Document of The World Bank Public Disclosure Authorized Report No. 16001-KE
STAFF APPRAISAL REPORT
Public Disclosure Authorized KENYA
ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT Public Disclosure Authorized May 21, 1997 Public Disclosure Authorized Water, Urban and Energy 1 Division Eastern and Southern Africa Department Africa Region CURRENCY EQUIVALENTS
Currency unit = Kenya Shilling (K Sh) USS 1.00 = K Sh 56 (As of January 1996) K Sh i 00 = US$0.01,
WEIGHTS AND MEASURES
Metric System
I Kilovolt (RV) 1,000 Volts I Megawatts (MW) = 1,000 Kilowatts (kW) I Gigawatt hour (Gwh) I million kilowatt hours (kwh) I ton of oil equivalent (toe) = about 7 bbl of crude oil 1 barrel (bbl) = 0.16 cubic meters
GLOSSARY OF ABBREVIATIONS
CAS Country Assistance Strategy CPDM Chief Project Development Manager EA Environmental Assessment EAPLC Eastern Africa Power and Lighting Company EIB European Investment Bank ERB Electricity Regulatory Board ERR Economic Rate of Retum ESAF Enhanced Structural Adjustment Facility ESMAP Energy Sector Management Assistance Programme GoK Govemment of Kenya ICB Intemational Competitive Bidding IDA International Development Association IDC Interest During Construction IMF Intemational Monetary Fund IPP Independent Power Producer ISG Implementation Support Group KICM Kenya Association of Manufacturers KffW Kreditanstalt fur Wiederaufdau KPC Kenya Power Company Limited KPL Kenya Pipeline Company Limited KPLC Kenya Power and Lighting Company Limited KPRL Kenya Petroleum Refinery Company Limited KVDA Kerio Valley Development Authority KWS Kenya Wildlife Services LPG Liquefied Petroleum Gas LRMC Long Run Marginal Cost MOE Ministry of Energy MOF Ministry of Finance NCB National Competitive Bidding NGO Non-Govemmental Organization NOCK National Oil Corporation of Kenya NPV Net Present Value OECF Overseas Economic Cooperation Fund PPF Project Preparation Facility SDR Special Drawing Rights SOE Statement of Expenditure TARDA Tana River Development Authority TRDC Tana and Athi Rivers Development Authority UEB Uganda Electricity Board
GOVERNMENT FISCAL YEAR
July I - June 30
Vice President Callisto E. Madavo Director Harold E. Wackman Technical Manager Jeffrey Racki Team Leader Joel J. Maweni KENYA
ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT
CONTENTS Page No.
CREDITAND PROJECTSUMMARY
1. ENERGYSECTOR AND THE MACROECONOMICCONTEXT ...... I A. MACROECONOMICCONTEXT ...... 1 B. THE ENERGY SECTORAND THE ECONOMY...... 2 C. ENERGYRESOURCES ...... 3
2. ENERGY SECTOR ORGANIZATION ...... 6 A. POLICYINSTITUTIONS ...... 6 B. ELECTRICITYSUB-SECTOR ...... 6 C. PETROLEUMSUB-SECTOR ...... 9
3. ENERGY MARKETS, PRICING AND KEY ISSUES ...... 10 A. THE ENERGY MARKETS- ENERGYCONSUMPTION AND SUPPLY ...... 10 B. ENERGYPRICING ...... 15 C. KEY ISSUESIN THE ENERGYSECTOR ...... 16 D. WORLD BANK GROUP INVOLVEMENT...... 21
4. THE PROJECT ...... 23 A. PROJECT ORIGIN, RATIONALE AND OBJECTIVES...... 23 B. PROJECTDESCRIPTION ...... 24 C. PROJECTCOSTS AND FINANCING...... 27 D. PROJECTSUSTAINABILITY ...... 28 E. PARTICIPATION...... 29 F. ENVIRONMENTALASPECTS ...... 29
5. FINANCIAL ANALYSIS ...... 31 A. THE FINANCIALMANAGEMENT FRAMEWORK ...... 31 B. PAST AND PRESENTFINANCIAL PERFORMANCE ...... 32 C. PROJECTED FINANCIALPERFORMANCE ...... 36 D. AN ACTION PLAN FOR FINANCIALREFORM IN THE ELECTRICITYSUBSECTOR ...... 37
6. IMPLEMENTATION ARRANGEMENTS ...... 39 A. OVERALL...... 39 B. IMPLEMENTATIONARRANGEMENTS ...... 39 C. PROJECTIMPLEMENTATION PLAN ...... 40 D. PROCUREMENT...... 41 E. DISBURSEMENTS...... 43 F. ACCOUNTINGAND AUDITING...... 44 G. MONITORINGAND EVALUATION...... 44
7. PROJECT JUSTIFICATION, ECONOMIC ANALYSIS AND RISKS ...... 45 A. OVERALL...... 45 B. NEED FOR THE PROJECT, ITS SIZE AND TIMING...... 46 C. ECONOMIC RATE OF RETURNAND SENSITIVITYANALYSIS ...... 47 D. RISK MITIGATION...... 49 E. FISCAL IMPACT AND SUSTAINABILITY...... 50
8. AGREEMENTS TO BE REACHED AND RECOMMENDATION...... 52
ANNEXES
Annex 2.1 Action Plan for Restructuring the Power Subsector Annex 3.1 Energy Balance Annex 3.2 Electricity Generation, Sales and Losses Annex 3.3 Available Generating Capacity and Generation in FY1994/95 Annex 3.4 Letter of Sector Development Policy Annex 4.1 Documents Available in the Project Files Annex 4.2 Description of the Sector Restructuring and Reform Component Annex 4.3 Description of the Efficiency Improvement Component Annex 4.4 Description of the Power System Expansion and Rehabilitation Component Annex 4.5 Description of the Geothermal Resource Development Component Annex 4.6 Rural and Household Energy Development Strategy Annex 4.7 Project Component by Financier Annex 4.8 Project Component and Expenditures by Year Annex 5.1 Financial Analysis Annex 6.1 Table of Contents for the Borrower's Project Implementation Plan Annex 6.2 Summary Project Implementation Schedule Annex 6.3 List of IDA-financed Activities Annex 6.4 Estimated Schedule of Disbursements Annex 6.5 Supervision Plan and Staff Input Annex 7.1 Lease-Cost Generation Expansion Plan Annex 7.2 Details of Economic Analysis and Assumptions Annex 7.3 Estimated Willingness to Pay for Electricity Annex 7.4 Quantitative Risk Analysis Annex 7.5 Fiscal Analysis Annex 7.6 Performance Indicators
IBRD MAP No. 28165
This report is based on the findings of Bank appraisal and post appraisal missions in November 1994 and January 1996, respectively. The mission members included: Mr. Joel Maweni (Task Manager), Mangesh Hoskote (Power Restructuring Specialist/Consultant), R. I. GopalKrishnan (Senior Procurement Specialist), Paivi Koljonen (Economist), Rowena Martinez (Operations Analyst), T. S. Nayar (Principal Chemical Engineer), Said Al Habsy (Senior Legal Counsel), J. Koenig (Consultant, Geothermal Specialist), A. Posada (Consultant, Power Engineer), K. Zaki (Consultant, Petroleum Exploration Specialist), S. Dhar (Consultant, Power Engineer), G. Calderon (Consultant, Geothermal Specialist), J. Sasia (Operations Officer). Peer reviewers for the project were Messrs. B. Thiam, D. Jordan and C. Algandona. Secretarial support and report production were done by Mmes: N. Jones and V. Fofanah. REPUBLIC OF KENYA
ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT
CREDIT AND PROJECT SUMMARY
Borrower: The Republic of Kenya
Implementing Agency: Ministry of Energy (MOE)
Beneficiaries: Kenya Power Company (KPC); Kenya Power and Lighting Company (KPLC)
Poverty: Not applicable.
Amount SDR 86.6 million (US$125.0 million equivalent)
Terms: Standard IDA Terms with a 40-year maturity
Commitment Fee: Standard (variable rate between 0 and 0.5% of the undisbursed credit balance set annually by the Executive Directors of IDA)
Onlending Terms: SDR 72.4 million (US$104.6 million equivalent) and SDR 8.1 million (US$11.7 million equivalent) would be onlent to KPC and KPLC respectively at 7.7% with a repayment period of 20 years, including five years' grace. KPC and KPLC would bear the foreign exchange risk.
Financing Plan: See Schedule A
Net Present Value: US$ 343.0 million
Staff Appraisal Report: Report No. 16001-KE
Map: IBRD No. 28165
Project ID 1344
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1. ENERGY SECTOR AND THE MACROECONOMIC CONTEXT
A. MACROECONOMICCONTEXT
1.1 Kenya's 25 million people had a per capita income of US$260 in 1994 (at current prices and exchange rate). Kenya's economy depends on agriculture, which employs 70 percent of the labor force and contributes more than one quarter of GDP. Coffee and tea are the main agricultural products and account for almost one half of merchandise exports. The service sector, including tourism (a leading foreign exchange earner), accounts for half of GDP and is an important source of employment. The manufacturing sector is relatively developed and diversified, and contributes about 13 percent of GDP.
1.2 Recent Economic Developments. The period 1990-1993 was marked by a sharp decline in all the major macroeconomic performance indicators. Agricultural production was adversely affected by unfavorable weather conditions. External imbalances worsened as a consequence of the Gulf crisis during 1990-1991, a general deterioration in terms of trade, and the decision of multilateral and bilateral donors, in November 1991, to withhold aid to Kenya because of concerns about poor macroeconomic performance, governance and multiparty democracy.
1.3 Since the middle of 1993, the Government's sustained effort to tighten fiscal and monetary policy has been effective in stabilizing the economy and contributing to the revival of economic growth. GDP grew by 3 percent in 1994 and by 5 percent in 1995. The fiscal deficit (exclusive of grants) has sharply reduced to 1.4 percent of GDP in 1995 and annual inflation declined from a peak of 62 percent in January 1994 to 6.9 percent in December 1995. With respect to structural reforms, the Government has eliminated foreign exchange controls and most controls on exports and imports. The liberalization of the maize market in December 1993 and the petroleum sub-sector in October 1994 abolished all price controls. Since 1992, the Government has also been implementing a major civil service reform program that has trimmed the sector by over 40,000 since July 1993. However, progress on parastatal reform has been slow until recently.
1.4 The Government has outlined its reform program over the period 1996-1998 in a Policy Framework Paper, which was distributed to the Board on February 23, 1996. This document highlights poverty reduction as the principal objective. The reform program is being supplemented by a new one-year Enhanced Structural Adjustment Facility (ESAF) arrangement with the IMF and an IDA Structural Adjustment Credit. - 2 -
1.5 As noted in the Bank's Country Assistance Strategy (discussed by the Board on January 30, 1996), an acceleration of economic growth is needed for poverty reduction in Kenya. Thus, the key development challenge facing the Government over the next few years would be to create the conditions for rapid and sustained growth which would reduce unemployment and poverty significantly. Given its relatively strong human resource endowment, Kenya has good prospects for export-led economic growth in excess of 5 percent per year, over the medium term, and even higher growth rates could be achieved in the longer term. However, in order to achieve these growth rates, which require rapid growth in manufactured exports, investment in basic infrastructure, including energy, must increase.
B. THE ENERGY SECTOR AND THE ECONOMY
1.6 The energy sector plays a critical role in the development of the economy. Adequate and reliable supplies of power and energy are indispensable for economic growth, which is central for poverty reduction - current shortage of power supplies is seriously affecting economic activity. The energy sector also contributes significantly to the financing of public expenditures through petroleum and income taxes. On the other hand, crude oil and petroleum products imports have a significant impact on the balance of payment account and the sector draws on foreign export earnings to service its external debt.
1.7 Because of the long time it has taken to reach agreemnet between the Government and the donors on sector policies, investment in new power generation capacity has been delayed. As a result, the power system is not adequate to meet demand. Peak load shedding has become unavoidable and has increased from about 40 MW (6 percent of peak) in FY93/94 to about 75 MW (10 percent of peak) in FY94/95. During FY94/95 the Kenya Power and Lighting Company Limited (KPLC) implemented a daily load shedding program, which curtailed supplies during the morning and evening peak hours. Although many industries shifted loads to off-peak periods in consultation with KPLC, and were thus able to reduce the economic impact of the rationing, continuous processing industries had limited possibilities to shift their consumption and therefore suffered losses in output. Although exact data on the quantity of unserved energy demand is not available, the comparison of the forecast and actual sales for FY94/95 indicate a figure of about 190 GWh. Assuming conservatively that the cost of unserved energy demand is US$0.25 per kWh, which is comparable to the cost of running a private diesel generator, the cost of energy shortages could be estimated at about US$50 million in FY1995. The rehabilitation of existing plant is providing some relief in 1996, but, as the earliest possible date for commissioning new generating capacity is FY1997/98, the gap between demand and supply would grow wider, resulting in increased private sector costs and disincentives for new investment.
1.8 In terms of contribution to the exchequer, the sector contributes revenues in the form of taxes from the importation and sale of petroleum products, and corporate taxes and dividends. In FY94/95, the sector generated about KSh 16,831 million (US$ 300 million) in fiscal revenue, which was about 13 percent of total central Government revenue. About 80 percent of this was from petroleum taxes. - 3 -
1.9 On the expenditure side, the net petroleum import bill in 1995 was about US$270 million. This means that Kenya used about 20 percent of its merchandise export earnings to pay for petroleum - mostly crude oil imports. In addition, because of its high degree of monopoly power, the refinery is able to pass on the costs of inefficient operations to the consumers. This cost is estimated at about US$22 million per annum in the form of high prices for petroleum products. Deregulation of the petroleum sub-sector, which is partially supported by the proposed project would benefit consumers through efficient market-determined prices.
1.10 Because of Government policy of low tariffs until recently, the power sub-sector has depended on Government support for financing some of its investment programns.With the tariff reforms and other efficiency improvements initiated in the course of the preparation of the project, the power sub-sector's financial performance would improve significantly, thereby eliminating the requirement for future Government expenditure support.
C. ENERGY RESOURCES
1.11 Kenya's known energy resources include hydro and geothermal power, biomass, wind and solar energy. Exploration is in progress for hydrocarbons, but to date no significant reserves have been discovered.
1.12 Hydropower. The hydroelectric potential that would be economic to develop for the grid including installed capacity, exceeds 1,400 MW, with an annual average generation potential of about 6,000 GWh. Tana and Turkwell Rivers have the largest potential. Hydro potential also exist on other rivers, including the Ewaso Ngiro, Sondu, Nzoia, Nyando, Arror, and Athi. The Sondu basin has been the subject of two studies towards the multipurpose development of the basin's hydropower and irrigation potential. Consultants' reports have indicated that the development of the Miriu Falls site on the Sondu River for power generation would be economic. A feasibility study and economic evaluation was prepared under the Geothermal Development and Pre-Investment Project (Cr. 1973-KE).
1.13 Geothermal Power. Potential geothermal sites are located in the Rift Valley which runs from the border with Tanzania in the south to Ethiopia in the north. There are three major areas of geothermal activity: Olkaria, Eburru, and Lake Bogoria, with possible reserves measured in thousands of megawatts of electric generation capacity. The Olkaria field near Lake Naivasha, about 100 km west of Nairobi, contains proven reserves of 350 MW, which are the basis for power generation at the existing Olkaria Power Plant, and probable reserves of 600 MW at exploration sites. The Eburru prospect, 30 km north of Olkaria, contains probable reserves in the order of 100 MW. Several thermal manifestations in the Rift Valley between Eburru and the northern border of Kenya indicate the existence of extensive, but as yet unquantified additional energy resources. The Geothermal Development and Pre-Investment Project (Cr. 1973-KE) assisted in drilling of about 30 production wells to deliver steam to the Olkaria I and II Power Plants.
1.14 Biomass Resources. Kenya has large and diverse forest resources, though there is pressure on forests around major population centers. The main biomass energy is woodfuel -- - 4 - firewood and charcoal -- which is the major source of energy in Kenya, accounting for about 70- 75 percent of total energy use. Firewood is consumed by rural households and industries, particularly for tea drying, while charcoal provides cooking energy for many urban households and small commercial establishments. The only non-woody biomass resource which is being utilized on a proven commercial scale is sugar cane bagasse. The Kenya sugar industry produces about 35,000 tons of bagasse annually which, supplemented by fuelwood or fuel oil, is used to raise steam for producing sugar cane and generating about 25 GWh of electricity from turbines installed at individual sugar mills. The efficiency of power production from bagasse is low and could be increased with the introduction of pre-drying, palletizing and other measures, which could create surpluses to produce power for additional uses such as pumping water for irrigation or for sale to a power company. The project would provide financing for a Renewable/Household Energy Survey to provide the analytical basis for formulating a sustainable renewable/household energy strategy. Further, a rural electrification master plan is currently being carried out to explore alternative strategies for meeting rural power needs.
1.15 Solar and Wind. Kenya has a large potential of solar and wind energy, which have economic potential for meeting energy requirements particularly for rural communities because of the high cost of traditional network electrification. Indeed, Kenya has utilized its solar energy potential more successfully than most African countries. According to an ESMAP study, at least 20,000 photovoltaic units (PV) have been sold by the private sector since 1987. The systems have been sold mainly to rural middle class households, which are well integrated into the cash economy, but live far away from KPLC's power lines.' A unique feature is also the predominant role played by the country's private sector. There are currently eight Nairobi-based companies who supply the PV market, each with scores of agents in rural areas, to market, install, and maintain the systems. To promote the use of PV technology, the Government has over the past couple of years reduced the level of import tariffs and value-added tax on most PV equipment. The proposed project would further assist the Government to maintain a competitive tariff and tax policy for renewable energy equipment, and to establish guidelines for equipment quality. These policy actions are supplemented by an ESMAP-financed micro-solar project, initiated in 1995. The objective of the project is to overcome hurdles to wider adoptation of solar energy technology: it would investigate innovative financing options for lower income households, disseminate small solar powered lanterns on a commercial basis in rural villages and evaluate technical product performance and customer satisfaction. In addition, the Arid Lands Development Project, approved in November 1995 (Cr. No. 27970) would support renewable energy. For example, if a community microproject on water would use a solar or a wind-driven pump the project would finance it. To promote renewable energy technologies, the district mobile extension teams would sensitize communities and other development actors on the potential of renewable sources of energy and train community personnel in maintenance of the facilities.
1.16 Wind energy is used on a limited scale, mainly for irrigation: currently some 200 water pumps are in operation, many of them manufactured locally. In addition, KPLC operates a 200
Further informationabout photovoltaicsin Kenyacan be found in the ESMAPreport "PhotovoltaicPower to the People - The Kenya Case", January 1994 (no reportnumber). - 5 - kW wind turbine which, in 1995, provided 1.1 GWh to the grid, and a 350 kW hybrid wind/diesel system to serve the electricity needs of the surrounding community.
1.17 Hydrocarbons. No commercial petroleum resource has yet been discovered. Based on evidence available from drilling by privately owned oil companies in Kenya and in neighboring countries, Kenya's petroleum prospects are rated modest, but in view of the sparse data coverage its petroleum prospects remain to be fully evaluated. The most attractive areas at present are the Rift-related structural basins in the interior. Also of interest is the coastal margin basin where the majority of Kenya's exploration to date has taken place. The Bank has supported Kenya in promoting petroleum exploration by private companies, most recently through the Petroleum Exploration Technical Assistance Credit 1675-KE. - 6 -
2. ENERGY SECTOR ORGANIZATION
A. POLICY INSTITUTIONS
2.1 The Ministry of Energy (MOE) is responsible for energy policy formulation and oversight of the operations of the organizations in the power and petroleum sub-sectors. MOE is also concerned with the development of power, petroleum exploration and supply, and the development of biomass and other new and renewable energy resources. Until recently the Ministry of Finance (MOF), in consultation with MOE, established prices and tax rates for both power and petroleum products. Since October 1994, petroleum products retail prices have been market-determined.
B. ELECTRICITY SUB-SECTOR
2.2 Sub-sector Institutions. Three limited liability companies, and two regional development authorities are currently operating in the power sub-sector: the Kenya Power Company (KPC), the Kenya Power and Lighting Company (KPLC), the Tana River Development Company (TRDC), the Tana and Athi Rivers Development Authority (TARDA) and the Kerio Valley Development Authority (KVDA). The salient features of these institutions are:
(a) KPLC: KPLC was established in 1983, to become the successor of the East Africa Power and Lighting Company (EAPLC), a private company founded in 1922. KPLC is owned by the GoK (51.49%), Kenya residents (41.13%) and nonresidents (7.38%). It is the only institution licensed to distribute electricity, and therefore, owns all the distribution facilities. It also owns some small hydroelectric plants, some thermal plants and transmission lines. It operates the generation and transmission system and manages both KPC and TRDC, as well as the generation facilities of TARDA and KVDA. It is responsible for the preparation of the sub-sector's expansion programs and is the GoK's executing agency for designing, constructing and operating rural electrification schemes.
(b) KPC: KPC was created in 1954, to import electricity from Uganda for sale by the EAPLC. KPC is wholly owned by the GoK, has no staff of its own and is managed by KPLC under a management contract. It owns the Olkaria geothermal power station, two small hydro plants (Tana and Wanji, 14 and 7 MW, respectively), the interconnection line with Uganda and other transmission lines. The power generated from KPC's plants and imported power from Uganda is sold - 7 -
to KPLC at cost (includes debt service, operation, maintenance and development surcharge to meet the local contribution for new investment).
(c) TRDC: TRDC was created in 1964 as a separate company to develop the hydroelectric potential of the Tana River. TRDC is wholly Government owned and is also managed by KPLC. The company owns three power stations, Gitaru (145 MW), Kamburu (92 MW) and Kindaruma (44 MW).
(d) TARDA: This is a development authority fully owned by GoK. It was created in 1974 for the integral development of several basins in the Tana river including their hydroelectric, irrigation, fisheries and associated tourism potential. It owns the Masinga (40 MW) and Kiambere (144 MW) power stations and their associated transmission lines. KPLC operates and maintains the power facilities and buys power in bulk from TARDA. Under the financing of Kiambere, KPLC is obligated to cover the cost of debt service on higher terms than those provided to the Government by lenders. The difference was originally intended to provide TARDA with financing for its non-power activities. In 1988 the GoK instructed KPLC to direct its payments to the Treasury and to base them on the terms at which the loans had been provided to the GoK. To compensate TARDA for the loss of revenue, since 1994 the Treasury and KPLC have provided support to TARDA.
(e) KVDA: This is also a development authority fully owned by GoK. It was created in 1979 with similar objectives to TARDA. It implemented the Turkwell Hydro Plant (106 MW), completed in 1991 (para 3.18(c)).
2.3 The complexity of the power sub-sector organization, especially the overlapping financial functions among the entities, has given rise to disputes on issues of assets ownership and responsibility for debt service. The GoK has therefore decided to restructure the sub-sector with a view to creating commercial-type relationships among the companies. The restructuring has separated management of generation assets from that of transmission and distribution assets. The Turkwell Hydropower Plant will be transferred to the generation company at a cost reflecting replacement cost. The action plan for reorganization of the power sub-sector which has been agreed with the Government is shown in Annex 2.1.
2.4 As of May 1993, KPLC, the only institution with staff, was over-staffed. It had 10,616 employees, serving 300,000 customers giving a customer/employee ratio of 28:1. In early 1994, agreement was reached between KPLC and the Bank for KPLC to improve its customer/employee ratio to at least 45:1 by the end of 1995. By December 1994 the customer/employee ratio had increased to 35.4:1 and currently stands at 50:1. Since KPLC was understaffed at the professional level and over-staffed at other levels, these improvements have been achieved through contracting out non-core services and staff reductions, - 8 -
2.5 Applicable Legislation and its Impact on the Sub-Sector: The limited liability companies are governed by the Companies Act, and as such should be able to operate as commercial concerns. As part of the sector reforms, KPLC and KPC were recently exempted from the provisions of the State Corporations Act. The Act severely limits the entities' management and operational autonomy including that of the development authorities. Apart from the State Corporation Act, the other legislation affecting the generation, transmission and distribution of power consists of the Electric Power Act, the Geothermal Resources Act, and other Acts that deal with foreign investment and with land use. There is currently no environmental legislation for the sub-sector. The effects of the various laws on the sub-sector are as follows:
(a) The State Corporations Act poses restrictions on the companies and development authorities, as it gives the President and the responsible Minister wide discretionary powers over them. For example, the President may appoint and remove board members, and he may issue directives which must be implemented by the Board.
(b) The Electric Power Act. The Act provides the Minister with broad powers. In addition to formulating sub-sector policy, he has control over electricity tariffs. The Minister also is the dispenser of the licenses needed to participate in any of the sub-sector's activities. He may also revoke or modify the terms of a license during its life. Such wide ranging powers are not conducive to the efficient operation of the sub-sector and are incompatible with today's accepted industry and business practices which are based on a clear separation of the ownership, regulation and operation of the sub-sector.
(c) The Geothermal Resources Act is meant to regulate the use of Kenya's geothermal resources. It establishes that the resources belong to the State and again confers power to the Minister of Energy. He issues licenses for exploration and exploitation and can impose levies, rentals and royalties for use of the resources.
2.6 The sub-sector has been regulated by the Minister of Energy. The creation of an independent and credible regulatory mechanism is clearly important for the long-term sustainability of private sector participation in the sub-sector. The Government has prepared an action plan for reform of the legal and regulatory framework for the power sub-sector including specific proposals for establishment of an autonomous Electricity Regulatory Board (ERB). The draft enabling legislation has been prepared with PPF financing and would be presented to the Borrower's legislature prior to Credit effectiveness (para .8.2 (i)). Further, the Government has stated in its Letter of Sector Policy that the power sub-sector will now be required to operate on a commercial basis without burdening the Government budget. -9 -
C. PETROLEUM SUB-SECTOR
2.7 Sub-sector Institutions. Eight private companies, two parastatals and one semi private company operate in the petroleum sub-sector. The supply and distribution of petroleum products is in the hands of subsidiaries of six multinational oil companies (AGIP, BP, CALTEX, ESSO, SHELL, TOTAL), and two other private companies (KOBIL and KENOL). The state-owned National Oil Corporation of Kenya (NOCK) oversees exploration activities and procures crude oil and petroleum products in competition with the other oil companies. The Kenya Petroleum Refenery Ltd. (KPRL) at Mombasa, is jointly owned by four oil companies (Shell, BP, Esso and Caltex - 50%) and the Government (50%). The Kenya Pipeline Company (KPL) operates the petroleum products pipeline which runs from Mombasa to Nairobi and farther to Nakuru, Eldoret and Kisumu in western Kenya.
2.8 The Government deregulated the procurement and importation of crude oil and finished products, and retail prices in October 1994. NOCK's right to supply at least 30% of the distributors' crude oil requirements was rescinded and the distributors are no longer obliged to meet their requirements through KPRL (para. 3.22). However, the petroleum sub-sector could not be fully deregulated because of the market's dependence on KPRL for LPG (a by-product in the refining process) and the absence of infrastructure for its importation. Therefore, the Government: (i) required oil companies to import and process through the refinery at least 1.6 million tons of crude annually, which is the volume required to meet the market's current demand for LPG; and (ii) protected the refinery's operations, initially for two years through a tax on selected imported products. -10-
3. ENERGY MARKETS, PRICING AND KEY ISSUES
A. THE ENERGY MARKETS - ENERGY CONSUMPTION AND SUPPLY
3.1 Kenya's total energy consumption amounted to about 12.5 million tons of oil equivalent (toe) in 1994. This translates to 0.48 toe per capita, which is low by world standards but the highest in the Eastern Africa Region'. Fuelwood and charcoal met 70- 75 percent of total energy consumption. Modem energy products - electricity and petroleum products - met the remainder. Kenya's modem energy consumption (0.10 toe per capita) is below other developing countries, though it is higher than the average 0.07 toe for sub-Saharan Africa2 . Annex 3.1 shows the national energy balance.
Electricity
3.2 Consumption. The growth rate in KPLC's electricity sales has declined during the past couple of years, owing to a combination of a slowdown in economic growth, and a supply shortage. While KPLC's sales increased by more than 5 percent annually during 1987 and 1991, the average annual increase has been around 4 percent since 1991. Total sales in the interconnected system were 3,402 GWh in FY96 of which 45% was to large industrial and service establishments. Larger industrial and service sector have also been the consumer category with the most rapidly increasing demand. The total number of consumers, including rural electrification, is about 406,000 of which 307,000 (76%) are residential. It is estimated that only 7 to 8 percent of the total population has access to electricity. Table 3.1 and Annex 3.2 show electricity sales by consumer category in FY96.
3.3 The growth in system peak demand has also slowed down significantly over the past few years, and was 648 MW in the 1995/1996 fiscal year. Overall, the average annual increase has been below 4 percent since 1990, compared to 6.5 percent during the second half of the 1980s.
Total per capita energyconsumption in Ugandaand Ethiopiais about 0.3 toe and in Tanzaniaabout 0.45 toe. 2 Modemper capitaenergy consumptionin 1991was about 0.4 toe in Thailand;about 0.3 toe in the Philippines,India and Indonesia,while it was about2.1 toe in Korea. - I1 -
Table3.1 - ElectricitySales by ConsumerCategory in FY96
1995/96 Average annual growth rate ConsumerCategory (GWh) FY90-FY96 (%)
Domestic/smallcommercial & 993 4.1% irrigation Medium commercial& industrial 660 3.0% Large commercial& industrial 1,492 4.7% Off-peak 92 -3.9% StreetLighting 15 1.2% Total KPLC 3,252 3.8% Rural electification 150 14.7% Total Sales 3,402 4.2% SystemPeak (MW) 648 3.7% Source: KPLC
3.4 Chart 3.1 below illustrates that the Nairobi and the Coastal (including Mombasa) areas account for the bulk (70 percent) of KPLC sales.
Chart 3.1 KPLCElectricity Sales per GeographicArea FY1995
M t. K e ny a North Rift W cst Kcn y
C entrol R ift
N airobi
C oIut
3.5 Generation Facilities. Hydro power stations dominate (79%) the interconnected system of 776 MW of available generating capacity, while geothermal and oil thermal stations provide the balance. In addition, Kenya has an import agreement with the Uganda Electricity Board (UEB) for 30 MW of firm power up to the year 2005. However, because UEB has had little capacity to spare, it has usually been able to export only during off-peak hours. During 1990-1995, UEB provided only 17 MW of off-peak power. Table 3.2 shows the available generating capacity and annual generation in FY96. Annex 3.3 provides plant details. - 12-
Table 3.2 Available Generating Capacity and Generation
Capacity (MW) as at February 1996, and generation (GWh) in FY96
AVAILABLE CAPACITY (excl. imports) MW 776 Of which Hydro 619 Oil thernal/thennal/diesel/gas turbine 105 Geothermal 45 Wind 0.4 Diesels in isolated areas 7
GENERATION (gross) GWh 4,119 Of which Hydro 3,163 Oil thermal/diesel/gas turbine 397 Geothermal 390 Wind I Imports from Uganda 149 Diesels in isolated areas 19 Network losses and station use GWh 717 SALES GWh 3,402 Source: KPLC
3.6 The two most important power stations are the Gitaru and Kiambere hydroelectric stations, which together produced almost 80 percent of total energy in the interconnected system in 1995/1996. The Olkaria I geothermal station and the liquid fuel generators (diesels, steam units and gas turbines) provided less than 10 percent each.
3.7 Transmission and Distribution Facilities. The transmission facilities are the following: 980 km of 220 kV lines; 450 km of 66 kV; 120 km of 40 kV; 3,450 km of 33 kV; and 8,300 km of 11 kV circuits. The 220 kV network is about 10 years old and consists of four line segments. All 220 and 132 kV lines have single pole reclosing. As a result of only one 220 kV line connecting Mombasa to the major hydrostations and because the thermal capacity in the Mombasa area is insufficient to meet the demand, the quality of service suffers when the line fails. There is also insufficient voltage support in Mombasa (supply voltage is too low part of the time, and too high at other times). To improve supply in Mombasa, the project includes installation of transformers, construction of lines and substation. Distribution voltage is typically 33 and 11 kV. Secondary distribution voltage is 415 volts for three phase supply and 240 volts for single phase service.
3.8 System Operations. System operations have been constrained over the last few years due to insufficient reserve margin, and were further affected by the damage suffered by one of Gitaru's generating units which took about a year to repair and was returned to service in March 1996. As no new capacity has been added to the system since FY 1990/1991, reserve margins have continuously decreased, and KPLC has been forced to resort to periodic load shedding (para 1.7). The output from the thermal plants have increased in the past couple of years as a result of: (i) a rehabilitation program that has managed to bring up the steam, gas turbine and diesel units close to their rated capacities; and (ii) the connection, in 1995, of drilled make-up wells to recover the original output of the Olkaria I Geothermal Power Plant. - 13 -
3.9 KPLC has been relatively successful in managing system losses -- about 16 percent of net generation -- when compared to neighboring countries (international standard is 10 %). However, they are quite high in some parts of the transmission and distribution system, especially in the Coastal area, where KPLC rely on long 33 kV feeders to supply load concentrations on the Mombasa Island. As loss levels increase with load growth, targeted loss reduction measures are required to prevent unacceptable growth. The proposed project includes a four-year line loss reduction program comprising upgrading and installation of new feeders, replacement of capacitors, low voltage system reinforcements and construction of new substations (para. 4.5 (c (ii)).
3.10 Demand and Supply Balances. The sales forecast predicts electricity consumption to increase on average by 5.6 percent per year over the next ten years to 5,785 GWh in 2006. Charts 3.2 and 3.3 below depict the operation of the interconnected system with and without the proposed project. Chart 3.2 shows the annual balance between peak demand and available generating capacity and indicates that the system's reserve margin presently is negligible resulting in peak load shedding. The situation worsened during 1996 as several of the old Kipevu thermal units were derated due to breakdown. With the investments under the proposed project, the capacity balance would remain comfortably positive from the year 2000 through 2004. Thereafter, new capacity needs to be installed to meet the growing demand. The chart also shows that without the project, the capacity of the existing system would decline slightly with the retirement of the old steam and gas turbine units (Annex 7.3 provides details).
Chart 3.2: Capacity Balance
1,600
1.400
1,200- 1l200* | | T _New geothemalMW
1,000 ! New hydro MW
800 - t Newdiesel MW
6 7E.isting capacatywith project 600 m
2+_-E.isting capacitywithout 400 projectMW -- Forecastsystem peak MW
200
0
3.11 Chart 3.3 below shows the annual balance between electric energy demand and supply. The system is not able to meet the current energy demand and the shortage of energy would continue until Kipevu II and Olkaria III are commissioned in FY2000. Then, with the other investments under the proposed project - and under average - 14 - hydrology - the system would be able to meet demand until around the year 2004, when the demand again starts pressing close on supply.
Chart 3.3: Electric Energy Demand and Supply Balance
7,W /
5IOW
,:~~~~~~~~~ tst0 No-U6Q>
Petroleum
3.12 Domestic petroleum products consumption has grown relatively slowly in the past years (I% per year on average), and was 2 million tons in 1995 (Chart 3.4). The transport sector accounts for about 67 percent of total consumption; government establishrnents for 25 percent; and non-governmental industries, the service sector, agriculture and households for the balance of 8 percent. Given strong economic growth of at least 5 percent per year, future consumption growth levels are expected to be higher than those experienced in the recent past. In addition, LPG consumption is expected to increase once the supply constraints are removed.
