2012 MYTO For Generation
2012 MYTO For Generation
2012 MYTO For Generation
TO 31 MAY 2017
Table of Contents
List of Tables Appendices Glossary of Terms PART ONE PART TWO 1 1.1 1.2 1.3 1.4 2 3 3.1 4 4.1 4.2 4.3 4.4 4.5 4.6 5 5.1 5.2 5.3 5.4 6 7 2 3 3 4 7 9
Introduction ........................................................................................................................ 8 Background .............................................................................................................. 8 Insight into 2008 Multi Year Tariff Order ................................................................ 10 Electricity Pricing in Nigeria .................................................................................... 11 Rationale for Tariff Review ..................................................................................... 12 Legal and Regulatory Framework....................................................................................... 14 Pricing Principles ............................................................................................................... 16 Existing Power Purchase Agreements ..................................................................... 18 Technical Assumptions for the Determination of the LRMC for the 2012 Tariff Order ........ 19 Introduction ........................................................................................................... 19 Gas-to-Power Plants ............................................................................................... 19 Coal-Fired Power Plants.......................................................................................... 21 Renewable Power Plants ........................................................................................ 23 Gas Price ................................................................................................................ 25 Generation/ Load projection .................................................................................. 26 Economic and Financial Assumptions for the 2012 Tariff Order ......................................... 26 Introduction ........................................................................................................... 26 Inflation.................................................................................................................. 26 Exchange Rate ........................................................................................................ 27 The Weighted Average Cost of Capital (WACC) ....................................................... 27 Generation Tariffs for Various Fuel Sources ....................................................................... 32 Bi-Annual Review ................................................................... Error! Bookmark not defined.
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List of Tables
Table 1: Technical Characteristics of New Entrant Plants -2012 ................................................. 20 Table 2: Technical Assumptions for Feed-in tariffs ..................................................................... 25 Table 3: Gas and Gas Transmission Cost (2012-2016) ................................................................ 25 Table 4: Projected Generation Capacity to National Grid- (2012-2016) ...................................... 26 Table 5: Assumed Rate of Nigerian Inflation Rate (2012-2016) ................................................ 277 Table 6: Assumed Naira/US Dollar Exchange Rate (2012-2016) .................................................. 27 Table 7: Wholesale Generation Prices of the Successor Thermal Power Plants .......................... 33 Table 8: Wholesale Generation Prices of the New Entrant Thermal Power Plants.33 Table 9: Wholesale Generation Prices of the New Entrant Coal Plants ....................................... 33 Table 10: Wholesale Generation Prices of the Successor Large Hydro Plants ............................. 34 Table 11: Wholesale Feed-in Tariff Small Hydro Plant ................................................................ 34 Table 12: Wholesale Feed-in-Tariff for Land Mounted Wind Power Plant ................................ 345 Table 13: Wholesale Feed-in-Tariff Solar Power Plant ................................................................ 34 Table 14: Wholesale Feed-in-Tariff for Biomass Power Plant ..................................................... 34
Appendices
1: List of parties consulted on MYTO methodology and tariff 2: Comments and Observations on MYTO methodology
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Glossary of Terms
ARR BPE Capex CAPM CCGT CPI DISCO DUOS EPC EPSRA FGN GENCO IFC IMF IPP KWh LRMC MAR MDAs MLF MMBTU MO MWh MYTO N/KWh 4 Annual Revenue Requirement Bureau of Public Enterprises Capital expenditure Capital Asset Pricing Model Combined Cycle Gas Turbine Consumer Price Index Distribution company Distribution Use of Service Engineering, Procurement and Construction Electric Power Sector Reform Act Federal Government of Nigeria Generation Company International Finance Corporation International Monetary Fund Independent Power Producer Kilo Watt hours of electrical energy Long Run Marginal Cost Maximum Allowable Revenue Ministries, Departments and Agencies of the FGN Marginal Loss Factor Million Metric British Thermal Units Market Operator Mega Watt hours of electrical energy Multi-Year Tariff Order Naira per Kilo Watt Hour of electrical energy
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NBET NELMCO NEPP NERA NERC NESI NTB NUT OCGT ODRC O&M Opex PHCN PI PPA RAB ROE ROT SO SPE SPV TSO TCN TUOS WACC
