatory hierarchy as various organisations such as the GACN, NGC, DPR and PPPRA 33 all act as pseudo regulators to a greater or lesser degree. It is hoped that the long-awaited Petroleum Industry Bill, should it be eventually passed by the Legislature, will clarify the situation. Figure 31: Operations of the Gas Aggregation Company of Nigeria Power Sector Price Supplier 1 GBI Sector Price GACN Supplier 2 LDC Sector Price Supplier 3 Cash Flows Gas Flows Source: CSL Research, GAGN GBI: Gas-Based Industries LDC: Local Distribution Companies. Domestic sellers of gas to commercial and manufacturing companies. 32 Part of the Ministry of Petroleum Resources. 33 Petroleum Products Pricing Regulatory Agency Page 103

4 Russia Iran Nigeria Iraq Venezuela Angola US Indonesia Libya Mexico Algeria Kazakhstan Canada Brazil Congo (Brz) Billion Cubic Feet (Bcf) Billion Cubic Feet (Bcf) Nigerian Power Sector Gas Flaring Financial Waste & Environmental Scourge In the current operating environment natural gas in Nigeria is essentially a by-product of extracting crude oil. In 2011, having flared or vented 620 BCF of natural gas, Nigeria was second only to Russia, a country that produces over 10 times as much gas as Nigeria. There was slight improvement in 2012 when Nigeria claimed the no.3 spot, having flared 587 BCF of natural gas. This amounted to 23% of gas extracted in It is estimated that flaring gas costs Nigeria between US$ billion a year in lost direct revenues. Thus by reducing flaring to a minimum, the Nigerian gas industry can be self-funding vis-à-vis the investment in infrastructure that is required to bring the infrastructure up-to-scratch 34. Chart 23: World s Top Gas Flaring Countries, 2012* Chart 24: Nigeria Gas Production vs Flared, , % 45% 2, % 32.6% , % 27.7% 30% 24.3% 25.8% 22.7% ,500 1,000 15% % Gross Production Flared/Vented % Flared/Vented Source: US EIA, CSL Research * Mexico, Kazakhstan, Brazil & Germany = 2011 Source: NNPC, CSL Research Financial Loss The real cost of gas flaring to the economy is greater if we include loss of opportunity and production losses from the lack of gas supply to power plants. We have used another proxy to indicate the extent of financial/opportunity waste resulting from flaring gas. We look at the ratio of carbon dioxide (CO 2 ) emissions from flaring alone to carbon dioxide emissions from both consumption (a productive activity) and flaring. If we compare Russia and Nigeria, both are responsible for about 14% of world CO 2 emissions from flaring gas. However, CO 2 emissions from flaring represent just 3% of Russia s total CO 2 emissions from both consumption and flaring of natural gas. Russia at 3% compares to Nigeria at 75% (Chart 25). 34 Estimated at US$1.5-2 billion over the next five years. Page 104

5 Russia Nigeria Iran Venezuela Iraq Angola US Indonesia Mexico Algeria Qatar Brazil Canada Congo (Brz) Cameroon Million Metric Tonnes Nigerian Power Sector Chart 25: Degree of Opportunity Loss from Flaring Productive CO 2 Emissions (from Consumption) vs Wasteful CO 2 Emissions (from Flaring) 35 91% 90% 90% 100% 30 75% 80% % 60% 15 40% 10 22% 5 3% 9% 1% 11% 5% 10% 12% 6% 2% 20% 0 0% CO2 2 from Flaring flaring % COCO2 2 from Flaring flaring vs. Total CO2 2 from Consumption consumption & and Flaring flaring Source: US EIA, CSL Research 2011 Figures Page 105

6 Environmental Cost The financial cost to a country of flaring is one thing but the overall cost to the country is far higher. A more holistic approach would include the environmental cost by way of air pollution, carbon emissions etc. Without any suitable carbon-capture technologies in place, Nigeria also ranks high in carbon dioxide emissions from flaring (Table 20). Table 20: Carbon Dioxide Emissions from Gas Flaring, 2011 (MMT) World Rank CO 2 Emissions from Flaring 1 Russia Nigeria Iran Venezuela Iraq Angola United States Indonesia Mexico Algeria Qatar Brazil Canada Congo (Brazzaville) Cameroon 2.7 WORLD AFRICA 64.0 Source: US EIA MMT Million Metric Tonnes Pragmatism on Green Electricity and the Environment Having consideration of the environmental impact of any industrial activity has become as critical as the evaluation of the economics. So much so that major finance institutions such as the World Bank, the IMF and the African Development Bank will not support a project without an environmental impact assessment report. Nigeria, in looking to make more constructive use of its gas reserves and reduce flaring, improves its environmental awareness credentials significantly. We acknowledge that thermal power generation is far from being carbonneutral, however it causes less environmental damage than flaring gas. The thermal generating plants in situ and those planned are open-cycle gas turbine (OCGT) plants rather than combined-cycle gas turbine (CCGT) plants largely due to the fact that CCGTs have higher construction costs 35. However it is anticipated that over time many will be converted to CCGT plants as these are more energy efficient and have less impact on the 35 See Appendix 5: OCGT and CCGT Power Plants, page 189. Page 106

7 environment. The advantage of having efficient electrical power supply to households is easy to appreciate as it would alleviate the need to burn biomass for light and heat. There are also benefits to industry by making it more energy-efficient. It is still early days and there are more ground-level activities to address regarding power generation. Notwithstanding we consider it commendable that the FGN s plans have integral yet pragmatic considerations for reducing the carbon footprint of the power industry. Renewable energy such as solar power, wind and small hydro have dedicated resources at the federal level to support and encourage the expansion of this sub-sector under the aegis of the Federal Ministry of the Environment. We believe that the incorporation into MYTO II of a specific tariff schedule for electricity generation from renewables is a firm indication of the FGN/NERC s longterm commitment to green electricity. Figure 32: Gas Processing and Transport in Nigeria Domestic Buyers Lean Gas Gas Transmission Line Dry Gas Gas processed and treated to remove impurities Central Gas Processing Facility Power Plants Wet Gas LPG & NGL Wet Gas Gas, other hydrocarbons and impurities extracted Gas Compressor Station Gas Compressor Station LPG Storage Trucks Gas Wells LPG Liquefied Petroleum Gas NGL Natural Gas Liquids Ships Source: CSL Research Page 107

8 Chapter 10: The Privatised Power Sector The Nigerian Electric Power sector has now been privatised to the extent planned. The new owners took control of the Successor GenCos and DisCos on 1 November But for nominal (non-participatory) holding stakes retained in some GenCos and DisCos, the FGN is effectively out of the power generation and distribution business. It only maintains control over transmission system operation and market operation, for now. Ideally, the FGN would have preferred to privatise the entire electric power supply value chain and just retain regulatory oversight and monitoring. However for a number of reasons, some alluded to in previous chapters and others to be elaborated on in those ensuing, the FGN has had to settle on privatising just the PHCN DisCos and GenCos and, it hopes soon, the NIPPs. Figure 33: The Privatised Nigerian Electricity Supply Industry NIPPs Successor GenCos IPPs IPP Distribution Licence Holder TCN NBET Embedded Generation Successor DisCos Private Generators Private Generators Private Generators Source: CSL Research Credit Where and When Due In our view it is already an achievement that long-held vaulted plans to privatise the PHCN GenCos and DisCos per se have been seen through. In any context privatising a state utility is no small feat. Irrespective of the motives behind allowing this attempt at reform (for there have been many) to get as far as it has, it is a sine qua non that realism and pragmatism enabled the FGN to see the raiment-less emperor NEPA in the bare state it was. It is only from such a point that a workable plan could be devised. Page 108

9 Leadership and Intellectual Capital Responsibility Unlike the case of mobile telephony, it was impractical to start the entire electricity system of the country from scratch. Transforming a moribund industry into one with the culture, systems and technology fit for the twentyfirst century was going to require unwavering commitment and intellectual brawn. Any hope of success in privatising the electricity sector was/is dependent on getting the right professionals in to oversee the process and to lead the new institutions. In our estimation, and gauging by the opinions of numerous industry stakeholders we have canvassed, the FGN has done well in this regard. The intellectual and professional capital of key institutions like the regulator NERC, NBET and TCN has been bolstered by recruiting skilled leaders from within the domestic power industry and also from outside the domestic market. However we have reservations about the amount of political interference that could come from the country s Executive and Legislative arms going forward. Our concerns particularly relate to NERC and TCN. The degree to which these two institutions are left to carry out their statutory roles independently and for the benefit of all the stakeholders in the electricity market and they actually do so, is the degree to which the privatised industry will endure, will be efficient and will be profitable. The Privatisation Process What, When & How? The FGN sold 60% stakes in 11 successor DisCos to the private sector raising US$1.46 billion. It also sold between % stakes in 5 successor thermal GenCos and awarded 15-year concessions for 2 successor hydroelectric power plants, raising US$1.65 billion. Purchasers of Successor GenCos and DisCos Table 21 and Table 22 below give the names of the winning bidders for the successor GenCos and DisCos respectively. We expand these tables with the salient details of the privatisation in Table 21 and in Table 22 at the end of this chapter. In the tables we include the parties within the winning consortia and have sought to identify, as far as possible, key individual(s) connected with each of the winners. Page 109

10 Table 21: Purchasers of Successor DisCos Successor DisCo Purchaser Bid (US$ mn) Stake Acquired Distribution (GWh) Abuja Electricity DisCo KANN Consortium Utility Co. Ltd % 1,802 Benin Electricity DisCo Vigeo Power Consortium % 1,855 Eko Electricity DisCo West Power & Gas Consortium % 1,440 Enugu Electricity DisCo Interstate Electric Consortium % 1,920 Ibadan Electricity DisCo Integrated Energy Distribution & Marketing % 1,989 Ikeja Electricity DisCo NEDC/KEPCO Consortium % 2,077 Jos Electricity DisCo Aura Energy Ltd % 714 Kaduna Electricity DisCo Northwest Power Ltd % 1,233 Kano Electricity DisCo Sahelian Power SPV Consortium % 788 Port Harcourt Electricity DisCo 4Power Consortium % 1,164 Yola Electricity DisCo Integrated Energy Distribution & Marketing % 265 Source: BPE Table 22: Purchasers of Successor GenCos Successor GenCo Purchaser Bid (US$ mn) Stake Acquired Installed Capacity (MW) Afam Power Taleveras Energy Group % 776 Egbin Power NEDC/KEPCO Consortium % 1,320 Geregu Power Amperion Power Distribution Co. Ltd % 414 Kainji Hydro Electric Mainstream Energy Solutions Ltd A 15-yr concession, the fee structure being: 1) A commencement fee (the bid price); 2) Yr1-Yr5 a royalty payment of 5% of plant annual revenues; 3) Yr6-Yr15 a fixed annual fee US$50.8mn. 760 Sapele Power CMEC/EURAFIC Energy Consortium % 1,020 Shiroro Hydro Electric North South Power Consortium A 15-yr concession, the fee structure being: 1) A commencement fee (the bid price); 2) Yr1-Yr5 a royalty payment of 5% of plant annual revenues; 3) Yr6-Yr15 - a fixed annual fee US$23.6mn. 600 Ugheli Power Transcorp Consortium % 942 Source: BPE Page 110

11 Industry Agreements In February 2013 the preferred bidders and the BPE signed Shareholders Agreements and Share Sale Agreements. They also executed Industry Agreements which serve as the framework for the fully-commercialised power sector. The following have emerged as some of the key documents which will need to be in place and bankable for power sector financings: Share Sale Agreements (DisCos and thermal GenCos) Concession Agreements (Hydro GenCos) Gas Supply and Aggregation Agreements Gas Transportation Agreements Power Purchase Agreements (GenCos; 15 year duration): capacity and energy payments are broken into Naira and US Dollar components. The foreign components are payable in naira at the prevailing exchange rate. Vesting Contracts (DisCos; 15 year duration) Transmission Use of Network System Agreements Grid Connection Agreements Ancillary Services Agreements Bulk Trader Credit Support Deed of Assignment of Pre-Completion Receivables Operations and Maintenance Agreement Pre-Completion Liabilities Transfer Agreement Future Performance Evaluation and Monitoring The Nigerian Electricity Supply Industry (NESI) is now fully regulated. NERC is charged with overall regulation and issuing of licences for participants in the sector. The BPE is the FGN s signatory to the agreements with the new owners of GenCos and DisCos. The documents that govern the monitoring and regulatory frame work are in Table 23. Page 111

