The Consultant’s final report is a document of a team of consultants led by Mr D N Raina. The views expressed herein do not necessarily represent those of ADB's Board of Directors, Management, or staff, and may be preliminary in nature. Your attention is directed to the “Terms of Use” section of this website. Consultant’s Final Report Project No. 41154 Final Report September 2013 TA 7628 (NEP): Energy Sector Capacity Building Prepared by Mr. D. N. Raina, A. Subbiah, S. Zaidi, P. Choynowski and G. Pandit
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The Consultant’s final report is a document of a team of consultants led by Mr D N Raina. The views expressed herein do not necessarily represent those of ADB's Board of Directors, Management, or staff, and may be preliminary in nature. Your attention is directed to the “Terms of Use” section of this website.
Consultant’s Final Report Project No. 41154 Final Report September 2013
TA 7628 (NEP): Energy Sector Capacity Building Prepared by Mr. D. N. Raina, A. Subbiah, S. Zaidi, P. Choynowski and G. Pandit
Final Report
TA 7628 (NEP): Energy Sector Capacity
Building
Submitted To
The Asian Development Bank
By
D. N. Raina, A. Subbiah, S. Zaidi, P. Choynowski and G. Pandit
November 2012
3
Acknowledgement
This Final Report for Asian Development Bank’s (ADB) Technical Assistance, TA 7628 (NEP): Energy
Sector Capacity Building has been prepared by the team of experts that carried out the various
components of the TA. The team comprised of Mr. D. N. Raina (Capacity Development Coordinator-
International), Mr. S. Zaidi (Hydropower Policy and Planning Specialist- International), Mr. A. Subbiah
(Energy Sector Capacity Building Advisor- International), Mr. Peter Choynowski (Project Evaluation and
Monitoring Specialist- International) and Mr. Gandhi Pandit (Legal Expert-National), all selected by the
ADB as independent consultant to implement the TA. The team implemented the TA activities initially
under the guidance of Dr. Priyantha Wijayatunga, Senior Energy Sector Specialist and then under Mr.
Tika Limbu, Energy Economist, South Asia Department, from the ADB.
The team of experts acknowledges and puts on record their sincere appreciation with gratitude for the
cooperation and insights provided by the following organizations and their professionals during the
carrying out of the TA activities:
Secretary, Ministry of Energy (MOE), Government of Nepal (GON)
Joint secretaries and other officials of the MOE, GON
Director General and his Senior Management Team at the Department of Electricity Development
(DOED), Nepal
Electricity Tariff Fixation Commission, Nepal
Nepal Electricity Authority (NEA), Nepal
Water and Energy Commission, GON
The World Bank, Nepal Resident Mission
Embassy of Norway in Kathmandu
Country Director, SN Power, Nepal
Asian Institute of Management, Manila, Philippines
Nam Theun 2 Power Corporation (NTPC), Lao, PDR
Administrative Staff College of India, Hyderabad, India
Ministry of Energy and Mine, Government of Lao, PDR
ADB, Nepal Resident Mission
The team expresses its sincere thanks to various other organizations, specifically not mentioned herein
above, but who provided active support in hosting the trainees during their training programs and made
valuable contribution by sharing their experiences with them. Thanks are also due to the vendors, and
other agencies that helped the team in providing necessary logistic support for the accomplishment of the
TA objectives.
Last but not the least, the team expresses it gratitude to the Asian Development Bank, Manila for hiring
the services of the team of Consultants and guiding them in the TA implementation, especially the
Director, Energy Division, South Asia Department at the Bank and other senior officials of the Bank who
took out their precious time out to meet with the participants of the AIM training program during their
visit to ADB Headquarter Manila.
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List of Abbreviations
ADB Asian Development Bank
AHEC Alternate Hydro Energy Centre
CBOM Community Based Operation and Maintenance
CBRE Community Based Rural Electrification
CA Concession Agreement
CD Capacity Development
CDM Clean Development Mechanism
DOED Department of Electricity Development
EIRR economic internal rate of return
ETFC Electricity Tariff Fixation Commission
FIRR financial internal rate of return
GON government of Nepal
IAEA International Atomic Energy Agency
ICH International Centre for Hydropower
IPP independent power producer
MOE Ministry of Energy
NEA Nepal Electricity Authority
NEP National Energy Policy
NERC National Electricity Regulatory Commission
PPA power purchase agreement
RFP request for proposals
SAARC South Asian Association for Regional Cooperation
SEB State Electricity Board
TA technical assistance
T&D Transmission and Distribution
TOR Terms of Reference
UNDP United Nations Development Programme
WASP Wien Automatic System Planning
WBI World Bank Institute
WECS Water and Energy Commission Secretariat
WEIGHTS AND MEASURES
GWh – gigawatt-hour (1,000 megawatt-hours)
km – kilometer (1,000 meters)
kV – kilovolt (1,000 volts)
kW – kilowatt (1,000 watts)
kWh – kilowatt-hour (1,000 watts)
MVA – megavolt-ampere (1,000 kilovolt-amperes)
MW – megawatt (1,000 kilowatts)
NOTES
In this report, "$" refers to US dollars.
5
Table of Contents
Content Page
Acknowledgement 2
List of Abbreviations 3
Table of Contents 4
Executive Summary 10
Chapter-I: Capacity Building Needs Assessment 14
Section-1: Introduction 15 1.1 Background 15 1.2 Objectives of the TA 15 1.3 Implementation Arrangement 16 1.4 Implementation Strategy 16
Section-2: Capacity Building Needs Assessment 17
2.1 Fact Finding Mission 17 2.2 Capacity Building Needs, Assessment 17
2.2.1 Support for DOED 18 2.2.2 Support for ETFC 19 2.2.3 Support for NEA/DOED/MOE 19
2.3 Delivery Mechanism 19 2.4 Next Steps 20 2.5 Finalization of the Capacity Building Program 21
Chapter II: Hydropower Policy & Planning 23
24 Section 1: Hydropower Policy & Planning 24
1.1 Purpose 24 1.2 The IPP Solicitation Process 24 1.3 Intervention Points for the Private Sector 24 1.4 Models for Future Developments 25
1.4.1 One-Stage Model 25 1.4.2 Two-Stage Model 26 1.4.3 Hybrid Model 26
Section 2: Legal Framework for IPP Selection and Engagement 27 Section 3: Institutional Arrangements for IPP Selection and Engagement 28
3.1 Power Sector Organization 28
Section 4: IPP Project Documentation 30
Section 5: Procedures for the Selection, and Engagement of IPP for Hydropower 31
6
Development
5.1 Introduction 31 5.2 Development of Regulations for IPP Selection and Engagement 31 5.3 Adjustment in Nepal’s Traditional Regulatory Guide to IPP Engagement 31
Section 6: IPP Project Development Process 33
6.1 Objectives of IPP Project Development 33 6.2 Stages in IPP Project Development 35 6.3 Investment Decision 36
6.3.1 Decision Process 36 6.3.2 Selection of the Best Investment 37 6.3.3 Adequacy of Returns 37
6.4 Financing Decision 37 6.5 Procurement Decision 38
6.5.1 General 38 6.5.2 Selection and Engagement of IPP for Privately Financed Projects 38
6.6 Pre-selection of Developer 39 6.7 Project Preparation to Seek RFP from IPP 39 6.8 Solicitation, Negotiation and Award of Concession 41 6.9 Post-award Activities 41
Section 7: Pre-election of Developers 43 7.1 Mandatory Pre-selection 43 7.2 Invitation to apply for Pre-selection 43 7.3 Participation of Consortia 43 7.4 Pre-Selection Criteria 44 7.5 Decision on Pre-selection 44 7.6 Post-qualifications 44
Section 8: Selection of IPP Bid under Open/Competitive Procedure 45 8.1 Process for Solicited IPP Bids (Proposals) 45
8.1.1 Request for Proposals 46 8.1.2 Bid Bond, Letter of Support, and Performance Guarantee 46
8.2 Process Subsequent to Issuance of LOS 47 8.3 Security Package and Risk Cover 47 8.4 Corporate, Fee, and Contractual Arrangements 48
8.4.1 Fee Structure 48 8.4.2 Enterprise Structure and Licensing Requirements 50 8.4.3 Lock-in Period 50 8.4.4 Type of Contracts 50 8.4.5 Nature of Equipment 50
8.5 Determination of Tariff for Grid-Connected IPPs 51 8.6 Competitive Bidding Process 51 8.7 Off-taker Involvement in Bidding Procedure 52 8.8 Bidding Documents for Inclusion in Request for Proposals 53 8.9 Evaluation of Bids and Ranking of Bids 54
7
8.9.1 Bids Evaluation Process 54
8.9.2 Bid Evaluation Committee 54
8.9.3 Committee Members Experience and Qualifications 54 8.9.4 Committee Members Responsibilities and Duties 54 8.9.5 Evaluation of Bids and Their Ranking 55 8.9.6 Typical Bid Evaluation Criteria 55
8.10 Negotiation and Award 56 8.11 Post-Award Proceedings 57
Section-9: Alternative Methods of IPP Selection and Engagement 58 9.1Authority to use Alternative Methods of Procurement 58 9.2 Restricted Competitive Procedure 58 9.3 Two-Stage Bidding Procedure 58 9.4 Negotiated Award Procedure 59
9.4.1 Conditions for use of Negotiated Procedure 59 9.4.2 Procedural Steps in a Negotiated Award 59 9.4.3 Transparency in Negotiated Procedures 60
Section-10: Unsolicited IPP Proposals 62
10.1 Admissibility of Unsolicited IPP Proposals 62 10.2 Selection and Engagement Procedure for Unsolicited IPP Proposals 62 10.3 Process for Unsolicited Proposals 63
10.3.1 Submission of Unsolicited Proposals 63 10.3.2 Evaluation of Unsolicited Proposals and Issuance of Letter of Intent 64 10.3.3 Feasibility Study 64 10.3.4 Bank Guarantee and Validity Period of Letter of Intent 65 10.3.5 Request for Determination of Tariff 65 10.3.6 Performance Guarantee and Letter of Support 66
Chapter III: Project Documentation for Hydropower Projects Financed
Through Independent Power Producers 67
Section-1: General Considerations in IPP Project Documentation 68 1.1 Need for Model Project Agreements 68
1.2 Model Agreements to be based on International Conventions 69 Section-2: Tentative list of Project Documents 70
2.1 Project Agreements to which GON Agencies are a signatory 71 2.1 Project Agreements to which GON Agencies are not signatory 71 2.2 Financing Documents 71 2.4 Project Agreements and Financing Documents 72
Section-3: Features of Model IPP Project Agreements 73
3.1 Model Memorandum of Understanding 73
8
Section 4: Model Project Development Agreement (PDA) 75 4.1 Purpose of the model form of the PDA 75 4.2 Features of the Model PDA 75 4.3 Negotiation of successor agreement 75
4.3.1 Comprehensive List of Studies and Program for Inclusion in PDA
and/or CA 75
4.3.2 Brief Outline of Coverage in the Studies 77 4.3.3 Brief Outline of Consultation Program/ Process for Inclusion in
PDA and/or CA 81
4.3.4 Capacity-Building Program for Social Aspects 82
Section 5: Model Concession Agreement 83 5.1 Model CA based on international contract principles 83 5.2 Model CA covers the general conditions of the concession terms 83 5.3 Preceding agreements 83 5.4 Form and structure of the Model CA 84 5.5 Bankability of the Model CA 84 5.6 Domestic Preference 84
Section 6: Model Power Purchase Agreements 85
6.1 General Observations 85 6.2 Tariffs Structure 86
6.2.1 Minimum offtake obligations 87 6.3 PPA for Domestic/ Foreign Hydropower Offtakers in Nepal 87
6.3.1 PPA for foreign off-take 87 6.3.2 PPA for DOED off-take 87
Section 7: Engineering, Procurement, and Construction Contract (EPC) for Project
Implementation 89
Section 8: Implementation Arrangements 90
8.1 Adaptive Management 90 Section 9: Project Monitoring and Performance Evaluation 91
9.1 Monitoring Arrangements 91 9.2 Appointment of Panel of Experts for Monitoring and Evaluation 91 9.3 Project Monitoring Indicators 91
9.4 Monitoring By Independent International Panel of Experts (Starting from
Project Design) 92
9.4.1 List of Panel of Experts 92 Section 10: Conflict Resolution 93
10.1 Panel of Experts 93 10.2 International Arbitration 93
Chapter IV: Capacity Building Needs of DOED & Economic Analysis of 94
9
Hydropower Projects Section 1: Capacity Building Needs of DOED 95
1.1 Background 95 1.2 What Is Economic Analysis & Why the Need 96
Section 2: Overview of DOED, its organization & responsibilities 98
2.1 Department of Electricity Development 98 2.2 Organization of DOED 98
2.2.1 Project Division 98 2.2.2 Privatization Division 99 2.2.3 Inspection Division 100
2.3 DOED staffing 101
Section 3: Assessment of DOED Facilities and Capacity for Economic Analysis of
Hydropower Projects 102
3.1 DOED Location & Physical Infrastructure 102 3.2 Capacity Needs 102
3.2.1 Load Forecasting 102 3.2.2 Least Cost Generation Planning 105 3.2.3 Benefit-Cost Analysis 105 3.2.4 Financial Sustainability 106
3.3 Staffing Needs 106
Section 4: Conclusions and Recommendations 107 4.1 Conclusions and Recommendations 107
Section 5: Training Course on Economic Analysis of Hydropower Projects 108
CHAPTER-V: Legal Aspects in Hydropower Project Development and
Project Documentation 109
Section 1: Review of Legal Documentation and Support to Team of Expert in
Accomplishing TA Objective 110
1.1 Introduction 110
1.2 Task perform during Inception Mission 110
1.3 Task performed after Inception Mission 110 1.4 Summary of the Activities completed by the Legal Consultant against the
items listed in the TOR 114
1.5 Conclusions and Recommendations 115
CHAPTER-VI: Training, Equipment Procurement, Project Coordination and
Implementation 116
10
Section 1: Training, Field Visit, Equipment procurement and Coordination 117
1.1 Training Needs Assessed 117
1.2 In-county Training Programs 117
1.3 External Training Programs 118
1.4 Field Visit to Nam Theun 2 Hydropower Project 120
1.5 Procurement of Equipment 121
1.6 Coordination of Activities performed under the TA 121
Annexure-A: Guidelines for Determination of Tariff for IPPs 122
Annexure-B : Hydropower Pricing 129
Annexure-I Terms of Reference of Consultants 133
Annexure-II: Schedule of Meetings and Persons Met during Fact Finding Mission 135
Annexure-III: LIST OF OFFICIALS MET DURING THE INCEPTION MISION 136
Annexure-IV: LIST OF OFFICIALS PRESENT IN THE WORKSHOP 137
Annexure-V: Presentation in the Inception Workshop 138
Annexure-VI: Gantt Chart 139
Annexure-VII: Training Course in Economic Analysis of Hydropower Projects 140
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Executive Summary
ES 1: The Capacity Development TA:
ADB, at the request of the Government of Nepal (GON) provided a Capacity Development Technical
Assistance (CDTA) for the Nepal power sector under TA No. 7628 (NEP): Energy Sector Capacity
Building for the power sector development in the country. The organizations identified for receiving
support under the TA included, the Ministry of Energy (MOE), Department of Electricity Development
(DOED), and Electricity Tariff Fixation Commission (ETFC). An amount of US$ 600,000 was given as
grant by the ADB and an amount of US$ 100,000 was to be contributed by the GON in kind by providing
the counterpart staff and office accommodation for consultants during their work in Nepal.
ES 2: Objectives of the TA:
The CDTA was designed to be implemented over a period of 20 months. The main focus areas to be
covered under the CDTA aimed at providing capacity development support to the institutions and
personnel dealing with hydropower in the country. Following were the envisaged outcomes of the CDTA:
a. A streamlined procedure for hydropower development instituted by end-2011,
b. A long-term investment plan for hydropower development instituted by end-2011, and
c. Public Private Partnerships (PPP) in hydropower approved for at least 600 MW by 2015
hydropower policy making, regulation; planning and investment promotion.
These initiatives in turn would help the country to put the hydropower development on a fast track.
ES 3: Implementation Arrangement:
It was decided to implement the CDTA by a team of five independent consultants, each one appointed
individually by the Bank. The experts included (i) an Energy Sector Capacity Development Advisor
(International), (ii) a Capacity Development Coordinator (International), (iii) a Hydropower Policy and
Planning Specialist (International), (iv) a Project Evaluation and Monitoring Specialist (International),
and (v) a Legal Expert (National). The Terms of Reference of the each of the five consultants is attached
at Annexure-I of this report. It was also decided that the equipment purchased under the TA will be
turned over to the DOED upon completion of the TA.
ES 4: Implementation Strategy:
The TA was to be implemented in two phases. Under Phase-I, the capacity development advisor would
assess the capacity building needs of the beneficiary organizations viz. (i) MOE, (DOED) and (iii) the
ETFC. A capacity development coordinator, with the support of the advisor, will then identify specific
training requirements, select the tools and experts to be utilized, and coordinate subsequent activities
under the TA. Phase II activities were to include (i) developing policies, plans, and evaluation and
monitoring tools for hydropower projects; (ii) standardizing documentation submitted for project approval
and, where possible, methodologies for evaluating private hydropower projects; (iii) assisting the DOED
in negotiating at least one large hydropower project based on a public–private partnership (PPP); and (iv)
12
conducting in-house and external training and exchange programs for MOE, ETFC and DOED staff
arranged by the capacity development coordinator. MOE was identified as the nodal agency for the
implementation of the TA by the GON. For day to day interaction with the consultants, a Senior
Divisional Engineer of the DOED was named by the GON as the contact person for the implementation
of the TA.
ES 5: ADB Missions to Nepal for the TA
ADB Fact Finding Mission along with the Energy Sector Capacity Development Advisor, Capacity
Development Coordinator and Hydropower Policy & Planning Specialist visited Nepal in March, 2011 to
hold consultations with the GON and Stakeholder organizations to assess their capacity development
needs. Based on these interactions, a Capacity development Needs Assessment was prepared and
submitted to the GON as part of the Inception Report. This was followed up with ADB Inception Mission
in May 2011. In addition to the meeting with the senior most management of the identified stakeholder
organizations, a half day Inception Workshop was organized for the stakeholders. The workshop was
inter-alia attended by the Secretary and senior officials of MOE, Director General and Deputy Director
Generals of DOED, ETFC and NEA. The activities to be carried out under the TA were finalized in
consultation with the stakeholders.