3.13 Since Kenya does not have its own oil resources, all petroleum requirements are imported. Crude oil is refined at the Mombasa refinery, but due to the simple configuration of the refinery, it is uneconomic to process sufficient crude oil to match the domestic demand and, therefore, refined products are imported to meet the supply shortfall. Kenya imported about 2 million tons of crude oil and 500,000 tons of refined products in 1995.
3.14 Refined products are transported via a pipeline from the Mombasa Refinery to Nairobi, and after the recent extension of the pipeline, from Nairobi farther to the towns of Kisumu and Eldoret in western Kenya. The pipeline also serves as a transport media for about half of the petroleum products requirements of Uganda (the other half is transported via Tanzania). - 15 -
CHART 3.4 DOMESTIC DEMAND FOR PETROLEUM PRODUCTS
z5s00,__
2000,~3- U Kerosene UPetrol 115NIOW~ ~ ~~~IOMP I I E~~~~~~~~~~~~~MJetFue 1,000,000, o~~~~~IIIIIII~~IFuelOil * Diesel
1983 1986 1989 1992 1995
B. ENERGY PRICING
3.15 Electricity Tariffs. Kenya has had a history of low electricity tariffs. The low prices led to the deterioration of the power sub-sector's financial viability (paras. 5.8 - 5.12). In 1994, however, Kenya started moving towards economic pricing. Under the program of tariff adjustments agreed with IDA, the first installment raised the average tariff by about 60% in March 1994. The resulting average tariff was about 55%of LRMC. The second installment, effected in October 1996, increased the average electricity tariff to about 73 percent of LRMC. An update of the November 1993 Tariff Study to be completed by November 1997, would provide the basis for the Govemrment to agree with IDA on the magnitude and timing of additional adjustments to cover full LRMC. The 1994 increases improved KPLC's financial position, and future increases would help it to finance a reasonable share of the costs of its investment program and contribute to more efficient use of electricity. As the sub-sector is moving towards commercialization and independent power producers (IPPs), bulk supply tariffs for purchases from IPPs would be based on the ICB process while the tariffs to final consumers would be decided by an autonomous ERB (para. 2.6) on the basis of LRMC principles and the financial needs of the subsector.
3.16 Petroleum Products Prices. On October 27, 1994, the GoK deregulated petroleum products pricing in line with the agreement reached with the Bank in the Policy Framework Paper for 1994-1996. Taxes account for between 0 percent (jet fuel) and 53 percent (regular gasoline) of retail prices.
3.17 Comparative Household Energy Costs. Table 3.5 below shows that firewood and charcoal are the lowest cost cooking fuels on an equivalent energy basis. Electricity is substantially more expensive and consequently it is not commonly used for cooking. - 16 -
In an effort to promote switching from kerosene and charcoal to LPG, the Government is considering standardizing LPG equipment to increase market competition and lower prices. The proposed project would finance a study to recommend uniform standards for LPG cylinders, valves and pressure regulators including the associated testing, monitoring and regulatory arrangements (para. 4.5 (B)). Additionally, the liberalization of petroleum prices should increase the availability of fuels even in the more remote areas. Availability would also improve upon completion of the infrastructure to allow increased production and/or importation of LPG. The household/rural energy studies under the project would assess taxation policies to promote transition to efficient modem fuels (para. 4.5(B)).
Table. 3.5 Comparative Cooking Costs
LPG Kerosene Charcoal Firewood Electricity
Nairobi retail price 667 269 135 31 113 US$/ton or US$/MWh Net heating value 44.8 40.5 34.4 16.7 3.4 MMBTU/ton or MMBTU/MWh Price 14.8 6.64 3.93 1.85 33.0 US$ per MMBTU Stove Efficiency 55% 42% 30% 17% 60%
Efficiency adjusted cost US$ per MMBTU 27.1 15.8 13.1 10.9 55.0 1/ Exchange rate: I $US =55 KSh C. KEY ISSUES IN THE ENERGY SECTOR
3.18 The principal issues in the energy sector are: (i) Government involvement in all aspects of energy sector operations (para. 2.5); (ii) low electricity prices in relation to the power sub-sector's financial requirements and to the economic cost of supply (para. 3.15); (iii) complex power sub-sector organizational structure (para. 2.3); (iv) until recently, GoK control of petroleum products pricing, marketing and procurement resulting in economic distortions; (v) low demand and supply-side energy efficiency; and (vi) potentially negative environmental effects of energy projects. Because of the long time it has taken the GoK and the Bank to reach agreement on sector reform policies, it has proved difficult for the GoK to mobilize resources for the required investmnents,thus resulting in the current electricity supply shortages.
(a) Government Involvement. The GoK has played a dominant role in the sector through ownership of facilities and a significant involvement in strategic and operations management. It is the main owner of power generation facilities, owner of the oil pipeline and petroleum storage facilities, and has a 50 percent stake in the KPRL. In addition, the GoK takes an active management role in the key areas of setting and approving electricity prices, approving investment programs, and appointing the Boards of the energy enterprises. Prior to the exemption of KPLC and KPC from the State Corporations Act, the GoK also provided the ceilings on staff remuneration and benefit levels under the general categorization of parastatals. - 17-
(b) Electricity Pricing. For many years, the average electricity tariff remained substantially below the economic and financial cost of supply (para. 3.15). As a result, the sub-sector experienced financial difficulties which impacted on its ability to service external debt obligations, which the Government had to meet under guarantee agreements with lenders. However, following recent tariff increases, the industry has reimbursed the GoK. Low prices have also promoted inefficient use of electricity.
(c) Complex Organization of the Electricity Sub-Sector. Power purchase arrangements between the KPLC and the bulk supply companies (KPC, TRDC, TARDA and KVDA) are complex. KPLC purchases power from the bulk supply companies under various purchase and lease agreements. A number of unusual practices are apparent in the execution of these agreements. First, with respect to power purchases from TARDA, the Government requires KPLC to remit payments to cover TARDA's debt obligations to the Treasury, instead of making payments to TARDA as envisioned under the original agreement. Since 1994, KPLC also pays KSh 55 million annually directly to TARDA to cover expenditure on catchment preservation, dam monitoring and security. In addition, the GoK finances the cost of TARDA's other activities. Second, the ownership of the Turkwell power plant implemented in 1991 (developed by KVDA and operated by KPLC) is undefined. Nevertheless, KPLC has since 1994 paid KVDA KSh 45 million annually to cover operating and maintenance costs related to the Turkwell dam. In addition to the annual payments, KPLC also pays the equivalent of US cents 3 per KWh for the electricity dispatched from Turkwell and covers the operation and maintenance costs of the power station.
(d) Petroleum Sub-Sector Operations. With the deregulation of petroleum products prices and importation in October 1994, the main outstanding issue is the removal of the remaining impediments to full competition: (i) the requirement for the market participants to process at least 1.6 million tons of crude oil per annum so as to meet the current consumption of LPG; and (ii) the import taxes on fuel products instituted to protect KPRL, initially for two years up to October 1996. Based on estimates by the present shareholders, the minimum level of protection that the refinery in its present state would need to be competitive with direct product imports is equivalent to about US$1.5 per barrel imported products. This translates into an annual cost to the economy of about US$22-37 million. These issues are being addressed under the Bank's macroeconomic dialogue with the Government.
(e) Delays in Implementing Sector Investment Programs. Investment, both in new plants and in the rehabilitation of existing facilities to meet the growing demand for energy has been inadequate. The main reasons - 18 -
for inadequate investment have been lack of donor support due to slow implementation of sector reforns and inadequate self-financing. As a result, Kenya is now experiencing electricity shortages which are imposing a substantial cost to the economy and restraining economic growth (para 1.7). If the required investments are not undertaken quickly, electricity shortages would continue to increase with serious consequences to the economy, especially if rainfall is below average and reduces the output from the hydro plants. The sub-sector's aggregate investment requirements are estimated to total almost US$1,000 million during FY96- 2001, the financing of which would be a heavy burden on the economy unless the Government seeks new ways of mobilizing resources, for instance from the private sector as well as substantially improving the financial performance of the power companies. This in turn requires increasing the operational efficiency of the companies and adoption of sound pricing policies. The proposed project would finance about US$700 million (excluding interest during construction) for the next five years. Additional resources would therefore need to be soon mobilized, particularly for financing of transmission and distribution systems.
(f) Demand and Supply-Side Energy Efficiency. Although some efforts have been made to improve energy efficiency, inappropriate energy pricing policies and lack of awareness of savings opportunities have impeded progress in this area. On the supply side, KPLC has recently carried out a loss reduction study, with the assistance of ESMAP, to identify cost-effective means to reduce distribution losses in the major load centers. On the demand side, the Kenya Industrial Energy Management Programme -- initiated in 1985, and administered by the Kenya Association of Manufacturers (KAM) -- focuses on the provision of information and energy audit services on a cost- sharing basis. Currently, ESMAP is providing support to increase the program's commercialization through greater cost-sharing by the benefiting industries, and to introduce modem techniques and skills. The outlook for improved demand and supply-side energy efficiency is more promising today because of the new tariff policy, the power sub-sector reorganization, including greater commercial orientation and private sector participation. The proposed project would build on the past experiences and the new incentives and finance activities to develop the human and institutional capabilities, promote private sector participation and introduce energy efficient technologies.
Agenda for Policy Reform
3.19 The dialogue between the Bank and the Government of Kenya on energy sector reforms has been going on since the preparation of the Geothermal Development and Pre- Investment Project in 1988. The Government fully recognizes the importance of the - 19 - issues discussed above on both sector and macroeconomic performance and has recently committed itself to creating an efficient and viable energy sector.
3.20 The GoK's overall strategic objective is to create enabling conditions for an efficient energy sector and eliminate electricity supply deficits. To accomplish this objective, the strategy is detailed in Government's Letter of Sector Development Policy (Annex 3.4). The strategy comprises: (i) macroeconomic measures to create an enabling environment for attracting private sector investment and to improve incentives for operational efficiency; (ii) reforms of the sector's institutional and legal environment; and (iii) least-cost investments in power to eliminate supply deficits in the late 1990s and early 2000s. Public sector investments are expected to be complemented by private sector investment in at least two power plants in the next five years.
3.21 Macroeconomic. The macroeconomic measures relate primarily to the adjustment of power tariffs and to the deregulation of the petroleum sub-sector. On electricity prices, the objective is to reach economic levels so as to provide appropriate consumer signals and to enable the sub-sector to become financially viable. The Government agreed in the context of the 1994-1996 PFP, to raise the average tariff to 75 percent of the LRMC by 1996, in three installments starting in March 1994. In the first installment, a nominal increase of about 60 percent in the average tariff raised it to about 55 percent of LRMC. The second installment, scheduled for March 1995 was postponed since the average tariff had already reached the 65 percent of the LRMC target due to appreciation of the KSh. The installment on October 1, 1996, raised the average tariff to about 73 percent of LRMC. In addition, the Government has: (i) given KPLC the autonomy to implement a fuel adjustment clause since March, 1994; (ii) agreed to allow KPLC to automatically adjust tariffs to reflect changes in the cost of external debt service arising from fluctuation in the exchange rate of Kenya shilling. Further adjustments would be determined on the basis of an update of the Tariff Study to be completed by November 1997 and recommendations, satisfactory to IDA, would be implemented during FY1997/98. This issue will also be addressed under the Bank's macroeconomic dialogue, as the agreement between the Government and IDA on an action plan for the implementation of further tariff adjustments is a condition for the Structural Adjustment Credit's second trance release.
3.22 With regard to the petroleum sub-sector, the GoK deregulated the importation, marketing and pricing of petroleum products on October 27, 1994. The objective of the deregulation was to create a competitive and efficient market for petroleum products by removing controls on procurement, distribution and pricing of products. The following measures have been implemented to date:
(i) NOCK's right to import upto 30 percent of domestic product requirements was rescinded; - 20 -
(ii) temporary import tariff of KSh 0.50 per liter on all finished petroleum products except kerosene, LPG and automotive diesel, to allow KPRL to prepare for a competitive environment;
(iii) liberalization of retail prices, although, under the Restrictive Trade Practices and Monopolies Act Ch. 504, the MoF has powers to fix ceiling prices in areas with inadequate competition;
(iv) a monitoring cell was established in MOE to monitor petroleum products' prices and maintenance of minimum operating stocks of 30 days consumption of liquid products and 10 days for LPG by oil companies; and
(v) requirement that the oil companies refine at least 1.6 million tons of LPG rich crude oil at KPRL to secure LPG supply until alternative supply arrangements have been worked out.
3.23 The Government and other shareholders in the refinery are currently discussing tbe options for the future of the refinery. These include: (i) extension of protection to gine KPRL more time to improve its competitiveness in an open environment, including investment in improving LPG output; and (ii) closure of the refinery with the possibility o-fconverting it into a fuel import facility including importation of LPG. These issues are beivigaddressed under the Bank's macroeconomic dialogue with the Government.
3.24 Institutional and Legal Environment. This aspect of the strategy comprises restructuring of the power sub-sector to create arm's length commercial-type relationships between the companies and reforms of the legal and regulatory framework o tlacilitate the restructuring of the sub-sector and encourage private sector participation. Ati autonomous regulatory arrangement is particularly important to ensure that decisions im'electricity pricing, and environmental issues among other things are taken in an ,o'bi(ctivemanner.
'.X95 On power restructuring, the GoK commissioned a two phase Power Sector P,estructuring Study to recommend an efficient industry structure and an implementation anidfinancial restructuring plan. Based on the reports' recommendations, the Go vernrnent agreed to restructure the sector entities into two separate companies, one for generation and one for transmission and distribution, both to be managed on a commercial basis under the auspices of performance contracts. In addition, new power oplantswould be offered to both the private and public sector generating companies to construct, own, manage and operate. Further efficiency gains would be achieved from stteamlining staffing to levels consistent with industry standards and from contracting out ml.2iIlaryand other services. Agreement has been reached with the Government on an actiocnplan for restructuring the power sub-sector and implementation of the r-estructuringhas started. - 21 -
3.26 The Government has also commissioned a study of the legal and regulatory framework for the energy sector. On the basis of the study's findings, agreement has been reached with the Government on an action plan for implementation of the recommended reforms (including a detailed proposalfor the establishment of an autonomous regulatory arrangement for the power sub-sector). Submission to Parliament of the required amendments to the Electric Power Act would be a condition for Credit effectiveness (para. 8.2 (i)).
3.27 Investment. The third element of the strategy comprises investments in power generation and associated transmission and distribution, designed to eliminate electricity supply deficits in the late 1990s and early 2000s and to increase supply and demand-side efficiency. Agreement was reached, during appraisal, on a five-year investment plan for the power sub-sector. Further, during negotiations, agreement was reachedfor the Government to review with IDA its power sub-sector five-year rolling investment plan by March 31, of each year. GoK would not undertake any investments of more than US$10 million (including IPPs), outside the agreed least-cost plan without consulting with IDA (para 8.1 (i)). The investment program includes construction by KPC of three power plants which are critical for meeting power demand in the late 1990s, addition of a 72.5 MW unit at an existing power station (Gitaru) and private sector construction and operation of two other power plants (75 MW Kipevu II Diesel and 64 MW Olkaria III Geothermal) which are required under the least-cost investment program, and which would increase competition in the sector and improve operational efficiency.
D. WORLD BANK GROUP INVOLVEMENT
3.28 IDA has provided seven loans and credits totaling about US$212.2 million for financing power investments in Kenya between 1971-1988. The first two power projects (Ln. 745-KE and Ln. 1147-KE) helped finance hydroelectric development on the Tana River. The projects were designed to meet the demand for power in Nairobi and the coastal area around Mombasa, where most of the industrial and commercial activities of Kenya are concentrated. Five loans and credits were made for the development of geothermal power in Kenya. The Olkaria Geothermal Engineering Loan (Ln S-12-KE of 1978) financed drilling of additional wells to gauge the productivity of the Olkaria steam field and to ensure that there was sufficient steam for each generating unit proposed under Phase II of the Olkaria Geothermal Development Project. The Olkaria Geothermal Power Project (Ln. 1799-KE of 1980) aimed to provide a firm source of power and energy within the country to meet the growth of demand expected from 1981 to 1985 and to assist in reducing the country's heavy dependence on imported oil. The Olkaria Geothermal Power Expansion Project (Ln. 2237-KE of 1983) was intended to meet the growth in energy demand which was projected to exceed the available capacity at the time. The Geothermal Exploration Project (Ln. 1486-KE of 1984) was to support acceleration of the geothermal exploration and improve new reserves that could support additional power generation during the 1990s. The main objective of the recently completed Geothermal Development and Energy Pre-Investment Project (Cr. 1973-KE of - 22 -
1988) was to assist Kenya in preparing a least-cost power generation expansion plan, largely through utilization of indigenous energy resources, and to develop options for energy pricing policies. It also addressed selected aspects of rural electrification policy and household fuel supply and distribution.
3.29 Three loans were made for reforestation (Loans 641-KE. 1132-KE/Credit565-KE and 2098-KE/Cr. 1213 -KE). The first loan was implemented satisfactorily, while the second loan suffered from cost overruns and implementation problems. In the petroleum sub-sector, the Bank financed the construction of the products pipeline from Mombasa to Nairobi (Ln. 1 133-KE) between 1975 and 1981 and two petroleum exploration promotion projects (Ln. 2065-KE and Cr. 1675-KE). Pipeline construction was completed on schedule. The exploration promotion projects have been successful in helping to attract six international companies to take acreage in Kenya, but no commercially viable oil or gas reserves have been discovered to date.
3.30 The hydroelectric projects (1971 and 1975) concentrated largely on financing of construction and equipment; execution of the physical components was generally good. In the later years, lending shifted to strengthening the institutions with provision of technical assistance and training, particularly for geothermal development. The Project Completion Reports on all power projects concluded that while the objectives of physical components were generally achieved, there were weaknesses in project design, institutional, environmental and financial aspects, as well as in monitoring, and procurement. The lessons learned from these operations have been incorporated in the design of the proposed project.
3.31 The project has incorporated the recommendations of the Bank's policy papers on electric power and energy efficiency, which emphasize the importance of transparent regulatory processes, private sector participation, sector restructuring, and promotion of both supply and demand side efficiency. ESMAP's recommendations for reducing power losses have also been taken into account in the design of the project's efficiency component. - 23 -
4. THE PROJECT
A. PROJECT ORIGIN, RATIONALE AND OBJECTIVES
4.1 Origin. A number of studies undertaken with IDA financing provided under the Geothermal Development and Energy Pre-Investment Project (Cr. 1973-KE), the Parastatal Reform and Privatization Technical Assistance Project (Cr. 2440-KE) and under a Project Preparation Facility - have facilitated the preparation of the project. In the late 1980s, it was foreseen that new investments were needed in the power sub-sector by the mid 1990's to avoid supply shortages. However, IDA could not support new investments in the absence of an agreement on sector reform policies and program for implementation. The following issues were identified as requiring in the dialogue with the Government: (i) low electricity prices in relation to the power sub-sector's financial requirements and to the economic cost of supply; (ii) complexity of the power subsector organization (para. 3.18); (iii) need for annual update of and adherence to least cost power expansion plan; and (iv) need to incorporate environmental analysis in project feasibility studies; and (v) GoK control of petroleum pricing, procurement and marketing. To address these issues, studies were commissioned on electricity tariffs; power sector organization; least-cost generation expansion planning; and petroleum pricing, procurement and marketing. These studies provided the basis for the policy dialogue which culminated in an agreement with the Bank on a broad sector reform strategy in the framework of the PFP for FY1994-96. The studies also provided the basis for further dialogue with the Bank on the details of the policy reform during the preparation of this project. The project's Sector Restructuring and Reform Component has been designed to assist the GoK in implementing the most critical policy reforms. An Environmental Ranking Study was also carried out with Bank staff assistance. In addition, environmental assessments have been carried out for three of the five power generation plants included in the proposed project.
4.2 Rationale for IDA Involvement. IDA's participation in this project would support the Government's development objectives and policies towards economic growth and poverty reduction as expressed in the 1996-1998 PFP (para. 1.4). Mirroring the PFP, the Bank's Country Assistance Strategy (discussed by the Board on January 30, 1996) emphasizes poverty reduction as key to be met by faster growth, improved expenditures and targeted measures. This project is an integral part of the CAS for poverty reduction in terms that it would stimulate economic growth by: (i) improving and expanding basic infrastructure, which is critical to both improving the efficiency of existing private sector investment and attracting new private investment; (ii) improving public sector efficiency; and (iii) promoting private participation in energy provision. Specifically, the project would eliminate the electricity shortages which are a key bottleneck to economic growth, support the implementation of parastatal reforms in the electricity sub-sector, - 24 - create an enabling policy and regulatory environment for private sector investment and management, and improve the human capabilities in the energy sector. In addition, IDA's involvement leverages about US$290 million in cofinancing and is critical in boosting private sector confidence in Kenya's energy sector.
4.3 Project Objectives. The project's objectives are to assist the GoK in formulating and implementing major policy and institutional reforms aimed at creating an efficient and environmentally sustainable energy sector and to support investments needed to meet power demand and increase operational efficiency. The project's specific objectives are to:
(i) finance investments needed to meet power demand and improve the operational efficiency in the sub-sector;
(ii) reform the organizational structure of the power sub-sector to enable the operating entities to function efficiently and on a commercially sustainable basis;
(iii) create a legal and regulatory environment necessary for private sector participation in the supply of electricity;
(iv) support the GoK's adoption of economic pricing of both electricity and petroleum products and implementation of demand and supply-side efficiency improvement measures; and
(v) develop indigenous geothermal energy resources and a strategy for sustainable household and rural energy development.
B. PROJECTDESCRIPTION
4.4 The project would consist of the following six components: A. Sector Restructuring and Reform
B. Other Institutional Support
C. Efficiency Improvements
D. Power System Expansion & Upgrading
E. Geothermal Resource Development
F. Future Project Preparation
4.5 A brief description of the various components of the project is given below, while detailed descriptions are provided in the Project Implementation Plan and in Annexes 4.2 through 4.2. - 25 -
A. Sector Restructuring and Reform (US$3.6 million) - The project would support (i) establishment of a legal and regulatory framework necessary to improve sector efficiency; (ii) reform of the organization, management and financial structure of the power subsector companies, and separation of generation from transmission and distribution functions; and (iii) promotion of private sector participation in the provision and management of operations. Details of the program are contained in Annex 4.2.
B. Institutional Support (US$24.6 million) - This component comprises studies, advisory services and logistical support to project implementing entities. The studies fall under four categories. The first category consists of identified prefeasibility and feasibility studies, and preparation of tender documents for future projects. The second category assists in determining a strategy for sustainable and affordable household and rural energy development, and includes energy supply and demand studies and policy and institutional analysis. It will draw upon the results of the ongoing rural electrification study. The third category addresses consumer concerns about the quality of solar photovoltaic components and systems and examines the establishment of quality guidelines, including regulatory incentives to encourage the application of minimum norms. The fourth category will seek to promote competition in the supply of LPG to consumers through the development of uniform standards for LPG cylinders, valves and pressure regulators and the associated testing, monitoring and regulatory arrangements '. Advisory services comprise policy, engineering and financial management support to the Implementation Support Group (ISG) in MOE which will be responsible for coordination of project implementation. Engineering and financial management support will also be provided to KPC for implementation of the power generation component. Logistic support in the form of office technology and equipment will be provided to the ISG (para. 6.2).
C. Efficiency Improvements (US$11.8 million)
(i) Demand Side Improvements (US$5.4 million) - The project would assist in: (a) developing capacity in KPLC and in the local private sector to design, implement and evaluate efficiency and electricity demand management projects; (b) establishing pricing incentives for energy efficiency, such as time-of-use tariffs, and interruptible rates to complement the agreed tariff reforms; (c) conducting demonstration programs on energy efficient lighting, air conditioning and other consumer equipment in public buildings including KPLC's buildings; (d) mapping out mechanisms for third party financing of efficiency improvement measures; (e) establishing guidelines for energy efficiency labeling and standards for electric appliances and motors.
(ii) Line Loss Reduction (US$6.4 million) - The project will: (a) finance major distribution rehabilitation and loss reduction programs in the Nairobi and the
The project activitiesin rural, renewableand householdenergy developmentsupport the recommendationsof the Bank's Best PracticePaper "Rural Energyand Development",July 1996(report No. 15912-GLB). - 26 -
Coastal areas based on the results of the KPLC/ESMAP loss reduction study; (b) assist KPLC to implement the ESMAP recommended program for the reduction of non-technical losses; and (c) finance the required technical assistance to set up an implementation plan and train a task force. Annex 4.3 details the efficiency improvement component.
D. Power System Expansion & Rehabilitation (US$609.1 million)
(i) Power Generation (US$579.1 million) - The objectives of this component are to increase generation capacity and to install associated transmission facilities. The component includes financing of: (i) a 75 MW Diesel Power Plant at Mombasa (Kipevu I); (ii) a 64 MW Olkaria North-East Geothermal Power Station at Naivasha (Olkaria II); (iii) a second 75 MW Diesel Power Plant at Mombasa (Kipevu II); (iv) another 64 MW Geothermal Power Plant (Olkaria III); (v) a third 72.5 MW unit at Gitaru Hydropower Station; and (vi) connection of two additional wells for the existing Olkaria I Geothermal Power Plant. KPLC's least- cost generation plan which has been reviewed and endorsed by independent consultants indicate that Kipevu I and Olkaria II would be needed to meet demand starting in FY 1997/98, FY 1998/99 and FY1999/00 respectively. However, because of delays in implementing the investment program (para. 1.7), these plants are now expected to be commissioned in FY1999/00 and FY2000/01 respectively. Because of the urgent need to start construction in order to meet these commissioning dates, these plants would be financed through traditional public financing sources. Kipevu II and Olkaria III would also be commissioned in FY1999/00 and FY2000/01 respectively. The two power plants are expected to be constructed by independent power producers. The preparation work leading to the award of contracts to IPPs is being supported by an IDA Project Preparation Facility advance. A detailed description of the power system expansion and upgrading component is given in Annex 4.4.
(ii) Upgrading of Distribution System (US$30.0 million) - This sub-component would cover implementation of a program for the reinforcement of the primary distribution systems in Nairobi and in the Coastal areas. In the Nairobi area the 66 kv ring road around the city would be completed and the 66 kv-11 kv substations capacity would be expanded. Reconductoring of some sections of the 66 kv lines would also be carried out to eliminate bottlenecks. In the Coastal area, the program consists of increasing the 33-11 kv substation capacity in Mombasa and along the Indian coast. In addition, a 132 kv line would be built between Rabai and Diani. Details of the program are contained in Annex 4.4.
E. Geothermal Resource Development (US$49.3 million) - This component would assist the Government in developing geothermal energy resources. The project will also finance resource development activities aimed at supporting production of power at the next power plant (Olkaria IV), and developing resources for future private sector participation. Details of the program are shown in Annex 4.5. - 27 -
F. Future Project Preparation (US$1.5 million) - This component would support preparatory activities for the follow-on projects in support of the GoK's least-cost energy investment program.
C. PROJECTCOSTS AND FINANCING
4.6 The total cost of the project is estimated at US$699.9 million equivalent, excluding taxes and duties and interest during construction, broken down by component as detailed above. Of the total cost, about US$570.1 million or 81%, would be in foreign costs. Total costs include about US$36.5 million in physical contingencies or about 6% of total base costs; and US$42.5 million in price contingencies or about 7% of total base costs plus physical contingencies. Engineering and construction supervision costs are included in the cost estimates for the physical components at an average rate of about 10% of base cost. Price contingencies have been calculated on the basis of estimated international inflation of 2.4% from FY1996/97. This inflation rate has been used for both foreign and domestic costs as it has been assumed that any differences between domestic and international price will be offset by equivalent adjustments in Kenya's foreign exchange rate. A summary of the cost estimates is provided in Table 4.1 below
Table 4.1 - Estimated Project Costs Kenya EnergySector Investment Project % % Total ComponentsProject Cost Summary (KShs'000) (USS'000) Foreign Base Local Foreign Total Local Foreign Total Exchange Costs A. Sector RestructuringReform SectorReorganization - 235,266.5 235,266.5 - 3,182.7 3,182.7 100 1 Deregulationof PetroleumMarkets 3,696.0 21,735.7 25,431.7 50.0 294.0 344.0 85 - SubtotalSector RestructuringReform 3,696.0 257,002.2 260,698.2 50.0 3,476.8 3,526.8 99 1 B. Institduonal Support 168,870.2 1,516,122.1 1,684,992.4 2,335.4 20,889.6 23,225.1 90 4 C. Efficiency Improvements DemandSide Improvements 5,895.1 323,751.1 329,646.2 81.6 4,480.5 4,562.1 98 1 LineLoss Reduction 61,205.8 350,528.6 411,734.4 847.0 4,849.9 5,697.0 85 1 Subtotal Efficiency Improvements 67,100.9 674,279.8 741,380.6 928.6 9,330.4 10,259.0 91 2 D. PowerExpansion and Rehabilitation PowerGeneration 6,853,352.430,040,193.6 36,893,545.9 94,845.5415,734.8 510,580.3 81 82 Upgradingof DistributionSystems 960,960.0 960,960.0 1,921,920.0 13,299.0 13,299.0 26,598.0 50 4 Subtotal Power Expansionand Rehabilitation 7,814,312.431,001,153.6 38,815,465.9 108,144.5 429,033.8 537,178.3 80 87 E. GeothermalResource Development 323,799.2 2,955,292.0 3,279,091.2 4,481.1 40,899.1 45,380.3 90 7 F. FutureProject Prepration - 93,139.2 93,139.2 - 1,289.0 1,289.0 100 - Total BASELINECOSTS 8,377,778.636,496,988.9 44,874,767.6 115,939.7 504,918.7 620,858.5 81 100 PhysicalContingencies 422,279.8 2,218,721.4 2,641,001.2 5,844.1 30,705.5 36,549.5 84 6 PriceContingencies 3,849,938.316,813,732.1 20,663,670.4 8,026.0 34,497.3 42,523.2 81 7 Total PROJECTCOSTS 12,649,996.855,529,442.4 68,179,439.2 129,809.7 570,121.5 699,931.2 81 113
4.7 Project Financing. An IDA Credit of US$125 million would finance about 17.9% of total project costs excluding taxes and duties. Other financiers would be OECF (about US$82.8 million); European Investment Bank (EIB) (about US$48.7 million), KfW (about US$20.8 million) and private sector investors (about US$262.5 million). KPC and KPLC would finance the balance of US$160.1 million and about US$99.0 million of interest during construction. Table 4.2 below provides the financing plan. - 28 -
Table: 4.2 - Project Financing Plan (US$ million equivalent)
Local Foreign Total IDA 2.1 122.9 125.0 OECF 4.9 77.9 82.8 EIB - 48.7 48.7 KfW 3.5 17.3 20.8 Private Investors 51.0 211.5 262.5 Government 68.2 91.9 160.1 KPLC KPC Total Project Costs 129.7 570.2 699.9 Interest During Construction 99.0 99.0 TOTAL FINANCING REQUIRED 228.7 570.2 798.9
4.8 Project Onlending Arrangements. The IDA Credit would be made to the Government of Kenya on standard terms. The Government would re-lend about US$104.6 million and US$11.7 million equivalent to KPC and KPLC respectively. The balance of about US$8.7 million equivalent, not initially re-lend, would include funding for preparation of future projects (US$1.5 million), institutional support (US$3.9 million), and sector reorganization (US$3.6 million). Since the preparation activities for future projects and some of the institutional support activities cannot be determined in advance, the related funds would be relend to KPC and/or KPLC where the activities concerned are of a commercial nature. The relent funds would be provided for 20 years including 5 years grace, at an effective interest rate of not less than 7.7 percent. KPC and KPLC would bear the foreign exchange risk. Execution of subsidiary loan agreements between the Government and the implementing agencies pertaining to the onlent IDA funds, on terms and conditions satisfactory to IDA, would be a condition of effectiveness (para. 8.2 (ii)). D. PROJECTSUSTAINABILITY
4.9 The project includes substantive policy and institutional reform components which are designed to create a more efficient and sustainable sector. The Sector Restructuring and Reform component includes financing and implementation of three key reforms. First, the power sub- sector is in the process of being reorganized to better establish commercial arm's length relationships between the management of generation assets on one hand and those of transmission and distribution assets on the other hand. The reorganization will clearly define the ownership of power assets and the responsibilities for subsector debt. Second, the Government will separate the responsibility for regulation of the power subsector from policy and from operations. This will provide an environment for more objective decisions on important issues such as tariff-setting and licensing, thereby making the subsector a more attractive destiny for private capital investment. Third, the GoK has committed to opening up the power market to the private sector for investment and operations. Under the project, two of the five power plants accounting for about 40% of the generation capacity to be installed under the project, have - 29 - already been offered to the private sector. In addition, the project will make significant positive contributions to the Governments budget through payment of incremental corporate taxes, dividends and interest on funds to be relent to the power companies (para. 7.20).
E. PARTICIPATION
4.10 The project was prepared in a collaborative manner with the GoK taking the lead role. Environmental studies were prepared almost exclusively by local consultants. Local consultants also participated in the preparation of the power sector reorganization and the legal and regulatory framework studies. NGOs, both international and domestic, participated in reviews of environmental impact assessments and attended meetings at the Bank's Resident Mission on the project. Representatives of various civic organizations also participated in the review of tariff increase proposals. Throughout the preparation process, discussions were held between IDA and the donors had discussions. In early 1995 the Government briefed donors on the status of the project followed by a donors' meeting in September 1995. The private sector has also been invited to participate in the project through the offer of two power plants for independent power producers. Evaluation of private sector bids has been completed and negotiations with successful bidders are expected shortly.
4.11 During implementation, the following arrangements are foreseen for participation. With regard to power supply, KPLC will monitor customer satisfaction through repeat surveys. The monitoring and the implementation of any remedial actions will be supervised by the Chief Manager Customer Care, a recently created position to improve KPLC's customer responsiveness and service orientation. As part of the efficiency improvement component, stakeholder participation will take place in the context of a number of action-planning workshops. These workshops will discuss opportunities to improve energy efficiency and disseminate information. Finally, the program evaluation will include a survey of stakeholders satisfaction with the efficiency initiatives carried out under the project. The Renewable/Household Energy component will ensure the participation of a representative group of medium and low income households, rural industries, service establishments, energy vendors through systematic surveys. In addition, NGOs concerned with rural and renewable energy supply will be consulted. Adequate communication will be maintained with co-financiers, for instance through shared missions.
F. ENVIRONMENTAL ASPECTS
4.12 The Project is classified as an Environment Assessment Category A. EAs were conducted for NE Olkaria Geothermal and for the two Kipevu Diesel plants. A sectoral EA was not carried out as the components were identified at different times. Instead of a sectoral EA, KPLC decided to rank project components in order of environmental preference. This ranking also served as environmental/social summaries for project components.
4.13 The geothermal site at NE Olkaria is located within Hell's Gate National Park, a park that was created around the existing geothermal plant and with the knowledge that the NE Olkaria site would be developed for geothermal energy. The area is rich with wildlife and serves as a - 30 - grazing area/migration route for Maasai pastoralists. Experience with the existing site shows that wildlife accommodate quickly to the production wells and pipes and normally groups can be seen grazing or resting in the shade of wells or pipes. The fenced perimeter of the existing plant has interrupted livestock grazing although wildlife species are found within the active field. As a part of the mitigation measures, the new facility will be fenced only around the wells and separators so that wildlife and livestock will have continued access to most of the project area. Since the facility will convert wild lands to other uses, Bank wild lands policy requires compensatory actions. During negotiations, KPC agreed to take all necessary measures to ensure free movement of wildlife within the Olkaria area and between Olkaria and Hells Gate and Longonot National Park in accordance with the agreement dated September 20, 1994 between KPC and KWS (para. 8.1, xi). Currently, KPC assists KWS in the maintenance of park facilities.