12 Table 23: NESI Monitoring and Performance Evaluation Documents Governing Document Share Sale and Purchase Agreement (SSPA) Performance Agreements (PA) Scope Terms and conditions of sale of shares to investors Contains terms of payment and Post- Acquisition Plans (PAP) implementation BPE's Post Privatisation Monitoring Template NERC's Reporting compliance Regulation NERC's Terms and Conditions of Licensing Outlines the level of compliance and standards expected of utilities Sets out mandatory requirements for acquiring a licence and penalties for breach of terms. Source: BPE Post-privatisation monitoring by the BPE was expected to start in May But as TEM has not yet been declared, it is not likely that the full scope of performance monitoring under the regulatory powers given to the BPE and NERC will be in effect. The Performance Agreement (PA) is the main document empowering the BPE in its monitoring function. Compliance monitoring gives the BPE the right to enter and monitor the privatised companies every six months upon giving five days notice of such action. It also gives it the right to audit or review the businesses every six months. Performance Obligations Under the PA General The intent of these general provisions in the PA is to ensure that the investor is held to the spending plans. The BPE retains these rights to ensure that the development of the NESI remains on target. From a public policy perspective, we consider this to be a shrewd arrangement by the BPE/NERC given the FGN will no longer have direct control of the GenCos or DisCos and will not be contributing any capital pro rata to its retained stakes 36. Some general provisions of note include: The investor must ensure the purchased DisCo or GenCo achieves the Minimum Performance Targets; The investor is liable to pay liquidated damages for performance falling below the stipulated standard; 36 Thus in the case of any further capital raising by the GenCo or DisCo in which the FGN has retained a stake, the FGN s holding with be diluted. Page 112

13 The investor must comply with the initial budget and Post-Acquisition Plans (PAP) set out in the Performance Agreement, to which they agreed to enter when they signed the SSPA. For the first 5 years, annual revisions to budgets and plans require the consent of the BPE and thereafter the BPE reserves the power of veto over certain expenditures; The investor is not allowed to take on senior debt without the prior consent of the BPE, which shall not delay or unreasonably withhold consent. This provision is included to safe-guard against the Successor Companies being laden down with debt; The Debt to Equity ratio of the successor company cannot exceed 70:30 for the first 5-years. Thereafter it may only rise to 75:25; Insurance cover must be maintained on the companies at all times; Performance obligations are to be secured by Parent Company Guarantee. In the case of a consortium, the parent company of the lead investor is to provide the guarantee, subject to BPE approval in relation to the technical and financial standing of the parent company. Successor GenCos-Specific: Successor GenCos capacities are expected to be increased from current low available capacity levels to meet minimum target generation capacities set out in the Industry Agreements. Successor DisCos-Specific: The performance of the business operations of the new owners of the successor DisCos will be measured on the basis of their abilities to reduce distribution losses to loss targets specified in their business plans. They will also have targets for expanding their distribution networks and in connecting new customers. ATC&C Losses The Successor GenCos were sold to the highest bidder for the specific GenCos. Bidders for the Successor DisCos, on the other hand, were given the figure the FGN was going to sell the DisCo for and the evaluation of bids was on the basis of the projected reduction in Aggregate Technical, Commercial and Collection Loss (ATC&C Loss) over the first five years of acquisition. The DisCo was sold to the bidder with the highest reduction in ATC&C Loss. The ATC&C loss figure is a key performance indicator for power distribution companies. It enables operators to monitor efficiency and profitability in delivery of power to customers. ATC&C Loss is the difference between the amount (in MWh) of electricity received by the DisCo and the amounts Page 113

14 billed and received from customers (in ). The difference in electricity received by the DisCo and electricity it bills the customer gives the technical and commercial loss, while the difference in the amount billed and the amount received/collected from the customer gives the collections loss. Thus reduction in these losses improves profitability. Each bid contained a 5-year ATC&C Loss reduction schedule based on a starting loss figure provided by PHCN. The winning bidder had the lowest end loss level for that particular successor DisCo. The purchasers ATC&C Loss figure is very important because the purchaser s end level figure is then incorporated into the MYTO model, as each DisCo has its own MYTOdetermined tariff plan. If the purchaser does not achieve the loss target, it will be less profitable than it has planned, and vice-versa should the target be exceeded (i.e. the end ATC&C Loss figure achieved turns out lower than targeted). If the purchaser consistently fails to meet its loss-reduction targets, NERC may decide to revise the purchaser s capex allowance amount under its DisCo tariff. The ATC&C Loss targets of the winning bidders are shown in Table 24. Table 24: Distribution (ATC&C) Losses and Loss Reductions Successor DisCo Winning Bidder Opening Loss Bidder's Yr 5 Loss Bidder's Yr 5 ATC&C Loss Relative to Opening Loss Abuja DisCo KANN 35.00% 12.78% % Benin DisCo Vigeo Power 40.00% 12.19% % Eko DisCo West Power & Gas 35.00% 12.76% % Enugu DisCo Interstate Electric 35.00% 6.70% % Ibadan DisCo Integrated Energy 35.00% 12.71% % Ikeja DisCo NEDC/KEPCO 35.00% 9.99% % Jos DisCo Aura Energy 40.00% 18.09% % Kaduna DisCo Northwest Power 40.00% 11.70% % Kano DisCo Sahelian Power 40.00% 13.02% % Port Harcourt DisCo 4Power 40.00% 14.90% % Yola DisCo Integrated Energy 40.00% 17.34% % Source: BPE India s Tata Power Delhi Distribution Limited (TPDDL) is a joint venture between Tata Power and the Government of the National Capital Territory of Delhi, with the majority stake being held by Tata Power (51%). Tata Power acquired its stake following the unbundling of the Delhi Vidyut Board (DVB) in As is the case for investors in Nigeria s DisCos, Tata also had five-year ATC&C Loss reduction targets. Its opening ATC&C Loss was 53% and its target was 31%. TPDDL s ATC&C Losses stood at 11% at the end of the 2012/13 financial year. This compares to a world average of about 15%. Page 114

15 Table 25: Successor DisCo 5-Year Capex* Table 26: CSL Estimated* Successor GenCo Capex (US$ million) Capex Abuja DisCo 180 Benin DisCo 119 Eko DisCo 134 Enugu DisCo 215 Ibadan DisCo 112 Ikeja DisCo 147 Jos DisCo 149 Kaduna DisCo 222 Kano DisCo 288 Port Harcourt DisCo 125 Yola DisCo 64 Total 1,755 Source: NERC * MYTO II Model assumptions. NGN:USD rate of 160 Installed Capacity (MW) 2011 Available Capacity (MW) Estimated Capex (US$ mn) Afam Power Egbin Power^ 1, Geregu Power Kainji Hydro Sapele Power 1, Shiroro Hydro Ughelli Power Total 5,790 2,401 3,915 Source: BPE, CSL estimates * Please note boxed commentary within the main body of the report. ^ Not included in 2011 BPE presentation. Figures from market sources. - NOTE - There have been varying reports over the last few months of the level of Available Capacity (AC) of these successor power plants and it continues to be difficult to get precise figures. Now that the GenCos are under private ownership, for the time being at least, we expect the precise figures to be considered privilege between the operators and NERC/BPE. This is especially so given the sensitivities surrounding the delay in the declaration of TEM and the operation of the Interim Rules Period. Notwithstanding, we wanted to have a rough sense of how much capex could be required to get each GenCo's Available Capacity close to its Installed Capacity, as this is a key performance requirement of the new owners set out in the Performance Agreements signed with the BPE. At the 2011 Bankers Conference Workshop for the PHCN privatisation, the BPE provided the AC of each PHCN GenCo. We have based our calculations on this figure and used the MYTO II model s level for AC of 95% as our target. Given the 2011 AC date, we caveat our calculated figures because the reality on the handover date may have been higher or lower for any of the GenCos. We have assumed that each MW added for the gas-fired plants costs US$1.15 million based on the industry yardstick of US$1-1.3 million of capex per MW. We have used the MYTO II estimate of US$1.8m per MW for the hydro plants. Page 115

16 Current Market Stage Interim Rules Period Figure 34: Key Characteristics of the Market Stages in the Evolution of the Nigerian Electricity Supply Industry Pre-TEM Stage Interim Rules Period (IRP) Transitional Electricity Market (TEM) Medium Term Market Long Term Market Unbundling of NEPA/PHCN; Privatisation of PHCN GenCos and DisCos; Review and subsequent application of the Market Rules and procedures; Establishment of performance incentives and performance standards for the distribution and generation companies; Payments and settlements based on Shadow Trading and Transfer Pricing; NBET, TCN and PRGs not yet operational; TEM was expected to start at the end of January However a number of factors made NERC deem it necessary to delay the start of TEM and introduce a set of Interim Rules. Notable points on the IRP: i. As contracts of the privatisation such as PPAs and VCs only become fully enforceable once TEM is declared, Successor GenCos and DisCos are expected to continue with their Pre-TEM trading arrangements during the IRP. ii.gencos bill the Market Operator (MO) for electricity generated and available capacity based on MYTO II tariffs. However as Pre-TEM contracts apply, Transfer Pricing and Estimated Billing is in operation. iii.the MO continues to bill the DisCos for electricity. iv.the MO determines the allowable amount of funding (the Minimum Funding Requirement) for the Successor DisCos, Successor GenCos and for the Service Providers including NERC, the Transmission Service Provider (TSP) and the System Operator (SO). NBET and TCN roles within NESI become effective/operational; Contracts of privatisation signed between Successor Companies and State institutions including Power Purchase Agreements (PPAs), Vesting Contracts (VCs) and Partial Risk Guarantees (PRGs) become effective; Payments and settlements based on prices and terms contained in PPAs and in VCs. No centrally-administered balancing mechanism for the market; Development of procedures for the management of inadequate supply and shortage in the system; Open access to the transmission network to GenCos and DisCos. Wholesale Electricity Market will be the balancing market for trading electricity in the industry. It will be characterised by a spot market where electricity prices are set daily. DisCos and GenCos will be permitted to enter bilateral contracts for the purchase and/or sale of electricity. Open entry to the transmission network to GenCos, DisCos and large power consumers. All subject to technical and environmental obligations, and overseen and licensed by the regulator NERC. Retail competition - all consumers choose their suppliers; Clear differentiation between distribution (delivery) and retail activities; Open access to the transmission and distribution networks. Source: CSL Research Page 116

17 Table 27: Pre-TEM and TEM Characteristics Compared PRE-TEM TEM Market Structure Pricing Regime Service Provision Payment & Settlement System Source: CSL Research Transmission, Distribution and System Operations retain their monopoly and regulated status during Pre-TEM and TEM. Sellers:- Sellers:- - Successor GenCos - Successor GenCos - IPPs with PPAs - IPPs with PPAs Buyers:- Buyers:- - Successor DisCos - Successor DisCos (also licensed as marketers) - International connections - International connections/customers - Local large power consumers - Local large power consumers Service Providers:- Service Providers - TSP - TSP - ONEM Market Operator - NBET - System Operator - TCN System Operator - Central (Headquarter) Services - TCN Market Operator Transfer Pricing Successor GenCos and IPPs sell to Successor DisCos - Successor GenCos sell at Transfer Prices calculated every 3 months - IPPs sell at their PPA prices Buyers:- - Successor DisCos buy at Transfer Prices - International connections buy at prices in their Connection Agreements. - Local large power consumers buy at regulated end-user tariffs Vesting Contract and PPA Prices TSP TSP - Provides transmission access to both GenCos and DisCos - Provides transmission access to both GenCos and DisCos - Recognises and accounts for transmission losses - Recognises and accounts for transmission losses ONEM Market Operator NBET - Commercial administration of the market including settlements and payments using Market Rules - Commercial administration of the market including settlements and payments using Market Rules System Operator TCN System Operator - Technical administration of the market using the Grid Code and provision of other services for grid stability. - Technical administration of the market using the Grid Code and provision of other services for grid stability. Central (Headquarter) Services - Pricing of transmission access - Provides common services such as funding of special projects, emergency funding Market does not always balance Market in equilibrium - a debit by a DisCo has a corresponding credit to a GenCo therefore NBET maintains a zero balance. Shadow Trading Wholesale Electricity Market Trading - MO receives payments into its market clearing account from - NBET receives and transfers payments between GenCos DisCos and eligible customers and Successor DisCos - Existing IPPs sell through PPAs with NBET - New IPPs may contract to sell either to NBET or with the - MO transfers payments to GenCos and service providers DisCos directly Settlement Settlement - Per individual settlement calendar - Market settlement each month (M) for each DisCo - DisCos sell at uniform prices and use estimated billing - Monthly payment (M+1 month) - IPPs sell at PPA prices; Successor GenCos at various Transfer Prices. Payment Payment - DisCos submit a Letter of Credit covering three months of payments to be drawn down (plus interest) in the event of - Payment made into escrowed settlement accounts non-payment by the DisCo. - Incomes in line with MYTO II Revenue Requirement - Based on Minimum Funding Requirement determined by the MO provisions - The Transfer Price is expected to cover the budget for operating costs only. - Per MYTO II, capital costs and return on investments can also be recovered. Page 117