E 6: Hydropower Policy and Planning:
The Hydropower Policy and Planning Specialist reviewed the IPP solicitation process in Nepal
and suggested measure and set out guidelines and procedures for Private Sector Participation in
Nepal’s Hydropower Development that covered the Guidelines and Procedures for the
Preparation of Request for Proposal document for soliciting bids from Independent Power
Producers. Laid down the legal framework for IPP selection and engagement; institutional
arrangements for IPP selection and engagement; IPP project documentation; procedures for the
selection and engagement of IPP for hydropower development; IPP project development process;
discussed therein the pre-selection of developers; solicitation of IPP bids under open/competitive
procedure; suggested alternative methods of IPP selection and engagement; how to handle
unsolicited IPP proposals; laid down the guidelines for determinations of tariff for the IPPs; and
hydropower pricing.
The policy and planning specialist also provided guidelines for preparation of the project
documentation for hydropower development financing through IPPs; covering General
Considerations in IPP Project Documentation; Tentative List of Project Agreement Documents; Features
of Model IPP Project Agreements; Model Project Development Agreement (PDA) Main Features; Model
Concession Agreement (CA); Engineering, Procurement, and Construction (EPC) Contract for Project
Implementation; Implementation Arrangements; Project Monitoring and Performance Evaluation; and
Conflict Resolution. He was assisted by the Legal expert in providing the advice.
Two capacity development training programs on policy and planning of hydropower projects covering all
the above areas were conducted for the professional of the MOE, DOED, NEA and ETFC. The first
training program on Private sector Participation in Nepal’s power sector was held from October 30, 2011
to November 30, 2011. The purpose of the training program was to give detail knowledge and
international prospective to participants on the following issues in developing hydro project/selecting
project developers:
13
i. Provide guidelines and procedure for the preparation of Request for proposal documents for
soliciting Bids from Independent Power procedure and evaluation of Bid received
ii. Legal framework for IPP selection and development of Regulations for IPP Selection
iii. IPP Project Development Process
iv. Method and process of Procurement
v. Grounds for going for Unsolicited Proposal
The program was mainly led and organized by International Hydropower Policy Specialist. Legal
Consultant assisted and was closely involved with the international consultant in conducting and
completing the said training program.
The other training program on "Project Documentation for Hydropower Development Financing through
Independent Power Producers" was conducted by the Hydropower Policy & Planning Specialist along
with Legal consultant for 50 participants from DOED, MOE and NEA. The program was conducted in
the morning and afternoon sessions each day. Each session was attended by 25 participants. The
Hydropower Policy & Planning Specialist and Legal consultant made presentations on “General
Considerations in IPP Hydro project Agreement documentation”. Presentations and discussions were held
on:
i. Tentative list of Project Agreement Documents
ii. Model MOU
iii. Main feature of Model PDA
iv. Model Power purchase agreement
v. EPC contract
E 7: Project Evaluation and Monitoring:
As enunciated in his scope of work, the Project Evaluation and Monitoring Specialist conducted the
capacity development needs assessment of the DOED from the perspective of the capacity of its officials
to carry out financial and economic analysis of hydropower projects. The methods currently deployed by
the DOED to evaluate the potential hydropower projects were reviewed and recommendations for
possible modifications to these methods were made. Recommendations about the procurement of
potential tools for economic and financial analysis, mostly available free of cost to National power
utilities were suggested. The important considerations, such as, relevance of the project, cost
effectiveness, efficiency, sustainability, uncertainty about the projects were discussed with the DOED
and how they can evaluate these features. During the review, it was acknowledged that the professionals
of DOED are highly capable of carrying out the technical analysis of the proposed projects. However,
technical viability assessments are insufficient to ensure that Nepal’s scare investment resources are
efficiently utilized. To guide the development of Nepal’s power system and to evaluate potential
hydropower projects on an economic basis, it was felt that DOED needs to establish an Economic
Planning Unit that has an ability to: (i) prepare long-term load forecasts, (ii) develop least cost generation
expansion plans, (iii) determine the economic viability of individual generation projects, and (iv) to assess
the financial impact of these projects on the operating entities. This exercise led to the identification of the
staff need of DOED for an Economic planning unit.
The Evaluation and Monitoring Specialist conducted a training program on “Economic Analysis of
Hydropower Projects from March 7-11, 2012 for 50 participants from the MOE, DOED, NEA and ETFC.
In addition to class room lectures, the participants were given exercises on carrying out economic and
financial analysis based on the actual project data to help them gain hand on experience in carrying out
these tasks.
14
E 8: Legal Review of Hydropower Project Documentation The Legal consultant reviewed some of the documents provided by DOED and identified issues that need
to be addressed during PDA negotiation. He also reviewed Model PDA prepared by DOED. The issues
that have been flagged by the legal consultant during the review of project documents include: Terms of
Concession agreement, Commercial operation date, Change of law, Sovereign Guaranty, performance
guarantee; repatriation of interest, principal and other earnings of the developer, default and
compensation, Force Majeure Events, issue regarding condition of termination of the Agreements and
dispute settlement clauses in the project documents. These issues were discussed and analyzed during the
CD program conducted in November 2011 and May 2012.
E 9: Support in carrying out economic & financial analysis and project
negotiations with private developers for an identified project
One of the primary objectives of the TA was that the Consultants will assist DOED staff in handling the
legal issues during negotiations with the private companies on developing potential hydropower projects
and assist in negotiations, primarily with the terms of the power Development agreement. The other one
was to carry out economic and financial analyses and evaluate already identified potential hydropower
projects to be developed by private sector; and assist DOED in negotiating with the private company on
the terms of developing the hydropower projects.
Both these tasks could not be undertaken as DOED did not conduct any negotiation with any private
project developer during the TA period. Nor did they have a project ready for carrying out the economic
and financial analysis. However, it is expected that the advice provided by the consultants during the
review and/or development of the project documents and the training programs imparted, would help
them in undertaking these task.
E 10: External Training Programs and Field Visit
In addition to the three training programs conducted in Nepal, two training programs were conducted for
the MOE, DOED, NEA and ETFC outside the country. The first one on “Project Planning and
Management” was organized at AIM Manila, Philippines and the other one titled on “Power Sector
Regulation for Nepal Electricity Tariff Fixation Commission” was conducted at Administrative
Staff College Hyderabad, India. A field visit to Nam Theun 2 hydropower project in Lao PDR was also
organized to help the participants realize as to how an underdeveloped country could successfully
implement a large hydropower project despite all the constraints, somewhat similar to those faced by
Nepal.
E11: Equipment procured during the TA Implementation
One Digital Photocopy Machine (Heavy Duty), Make RICOH, Model MP 2000; one Canon
Multifunction PRINT, COPY, SCAN, FAX; Ten Dell N5110 Laptops and Software Microsoft Office
2010, one each for the laptops, as requested by the DOED was procured at a cost of NR 1,381,990. The
equipment was handed over to the DOED under the supervision of the ADB Nepal Resident Mission
representatives and a formal handover/takeover receipt was obtained and submitted to the ADB.
15
CHAPTER-I
Capacity Building Needs Assessment
16
SECTION 1: Introduction
1.1 Background:
Nepal has a vast techno-economically exploitable hydropower potential of about 42,000 MW, much
higher than the domestic electricity requirements. Exploitation of this natural resource, therefore, not only
provides an opportunity to meet its own domestic electricity needs, but also to export the surplus energy
for the overall economic development of the country. However, due to various reasons, the country has
not been able to harness its hydropower potential. The country is not able to meet its own electricity
demand and has to import electricity from India. The load shedding has reached a crescendo leading to
rising public outcry against the electricity outages. This is despite the fact that only 56% of house holds
have access to electricity as of now. The annual demand growth for electricity is hovering around 9%-
10%. If Nepal has to provide electricity to its entire population and support it industrial and economic
development, the country needs to move at a much faster pace in exploiting this resource in a big way.
Power sector in Nepal is dominated by the state owned vertically integrated power utility Nepal
Electricity Authority (NEA). The performance of NEA has been very poor for over a decade now. It has
been incurring financial losses year after year. Its financial health is does not give the confidence to the
private sector to invest in the hydropower sector a big way, despite the fact that electricity generation has
been opened to the private sector for nearly two decades now. One of the major reasons for NEA’s poor
financial health has been the poor regulatory mechanism put in place by the government. As a result the
total installed generation capacity of Nepal has been hovering around 700 MW. Hydropower being one of
the major natural resources that the country has; it is envisaged that its development could be a major
contributor to its overall economic development. The Three Year Interim Plan (2007/08-2009/10),
prepared by the National Planning Commission of the GON, envisages the development of 4000MW
additional capacity by the year 2027. To achieve this goal, the government intends to improve the
regulatory environment and encourage investment in the sector by facilitating investments through single
window clearance mechanism and take other policy initiative to encourage investment in the power
sector. It is in this backdrop that GON made a request to the Asian Development Bank (ADB) for
technical assistance support.
ADB at the request of the Government of Nepal (GON) provided Capacity Development Technical
Assistance (CDTA) - TA No. 7628 (NEP): Energy Sector Capacity Building for the power sector
development in the country. The organizations identified for receiving support under the TA include the
Ministry of Energy (MOE), Department of Electricity Development (DOED), and Electricity Tariff
Fixation Commission (ETFC).
The size of the TA was fixed at US$ 700,000. Funds for the TA were to be provided by the ADB as grant
to the tune of US$ 600,000 and the balance amount of US$ 100,000 were to be provided by the GON as
its contribution in kind by contributing the counterpart staff and office accommodation for consultants
during their work in Nepal.
1.2 Objectives of the TA:
The TA is aimed at helping the capacity building of the organizations mentioned above to help the
country in expediting the development of the hydropower sector. So that Nepal is able to meet its
domestic electricity needs, as well as, helps the country to exploit its vast hydropower potential for export
17
of surplus energy. The CDTA is designed to be implemented over a period of 20 months. The main focus
areas to be covered under the CDTA aims to support capacity development of institutions and personnel
dealing with hydropower. Following are the envisaged outcomes of the CDTA:
d. A streamlined procedure for hydropower development instituted by end-2011,
e. A long-term investment plan for hydropower development instituted by end-2011, and
f. Public Private Partnerships (PPP) in hydropower approved for at least 600MW by 2015
hydropower policy making, regulation; planning and investment promotion.
These initiatives in turn would help the country to put the hydropower development on a fast track.
1.3 Implementation Arrangement:
ADB decided to implement the CDTA by a team of 5 independent consultants, each one appointed
individually by the Bank. The experts included (i) an Energy Sector Capacity Development Advisor
(International), (ii) a Capacity Development Coordinator (International), (iii) a Hydropower Policy and
Planning Specialist (International), (iv) a Project Evaluation and Monitoring Specialist (International),
and (v) a Legal Expert (National). The Terms of Reference of the each of the five consultants is attached
at Annexure-I of this report.
It was also decided that the equipment purchased under the TA will be turned over to the DOED upon
completion of the TA.
1.4 Implementation Strategy: The TA was to be implemented in two phases. Under Phase-I, the capacity development advisor would
assess the capacity building needs of the beneficiary organizations viz. (i) MOE, (DOED) and (iii) the
ETFC. A capacity development coordinator, with the support of the advisor, will then identify specific
training requirements, select the tools and experts to be utilized, and coordinate subsequent activities
under the TA.
Phase II activities were to include (i) developing policies, plans, and evaluation and monitoring tools for
hydropower projects; (ii) standardizing documentation submitted for project approval and, where
possible, methodologies for evaluating private hydropower projects; (iii) assisting the DOED in
negotiating at least one large hydropower project based on a public–private partnership (PPP); and (iv)
conducting in-house and external training and exchange programs for MOE, ETFC and DOED staff
arranged by the capacity development coordinator.
MOE was identified as the nodal agency for the implementation of the TA by the GON. For day to day
interaction with the consultants, a Senior Divisional Engineer of the DOED was named by the GON as
the contact person for the implementation of the TA.
18
SECTION 2: Capacity Building Needs Assessment
2.3 Fact Finding Mission
A Fact Finding Mission1 from the Asian Development Bank (ADB) visited Kathmandu, Nepal from
March 6-12, 2011. The Mission was to achieve the following principal objectives:
Meet with personnel at DOED, MOE, and the ETFC – the principal stakeholders
for this TA.
Meet with relevant donor agencies, international financial institutions and private
sector stakeholders active in supporting hydropower development in Nepal.
Understand the principal barriers to hydropower development in Nepal.
Identify the gaps in learning and develop preliminary plans for capacity building
to support increased hydropower investments in Nepal.
Understanding the goals and needs of stakeholders in Nepal was crucial for the development of
appropriate learning and capacity development programs to promote development of hydropower projects
in Nepal. The first step was to identify the gaps in knowledge and identify the capacity building needs of
stakeholders targeted by this TA. A “Capacity Development Needs Assessment Framework” was used to
conduct a needs assessment study, whose outcome led to the preliminary identification of appropriate
capacity building and learning programs to achieve the objectives of this TA.
The mission held discussions with Ministry of Energy GON, DEOD, ETFC, NEA, public and private
sectors stakeholder organizations and also with other donors and financing agencies with a view to
understand the roles of various agencies in promoting and developing hydropower resources in Nepal,
and to identify the gaps in capacity that hinder their ability to discharge their responsibilities in an
effective manner. The team also met with the World Bank Nepal Mission and the Norwegian Embassy to
get their feedback on assistance they are providing to the Nepal power sector and their TA initiatives. In
order to get the feedback from the private sector the team also met with SN Power, one of the major
hydropower developers in Nepal.
2.2 Capacity Building Needs, Assessment
Based on the meetings and discussions held with various stakeholder organizations in Nepal, including
other donor and international financing agencies, it was felt that there is considerable scope for capacity
building to promote the development of hydropower in Nepal. The names of the persons met with and
their organizations are given at Annexure-II. While a number of options for capacity building were
identified, the guiding factor for capacity development under the ADB TA was to identify specific
activities that serve the needs of local stakeholders (DOED, EFTC, MOE and NEA), build on past
1 ADB Fact Finding Mission comprised of D.N.Raina, Capacity Development Coordinator; A. Subbiah Energy Sector Capacity
Development Advisor, and Hydropower Policy and Planning Specialist, engaged by the ADB for this TA, under the Mission
Leader Dr. Priyantha Wijayatunga together with Mr. Shahid Pervez ADB Nepal Resident Mission staff.
19
activities and do not duplicate the efforts being made by other donor programs, offering much higher
levels of funding. DOED and ETFC also provided written input of their needs for capacity building.
The preliminary conclusion of the mission for providing capacity building and training in support of
promoting hydropower in Nepal were to focus on the following activities. The final capacity building
recommendations were based on the available resources and discussions with ADB and relevant
stakeholders in Nepal.
Based on the above interactions, the Mission came to the conclusion that the beneficiary organizations
need the support listed under each one of them:
2.2.1 Support for DOED
Capacity building and training is suggested for DOED staff covering the
following issues and topics:
Capacity Development and tools for setting up Guidelines and procedures for
generation system planning (coordinated with NEA and the Water and
Energy Commission Secretariat [WECS]).
Guidelines and procedures for preparation of request for proposals (RFP)
packages to solicit independent power producers’ (IPP) bids.
Guidelines and procedures for technical evaluation of IPP bids received in
response to RFPs and unsolicited bids received from IPPs for developing
projects on a first-come-first served basis, including evaluation of feasibility
studies, hydrology reports, environmental and social impacts, etc.
Guidelines and procedures for financial and economic analysis of IPP bids,
including easy-to-use financial models.
Guidelines and procedures for monitoring and evaluation of bids and projects
under development.
Capacity to disseminate project information through a website for greater
transparency.
Guidelines and procedures for evaluating Clean Development Mechanism
benefits of hydropower projects.
Guidelines and procedures for free power, free equity, royalties and
licensing, etc. and model project development agreements.
Conducting negotiations with project developers.
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2.2.2 Support for ETFC
Capacity building and training for ETFC covering the following issues and
topics:
Formats for tariff applications to be made by NEA and other licensees.
Guidelines and procedures for analyzing tariff applications through
application of cost based tariff application and unbundled tariffs (in view of
pending electricity sector reform).
Guidelines and procedures for estimating the regulatory asset base of
utilities.
Preparation of a tariff toolkit.
2.2.3 Support for NEA/DOED/MOE
Capacity building and training for NEA/DOED/MOE covering the following
issues and topics:
Standardized power purchase agreements (PPA) for hydropower projects of
varying size, for domestic and export-power projects, and other model
contracts including concession agreements, project development agreement,
etc.
Guidelines and procedures for PPA, project development agreements and
concession negotiations.
Guidelines and procedures for tariff filings with ETFC (and proposed
National Electricity Regulatory Commission).
Concepts of generation and transmission least-cost planning.
Operations of system planning software models.
Enabling frameworks: laws, policies and regulations.
Institutions with clear mandates and authorities to develop and negotiate
projects.
2.3 Delivery Mechanism
Given the constraints of budgets and the need for on-going training, it was identified that a variety of
delivery mechanisms could help in effective capacity development of the various institutions involved in
the development of hydropower in Nepal. These mechanisms for could include:
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On-the-job training: handholding by consultants during project implementation for a
learning-by-doing experience. On-the-job training will be given by the consultants
whenever they are in Nepal to implement the TA.
In-country training: face-to-face training programs conducted in-country by external
consultants in specific areas of expertise. Experts, other than the TA consultants, may be
invited to deliver workshops to impart training in specialized areas, to ensure larger
participation of stakeholders.
Out-of-country training: study tours and workshops for intensive training of selected
personnel in specific areas due to the cost of participating in programs outside the
country.
Twinning programs: twinning Nepal stakeholder institutions with other similar
institutions in the region to promote exchange and sharing of knowledge and experiences.
Such programs are funded by bilateral agencies. The TA will identify opportunities for
twinning arrangements and the partners.
Learning programs: development of learning programs (online courses, certification
programs, continuing education, etc.) to enable long-term and sustainable capacity
building of institutions and personnel. All training material and related documentation
prepared by this TA will be provided in documents and as power point presentation for
on-going learning programs. The possibility of developing specific on-line training
course material and provision publicly available standard toolkits developed by other
programs and agencies will also be explored.
Train the trainers: training imparted to local agencies/experts who in turn train others
thereby developing a long-term sustainable mechanisms for imparting training to
agencies and personnel. Training of trainers will be emphasized in the delivery of
learning programs to ensure that local experts can substitute for TA experts at the end of
the program.
Given the active support of various multilateral and bilateral agencies to Nepal to develop its energy
sector, it was critical that capacity building programs to be developed and delivered through the current
ADB TA be closely coordinated with the World Bank, Norwegian Agency for Development Cooperation,
United States Agency for International Development, and others development partners active in assisting
the energy sector in Nepal to foster cooperation, leverage financing, and avoid duplication of effort.
2.4 Next Steps
The following were identified as the next steps towards the finalization of capacity development programs
and programs to be implemented through this TA.
i. The proposed preliminary listing of capacity building programs would be discussed with
ADB, MOE and other stakeholders in Nepal in early May 2011, wherein the team of
consultant in the presence of ADB will make a presentation on the finding of this Inception
Report to GON and the concerned stakeholders.