4.14 The EA for the geothermal facility recommended that condensates be reinjected as they would be more harmful to livestock and wildlife than the condensates produced by the existing plant. The reinjection is a part of the mitigation plan. The EA also closely reviewed water extraction from Lake Naivasha and concluded that KPC extraction was far less than other present water users and that the increased extraction for the new plant will not pose serious threats to the lake levels.
4.15 The Kipevu diesel unit will be designed to meet western air emission standards and liquid wastes will be treated on site. The facility will be built on land adjacent to the existing oil-fired steam electric plant. The new facility will not require large amounts of water and it is likely that it will be able to use water from a new waste treatment plant. It will not use Mombasa Municipal water. The site will not involve relocating people and the land is currently unused and was a former site of a WWII military installation.
4.16 Execution of the mitigation plans which are detailed in the EAs and in the Project Implementation Plan would be monitored by KPC's Environmental Unit. KPC's staff would receive further training, particularly in the area of environmental analysis for hydropower plants. IDA implementation support missions would also include an environmental specialist to monitor implementation of mitigation plans. During negotiations the Government agreed that adequate environmental analysis would be carried outfor allfuture power sub-sector projects and appropriate mitigation plans would be developed and carried out (para. 8.1 (ii)). - 31 -
5. FINANCIAL ANALYSIS
A. THE FINANCIAL MANAGEMENT FRAMEWORK
5.1 As indicated in paragraph 2.3, the organization of the power sub-sector is complex. The complexities include:
(i) financial rules regarding settlement of the costs of supplying power from the KPLC-managed power stations owned by multi-purpose river development authorities; and
(ii) the pricing system under which KPLC bears the full cost of the operations of the two paper companies which it manages (KPC and TRDC), effectively making the two companies mere cost centers.
5.2 FinancialRules. The two hydroelectric power stations owned by TARDA (Masinga and Kiambere) supply power to TRDC and KPLC respectively. 'The original agreements between TARDA and KPLC and TRDC provided for certain costs to be borne by TRDC and KPLC. In the case of Kiambere, the lease agreement requires KPLC to pay a development surcharge equivalent to 15% of the total cost of Kiambere; debt service for the loans contracted for construction of the plant; and the cost of replacements and repairs necessary to maintain efficient operation of the plant. The agreement was structured so as to enable TARDA to obtain surpluses for investment on irrigation and rural development projects. Between 1988 and 1990, GOK issued instructions directing KPLC and TRDC to make payments for the cost of supply from the two power plants (primarily debt service) directly to Treasury instead of to TARDA. The debt service payments were also to be made on the same terms on which the loans had been provided to TARDA. TARDA was to be compensated for the loss of revenue from the power industry through direct payments from the Treasury. Following these changes, TARDA became dependent on the Government for budgetary support. However, since 1994, it has received annual payments of Ksh 55 million from KPLC to cover dam related operation and maintenance expenditures (para 3.18 (c)).
5.3 The power sub-sector organization study has recommended that the revalued power generation assets for Masinga, Kiambere and Turkwell power stations be transferred to the generation company together with their related debt. The power
Although the lease agreement for Kiambere is between KPLC and TARDA, since FY1995/96 the debt service costs for the plant are being in TRDC accounts. TRDC in turn recovers these costs from KPLC. These anomalies will be corrected when the arrears are transferred to KPC as part of the sector restructuring. - 32 - generation company (KPC) would therefore be responsible for the debt service related to the assets and for the costs of operating the facilities and would recover these costs through tariffs from bulk power sales to KPLC. The Government has accepted the recommendations and developed an action plan for reorganization of the power sub- sector which includes as main features.' the establishment of separate companies for generation and for transmission and distribution; the establishment and appointment of a Board; and appointment of key managersfor the new power generation company. In January 1997, the GOK itnplemented the initial step under the plan by appointing a Managing Director, Chairman and Board.for the new KeniyaPower Company Limited. The GOK also established a Task Force to oversee the sharing of staff and other resources between KPLC and the new KPC.
5.4 Cost- Plus Pricing.In the power industry itself, excluding the multipurpose development authorities, KPLC purchases power from KPC and TRDC at an "ascertained cost" which is calculated as the total costs incurred by the supplier comprising all operating expenses, debt service and a surcharge to provide a contribution towards new capital expenditures. Although the two companies are essentially KPLC's cost centers, they incurred substantial losses up to FYI 992/93. These losses are due to revaluation of their foreign currency denominated liabilities which are not absorbed in the ascertained cost calculation until they are realized in the form of increased debt service payments.
5.5 Since the GoK's sub-sector reform objectives include requiring companies to operate on a commercial basis, the bulk tariffs between the generation company and the transmission and distribution company would be determined by the ERB on the basis of LRMC principles and the need to finance at least 20% of the generation company's investment program during FY1997/98 and FY1998/99 and 25% for each fiscal year thereafter. The responsibilities and duties of the ERB and the timing for its establishment are spelt out in the action plan for the legal and regulatory framework for the power sub- sector.
B. PAST AND PRESENT FINANCIAL PERFORMANCE
5.6 Performance Targets. Under Credit 1973-KE, it was agreed that the power industry would achieve the following financial targets:
(i) self-financing ratios of 25% in FY1988/89, 27% in FY1990/91 and 30% in FYI 993/94 and subsequent years; (ii) debt/equity ratio of 75% in FYI1990/91and 70% in FYI1991/92and subsequent years; (iii) debt service coverage ratio of at least 1.5%; and (iv) a current ratio of at least 1. 1.
5.7 In practice, monitoring the performance of the sub-sector proved difficult because of the complex pricing arrangements, lack of clarity on such issues as asset ownership and debt service obligations. However, the weakness in the sub-sector's performance are apparent from Table 5.1 which summarizes the principal financial ratios for the - 33 - individual companies during FY1990/91 through FYl994/95. Actual financial statements (FY1994/95) are shown in Annex 5.1 which also shows the projected performance during FY1995/96 through FY2000/01.
Table 5.1: Principal Financial Ratios for Power Sub-sector Companies2
1990/91 1991/92 1992/93 1993/94 1994/95 1995/96 Capital Structure (D/E Ratio)
(% ) ______KPLC 52 62 72 56 42 31 KPC 79 81 109 92 60 41 TRDC 193 261 776 500 262 191 Debt ServiceCoverage (times) KPLC 0.7 0.8 1.2 2.1 13 5.2 KPC 1.4 2.2 4.2 1.6 4.1 4.2 TRDC 1.2 1.1 1.0 1.0 0.7 0.8 Self-FinancingRatio (%) KPLC -22 -125 -34 94 35 31 KPC 9 81 103 54 0 75 TRDC 100 100 175 900 0 (18) Liquidity (Current ratio) KPLC 0.9 1.0 1.0 1.0 1.0 1.0 KPC 0.9 0.8 0.7 0.6 2.0 4.0 TRDC 0.9 0.8 0.8 0.8 0.8 0.9
5.8 As the ratios above indicate, for the fiscal years up to FY1992/93, the financial performance of the three power companies was characterized by weakening capital structures and significant liquidity constraints. In terms of profitability, KPLC's performance was fairly good compared to the performance of the other two power companies which experienced significant losses. For the power industry as an entity the poor financial performance was attributable to low tariffs, high levels of debt service and the depreciation of the Ksh. The average tariff was not regularly adjusted to fully cover increased revenue requirements arising from higher operating costs and higher debt service burden caused by exchange rate movements.
5.9 Chart 5.1 below shows the relative proportions of debt and equity in the capital structures of the three power companies during fiscal years FY1991/92 through FY1994/95. The chart demonstrates the weakening financial position of the companies and the modest recovery that started with the March 1994 tariff increase and the appreciation of the Ksh in 1995. Also noteworthy are the sharp increases in the debt/equity ratios of both KPC and TRDC in FY1992/93 due to unrealized foreign exchange losses which are not considered a cost in the ascertained cost formula until realized and were therefore not compensated through the bulk tariff.
2 These ratios do not fully capture actual performance since they are based on accounting data which does not take account of all the operating costs and debt service. - 34 -
Chart 5.1: Capital Structures of KPLC, KPC AND TRDC (FY92-95)
KPL.C KPC
6 00010,000A
6,000,
1,000EllDebt ^ _ -2 0 UDebt
199219931 1995 _
TRDC
4000 3000 2000 1000 UDebt 0 -1000 U Equity I -2000 -3000 d 1992 1993 1994 1995
5.10 Chart 5.2 below compares the total internal funds that were available for debt service' in each of the years FY1991/92 through FY1994/95 to the actual debt service requirements. While both KPC and TRDC were able to meet their debt service costs during FY1991/92 and FY1992/93, KPLC was able to generate from internal operations funds to meet only 80% of its debt service costs in FY1991/92. KPC and TRDC were able to meet their debt service costs during this period because the ascertained formula guarantees them an adequate tariff to cover all their costs with the exception of unrealized foreign exchange losses. Since FY1993/94, the debt service coverage ratios have improved significantly for KPC and KPLC.
3 Total internalfunds available for debt serviceis calculatedas the differencebetween total revenuesand operatingcosts (excludingdepreciation) before adjusting for movementsin workingcapital balances - 35 - Chart 5.2: Debt Service Capacity of KPLC, KPC and TRDC (FY1991/92 - FY1995/96)
KPLC KPC
2,000 4.000 1,500 ------E 3,000 C1,0 0 ------2,000^ 500 =- 1,0O00
1992 1993 1994 1995 1996 19921993 19941995 1996
4Avail. Funds DebtServi i -4-Avail. Funds -Debt Servicei
TRDC
1,000 800 . 60006 400 0-n-I4I
1992 1993 1994 1995 1996
_Avail. Funds r Debt Service +--
5.11 All three companies consistently had low liquidity ratios in the period FY1991/92 - FY1994/95. For KPLC this is because of delays in collecting receivables from final consumers. As of June 30, 1995 receivables represented about 88 days sales revenue. Some of the delays in revenue collection are due to problems in billing. A new billing system has been installed and a contract has been signed with a foreign utility to assist KPLC in strengthening its operational efficiency (institutional strengthening program) including improving the metering and billing system. For KPC and TRDC, the liquidity constraints are caused primarily by slow payments from KPLC. The increased commercial orientation when the sub-sector is reorganized with separate management for generation and for transmission and distribution, and KPLC's institutional strengthening program would help to improve working capital management, thus enabling arrears to be maintained at levels not exceeding 60 days sales revenue..
5.12 Despite the structural issues noted in paras. 5.1-5.5 and the past poor financial performance, KPLC, KPC and TRDC have sound accounting systems and procedures, and KPLC has competent financial management and accounting staff. Thus, financial statements have been prepared broadly in conformity with generally accepted accounting principles. In spite of this there has been serious delays in submission of audited financial statements to IDA. Significant improvements in financial management and auditing are expected to result from: (i) resolution of structural issues related to assets ownership, debt service responsibility and pricing in the context of the reorganization of - 36 - the sub-sector; (ii) the recent exemption of both KPLC and KPC from the provisions of the State Corporations Act which has enabled KPLC to, amongst other things, appoint private auditors for FYl996/97; and (iii) KPLC and KPC's commitment to endeavor to schedule AGMs promptly following the end of each fiscal year. KPLC and KPC audited accounts for FYI 995/96 were submitted to IDA about seven months and eight and one half months after the end of the fiscal year respectively. Taking into account past performance and the expected improvements during negotiations, agreement was reached that both KPLC and KPC would submit auditedfinancial statements to IDA within six months of the end of each fiscal year (para. 8.1 (v)).
C. PROJECTED FINANCIAL PERFORMANCE
5.13 Taken as entity, the financial performance of the power industry started improving in FYl993/94 when the first tariff increase under the Government's new policy of economic pricing for electricity was implemented. Projections for the next six years indicate that the industry's performance would continue to improve due to the increases in tariffs, assumed slower rate of depreciation of the shilling and improvement in operational efficiency.
5.14 The key assumptions used in projecting the future financial performance for the three companies are that: (i) the average tariff would remain 73 percent of LRMC; (ii) fuel prices would increase by about 7.5% per annum between FY1996/97 and FY1997/98 and 5% per annum thereafter, and a fuel adjustment formula would be applied to recover effects of fuel price increases through automatic tariff increases; and (iii) domestic inflation rates would be about 7.5% in FY1996/97 and FY1997/98 and 5% per annum thereafter. The financial projections assume further increases in the average revenue of about 12% in FY1997 and about 8% in each of FY1998 and FY1999. The financial projections are also based on the current practice which requires KPLC to finance the local currency costs of KPC and TRDC investment programs. These contributions, called development surcharges are treated as part of the generation companies revenues (tariff) and are therefore reflected in the self-financing ratios. On the basis of these assumptions:
(i) KPC, the main participant in the investment program would generate modest levels of self-financing, averaging about 20% in the first three years and declining thereafter. KPC's financial performance would require an early review of its bulk tariff especially with the phasing out of the development surcharge system as part of the reorganization. This would be upon completion of the tariff study in November 1997. (Similarly KPLC's tariffs to final consumers would require further adjustments to enable it to achieve the target self financing levels of 25% in FYl997/98 and FYl998/99 and 30% in each fiscal year thereafter). TRDC has been merged with KPC as part of the restructuring of the sub- sector. The process of merging operations is ongoing. - 37 - (ii) The companies' debt service capacity would remain healthy: the result of the March 1994 tariff increase as well as the increase to about 73% which is built in the projections.
(iii) The overall financial health of the companies would be greatly influenced by the automatic adjustment of tariffs to recover fuel price increases.
During negotiations, agreement was reached with the Government on the date for completion of the tariff study (November 30, 1997) andfor implementation of agreed tariff adjustments during FY1997/98. In addition, KPC would generate adequate funds from internal operations to finance at least 20% of its individual investment program for FY1997/98 and 25% thereafter. KPLC would generate adequate funds from internal operations to finance at least 25% of its individual investment program for FY1997/98 and FY1998/1999 and 30% thereafter (paras.8.1 vii and viii). KPLC would also be required to maintain their accounts receivable at levels not exceeding 60 days sales revenue at all times (para. 8.1 (ix). During negotiations, it was agreed to revise the self- financing targets downwards for FY1997/98 and FY1998/99 to take into account the heavy investment requirements and the proportion offunding already indicated by donors.
D. AN ACTION PLAN FOR FINANCIAL REFORM IN THE ELECTRICITYSUB-SECTOR
5.15 What emerges from the analysis of the historical financial results of the three power companies is significantly weak performance both in terms of failure to meet the agreed financial covenants with lenders and in terms of failure to meet the sub-sectors financing requirements. The financial performance of the power industry suffered because tariffs were not adjusted to meet increasing operational costs and to meet increases in debt service obligations arising from exchange rate changes.
5.16 The Action Plan for financial reform therefore includes: (i) establishment of a regulatory process to set bulk tariffs for the public sector generation company and retail tariffs to final consumers on the basis of LRMC and financial criteria; (ii) the recent GOK authorization for KPC to adjust tariffs for changes in price of fuel and in the exchange rate without reference to ERB; (iii) determination of tariffs from IPPs on the basis of competitive bidding; and (iv) implementation of efficiency improvements through line loss reduction; staff reduction; contracting out ancillary services to the private sector and institution of performance contracts for parastatal companies. As a package of measures, this action plan should help the power sub-sector to improve its operational and financial performance and achieve the targets proposed under the Credit. The status of the action plan is summarized as follows:
(i) Reorganization of the Sub-sector. (para. 5.3).
(ii) Autonomy to Adjust Tariffs for Fuel and Exchange Rate Changes. In 1994, the Electricity Bye-laws were amended to provide KPLC, with the autonomy to adjust electricity tariffs for changes-in-fuel prices. GoK has - 38 - also allowed KPLC to adjust tariffs for changes in the cost of debt service arising from fluctuations in the exchange rate of the Ksh with effect from October 1, 1996.
(iii) Bulk Tariffs. A newly revised Electric Power Act providing for establishment of an autonomous electricity regulatory board is expected to be submitted to Parliament by Credit effectiveness (para. 8.2 (i)).
(iv) Efficiency Improvements. A line-loss reduction component to be implemented under the project is expected to reduce T&D losses from about 16% to about 13.5% of net generation in the next five years, thereby reducing the amount and cost of generation needed to meet demand. A staff reduction plan implemented by KPLC since 1994 had increased of KPLC's customer/staff ratio from about 28:1 to 49:1 by the end of 1995. KPLC has contracted out some ancillary services such as line construction, cleaning, security and janitorial services. Further options for contracting vehicle maintenance works, etc., are being considered.
5.17 Implementation of the sub-sector reorganization plan and the financial action plan would be reviewed during IDA implementation support missions and a major review would be carried out during project's mid-term review with cofinanciers by June 30, 2000. - 39 -
6. IMPLEMENTATION ARRANGEMENTS
A. OVERALL
6.1 MOE has prepared a Project Implementation Plan (PIP) containing a description of the main features of the project; implementation arrangements; implementation plan; and a monitoring and evaluation plan. The PIP would serve as a Handbook to assist project implementation agencies in the execution of the project. Annex 6.1 shows the table of contents for the PIP. During project implementation, the PIP would be updated annually by MOE and reviewed by IDA's implementation support missions. The implementation arrangements, implementation plan and monitoring and evaluation plan are summarized below.
B. IMPLEMENTATION ARRANGEMENTS
6.2 The Government of Kenya would have overall responsibility for implementation of the project through MOE, KPLC and KPC. KPC which would become the sole public sector generation company would implement the generation projects and geothermal resource development components. KPLC would be responsible for implementation of distribution systems and some aspects of the efficiency component. A GoK task force established in early 1997 is allocating staffing among the two companies. The reorganization is not likely to disrupt implementation of the project. An Implementation Support Group (ISG) has been established within MOE to oversee the implementation of the project. The ISG would comprise experts with experience in procurement, contracting and construction of major projects, and financial management. Selection of consultants (engineer andfinancial management expert) to complement MOE's own staff would be completedprior to credit effectiveness (para. 8.2 (iii)). KPC would also, prior to credit effectiveness, select consultants for its Project Management Teams which would be responsible for management of the contracting process andfinancial management of the project (para. 8.2 (iii)).
6.3 The specific responsibilities for project implementation would be as follows:
(a) Sector Restructuring and Reform Component. MOE would have the overall responsibility for implementation of the Sector Restructuring Reform Component. The component would be implemented in accordance with the timetable shown in Annex 2.1.
(b) Efficiency Improvements. The loss reduction and demand management subcomponents would be implemented by KPLC. MOE would implement - 40 -
the information programs studies and training. Action planning workshops would be implemented by MOE in cooperation with KPLC.
(c) Power System Expansion and Rehabilitation. KPC would be responsible for construction of the power stations to be financed from traditional public financing sources (Kipevu I Plant, Olkaria Power Plant and the third unit at Gitaru Hydropower Station). Kipevu II and Olkaria III would be implemented by project companies to be set up by private sector investors.
(i) Kipevu I would be constructed as a turnkey project. The contractor's responsibility would include construction of the power house building and all civil works as well as the supply and installation of engines, generators, substation equipment; etc. KPC has already selected the supervision consultants and received bids from construction firms. KPC would have overall responsibility for project management and control, while providing the required facilities at the construction site.
(ii) Olkaria North-East Geothermal Power Station (Olkaria II). KPC would engage consultants to assist with the contract process and with project management during the construction of this plant. Contractors would be required for the following six contract packages: civil works; turbine-generator and auxiliaries; erection of substations; construction of transmission; steam field development; and relocation of the existing X-2 camp. KPC has prepared bidding documents for all the contract packages, however, the documents have to be updated.
(iii) Transmission and Distribution lines would be erected by KPLC except those required to link the above generation plants to the grid. Consultants services would be retained to assist with the contracting and supervision of works.
(d) Geothermal Assessment and Resource Development. MOE would carry out geothermal exploration and pre-feasibility studies as part of the geothermal resource assessment and development program with the assistance of an Advisory Board of Experts. Consultant firms would be contracted to execute the geothermal feasibility studies included in the program. The Advisory Board of Experts would also assist in carrying out the feasibility studies.
C. PROJECT IMPLEMENTATION PLAN
6.4 The project would be implemented in accordance with the implementation and procurement schedules in the PIP. The PIP contains the following information: - 41 -
(i) detailed descriptions of the project components, budget and implementation timetable; (ii) schedule of procurement actions including target dates for each step, including standard procurement documents; (iii) schedule of disbursements for each component, including financial reporting and audit requirements; (iv) detailed description of the roles and responsibilities of the implementing agencies; (v) key monitoring and performance indicators for each component; and (vi) schedule of progress reporting and format of quarterly reports.
D. PROCUREMENT
6.5 Table 6.1 summarizes the project elements, their estimated costs and the proposed procurement methods. The total value of civil works to be financed under the project is estimated at US$135.6 million of which US$27.6 million would be financed by IDA. Annex 6.3 provides a list of goods, studies and consultants services to be financed by IDA. The goods would include the supply and installation of turbine generator equipment, under ICB procedures, for Olkaria II Power Plant for which IDA would finance the foreign exchange costs of about US$41.6 million. Procurement of goods and works in packages estimated to cost more than US$200,000 would be subject to ICB procedures. Goods estimated to cost between US$50,000 and US$200,000 up to an aggregate of US$200,000 would be subject to national competitive bidding procedures (NCB), while shopping procedures would apply to those estimated to cost less than US$50,000 up to an aggregate of US$200,000. Consultant services of US$25.6 million would be financed by the Credit out of total consultants services of US$73.1 million. IDA would also finance studies (US$8.5 million), training (US$1.2 million) and about US$200,000 of incremental recurrent expenditures. Of the US$27.6 million in civil works to be financed by IDA, about US$26.79 million would be subject to ICB procedures and the balance of about US$807,000 would be procured through NCB procedures, such packages being less than US$200,000 each. For works contracts to be procured under NCB procedures, advertising including explicit bid evaluation criteria and public bid opening would be followed. Interested foreign contractors would not be precluded from bidding for contracts let out under NCB procedures.
6.6 Consulting Services, Training and Studies. Consulting Services, training and studies to be financed by IDA are estimated to cost a total of US$35.3 million. Consultants would be recruited in accordance with the Bank's Guidelines for the Use of Consultants by World Bank Borrowers and by the World Bank as Executing Agency, August 1981.
6.7 Review of Procurement Documentation. During project implementation, IDA- financed contracts for goods and works above a threshold of US$200,000 would be subject to IDA's prior review procedures. Contracts for goods and works subject to prior review are estimated to account for more than 90% of the total value of the contracts. All contracts for consultants services estimated to cost more than US$100,000 for firms and US$50,000 for individuals and all training proposals would be subject to prior review. - 42 -
However, all sole source contracts and extensions within these limits would be subject to mandatory review. The terms of reference would require IDA's clearance. The IDA supervision missions would selectively review contracts not subject to prior review. In all cases, the GoK would submit signed copies of the contracts to IDA before requesting disbursement.
6.8 KPLC's procurement unit which is attached to the Office of the Chief Project Development Manager (CPDM) would process contracts for the power generation and upgrading component and would be supported by consultants to be attached to the CPDM. Bidding documents have already been prepared by consultants for two of the four power stations to be constructed and operated by KPC, but would need to be revised on the basis of the Bank's new standard bidding documents. Pre-qualification would be required for the civil works and the supply and erect contracts for the turbine-generator packages to be procured on the basis of ICB procedures and to be financed by IDA. The ISG would provide overall coordination support, ensuring that accurate progress reports are prepared and forwarded to IDA and participating donors, updating the PIP and ensuring the use of the Bank's standard procurement documents.
6.9 Standard procurement processing times have been discussed with the borrower and the project implementation plan has been prepared on this basis. The borrower would update the procurement plan annually.
Table 6.1: Summary of Procurement Arrangements (US$ million equivalent)
Description ICB NCB Other Non-Bank Total Financed Civil Works 50.6 0.9 84.1 135.6 (26.8) (0.8) (27.6) Supply & Erect 51.4 89.3 140.7 (41.6) (41.6) Goods 20.4 0.2 0.2 301.3 322.1 (19.9) (0.2) (0.2) (20.3) Consultant 24.5 47.5 72.0 Services (24.5) (24.5) Training 1.2 1.2
______(1.2) (1.2) Studies 7.6 18.5 26.1
______(7.6) (7.6) Household Survey 0.2 0.2
______(0.2) (0.2) Refunding of PPF 2.0 2.0
______(2.0) (2.0) TOTAL 122.4 1.1 35.7 540.7 699.9 1 (88.3) (1.0) (35.7) (125.0) Note: Figures in parenthesis are the respective amounts financed by IDA - 43 -
E. DISBURSEMENTS
6.10 The IDA Credit would be disbursed against the following categories and on the basis of the estimated disbursement schedule in Annex 6.4.
Table 6.2: Disbursement Categories (US$ million equivalent)
Category Amount of Credit % of Expenditures Allocated to be financed Civil Works 25.5 100% of foreign expenditures Supply & Erect 38.4 100% of foreign expenditures Consultant Services 23.5 100%
Goods 19.1 100% of foreign expenditures and 80% of local expenditures.
Training 1.1 100%
Studies 8.6 100%
Household Survey 0.2 100%
PPF Advance 2.0 Amount due
Unallocated 6.6
TOTAL 125.0
6.11 Disbursements for procurement of goods and works estimated to cost up to U$200,000 would be made against statement of expenditures (SOE). Other disbursements would be made against standard documentation. To facilitate payments from the Credit, the borrower would establish a Special Account and would operate and maintain it on terms and conditions satisfactory to IDA. The account would have an initial authorized allocation of US$5 million, approximately equal to three months of expenditures under the project. The Special Account would be replenished following application for reimbursement by MOE, together with appropriate supporting documentation. The amount of IDA replenishment would not exceed the authorized allocation. The Credit closing date would be June 30, 2004, with physical completion of works expected by December 31, 2003. Since MOE would process payments under the credit it would engage a financial management expert (consultant) to work with ISG to, amongst other functions, facilitate the accounting and the payment process.
6.12 Statements of Expenditures (SOEs) - Disbursements for contracts of goods and works estimated to cost up to US$200,000 and consulting contracts with firms costing up to US$100,000 equivalent and up to US$50,000 equivalent with individuals would be made against statement of expenditures. - 44 -
F. ACCOUNTING AND AUDITING
6.13 During negotiations, it was agreed that MOE, KPC and KPLC would maintain appropriate records and accounts for expenditures under the project, including SOEs, as well as the Special Account, in accordance with internationally acceptable accounting standards, that such records and accounts would be audited by independent auditors acceptable to IDA, and that the borrower would provide a certified copy of the auditor 's report, including a separate opinion on the SOEs, and the Special Account to IDA within six months of the end of each fiscal year (para. 5.12 and 8.1 (iv)).
G. MONITORING AND EVALUATION
6.14 MOE and IDA would carry out Project monitoring to ensure that the project is implemented in accordance with the project implementation plan. It would be based on monthly and quarterly progress reports to be produced by the implementing agencies and consolidated and verified by the ISG. The contents and format of the reports were discussed with the implementing agencies during negotiations, it would include: (i) updated project costs for individual contracts and the total project, including the estimates of physical and price contingencies; (ii) revised timing of procurement actions including advertising, bidding, contract award and completion time for individual contracts; (iii) status of progress for physical works as well as for the institutional and policy reform components; (iv) implementation of environment mitigation plans for the main components; and (v) an implementation completion report within six months of the Credit's closing date.
6.15 IDA would monitor project implementation through field visits, implementation support missions, reviews of progress reports and consultations with the borrower, implementing agencies and participating donors. Principal performance indicators (Annex 7.6), were discussed and agreed with implementing agencies during negotiations, and will form the basis for performance evaluation. Estimates of the timing of IDA missions, areas of focus, skills requirements and inputs are provided in Annex 6.5. By June 30, 2000, the Government would convene a mid-term review meeting to be attended by cofinanciers and implementing agencies. The objectives of the meeting would be to review the overall status of project implementation, adherence to the project implementation plan, and determine any required changes in design or implementation arrangements needed to ensure achievement of the project's developmental objectives. Specifically, the review meeting would focus on the status of progress in: (i) adjustment of tariffs towards satisfying the power sub-sector's financial objectives and LRMC; (ii) attracting private sector participation in power generation and management of operations; and (iii) restructuring the organization of the power subsector to improve operating efficiency and transparency in financial relations between operating entities. -45 -
7. PROJECT JUSTIFICATION, ECONOMIC ANALYSIS AND RISKS
A. OVERALL
7.1 This project is an integral part of the Kenya CAS, presented to the Board in January 1996. The CAS focuses on reducing poverty through improved economic growth. It identified the proposed project as a priority in terms that it would contribute to poverty reduction by stimulating economic growth through: (i) the improvement and expansion of basic infrastructure, which is critical to both improving the efficiency of existing private sector investment and attracting new private investment; (ii) improvement of public sector efficiency; and (iii) promotion of private participation in power supply.
7.2 In line with the objectives of the CAS, the proposed project aims to: (i) eliminate electricity shortages which are a key bottleneck to economic growth by assisting in financing high priority least-cost investments in generation, transmission and distribution facilities; (ii) support the implementation of parastatal reforms through the restructuring of the power sub-sector and commercialization of existing corporations; (iii) create an enabling policy and regulatory environment for private sector investment and management; (iv) raise tariffs to cost recovery levels and restrict cross-subsidies to only the basic needs of the poor consumers; and (v) promote greater efficiency in energy supply and end-use.
7.3 The proposed project is part of Kenya's FY95 - FY2013 least-cost generation expansion plan required to meet the demand up to FY2004 l. The project is technically, financially and economically sound and is thus justified for financing. Its technical design has been carried out by experienced international consultants and reviewed by the Bank. The discounted present value of the project's net economic benefits is US $344 million, and the internal economic rate of return (ERR) is 17.3 percent, which is higher that the opportunity cost of capital (12%). In addition, the project has a positive fiscal impact (para 7.20). The salient features of the economic analysis for the power sub- sector investments are discussed below.
IThe least-cost generation plan was prepared by KPLC, confirmed by independent consultants, and reviewed and found acceptable by the Bank (available in project files). - 46 -
B. NEED FORTHE PROJECT, ITS SIZEAND TIMING
7.4 Need. The forecasts of electricity demand indicate that there will be sufficient demand to absorb the output from the project facilities. The reference forecast (Table 7.1), which -- in line with the base case macro economic scenario in the CAS -- is based on a 5.5 percent average annual economic growth, translates into an average increase in electricity sales of about 5.6 percent per year, and an average annual growth in system peak of about 6 percent. This is reasonable in light of the historical growth rates of the same magnitude, and considering that there is currently significant suppressed consumer demand waiting to be served. The forecast takes account of the growth moderating impact of energy efficiency and demand management measures to be implemented under the project, and tariff increases. A detailed forecast is available in the Project Files.
Table 7. 1. Reference Electricity Demand Forecast (Interconnected System)
Avg. Annual Growth 1995/96 1997/98 2000/01 2005/06 2011 1996-2011 Sales forecast with DSM GWh 3,391 3,722 4,346 5,785 7,753 5.6% Losses GWh (Transmission & Distribution Losses & Station Use) 709 730 769 987 1,313 n/a Generation requirement GWh 4,100 4,452 5,115 6,772 9,066 5.4% System Peak MW 648 755 872 1,157 1,562 6.0% Load factor (%) 72.2% 67.3% 67% 66.8% 66.3% n/a Source: KPLC
7.5 As Table 7.1 shows, the required generation is expected to rise slightly slower than sales, owing to a reduction in transmission and distribution losses from about 16 percent of net generation in the interconnected system in FY96 to around 14 percent of net generation by FY2002. This would be the result of the installation of two diesel units at Kipevu, Mombasa -- to reduce longhaul transmission -, network reinforcement and loss reduction investments under the proposed project.
7.6 Size. The project facilities - five generating plants - will provide a total of 338 MW of new capacity and upto 2,200 GWh of electric energy annually. In addition, the 60 MW Sondu Miriu hydro plant, to be constructed in parallel with the project, will provide, on average, some 310 GWh of annual energy. The new facilities will replace about 70 MW of old, inefficient thermal plant at Kipevu and Nairobi. With the net addition of 328 MW, Kenya's power system will, under average hydrological conditions, be sufficient to meet consumer demand through the year 2004, whereafter new capacity has to be installed (paras 3.10 & 3. 11).
7.7 Timing. The project is critically needed. All the investments are required as soon as possible to prevent continued load shedding (para 1.7 & 3.11). - 47 -
C. ECONOMIC RATE OF RETURN AND SENSITIVITY ANALYSIS
7.8 Project economic rate of return (ERR) is calculated at about 17.3 %. The ERR was calculated for the incremental net benefits after identifying the project's economic costs and benefits as the difference between inputs and outputs with and without the project. In the "without the project" case, system demand is not met even at the current level, whereas "with the project", the forecast system peak and energy demand are met through the year 2004 (Annex 7.2). In addition to new generation capacity, the energy available for sale under the proposed project is augmented by the investments in loss reduction measures. The distribution network rehabilitation and loss reduction components of the project are justified also on a stand-alone basis. According to the ESMAP report "Kenya Power Loss Reduction Study" (No. 186/96), the proposed investments in the Nairobi and the Coastal areas have benefit/cost ratios of 21 and 27 respectively.
7.9 Economic Benefits. The measurable economic benefits of the proposed project are two fold: (i) increased electricity sales made possible by the planned investments; and (ii) fuel cost savings resulting from the replacement of the old and inefficient steam plants and gas turbines by modern diesel plants burning lower value fuel. The benefits from incremental sales are calculated as the difference between the forecast sales with and without the project. The value of the benefits from incremental sales includes an estimate of consumer surplus, i.e the benefit of increased consumption because of the availability of lower cost electricity, indicated by consumers' willingness to pay for electricity service over and above what they actually pay to KPLC. The analysis uses an average willingness to pay for all consumer categories equivalent to about US cents 14 per kWh in mid-1995 prices. With KPLC's current average tariff of about US cents 9.1 per kWh, the consumer surplus is estimated at about 4.9 US cents/kWh (Annex 7.3 ). The fuel cost savings are similarly calculated as the difference in fuel costs with and without the project and valued at border parity prices. These savings are the result of the greater efficiency of the new plants, and the substitution of the presently used gas oil and jet fuel by lower value fuel oil, that will cut the average fuel cost per kWh.
7.10 Economic Costs. The economic costs of the proposed project comprise: (i) investment in generation plant, transmission, and distribution required to meet incremental demand and replace output from retired units. These costs include not only the investments under the proposed Project, but also the Sondu Miriu hydro power plant to be financed outside of the project as well as additional transmission and distribution investments required for which KPLC will seek financing outside of the project; (ii) incremental operation and maintenance costs; and (iii) incremental fuel costs. Economic costs are expressed in mid 1995 prices net of taxes and duties (Annex 7.2).
7.11 Switching Values and Sensitivity Analysis. The switching values were calculated for four critical parameters as noted in Table 7.2. The results indicate that project economics are robust with respect to increases in investment, operation and - 48 - maintenance cost, and fuel costs, but that they show sensitivity to the demand forecast and the value of benefits. Given that currently the demand is suppressed because of supply constraints, the risk of overestimated sales is small. Regarding the value of benefits, the estimated value is between KPLC's current tariff and the cost of alternatives to grid electricity. It is, therefore, considered to reflect the consumer surplus adequately (Annex 7.3).