Nigerian Bulk Electricity Trading Company Nigerian Electricity Liability Management Company National Electric Power Policy National Economic Research Associates Nigerian Electricity Regulatory Commission Nigerian Electricity Supply Industry Nigerian Treasury Bonds National Uniform Tariff Open Cycle Gas Turbine Optimised Depreciated Replacement Cost Operations & Maintenance Operating expenditure Power Holding Company Of Nigeria Price Index Power Purchase Agreement Regulatory Asset Base Return on Equity Rehabilitate, Operate, and Transfer System Operator Special Purpose Entity Special Purpose Vehicle Transmission System Operation Transmission Company Of Nigeria Transmission Use of System Weighted Average Cost of Capital
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The process for adoption of this methodology was transparent, as consultations took place with government, consumers, customer groups, other major stakeholders and industry practitioners. Their contributions to the proposed methodology were at various public fora and/or through written representations. There are three separate Tariff Orders; one for each of the sectors in the NESI namely: generation, transmission and distribution/retail. This Generation Tariff Order is divided into two parts; this Part One, which is the proclamation of the Order; and Part Two, which presents the basis of the Order. Part Two is further divided into eight sections - the Introduction, Legal and Regulatory Framework, Pricing Principles, Technical Assumptions for the Determination of the LRMC for the 2012 Tariff Order, Economic and Financial Assumptions for the 2012 Tariff Order, Generation Tariffs for Various Fuel Sources, Bi-Annual Review, and the Effective Date. Accordingly, by virtue of the powers conferred by S. 76 of the EPSRA, NERC hereby, makes the following ORDER: 1. The Tables for the Generation Tariff shown herein set out the wholesale electricity generation prices that shall come into effect as from midnight on 31st May, 2012 and continue in force until midnight on 31st May 2017 shall be as shown herein below, subject to the provisions of this Order. 2. Upon coming into effect, the said Charges shall continue in force subject to such minor and major reviews as NERC may hold from time to time. 3. This Order shall be called the Nigerian Electricity Generation Charges MultiYear Tariff Order, 2012.
PART TWO
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1 Introduction
By this Multi-Year Tariff Order 2 (MYTO 2), NERC establishes the regulated prices to be paid to licensed electricity generation companies (Gencos) in providing electricity to distribution and retailing companies (Discos) for the period 1st June, 2012 to 31st May, 2017, pursuant to the authority given under Section 76 of the Electric Power Sector Reform Act 2005 (the Act). These retail tariff schedules will be reviewed bi-annually and changes may be made thereto if any or all of the generation wholesale contract price, the Nigerian inflation rate, US$ exchange rate, daily generation capacity and accompanying capex, and opex requirements have varied materially from that used in the calculation of the tariff. A material variation for this purpose is defined as a price variation of plus or minus five per cent (+/- 5%) in any of these indices. A review of all inputs to the tariff calculation will commence in 2016 as the basis for a new Multi-Year Tariff Order (MYTO) to commence for 5 years from 1st June 2017.
1.1 Background
NERC is an independent regulatory agency established by the EPSRA, and was officially inaugurated on 31st October, 2005. The EPSRA provides the legal and regulatory framework for the entire NESI, and empowers the NERC to undertake technical and economic regulation. The various challenges that the Industry must contend with may be summarised as follows: Acute shortage of generation capacity; Acute shortage of natural gas; Transmission constraints and inadequacies; Lack of private sector participation; Inadequate generation mix e.g. solar, wind, coal, etc; Unacceptable technical and non-technical loss levels; and Unacceptably high payment or credit risk in the distribution sector.
The establishment of NERC was the direct result of a genuine desire to transform the electricity supply industry into a market-based industry, in line with the Federal Governments reform agenda for the countrys economic, industrial and social development. Thus, the NERC was established to facilitate the introduction and management of competitive, safe, reliable and fairly-priced electricity in the country. Pursuant to the above, the objectives of the NERC include:
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To create, promote, and preserve efficient industry and market structures, and to ensure the optimal utilisation of resources for the provision of electricity services; To maximize access to electricity services, by promoting and facilitating consumer connections to distribution systems in both rural and urban areas; To ensure that an adequate supply of electricity is available to consumers; To ensure that the prices charged by licensees are fair to consumers and are sufficient to allow the licensees to finance their activities and to allow for reasonable earnings for efficient operation; To ensure the safety, security, reliability and quality of service in the production and delivery of electricity to consumers; To ensure that Regulation is fair and balanced for licensees, consumers, investors and other stakeholders.