22
ii. A capacity building support program for Nepal will be finalized after initial discussions with
stakeholders and an assessment made of the scope of the capacity building program based on
the relevance to the country, the available budget, and project timeline.
iii. The final proposal for capacity building will be prepared on approval from Nepal
stakeholders and ADB.
iv. Upon approval of final proposal, development of the capacity building and training program
will be initiated.
v. An implementation plan for the capacity building and training programs will be prepared
along with plans for future missions to Nepal by project experts.
2.5 Finalization of the Capacity Building Program
An Inception Report based on the findings of interactions with the stakeholder organizations during the
visit of the Fact Finding Mission to Kathmandu in March 2011was prepared and presented to the Ministry
of Energy Government of Nepal in early May, 2011 for their review and comment if any. The objective
was to GON and the stake holder organizations, an opportunity to fine tune the capacity building program
to be initiated under the TA and also cover any additional aspects that they may like to cover, before the
finalization of various activities in the capacity building program.
A CDTA Inception Mission2 from the Asian Development Bank (ADB) visited Nepal from June 2-5,
2011 and met with the officials of the Ministry of Energy (MOE) and Department of Electricity
Development (DOED), and other development partners. A list of key officials met by the Mission is
given in Annexure-III. During the mission, in addition to holding meetings with the Secretary Ministry
of Energy, senior most management of the key stakeholder organizations; the consultants conducted a
half day inception workshop (the Workshop) at which the inception report was discussed and
presentations thereon were made by the consultants: D N Raina (Capacity Development Coordinator);
Sadiq Zaidi (Hydropower Policy and Planning Specialist), Peter Choynowski (Project Evaluation and
Monitoring Specialist) and Gandhi Pandit (Legal Expert) to the stakeholder organizations viz. MOE,
DOED, ETFC and NEA. The workshop was attended by 30 participants including the Secretary and Joint
Secretaries of the MOE, Director General (DG) and Deputy Director Generals (DDG) of the DOED, and
other officials from the MOE, DOED, Water and Energy Commission WECS, Electricity Tariff Fixation
Commission (ETFC) and Nepal Electricity Authority (NEA). The lists of the participants in the
Workshop are presented in Annexure-IV. Copies of the presentation made by the Consultants are
attached at Annexure-V.
Each of the activities identified in the inception report was discussed in detail and the inputs of the
beneficiary organizations were obtained and incorporated in the final list of activities for implementation
under the TA. Their views were sought about the training needs assessed during the inception Mission
and to finalize the activities that could be accomplished under the TA. The need for the same arose from
the fact that the requirement of financial resource to accomplishing all the capacity development needs for
the Nepal Power sector; far exceed the resources available under the TA. The Final Work Plan on
capacity development for the Nepal power sector was prepared and presented to the Government of
2 The Mission comprised of Tika Limbu, Mission Leader, ADB, Manila; D.N.Raina, S. Zaidi, P. Choynowski, G.
Pandit and Shahid Parwez, Project/Program Implementation Officer, NRM
23
Nepal. The final list of activities identified for implementation under the TA, are given in the Gantt chart
placed at Annexure-VI to this report.
After the finalization of the Work plan, the consultants initiated their respective tasks, as per the list of
activities identified for implementation under the TA. The activities carried out by each expert are briefly
summary in the next Chapter and the ensuing sections there under. The details of the training program,
training material and other deliverables have been put as annexure to this report.
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CHAPTER-II
Hydropower Policy & Planning
25
SECTION 1: Hydropower Policy & Planning
1.1 Purpose
This section sets out general principles and procedures to undertake the process of inviting proposals from
Independent Power Producers (IPPs) for the development of hydropower resources in the country,
evaluation of proposals; negotiation for finalization of project agreements and for the award of
concessions.
It provides details of hydropower IPP engagement in Nepal under transparent and competitive process
and contributes to enhance the understanding of these processes through a training program. It provides a
set of guidelines and documentation for the IPP engagement of medium and large hydropower projects on
a Build-Operate-Transfer (“BOT”) or a Build-Own-Operate-Transfer (“BOOT) basis. It has been
prepared to guide Government Agencies in the selection of developers, solicitation and evaluation of IPP
proposals, and the drafting and execution of Project Agreements. The track record of IPP engagement for
BOT/BOOT hydropower in Nepal and elsewhere is still relatively short and inconsistent. Internationally-
accepted and well documented selection and engagement procedures of the sort that govern traditional
ICB procurement have not yet emerged. The IPP selection and engagement procedures and
documentation contained in this document must be considered to be a work-in-progress. With experience
gained from each new concession award, and with changing expectations of governments, investors,
lenders, and International Financing Institutions (IFIs), the document will need to be updated regularly to
maintain compliance with prevailing rules.
It is also important to note that selection and engagement processes for IPP hydropower projects cannot
be defined too rigidly. A balance is needed between flexibility and control. Flexibility allows sponsors the
room to optimize projects for the physical conditions at the site to meet changing requirements of power
purchasers, lenders and other parties; control is needed to prevent sponsors from appropriating a
disproportionate share of a project’s benefits or inflicting undue damage on the environment.
1.2 The IPP Solicitation Process
The government wishing to attract private financing for the development of hydropower sector need to
address a number of fundamental issues:
At what stage in the project cycle should the private sector be introduced?
In what form should that participation occur?
The nature of the solicitation process.
The following paragraphs examine the various options open to the host government in these areas.
1.3 Intervention Points for the Private Sector
In general, there are three points in the project life cycle where the private sector might be introduced.
These are:
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Option Financing Source Construction /Development Operation
1 Public Public Private
2 Public Private Private
3 Private Private Private
The principal features of each option are as follows:
Option 1: The public sector develops the project using its own resources and then privatizes it
by the sale of equity in the project company, or refinances it through granting a
concession to a private operator.
Option 2: The public sector completes the project definition studies (technical feasibility, site
investigation, and so on) and then brings in the private sector to finance, design,
construct and operate the project under concession.
Option 3: Where the public sector is unable or unwilling to finance project definition and other
preparatory studies, the private sector conducts such studies and assumes
responsibility for the full project cycle.
1.4 Models for Future Developments
In considering models for the participation of the private sector in future hydropower development, it has
to be recognized that no single prescriptive formula can apply to the diversity of situations that can occur.
In particular, in the case of large and multipurpose hydropower projects, development entirely in the
private sector may not be a practical option. All of the models outlined below are focused on meeting the
following general criteria:
The project must represent the optimum development of the site in terms of the future
requirements of the power system and in the broader context of other developments, both
existing and potential.
The award of exclusive rights to the site, and endorsement of the tariff structure must
satisfy reasonable standards of transparency.
Implementation contracts need to be structured in a manner that encourages competitive
and responsible pricing.
A security package acceptable to international financiers should be developed at an early
stage. For the above noted requirements the solicitation processes may involve the
following:
1.4.1 One-Stage Model
In this model it is assumed that the prospective concessionaire has been provided with enough
information by the government to determine the project cost at the time of bidding for the concession. The
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concessionaire is thus selected by the government on the basis of the lowest tariff offered during a single
round of bidding. In this case, the public sector is not involved in any way with the project construction
contract that the concessionaire may enter into. However, the difficulty with this approach is that the
private sector has been faced with too many uncertainties at the bid stage, which has deterred prospective
sponsors. To overcome this, the public sector must secure all the necessary clearances and environmental
permits, and establish beforehand a realistic risk-sharing formula and security package acceptable to
international lenders (see table 1), section 8.3, and Annexure A). Site investigation and technical studies
need to be undertaken to a reasonably advanced stage (preliminary design level). This information is then
integrated into a single Project Information Memorandum on which prospective developers are required
to base their proposals.
1.4.2 Two-Stage Model
In a two stage model, the bidding of the concession is separated from the pricing of the works, and hence
the procurement process takes place in two stages. The government (or utility) is party to the award of
both the concession and the construction contracts, in a process that allows it first to select the sponsor on
his own merits, and later to jointly arrange with him the construction contracts in a manner aimed at
minimizing the cost. The sponsor is selected on the basis of his capability, resources and an indicative
tariff based on an assumed construction price. He then undertakes at his own expense the project
definition studies and invites bids for construction, after which a target cost is agreed with the utility and
the tariff revised accordingly. Construction is then managed by the sponsor under a risk sharing
mechanism with appropriate incentives and penalties for the private sector partner in areas where he can
control the risk. Some construction risks, like unforeseen ground conditions, may pass back through the
sponsor, to the utility.
1.4.3 Hybrid Model
Another option, which will serve some situations, is a hybrid model under which the private sector builds,
owns and operates the power elements of a project that is otherwise in the public sector. This arrangement
is applicable to large and complex multipurpose projects with a significant non power element that are
unlikely to be viable on their own in the private sector. For example, in a multipurpose project the dam
and basic site infrastructure could be funded by public sector using concessional financing, leaving the
private developer to build, own and operate the power intakes, penstocks and powerhouse. The model
could also be used in retrofit situations, where a power station is added to an existing publicly owned
irrigation or water supply dam. The consequence of separating off the non power elements is generally to
pass the major civil works construction risk back to the public sector, making it easier to finance the
private portion.
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SECTION 2: Legal Framework for IPP Selection and Engagement
A list of all legal frameworks covering the private sector investment in infrastructure development should
be prepared and included in RFP Document. The list may have the following:
• Law on Foreign Investment (19xx ?)
• Contract Law (19xx?)
• Commercial Bank and Financial Institutions Law (19xx?)
• Customs Law (19xx?)
• Labor Law (19xx?)
• Business Law (19xx?)
• Secured Transaction Law (19xx?)
• Water & Water Resources Law (19xx?)
• Electricity Law (19xx?)
• Environmental Protection Law (19xx?)
• Rules for Consideration and Approval of Foreign Investment Projects ( xxxx?)
• Law on Promotion and Management of Foreign Investment (xxxx?)
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SECTION 3: Institutional Arrangements for IPP Selection and Engagement
3.1 Power Sector Organization
A systematic division of institutional responsibilities for IPP projects would outline, as appropriate, a
separation of contracting, monitoring, off-take and investor functions, under a Contracting Authority, a
Monitoring Authority, an Off-take Authority and an Investor Authority respectively. The institutional
framework for IPP procurement in Nepal is still developing and the allocation of Contracting,
Monitoring, Off-take and Investor responsibilities is being refined on a regular basis. The functions of the
agency, or agencies, performing the role of each of these would normally include:
(a) The Contracting Authority
Advise GON agencies and provide input into power policy development, project
planning, procurement processes and regulatory issues;
Promote viable projects to the investor community;
Make available to developers information on IPP project pipeline;
Make available to developers all laws and regulations of general application to IPP
projects;
Confirm investment incentives for IPP concessionaires in line with Nepal law;
Stipulate and, where appropriate, obtain on behalf of a developer the licenses,
approvals and permits required under the project concession agreement and other
project agreements;
Procure projects in line with set procurement procedures and rules;
Lead the GON team in negotiating MOU, PDA and CA with developers;
Provide support in GON negotiations with foreign power purchasers;
Engage, manage and coordinate specialized financial, legal and technical advisors in
the evaluation of IPP proposals and negotiation of IPP documentation; Negotiate with
developers and sign the Project Development Agreement (PDA) on behalf of GON;
Initial Concession Agreement on successful conclusion of concession negotiations;
Administer the Concession Agreement during the construction, operating and transfer
phases of a project.
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(b) The Monitoring Authority
Advise GON with respect to IPP procurement policies;
Set procedures and rules governing procurement of IPP;
Monitor compliance of IPP procurement with Nepal law;
Recruit and manage independent assessors and advisors;
Settle disputes between developer and GON agencies
(c) The Off-take Authority
Negotiate PPAs providing for off-take by a GON agency;
Administer GON PPAs during the construction, operating and transfer phases of a
project.
(d) Investor Authority
Hold shares in IPP projects on behalf of GON and administer GON interests under
project Shareholder Agreements;
Raise capital to meet GON equity commitments;
Manage GON’s IPP share portfolio, prudently acquiring and divesting equity
holdings to optimize shareholder benefits;
Manage and disburse GON receipts from dividends, re-financings, etc.
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SECTION 4: IPP Project Documentation
IPP project development is based on an intricate web of interlocking contracts and security instruments.
Project sponsors will register a project company (“the Company”) which will execute Project
Agreements and Financing Agreements in accordance with Nepal law, as applicable (refer Figure 1).
Figure 1 - Principal Project Agreements and Financing Documents
The details of contents in each project documents outlined above will be presented and discussed in a
subsequent seminar.
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SECTION 5: Procedures for the Selection, and Engagement of
IPP for Hydropower Development
5.1 Introduction
It appears that systematic formal IPP procurement procedures for Nepal have not been published yet.
Reputable private developers are sometimes discouraged by public sensitivity to hydropower projects, in
particular with regard to environmental and resettlement issues for reservoir schemes and social impacts
of basin transfer schemes. This sensitivity may provoke international reaction which could disrupt and
delay proceedings for IPP selection, engagement, and financing arrangements. Public sensitivity to
hydropower cannot be deflected by procurement procedures alone but structured and transparent
procurement proceedings that meet adequate standards of public consultation and accountability will allay
many of the concerns of international lenders.
5.2 Development of Regulations for IPP Selection and Engagement In response to the need for structured and transparent selection and engagement procedures, the
Regulatory Guide on Award of Concession Contracts for Privately Financed Power Generation Projects
(“the Regulatory Guide”) should be prepared and made public. Competitive and transparent bidding has
proved to be the most effective procurement method to ensure cost-efficient and timely IPP projects
worldwide. Experience from developing countries clearly indicates that to promote competitive and
transparent bidding for IPP projects and to attract reputable foreign investors, a legal or regulatory
framework is needed. Such a framework should also promote transparency and regulate exceptional cases
where selection and engagement methods other than competitive bidding are applied. The first stage of
the drafting process would involve taking key principles from international procurement rules, and then
formulate the process that suits Nepal’s conditions and the regulatory requirements. It may take few
stages to complete the regulation.
5.3 Adjustment in Nepal’s Traditional Regulatory Guide to IPP
Engagement
The Regulatory Guide should be adjusted to fit into and be suitable to the procurement tradition and
current, overall PPP conditions of Nepal. From the information available it appears that to date, all
concessions for larger, privately financed hydropower projects in Nepal (as in most developing countries)
have been awarded by negotiated procedure. The features of the negotiated procedure generally include
the following:
The potential developer is offered an exclusive MOU for a period of xxx (12 to 18)
months to conduct preliminary investigations of the project and feasibility studies;
The Contracting Authority and the developer signs a project development agreement
(PDA) providing the developer with the right to develop the project further on a
BOT/BOOT basis and confirming the agreement of the parties to draft and negotiate the
necessary project agreements;
33
A tariff and a PPA are negotiated with the foreign power purchaser through a government
to government committee and between the developer and the foreign utility. In the case
of domestic off-take, a tariff and PPA are negotiated with the concerned Government
Agency;
The Contracting Authority and the developer sign the final concession agreement before
the project is submitted for approval to the National Assembly of Nepal(?).
This model for award of privately financed concession contracts has exposed the Contracting Authority to
closed-door negotiations against developers that are better resourced and at a natural advantage in terms
of access to project technical and cost data. The model has led to commercial arrangements and risk
allocations onerous to the developing countries including Nepal interests and clearly contrary to the basic
principles of the PPP concept. There has been no competition under the negotiated procedure to extract
the best possible technical, commercial and contractual terms from the developers and power purchasers.
It is likely that the negotiated procedure will continue to be applied in the award of hydropower
concession contracts in Nepal also for the time being. Without external support, the contracting
authorities of Nepal lack the experience and funds to manage complex, competitive procurement
proceedings for larger hydropower projects. Also, it does not possess the credit rating, the legal
framework and other conditions necessary to attract qualified foreign developers willing to participate in a
competitive contest in the numbers needed for a successful competitive procurement process.
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SECTION 6: IPP Project Development Process
6.1 Objectives of IPP Project Development
The primary objectives of an IPP development process are to facilitate investments as quickly, efficiently,
reliably and beneficially as circumstances allow. Specific objectives of the development process are:
Maximize system efficiency (domestic) and GON revenues (export)
Minimize project cost, mitigate impacts and maximize GON benefits
Maximize certainty in operating dates
Assure construction quality standards
Allocate and manage risks effectively (see Table 1 for risks and risk sharing)
Maximize acceptance by lenders and guarantors
Apply effective governance to promote transparency in the development process and
equality among participants.
To achieve these objectives, the IPP project development process must be designed to account for
variations in:
The legal and regulatory framework in force at the time;
The institutional framework;
Type and size of the project;
Source of finance and securities;
Characteristics of a market in which the off-take from hydropower projects may be sold
into national or international markets, or both.
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Table 1: NORMAL RISK SHARING ARRANGEMENTS FOR HYDRO PROJECTS
RISK PRIMARY OBLIGANT
Hydrology
temporary deficits Usually PC, but sometimes access to GV funds. Insurable
long-term deficits GV/UT increasingly assuming this risk. Not insurable
flood damage (construction) Generally CO risk unless force majeure, or insurance
flood damage (permanent works) PC risk. Insurable
Construction Risk
Changes in quantities/cost overruns Depends on reason. Either CO, PC or shared
unforeseen ground conditions Increasingly borne by the UT or shared. Partly insurable
delayed completion Normally CO risk, but some exposure by PC
Performance Risk
equipment Plant supplier or turnkey contractor
project performance CO, and possibly PC
transmission Usually the responsibility of the UT
Environmental Aspects
permitting PC or, by preference, UT
land acquisition/resettlement GV/UT
EMP GV/UT
Market
market risk Usually UT through take-or-pay
dispatch Obligation and right of the UT
Force Majeure
continued debt servicing Generally obligation on the UT to maintain payments
rehabilitation costs Principal exposure on the UT (increased tariff) and insurers
Political
obligations of utility GV obligation often backed by political risk insurance
changes in law GV obligation often backed by political risk insurance
changes in tax GV obligation often backed by political risk insurance
non-sequestration/buyout obligations GV obligation often backed by political risk insurance
Financial
increase financing costs Generally passed to UT in the tariff, or absorbed by PC
exchange rate Generally passed to UT, backed by GV
cost escalation Usually reflected in tariff during construction and by limited
tariff escalation thereafter
Note: GV – Government, UT – Utility PC - Project Company CO – Contractor
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6.2 Stages in IPP Project Development
The way in which IPP projects are selected, prepared, finalized, and awarded will determine the extent to
which the objectives of the IPP program are met. IPP Projects should be developed in the following
sequential stages:
Investment decision
Financing decision
Procurement decision
Pre-selection of developer
Preparation of request for proposal and evaluation
Negotiation and award of concession
Post-award activities
An appropriate decision making process for hydropower project development, is outlined
diagrammatically in Figure 2 and is based on a simplified distinction between competitive and non-
competitive procurement models.