Table 7.2. Switching Values
Parameter Percentchange required to turn NPV negative@12% discount
Electricitysales -18% Capitalcost +50% O&M cost +290% Fuel cost +500% Willingnessto pay -28%(US$0.10)
7.12 Graph 7.1 below, illustrates the sensitivity of the ERR to various percentage changes in four parameters: capital investment cost, O&M cost, electricity sales; and willingness to pay.
Graph 7.1. Sensitivity of ERR to Various Percentage Changes in Parameters
30.0% 27.0% ; ------^0------.---- 24.0% --a ------0------La i--0- -v 21.0% . ------
18.0% I ------+-Investrnent cost
15.0%-_I ------&Mcost| z 15.0% :fr 0 X : z__ Sales 12.0% - -- - L-*(--WTP
9 .0 % a ------
6.0%.- - . ..
0.0% I l I -50% -30% -10% 1 +10% +30% +50%
Percentage change in parameter
7.13 With regard to the impact of possible delays in project implementation, the sensitivity analysis indicated that project economics are relatively insensitive to moderate delays. Given, however, that the Kenyan economy is already suffering from power - 49 - shortages, a delay in the commissioning of the generating plants would mean continued electricity rationing and subsequently lowered prospects for economic growth. Minimizing delays for the diesel and geothermal plants, especially Kipevu I and Olkaria II - planned to be commissioned in 1999 and 2000 respectively - is particularly important because these plants are in the forefront of the investment program. In contrast, a one year delay in the commissioning of the hydro plants would have a less critical impact on the economy, because part of the lost output could be compensated for by the diesels if they are installed according to plan, however, at a higher cost.
7.14 The likelihood for delays is largest for plants for which financing has not yet been identified, i.e., Kipevu II, and Olkaria III. Although negotiations with successful bidders are expected to start shortly, negotiations may be protracted or rebidding may be required in one case. To mitigate the risk of delays, the project preparation facility has financed consultants to prepare the bidding documents and assist the Government in the negotiations with the successful bidder (para. 7. 18).
7.15 Quantitative Risk Analysis. The quantitative risk analysis produces a probability distribution for the ERR and the NPV based on the interaction among key variables and the shape of the probability distribution of the variables. The main risks affecting the project's economic outcome include: (i) deterioration in Kenya's economic situation which would reduce the demand for electricity making the investments premature; (ii) the value of benefits; (iii) delays in the commissioning of generation facilities; and (iv) investment cost. The analysis used probabilistic risk analysis software using Monte Carlo simulation to determine the probability distributions for the ERR and the NPV. The results of the analysis implied an 80 percent probability of a positive NPV. The probability of a negative return for the project is thus an acceptable 20 percent. Lower than expected electricity sales growth rates, significant delays in the commissioning of the facilities and lower than expected willingness to pay would contribute to the negative NPV (Annex 7.4).
7.16 Other Benefits of the Project. In addition to the benefits discussed above, the power restructuring and reform component will contribute to improving the efficiency of the sector so as to increase its contribution to the country's overall economic development. The project will help develop sound energy sector policies and regulatory frameworks, which will create an enabling environment for private investment and management. The project will assist Kenya to restructure the energy sector for increased operational efficiency and establish economic pricing of energy. It will also assist in establishing two privately owned and operated power generating plants, and to build investor confidence in Kenya's energy sector. Training and technical assistance provided under the project will help improve the human capabilities in the energy sector.
D. RISK MITIGATION
7.17 Althoughthe risk analysis indicated that the probability of a negative NPV is not significant, project design and implementation were formulated to mitigate the risks of - 50 - unfavorable outcomes. With respect to the deteriorating economic performance which could result in lower than forecast demand for electricity - the Bank's continued broad policy dialogue on the macroeconomic reform program, will help focusing the Government's macroeconomic reforms on maintaining stability. Project design allows a limited possibility to delay construction of plants for which contracts have not been signed, in case of drastically lower than expected demand growth - an unlikely scenario.
7.18 The risk associated with delays in the commissioning of facilities has been reduced for the publicly financed projects by preparing the bidding documents before Board presentation. In addition, KPC's track record in project implementation is fairly good. Nevertheless, given the large size of the Project, it will provide consultant and advisory services for project implementation, engineering and financial management. For the privately financed, IPP projects, the risk of delays has been partially reduced, through financing under the Project Preparation Facility for consultant services for the preparation of bidding documents. They were issued in July 1996, and several bids were received at the bid closing date in November 1996. In addition, the agreed changes in the legal and regulatory framework should contribute to increased investor confidence. Another risk is delay in mobilizing the corresponding local financing requirements, that could lead to implementation delays. The agreement on annual reviews of the investment program and related financing plans is designed to minimize this risk. The agreed power sector restructuring will also assist in improving the operational efficiency and financial situation of the implementing agencies. Finally, IDA's continued macroeconomic dialogue will help in keeping retail and bulk tariff adjustments on track to insure adequate counterpart funding. The agreement on an action plan for the implementation of adequate adjustments based on a Tariff Study - to be completed by November 1997 - is a condition for the second tranche release of the SAC (para 3.21).
7.19 The capital equipment of the project comprise mainly of standard equipment and the civil works are not significant, indicating a moderate risk for cost over-runs. To mitigate these risks, the cost estimates include adequate contingencies
E. FISCAL IMPACT AND SUSTAINABILITY
7.20 The proposed project has a positive fiscal impact (Annex 7.5). The net present value of the project's contribution to Government budget is estimated at about US$ 160 million over a twenty year period. On average, the annual net revenue to the Government is about US $30 million (about 0.5% of GDP). The main source of the revenue to the Government from the proposed project is the margin between the interest rates KPLC and KPC pay the Government on the relend proceeds and the concessional interest rates the Government pays IDA, EIB and KfW. In addition, the Government would receive increased revenue from corporate taxes and VAT on the incremental electricity sales. The project will not crowd out public expenditures on other development programs, such as health and education, because no counterpart funding is provided from the Government budget (it is provided by the implementing agencies from their internal cash - 51 - generation). The proposed project would not affect domestic interest rates, neither would it crowd out domestic borrowing: It is roughly estimated that US $50 million of the about US $260 million in private equity and commercial debt for the financing of the IPPs, would be raised within Kenya. This is a small share of the about US $3 billion in outstanding credit to the private sector from the financial sector as a whole in mid-1996. Furthermore, on an annual basis, the project's domestic borrowing would be only about 1/2 percent of the outstanding stock.
7.21 The structure of the proposed project is favorable for sustainability, because all key stakeholders have an incentive to see that it succeeds. For instance: (i) the project's positive fiscal impact should provide an incentive for the Government to solidly support it; (ii) the project would provide both KPLC and KPC urgently needed financing for priority investments, thus enabling them to reduce the cost of supply and sell more electricity; and (iii) the electricity end-users would gain because of increased and more reliable power supply. Finally, the project would create 3,000 - 4,000 temporary construction jobs. - 52 -
8. AGREEMENTS REACHED AND RECOMMENDATION
8.1 During negotiations agreement was reached on the following:
(i) the Government and IDA would review the power sub-sector's five-year rolling investment plan by March 31 of each year (para. 3.27) and the GoK would not undertake any single capital investment in new facilities of more than US$10 million (including investments by independent power producers) outside the agreed plan without prior consultation with IDA;
(ii) adequate analysis of environmental impacts would be carried out for all future power subsector projects and appropriate mitigation plans would be developed and carried out (para. 4.16);
(iii) KPC would establish and maintain Project Management Teams comprising staff (including consultants) with experience in procurement, contract management and project finance, to assist with the management of its components (para. 6.2);
(iv) KPC and KPLC would maintain adequate accounting records and supporting documentation for expenditures related to the project (project accounts) and would have them audited, within six months of the end of each fiscal year, by independent auditors on the basis of terms of reference satisfactory to the Association (para. 5.12 and 6.13);
(v) KPC and KPLC would submit to IDA, financial statements covering their respective total operations, audited on the basis of terms of reference satisfactory to IDA, within six months of the end of each fiscal year (para. 5.12);
(vi) KPC would employ consultants in accordance with the Bank's Guidelines, to assist with the design and supervision of its components (para. 6.2);
(vii) KPC would generate adequate funds from internal operations to finance at least 20% of its investment program in FYI 997/98 and 25% in each fiscal year thereafter (para 5.14); - 53 -
(viii) KPLC would generate adequate funds from internal operations to finance at least 25% of its individual investment program for FY1997/98 and FY1998/1999 and 30% thereafter (para 5.14);
(ix) KPC and KPLC would maintain their accounts receivable at levels not exceeding 60 days sales revenue at any time (para. 5.14);
(x) the Government shall complete an update of its 1993 Electricity Tariff Study no later than November 30, 1997 and shall implement the agreed recommendations (para. 5.14); and
(xi) the Borrower shall take all steps necessary to ensure the movement of wildlife within the Olkaria area and between Olkaria and Hells Gate and Longonot Park in accordance with the agreement between KPC and KWS dated September 20, 1994 (para. 4.13).
8.2 The following are the conditions for Credit Effectiveness:
(i) submission to the Borrower's Parliament of amendments to the Electric Power Act providing for the establishment an autonomous Electricity Regulatory Board (paras. 2.6, 3.26 and 5.16);
(ii) execution of subsidiary loan agreements between KPLC and KPC and the Government (para. 4.8); and
(iii) MOE and KPC have selected consultants for their PISG and Project Management Teams (para. 6.2).
Recommendation
8.3 Subject to the above agreements and conditions, the project is suitable for a Credit to the Government of Kenya in the amount of SDR 86.6 million (US$125.0 million) equivalent, on standard IDA terms. Annex 2.1 Page 1 of 4 KENYA
Energy Sector Reform and Power Development Project
Action Plan for Restructuring of the Power Sub-Sector
ACTIVITY 1 SPECIFIC ACTION T TIMING
A. Merger of TRDC and KPC I . Obtaining consents from creditors T A. Mergerof TRD and KPC I KPC and TRDC All consents have been obtained. Started on 2/5/96 anidcompleted on 7/8/96.
2. Obtaining consent from the Minister for 15/7/96-29/11/96 Finance in light of the likely infringement of the Restrictive Trade Practices, Monopolies and Price Control Act, Cap 504 of the Laws of Kenya by the proposed merger of TRDC and KPC. This is a four step process entailing:
(i) Leteers from KPC and TRl- to Minister for Finance through the Monopolies and Prices Commissioner requesting for the Minister's approval of the intended merger.
(ii) Consultations, if any between Minister for Finance, Monopolies and Prices Commissioner and KPC/TRDC on intended merger.
(iii) Grant of the approval by the Minister
(iv) Publication of approval by ministerial order in the Gazette
A. Merger of TRDC and 3. Obtaining approvals of the Treasury 16/8/96-29/11/96 KPC. and of the Minister for Energy for transfer of assets and liabilities of TRDC to KPC (Sections 11 and 13 of State Corporation Act, Cap 446). This is a two step action entailing:
(i) Letter from KPC and TRDC to 16/8/96-19/8/96 Minister for Energy and Minister Done. for Finance for requesting for approval of intended transfer of Annex 2.1 Page 2 of 4
ACTIVITY SPECIFIC ACTION TIMING
assets and liabilities, in accordance with the provisions of Cap 446 (Section 11 and 13).
(ii) Consents of Minister for Finance 20/8/96-29/11/96 and Minister for Energy to the intended transfer of assets and liabilities.
4. TRDC Board to pass a resolution for 2/9/96-13/9/96 transfer of TRDC's assets and liabilities to KPC.
5. An Extra-ordinary General Meeting of 13/9/96-11/10/96 TRDC to pass a special resolution for Done. transfer of its assets and liabilities to KPC.
6. KPC Board to pass a resolution of 2/9/96-13/9/96 accepting the transfer of TRDC's assets Done. and liabilities to KPC.
7. Joint agreement between KPC and 12/10/96-15/12/96 TRDC for the transfer of assets and liabilities to KPC.
8. Joint notice by KPC and TRDC of the 31/12/96 transfer of assets liabilities and business under the Transfer of Business ACT, Cap 500.
9. An Extra-ordinary General Meeting of By 31/1/97 TRDC to pass a special resolution to wind the company up and appoint a liquidator.
10 Issuance of Gazette Notice and By 15/2/97 Advertisement in the local dailies of the special resolution to wind up TRDC.
11 TRDC to voluntarily wind up. 31/3/97
Appointment of new KPC 1. Appointment of a Managing Director Done - January 1997 Board. for the new KPC.
2. Appointment of Chairman and other Done - January 1997 _ _ _ _ Board members. _ _ _
Appointment of personnel 1. Appointment of a Task Force Done - January 1997 for KPC (comprising the Mds of KPLC and KPC and representatives of MOE, MOF and l ______l DPM)_to identify appropriate personnel |_l Annex 2.1 Page 3 of 4
ACTIVITY SPECIFIC ACTION TIMING
from existing KPLC staff establishment for transfer to KPC.
2. Identify and transfer of identified 1/3/97-31/5/97 personnel to KPC from KPLC.
3. Recruitmentof staff shortfalls by KPC From 1/6/97 onwards Board.
Location of offices for MD for KPC and his key staff to look 1/3/97-30/6/97 KPC. for appropriate accommodation for the company and move in.
Recruitment of Specialists Appointnent of Specialists to assist in 1/3/97-31/5/97 the transfer of assets and liabilities and in the preparation of Power Purchase Agreements (PPAs).
Transfer of TARDA's I . Generating assets belonging to TARDA 1/3/97-31/10/97 generating assets and to be transferred to KPC on historical liabilities to KPC and cost basis as per EDF's assets transfer pricing recommendations. principle.
2. All existing liabilities associatedwith TARDA's generating assets to be transferred to KPC at their current values.
3. KPLC will cease to service the debt obligations for Kiambere liabilitiesto KPC.
Transfer of Turkwell's 1. The Turkwell Gorge multipurpose 1/3/97-31/10/97 generating assets and project generating assets to be liabilities to KPC and transferred to KPC on historical cost assets transfer pricing basis as per EDF's recommendations. principle. 2. Transfer value of liabilities associated with the generating facilities of the Turkwell Gorge project to be based on the replacement cost of the assets. This approach is being used because Turkwell loans are being serviced by the Treasury and limiting the level of liabilitiesto historical costs of the assets would impact negatively on the fiscal |__ _budget. __ l_l 3. Treasury and KPC to work out modalities for servicing of such liabilities over a twenty year period from the date of commercial operation |_l Annex 2.1 Page 4 of 4
ACTIVITY 1 SPECIFIC ACTION TIMING
I of the Turkwell Gorge project.
Transfer of assets and I . Transfer of assets between KPLC and liabilities between KPLC KPC to be effected on the basis of and the new KPC and replacement costs, taking into account assets transfer pricing useful lifespans of the assets involved. principle. This approach is being used as opposed to effecting transfer on historical costs basis because KPLC is not wholly Govcrnment owned.
2. Transfer of liabilities belween the two companies to be effected on the basis of their current values.
Termination of I1. All management agreements between 1/3/97-31/10/97 management agreements. KPLC on one hand and KPC and TRDC on the other, to be terminated upon full operation of the new KPC.
2. Agreements between KPLC and TARDA for mianagementof the gene,atitig I sets to he terron?,te(I opln transfer of assets te and ful' operation ot, new KrC.
3. Management of Turkwell generating assets by KPLC will cease upon transfer of the generating assets to and full operation of, new KPC.
Rural Electrification KPLC to be fully reimbursed for all capital Continuous Programme expenditures and recurrent costs for rural electrification programme. This understanding to be reflected in a performance contract to be signed between KPLC and GOK.
Dam monitoring, Both KVDA and TARDA will be fully Already being done on a catchment presentation and compensated on an annual basis for continuous basis. security expenditures on dam monitoring and maintenance, catchment preservation and security.
Power Purchase PPAs to be prepared by KPLC, negotiated 113/97-30/6/97 Agreements (PPAs) with KPC and signed by the two companies. KENYA Annex 3.1 ENERGY SECTOR INVESTMENT PROJECT Page 1 of 1 ENERGY BALANCE 1994 000 Tonnes of ON EqitAvlent (tool
; , 4'.'$;"', ~ !o ~ ootilwa cog a #.Wy¢o Cn*Ocm odS w cm> 0tt, one" Iktewss' ok1 , . et , ty 'udWr Reskk Co to Traditionalt Commenrcrial oS SUPPLIES
Indigenous Production 73 0 776 0 0 0 0 0 n 0 0 10,793 0 0 10,793 848 11.642 knport 87 2.090 0 132 142 291 (r 2,655 16 0 0 0 0 2.756 2758 Export 0 1421 1491 (54) 1231 It) (1to1 0 0 0 0 0 1168) t16SI Bunkers 0
IG oss Suppl 73 87 778 2,090 t421 54 Be 268 tl) 2,487 Iff 10,793 n/a ° 10.793 3,439 1-4,232
CONVURSION
P.tro)um Refinkin 0 2.0901 005 533 339 425 31 1S56) 0 0 0 0 0 11561 (1561 ChwcodProduction 0 0 0 0 0 0 0 0 0 11,1781 0 252 (9261 0 19261 Power Georton Hydro 0 t7761 0 267 0 0 0 0 (5091 (5091 Power GwnwOaton0 ltvnmd 0 0 1631 (01 (201 0 0 (631 24 0 0 0 0 (S8R (581 Power genarationGoo tthrm 1731 0 0 25 (48) Losses 0 0 0 0 0 0 0 0 1431 0 0 0 0 (431 143) ErrorS 0 0 0 0 '0 0 0
CONSU11117"
industry 67 356 47 a 6 5 420 122 481 0 481 629 1.109 Transport 0 4 426 372 450 0 1.252 nfl 0 0 0 1.252 1.252 Agacutture 0 39 32 4 2 0 78 nl/ 317 0 117 78 395 Houselvold 0 0 0 0 223 20 243 90 .8817 199 9.316 333 9,349 Connwerc. , Othwr 0 102 II1 25 13 6 256 78 0 52 52 334 386
Total Corsuption 0 67 0 0 501 616 407 693 31 2.249 289 9,615 nts 252 9,867 2.625 12,492
%of TotalEnergy 0% 1% 0% 0% 4% 5% 3% 6% 0% 16% 2% "7% 0% 2% 79% 21% 100% %ofComnwerdaEnerry 0% 3% 0% 0% 19% 23% 16% 26% 1% 86% 11% 100%
Soumces.Mitthbrv of Enrrgy end mission osth,ats
ENERGYCOUsJMPYTI DVCONSUMER CATEGORY
% of % of Category Total Commercia
Industry 9% 24% Transport 10% 46% Household 75% 13% Commerc & Others 6% 16%
Sum 100% 100% 0W
Per coplt CommercialEnergy Consumption: 0.10 toe/capita Per capit Totaltneegy Consumption: 0 48 too/capita Peocapita Electricity Consumption: 129 kWh/capita Pei capits PatrotoumProducts Consumption: 87 kg/capti Annex 3.2 Page 1 of 1
KENYA ENERGYSECTOR REFORMAND POWERDEVELOPUAENT PROJECT
1. ELECTRICrTYCOMSUMPTION GWh
86/87 87188 88189 89'90 90/91 91t92 92!93 93/94 94/95 9596
Domest c *,aI. conmmocla' and Mdusl'41 633 678 729 780 823 877 928 977 1.026 993 Chsnne rfro c*'ous Year % 7% 8% 7% 6% 7% 6% S% 1% 3% Sna'ec lots % 287% 290% 301% 301% 304% 31 8% 320% 326% 332% 3055% Med,ou, co-rtmca 8r1 -dus¶r,a 536 555 516 554 585 567 564 559 569 660 Cnange fron Dov,dous "a' % 4% 7% 7% 6% 3% 11% -1% 2% 16% Share o! iota % 24.3% 23 7% 21 3% 21 3% 21 6% 20 5% 19 4% 18 7% 184% 20 3% Large co-vmrrcwa and -cuSt'ia 919 985 1046 1130 1178 1198 '281 1326 1 356 1492
Change fro, osraouos weaa % 7% 6% 8% 4% 2% 7% 4% 2% S0% SnhrO ol Iota % 41 6% 42 1% 43.3% 43.5% 43 5% 43 4% 44 2% 44 2% 43 9% 45 9% OfftDesk III 110 113 117 109 104 115 125 119 92 Change from oer",ous Year % .1% 3% 4% -7% -5% 11% 9% *5% .23%
Share of tota5 S S0% 4 7% 47% 45% 4 0% 3 8% 4 0% 42% 3 9% 2 8% Strea L,ghtrng 9 12 14 14 14 14 13 10 18 15 Change from r,av.ous Year % 33% 17% 0% 0% 0% -7% -23% 85% 19% Share of tolai % 0 4% 0.5% 0 6% 0.5% 0 5% 0.5% 0 4% 0 3% 0 6% 0 5%
TOTAL SALES OWh tKPLC) 2.208 2.340 2.418 2.59S 2.709 2.760 2.901 2.997 3.089 3.252 Change trom pravous Year % 6% 3% 7% 4% 2% 5% 3% 3% 5%
Rural Electrof.caton aers (REF) GWh 25 36 49 66 76 85 104 138 134 150
GDP growth rate in -FY trmsa 5.2% 1.0% 6.1% 4.7% 2.8% 0.3% -0.2% 2.2% 4.5% 5.0% GOP aluticrny 1.2 0 7 1.6 1.6 6.3 -25.5 1.5 0.7 1 1
2. NtJMEW OF CONSUMERS
Number of Coumr4 (KPLCI 213.600 223.718 234.674 246,348 262.521 277.622 294.520 310.916 321.738 316.024 Nua of Consumws (REF) 8.706 11,494 15,132 19.067 24.491 29.513 34.561 40.731 43.718 50.306 NtumberofR AldntsslCoa4umne 177J171 187,159 197,612 206,023 224.611 239.816 256.128 272.217 2UH.116 307,518
Total Popustaon mllional, 21.7 22.4 23.2 23.7 24.5 25.2 26.0 26.B 27.5 28.3 t4efcataon rate % of poulation 51.7% 5.8% 6.0% 6.2% 6.4% 6.7% 6.3% 7.1% 7.3% 7.8% Conwtmt. perC.pirtsf1Wheai*ts)on 102.9 10.1 106.3 112.3 113.7 112.9 115.6 117.0 117.2 120.2
2. GENEATON OWih SS/37 6711111 683 38/30 60K131 31132 32133 3/94 34/1 3195/"6
Hydro 1.793 2.036 2.449 2,517 2.760 2.776 2.972 3.04t 3,103 3.163 Imports 211 154 112 174 134 240 273 264 187 149 Od Tharmal (Kiru) I" 206 25 37 74 75 59 140 218 224 G.otiaermal lOlkaitl 374 34 322 336 236 272 272 261 291 330 Gs TurelNba-cou.h Kpowvl 44 85 21 10 21 3 2 2 47 171 otass 5 3 2 2 0.3 3 0.2 0 2 2 WandTuwb4. I 1 1 Total hlntrconr. ctd 2.516 2,lO 2.331 3.136 3.2t7 3.36t 3.578 3,716 3,348 4,100 leotd dysxtm 3 10 11 12 14 1 20 17 17 19
GROU GENERATION 2.604 2.JJ6 2.942 3.118 3.301 3.316 3,St 3.732 3.966 4.113
Auxeryc oaumaaton 23 43 27 3 383 30 2S 3t 45 52
NEtTGENEATIOTM 2.86 2.7 LO 3,116.S 3.6 3261 3.536 3.3 31t21 4.067
System Lte 347 407 448 48 484 51D0 6114 5o 53" 66 la as % of nt gan 13.5% 14.E% 15.4% 14.6% 14.8% 16.2% 1$.8% 11.2% 15.7% 16.4%
Sala KPIC 2.206 2.340 2.418 2.5111t 2.708 2.780 2.901 2.937 3.069 3.252 Sala REF 21 26 48 67 7 tl 104 13i 134 1S0
3 GENERATION60tJUl
lvdro 63.1% 72.4% t3.6% 30.3% U4.0% 82.4% t3.1%S 2.0% 60.6% 77.1% hwpu 6.1% 5.5% 3.8% 1.1% 4.1% 7.1% 7.6% 7.1% 4.93 3.6% 04 Th_mal Wapul .5% 7.4% 0.% 3.1% 2.3% 2.2% 1t.% 3.S% B.7% 5.6% G.otheta tOtisrs) 14.4% 12.4% 11.0% 10.7% 9.1% E.1% 7.6% 7.0% 7.5% 9.5% Ga TurIa Itib-south. )Kiparval 1.7% 2.3% 0.7% 0.3% 0.6% 0.1% 0.1% 0.0% 1.2% 4.2% tea 0.2% 0.1% 0.1% 0.1% 0.0% 0.1% 0.0% 0.0% 0.0% 0.0% Wind Tia 0.0% 0.0%
antacoawactadof total gora gan 3.7% n.6% 33.6% n3.6% 8.6% 33.1% 39.4% 3.5% 911.6% 3.6% solated *natae of total ora at 0.3% 0.4% 0.4% 0.4% 0.4% 0.5% 0.6% 0.5% 0.4% 0.5%
4. SYSTEMMEAt 8W 430 481 480 320 IgO 646 5Uh O12 Ot6 64t Changeft=mpraoeuY.r"% 7% 4% 8% 6% 3% 5% 3% .1% 7%
S. LOADFACTORt 64.4% 4.3% 6311.3% 64.4% 67.5% 67.7% 63.4% 64.3% 72.1% 71.6%
1/ 113136gm,. p ena Ssures: KPLC Annex 3.3 Page lof 1 KENYA
Available Generating Capacity and Generation in 1994/95
Station Owner InstalledCapacity Effective Capacity Energy Produced in MW Capacity in MW 1994/1995 in GWh
Hydro Tana KPC 14.4 12.4 78 Wanjii KPC 7.4 7.4 27 Kamburu TRDC 91.5 84.0 485 Gitaru TRDC 145.0 120.0 704 Kindaruma TRDC 44.0 44.0 213 Various KPLC 6.2 5.7 22 Masinga TARDA 40.0 40.0 200 Kiambere TARDA 144.0 144.0 996 Turkwel 106.0 106.0 379 Thermal Kipevu KPLC 93.0 86.0 218 Geothermal Olkaria KPC 45.0 45.0 291 Gas Turbine Nairobi South KPLC 13.5 10.0 16 Kipevu KPLC 30.0 30.0 31 Diesel Various KPLC 4.0 2.0 2 Wind Turbine Ngong KPLC 0.35 0.35 1 Isolated Stations KPLC 7.3 6.7 17 Imports from UEB 30.0 off peak only 187 Total 821.7 743.4 3,866
Source: KPLC 21-NOV.'96(THU) 17 07 (WB)KENYA DIRECTOR: FAX:2542 26038? P.002
Annex 3.4 Page, 1 of 6 RIEP3BLIC OF KEENYA NLISTRY OF FINANCE
Tclegraphic Address: ''921 Orrice of the ?Minister FINANCE - NAMOST P.O. Box 3a007 Telephone: 338171 NAG LOBI Wben replying please quote XXY A
Ret. Yo. EA/rA 621323/01 15th November, 1996 and dae
MvIr.James D. Wolfensohn President World Bank 1818 H Street N.W Washington, D.C. U.S .A
Dear Mr. Wolfensohn,
Kenya: Energy Sector Reform and Power Development Project Letter of Power Sub-Sector Policy
Introduction
The energy sector plays an important role in the country's economy, in cerms of its impact on the balance of payments, concribution to the govermnent's revenues, and share of investment and employment. The Goverrnent. therefore, accords a high priority to the development of the sector in a cost-efficient and environmentally sustainable manncr. The purpose of this lerter is to highlight the Government's sector development objectives, and the policy and institutional reforms being pursued to achieve the objectives. These reforms are an integral part of the design of the Energy Sector Reform and Power Development Project and underpin che invesanenrs proposed under the Project. The Government has undertaken several studies to provide a basis for formulation of sector policies and strategies. A broad sector stracegy was developed and agreed with the World Bank and che IMF and this is reflected in the Policy Framework Pacers (PFP) covering the periods 1993-95 and 1996-98. In the PFP for the period 1996-98, energy seccor reform policies have been articulated in paragraphs 35, :52, 53 and 54.
Policy Objectives
The sector's stracegic objectives areto improve investment and operational efficiency by: - (i) separating commercial funccions from policy setting, regulatory and coordinaEing functions: - (ii) implementation of power projects on the basis of improved leasc cost-investment planning; (iii) creating more competitive market conditions in electricity generation and in rhe petroleum sub-secror; (iv) restructuring power companies and requiring them to operate on a commercial basis supoorted by a system of perfornance contracts and wich transparent financial relationships; (v) adjusting the struccure of electricity prices to ultimarely reflect long run 21-NOV.'96(THU) 17:08 (WB)KENYA DIRECTOR: FAX:2542 260382 P. 003 Annex 3.4 Page 2 of 6
t *arrerof Power Sub-Secro' Policl 2
marginal cost of supply and ensuring that petroleum product prices are set by Ehe market while discouraging cartetizaLion; and (vi) carrytng outdcmand and supply-side efficiency improvements in the power sub-sector and in industry.
Role of Government - Sector Restrucruring
The Government's principal role in a restructured energy sector will be t-hat of a facilitator of development by providing a stimulus to invescment and growth through provision of an enabling environment, policy formulation, regulation, monitoring and coordination. In this respect, the Government will strengthen its capaciEy for regulating any market segments characterized by limited competition and will improve the legal framework for che sector so as .co effectively protect the interests of consumers, facilitatc private sector participation and enhance the efficiency of operating companies. In the power sub-sector, the Government's role will focus on;
i) reviewing bulk and the end-user tariffs and approving adjustments in order to meet thc financial requirements of thc power-sub-sector;
ii) reviewing power purchasing arrangements to ensure that they meec the requircments of the relevant laws of Kenya;
iii) ensuring system reliabiliry and security;
iv) licensing of power operacions on conditions intended to promote efficiency of the industry and institution of concrols against non-competitive behaviour,
v) protecting the interest of electricity consumers by ensuring that appropriate standards for supply are adhered to;
vi) setting up and enforcing standards in respect of safetcy;
vii) setting uo and enforcing scandards in respect of environmental protection;
viii) promoting the developmnen of viable and healthy competition and technology advancement of the sector; and,
ix) establishment of an autonomous Electricity Regulacory Board, under the Electric Power Act, CAP 31.4, to carry out activities (i), (ii) and (v) listed above, among othcr things, under the general policy advice of the Ministry of Energy.-
nergy Secwor Reform and Power DeOelopmenr Projecr 21-NOV.' 96(THU) 17:08 (WB) KENYADIRECTOR FAX:254 2 260582 P. 004 Annex 3.4 Page 3 of 6
LcrTCr of PRwe:r SUb-Secror PoUer . 3
Restructuring and Commercializing Power Companies
Thc existing limiced liability companies (KPLC, KPC and TRDC) will be reorganized by end of October. 1997, to place all the generation assets under one company and all the transmission and distribution assets in another. The generation assets owned by che multi- purpose authorities will be transferred to the new electric powcr generation company on historical cost basis. by end October, 1997. Assers rransfer between the new generation company and the transmission. and distribution company will be Rffected on the basis of replacement costs, taking inco account the residual life spans of the assets involved. Liabilities relating to the generation and transmission assets will be transferred betwecn and among the oarganizations on the basis of the current outstanding debts, save for the Turkwel project. The liabilities for the Turkwel project will be transferred on the basis of the replacement cosr of the electro-mechanLical components. However, the new generation company and the Treasury will work out the project's debt service arrangemenc over a period of twenty years. Debt service for Kiarnbere will be transferred to the new generation company when ir becomes fully operational. The power comoanies will be required to operate on sound commercial principles. To improve the companies' operating and financial performance, a system of performanc_ contracts will be institured by June 30, 1997 for the two new electric powcr companies. Strcamlining of sraffing levels in KPLC (the only company with staff) has been initiated and the customcr/staff racio improved from about 36: t ac the end of 1994 to 49:1 by the end of 1995. KPLC has also made subscancial progress in contracting our non-core services: both the security and janitorial services are now 100% contracted out; and construction of Kilifi-Malindi 33kV line which was contracted out in August 1995 was completed in January 1996. KPLC plans to contract out more line construction work including 66kV lines in Nairobi area. Contracting out of transport workshops and repair workshops is also planned.
Private Sector Participation
The Government Ehasdecided to intoduce competition in the generation segment of the electricity supply markec, so as to improve efficiency and expand che scope of resourc-s mobilization by encouraging private sector participation. In this regard, invitations for private sector bids for developmenc and operation of two power plants (Kipevu 11 Diesel and Olkaria IIL Geothermal) were issued in July 1996. with November 29, 1996 being the closing date for receipt of duly completed-bids. In addition co chese two power plants, all future power projects. except multipurpose hydro schemes, will be offered for development, on a competitive bidding basis, by both che privare and publiv sector companies Private companies, together with the proposed generation parastacal will supply electricity to che proposed cransmissicn and distribucion company under long-term power purchase agreements (PPAs). As an interinm measure to redress the current power supply shortfalls, while projects programmed for devclopmcen under the rolling five year least cost development plan are being constructed, the Government has decided to have in place a 44-.5 MW oil fired plant developed by an IPP, on a fast track basis. An IPP has already been selected through a competicive
Ener_V Sec:or Refomiw and Power Deve!opmenrt Projecr 21-NOV.'96(THU) 17:09 (WB)KENYA DIRECTOR: FAX:2542 260382 P. 005 Annex 3.4 Page 4 of 6 Le,rer of Po%wrSub-S cror Po.licy 4
bidding process to develop che plant, on the basis of build-own-operatm (BOO) arrangement. The IPP will scll power to KPLC under a PPA. On its part, KPLC has finalized similar arrangemenns for an IPP to develop a 43 MW oil fired plant to replace generation by retired uneconomic thermal capacity at Kipevu. In the petroleum sub-sector, the procurcmenc, marketing and distribution and pricing of crude oil and petroleum products is already being carried our by the private sector. On Ocxober 27. 1994 the Government deregulated the petroleum markets and removed the National Oil Corporation of Kenya's monopoly rights to procure 30% of the country's crude oil requirements, and allowed consumer prices to be market-deternined.
Least Cost Investment Planning
The Government will ensure that a rolling five-year energy sector inves;ment program, including a least-cost power system expansion plan is updated annually and rolled over by onc year. These documents will be submitted to IDA for comments prior to finalization and subsequent implementation. All investments will bc ranked in tcerms of their imoact on the environment and cnvironmental assessments will be carried out in line with the World BanJk's/any other donor's guidelines for all planned projects. Mitigation plans will be prepared anrd implemented for all projects with adverse environmental impacts.
Capacity Building
The Gcvernmenc will continue to build its personnel capacicy through training in institutions of higher learning, middle level colleges and polyrechnics. and through participation in seminars and workshops including overseas attachments in appropriate institutions to ensure effective management and development of the energy secror.
