Report and Recommendation of the President to the Board of Directors
Sri Lanka Project Number: 42085 August 2008
Proposed Loan Power Transmission Enhancement Project (Azerbaijan)
CURRENCY EQUIVALENTS (as of 31 July 2008)
Currency Unit – Azerbaijan new manat/s (AZN) AZN1.00 = $1.24 $1.00 = AZN0.81
ABBREVIATIONS
ADB – Asian Development Bank CAPEX – capital expenditure EA – executing agency EBRD – European Bank for Reconstruction and Development EIRR – economic internal rate of return EMMP – environmental management and monitoring plan ES – environmental specialist ESM – environmental supervision and monitoring expert FIRR – financial internal rate of return FMIS – financial management information system ICB – international competitive bidding IEE – initial environmental examination IFRS – international financial reporting standards IsDB – Islamic Development Bank JBIC – Japan Bank for International Cooperation JSC – joint-stock company KfW – Kreditanstalt für Wiederaufbau LARP – land acquisition and resettlement plan LIBOR – London interbank offered rate MENR – Ministry of Ecology and Natural Resources NCB – national competitive bidding NPV – net present value PCB – polychlorinated biphenyl PMU – project management unit ROW – right-of-way TA – technical assistance TOR – terms of reference VAT – value-added tax WACC – weighted average cost of capital
WEIGHTS AND MEASURES
GWh (gigawatt-hour) – 1,000 megawatt-hours kV (kilovolt) – 1,000 volts kWh (kilowatt-hour) – 1,000 watt-hours MVA (megavolt-ampere) – 1,000 kilovolt-amperes MW (megawatt) – 1,000 kilowatts MWh (megawatt-hour) – 1,000 kilowatt-hours V (volt) – unit of voltage
NOTES
(i) The fiscal year of the Government and its agencies ends on 31 December. (ii) In this report, "$" refers to US dollars.
Vice-President B. Lohani, Vice-President-in-Charge, Operations 1 Director General J. Miranda, Central and West Asia Department (CWRD) Director H. Wang, Infrastructure Division, CWRD
Team leader T. Luo, Energy Specialist, CWRD Team members R. Abbasov, Economics Officer, CWRD L. Blanchetti-Revelli, Social Development Specialist (Resettlement), CWRD R. Nagpal, Counsel, Office of the General Counsel A. Rullan, Associate Project Analyst, CWRD R. Sanda, Investment Specialist, CWRD M. Villanueva, Administrative Assistant, CWRD J. Weinstock, Senior Environment Specialist, CWRD
CONTENTS Page
LOAN AND PROJECT SUMMARY i MAP I. THE PROPOSAL 1 II. RATIONALE: SECTOR PERFORMANCE, PROBLEMS, AND OPPORTUNITIES 1 A. Performance Indicators and Analysis 1 B. Analysis of Key Problems and Opportunities 2 III. THE PROPOSED PROJECT 7 A. Impact and Outcome 7 B. Outputs 7 C. Project Investment Plan 8 D. Financing Plan 9 E. Implementation Arrangements 9 IV. PROJECT BENEFITS, IMPACTS, ASSUMPTIONS, AND RISKS 13 A. Economic Analysis 13 B. Financial Analysis 13 C. Financial Management and Sustainability of Azerenergy 14 D. Environmental Assessment 16 E. Social Safeguards 17 F. Assumptions and Risks 18 V. ASSURANCES 18 VI. RECOMMENDATION 20
APPENDIXES 1. Design and Monitoring Framework 21 2. Power Sector Analysis 23 3. Problem Tree Analysis for the Power Sector 29 4. External Assistance to the Power Sector 30 5. Cost Estimates and Financing Plan 31 6. Project Implementation Schedule 32 7. Procurement Plan 33 8. Outline Terms of Reference 37 9. Summary of Economic Analysis 39 10. Summary of Financial Analysis 45 11. Financial Performance and Projections of Azerenergy 49 12. Financial Management Assessment of Azerenergy 56 13. Summary Poverty Reduction and Social Strategy 60
SUPPLEMENTARY APPENDIXES (available on request) A. Initial Environmental Examination B. Summary Initial Environmental Examination C. Detailed Economic Analysis D. Financial Projections and Corporate and Organization Structure of Azerenergy E. Detailed Analysis of Financial Performance and Management of Azerenergy
LOAN AND PROJECT SUMMARY
Borrower Azerenergy Open Joint-Stock Company
Guarantor Republic of Azerbaijan
Classification Targeting classification: General intervention Sector: Energy Subsector: Transmission and distribution Theme: Sustainable economic growth Subtheme: Fostering physical infrastructure development
Environment Category B: The initial environmental examination (IEE) has been Assessment conducted (Supplementary Appendix A) and the summary IEE is in Supplementary Appendix B.
Project The proposed Project is a priority investment project under the state Description program on the development of the fuel and energy sector in the Republic of Azerbaijan. It will construct a double-circuit 220 kilovolt (kV) transmission line from Mingechevir hydropower plant to Absheron substation, to replace the existing two single-circuit 220 kV transmission lines (Mingechevir 1 and 2), which have been used for about 60 years. The Project will increase the capacity of the power transmission network in the west-to-east direction. This is crucial for ensuring the required stability of power supply to consumers in the key Azeri industrial and economic hub closest to the capital city of Baku.
The project components comprise (i) construction of a double-circuit 220 kV transmission line of 280 kilometers (km); (ii) construction of Agdash substation with installation of two 125 megavolt-ampere (MVA) transformers and associated 110 kV transmission lines near Agdash substations; (iii) expansion of Absheron substation; (iv) project management support; and (v) institutional strengthening.
Rationale Energy is a vital input to support growth in Azerbaijan’s non-oil services and industry sectors. The power sector, along with the oil sector, plays a leading role in Azerbaijan’s social and economic growth, contributing one third of the country’s gross domestic product in 2007. Development of the power sector has been one of the Government’s priorities. While the country has been successful in engaging the private sector for developing and exporting its oil and gas resources, the domestic energy sector is threatened by unreliable and inadequate power supply caused by limited maintenance of aging infrastructure and underinvestment. Effective generation capacity has shrunk because of insufficient funds for rehabilitation and capacity addition. Low power plant efficiency and high losses of transmission and distribution lead to wastage of fossil fuels that could have been exported, and nearly double the emissions of greenhouse gas and other pollutants that damage the regional and global environment.
Today, about 48.4% of Azerbaijan’s 8.5 million people live in rural areas, often with insufficient access to quality basic services. Lack of sufficient ii
power, gas, and heat has aggravated the regional imbalance in the country. Poor quality and unreliable electricity supply (i) inhibit industrial and commercial activities, constraining economic growth and employment opportunities in regional areas; (ii) promote switching to more polluting fuels and accompanying environmental impacts; and (iii) cause hardship to the population and affect their health.
The power network of Azerbaijan faces two major development challenges: (i) deteriorating and aging generation, transmission, and distribution facilities; and (ii) inadequate levels of investment and maintenance. Over 20% of all energy equipment and over half of the network facilities are well beyond their useful life. This reduces the reliability and efficiency of the power network operation. The high level of physical wear of equipment at power plants and networks leads to frequent power failures in the populated areas and affects the economic activities in the country. The inadequate capacity of transmission lines also results in a shortage of reserves in the stability of the power system, increasing the potential risk of power system operation. Rehabilitation and upgrading of transmission facilities would significantly reduce the risk of future system failure.
The Project targets key strategic transmission lines, which are severely deteriorated and need to be rehabilitated on a priority basis. The Project will also contribute to optimizing the domestic energy resource utilization and reducing fossil fuel consumption and power import. The current Azerbaijan power system is not being operated optimally because of constraints on existing components of the transmission network. Hydropower energy generated in the west region is not efficiently delivered to the central region where demand is increasing rapidly. Replacement of the 220 kV transmission lines would allow the existing hydropower plant to increase its available outputs to the optimal level— the peak power supply could be enhanced while power energy generated from thermal power plants in the central and east regions could be reduced. This would permit optimal utilization of the grid networks and generation capacity by reducing the shifting operation time of large thermal power plants, thus improving the efficiency and stability of generation units and reducing excessive consumption of fuels. The saved fuel including gas and oil would be exported to increase government revenues. Thus, Azerenergy Open Joint-Stock Company (Azerenergy) and the country would benefit from savings in fuel expenditures, improving energy efficiency, and reducing environmental pollution.
Impact and The Project aims to facilitate the country’s economic development by Outcome strengthening infrastructure development, removing the bottleneck of power transmission, and improving the efficiency of services. The project impact is an improved power transmission system that provides reliable and adequate electricity for sustained economic growth.
The outcome will be an expanded and strengthened backbone 220 kV power transmission and distribution network, with transmission bottlenecks removed and losses reduced.
iii
Project The total investment cost of the Project is estimated at $240 million. Investment Plan
Financing Plan Source Amount % Asian Development Bank Ordinary Capital Resources 160.0 67 Azerenergy 80.0 33 Total 240.0 100 Source: Asian Development Bank estimates.
A loan of $160.0 million from the ordinary capital resources of the Asian Development Bank (ADB) will be provided under ADB’s London interbank offered rate (LIBOR)-based lending facility. The loan will have a 25-year term including a grace period of 5 years, an interest rate determined in accordance with ADB’s LIBOR-based lending facility, a commitment charge of 0.15% per annum, and such other terms and conditions set forth in the draft loan and guarantee agreements.
Azerenergy, which is the state-owned enterprise responsible for power production, transmission, and distribution in Azerbaijan, will be the Borrower while the Government will provide the sovereign guarantee. The foreign exchange risk will be borne by the Borrower.
Period of Until 30 June 2012 Utilization
Estimated Project 31 December 2011 Completion Date
Executing Azerenergy Agency
Implementation Azerenergy will set up a project management unit (PMU) responsible for Arrangements overall project implementation. Azerenergy will be assisted by a team of international and national consultants in the preparation of bidding documents, bid evaluation, and project supervision. Relevant international practices and standards will be adhered to in the implementation of the Project. Detailed construction and installation drawings will be available under the Project and will be in line with specifications in the design, supply, and installation (turnkey) contracts.
Procurement Procurement of goods and services financed from the proposed ADB loan will be carried out in accordance with ADB’s Procurement Guidelines (2007, as amended from time to time). The major procurement will be design, supply, and installation contracts for the transmission lines and substation facilities. The procurement plan will be updated at least annually covering the next 18 months of procurement activity.
Consulting The project implementation consulting services include (i) procurement Services and bidding for the tendering of design, supply, and installation contracts; (ii) supervision of installation and construction, final testing and commissioning, and quality assurance; and (iii) project performance
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monitoring and evaluation. Azerenergy will finance the project implementation consultants entirely from its own resources, and engage the consultants in accordance with its procedures acceptable to ADB.
Project Benefits The direct benefits of the Project are improved system performance, and Beneficiaries reduced transmission system losses, reduced maintenance costs, deferred expenditure on new generation, reduction in imported power, and salvage value from removal of the existing line. Such benefits have been estimated using extremely conservative figures. The economic base case shows the Project’s economic internal rate of return of 14.8%.
Long-term economic benefits are generated from the least-cost production of power, compared with developing an alternative energy source. Social impacts include increased industrial production, opportunity for expansion of small and medium-sized enterprises, higher living standards through better infrastructure for schools, clinics, local services for lighting and communication, and new job opportunities for local residents.
Risks and The Project is fully supported by the Government. The project components Assumptions are straightforward, with minimal environmental and social impacts. The Project was designed based on the following key assumptions: (i) macroeconomic growth remains stable, (ii) the Government remains committed to power sector reforms and development, (iii) the Government is committed to establishing cost-recovery tariffs, (iv) Azerenergy is committed to implementing social and environmental mitigation measures in a timely manner, (v) the project and financial management of Azerenergy is sound, and (vi) counterpart financing is adequate.
Risks to the Project include (i) an unexpected increase in the prices of commodities and raw materials, (ii) a delay in procurement and recruitment of consultants caused by government approvals, and (iii) delays in implementation of social and environmental mitigation measures. The Government and Azerenergy have taken the necessary measures to minimize these risks. The cabinet of ministers will coordinate the work of the relevant government agencies to ensure that issues are resolved promptly. Adequate consulting services are provided to assist Azerenergy to manage implementation, monitor performance, and report to ADB. Price contingency funds are included to respond to unforeseen cost changes. Azerenergy also committed to implement the social and environmental mitigation measures fully, and relevant provisions will be incorporated in the civil works contracts.
The project financial risk is low. There is clear evidence that the Government has had considerable success in transition to full cost recovery for the power utility by 2010. It also confirmed that no subsidies will be given to Azerenergy from 2008. Tariff reform has significantly supported the target of achieving a financially self-sustainable power sector. The proposed Project, together with efforts from other development partners, will have a synergized effect on enhancing the financial performance of Azerenergy and will assist the Government in achieving its reform agenda.
o o 46 00’E 50 00’E
REPUBLIC OF AZERBAIJAN Balaken R U S S I A N F E D E R A T I O N er G E O R G I A iv POWER TRANSMISSION Zagatala R Khudat ur m ENHANCEMENT PROJECT Sa
Gusar Khachmaz Gakh
Guba Sheki Devechi Agstafa C A S P I A N S E A Shamkir Gazakh Siazan o Reservoir Oghuz o 41 00’N Tovuz Min 41 00’N gec hev Govla ir R Gabala eser Khyzy voir Shamkir Mingechevir Ganja Ismailly Sumgayit Geranboy Yevlakh Khanlar Gadabey Maraza Pirallahl Agdash Ujar Agshu Pirallahl Island Dashkesan K Absheron Khyrdalan ur Terter R iv BAKU Chilov Island Barda er Kyurdamir Sangachal Agdere Zardab A R M E N I A Hajiqabul Kelbajar Agjabedi Sabirabad Alyat Sarisu Lake Agdam Ali-Bayramli Khojaly Imishli Saatly Khankendi K u Beilagan r
R
Khojavend i Shusha v Heidarabad e Lachin r A Sharur Fuzuli National Capital r a Salyan z r City/Town R ive Bilasuvar i v R e az r Ar Thermal Power Station Shahbuz Gubadly Neftchala Hydropower Station Qivraq Jebrail NAKHCHIVAN Substation Araz Reservoir AUTONOMOUS Jalilabad Project Transmission Line Nakhchivan REPUBLIC 500 kV Transmission Line Babek Zangilan Masally o 300 kV Transmission Line o 39 00’N Julfa 39 00’N Ordubad 220--230 kV Transmission Line River Araz River Yardymly International Boundary N Lenkaran Lerik Boundaries are not necessarily authoritative.
0 25 50 75 0
8 I R A N
- Astara 0 Kilometers 7 6 5
H o o 46 00’E 50 00’E R
I. THE PROPOSAL
1. I submit for your approval the following report and recommendation on a proposed loan to Azerenergy Open Joint-Stock Company (Azerenergy), guaranteed by the Republic of Azerbaijan for the Power Transmission Enhancement Project. The design and monitoring framework is in Appendix 1.
II. RATIONALE: SECTOR PERFORMANCE, PROBLEMS, AND OPPORTUNITIES
A. Performance Indicators and Analysis
2. Azerbaijan is rich in diverse and abundant energy resources. The overall volume of the country’s hydrocarbon reserves is estimated 4 billion tons of oil equivalent, while the natural gas reserves are 1.8 trillion cubic meters. Oil production dominates in the country’s economy, with 50 million tons of oil produced annually.
3. In 2007, gross domestic product increased by 25%, supported by a surge in crude oil production (31.5% increase) and exports (39.1% rise). This was due to increased production in the Azeri–Chirag–Guneshli oil field, whose offshore oil is exported to western markets through the Baku–Tbilisi–Ceyhan pipeline. Natural gas production was increased by over 70% owing to the Shah Deniz offshore bloc, which started in 2007. Overall, the economy was boosted by large-scale public investment in infrastructure. Public investment focused on social sectors (health, education) and improvement of public utilities (electricity, heating, water supply, and sanitation).
4. The power sector, along with the oil sector, plays a leading role in Azerbaijan’s social and economic growth. The energy sector plays a central role in the economy, contributing to one third of the country’s gross domestic product in 2007, making it the economy’s largest segment. Development of the power sector has been one of the Government’s priorities.
5. Azerenergy is the state-owned enterprise responsible for operation and management of the high-voltage transmission network and major thermal and hydropower generation plants. Azerenergy owns major generation and all transmission assets, with the exception of two hydropower plants run by the private sector. Of the total installed generation capacity in Azerbaijan, which reached 5,508 megawatts (MW) by March 2008, Azerenergy owns 98.5% including six thermal power plants (3,956 MW), four hydropower plants (1,018 MW), and five modular power plants (452 MW). The power transmission and distribution grid consists of substations and transmission lines from 400 volts (V) to 500 kilovolts (kV), with a total length of 110,000 kilometers (km). It has an extensive power transmission system connected to those of its neighbors, which allows import of power from the Iran, Russian Federation, and Turkey.
6. The electricity production of Azerbaijan in 2007 was 21,416 gigawatt-hours (GWh), of which 19,053 GWh (89% of total) was generated from thermal power and 2,363 GWh (11% of total) from hydropower. In 2007, about 360 GWh of electricity energy was imported from abroad. The imported energy was primarily from Iran to supply Nakhchivan Autonomous Republic, which does not have direct access to the national power network, and also from the Russian Federation with which Azerbaijan maintains an annual balance of import and export. The total export electricity energy to Iran and the Russian Federation was 727 GWh. The total domestic electricity consumption in 2007 was 19,000 GWh. The average growth rate of domestic electricity demand is expected to be about 4.7% annually through 2015.
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B. Analysis of Key Problems and Opportunities
1. Challenges
7. While the country has been successful in engaging the private sector for developing and exporting its oil and gas resources, the domestic power sector is threatened by unreliable and inadequate power supply mainly because of deterioration of power facilities, inadequate maintenance and rehabilitation, inadequate investment, and inefficient utilization of energy resources. This undermines industrial competitiveness and constrains economic growth. Effective generation capacity has shrunk because of insufficient funds for rehabilitation and capacity addition. Low power plant efficiency and high losses of transmission and distribution lead to wastage of fossil fuels that could have been exported, and nearly double the emissions of greenhouse gas and other pollutants that damage the regional and global environment.
8. Deterioration of Power Facilities. Over 20% of all energy equipment and over half of the network facilities are well beyond their useful life. This inevitably reduces the reliability and efficiency of the power network operation. The high level of physical wear of the equipment at power plants and networks leads to frequent power failures in populated areas and affects economic activities. The inadequate capacity of transmission lines also results in a shortage of reserves in the stability of the power system, increasing the potential risk of power system operation.
9. Inadequate Maintenance and Rehabilitation. The power sector has suffered from inadequate funding to perform essential maintenance functions and introduce new technology. The result has been a distinct deterioration in the quality of the infrastructure and associated deterioration in the quality of service. The power grid is becoming increasingly exposed to the risk of systemic collapse. Rehabilitation and upgrading of transmission facilities could significantly reduce the risk of system failure.
10. Inefficient Utilization of Energy Resources. Another prominent problem of the power network is the shortage of peak power supply. Hydropower plants, with only 19% of the available capacity of all power generation and lower reliability caused by aging of equipment, cannot meet peak demands adequately. Large thermal power plants have to participate in the shifting operation, thus reducing the efficiency and stability of generating units and excessive consumption of fuels. Because of lack of sufficient peak power supply, Azerenergy has to import power from abroad in the peak hours as well as the winter season with higher demand.
11. Insufficient and Unreliable Power Supply. Today, about 49% of the Azerbaijan’s 8.5 million people live in rural areas, often with insufficient access to quality basic services. Lack of sufficient power, gas, and heat has aggravated the regional imbalance in the country. Poor quality and unreliable electricity supply inhibits industrial, agricultural, and commercial activities, constraining economic growth and employment opportunities in regional areas. The unreliability of electricity supply remains a constraint to business operation and daily life. Almost 7% of total annual sales were lost because of power outages. Some areas of the country receive only a few hours of electricity a day, and there are frequent localized outages and occasional widespread system failures. Detailed analysis of the power sector is in Appendix 2 and problem tree analysis is in Appendix 3.