37
Figure 2: IPP Development Process
6.3 Investment Decision
6.3.1 Decision Process
The first step in the IPP project development cycle is to decide whether an investment should be made
and in which project. The investment decision is based on an economic analysis of project alternatives
using appropriate assumptions and parameters to facilitate fair comparison. IPP concessions may be
awarded for projects that provide demonstrable benefits to the economy and society and are consistent
with national planning. Any decision to invest should therefore follow a two-step process in determining,
firstly, which project out of a number of alternatives is the best investment and, secondly, whether the
favored project provides a return that justifies the investment taking into account alternative applications
of GON’s scarce resources. A decision to invest will follow where an economic analysis shows the
project is the best use of scarce capital and is likely to generate adequate returns.
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6.3.2 Selection of the Best Investment
The objectives of an IPP investment will vary depending on the perspective of the party, be it investor,
lender or government. A developer will, for instance, have a single-project, commercial focus whereas
GON will have a broader macroeconomic and program focus. GON’s investment objectives are optimal
generation augmentation (domestic off-take) and revenue maximization (export off-take). Selection of the
optimal project requires, amongst others:
Identifying projects in the context of the relevant optimal river basin development plan;
Sequencing and configuring projects for domestic supply according to least-cost
hydrothermal generation expansion principles;
Sequencing and configuring projects for cross border off-take according to GON revenue
maximization criteria.
Power system planning and project ranking studies should be periodically undertaken by the Government
and the choice of project to offer to the market should be consistent with the sequencing and timing of
projects set out in the updated editions of these studies.
6.3.3 Adequacy of Returns
It is not sufficient that a project is the best available; it must further be shown that the GON benefits
generated from the project are adequate. Although the private sector contributes most of the capital, the
public sector also has a considerable stake in an IPP project and should proceed only if the commitment
promises an adequate return. The public commitment includes:
Opportunity cost of site: The land and water resources tied up by the project may have
alternative uses, and the returns from these uses are foregone in the decision to develop the
project.
Risks are borne by GON: Many project risks are borne by GON, its agencies, IFI supporters
and local communities. The capacity of GON to cover project risks is not unlimited and the
decision to proceed with one project may imply an inability to support another.
GON share participation: GON’s decision to participate in the shareholding of the
ownership company may require the investment of significant capital.
In demonstrating that the investment is a justified application of GON’s scarce resources, it is necessary
to show that adequate EIRR are achieved.
6.4 Financing Decision
The investment decision is followed by a decision on the manner of the project’s financing. Financing
options include:
Public sector financing
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Private financing (BOT/BOOT)
Mixed public / private financing
The choice of financing plan is based on the most attractive realistic financing option. Factors to be
considered in designing an appropriate financing plan include:
Project characteristics (e.g. single or multi-purpose, type of impacts, nature of the
infrastructure services, specific cost of capacity and energy);
Cash flow projections and project financial performance;
Project risk profile and risk management strategies (e.g. insurance, risk transfer to EPC
contractor, political risk cover);
Security of revenue stream and creditworthiness of off-takers, particularly those on which
lenders will rely on for bankability;
Capital market characteristics (local and regional market liquidity, cost and availability of
equity and debt).
Extent of equity participation by GON and the likely source and cost of capital for GON’s
equity contributions.
To assist in the formulation of a financing strategy, spreadsheet financial modeling of the project should
be conducted to calculate cash flow projections and calculate financial performance indicators under
various financing assumptions.
6.5 Procurement Decision
6.5.1 General
Following the financing decision, a choice is made about the procedure of selection and engagement of
IPP to assist GON in developing the project. The method of selection and engagement of IPP takes into
account the size of project and whether it is publicly or privately financed:
Selection and engagement of IPP for publicly financed projects follows ICB / LCB
procedures, as appropriate;
Selection and engagement of privately financed projects is in accordance with the
Government Regulations, except as otherwise provided in the following section 6.5.2.
6.5.2 Selection and Engagement of IPP for Privately Financed Projects
The methods of selection and engagement, and the conditions for their use are outlined below:
(i) Open Competitive Procedures for IPP Procurement
(ii) Alternative Method of Procurement
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(iii) Unsolicited Proposals
6.5.2(i) Open Competitive Procedures for IPP Procurement
The Government Regulation proposes open competitive bidding as the general procurement method for
IPP projects. The procedure is outlined in Section 8.0.
6.5.2(ii) Alternative Methods of Procurement
The Government authority may use selection and engagement procedures other than open, competitive
bidding where the approval of GON is obtained. The procedures may include:
Restricted competitive procurement procedures– Restricted competitive procurement
differs from an open competitive procurement procedure only in that pre-selection is
restricted to invited applicants.
Two-stage procedure– For complex projects where it is not possible to describe in
sufficient detail in bidding documents the characteristics of the project (technical
specification, financial arrangements, contractual terms), the contracting authority may
engage the market through a two-stage procedure as described in Section 9.0.
Negotiated procedure – The negotiated procedure involves the direct negotiation of a
concession with a developer that has met pre-selection standards. The negotiation process
involves the progressive negotiation of MOU, PDA and concession agreement as the
developer undertakes increasingly detailed studies of the project as further described in
Section 9.4.
6.5.2(iii) Unsolicited Proposals
The contracting authority is authorized by the Government to consider unsolicited proposals if it
considers the proposal to be in the public interest. The procurement procedures for unsolicited proposals
are described in Section 10.0.
6.6 Pre-selection of Developer
The next step in the project development process is the selection of a developer. For all procurement
procedures permitted under the Government Regulations, including the unsolicited proposals procedure, a
pre-selection process is involved. Pre-selection requirements for each method of procurement are
discussed further Section 7.0.
6.7 Project Preparation to Seek RFP from IPP
Reputable investors will be attracted by the promise of a well-defined project and an orderly, transparent
award procedure. The objective of project preparation is to provide bidders with the information they
need to: (i) estimate costs and revenues; and (ii) to assess risks. Better prepared projects encourage tighter
bidding contests, smaller contingencies and a shorter procurement period. Preparations may include some
or all of the following:
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Site selection according to national power plans and off-taker requirements;
Investigations and studies to determine site characteristics, including:
- Hydrology – long term mean monthly flow and flood frequency estimates;
- Topography – head, reservoir storage characteristics and other inputs;
- Geology – project layout and preparation of project cost estimates;
- Social and environmental effects – impact studies and management plans and
costs;
Preparation of bid documentation and particular conditions for model agreements;
Off-take terms and conditions (determined in consultation with export and domestic
offtakers);
GON and IFI support (e.g. exemptions, incentives, guarantees);
Site preparation (e.g. permits and approvals, resettlement, UXO) and infrastructure (e.g.
coordinated development of transmission).
Eligibility for carbon credits;
GON may not have the resources to progress project preparations to an advanced stage and the
Contracting Authority may therefore not be in a position to define in the bidding documents the
characteristics of the project in a manner sufficiently detailed and precise to permit final bids to be
formulated. The Contracting Authority may also be unable to assess what the market can offer in the form
of technical or financial solutions. To accommodate this situation, the following procedures may be
considered:
(i) Within a competitive bidding procedure:
The Contracting Authority in the pre-selection documents may ask Bidders to submit an outline proposal
indicating the Bidders’ technical and financial solutions to meeting specified objectives or functional
requirements of the project. The Contracting authority may then discuss the outline solutions with each
pre-selected Bidder to clarify those best suited for the IPP Hydropower project. The Contracting
Authority can then draw on these solutions to prepare the final terms of the bidding documents and invite
pre-selected bidders to submit a formal bid. During the dialogue the Contracting authority may not
disclose to other Bidders the outlined solution proposed or any other confidential information given by
Bidders. The Contracting Authority shall prepare minutes of any such discussions and submit them to the
Monitoring Authority as part of the formal record of procurement proceedings.
(ii) Within a non-competitive procedure:
Under a negotiated procedure, a sole mandate in the form of an MOU may be given to a developer
without the need to define the project characteristics to the same level of detail. There are, however,
disadvantages in this approach:
GON is reliant on studies financed, managed and executed by the developer for its
understanding of the project;
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The front-end development time and cost may deter reputable developers;
GON becomes committed to a developer and to a project before it knows much about
either.
6.8 Solicitation, Negotiation and Award of Concession
The process of soliciting and obtaining proposals, evaluating them, negotiating deviations and awarding
the concession contract should follow the procedures outlined below:
For an open, competitive bidding procedure, the process is described in Section 8.0;
For a restricted, competitive bidding procedure, two-stage procedure and negotiated
procedure, the process is described Section 9.0;
For an unsolicited proposal procedure, the process is described Section 10.0.
Irrespective of the procurement model used, negotiation plays a role in bridging differences between
parties’ expectations. The negotiations involving GON agencies primarily involve the following
agreements:
Concession Agreement (and in the case of negotiated procurement procedures, its
precursor, the Project Development Agreement);
PPA with the project’s export off-taker – GON agencies are involved in government-to
government negotiations on the wholesale tariff to be paid by the foreign off-taker for
output delivered by the Company;
PPA with concerned Government Agency for domestic off-take – Concurrent with the
Company’s negotiations with the foreign off-take.
6.9 Post-award Activities
A special feature of competitive bidding for PPP projects is the number of activities that must take place
after the award of the concession to the successful bidder and prior to the final execution of the
Concession Agreement (or the unconditional validity of that contract). The award and execution of the
Concession Agreement for projects with an installed capacity exceeding 50 MW(?) will require approval
by the National Assembly. Other post-award activities may include:
Establishment and registration of the project company (which shall be a signatory party
to the Concession Agreement);
Arrangement of equity contributions or equity commitments;
Achievement of approvals and permits required by the law of the country;
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Requisition of project land;
Finalization of a number of project agreements; and
Achievement of financial closing.
The post-award activities must be performed within a certain period following the award and prior to the
final execution of the Concession Agreement as a condition for the sustained validity of the award and the
release of the bid security.
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SECTION 7: Pre-selection of Developers 7.1 Mandatory Pre-selection
Preparation of bids for concession contracts for hydropower projects is costly and time consuming and
this discourages competent developers from participating in the bidding proceedings unless the
proceedings are based upon a shortlist of prequalified bidders, comprising three or four applicants at
most. There is a consistent need for pre-selection in IPP projects to eliminate unsuitable applicants early
in the procurement proceedings. Competent developers may be reluctant to participate in expensive
procurement proceedings for IPP projects if they risk competing with unrealistic proposals submitted by
unqualified bidders. Therefore, the pre-selection of eligible developers for IPP projects in desirable:
7.1 (i) Competitive Procurement
Procedures for pre-selecting bidders for open competitive bidding are presented below. A competitive
bidding procedure will be preceded by a general invitation to parties to express interest in submitting an
application for pre-selection.
7.1 (ii) Alternative Methods of Procurement
Pre-selection (or the achievement of pre-selection standards) is required for procurement by:
Restricted competitive procedure
Two-stage procedure
Negotiated procedure
7.1 (iii) Unsolicited Proposal
If the Government decides to implement a project proposed through an unsolicited proposal, a developer
selection procedure shall be conducted including pre-selection process.
7.2 Invitation to apply for Pre-selection
An invitation to apply for pre-selection is advertised and is issued by GON. Parties responding to the
invitation to submit applications for pre-selection will be provided with a pre-selection document.
Applicants may seek clarification of the pre-selection documents.
7.3 Participation of Consortia
Bidders are allowed to participate in procurement proceedings through consortia established especially for
the project. A consortium is better able to meet particular challenges of larger IPP projects because it can
better accommodate:
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The heavy financing requirements of large infrastructure projects;
The need for broad expertise in financing, developing and operating projects;
Project risks by diversifying them among consortia members.
7.4 Pre-Selection Criteria
Applications for pre-selection will be evaluated according to the criteria stated in the pre-selection
document. Parties eligible for IPP concessions shall have access to finance and technical expertise in
power projects and shall be of good repute and have a sound commercial background. The minimum
criteria to be met by applicants may include:
Adequate professional and technical qualifications and experience, human resources,
equipment and other physical facilities as necessary to carry out all the phases of the
power generation project, including design, construction, operation and maintenance;
Sufficient ability and experience to manage the financial aspects of the power generation
project and capability to sustain its financing requirements;
Appropriate managerial and organizational capability, reliability and experience,
including previous experience in operating similar power generation projects.
The Pre-selection Document should define these minimum pre-selection criteria in an objective manner to
facilitate objective assessments and comparisons of applications.
7.5 Decision on Pre-selection
The contracting authority evaluates pre-selection applications and makes a decision about the
qualifications of each applicant based solely on the stated pre-selection criteria. The contracting authority
may, provided it has made the appropriate statement in the pre-selection document, reserve the right to
request bids only from a limited number of bidders that best meet the pre-selection criteria.
7.6 Post-qualifications
During such long procurement proceedings the qualifications of pre-selected bidders may change.
Therefore, most PPP-related Invitation- to- Bids provide the Contracting Authority with a right to require
at any stage of the procurement proceedings that the bidders again demonstrate their qualifications in
accordance with the same pre-selection criteria applied to the earlier pre-selection.
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SECTION 8: Solicited IPP Bids under Open/Competitive Procedure
The private sector will be encouraged to undertake commercially viable hydropower generation projects
as Independent Power Projects (IPPs) for export of electricity and for sale of electricity to the national
grid through the following two processes:
a. Solicited Bids
b. Unsolicited Bids
These processes are described in detail below.
8.1 Process for Solicited IPP Bids (Proposals) Proposals for grid-connected power generation projects at preselected sites may be solicited by the
Government Agency through public advertisement. These may include sites/projects for which feasibility
studies have already been completed in the public sector, as well as ‘raw sites’ not yet fully investigated.
Such projects will be processed according to the steps and schedule given in Table 2.
Table 2: Processing Schedule for Solicited Projects
Activity Typical
Allowance
(Days)
a. Prequalification of bidders for specific projects at sites
identified by the Government Agency, which shall invite
sponsors for registration and for collection of
prequalification documents through public advertisement 30
b. Submission of prequalification documents by sponsors to the
Government Agency 30
c. Evaluation of prequalification documents and notification of
prequalified bidders by the Government Agency 15
d. Requests for proposals (RFPs) from prequalified bidders issued
by the Government Agency and collection of bidding 30
e. Submission of bids to the Government Agency, together with bid
bond and evaluation fee 90
f. Evaluation of bids by the Government Agency, including
preliminary tariff determination, and notification of successful
bidder 30
g. Posting of Performance Guarantee by successful bidders 15
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h. Issuance of Letter of Support (LOS) by the Government
Agency after determination of final tariff 7
i. Issuance of Generation License and Tariff Determination by
Government Agency 15
Note: The above are indicative time allowance for processing period.
For new project sites (raw project sites), the relevant data, location, and other preliminary information
will be made available to investors and Expressions of Interest (EOI) invited. The bidder ranked highest
in the prequalification process shall be awarded an LOS for the corresponding project.
For sites for which feasibility studies may have been completed prior to bid solicitation, specific tender
documents will be prepared and bids will be invited for the sale price of electricity (against Government’s
indicative tariff as a benchmark, using the same parametric formulation to allow for a standardized
comparison basis). The successful bidder shall be awarded an LOS to help achieve financial close. The
schedule of activities leading to issuance of LOS, are also given in Table 2. In order to further economize
processing time, steps ‘a’, ‘b’ and ‘c’ in Table 2 may be eliminated and instead sponsors may be asked,
through advertisement, to submit their proposals in two envelopes. The first envelope would be meant for
evaluating the bidders’ qualifications and the second envelope for the main commercial bid. In such a
case, the commercial bids (second envelope) only of qualified bidders will be opened, and the maximum
time allowance for activity ‘e’ may be increased to 100 days.
8.1.1 Request for Proposals
The RFP for solicited projects shall contain all project specifications, components, and requisite details
necessary for the preparation of a proper technical and commercial bid. The documents will also explain
the evaluation criteria to be employed in scoring the bids. If necessary, a pre-bid conference may be held
by the Government Agency to facilitate exchange of information with qualified sponsors, giving equal
and adequate opportunity to all prospective bidders to seek clarification on project requirements.
8.1.2 Bid Bond, Letter of Support, and Performance Guarantee
A Bid Bond based on the project’s installed generation capacity shall be required from each bidder at the
time of submission of bids. After selection of the successful bidder, the bid bonds of all bidders other than
the sponsors of the successful bid shall be returned, and the successful bidder will be required to post a
Performance Guarantee based on project capacity in favor of the relevant Government Agency for
issuance of a Letter of Support (LOS), and which shall be valid initially for a period of three months in
excess of validity of the LOS. After submission of the Performance Guarantee by the successful bidder,
the Bid Bond shall be returned and the LOS issued to enable the project to achieve financial close. Until
financial close is achieved, the LOS shall govern the project and supersede all other documents and
agreements.
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The Performance Guarantee will secure the successful bidder’s obligations to execute the IA, PPA, and
other relevant agreements and achieve financial closure within the specified time period. In addition, the
sponsor may also be required to reimburse the cost of feasibility study utilized (if so indicated in the
bidding documents). The Performance Guarantee shall be in the form of an irrevocable, direct-pay letter
of credit, issued by a scheduled local or foreign bank acceptable to the Government of Nepal, in favor of
the relevant Government Agency. The Performance Guarantee must always remain valid for a period not
less than three months in excess of the then-prevailing financial close deadline. If the Performance
Guarantee is not furnished within the specified period, the LOS shall lapse automatically, and neither the
sponsor nor the project company shall have any claim for compensation or damages against the
Government of Nepal or any of its organizations, provinces, or institutions on this account.
8.2 Process Subsequent to Issuance of LOS
After the issuance of the LOS to sponsors of solicited IPP projects, the sponsors will be expected to carry
out the following activities:
i. Sign the Implementation Agreement (IA) and a Certified Emission Reduction
Agreement (CERA), with the Government Agency acting on behalf and with the
permission of the GON, and the Power Purchase Agreement (PPA) with the
power purchaser.
ii. Achieve financial close (as defined in the IA or PPA)
iii. Achieve construction start (as defined in the IA or PPA)
iv. Execute and commission the project according to major milestones established in
the LOS.
In case of default or departure from agreed milestones by project sponsors, the Government Agency shall
have the right to terminate the LOS and en-cash the sponsors’ Performance Guarantee upon issuance of
due notice assigning reasons for such action and after provision of sufficient opportunity for the redress al
of such default. However, if the delay is caused by actions of the power purchaser or by the government,
then the IPP shall not be penalized. Upon financial close, the security agreements (IA and PPA) will
supersede the LOS and all other documents and agreements. If the LOS expires, the IA and PPA and all
other agreements with any governmental entity shall automatically terminate.
The investor, after receiving the LOS, will be required to submit to the relevant Government Agency; on
a format specified by the agency, a mutually acceptable implementation schedule with specific milestones
for progress monitoring. The Government Agency shall execute the project’s Implementation Agreement
(IA) on behalf of the Government, whereas the Power Purchase Agreement (PPA) will be executed
between the IPP and the buyer upon GON’s formal approval.