Ener,y Pr:icing
The Government's energy pricing policies are aimed at encouraging efficient utilization of electricity and other commercial fuels, prudent management of resourc:s dedicated to supply and delivery of energy to consumers, ensuring the financial viability of energy enterprises and generation of fiscal revenue. In the power sub-sector, the government is commitred co adjusting generation tariff and end-user cariff structure so as to ultimately reflecr long run marginal cost (LRMC) of electricity supply to enable the sub-sector co achieve an operational profit and thus raise adequate capital to sustain its investment programs and attract IPP invescmcnts in the gcncration segment. As part of thc tariff adjustments process, in March, 1994 the Government increased the average tariff level by 60%, which together with subsequent appreciation d2 the Kenya shilling against the US dollar had raised che tariff level from about 54.5% to 67.5% of LRMC. currently. 71 4 Tariffs were raised to 75% of LRIMC wich effecc from October 1, 1996. An update ot 7 the November, 1993 tariff study, envisaged to be completed by April 30, 1997, will provide the
Energy Secror Reform nsdPower Development Project 21-NOV.'96(THU) 17:09 (WB) KENYADIRECTOR: FAX:2542 260382 P.006 Annex 3.4 Page 5 of 6
Lart'r of Por)w Sub-recror PoIicy 5
basis for che Government to determine the magnitude and phasing of Further adjustments required to achieve LRMC, after t'aking due consideration of the cost of power from independent power producers and the sector's overall financing requirements. Scarting in 1994, the Government has authorized KPLC to automatically adjust the level of ics tariffs so as co reflect changes in the cost of petroleum fuels used in thermal generation of electricity. EFfective Ist October, 1996, KPLC has been authorized to automatically adjust its tariffs to reflect changes in the cost of external debts service arising from fluctuations in the exchange rates of the Kenya Shilling. The bulk tariff for sales of electricity by the public sector generation company will be based on tie tariffs established through the LRMC pricing principle, as determined through the regulatory proc-ss. In addition, the bulk tariff for sales of electricity by independent power producers will be based on prices escablished through international tendering proc-ss.
Eaergy EtTciency
It is the Governmenc's policy to promote che efficient supply and use of energy. On the supplv side, the policies and institutional reforrns to improve efficient provision of energy include the reorganization of the power sub-sector, the planned introduction of private sector participation in power generation, the contracting out of services to the private scctor, the inrroduction of performance contracts for energy enterprises and screamlining of smTffinglevels. More specific measures to improve the efficiency of power supply include reduction of losses, particularly in the discribution systems and installation of efficient generation facilities. On che demand side manacement. the Government will encourage large consumers of electricicy to even out demand, time of use and inrerruptible electricity tariffs will soon be introduced. The Government will also promote energy audirs for commercial and industrial consumers, develop a demand side management programme, make available information to the public on efficient usC of energy and cost-effective technologies and encourage private sector participacion in the delivery of energyefficiency improvemenc measures. Efficiency standards for electric equipment will also be developed.
Renewable Energy
On new, renewable and rural energy, the Government will together with theprivate secror promote the economic developmenr of new and renewable energy sources such as wind, solar and biomass, particularly to complement energy supplies in areas not served by the grid. The Government will regularly review its policy on import duties and taxes levied on solar and wind- power equipment in order to ensure that these arc not higher chan those levied on convencional electrical equipment and will also establish quality standards for phocovoltaic (PV) and wind power equipment. The Government attaches great importance to rural electrification and in chis respect a rural clectrification master-plan is currently under preparation with technical assistance from che African IDevelopment Bank (ADB) to among other things examine alternative options for the provision of energy in che rural areas in a cost-effective manner, taking account of GoK's
Energy Scc:or Reforr antd Pov.r Develtoarnenz Projrct 21-NOV.'96(THU) 7:10 (WB)KENYA DIRECTOR: FAX:254 2 260382 P.007
Annex 3.4 Page 6 of 6 Lezlar of Power Sub.Sector PeUicy 6
policies on industrial dispersion. The GoverTnmnen will also review its policies on new and renewabie cnergy, from Lime to time with a view to promocing widespread use of new and renewable sources of energy including wood-fuel.
Conclusion
The Government believes that the implementation of the above measures, togecher witil the other policies spelt out in the current Policy Framework Paper, will bring abouc accelerated economic development and promote the reduction of poverty.
Yours sincerely
MUSALL.A
Copy to:-
Hon. Noah Kataua Ngala, E.G.H., M.P. Minister for Energy .Ministry of Energy Nairobi
Mr. Fares Kuindwa, E.B.S. P.ermanent Secretary, Secretary to the Cabinet and Head of Public Service Office of the President Nairobi
Energy Seclor Reform and Power DevelopmcntrProject Annex 4.1 Page I of 1 KENYA
Energy Sector Reform and Power Development Project
Documents Available in the Project File
Kenya: Electric Power Sector Organization Study Phase I Report ( three Volumes); July 1993, Prepared by London Economics in association with Kaplan & Stratton Advocates
Electric Power Sub-Sector Organization Study in Kenya; Final Draft Report ( two volumes), May 1996, Prepared by EDF of France
Kipevu Diesel Power Plant (Phase 2) Feasibility Study, Final Report; August 1994, Prepared by Ewbank Preece ( UK)
Electricity Tariff Study, Final Report (three Volumes), Prepared By London Economics Limited (UK), April 1993
Legal Consulting services to review and develop an Appropriate Legal and Institutional Framework for the Energy Sector in the Republic of Kenya, Prepared bt Oraro & Rachier Advocates (Kenya) Steptoe & Johnson LLP (USA) Volume 1- Petroelum Subsector Reform Volume II- Corporate Restructuring Volume lIl- Electricity Law Reform
Kenya's Energy Sector Investment Programme 1995/96-1999/2000, document presented by the Government for discussion at a consultative Donor's Meeting in Paris, September 1995
Petroleum Market Structure and Pricing Study, August 1993, Prepared by Arthur D. Little Inc. (USA)
Feasibility Study for a Geothermal Power Station at North East Olkaria, Final Report, December 1989 ( three volumes), Prepared by Ewbank Preece (UK) Annex 4.2 Page I of I
KENYA Energy Sector Reform and Power Development Project Description of the Sector Restructuring and Reform Component
Implementation of the Sector Restructuring and Reforrn component is already in progress with financing provided by IDA under a Project Preparation Facility and supplemented by other IDA credits. The objectives of the component are to support deregulation of the petroleum subsector, reforms of the organization, management and financial structures of the power subsector companies, the establishment of a legal and regulatory framework necessary to improve subsector efficiency and the promotion of private sector investment in the sector. The table below summarizes the relationship among the reform objectives, the studies included in this component, the costs of the studies, and the outputs.
Reform Objective Activity Specific Objectives Cost Status (US$) ______I. Power subsector (i) Power Sector Propose institutional and Consultant recommendations for reorganization and Organization Study organizational changes needed separation of generation assets from restructuring - Phase I in order to maximize efficiency transmission and distribution assets and and effectiveness and to promote an effective regulatory arrangement have investment. 332,000 been accepted by GoK. (ii) Power Sector Propose specific steps to be 486,000' Draft final report has been prepared. Organization Study taken to implement the GoK to prepare action plan for - Phase 11 separation of generation from implementation of accepted transmission assets into separate recommendations. Action plan to be companies, in particular, the agreed with IDA prior to negotiations. organizational management, assets and financial restructuring of the existing companies and the required contractual arrangements. 2. Promotion of private sector (iii) Consultants services Pre-qualification of IPPs, 600,000 Bid documents have been issued. participation in generation preparation and evaluation of Requests for Proposals (RFPs) and assistance to the GoK during negotiations with qualified bidders. 3. Enhancement of the legal Legal and Regulatory Identify reforms necessary to 250,00 Draft final report has been prepared. and regulatory framework Framework Study achieve a reorganization of the GoK to prepare action plan for for the sector. power subsector, attract private implementation of recommendations sector investment and to Action plan to be agreed with IDA prior improve the sector's operational to negotiations. ______efficiency. 4. Deregulation of the (i) Petroleum Market Propose recommendations for 267,000 Study completed. Petroleum Subsector Petroleum Market Structure and reform of the procurement, deregulated in October 1994. The main Pricing Study marketing and pricing practices outstanding issue is the future of the in order to create a more refinery which is protected by a tax on competitive environment. imports until November 1996. Closure of refinery would require altemative sourcing of LPG. These issues are being addressed in the macroeconomic dialogue. (ii) Petroleum Import Assist MOE in preparing for the 27,000 Services in progress. Deregulation deregulated market, particularly with respect to its monitoring role. (iii) Staff Training Build capaciht for monitoring 50,000 Training completed. subsector activities after the deregulation of the petroleum market. TOTAL COST . 2,012,000
Financed under the Parastatals Reform and Privatization Technical Assistance Project. Annex 4.3 Page l of 5
KENYA
Energy Efficiency and Demand Management Component
Background and Context
I. The Government's overall strategy for energy efficiency, as expressed in its Letter of Sector Policy, addresses opportunities at four levels. First, the introduction of macro-economic measures relating to energy pricing and increased reliance on market forces, will foster an enabling environment for energy efficiency improvements. Second, to increase the efficiency on the supply side, the power utilities will implement a distribution system loss reduction program and install efficient generation facilities. Third. KPLC and the Manufacturers' Association will develop electricity demand management and energy efficiency programs. Fourth, recognizing that an appropriate institutional capacity is required to sustain energy efficiency programs, the strategy emphasizes local capacity building and technology transfer.
2. As a result of past energy efficiency initiatives, Kenya is probably on a better footing than many sub-Saharan African countries. However, many initiatives have been dependent on donor and Government financing, so their sustainability has not been granted. The history of low power tariffs has also impeded progress. The situation today is more promising, the new tariff policy, the power sub-sector reorganization, including greater commercial orientation and private sector participation will provide sound incentives for increased efficiency.
Objectives and Components
3. The objective of the energy efficiency component is to seek to develop and implement market based strategies and programs to promote more efficient energy supply and use.
4. The project has five components: (i) the KPLC efficiency improvement and demand management. program; (ii) a study to investigate how the availability, affordability and attractiveness of efficient electrical technologies could be improved through policy interventions at manufacturing, importing and marketing levels, for instance through the introduction of efficiency standards and an appliance labeling program; (iii) the Kenya Energy Management Program (KEMP), which is ongoing with the help of technical assistance by ESMAP (will not be described here); (iv) an energy efficiency workshop; and (v) program evaluation.
1. KPLCEnergy Efficiency Improvement Program
IA. Supply-Side Efficiency Improvements (Distribution Loss Reduction)
5. Although KPLC's aggregate system losses (16% of net generation) are not excessive, they are quite high in some parts of the transmission and distribution system, and without improvements, would increase to unacceptable levels. With the assistance of ESMAP, KPLC established an in-house capacity -- an Efficiency Improvement Unit -- which has established the level of system losses in Nairobi City and the Coastal Area, which collectively account for 70 percent of total system load, as follows:
6. Nairobi. As a result of a well configured 11 kV system supplied by seven 66/11 kV sub-stations, the peak power and energy losses in Nairobi's medium voltage distribution networks that contain the highest load concentration appear reasonable at present -- 2.6% for power and 1.8% for energy at present loading levels. But, in the absence of system improvements, the power and energy losses would increase to some 6.4% and 4.6% respectively over the next ten years. Annex 4.3 Page 2 of 5
7. Coastal Area. In the Coastalarea, where KPLCrely on long 33 kV feedersto supplyload concentrationsin and aroundthe MombasaIsland, the levelof peak power and energy lossesin the mediumvoltage distribution networks are some 6.4% for powerand 4.4% for energy. In the absence of systemimprovements the power and energy losseswould increaseto 11.2%and 8.2%. respectively,in ten years.
8. Basedon the abovefindings, KPLC has developeda lossreduction program for the Nairobiand CoastalArea systemsto be implementedas part of the proposedProject:
(a) Nairobi: (i) upgradingof II kV feeders,and installationof new feeders:(ii) replacement of capacitorson feeders;(iii) new 66/1I kV substationat Kiambuplus new feedersto link Kiambuto the LV network;and (iv) reinforcementsin the LV networks
(b) Coastal Area: (i) new 33/11kV sub-stationsat three locations-- Rabai,Tiwi. and Galu; (ii) II kV feedersto link the above sub-stationsto the existingLV network;and (iii) reinforcementsin the LV networks
IB. Demand-SideEfficiency Improvements (Demand Management)
9. The economicviability of loss reductionprograms, such as the installationof capacitorsto improvepower factor in the MV and LV feeders,usually can be enhancedwith the introductionof electricitydemand management (EDM) measures. To that end, and in order to alleviatethe effects of load shedding,KPLC's EfficiencyImprovement Unit are workingtowards integrating cost effectiveand complementaryEDM measures into their operations.The Unit is presentlyfocusing on EDMmeasures that would target industrialand commercialcustomers to improvepower factor, and shift demand away from the peak load periods.
10. To enhancethe level of KPLC's customerservice in energyefficiency, the proposedProject would providetechnical assistance to KPLC's EfficiencyImprovement Unit to: (i) build an in-house capacityon EDMto complementthat for loss reduction;(ii) apply their skillson-the-job, drawing on the extensiveinformation already gathered from the loss reductionwork to plan complementaryactivities on EDM;(iii) design EDM projects;and (iv) implementEDM projects and strategy.The proposedproject will financeconsultancy services and trainingfor this purpose. In addition,key energy efficiencypersonnel at the MOEwould participatein major trainingevents, while ESMAPwould financetraining to other organizationsand localconsultants under the KEMPprogram.
11. Trainingand CapacityBuilding in EDM. KPLCproposes to build its in-housecapacity for EDMwork through a "twinning"arrangement with anotherpower utilitywith an establishedtrack record in designingand implementingEDM programs. The trainingthat KPLCstaff would receiveunder such arrangementwould be supplementedby their participationin seminarsand workshopsand by visiting researchand other institutions.
12. On-the-JobTraining on EDMPlanning and Load ProfileSurveys. In orderto develop comprehensiveEDM actions, KPLCneeds to build up a disaggregatedemand management database. To this end, KPLCneeds to complementits feederlevel load data with additionalinformation on demand profilesand end-usepractices within the premisesof key customers. Therefore,using a similaron-the-job training approachthat was successfullyapplied by ESMAPto build in-housecapacity for lossreduction work, KPLCwill to engageEDM experts to assist in designingand carryingout customerload surveysand data collectionactivities to yield informationon: (i) daily load curves;(ii) load durationcurves; (iii) power factor at peak periods;(iv) load density;(v) load factors in key marketsand customergroups; (vi) market penetrationrates of electricequipment and appliances;and (vii) impactof poweroutages. KPLCwould carry out most of the requiredsurveys using its own staff so as to enhanceits EDMcapacity. A numberof Annex 4.3 Page 3 of 5
the surveys will also be contractedout to the privatesector, including local energy firms, and the ESMAP trained KAM professionalsin orderto create businessopportunities for increasedprivate enterprise deliveryof energy efficiencyservices in linewith the Government'spolicy.
13. EDM Program Evaluation and Development. The next step is to develop,evaluate and rank differentEDM optionsaccording to electricitysavings potential and cost-effectivenessto achieve KPLC's systemrequirements. The optionsinclude but are not limitedto (i) power-factorimprovement, (ii) load management;and (iii) end-useefficiency.
14. Power-FactorImprovement. The evaluationwill identifythe customerswhere power factor improvementwould reducedemand and developa programto install powerfactor correctioncapacitors eitherat the customerspremises or on KPLC'stransmission and distributionsystem.
15. Load Management.Primary load managementtechniques include tariff rates (e.g. specialtariffs for "interruptible"or "curtailable"supply) which discourageuse at times of systempeak; and directcontrol of customers' load. The technicaland economicviability of re-structuringKPLC's time-of-usetariffs and direct load controlto createincentives for customersto use electricityin a way that minimizesKPLC's supplycosts will be evaluated.
16. End-UseEfficiency. Dependingon the survey results,the investigationwould focus on programs to improvethe efficiencyof lighting,cooling, heating, water pumping,and electricmotors. These measureswould generallybe implementedand financedby the customersthemselves, but to reduce transactioncosts, KPLCwill design and fieldtest a numberof servicesthat it wouldoffer to assist key customergroups. Suchcustomer services include: (i) collaborationwith local energyefficiency programs, such as the KEMP,to providediagnostic services of electricityend-use practices; (ii) advice to efficiency improvinghousekeeping measures, and to introduceenergy monitoringand targetingsystems; (iii) design and implementationof action plansto assist customerseliminate in-plant power losses;and (iv) preparation of specificationsfor biddingdocuments that wouldbe appliedby customersto procuretechnical services from third parties to upgradeend-use efficiency.
17. Study on FinancingMechanisms. Some of the efficiencyimprovement measures would require consumersto investin retrofit measuresor equipment.The low implementationrate of the recommendationsof the past energy auditssuggest the existenceof fundingproblems and lackof incentives. As the cost-effectivenessof energy efficiencywill improvewith the increasedtariff levels, the issue of adequatefinancing mechanisms remains. Therefore,MOE in conjunctionwith KPLC, will carry out a study to map out sustainablemechanism for third party financingof efficiencyimproving measures, which may involve,for instance,leasing arrangements with industrialand commercialconsumers.
18. EDM ProgramImplementation. KPLC would initiallyimplement the following EDM programsthat would primarilytarget the Nairobiand Mombasaareas to integratethem to the programon distributionloss reduction.
* NairobiEDM Pilot DemonstrationProject. This pilot projectwould target industrialand commercialcustomers in a well defined area,for examplethose that are suppliedfrom the existing66/11 kV sub-stationslocated at IndustrialArea and Nairobi South.The primary aim is to encouragethe customersto improvepower factor levels,shift operationsaway from eveningpeak periods,and replaceobsolete and inefficientend-use equipment.
* MombasaEDM Pilot DemonstrationProject. This pilot projectwould target mainly commercialbut also industrialcustomers in the area suppliedprimarily from the Kipevusub- station and its networkof 33 kV feeders.These include hotels and other commercialloads that are suppliedfrom the existingLV network;and Annex 4.3 Page 4 of 5
* Western Kenva. KPLC would study the viability of extending the coverage of EDM measures to the Western Distribution areas, where the principal targets would include industries that also may have significant potential to contribute energy to the grid through co- generation.
* EDM Promotional Activities in the Commercial Sector. In order to demonstrate the cost effectiveness and economic benefits of energy efficiency improvements in commercial and institutional buildings, KPLC's demonstration activities would include: (i) the retrofit of KPLC's headquarters building, especially the banking hall in Nairobi with energy efficient lighting and promotional exhibits; and (ii) the retrofit of at least two other buildings which would be selected to reflect the KPLC customer mix in the Nairobi and Mombasa load centers. KPLC would also in collaboration with professional bodies to provide advisory to building owners, management companies and designers.
* EDM Promotional Activities for the Residential Sector. For the residential sector, KPLC's initial thrust would be to promote "good practice" in end-use energy efficiency through the activities of the existing KPLC Demonstration Center in Nairobi, which caters especially to women and students. The Center would be modernized and equipped with efficient lights and appliances, etc. It would set-up exhibits on efficient lights and other energy saving household devices.
2. Energy Efficiency Standards and Labeling Program for Electric Appliances and Motors
19. Objectives. This activity will support and expand on activities at the end-use level, in particular to address the question of how the availability, affordability and attractiveness of efficient electrical technologies could be improved through policy interventions at manufacturing, importing and marketing levels, for instance through manufacturing incentives, efficiency standards, and labeling and information programs. The objectives are to:
i Analyze the potential energy savings that could be achieved through improving the efficiency of appliances and motors;
- Identify the technical and policy measures needed to improve the efficiency of appliances and electric motors in Kenya;
* Analyze the implications of implementing such improvements in terms of the production changes needed, the effects on prices, impacts on import/export of appliances and motors, and institutional requirements;
* Analyze the cost effectiveness of implementing efficiency standards and a labeling program;
* If implementation of efficiency standards and labeling program is shown to be cost-effective, then select the most promising technologies and strategies (addressing issues such as financing and institutional responsibilities) for further action, and develop preliminary implementation documents, such as a draft set of appliance/motor efficiency standards and a proposal for a labeling program.
* Propose an effective legal/regulatory framework for implementing the proposed program.
20. Implementation. The activity will be implemented by MOE in collaboration with the Ministry of Trade and Industries (MOTI). A detailed project implementation plan will be produced following a Project Planning Workshop that will gather the major stakeholders including the Kenya Bureau of standards, Annex 4.3 Page 5 of 5
MOE, KPLC, MOTI, and organizations such as the Kenya Association of Manufacturers. The workplan will include components to:
* Review international experience with standards implementation; * Review current manufacturing and import activities, and market status; and * Review the national legislative and regulatory context (import tariffs, etc.);
21. Following the completion of the above activities and the production of the draft report, an Action Planning Workshop wi]l be held to present and review project outputs and discuss the further curse of action with all stakeholders.
3. Energy Efficiency Workshop
22. Once the survey data is available from the KPLC and KEMP energy surveys and audits, and the preliminary results has been obtained from the Efficiency Standards Study, a workshop will be held to discuss and disseminate the results and explore further options to improving efficiency. The workshop will target major energy users in the industrial and commercial sectors.
4. Program Evaluation
23. At the end of the third year of implementation, an independent audit and evaluation will be carried out to investigate the programs' effectiveness, customer satisfaction and propose a further course of action.
Implementation Arrangements and Estimated Costs
24. KPLC, MOE and KAM respectively will be responsible for the different sub-components as detailed in the table below.
Sub-Component Responsible Estimated Costs USS million Agency (inC.contingencies) Local Foreign 1 EfficiencyImprovement and EDM Program
a. Supply Side Efficiency (loss reduction) - Phase I KPLC 0.56 3.2 - Phase 11 KPLC 0.4 2.3 b. Demand Side Efficiency - Capacity building & training KPLC 0.1 0.2 - Load & market surveys KPLC 0.1 0.3 - Design & evaluation of EDM programs KPLC 0.1 0.3 - Implementation of EDM programs .Nairobi Pilot KPLC 0.1 0.6 Coastal Pilot KPLC 0.1 0.6 .Westem Kenya analysis KPLC 0.05 0.15 Commercial buildings KPLC 0.05 0.2 KPLC Demonstration Center KPLC 0.15 0.25 . Other KPLC and MOE 0.2 0.7 Study on financing mechanisms MOE 0.25 - Training of MOE staff MOE 0.05 - Training of local consultants KAM ESMAP ESMAP 2. Guidelines for Appliance Efficiency Standards and Labeling Study MOE 0.05 0.35 3. Kenya Energy Management Program KAM ESMAP ESMAP 4. Energy Efficiency Workshop MOE and KPLC 0.01 0.05 5. Program Audit and Evaluation KPLC and MOE 0.05 0.25 EstimatedTotal Cost(excluding ESMAP) 2.0 9.8 Annex 4.4 Page I of 8
KENYA
ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT
Description of the Power System Expansion and Rehabilitation Component
A. Power Generation
Kipevu Diesel-Electric Plant
1. Background. The desirability of constructing a large oil fired thermal generating plant on the coast of Kenya has featured in electric sector planning for a number of years. However, it was not until the 1990s that electricity supply/demandforecasts indicated a need to proceed with this new power project within a definite timetable. Currently loss of load expectation in the Kenyan interconnected system in an average hydrological year is such that shedding can be expected every day of the year. The design criterion is for load shedding to be expected in no more than ten days in a dry year. Consequently the system is now considerably less reliable than intended and in the event of a dry period occurring, or major failure of units, as has been the case at Gitaru hydropower plant, extensive load shedding will be required with the resulting adverse economic impact. New capacity in the range of 150 MW is therefore urgently needed to return the power system to somewhere near its design level of reliability. Screening analysis demonstrated that from among the potential candidate generation options considered (oil and coal fired steam plant; gas turbines in combined and open cycle; medium and low-speeddiesel engines; geothermal; and hydro projects) the diesel options are least cost for supporting the power system demand. The appropriate site for installing this diesel-electricpower station is Mombassa given the fuel supply requirements.
2. The rationale for the Kipevu diesel-electricproject are therefore threefold:
* to add further installed generation capacity in response to the country's projected increase in demand over the short-mediumterm; * to help achieve greater reliability, security and stability of power supply within the interconnected grid; and * to help produce a more satisfactorybalance between energy sources for electricity generation.
3. General Characteristics of the Power Plant. The Plant would be developed in two stages of 75 MW net each. It is planned that the first stage would be implemented by the public sector (KPC), while the second phase would be built, owned, maintained and operated by an Independent Power Producer (IPP). Electric power produced at this second stage would be purchased by KPLC through a Power Purchase Agreement (PPA).
4. The proposed power station would be located at Kipevu near the existing thermal power station. The area is restricted and hilly. Leveling will be done for both stages of the power station simultaneously. Site investigations, including appropriate borehole drilling, were carried out by a reputable engineering firm, and concluded that the hilltop area next to the existing power station has competent foundation condition for the new power plant.
5. Feasibility studies for the Kipevu Diesel-Electric Power Scheme were carried out by a reputable engineering firm. The feasibility-leveldesign calls for two adjacent power stations each with 12.5 MW medium-speed diesel-electricsets burning heavy fuel oil (No. 6 HFO). Net capacity of each station would be 75 MW. Fuel oil would be supplied via pipeline, either directly from the Mombassa Port nearby (less than 1.0 km) or from Mombassa Refinery (7 km). This provides dual sourcing and gives an enhanced level of security. Nevertheless, a strategic reserve of 30 days will be kept on site. The confines of the available site requires that a central fuel storage area be provided for both stages of the power station, with provision for separation within this area. It is proposed therefore that two bulk tanks be provided, each 900 cubic meters capacity, surrounded by a common bond and with individual designated unloading and forwarding Annex 4.4 Page 2 of 8 facilities. An emergency transfer line interconnectingthe two tanks would be provided to enable cross supply of fuel and to permit tanks to be emptied for maintenance. From the bulk storage tanks, fuel would be supplied to two large service tanks adjacent to the engine room of each stage, to await treatment. These tanks would be sized to hold 250 cubic meters. Similar tanks would be provided post-treatment, giving each stage 1.000 cubic meters on-site storage. Total strategic reserve would amount therefore for both stages together to 3,800 cubic meters.
6. Each stage of the power station would be self-contained,with separate engine rooms, auxiliaries and step up substations. The diesel engine will be driving directly coupled synchronous generators. A main supplying water from Mombassa runs near the project site. The quality and quantity of water is considered adequate to meet the need of a closed-circuit non-evaporative cooling water system and therefore it will not be necessary to provide a major water supply, nor a water treatment plant. The cooling system would be provided with air blast radiators.
7. Combustion air would be drawn from outside the engines powerhouse building, via intake filters to minimize intake of airborne dust particles and insects. An exhaust gas system would be provided for each diesel-electric set, which will include an exhaust heat-recovery boiler to provide steam or pressurized hot water to supply all fuel heating requirements. After crossing the heat-recovery boiler, the exhaust gases will be conducted to a common chimney stack for each stage of the power station.
8. Fuel oil and lubricatingoil sludge would be piped to a station collecting tank (one for each stage). From there it would be treated in a dedicated treatment system. Separated concentrated sludge would be discharged into an incinerator, while oily water would go to a separator. From this separator clean water would pass to the drain system and oil would be returned to the sludge tank for further treatment.
9. The fuel treatnent plant would draw fuel from the two heavy fuel pretreatment tanks. The fuel treatment will comprise two 100% duty fuel treatment modules in parallel. Each module would include fuel heaters and automatic fuel centrifuges.
10. Power generated in each stage of the power station will be stepped up to 132 kV. Generators will be connected in pairs via two-winding transformers to the gas-insulated 132 kV switchgear.
Within these parameters, specification of the exact unit size will be a matter for the tenderers, so long as the net capacity of each state is achieved. The general plant design must aim for: (i) high operating efficiency and low generating cost; and (ii) high reliability and long useful life.
II. Concerning the second stage of the power station, the terms and conditions of tender document will contain a Minimum Functional Specifications (MFS) for the plant, which will act as guide for bidders. Subject to complying with the MFS parameters, bidders will be free to propose the plant configuration, capacity and design which they wish, subject to space limitations.
12. Environmental Aspects. A comprehensive environmental impact assessment has been carried out by competent consultants. From this assessment it appears that the project would have the following adverse environmental effects that would need to be mitigated: (i) emission of contaminants from fuel combustion; (ii) noise from engines operation and from air-cooled radiators; (iii) oil spill accidents; and (iv) sludge from fuel and lube oil
13. The measures that would need to be taken to mitigate these environmentally undesirable effects, are the following:
* contaminants emissions would have to meet World Bank guidelines; in addition, the exhaust gases after cooling in heat-recovery boilers would be dispersed by means of high stacks (minimum 60 m high); contaminants dispersion would be aided by the fact that the power station would be sighted on a high bluff receiving sea breeze; Annex 4.4 Page 3 of 8
* engines air intakes and exhaust would be equipped with silencers adequate to meet noise level requirements around the power station building. Control room would be sound- proofed, and sound proof booths would have to be provided in the machine halls. Silencers would be adapted to air-cooled radiators. In addition, the power plant would be screened by rows of trees; * oil spills would be contained by appropriate bunds around tanks; and * sludge from fuel and lubricant would be treated and after separation burned in incinerators.
Third Unit at Gitaru Hydropower Plant
14. The existing powerhouse at Gitaru Hydropower Plant is underground with two 72.5 MW generating units. Provision was left in the original design for the future addition of a third unit. Penstock with bolting flange for turbine intake and draft turbine connections including gates have already being installed. The work to be done in order to commission the third unit consists of: (i) Turbine; (ii) Main inlet value; (iii) Generator and exciter; (iv) Concrete for embedded; (v) Low voltage switchgear; (vi) Bus duct to main transformer; (vii) Main generator transformer; (viii) Auxiliaries, pumps, etc.; (ix) Control panels and relays; and (x) B2kV switchgear with breaker and isolators.
15. January 1995, a fault develop in one of the generators forcing shutdown of the unit. The fault, apparently due to aging of the varnish covering the stator core steel sheets at core joints, thus causing the development of hot spots due to the eddy currents generated. The stator windings suffered consequent damage from these hot spots, until failure of the insulation resulted. Repair work took about a year and was completed in March 1996. The units at Gitaru are the largest in KPLC power system and the prolonged outage of one of the units has adverse effects on the power system ability to meet peak demand and has forced load shedding measures. Moreover, recent tests on the faulty generator have detected flaws in the generators stator core joints. Therefore, on recommissioning,the unit could not be restored to its full rated output of 72.5 MW without risking further faults. The other generator will also require inspection to ascertain the state of the generator stator core. Indicationsat the moment are that the faulty unit would have to be limited to a maximum load of 60 MW, the KPLC power system would have serious constraints. The installation of the third unit, therefore, becomes an unavoidable necessity. On average, Gitaru Power Station produces 840 GWh per year with both units in operation. With only one unit, as has been the situation in 1995, the power station will generate about 500 GWh per year. The loss in energy production from a fault in one unit is a minimum of 340 GWh a year while the defect is corrected.
16. Commissioning of the third unit for Gitaru Hydropower Plant would result in the following effective capacity of: (i) 2 x 60 MW plus I x 70 MW= 190 MW; and (ii) 763 GWh from original units plus 112 GWh from the third unit for a total of 875 GWh per year.
17. The addition of a third unit at Gitaru would have no detrimental environmental impact. Procurement of the unit would be by ICB. A span of 3 years is foreseen for design, tendering manufacturing, transport and installation.
Olkaria II Geothermal Power Plant (2x32 MW)
18. The Olkaria If power plant - with an installed capacity of 64 MW in two units of 32 MW - will be located at the northeast part of the Olkaria geothermal field. Steam will be collected from the steamfield - already developed with 29 wells (out of which 20 are capable of providing steam for 78 MW - an average of 3.4 MW/well). Reservoir engineering studies indicate that the geothermal field can support the electric power generation of 64 MW during the life of plant i.e., 30 years, with pressure and temperature within the required values for power generation and without detrimental impact upon the production of the existing Olkaria I power plant. The non-productive wells will be utilized for the reinjection of the residual waters. Steam separation will be carried-out at a number of sites around the geothermal field and steam transmitted through the gathering system to the steam turbines at the power plant. The non-condensable gases will be dispersed through the cooling towers. Annex 4.4 Page 4 of 8
19. The plant will be of a modified modular type. In a modular geothermal power plant, the upward exhaust turbine, gets to the site tested and assembled in a module, the generator is modularized separatelv with the rotor assembled in the stator, and the direct contact condenser mounted outdoors, everything installed on a concrete floor using a low level arrangement. The idea is to avoid as much as possible the excavations and civil works required by the conventional arrangement. KPC and its consultants, as a transition from the conventional design to the modular concept, accepted most of the modularization except in two aspects: (i) all equipment, except the condenser is placed indoors in several buildings carefully designed to blend with the environment of the Hell's Gate National Park, and (ii) the commonly used direct contact condenser was changed to a condenser with a barometric leg requiring a seal pit.
20. The designs of the civil works specify a power house superstructure with reinforced concrete columns and concrete beams for a traveling crane. Deep piled foundations for all major structures are required and thus specified. In addition, the project civil works include the provision of 65 staff houses, comprising 36 junior staff and 29 senior staff.
21. The steam transmission or gathering system designs were based on the prediction of the 20 wells selected for production. The current design proposes the use of separators with integral water drums. The separators have been standardized for three steam flow capacities 25, 50, and 100 tones/hour. The design specifies three separator stations of 25 t/h, seven of 50 t/h, and three of 100 t/h. Using these dispersed number of separator stations minimizes the amount of two phase flow and corresponding losses. Motorized wellhead flow control valves will be installed. Discharge silencers will be provided at each separation station.
22. The design of the reinjection sy'stemcomtemplates only cold reinjection of the waters from the separator stations. The residual waters will be conveyed by steel gravity pipes to two main conditioning and cooling ponds. From these ponds the fluids flow to the main overflow pond and a reinjection sump from which they will be pumped to the reinjection wells. The reinjection system will be refined to included a hot reinjection system - which will become the primary reinjection system. In the hot reinjection system, the hot waters from the separators will be conveyed directly by steel pipes to the reinjection wells (wells R2 and R3 are already available), without passing through the silencers and the cooling ponds. With the hot reinjection system, the well head pressures are improvedthereby prolonging the life time of the system. A system with both hot and cold reinjection improves the management of the reservoir and provides greater flexibility of field operations.
23. The designs of the electro-mechanicalworks include: (a) a single flashed steam condensing turbine cycle; (b) two 32 MW single shaft, single flow turbines, mounted at ground level with the condenser located adjacently; (c) a barometricalily drained condenser into a seal pit, where vertical shaft pumps will pump the condensate water to the cooling towers; the condenser will incorporate an integral gas cooler; (c) a steam ejector or gas extraction system which will disperse the non-condensable gases through the cooling tower plume; (d) mechanical induced draught cooling towers aligned parallel to the prevailing wind direction will be provided as well as (e) two electric generators with an output capacity of 32 MW at a power factor of 0.8, that will generate electricity at II KV.
24. The power plant will be connected to the national grid at 220 KV through a 220 KV substation located adjacent to the plant. A double circuit 220 KV line will feed power to a new substation in Nairobi (Nairobi North) and the existing Dandora 220/132 KV substation that will be extended with additional bays. A 132 KV line will interconnect the existing Olkaria I plant through a 220/132 KV, 80 MVA autotransformer with the substation at Olkaria I. Both 132 and 220 KV lines will be strung with Canary ACSR conductors with one conductor per phase giving a rating of 282 MVA per phase at 220 KV. Steel lettice towers will be used with vertical configuration for the double circuit 220 KV lines and with triangular configuration for the single circuit 132 KV lines. The substations will be constructed as double busbar with one-and-a-third circuit-breaker configuration. Circuit Breakers will be of the SF6 or minimum oil type. Annex 4.4 Page 5 of 8
Olkaria III Geothermal Power Plant
25. The Olkaria III Geothermal Power Plant, to be implemented in the Olkaria Southwest sector of the Olkaria Geothermal Field (an area of approximately 7 square kilometers), is expected to be similar to the Olkaria 11Geothermal Project described above'. As indicated before there are 4 productive wells and two additional wells (wells OW-308 and OW-102) being drilled by KPC. The electrical connection to the national grid of Olkaria III will be a simple line interconnectionbetween the Olkaria Ill step-up substation to the 132 KV side of the Olkaria 11power substation.