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19 PART III The Investment Case Page 119

20 Chapter 11: Pitfalls and Opportunities It is an indisputable fact that the supply/demand gap for power in a country with a population of almost 170 million generating less than 4GW presents a prima facie investment opportunity. How the theory (of the new regime) works in practice is the crux of the investment case for the Nigerian power sector. As with any such sector-wide endeavour, stakeholders (investors, customers etc) and other commentators need to make allowances for the journey not going entirely smoothly. This is not a Nigerian phenomenon but is to be expected in the implementation of corporate or industry-wide strategy the world over. The concern and hope is that these bumps amount to minor, surmountable hiccoughs. We ultimately want to identify where the equity is in the new sector and assess how much funding is available to make the required investments. This involves an initial evaluation of the main risks in the Nigerian Electricity Supply Industry. We have grouped the risks methodologies adopted and operating procedures in the NESI Financial and Systemic Risks. The latter not least highlighted by and revealed in the Interim Market and the delay in the declaration of the Transitional Electricity Market (TEM). We then analyse the Structural Risks of the industry. GENCOS GAS SUPPLIERS END-USERS FGN DISCOS FINANCE MARKETS NERC TCN / NBET Page 120

21 Chapter 12: Financial Risks We will address two core financial risks in this chapter: 1. The skewness of risk allocation amongst counterparties; 2. Critical problems with MYTO II, which in practice results in a tariff structure that is not commercially sustainable as it currently stands. Network Risk Allocation Skewed Against Discos NERC insists that the pricing structure is set so that it spreads the risks equitably among the users of the transmission network. It is intended to assign the costs or charges to the user or group of users incurring those costs 37. At the same it states that the rationale on risk allocation is that the pricing arrangements should allocate risks efficiently [which implies] generally to those who are best placed to manage them. 38 These two phrases may strike one as incompatible because they both claim to be the premise on which the transmission tariffs are set and load allocated, yet on interpretation they could lead to different results. One purports to allocate costs to the user(s) incurring the cost and yet for the second to also hold true, it implies that costs are incurred by those best placed to manage them. This is not necessarily the case. If we then look at how this has worked in practice, in MYTO II the bulk of the cost of the transmission network (build, management and maintenance) is charged to the DisCos 80% of the TUOS charge is borne by the DisCos. It is not immediately apparent why: (a) 80% of the cost of getting the energy from the generator to the distributor/retailer should be incurred by the DisCo and/or (b) the DisCo is considered to be better placed and more efficient than the GenCo to manage transmission costs. All these costs are ultimately passed onto the end-user, so it could be said that neither GenCo nor DisCo are disadvantaged. However from a cash management and capital structure perspective, to say the least, it does matter. It has implication for the risk exposure of the businesses hence their cost of capital and returns profiles. 37 NERC Multi Year Tariff Order for the Determination of the Cost of Electricity Transmission and the Payment of Institutional Charges for the Period 1 June 2012 to 31 May 2017 (herein after MYTO II Transmission ); p MYTO II Transmission, p. 17. Page 121

22 According to NERC, if GenCos were to be exposed to connection charges, they would be more likely to choose locations that minimise these charges. NERC contends that this could be detrimental to the even distribution of access to electricity across the country. GenCos Not Let Off in Entirety NERC asserts that GenCos have an incentive to reduce the losses associated with transmitting their generated energy. GenCos have limited ability to effect improvements in transmission losses (and by equivalence Marginal Loss Factors, MLFs). We believe the incentive to improve this is limited since they do not bear the cost of system transmission loss. They can minimise the losses associated with transmission up to their network node connection point, however it is on a de minimis scale when considering the vast bulk of transmission occurs after title/responsibility passes from them at their node connection. DisCos essentially pay for transmission losses however they too have no means of reducing these losses. They are not in control of the spending to improve and extend the transmission network even though they provide the financing (through the TUOS charge). Under the terms of the PRG, NBET/TCN bears the risk of Availability Events. It essentially guarantees transmission. We understand the full implication of this, in light of the realities of the market post handover, might be weighing heavy on the FGN. Current negotiations, renegotiations and discussions during the Interim Rules Period may well be seized upon to adjust the blanket guarantee. However we believe this would send a very negative signal to the market as it smarts of an inclination of the FGN shifting the goal posts after the fact. The MYTO II Powder Keg We have analysed the methodology and assumptions used in the MYTO II models for generation, transmission and distribution. In Chapter 5: we talked about the theoretical soundness of the methodologies used and pointed to similar examples in other electricity markets. It goes without saying that the utility of a financial model is only as good as the assumptions plugged into it. We have found the MYTO II model does not stand up to scrutiny in this regard. The components of the gun powder we have identified which we discuss in detail next are: A. Generation Technical Assumptions (i) Available Capacity Factor assumptions need to be more conservative (ii) Construction period for Large Hydro is too ambitious (iii) Plant Availability needs to be lowered (iv) Fuel cost assumption is too low B. Miscalculation of Wholesale Prices leaves GenCos short C. Transmission Capex is insufficient for actual requirements D. Distribution ATC&C Losses assumptions are too low Page 122

23 MYTO II Generation Technical Assumptions The technical assumptions of GenCos are set out in Table 1: Technical Characteristics of New Entrant Plants 2012 of the MYTO document on the determination of the generation tariff published by NERC on 1 June We have reproduced it below and discuss our findings: Figure 35: MYTO II Generation Technical Characteristics of New Entrants Source: NERC, Multi-Year Tariff Order for the Determination of the Cost of Electricity Generation for the Period 1 June 2012 to 31 May 2017, Table 1: Technical Characteristics of New Entrant Plants 2012, p.20. The industry rule of thumb for construction costs of an OCGT plant is approximately US$ 1 million per megawatt (i.e. US$1,000 per kilowatt). Hence this Unit should be per kw and not per kwh (kilowatt hour). Otherwise it would mean NERC assumes that a 250 MW OCGT plant costs over US$ 2 trillion! (250 MW = 2.19 billion kwh) As far as the calculations in the MYTO financial model is concerned, after analysing the calculations in the MYTO financial model, we can confirm that the effect of this particular typographical error turns out to be merely cosmetic. However, as we illustrate in Table 29 page 126 and Table 30 on page 127, other typographical errors led to a significant miscalculation of the Revenue Requirement. This is notable because it is the (purported cost-reflective) Revenue Requirement from which tariffs are set. Page 123

24 (i) Available Capacity Factor Assumptions Need To Be More Conservative We have compared MYTO II plant Available Capacity Factors (ACF) with those from more established and efficient markets (see Table 28 below). As a result, we believe those in MYTO II need to be more conservative. ACF is sometimes referred to as Available Capacity or Capacity Factor (as in the MYTO II financial model; item #5 in the MYTO table shown in Figure 35). There is an inverse relationship between the ACF and the end tariff. So MYTO assumes that as the ACF of plants increases, the enduser tariff should decrease. This is not a one-for-one proportional relationship as there are several other technical variables that also affect the end-tariff and/or also affect each other. Available Capacity Factor is the ratio of the actual output of a power plant over a period of time versus the theoretical power output were it possible to run the plant at nameplate/installed capacity indefinitely. Equipment availability characterises the operating reliability of the plant. Available Capacity Factor = Actual Plant Output (in MWh) Theoretical Nameplate Output (MWh) Hence the ACF of a 1,000 MW plant generating 648,000 MWh of electricity in 30 days, for example: = = 0.9 = 90% 648,000 MWh 1,000 MW 24hrs 30 days Table 28: Comparison of Capacity Factors (Available Capacity) Natural Gas Hydro Coal Comments US 43% 40% 64% Best In Class gas thermal plants have ACFs over UK 57% 34% 45% 90%. MYTO II Successor 65% New 85% 65% 70% The inference from the MYTO II Capacity Factor GenCos Entrants assumptions for the gas plants is that they are akin to base load plants running at or very near full capacity (i.e. nameplate capacity). While this might not be such a stretch in situations where demand far exceeds supply, it is not a reasonable or realistic assumption in a situation like Nigeria s where lack of maintenance, equipment inefficiencies and gas and transmission infrastructure issues result in a lot of downtime. Source: NERC, US EIA (2009), UK Dept. Of Energy & Climate ( Averages) The world average for Hydro is 44% but the spectrum is wide (10-99%) due the variations in plant design. A small hydro plant in a small river, or one with a sufficiently large dam reservoir will always have enough water so won t suffer downtime from fuel supply issues. The seemingly low ACFs for UK and US gas plants are due to the number and variation of participants selling electricity in their open-traded wholesale markets. Electricity is offered for sale from power generating installations that use various fuels nuclear, gas, coal, wind, solar, etc. The running costs of these generators vary and at a particular time it might not be economical for a particular plant to produce electricity at its optimal (possible) ACF level. Typically, those with the lowest running costs can offer the best prices but the major determinants of price are ultimately supply and demand and any regulatory price controls that might exist. Page 124

25 (ii) Construction Period for Large Hydro Plants Is Too Ambitious The construction period for Large Hydro plants is set at 4 years, just a year longer than the construction period assumed for small hydro plants under the feed-in tariff plan. The norm in most markets is a construction period of 5-7 years. (iii) Plant Availability Needs To Be Lowered Plant Availability is the percentage of time the plant is available to generate electricity over a period of time. It is affected by a plant s Available Capacity (AC)/Available Capacity Factor (ACF). The MYTO II model sets Plant Availability at 95% of AC for both successor and new entrant thermal plants. Most gas thermal plants have high Plant Availability, about 80-99%. The new plants are more likely to have such a high figure, but this is very unlikely for the Successor GenCos. Furthermore the figure assumes that plants will not suffer fuel supply or transmission issues that would effectively make them unavailable even though technically they might be able to produce electricity (at their ACF level), as is currently being faced by Successor GenCos. (iv) Fuel Cost Assumptions Are Too Low The gas price is based on the regulated price for both the successor GenCos and new entrant GenCos (Chart 26). In our view this is not a plausible assumption for a number of reasons starting with the fact that the current market price of gas is about US$3 per MMBtu 39 : The DSO price as incorporated in the successor GenCos privatisation GSA s only applies to the Available Capacity at the time of sale. There was a wide variation in ACs but the average for the gas-fired plants was c.40%. Thus using MYTO II s ACFs of 65% the successor GenCos will need to buy gas for 35% of their output at the market price. The IPPs/new entrants do not benefit from the DSO price but buy at the market price. 39 Million British Thermal Units. Page 125

26 US$/MMBtu Nigerian Power Sector Chart 26: MYTO II Gas Price Assumptions vs Market and DSO Prices MYTO II price DSO price Avg. current market price Source: NERC, CSL estimates Miscalculation of Wholesale Prices Leaves GenCos Short The most significant problem we have found with the MYTO II model stems from a miscalculation of the Capacity Charge component of the Wholesale Generation price. On its own, not taking into account any of our aforementioned adjustments in underlying assumptions, this error resulted in the calculated tariff being c.30% lower that it should been. This error affects successor gas GenCos, new entrant gas GenCos (IPPs selling electricity to the grid), new entrant coal plants and successor hydro plants. Instead of calculating the Capacity Charge on the basis of naira per MW per Hour, the model used naira per MW per Month. Table 29 and Table 30 show the MYTO II figures and the corrections which converts the per MW/month charge into per MWh by dividing the former by the number of hours in a month. Table 29: Miscalculation in MYTO II Model Underquotes Capacity Charge Tariff by c.30% - Successor Gas GenCos Units MYTO II Capacity charge '000/MW/month 3,515 3,789 4,084 4,403 4,747 MYTO II Energy charge /MWh 5,389 5,758 7,290 7,944 8,658 MYTO II Wholesale contract price /MWh 9,563 10,257 12,140 13,172 14,296 CORRECTION MWh not MW/month Units Capacity charge /MWh 4,812 5,187 5,590 6,027 6,498 % Underestimation of Tariff -27% -27% -27% -27% -27% Source: NERC, CSL estimates Page 126