In its effort to provide a viable and robust tariff policy to support the long-term viability of the NESI, the NERC in 2008 decided to introduce a Multi Year Tariff Methodology as the framework for determining the industrys pricing structure. The MYTO Methodology establishes and lays out the process to be followed in meeting the statutory obligation in S.76, EPSRA. It provides a fifteen (15)-year tariff path for the electricity industry with bi-annual minor reviews and major review every five years. This is the second Tariff Order issued by NERC and it is for the period 1 June 2012 to 31 May 2017. Two other Tariff Orders are being issued concurrently to cover generation prices in wholesale contracts and transmission tariff/institutional charges respectively. The MYTO regulatory model depends on data received from market participants. Institutions within the NESI have supplied estimates and forecasts upon which the industry costs and tariffs developed in the MYTO financial model are based. NERC is conscious that the NESI must evolve to meet the demands placed upon it. The data inputs and estimates underlying the MYTO will be reviewed periodically to ensure they remain current. Following the procedures set out in Section 76, EPSRA, the NERC has published the MYTO Methodology upon which both MYTO 1 and 2 are based see www.nercng.org. In describing its methodology the NERC noted that it had adopted three basic principles. These principles require that a regulatory methodology: produces outcomes that are fair; encourages outcomes that are efficient in that it involves the lowest possible costs and encourages investment in electricity generation; and is simple, transparent and devoid of excessive regulatory costs.
In establishing MYTO 2, the NERC has sought to apply these principles more precisely in order to produce tariffs that incentivise the NESI to attain standards of
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performance set by NERC to produce the positive outcomes mandated in Section 32(1) of EPSRA. NERCs recent major review highlighted the need for an amendment to the existing assumptions and so a Notice of Proposed Change to the Multi-Year Tariff Methodology was published, explaining the need to adjust the existing methodology. There were two (2) major changes expected to be made to the existing methodology and were brought about by: the need to be more flexible in wholesale generation pricing; and the need to consider a number of other essential variables during the minor reviews.
The major reviews involve a comprehensive review and overhaul of all the assumptions in the MYTO model. During the minor review of MYTO in May 2009, Successor Discos requested that the major review of MYTO scheduled for 2013 be brought forward in order to take care of the increasing cost of power, the rising cost of O&M expenses, and also because of their declining revenue due to the absence of the growth in generation capacity envisaged in the 2008 Tariff Order. The NERC after due consideration of this request, brought forward the major review of the MYTO.
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This major review afforded stakeholders the opportunity to evaluate the methodology, make inputs to the existing model, incorporate Feed-In Tariffs (FITs) for renewable energy (wind, biomass, solar and small hydro) and also develop tariffs for generation using coal. Some of the assumptions reviewed include: Available generation capacity; Forecast of electricity demand; Expansion of the transmission and distribution networks; Capital expenditure (capex); Actual and projected sales; Operating costs (opex); Fuel costs; Interest rates; Weighted average cost of capital (WACC); Revenue collection efficiencies; and Subsidies.
Having concluded that establishing a cost-reflective tariff would ordinarily lead to a general increase in tariffs across all classes; and in order to avoid the effects of a rate shock on more vulnerable consumers, the tariffs paid by certain classes consumers will be less than cost-reflective values over the first two years, up to June 2014, following the introduction of MYTO 2. In this vein, FGN support will be provided in the form of a subsidy to make up the shortfall between actual and cost-reflective tariffs over this period, while the tariff moves gradually towards viable levels. Unlike before, this will be enjoyed only by the tariff classes that genuinely need support. The removal of the subsidy over a period of time is expected to lessen the burden on consumers while allowing them to adjust to the new price level. The Federal Government subsidy is intended to exit when power availability increases enough to enable a further rebalancing of tariffs. This rebalancing will be such that the NESI is left with only a cross-subsidy scheme established within the framework of the Power Consumer Assistance Fund (PCAF), as mandated by Part VIII (Sections 83 87) of the EPSRA.
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NERC has since September 2010 carried out wide consultations with the industry operators, consumer advocacy groups, the legislature and relevant MDAs on both the MYTO methodology and tariff. (See Appendix 1 for the list of stakeholders consulted).