12. Government Strategies and Policies. The principle objectives of the power sector development are to utilize domestic energy resources efficiently, protect the country’s energy security, and ensure the delivery of reliable and adequate electricity services for sustained economic growth. To accelerate the power sector reform and development, the Government
3 has set the overall policy framework for the power sector development, which has the following components: (i) sector restructuring to separate the ownership and management of generation; transmission, and distribution; (ii) development of a regulatory framework and institutions to promote competition and ensure the financial viability of sector enterprises; (iii) introduction of targeted social protection programs to mitigate the impact of higher tariffs on vulnerable groups; and (iv) involvement of the private sector in the operation and financing of generation and distribution facilities. Since 2005, the Government has been implementing reforms in the utilities and infrastructure sectors, through financial restructuring of the large natural monopolies; separation of commercial and regulatory functions; and introduction of a proper regulatory framework. Progress on sector restructuring has been achieved, including establishment of four regional distribution companies, private sector operation in generation, and creation of the Ministry of Economic Development responsible for energy sector policy making, pricing and tariffs, licensing, and management of fixed assets. The Tariff Council, chaired by the Ministry of Economic Development, has authority to propose tariff adjustments, define customer categories, and adopt cost-reflective tariff design. Furthermore, the Government has ordered that all large companies have to change to international financial reporting standards (IFRS) by January 2008, and all government ministries have to implement the IFRS by January 2009. This will be under the management and control of the Ministry of Finance.
13. The Government recognizes the importance of using energy resources efficiently, and acknowledges that the delivery of affordable utility service of acceptable quality is an essential requirement in enhancing the living standards of the population. Consequently, the Government has developed a state program for development of fuel and energy sector in Azerbaijan (2005– 2015),1 which identifies and sets development targets for the various subsectors.
14. The state program envisages the development of the power sector and plans to restructure the sector, expand generation and transmission facilities, and introduce a modern management system, including (i) development of new combined cycle gas turbine generation units and hydropower generation capacities; (ii) modernization and reconstruction of power facilities—increasing efficiency and prolonging useful life and expanding available capacities; (iii) promoting the development of small hydropower and other renewable energy sources (wind and solar) to supplement the energy balance; (iv) construction of new substations and transmission lines to expand transmission and distribution networks; (v) reconstruction and upgrade of dispatch control systems; (vi) strengthening cross-border links with Russian and Iranian grids to increase power trade capacity; (vii) increasing investments for energy sector development and attracting foreign investments; and (viii) expanding regional cooperation and participating in the formation of regional energy markets.
15. The Government has established a medium-term tariff policy that incorporates a transition to full cost recovery for utility service providers by 2010, to make the power sector financially self-sustainable. As the economy continues to expand, the purchasing power of the population will continue to increase and, with it, the capacity to pay higher prices for utility services. In addition, the development and implementation of a targeted social safety net that is under way will ensure that the most vulnerable continue to be able to afford essential utility services as prices rise towards, and eventually reach full cost recovery levels. Taking into account these considerations and under joint efforts from development partners, the Government took a number of measures to curtail implicit energy subsidies, including the increase in energy and utilities prices in January 2007. The current wholesale electricity tariff is AZN0.041 per kilowatt-hour (kWh) ($0.051 per kWh) and the retail electricity tariff is AZN0.06
1 Cabinet of Ministers. 2005. State Program for Development of Fuel and Energy Sector in Azerbaijan (2005–2015). Baku.
4 per kWh ($0.075 per kWh). This led to a reduction in energy subsidies from 21% in 2006 to an estimated 11% in 2007. Azerenergy has confirmed that no subsidies will be received for 2008. The collection of utility payments has also been substantially improved from about 40% to 90%. The implementation of the proposed Project will further improve the power sector performance and assist the Government to achieve its committed reform agenda.
2. Opportunities
16. An unreliable and inefficient power network is a bottleneck to sustained economic growth and rapid poverty reduction. With support from the Asian Development Bank (ADB) and other development partners, a comprehensive energy sector road map2 was prepared in 2006, which identified three key areas for ADB assistance: (i) rehabilitation of the power grid for improvement of power supply quality and loss reduction, (ii) development of renewable energy, and (iii) improvement of demand-side energy efficiency and energy conservation. The Government expressed interest in cooperation with ADB to address these matters, and ADB is exploring suitable investment projects through public and private sector operation. The power transmission subsector in Azerbaijan has substantial investment demand in terms of strengthening the backbone power grid, reducing losses and enhancing energy efficiency, and minimizing environmental impacts. State-of-the-art technology will also be needed to transfer power with minimal losses and provide adequate power supply to consumers.
17. The 220 kV Mingechevir-1 transmission line was put into service in 1949, and the Mingechevir-2 transmission line in 1954. These two single circuit transmission lines provide the transmission of electric power with a total capacity of 250 MW from Mingechevir hydropower station to the Absheron economic region, which is closest to the capital city of Baku and has the highest electricity consumption. Both lines were partially renovated in the 1980s. However, most segments remain unchanged, with a large number of defective pylons, insulators, and wires, leading to increased power losses and higher voltage drops. A large number of foundations of towers were damaged as a result of landslides and floods. Statistical analysis of power failures concluded that the technical conditions of both lines are inadequate and past their useful life. In addition, increased power demand causes these lines to be frequently overloaded, which leads to an increase of 6%–7% in losses, with frequent outages (8–17 times annually). Therefore, the transmission capacity must be expanded to deliver adequate and reliable power supply. The power system studies concluded that construction of a new double circuit 220 kV transmission line to replace the aged existing lines used for 60 years would be the most suitable and least- cost option, which will increase transmission capacity by 300 MW and reduce power losses by 25 GWh. The increase in transmission capacity will remove the bottleneck of the transmission capacity of the backbone power networks. It is expected that by 2012, the total annual electricity supply in the project area could be increased by about 1,000 GWh accordingly. The electricity energy generated from the Mingechevir hydropower plant could also be increased by 200 GWh annually, from 1,200 GWh to 1,400 GWh.
18. The power supply in the central region is provided through the 110 kV transmission lines from Akhsu 220/110 kV substation, covering Akhsu, Ujar, Geokchai, and other administrative regions with a total population of 0.5 million. The majority of these transmission lines were built in the 1950s–1960s and are now overloaded, with considerable risks including low voltage in distribution networks, high losses, and frequent outages. In peak hours, the voltage of the distribution network is only 92–94 kV, or 85% of the standards, lower than the minimum allowed voltage (104.5 kV) for normal operating conditions. Azerenergy has studied various options for reliable power supply in the central region, including construction of new thermal power plants,
2 Valiyev, Vilayat. 2006. Preparation of Energy Sector Roadmap. Manila: ADB.
5 and concluded that construction of a new 220 kV substation at Agdash with installation of two sets of 125 megavolt-ampere (MVA) transformers would be required.
3. External Assistance
19. The major sources of external assistance in the power sector include the European Bank for Reconstruction and Development (EBRD), Islamic Development Bank (IsDB), Japan Bank for International Cooperation (JBIC), German development cooperation through Kreditanstalt für Wiederaufbau (KfW), and the World Bank. External assistance has focused on support for gas- fired and hydropower generation, transmission, and distribution projects. The World Bank helped to improve the management of the energy system and restructure the relevant institutions. EBRD provided two loans for the rehabilitation of two hydropower plants, and the Government of Japan provided two loans to finance the gas combined-cycle power plant. KfW also provided a loan for the power transmission rehabilitation program.
20. Besides these, ADB, EBRD, European Union, and the World Bank have provided technical assistance (TA) for feasibility studies and capacity development. ADB has been actively involved in policy dialogue with the Government since 2005. A project preparatory TA3 for renewable energy development was implemented successfully, which assessed the potential and options for renewable energy development and identified pilot small hydropower projects to be developed. The TA also assessed the government policy framework, developed a road map for implementation of renewable energy projects, and prepared a standardized power purchase agreement and other policy documents. The Government is considering adopting an appropriate investment modality and identifying the implementing agency, and will seek ADB’s continued support. 21. The World Bank assistance focuses on the establishment of a full cost recovery tariff policy, implementing IFRS, creating an appropriate regulatory environment, and strengthening private participation in the provision of utility services. The European Union is also supporting the Ministry of Industry and Energy to enhance its capacity to develop and implement a national energy strategy and public sector reform for attracting foreign investments for infrastructure development.
22. The Project was prepared and will be implemented in coordination with the external aid agencies active in the power sector. During project processing, ADB’s project team frequently consulted with counterparts on policy reforms, project design, and capacity development in the sector. The Project will complement the ongoing assistance programs, improve the effectiveness of external assistance, and synergize the institutional strengthening of Azerenergy.
23. Through the synergized external assistance from international financing agencies, several key policy initiatives have resulted. The Government has adopted and approved a preliminary energy sector strategy and policy framework, established a full cost recovery tariff policy, and is continually improving sector governance. Sound procurement procedures and a financial management and audit system have been introduced in the energy sector. Details of external assistance to the power sector are in Appendix 4.
3 ADB. 2005. Technical Assistance to the Republic of Azerbaijan for Preparing the Renewable Energy Development Project. Manila TA 4726-AZE, $900,000, approved 22 December 2005, cofinanced by the Government of Finland).
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4. ADB’s Operations and Sector Strategy
24. The energy sector was identified as a priority area for ADB interventions. The 2006 country strategy and program update for Azerbaijan4 indicated that the Government requested ADB support for energy within an expanded lending program. The proposed power transmission project is under the Government strategic priority, and is in line with ADB’s country strategy and energy policy.5
25. ADB has no lending operations in the Azerbaijan energy sector yet and the Project provides a unique opportunity to enter it. Currently, private sector funding in Azerbaijan is not sufficient to fully rehabilitate the power system. ADB can contribute to fill the funding gap and work with the Government and development partners to improve the structural, legal, and regulatory framework needed to attract private sector funding in the sector. ADB has extensive experience in the design and implementation of transmission projects in its developing member countries, with lessons that are directly applicable to Azerbaijan. The Project will complement other ADB support for infrastructure, including the development of roads and regional towns.
26. The Project targets key strategic transmission lines, which are severely deteriorated and need to be rehabilitated on a priority basis. It will also contribute to optimizing domestic energy resource utilization and reducing fossil fuel consumption and power imports. The current Azerbaijan power system is not being operated optimally because of constraints on existing components of the transmission network. Hydropower energy generated in the west region is not delivered efficiently to the central region where demand is increasing rapidly. Replacement of the 220 kV transmission lines would allow the existing Mingechevir hydropower plant (360 MW) to increase its available outputs to the optimal level (420 MW)—peak power supply could be efficiently enhanced, while power energy generated from the gas and oil fired plants in the central and east regions could be reduced. This would permit optimal utilization of the grid networks and generation capacity by reducing the shifting operation time of large thermal power plants, thus improving the efficiency and stability of generation units and reducing excessive consumption of fuels. The saved fuels including gas and oil would be exported to increase government revenue. Therefore, Azerenergy and the country would benefit from savings in fuel expenditures, improved energy efficiency, and reduced environmental pollution.
27. Azerbaijan has actively participated in Central Asia Regional Economic Cooperation. The Government is also involved in ADB regional TA on promoting renewable energy, energy efficiency, and greenhouse gas abatement; and has committed itself to exploring the use of renewable energy as part of its generation expansion.6 Implementation of the proposed Project is helping to reinforce the relationship between Azerbaijan and ADB in the energy sector, and establish the conditions for expansion of long-term cooperation.
5. Lessons Learned
28. ADB has not yet provided loans to the energy sector of Azerbaijan. Nevertheless, ADB has accumulated substantial experience in implementation of infrastructure projects and understanding of problems in the energy sector in other countries in the region. Relevant lessons learned are that (i) project components shall be carefully designed and evaluated based on in-depth technical, economic, environmental, and social (including land acquisition and
4 ADB. 2006. Country Strategy and Program Update (2006): Azerbaijan. Manila. 5 ADB. 2000. Energy 2003: Review of the Energy Policy. Manila (adopted in 2000). 6 ADB. 2007. Regional Technical Assistance on Establishing Renewable Energy, Energy Efficiency and Greenhouse Gas Mitigation Investment Funds. Manila.
7 resettlement) assessments to ensure quality at entry; (ii) advance contracting shall be undertaken to expedite project implementation; (iii) infrastructure investments will be accompanied by support for policy reform and institutional strengthening to maximize the development impact and benefits of investment; and (iv) close collaboration with other development partners shall be undertaken when conducting policy dialogue with the Government on sector governance issues. In addition, early attention on procurement matters, including bid documents preparation and review procedures, will be given to avoid delays. Close follow-up during project engineering designs, construction of civil works, and installation should ensure timely corrective measures where needed and early completion of project components.
29. Azerbaijan has embarked on energy sector reforms. However, the process of restructuring, legal and regulatory reforms, and enhancement of utility financial performances is a progression that is mainly being supported by other development partners, including the World Bank and the European Union. The Project would complement these efforts with needed investment in transmission network enhancement. This integration of policy and investment support is designed to maximize their combined effect on the sector's financial position and sustainability of sector reforms.
III. THE PROPOSED PROJECT
A. Impact and Outcome
30. The Project was developed following technical, economic, and financial studies that have taken into consideration environmental and social aspects. The proposed Project will construct a double circuit 220 kV transmission line with a total length of 280 km between Mingechevir hydropower plant and the 500/330/220 kV Absheron substation to replace the existing 220 kV transmission lines. It will also construct a 220/110 kV substation at Agdash and expand Absheron substation. The new 220 kV transmission line will be built at the same corridor of the existing old lines, and the latter lines will be demolished before and during the construction of new lines. The existing power supply will be shifted to other transmission lines and the deficient parts will be supplied from increase of imported power.
31. The Project aims to facilitate the country’s economic development by strengthening infrastructure development, removing the bottleneck of power transmission, and improving the efficiency of services. The project impacts are to improve the power transmission system to provide reliable and adequate electricity for sustained economic growth. It will strengthen the backbone power transmission network in the west-to-east direction, which is crucial for ensuring the required stability of power supply to consumers in the key Azeri industrial and economic hub. The Project is an integral part of Azerbaijan’s power sector development strategy.
32. The project outcome will be an expanded and strengthened backbone 220 kV power transmission and distribution network with transmission bottlenecks removed and losses reduced.
B. Outputs
33. The outputs of the Project are summarized below:
(i) 220 kV transmission line. Construction of 220 kV double-circuit transmission line from Mingechevir hydropower plant to Absheron substation with a total length of about 280 km. The new transmission line will increase the transmission
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capacity by 300 MW, remove the bottlenecks of backbone transmission network, and reduce the transmission losses.
(ii) Agdash substation (220/110 kV). Construction of a new 220/110 kV substation at Agdash and installation of two units of transformers each with capacity of 125 MVA, switches, breakers, protection, communication and control devices, and associated 110 kV transmission lines in the vicinity area of the substation. The new substation and associated 110 kV lines will provide reliable and adequate power supply to meet growing electricity demand in the central part of the country including Akhsu, Ujar, Geokchai, and Kurdamir regions.
(iii) Expansion of Absheron substation (500/330/220 kV). Installation of one unit of transformer with capacity of 400 MVA and breakers, to provide reliable and adequate electricity power to consumers in the Absheron industrial and economic hub and improve the power service quality.
(iv) Project management support. International consultants will be engaged to assist Azerenergy in procurement and bidding for the tendering of design, supply, and installation contracts; implementation supervision; and other capacity building support.
(v) Institutional strengthening. The Project will strengthen Azerenergy staff capacity through providing on-the-job training on transmission and substation operation and maintenance, environmental management, and social safeguard implementation.
C. Project Investment Plan
34. The total cost of the Project is estimated at about $240 million equivalent, including taxes, duties, physical and price contingencies, interest, and other charges. The cost estimates are summarized in Table 1 and detailed in Appendix 5.
Table 1: Project Investment Plan ($ million) Item Amount A. Base Costa 1. Equipment and Materials 128.4 a. 220kV Substation 18.3 b. 220kV Transmission Line 101.8 c. 500/330/220kV Substation Upgrading 8.3 2. Civil Worksb 34.2 3. Consulting Services 1.1 4. Taxes and Duties 32.5 Total Base Cost 196.2 B. Contingencies 37.9 C. Interest During Construction 5.9 Total 240.0 a In 2008 prices. b Includes civil works, social and environmental mitigation, resettlement, and detailed engineering design. Source: Asian Development Bank estimates.
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D. Financing Plan
35. Azerenergy has requested a loan of $160 million from ADB from its ordinary capital resources to help finance the Project. The ADB loan will have a 25-year term, including a grace period of 5 years, an interest rate determined in accordance with ADB’s London interbank offered rate (LIBOR)-based lending facility, a commitment charge of 0.15% per annum, and such other terms and conditions set forth in the draft loan and guarantee agreements. Azerenergy has provided ADB with (i) the reasons for its decision to borrow under ADB’s LIBOR-based lending facility on the basis of these terms and conditions, and (ii) an undertaking that these choices were its own independent decision not made in reliance on any communication or advice from ADB. The Government of Azerbaijan will provide the sovereign guarantee. The foreign exchange risk will be borne by the Borrower. Azerenergy will finance the remaining costs including consulting services, local taxes and duties, interest during construction, and contingencies, from its own resources of an estimated $80 million. The proposed financing plan for the Project is summarized in Table 2 and detailed in Appendix 5.
Table 2: Financing Plan
Source Amount ($ million) % Asian Development Bank Ordinary Capital Resources 160.0 67 Azerenergy a 80.0 33 Total 240.0 100 a Includes value added tax, other taxes and duties, price contingencies, and interest during construction. Source: Asian Development Bank estimates.
E. Implementation Arrangements
1. Project Management
36. Azerenergy will be the executing agency. Azerenergy has been the executing agency for six investment projects financed by the World Bank, EBRD, KfW, IsDB, and JBIC. The capacity of Azerenergy and its staff to undertake the project implementation responsibilities is considered satisfactory, given their adequate experience with previous projects and the staff’s technical skills. A financial management assessment was undertaken during project preparation, indicating that Azerenergy has satisfactory management capacity and systems for financial and accounting management, reporting, auditing, and internal controls.
37. A project management unit (PMU) will be established, headed by a project manager and staffed by specialists in technical, financial, procurement, social, and environmental matters. The PMU will report to the chief engineer or deputy president of Azerenergy. The PMU will be responsible for day-to-day project implementation, comprising procurement, contract supervision and management, project social and environmental management, and project financial management, including project accounting, financial reporting, loan disbursements, and arrangements for external audits. Relevant international practices and standards will be adhered to in the implementation of the Project. Detailed construction and installation drawings will be available under the Project and will be in line with specifications in the engineering, procurement, and commissioning contracts.
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2. Implementation Period
38. The Project will be implemented around 3 years starting in January 2009. Physical works are expected to be completed by the end of 2011 and the loan utilization period will be up to June 2012. Detailed engineering designs, surveys, investigations, will start in the fourth quarter of 2008. The civil works are expected to commence in the second quarter of 2009. The project implementation schedule is in Appendix 6.
3. Procurement
39. ADB-financed goods and services will be procured according to ADB’s Procurement Guidelines (2007, as amended from time to time). International competitive bidding procedures will be followed for civil work contracts costing $3 million equivalent or more. Contracts estimated at less than $3 million will be awarded using national competitive bidding under Azerbaijan’s Public Procurement Law of 27 December 2001 and acceptable to ADB. The procurement plan will be updated at least annually, covering the next 18 months of procurement activity. The procurement plan is in Appendix 7.
40. The operation of transmission lines and substations is highly integrated because of technical specifications. Proper system performance of the transmission and substation facilities also requires strong integration between the equipment suppliers and the construction contractors. The successful bidder will be required to warrant performance of the lines and electrical equipment, which reduces the risk to Azerenergy. Therefore, a plant design, supply, and install (turnkey) contracting approach has been taken to ensure proper system design integration and facility performance. A plant contracting approach also has the advantage of ensuring that the contractor has adequate experience of civil works requirements and in-depth knowledge of equipment to be installed, and can ensure better design integration. To facilitate project implementation and administration in a more efficient and economical manner, the project subcomponents are packaged into one single plant (turnkey) contract. This approach will be more likely to attract more qualified national and international bidders and lower bid prices because of the award of multiple subcomponents.
41. The single plant (turnkey) contract for construction of the transmission line and substation facilities will be awarded using international competitive bidding following ADB’s standard bidding document: single-stage bidding procedure.
4. Advance Contracting and Retroactive Financing
42. To expedite project implementation, Azerenergy has requested ADB approval for advance contracting for the ADB-financed components. This will enable Azerenergy to initiate the procurement process.
43. Azerenergy has also requested ADB for retroactive financing for expenditures in respect of civil works if incurred prior to effectiveness of the loan agreement. Reimbursement by ADB of any payments made by Azerenergy under the contract will not exceed 20% of the loan amount provided that expenditures are in accordance with ADB’s Procurement Guidelines and safeguard policies, and were incurred not earlier than 12 months prior to signing of the loan agreement. The Government and Azerenergy have been advised that approval of advance contracting and retroactive financing does not commit ADB to financing the Project.