26. This project is being offered to independent power producers (IPP's) for development. The project scope that would be carried out by the successful IPP include: drilling and testing of the production field (includes reservoir engineering studies); design and construction of the power plant and the design of the electrical interconnection to the Olkaria II substation; and finally the operation of both the well field and the power plant to comply with the terms of a purchase power agreement that would be entered between the IPP and KPLC.
Support for Olkaria I Geothermal Power Plant
27. The East production field, as indicated before, supports an installed capacity of 45 MW (Olkaria 1). As is normal in all geothermal fields there is a decline of pressure and steam rate as a consequence of exploitation of the resource; the rate of such decline depends on the specific characteristic of the field being exploited. In the case of the Olkaria Field, the experienced decline is about 4% per year. The production of Olkaria I, as a consequence of the indicated phenomena, decreased to 29 MW some few years ago. Now with the connection of several make-up wells, the power output of the power station has been restored to full capacity.
28. The proposed "Support for Olkaria I Geothermal Power Plant Project" consists of: (a) the connection of two additional wells (already drilled), plus (b) the drilling of four new wells, to be later connected by KPC, using its own resources, to the gathering system of Olkaria 1, with an independent contractor.
EnvironmentalAspects
29. The Environmental Assessment and related environmental analysis following the Bank policies and procedures regarding EA's was carried-out by a specialized consulting firm in 1992 to provide information on the following matters: (a) the existing environmental baseline conditions; (b) the potential Environmental impacts, both direct and indirect; (c) the identification of preventing, mitigating and compensating measures; (d) environmental management and training; and (e) monitoring.
30. The environmental impacts of using geothermal energy for power generation are generally related to impacts on: (a) air quality; (b) water pollution; (c) land disturbance; (d) aesthetics or visual impacts; (e) noise; and (f) socio-economic aspects. The main findings of the EIA study on these aspects are summarized as follows:
31. Air Quality. The gaseous elements carried out by the geothermal steam are discharged to the air, depending on the characteristicsof the particular resource, problems may arise. In the case of the Olkaria NE resource the non-condensable gases consist mainly of carbon dioxide (up to 96% of volume) and small amounts of hydrogen sulfide (up to 5%), plus very small amounts of hydrogen, methane, and nitrogen. In
In the area assigned to Olkaria III, the field still has to be explored with additional geoscientific work and exploratory/production drilling. The additional wells will have to be strategically located in the field in accordance to the conceptual geothermal model. After drilling a sufficient number of wells, a detailed reservoir engineering analysis will have to be executed to determine the generating capacity that the reservoir in that area can support. Annex 4.4 Page 6 of 8 the Olkaria 11power plant, these gases will be dispersed through the cooling tower plume. Modeling calculations indicate that the dispersion obtained is good and the concentrations will be much less than those registered with the existing Olkaria I power station.
32. The modeling calculations also indicated that concentrations of H1S in most settlements will reach the same levels of the current situation, except in the existing X-2 camp in which the threshold for odor detection will be increased by 40%. For this reason it was recommended that the X-2 camp be relocated outside the Hell's Gate National Park. This recommendationhas been accepted and the cost of the relocation has been included in the cost of the project. Moreover, it is important to note, that ground level concentrations were found below those levels that could adversely affect the health of workers and local population. Another minor recommendation on air quality relates to the need for continual monitoring of the local flower growing areas.
,3. Water Pollution. The main problem that could be derived from geothermal power stations is related to the handling of the geothermal residual fluids. High temperature reservoirs, greater than 2300C - the case of Olkaria - produce waste water containing an extensive menu of dissolved minerals. The elements of most concern are fluoride, arsenic, and lead. Although by world standards the Olkaria geothermal brines are not particularly toxic, it does exceed health-based water quality goals and needs to be disposed of in a safe manner. The current method of disposing of the geothermal brines into gullies and natural drainage lines, currently practiced in the existing Olkaria I station are inappropriate since serious erosion has been caused in some areas.
34. In the Olkaria 11geothermal project, as explained before, all residual waters will be reinjected into the geothermal reservoir, using several non-productiveor specially drilled reinjection wells. Reinjection not only is an environmental sound way of disposing of the waste water but also has a positive impact on the maintenance of reservoir pressure and steam rates over a longer period of time.
35. Since the whole geothermal operation depends from abstraction of fresh water from neighboring Naivasha lake, and although the amount taken by KPC is only around 3% of total abstraction, it was however recommended that KPC monitors the lake level variation (long term).
36. Land Disturbance. As indicated before, the geothermal development is within the Hell's Gate National Park which present a host of animal life. In order to minimize the disturbance of the habitat there will not be a perimeter fence around the whole complex. Only individual well heads will be fenced, and the power house and substation will have their own perimeter fences.
37. Where drilling operations have been completed the larger area required to accommodate the equipment will be restored to its original state.
38. No impacts have been experienced with the current operations of Olkaria I on the local flora. The situation with Olkaria 11is further improved since all waste waters will be piped instead of ditched. This will prevent new vegetation to occur in the neighboring areas.
39. Aesthetics or Visual Impacts. The choice of the Site A versus an alternative Site B, for the power station was taken despite its greater visual impact. This impact will be mitigated by the construction of embankments around the station, the planting of trees and appropriate architectural designs of the buildings that make up the power complex.
40. Noise. Noise measurements indicate that present drilling operations have a very low noise level in the range of 24 to 34 DB(A). The power station operation, test drilling, and well head operations will generate noise levels above this type of background noise detectable specially at night. The only major impact on any residential area is in the existing X-2 camp where noise levels will be increased to about 43- 50 dB(A), during the well testing phase, but as mentioned before, the camp will be relocated. There will also be a noise impact during the construction phase of the power station but it will be a temporary problem. Annex 4.4 Page 7 of 8
41. Socio-EconomicAspects. The EnvironmentalAssessment concluded that the project would have a significant impact on the socio economic of the surroundings. It was considered necessary that KPC provides all necessary accommodation and infrastructure because the local towns would not be able to accommodate the workforce during construction and later during the operation of the station.
42. The long term impact on tourism was not considered a major problem. Indeed many tourist considered such a development and attraction rather than a detraction.
43. The recommendationsof the Environmental Impact Assessmentwere incorporated in the ..Agreement on Geothermal Development in Hell's Gate and Longonot National Parks" entered between the Kenya Wildlife Service and The Kenya Power Company LTD on September 20, 1994. All activities are now executed under the terms of the Agreement. However, still pending is the relocation of the existing camp X-2 outside the boundaries of the park.2The cost of this relocation are included to be financed within the Energy Sector Investment Project. The architectural and civil engineering designs for the Olkaria 1I residences have been adopted for the new X-2 camp.
Implementationof the Geothermal Components
44. Organization. The geothermal components will be implemented by KPC (generation); the transmission and substations financed with Olkaria II will be implemented under the supervision of KPLC (transmission and distribution). For Olkaria [I a project management team will established under the Geothermal Development Coordinator, who reports to the Chief Project Development Manager. The project management team will use the services of the existing units of the Office of the Geothermal Coordinator, namely, the Procurement Unit and the Project Procurement, Monitoring and Control Unit. Through the Office of the Chief Project Development Manager, the project management team obtains the services of the Finance Department for matters relating to disbursement and payments to contractors and consultants
45. For the implementation of the Olkaria 11project, a Consultant Firm will be contracted. This firm selected among a short list firms, previously approved by IDA, will assist KPC during the bidding process as well as for supervision of construction which includes factory inspection, as-built designs and the testing and commissioning of the power plant. The Operation Division of KPC will assigned three engineers to work with the consulting firm in field supervision of construction and assembly of power plant equipment
46. The Implementation Schedule of Olkaria 1I shows that the project requires 39 months or 3 114 years of execution after the eligibility of the loan and/or the tendering process are initiated. The critical path of execution is conformed principally by the contracting and manufacturing of the electromechanical equipment, interrelated with the civil works. Because of this fact, project managementand engineering is critical in assuring that the contractors for the civil works contract and the electromechanical equipment contractor do not interfere with the schedule of the other.
47. The Implementation Schedule of Olkaria 111,if negotiation with the private sector are successful, considers that it will be executed in parallel and during the same period of time as Olkaria 11.
48. The relocation of the X-2 camp will required three years and half. One year for contracting and engineer/Architect firm to prepare the studies and designs, and the remaining two and half in the contracting and construction of the works.
B. DistributionSystems Reinforcement
2 Another important requirement is the reinjection of the residual waters from both the field and the cooling system. This however will be implemented during the construction of the power plant and the gathering system. Annex 4.4 Page 8 of 8
49. KPLC intends to carry out a program to reinforce primary distribution (subtransmission) in Nairobi and in the Coastal Area, particularly around Mombassa. The program in Nairobi would essentially complete the 66 kV ring around the city and expand the 66/11 kV substation capacity feeding into the II kV feeders network.
50. Nairobi. The Nairobi System receives power at 132 kV and 220 kV from Juja Road, Ruaraka and Embakasi substations all located on the outskirts of the city. Transfornation to the primary distribution voltage of 66 kV is done presently at these three substation. Fifteen 66/11 kV primary distribution substations are located in and around Nairobi.
51. The method used to forecast demand was developed by KPLC consultants and used in the National Power Development Plan. This method relates energy sales for various categories of consumers to the related sectorial GDPs, historical sales and projected tariff increases. By imputing the Nairobi area sales figures and the national economic data up to 1994, and the projected GDP growth rates for future years, the area total sales and peak demand were forecasted. From peak demands forecast, the annual growth rate for the total area load is obtained. The calculated growth rate is then applied to all the individual substation loads with appropriate adjustments.
52. Reinforcement required for each of the existing substations was determined on the basis of having a firm transformer capacity available at each substation, i.e. transformer capacity sufficient minus one transformer to accommodate the expected load. Location and capacity of new substations was also determined, as well as reinforcementor new 66 kV lines. A number of arrangements for the 66 kV grid were then compared on the basis of their benefit/cost ratio. The increase in grid capacity is costed at the Long Run Marginal Cost (LRMC) attributable to HV and MV reinforcements. The LRMC in this case has been calculated by KPLC's consultants at USSO.O18per kWh.
53. Within the selected option for reinforcement of the Nairobi Grid, the program for the period 1996/97-2000/01 consist of the following works: * Limuru 66/11 kV Substation, install 2 x 15 MVA transformers; * Kikuyu 66/11 kV Substation; install second 10 MVA transformer; * Parkland 66/11 kV Substation; install 2 x 45 transformers; * Juja-Parkland 66/kV line; reconductor of 2x6.5 km; * Embakasi - Nairobi West 66 kV line; reconductor of 2x3 km; * Juja - Jeevanjee/Bahati 66/kV line, construct 1.0 km of double circuit line; - Parklands-Catedral66 kV cable, install 2.5 km of cable; * Nairobi West - Karen - Kileleshwa 66 kV line, construct 5.5 km of line; * Bahati 66/11 kV Substation;establish new substation with 2x23 MVA transformers; and * Kileshwa 66/11 kV Substation; establish new substations with 2x23 MVA transformers.
54. Coastal Area. The study for the reinforcementof the 33 kV and 132 kV primary distribution grid in the Coastal Area, was carried out by KPLC using the same approach as for Nairobi. The reinforcement program thus established for the period 1996/97-2000/01comprises the following works:
* Nyali 33/11 kV Substation, install 23 MVA transformer; * Gede 33/11 kV Substation, install second 7.5 MVA transformer; * Miritini 33/11 kV Substation, install second 7.5 MVA transformer; * KPR 33/11 kV Substation; install second 7.5 MVA transformer; * Kipevu 132/33/11 kV Substation; install 23 MVA transformer; * Diani 33/11 kV Substation; install 23 MVA transformer; * Rabai-Diani 132 kV line; construct 45 km and install 45 MVA Substation; * Likoni 33/11 kV Substation; install 2.5 MVA transformer; * Kipevu 132/33/11 kV Substation;install second 23 MVA transformer; and * Shanzu 33/11 kV Substation; install 23 MVA transformer.
55. Equipment already in stock, mainly transformers, represents about US$12 million. Some shifting of transformers between substations would also be done. Annex 4.5 Page 1 of3 KENYA
Description of the Resource Assessment Component
I. The 1992 updated National Power Development Plan prepared by Acres International recommends the addition of about 493 MW of geothermal power capacity up to the year 2011'. The corresponding least-cost Development Plan requires that two units of 32 MW (units # 6 & 7) come in line by the year 2001, and another two units (units # 8 & 9). of the same capacity, by year 20032. To achieve these ambitious long and short term objectives, requires a continuous program of surface investigations,drilling and well field development, along with the design, financing, tendering and construction of power plants. The Geothermal Resource Assessment Program included in the "Energy Sector Investment Project" can be subdivided in two sub-components,as follows: (a) Field Development and Feasibility/Detailed Design for Olkaria IV or Olkaria III & IV, and (b) Advanced Pre-feasibility Studies at Olkaria Domes and Suswa, and Pre-feasibility Studies at Longonot and a New Area. The descriptions of these components follow:
A. Field Developmentand Feasibility/Detail Designs for Olkaria IV or Olkaria III & IV
2. The Field Development Activities proposed, within the Geothermal Resource Assessment Program, were established to comply with the stated objectives of the National Power Development Plan and the "normal geothermal development criteria " followed by the geothermal industry in other developing countries.3
3. The proposed Base Field Development Program considers the drilling of 26 wells. This does not comply strictly with the described "normal development criteria", since under normal circumstances only 11 wells would have been required to prove the feasibility of the Olkaria IV geothermal project. The departure from the normal practice is justified with the following considerations: (a) the need to develop the field of the next geothermal power plant (Olkaria IV) to ensure its implementation by year 2003; and, more importantly, (b) the need to establish an Alternative Program - with the same cost as the Base Program - as a back-up, in case that negotiations with the private sector for Olkaria III are not successful; in this instance, the Govemment of Kenya will be confronted with the need to prove feasibility for the two projects to secure their financing and implementation.
4. With the proposed Altemative Program, 11 wells will be drilled in each of the two areas assigned for the Olkaria Ill and IV geothermal projects - a total of 22 wells - plus the preparation of the feasibility level studies and designs of the corresponding power plants. The Alternative Program thus established follows strictly the described "normal geothermal development criteria" followed by other geothermal developing countries.
B. Advanced Pre-Feasibility Studies at Olkaria Domes and Suswa, and Pre-Feasibility Studies at Longonot and a New Area
I The probable generating capacity that can be supported by the geothermal resources of the country still has to be demonstrated.
2 Due to the delays incurred in funding the current Program it is doubtful that these additional units can be commissioned by the indicated years.
3 Following common practice or "Normal Process" ,the geothermal fields are developed to a level of 30% of the steam required for full production of a given generating capacity, and, utilizing the geoscientific data of the drilling campaign, the surface geoscientific studies are upgraded, thus obtaining an improved geothermal conceptual model and a detail synthesis map of the geoscientific anomalies.The studies related to the geothermal field, complemented with reservoir engineering studies and power plant and gathering systems feasibility level designs - including cost estimates - constitute a feasibility report adequate for seeking the financing for the implementation of the project. The detail designs (tender level designs) are prepared during the year in which the financing is sought and negotiated. Annex 4.5 Page 2 of 3
5. Surface exploration will be concluded in Olkaria Domes and Suswa and in the areas of Longonot and in some new area in the north (probably Menengai)with KPC own resources. A slim-hole drilling Program will be carried out in Olkaria Domes and Suswa. It includes the drilling, in each of the indicated areas of six temperature gradient holes (500 meters depth), and 3 deep (2,500 meters) slim holes. These drilling activities will be done with a drilling contractor.
6. To support KPC scientific geothermal activities, it was agreed to include as part of this component, the financing of an Advisory Board integrated by six recognized international geothermal experts. The respective specialization of the six experts will be as follows: (i ) geothermal exploration in the discipline of geology volcanology: (ii) geothermal exploration in the discipline of geochemistry and geophysics, (iii) geothermal field development. which includes drilling engineering, well test and reservoir engineering; (iv) geothermal plant design and installation, which includes mechanical,chemical, electrical and construction engineering; (v) management and operations of geothermal projects, which includes project planning, production engineering, financing and financial control, and (vi ) environmental science, which includes hydrology, meteorology, biology and sustainable development
7. To support KPC drilling operations, the project would include the financing of the purchase of equipment (vehicles, tractors, scientific instruments, drilling equipment spare parts, excavation equipment, well testing equipment). drilling services and repairs, training and the preparation of feasibility and other geothermal studies, and the contracting of drilling services.
8. KPC with its own resources will purchase local materials and services as spares, environmental materials (trees, plants. etc.), water supply system maintenance (spare and services), water pipeline for drilling operations, and land acquisitions.
Implementation
9. Organization. The Advance Pre-feasibility level studies, and Field Development Program for additional units in the Olkaria Geothermal Field, included in the Resource Geothermal Assessment Program, will be carried out by the Geothermal Development Manager's Office at Olkaria. This Office has under its supervision the Team of Geoscientists and the Drilling Crew Operations,who will supervise the slim drilling operations that will be contracted with a private drilling company. The Geothermal Development Manager reports to the Geothermal Development Coordinator. As support for the indicated studies, an Advisory Board integrated by six recognized geothermal experts in the different disciplines that enter into the studies of a Geothermal Project, will assist KPC in all areas of the Geothermal Program of the Project, but especially in the Resource Assessment and Field Development Areas. The Advisory Board will review the studies and reports prepared by KPC Geoscientists. The recommendations of the Advisory Board agreed during the Advisory Board meetings will be mandatory
10. A geothermal consultant firm or firms, following IDA's procedures, will be contracted for carrying out the feasibility level studies that will be completed, after a pre-approved number of commercial diameter wells have been drilled4. The supervision of feasibility level studies fall under the leadership of the Office of the Corporate Planning Manager. This Office will have the support on geothermal matters of the Offices of the Coordinator of Geothermal Development and the Staff of Scientistsof the Geothermal Development Manager, and of the Advisory Board of international experts. All described arrangements are considered satisfactory for the implementation of the geothermal components of the Energy Sector Investment Project.
I1. Implementation Schedules. In accordance to the Implementation Schedules the Geothermal Program requires four year years for its execution and four and half year for loan disbursements, after the loans are declare effective. The most important aspects of the Implementation Schedules are summarized as follows:
4These wells will be drilled by KPC 's drilling crew, utilizing an existing drilling rig which will be overhauled with resources of the program. Annex 4.5 Page 3 of 3
12. The Implementationfor "Support of Olkaria I" and the "Geothermal Resource Assessment" can be grouped as a single program of procurement of services, materials and equipment/instruments.The procurement activities of this group have been divided in two round of activities, the first round covers the needs of materials/equipment and services for approximately II wells for 2 years. The second round for the remaining two years. Under this group the development drilling for Olkaria IV or III and IV and the feasibility studies of these projects will be concluded in the indicated four years: the Pre-feasibility level studies of the other geothermal areas are also concluded during the fourth year of activities. Annex 4.6 Page I of 2
ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT
RURAL & HOUSEHOLD ENERGY DEVELOPMENT STRATEGY
Introduction
Woodfuel and agriculturalresidues are estimated to account for about 75 percent of the total primary energy use. According to the most recent bousehold energy use survey, which was carried out in 1980. about 95 percent of the domestic sector's energy demand was met bv firewood, charcoal and residues. During the 1980's a number of bilaterally funded household energy activities have been implemented, including the development of efficient cooking stoves, agroforestry, and biogas and wind energy development. Currently, however, no reliable data exists of the woodfuel demand and supply situation, or of the impact of the activities in the sub-sector. The Government,therefore, has decided to develop a Rural and Household Energy Strategy to accelerate the access to sustainable and affordable energy by lower income rural and urban households.
Objective
Theobjective of this activityis to developa Ruraland HouseholdEnergy Strategy, including a priorityinvestment and technicalassistance program to efficientlyaddress the energyrelated problems of mediumand low incomehouseholds.
ActivityDescription
Tbe projectcomprises the followingthree sb- o . (i) HouseboldEnergy Use Survey;(ii) EnergySupply and MarketingStudy; and (iii) Policy,Institutional and Pricing Study.
Household Fnergy Use Survey
Objective. TMeobjective of theHousehold Energ Use Surveyis to obtaindata of energyuse in households.The survey will targetmedium and low imcome households in ruraland urban areas. Specifically,the surveywill estabih te typesof energyused (firewood,charcoal, agricultural residues, kerosene,LPG, electicity, solar,etc.), quandtiesused, type of end-useby fuel, sasonalvariatios in fuel use and fuel availability,equmet used, houehold'sener expenditure,whether fuel is purchasedor collectedfree of charge,where uel is purcsed ad collected,supply constains andother problems encounteredby the householdsrelaed to tei enerV use (health,envirounme). The uv will also seek to obtain informationof householdsenery cosrvationawazeu, use of energUefficiet equipment,and reasons for not usig energyeffint equipmt. In addition,the surveywill obtain informaton of household attitudestoward fuel swihing and how the hoseoldsperceive the availabilityof alternativefuels and their possibilitiesto switchto alternativefuels.
Saple andSurvey Mehod. About100 bouseholds will be interviewedin 10-15districts and 3-5 urban centers in order to identify differences between urban and rural households and between different ecologicalareas.
Energ S=p,F and Makting Sr
Objecnve. The objectiveof the EnergySupply and Marketing Survey is to establishthe seasonal availabilityof fuelwoodand modernfuels in the areas of the householdsurveys, the originof firewoodand charcoalsupplies, the fuelsupply chai, nd prices. The surveyalso aims to establishchanges in fuel Annex 4.6 Page 2 of 2
consumption and availability over the past years. The study will build on the existing data, for instance the Kenya Forestry Master Plan.
Survex Method. Interviews with fuelwood vendors, petroleum products distributors, forestry officials, NGOs, and others. The interviews will be conducted in parallel with the Household Energy Use Survey. A sample of the areas will be selected for a second survey to caprure seasonal availabilinyof fuel more accurately.
Policy. Istitutignal and Pricing Stidy
Objective. The objecti-veof the Policy, Institutional and Pricing Study is to: (i) identify and evaluate the policies that influence the household energy sub-sector today; (ii) identify barriers to energy conservation and fuel switching; (iii) evaluate the impact of the policy reforms in the petroleum and power sub-sectors on the household energy sub-sector; (iv) how can markets be tapped in such a way to encourage a shift from non-sustainable, mostly land clearance operations to sustainable tree growing or forest/woodland management initiatives; (v) propose changes in the policy, and pricing frameworks to promote sustainable and affordable energy supplies to medium and low income households (including energy conservation and fuel substitution), and (vi) assess the capacity of the various institutions (GOK, NGOs, private sector) to address household energy issues effectively and propose improvementsas required. The study will also evaluate the impact of the past activities in the household energy sub-sector (both supply and demand side).
The study will result in the development of a strategy for implementing the proposed policy reforms, and in outlining investment and technicalassistance programs.
Implementation Armngements
The Ministry of Energy will have the implemenation responsibility. The samplng, interviews, coding of responses, quality control of responses, computerization of responses, and production of results will be carried out by consultanttsand the Central Bure;..i of Stistics. An international household energy expert(s) will be engaged to asist MOE and CBS m projectdesign, questonnairedesign, sampling; enumerator training; repordng; and to cary out the Policy, Instiuonal &adPricing Study.
Staffing
IntenmationalExperts (householdsury specalist ad househol enery specialit) National Experts CBS MOE Anncx 4.7 Page I of I
PROJECTrCOMPONENTS B)' FINANCIERS (UJSSmillion)
Kenya EnergySector Invfetment Project Conponensby Finuncimra (USS 000) GOK IDA OECF Pri-te Equity Comn.er.a.IDebt EIB KIW Toal Local(Excl Dules& Amwnt % Anout % Ameou.t % Amount % Amount % Amount % Amontm % Amoumt For E-ch ianes) tlses
A SectorRestructuring Reform SectorReorgtpmattion 3,2S310 100 - - 3283 10 0 5 3,28310 Dercgulationof PetroleumProduct -s 3432 100 - . . . 6 50 6 SubtotulSectorRestrucurmgReform - - 3,63130 100 ------363-u 303 05 3.5S070 506 B Insatnut.onalSupport 18,48610 751 6,12710 24 9 . . . - 24613 20 35 22143 50 2.46970 C EfficiencyImprovements Dem5ASide Improvememt 0 - 5,36980 100 - - - - - . 53690 0 8 5,28400 85 a LineLotReduction 1425 22 6,30940 978 - - . . , 6,45190 09 5,49200 9599 SubtotalEfficiency Improvement 1425 12 11,67920 988 11,82170 1 7 10,77600 1.04570 D PowerEpansmon and Rehatiubtuon PocerGeneration 93,99360 161 S2,35150 142 82,0740 296 65,62540 113 196.87630 340 36.62020 63 20,85250 31 S79,12690 827 472.68780 106.43900 Upgradingof DistributonSystens 29,94340 100 ------29,94840 4 3 14,97420 14,97420 SubtotalPomec E.pamonand Rehtoat,on 123.94210 194 S2,35150 135 82,80740 285 65,62540 108 196,87630 323 36,62020 60 20.85250 34 609,07530 87 487.66200 121.41320 E eotlhermm1Resource Dcelopment 17,52380 35 6 19,70920 40 - - - 12,05360 24 5 - - 49.2S660 70 44,45620 4.85040 F FutureProject Preparation - - 1,50310 100 - - - - 1-503 10 0 2 1 5031 - Total 16borsmeotIt0,094.50 21.5 125,001.40 17.9 32,t07.40 25.5 65,625.40 9.4 196,.76.30 9.4 48,673.80 7.0 20,852.50 3.0 69,931,20 IO0 570,121.50 129,809.70
41,sJ0. Annex 4.8 Page 1 of 1
PROJECT COMPONENTS AND EXPENDITURES BY YEAR (US$ million) Kenya Energy Sector Reform and Development Project
Totals Including Contingencies 1997 1998 1999 2000 2001 2002 2003 Total
A. Sector Restructuring Reform Sector 1,500.5 891.2 891.4 - - - - 3,283.1 Reorganization Deregulationof PetroleumMarkets 348.2 - - 348.2 Subtotal Sector Restructuring Reform 1,848.7 891.2 891.4 - 3,631.3 B. Institutional Support 12,513.5 5,354.8 1,349.8 1,268.4 3,511.4 615.3 - 24,613.2 C. Efficiency Improvements DemandSide Improvements 451.3 1,256.9 1,692.2 1,969.4 - - - 5,369.8 Line Loss Reduction 12.7 3,910.8 905.3 808.8 814.3 - - 6,451.9 Subtotal Efficiency Improvements 463.9 5,167.7 2,597.5 2,778.3 814.3 - - 11,821.7 D. Power Expansion and Rehabilitation PowerGeneration 123,517.7 274,009.9 155,174.3 26,425.0 - - - 579,126.9 Upgradingof DistributionSystems 11,576.4 6,397.4 2,231.8 4,570.8 5,172.0 - - 29,948.4 Subtotal Power Expansion and Rehabilitation 135,094.0 280,407.3 157,406.1 30,995.8 5,172.0 - - 609,075.3 E. Geothermal Resource Development 10,551.6 14,648.2 15,475.7 8,611.2 - - - 49,286.6 F. Future Project Prepration - - - - 484.2 495.8 523.1 1,503.1 Total PROJECTCOSTS 160,471.8 306,469.2 177,720.5 43,653.6 9,981.9 1,111.1 523.1 699,931.2
Fh0. Annex 5.1 FINANCIALANALYSIS Page 1 of 9
Konya PovewCompany Umit d_. Projected Prndit and Los Statnent_
Actual Actual Projected- Fiscal Year EndingJune 30 1*n5 1996 1107 1998 100 200 2001 2002 In Ksh 000 Unless otherwise statd Reo"nue I Bulk sales to KPLC 1,055,673 1,271,322 2,092,200 1,951,983 1,959,406 3,198,953 5,216,974 5,507,031 DevelopmentSurcharge 2,633,023 2,676,114 1,166,531 2,145,582 1,585,489 584.444 171,830 3,688,696 3,947,436 3,258,731 4,097,565 3,544,895 3,783.397 5,388,804 5,507,031
Opeatng Costb Generation 132,453 184,000 141,971 153,971 259,228 1,300,879 2,147,083 2,044,794 Purchases-imports 205,370 170,609 381,920 400,400 429,542 440,966 452,390 464,576 Transmissionand Distribution 8,091 9,924 8,899 9,149 9,405 9,668 9,939 10,217 Adminsalaries and wages 16,082 19,700 21,178 22,766 24,473 26,309 28,282 30.403 OtherAdmin expenses 11,223 58,191 22,677 23,964 26,034 29,075 33,380 39,395 Insurance 19,740 20,000 33,788 36,122 86,271 165,588 239,437 234,879 Depredabon 106,243 179,229 208,980 227,447 257,531 916,793 1,285,525 1,308,732 Total OperatingCosts 499,202 641,653 819,413 873,819 1,092,484 2,889,278 4,196,006 4,132,995
Net Operating Income 3,189,494 3,305,783 2,439,318 3,223,746 2,452,411 894,119 1,192,799 1,374,036 Interat Chargeableto Operations 98,141 160,717 370,126 304,207 249,841 309,675 1,020,969 1,132,041 ForeignExchange Losses Chargeableto Operations 96,390 (68,294) (76,654) - 72,180 184,798 421,103 660,586 Net Profitfor the Year 2,994,963 3,213,360 2,145,847 2,919,539 2,130,390 399,646 (249,273) (418,591)