Allow for the recovery of appropriate reasonable return on capital invested, depreciation (and replacement) of capital and recovery of fuel, operation, maintenance and overhead costs; Provide an incentive for new investment in capital equipment; Provide incentives for reducing technical, and commercial losses;
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Provide viable and transparent tariff methodology that will allow NESIs progress towards a reformed and market-oriented system in which generation and retail activities are not subject to price regulation while the monopoly activities of transmission and distribution continue to be under price regulation; and Finally, ensure that the benefits of a reformed NESI are passed through to consumers in the form of reliable electricity supply at the lowest possible price consistent with the above objectives.
The NESI will, as it grows and evolves during the coming years, move to a marketbased system whereby generators and electricity retailers will be free to contract with each other for the supply of electricity. Transmission and distribution will remain regulated.
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Section 76(1) of the Act subjects the following activities to tariff regulation: (a) Generation and trading, in respect of which licences are required pursuant to this Act, and where the NERC considers regulation of prices necessary to prevent abuse of market power; and Transmission, distribution and system operation, in respect of which licences are required under this Act.
(b)
Section 76(2) provides for the NERC to adopt appropriate tariff methodology within the general principles established in the Act, which: Allows recovery of efficient cost including a reasonable rate of return; Gives incentives to improve efficiency and quality; Sends efficient signals to customers on costs they impose on the system; and Phases out or reduces cross subsidies.
This Tariff Order (MYTO 2) is based on a set of principles designed to provide tariffs for each of the generation, transmission, and distribution (including retail) sectors (reference Section 1.4 above): Cost recovery/financial viability regulated entities should be permitted to recover their efficient costs, including a reasonable rate of return on capital.
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Signals for investment prices should encourage an efficient level and nature of investment (e.g., location) in the industry. Certainty and stability Confidence in a pricing framework is also important for private sector investment. Efficient use of the network Generally, this requires efficient prices that reflect the marginal costs that users impose on the system and the reduction of cross-subsidies. Allocation of risk pricing arrangements should allocate risks efficiently (generally to those who are best placed to manage them). Simplicity and cost-effectiveness the tariff structure and regulatory system should be easy to understand, and not excessively costly to implement (e.g., facilitate metering and billing). Incentives for improving performance the way in which prices are regulated should give appropriate incentives for operators to reduce costs and increase quality of service. Transparency/fairness prices should be non-discriminatory and transparent, as non-discriminatory access to monopoly networks is also a key pre-requisite for effective competition in the contestable sectors. Flexibility/robustness the pricing framework needs to be able to cater for unforeseen changes in circumstances. Social and political objectives the pricing framework needs to provide for the achievement of social policy goals such as universal access, demand-side management, and user affordability.
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3 Pricing Principles
Section 3 of the MYTO Methodology states that The main objective in setting bulk electricity prices in vesting contracts are to cover the costs of existing plant and allow for their efficient maintenance and on-going investment programs while ensuring that an appropriate price for bulk electricity supplied by generators under vesting contracts is the unit price an efficient new plant would require in the Nigerian Electricity Supply Industry (NESI). The strategy for managing the transition to a competitive wholesale market includes the use of vesting contracts for generators. Wholesale contract prices offer the prospect of some certainty about cash flows during the transition towards a competitive market. The method to be used here is the Long Run Marginal Cost (LRMC) method. LRMC involves calculating the full life cycle cost of the lowest-efficient-cost new entrant generator, taking into account current costs of plant and equipment, return on capital, operation and maintenance, fuel costs, etc. In this Order, LRMC is applied in two ways: Benchmark costing: Creates a proxy for the market price which an efficient generator is expected to operate below. Individual long run marginal cost for each generator: This sets prices for each generator according to its plant and site specific costs.
NERC has determined that the price of electricity to be paid to generators will be at the level required by an efficient new entrant to cover its life cycle costs (including its short run fuel and operating costs and its long run return on capital invested). In a market such as the NESI, where demand is in excess of supply, the price of electricity should be at the price required to encourage operators who have already invested into the market, and also attract new entrant investors. The two methods above will be utilised by the NERC. The classic LRMC applies to the successor Gencos, as set out in the 2008 Tariff Order, in which the long-run marginal cost of an OCGT plant will be calculated for the successor Gencos by the NERC. The individual (site-specific) LRMC model requires each new entrant IPP that requires a tariff beyond the MYTO benchmark to apply to the NERC for approval. In such case, the IPP will open its plans, accounts and financial model to scrutiny by the NERC, which will then apply prudence and relevance tests to determine whether such plant- and site-specific costs should be allowed in the tariff. It is pertinent to note that feed-in tariffs have been developed for investors wishing to invest in generation capacity that utilises other sources of energy including solar, wind, biomass and small hydro.