27 Table 30: Miscalculation in MYTO II Model Underquotes Capacity Charge Tariff by c.30% - New Entrant Gas GenCos Units MYTO II Capacity charge '000/MW/month 4,359 4,701 5,071 5,470 5,902 MYTO II Energy charge /MWh 5,568 5,951 7,499 8,169 8,902 MYTO II Wholesale contract price /MWh 10,743 11,534 1,350 14,665 15,910 CORRECTION MWh not MW/month Units Capacity charge /MWh 5,967 6,435 6,942 7,488 8,079 % Underestimation of Tariff -27% -27% -27% -27% -27% Source: NERC, CSL estimates Allocation for Ancillary Services is Grossly Inadequate The MYTO Model only allocates 1.5% of revenues of the system to Ancillary Services. In an electrical system at the stage of development that Nigeria s is, at a bare minimum 10% of revenue needs to be put towards Ancillary Services. Thus the under-provision understates the Revenue Requirement of the sector. Ancillary Services consist of system capacity allowances vital to the stability of the entire electrical network. They include: Spinning Reserves: This is back-up energy production capacity which can be made available to the system operator (for transmission) within ten minutes of a power system failure and can operate continuously for at least two hours once brought online. It is done by increasing the power generation output of power plants already connected to the system. Voltage Support: This is used to maintain the voltages in the transmission system within a secure, stable range. It is an essential service for the security of equipment and people. Its proper management ensures cost and operational efficiency of the transmission system. Black Start Capability: It is the process of restoring a power plant to operation without relying on power from the grid in the event of a major system collapse or system wide blackout. In the event of a power blackout, black start system capability is critical. Transmission Capex Insufficient for Actual Requirements Capital expenditure on transmission feeds into the TUOS charge component of the tariff however MYTO II only assumes 56 billion (US$350 million) per year for the capital which is less than a quarter of The Roadmap s (and the industry s) estimate of US$1.5 billion per year over the next five years. Page 127

28 In the Transmission Tariff Order, NERC expressed reservations with the capital expenditure figure initially provided by the then management of TCN when MYTO II was being prepared. So much so that it rejected the figure presented on the basis that TCN s management had not be able to justify its projected figures to NERC s satisfaction. As a result, NERC nominally included the 56 billion figure in the MYTO II Model in the expectation that when Manitoba Hydro International took over the reins at TCN, they would be able to provide and justify capex projections. Distribution ATC&C Losses Assumptions Too Low The starting point for Aggregate Technical, Commercial and Collection Losses assumed in the Model is too low based on the Opening Loss levels given by the BPE. The figures provided by the BPE are the levels on which bidders for DisCos were to benchmark their 5-year ATC&C Loss reduction targets in 2013 (Table 31 and Table 32). It has transpired that the reality faced by the new owners of the DisCos upon taking control of operations was far worse than the BPE figures. This is discussed in detail in Chapter 13: Systemic Risks (page 129). Table 31: MYTO II ATC&C Loss Assumptions Table 32: Opening ATC&C Losses (GWh) Successor DisCo Opening Loss Energy received 26,830 36,587 44,201 49,128 51,568 Abuja 35% Energy billed to customer 21,249 29,964 37,412 42,948 45,560 Benin 40% Energy sales collected 19,975 28,766 36,664 42,089 44,649 Eko 35% Agg. Tech. & Commercial Loss 21% 18% 15% 13% 12% Enugu 35% Collections Loss 6% 4% 2% 2% 2% Ibadan 35% ATC&C Losses 26% 21% 17% 14% 13% Ikeja 35% Source: NERC Jos 40% Discrepancy between the MYTO II Model and the BPE Figures on which bidders for the Successor DisCos based their ATC&C Loss reduction targets. Achievement of these targets is one of the performance obligations of the Successor DisCos and their Investors. Kaduna 40% Kano 40% Port Harcourt 40% Yola 40% Average 38% Source: BPE Page 128

29 Chapter 13: Systemic Risks We have identified three main systemic risks relating to: 1. Load allocation between the DisCos by the System Operator; 2. Implications of the delay in declaring the Transactional Electricity Market (TEM) and operation of the Interim Rules Period (IRP); 3. Legacy issues of the monitoring and reporting standards of the old system; notably the discovery that the state of the newly-acquired assets was worse than investors expected, based on information provided to bidders in the Data Room. Load Allocation Mechanism Load allocation of the first 3,200 MW among the 11 DisCos is based on a number of factors including projected demand. The limited amount of energy available has necessitated the System Operator (SO) having a system to ration between the DisCos. The DisCos will be evaluated and scored on achievement of minimum customer service performance standards and NESI Key Performance Indicators (KPIs). The criteria used and their respective weightings are depicted in Chart 27. While some of the criteria have more objective parameters than others, there is still a significant degree of subjectivity in the evaluation criteria. This is an area of concern, in our view, due to the potential for political and other vested interests to use this an opportunity to create a bias in favour of one or other DisCo. The political in-fighting that already has been demonstrated over the Manitoba Hydro International matter and the machinations surrounding the composition of the TCN board does not bode well in our view. Page 129

30 Chart 27: Weighting of Energy Allocation Evaluation Criteria 5% Reduction of losses 15% Attainment of metering targets 15% Customer service ratings based on biannual customer surveys 30% Achievement of distribution network expansion targets 35% Distribution Capacity Source: NERC, CSL Research IRP and Delay in Declaration of TEM The winning bidders of the successor GenCos and DisCos were announced in February These new owners were due to be handed full control of the purchased assets on 1 November 2013 after which there was to be a 4 month shadow-management period. In the months leading to the handover, some stipulated conditions-precedent to declaration of TEM (originally planned for October ) were still outstanding. So as not to stall the handover of the Successor Companies to the new owners on November 1, NERC developed a set of Interim Rules to govern the market in the pre-tem, post-handover market. The Interim Rule Order (IRO) committed to a maximum duration of the IRP of 3 months. The IRO was issued in December with retroactivity to November 1. The 3-month deadline has come and gone and the market continues to operate under Interim Rules with no firm indication on when it will end and TEM will begin. The prolongation of the IRP creates several problems for the new owners of the Successor Companies because: 1. The expected, unbundled market with NBET and TCN as the link between GenCos and DisCos is yet to become effective. There is little difference operationally between the previous vertically-integrated PHCN market and the status quo. A no-man s land post-handover is not what investors and the market subscribed to; 2. The no-man s land situation has been compounded by discoveries made by the new owners relating to the state of the assets themselves and concerns raised over the validity of certain agreements central to the privatisation. Page 130

31 No-Man s Land Suffocates Cash Flow Management While the bidders of the Successor Companies were not permitted to use the target company s assets as surety to raise funds for the bid process, they were permitted to secure contingent finance against the cash flows. The anniversary for repaying these loans is in August Operation of the Interim Rules At the heart of the matter, the operation of the IRO itself can negatively impact the sustainability of the NESI. Clause 3 of the IRO states that: During the Interim Period, PPAs and Vesting Contracts executed by the Successor Companies shall not be effective. This has profound implications for cash flows expected by the owners of the Successor Companies, not least: i. Ultimately it means that the Successor Companies cannot raise the project or corporate finance to fund capex and their operations as expected because banks will only lend to them if they have bankable PPAs, Vesting Contracts, GSAs, etc which underpin their respective business plans. ii. The MO handles settlements as before. The MO invoices and receives payments from Successor DisCo on behalf of Successor GenCos and IPPs. In the event that DisCos do not pay invoices in full, GenCos do not get full payment but are settled based on an Allowable Revenue formula to arrive at a Minimum Funding Requirement. Table 33: Allowable Revenue During the Interim Rules Period The adjustments made to the Revenue Requirement (RR) that underpins MYTO II for the MO to arrive at the allowable amount of funding are as follows: DisCos Fixed and variable costs 20% of MYTO II revenue requirement Admin costs 100% of MYTO II revenue requirement Return on Capital 50% of MYTO II revenue requirement Depreciation 10% of MYTO II revenue requirement GenCos Energy charge 100% of energy generated and supplied to grid Capacity charge 45% of Available Capacity Those that have existing PPAs which would have been operational during the IRP will have any difference reimbursed once TEM is declared. Other Service Providers TSP 70% of MYTO II market revenue NERC 70% of MYTO II market revenue MO 60% of MYTO II market revenue SO 60% of MYTO II market revenue NBET 20% of MYTO II market revenue Source: NERC Page 131

32 iii. NBET, purportedly, is meant to make up for any shortfalls in PPA amounts for GenCos (IPPs and Successor GenCos) that have effective PPAs during the Interim Period. We believe this to be at best an ambiguous provision because Effective Contracts for the purpose of the IRO are those that for which all conditions-precedent have been met. Furthermore, it is unclear where NBET is going to get these funds from as not only are there concerns over if and how the FGN subsidy will be disbursed during the IRP, the other purported sources of funds appear less than certain at this stage, in our opinion. Power Shortfall the Gas Supply Red Herring During the IRP GenCos are now expected to pay for their gas supplies directly. This contrasts with the former practice where the MO deducts gas costs from the GenCos receivables. Gas is supplied on a take-or-pay basis so come what may, the GenCos must pay for their gas offtake obligations under their GSAs. Other than the take-or-pay arrangement, the gas suppliers have willing buyers for any gas not taken up by the GenCos. Furthermore, those willing buyers will purchase the gas at market prices as opposed to the GenCos which pay the DSO price for gas. An operating fact of the IRP (and one of the main reasons that necessitated an IRP in the first place) is that NBET and the MO are not functioning (or funded) as they should and were expected to be at that time. In particular, as previously stated, they are not paying for all the capacity generated by the GenCos nor making up shortfalls in the PPAs. Caught between a proverbial rock and a hard place, the GenCos cash flows are strained. Shortfalls in settlements meant gas suppliers weren t being paid, everybody owes everybody money. This eventually resulted in the gas suppliers turning off/limiting flow from their taps to the GenCos, hence the recent decline in generation. In Chapter 9: Gas Supply Fuel-to-Power (on page 101), we talked about the 2 August 2014 announcement made by the FGN via the Ministries of Power and Petroleum and NERC on the upward revision of the DSO gasto-power price. In the same announcement it was stated that in conjunction with the Central Bank of Nigeria (CBN), they would be setting up a facility to settling outstanding gas-to-power debts owed to the gas suppliers, estimated at 25 billion (US$156.3 million). These developments are certainly welcome; however it is very early-days. Moreover, the precise mechanism for managing this process is yet to be finalised as the CBN plans to engage the banking sector in the bid to settle these accounts. Page 132

33 Figure 36: Gas to Power Cash Flows Gas Producers / Transporters Gas Supply Bill GenCos Transmission Gas Payment TUOS Payment Transmission Bill PPA Bulk Trader PPA Payment DisCos Bill Payment Bills Customers Source: CSL Research When Is A Contract Not A Contract...? Numerous inconsistencies in the Industry Agreements and operating manuals signed between the investors of the successor Companies and the authorities have come to light. There are inconsistencies within the same document and between the documents and the MYTO Financial Model. The range spans from typographical errors on Units of measurement, wrong calculations and formulae to ambiguous and contradictory terms. These are legal documents on which investors have based their decisions. Consequently, other legal documents at the heart of transactions in the privatisation have incorporated these inconsistencies. The effect of each error individually and collectively could be of sufficient degree to argue that some of these contracts could be rendered void or voidable at law. As they stand, these transaction documents, which are essential to raise finance are not bankable. Page 133