PerformanceIndicators Nat IncomeBefore Int. as % of SalesRevenue 86% 84% 75% 79% 69% 24% 22% 25% Net IncomeAfter lnt. as % of Sales Revenue 81% 81% 66% 71% 60% 11%_ -5% -8%
0. * - FINANCIAL ANALYSIS Annex 5.1 Page 2 of 9
Kenya Powur Company Umited I ProjectedBalance Sheet Statements Actual Actual Projected. Fisca Year EndingJune 30 199 1996 1997 1998 1999 2000 2001 2002 In KSh000 unlessotherwi statd FixedAssts Plant in Sevioe at cost 3,586,337 3.739,154 5,663,420 6,078,780 12,275,104 22,282,501 31,598,365 31,750,621 Accumulateddepraecation 1,005,698 1,184,927 1,393,907 1,621,355 1,878,886 2,795,679 4,081,204 5,389,936 Net BoockValue 2,580,639 2,554,227 4,269,513 4,457,425 10,396,219 19,486,821 27,517,161 26,360,685 WorkIn Progress 3,662,412 3,867,303 8,349,571 18,630,843 21,660,746 16,757,965 9,036.696 9,346,241 Totl FixedAsets 6,243,051 6,421,530 12,619,084 23,088,268 32,056.964 36,244,786 36,553,857 35,706,926
CunrentAssebt Cash - 79.016 1,022,365 1.227,009 1,826,202 2,193,740 2,888.739 KPLCDebt 3,081,985 5,712,490 4,633,137 3,181,641 1,754,756 533,169 869,670 918,022 Otler Debtors 82,500 81,400 83,354 85,354 87,403 89,500 91,648 93,848 Stocks 125,144 96,797 146,611 157,364 317,771 576,836 818,000 821,941 TotalCurrent Assets 3,289,629 5,890,687 4,942,118 4,446,723 3,386,938 3,025,708 3,973,057 4,722,550
Current Liabilies" Creditor 728,666 938,681 181,868 192,485 241,807 599,938 892,558 862.849 Curent Maturitieson Longterm debt 657,491 644,319 697,197 624,771 634,716 202,844 418.685 - TotalCurrent Liablities 1,386,157 1,583,000 879,065 817,256 876,523 802,782 1,311,243 862,849
Net Working Capital 1,903,472 4,307,687 4,063,053 3,629,467 2,510,415 2,222,926 2,661,814 3,859,702 Total Asses 8,146,523 10,729,217 16,682,137 26,717,735 34,567,380 38,467,713 39,215,671 39,566,628
Financed by: Share capital 152,662 152,662 152,662 152,662 152,662 152,662 152,662 152,662 Reserves 3,344,112 6,557,472 8,703,319 11,622,858 13,753,248 14,152,894 13,903,621 13,485,030 Total Equity 3,496,774 6,710,134 8,855,981 11,775,520 13,905,910 14,305,556 14,056,283 13,637,692
Long Term Debt Loans 5,307,240 4,663,402 8,523,353 15,566,986 21,296,186 24,365,000 25,578,073 25,928,936 Less Currentmaturities 657,491 644,319 697,197 624,771 634,716 202,844 418,685 - 4,649,749 4,019,083 7,826,156 14,942,215 20,661,470 24,162,156 25,159,388 25,928,936 Total Financing 8,146,523 10,729,217 16,682,137 26,717,735 34,567,380 38,467,713 39,215,671 39,566,628
Peformance Indicator DebtVEquityRatio 60% 41% 49% 57% 60% 63% 65% 66% CurrentRatio 2 4 6 5 4 4 3 5 . 'Ch Annex 5.1 FINANCIAL ANALYSIS Page 3. of 9
"an Povwer Company Umftd Sourn: and Appil4lo of Funds Stltnnt Actud Ac_al_ Proected. FiscsJYear EndingJune 30 1995 199S 1997 1996 1999 2000 2001 2002 In Ksh 000 unles otherwise st*tb Funds from Inbnul Oper 'ons Not Inrome 2.994,964 3,213,360 2,145,847 2.919,539 2,130,390 399,646 (249,273) (418,591) Items not InvolvingMovement of Funds _ ForeignExchange Losses (443,321) (68,294) (76,654) - 388,299 557,948 628,590 683,333 Deprnxiaton 106,243 179,229 208,980 227,447 257,531 916,793 1.285,525 1,308,732 2,657,886 3,324,295 2,278,173 3,146,986 2,776,220 1,874,387 1,664,841 1,573,473 Othr Soures of Funds Loan Disbursements 336,013 57,853 4,678,121 7,740,831 5,965,672 3,145,583 787,327 86,215 Other 336,013 57,853 4,678,121 7,740,831 5,965,672 3,145,583 787,327 86,215 2,993,899 3,382,148 6,956,294 10,887,817 8,741,892 5,019,970 2,452,168 1,659,688
Appwllcadon of Funds Loan Amorfization 550,979 633.397 741,516 697,197 624,771 634,716 202,844 418,685 Capitl expenditures (178,854) 357,708 6,406,534 10,696,632 9,226,228 5,104,615 1,594,595 461,801 372,125 991,105 7,148,050 11,393,829 9,850,999 5,739,331 1,797,439 880,486 Not Outflow 2,621,774 2,391,043 (191,756) (506,012) (1,109,107) (719,361) 654,729 779,202
R prntbd by: Movement in non-Cash Working Capital 2,697,748 2,391,043 (270,773) (1,449,360) (1,313,751) (1,318,554) 287.191 84,203 Movement in Cash Balances (75,849) - 79,016 943,348 204,644 599,193 367,537 694,999 Total Movement in Working Capital 2,621,899 2,391,043 (191,756) (506,012) (1,109,107) (719,361) 654,729 779,202
Performance Indicators Debt Service Coverage 4.09 4.19 2.05 3.14 3.17 1.98 1.36 1.01 Self-Financing Ratio 0% 75% 20% 24%1 23%, 18% 18% 3%
UA1 0. FINANCIAL ANALYSIS Annex 5.1 Page 4 of 9
KenyaPower and Ughmng Company Umted ProjectedProflt and Loa Statemet Actual Actual Projected - Fical year EndedJune30 199S 1996 1997 1998 1M99 2000 2001 2002 Kah 000 unles otherwlae statd Rennue Eltridty Sale 12,957,798 14,925,280 16,232,080 18,591,380 20,663,787 22,993,112 25,070,614 28,448,336 Other Revenue 162,321 185,914 206,638 229,931 250,706 284,483 Fuel ClauseAdjustment 304,872 1,785.417 2,242,513 2,190,615 2,125,295 1,915,485 12.957,798 14,925,280 16,699,273 20,562,711 23,112,938 25,413,658 27,446,615 30.648,305 Operating Coats Generton 1,019,593 2,432,915 2,133,403 1,981,824 2,305,327 1,019,302 446,035 447,731 Purchasedpower-KPC 1,055,673 1,271,322 2,092,200 1,951,983 1,959,406 3,226,550 5,155,262 5,886,002 PurchasedPower-Turkwell 118,782 595.058 660,760 664,004 681,030 699,221 717,535 737,026 PurchasedPower-TRDC 3,248,140 2,433,904 2,611,720 2,678,258 2,288,762 1,950,749 1,997,670 1,912,300 PurchasedPower-IPPs - - - 3,103,796 3,230,758 4,814,307 4,650,721 6,902.704 Tota cost generated+ purchasedpower 5,442,188 6,733,199 7,498,083 10,379,865 10,465,283 11,710,128 12,967,223 15,885,763 Developmenrtsurcharge-KPC 2,633,023 2,676,114 1,166,531 2,145,582 1,585,489 584,444 171,830 developmentsurcharge-TRDC 388,410 868,010 18,688 20,844 23,701 27,572 Total DevelopmentSurcharges 2.633,023 2,676,114 1,554,941 3.013,592 1,604,177 605,288 195,531 27,572 REF 259,141 298,515 324,642 371,828 413,276 459,882 501,412 568.967 Transmisionand distribution 647,137 860,626 946,689 1,041,357 1,145,493 1,260,043 1.386,047 1,524,651 Admin salariesand wages 2,161,731 2,433,995 2,570,299 2,714,235 3,128,768 3,598,471 3,799,986 3,799,986 Insurance 306,669 284,707 300,651 317,487 365,975 420,917 444,488 444,488 Insbtubonalsupport - 347,848 481,415 585,881 182,232 Depreciation 203,059 335,134 588,463 675,735 770,436 876,994 996,939 1,146,076 Total OperatngCosts 11,652,948 13,970,138 14,265,182 19,099,981 18,075,641 18,931,703 20,291,625 23,397,504
Nat Operating Income 1,304,850 955,142 2,434,091 1,462,730 5,037,296 6,481,955 7,154,990 7,250,801 Net InterestExpenses (268,900) (544,496) 76,790 76,790 76,790 76,790 76,790 270,361 ForeignExchange Losses 73,948 (15,279) (28,184) - 21,468 15,434 10,157 7,877
Profit Before Taxation 1,499,802 1,514,917 2,385,485 1,385,940 4,939,039 6,389,731 7,068,042 6,972,563 CorporationTax 9 35% 416,872 396,926 834,920 485,079 1,728,664 2,236,406 2,473,815 2,440,397 Profit After Taxaton 1,082,930 1,117,991 1,550,565 900,861 3,210,375 4,153,325 4,594,227 4,532,166 Dividendon PreferenceShares 1,930 1,930 1,930 1,930 1,930 1,930 1,930 1,930 Dividendon OrdinaryShares 35,168 70,336 63,302 63,302 63,302 63,302 63,302 63,302
RetainedProfit 1,045,832 1,045,725 1,485,333 835,629 3,145,143 4,088,093 4,528,995 4,466,934
0. PerfornanceIndIcators Net IncomeBefore Int.& Taxesas % of Sales Revenue+ 10.1% 6.4% 15.0% 7.9% 24.4% 28.2% 28.5% 25.5% ,Profit afterlInterestand Taxesas %of SalesRevenue 8.4%1 7.5%, 9.6%1 4.8%1 15.5% 18.1%1 18.3% 15.9% FINANCIAL ANALYSIS Anmex 5.1 Page 5 of 9
KonyaPower and Ughting Company Limited Balance Sheet Actual Actual Projected Fiscal Year EndedJune 30 199C 1996 1997 1998 1999 2000 2001 2002 In Ksh 000 unless otherwise stated Fixed Asset at Cost 6,245,201 6,636,182 8,199,321 9,716,870 11,200,883 12,882,403 14.717,287 17,211,760 AccumulatedDepreciation 2,343,182 2,677,835 3,266,298 3,942,033 4,712,470 5,589,463 6,586,402 7,732,478 Net BookValue 3,902.019 3,958,347 4,933,022 5,774,836 6,488,413 7,292,940 8,130,885 9,479,282 Work In Progress 621,320 812,383 843,805 879,893 1,088,007 1,351,809 1,664,713 1,798,837 4,523,339 4,770,730 5,776,828 6,654,730 7,576,420 8,644.749 9,795,598 11,278,120 Investments 4,300 4,300 4,300 4,300 4,300 4,300 4,300 4,300 DeferredDebt 298,056 233,591 175,386 175,386 175,386 175,386 175,386 175,386 Current Asset. Cash 493,256 374,459 1,633,034 (2,492,294) (2,920,024) (2,961,225) 68,770 1,309,179 Investments 2,882,899 4,097,121 4,097,121 4,097,122 4,097,123 4,097,124 4,097,125 4,097,126 Debtors 4,433,018 5,114,387 2,705,888 3,099,183 3,444,653 3,832,952 4,179,271 4,742,338 Stocks 2,537,327 3,189,427 3,974,769 4,653,058 5,228,021 5,876,266 6,551,438 7,637,905 Total CurrentAssets 10,346,500 12,775,394 12,410,812 9,357,069 9,849,773 10,845,117 14,896,605 17,786,548
Current LiabilKites Due to KPC 3,081,985 5,712,490 4,633,137 3,181,641 1,754,756 537,866 859,382 981,197 Due to TRDC 3,229,405 3,053,015 2,725,135 1,972,974 1,144,791 325,190 333,012 318,780 Others 3,529,039 3,152,010 2,474,156 1,686,694 901,531 116,560 119,613 122,862 Tax 230,232 (10,890) 834,920 485,079 1,728,664 2,236,406 2,473,815 2,440,397 Dividends 50,252 113,207 65,232 65,232 65,232 65,232 65,232 65,232 Current Maturitieson L-T Debt 332,954 328,582 359,699 307,586 263,177 320,051 247,873 10,453,867 12,348,414 11,092,278 7,699,206 5,858,150 3,601,305 4,098,926 3,928,468 Net Working Capial (107,367) 426,980 1,318,534 1,657,864 3,991,623 7,243,812 10,797,678 13,858,080 Total Assets 4,718,328 5,435,601 7,275,047 8,492,279 11,747,729 16,068,247 20,772,963 25,315,886
Capital and Reserves Ordinary Shares 351,680 351,680 351,680 351,680 351,680 351,680 351,680 351,680 PreferenceShares (4%) 36,000 36,000 36,000 36,000 36,000 36,000 36,000 36,000 PreferenceShares (7%) 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 Reserves 2,551,745 3,597,953 5,083,286 5,918,915 9,064,058 13,152,152 17,681,147 22,148,081 Total ShareCapital and Reserves 2,946,425 3,992,633 5,477,966 6,313,595 9,458,738 13,546,832 18,075,827 22,542,761 Long-Tern Debt 2,104,857 1,771,550 2,156,780 2,486,269 2,552,166 2,841,463 2,945,004 2,773,120 P CurrentMaturities 332,954 328,582 359,699 307,586 263,177 320,051 247,873 03 1,771,903 1,442,968 1,797,081 2,178,683 2,288,989 2,521,412 2,697,132 2,773,120 lb Total Financing 4,718,328 5,435,601 7,275,047 8,492,278 11,747,727 16,068,244 20,772,959 25,315,881 sn PerformanceIndicators 0. DebVEquityratio 42% 31% 28% 28% 21% 17% 14% 11% Currentratio 0.99 1 03 1.12 1.22 1.68 3.01 3.63 4.53 Annex 5.1 FINANCIAL ANALYSIS Page 6 of 9
K*nya Powe ndUghtng Company Sta"nnt of Sources and Application of Fund Actual Actual Projected Ficl Year EndedJune 30 1S96 1996 1997 1998 199 2000 2001 2002 In Ksh 000 unles oathewae sbtatd Funda fom Innal Operatona Net Incom 1.499,802 1,514,917 2,385.485 1,385,940 4,939.039 6,389,731 7,068,042 6,972,563 Adjuant for itrna not Invoving Movemnentof Funds Depecdation 203,059 335,134 588,463 675,735 770,436 876,994 996,939 1,146,076 ForeignExchange Loases 73,948 (15,279) (28,184) - 21,468 15,434 10,157 7,877 1,776,809 1,834,772 2,945,764 2,061,675 5,730,943 7,282.158 8,075.138 8,126,516
Ohr Soure, of Funds Loan Disburaements - 799,920 689,188 314,111 488,097 354,125 Deferreddebt 80,627 64,465 58,205 - - - ForeignExchange Losses - - 37,905 48,943 59,310 68,111 Other 665 6,085 - Total Sources 1,858,101 1,905,322 3,803,889 2,750,863 6,082,958 7,819,199 8,488,573 8,194,627
Appicaton of Funds Loan Amorfization 407,510 356,417 386,506 359,699 307,586 263,177 320,051 247,873 CapitalExpenditures 979,782 588,608 1,594,561 1,553,637 1,692,127 1.945,322 2,147,788 2,628,597 TaxationPaid 396,926 834,920 485,079 1,728.664 2,236.406 2,473,815 2,440,397 DividendsPaid 72,266 65.232 65,232 65,232 65,232 65,232 65,232 1,387,292 1.414,217 2,881,219 2,463,647 3,793,609 4,510,137 5,006,886 5,382,099 Nat Outiowllnflow 470,809 491,105 922,671 287,216 2,289,349 3,309,062 3,481,687 2,812,528
Movementin non-CashWorking Capital 232,405 609,902 (335,904) 4,412,544 2,717,080 3,350,263 451.692 1,572,119 Movementin Cash balances 238,404 (118,797) 1,258,575 (4,125,328) (427,730) (41,201) 3,029,996 1,240,409 Total Movementin WorkingCapital 470,809 491,105 922,671 287,216 2,289,349 3,309,062 3,481,687 2,812,528 ParfonnancaIndIcator Debt ServiceCoverage 13 (10) 6 5 15 21 20 16 Saf-FinancingRatio 52% 46% 22% 11% 34% 40% 38% 53%
Pt I 0% 0. 'h_ Annex 5.1 FINANCIAL ANALYSIS Page 7 of 9
TansRiver Development Company Llmited . Projected Profit and Lose Sttments Actual Actual Projected Flbcal Years nded June 30 1996 1996 1997 1998 1999 2000 2001 2002 Kah 000 unles otherwiea stabd Revenue Bulk sales to KPLC 3,312,140 2,433.904 2,611,720 2,678,258 2,288,762 1,950,749 1,997,670 1,912,300 Development Surcharge . 388,410 868.010 18,668 20,844 23,701 27,572 3,312,140 2,433,904 3,000,130 3,546,268 2,307,430 1,971,593 2,021,371 1,939,872
Ope,abng Costs generation 94,716 220,370 231,980 244,224 257,134 270,750 285.109 300,253 transmission & distribution expenses 4,123 5.005 5,285 5,581 5.894 6.224 6,572 6,940 admin salaries and wages 23,946 31,500 33,264 35,127 37,094 39,171 41,365 43,681 Other Admin expenses & insurance 117,097 145,663 153,820 162,434 171,530 181,136 191,280 201,991 Masinga Debt ServiCe 47,956 47,956 49,729 48,795 47,860 46,926 45,991 45,057 Kiambere Debt ServiCe 2,331,969 1,171,860 1,297,966 1,451,798 1,289.284 1,267,738 1,244,266 1,218,777 Deprciation 43, 104 35,550 36,089 86,425 88,292 90,377 92,747 95,504 Total Operating Costs 2,662,911 1,657,904 1,808,134 2,034,384 1,897,089 1,902,322 1,907,329 1,912,204
Net Operating Income 649,229 776,000 1,191,995 1,511,884 410,341 69,272 114,041 27,668 IntereStChargeable to Opeations 188,124 1 52,337 132,338 81,452 39,861 18.795 7,414 96 Foreign Exchange LOssesChargeable to Operations 214,809 (107,245) (27,408) - 11,516 5,670 2,180 29 Net Profit for the Year 246,296 730,908 1,087,065 1,430,432 358,965 44,807 104,448 27,543
Check Net profit=Depn-debtService+Dev surch+ Forex var. 1,087,065 1,430,432 358,965 44,807 104,448 27,543 Perfromance Ratios _ Net income Before Interest as % of Revenues 20% 32% 40% 43% 18% 4% 6% 1% Net inComeAfterInterest aS % of Revenues 7% 30% 36% 40% 16% 2% 5% 1%
O0. Annex 5.1 FINANCIAL ANALYSIS Page 8 of 9
Tsna River Development Company Limited Projected Balance Sheet Statmet FiscalYears Eneded June 30 Actual Actual Projected 19E 1996 1"7 1M99 19m 2000 2001 2002 ______iKah 000 unless otherwise d Fixed A"ets Plant in Service d cost 1,677,999 1,881,995 1,698,495 2.931,155 2,949,823 2,970,867 2,994,368 3,021,940 Accumulateddepreciation 714,954 750,504 786,593 873,019 961,311 1.051,688 1,144,434 1,239,938 Net Book Value 963,045 931,491 911,902 2,058,136 1,988,512 1,918,980 1,849,934 1,782,002 Work In Progress 713 912 387,815 23,671 24,743 25,869 27,009 28,203 Total Fbied Assets 963,758 932,403 1,299,717 2,081,807 2.013,256 1,944,849 1,876,943 1,810,205
Current Asset Cash 157 7 68.039 564,523 626,735 670,206 (126,836) (35,986) KPLC Debt 3,229,405 3,053,015 2,725,135 1,972,974 1,144,791 325,190 333,012 318,780 Other Debtors 11,306 17,200 35.890 37.900 40,023 42,264 44,631 47,130 Stocks 98,151 60,544 109,278 115,398 121,860 128.684 135,890 143,500 Total Current Assets 3,339,019 3,130,766 2,938,342 2,690,794 1,933,408 1,166,344 386,697 473,425
Current Liabilities Creditors 3,315,832 3,106,568 2,774,799 2,446,305 1,649,571 864,237 77,716 71,674 Current Maturities on Long term debt 669,521 400,312 567,395 400,244 101,215 168,259 2,180 - Total Current Liabilities 3,985,353 3,506,880 3,342,194 2,846,549 1,750,786 1,032,496 79,896 71,674 Net Working Capital (646,334) (376,114) (403,852) (155,755) 182.623 133,847 306,801 401,751 Total Assets 317,424 556,289 895,865 1,926,053 2,195,878 2,078,697 2,183,744 2,211,956
Financedby: _ Sharecapital 120,002 120,002 120,002 120,002 120,002 120,002 120,002 120,002 Remrves (1,716,642) (985,734) 101,331 1,531,762 1,890,727 1,935,534 2,039,982 2,067,524 Totel Equity (1,596,640) (865,732) 221,333 1,651,764 2,010,729 2,055,536 2,159,984 2,187,526
Long Term Debt _ Loans 2,583,585 1,822,333 1,241,927 674,532 286,364 191,419 25,940 24,429 Leu Current maturities 669,521 400,312 567,395 400,244 101,215 168,259 2,180 - 1,914,064 1,422,021 674,532 274,288 185,149 23,160 23,760 24,429 Total Financing 317,424 556,289 895,865 1,926,053 2,195,878 2,078,697 2,183,744 2,211,956
Performance Ratios C0 Debt asa % of Total Capital 262% 191% 85% 29% 12% 9% 1% 1% O Current Ratio 0.84 0.89 0.9 0.9 1.1 1.1 4.8 6.6 Annex 5.1 FINANCIAL ANALYSIS Page 9 of 9
Tun River Deopmet Company Umited Sourceeand Application of Funds ttnt Actual Acbtal Projected Fiscal Yea Ended June30 1S6 1996 117 1ns 1999 2000 2001 2002 Koh 000unhes otherwIs atated Funds from internalOperations Not Income 246,297 730,908 1,087,065 1,430,432 358,965 44,807 104,448 27,543 Itemsnot lnvoMngMovemnent of Funds Foreign ExchangeLoses 214,809 (107.245) (27,408) - 11,516 5,670 2,180 29 Depreciation 43,104 35,550 36,089 86,425 88,292 90,377 92,747 95,504 504.210 659,213 1,095,746 1,516,857 458,773 140,854 199,374 123,076 Other Sourcesof Funds Loan Disbursement - 22,000 - - - - - Foreign ExchangeLosse - 560 600 600 640 - 22,000 560 600 600 640 504,210 659,213 1,117,746 1.516,857 459,333 141,454 199,974 123,716 Application of Funds Loan Amorfization 501,893 654,007 574,998 567,395 400,244 101,215 188.259 2,180 Capital expenditures 1,468 4,195 403,403 868,516 19,741 21,970 24,840 28,766 503,361 658,202 978,401 1,435.911 419,985 123,185 193,099 30,948 Net Ouflow 849 1,011 139,345 80,946 39,348 18,269 6,875 92.770
Represnted by:
Movement in non-Cash Working Capital 1,359 - 71,313 (415,537) (22,864) (25,201) 803,916 1,920 Movement in Cash Balances (510) 1,011 68,032 496,483 62,213 43,470 (797,042) 90,850 Total Movement in Workig Capital 849 1,011 139,345 80,946 39,348 18,269 6,875 92,770
Perfomance Ratios
Debt Service Coverage 0.7 0.8 1.5 2.3 1.0 1.2 1.1 54.1 Self-Financing 0% -18% 15% 49% 22% 22% 22% 210%
0. Ul
40 Annex 6.1 Page I of 4
KENYA
Energy Sector Reform and Power Development Project Project Implementation Planl
Table of Contents
Page No. INTRODUCTION ...... ix
Summary of Project Objectives...... ix
Summary of Projects Description and Components...... x
SECTION I ...... 1.0 Energy Sector Policy Framework.I 1.1 Policy Objectives for the Energy Sector. 1.2 Sector Restructuring .1 1.3 Least Coast Investment Planning .2 1.4 Energy Pricing...... I...... 1.5 Energy Efficiency.3 1.6 Rural Energy Supply and New and Renewable Energy .4
SECTION 2...... 5 2.0 Detailed Project Description .5 2.1 Project Objectives ...... : 5 2.2 Project Cost Estimates.5 2.3 Project Scope and Description.12 2.3.1 Sector Restructuring and Reform .12 2.3.1.1 Legal and Regulatory Reform.12 2.3. 1.2 Promotion of Private Sector Participation.13 2.3.2 Efficiency Improvements.13 2.3.2.1 Demand Side Management Improvements.13 2.3.2.2 Industrial Energy Management .14 2.3.2.3 Energy Efficiency Standards for Electric Equipment .14 2.3.3 Power System Expansion and Upgrading .14 2.3.4 Kipevu I and II Medium Speed Diesel Electric Power Plants.14 2.3.5 Olkaria II 2 x 32 MW Geothermal Power Station.14 2.3.6 Olkaria III 2 x 32 MW Geothermal Power Station .15 2.3.7 Distribution Reinforcement and Loss Reduction Program.15 2.3.8 Distribution Reinforcement Subcomponent .15 2.3.9 Power Loss Reduction.16 2.3.10 Development of Indigenous Resources.17 2.3.10.1 Make-up Wells ConnectionI .18 2.3.10.2 Geothermal Resource Assessment Program.18 2.3.10.3 Relocation of X-2 Camp. 19
PIP will be revised to exclude the petroleum subsector components which have been delinked from the project, and the Nairobi-Mombasa and Nairobi-Kiambere 220 kv transmission lines for which funding has not yet been secured. Annex 6.1 Page 2 of 4 2.3.10.4 Household Energy Strategy...... 19 2.3.10.5 Solar Photovoltaic Standardization Study and Information and Dissemination...... 19 2.3.10.6 LPG Cylinder Standardization Study ...... 19 2.4 Project Financing Plan...... ,,26 2.5 Major Loan Covenants/Target Dates...... 32 2.6 Detailed Financial and Economic Analysis of the Project ...... 32 2.6.1 Economic Analysis of Projects for KPLC/KPC...... 32 2.6.1.8 Risk Analysis of Power Sub-sector Components ...... 38
SECTION 3..47 3.0 Projection Organization...... and Management 47 3.1 Organization Structure ...... 47 3.2 Project Management Arrangement ...... 48 3.3 Management of Various Components of the Energy Sector Investment Project ...... 48 3.3.1 Energy Sector Policy Reform Studies ...... 50 3.3.2 Efficiency Improvements ...... 51 3.3.3 Power System Expansion and Upgrading ...... 51 3.3.4 Development of Indigenous Resources of Energy ...... 53
SECTION 4.56 4.0 Project Plan and Implementation.56 4.1 Consolidated Project Implementation Schedule Summary .56 4.2 Implementation Schedule for each component .56 4.3 Implementation, Supervision and Control.56
SECTION 5..57 5.0 Procurement ...... 57 5.1 IDA Procurement Guidelines ...... 57 5.2 GOK Procurement Guidelines for Goods, Equipment and Services ...... 57 5.3 KPLC Procurement Guidelines ...... 57 5.4 Procurement Guidelines for Goods, Equipment and Services for OECF, EIB, etc...... 57 5.5 Summary of Disbursement Procedures of IDA...... 57 5.6 Disbursement Procedures for OECF, EIB, GOK, KPLC, KPC.57 5.7 Accounting and Auditing Procedures for IDA ...... 57 5.8 Accounting and Auditing Procedures for OECF, EIB, GOK, KPLC, KPC ...... 57 5.9 Procurement Methods, Procurement Processes and Expected Time Lapse ...... 57 5.10 Procurement Processing, Disbursement Procedures, and Accounting and Auditing ...... 57
SECTION 6...... 58 6.0 Financial Management ...... 58 6.1 Schedule of Disbursements for each Component...... 58 6.1.2 Economic Analysis and Disbursement Schedule of Project Components Implemented by KPC AND KPLC ...60 6.2 Funds Flow Chart ...... 62 6.3 Work Certificates and Payment Procedures ...... 62 6.4 Financial Statements and Reports...... 62 6.5 Audits ...... 62
SECTION 7..63 7.0 Monitoring and Reporting .63 7.1 Key Development Impact Indicators for measuring Progress in Reaching Project Objectives.63 7.2 Key Indicators for Monitoring Progress in the Physical Implementation of the Project. 63 7.3 Key Financial Indicators to assess the Project Budgetary and Financial Health ...... 63 Annex 6.1 Page 3 of 4
7.4 Monitoring and Evaluation...... 63 7.5 Reporting Routines...... 63 7.5.1 Filing Index/Filing/Library...... 63 7.5.2 Protocol for Communication and Copy Distribution ...... 63 7.5.3 Computers and System Management and Operation ...... 63 7.6 Implementation Completion...... 65
SECTION 8.65 8.0 Environmental Mitigation Plan and Monitoring Arrangements ...... 65 8.1 Environmental Mitigation Plan for KPLC and KPC ...... 65 8.1. I North East Olkaria 2x32 MW Power Development Project...... 65 8.1.2 Mombasa Diesel Generating Power Plant Project...... 67 8.2 Environmental Mitigation and Monitoring Arrangement ...... 70 8.2.1 Mitigation and Monitoring Arrangements for KPC and KPLC ...... 70 8.3 Implementation Guidelines ...... 71 8.3.1.1 North East Olkaria 11,2x32 MW Power Development Project...... 71 8.3.1.2 Mombasa Diesel Generating Power Plant Project...... 72 8.3.2 Environmental Guidelines for KPLC and KPC...... 72 8.3.2.1 North East Olkaria 2x32 MW Power Development Project...... 72 8.3.2.2 Mombasa Diesel Generating Power Plant Project...... 73
SECTION 9 ...... 78 9.1 Policy Reform Items, Schedules and Budgets...... 78 9.1.1 Terms of Reference for Study to Update the Electricity Tariff Study Completed in November 1993 ...... 78 9.2 Institutional Support Items, Schedules and Budgets ...... 82 9.2.1 Institutional Strengthening Items for MOE...... 82 9.2.2 Institutional Strengthening Items for KPLC and KPC ...... 89
SECTION 10 ...... 107 Capacity Building..107 10.0 Human Resource Development (HRD).107 10.1 Transfer of Expertise Guidelines for Power Sub-sector .107 10.2 PowerrSub-sector.107
APPENDIX I..I. IDA Procurement Guidelines .. 111 A. Use of Consultants by World Bank Borrowers and by World Bank as Executing Agency .111 B. Procurement Under IBRD Loans and Credits .114
APPENDIX II.118 Government of Kenya Procurement Guidelines for Goods, Equipment and Services .118
APPENDIX III.126 KPLC Procurement Guidelines.126
APPENDIX IV.131 Procurement Guidelines for Goods, Equipment and Services.131
APPENDIXVV132 Summary of Disbursement Procedures for IDA/IBRD.13
APPENDIXVI ...... I...... 144 Disbursement Procedures.144 Annex 6.1 Page 4 of 4
APPENDIX Vll ...... 1454...... Accounting and Auditing Procedures for IDA/IBRD...... 145
APPENDIX Vill ...... 146 Accounting and Auditing Procedures ...... 146 Annex 6.2 Page 1 of 1
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',. .', 1;0JI 1 ., Annex 6.3 Page I of 2
KENYA
IDA-Financed Civil Works
Est'd#. of Description Estimated IDA Procurement Packages Cost (US$) Funding Method I Olkaria 11Power Plant-Civil Works 50,600,000 26,800,000 ICB 5 Civil Works for Substations under the Line Loss 950,200 807,300 NCB Reduction Subcomponent Total 51,550,200 27,607,300
IDA-Financed Goods Est'd #. of Description Estimated IDA Procurement Packages Cost (US$) Funding Method IDA-Financed Goods I Olkaria 11Power Plant-Electromechanical Equipment 51, 376,800 41,615,200 ICB for 64 MW Equipment for demand Side Management1 4,418,800 4,418,800 ICB 2 Equipment for Line Loss Reduction 5,449,300 5,449,300 ICB 2 Connection of make-up wells for Olkaria 1 1,188,400 713,000 [CB 2 Office Equipment for MoE's Implementation Support 80,300 80,300 Sh2 Group I Household Energy Strategy 11,200 11,200 Sh 2 Motor Vehicles for Geothermal Resource Assessment 138,000 138,000 Sh 2 Drilling consumables for geothermal wells 4,899,300 4,899,300 ICB 2 Spare parts for drilling operations 261,700 261,700 ICB 2 Spare parts for drilling operations 200,000 200,000 NCB 2 Geothertnal drilling equipment 4,136,100 4,136,000 ICB Total 72,159,900 61,923,600
List of EDA-FinancedStudies 3 Title Estimated Status mm Power Sector Organization Study-phase 1 20 completed under PPF Legal and Regulatory Framework 15 completed under PPF Petroleum Market Structure and Pricing 18 completed under PPF Study on Financing Mechanisms for Energy Efficiency 15 Measures Feasibility Studies and Detailed Design for Olkaria IV 185 Prefeasibility Studies for Olkaria Domes/Suswa/Longonot 185 Line Loss Reduction 20 LPG Clynder Standard Study 10 Solar PV and Standard Study 5 Preparation of Future Studies 100 Total 553
1To be determinedon the basis of the resultsof demandmanagement programs to be designedby KPLCwith the assistanceof consultants. 2 Sh = shoppingprocedures, procurement to be carried out in packagesof less than USS50,000. 3 Consultantsservices for studieswill be procuredin accordancewith the Bank's Guidelinesfor selectionof Consultants,which generally require shortlisting of prospectivefirns. Annex 6.3 Page 2 of 2
Listed of IDA-Financed Consultants Service4
Title Estimated Status mm Demand Side Management Programs 20 Distribution Systems Adviser 3 Engineering Contract for Olkaria It Power Plant 920 Drilling Services for connection of make-up wells for Olkaria 45
Procurement Services for connection of make up wells for 6 Olkaria I Drilling by KPC with own rig 35 Engineering Adviser to KPC CPDM 80 Financial Adviser to KPC CPDM 80 Engineering Adviser to MoE's Implementation Support 80 Group Financial Adviser to MoE's Implementation Support Group 70 Policy Adviser to MoE 48 Ongoing under PPF Household Energy Strategy 14 Private Sector Participation 40 Ongoing under PPF Implementation Support for Sector Restructuring and Reform 135 Support on Petroleum sub-sector deregulation 2 Ongoing under PPF Procurement of drilling services 35 Geothermal Advisory Board 50 Total 1663
4 Consultantsservices will be procuredin accordancewith the Bank's Guidelinesfor selectionof Consultants,which generallyrequire shortlisting of prospectivefirms. Annex 6.4 Page I of I KENYA Estimated Schedule of Disbursements (US$ millions)
Cumulative Standard Disbursement Disbursement Cumulative (%) Disbursement Fiscal Year Ending (US$ Million) (US$ Million) Disbursement Cumulative %
Fiscal Year 1997/98 December 31 3.5 3.5 2.0 0% June 30 10.0 13.5 11.0 6%
Fiscal Year 1998/99 December 31 15.0 28.5 23.0 14% June 30 17.0 45.5 36.0 22%
Fiscal Year 1999/2000 December 31 20.0 65.5 52.0 34% June 30 17.3 82.8 66.0 42%
Fiscal Year 2000/2001 December 31 17.3 100.1 80.0 50% June 30 9.5 109.6 88.0 62%
Fiscal Year 2001/2002 December 31 9.5 119.1 95.0 74% June 30 1.4 120.5 96.0 82%
Fiscal Year 2002/2003
December 31 1.2 121.7 97.0 90% June 30 1.2 122.9 98.0 98%
Fiscal Year 2003/2004
December 31 1.1 124.0 99.0 99% June 30 0.5 125.0 100.0 100%
100 . ______''_ _ _ _
80 70 60 _r
40 : - =S1 : | _ ~~~~~Standard| 30 20 10. 0 O~Ogo CD 0o4
_ _ N b1 04N b N Annex 6.5 Page 1 of 2 KENYA
Implementation Support Plan and Staff Input
1. The Borrower's supervision activities would be carried out by the Ministry of Energy (MOE), Kenya Power and Lighting Company (KPLC), and Kenya Power Company (KPC). Their supervisory functions would involve the following:
(a) initial review, recording and forwarding of: (i) all procurement orders (ii) all disbursement requests (iii) special accounts expenditures/reimbursements (b) preparation of an annual project implementation budget (c) preparation of bidding and other project contract documents (d) preparation of monthly financial statements (e) preparation of semi-annual progress reports to IDA in December and June of each year on all aspects of project implementation (f) preparation of annual project accounts (g) monitor key performance indicators and environmental mitigation plans (h) arranging for the annual audits of project accounts and SOEs (i) liaising with all Bank supervision missions
2. In addition to the regular implementation support missions to be carried out by IDA in accordance with the schedule set out below, IDA staff would spend time on dealing with correspondence, reviewing and commenting on procurement documents, disbursement requests, half-yearly reports and audited accounts. The amount of time estimated is as follows:
HQ Time Field Time Total Time Project Year 1 8 sws 36 sws 44 sws Project Year 2 8 sws 36 sws 44 sws Project Year 3 7 sws 39 sws 39 sws Project Year 4 7 sws 27 sws 34 sws Project Year 5 5 sws 27 sws 32 sws Project Year 6 5 sws 27 sws 32 sws Project Year 6 5 sws 27 sws 32 sws Project Year 7 5 sws 27 sws 32 sws
3. Mid-term Review by the Borrower and IDA would be held not later than June 30, 2000. The terms of reference and background papers for the review would be prepared by the Ministry of Energy and the implementing agencies with IDA staff assistance as may be necessary. The principal objective of the implementation review would be to examine the status of implementation of the project, determine any required changes in design and implementation arrangements needed to ensure achievement of the project's development objectives. Specifically, the review meetings will focus on the status of progress in: (i) adjustment of tariffs towards LRMC; (ii) attracting private sector participation; (iii) restructuring of organization of the power subsector; and (iv) the operation of the Electricity Regulatory Board. Annex 6.5 Page 2 of 2
BANK IMPLEMENTATION SUPPORT INPUT (STAFF WEEKS) INTO KEY ACTIVITIES
Fiscal Year Approximate Date Activity Expected SkiHs Staff Input FY1997/98 November 1997 Implementation Support Mission Sr. Financial Analyst 18.0 Power Engineer Energy Economist Operations Analyst Sector Restructuring Expest March 1998 Implementation Support Mission Sr. Financial Analyst 18.0 Power Engineer Energy Economist Operations Analyst Environmental Specialist FY1998/99 November 1998 Implementation Support Mission Sr. Financial Analyst 18.0 Power Engineer Energy Economist Operations Analyst Environmental Specialist March 1999 Implementation Support Mission Sr. Financial Analyst 18.0 Power Engineer Energy Economist Operations Analyst Environmental Specialist Procurement Specialist FY1999/00 October 1999 Implementation Support Mission Sr. Financial Analyst 15.0 Power Engineer Energy Economist Operations Analyst Environmental Specialist June 30, 2000 Mid-Term Review Sr. Financial Analyst 24.0 Power Engineer Energy Economist Operations Analyst Environmental Specialist Procurement Specialist FY2000/01 October 2000 Implementation Support Mission Sr. Financial Analyst 15.0 Power Engineer Energy Economist Operations Analyst .______Environmental Specialist March 2001 Implementation Support Mission Sr. Financial Analyst 12.0 Power Engineer Energy Economist Environmental Specialist FY2001/02 October 2001 Implementation Support Mission Sr. Financial Analyst 15.0 Power Engineer Energy Economist Operations Analyst Environmental Specialist March 2002 Implementation Support Mission Sr. Financial Analyst 12.0 Power Engineer Energy Economist Environmental Specialist FY2002/03 October 2002 Implementation Support Mission Sr. Financial Analyst 15.0 Power Engineer Energy Economist Operations Analyst l______EnvirommentalSpecialist March 2003 Implementation Support Mission Sr. Financial Analyst 12.0 Power Engineer Energy Economist EnvirommentalSpecialist FY2003/04 October 2003 Implementation Support Mission Sr. Financial Analyst 12.0 Power Engineer Energy Economist Environmental Specialist March 2004 Preparation Work for Implementation Sr. Financial Analyst 15.0 Completion Report Power Engineer Energy Economist Operations Analyst Environmental Specialist Annex 7.1 Page 1 of 1
KENYA
Least-Cost Generation Expansion Plan
Fiscal Year Generation Additions Net Installed Critical Weighted Capacity LOLE EUE l______(MW ) (d/yr) (GW-h) Hydro Geothermal LS Diesel MS Diesel 1993 - 1994 747 365 191 1994- 1995 747 357 273 1995 -1996 747 365 307 1996 -1997 747 365 438 1997 -1998 6 x 12.5 809 365 250 1998 -1999 2 x 30.7 1x 50 6 x 12.5 995 4.4 0.5 1999 - 2000 2 x 30 1032 5.5 0.7 Sondu Miriu 2000 - 2001 2 x3/07 1094 1.7 0.1 2001 - 2002 2 x 45 1150 1.0 0.4 Ewaso A 2002 - 2003 2 x 18 + 2 x 27 2 x 30.7 1297 0.02 0.0 EwasoB 2003 - 2004 1 x 50 1347 0.03 0.0 2004 - 2005 2 x 30.7 1409 0.05 0.0 2005 - 2006 1409 0.4 0.4 2006 - 2007 2 x 30.7 1470 0.6 0.5 2007 - 2008 2 x 50 1539 0.8 0.7 2008-2009 2x30.7 1601 1.3 1.4 2009-2010 1x50 1651 3.2 4.7 2010-2011 2 x 30.7 1 x 50 1762 2.5 3.1 2011 - 2012 1 x50 1812 5.8 9.0 2012 - 2013 2 x 50 1912 6.5 10.5 TOTAL 240 MW 430 MW 450 MW 150 MW NOTE: Unit deratingsand retirementsare not shownin the above table.