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For the time being, the NERC has determined that the lowest cost new entrant generator is an open-cycle gas turbine (OCGT) using natural gas. Most new power stations completed or under construction are currently open cycle gas turbines. Given the current price of gas used for electricity generation in Nigeria, this form of generation technology produces electricity at a lower life cycle cost than combinedcycle gas turbines, and at a lower cost than coal-fired generation. However, it is anticipated that the gas price will become market-based in the near future, and CCGT is likely to emerge as the benchmark for a lowest-cost new entrant generator. Then, the NERC will review the generation pricing methodology accordingly. It is to be noted that when the Nigerian electricity market evolves to a point where bilateral contracts are signed between generators and distributors, this LRMC will determine the price set in wholesale contracts. Such bilateral contracts will be executed via the procurement framework now being developed by the NERC. At this point, the wholesale price for each site procured by a Disco or by the Bulk Trader will be the lowest price bid for that site. That lowest price will be the price set in the PPA awarded by the procuring entity. The selection of OCGT as the lowest price new entrant is in recognition of the fact that natural gas is the most abundant and environmentally-appropriate fuel in Nigeria, and therefore that which gives Nigerian generators the greatest competitive advantage. New entrants, particularly in a number of locations where natural gas is not most efficient fuel available, are entitled to submit bids for generating plant using the most efficient fuel for that particular site. The estimation of the generation costs of an open cycle gas turbine power station in Nigeria is based on the estimation of the price required, over the life of such a generation project to pay all of its component costs, including fuel, operation and maintenance, tax and a return on capital. These costs are brought together in a financial model which finds the average price per unit of output that needs to be achieved in order for all of the component costs to be met over the projects life. The component costs are: Fuel; Capital; Fixed and variable operation and maintenance; Company tax; and Transmission costs.
Other factors that must be determined in calculating the LRMC in this way include conversion efficiency (heat rate) and internal energy use. The capacity factor assumed is important because it determines the output over which fixed costs can be spread. Having determined the values to be assigned to these inputs, they are brought together in a financial model that determines the life cycle price (the LRMC)
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by calculating a price that makes the net present value of the power station equal to zero. The methodology is different from the building blocks approach that NERC uses for the calculation of regulated prices for transmission, distribution and retail. In setting the wholesale contract price in this way the NERC is determining a proxy for a market price of generation, not a regulated price, in a way that estimates the price needed to attract the next unit of energy (and the next power station) on to the system. The financial model used to estimate life cycle cost attempts to broadly simulate the financial approach taken by a new entrant when making their investment decision. It includes tax payments, a weighted average cost of capital that reflects generator risks and the effects of other costs, such as an allowance for transmission losses. At the beginning of the transition stage of the industry, generation output pricing will still be determined by the NERC to ensure that only prudently incurred costs are recoverable. However, it is envisaged that with the imminent introduction of a bulk procurement framework, the market will evolve to having wholesale generation prices set via the bid process albeit benchmarked against the LRMC prices established by the relevant MYTO.
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4 Technical Assumptions for the Determination of the LRMC for the 2012 Tariff Order
4.1 Introduction
The 2012 Tariff Order determined that the generation price is to be based on efficient new entrant life cycle costs and this price is to be paid to all generators who sell to the grid. Further to this, it was determined that this new entrant will be an Open Cycle Gas Turbine Plant (OCGT). To further open the market and encourage other sources of fuel, the NERC has allowed for coal-fired plants, renewable energy plants, and has also developed a separate LRMC for large hydro plants. The OCGT plant, chosen due to the abundance of gas in Nigeria at a relatively low price, is regarded as one of the most efficient plants, and all new entrants are to use this efficient technology benchmark for project evaluation and analysis.