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5. Consulting Services
44. Consulting services will be required for project implementation support and capacity development. Key tasks include (i) procurement and bidding for the tendering of plant design, supply, and installation contracts; (ii) supervision of construction, testing and commissioning, and quality assurance; (iii) monitoring of project implementation and performance; and (iv) capacity development. The capacity development component will involve project management and monitoring activities, including safeguards monitoring and evaluation, and training on transmission system operations, and maintenance. The outline terms of reference for project implementation consultants are in Appendix 8.
45. Because of the power system operation requirement, Azerenergy plans to complete the construction of transmission and substation facilities by the end of 2011. To expedite project implementation, Azerenergy will finance the project implementation consultants entirely from its own resources, and engage the consultants in accordance with its procedures acceptable to ADB. DECON, 7 an international consulting firm, has been engaged by Azerenergy through international competitive bidding under a transmission line project financed by KfW. The consultants have adequate professional qualifications and satisfactory performance in the assignment. The consulting services under the Project represent a very similar technical approach and professional expertise with the ongoing assignment. Azerenergy intends to engage this firm directly through negotiation. The consulting firm has submitted technical and financial proposals based on the terms of reference. This single-source selection approach is considered appropriate and cost-effective, given that (i) the consultants are selected based on international competitive bidding and have the necessary professional qualifications, (ii) the consultants will carry out the assignment in accordance with the agreed schedule, and (iii) the scope of the services is consistent with the needs of the Project. The consultant’s experience and competence have been assessed and found adequate to the proposed assignment.
6. Anticorruption Policy
46. ADB’s Anticorruption Policy (1998, as amended to date) was explained to and discussed with Azerenergy and the Government. Consistent with its commitment to good governance, accountability, and transparency, ADB reserves the right to investigate, directly or through its agents, any alleged corrupt, fraudulent, collusive, or coercive practices relating to the Project. To support these efforts, relevant provisions of ADB’s Anticorruption Policy are included in the loan regulations and bidding documents for the Project. In particular, all contracts financed by ADB in connection with the Project shall include provisions specifying the right of ADB to audit and examine the records and accounts of all contractors, suppliers, consultants, and other service providers as they relate to the Project.
47. The Government and Azerenergy agreed to take additional measures to improve governance, accountability, and transparency under the Project. These measures include (i) independent external auditing of contracts, project accounts, and financial statements; (ii) decisions on all procurement-related matters being taken by the tendering committee, which comprises representatives of the Ministry of Economic Development, Ministry of Finance, Ministry of Industry and Energy, and State Procurement Agency; (iii) verification of contractors’ payment claims by the supervision consultant in accordance with contract specifications; (iv) timely disclosure of information on selection of consultants and contractors through local
7 DECON, a European consulting firm with headquarters in Germany, has a 35-year history of implementing more than 700 projects at home and abroad. The focus of DECON’s business activities is on electricity generation, transmission, and distribution as well as renewable energy and energy policy.
12 newspapers; and (v) publication of the status of procurements and awards of contracts on Azerenergy’s website in accordance with ADB’s Procurement Guidelines.
7. Disbursement Arrangements
48. The loan proceeds will be disbursed in accordance with ADB’s Loan Disbursement Handbook (2007, as amended from time to time). To reduce cash flow difficulties in Azerenergy and facilitate project implementation, the imprest account procedures described in ADB’s Loan Disbursement Handbook will be followed. An imprest account will be established at the National Bank of Azerbaijan or a commercial bank in Azerbaijan acceptable to ADB after loan effectiveness, and will be liquidated and replenished in accordance with ADB’s Loan Disbursement Handbook. The total advance will not exceed ADB’s estimated share of eligible project expenditures to be financed through the imprest account for the next 6 months, or 10% of the amount of the loan, whichever is lower. For simplified documentation, the statement of expenditures procedure, as described in the Loan Disbursement Handbook, will be followed to reimburse expenditures and liquidate the imprest account for any individual payment transaction of $100,000 equivalent and below.
8. Accounting, Auditing, and Reporting
49. Azerenergy agreed to adhere to sound financial management requirements during implementation of the Project. Azerenergy will maintain separate project records and accounts adequate to identify the (i) goods and services financed from the loan proceeds, (ii) financing resources received, (iii) expenses incurred on the components of the Project, and (iv) use of counterpart funds. Azerenergy will engage independent external auditors acceptable to ADB to audit project accounts and financial statements annually, and will arrange a periodic or annual audit of statement of expenditures transactions. Azerenergy will submit to ADB certified copies of audited annual project accounts and related financial statements as well as the auditor’s report in English, including the proposed use of the imprest account and the statement of expenditures procedure, within 6 months after the end of each financial year during implementation. Azerenergy was advised of ADB’s requirement for timely submission of audited annual project accounts and financial statements, and the suspension of disbursements of the ADB loan in case of noncompliance with the requirements.
50. Azerenergy will prepare and submit to ADB quarterly progress reports, which will include (i) a narrative description of progress made during the reporting period, (ii) changes in the implementation schedule, (iii) problems or difficulties encountered, and (iv) activities and actions to be undertaken in the next reporting period. Azerenergy will prepare and submit to ADB a project completion report within 3 months of project completion.
9. Performance Monitoring and Evaluation
51. A set of targets and indicators for monitoring and evaluation of project performance were discussed with Azerenergy during fact-finding (key performance targets and indicators are in Appendix 1). Azerenergy will (i) engage project implementation consultants for monitoring and evaluation by the end of 2008; (ii) collect additional data from relevant agencies, including local governments and statistics bureaus, to measure the performance indicators at inception, completion, and 3 years after completion of the Project; and (iii) report to ADB key findings on a quarterly basis. Azerenergy, with the assistance of the supervision consultant, will monitor and evaluate project impacts to ensure that the project facilities are managed effectively and benefits maximized.
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10. Project Review
52. ADB will field an inception mission within 3 months of loan approval, and a review mission every 6 months. The Government, Azerenergy, and ADB will jointly undertake a midterm review in late 2009. The midterm review will focus on (i) project impacts, (ii) implementation progress, (iii) sector reform and performance, (iv) performance of consultants and contractors, (v) status of compliance with covenants in the loan agreement, and (vi) the need for any midcourse changes in the scope or schedule of the Project to ensure full achievement of its impact.
IV. PROJECT BENEFITS, IMPACTS, ASSUMPTIONS, AND RISKS
A. Economic Analysis
53. The proposed Project will need to demonstrate economic viability and sustainability in accordance with ADB’s Guidelines for the Economic Analysis of Projects.8
54. Economic analysis of Azerenergy’s proposed Project under the state program for development of fuel and energy sector in Azerbaijan (2005–2015) has been carried out in accordance with the Guidelines for Economic Analysis of Projects. Azerenergy identifies benefits to the replacement transmission line that are within the context of the state program for energy transmission. However, there is no numerical analysis to support these benefits other than that the Project will increase the capacity of the power network and reduce losses of capacity and electric energy. The issue of lack of peak capacity was also identified, which requires that peak demand is met by importing energy from the Russian Federation. It is on this basis that the justification of the replacement transmission lines is proposed, by evaluating the avoidable cost of the imported peak power. The Project has an estimated economic internal rate of return (EIRR) of 14.8%, indicating that it is economically viable. Sensitivity analysis revealed that expected economic outcomes are robust under a range of downside scenarios, reflecting the strong link between an adequate electricity supply and economic growth. A summary of the economic analysis is in Appendix 9.
B. Financial Analysis
55. Financial analysis of the Project has been carried out in accordance with ADB’s Financial Management and Analysis of Projects.9 All financial costs and benefits have been expressed at 2007 prices. Cost streams used to determine the financial internal rate of return (FIRR), i.e., capital investment, and operations and maintenance, reflect the cost of delivering the estimated benefits. The tariff for electricity has been assumed as the difference between the cost of imported electricity and the cost of own generation of electricity and has been set at $0.036 per kWh. The tariff is applied to the volume of 650 GWh—assuming that the Project will enable domestic generation to replace imports.
56. The FIRR of 11.69% compares favorably with the estimated weighted average cost of capital (WACC) of 2.45% indicating financial viability for the Project. Financial viability was gauged by comparing the incremental costs and benefits of with- and without-project investment scenarios. The incremental benefits arise through the replacement of imported electricity and reduction in operating expenditures. Nonquantifiable financial benefits such as quality of power
8 ADB. 1997. Guidelines for the Economic Analysis of Projects. Manila. 9 ADB. 2005. Financial Management and Analysis of Projects. Manila.
14 supply were not included in the financial evaluation. A summary of the financial analysis is in Appendix 10.
57. Sensitivity and risk analysis indicates that the FIRRs are robust with (i) a 10% increase in capital costs, (ii) a 10-year benefit stream (instead of 20 years), (iii) LIBOR increasing by 10%, and (iv) net benefits decreasing by 10%. Two extreme scenarios have also been run where both benefits and capital costs were reduced to a point where the net present value (NPV) of free cash flow was set to zero. Both scenarios came out with acceptable FIRRs. The sensitivity analysis can be found in Table 3 below.
Table 3: Summary Results of Financial Analysis
Benefits LIBOR Base CAPEX Benefit Item reduced to increase Case +10% minus 10% 10 year by 10% WACC (%) 2.45 2.45 6.75 2.45 2.45 FIRR (%) 11.69 3.32 12.41 10.58 10.46 NPV ($ million) 277.20 10.20 112.30 260.00 232.20 CAPEX = capital expenditure, FIRR = financial internal rate of return, LIBOR = London interbank offered rate, NPV =net present value, WACC = weighted average cost of capital. Source: Asian Development Bank estimates.
58. For each of the scenarios in Table 3, the FIRR is greater than the WACC and the NPV is positive. Therefore, it can be concluded that, in the all unlikely circumstances including the most negative scenario (i) the expected benefit stream will be 10 years instead of 20 years; (ii) the Project is financially viable; and (iii) the company will be able to generate sufficient cash flows to cover the projected costs, including loan interest and principal repayment requirements.
59. Two additional scenarios have been calculated to investigate at what level the expected benefits should decrease, or at what level capital expenditures should be increased to get the NPV to zero. The calculations show that this level will be achieved if benefits are reduced by 60% or capital expenditures increase more than 2.5 times, which may be concluded as extremely unlikely.
C. Financial Management and Sustainability of Azerenergy
60. Prior to the country’s independence, Azerenergy was administratively a government agency. In 1996, it became an open joint-stock company. Although it is fully owned by the Government, and senior management is handpicked by the Government, Azerenergy enjoys relative autonomous status according to its charter. The detailed corporate and organizational structure of Azerenergy and its financial performance are in Supplementary Appendixes D and E.
61. Azerenergy generates electric power. It transmits and sells electricity directly to consumers as well as in bulk to power distribution companies. Based on the agreements, distribution companies deliver electricity to retail consumers within their service areas. Azerenergy comprises 20 generation and transmission entities and the energy management network; these are under the direct financial control of Azerenergy. The revenue collection of these entities is centralized and managed directly by the head office of Azerenergy. The nine regional distribution entities and Nakhchivan autonomy agency collect their own revenue and therefore pay corporate income tax as individual entities. There are also seven decentralized enterprises under the umbrella of Azerenergy—Research Centre, Construction Enterprise,
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Repair and Construction Enterprise, Security Service Enterprise, Supply Entity, Energy Service Supply Entity, and Research Institute. The total number of employees in 2007 was 8,092.
62. Two distribution companies—Joint-Stock Company (JSC) Baku Electricshebeke and JSC Sumgait Electricshebeke—are outside Azerenergy management control and operate as separate entities. Azerenergy concluded contracts with JSC Baku Electricshebeke and JSC Sumgait Electricshebeke for the transmission of electricity in Baku and Sumgait cities.
1. Past Financial Performance
63. Azerenergy’s overall financial performance has been satisfactory in the past 3 years and total revenue has increased steadily because of the increase in tariffs as well as the reduction in imported energy, thus facilitating Azerenergy to expand its investment in the sector. Azerenergy experienced a growth in total revenue in 2007 (AZN934 million), increasing by 222% over 2006.
64. The company’s operating results also improved during 2007 because of the overall increase in tariffs. The cost of sales amounted to AZN695 million or 74% of total revenue in 2007—a significant improvement over 2006 where it was 185% of total turnover.
65. The ratio of equity to total equity and liabilities is improved slightly from 22% in 2006 to 26% in 2007. Accordingly, the total liabilities to equity ratio also improved from 3.45 in 2006 to 2.84 in 2007. The improvement of the company’s gearing ratio is very important, and shows that the company is able to earn enough capital using long-term borrowings for investment in the industry.
66. In spite of significant improvement of the debt service coverage ratio which is up to 0.5 in 2007 from 0.05 in 2006, this performance indicator is still low. The Government has been making efforts to increase tariffs (thereby increasing cash flow available for debt service) starting in 2007. It is therefore believed that the debt service coverage ratio should be at a level acceptable when repayment starts in 2012. More detailed analysis of Azerenergy’s financial performance is in Appendix 11.
2. Financial Projections
67. Up to 2006, retail tariffs were set below cost and as a result, Azerenergy was receiving subsidies from the Government. At the beginning of 2007, the Government made a difficult political decision to set tariffs to cover costs with a 10% return. The results have been seen in Azerenergy’s financial statements in 2007 where sales significantly increased and subsidies decreased.10 Retail tariffs increased from AZN0.017 per kWh to AZN0.060 per kWh in January 2007.
68. It is projected that there will be a gradual improvement in the company’s financial performance and position during the planning period from 2008 to 2015. Estimated financial results are considerably improved over that period. Net profit after taxation is forecast to increase from AZN130 million in 2008 to AZN657 million in 2015.
69. Revenues are forecast to increase from AZN1.06 billion in 2008 to AZN2.34 billion in 2015 because of a growth in production and demand, and the increase in tariffs.
10 Subsidies for 2007 were zero; those subsidies in the 2007 statements were incurred the previous year.
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70. The increase in sales and general improvement in performance is mainly due to Azerenergy and the Government’s new attitude toward electricity tariffs covering Azerenergy’s costs. The financial projections assume that tariffs will increase at the same rate as gross electricity production but will also be adjusted from time to time to meet the covenants set forth by the ADB loan. The base case therefore assumes a 30% increase by 2012. As the Government increased retail tariffs by more than three times in 2007, such increase can be concluded as reasonable.
71. Improvement in each of the key performance indicators during 2008–2015 reflect the positive changes forecast in the financial statements. Total equity is forecast to increase from AZN1.03 billion in 2008 to AZN5.05 billion in 2020, and AZN13.73 billion by 2030.
72. Because of careful forecast of cash disbursement, the repayment of current trade payables will be only 40% in the year of purchase in 2008, 60% in 2012, and 70% in 2015, reaching 90% in 2020 and afterwards. It is assumed that such cash disbursement policy will be available because of the Government’s full control over the oil and gas companies (biggest suppliers to Azerenergy). This policy enables the company to keep a positive balance of cash at the end of each year during the forecast period. Projected increases in electricity sales and the gradual improvement in cash collections will lead to a substantial increase in cash in subsequent years. A positive cash flow will allow the company to fulfill its commitments (including the previously mentioned outstanding debts) and to carry out self-financing of required capital investments.
3. Financial Management Structure
73. The financial management structure of Azerenergy was assessed and found to be adequate. A financial management assessment was undertaken to ensure the current ability of Azerenergy to fulfill ADB’s fiduciary requirements under the proposed loan. A financial management assessment questionnaire was completed by Azerenergy to facilitate a review of its financial systems and processes, and to identify any issues or constraints. Azerenergy’s management assessment is in Appendix 12.
74. Azerenergy currently maintains its accounting and reporting procedures in accordance with Azerbaijan’s Accounting Regulations. However, significant steps have been taken for the adoption of IFRS. Azerenergy prepared a draft new accounting policy and new chart of accounts to meet IFRS requirements. Preparatory work for the reconciliation of all expositing accounts to the new accounts is currently being carried out. The management of Azerenergy assumes that the new accounting policies and procedures will be adopted in the company during the year. However, there are significant obstacles in disseminating the new policies among the accounting staff of the company’s subsidiaries. The level of qualification of the accountants is varied in different regions of the country.
D. Environmental Assessment
75. The Project has no major environmental impacts. A minor impact on nature is that of white storks (ciconia ciconia), which have built nests on transmission towers near the Turianchay Reserve. It is recommended that the Project avoid these during the breeding season and then move the nests to the newly constructed towers or specially built nesting towers. Special handling will be required with respect to toxic polychlorinated biphenyls (PCBs) in transformer oil. This includes one old transformer containing PCBs, which will be removed for use elsewhere. The Project will require an assurance from Azerenergy that the new transformer
17 will be filled with a nontoxic substitute for PCB. Azerbaijan does not have specific laws or regulations on handling of PCBs but is a signatory to the Stockholm Convention, thus the terms of the convention and United Nations guidelines detailing safe handling and prevention of PCB emissions are to be followed.
76. Project implementation will require environmental monitoring as detailed in the environmental management and monitoring plan (EMMP) to avoid standard construction impacts. These include environmental standard operating procedures such as cleaning up construction sites, proper disposal of spoils, grading damaged land and replanting vegetation, protecting the public from excessive noise and dust during construction, etc. With respect to handling PCBs, Azerenergy will need to coordinate with the Ministry of Ecology and Natural Resources (MENR) as the government agency responsible for handling hazardous materials and to engage the services of the specialized hazardous materials company established by MENR.
E. Social Safeguards
77. Resettlement. The new 280 km transmission line will pass inside the corridor of the old lines, with the new towers sited in principle on the same bases of the old ones. As the line corridor is already formally owned by Azerenergy, no land acquisition will be needed. Based on existing agreements, no land compensation will be given to farmers that may be affected by the few towers that may require new bases following detailed design. 11 By regulation, the transmission line may require the removal of a few houses already existing within the corridor and may cause temporary impacts to crops (wheat) cultivated under various transmission line sections for a total of some 130 km. 12 To avoid these impacts as required by the ADB’s Involuntary Resettlement Policy (1995), Azerenergy has agreed to (i) allow the permanence of existing houses under the lines; (ii) schedule construction in farmed areas during the nonagricultural season (from June to September); and (iii) reflect these provisions in the civil works contracts. Based on this, the Project is classified category C and no resettlement plan was prepared. However, to guarantee that the transmission line construction plan and schedule needed to avoid impacts is adopted, Azerenergy has prepared a detailed due diligence report providing all needed qualitative and quantitative background on potential project impacts, detailing all provisions needed to avoid them, and indicating the result of a consultation process carried out among selected communities farming land under the lines. To cover all possibilities, the due diligence report also details the project implementation conditions and the action needed to satisfy ADB policy requirements on compensation if the adopted impact avoidance measures cannot be implemented because of force majeure.
78. Indigenous Peoples. The areas crossed by the transmission lines are all occupied by communities belonging to the Azeri national majority. This Project will thus not trigger the ADB Policy on Indigenous Peoples (1998); it will be classified category C and will not require the preparation of an indigenous peoples development plan. The summary poverty reduction and social strategy is in Appendix 13.
11 Based on existing agreements, Azerenergy allows local farmers to cultivate land under the line but retains the right to reclaim the right to use the corridor if needed. 12 The remaining length of the line passes over desert, steppe, or grassland areas where no impact to livelihood will occur.
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F. Assumptions and Risks
79. The Project was designed based on the following key assumptions: (i) macroeconomic growth remains stable, (ii) the Government remains committed to power sector reforms and development, (iii) the Government is commitment to establishing cost-recovering tariffs, (iv) Azerenergy is committed to implementation of social and environmental mitigation measures in a timely manner, (v) project and financial management of Azerenergy is sound, and (vi) counterpart financing is adequate.
80. Risks to the Project include (i) an unexpected increase in prices of commodities and raw materials, (ii) a delay in procurement and recruitment of consultants caused by government approvals, and (iii) delays in implementation of social and environmental mitigation measures. The Project is fully supported by the Government, and the cabinet of ministers will coordinate the work of government agencies to ensure that any issues are resolved promptly. Adequate consulting services are provided to help Azerenergy manage implementation, monitor performance, and report to ADB. Price contingency funds are included to respond to unforeseen cost changes. Azerenergy is also committed to implement the social and environmental mitigation measures fully, and relevant provisions will be incorporated in the civil works contracts.
81. The project financial risk is low. There is clear evidence that the Government has had considerable success in the transition to full cost recovery for the power utility by 2010. The Government also confirmed that no subsidies will be given to Azerenergy from 2008. Tariff reform has significantly supported the target of achieving a financially self-sustainable power sector. The proposed Project, together with efforts from other development partners, will have a synergized effect on enhancing Azerenergy’s financial performance and will assist the Government to achieve its committed reform agenda.