8.3 Security Package and Risk Cover
The security package for IPPs will comprise of the following:
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i. Implementation Agreement (IA), Power Purchase Agreement (PPA), Certified
Emissions Reduction Agreement (CERA), and Water Use Agreement (WUA), as
applicable.
ii. GON guarantee on payment obligations of public sector entities. If some or all of
the utilities are restructured or privatized during the term of various agreements,
appropriate safeguards shall be built in the privatization agreements so that the
IPP contracts are wholly securitized over their respective full terms.
iii. Provide protection against specific ‘political’ risks.
iv. Provide protection against changes in the tax and duty regime.
v. Ensure convertibility of Nepalese Rupees into US Dollars at the prevailing
exchange rate and the remit ability of foreign exchange to cover necessary
payments related to the project, including debt servicing, payment of dividends,
and repatriation of equity.
vi. Specific risk cover against hydrology resource variability as detailed in
Annexure A.
vii. Suitable indexation of tariff components to cover the risk of exchange rate
variations and inflation, etc.
8.4 Corporate, Fee, and Contractual Arrangements
8.4.1 Fee Structure Fees are to be paid by sponsors of IPPS to the Government Agency as indicated in Table 3 below. All
fees are subject to revision from time to time.
Table 3: Fee and Financial Charges for Grid-Connected IPPs
Activity Fee (US$) Remarks
a. Registration 100 The Govt. will
provide an information
package upon
registration
b. Prequalification
Purchase of
prequalification
Documents 500
c. Bidding The RFP by
Purchase of the RFP 1,000 prequalified
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bidders shall also
include the feasibility study, where relevant, and standard, IA, PPA,
etc., as applicable
d. Project facilitation and
evaluation expenses for
projects registered
with the AEDB/Provincial
Government:
≤ 5 MW 1,000
> 5 MW to 20 MW 5,000
> 20 MW to 50 MW 10,000
> 50 MW 20,000
e. Bank Guarantee for issuance
of Letter of Intent (LOI) by
Government:
Solicited projects 500/MW nameplate
capacity or bid bond
specified
Unsolicited projects 500/MW nameplate
capacity
f. Reimbursement of public As determined by Payable prior
sector feasibility study Government to issuance
cost, if applicable. of LOS based
on costs
incurred,
up to
maximum
ceiling
Reimbursement of private As per cost
Sector feasibility cost, ascertained by
if applicable Govt. from
relevant A/C.
g. Performance Guarantee for Payable upon
issuance of Letter of approval of
Support(LOS) by Government: power purchase
Tariff by Govt.
Solicited projects 2,500/MW capacity
Unsolicited project 2,500/MW capacity
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h. Legal fees Subject to a cap of US$ 100,000 for projects
above 50 MW, US$ 50,000 for projects in
the range of 6-50 MW, US$ 20,000 for
projects in the range of 1-5 MW, and no
charge for projects of capacity below 1 MW
Note: Upon financial close, the IPP will provide a letter of credit to the power purchaser as
performance guarantee as specified in the PPA (US$3/kW per month), subsequent to which the
original Performance Guarantee furnished at the time of issuance of the LOS shall be released.
8.4.2 Enterprise Structure and Licensing Requirements Each IPP setting up a plant meant only for supplying power to the utility grid and for export will be
required to form a company in accordance with the laws of Nepal under the Companies (Ordinance ?,
19??), for the specific purpose of power generation and obtain a generation license from the concerned
Government Agency. However, producers who wish to establish plants which are not exclusively for sale
to power utility (e.g., captive or dedicated plants with or without grid spillover provision) may not form
such a special purpose company. Small producers of installed capacity less than or equal to 5 MW not
connected to the grid (i.e., standalone captive or isolated local distribution) shall not be required to form a
special purpose company or obtain a generation license from the Govern, but would be required to
register with the Government Agency and obtain consent from the local administration as per prescribed
procedure.
8.4.3 Lock-in Period The ‘Main Sponsor’ (defined as the individual or group holding at least 20% equity in the IPP project),
together with other initial project shareholders, must hold 51% of the project equity for a period up to the
project’s Commercial Operations Date (COD).
8.4.4 Type of Contracts IPP projects for sale of all power to the grid system or for export may be implemented through either
‘Build, Own, and Operate’ (BOO) and ‘Build, Own, Operate, and Transfer’ (BOOT) contracts between
the parties concerned, valid for a period of not less than 20 years. For the other type of projects, no such
contracts shall be required. Instead, for captive, dedicated, or grid spillover projects, or projects availing
of ‘net billing’, ‘wheeling’ or ’banking’ facilities, separate contractual arrangements will be required
between the parties dealing with matters such as metering, maintenance of interconnection, system
protection, and billing of net sales and purchase, wheeling, and banking charges/tariffs, etc.
8.4.5 Nature of Equipment
Projects which are meant for generating electricity for the sole purpose of supply to the utility grid
system, i.e., grid connected IPPs will be required to use new equipment. There shall be no such restriction
on other producers.
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8.5 Determination of Tariff for Grid-Connected IPPs
Guidelines for determination of tariff for power generation projects selling all electricity produced to the
utility are given in Annexure A.
8.6 Competitive Bidding Process
Open competitive procedure is the applicable procurement option unless approval of the
Government is obtained to use an alternative procedure. The steps of the open, competitive procedure are
illustrated in simplified form in Figure 3(a):
Pre-selection of bidders;
In case of complex generation projects (larger IPP projects) the Contracting Authority may -
under specified conditions - conduct a technical dialogue with the pre-selected bidders to
clarify the means and solutions best suited to meet the project needs and requirements;
Prepare and issue bidding documents;
Clarifications and modifications to the bidding documents;
Bidders option to undertake further site investigations;
Preparation of proposals by bidders;
Submission of proposals;
Opening, examining, evaluating and ranking proposals by the contracting authority;
Bid award and notification of award;
Proceedings after the bid award.
Open competitive tendering is effective in obtaining the best offer on price and risk for the project but
will succeed in this only if project is adequately defined and bidders compete equally under the bidding
rules. In addition to the steps specified above, other matters to be considered by the contracting authority
in conducting the solicitation are:
Completion of project preparation activities (refer Section 6.7) and preparation of a
comprehensive package of bidding documents (refer Section 8.3).
Decision by GON on its intended shareholding in the project, its proposed terms and conditions
under the shareholders’ agreement, and proposed sources of capital to fund its equity.
Decision by GON on state support, including, if appropriate, the support of an agency (ADB/WB)
offering political risk cover.
Consultations with the export power purchaser to: (i) reach agreement on tariff and PPA, (ii)
obtain approval of pre-selected bidders, and (iii) other matters of mutual interest
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Figure 3: Procurement Procedure
Note: Procedural steps are simplified to highlight differences between procedures. In practice,
procedures would need to accommodate intermediate steps and involvement of third parties such
as off-takers (foreign and domestic).
8.7 Off-taker Involvement in Bidding Procedure
For export projects, the foreign off-taker is interested in all matters, technical and commercial, related to
the delivery of the foreign off-take portion of the project’s output. The involvement of a foreign power
purchaser introduces a third party into the project preparation, bid evaluation and negotiation processes.
Pre-agreement on a draft PPA (including tariff) in advance of solicitation would minimize three-way
discussions during bid negotiations. The draft PPA would be included in the RFP package and the export
tariff would in this way be fixed for the purposes of the bid. Evaluation of price attributes of bidder’s
proposals would therefore be based on the discounted value of tendered royalty payments.
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In the event that bidders indicate deviations to the draft PPA in their proposals, the foreign off-taker
would be involved in their negotiation and resolution. A Model PPA (and tariff) would be included in the
RFP to alert bidders to the price and terms applying to the project’s off-take.
8.8 Bidding Documents for Inclusion in Request for Proposals
The bidding documents for procurement of IPP hydropower projects should be prepared and assembled
according to the characteristics of individual projects. The bidding documents would typically comprise
the following:
Bid document (Instructions to Bidders),
Model Concession Agreement
Draft PPA for export off-take
Model PPA for domestic off-take
Minimum Technical Requirements of the Facility (functional specification)
Grid codes for the systems of the foreign power purchaser and domestic purchaser
Project Information, including feasibility studies, interconnection studies, environmental and
social impact / management studies, etc.
The Bid document provides bidders with information about the project, instructs them on the content of
their technical and financial proposals and specifies the format in which their proposals are to be
presented. The contents include:
Invitation to Bidders
Project Description and General Information
Instructions to Bidders
Evaluation Procedure
Minimum Technical Specification, Schedule and Performance Requirements
Proposal Forms, including proposal letters, clarification forms, form of bid security, technical
proposal forms and financial template.
Technical specifications for the projects are formulated either in terms of performance or in functional
requirements, leaving the technical details of how and by what means these requirements shall be
achieved to the experience and innovative skills of the bidders.
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8.9 Evaluation of Bids and Ranking of Bids
8.9.1 Bids Evaluation Process
In the hydropower sector, most projects are awarded through a process called bidding. While the idea is
generally to choose the lowest bidder, the process is rarely that simple. The bid reviewer must examine a
variety of factors to ensure the bids are evaluated accurately and fairly.
8.9.2 Bid Evaluation Committee
The Contracting Authority should establish a Bid Evaluation Committee (BEC) consisting of experts
from each profession (technical, financial, legal, costing, environmental, resettlement, social aspects, etc).
8.9.3 Committee Members Experience and Qualifications
The Committee must have the following experience and qualifications:
I. Be familiar with Nepal’s existing energy sector policy, legislation, regulations,
Electricity Act and the amendments, and electricity market, and Nepal’s current
electricity market place, etc.
II. Be thoroughly familiar with the Request for Proposals process and the template RFP used
for project.
III. Have a working knowledge of Power Purchase Agreements and specific understanding of
the Concession Agreements.
IV. Have strong technical understanding to evaluate different electricity projects and
technologies including, but not limited to hydropower.
V. Have strong understanding of project economics, including system impacts,
interconnection costs and have the ability to evaluate the economic merits of a proposal
as required to choose a successful bid(s).
VI. Have sufficient experience in bids evaluation, and in responding to all questions and
concerns in a timely manner.
8.9.4 Committee Members Responsibilities and Duties
The BEC is responsible to conduct the RFP process in a fair and transparent manner. The BEC will
evaluate the proposals and select successful bid using the evaluation criteria as outlined below in this
document. The BEC will inform the Government (MOE/DOE) of its findings. If authorized by the
Government, the BEC will inform all bidders the results of the process through written correspondence
within one week of the decision.
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8.9.5 Evaluation of Bids and Their Ranking
The process for the evaluation of bids is outlined below:
1. It is possible to receive a large number of proposals (bids), may be half-dozen or
more. Work with one bid at a time to help stay focused.
2. Start with pricing. If one bidder is very much higher or very much lower than the
others, these bids can usually be eliminated fairly quickly.
3. Check bids responsiveness in project scope as outlined in RFP.
4 Check if any specific project conditions are included. This may include payment or
performance bonds, or special facility, such as security protection, special tax
exemption etc. Any of these factors could impact a bid price significantly.
5. Determine whether each bidder is capable of meeting the project's schedule. Some
bidders (companies) may not have the man-power, or may be too busy with other jobs
to give your project the attention it needs per your schedule.
8.9.6 Typical Bid Evaluation Criteria
The typical bid evaluation criterion is presented below:
Criteria Points
a. Sponsor Experience xxx
(i).
(ii).
(iii).
b. Organizational Structure
(i). total Staff
(ii).Staff Assigned to project
(iii).Qualification & Experience
c. Technical Capacity
d. Financial Position of Company
(i).
(ii).
e. Past Experience
(i).No. of project completed
(ii).No. in Developing Countries
(iii).Completion Time (Delays)
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f. Environmental Mitigation Measures
g. Social Considerations/Mitigation
h. Project Cost Estimates
i. Implementation Plan
(i). Manpower Plan
(ii).Expat Labor
(iii).Domestic Labor
j. Financing Plan
(i).Structure
(ii).Consortium Participation
(iii). Debt Financing
(iv).Debt Maturity Period
(v).Equity Contribution
(vi).Source of Equity Financing
(vii).Free Electricity to Gov.
(viii).Tariff Structure
All responsive bids are evaluated. Evaluation of bids is conducted according to the evaluation process
described in the bidding documents. The relative weight of individual criteria, and weighting of price and
non-price criteria, is specified in the bidding documents. The contracting authority may establish
thresholds for acceptance of quality, technical, financial and commercial aspects. The contracting
authority ranks responsive bids according to the scores achieved and invites the highest ranked bidder to
negotiate the concession contract.
8.10 Negotiation and Award
Before an award can be made, any deviation in the bid, which does not result in rejection
of the bid, must be resolved by negotiations. The complexity and phase by phase development of IPP
projects makes negotiations between the Contracting Authority and the preferred bidder a practical
necessity and some scope for negotiations before the award of concession contracts is therefore
acceptable.
Any deviations to contractual terms listed in the bidding documents as non-negotiable shall be regarded
as material and grounds for rejection of the bid.
If it becomes apparent that negotiations with the invited bidder will not result in a successful outcome,
the contracting authority can terminate negotiations, allowing the bidder to formulate its best and final
offer. If such offer is unacceptable, the contracting authority shall invite for negotiations other bidders in
the order of their ranking until it arrives at an award or a rejection of all bids.
When an acceptable proposal is negotiated, the agreed concession contract is initialed with the successful
bidder and will be binding on the parties subject to the approval of the National Assembly. The
contracting authority will notify the unsuccessful bidders of the award.
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8.11 Post-Award Proceedings .
In the period between initialing the concession contract and final execution, the successful bidder shall:
Provide the Contracting authority with all requisite applications, requests and
documentation for obtaining the approvals, licenses and permits listed in the bidding
documents to allow the project company to be established and commence construction;
Establish and incorporate the project company;
Ensure that the project company has binding commitments with respect to equity
contributions from all shareholders;
Provide a performance bond from an eligible bank in the required amount and form;
Achieve Financial Closing, except with regard to those conditions which can only be
satisfied on or after the execution of the Concession contract; provided that each such
outstanding condition is satisfied within seven??? (7????) days after the execution of the
Concession contract.
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SECTION 9: Alternative Methods of IPP Selection and Engagement
9.1 Authority to use Alternative Methods of Procurement
The contracting authority may use procurement methods other than an open, competitive procedure as
approved by the Government, and subject to the requirement that it takes all necessary steps to ensure
compliance with the principles of transparency, fairness and equality of treatment. Alternative methods of
IPP selection and engagement permitted are:
Restricted competitive procedures
Two-stage procedure
Negotiated procedure
These are discussed below.
9.2 Restricted Competitive Procedure
Subject to approval of the Government, the contracting authority may finalize concession contracts
through a restricted, competitive procedure. A restricted competitive procedure will be approved if, by
reason of the project’s scope or complex nature, it can only be developed by a limited number of
developers.
The restricted, competitive procedure is illustrated in simplified form in Figure 3(b). The procedure is the
same as for the open, competitive bidding in all respects, accept that pre-selection is open only to bidders
selected and invited by the contracting authority. The contracting authority is obliged to invite a sufficient
number of bidders to ensure effective competition.
9.3 Two-Stage Bidding Procedure
It is a key condition for transparent and competitive procedures that the characteristics of the project are
defined in a manner sufficiently detailed and precise to permit the bidders to formulate final bids and the
Contracting Authority to compare the bids in an objective manner. With complex projects, however, the
Contracting Authority may be unable to assess in advance the most economically advantageous solution
for the country. In such cases it may be appropriate to permit the contracting authority to employ a two-
stage bidding procedure.
Subject to approval of the Government, the contracting authority may undertake the finalization of
concession contracts through a two-stage procedure. A two-stage procedure will be approved where it is
not feasible to describe in the bidding documents the characteristics of the project and terms of the
concession in sufficient detail and precision to permit final and binding bids to be formulated.
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The two-stage procedure is illustrated in simplified form Figure 3(c). The procedure involves the
following steps:
1. First-stage call for proposals from pre-selected bidders based on an initial RFP describing the
owner’s requirements, performance indicators, financing requirements and principal
contractual terms;
2. Meetings with bidders convened by the contracting authority to clarify matters concerning
the initial RFP or the proposals submitted in response to it;
3. Review and revision of the initial RFP by the contracting authority in the light of the concepts
presented by bidders in their initial proposals;
4. A second-stage call for final proposals based on the revised RFP;
5. Evaluation of the final proposals and ranking of bidders accordingly.
In other respects, the requirements for open competitive bidding also apply to a two-stage procedure.
9.4 Negotiated Award Procedure
9.4.1 Conditions for use of Negotiated Procedure
Flexibility is needed in the procurement of IPP projects. Where a project is complex, information about it
is limited, and time and budget constrain public sector preparatory work, the only practical avenue open
to GON may involve a negotiated award of the project concession.
The Contracting Authority may use a negotiated procedure for awarding concession contracts if the
approval of the Government is obtained and one or more of the following conditions is satisfied:
The need to complete the project is urgent (provided that the circumstances giving rise to the
urgency were neither foreseeable nor caused by the Contracting Authority’s slow response);
A pre-selection process was conducted but the response was poor and time does not permit a
new invitation;
The offered concession follows naturally on from an earlier concession and it is cost-effective
to seek continuity in the concessionaire;
Extensive preparatory work is needed to define the project sufficiently for firm bids to be
prepared for which budget and time is not available;
When a negotiated approach otherwise serves the public interest.
9.4.2 Procedural Steps in a Negotiated Award
A negotiated IPP procurement procedure involves negotiating successive mandate agreements of
increasing commitment and detail as the parties’ understanding of the project grows. As prefeasibility and
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feasibility studies are completed, and as tariff MOUs and PPAs are negotiated, a firmer foundation is
created for upgrading mandates from MOU to PDA and from PDA to Concession Agreement.
The negotiated procedure is illustrated in simplified form in Figure 3(d). The steps to be taken by the
contracting authority are outlined below.