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Auxiliary requirement: This is the internal energy use in the power station and it has been reviewed upwards to 2% from 1% that was in the 2008 Tariff Order. Construction period: The time it takes to complete and commission the plant has been reviewed to 3 years from the 2 years that was in the 2008 Tariff Order. Plant life: This is the life over which costs are recovered and for the purpose of calculating the long run marginal cost of a new plant. A project life of twenty (20) years has been set. Plant availability: The percentage (%) of time the plant is available to generate has been set at 95% of the available capacity. Capital cost: The capital cost includes the following components: o Engineering, Procurement and Construction (EPC); o Planning and approval; o Professional services; o Land acquisition; o Infrastructure costs (including water); o Spares and workshop, etc; and o Connection to the electricity transmission network o Fuel connection, handling and storage Fuel: This is what drives the turbines to produce electrical energy. The price of natural gas is a pass through cost. Fixed and variable operation and maintenance: These are the expenses that the generator incurs in providing service to its customers. They include the cost of labour, materials, rent, etc. Fixed costs are not a function of energy produced. These remain unchanged from the 2008 Tariff Order, but are escalated by the exchange rate and rate of inflation.
S/N
Description
Units
1 2 3 4 5 6 7 8 9 10 11
Installed capacity Capital cost O&M Cost (Fixed) O&M Cost( Variable) Capacity Factor Auxiliary Requirement Economic life Construction period Sent-out efficiency Availability Fuel costs
COAL
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consists of planned outages for scheduled maintenance and forced outages when plants are forced to stop or operate at reduced output for technical reasons. Data on new plants and technologies indicate that outage rates can be high and so availability for a new coal fired plant in Nigeria is estimated at 86%. Construction period: The construction period or build time assumed for subcritical black coal technology is four (4) years. Fixed O&M cost: Fixed O&M costs include maintenance, operating, and overhead costs that are not dependent on hour-by-hour level of generation from the station but on available capacity. The estimated fixed O&M costs is $32,000 per MW. Economic life of the plant: For the purpose of calculating the long run marginal cost of a new plant a project life of forty (40) years has been assumed. Capacity factor: NERC has continued to adopt the approach of setting the plant factor based on the actual performance of the most efficient subcritical black coal generator. The capacity factor has been set at 70%. New plants will have a high level of availability and so should be running at maximum output for a high proportion of the time in order to meet demand. Auxiliary/Internal usage: The subcritical black coal plant will require a water cooling system, therefore the auxiliary is estimated at 7.5% Capital Cost: The estimate of project capital cost for a new coal-fired power station includes the following components: o Engineering, Procurement and Construction (EPC) o Planning and approval o Professional services o Land acquisition o Infrastructure costs (including water) o Spares and workshop etc and o Connection to the electricity transmission network o Fuel connection, handling and storage The estimate of the project capital cost excludes Interest During Construction (IDC), capital costs, and site works for a coal mine. IDC is excluded, as a return on investment is required in this model from year zero (i.e., at the commencement of the project before construction has begun) and interest charges are a component of the WACC.
Variable cost: The estimates of variable O&M cost is presented as cost per MWh sent-out. This is estimated at $0.96MWh.
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Electricity generation costs vary according to the renewable energy source and technology used. Therefore, the FIT levels will be technology-specific and will depend on: The investment costs for the plant; The O&M Costs; Fuel costs (where applicable); Financing costs and return on the invested capital; Estimated lifetime of the power plant; and Capacity of the plant.
In view of the high cost of renewable energy power plants, NERC has, for the next five years, set a cap on energy from renewable sources at 10% of total energy sent out. The cap shall be reviewed whenever the Federal Governments policy on energy mix is established. In this Order, NERC has set Feed-In-Tariffs (FITs) for four major sources of renewable energy, Wind, Solar, Small Hydro and Biomass/Biodiesel.