V. ASSURANCES
82. In addition to the standard assurances, the Government and Azerenergy have given the following assurances, which will be incorporated in the legal documents:
83. Counterpart Support. Azerenergy will make available the funds, facilities, services, land, and other resources, as required, for timely implementation and operation of the Project.
84. Financial Management:
(i) Azerenergy will ensure that ADB is kept informed about the Government’s announcement on the implementation of tariff policy reform, and it will implement the tariff policy in accordance with its terms and defined timetable, which will enable Azerenergy to achieve its full cost recovery of its operations by 31 December 2010.
(ii) Within 6 months following the end of each financial year, Azerenergy will submit to ADB (a) the IFRS consolidated financial statements of the company and its subsidiaries, audited by an international auditing firm acceptable to ADB, and (b) audited financial statements in respect of the Project.
(iii) Within 3 months of the end of each financial year, Azerenergy will compute its debt service coverage ratio and gearing ratio for each such financial year, and
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submit these to ADB; and from the year 2012 onwards, Azerenergy will maintain the debt service coverage ratio of not less than 1.5, and the gearing ratio of not more than 70%.
85. Environment. Azerenergy will ensure that (i) the Project is designed, constructed, and operated in accordance with Azerbaijan’s applicable laws and regulations, ADB’s Environment Policy (2002) and the initial environmental examination (IEE); (ii) any adverse environmental impacts are minimized by undertaking the mitigating measures detailed in the EMMP as set out in the IEE; (iii) implementation of the EMMP and any violation of environmental standards are reported semiannually to ADB; (iv) the EMMP is incorporated in bidding documents and bills of quantities of the civil work contracts; (v) the EMMP is updated after detailed design and due diligence, with prior approval of ADB; and (vi) all environmental permits, licenses, and clearances are obtained in a timely manner prior to commencement of civil works in the relevant section of the Project.
86. Azerenergy will ensure that the handling of transformers and PCBs adheres to the terms of the Stockholm Convention, of which the Government is a signatory, and with United Nations procedures for safe handling of PCBs. Azerenergy will ensure that the new transformers are filled with a nontoxic substitute for PCB. Azerenergy will coordinate the handling of transformers and PCBs with MENR as the agency responsible for hazardous materials.
87. Resettlement. Azerenergy will ensure that (i) the Project does not require any land acquisition or involuntary resettlement; (ii) the new transmission lines and towers follow the existing alignment and locations, respectively; (iii) before commencement of civil works, a detailed due diligence report is completed on potential social impacts and submitted to ADB for approval; (iv) in the event any land acquisition or resettlement becomes necessary, or any potential impact on indigenous peoples is identified, a suitable resettlement plan is drawn up in consultation with the affected people, and approval of ADB, in accordance with the applicable laws of the Republic of Azerbaijan, ADB’s Involuntary Resettlement Policy, and Policy on Indigenous Peoples, and is implemented in accordance with its terms; (v) the existing houses under the transmission lines remain intact during project implementation; (vi) the construction is scheduled in the farm areas only during the nonagricultural season (June to September); and (vii) these provisions are incorporated suitably in the bidding documents and made part of the civil works contracts.
88. Change of Ownership and Operation. In the event a change is proposed (i) in the ownership or control of the Project, Azerenergy will, at least 6 months prior to implementation of such a proposal, consult with ADB and obtain its consent; and (ii) in the ownership of Azerenergy, the Government will consult with ADB to ensure that it does not affect the implementation of the Project or the terms of the loan agreement.
89. Government. The Government will ensure that (i) it remains committed to the implementation of the State Program on the Development of the Fuel and Energy Sector in Azerbaijan (2005–2015); (ii) it fully implements its medium-term tariff policy, which incorporates transition to full cost recovery for utility service providers by 2010; (iii) the distribution companies are required to make timely payments for 100% of the power received from Azerenergy; (iv) it provides financial support, as and when needed, to Azerenergy to enable it to fulfill its obligations under the loan agreement with ADB; (v) it causes Azerenergy to make available all counterpart funding and facilities; and (vi) its cabinet of ministers coordinates the work between the Ministry of Economic Development, MENR, Ministry of Industry and Energy, Ministry of
20
Finance, and other government ministries/agencies for expeditious resolution of any issues, and timely implementation of the Project.
VI. RECOMMENDATION
90. I am satisfied that the proposed loan would comply with the Articles of Agreement of the Asian Development Bank (ADB) and recommend that the Board approve the loan of $160,000,000 to Azerenergy Open Joint-Stock Company, guaranteed by the Republic of Azerbaijan, for the Power Transmission Enhancement Project from ADB’s ordinary capital resources, with interest to be determined in accordance with ADB’s London interbank offered rate (LIBOR)-based lending facility; a term of 25 years, including a grace period of 5 years; and such other terms and conditions as are substantially in accordance with those set forth in the draft Loan and Guarantee Agreements presented to the Board.
Haruhiko Kuroda President 19 August 2008
Appendix 1 21
DESIGN AND MONITORING FRAMEWORK
Design Performance Data Assumptions Summary Targets/Indicators Sources/Reporting and Risks Mechanisms
Impact Annual electricity supply in Annual national Assumptions Improved power the project area increased statistics report Macroeconomic growth transmission system by 1,000 GWh by 2012 remains stable that provides reliable Statistics regularly and adequate Annual average electricity conducted by Government remains electricity for outrages reduced by Azerenergy committed to power sustained economic 40 times, from 8–10 times sector reforms and growth per year to 0.2 times per Project quarterly development year by 2012 progress reports Planned transmission Transmission system ADB project completion and generation projects operating and maintained reports commissioned in accordance with technical requirements by 2012
Optimization of power generation resource use through increase of domestic hydropower production by 200 GWh and reduction of importation energy by 650 GWh by 2012
Annual net CO2 emission reduced by 1.3 million tons Outcome The capacity of the Transmission bottlenecks National economic and Assumptions backbone 220 kV removed by 2012 social statistics Government’s high power transmission priority accorded to the and distribution Power transmission Azerenergy annual Project network is expanded capacity of the 220 kV grid report, financial and strengthened, increased by 300 MW in statement, and project Load growth and with transmission 2012 account system expansion as bottlenecks removed forecast and losses reduced Distribution capacity of Project quarterly 220 kV substations progress reports Improved institutional increased by 650 MVA by capacity 2012 ADB review missions Adequate Reduction of transmission maintenance of line losses by 25 GWh, facilities from 6% in 2007 to 3% in 2012 Risk Delay in project implementation
22 Appendix 1
Design Performance Data Assumptions Summary Targets/Indicators Sources/Reporting and Risks Mechanisms
Outputs 1. Construction of a 280 km double-circuit Azerenergy annual Assumptions new double- 220 kV transmission line report, financial Timely provision of circuit 220 kV from Mingechevir to statement, and project counterpart funding transmission line Absheron account Azerenergy full 2. Construction of a Installation of two sets of Project quarterly cooperation with ADB new 220/110 kV autotransformers with a progress reports and compliance with substation in total capacity of 250 MVA, ADB’s procurement Agdash with and other equipment ADB review missions and safeguard adequate guidelines facilities Installation of one set of 3. Expansion of autotransformers with a Procurement of high Absheron capacity of 400 MVA, and quality equipment and substation other equipment material
Erection of 110 kV Adequate project 4. Construction of transmission lines in the management associated 110 vicinity of Agdash kV transmission substation Risks lines in the Unexpected increase vicinity of in prices of Agdash commodities and raw substation materials
Recommended social and Delay in procurement 5. Capacity environmental mitigation and recruitment of development measures are implemented consultants caused by activities for well. Implementation of slow government improving Azerenergy operation approvals Azerenergy’s improvement and training performance programs
Activities with Key Milestones Inputs
1. Recruitment of project implementation consultants completed by August ADB: $160 million 2008. Azerenergy: 2. Turnkey contract for civil works awarded by January 2009. $80 million 3. Compensation for affected people completed by June 2009. 4. Construction and installation of transmission facilities completed by end of Total: $240 million 2011. 5. Capacity development program commenced by January 2009. ADB = Asian Development Bank, CO2= carbon dioxide, GWh = gigawatt-hour, km = kilometer, kV = kilovolt, MVA = megavolt-ampere, MW = megawatt.
Appendix 2 23
POWER SECTOR ANALYSIS
A. Overview
1. Azerbaijan is rich in diverse and abundant energy resources. The overall volume of the country’s hydrocarbon reserves is estimated at 4 billion tons of oil equivalent. Oil and natural gas reserves are 1.8 trillion cubic meters. Along with oil and gas reserves, Azerbaijan has 200 million tons of natural bitumen reserves, 350 million tons of shale oil reserves, and 25 million tons of projected reserves of lignite. Oil production dominates in the country’s economy; about 50 million tons of oil is produced annually.
2. By early 2007, Azerbaijan was importing about 5 billion cubic meters of natural gas annually from the Russian Federation. This gas was used exclusively for electricity generation to reduce inefficient heavy oil consumption. Currently, domestic gas production is increasing because of incrementing gas production by the State Oil Company of Azerbaijan Republic and the development of Shah Deniz field (whose reserves are estimated at over 1 trillion cubic meters). The weight of natural gas consumption in electricity generation is therefore increasing. The country also improves gas supply and district heating. In addition, Azerbaijan has substantial potential in the development of alternative and renewable energy sources mainly, from small hydropower and wind power.
B. Power Generation and Supply
3. Power Generation. Thermal power generation accounted for 89% of total electricity generation in 2007 (78.9% from natural gas and 21.1% from heavy oil), while hydropower generation accounted for 11%. The overall installed capacity of all generation plants in Azerbaijan as of 1 March 2008 was 5,508 megawatts (MW). Azerenergy owns six thermal power plants (TPPs) (3,956 MW), four hydropower plants (HPPs) (1,018 MW), and five modular power plants (452 MW). Other power plants are owned by various state-owned and private enterprises, including Ganja Clay Factory of Azeraluminum (75 MW), Gas Turbine Power Plant at Oil Rocks of the State Oil Company of Azerbaijan Republic (48 MW), TPPs at EP-300 Enterprise of Azerkimya (33 MW), and small hydropower plants (HPPs) (19.2 MW). Table A2.1 shows details of the power generation capacities.
Table A2.1: Power Generating Capacities (as of March 2008) Capacity (MW) Plants Commissioning Date Number of Units Energy Source Installed Available Thermal Power Azerbaijan 1981–1990 8 Gas-mazut 2,400 2,140 Ali-Bayramly 1962–1968 7 Gas-mazut 1,050 860 Shimal 2002 1 Gas 400 350 Baku-1 Gas 1973–2002 2 Gas 106 100 Turbine Nakhchivan 1995–2006 4 Gas-mazut 64 64 Bakı 2007 12 Gas 104 104 Astara 2006 10 Gas 87 87 Sheki 2006 10 Gas 87 87 Khachmaz 2006 10 Gas 87 87 Nakhcevan 2007 10 Gas 87 87 Subtotal TPPs 4,472 3,966 24 Appendix 2
Capacity (MW) Plants Commissioning Date Number of Units Energy Source Installed Available Hydropower Mingechevir HPP 1953–2000 6 Hydro 418 360 Varvara HPP 1956–1957 3 Hydro 16 10 Shamkir HPP 1982–2003 2 Hydro 380 190 Enikend HPP 2000–2003 4 Hydro 150 100 Ter-ter HPP 1976 2 Hydro 50 0 Araz HPP 1970–1971 2 Hydro 22 22 Subtotal HPPs 1,036 682 Total 5,508 4,648 HPP = hydropower plant , MW = megawatt, TPP = thermal power plant. Source: Azerenergy Open Joint-Stock Company.
4. Power Supply and Balance. The electricity production of Azerbaijan in 2007 was 21,415 gigawatt-hours (GWh), of which 19,053 GWh (89% of total) was generated from thermal power and 2,363 GWh (11% of total) from hydropower. In 2007, about 360 GWh of electricity energy was imported from abroad. The imported energy was primarily from Iran to supply Nakhchivan Autonomous Republic, which does not have direct access to the national power network, and also from the Russian Federation, with which Azerbaijan maintains an annual balance of import and export. The total export electricity energy to Iran and the Russian Federation was 727 GWh. Total domestic electricity consumption in 2007 was 19,000 GWh. The growth rate of domestic electricity demand reached 5.8% in 2007 and 4.4% in 2006. However, countrywide electricity consumption decreased by 13% in 2007 compared to 2006 because of extensive installation of accurate meters and a tariff increase. It is forecast that electricity demand will grow by an average of about 4.7% per year through 2015. The power supply and balance is in Table A2.2.
Table A2.2: Power Supply and Balance (GWh) No. Items 2000 2001 2002 2003 2004 2005 2006 2007 1. Power generation 18,603.0 18,822.0 18,578.0 21,150.0 21,345.0 22,348.0 23,782.0 21,415.0 Thermal power 17,069.0 17,521.0 16,558.0 18,681.0 18,589.0 19,340.0 21,269.0 19,053.0 Hydropower 1,534.0 1,301.0 2,020.0 2,470.0 2,755.0 3,008.0 2,514.0 2,363.0 2. Auxiliary consumption 1,020.0 1,048.0 956.0 985.0 993.0 1,000.0 1,042.0 885.0 3. Power supplied 17,583.0 17,774.0 17,622.0 20,166.0 20,352.0 21,348.0 22,740.0 20,530.0 Thermal power 16,060.0 16,487.0 15,611.0 17,704.0 17,605.0 18,349.0 20,235.0 18,176.0 Hydropower 1,523.0 1,290.0 2,011.0 2,462.0 2,747.0 2,999.0 2,505.0 2,355.0 4. Power imported from 1,357.0 1642.0 2,235.0 2,436.0 2,373.0 2,082.0 1,766.0 548.0 Iran 290.0 483.0 510.0 548.0 619.0 656.0 631.0 178.0 Georgia 0.9 0.0 0.0 32.7 0.0 20.0 54.0 110.0 Russian Federation 654.0 727.0 1,300.0 1,454.0 1,376.0 1,004.0 755.0 246.0 Turkey 413.0 433.0 425.0 402.0 379.0 403.0 326.0 15.0 5. Total power supplied 18,940.0 19,416.0 19,857.0 22,602.0 22,725.0 23,430.0 24,506.0 21,078.0 6. Network losses 2770.0 2,272.0 1,237.0 1,059.0 1,076.0 1,001.0 829.0 733.0 % 14.6 11.7 6.2 4.7 4.7 4.3 3.4 3.5 7. Power exported to 863.0 966.0 565.0 871.0 1,008.0 880.0 879.0 786.0 Iran 0.0 454 565.0 554.0 737.0 583.0 542.0 343.0 Georgia 17.8 3.3 0.0 0.0 0.0 20.7 20.0 107.0 Russian Federation 845.0 509 0.0 317.0 271.0 276.0 317.0 321.0 Turkey 0.2 15.0
Appendix 2 25
No. Items 2000 2001 2002 2003 2004 2005 2006 2007 8. Power supplied to 15,308.0 16,178 18,055.0 20,672.0 20,640.0 21,549.0 22,798.0 19,558.0 customers Source: Ministry of Industry and Energy; Azerenergy Open Joint-Stock Company.
5. Transmission Network. The backbone power transmission network includes 500–110 kilovolt (kV) substations and transmission lines, and 0.4–35 kV distribution networks. The power grid includes about 130 main substations. The installed capacity of the step-down transformers at substations is over 13,500 megavolt-amperes (MVA). Table A2.3 shows the power grid backbone network. Table A2.3: Azerbaijan Power Grid’s Backbone Network Substations Length of Transmission Lines 500/330/220 kV Absheron—1 substation 500 kV—2 lines (450 km) 330/110/10 kV—6 substations 330 kV—14 lines (1,207 km) Ganja, Yashma, 330 kV Imishli, Agstafa, Agdjabedi, Aghdam (Ermənistan işğalında olan ərzidədir) 220/110/10–6 kV—9 substations 220 kV—19 lines (1,230 km) Masally, Agsu, Nizami, Sangachal, Moushvig, Khyrdalan, Gabala, Babek, Hovsan 110/35/6–10 kV—112 substations 110 kV—175 lines (2,484 km) 35/6–10 kV—620 substations 35 kV—more than 350 lines (4,800 km) 6–10/0.4 kV—more than 17,500 substations 6–10 kV—more than 3,200 lines (37,900 km) 0.4 kV—around 60,000 lines (61,000 km) Source: Consultant report prepared for ADB (2008).
6. Cross-border interconnections with neighboring countries enable power swap and export and import with (i) the Russian Federation via 330 kV transmission lines; (ii) Georgia via a 330 kV transmission line; and (iii) Iran via 110 kV and 230 kV transmission lines. Azerbaijan used to import electricity from Turkey via 154 kV transmission lines to meet the power demand of Nakhchivan Autonomous Republic. However, since 2007, power is exported from Nakhchivan Autonomous Republic to Turkey to pay back debts for imported electricity—this was made possible by the construction of new generation capacities in Nakhchivan Autonomous Republic.
7. The majority of the power network has been in operation for 30 years or more. As a result, thermal carrying capacity has decreased and transmission losses have increased.
C. Government Policies and Strategies for the Power Sector
8. Sector Reforms and Policies. With support from the Asian Development Bank (ADB) and other development partners, a comprehensive energy sector (including power, renewable energy, gas, and heat supply) road map 1 was prepared in 2006. The Government’s main objectives for development of the power sector are to utilize energy resources efficiently, protect the country’s energy security, and ensure the delivery of reliable and adequate electricity services for sustained economic growth. Since 2005, the Government has been implementing reforms in the utilities and infrastructure sectors, through financial restructuring of the large
1 Valiyev, Vilayat. 2006. Preparation of Energy Sector Roadmap. Manila: ADB .
26 Appendix 2 natural monopolies, separation of commercial and regulatory functions, and introduction of a proper regulatory framework. The Government’s overall policy framework for development of the power sector has the following components: (i) sector restructuring to separate the ownership and management of generation, transmission, and distribution; (ii) development of a regulatory framework and institutions to promote competition and ensure the financial viability of sector enterprises; (iii) introduction of targeted social protection programs to mitigate the impact of higher tariffs on vulnerable groups; (iv) involvement of the private sector in the operation and financing of generation and distribution facilities; and (v) promotion of the use of renewable energy sources and energy efficiency. Progress on sector restructuring has been achieved, including the establishment of four regional distribution companies; private sector operations in the power generation; and the creation of the Ministry of Economic Development who is responsible for energy sector policy making, pricing and tariffs, licensing, and management of fixed assets. The Tariff Council, chaired by the Ministry of Economic Development, has the authority to propose tariff adjustments, define customer categories, and adopt cost-reflective tariff design. Furthermore, the Government ordered all large companies to change to international financial reporting standards (IFRS) by January 2008, and all government ministries have to implement international public reporting standards by January 2009. This is under the management and control of the Ministry of Finance.
9. Development Strategies. The Government’s power sector development strategies are defined by the state program for the development of fuel and energy complex of Azerbaijan (2005–2015),2 which was approved by presidential decree on 14 February 2005. The outlines of the strategies include (i) construction of new combined cycle gas turbine generation units and hydropower generation capacities; (ii) modernization and reconstruction of operating power units—increasing their efficiency, prolonging their useful life, and expanding available capacities; (iii) development of small hydropower and other renewable energy sources (wind and solar) to supplement the energy balance; (iv) construction of new substations and transmission lines to expand transmission and distribution networks, and reconstruction and upgrade of dispatch control systems; (v) strengthening of cross-border links with the Russian and Iranian grids to increase power trade capacity; (vi) increasing investments for energy sector development and attracting foreign investments; (vii) expanding international collaboration and participating in the formation of regional energy markets; and (viii) promotion of private sector participation in infrastructure development.
10. Existing Legislative Framework. The following normative legislative acts of Azerbaijan, relating to the power sector, are currently in force:
2 Cabinet of Ministers. 2005. State Program for Development of Fuel and Energy Sector in Azerbaijan (2005–2015), Baku.
Appendix 2 27
(i) Law on Energy (1998). This covers policy objectives, ownership of resources, control of exploration, development of fields, and construction and maintenance of energy systems. It includes a strong commitment to energy efficiency and contains significant licensing provisions.
(ii) Law on Power Engineering (1998). This provides the legal basis for power generation, transmission, distribution, purchase, sales, and consumption. It governs the activities of state power engineering companies, power supply companies, independent power producers, and consumers. The relevant state authorities are responsible for licensing, transmission and distribution contracts, pricing, de-monopolization, performance criteria, rules, and standards.
(iii) Law on Electric and Thermal Electric Plants (1999). This creates convenient conditions for the production of electricity and heat in power plants, including development of independent power producers; construction and operation of power plants with sovereign guarantee; and implementation of environmental monitoring and management for power plants.
(iv) Law on Use of Energy Resources (1999). This provides the legal, economic, social, and environmental grounds for utilization of energy resources.