1. Confirm that the project is consistent with optimal development of the power system;
2. Confirm the developer’s eligibility according to the prevailing pre-selection criteria;
3. Execute an MOU (and provide an MOU-bond) granting a mandate for a defined period to
undertake stipulated studies;
4. Reach agreement with the foreign off-taker on tariff and principal sale and purchase terms
and conditions, and execute a formal tariff agreement;
5. Upon satisfactory completion of obligations under the MOU, execute a PDA that extends the
mandate and sets out activities to be undertaken to advance the project’s readiness for
financing;
6. Submit to the developer the model concession contract with non-negotiable and particular
conditions demarcated;
7. Establish transparent evaluation criteria by which the adequacy of the developer’s proposal is
assed;
8. Negotiate and initial the concession agreement and publish a notice of its essential terms;
9. Finalize and execute the PPA (and provide a PDA-bond) for foreign off-take and the PPA for
domestic off-take;
10. Establish and incorporate the Company under Nepal law;
11. Arrange permits, consents and approvals as listed in the Concession Agreement;
12. Finalize debt and equity financing for the project and close loans;
9.4.3 Transparency in Negotiated Procedures
To improve transparency, competition and quality in the procedures for negotiating IPP concessions, the
general requirements of the international procurement principles are:
MOUs only issued for projects identified and scoped to meet the objectives of optimal
national planning;
MOUs only issued to developers achieve minimum pre-selection standards;
Developers to demonstrate their seriousness (and protect Nepal authorities against economic
loss in the event of their breach of contract) by providing MOU and PDA securities;
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Issuance of MOUs and award of concession contracts to be publicly advertised;
Transparent and competitive evaluation criteria to be established, as thresholds for evaluating
negotiated terms and conditions. Such criteria to be disclosed to the developer;
The contracting authority to take the lead in negotiating the concession contract by submitting
to the developer a model concession contract with non-negotiable and particular conditions
demarcated;
Major contracts for engineering, procurement and construction of the project facilities to be
awarded by transparent and competitive procedures based on international competitive
bidding principles;
Project development under the PDA shall follow the structured and transparent process; and
The Contracting Authority shall keep an appropriate record of the negotiated procurement
proceedings, to promote transparency and public accountability.
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SECTION 10: Unsolicited IPP Proposals
10.1 Admissibility of Unsolicited IPP Proposals
Where a developer submits a proposal to GON for the development of an IPP project in respect of which
no public procurement process has been opened, the contracting authority with the approval of the
Government is permitted, to consider the unsolicited proposal provided that it is in the public interest.
10.2 Selection and Engagement Procedure for Unsolicited IPP
Proposals
The procurement procedure to be followed by the contracting authority for unsolicited proposals is
illustrated in simplified form in Figure 3(e). The steps involved in an unsolicited proposal procedure are
outlined below, with additional steps included to account for off-take negotiations:
1. A project proponent submits a proposal which does not relate to a current selection procedure
initiated by GON. The unsolicited proposal is received by, or referred to, the contracting
authority.
2. The contracting authority assesses the proposal for consistency with public interest, and
consistent with GON’s power development plans and the potential benefits it would yield to
Nepal.
3. If the project is considered to be in the public interest, the contracting authority, with the
approval of the Government invites the proponent to submit as much information on the
project as is feasible at that stage. This will include a concept design, an economic feasibility
study and an EIA including social aspects.
4. The contracting authority evaluates the project’s technical, financial and economic attributes
and the proponent’s qualifications to determine whether implementation of the proponent’s
proposal is likely to be successful.
5. If the Government decides to implement the project, it arranges through the appropriate GON
agency to open up formal negotiations with the foreign power purchaser and to conclude
agreement on tariff and draft PPA. Parallel discussions could also take place to determine
price and conditions applying to domestic off-take.
6. The contracting authority initiates a selection procedure in accordance with the open
competitive procedure. It prepares bidding documents based on the proponent’s proposal and
studies, and on the outcomes of the power purchase negotiations. The scope of the bidding
documents is as discussed in Section 8.9.
7. The proponent is invited to participate in the selection procedure and may be given an
incentive or benefit in recognition of the proponent’s role in developing the proposal. Any
such incentive or benefit is declared in the bidding documents.
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8. Proposals are evaluated in accordance with the evaluation procedure set forth in the bidding
documents and bidders are ranked according to their evaluation score. The proponent’s
ranking will reflect any incentive or benefit it receives.
9. The top-ranked bidder is invited to negotiate to resolve any deviations from the bidding
documents included in the invited bidder’s proposal. If it becomes apparent during the course
of these negotiations that the negotiations are unlikely to be successful, the negotiations are
terminated and the next bidder in the rankings is invited to negotiate.
10. Upon successful conclusion of negotiations, a concession agreement is initialed. Progress to
financing and formal award of the concession agreement is as for other procurement
procedures.
10.3 Process for Unsolicited Proposals
Potential sponsors of IPP projects to be connected to the utility grid at a location of their choice (‘raw
site’), may submit their proposals to the Government Agency on an unsolicited basis. The schedule of
activities leading to issuance of Letter of Intent (LOI) and/or Letter of Support (LOS) is given in Table 4
and is explained further in subsequent paragraphs.
10.3.1 Submission of Unsolicited Proposals
Any sponsor wishing to undertake a project at a raw site would be required to submit a detailed proposal
to the Government Agency, which must be in compliance with applicable policy guidelines and include,
at a minimum, the following:
i. Statement of qualification of project sponsors, listing relevant corporate experience,
personnel, and financial capacity
ii. Project name and location
iii. Project location (including geographical or GPS coordinates)
iv. Proposed net installed capacity (MW) and expected annual energy output (MWh)
v. Basic outline of plant and structures
vi. Summary implementation plan, committing milestones for project preparation,
implementation and completion date.
vii. Estimated distance from the nearest transmission line (132 kV or 11 kV) or grid station.
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Table 4: Processing Schedule for Unsolicited Grid-Connected IPPs
Activity Typical
Allowance
(Days)
a. Submission of proposal on raw site by sponsors –
b. Review of proposal and qualification of sponsors by
Government Agency 30
c. Posting of Bank Guarantee by sponsors 15
d. Issuance of Letter of Intent (LOI) by Government Agency 7
e. Initial time allowed to carry out feasibility study and
term of the LOI Based on
schedule submitted
by IPP, subject to
maximum of
18 months.
f. Tariff negotiations with power purchaser and approval of
tariff by GON (the time can be significantly reduced if
up-front tariff is accepted by IPP) 90
g. Submission of Performance Guarantee by sponsors upon
approval of tariff (by Govt. Agency ???) 15
h. Issuance of LOS by Government Agency 7
Note: The above are indicated time allowance represents processing period.
10.3.2 Evaluation of Unsolicited Proposals and Issuance of Letter of Intent
Proposals for unsolicited projects on raw sites will be examined by a Project Committee appointed by the
Government Agency. Proposals approved by the Committee will be processed by the concerned
Government Agency for issuance of a Letter of Intent (LOI) against a Bank Guarantee (see Table 3). This
Bank Guarantee shall be valid for a period not less than six (6) months in excess of the validity of the
LOI, following which the provisions of the agreements shall be applicable. LOIs for raw sites shall
include relevant project milestones to enable the Government Agency to monitor progress, and the
sponsors shall commit to meeting the milestones stipulated therein.
10.3.3 Feasibility Study
The sponsors shall enjoy exclusive rights to carry out a feasibility study at a given site during the period
of the LOI, as long as they continue to meet the milestones specified in the latter. The feasibility study
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will be reviewed by a ‘Panel of Experts’ (POE) appointed by the Government. If at any time during the
feasibility study period, the POE determines that the sponsors have failed to adhere to relevant milestones
or rectify such deviation, or are not diligent, the Government Agency may serve a notice to the IPP to
rectify the situation, failing which it shall terminate the LOI and en-cash the Bank Guarantee. In such a
case, the sponsors will have no claim for compensation against any Government agency.
Feasibility studies undertaken by the public sector and donor agencies will be made available to all
interested private entrepreneurs by the Government Agency against a nominal administrative fee. The full
cost of the feasibility study (up to a reasonable ceiling and as reflected on the books of the concerned
agency as being the actual cost of the feasibility study), shall be indicated in the LOI and charged to the
project developer at the time of issuance of the Letter of Support (LOS), and shall be reimbursed to the
agency which originally conducted the study, except in the case where such study was conducted under
grant financing (e.g., donor funding, etc.). Wherever the GON has obtained such a feasibility study
prepared by the public or private sector, preference would be given to the award of these projects through
international competitive bidding (ICB). For studies furnished to the private sector by the Government
Agency or any public sector organization, investors shall be responsible for verifying any or all aspects of
the relevant feasibility study, and would be encouraged to carry out additional or alternative project
appraisal of the site on their own for such purposes. In case the feasibility study has been completed by
the public sector or private sponsor but the unsolicited proposal does not materialize for any reason
whatsoever, and the Government Agency wishes to invite bids using the same feasibility study, then the
cost of feasibility study (up to a reasonable ceiling and as per proper audit) will be recovered from the
successful subsequent bidder, if any, and be reimbursed to the public sector entity or sponsor who
originally paid for, or conducted, the study.
10.3.4 Bank Guarantee and Validity Period of Letter of Intent For issuance of the LOI, sponsors will be required to post a Bank Guarantee (see Table 3) in favor of the
Government Agency based on the project’s estimated installed capacity. This guarantee shall be valid for
a period extending six calendar months beyond the original validity of the LOI. The initial validity of the
LOI shall be up to 18 calendar months, depending on the size of the project and the schedule committed
to by the IPP. A one-time extension to the LOI of up to a maximum period of 180 calendar days may be
granted by the relevant Government Agency if the Panel of Experts (POE) deems the sponsors’ progress
on the feasibility study to be otherwise satisfactory and its completion imminent. Submission of a Bank
Guarantee valued at twice the original amount (i.e., US$ 1,000/MW) and valid for six calendar months
beyond the extended LOI period will be mandatory to qualify for an LOI extension. If during the currency
of the LOI, a sponsor wishes to withdraw from the project, the extent to which the Bank Guarantee
amount shall be en-cashed will be in proportion to the time elapsed since the issuance of the LOI with
respect to the total period of the LOI.
10.3.5 Request for Determination of Tariff Upon completion, the feasibility study will be reviewed by the POE, and if approved, the project sponsors
will be expected to apply to the concerned Government Agency for the determination of bulk power
purchase tariff and grant of generation license within a period not exceeding three calendar months from
the date of said approval. Details of guidelines of determination of tariff are provided in Annexure A. In
case the IPP opts to accept the up-front tariff, if already notified by the Government Agency, the process
of tariff determination would likely be significantly shorter.
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10.3.6 Performance Guarantee and Letter of Support Subsequent to determination of the bulk power purchase tariff by the Government Agency, the project
sponsor shall be required to post a Performance Guarantee based on project capacity in favor of the
relevant Government Agency, valid initially for a period of three months in excess of validity of the LOS.
Upon submission of the Performance Guarantee, a Letter of Support (LOS) shall be issued to the project
sponsor by the relevant Government Agency to enable the project to achieve financial close. Until
financial close is achieved, the LOS shall govern the project and supersede all other documents and
agreements.
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CHAPTER-III
Project Documentation for Hydropower Projects
Financed Through Independent Power Producers
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SECTION 1: General Considerations in IPP Project Documentation
Private hydropower development is still in a state of evolution, with the process proving to be slow and
expensive. There is a danger that interest will falter in the larger hydropower projects if prospective
developers continue to be faced with high upfront costs and long preparation periods, with only limited
prospects of success. The findings of the study suggest the need for longer-term financing to better suit
hydropower characteristics; a regulatory framework and realistic public-private risk-sharing arrangements
responsive to the requirements of hydropower projects; and the careful preparation of projects by the
public sector to enable their formulation on an adequate technical and contractual basis for development
as a private concession.
It is important to keep in mind that government-drafted model Project Documents are to facilitate the
development of IPP projects to the benefit of all parties involved and should not include terms biased
against the interest of the private developers and their lenders. Some provisions of the Model Agreements
are standard and non-negotiable, while others are project specific and open to negotiation. Model
documents must strike a careful balance between the need to promote and protect the interest of Nepal
and the need to offer commercially attractive projects to the developer.
1.1. Need for Model Project Agreements
Model project agreements drafted by government authorities are needed in particular to:
• Ensure that GON’s policies on IPP projects are implemented effectively and on equal
terms in every project;
• Reduce the very high legal costs, including delay and development cost for preparing and
negotiating agreements project by project;
• Prevent developers and their advisors from exploiting their often superior resources and
experience in contract drafting and negotiation, and thus protect the country against
unfair contract terms, onerous risk allocation and other contract terms biased against
national interest;
• Facilitate the financing of IPP projects and reduce the time needed for financial closing.
The familiarity of the lenders with the risk allocation in model concession IPP
Hydropower Procurement Manual enhances lenders’ understanding of the project
structure, which reduces the time and cost of lenders’ due diligence;
• Increase familiarity and understanding of GON Agencies of project agreements and thus
facilitate administrative approvals, control and supervision of the IPP project;
• Ensure that project documents promote the cost-efficient advantages inherent in IPP
concepts to the benefit of the public interest; and
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• Ensure higher legal quality of the project agreements which will make IPP projects more
attractive to developers and their lenders, facilitate the implementation of the project and
reduce future disputes.
1.2. Model Agreements to be based on International Conventions
The Model Agreements are based on international conventions and principles of commercial law outlined
in the United Nations Convention on Contracts for the International Sale of Goods (CISG), United
Nations Commission on International Trade Law (UNIDROIT), Principles of European Contract Law
(PECL - Commission on European Contract Law), etc. This ensures that:
• Contract terms per se are fair and balanced;
• The scope for contract negotiations is reduced considerably to the negotiation only of
particular project terms;
• Contract terms are well-known and acceptable to lenders;
• Contract terms, being developed and reviewed over a period of time, are usually of a
higher legal quality and authority than terms drafted for individual projects.
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SECTION 2: Tentative list of Project Documents
IPP project development documents are based on a number of interlocking contracts and security
instruments. Generally, a Project sponsor (may be a group with equity holding) will form a company and
register this project company (“the Company”) in the country of the project location under the laws of
the land.
The Company will execute the following Project Agreements and Financing Agreements, in accordance
with laws of Nepal as applicable:
Concession Agreement,
Power Purchase (Off-Take) Agreement,
Engineering, Procurement, and Construction (EPC) Contract(s)
Shareholders Agreement,
Insurance Contracts,
Guarantees Supplier Agreements,
Financing Agreements,
Land Procurement Agreement,
Operation and Maintenance (O & M) Contract(s)
These are illustrated in the figure 1 below.
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2.1 Project Agreements to which GON Agencies are a signatory
2.1(a). Concession Agreement (CA): to be executed by the developer (Company) with the Ministry of
Energy/DOED on behalf of GON, for the development of a
concession (the Project) for power generation.
2.1(b). Power Purchase (off-take) Agreement Domestic Offtaker
(Domestic PPA):
to be executed with the Project Company, and GON (NEA)
for the sale of total power or a portion of the output from the
project;
2.1 (c). Power Purchase Agreement for Export Off-take (Export
PPA):
to be executed with the foreign power purchaser, the Company,
GON (NEA) for the sale of total/ or a portion of output from the
project.
2.1(d). Shareholder’s Agreement:
to be executed by the shareholders of the Company, including
the Investor Authority designated by GON (normally Ministry of
Finance) to hold shares in the project on its behalf.
2.1(e). Direct Agreements:
to direct agreements between project participants may be needed
to manage the relationships between shareholders, off-takers,
contractors, lenders, guarantors and GON.
2.2 Project Agreements to which GON Agencies are not signatory
2.2(a). Engineering, Procurement and Construction
Contract(s)/EPC:
usually executed as a single turnkey contract, it defines the
Company’s requirements for the project facilities, and specifies a
fixed price and a set time subject to narrow opportunities for
relief.
2.2(b). Operating and Management Contract(s)/O&M: to be executed with contractor(s) for the operation and
maintenance of the project facilities for a defined period of the
operating phase of the project.
2.3 Financing Documents
2.3(a). Loan Agreements for Project Debt:
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to be executed by the Company and its lenders to define the
terms and conditions under which the lenders agree to provide
debt finance for the project.
2.3(b). Loan Agreements for GON Equity Contributions:
to be executed by the Ministry of Finance and GON’s lenders to
define the terms and conditions under which GON’s lenders
agree to fund GON’s equity subscriptions (as defined in the
Shareholders’ Agreement).
2.3 (c). Security Documents:
to define the security arrangements and the rights of the
Company’s lenders and GON’s lenders to enforce them or rely
upon them (e.g. disposal of assets, cross default and step-in
rights, guarantee support, protection from actions of unsecured
creditors).
2.4 Project Agreements and Financing Documents
2.4(a). These documents provide an interdependent contractual
agreement with interlocking, back-to-back provisions to transfer
project risks, rights and responsibilities to the parties according
to their respective agreements.
2.4(b). Interface issues, in particular with regard to the Concession
Agreement, off-take agreements, EPC contract(s) and Financing
Documents must be addressed in the Project Development
Agreement or procurement rules or in the Concession
Agreement.
2.4(c). The GON Regulatory Guide may propose some procurement
rules with regard to the EPC contract(s), which rules may be
essential for effective risk-allocation and competition under PPP
concession contracts.
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SECTION 3: Features of Model IPP Project Agreements
The following paragraphs list some features of the drafts of the Model Project Agreements.
3.1 Model Memorandum of Understanding
Instruments such as letter of intent, memorandum of understanding (MOU), memorandum of intent,
heads of agreement, letter of understanding, memorandum of agreement etc. in business transactions
usually reflect preliminary undertakings of one or more parties to larger, future contracts. In other words
they are pre-contractual instruments representing initial steps towards final contracts.
3.1(a) Legal Effect of the Model MOU
The law that determines the legal effect of MOUs and other pre-contractual documents is not yet
structured either in the civil law or in the common law countries. Under the law as it presently exists in
the different legal systems, the treatment of pre-contractual instruments varies substantially, which creates
potential for misunderstandings and disputes. Documents labeled “MOU” are viewed by many as merely
preliminary with no legal force and effect and there is some support for this general proposition in case
law and in scholarly works. However, the legal effect of such documents depends not only on the label
given to it by the parties but also on its content. Under the law as it presently exists, civil law and
common law systems agree in providing the parties with considerable party autonomy with respect to the
legal effects of pre-contractual instruments. This means that most of the uncertainties in the law that
governs pre-contractual documents can be eliminated by properly drafting of the documents.
3.1(b) Purpose of the model form of MOU
The model form of MOU for private financed hydropower projects, defines the boundaries of the mandate
and address any other matters as may be applicable for a particular project. The Model MOU is drafted to:
Constitute a legally binding contract with respect to the transactions it describes and within
the mandate period;
Define the mandate and describe the developer’s obligations in studying the project to better
understand the characteristics of the project;
Ensure that the GON or any GON Agency is not responsible for the costs and expenses of the
private developer, including the costs of feasibility and technical studies;
Ensure the developer exclusive and enforceable rights with regard to the project development
before the developer invests in feasibility and technical studies;
Address those issues identified as relevant by the experience of earlier MOUs in Nepal; and
Establish a good faith obligation to conclude a Project Development Agreement (PDA)
within the mandate period.
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3.1(c) Negotiation of successor agreement
The good-faith obligation in the Model MOU does not commit the parties to conclude a successor
agreement (PDA) within the mandate period but it does commit them to conduct negotiations, in
accordance with the terms set forth and with recognized commercial standards of fair conduct. For
example, the good-faith obligation bars a party from unilateral refusal or postponement of negotiations or
from insisting on terms that:
Are not customary or internationally recognized for this type of transaction;
Do not substantially conform with those outlined in MOU; or
Are so unreasonable that they cannot expect acceptance.