4.4.1 Qualifying Renewable Energy Sources
As used in this Order, biomass includes diverse fuels ranging from lumber, lumber waste, agriculture and industrial food processing waste, municipal solid waste, methane from land fill, bio-fuels from crops that are specifically grown or reserved for electricity generation. Wind power here refers to onshore wind power The Solar Tariff is for ground-mounted solar PV with no tracking Small Hydro refers to those producing less than 30MW
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4.4.2
For the purpose of computing the amount received by a power station with a mixture of sources, the amount of renewable electricity generated by an accredited power station is worked out in accordance with equation:
(1)
Where: NetREGeneration is the amount of renewable electricity generated by an accredited power station in a year is the total amount of electricity, in MWh, generated by the power station in the year, as measured at all generator terminals of the power station. is the amount, if any, of electricity, in MWh, generated by the power station in the year using non-eligible energy sources is the auxiliary loss, in MWh, for the power station for the year is the amount of electricity, in MWh, transmitted or distributed by the power station in the year. MLF is the marginal loss factor, to allow for the amount of electricity losses in transmission networks
General Assumptions
TEG
FSL
AUX DLEG
4.4.3
The following assumptions are proposed for the determination of Feed-in Tariffs: Installed Capacity: This is the total available capacity of the plant and the assumption here differs for each of the technologies. It ranges between 5MW to 10MW Capital Cost: This refers to the one-time set cost of the plants including connection cost to the grid Fixed O&M Cost: These are the expenses that the generator incurs in operating and maintaining their facilities, in N/MW/Yr. Variable O&M Cost: These are indicated in N/MWh Capacity Factor: The plant capacity factors are relatively low due to the fact that natural fuels, i.e., wind, sun and water are intermittent and not always optimally available.
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Auxiliary Requirement: This is the internal use of electricity with the premises of the generating station, which is assumed at a rate of 1% for all the sources, except Biomass which is set at ten percent (10%) Economic Life: A project life of twenty (20) years is assumed for all the sources and it is used to derive the period over which the costs are recovered. Construction period: This is the assumed length of time it will take to design, import and construct the plant to get it up and running. It is assumed to be three (3) years.
S/N 1 2 3 4 5 6 7 8
Description Installed capacity Capital cost O&M Cost (Fixed) O&M Cost (Var.) Capacity Factor Auxiliary Requirement Economic life Construction period
2013 1.80
2014 2.30
2015 2.37
2016 2.44
Gas prices are pass-through costs for the electricity producer. Where there is a material change in the price, the NERC will effect a commensurate change to the wholesale contract price.
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Gross Generation Capacity Sent Out to Grid (Gwh) 30,715 41,884 50,601 56,242 59,034
This projection assumes that improvements in the generation capacity are solely from the successor Gencos and based on realistic expectations for improvements in efficiency and the refurbishment and expansion of facilities and the completion of ongoing NIPP projects. These figures will be reviewed bi-annually.
5.2 Inflation
An inflation rate of thirteen percent (13%) was adopted. This however, is subject to minor review bi- annually. In an event of any material change in inflation rate, this would be reflected and the tariff adjusted accordingly.
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In the MYTO, the rate of inflation is used to ensure that investors are well compensated against rising cost of doing business and workers in the industry are paid living wages. To achieve this, the NERC has escalateed the following variables: WACC; Fixed labour cost; Fixed admin cost; Variable O&M cost; Other Fixed O&M cost; and Capital Investment.
2012 Inflation 13
2013 13
2014 13
2015 13
2016 13
2013 169
2014 178
2015 189
2016 198
requirement calculation as a return on the value of capital invested. The regulated asset value at the start of a given year is calculated by taking the depreciated replacement cost of capital assets at the start of the immediate proceeding twelve (12) months, and adding the investments in new capital assets acquired during the same period. The Capital Asset Pricing Model (CAPM) is used to estimate a WACC for the NESI. While this approach gives a method for estimating the average cost of capital in a sector and is widely used by regulators, it requires consideration of volatility of returns in the sector, as well as the domestic cost of debt. Even in developed economies, the calculation of a WACC frequently requires estimation of a number of the inputs. This is the case in Nigeria, and most of the inputs to the WACC calculation are, the NERC estimates. The WACC is set at the level that attracts investment funds to the industry, but is not sufficient to produce super profits. The CAPM provides estimates of the appropriate return on equity and the returns to equity are measured in relation to the risk premium on the equity market as a whole. Thus:
Re = Rf + e (Rm - Rf)
Where: Re Rf e Rm Rm Rf is the return on equity is the risk free rate observed in the market is the correlation between the equity risk and overall market risk is the return on the market portfolio is the market risk premium
(2)
The WACC lies between the cost of equity and the cost of debt. The WACC is calculated as:
(3)
is the total market value of debt is the total market value of equity
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Rd Re
This formulation does not include the effects of tax. The formulation of the WACC that allows for the effects of taxation specifically the corporation tax rate (T c ) and used extensively by regulators is as follows:
(4)
(5)
The company tax rate used is the statutory corporation rate of thirty-two percent (32%).