(v) Law on Natural Monopolies (1998). This defines the institutional and legal basis of state regulation of natural monopolies, and ensures the conformity of the activities of natural monopoly with consumers’ interests.
(vi) Law on Privatization of State Property (2000). According to the law, the major objective of privatization of state property is to achieve improvement in the efficiency of the economy, structural adjustments, and living standards of the population through liberalization of the economy, strengthening of entrepreneurship, formation of a competition climate, and attraction of investments.
11. Institutional Structure. The cabinet of ministers mainly provides the normative and legislative basis for the sector, while the Ministry of Industry and Energy carries out state policy in the energy sector (development and application of strategies, investment plans, development programs, normative and legal documents, etc.) and conducts regulatory (issuance of licenses, development and application of standards, preparation of various codes, etc.) and supervisory functions (technical audits, monitoring, reporting, information requests, etc.) for sector enterprises. As regulatory bodies, the Ministry of Economic Development and the Ministry of Finance implement the regulatory functions, such as formation of the economic and financial policy in the sector; and overseeing investment plans, tariff issues, subsidies, and financial and social assistance. The Tariff (Price) Council addresses monopoly services for the electricity, natural gas, and water sectors. It has authority to propose tariff adjustments to the cabinet of ministers, define customer categories, and adopt a cost-reflective tariff design. The committee for management of state property has the supervisory function over the concession agreements for electric distribution networks and approves their investment programs. It also supervises relations with consumers, and oversees any privatization and management of property in the energy sector.
12. Azerenergy Open Joint-Stock Company (JSC) is the state-owned power company that generates electricity, transmits the generated electricity, and delivers part of it directly to
28 Appendix 2 consumers and sells it in bulk to power distribution companies. Distribution companies deliver electricity to retail consumers within their service areas. Small private hydropower plants (independent power producers) generate electricity and deliver it directly to power system or consumers.
13. Private Sector Participation. Under the laws governing the power sector, the sector’s institutional structure comprises interrelations among Azerenergy, power supply enterprises, independent power producers, and power consumers. Azerenergy is dominant in the generation and transmission of electricity, as well as about 50% of electric distribution networks. Independent power producers have emerged as a result of the privatization of three small hydropower plants. They operate within the structure of other enterprises and sell the generated power independently. In September 2007, the Ministry of Economic Development and the Korean Power Company signed a preliminary agreement on the construction of the first private thermal power plant (700 MW).
14. Price–Tariff Policy. The price and tariff regulation is conducted by the reorganized Tariff Council. In compliance with existing legislation, decisions on the regulation of prices (tariffs), service fees, and collections are adopted by a simple majority of vote principle. The regulations also provide the principles and methodology for state regulation.
15. Current wholesale and retail electricity tariffs were approved by the Tariff Council on 6 January 2007. The wholesale tariff is AZN0.041 per kilowatt-hour (kWh) inclusive of value- added tax (VAT) for Azerenergy Open JSC, AZN0.025 per kWh for small private hydropower plants, and AZN0.045 per kWh (VAT-inclusive) for wind power plants. Retail tariffs for all consumer categories (residential, commercial, and others) is AZN0.06 per kWh (VAT-inclusive). The transmission tariff is AZN0.002 per kWh (VAT-inclusive). Prices for export and import transactions are regulated under the terms of relevant agreements. Electricity import–export arrangements are conducted with the neighboring Georgia, Iran, and Russian Federation. The majority of import–export arrangements with the Russian Federation are on a monetary basis (prices are subject to negotiations between two countries). There is a severe difference in export and import transactions because Azerbaijan imports Russian electricity mainly for peak demand periods at higher tariffs, and exports electricity to the Russian Federation at lower tariffs during nighttime. The electricity swap with Iran is conducted on a seasonal basis—this is efficient because Azerbaijan imports electricity from Iran in the winter (when Azerbaijan has peak electricity demand) and exports to Iran in the spring and summer (when Iran has peak electricity demand).
D. Existing Problems and Challenges in the Power Sector
17. The power sector has suffered from inadequate funding to invest in new power facilities, perform essential maintenance functions, and introduce new technology. The most challenging technical problems of the power sector are (i) deterioration of 20% of the power equipment and more than 50% of the grid facilities; (ii) a shortfall of peak load in the system (about 300 MW); and (iii) lack of adequate capacity of transmission lines. The high-voltage transmission lines, including those connecting Mingechevir and Absheron, are obsolete with high losses and frequent outages. Some of these transmission lines have completed their useful life. The result has been a distinct deterioration in the quality of the infrastructure and an associated deterioration in the quality of services. Rehabilitating and upgrading generation and transmission facilities could significantly improve the reliability and quality of power system operation, and reduce system losses. The proposed Power Transmission Enhancement Project will substantially contribute to the Government’s efforts in that respect.
Appendix 3 29
PROBLEM TREE ANALYSIS FOR THE POWER SECTOR
Limited Socioeconomic Development
Effects
Poor Financial Negative High Energy Performance of Environmental Losses Utility Impact
Unreliable and Core Problem Inadequate Power Supply
Causes
Regulatory and Weak Institutional Power System Investment and Policy Constraints Capacity and Operation Financing Governance Problems Problems
Inadequate Legal Human Resources Obsolete and Old Non-Economic and Regulatory Constraints Equipment and Pricing of Environment Technology Electricity
Sector Lack of Sound Suboptimal Restructuring in Governance with Operation Poor Financial Transition International of Power Grid Management Practice Lack of Efficient Inadequate Limited Private Coordination Lack of Sound Maintenance and Sector among Line Sector Rehabilitation Participation Ministries Development Strategy and Inadequate Limited Fiscal Road Map Lack of System Planning Budget on Public Self-Sufficiency and Studies Infrastructure Policy Shortage of Peak Power Supply
Source: Asian Development Bank.
30 Appendix 4
EXTERNAL ASSISTANCE TO THE POWER SECTOR
Funding Amount Project Approval Source ($ million)
ADB Technical Assistance
TA 4726: Preparing the Rural Renewable ADB 0.70 December 2005 Energy Development Project (PPTA) TA 7069: Preparing the Power Transmission ADB 0.15 March 2008 Enhancement Project (SSTA)
External Lending Agencies
Construction of 400 MVt Steam–Gas plant at JBIC 272.75 June 2005 Shimal Power Plant (¥29,280 million) Reconstruction of 1st–4th and 6th–8th units EBRD 207.00 December 2007 of Azerbaijan TPP Mingechevir HPP 1st and 3rd units Varvara IsDB 80.00 2008 HPP Khachmaz substation IsDB 13.50 September 2005 Program for rehabilitation of electric KfW 23.96 July 2003 transmission sector II (initial phase of (€15.34 million) SCADA system) Program for rehabilitation of electric World Bank 48.00 February 2006 transmission (establishment of SCADA system and reconstruction of transmission) Azerbaijan TPP-Imishli 330 kV electric power KfW 46.85 December 2007 line (€30 million) ADB = Asian Development Bank, EBRD = European Bank for Reconstruction and Development, HPP = hydropower plant, IsDB = Islamic Development Bank, JBIC = Japan Bank for International Cooperation, KfW = Kreditanstalt für Wiederaufbau, PPTA = project preparatory technical assistance, SCADA = supervisory control and data acquisition, SSTA = small-scale technical assistance, TPP = thermal power plant. Source: Asian Development Bank.
Appendix 5 31
COST ESTIMATES AND FINANCING PLAN ($ million)
Total ADB Azerenergy Base Cost 1 Equipment and Materials 128.4 128.4 0.0 a 220kV Substation Agdash Construction 18.3 18.3 0.0 b 220kV Tranmission Line Mingechevir 1 and 2 101.8 101.8 0.0 c 500/330/220kV Substation Absheron Upgrading 8.3 8.3 0.0
2 Civil Works 34.2 28.8 5.4 a 220kV Substation Agdash Construction 3.1 3.1 0.0 b 220kV Tranmission Line Mingechevir 1 and 2 15.8 15.8 0.0 c 500/330/220kV Substation Absheron Upgrading 1.4 1.4 0.0 d Dismantling Works and Local Transportation 8.5 8.5 0.0 e Detailed Engineering Design 5.4 0.0 5.4
3 Consulting Servicesa 1.1 0.0 1.1
4 Taxes and Duties 32.5 0.0 32.5 a VAT 31.6 0.0 31.6 b Customs Duties 0.9 0.0 0.9
Total Base Cost 196.3 157.2 39.1
Contingencies 1 Price contingencies 26.7 0.0 26.7 2 Physical Contingencies 11.2 2.8 8.4
Total Contingencies 37.9 2.8 35.1
Interest During Construction 5.9 0.0 5.9
Total Project Cost (A+B+C) 240.0 160.0 80.0 a Consulting services include environmental handling costs. Source: Azerenergy and ADB estimates. 32 Appendix 6
PROJECT IMPLEMENTATION SCHEDULE
IMPLEMENTATION SCHEDULE
IDTask 2008 2009 2010 2011 2012 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
1 Loan Approval 2 Loan Effectivity 3 Advance Recruitment of Consultants 4 Appoint Supervision Consultants 5 Bidding documents preparation 6 Bidding for EPC contract 7 EPC Contract Award
8 220 kV Transmission Line Detailed engineering design Civil works and installationa Commissioning and testing Start of commercial operation 9 Agdash Substation Detailed engineering design Civil works and installation Commissing and testing Start of commercial operation 10 Expansion of Abshron Substation Civil works Equipment installation Start of commercial operation
11 Loan Closing
EPC = engineering, procurement and construction. a Construction in farmed areas only during the non-agricultural season (from June to September). Source: Asian Development Bank estimates. Appendix 7 33
PROCUREMENT PLAN
Project Name: Power Transmission Loan (grant) Number: To be determined (tbd) Enhancement Project Loan Amount: $160 million Executing Agency: Azerenergy Open Joint– Stock Company Date of first Procurement Plan: Date of this Procurement Plan: September 2008 September 2008
A. Process Thresholds, Review, and 18-Month Procurement Plan
1. Project Procurement Thresholds. Except as the Asian Development Bank (ADB) may otherwise agree, the following process thresholds shall apply to procurement of goods and works.
Method Threshold International Competitive Bidding (ICB) for $3,000,000 Works
2. ADB Prior or Post Review. Except as ADB may otherwise agree, the following prior or post review requirements apply to the various procurement and consultant recruitment methods used for the project.
Procurement Method Prior or Post Comments ICB Works Prior
3. Goods and Works Contracts Estimated to Cost more than $1 million. The following table lists goods and works contracts for which procurement activity is either ongoing or expected to commence within the next 18 months.
General Description Contract Procurement Prequalification Advertisement Comments Value Method of Bidders Date (y/n) (quarter/year) Turnkey contract $165 million ICB works No Q4 2008 ADB: (design, procurement, $155 million and installation) including: Azerenergy: (i) 220 kV $10 million transmission line (ii) 220 kV substation (iii) 110 kV lines (iv) Upgrading Absheron (v) Dismantling works (vi) Detailed engineering design ADB = Asian Development Bank, ICB = international competitive bidding, kV = kilovolt, Q = quarter.
34 Appendix 7
B. Project Procurement Plan
4. Indicative List of Packages Required under the Project. The following table provides an indicative list of all procurement (goods, works, and consulting services) over the life of the project. Contracts financed by the Borrower and others should also be indicated, with an appropriate notation in the comments section.
General Description Estimated Estimated Procurement Domestic Comments Value Number of Method Preference (cumulative) Contracts Applicable Works: Turnkey contract $165 million 1 ICB Works No (design, procurement, and installation) including: (i) 220 kV transmission line (ii) 220 kV substation (iii) 110 kV lines (iv) Upgrading Absheron (v) Dismantling works (vi) Detailed engineering design Estimated Estimated Recruitment Type of Comments Value Number of Method Proposal (cumulative) Contracts Consulting Services $1.1 million 1 International Full proposal Finance by assignment, Azerenergy Single source selection ICB = international competitive bidding, kV = kilovolt.
C. National Competitive Bidding
5. General. The procedures to be followed for national competitive bidding (NCB) shall be those set forth in the Public Procurement Law of 27 December 2001 with the clarifications and modifications described in the following paragraphs required for compliance with the provisions of ADB’s Procurement Guidelines (2007, as amended from time to time).
6. Eligibility. No bidder or potential bidder should be declared ineligible for reasons other than those stated in section I of the Procurement Guidelines. Bidders must be nationals of member countries of ADB, and offered goods, services, and works must be produced in and supplied from member countries of ADB.
7. Prequalification. Normally, post-qualification shall be used unless explicitly provided for in the procurement plan. Irrespective of whether post-qualification or prequalification is used, eligible bidders (both national and foreign) shall be allowed to participate.
8. Registration and Licensing. The following procedures will be adhered to with respect to registration and licensing:
(i) Bidding shall not be restricted to preregistered or licensed firms.
(ii) Where registration or licensing is required, bidders (a) shall be allowed a reasonable time to complete the registration or licensing process; and (b) shall
Appendix 7 35
not be denied registration or licensing for reasons unrelated to their capability and resources to perform the contract successfully, which shall be verified through post-qualification.
(iii) Foreign bidders shall not be precluded from bidding. If a registration or licensing process is required, a foreign bidder declared the lowest evaluated bidder shall be given a reasonable opportunity to register or to obtain a license.
9. Bidding Period. The minimum bidding period is 28 days prior to the deadline for submission of bids.
10. Bidding Documents. Procuring entities should use standard bidding documents for the procurement of goods, works, and services acceptable to ADB. 11. Preferences. No domestic preference shall be given for domestic bidders and for domestically manufactured goods.
12. Advertising. Invitations to bid shall be advertised in at least one widely circulated national daily newspaper or freely accessible, nationally known website allowing a minimum of 28 days for the preparation and submission of bids. Bidding of NCB contracts estimated at $500,000 equivalent or more for goods and related services or $1,000,000 equivalent or more for civil works shall be advertised on ADB’s website via the posting of the procurement plan. 13. Bid Security. Where required, bid security shall be in the form of a bank guarantee from a reputable bank.
14. Bid Opening, Bid Evaluation, and Award of Contract. The following procedures will be adhered to with respect to bid opening, bid evaluation, and award of contract:
(i) Bids shall be opened in public.
(ii) Evaluation of bids shall be made in strict adherence to the criteria declared in the bidding documents and contracts shall be awarded to the lowest evaluated bidder.
(iii) Bidders shall not be eliminated from detailed evaluation on the basis of minor, non-substantial deviations.
(iv) No bidder shall be rejected on the basis of a comparison with the employer's estimate and budget ceiling without ADB’s prior concurrence.
(v) A contract shall be awarded to the technically responsive bidder that offers the lowest evaluated price, and meets the qualifying requirements. Negotiations shall not be permitted.
(vi) Splitting of award, of a single contract, among two or more bidders shall not be permitted.
(vii) Price verification shall not be applied.
15. Rejection of All Bids and Rebidding. Bids shall not be rejected and new bids solicited without ADB’s prior concurrence.
36 Appendix 7
16. Disclosure of Decision on Contract Awards. At the same time that notification of award of contract is given to the successful bidder, the results of bid evaluation shall be published in a local newspaper or a well-known freely accessible website, identifying the bid and lot numbers and providing information on (i) the name of each bidder who submitted a bid; (ii) bid prices as read out at bid opening; (iii) the name of bidders whose bids were rejected and the reasons for their rejection; and (iv) the name of the winning bidder and the price it offered, as well as the duration and summary scope of the contract awarded. The executing agency, implementing agency and contracting authority shall respond in writing to unsuccessful bidders who seek explanations on the grounds on which their bids are not selected.
17. Participation by Government-Owned Enterprises. Government-owned enterprises in Azerbaijan shall be eligible to participate as bidders only if they can establish that they are legally and financially autonomous, operate under commercial law, and are not a dependent agency of the contracting authority. Furthermore, they will be subject to the same bid and performance security requirements as other bidders.
18. Right to Inspect and Audit. A provision shall be included in all NCB works and goods contracts financed by ADB, requiring suppliers and contractors to permit ADB to inspect their accounts and records and other documents relating to the bid submission and the performance of the contract, and to have them audited by auditors appointed by ADB.
19. Fraud and Corruption. The following provisions shall be adhered to with respect to fraud and corruption:
(i) The Borrower shall reject a proposal for award if it determines that the bidder recommended for award has, directly or through an agent, engaged in corrupt, fraudulent, collusive, or coercive practices in competing for the contract in question.
(ii) ADB will declare a firm or individual ineligible, either indefinitely or for a stated period, to be awarded a contract financed by ADB, if it at any time determines that the firm or individual has, directly or through an agent, engaged in corrupt, fraudulent, collusive, or coercive practices in competing for, or in executing, ADB- financed contract.
Appendix 8 37
OUTLINE TERMS OF REFERENCE
A. Introduction
1. Azerenergy Joint-Stock Company (Azerenergy) intends to construct a double circuit 220 kilovolt (kV) transmission line with a total length of 280 kilometers (km) between Mingechevir hydropower plant and the 500/330/220 kV Absheron substation to replace the two existing transmission lines used for 60 years. The Project consists of (i) construction of a double-circuit 220 kV transmission line of 280 km between Mingechevir hydropower plant and 500/330/220 kV substation Absheron; (ii) construction of the 220/110 kV Agdash substation, including installation of two 125 megavolt-ampere (MVA) transformers and other equipment; (iii) construction of 110 kV transmission lines near Agdash substations; (iv) expansion of the 500/330/220 kV Absheron substation and installation of one unit 400 MVA transformer and breakers; and (v) miscellaneous work, including project supervision, an environmental management program, and a compensation program.
2. A team of international consultants will be recruited by Azerenergy to assist with procurement, supervision of construction, final testing, and commissioning of the works; and improve the agency’s project management capacity. The team will include transmission and distribution specialists, procurement specialists, contract management experts, and social and environmental management specialists. The consultants will perform the tasks in Azerbaijan with suitable head office backup, and improve the design and project supervision skills of Azerenergy staff; where possible, they will use local expertise.
B. Terms of Reference
3. A consulting firm will be engaged to carry out the following main tasks:
(i) Review the existing feasibility studies for the Project and other relevant power transmission design documents. Prepare preliminary designs taking into account the design practices used by Azerenergy and current international standards.
(ii) Prepare the scope of supply and technical specification of transmission and substation equipment, including spare parts and terms of reference for training operation and maintenance.
(iii) Consolidate (i) and (ii) into a design report giving project details, costs, implementation schedule, and recommendations for mitigation of adverse environmental impacts for approval by Azerenergy and the Asian Development Bank (ADB).
(iv) Prepare bidding documents for all equipment and services required to implement the Project, suitable for international competitive bidding, and local competitive bidding procedures as necessary and acceptable to the Government and ADB.
(v) Assist Azerenergy in inviting suitable qualified bidders and evaluating bids, and awarding contracts.
(vi) Review and approve the contractor’s detailed design drawings and technical documents.
38 Appendix 8
(vii) Supervise construction of the project facilities and provide guidance to the contractors to conform with the specifications.
(viii) Witness commissioning, guarantee, and acceptance tests; and assist Azerenergy in taking over the completed facilities.
(ix) Review and compile “as-built” drawings, and review the operation and maintenance manuals provided by the contractors for accuracy and adequacy.
(x) Assist Azerenergy to update and implement the resettlement and compensation plan, to provide capacity building to Azerenergy in environmental management and social safeguards as well as training to other agencies implementing resettlement at district and commune levels.
(xi) The consultants will assist Azerenergy in implementing the environmental management and monitoring plan in accordance with the laws and regulations of the Government of Azerbaijan. This will include (i) preparing an implementation schedule for mitigation measures, based on the Project’s initial environmental examination (IEE); (ii) establish an environmental monitoring and reporting plan; and (iii) provide training for relevant government officers in the implementation of detailed environmental management plans.
(xii) Prepare and submit an inception report and quarterly progress reports acceptable to ADB, and compile a project completion report in the format prescribed by ADB providing details of project implementation, problems encountered, solutions adopted, and detailing and explaining any variation in project costs and implementation times from the original estimates.
(xiii) The consultant will monitor and evaluate the performance of the completed project by comparing a number of indicators prior to and after completion of the new transmission lines. The impact of the Project on Azerenergy’s operations will be monitored by evaluating data on electrical losses, sales loss through system breakdown, average cost of service, and monthly consumption by consumer category. The impact of the bulk supply distribution system will also be evaluated.
C. Reporting Requirements
4. Besides the design report, the consultants will provide a brief inception report within 4 weeks from the start of the assignment, a quarterly progress report within 15 days from the end of each quarter, and a project completion report at the end of the assignment. Three copies of these reports will be provided to Azerenergy, and three to ADB (two to Manila and one to the Azerbaijan Resident Mission).