3.1(d) Violation of MOU
Violation of MOU constitutes a breach of contract entitling the damaged party to receive compensation
and/or to terminate the MOU. To facilitate the good-faith negotiations, a copy of the Model PDA is
included as a schedule of the Model MOU, providing a clear indication to the parties of the nature of the
terms to be agreed in negotiations.
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SECTION 4: Model Project Development Agreement (PDA)
The Model PDA is an interim agreement between the MOU and Concession Agreement, and is generally
a step in the procurement sequence if concessions are negotiated directly and exclusively with a
developer. Without the PDA step, the execution of a Concession Agreement would need to be sooner in
the development cycle and its effectiveness conditioned by conditions precedent.
4.1. Purpose of the model form of the PDA
In an exclusively negotiated mandate, a PDA provides an interim step between MOU and Concession
Agreement in the award of an IPP hydropower concession. The inclusion of the PDA stage in the award
sequence allows greater certainty and detail to be developed in the terms of the mandate before large
project preparation expenditures are incurred and power purchase commitments are made.
4.2. Features of the Model PDA
Some customization of the Model PDA is necessary to introduce information and terms and conditions
specific to a particular project. Matters addressed in the Model PDA include;
• Provision for specifying the mandate including key project parameters;
• Obligation of the developer to lodge a PDA bond;
• Actions and obligations of the parties during the mandate period;
• Agreement by the parties on a project development timetable;
• Establishment and structuring of the Company;
• Agreement by the parties on taxes and royalties payable by the Company;
• Management and accounting of project development costs.
4.3. Negotiation of successor agreement
The good-faith obligation in the Model PDA commits the parties to negotiate successor agreements to the
PDA including the Concession Agreement. Failure to execute all relevant Project Agreements within the
mandate period of the PDA will trigger its automatic expiration. To facilitate the good-faith negotiations,
a copy of the Model CA is included as a schedule of the Model PDA, providing a clear indication to the
parties of the nature of the terms to be agreed in negotiations.
4.3.1 Comprehensive List of Studies and Program for Inclusion in PDA
and/or CA
The following is the list of studies, documents and programs needed for the development of a project. The
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findings of these studies, documents, and analysis should be a part of the Project Development Agreement
(PDA). Through consultation with GON and all concerned agencies, it should be ascertained if any of the
studies in the list are already undertaken and completed. The list should be reviewed by donors and other
development partners to ensure its adequacy and the necessity for such work, as well as to ascertain the
possibility of sharing the financing costs for undertaking the studies/ program.
1. Power Sector Analysis Study (may need only update)
(i) power demand forecast outlining supply demand gap;
(ii) realistic export potential;
(iii) hydropower development plan
(iv) study of alternatives
(v) power sector development plan’s least-cost analysis
2. Hydrology Modeling Study for the Downstream
3. Water Quality Assessment Program
4. Riparian Release Study
5. Hydropower Sectoral Environmental Assessment study
6. Public Health Plan
7. Development Study for Project Affected People (PAP)/Tribal/Ethnic Minorities
8. Livelihood Study of PAP
9. Human Trafficking Awareness Plan
10. Gender and Development
11. Deforestation and Compensatory Plan
12. Physical Religious and Cultural Resources Survey.
13. Natural Habitats Accounting Analysis.
14. Project Specific Environment Assessment and Management Plan (EAMP)
15. Social Development Plan (SDP) including Resettlement Action Plan and Tribal/
Minorities Development Plan
16. Summary Environment and Social Impact Assessment (SESIA)
17. Environmental and Social Cost- benefit Study
18. Cumulative Impact Assessment Study of Hydropower Project
19. Hydropower Project Construction Contractor Environmental/Social Monitoring and
Mitigation Plan
20. Procurement Process for Hydropower Development
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21. Stakeholders Consultation Process
22. Seminars on:
(i) Sedimentation Management and Dam Safety
(ii) Environmental and Social Aspects
(iii) Communication, Information Gathering and Dissemination
23. Formulation of Concession Agreement (CA)
24. Formulation of Power Purchase Agreement (PPA)
25. Hydropower Project Cost Estimation (including all environmental and social costs) and
Funding Modality and Structure
26. Economic Analysis
27. Macroeconomic Impact Study of Hydropower Development
28. Hydropower Revenue Management Study
29. Due diligence on:
Project design, dam safety, financing plan, safeguard compliance of all social and
environmental impact assessment, Construction Contractor Environmental Monitoring
and Mitigation Plan, CA, Power Purchase Agreement, and review of commercial and
investment analysis.
4.3.2 Brief Outline of Coverage in the Studies
The following paragraphs describe briefly the outline of the coverage of the studies:
1. Environment Assessment and Management Plan (EAMP). The document will contain
an assessment of environmental impacts of the project and management plan to avoid,
minimize, or mitigate, these impacts.
2. Social Development Plan (SDP) including Resettlement Action Plan and Tribal/
Minorities Development Plan. The documents will provide a management plan for
resettlement under the Project and working with tribal/ minorities.
3. Riparian Release Study. The Project may reduce the flow of water in the river system.
The study will assess the environmental and social impacts of changes in flow. It will
also identify environmental and social objectives for different river reaches and
management measures to achieve these objectives.
4. Hydrology Modeling Study for the Downstream. The study will:
(i) provide an understanding of the hydrology of the lower region, including the
relationship between water levels in the river system; and
(ii) evaluate potential hydrological impacts of the proposed project. The study’s
outputs will be used for further assessment of social impacts on villages
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during flooding and non-flooding.
5. Water Quality Assessment Program. The program will provide baseline water quality
and water quality changes during the preliminary construction and full construction
phases of the project. The program will monitor ground and surface water quality during
the preconstruction, preliminary construction, and construction phases to identify
variations, trends, and abnormal levels and take action where levels are exceeded.
(Ongoing)
6. Chronology of Deforestation and Evaluation of the Current Biomass. The study will
provide a chronology of clearance of the proposed project area in terms of habitat type
and cover density and quantify the biomass currently present. The study will propose
means for maximizing removal of biomass (timber and firewood) so as to improve water
quality. This will also be used as an input to the Natural Habitats Accounting Analysis.
7. Physical Religious and Cultural Resources Survey. The work will establish a cultural
resources registry and management and mitigation procedures. The survey will be split
into three phases:
(i) Phase A: will include a survey of project lands required for preliminary
construction activities;
(ii) Phase B: will survey the proposed project lands that contain features that
have a little or no flexibility in their location, those that may be required for
other preliminary construction works; and
(iii) Phase C: will survey project lands not included in phase B.
8. Natural Habitats Accounting Analysis. The quality and quantity of natural habitats
that will be degraded and converted due to the proposed Project will be analyzed and
compared with those planned to be created or conserved as part of the Project. The study
will provide a quantitative rationale for the conservation of the national protected area as
compensation for natural habitats degraded and converted as part of the Project
9. Pest Management Study. Project activities may lead to an increase in the use of
pesticides in the project area. If pesticides are toxic, it may endanger health and the
environment in the project area. The study will identify pest management issues and
impacts in the project area and suggest management and mitigation measures. 10. Construction Contractor Environmental Monitoring and Mitigation Plan. A
Construction Contractor Environmental Monitoring and Mitigation Plan will be
developed for the preliminary construction and construction phases and will contain a
large number of sub-plans to address impacts such as spoil disposal, erosion, physical
cultural resources, construction work camps, and a spontaneous settlement areas plan.
11. Public Health Plan. The plan will identify the health risk to local communities as well as
construction workers and camp followers and develop a public health action plan
covering the following:
(i) identification of health issues related directly to the water resource
development,
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(ii) Strengthening of the resettler’s health plan, and strengthening of the regional
health program, including a HIV/AIDS/STD1
awareness program.
(iii) strengthening of the staff health plan for the construction workforce,
(iv) development of a spontaneous resettlement health plan for camp followers.
All of these outputs will be a part of the SDP.
12. Human Trafficking Awareness Plan. The plan will assess the potential for the increase
in the risk of trafficking in women and children, and develop an awareness program
about trafficking and safe migration.
13. Summary Environment and Social Impact Assessment (SESIA). The assessment
report will summarize the salient features of the EAMP, SDP, and other key supporting
studies and assessment including the cumulative impact assessment (CIA) and the
environment and social assessment of the transmission lines.
14. Due diligence on project design, dam safety, financing plan, and safeguard compliance
of all social and environmental impact assessment will be prepared. Due diligence will
also review the commercial and investment analysis.
15. Review of Procurement Process. An external expert will review the procurement
process, packaging, and costs; concession agreement and power purchase agreement
(PPA).
16. Macroeconomic Impact Study will be required to study the macroeconomic and
poverty impact of the project.
17. Revenue Management Study and financial revenue flows for poverty reduction will be
required under the project.
18. Economic Analysis Studies will include :
(i) power demand forecast;
(ii) least-cost analysis ;
(iii) distribution analysis;
(iv) risk analysis of the least-cost analysis,
(v) risk analysis of the least-cost alternatives;
(vi) development of the power sector development plan’s least-cost analysis; and
(vii) determination of the environment and social cost.
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19. Sectoral Environmental Assessment study will address the broader issues relating to
hydropower development in Nepal and formulate a strategy for improvement of
environmental and social management within the sector.
20. Cumulative Impact Assessment Study. The study will provide an understanding of the
cumulative impacts of the Project in a regional context. It will evaluate impacts for the
next 5 years and 20 years.
21. Compensatory Forestry Program Study. The study will determine the forests/trees
that will be lost (or cut) due to the Project and identify areas for compensatory forestry,
including forest rehabilitation, restoration, deforestation, reforestation and other
possibilities. It will also formulate an implementation plan. 22. SESIA Report. The SESIA report prepared for the project will be finalized for
circulation to the donor community and other development institutions. The report will
summarize the major environmental and social impacts and mitigation and/ or
compensatory measures under the Project. The SESIA is also to be a key public
document for regional and international consultations. 23. Confirmation of Livelihood Study. The study will confirm the viability of the
livelihood options for the resettlement areas based on technical analysis, absorptive
capacity, and implementation risks.
24. Gender and Development. The study will prepare a gender strategy covering:
(i) specific activities and mitigation measures needed for women’s issues;
(ii) training;
(iii) a partnership mechanism among stakeholders on gender issues, and;
(iv) gender sensitive monitoring and evaluation framework. The overriding aim
will be to ensure the gender issues are mainstreamed in the social
development plan. The gender strategy and associated mitigation measures
will be integrated into key safeguard documents and operations plans with an
overview chapter in the EAMP.
25. Development Study for Tribal/Ethnic Minorities. The study will review the relevant
documents prepared under the proposed project with special focus on:
(i) a consultation and participation process with tribal/ethnic minorities for
project planning;
(ii) participation in the resettlement planning and decision making process;
(iii) classification of land titles;
(iv) community land resources tenure arrangements;
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(v) access to forest and or other resources until the new livelihood program is
fully operational.
4.3.3 Brief Outline of Consultation Program/ Process for Inclusion in PDA and/or
CA
The program will include activities involving local, provincial, national, regional, and international
consultation on environment, social, and safeguard issues. Information disclosure and consultation are
important to ensure development effectiveness and sustainability of development projects. They create
opportunities for informed debate, enhance transparency and accountability, strengthen public support,
reduce risks, facilitate collaboration among parties concerned, and improve the quality of project design
and implementation. Conceptually, disclosure and consultation are mutually supportive activities. The
goal is to ensure that affected people and interested stakeholders have access to information about the
project to improve their understanding and facilitate their participation in a meaningful process of
consultation. Under the proposed project, such information would be available in a timely manner and in
a format and content understandable to the Project Affected People (PAP) and other stakeholders.
The Government should continue to promote the informed participation of all level of the Government,
PAP, civil society, and other stakeholders in an open and inclusive manner. During the project
preparation, stakeholders should have the opportunity to comment on the details of the Project. The
consultation should be conducted in a more balanced, transparent, and meaningful way. The related
documents should be posted on website for the public review and comments. The risks and mitigation
plans should be discussed with a wide group of stakeholders through a series of local consultations with
project-affected communities.
The consultation process provides; a forum for open and well-informed dialogue, explanation of project
details, clarifications of issues and provide an opportunity to discuss the stakeholders concerns, inform the
due-diligence process of the IFIs, and provides feedback to the Government before finalization of project
documents.
4.3.3(a) Consultation during Project Implementation
Public consultation and disclosure of environmental and social information prepared for the project would
continue to be undertaken during project implementation. The consultative process followed during
project preparation is only part of the overall project communications and participation strategy. The
Social and the Environmental Assessment and Management Plan (EAMP) would outline the participatory
planning, implementation and monitoring methods that will be employed in different areas of the Project.
There would be specific plans for continuing a proactive program of public meetings and dissemination of
information throughout the project implementation period. Participatory planning process at the local and
provincial levels and other mechanisms would continue to play key roles in providing information and
gathering inputs from affected people. Consultation should be continued after the effectiveness of the
loans.
Periodic meetings of co- financiers would be convened for review of:
(i) the physical implementation of project investments,
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(ii) results of monitoring and evaluation of social and environmental impacts
and outcomes, if any,
(iii) measures taken to address unforeseen events, and
(iv) other dimensions of the Project. In support of these processes, the
Government will need support to improve its capacity in public
communications and media relations for the Project and will, among
other actions, improve its project website and ensure that it is provided
with up-to-date information on the project.
4.3.4 Capacity-Building Program for Social Aspects
The Government agencies that will manage and implement the various social and environmental
safeguard plans need to have sufficient capacity to do so. However, the risk that the environmental and
social mitigation programs may not be managed and implemented properly is considerable due to
insufficient institutions capacity. The capacity building program, as a first step, will undertake a need
assessment, review the adequacy of the institutional structure, identify gaps, if any, in terms of roles,
responsibility, and authority. The capacity building program will assist the Government in implementing
the institutional structure best suited for monitoring compliance and policy oversight for environmental
and social mitigation measures. The program will formulate and implement the short-, medium-, and
long-term capacity-building in the hydropower sector.
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SECTION 5: Model Concession Agreement
The Model Concession Agreement (CA) is the key legal instrument granting the concession to the
developer, specifying the rights and obligations of the parties, and providing GOL with control of the
complex implementation issues. The Model CA may, as a general rule of thumb, be contained in 3
volumes:
• Volume 1 contains the basic, operative provisions of the agreement.
• Volume 2 contains the Schedules to the Model CA, typically addressing particular
condition for each project.
• Volume 3 contains documents of informative nature.
Volume 1 and Volume 2 will together comprise the legal rights and obligations of the parties.
5.1 Model CA based on international contract principles
In order to ensure that the terms of the Model CA are balanced and fair to both parties, the document
embodies internationally recognized contract principles as far as applicable. To a considerable extent it
relies on the legal principles set forth in international conventions such as the CISG, UNIDROIT’s
Principles of International Commercial Contracts, internationally applied standard forms of contracts and
the legal solutions common for the large codifications such as Code Civil and BGB. The Model CA also
draws on the vast body of laws on unfair contract terms promulgated in most industrialized countries over
the last thirty years (e.g. the laws on unfair contract terms or on general conditions of business contracts
of Sweden (1974), Germany (1976), UK (1977), France (1978) and Norway (1983); also the United
States Uniform Commercial Code, sec 2-302). The international principles are well known, or should be
well known, to foreign developers and their lenders and are difficult to reject since in most cases they will
have been ratified or recognized by their home-countries. Their international acceptance gives them
authority which tends to narrow the scope for contract negotiations and reduce transaction costs and time
5.2 Model CA covers the general conditions of the concession
terms
The Model CA sets forth the General Conditions for hydropower concessions. Specific terms (“Technical
Specifications”) such as a project’s physical characteristics, design and construction specifications,
specific operational requirements, off-take arrangements, etc. must be addressed, project by project, and
attached as schedules to the Model Concession Agreement. The General Conditions of the Concession
Agreement may need to be changed, supplemented or clarified by Particular Conditions due to the
requirements of each project.
5.3 Preceding agreements
The Model CA is drafted on the assumption that its execution is preceded either by an international,
competitive bidding procedure or by a negotiated procurement procedure involving progressively MOU
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and PDA contracts. If a negotiated procurement procedure is used without the use of a PDA, the Model
CA should be modified to specify a number of conditions-precedent to be satisfied before the CA
becomes effective.
5.4 Form and structure of the Model CA
The proposed structure of the Model CA is strictly “functional”. This means that the provisions of the
agreement are ordered in accordance with the development phases of the project; from the signing of the
agreement; to the construction phase (design, construction and commissioning); to the operating phase
and to provisions on transfer of the project. Finally, the Model CA contains provisions on breach of
contract and on the position of third parties. The functional structure is designed for ease of use by non-
legal persons. In order to avoid repetition and overlapping, provisions applicable to all phases of the
project are listed as “General Obligations”. This chapter includes such issues as changes in law,
environmental protection and insurances. Note that this structural approach is adopted in international
conventions, e.g. the United Nations Vienna Convention of 1980.
5.5 Bankability of the Model CA
A model concession contract must be bankable. Foreign investors may not regard the credit rating of
Nepal as attractive and to facilitate foreign financing. The Model CA accommodates many lender
concerns including security arrangements, charge over offshore accounts, step-in rights, insurance
requirements, etc. The Model CA is an evolving document and the document may need further
development to address reasonable lender concerns.
5.6 Domestic Preference
The proposed provisions on domestic preferences and review procedures may require some clarifications
with regard to the administrative system of Nepal and the industrial and commercial policies of Nepal.
International experience shows that PPP projects may have considerable and positive impact on the
development of national industry and research.
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SECTION 6: Model Power Purchase Agreements
6.1 General Observations
In reviewing the Power Purchase Agreements (offtake contracts) the most notable fact that
emerges is the diversity of the arrangements. There is no single standardized formula as is
generally the case for thermal IPPs. This reflects not only the individual nature of hydro projects,
but also the relative immaturity of the process of developing a PPA that properly values the
contribution of hydro to the system.
All of the tariffs are negotiated on the basis of an agreed project cost that is generally defined in
advance of construction, and often on the basis of only a preliminary project definition. This
meant that the owner, or his engineering, procurement and construction (EPC) contractor, was
usually required to assume the full construction risk including geological conditions.
There are exceptions, in particular Birecik (Turkey) where there is provision for a tariff reopener
in the event of unforeseen ground conditions (which is common to all Turkish BOT hydro
projects).
There is an inherent conflict between the need of the utility to fix the tariff early in the
concession process, and the fact that for most schemes the final cost cannot reliably be
determined in advance of construction. Although the tendency in the past has been for the utility
to seek to place this risk on the developer, there is a growing consensus toward some form of risk
sharing between the three parties-the offtaker, the developer and the contractor. This can involve
a tariff reopener, as in the Turkish model, or a geographic splitting of the project into public and
private elements, as in San Roque (Philippines) where the public partner assumed responsibility
for the riskier civil works.