5.4.1
This section provides the NERCs estimates of the various components required to calculate a WACC for the NESI. These estimates are then drawn together in a description of the process used for the first WACC calculation.
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The risk free rate The yield on government bonds is regarded here as the risk free rate. The NERC has had regard to relevant yields on Nigerian Treasury bonds, and has selected a riskfree rate of eighteen percent (18%) Many regulators use 10-year bond rates or 10-year (indexed linked) bonds or their local equivalent. The longer term also ensures consistency with the risk free rate used to estimate the market risk premium - that is also based on 10-year bonds.
The cost of debt The NERC adopted a nominal cost of debt of twenty-four percent (24%) for generation reflecting current debt levels for business and project. The cost of debt is generally determined by adding a debt premium, and sometimes a transaction cost, to the risk free rate.
Rd = Rf + DRP + DIC
(6)
Where: DRP DIC is the debt risk premium is the debt issuance cost lending in Nigeria
Betas Beta reflects the riskiness of an asset relative to the market as a whole (usually represented by the stock market). Equity betas will reflect the financial risk carried by shareholders, which is in turn influenced by the level of gearing since high levels of debt increase the risk to shareholders. Electricity supply is not an area with any history of investment from which to draw information on the relative risk and it is not considered possible to derive at statistically significant betas. The NERC has decided not to apply any value for the 2012 Tariff Order, but appropriate estimates will be made against next tariff review when enough data exists for estimates to be made.
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Gearing The ratio of equity and debt is used to weight the equity and debt returns in the WACC calculation. In the past, independent power producers in developing countries were financed with high gearing ratios commonly 80:20 debt to equity. However, the World Bank considers that in future, greater caution by lenders will result in project sponsors being expected to assume a greater degree of the project risk, by accepting lower debt-equity ratios. The Bank has suggested that future ratios would be closer to 60:40. This level would also apply to regulated assets, such as transmission and distribution. The NERC has selected a gearing ratio of 70:30 in the development of the WACC for the NESI.
WACC estimate The following are the main assumptions used in the WACC calculations: risk free rate nominal return on equity nominal cost of debt gearing level (debt/equity) corporate tax rate 18% 29% 24% 70%/30% 32%
Nominal before tax WACC Nominal after tax WACC Real pre-tax WACC Real after tax WACC
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charge comprises fuel cost, variable operation and maintenance cost, the transmission loss cost and a third (1/3) of tax cost. The capacity and energy charge will be included in the wholesale contract and will be the basis for payments to the eligible generators. However renewable energy generators are not entitled to capacity payment but will be paid full wholesale price based on power sent out from their plants.
Table 7: Wholesale Generation Prices for the Successor Gas Power Plants
2012 Wholesale contract prices (N/MWh) Capacity charge (N'000/MW/month) Energy charge (N/MWh) 9,563 3,515 5,389
Table 8: Wholesale Generation Prices for New Entrants Gas Power Plants
2012 Wholesale contract prices (N/MWh) Capacity charge (N'000/MW/month) Energy charge (N/MWh)
10,743 4,359 5,568
2013
11,534 4,701 5,951
2014
13,520 5,071 7,499
2015
14,665 5,470 8,169
2016
15,910 5,902 8,902
Table 9: Wholesale Generation Prices for the New Entrant Coal Plants
2012 Wholesale contract prices (N/MWh) Capacity charge (N'000/MW/month) Energy charge (N/MWh) 25,106
2013 27,024
2014 29,097
2015 31,559
2016 34,232
13,971 11,135
15,103 11,921
16,328 12,769
17,651 13,907
19,083 15,150
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Table 10: Wholesale Generation Prices for the Successor Large Hydro Plants
2012 Wholesale contract prices (N/MWh) Wholesale price including HYPADEC charges HYPADEC Charges Capacity charge (N'000/MW/month) Energy charge (N/MWh) 4,898 6,368 1,470 4,928 1,439
2013 25,433
2014 27,456
2015 29,643
2016 32,006
Table 12: Wholesale Feed-in-Tariff for Land Mounted Wind Power Plant
2013 26,512
2014 28,641
2015 30,943
2016 33,433
2013 73,300
2014 79,116
2015 85,401
2016 92,192
2012
2013
2014
2015
2016
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27,426
29,623
32,000
34,572
37,357
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