34 Reality of Acquired Assets Worse Than Expected We have already discussed concerns regarding the assumptions used in MYTO II as they stand. Notwithstanding, the new owners and NERC have discovered that the reality has been far worse. When Is A Data Room Not A Data Room...? The Successor GenCos were sold to the highest bidders. On the other hand the BPE set the price for each successor DisCo and based the selection on the basis of the bidder with the highest reduction in ATC&C Losses in their business plan for a particular DisCo. It was generally accepted that the information required to conduct due diligence on the Successor Companies provided in the Data Room was not entirely accurate. With this in mind, bidders made what they thought were adjustments for this in their valuation of the assets. However even these adjustments proved to be insufficient. There was reassurance from NERC that if after the handover of the assets a winning bidder discovered any liabilities that had been overlooked in the transfer of PHCN liabilities to NELMCO, this will be rectified. Furthermore, the IRO stated that NERC will review the tariff and make adjustments that are to be implemented at the start of TEM. In NERC s defence, it has been in a running battle with the old PHCN culture on transparency and reporting. When NERC embarked on its mandate in 2005, it required PHCN to carry out an audit of the entire industry statistics, financials, etc for all successor DisCos, GenCos, infrastructure and tariffs. The information provided was used as the basis to plan the new regimes of the NESI including MYTO. As we discussed, PHCN had to redo its homework, and MYTO II was one of the outcomes of the re-submitted data. Page 134

35 Interim Rules MYTO II Nigerian Power Sector Table 34: The Reality of the Successor Companies Has Been Worse Than Expected SOURCE OF ISSUE CRITICAL ISSUE DISCOVERED CURRENT IMPACT 1. Miscalculation of Wholesale Tariff 30% cut in Capacity payments 2. Tariffs are based on an assumption that there will be c.4,500 MW of capacity by now. The reality is has been more than 35% short. 3. Customer numbers for the DisCos are inaccurate 4. Customer segmentation is not suitably balanced Successor Companies are not earning as much as they projected in their business plans MYTO II costs and WACC assumptions are not in-line. Range of disparities discovered is between 15-35% R1&R2 tariffs are subsidised by the FGN. Customer groupings need to be reclassified because it looks like R2 is too wide as some well-off customers appear to be categorised as R2. 5. Transmission losses are much higher than stated 6. ATC&C Losses are much higher than stated MYTO II assumes 8.05% but the reality is over 13% MYTO II assumes ATC&C losses for the system to be 21%. DisCos are reporting ATC&C losses of 50-70%. DisCo ATC&C loss reduction targets are based on a starting point of between 35-40% depending on the particular DisCo. Each winning bidder's 5-year loss reduction target was incorporated into the performance targets in their Performance Agreement. But with a 10-20% discrepancy in the baseline, the performance targets of the DisCos are not achievable. 7. Available generation capacity of some generation assets are less than expected 8. Successor Companies are being paid less than the Revenue Requirement as indicated in MYTO II 9. Estimated billing and transfer pricing in operation More capital expenditure than expected could be required to renovate the assets. Each winning bidder's 5-year generation capacity target was incorporated into Performance Agreements. The baseline will need to be re-set. Under the Interim Rules, the MO only pays the equivalent of 60% of the Revenue Requirement. Note the Revenue Requirement is based on 4,500 MW. The reality has been well under 3,500 MW. The rate paid for energy in MWh has been cut by c.20% as part of efforts to manage cash flow in the system in the interim. Under TP there is no capital recovery at all. Total cost of generation and transmission are fixed on a de minimis standard. Under the current attenuated state of operations, there is limited if any scope to recover central costs. Low collection efficiency of the system makes the squeeze even tighter. In the current working environment where delivered energy is far less than planned, and issues with metering and collections persist, the DisCos may be slightly better off with estimated billing in some respects. 10. GenCos are only being paid for a fraction of their capacity. They are also not being paid for capacity (MW) power stations are to reserve for Ancillary Services (Spinning Reserves, Voltage Support, Black Start Capability). GenCo cash flows have been squeezed and they have struggled to pay their gas suppliers as during the IRP GenCos pay their gas suppliers directly rather than via the MO. Not surprisingly, as they are already paid short on MW for power generation, committing vital capacity to Ancillary Services could be viewed as a luxury as far as their profit and loss and cash flow statements go, especially in the short term. Hence Spinning Reserves have gone from 10-15% to 0%. As a benchmark, Spinning Reserve in the US is between 13-20%. Source: CSL Research Page 135

36 Figure 37: Transfer Pricing in the Interim Rules Period At PPA price IPPs Market Operator National Uniform Tariffs Successor Discos DisCos Transfer Payments At an end-user tariff deduced energy purchase price Clearing Accounts Receives payments from DisCos and Eligible Customers Transfers Payments to GenCos and service providers MO Transfer Payments At an end-user tariff deduced energy sales price Successor GenCos Eligible Customers Headquarters Wheeling charges Transmission System Operation Source: CSL Research Compare with costs recovered, including capital costs, under MYTO II Methodology shown in Figure 15 on page 23. Figure 38: The Theory of Transfer Pricing There is No Recovery of Capital Costs Generation Transmission Distribution Px 1 Generation O&M costs Px 2 Transmission O&M costs Px 3 Wholesal e Price Distribution O&M costs Px 4 End-User Tariff The Theory of Transfer Pricing (TP): TP is used to arrive at Px 4. Only operating costs are used to determine Px. There is no capital cost recovery. Px 1 and Px 2 are fixed based on minimum funds required to keep the entity operational i.e. a de minimis standard. Px 3 is determined every 3mths in line with projected improvements in revenue management. TPs are ultimately derived from and limited by DisCo takings based on the end-user tariff which in Nigeria were fixed, national uniform end-user tariffs. But if the tariffs are not cost-reflective, full cost recovery of generation, transmission and distribution O&M costs is not possible. Historical low collection efficiency in the system makes the squeeze on the Successor Companies margins even tighter under TP. The only way to recover central (HQ) costs under a TP regime is through improvements in revenue management (i.e. efficiency) beyond projected levels. Px 4 Distribution O&M cost Px 3 Px 3 Px 2 Px 1 Px Wholesale Price of... O&M Operations and Maintenance Source: CSL Research Page 136

37 Hobson s Choice Take It or Leave It The stark reality of the due diligence and bidding process is that the bidders and other stakeholders in the industry were given very limited amount of time to review and comment on documentation. The FGN s approach was essentially that there were a vast number of documents (PPAs, VCs, GSA, GPO, Market Rules, Grid Code, etc, etc) and there wasn t much room for negotiation. The FGN was only willing to budge minimally on the issue of risk allocation. It was not an altogether comfortable state of affairs but the bottom line as far as the FGN was concerned was that potential investors could either accept the process and documents as they were (with the minor FGN concession on review) or not get involved at all. It is little wonder that this amount of uncertainty and obfuscation put off international banking institutions from participating directly in the bidding process. Amidst protests, and wanting to keep to its schedule, the FGN made a concession by appending a review clause which stated that based on certain conditions, key documents such as PPAs and VCs can be reviewed within a year. This was signed in February 2013, so technically-speaking, this window has now closed. However we understand that pragmatism has prevailed and negotiations are ongoing. Page 137

38 Chapter 14: Structural Risks We have identified two main structural risks associated with: 1. Investment in TCN and investment by TCN in the expansion of the transmission network. 2. Gas supply and transportation. Transmission GenCos & DisCos at the Mercy of the FGN TCN is in charge of transmission wheeling power around the grid and installing transmission lines. For reasons outlined in Chapter 8:, it remains in government hands for the foreseeable future. One of the main reasons the FGN privatised the sector was because NEPA/PHCN had not kept up with investing in the electricity transmission infrastructure the critical link between generating and supplying electricity to the end-user. Our concern here is that the NEPA/PHCN pattern of non-performance will continue. Generation and distribution are now in private hands. Private companies have their shareholders and lenders to answer to for the profitability of their businesses. The figurative and literal bottom line for the GenCos and DisCos is that if they do not supply electrical power to the end user, the consumer, they will not make money. But they are not in complete control of one essential element needed to attain and then increase profitability transmission. If the power generated is not delivered or transmitted around the national grid, cash does not flow as expected in the system. Consumers pay a fixed charge which covers 75% of the DisCo s costs/payments, but they also pay for the amount of electricity they receive by way of an energy charge. It only takes so long of not being given the service for which the fixed charge is paid for the customer to begin to protest and refuse to pay thereby putting the stability/viability of the entire system at risk. TCN is obligated to network build-out targets under the Industry Agreements signed with the GenCos and DisCos. In the event of nonperformance, NERC has penalties it can impose and the DisCos and GenCos have some legal recourse. Notwithstanding, in the meantime, expenses must still be settled, debt must still be serviced. Wide Impact of Harvesting Low-Hanging Fruit As far as the main body of the current transmission infrastructure is concerned, if brought to optimal wheeling capacity, it is capable of transmitting 6,000 MW of power, which is practically twice as much electricity currently being supplied. Getting to 6,000 MW wheeling capability is the low-hanging fruit for TCN, the easy win. This will make a noticeable difference to the end user. Experiencing such an improvement in electricity Page 138

39 supply will give confidence in the system and make further tariff increases, which are invariably necessary, much easier for the end customer to stomach. Financing TCN Less than 40% of the country is connected to the National Grid and about US$1.5 billion per year over the next five years needs to be invested in the transmission infrastructure in order to make the system more reliable and stable. In Chapter 8: (Chart 17, page 91) we explained that on a five-year view, TCN s capital requirement is over US$780 million short. Additional sources of funds might come from bilateral arrangements, via funding consortia and turnkey solution providers. Chart 28: External Sources of Funds for TCN, World Bank/China Loan African Development Bank Agence Française de Développement^ China Exim Bank* FGN 2013 US$1bn Eurobond Issue Islamic Development Bank Japan International Co-operation Agency" NDPHC transaction investment Source: The Roadmap, CSL Research ^ France's overseas development agency. * Part of the trio of China s finance institutions designed to promote state policies in foreign trade, industry, diplomacy and economy, and promote Chinese products and services. Of the trio (China Development Bank, Exim and Sinosure), Exim is the sole provider of Chinese government concessional loans. Japan s overseas development agency. NDPHC - Niger Delta Power Holding Company, the parent company of the NIPP power plants. i. Sovereigns or Copper? With TCN s chequered track record of financial management, we believe that the FGN will have to be prepared to take on the credit risk of TCN for some time. This being the case, investors may rather take on sovereign risk directly rather than taking on TCN with its uncertain return profile, should the FGN decide to establish a commercial investment vehicle to fund TCN, for example. The FGN could make investing in the transmission sector more attractive by issuing infrastructure bonds or selling units in an infrastructure investment fund, for example. The mechanics and Page 139

40 configurations of these structured finance options can be complex and are beyond the scope of this report. What we would say, however, is that avoiding/minimising the risk of creating an arbitrage opportunity between sovereign debt and such sovereign-backed finance structures is one that would be at the forefront of the mind of the Central Bank and the Ministry of Finance. Current plans for TCN factor in US$125 million FGN budget appropriation per annum but in our view this is likely to prove overly conservative. ii. NIPP injection in question We also understand that TCN has assumed that US$1.6 billion of NIPP transmission assets will be transferred to TCN in exchange for shares in TCN. But this is by no means a certainty as we presume the winning bidders will need to agree to take equity in TCN in exchange for their transmission assets. This may well be a tough sell for the BPE because one of the advantages and strengths of the NIPP companies vis-à-vis others is that they also have control over transmission in their locale. iii. Rural Electrification Programme Rural electrification is less than 20% and the FGN has a target of 75% by Wary of rural areas getting neglected in the expansion of the distribution networks, the Electric Power Sector Reform Act 2005 established the Rural Electrification Agency to regulate the expansion of electricity in rural areas. The Rural Electrification Programme is funded separately by the Rural Energy Fund and we would expect TCN to benefit from co-ordinated buildout plans. However cost synergies might be elusive in the medium term because of the REA s poor track record of meeting key performance milestones and effective financial management. Its chequered history includes a portfolio of over 1,500 unfinished rural electrification projects. The REA has been restructured recently and a new Light-Up Rural Nigeria strategic plan was inaugurated by President Jonathan at the start of the year. However only time will tell... iv. The United States Power Africa Initiative Another source of funding for TCN, as well as other operators in the sector is the US Power Africa initiative launched in June It aims to double access to power in Sub-Saharan Africa and has committed US$7 billion over the next five years (to 2018) to six African countries including Nigeria 40. Financing provided under this programme will be in the way of financial support and loan guarantees. The US and other international finance institutions such as the World Bank and the African Development Bank together constitute a US$21 billion project finance, direct loan and equity investment package aiming to increase power generation in sub- Saharan Africa by 10,000 MW in the next five years. 40 Others are Ghana, Liberia, Ethiopia, Kenya and Tanzania) Page 140