D. Person-Month Estimates
5. A total of 90 person-months of international consulting, to be associated with about 100 person-months of local expertise, will be spread over 4 years, from the fourth quarter of 2008 to the end of 2011.
Appendix 9 39
SUMMARY OF ECONOMIC ANALYSIS
A. Background
1. The proposed Project, to be funded by the Asian Development Bank (ADB), is set in the context of the state program for development of fuel and energy sector in Azerbaijan (2005– 2015). 1 The state program recognizes the changing structure of energy demand, with the significant increase in the residential component, and the consequential impact on peak demand in the winter caused by the heating load.
2. Although Azerenergy identifies benefits to the replacement transmission lines, within the context of the state program for energy transmission, neither Azerenergy nor the Government have undertaken any cost–benefit analysis to support these benefits other than in the following references. It was however concluded by Azerenergy and confirmed by ADB that the Project will increase the supply of the power network by 300 megawatts (MW), reduce the capacity loss by 8 MW, and cut the loss of electric energy by 25 gigawatt-hours (GWh).
3. Azerenergy also identifies the shortfall in peak capacity (some 300 MW), which requires that peak demand is met by importing energy from the Russian Federation. It is on this basis that the justification of the replacement transmission lines is proposed, by evaluating the avoidable cost of imported peak power.
4. The economic internal rate of return (EIRR) compares the annual streams of economic capital and operating costs against benefits based on willingness to pay. All costs, benefits, and revenues are expressed in 2007 constant prices. The analysis period includes the construction period and 23 years (up to 2030) of operation. Details of the assumptions and calculations used for the economic analysis are in Supplementary Appendix C. The economic analysis confirms that the Project will alleviate high energy costs for the country, and help meet energy security and projected growth in demand for electric power. Cost–benefit projections were prepared and analyzed, and they indicated that the Project is economically viable.
B. Project Alternatives
5. If connections between existing centers of demand and generation need to be sustained, there are no viable alternatives to replacing existing transmission lines. There may be options regarding routing, connections to the lines, and the location of substations, and these should be subject to evaluation by system planning techniques.
6. When replacing existing transmission lines, consideration of the least-cost option will be a matter of evaluating the technical specifications.
7. Azerenergy has addressed the issue of the project alternative from a different perspective. Its prefeasibility study report projects that the new transmission lines will result in the availability of an additional 300 MW of capacity (which represents the design capacity of a generic thermal power plant).
8. The cost of the proposed transmission lines (capital cost of $176 million) has been compared with the construction cost of a generic power plant ($460 million). In addition, the
1 Cabinet of Ministers. 2005, State Program for Development of Fuel and Energy Sector in Azerbaijan (2005–2015). Baku. 40 Appendix 9 lifetime operational cost of the transmission lines is calculated to be some $16 million a year cheaper. While the comparison may serve to emphasize the merit of the replacement transmission lines, the alternative of constructing a new generating plant has not been proposed.
C. Economic Analysis Calculations
1. Cost–Benefit Analysis
9. The EIRR calculation was based on incremental cost and benefit streams associated to the Project. Economic performance was evaluated by comparing with- and without-project scenarios. Incremental consumption occurs because of the extended availability of lower-cost electricity. Economic benefits accrue to consumers and the economy as a result of the Project.
2. Project Benefits
10. Reduced Imports. The methodology applied for evaluating the single quantified benefit of the Project was the avoidable cost of importing peak energy from the Russian Federation. The value of 650 GWh for the saved import energy is based on actual data.
11. The basis for valuing the replacement transmission line is that it will permit the direct substitution of imported electricity with own generation. The economic benefit is therefore non- incremental, and relates to a traded product. The basis of valuation will be the tariffs relating to the import and export of electricity. Azerenergy indicates that, in terms of trading energy with the Russian Federation, it is only able to export at the low-rate night tariff of 2.3 cents per kWh (c/kWh) (which does not cover generation cost).
12. The economic price should therefore be based on the weighted average of the import and export prices, and it is assumed that these contractual prices have no element of transport, distribution, or handling. This approach follows ADB’s guidance on import substitute and exportable output.2 The base case has assumed the weighting of imports to exports at 50:50, based on the assumption of 650 GWh—this is considered conservative given that, aside from 2007, imports have exceeded exports by more than two times.3 This gives a weighted average price for import to export exchange of 4.25 c/kWh. A detailed explanation can be found in Supplementary Appendix C.
13. Transmission System Losses. The evaluation of reduced system losses is incorporated into the calculation of the total 650 GWh energy increase. There is an implied assumption of 4% system losses, which appears reasonable. Table A9.1 shows the recent levels of transmission losses.
Table A9.1: Transmission System Losses (%) 2005 2006 2007 3-Year Average 4.65 4.63 4.40 4.56 Source: Azerenergy Open Joint-Stock Company.
2 ADB. 1997. Guidelines for the Economic Analysis of Projects. Manila (Appendix 10). 3 Azerenergy regards 2007 an exceptional year because of reduced consumer demand resulting from the 2007 retail tariff increase of 170% in combination with the increased installation of electricity meters. Import and exports were estimated at about 250 GWh for a total of 500 GWh for 2007.
Appendix 9 41
14. A reduction of 12.5% in transmission losses (the midpoint in the anticipated 10%–15% range of improvement) will reduce the absolute level to 4% (para.13).
15. Improved System Performance. Based on 2006–2007 fault statistics, it is estimated that total annual outages amounted to 33 hours for Mingechevir 1 transmission line and 33.5 hours for Mingechevir 2 transmission line.
16. To derive a value for power lost from an annual average outage of 33 hours, reference was made to the World Bank report on the Azerbaijan Power Transmission Project.4 The report shows losses for Mingechevir 1 and 2 transmission lines in 2003 totaling 224.5 hours with losses of 13,605 megawatt-hours (MWh); by interpolation, the average annual 2006–2007 losses equate to 2,000 MWh.
17. The World Bank report also identifies willingness to pay on the basis of a weighted average cost of diesel and kerosene of 21.5 c/kWh. Adjusting this value from 2005 to 2007 prices by taking the movement in the AZN/$ exchange rate gives a value of 24.3 c/kWh for willingness to pay. If it is assumed that the new line will reduce outages by 50%, the annual economic benefit is 1,000 MWh valued at willingness to pay, giving a total of $243,000 per annum.
18. Reduced Maintenance Costs. An annual reduction in maintenance costs of $100,000 has been identified by Azerenergy for inclusion in the economic analysis.
19. Deferred Expenditure on New Generation. Azerenergy identifies the cost of constructing a 300 MW power station at $460 million as an alternative option to the replacement transmission lines. Investment in the new lines will defer any decision to increase capacity in generation, and the related benefit will be the capital costs savings of such a deferral—as measured by the potential interest earned on the deferred debt service costs. This benefit has been quantified at $3.0 million per annum, assuming a 10% deposit rate, and has been assumed for the first 2 years of the Project.
20. Salvage Value from Removal of Existing Lines. The removal of the existing lines will give rise to two streams of benefits: (i) scrap value of metal content of equipment, and (ii) opportunity benefit of reusing transmission towers at lower voltages.
21. Azerenergy does not have readily available data to quantify the potential volume of scrap metal.
22. The number of transmission towers to be reused is estimated at 600. The cost estimates for the new replacement lines include 980 new towers, so a recycling rate of 60% seems reasonable. The cost of a new 220 kilovolt (kV) steel tower from the estimates is $64,400; it is assumed that the replacement cost of a smaller 110 kV tower is 50% of this value.
23. The benefit of reusing 600 towers at lower voltage levels is therefore $19.3 million. However, to reflect the potential uncertainties in these figures, a lower value of $10.0 million has been taken as a one-off benefit in year 5.
4 World Bank. 2005. Project appraisal document on a Proposed Loan in the Amount of US$48 million to Azerenerji with the Guarantee of the Republic of Azerbaijan for a Power Transmission Project. Washington DC (31485-AZE).
42 Appendix 9
D. Project Costs
11. Construction Costs. The economic price of the construction costs will be the financial costs less any transfer payments. Therefore, customs duties, value-added tax, and payroll deductions have been removed. With regard to payroll deductions, assumptions have been made regarding the labor component of project costs.
25. Land Costs. The replacement transmission lines will follow the route of the existing twin lines, so the existing land usage will continue. This can be considered a sunk cost, with no economic cost consequences for the Project. However, in principle, half of the land under the existing transmission line will become “surplus” and can be considered to have a potential opportunity cost for the Project. Because Azerenergy owns the land, it has been suggested that any surplus could be utilized as compensation to the local population for the disruption of building the new lines. Therefore, the release of land would transfer an economic benefit, dependent on the use made of the land. No evaluation has been made of this benefit.
26. Operating Costs. The only incremental operating cost is the 30 staff required to operate the new substation; transfer payments relating to payroll deductions have been eliminated. It is understood that the intention would be to initially operate the substation with existing Azerenergy staff, but that over time local staff would be trained to operate the facility.
E. Results
27. The economic cost–benefit analysis results in an EIRR of 14.8% for the Project. The net benefits of the Project were estimated to be $26.14 million. The sensitivity analyses show that the investment program remains justified even if various risks materialize.
28. The economic classification of the benefits and costs is summarized in Table A9.2:
Table A9.2: Structure of Transmission Project Benefits and Costs ($ million) Item Present Value Capital Costs (142.34) Operating Costs Labor 0.29 Project Benefits Reduced energy imports 154.67 Reduced maintenance costs 0.56 Reduced system outages 1.36 Reuse of transmission towers 7.12 Deferral of generation expenditure 5.07 Total 26.14 Source: ADB estimates.
29. The significant elements are the capital costs and the benefits attributed to the reduced level of energy imports, and recycling the transmission towers. The labor cost is a second order of magnitude, and no adjustments have been made to reflect any implied economic costs for scarce labor resources during the construction phase.
30. The results of the economic appraisal are set out in Table A9.3, and are based on a 12% discount rate.
Appendix 9 43
Table A9.3: Project Economic Statement ($ million) Item Total 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2030 Economic Capital Cost (175.99) (52.80) (87.99) (35.20) Operating Costs Incremantal Salary and Wages (1.03) 0.00 0.00 (0.03) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05) Total Annual Costs (52.80) (87.99) (35.22) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05) (0.05)
Benefits Reduced energy imports 538.70 0.00 0.00 13.81 27.63 27.63 27.63 27.63 27.63 27.63 27.63 27.63 27.63 27.63 Reduced Maintenance Costs 1.95 0.00 0.00 0.05 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 Reduced system outages 4.74 0.00 0.00 0.12 0.24 0.24 0.24 0.24 0.24 0.24 0.24 0.24 0.24 0.24 Reused transmission towers 10.00 0.00 0.00 10.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Deferral of generation expenditure 6.00 3.00 3.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 561.39 Net Benefit (49.80) (84.99) (11.24) 27.92 27.92 27.92 27.92 27.92 27.92 27.92 27.92 27.92 27.92 Results: NPV @ 12% 26.14, EIRR 14.8%. ( ) = negative; EIRR = economic internal rate or return; NPV = net present value. Source: ADB estimates.
31. As translated into the economic parameters, the project EIRR exceeds the ADB benchmark of 12%.
F. Sensitivity Analysis
32. The results of sensitivity testing of the main parameters are shown in Table A9.4.
Table A9.4: Results of Sensitivity Analysis—Transmission Project (%) Item Change NPV EIRR Sensitivity Switching ($ million) Indicator Value Base Case 26.1 14.8 Costs Capital costs 10 12.9 13.3 5.08 19.7 Reduce labor element of CAPEX (50) 25.7 14.8 0.04 (2,702.6) Benefits Reduce value of reuse of transmission towers (50) 22.6 14.4 (0.20) (367.2) Reduce value of generation deferral (50) 23.6 14.5 (0.19) (514.7) Reduce ratio of imports/exports (50) 3.4 12.4 1.74 (57.6) Alternative scenarios Reduce construction period to 2 years 23.1 14.4 Single benefit of reduced GWh imports 12.0 13.2 Sensitivities to reduce NPV to zero Capital costs +19.2% 19 0.0 12.0 Ratio of imports/exports 31:39 (40) 0.0 12.0 Night rate export tariff reduces to 0.861 c/kWh (64) 0.0 12.0 ( ) = negative, CAPEX = capital expenditures, EIRR = economic internal rate of return, GWh = gigawatt hours, NPV = net present value. Source: ADB estimates.
44 Appendix 9
33. The most sensitive variables are the volume, pricing, and ratio of energy imports and exports, as well as variation in capital costs. If only the single benefit of the reduced imports is included, the EIRR will reduce to 13.2%.
34. A reduction in the net present value (NPV) to zero would require the following circumstances: (i) a 19.2% increase in capital costs; (ii) the ratio of imports/exports to move from 50:50 to 31:69; and (iii) the lowest export tariff to decrease from 2.3 c/kWh to 0.861 c/kWh.
35. The latter two conditions would reflect Azerenergy becoming a net exporter of electricity and continuing to sell the increased volumes of exports at the nighttime tariff of 2.3 c/kWh or lower. This is not a sustainable situation since the tariff would not cover generation costs, so it is anticipated that any sustainable increased level of exports would be at a higher price. The Project therefore delivers a robust and sustainable economic return at 14.8%, around which individual sensitivities do not indicate any significant stress. One element that has not been captured in this analysis is the future potential for transfer of energy from east to west, and the strategic opportunities that could be developed in the context of a regional power exchange. Since there is still no framework or data on which to evaluate this scenario, it remains an unquantified but potential benefit.
Appendix 10 45
SUMMARY OF FINANCIAL ANALYSIS
A. Introduction
1. The financial analysis of the Project has been carried out in accordance with the Financial Management and Analysis of Projects 1 of the Asian Development Bank (ADB). All financial costs and benefits have been expressed at constant 2007 price levels. Cost streams used for the purposes of financial internal rate of return (FIRR) determination (i.e., capital investment, and operations and maintenance) reflect the costs of delivering the estimated benefits. The tariff for electricity has been assumed as the difference between the costs of imported electricity and the cost of own generation of electricity, and has been set at $0.036362 per kilowatt-hour (kWh). The tariff is applied to the volume of 650 GWh—assuming that the Project will enable domestic generation to replace imports.
B. Methodology and Major Assumptions
2. The financial viability of the Project has been assessed assuming a 3-year construction period from 2009 to 2011. It is assumed that construction will finish in the first half of 2011 and the new line will start to operate in the second half of 2011. The weighted average cost of capital (WACC) is also calculated for the Project and was compared with the FIRR to ascertain the financial viability of the investment program. Price contingencies and interest during construction were excluded from the capital costs for the purpose of the FIRR, which is at 2009 constant prices. The net present value (NPV) of the projected incremental net cash flows arising from the Project was calculated using the WACC as the discount rate, and was used to predict whether the Project will generate sufficient funds to cover all project-related costs, including loan interest and principal repayment.
3. Financial viability was examined by comparing the incremental costs and benefits of with- and without-investment scenarios. The main incremental benefit assumed was due to the decreased import of electricity, estimated at 650 gigawatt-hours (GWh), and consistent over the period of review from 2011 to 2030 (half year benefit in 2011). No incremental additional maintenance costs were considered compared to the existing transmission lines. After consultation with Azerenergy, an assumption of an annual incremental benefit of $100,000 in maintenance savings was added. As the useful life of the new transmission lines is expected to be 40 years, the residual value of the transmission lines has not been included in the analysis.
4. Tariffs are governed by regulations specific to the electricity industry and national monopolies. Historically, such tariffs have been based on a “cost-plus” system, meaning cost of service plus a margin, where costs are determined under the rules and regulations on accounting and reporting of Azerbaijan. In practice, tariff decisions are significantly affected by social and political considerations. Current levels allow Azerenergy to pass though the full cost recovery of the loan, depreciation, return on equity, operation and maintenance expenses, and working capital expenses.
1 ADB. 2005. Financial Management and Analysis of Projects. Manila. 2 The generation element of tariffs has been announced to be 4.2 c/kWh. The cost of $0.03636 is derived from actual costs generated divided by actual generation for the year. As tariffs include a 10% markup, the cost assumption is consistent with actual generation tariffs charged. 46 Appendix 10
C. Weighted Average Cost of Capital and Financial Internal Rate of Return
5. To compute the WACC, it is assumed that the financing sources would consist of Azerenergy’s equity contribution financed through retained earnings. The cost of Azerenergy’s equity is assumed at the domestic long-term savings rate of 10%. The other assumptions are a domestic inflation rate of 5%. As shown in Table A10.1, the WACC for the investment program during the Project is 2.45%.
Table A10.1: Weighted Average Cost of Capital (%)
Financing Component Item ADB loan Azerenergy Total Amount of project ($’000) 160,000.00 79,745.00 239,745.00 Weighting 67.00 33.00 100.00 Nominal cost (for calculation) 3.01 10.00 — Tax rate 22.00 22.00 — Tax-adjusted nominal cost 2.30 7.80 — Inflation rate — 5.00 — Real cost 2.35 2.67 — Minimum rate test (4%) 4.00 4.00 Weighted component of WACC 2.70 1.30 4.00 WACC in real cost 1.57 0.89 2.45 — = not applicable, WACC = weighted average cost of capital. Source: Asian Development Bank and Azerenergy estimates.
6. The FIRR is calculated at 11.89% for the Project. This rate compares favorably with the estimated WACC value of 2.45% or the minimum test rate of 4% set by ADB, substantiating the financial viability of the Project. In performing a sensitivity and risk analysis of the projected variables used in the base case, the consultants used the following scenarios: (i) 10-year stream of expected benefit instead of 20 years, (ii) increase the London interbank offered rate (LIBOR) up to 10%, (iii) increase in capital expenditure (CAPEX) of 10%, (iv) decrease in benefits of 10%, (v) decrease in benefits up to get NPV to zero, and (vi) increase in CAPEX to get NPV to zero.
7. Each of the alternative scenarios was assessed in terms of the projected incremental discounted cash flows arising out of the capital project. Using the WACC rate established for the base case, the NPV and FIRR were calculated.
8. The net cash flow was calculated using the general approach of the presentation of a cash flow statement, i.e., loan principal receipts, loan repayments, loan interest, and commitment fees have been included in the calculation. However, for the calculation of the NPV and FIRR, the free cash flow has been used. Free cash flow excludes all debt service receipts, repayments, interest, and commitment fees.
Appendix 10 47
9. The cost estimates include an 8% physical contingency against equipment and materials, and civil works. Price contingencies are calculated on the basis of an annual price increase to 5% (average inflation rate for calculation of price contingency) compared to the previous year, and 2.5% caused by the price increase during the current year related to the period of construction.
10. Table A10.2 presents the NPV and FIRR for each scenario and Table A10.3 shows a summary of the net cash flows.
Table A10.2: Net Present Value and Financial Internal Rate Return ($’000)
Item 2009 2010 2011 2012 2013 2014 2015 2020 2030 Profit and Loss Total Income 0 0 12,408 23,057 27,360 28,728 30,164 38,498 62,709 Maintenance Cost 0 0 53 110 116 122 128 163 265 Salary and Wages 0 0 (38) (81) (85) (89) (93) (119) (194) Contribution 0 0 12,422 26,086 27,391 28,760 30,198 38,542 62,780 Depreciation in Period 0 0 (2,665) (5,330) (5,330) (5,330) (5,330) (5,330) (5,330) Interest Pauments 0 0 (2,254) (4,861) (4,566) (4,272) (3,977) (2,504) 0 Commitment Fee (240) (120) (48) 0 0 0 0 0 0 Profit Before Tax (240) (120) 7,456 15,896 17,495 19,159 20,892 30,708 57,450 Profit Tax 53 26 (1,640) (3,497) (3,849) (4,215) (4,596) (6,756) (12,639) Profit after Tax (187) (94) 5,815 12,399 13,646 14,944 16,295 23,952 44,811
Cash Flow Contribution 0 0 12,422 26,086 27,391 28,760 30,198 38,542 62,780 Commitment Fee (240) (120) (48) 0 0 0 0 0 0 Loan Interest (751) (2,754) (4,507) (4,861) (4,566) (4,272) (3,977) (2,504) 0 Loan Principal 48,000 80,000 32,000 (9,412) (9,412) (9,412) (9,412) (9,412) 0 Profit Tax 53 26 (1,640) (3,497) (3,849) (4,215) (4,596) (6,756) (12,639) Capex (62,229) (103,715) (41,486) 0 0 0 0 0 0 Net Cash Flow after Tax (15,167) (26,563) (3,259) 8,317 9,564 10,862 12,213 19,870 50,141 Free Cash Flow - excluding Debt Service (62,176) (103,688) (30,704) 22,589 23,542 24,545 25,602 31,786 50,141 Net Cash Start of Period 0 (15,167) (41,730) (44,989) (36,672) (27,108) (16,246) 59,500.00 355,335.00 Net Cash End of Period (15,167) (41,730) (44,989) (36,672) (27,108) (16,246) (4,033) 355,335.00 405,476.00 DCF Analysis NPV @ real WACC of 2.52% 273,860 NPV @ ADB minimum WACC of 4.00% 198,044 ADB = Asian Development Bank; CAPEX = capital expenditure; DCF = discounted cash flow; NPV = net present value; WACC = weighted average cost of capital. Source: ADB estimates.