SOURCE: KPLC andAcres International Annex7.2 KENYA Page1 of 3 Energy Sector Reform and Power Development Project Economic Analysis
Year |lectricity Sales |Benef"ts InvestmentCost 0 8 MCost |Fuel Cost |NetBenefits
I iththe Withoutthe Incremental lIncremental Withthe Withthe Withoutthe IncrermentalWith the Withoutthe Ilncremental TotalProject TotalProject Net Project Sales Benefts Project PProject Project O&Mcost Project Project fuel cost Costs Benefts IBenefts |GWh |GWh GWh EUSS million USSmillion USSmillion USSmillion USSmillion USSmillion 1USSmillion US$million USSmillion US$million USSmillion
1997 2,948 2,948 0J 0 165 0 0 0 20 20 0 165 0: -165 1998 3,3401 3,330 10 1 314 1 -312 1999 3,401 3,369 32 5 250 12 70i 5 17 18 -1 255j 5 -250 2000 4,124 3,453 671 94 112 28 7 21 28 17 11 144 94 -50 2001 4,346 3,486 8601 120 54 32 7 25 17, 18i -1 78I 120 42 2002 4 ,579 3,400 1,1801 165 0 33, 7 26 19 161 3 30j 165 135 2003 4,850 3,373 1,477 207 0 35 5 30 141 12 2 321 207 175 2004 5,143 3,389 1,7541 245 0 39, 5j 34 17 13; 5 39' 2451 207 2005 5,002 2,816 2,186 306 0 45 5 40 29' 13 16 55 306' 251 2006 5,020' 2 817 2,203I 308 0 45 5 40 30 13 17 571 3081 251 2007 50321 2,842 2,190 307 0 45 5 40 33 13! 20 601 3071 246 2008 4,860i 2,656 2,205 309 0 43 _ 3 40 - 37- 0 37 77 309 232 2009 4,853; 2,656 2,197 308 0 43 3 - 40 38 0 38 78' 3081 229 2010 4,855 2,656 2,200 308 0 43 3 - 40 39 0 39 791 308 229 2011 4,8481 2,656 2,192 307 0 43 3 40 27 0 27 67i 3071 240 2012 4,837 2,656 21811 305 0 43 _ _3 40 27 0, 27 67t 305 238 2013 4,830 2,656 2,175 304 0 43 _ 3 40 27 0 27 671 304 237 2014 4,820 2,6561 2,1641 303- - 43 3- - 40 27 0 27 671 303i 236 2015 4,821 2,656 2,166l 303 0 43 - 3 40 27 0 27 67 3031 236 2016 4,811 2,656 2,155 302 0 . 43 3 40 27 0 27 671 302 235 2017 4,797 2,656 2,142 300 0 . 43 3 40 27 0 27 67 300 233 2018 4,7891 2,656 2,134 299 0 43 3 40 27 0 27 671 299 232 2019 4,7781 2,656 2,123 297 11 43t 3 40 27 0 27 78! 297i 219 2020 4,770j 2,656 2,1141 296 22 43- 3 40 27 - 0 27 891 296 207 Residualvalue -380 - r -380 01 380
= I______.1 . * . ll = - .
PV of costs @12% discount: $926 .. PV of benefits@ 12%discount: $1,269 j . Netsenefts 12Y.discount $343
Rateof Retum: 17.327.6 . I I . . I ______P_lb
1/ Eledricity salesan th the projed indude the output of the SonduMiriu hydro plant,whid is financed outside of the project 2V Investment and O&M costs include in additionto projectcosts the SonduMiriu hydro plant and requiredtransmission and distribution. I 31 ,BenefltsvaluedatUScents14perkWh. I I L Annex 7.2 Page 2 of 3 KENYA Energy Sector Reform and Power Development Project Economic Analysis Assumptions
A. Benefits
Incremental ElectricitySales The benefitsfrom incrementalelectricity sales are defined as the difference betweenthe demand which the systemcan satisfywith the proposedinvestments and that it can satisfy withoutthe proposedinvestments. It is assumedthat thesebenefits will increaseas demandrises, until 2013 when they will reach a plateau at the maximumgeneration capability of the new generationfacilities. Thereafter,the benefitswill remain constantthrough 2020, the remainingeconomic life of the diesel and geothermalfacilities. The analysishas taken accountof the longereconomic life of the hydro plant and the transmissionand distributionfacilities through residual values. For the valuationof incrementalsales in GWh,the analysisused a rate of US 14 cents per kWh,which is the estimatedaverage consumers' willingnessto pay for electricity.
Estimation of ConsumerSurplus and Consumers' Willingness-to-Payfor ElectricityThe analysis estimatedthe consumer'swillingness-to-pay (WTP) for electricityusing estimateddemand functions for differentconsumer categories. The demand functionsare definedby two points: The "lower"end of the demandfunctions is representedthe price-quantitypair denotingthe quantityof electricityconsumed at KPLC's marginaltariff rates for differentconsumers. The "upper"end of the demand functionsis defined as the upper end of the functionrepresenting consumers willingness to pay for highervalued uses of electricity(such as lighting);this point is representedby the price-quantitypair of alternativeenergy sourcesto KPLCprovided electricity, in kWh equivalents. For householdsand small commercial consumersthe alternativeis generallykerosene for lighting. Surveydata on households'kerosene consumptionand fuel price data were usedto establishthe kWh consumptionthat wouldyield the equivalentamount of lightingprior to the availabilityof electricity;and to convert the cost of kerosene lightingto an equivalentcost per kWh. For industriesthe alternativeis captivediesel generatorsand data on equipment,maintenance and fuel costs were used to estimatethe kWh equivalentcosts. The average willingnessto pay by consumercategory is calculatedas the averageof the costs associatedwith the lower and upper ends of the estimateddemand function. Thedetailed calculationsin Annex7.3 showthat the averageWTP, in mid-1995, ranged from US cents 13 per kWh to US cents 18 per kWh. As of October 1996,KPLC's marginaltariff rates vary from 2.5 to 10.5US centsper kWh. KPLC's averagetariff is US cents 9.1 per kWh. This impliesan averageconsumer surplus of about 4.9 US cents per kWh.
Fuel CostSavings These savingsaccrue fromthe improvedefficiency of the new dieselplants, and the substitutionof gas oil and kerosenefor lowercost fuel oil, that will cut the averagecost of fuel per kWh.
B. EconomicCosts
General All costs are incrementalas comparedto the "withoutthe project"case, in whichnone of the investmentswould have been made. Theyare expressedin mid-1995prices net of taxes and duties. Investmentcosts includeon averageabout 6 percentphysical contingencies. The local currency component,which is wagesto skilledand semi-skilledlabor and materials,is about 24 percentof total investmentcost. The analysisused a generalconversion factor 0.9 used to convertthe local costs from marketprices to economicprices.
CapitalCosts of New ElectricityGenerating Units The unit cost for thermalgenerating facilities per kW of installedcapacity are as follows: Hydro:US$ 2,240; medium-speeddiesel units:US$ 1,100;and geothermalplants: $2,200-2,300. Annex 7.2 Page 3 of 3
Fuel CostsThe analysisuses border parityprices to definethe economiccost of fuel used in power generation.The forecastborder parityprices are derived fromthe WorldBank's forecastof crude oil prices,as of August 1996,taking accountof refiningmargins, freight, insurance, handling, and transport to project site. The WorldBank forecastsa decliningtrend in real crude oil prices.
Annual Operatingand MaintenanceCosts
Hydroplant: 1.5%of investmentcost ExistingGeothermal plant:158 per kWh New diesel plant fixed: $20 per kW New Geothermalplant: $57 per kWh New dieselplant variable: $0.0105per kWh Existingsteam plant fixed:$37-44 per kW Existingsteam plant variable: $0.0038-0.0044/kWh Existinggas turbine fixed:$17-25 per kW Existinggas turbinevariable: $0.0081-0.0088/kWh Transmission: 2% of cumulativeinvestment cost Distribution: 3.5% of cumulativeinvestment cost Incrementalconsumer cost (billingetc.): $0.003per kWh
C. EconomicLife of Facilities
Hydroplants: 50 years Low speeddiesel generatingunits: 25 years Mediumspeed dieselgenerating units and gas turbines: 20 years Geothermalwells and power plant: 20 years Transmissionand distributionlines: 35 years
D. Fuel Consumptionof Generating Units
Kipevustem plant (existing) 320 liters per MWh (fuel oil) Kipevugas turbine(existing) 370 liters per MWh (Jet fuel/kerosene) Nairobigas turbine(existing) 400 liters per MWh (Jet fuel/kerosene) Low speed diesel (new) 220 liters per MWh (fuel oil) Medium-speeddiesels (new) 230 liters per MWh (fuel oil) GasTurbine (new) 260 liters per MWh (fuel oil)
E. OtherAssumptions
DiscountRate: 12% Averagegrowth in electricitydemand: 5.6 percentper year Growthin GDP: 5.5 percentper year Growth in real prices of output: Constant Cost recovery: KPLC's retail tariffsat US cents 9.1 per kWh, as of October 1996,are about73% of estimatedLRMC, and are adequateto generatea self financingof 22 percent. Furtherincreases to cover full LRMCwill be based on a Tariff Studyto be completedby November1997. Nature of benefits: Supplyof forecastelectricity demand, fuel cost savings, environmentalbenefits fromthe use of more efficientdiesel plants,improved sector efficiency, building of private investor confidence,improved institutional capabilities. Main beneficiaries: Industry,commerce, and households Ano 73 Ntge I of 1 KENYA ENERGYSECTOR REFORM AND INVESTMENT PROJECT PRELIMINARY ESTIMATIONOF CONSUMERSWILLINGNESS TO PAY FOR ELECTRICITY Ksh USS
TYPICALRESIDENTIAL CONSUMER (about 250 kWb/month)
Keroseneusage for lighting(two kerosenelanps/consumer) 12 kWh/month
Monthlycost of keroseneused for lighting:about 4 literstlampat KSh17/1 136 2.47
Costper kWhequivalent to two 40 Wattbulbs for S bous/day(12 kWho/mo I1 0.20
Electricityuse 1995maginal unitrue KShJkkWh(incl. fixed charge) 4 0.07
A JfWHnugAszsgo Pay 7 *.13 TYPICALSMALL COMMERCIAL CONSUMER (about 250 kWljontb)
Keroseneusage for lighting(two kerose Ianmps/consumer)12 kWh/month
Monthlycost of keroseneused for lighting:about 4 litershampat KSh 17M 136 2.47
Costper kWhequivalent to two 40 Watt bulbsfor 5 hoursper day (12 kW I1 0.20
Electncityuse
1995 rwginatwiff rate Ks/kWh 5 0.09 for snall camercia eaaautnpio
SMALLINDUSTRY (abut 1,200kWLaiih)
*cdowwroVr:4 wt 5 A ,swk.JRt, N5X
CapitolCost at USSI100lkW, auitized at ir% 15 yams 38 161.51
AnnualO&M Cost 3% 1485 27.00
Totalcost of the aboveKlHkWh 7 0.12 48 wotk, 5 dqycel, 8 ours/ay. g0 % uundI
Fueleost per kWh at 290g&Wh d KIC28 pw bltdiuael 9 0.17
Tiul cost afqd nugeowm, 16 0.29
1995atnld tif rate 5 0.09 for lht i ianiad emonnptte Avow wOma'umw* 1Ut All
LARGEINDUSTRIES, WATER PUMIG
Diuuigaaa'uim48malz 4dqMwse* I*&h Nt6pAwfbcw
CApitdeos at USSI1001kW, m ithizdat I2%, 15 yons 3 161351
AnnualO&M Cost 3% 1435 27.00
Totaleost perkWh of the above 4 0.03
Fud oostper kWhat 290gikWnad KSh23 perliltu a 9 0.16
Totalcost of dised guafmt perkWh 13 0.24 6tfdbppWEhWA
1995weigted mwr l tiff nae for 1 hidmp a & _ dmeWcam 4 0.07 (id dm-d dwp) 4Amwub U6 Q15
W9I7GHEDA W4GE UTLLINGNW 0PA Y 7o K133EDVAALIS Iw: Dadm d' Pkame.muq,a.i4UJpt keftok ;__mid a. ZPLSCiI4N U_.frw.e _- Annex 7.4 Page 1 of 4 KENYA
Quantitative Risk Analysis
1. The mainrisks of this Projectrelate to three factors:(i) the uncertaintiesassociated with the macroeconomicenvironment, which could affectconsumer demand for electricity,and consequently, output fromthe project facilities;(ii) possibledelays in the commissioningof the generationfacilities; and (iii) the value of benefits. In addition,uncertainties related to the costsof equipmentand installationcould also affectthe project's net benefits,though not in the sameextent as thoseassociated with the demand forecast or the value of benefits. The projectis also subjectto risks which cannotbe hedgedin project design. These includerisks associatedwith hydrologywhich will affectthe outputquantity from the project facilities. They also includethe impactof internationalpetroleum prices.
2. A quantitativerisk analysiswas carriedout to asses the impacton the project's economicreturns of uncertaintyin underlyingassumptions and predictions. The primaryrisks affectingthe project's economicoutcome and the probabilitydistribution to be assignedto each of themwere defined based on the projectteam's estimates. The stochasticnature of the projectimplementation was subsequently modeledusing a commerciallyavailable risk analysisprogram. The expectedrate of returnand NPV- with their probabilitydistributions - were determinedusing a Monte Carloprocess with a LatinHybercube samplingtechnique in the simulationof the model. The major projectrisks and the probability distributionsassigned to each of the risk variablesare discussedbelow.
* Electricitydemandforecast. The electricitydemand forecast has a major impact on the project's economicviability. A triangulardistribution with minimum,most likelyand maximumvalues was assignedto the averageannual demand growth rates. The forecastprepared by KPLCand confirmedby Acres InternationalLtd. was used as the most likelyoutcome. It predictsan averageannual growth of some 5.6 percentbased on the expectedGDP growth rate of 5.5 percent. The Bank's economicforecast providesthree developmentscenarios: the low growthscenario assumes an averageannual GDP growth rate of about 3.2 percent,the high scenarioabout 7 percent,while the averagegrowth rate is estimatedat about 5.5 percent. To representthe uncertaintyin the economicgrowth rates in the electricitydemand forecast,the GDP growthrates were translatedinto averagedemand growth rates using the GDPto electricitydemand elasticity. The observedaverage elasticity for the period 1988-1992was about 2. Given, however,that the tariffshave (and will) go up and tnat efficiencymeasures will be introduced,the elasticityis assumedat I in this analysisin line with that used in the demandforecast. This gives the minimumand maximumannual growthrates of 3.2 percent,and 7 percentrespectively. The resulting distributionis skewedtowards the low side, that is, the probabilityfor low demand growthexceeds the probabilityfor high growth.
* Consumers'Willingness to Pay. The value assignedto consumerswillingness to pay will determinethe value of the benefits. A triangulardistribution was selectedwith the averagevalue being the estimatedUS$ 0.14per kWh and the maximumand minimumvalues defined as US$0.16and US$0.08, respectively. The minimumvalue coincideswith KPLC's currentaverage tariff. The resultingdistribution is negativelyskewed, i.e., the probabilityfor low valuesis greaterthan the probabilityfor high values.
* Commissioningdates for projectfacilities. The commissioningof the generationfacilities is expectedto follow the least-costinvestment schedule, where the first facility, Kipevu1, would be commissionedin 1999, and the two finalplants, Sondu Miriu and the OlkariaII in 2001. In case the constructionof someor all of the facilitiesis delayed,project benefits would decline and the economy would have to bear an additionalcost of not having electricityavailable. Sincethe Projectincludes both publiclyand privatelyfnanced facilitiesand they are at differentlevels of preparedness,it is expectedthat the probabilityof delay varies from plantto plant. For the publiclyfinanced projects, bidding documents have alreadybeen preparedso the biddingprocess could start as soon as the project becomeseffective. In this case, the main causeof delay in commissioningwould be delaysin the constructionprocess. However, Annex 7.4 Page 2 of 4 KPC's track record in projectimplementation is fairlygood, so the risk of delay in KipevuI and Olkaria II are consideredrelatively low. For SonduMiriu, the risk is higherbecause of the civil works involved. With respectto Gitaru, the risk of delay is related to the abilityof KPC to generatethe required financing internally. For the privatelyfinanced facilities, bidding document were issuedin July 1996,however, there is the possibilitythat the selectionprocess and negotiationscould drag. An additionalcause of delays could be the lapse in implementingtariff increases,resulting in insufficientcounterpart funding. The followingprobabilities were assignedfor delaysin the six generationfacilities:
Kipevu1: oneyear delay 10% KipevuII (IPP): oneyear delay 80 % twoyear delay 70 % threeyear delay 50 % OlkariaII: oneyear delay 20 % OlkariaIII (IPP): oneyear delay 80% twoyear delay 70% threeyear delay 50% SonduMiriu oneyear delay 40% Gitaru3rd unit: oneyear delay 50%
* Hydrology. The annualhydrology determines the outputfrom the hydroelectricplants. As the project wouldfinance both hydro and thermal plants,dry hydrologicalconditions would mean loweroutput from SonduMiriu and Gitaruand increaseduse of thermalgeneration resulting in highergeneration cost. Wet hydrologicalconditions would mean lessneed for the thermalplants and maximumoutput Sondu Miriu and Gitaru.A triangulardistribution representing minimum, most likelyand maximumvalues was assignedto the annualhydro outputbased on results from systemsimulations.
* Projectinvestment cosL The capitalequipment of the project comprise,to a large extent, standard equipmentand the requiredcivil works are not excessiveindicating a moderaterisk of cost variations. The civil works includetunneling work for SonduMiriu, erectionof powerhouses for the Geothermalplants, installationof the modulargeothermal plants, steam gathering and transmissionsystems, and the erection of a new power house for the Kipevuplants, and installationof the Kipevuand Gitaruunits. Poor procurementand supervisionperformance by the implementingagencies or certain Governmentactions could, however,cause cost increases.Cost savingsare also possibleowing to favorableconditions and strict cost-controlfrom the side of the privateinvestors. To representthe risk associatedwith the cost estimates,the analysisassigned a triangulardistribution to this variablewith the minimumand maximum valuesestablished at, minus25 percentand plus 25 percentrespectively of the estimatedvalue, i.e., total investmentcosts would vary in the range of US$695- US$1,160million
* Petroleumproducts prices. The analysisassigned a triangulardistribution to the petroleumprice forecast. The likeliestannual prices werederived from the Bank's crudeoil price forecastof August 1996, which predicts a decreasein real crude oil prices:from aboutUS$ 18 per barrel in 1996to US$ 15 per barrel in 2005(in 1995prices). The minimumand maximumvalues were establishedon eitherside of the likeliestvalues as plus or minus 1.96times the standarddeviations provided in the Bank's forecast. The internationalprices were adjustedfor borderparity pricesadding the economiccost of transportationand handlingto the FOB prices. Based on historicaldata, oil pricesdo not to vary fully randomlyfrom one year to another,rather, they tend to be sticky,except for major eventssuch as the Gulf War that caused a temporary,steep increase. A rank-ordercorrelation coefficient of 0.8 reflectsthe positive correlation between the annualprices. Annex 7.4 Page 3 of 4
Results
3. Figure 1. below showsthe probabilitydistribution for the expectedERR and indicatesa 50 % probabilityfor an ERR of 15.5percent or more. The expectedERR from the risk analysisis less than that from the deterministicevaluation because the probabilitydistribution for the main variablesaffecting projectbenefits - electricitydemand forecast and willingnessto pay - are negativelyskewed.
Figure 1. Probability Distribution for ERR
0.12 - 0.10 --- - -
0.0 8 ------
0.0 6 ------0 rI 0 .04 ------a.
0.02 ------o
0.00 I.- ER CD D C
ER(%)
4. Figure 2. below, displaysthe project's expectedNPV (at 12%)and showsthat the probabilityof a positiveNPV is about 80%. There is, therefore,a 20%probability that the projectwould have a negative NPV. Lowerthan expectedelectricity sales, significant delay in the commissioningof the facilitiesand lowerthan expectedwillingness to pay wouldcontribute to the negativeNPV.
Figure 2. Cumulative Probability for NPV ((@12%)
1.0 10 0.9 ------.. ------>< 0.7 ------.-.------
0.4 ------3 0.7 v . ------> 0.3 -V------0 0.1 ------0.0 co D CD 0 N CD 0 0 C SD 0) CD 0) - ? U~)C UD CI) 0 O CD CO N -- C') CV) ~ US$ million Annex 7.4 Page 4 of 4
Risk Management
5. The risk analysisindicated that the probabilityof a negativeNPV is not significant. However, projectdesign and implementationwere formulatedto mitigatethe risks leadingto unfavorableoutcomes. Withrespect to deterioratingeconomic performance which couldlead to lowerthan forecastdemand for electricity- the Bank's continuedbroad policy dialogueon the macroeconomicreform program,will help focusingthe Government'smacroeconomic reforms on maintainingstability. This includesthe tightening of fiscal policiesto attract inflowsof externalassistance to spur economicactivity.
6. The risk associatedwith delays in the commissioningof facilitieshas been reducedfor the publiclyfinanced projects by preparingthe biddingdocuments well in advance,so that the bidding process can start as soon as the projectbecomes effective. Previousexperience suggests that KPC is fairly good in implementingpublicly financed generation projects. Nevertheless,given the large size of the Project,the Projectwill provideconsultant and advisoryservices for projectimplementation, engineering and financial managementto complementKPC's capacity. For the privatelyfinanced, IPP, projects,the risk of delays has been partiallyreduced, through financing under the ProjectPreparation Facility for consultantservices for the preparationof the biddingdocuments, which is currentlyongoing. Theultimate success will depend on how attractiveKenya's energysector is for private investors. The agreedchanges in the legal and regulatoryframework should contribute to increasinginvestor confidence. Another risk is delay in mobilizingthe correspondinglocal financingrequirements, which could lead to implementationdelays. The agreementon annualreviews of the investmentprogram and related financingplans, as well as the requirementto meet at least 30% of investmentneeds is designedto minimizethis risk. Regardingthe potentiallack of counterpartfunding as a resultof delaysin implementingtariff adjustments,the agreement on adequatetariff adjustmentsbased on a tariff study,is designedto mitigatelapses. The tariff policy will also be monitoredin the contextof IDA's continuedmacroeconomic dialogue.
7. The capital equipmentof the projectcomprise mainly of standardequipment and the civil works are not significant,indicating a moderaterisk of cost increases.These risks are counterbalancedby includingadequate contingencies in the cost estimates. KENYA Annex 7.5 Enery Sector Reform and Power Development Project Page 1 of 1 Fiscal IGovernment Budget Impact Analysis
1997F 19981 1999 2000 2001r 2002 2003 2004 2005 2006 2007 2008 2009 2010 2017 2018 2019 2020 Budget Revenue USS million _ i
IbAcredit ;3.5 35.0; 46.7 26.8 10.6 1.41 1.0, EIB loan 4.31 16.1 18.6 8.2 1.5 . KfVloan 2.0 9.4 8.4 1.1 . - Interest & repayment on IDA onlendcredit I 13.01 13.1 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.21 13.2 13.2 13.2 Interest & repayment on EIB onlend loan 2.8 4.5 5.2 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 Interest & repayment on KfW onlend loan 2.11 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.11 2.1 2.1 Reduced debt service on behalf of KPLC & KPC VATon incrementalelectricity sales -. 0.0 0.0 oo9 1.1 1.5 1.9 2.3 2.9 2.9 2.9 2.9 2.9 2.9 2.80 2.81 2.8: 2.8 Incremental corporate tax revenue 0.01 0.0 0.0 0.84 1.0 1.4 1.8 2. 21 2.7 2.7 2.7 2.7, 2.7 2.61 2. 2.6i 2.6 Incrementalintake from petroleumtaxes 0o.0 °° o00.0o ' 0. 5.2 -4.1 1.1 5.5 13.2 24.6 24.65 24.6 32.3 32.31 32.3 32.3 32.3 Total 9.8 6051 76.6 42.2 19.4 30.0 21.2 26.1 31.6 W4 50.7 50. 58.5 58.4 58.3 58.31 58.3
Budget ExpenditureUSS million I jI - I 33 IDA creditonlending I 1.5 .0 44.7 24.8 8.6 1.4' 1.01 0.0 0.0 I EIB loan onlending 4.3 16.1 18.6 8.2 1.5 0.0 0.0 0.0 0.0 I 1 KfW loan onlending 2.0 9.4 8.4 1.1 0.0 0.0 o.0o 0.0 0.0 IDA credit fee | 0 0.3, 0.61 0.81 0.9 0.9 0.9 0.9 0.9 09 0.9 0.9 0.9o 0.9 0.9i 0.9, 0.9o 0.9
Repayment of IDA credit [ 3 3.2 3 t 2.51 2.5 2.51 2;53 53.3: 530 5.01 5.0 Repayment of EIB loan principal & interest 24 3 3.3 3.3 3.3 3.3 33 33. 3 3 33 33 33i 3.31 3.3 Repayment of KfW loan principal & interest I I3 1.3 1.3 1.3, 1.3, 1.34 1.3 1.3
Total 7.9 58.85 74.8 37.9 14.2 5.6 5.2 4.2 4.2 4.2 8.0 8.0 8.05 8.0 10.5: 10.5' 10.51 10.5
Annual Net Impact on Government Budget USS million 2.0| 1.7 1.8 4.3 5.2 24.4 16.0i 21.9 27.4 35.2 42.7 42.81 42.7 50.51 47.9 47.9! 47.8' 47.8
Present discounted value of revenue @ 12%: 327 US$ million ' 1 j 1 Presentdiscountedvalueofexpenses@12%: 167 US$milion j , I I | i NPV of fiscal revenue @12% 1611US$ million
'-"I-n0. Annex 7.6 Page 1 of 4
REPUBLIC OF KENYA ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT Summaryof Objectivesand Key PerfonnanceIndicators
OBJECTIVES INPUTS OUTPUTS RISKS AND OUTCOMES AND (Resourcesprovided (Goods and Services CRITICAL IMPACTS for project activities) produced by the Project) ASSUMPTIONS (of project activities) (The outcome is depended on...) Restructure the *IDA Credit (US$3.0 * study to restructure the *delays in the transfer *KPC Board and MD power subsector million) power sub-sector into two of assets, allocation of appointed by to increase separate companies; one for staffing and financial December 1996 efficiency and Credit will finance generation and another restructuring *KPC personnel task attract private phase I of a power sub- transmission & distribution force appointed by sector sector restructuring * performance contracts February 1997 participation study, consultants to between GoK and the two *Staff transferred to assist GoK in power companies (KPLC & KPC) KPC by May 1997 restructuring, in * power purchase agreement *TRDC to voluntarily securing private sector between KPC and KPLC wind up by March investment and in * non-core activities 1997 developing performance contracted out to the private *Transfer of assets contracts sector between the * private investors invited to companies by October Phase 11of the power generate electricity 1997 sub-sector restructuring *KPLC management study was financed agreements terminated under IDA credit 2440- by October 1997 KE. *Performance contracts between GoK and KPLC and GoK and KPC signed by June 1997 *Power purchase agreements between KPLC & KPC signed by June 1997 *KPC's self-financing ratio 20% in FY1997/1998 and FY1998/99, and 25% thereafter * KPLC's self financing ratio 25% in FY1997/19998 and 1998/1999, and 30% thereafter. *KPC's and KPLC's debt service coverage ratios at least 1.5times starting in FYI 997/98 *customer/staff ratio of 60 for KPLC *accounts receivable of no more than 60 days sales * KPLC has identified and contracted out additional non-core services to the private sector by FY1999. *increased private sector participation in the subsector's core Annex 7.6 Page 2 of 4
REPUBLIC OF KENYA ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT Summaryof Objectivesand Key Perfornance Indicators
activities
Create a legal *IDA Credit * legal and regulatory study *delays in *ERB established by and regulatory (US$250,00) to recommend amendments Parliamentary December 1997 framework to to the Electric Power Act to approval of the draft *Regulators appointed commercialize Credit fill finance a create an autonomous Amendments to the by December 1997 sector legal and regulatory Electricity Regulatory Board Electric Power Act * electricity tariffs operations and framework Study and (ERB) based on LRMC and increase private technical assistance for * technical assistance for *adequacy of staffing cover financial costs of sector the ERB. ERB of KPC and KPLC supply participation * Further tariff adjustments * the effectiveness of *all power subsector A tariff update Study will be based on the results the ERB activities will be financed under of the tariff update Study to commercially IDA Cr. 2440-KE. be completed by April 1996. operated
Meet forecast *IDA Credit (US$82.4 * installation of following * construction delays *Interconnected electricity million) generation capacities: * private sector system electricity sales demand at least *OECF loan (US$82.8 interest will increase from cost million) * 150 MW at Kipevu in * delays in obtaining 3,402 GWh in FY1996 *EIB loan (US$36.6 FY1999/00 private sector funding to 4,500 GWh in million) * 128 MW at Olkaria in * adequacy of internal FY2002 *KfW loan (US$20.9 FY2001/02 resources for funding * Number of new million) *72.5 MW at Gitaru in of the 72.5 MW at connections will *Private Sector FY2000/01 Gitaru, part of the cost increase annually from (US$262.5 million) of the other plants and 406,300 in FY1996 to *KPC intemal resources *reinforcement and for the upgrading of 540,000 in FY2002 (US$93.9 million) upgrading of distribution the distribution system * private sector owned *KPLC internal lines and installation of * project cost generation will resources (US$29.9 transformers and substations overruns/savings increase by 135 MW million) * macroeconomic by 2002 * two power plants offered conditions will affect Funds will be used to to the private sector electricity demand procure equipment, * hydro plant output works,consultants and will depend, inter alia, technical assistance for on hydrological increasing KPC's and conditions KPLC's implementation * adequate plant capacity maintenance measured as the average annual IDA, EIB and KfW capacity availability in funds will help to %. KPC's target cofinance construction availabilities in of Olkaria II Power FY2002: hydro 85%; Plant. Private sector geothermal 90%; equity and loans will Kipevu I 80%. finance construction of * international Olkaria III and Kipevu petroleum prices 11Power Plants. KPC and KPLC internal resources will finance part of the cost of new power plants and upgrading of the distribution systems
Improve the IDA Credit (US$11.7 * upgrading/installation of * timeliness of * Network losses of efficiency of million) feeders, capacitors and implementation 14.5% or less of net electricity substations * effort by KPLC staff generation by FY2002 supply and use Funds will be used to * electricity demand * cost overruns/savins *KPLC actively Annex 7.6 Page 3 of 4
REPUBLIC OF KENYA ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT Summary of Objectives and Key Performance Indicators
procure equipment, management program offering its customers works, studies, * study on guidelines on efficiency and demand consultants, training and energy efficiency standards management advice technical assistance. for equipment and labeling and service by 1998 program *at least 2 energy * study on financing efficiency/demand mechanisms for energy management measures efficiency measures implemented by 1999 * expand KPLC's training *KPLC select program in demand personnel trained in management and energy the design and efficiency implementation of * action planning demand management workshops programs by 1998 * demonstration programs *appliance codes and on efficient equipment and labeling study lighting completed by FY1998 * customer satisfaction measured through annual KPLC customer surveys.
Deregulate *IDA Credit * petroleum market and *may take long to * petroleum prices and petroleum (USS344,000) pricing study develop adequate importation liberalized markets * study to recommend monitoring capacity in November 1994 Credit will finance adequate LPG cylinder * market-determined studies, technical standards to promote retail prices for assistance and training competition petroleum products for deregulation * adequately trained peronel maintained implementation. in the monitoring cell in the * a monitoring cell at Ministry of Energy the MOE established by FY1996 * maintenance of trained personnel in the monitoring cell * avoidance of anti- competitive behavior * maintenance of adequate supplies by oil companies
Develop *IDA Credit (US$19 *confirmation of adequate *adequacy of the *.... wells drilled by indigenous million) geothermal resources for a geothermal resource FY2002. energy fourth power plant in the base * private sector invited resources *EIB loan (US$12 Olkaria area * private sector to develop resources million) *feasibility study and interest and construct and detailed designs for the * implementation operate power plants *KPC internal resources plant delays by FY1998. (US$17 million) *confirmation of adequate * possible cost The funds will finance resources for subsequent overruns/savings equipment, works, pre- power plant (s) in the feasibility and feasibility Olkaria Domes/ Suswa and studies, drilling of Longonot areas geothermal wells, a *prefeasibility and Panel of Experts, advanced feasibility studies training and technical assistance for capacity building. Annex 7.6 Page 4 of 4
REPUBLIC OF KENYA ENERGY SECTOR REFORM AND POWER DEVELOPMENT PROJECT Summaryof Objectivesand Key PerformanceIndicators
Developa *IDACredit * surveyof energyend-use * delays in * strategyfor strategyfor (US$258,000) * energysupply and implementation householdand householdand marketingsurvey * delays in GoK renewableenergy rural energy The funds will finance * policy, institutionsand approvalof strategy agreedby the GoK by development studies,equipment, pricingstudy * effort of the local FY1999 and promote trainingand technical * beter trained local professionals. * local analytical renewable assistancefor capacity professionals capacitydeveloped energy. building. * study on guidelinesfor * solar PV information solar PV standards campaigninitiated by * disseminationof 1998 informationabout solarPV * taxes on solar PV systems. equipmentat level withother generation eqipmentstarting in .______FY1997.
VictoriaFofanah M:\2EIEXCH\JJMAWENI\ANNEXES\ANX7-6NW.DOC December3, 1996 8:58AM
MAP SECTION
IBRD 28165
K E N YA 40 FACILITIESPROPOSED UNDER THE PROJECT EXISTINGFACILITIES LlENERGY SECTOROLL IV AREFORl M1AND 0 GEOTHERMALPOWER STATION t OLKARIAGEOTHERMAL FIELD POWERDEVELOPMENT PROJECT A DIESELPOWER STATIONS HYDROPOWER STATIONS POW ER DEVELOPMENTPROJECT ~ ~~~~~OTHERPROPOSED FACILITIES: A, DIESEL POWER STATIONS POWER SYSTEM 220kVTRANSMISSIONLINES * STEAMPOWER STATION -7 - 132 kV TRANSMISSIONLINES KPLCDISTRIBUTION AREAS S U D A N - 7 POSSIBLESITES OF HYDRO - 220 kV TRANSMISSIONLINES ,1, lPOWER STATIONS 132 kVTRANSMISSION LINES / -*,,,_- X DENSELYPOPULATED AREAS 66 kV TRANSMISSIONLINES INTERNATIONALBOUNDARIES 33 kV TRANSMISSIONLINES
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