41 Figure 39: 6 African Countries in the US Power Africa Initiative Ghana Liberia Nigeria Ethiopia Kenya Tanzania Source: CSL Research Man Management The Old Guard s Last Stand? The FGN has brought in Manitoba Hydro International to manage and implement a root and branch overhaul of TCN a very commendable and astute decision, in our view. However as we outlined in Chapter 8: the early days jamboree surrounding their appointment, ongoing political interference with the composition of the supervisory board and operational brick walls over control of the Market Operator budget all make us concerned that the old guard is more entrenched than we would like or indeed than it should be permitted to be. A management contractor must be left to bring in and implement to the full extent the expertise and skill for which it was hired. If it is failing in that role, contractual terms provide the avenue for it to be replaced by a more suitable firm. As with other key institutions such as NERC, in our opinion the FGN would be following a recipe for failure if they are not left to operate as they are designed to do, without political or vested interest interference. The rules and regulations to ensure transparency and accountability are already in place and are well detailed (as such regulations usually are in Nigeria). Page 141

42 Gas Supply and Transportation Additional GSA Will Be Required The Successor GenCos were sold with Gas Supply Agreements. But the GSAs only cover the pre-existing available generating capacity and not installed capacity. Available Capacity of the Successor GenCos was at about 40% at the time of sale so the successor GenCos will need to negotiate additional GSA, GTA etc with gas producers as they increase the Available Capacity of their plants towards Installed Capacity. Raising Available Capacity closer to Installed Capacity is an obligation contained in the Performance Agreement. The new GSAs will not be on the regulated (DSO) price as supplied by the Gas Aggregation Company of Nigeria (GACN). They will be bilateral contracts between the GenCos and the gas producers on a willing buyerwilling seller basis, at a commercial price. Chart 29: Installed vs Available Generation Capacity (MW) 1,320 1, Afam Power Egbin Power^ Geregu Power Kainji Hydro Sapele Power Shiroro Hydro Ughelli Power Installed Capacity (MW) 2011 Available Capacity (MW) Source: BPE, CSL estimates ^ Not included in 2011 BPE presentation. Figures from market sources. Page 142

43 Gas Supply Contracts Set On Take-Or-Pay Basis The payment and settlement terms in GSAs are on a take-or-pay basis. In other words, as long as the gas producer/supplier is ready and able to supply the amount of gas contracted for, the gas must be paid for. Fuel costs are passed through to the DisCos and ultimately to the end customer, so the DisCos bear the payment risk. Gas Transportation Adequacy is of Concern The current gas supply infrastructure is just adequate to support 4,000-5,000 MW of power generation. Thereafter, especially beyond 6,000 MW, there will need to be a significant increase in investment in gas transportation infrastructure. GSA s are typically of year duration so gas producers make investment decisions based on the GSAs they enter into. The contract price takes into account any infrastructure investment that is required such as gas pipelines to the buyer s facility. Thus those plants that are closer to the gas producer s processing facility are likely to get more favourable prices. Beyond a certain distance, the gas is transported via the FGN-owned Nigerian Gas Company s (NGC) transportation pipeline network. Investors should note that the Gas Master Plan is expected to address the infrastructure issue, but the GMP: (b) Has been behind the curve from a pricing and market operations perspective. In fact market participants expect the relevant sections of the Petroleum Industry Bill that relate to gas too be drafted to reflect current practice; a case of the tail wagging the dog. (c) Has manifested little success in building out infrastructure in line with targets in the named Strategic Sectors such as power and gas-reliant manufacturing. The market is already leading on the commercial trading/open market aspects so for the time being we believe it makes more sense for the raison d être of GMP to be a gas infrastructure plan. Regulatory oversight can remain with the Department of Petroleum Resources or put in the hands of a separate independent regulator, as was done with the creation of NERC for the power sector. Page 143

44 3-year Countdown to Gas Supply Crisis Started Yesterday The supply shortfall will come to a head in about 3 years time if a radical effort is not put into expanding the gas pipeline infrastructure. Demand for gas-to-power is going to more than double to 3 BCF per day by And it takes 3 years to make the investments in plant facility, gas transportation infrastructure etc. Recently-issued NERC regulations state that no new IPP licences are going to be issued until the operator has secured core industry agreements such as GSAs and GTAs. This ought not to be a hindrance in the short term as most of the new IPPs being built over the next few years will be situated near the gas facilities. They should therefore by-and-large not have to rely on the infrastructure-building efforts under the GMP. We have stated that the Successor GenCos were sold with GSAs already in place for the available capacity at the time of sale, so they are covered. The NIPPs will be sold with GSAs but it is not yet clear if this will cover all their generation. It will take the NIPPs and Successor GenCos 2-3 years to reach optimum capacity and hence peak fuel demand. In the meantime the IPPs being constructed will also be competing for gas. We believe that this increase in competition will invariably have the effect of raising gas prices. Cash Effect of the Gap In the chapter on MYTO (Chapter 5: ) we described end-user tariffs as consisting of a fixed charge and an energy charge. The fixed charge of the end-user tariff only covers 75% of generation and transmission costs. It covers the GenCos capacity charge and the DisCos transmission and O&M charges. The fixed charge cushions against Availability Events that reduce the amount of electricity generated. Availability Events could be due to issues with gas infrastructure affecting supply to the GenCos or problems with the transmission infrastructure affecting off-take/evacuation of electricity which could result in the plants scaling down production. This would have implication for cash flow and ultimately profitability. Page 144

45 Chapter 15: Financing the Power Sector Over the next five years, the Nigerian power sector will need to raise US$13-15 billion for capital expenditure in transmission, distribution and generation. Another US$ billion is required for supporting gas infrastructure. Of these amounts, the FGN is responsible for US$800 million which it has committed to NBET s capitalisation fund for its proper functioning. The FGN is also responsible for the US$1.5 billion annual requirement for transmission infrastructure and US$1.5-2 billion per annum for the gas infrastructure. The Successor GenCos and DisCos require a capex spend of US$5-6.5 billion over the next five years. The privatisation of the Successor GenCos raised US$1.65 billion for the FGN, while the Successor DisCos raised US$1.46 billion, hence there should not be any conceivable financial reason that the FGN cannot fund NBET. Furthermore, in February 2014 TCN announced it had received US$665 million of funding for transmission projects from various international finance agencies and from the FGN budget allocation 41. Bank Exposure in Acquisition of Successor Companies Questions have been raised about the extent of the exposure of domestic banks to the power sector due to the fact of the operations of the Successor Companies were not as expected and that the duration of the IRP is open-ended. The investors in Successor Companies were not permitted to use the target assets as surety for monies borrowed to fund their bids. However, they were permitted to use their prospective shares in the target companies and/or also prospective cash flows from the operations (a type of bare securitisation instrument) based on their business plans and financial projections. For those who pledged shares or cash flows, the lending banks typically also required secondary form of recourse using on non-target related assets of the investor. Due to the perceived high risk profile of the industry the new institutions had no track record of creditworthiness, NEPA/PHCN s 41 See page 78 for sources of TCN funds. Page 145

46 history of operational and financial management was abysmal and some early-day concerns thrown up by political interference and contractual irregularities banks were reluctant to get involved. It is one thing if the borrower is looking to invest in an already profitable enterprise, even without security against the target assets. It is quite another looking to put money into one of the most defunct ex-government enterprises, in an untested new regime, which was still going to rely on the same FGN involvement at the critical points in the value chain. Thus it came as little surprise that the only banking institutions involved in the privatisation were local. We also understand that all but one or two of the technical partners in the consortia were involved in financing the bids. So far, local banks have invested over 750 billion (over US$5 billion) in the power sector (privatisation, rehabilitation, other power-related assets, etc). But the major spend is capital expenditure from here How Big is the Pool of Finance Available for the Sector? Theoretically speaking, in the world of cross-border financing and free movement of capital, the answer to the question is, As big as it needs to be. In the wake of the global financial crisis, balance sheets of have been rebuilt, Long Only funds have built up higher cash balances which they now want to put to work, trade buyers are looking further afield to acquire growth and international development agencies have begun to step up their commitments. Add to this the renaissance of Africa as a place to do business, in particular sub-saharan Africa and the continent does not seem as remote as it did a decade ago. There is no denying that risks are higher than in more developed markets, that fact is inherent in its classification, hence investors require higher returns for taking on the extra risk. However, irrespective of how attractive the macro and sector fundamentals look, the sector (and country) has to compete with other calls on international finance other sub-saharan Africa countries and sectors, other fast-growing regions in the world. International financial investors will not buy alpha (growth/performance) at any price, even those that invest in emerging and frontier markets which have higher risk profiles. There are certain basic requirements that need to be in place, and that are robust enough legally and structurally. These all go into the investor s assessment of the risk profile of the market. Page 146

47 FINANCE CAPITAL Nigerian Power Sector Financing and Risk Matrix for Nigerian Power In Figure 40 we have set out a financing and risk matrix to indicate the sources or pools of finance that become available as the risk profile of the sector/market changes. Individual sectors within a particular market can be deemed to have higher risk profile than the overall market. It is arguable that at the onset of the power sector privatisation, the sector had a higher risk profile than the Nigerian market as a whole it was a sector on its knees, it was unprofitable, it was having a completely new, untested regime introduced and the FGN was going to keep control of vital aspects of the system. Figure 40: Power Sector Financing and Risk Matrix $$$ STAGE I STAGE II STAGE III Financing/Risk Disconnect? The size of capital required for the Nigerian power sector is of Stage III proportions. However these doors tend not to open if the market and/or execution risks are perceived to be high. International Private Equity Investment Funds, Sovereign Wealth Funds International Development Agencies International Banks Government, Local Banks & Local Private Sector Frontier Market Funds NOTE: The spheres are not proportional but merely representative of the size of the particular pool ofcapital. The balance between government and other sources of finance shifts to the latter during later stages. $ In the later stages, projects tend to be large and require greater capital commitments beyond those available from the State. Furthermore, local financial institutions do not have large enough balance sheets to absorb the funding needs ofthis stage. Hence the demand for external borrowings increases. High MARKET RISK Low [EXECUTION RISK] Typical IRRs of 15-20% E Q U I T Y Government Local private sector Government Local private sector Foreign & local trade partners Frontier market funds Government Local private sector Foreign & local trade partners Frontier market funds Global emerging market funds Pension funds Capital markets Debt service coverage ratios of up to x may be required depending on position in value chain. D E B T Local banks Local banks Development Finance Institutions (DFI) Multilateral agencies Local banks Regional banks International banks Development Finance Institutions (DFIs) Multilateral agencies Export credit agencies Capital markets Sovereign Wealth Funds Private Equity funds Source: CSL Research Page 147

48 Characteristics of Power Sector Financing Table 35: Characteristics of Power Sector Financings Long Tenor High Leverage Term of debt depends on the project, plant time and location Recent financings have called for 8-30 year term debt. Bridge funding is available but is expensive Amount of debt to equity banks would permit is constrained by the forecast cash flows of the project, which are expected to service repayments. Debt tends to be between 60-90% of project costs. However for the Successor Companies the BPE has put a cap of 70% for the first 5-years. Multi-Source Includes Local and international banks, DFIs and Export Credit Agencies. (See Figure 40: Power Sector Financing and Risk Matrix). Multi-Currency Naira and US Dollar mix is recommended. However FX risk mitigation must be addressed. Security of Finance Credit enhancements and supports include guarantees, warrantees and other covenants for the project sponsor, affiliate and other third parties. Strength of the guarantee ensures the transaction secures the optimal debt structure (pricing, tenor, etc.) and demonstrates commitment from the sponsor. Source: CSL Research Page 148