Table A10.3: Summary of Financial Analysis of Proposed Project ($’000) Base 10-Year LIBOR CAPEX Benefit Benefit –; CAPEX +; Indicators Case Stream 10% +10% less 10% FIRR+WACC FIRR=WACC Total Project Cost (incl. IDC, 212,967.00 212,967.00 226,197.00 234,261.00 212,967.00 212,967.00 458,454.00 without price contingency) Total Loan Amount 160,000.00 160,000.00 160,000.00 175,908.00 160,000.00 160,000.00 343,399.00 Discount rate (%) 4.00 4.00 7.05 4.00 4.00 4.00 4.00 NPV of Free Cash Flows at discount rate 198,044.00 (7,268.00) 103,425.00 180,600.00 160,871.00 0.00 0.00 Net Cash Flow to 2013 9,699.00 9,699.00 1,591.00 8,540.00 7,565.00 (54,061.00) (117,237.00) Net Cash Flow to 2020 19,944.00 19,944.00 15,530.00 18,938.00 16,941.00 (44,672).00 (96,513).00 Net Cash Flow to 2030 50,140.00 — 50,213.00 50,257.00 45,249.00 69,138.00 148,954.00
48 Appendix 10
Base 10-Year LIBOR CAPEX Benefit Benefit –; CAPEX +; Indicators Case Stream 10% +10% less 10% FIRR+WACC FIRR=WACC Internal Rate of Return (%) 11.69 3.32 12.41 10.58 10.46 4.00 4.00 ( ) = negative, – = no data, CAPEX = capital expenditure, FIRR = financial internal rate of return, LIBOR = London interbank offered rate, WACC = weighted average cost of capital. Source:
11. In all scenarios, except when the benefit stream is 10 years instead of 20 years (Table A10.3), the FIRR is greater than the WACC and the NPV is positive. In the most negative scenario (10-year benefit stream), the NPV is negative and the FIRR (3.32%) is less than the WACC test rate of 4% but above the actual projected WACC of 2.45%. The new transmission lines are expected to have a useful life of 40 years, so the benefit stream will most probably be more than 10 years. Therefore, aside from the most negative scenario of an expected benefit stream of 10 years instead of 20 years, the Project is financially viable and Azerenergy will be able to generate sufficient cash flow to cover the projected costs (including loan interest and principal repayment requirements).
12. The sensitivity analysis includes two more scenarios to investigate at what level (i) the expected benefits should be decreased, or (ii) the CAPEX should be increased—to get the NPV to zero. The calculations show that the NPV will be zero if (i) the benefits reduce by 54%, or (ii) the CAPEX increases more than two times.
Appendix 11 49
FINANCIAL PERFORMANCE AND PROJECTIONS OF AZERENERGY
1. The summary financial statements of Azerenergy are in Tables A11.1–A11.5. Figures for 2006–2007 (local statements) and the audited international financial reporting standards (IFRS) financial statements for 2005 (with comparative data for 2004) prepared by Price Waterhouse Coopers were reviewed. Figures for 2008–2030 are projections, based on notes and assumptions described below. Detailed financial projections are in Supplementary Appendix D.
A. Past Financial Performance 2. Azerenergy experienced growth in total revenue in 2007—AZN934 million ($1.146 billion), a 222% increase over 2006—despite the fact that energy demand did not increase correspondingly. The main reason for this growth was the increase in tariffs. The company’s operating results also improved during 2007 because of the overall increase in tariffs. The cost of sales amounted to AZN695 million ($853 million) in 2007, or 74% of total revenue, a significant improvement over 2006 where it was 185% of total turnover. The cost of fuel continued to be the largest component of the cost of sales—in 2005, it accounted for 73% of the total (74% in 2004). The cost of imported energy was AZN27 million ($32 million) in 2007, falling from AZN38 million ($46 million) in 2006. The ratio of total equity and liabilities improved slightly from 22% in 2006 to 26% in 2007. The total liabilities to equity ratio also improved from 3.45 in 2006 to 2.84 in 2007. The improvement in Azerenergy’s gearing ratio shows that the company is able to earn enough capital using long-term borrowings for investment in the industry. In spite of a significant improvement in the debt service coverage ratio (up to 0.50 times in 2007 from 0.05 times in 2006), this performance indicator is still low. However, from 2007, the Government has been making efforts to increase tariffs to cover costs plus a 10% return. In 2007, tariffs were increased to a point where government subsidies were no longer needed. Detailed financial analysis is in Supplementary Appendix E.
B. Projections 1. Inflation and Exchange Rate 3. An average annual inflation rate of 5% is projected during the entire forecast period. This is similar to the parameters used for financial analysis of the proposed Project. All data was prepared in Azerbaijan manats (AZN), so the amounts of capital expenditures forecast in other currencies have been exchanged to AZN at the rate of AZN0.85 = $1.00. To simplify the calculations, the same exchange rate was used for the whole forecast period, so exchange rate gain or loss was ignored.
2. Income Statement 4. Sales. Azerenergy provided the energy balance and demand forecast, based on actual data for 2007. Although actual electricity production and demand decreased in 2007 compared to 2006, Azerenergy management assures that this is a temporary decrease caused by the significant tariff increase and the introduction of a metering program in 2007. Therefore, it is assumed that gross electricity production will increase by 5% per year up to 2021, then by 3% per year up to 2025, and 2% thereafter. Imports of electricity will continue at 650 gigawatt-hours (GWh) per year until the transmission line is operational from the middle of 2010 (it is assumed that 300 GWh will be imported in 2011).
5. Tariffs. In principle, tariffs increase with gross electricity production (5% per year up to 2021, 3% up to 2025, 2% thereafter) but they are also adjusted to meet the covenants of at least 1.5 times debt service coverage ratio (free cash flow over debt service for the year) and a
50 Appendix 11 debt to liabilities and equity ratio of 70%. Therefore, there is a one-off increase of 30% in 2012. Tariff levels are shown in Table A11.1.
Table A11.1: Tariff Levels
Actual Projected Indicator 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 AZN/kWh 0.017 0.048 0.051 0.053 0.056 0.059 0.076 0.080 0.084 0.088 Increase (%) 170 5 5 5 5 30 5 5 5 DSCR (times) 1.530 1.960 1.830 2.420 Note: Principle repayment starts in 2012 from where DSCR calculation starts. DSCR = debt service coverage ratio. Source: ADB estimates.
6. Operating Expenses and Taxation. The cost of fuel, staff, and other operating costs are projected on the basis of actual 2007 data, adjusted on annual growth of electricity production which is assumed at an average growth of 3% per year from 2008 to 2020, 4% during 2021, and 5% from 2025 onward. Average growth in expenses is less than the total average inflation rate (5%) in the early years because of the effect of implementation of various cost control measures including the introduction of a financial management information system within a separate institutional strengthening program. Taxes are assumed to be the same as for 2007 (profit tax 22%, VAT 18%).
3. Balance Sheet and Cash Flow 7. Fixed Assets Capital Expenditures and Debt. Capital expenditures include proposed Asian Development Bank (ADB) project expenditures during 2009–2011; and other current and future projects financed by the European Bank for Reconstruction and Development (EBRD), World Bank, Japan Bank for International Cooperation (JBIC), Kreditanstalt für Wiederaufbau (KfW), and others. It is assumed that Azerenergy will increase its own contribution to financing capital expenditures starting from 2016. Total capital expenditures will gradually decrease from AZN658 million in 2009 to AZN200 million in 2013. A significant increase in capital expenditures is assumed from AZN350 million in 2015 to AZN1.70 billion in 2030 due to the expanding network and growing economy. It is expected that with the willingness of increasing tariffs to cover all costs, Azerenergy will generate enough cash for capital investments after 2016 and will finance the majority of capital expenditures itself. It was assumed that a significant part of capital expenditures after 2020 will be spent on replacement of old and out-of-date plants and equipment.
Appendix 11 51
Figure A11: Azerenergy Organizational Chart
Head Office Azerenergy
Energy Entities under Direct Decentralized Profit Nachchivan Management Financial Control Tax Payers Autonomy Network Agency
Generation Transmission Generation and Transmission Distribution Supporting Entities Companies
Azerbaijan Thermal Plant Baku Network Sheki Power Junction Genje Distribution Research Centre
Ali-Bairami Thermal Plant Absheron Network Khachmaz Power Junction Mingechevir Distribution Construction Company
Shimal Thermal Plant Sumgait Network Astara Power Junction Imishli Distribution Repair and Construction
Sumgait Thermal Plant Agstafa Network Ali-Bairamli Distribution Security Service
Baku Heat Power Center Genje Network Kurdemir Distribution Supply Department
Baku Thermal Power Plant Mingechevir Network Shemkir Distribution Energy Service
Mingechevir Hydro PS Ali-Bairamli Network Sheki Distribution Energy Research Institute
Shemkir Hydro PS Imishli Network Lenkaran Distribution
Agsu Network
Source: Azerenergy Open Joint-Stock Company.
52 Appendix 11
Table A11.2: Summary Income Statement (AZN’000)
Item 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2030 Operating Data Energy Sales (GWh 22,278 19,319 20,452 21,444 22,485 23,795 24,687 25,921 27,216 28,575 30,003 31,502 33,076 34,728 36,464 47,570 Increase in Energy Sales (%) (13%)5%5%6%4%5%5%5%5%5%5%5%5%5%2% Average tariffs (AZN/kWh) 0.018 0.048 0.051 0.053 0.056 0.059 0.076 0.080 0.084 0.088 0.092 0.097 0.102 0.107 0.113 0.147 Increase in Tariff (%) 170% 5% 5% 5% 5% 30% 5% 5% 5% 5% 5% 5% 5% 2%
Revenue 421,402 933,690 1,056,675 1,148,910 1,250,234 1,372,332 1,788,881 1,956,275 2,140,505 2,343,291 2,566,528 2,812,304 3,082,924 3,380,926 3,709,110 6,204,658 Electricity 326,190 764,933 878,779 967,456 1,065,151 1,183,547 1,596,320 1,759,863 1,940,166 2,138,945 2,358,094 2,599,702 2,866,069 3,159,735 3,483,495 5,929,635 Other sales 95,212 168,757 177,896 181,454 185,083 188,785 192,560 196,412 200,340 204,347 208,433 212,602 216,854 221,191 225,615 275,024
Cost of sales 780,670 695,138 753,038 827,842 899,985 973,670 1,049,327 1,124,762 1,205,097 1,291,677 1,388,162 1,496,837 1,614,800 1,743,669 1,885,778 3,909,604 Fuel expenses 574,902 505,112 547,685 593,771 643,656 697,651 787,761 851,963 921,398 996,492 1,077,706 1,165,539 1,260,531 1,363,264 1,474,370 3,015,885 Imported electricity 37,64027,31728,13728,98129,85030,7460000000000 Staff costs 40,174 44,349 47,963 51,872 56,100 60,672 65,617 70,965 76,748 83,003 89,768 97,084 104,997 113,554 122,809 215,348 Social charge to salary and wages 9,326 12,183 13,176 14,250 15,411 16,667 18,025 19,495 21,083 22,802 24,660 26,670 28,843 31,194 33,736 59,158 Other costs 82,020 50,651 54,779 59,244 64,072 69,294 74,941 81,049 87,654 94,798 102,524 110,880 119,917 129,690 140,260 245,948 Depreciation 36,608 55,526 61,297 79,725 90,896 98,640 102,983 101,290 98,213 94,582 93,503 96,664 100,512 105,967 114,603 373,266
Gross profit (loss) (359,268) 238,552 303,638 321,067 350,249 398,662 739,553 831,513 935,408 1,051,614 1,178,366 1,315,467 1,468,124 1,637,257 1,823,333 2,295,054
Other operating income 6,6003,21000000000000000
Other operating expenses 540 98,456 106,480 115,158 124,544 134,694 145,672 157,544 170,384 184,270 199,288 215,530 233,096 252,093 272,638 478,077
Profit (loss) from operations (353,208) 143,306 197,158 205,909 225,706 263,968 593,882 673,970 765,025 867,344 979,078 1,099,937 1,235,028 1,385,164 1,550,694 1,816,977
Net finance expense (income) 4,538 47,160 30,850 34,573 36,701 34,543 31,194 28,407 26,384 24,895 20,544 14,908 11,970 10,380 8,701 4,817
Profit (loss) before tax (357,746) 96,146 166,307 171,336 189,005 229,426 562,687 645,562 738,641 842,448 958,534 1,085,028 1,223,058 1,374,784 1,541,993 1,812,159
Profits tax expense 0 21,152 36,588 37,694 41,581 50,474 123,791 142,024 162,501 185,339 210,877 238,706 269,073 302,453 339,239 398,675
Net profit (loss) for the year (357,746) 74,994 129,720 133,642 147,424 178,952 438,896 503,539 576,140 657,110 747,656 846,322 953,986 1,072,332 1,202,755 1,413,484
( ) = negative. Source: Azerenergy Open Joint-Stock Company.
Appendix 11 53
Table A11.3: Summary Balance Sheet and Cash Flow (AZN’000)
Items 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2030 Budgeted ASSETS Noncurrent Assets Fixed Assets in service, net 838,818 866,124 1,320,098 1,646,482 1,708,030 1,844,150 1,723,558 1,555,225 1,370,194 1,180,885 1,128,176 1,148,751 1,123,410 1,214,995 1,334,657 5,784,660 Fixed Assets in service 1,790,069 2,196,178 2,348,621 2,583,382 2,565,773 2,498,729 2,411,912 2,317,185 2,357,979 2,475,217 2,550,388 2,747,940 2,982,205 9,801,394 Accumulated Depriciation (469,970) (549,695) (640,591) (739,231) (842,214) (943,504) (1,041,717) (1,136,299) (1,229,802) (1,326,466) (1,426,978) (1,532,945) (1,647,548) (4,016,734) Assets in Construction 459,086 525,453 410,181 461,661 461,385 220,652 188,261 155,304 142,122 136,849 146,055 178,816 203,645 256,093 271,828 702,639 ADB project 057,588159,75600000000000 Other projects 410,181 404,072 301,629 220,652 188,261 155,304 142,122 136,849 146,055 178,816 203,645 256,093 271,828 702,639 Long-term receivables 1,063,157 1,564,633 1,564,634 1,564,634 1,564,634 1,564,634 1,564,634 1,564,634 1,564,634 1,564,634 1,408,171 1,251,707 1,095,244 938,780 782,317 0 Total noncurrent assets 2,361,061 2,956,210 3,294,914 3,672,777 3,734,049 3,629,436 3,476,453 3,275,163 3,076,950 2,882,368 2,682,401 2,579,274 2,422,299 2,409,869 2,388,802 6,487,299 Current Assets Cash and Cash equivalents 30,888 50,952 1,830 81,198 61,706 52,206 267,356 594,736 859,870 1,267,732 1,554,351 1,882,658 2,415,838 2,988,102 3,529,257 7,473,226 Trade receivables, net 239,471 352,428 399,826 351,108 273,958 189,331 230,021 253,843 194,575 207,176 226,498 248,151 272,020 298,306 327,254 549,510 Actual Trade receivables 239,471 352,428 399,826 351,108 273,958 189,331 230,021 253,843 194,575 207,176 226,498 248,151 272,020 298,306 327,254 549,510 Inventories 72,057 95,784 62,275 67,351 36,420 39,388 42,598 46,070 49,825 53,885 58,277 63,027 68,163 73,719 80,501 60,318 Total current assets 342,416 499,164 463,931 499,656 372,084 280,925 539,975 894,648 1,104,269 1,528,794 1,839,126 2,193,836 2,756,022 3,360,126 3,937,011 8,083,054
Total Assets 2,703,477 3,455,374 3,758,845 4,172,433 4,106,132 3,910,361 4,016,428 4,169,811 4,181,219 4,411,162 4,521,527 4,773,110 5,178,320 5,769,995 6,325,814 14,570,353
EQUITY AND LIABILITY Equity Capital 607,994 899,980 999,980 1,136,768 1,240,936 1,307,763 1,357,763 1,357,763 1,357,763 1,357,763 1,357,763 1,357,763 1,357,763 1,357,763 1,357,763 1,357,763 Retained Earnings 29,720 (36,638) (189,215) (310,263) (171,367) 32,172 308,312 665,421 1,113,078 1,659,400 2,213,385 2,885,717 3,688,472 12,369,016 Total equity 607,994 899,980 1,029,700 1,100,130 1,051,721 997,500 1,186,396 1,389,935 1,666,075 2,023,185 2,470,841 3,017,163 3,571,149 4,243,480 5,046,235 13,726,780 Long-term liabilities Long-term loans 787,117 1,056,328 797,601 935,121 930,824 843,417 760,792 700,554 655,988 471,994 335,997 263,999 223,999 145,600 116,480 171,429 ADB loan 0 40,800 108,800 128,000 120,000 112,000 104,000 96,000 88,000 80,000 72,000 64,000 56,000 0 Other loans 797,601 894,321 822,024 715,417 640,792 588,554 551,988 375,994 247,997 183,999 151,999 81,600 60,480 171,429 Long-term payables 400,697 414,447 414,448 414,448 414,448 414,448 414,448 414,448 414,448 414,448 386,818 359,188 331,558 303,929 276,299 0 Total long-term liabilities 1,187,814 1,470,775 1,212,049 1,349,569 1,345,272 1,257,865 1,175,240 1,115,002 1,070,436 886,442 722,815 623,187 555,558 449,528 392,779 171,429 Current Liabilities Trade and other payables 508,862 526,162 746,317 910,967 928,599 911,612 924,130 958,260 756,676 678,504 663,881 565,998 536,133 541,830 419,030 566,059 Trade creditors 508,862 526,162 746,317 910,967 928,599 911,612 924,130 958,260 756,676 678,504 663,881 565,998 536,133 541,830 419,030 566,059 Payable to the State 124,724 186,205 56,697 56,234 55,991 56,524 75,784 74,123 71,213 66,784 60,557 52,144 57,680 63,771 70,481 106,086 Short-term borrowings 274,083 372,252 372,253 372,253 372,253 372,253 372,253 372,253 372,253 372,253 347,436 322,619 297,802 272,986 248,169 0 Current portion of long-term debt 341,829 383,280 352,296 314,607 282,625 260,238 244,566 383,994 255,997 191,999 159,999 198,399 149,120 0 Total current liabilities 907,669 1,084,619 1,517,097 1,722,735 1,709,139 1,654,996 1,654,792 1,664,874 1,444,708 1,501,535 1,327,871 1,132,761 1,051,614 1,076,987 886,800 672,145
Total liabilities andy equit 2,703,477 3,455,374 3,758,845 4,172,433 4,106,132 3,910,361 4,016,428 4,169,811 4,181,219 4,411,162 4,521,527 4,773,110 5,178,320 5,769,995 6,325,814 14,570,353 ( ) = negative. Source: Azerenergy Open Joint-Stock Company.