49 Key Documents in Nigeria Power Sector Financing These are some of the key documents that are required to be in place for financings in the Nigerian power sector: Table 36: Documents Essential to Securing Power Sector Financing Document Share Sale Agreements Concession Agreements Gas Supply and Aggregation Agreements Gas Transportation Agreements Power Purchase Agreements Vesting Contracts Transmission Use of Network System Agreements Grid Connection Agreements Ancillary Services Agreements Bulk Trader Credit Support Deed of Assignment of Pre-Completion Receivables Operations and Maintenance Agreement Pre-Completion Liabilities Transfer Agreement Application DisCos and thermal GenCos Equity financing commitments Share transfer restrictions Dispute resolution Hydro GenCos Gas-fired GenCos Gas-fired GenCos GenCos 15-years typical Includes plant specifications and performance standards Penalties for late commissioning or failure to meet performance targets Revenue write downs for under performance Default and termination provisions Details of credit quality of the off-taker and payment guarantees. DisCos 15-years typical Includes plant specifications and performance standards Penalties for late commissioning or failure to meet performance targets Revenue write-downs for under performance DisCos and GenCos DisCos and GenCos GenCos A combination of FGN letter of support for NBET meeting payment obligations and the World Bank/AfDB Partial Risk Guarantees Successor DisCos and GenCos Allocates operational risks Details penalties and incentives Operator must be bankable i.e. credit-worthy and experienced Successor DisCos and GenCos Source: CSL Research Page 149

50 Cost of Capital in the Power Sector MYTO II One of the components of the Revenue Requirement for the sector used to arrive at the tariffs is the Weighted Average Cost of Capital (WACC). It is included so that the tariff takes into account a return on the value of capital invested in the Successor Companies. NERC s objective was to arrive at a figure that attracts investment funds into the industry but is not sufficient to produce super profits. The MYTO Model uses the Capital Asset Pricing Model (CAPM) to calculate the WACC. WACC provides an estimate of the returns on equity and debt. The returns to equity in the power sector are measured in relation to the risk premium on the Nigerian equity market as a whole. The measure of the relative risk of the sector to the Nigerian equity market is expressed as Beta (ß). MYTO II WACC Assumptions and Estimate Assumptions: Risk free rate 18% Nominal return on equity 29% Beta 1 Nominal cost of debt 24% Gearing (Debt : Equity) 70:30 Total corporate tax rate 32%* *statutory corporation tax of 30% plus 2% education tax WACC Estimates: Nominal pre-tax WACC 25.5% Nominal post-tax WACC 17.3% Power Sector Risk Relative to the Nigerian Equity Market The MYTO Model assumes a sector Beta of 1. In other words it assumes the risk of investing in the power sector is no higher or lower than the risk of investing in the Nigerian stock market as a whole (i.e. market-weighted fund). NERC has indicated that it will review the figure it uses for Beta when enough data exists for statistically significant estimates to be made. It does not have sufficient data because electricity supply in Nigeria is not an area that has a history of steady supply of private investments to deduce the risk of return relative to the market. Page 150

51 While NERC s position is theoretically valid, from an investor s perspective it might be prudent to apply a Beta for the sector in the estimation of cost of capital. The electricity generation sector in emerging markets have been estimated to have a Beta of 1.34, while emerging market electricity distribution companies have a Beta of Sector Return on Equity Investment Re = Rf + ße(Rm Rf) Where: Re Return on Equity Rf Risk free rate (yield on 10-yr Nigerian Treasury bonds) ße Power sector risk relative to the Nigerian market Rm Return on the Nigerian market portfolio Rm Rf Market risk premium Power Sector Risk Premium Factors Some of the notable risk factors in the power sector we have discussed which we consider would justify the application of a premium to the market Beta include: In Chapter 13: Systemic Risks we pointed to certain inconsistencies, contradictions and ambiguity in key documents of the privatisation which rendered them effectively unbankable. Hence the doors of finance for future capex are very unlikely to be opened until this is rectified. We have also covered concerns over the need to rely on the FGN to deliver on transmission and gas transportation infrastructure. As far as the MO function goes, the machinations we have seen so far creates grave uncertainty about whether the payments and settlements system will be allowed to function freely and fairly. The shortcomings of the MYTO model assumptions mean that the Revenue Requirement, hence the computed tariffs, are too low. Yet there is no indication that the tariff will be adjusted to reflect this before national elections in The open-ended IRP and the lack of a definitive date for the declaration of TEM and the full functioning of the core institutions of the NESI. This is the most significant factor, in our view. The longer the transition plan stays off track, and the more unexpected variations are introduced after the fact, the greater the uncertainty and the 42 Ian H. Giddy, Aswath Damodaran; New York University Stern School of Business. Page 151

52 greater the justification for a higher risk factor (Beta) to be applied to the Nigerian power sector. Ultimately this could cripple investors ability to raise the finance required to fund the development of the sector as doors of the broader international sources of finance do not open until the risk level lowers (Figure 40). Without those doors being opened, the transition and development of the Nigerian power sector cannot come to fruition as planned. Has the BPE Declared Nigeria Closed For Business? Under our discussion of the Progression of Economic Value 43 in Chapter 3: we explained how successful reform of the power sector and increasing power generation is an immovable condition-precedent to Nigeria s transition to an industrialised economy. Thus the future profitability and competitiveness of every essential sector/industry in the country to a notable extent rests on the power sector and its regulatory regime being fit for purpose. In light of this we were especially taken aback by a BPE press release on concerns raised by local lending banks at an industry conference on 21 May Local Banks and the Stress of the August Anniversary There have been general concerns over what impact the stresses in the sector will have on the Nigerian banking industry. It is a fact that the privatised power sector is not running as expected, resulting in significant variations in the cash flows and profit forecasts of the Successor Companies business plans (and incidentally the BPE s own financial model for the industry). Thus local banks have expressed fear of default on the loans taken out to fund the bids for the Successor Companies when payments fall due in August The BPE press release, referring to the fact that Successor Company assets were not (permitted to be) used as collateral, stated: "The banks lent to the Core Investors based on their capability to pay. The investors are supposed to have made adequate provisions to take care of their obligations to their financiers from the outset. They knew that they were not going to make profit immediately on takeover of the [Successor Companies]. Their financiers also were aware of this" 44 We indicated at the opening of this chapter that investors could borrow against their shares in the Successor Companies and/or against forecasted cash flows of the businesses. These financial projections were based on information on the fundamentals of the Successor Companies that was provided by the BPE. The financials were incorporated into the investors business plans and initial budgets which, naturally, were presented as part of the loan applications. Furthermore, these financials were also an integral part of their submissions to the BPE in their bids. The new owners would 43 Page Bureau of Public Enterprise Press Release, 22 May (See Appendix 7: ) Page 152

53 not have been successful had their business plans not been thought to be sound by the BPE and in line with the FGN s targets for the power sector. The Post Acquisition Plans and Initial Budgets as shown in the business plans presented by the winning bidders were incorporated into Performance Agreements and other Industry Agreements signed by the investor, the Successor Company and the BPE. So investors and their financiers proceed on the basis that all parties will keep up with their end of the bargain and took actions in reliance of information provided by the various counterparties. Many banks would have taken secondary (or primary) non-power related collateral. But even with recourse, in the event of a default, banks will record a non-performing loan and there are costs involved in enforcing the claim against the asset. The banks did not lend blind. Investors did not borrow blind. Thus in the first instance we would agree with the BPE that [the investors] knew that they were not going to make profit immediately on takeover of the [Successor Companies]..[and their] financiers also were aware of this. However, as any reasonable counterpart to an agreement would, they were also expecting the BPE, NERC and the FGN to do what they had promised to do. The investors did not anticipate: (a) The degree of disrepair of the assets and other technical issues discovered post-handover; nor (b) That the start of TEM, with all its FGN-provided safeguards and sureties, would be delayed so long; and (c) That an IRP would be imposed after handover with a different set of rules and procedures relating to operations and settlements. The unexpected institution of a no man s land that is the IRP and the uncertainty that currently exists leaves the investment community feeling rather nervous. Everyone expects a few bumps along the way in such privatisations thus stakeholders proceed on the understanding that they will work towards resolution to get the project back on track as soon as possible. This usually involves some giveand-take, as there are often issues on both sides, mostly unforeseen. However in Nigeria s case, in our view the balance of responsibility is heavily weighted on the FGN/BPE/NERC s side due to the degree of inconsistencies and errors discovered by the new owners of the Successor Companies after handover. (See Table 34: The Reality of the Successor Companies Has Been Worse Than Expected). Page 153

54 Long Reach of the BPE s Summary Dismissal of Concerns The BPE s summary dismissal of what we consider to be valid concerns by the banks has potentially a far-reaching and profound impact beyond the power sector. At a basic level it raises questions over the BPE s regard for the sanctity of the contracts it enters into. Another question mark is cast over the degree of the BPE s realisation that both counterparties (FGN and private investors) have skin-in-the-game, hence something to lose. Finally, it sends a message of caveat emptor to the local and international investment community considering getting involved with any FGN privatisation. It drastically raises the execution risk of the project, which historically has been a perennial criticism of FGN enterprises. We believe such a stance by the BPE could threaten the FGN s medium and long term plans to attract private investment into the power sector, which in turn will have a knock-on effect on the evolution of the Nigerian economy. Page 154

55 Chapter 16: Investment Opportunities in the Sector Generally speaking, the issues that persist in the Nigerian power sector are not without precedents in other markets and can be resolved. Thus provided there are clear indications that all the current stakeholders are working together to get the schedule back on track, and allowances are made for shortfalls suffered so far, the sector demand story and macro opportunity can be fully realised. There are a number of ways to gain exposure to the Nigerian power sector directly (generation and distribution) and indirectly. We highlight a few of those we believe have the greatest potential below: Direct Investments Other than through debt financing to the Successor Companies or taking equity stakes, should that option become available, there are four direct ways to invest in generation and distribution: NIPPs The privatisation of the National Integrated Power Project GenCos is currently underway. We will cover this in detail in the next chapter. IPPs NERC s risk allocation in the industry appears more favourable to generation companies. Provided the IPP in question does not have to rely on the national gas infrastructure to get going, which means it will be situated close to its gas supplier, it has better control over its potential output. However as it will need to be connected to the national grid, it would potentially face similar off-take issues faced by the Successor GenCos. Independent Electricity Distribution Networks Licences for this are granted by NERC. At the moment these are associated with embedded generators but could be used as means to connect rural communities to the national grid. Page 155

56 Embedded or On-site Generation In our view this currently represents the most favourable play on generation, provided fuel supply is not an issue. The embedded GenCo is directly connected to the distribution network operated by a distribution licensee. Excess power generated and not used can be sold via the national grid. It also benefits from lower capital costs, reduced connection costs and avoidance of the TUOS cost. The customer benefits from increased and more reliable supply of electricity and potentially lower tariffs. Figure 41: Embedded Generation and Independent Distribution Networks Embedded Generation Independent Distribution Network Independent Distribution Network Grid Supply Points On-Grid Generation Direct Supply Customer NATIONAL GRID Direct Supply Customer Residential Distribution Network Distribution Network Commercial Industrial Source: CSL Research Page 156

57 Small-Medium Hydroelectric Plants They are typically 5-60 MW embedded hydroelectric power plants. Over 300 potential small and medium hydro-power projects have been identified and feasibility studies have been carried out on 12 dams. The FGN is open to private investors submissions of interest to invest in these projects. Figure 42: Small Hydro-Power Plants Figure 43: Potential Sites for Hydro-Power Plants Shiroro Dadinkowa Mambilla Kainji Jebba Abuja Gurara Zungeru Lokoja Onitsha Makurdi Ikom Hydroelectric Power Plant Site (Existing or Being Developed) Large Hydroelectric Power Plant Site Source: Vallibel Power Source: CSL Research Indirect Investments A Piece Meal Approach We believe that there are opportunities to gain exposure to potential growth in the power sector and make decent returns other than by electricity generation and distribution. In the immediate post-handover environment, indirect exposure might better suit investors with lower risk appetite than that required for the power sector as it currently stands. Industries such as equipment manufacturing and other service providers should also benefit from the procurement and capital spend that the power companies and the FGN will embark on. There is no going back for the FGN at this point. The main unknown thrown up by the issues in generation, transmission and distribution that we have highlighted is the pace of progress. This in turn has a bearing on the optimisation of returns within an acceptable timeframe for investors and banks operating in a developing market. We believe investors looking to get indirect exposure to power should look to companies that have close-ended, piece-meal interactions with the Page 157

58 power sector, providing products and services. The main areas we would point to are in: Power transmission infrastructure Gas transportation infrastructure Technology and engineering, including metering Technical capacity and knowledge services Page 158

59 PART IV Privatisation of NIPPs Page 159

60 Chapter 17: The NIPP Investor: Second-Mover Advantage? Private investors are to get another opportunity to acquire publicly-owned power generation assets by way of the privatisation of National Integrated Power Project (NIPP) GenCos. The NIPP programme is a separate and distinct enterprise from the PHCN companies and privatisation process. The Niger Delta Power Holding Company (NDPHC) was incorporated in It was set up to wholly own, manage and operate 10 new GenCos (with the necessary transmission lines connecting to the national grid) to be built under the NIPP programme using private sector best practices. The programme was instigated to ensure that the FGN did not stall on adding generation capacity at a time when the rest of the FGN-controlled sector (PHCN) was focused on readying to be privatised. Figure 44: Location of NIPP Assets Being Privatised Olorunsogo Omotosho Benin Geregu Egbema Ogorode Gbarain Omoku Alaoji Calabar Source: CSL Research Page 160

61 The Status Quo The NIPPs privatisation is at an advanced stage. On 13 March 2014, 19 Preferred and Reserved Bidders were shortlisted by the BPE. Not entirely unexpected for such processes, there has been some drama which has temporarily scuppered the privatisation of three of the NIPPs Alaoji Generation Company Limited, Gbarain Generation Company Limited and Omoku Generation Company Limited. On 17 March, the Federal High Court issued an interim order which enjoined the BPE from proceeding with the privatisation of Alaoji, Omoku and Gbarain GenCos. Ethiope Energy Ltd (EE), one of the pre-qualified bidders for these three assets, challenged its disqualification as a bidder for failing some aspects of the due diligence process and requirement. It accused the BPE of bias, prejudice, conflict of interests and manipulation of the technical bid evaluation due diligence process. EE s Statement of Claim against the BPE et al., it accused the Chairman of the Due Diligence Committee, Mr Atedo Peterside, of having immense influence on the BPE. It asserted that Mr Peterside should have excluded himself from the Technical Bid evaluation process as it related to EE because he had a bias against its Chairman, Chief Johnson Arumeni. EE said Mr Peterside had been having a running legal battle with Chief Arumeni in the courts of their home state, Rivers State, and that Mr Peterside was hostile and felt animosity towards Chief Arumeni. At the end of March, the parties to the case informed the court that they were in discussions to reach an out-of-court settlement. However on 30 April Counsel for EE informed the Court that the parties had not been able to reach an amicable settlement. This was confirmed by Counsel for the Defendants. Meanwhile the second Defendant, NDPHC, has filed an appeal at the Federal Court of Appeal seeking to have the Interim Order set aside so that the privatisation of the three NIPPs can proceed. At a hearing at the beginning of July, the sitting judge adjourned the case until October 7 for ruling. Page 161

62 Table 37: Preferred and Reserved Bidders for 7 of 10 NIPPs* Preferred Bidder Reserved Bidder NIPP Asset Organisation Bid (US$ mn) Organisation Bid (US$ mn) Benin GenCo EMA Consortium Index Consortium Nebula Power Generation Calabar GenCo EMA Consortium Consortium Egbema GenCo Dozzy Integrated Power Ltd AITEO Consortium Geregu GenCo Seoul Electric Power Ltd Yellow Stone Electric Ltd Ogorode GenCo Daniel Power Consortium ESOP Power Ltd Olorunsogo GenCo ENL Consortium Index Consortium Omotosho GenCo Omotosho Electric Power ENL Consortium OPTIMAL SALE VALUE 4,253.3 LEAST SALE VALUE 4,089.1 Source: BPE, CSL * Privatisation of Alaoji, Omoku and Gbarain GenCos temporarily suspended pending ruling on Ethiope Energy Ltd's High Court case against the BPE et al. for EE's disqualification as a bidder for these assets. Ogorode Generation Company Ltd owns the Sapele II Power Plant The Bidding and Selection Processes This is being handled along the lines of those done for the PHCN companies privatisation. There are three key stages: Stage 1: Expression of Interest (EOI) The key requirements here were that prospective bidders be existing local or international power companies or investors with power O&M operators as long term technical partners. Other stipulations included that the EOI must state the prospective bidder s number of years of experience in power generation and distribution. The BPE also required evidence of such ownership/activities, especially in developing countries. Other submissions included clear evidence of the bidder s having sufficient resources to finance the acquisition. Pre-qualified bidders were required to pay a US$20,000 fee for each NIPP asset/genco of interest and sign a confidentiality agreement. They then received the relevant Information Memoranda and Request for Proposals (RFPs). Page 162

63 Stage 2: Bid Proposal Submission This involved a two-envelope system. Bidders were to submit one containing their Technical Bid and one containing their Commercial/Financial Bid, in accordance to requirements set out in the RFP. On submission of their Technical and Financial Bids, the bidders were expected to submit a security deposit of a US$4 million on-demand payment bond. Stage 3: Two-Step Bid Evaluation The BPE conducted a full technical evaluation and scored each Technical Bid on criteria set out in the RFP. Those that passed the threshold moved onto the next stage and their Financial Bids were then evaluated. The most attractive financial proposal was declared the Preferred Bidder and the next attractive proposal declared the Reserved Bidder. Once the Preferred and Reserved Bidders were announced, the BPE and the Preferred Bidder immediately began negotiations to finalise the privatisation of the NIPP GenCo. Within 15 business days of being notified of selection as the Preferred Bidder and the Reserved Bidder, both bidders were required to lodge a bank guarantee equal to 15% of the amount bid by the party. The bank guarantee can be reimbursed if the bidder does not: a) agree to the terms of the final drafts of the Share Sale Agreement or Shareholders' Agreement; or b) on signing the SSA and SA, pay the initial deposit, which is 25% of the bid price for NIPPs that have reached full commissioning stage on the date of signing or 10% of the bid price for NIPPs that are not at full commissioning stage at the date of signing. NIPPs Privatisation Package The plants will be sold with Power Purchase Agreements with NBET in place as well as fuel supply agreements. The PPA covers low levels of dispatch for both capacity payments and obligations under take-or-pay provisions under the Gas Supply and Aggregation Agreement. The PPA capacity payment is designed to be sufficient to cover debt and return on equity (ROE) in the event of problems in dispatching electricity not caused by the power plant. The level is based on the 70/30 debt to equity ratio and ROE assumptions used by NERC in MYTO II. The new owners of the NIPP plants are able to enter into bilateral fuel supply agreements for additional fuel. They can also negotiate PPAs with Page 163

64 embedded networks not connected to the national grid, to which the plants will be connected before handover. Interim operations and maintenance agreements are currently effective. The new owners can either take these over or can replace them. Government Involvement in NIPPs Post-Privatisation NDPHN is owned by the FGN, and state governments and Local Government Authorities in their respective locations. After privatisation, NDPHC will retain 20% stake in the NIPP GenCos. Notwithstanding we would advise investors in the NIPP GenCos not to rely on NDPHC for further injections of capital. In contrast to the position of the FGN in this matter vis-à-vis its retained stakes in privatised PHCN companies, NDPHC has been equivocal about injecting further capital/contributing to costs prorata. Should NDPHC elect not to co-invest, it is prepared to have its holding diluted. Similar to the FGN, NDPHC expects to have board representation commensurate with its shareholding. Figure 45: Ownership of NIPP Assets Pre and Post Privatisation Federal Government of Nigeria 36 State Governments 774 Local Governments 47% 35% 18% Niger Delta Power Holding Company NIPP GENCOS Niger Delta Power Holding Company Private Investors in Specific NIPP GenCos 20% 80% NIPP GENCOS Source: CSL Research Page 164

65 Other Salient Terms Foreign Exchange Risk and Debt Financing The provisions for these two elements are similar to those for the PHCN plants as MYTO II schedule applies. To summarise: FX risk Payments by NBET under PPAs are in local currency. As discussed previously, MYTO II has factored in some foreign exchange components in the tariff computations so investors have a degree of exchange risk protection. The naira/us dollar exchange rate used in MYTO II is set at 1% above the official Central Bank rate as during the review of MYTO I, investors informed NERC that the CBN rates were not always accessible to them. MYTO II model assumes a steady increase in the NGN/USD over the years and also provides for bi-annual reviews. NERC has stated that US dollar indexation will be covered as far as possible, although payments will be made in local currency. Debt finance Shareholder loans made in the course of the bid for the NIPPs and thereafter cannot be secured against the NIPP assets. The regulations allow shareholder loans to be treated as equity provided that (i) the loans are unsecured and enjoy no priority over the claims of all other creditors of the company and (ii) there are no scheduled repayments falling due within the first 3-years of private ownership. Like the PHCN companies, the level of gearing for NIPP companies is capped at 70%. Similarly, any debt raised for the NIPPs can only be secured against cash flow (i.e. securitised) and not NIPP assets. This restriction endures for the first three years of private ownership. Credit Enhancements to the Transaction Partial Risk Guarantee Once TEM starts, monthly PPA payments by NBET are backed by a PRG. NBET is expected to have an US$800 million capitalisation fund to support its payment obligations. NBET has also secured a 3-month DisCo payment security backed by a Letter of Credit. PCOA As with the case of PHCN GenCos and IPPs, there will be a Put-Call Option Agreement in place. The parties to the NIPPs PCOAs will be the NIPP investor, NDPHC and NBET. The PCOA allows NDPHC to repurchase the investor s shares in the NIPP GenCo Company thereby protecting the investor and lenders in the event of buyer default. The buy- Page 165

66 out price will be determined post-arbitration. The shares thus bought will be transferred back to NDPHC. Operation of the NIPP Put-Call Option is analogous to those of the PHCN GenCos and the IPPs 45. Table 38: Key Dates for NIPPs June 2013 July 2013 August 2013 NIPP roadshow Deadline for submission of EOIs for NIPP Companies Pre-qualified bidders for NIPP Companies announced 27 September 2013 Deadline for NIPPs pre-qualified bidders to submit comments on Industry and Transaction Agreements and the RFP. [1 October 2013 Date initially planned for the declaration of TEM] 1 November 2013 Start of INTERIM RULES PERIOD 11 November 2013 Public opening of NIPP bid proposals 1 March 2014 Extended IRP expected to have ended and TEM declared. TEM expected to start before end of June March technically qualified bidders for NIPP GenCos announced 7 March 2014 NIPP financial bid opening May 2014 [June 2014 TEM is likely to be delayed further Date initially planned for privatisation (hand over to new owners) of NIPPs] Source: CSL Research Committed to the Process In for a Penny, In for a Pound The handover of privatised NIPP assets to new owners was initially scheduled for June 2014 by which time the plants were expected to have been completed. However the timetable has been extended. The Preferred and Reserved bidders were only announced on 21 March. In the PHCN privatisation schedule, Industry Agreements between the BPE and Preferred bidders were not signed until four months after the announcement of Preferred and Reserved bidders. No doubt the NIPP schedule is likely to gain some time advantage based on PHCN precedent vis-à-vis construction and terms that both parties can agree on, nonetheless there is still a six month period between the winning bidder paying their deposit and paying the balance of the bid amount. By the time the preferred bidders for the NIPPs were selected, and by the due date of payment of their bank guarantees (14 April 2014), the PHCN companies had been privatised and were operating under the Interim Rule Order. In Chapter 10: we explained that the Interim Rule Period was instigated as a stop-gap before TEM was declared to give time to resolve 45 Page 41. Page 166

67 significant issues concerning the business operations and the electricity market at large that emerged post handover of assets to investors. The PHCN privatisation process was not going as planned. The problems discovered, hence the need to delay TEM, would no doubt be of particular concern to the NIPP investors. The second-mover advantage that would have been anticipated at the start the NIPP assets are newer, there is precedent in the process, TEM would have been well-underway... now seem illusionary because the investors are already fully-committed to the process. Thus they must travel in faith that NERC, BPE and the FGN will resolve all issues before too long. The NIPP bidders are in a difficult position. An apt analogy would be a journey on an amusement park thrill/horror train ride. The train is hurtling towards a brick wall and at the moment prospective NIPP investors are travelling in the hope that the wall will be removed in time. They are not welded into their seats so while they can abort mid-journey and jump off the train, it will not be without incurring significant injury. The damage would be financial as the financial commitment to the process in terms of fees and man-hours is not inconsiderable. Furthermore, the damage might be by way of opportunity loss should the wall be removed before the train hits but after the bidder has jumped off the train. Page 167

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