54 Appendix 11
Table A11.4: Summary Cash Flow (AZN’000)
Items 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2030 Cash Flow from Operating Activities Cash receipts from customers (incl VAT) 180,318 828,143 1,199,479 1,404,432 1,552,427 1,703,978 2,070,189 2,284,583 2,585,064 2,752,482 3,165,645 3,453,328 3,770,444 4,119,670 4,504,265 7,300,632 Cash paid to suppliers and employees (incl VAT) (141,088) (546,711) (544,556) (703,701) (885,070) (1,029,679) (1,082,708) (1,150,356) (1,482,607) (1,463,598) (1,537,778) (1,743,153) (1,807,202) (1,914,470) (2,198,212) (4,002,114) Cash generated from operations 39,230 281,432 654,922 700,731 667,357 674,300 987,481 1,134,227 1,102,457 1,288,884 1,627,867 1,710,176 1,963,242 2,205,201 2,306,053 3,298,518 Interest paid (8,329) (25,903) (30,850) (34,573) (36,701) (34,543) (31,194) (28,407) (26,384) (24,895) (20,544) (14,908) (11,970) (10,380) (8,701) (4,817) Income and other taxes paid (20,411) (178,247) (356,297) (244,960) (266,867) (296,961) (426,529) (495,814) (550,702) (611,560) (679,080) (753,333) (818,464) (904,928) (1,000,168) (1,513,272) Cash generated from operating activities 10,490 77,282 267,775 421,197 363,789 342,796 529,757 610,005 525,371 652,429 928,243 941,934 1,132,808 1,289,892 1,297,184 1,780,429
Cash Flow from Investing Activities Capital expenditures (324,075) (447,487) (500,000) (657,588) (452,167) (294,027) (250,000) (200,000) (200,000) (200,000) (350,000) (450,000) (500,000) (650,000) (650,000) (1,700,000) ADB project 0 (57,588) (102,167) (44,027) 0 0 0 0000000 Other projects (500,000) (600,000) (350,000) (250,000) (250,000) (200,000) (200,000) (200,000) (350,000) (450,000) (500,000) (650,000) (650,000) (1,700,000) Investment from government 309,952 90,070 100,000 136,788 104,167 66,827 50,000 0 0 0000000 Cash Flow from Investing Activities (14,123) (357,417) (400,000) (520,800) (348,000) (227,200) (200,000) (200,000) (200,000) (200,000) (350,000) (450,000) (500,000) (650,000) (650,000) (1,700,000)
Cash Flow from Financing Activities Proceeds from long-term loans 228,172 422,086 400,000 520,800 348,000 227,200 200,000 200,000 200,000 200,000 120,000 120,000 120,000 120,000 120,000 120,000 ADB loan 040,80068,00027,2000000000000 Other loans 400,000 480,000 280,000 200,000 200,000 200,000 200,000 200,000 120,000 120,000 120,000 120,000 120,000 120,000 Principal repayments (206,592) (121,888) (316,898) (341,829) (383,280) (352,296) (314,607) (282,625) (260,238) (244,566) (383,994) (255,997) (191,999) (159,999) (198,399) (120,000) ADB loan 0 0 0 0 (8,000) (8,000) (8,000) (8,000) (8,000) (8,000) (8,000) (8,000) (8,000) 0 Other loans (316,898) (341,829) (383,280) (352,296) (306,607) (274,625) (252,238) (236,566) (375,994) (247,997) (183,999) (151,999) (190,399) (120,000) Increase in long-term payables 1 0 0 00000(27,630) (27,630) (27,630) (27,630) (27,630) (27,630) Cash Flow from Financing Activities 21,580 300,198 83,103 178,971 (35,280) (125,096) (114,607) (82,625) (60,238) (44,566) (291,624) (163,627) (99,628) (67,629) (106,029) (27,630)
Net cash flow during the yea
r 17,947 20,063 (49,122) 79,368 (19,491) (9,500) 215,150 327,380 265,134 407,863 286,619 328,307 533,180 572,263 541,155 52,799
Cash and Cash Equivalents At beginning of year 12,943 30,890 50,953 1,831 81,199 61,707 52,207 267,357 594,737 859,871 1,267,733 1,554,352 1,882,659 2,415,839 2,988,103 7,420,429 At end of year 30,890 50,953 1,831 81,199 61,707 52,207 267,357 594,737 859,871 1,267,733 1,554,352 1,882,659 2,415,839 2,988,103 3,529,258 7,473,227 ( ) = negative. Source: Azerenergy Open Joint-Stock Company.
Appendix 11 55
Table A11.5: Summary Key Performance Indicators (%)
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 A. Operating Indicators 1. Rate of Return on Net Fixed Assets in Service 1718141315334152688597109
2. Self-Financing Ratio 17 54 64 80 117 212 305 263 326 265 209 227
3. Operating Ratio 262928282941434445464748
5. Return on Average Total Assets 4444512131416171919
6. Return on capital employed 68891124252627272625
7. % growth in Revenues 119 13 9 9 10 30 9 9 9 10 10 10
8. Gross profit % 262928282941434445464748
9. Net profit as a % of operating revenue 8 12 12 12 13 25 26 27 28 29 30 31
10. Operating revenue as a % of total assets 27 28 28 30 35 45 47 51 53 57 59 60
11. Return on Equity 81312141837363232302827
B. Capital Adequacy Indicators 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 12. Debt Service Coverage Ratio (x) 0.52 0.77 1.12 0.87 0.89 1.53 1.96 1.83 2.42 2.29 3.48 5.55
13. Debt to Equity Ratio (x) 2.84 2.65 2.792.902.922.392.001.511.180.830.580.45
14. Long-term Debt to Total Equity Ratio 163 118 123 128 126 99 80 64 44 29 21 16
15. Long-term Debt to Total Capital 625455565650453930231713
16. Equity Ratio 262726262630334046556369
C. Liquidity Indicators
17. Current Ratio 0.460.310.290.220.170.330.540.761.021.391.942.62
18. Quick Ratio 0.370.260.250.200.150.300.510.730.981.341.882.56
19. Days in Receivables 113.72 128.14 117.65 89.99 60.77 42.20 44.52 37.71 30.86 30.42 30.38 30.37
20. Accounts Receivable Turnover 3.17 2.81 3.06 4.00 5.92 8.53 8.09 9.55 11.67 11.84 11.85 11.85
21. Days in Accounts Payable 268.01 304.16 360.35 367.92 340.20 314.90 301.25 256.15 200.00 174.06 147.90 122.85
22. Accounts Payable Turnover 1.34 1.18 1.00 0.98 1.06 1.14 1.20 1.41 1.80 2.07 2.43 2.93 Source: Azerenergy Open Joint-Stock Company. 56 Appendix 12
FINANCIAL MANAGEMENT ASSESSMENT OF AZERENERGY
A. Review of Current Financial Management Practices
1. Current financial accounting, planning, and reporting procedures at Azerenergy originate in the old Soviet system and have not changed much during the past several years. A general review of existing policies and procedures is presented in the following subsections, followed by recommendations for improvements to financial management and reporting practices.
B. Existing Accounting Policies
2. Major accounting transactions are recognized and recorded by Azerenergy following the accrual basis of accounting (e.g., the accounting of revenue, cost of sales, and the resulting receivables and payables). The adoption of the accrual basis of accounting is very important in the process of bringing local accounting procedures in compliance with international financial reporting standards (IFRS). However, some expenses (such as bank charges, interest expense, tax expense, and some other expenses) might be recognized by Azerenergy only when supporting documents are received, but not when the expense is incurred as required under the IFRS. Other departures from IFRS are noted in the following paragraphs.
3. Property, plant, and equipment is stated at cost less accumulated depreciation, except for items that were commissioned before 1996. Items acquired before 1996 are carried at the statutory indexed cost. According to existing accounting rules in Azerbaijan, fixed assets are those that are used for a period of more than 1 year and from which the company derives an economic benefit from their use. Depreciation of property, plant, and equipment is accrued monthly using the reducing balance method, by rates prescribed in tax legislation.
4. Property, plant, and equipment have been revalued (indexed) twice, in 1993 and 1996, to take account of the effects of inflation during these years. The indices used were prescribed in guidelines issued by the cabinet of ministers. Inventories are recorded at cost. The cost of inventory is determined on the weighted average basis. The cost of finished goods and work in progress comprises raw material, direct labor, and other direct costs.
5. A physical inventory of fixed assets and stocks is performed each year. A special commission (including fixed assets and materials accountants) is established to conduct the stocktaking and to prepare a report on the results of the inventory. A comparison of the fixed assets and stocks physical count and accounting data is presented in the commission’s report. This process is concerned only with the physical verification of the assets, not with their value.
6. The billing and cash collection system for generation and transmission is centralized and controlled by the management of Azerenergy. Distribution entities are decentralized, and generate their own profit and produce their own income statement.
7. Trade and other receivables are accounted on the accrual basis (in accordance with bills sent to customers). Revenue and resulting receivables, in accordance with the statutory local financial statements, contain a significant element of irrecoverable debts. The creation of provision for doubtful and bad debts is prohibited in accordance with local tax legislation. Azerenergy has the right to write off to bad debts expense those receivables that have not been collected during the past 3 years, but the amount of the write-offs is very limited and must be agreed with state authorities such as tax inspectors. The company does not attempt to discount the long-term part of trade receivables that was deferred in accordance with government Appendix 12 57 decrees. The company does not separate the long-term part of receivables in the local balance sheet, but shows the total amount as current receivables.
8. Trade and other payables are accrued when the counterparty performed its obligations under the contract and are carried at cost. Accounts payables comprise trade accounts payable, payables to employees for salary and wages, tax payable, payable to non-budget social funds, and payables to other creditors. The company does not discount the long-term part of trade payables and deferred tax payables in accordance with government decrees. The company does not separate the long-term part of payables in the local balance sheet but shows the total amount as current payables.
9. The authorized capital of Azerenergy has been created on the basis of certificates entitling the founder to the assets of the company. The sole founder of the company is the Government of Azerbaijan. From time to time, the authorized capital might be changed (adjusted) in accordance with changes in legislation or reregistration of the company’s legal position. No shares have been issued.
10. Starting in 2006, profit tax is calculated on the basis of 22% of taxable profit. Prior to that, the profit tax rate was 24%. Profit after taxation is distributed to the accumulation and consumption (social) funds. These funds are usually used for the reimbursement of expenses which, in accordance with local tax legislation, are not allowed to be included in the income statement as expenses. Examples include bonuses, additional payments, material aids to employees, provision for cultural and welfare facilities, charity, and other expenses.
11. In summary, the local accounting and financial reporting procedures followed by Azerenergy and its subsidiaries in general are in line with the norms and regulations set out in local tax legislation.
C. Internal and External Audit
12. Azerenergy does not have an internal audit department. However, company management has made the decision to create an internal audit function and preparatory work is under way. It is assumed that the internal audit department will include specialists in energy, marketing, economics, finance, and accounting. The objectives of the new function should be the control over the operating, marketing, and financial management activities of the company; and provision of recommendations for their future developments. Nevertheless, the structure and job descriptions for the staff of the internal audit department have not yet been developed.
13. The financial statements of Azerenergy have been audited in accordance with international auditing standards since 1998 because of lenders’ requirements (European Bank for Reconstruction and Development, World Bank, Islamic Development Bank). The international audit of Azerenergy’s 2005 IFRS financial statements were completed in June 2007. In mid-2007, the company decided to publicly tender the IFRS audit for 2006. As a result of the tender, Deloitte & Touche started the audit of the 2006 accounts in October 2007 and the work has not yet finished.
D. Information Systems
14. The level of computerization of accounting functions in the head office of Azerenergy and its subsidiaries is varied and ranges from the manual processing of all transactions in some subsidiaries to the implementation of a computerized system (“1C” accounting software). On the
58 Appendix 12 whole, automation of accounting and reporting procedures at Azerenergy is “in its infancy”; substantial investments are required for hardware, software, and computer literacy training programs.
15. As a result, any consolidated or segment reporting is difficult. This has contributed to the negative audit opinions the company has received so far. Therefore, implementation of an integrated financial management information system (FMIS) is necessary for Azerenergy. Given the company’s size, top of the range systems would be required (mid-range systems are normally recommended for companies with up to 200 system users). Assistance is required with system specification, tendering, and implementation management. The company recognizes the need for introduction of an integrated FMIS but the poor financial situation has not allowed such investment so far.
16. Azerenergy already benefits from the following infrastructure: (i) local area network in head office, (ii) computers in head office, (iii) dial-up connection links to most accounting units, and (iv) limited computers in the accounting units.
17. While this infrastructure is adequate to support operation of a modern FMIS, the company will continue to experience problems with effective financial management and audit requirements. When requirements for a new FMIS are defined, they should take into account the need for additional infrastructure to support system operation.
E. Divergence from IFRS
18. A review of local accounting procedures and statutory financial statements and their comparison with the audited IFRS financial statements for 2005 prepared by Price Waterhouse Coopers revealed a number of divergences from IFRS. Several adjustments were required to restate local financial statements in line with the requirements of IFRS.
19. The major adjustments include the following: (i) Eliminate all intercompany balances between head office of Azerenergy and its subsidiaries at the consolidation level, and present the net value of accounts receivable and accounts payable in the consolidated balance sheet. (ii) Calculate and reflect in the accounts provisions for bad and doubtful debts for trade and other receivables. (iii) Trade and other accounts receivable and accounts payable should be carried at amortized cost using the effective interest method. (iv) Recognize the long-term part of accounts receivable and accounts payable, and present in an appropriate manner in the balance sheet. (v) Recognize the current part of long-term borrowings, and present in an appropriate manner in the balance sheet. (vi) Transfer the net book value of low-value items in use from the balance sheet to the income statement as expenses.
20. Fair valuation of fixed and other assets is always a difficult issue in the transition of accounting under local standards and regulations to those required under IFRS. While fixed assets in the initial IFRS balance sheet of Azerenergy may be brought in at deemed cost, provided that previous revaluations were based on approved indices, the adoption of a
Appendix 12 59 revaluation measurement model under International Accounting Standards 16 requires periodic revaluation of assets in accordance with professionally appraised market or replacement cost values as well as ongoing verification of the accuracy of such valuations through the application of tests for impairment. Alternatively, the adoption of the historical cost model under International Accounting Standards 16 removes entirely the scope for revaluation, which appears to contradict the asset measurement policy maintained by Azerenergy to date: (i) Transfer to retained profits appropriations (balance sheet) from profit )income statement) that have been made to the accumulation, consumption, and social funds; and
(ii) Transfer current expenses recorded in the fund accounts to the income statement (e.g., staff costs, general and administrative costs, other costs).
21. Occasionally, minor adjustments are necessary to the local financial statements as a result of human error. It is anticipated that local accountants will themselves correct such clerical errors in future in response to possible auditors’ or consultants’ recommendations.
60 Appendix 13
SUMMARY POVERTY REDUCTION AND SOCIAL STRATEGY
Country/Project Title: Azerbaijan: Power Transmission Enhancement Project
Lending/Financing Department/ Central and West Asia Department Project Modality: Division: Infrastructure Division
I. POVERTY ANALYSIS AND STRATEGY A. Linkages to the National Poverty Reduction Strategy and Country Partnership Strategy
1. The country’s poverty incidence has been reduced from 47% in 2002 to 24% in 2006. This is partly the result of consistently double-digit gross domestic product growth from 2003 to 2007, which averaged 21.8% per year. This growth owes much to its expanding oil industry and the rising oil price in the world market. The interim operational strategy, which guided Asian Development Bank (ADB) investment in the country since it became a member in 1999, identified development outside the oil sector as one area of ADB operations so that other sectors would grow as well. The country strategy and program (CSP)a considers the country’s development needs as still tremendous. However, the 2005 ADB sector review mission identified renewable energy and gas supply in regional towns as investment niches. The CSP nonetheless identified deteriorating physical infrastructure and its need for rehabilitation. The state program on poverty reduction and economic development (2003–2005),b which is currently being updated, identified power lines that have to be improved as one action to reduce poverty. B. Poverty Analysis Targeting Classification: GI 1. Key Issues
The Project intends to increase the efficiency of power transmission from Mingechevir hydropower plant to Baku, the country’s industrial center. It is not a core poverty reduction project but is expected to address the interim operation strategy to develop the non-oil sectors of the economy to attain more balanced and sustainable growth. One constraint of the improvement of the country’s power sector is the aging facilities, including power lines. The Project will replace the 50-year old Mingechevir–Xirlan power line. The greater efficiency in power transmission will contribute to the improvement of power quality and availability in Baku. The capital city harbored a quarter of the country’s poor in 2002, and this may have not changed much at present.
The contribution of the Project, in providing more reliable and stable supply of electricity, will benefit both industrial and domestic users. It can enhance the employment capacity of industrial users and has multiple poverty impacts on domestic users. It is well established that electricity supply can encourage home businesses to flourish as lights extend available time, and access to information and communication improves. The quality of water service, health care, and schools improves; and becomes more available as electricity-driven devices are put to use. The greater and wider availability of public and private services saves time that can be diverted to other activities and further improves production. Wider use of electricity for lighting and cooking can spare wood fuels, which reduces forest use and improves indoor air quality. Electricity also has an enabling effect on women. It enhances their income generation capacity, physical mobility, ability to organize work based on convenience, knowledge on gender issues, and decision-making power.
2. Design Features. The Project is designed to avoid land acquisition and resettlement impacts. Land acquisition is avoided by using the existing corridor and situating new towers on the same sites as old ones. Resettlement impacts are avoided by scheduling the civil works during the 8-month fallow period, dismantling the old towers and installing the new ones piece by piece, and use of poles instead of towers in sites where houses are close by.
C. Poverty Impact Analysis for Policy-Based Lending 1. Discuss the impact channels of the policy reform(s) (direct and indirect, short and medium term) to the country and major groups affected. Not Applicable
2. Discuss the impact of the policy reform(s) on vulnerable groups and ways to address it/them (refer to social analysis). Not Applicable
3. Discuss how the policy reform(s) contribute(s) to poverty reduction, pro-poor growth, and the MDGs. Not Applicable
a ADB. 2006. Country Strategy and Program Update (2006): Azerbaijan. Manila. b Cabinet of Ministers. 2005. State Program for Development of Fuel and Energy Sector in Azerbaijan (2005–2015). Baku. Appendix 13 61
II. SOCIAL ANALYSIS AND STRATEGY A. Findings of Social Analysis
1. The Project has no land acquisition and resettlement impacts. If some crops are affected during the civil works, the owner will be compensated with an amount equivalent to 1 year’s production.
2. The main beneficiaries of the Project are industries in Baku. The improvement of the quality and availability of power supply are bound to enhance their production and employment-generating capacity.
3. The improvement of employment will benefit the urban poor.
4. Domestic users will also benefit from the improved quality and availability of power supply by encouraging home business—extending time for work and recreation, and enhancing social services among others.
5. The improved quality and availability of electricity will increase women’s access to information and technology; and increase their income generation capacity, physical mobility, ability to organize work based on convenience, knowledge on gender issues, and decision making power.
6. No indigenous peoples groups will be affected.
B. Consultation and Participation 1. Provide a summary of the consultation and participation process during the project preparation.
There were meetings with local officials and representatives of nongovernment organizations, youth groups, and media on 11 and 12 April in Mingechevir and Agsu to inform them about the Project and draw out their concerns. About 18 persons attended each meeting. About six meetings were held with people cultivating under the existing lines to elicit their concerns over the Project and inform them of the design measures to be taken to avoid any adverse impacts. In these meetings, they were also informed of the plan to compensate for any destroyed crops with an amount equivalent to 1 year’s production. Their recommendations to further avoid any potential impacts were also solicited.
2. What level of consultation and participation (C&P) is envisaged during the project implementation and monitoring? █ Information sharing █ Consultation Collaborative decision making Empowerment
3. Was a C&P plan prepared? Yes █ No If a C&P plan was prepared, describe key features and resources provided to implement the plan (including budget, consultant input, etc.). If no, explain why. Because of the minimal adverse social impact expected if any, a C&P plan was deemed unnecessary.
C. Gender and Development 1. Key Issues.
The Project is expected to benefit women in various aspects. Like any other project that increases the quality and availability of power supply, it is expected to enhance their income-generation capacity, physical mobility, ability to organize work based on convenience, knowledge on gender issues, and decision making power.
2. Key Actions. Measures included in the design to promote gender equality and women’s empowerment—access to and use of relevant services, resources, assets, or opportunities and participation in decision-making process: Gender plan Other actions/measures █ No action/measure
Summarize key design features of the gender plan or other gender-related actions/measures, including performance targets, monitorable indicators, resource allocation, and implementation arrangements.
62 Appendix 13
III. SOCIAL SAFEGUARD ISSUES AND OTHER SOCIAL RISKS
Issue Significant/Limited/ Strategy to Address Plan or Other Measures No Impact Issue Included in Design No land acquisition and Involuntary resettlement impacts are Full Plan Resettlement expected because of the Short Plan technical design and Resettlement Framework scheduling. █ No Action There are no indigenous Indigenous Peoples peoples in the project site. Plan Other Action Indigenous Peoples Framework █ No Action The Project will mostly use Labor local labor to expand Employment opportunities for wage Plan opportunities earning. Their employment Other Action Labor retrenchment will abide with local labor █ No Action Core labor standards laws, which embody key International Labour Organization labor standards. There is no indication that Affordability the Project will increase Action power pricing or benefit the █ No Action nonpoor more. Other Risks and/or The Project will not establish Vulnerabilities long-term camps and will not Plan HIV/AIDS draw camp followers, Other Action Human trafficking including sex workers, █ No Action Others(conflict, political because of the fast transfer instability, etc), please of workers from one site to specify another. The exclusion of sex workers and use of local workers is expected to prevent human trafficking. The area is free from political conflict in spite of the presence of internally displaced persons. IV. MONITORING AND EVALUATION
Are social indicators included in the design and monitoring framework to facilitate monitoring of social development activities and/or social impacts during project implementation? █ Yes □ No