The treatment of hydrological risk presents similar problems. Early attempts to place all of the
risk onto the developer generally failed because the schemes proved impossible to finance, with
the result that the trend is now toward the sharing of hydrological risk or its total assumption by
the domestic offtaker. Generally, the developer is the primary carrier of the hydrological risk, but
in practice this exposure sometimes is reduced through other guarantees provided by the utility.
Where there are upstream storages or abstractions that can influence the water flow to the power
station it becomes increasingly difficult to expect the private owner to assume hydrological risks
and the exposure inevitably, falls on the utility. This is the case in Birecik, where the developer
(owner) gets paid irrespective of flow, provided the prescribed plant availability is maintained.
On international rivers the situation is more difficult because there are no widely enforceable
water laws to preserve natural flows for downstream riparian states. In the case of Upper Bhote
Koshi the owner accepted the risk of interference with upstream flow accruals in Tibet because it
was considered that the exposure was low, but this will not always be the case on international
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rivers, and in such circumstances private schemes will only be bankable if the utility assumes the
hydrological risk.
Tariff structures tend to be based on energy for run-of-river schemes subject to a guaranteed
minimum offtake, and on capacity and energy for storage projects. In some cases a dual energy
tariff has been used to reflect the higher value of firm energy over dump energy. Where there is
no capacity charge or other fixed payments, the minimum offtake or "firm energy" tariff is
usually structured to ensure that it covers these elements, thereby effectively guaranteeing the
minimum necessary revenue for debt servicing.
All of the tariffs are denominated in foreign currency, usually US dollars with the currency
fluctuation and conversion risk falling on the utility. In some cases the exposure of the utility has
been reduced by having the tariff denominated in local currency, with only the proportion
representing the foreign funding and offshore equity convertible into hard currency (at a
predefined exchange rate).
A conspicuous omission from all of the offtake agreements was any form of payment for
ancillary services such as frequency control, spinning reserve and emergency standby. The
absence of such payments means that in many cases hydro is being seriously undervalued. As
already noted, such services were not explicitly accounted for in the past but there is growing
evidence that in the future, as deregulation reveals the real cost of the different components of a
power system, the ancillary functions of hydro will become increasingly significant elements to
be included in any offtake agreement.
6.2 Tariffs Structure
The tariff structures are based on a two-part structure with Capital Recovery Fees and Operating
Fees. The Capital Recovery Fee is US dollar-denominated, with the Project Company taking the
currency risk (?). The Operating Fee is generally in local currency.
Projects are clearly defined at the bid stage before the PPA is negotiated.
No pass-through of construction risk to Government.
The Company/ or the Government bears the costs of resettlement, relocation and
compensation, and is responsible for executing these aspects.
The Government makes available (at no cost to the developer?), the land,
easements and rights-of-way for the project.
Government may be responsible for the transmission line, but may reserve the
option to devolve the responsibility for its construction onto the company, with a
commensurate increase in the tariff.
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6.2.1 Minimum offtake obligations:
The off taker guarantees payments for capital recovery based on
Dependable Capacity for storage schemes, and Firm Energy for run-of-
river projects, irrespective of actual output.
Offtaker is obligated to purchase any additional energy generated, over
and above the contracted energy, but at a lower unit cost.
Penalties apply for the non delivery of the minimum contracted capacity
and/or energy unless it can be shown to be beyond the operator's control.
6.3 PPA for Domestic/ Foreign Hydropower Offtakers in Nepal
Off-takers from Nepal projects will include foreign buyers. Current GON policy contemplates some
domestic off-take for all projects. Projects can be classified according to their off-take arrangements:
(i). Export project with some domestic off-take:
The Company will enter into PPAs with one or more foreign power purchasers
and with MOE/DOED for the sale of a project’s output. A project’s financing is
normally secured on the sales revenue of the foreign buyer only and export sales
will therefore account for the greater part of a project’s production.
(ii). Domestic project:
Where financing can be secured on DOED sales revenue, IPP projects selling
exclusively to DOED can be promoted. In such cases, the Company would enter
into a PPA with DOED only. The Company will therefore contract for the sale
and purchase of electricity from the project as follows:
6.3.1 PPA for foreign off-take
GON Agencies are involved at a government-to-government level in negotiating umbrella power trading
agreements between Nepal and its neighbors and are also participants in tariff negotiations for individual
export projects. However, they are not signatories to any PPA between a project company and a foreign
power purchaser. The practice of foreign buyers to date is to negotiate PPAs individually for each project
without the use of a model document. If a competitive tendering process is employed in awarding an IPP
concession, a draft PPA may be negotiated between GON and the foreign buyer in advance of the
solicitation and a copy provided with the Request for Proposals (RFP) suite of documents. This would
alert bidders to the terms and conditions covering the portion of a project’s output committed to the
foreign buyer.
6.3.2 PPA for DOED off-take
The Model PPA for DOED off-take (Model DOED PPA) sets out sale and purchase terms and conditions
as they apply to off-take by DOED. Matters addressed in the Model DOED PPA generally parallel those
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in the PPA for foreign off-take. However, Model DOED PPA and the PPA for export off-take should be
carefully coordinated in respect of the following:
The Company’s total electricity sale commitments are consistent with site hydrology,
project design and water rights under the Concession Agreement;
Transmission and interconnection arrangements with the foreign buyer’s system and
the DOED system;
Minimum technical requirements of project elements supplying each market.
The tariff payable by DOED for domestic off-take; is generally set at a level to achieve a revenue neutral
position for the Company between export and domestic sales. Accordingly, the Model DOED PPA
stipulates a tariff based on the opportunity cost of export sales foregone but leaves open the level of
domestic electricity sales.
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SECTION 7: Engineering, Procurement, and Construction Contract (EPC) for Project Implementation
Under private financing there has been a strong move toward engineering, procurement and construction
(EPC) contracts, away from the traditional arrangements where the owner retains control of the design
and the project is managed as a series of single-discipline contracts. Whereas this makes little difference
in the context of equipment supply, it has a big impact on the civil works, on the bidding process and on
the overall cost of the project, which is generally accepted to be higher under EPC arrangements.
The move toward EPC contracts is being driven by financiers in the belief that it insulates the owner, and
therefore the financiers themselves, from risk. However the record to date suggests that this may not be
the case and serious contractual difficulties are occurring with increasing frequency on EPC hydro
projects.
Problems arise when contractors are required to bid firm prices against a weak project definition and with
inadequate site studies. Early attempts to put all of the risk onto the contractor have generally proved
unsuccessful, and the trend is now toward some form of risk-sharing, especially for unforeseen geological
conditions. When these risks cannot be passed on to the offtaker, provision has to be made for contingent
financing through the project company.
Contractors are also appearing as equity holders and sometimes as project sponsors, although their
primary interest generally lies in the construction contract itself. They remain important players in a field
where there are not many natural sponsors, other than a few hydro-based utilities and the small number of
independent power developers who are comfortable with hydro.
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SECTION 8: Implementation Arrangements
In view of the complexity, sensitivities, and the enormity of the project scope and related activities, it is
considered necessary that an international private company with extensive experience in undertaking the
development and operation of large hydropower projects who will formulate, design in conformity with
the international best practices, develop, implement, operate, and monitor the achievement of the stated
objectives of the project. The new company will take the project as BOOT and at the end of the
concession period will transfer all the assets to GOP at no cost.
8.1 Adaptive Management
It is recognized internationally the need for a flexible approach to environmental management that
accommodates periodic changes in scope or the objective of a specific measure. Because of its complexity
the project will entail enormous environmental and social impacts. “Adaptive management” is a key
element in the overall environmental management approach. The principles of adaptive management
involve modifying environmental programs based on monitoring and evaluation of the environmental
performance of specific actions. By definition, this is an iterative process which requires intensive
monitoring.
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SECTION 9: Project Monitoring and Performance Evaluation
A comprehensive design and formulation of different aspect of project monitoring and evaluation is an
important aspect of planning process.
9.1 Monitoring Arrangements
The monitoring arrangements for hydropower projects, financed by a consortium of international banks,
private developer (owner), international financial institutions (IFIs), bilateral donor agencies, generally
consist of the following multilayered complementary components. These monitoring arrangements would
form the basis for reports on project progress. These reports will be presented to an annual meeting of
project stakeholders, including GON, sponsors, financial institutions, and local and international civil
society
9.2 Appointment of Panel of Experts for Monitoring and Evaluation
9.2.1 a dam safety Review panel
9.2.2 an independent monitoring agency for environment and social aspects
(resettlement)
9.2.3 Lender’s advisors
9.2.4 a Government engineer
9.2.5 an owner’s engineer
9.2.6 supervision by staff from IFIs and commercial lenders
9.3 Project Monitoring Indicators
Monitoring indicators will be established during project formulation and processing and will cover
technical, safeguards and revenue management components of the project, primarily including:
Completion of the physical works, and goods and services against time and budget targets
will measure physical progress of the project
Indicators to measure social and environmental programs will measure the effectiveness of
the conservation, resettlement, and livelihood restoration activities
Indicators to measure implementation of the revenue management program will evaluate the
effectiveness of the use of GON revenue from the project for poverty reduction program as
agreed on by the GON and the donor partners.
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9.4 Monitoring By Independent International Panel of Experts
(Starting from Project Design)
It is necessary to retain a group of professionally qualified independent international experts to monitor
project implementation. These bodies and the individual members must be fully independent from the
project sponsors (GON, WB, ADB, other IFIs, and development partners) in order to avoid any
perception that one or more of the sponsors could censor or water down their recommendations. The
preliminary list is outlined below. The Panel of Experts (POE) should report to the highest body of the
Government, where as the Independent Monitoring Agencies (IMA) should report to the National Energy
Coordinating committee, and the Dam Safety Panel (DSP) report to the GON project Committee.
9.4.1 List of Panel of Experts
The preliminary list is outlined below.
Panel of Experts (POE) for Safeguard Issues
Independent Monitoring Agencies (IMA) for Project Implementation
Dam Safety Panel (DSP) of Experts
The Panel of Experts (POE) should report to the highest body of the Government.
The Independent Monitoring Agencies (IMA) should report to the National Energy Coordinating
committee.
The Dam Safety Panel (DSP) should report to the GON project Committee.
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SECTION 10: Conflict Resolution Any conflict arising out of the alleged breaches in the CA, or PDA or the PPA should be resolved through
the good offices of the
10.1 Panel of Experts
If the parties cannot agree with the decisions of the Panel of Experts then the matter could be referred to
the court of the
10.2 International Arbitration
The legal aspects of hydropower project development, documentation, contract negotiation including the
International Arbitration are given in Chapter-V of this report.
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CHAPTER-IV
Capacity Building Needs of DOED
&
Economic Analysis of Hydropower Projects
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SECTION 1: Capacity Building Needs of DOED
1.1 Background
In addition to identifying capacity gaps and building the capacity of the Nepal power sector as a whole
under the TA, the Project monitoring and Evaluation Specialist inter-alia was tasked to specifically
identify capacity gap of the DOED and make recommendations for its capacity building. So that DOED is
able to assess and monitor the development of hydropower project proposals; respond to other emerging
needs and in turn to enhance the capacity of the Ministry of Energy (MOE) and Electricity Tariff Fixation
Commission (ETFC) to carry out their policy making and regulatory roles, while ensuring the financial
sustainability of hydropower projects. This Chapter lists the tasks assigned to the Project Evaluation and
Monitoring Specialist and delineates on the activities performed. The terms of reference of the project
evaluation and monitoring specialist are as follows:
(i) review the methods that DOED currently employ to evaluate potential
hydropower projects;
(ii) recommend possible modifications to these evaluation methods;
(iii) identify and help DOED procure effective tools for economic and financial
analyses and evaluation of hydropower projects;
(iv) carry out economic and financial analyses and evaluate already identified potential
hydropower projects to be developed by private sector;
(v) assist DOED staff in negotiating with the private companies on the terms of
developing the hydropower projects;
(vi) design and implement a tool for monitoring project implementation;
(vii) train DOED staff in using tools for economic and financial analyses and
evaluation and monitoring of hydropower projects; and
(viii) provide inception, interim, and final reports on the assignment.
This Chapter covers the first three items of the terms of reference, namely:
(i) review the methods that DOED currently employ to evaluate potential hydropower
projects;
(ii) recommend possible modifications to these evaluation methods; and
(iii) identify and help DOED procure effective tools for economic and financial analyses and
evaluation of hydropower projects.
This section of the report discusses economic analysis and the rationale for capacity enhancement in
economic analysis. Section 2 provides an overview of DOED, including its organization and
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responsibilities. Section 3 assesses the capacity and staffing needs of DOED for economic analysis.
Section 4 concludes and makes recommendations.
1.2 What Is Economic Analysis and Why the Need
The production of electricity from hydroelectric power stations is inherently capital intensive. It normally
takes large amounts of excavating equipment, cement and reinforced steel, along with electrical and
mechanical machinery to construct a hydroelectric power station. The capital cost is often higher when
hydroelectric sites are located in remote or difficult to access areas such as those in the Himalaya region.
Operation of a hydroelectric power station also involves highly skilled personnel. On the other hand,
hydroelectricity is a domestic source and is clean, renewable, usually with minimal negative
environmental and social impacts. It is also a reliable source of energy where water flows are predictable
or when reservoirs serve as storage. For these reasons, hydroelectricity is an attractive source of energy.
The investment needed to develop hydroelectric power stations is relatively large, sometimes with
substantial macroeconomic and balance of payments impacts for smaller economies such as Nepal’s. On
the microeconomic level, the decision to build hydroelectric power stations will often be a factor in the
price that consumers of electricity ultimately pay. It may also have an impact on the government’s budget
when power pricing policies involve less than full cost recovery of the hydroelectric facilities’
investment, operating and maintenance costs. Given the potential economic impacts of large investments
in hydroelectricity, projects must have strong justification in technical and economic terms.
Assuming that a hydroelectric power project is technically feasible, a necessary condition for proceeding
with its development is economic viability. Economic viability is a term that has a broader meaning than
the usual internal rate of return that it is often associated with. It essentially comprises four criteria: (i)
relevance; (ii) cost effectiveness; (iii) efficiency; and (iv) sustainability. To take into account imperfect
information and uncertainty, sensitivity and risk analyses are conducted to determine their impact on
economic viability. These four criteria and uncertainty are briefly discussed.
Relevance. The load forecast is usually the main rationale behind any power project. However,
hydroelectric power projects cannot be designed and implemented in isolation from the rest of the
economy. Economic analysis assesses how the project influences macroeconomic performance, including
balance of payments and fiscal management. An analysis of pricing issues, environment and social issues
are also important aspects of relevance. Relevance also provides justification for public or private sector
participation in the project.
Cost Effectiveness. Having established the need for a project (relevance), economic analysis then
identifies the options available to meet the demand for electricity or some other objective that had been
identified. To ensure that the country’s resources are used effectively, the least cost alternative is selected,
which involves calculating the present value of streams of economic costs of technically viable generation
projects.
Efficiency. Economic analysis confirms that the selected hydroelectric power project makes use of the
invested resources efficiently. Efficiency is ensured when the project’s economic benefits sufficiently
outweigh their economic costs. The criterion used by ADB and many other international financial
institutions is an economic internal rate of return (EIRR) greater than 12% real (constant currency terms).
Sustainability. To ensure that the net economic benefits are realized over the expected life of the project,
economic analysis confirms that the project is sustainable in financial and institutional terms. Financial
sustainability consists of comparing the financial internal rate of return (FIRR) with the weighted average
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cost of capital, normally calculated in after tax and constant currency terms. An FIRR, greater than the
weighted average cost of capital; indicates that the project will increase the financial value of the
institution that invested in it. Economic analysis should also provide an assessment of the financial
position of the institution that invests in the project in terms of profitability, solvency and liquidity. An
assessment of the institutional capacity to operate and maintain the project is also an important aspect of
sustainability.
Uncertainty. A complete economic analysis acknowledges imperfect information and uncertainty about
future events. Therefore, the EIRR calculation should be subjected to sensitivity and risk analyses.
Sensitivity analysis is undertaken to identify parameters that are uncertain, such as, capital cost and the
load forecast, and for which the project decision is sensitive. Switching values show the change in a
parameter required for the project decision to shift from acceptance to rejection. The risk analysis assigns
probabilities to key parameters and calculates the likelihood of the EIRR falling below the critical 12%
real cut-off point. Sensitivity and risk analyses can point to measures that mitigate the major sources of
uncertainty.
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SECTION 2: Overview of DOED, including its organization and responsibilities
2.1 Department of Electricity Development
The Electricity Development Center was established on 16 July 1993 under the then Ministry of Water
Resources to develop and promote the power sector and to improve its financial effectiveness at the
national level by attracting private sector investment. It was renamed the Department of Electricity
Development on 26 January 2000. DOED is responsible for assisting MOE in implementing government
policies related to power sector. The main functions of the DOED are to ensure transparency of the
regulatory framework, accommodate, promote and facilitate private sector's participation in power sector
by providing "One Window" service and to license to power projects.
2.2 Organization of DOED
DOED is headed by a Director General and consists of three divisions, each headed by a Deputy Director
General. Each division comprises two sections. The main functions of each section may be found on
DOED’s website (www.doed.gov.np/divisions.php) and is duplicated below.
2.2.1 Project Study Division
a. Survey & Feasibility Study Section
Main Functions
(i) Prepare a master plan for the development of river basins and identify and assess
potential hydroelectric projects;
(ii) Conduct pre-feasibility studies of identified projects;
(iii) Conduct feasibility studies of projects whose pre-feasibility studies were
completed;
(iv) Conduct detailed engineering designs of feasible projects;
(v) Conduct studies on alternate sources for electricity generation, such as solar and
wind;
(vi) Conduct studies and prepare reports of feasible projects ready for
implementation;
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(vii) Carry out feasibility studies, detailed design, etc. of mega-projects such as
Karnali, Pancheshwar, Budhi Gandaki and Pancheshwar, as agreed with India;
and
(viii) Promote power exchange between Nepal and India.
b. Planning Section
Main Functions:
(i) Prepare program and budget; assist MOE with foreign assistance;
(ii) Prepare monthly and quarterly progress reports;
(iii) Monitor activities undertaken by DOED;
(iv) Public relations;
(v) Implement Government directives;
(vi) Prepare responses to questions arising in Parliament for the Ministry;
(vii) Manage the computer and documentation systems; provide these services to other
divisions and sections; and
(viii) Manage works related to solar energy, wind energy, and heat energy.
2.2.2 Privatization Division
a. Proposal Evaluation and License Section
Main Functions:
(i) Study and evaluate proposals from the private sector for electricity development
considering technical, economical and environmental aspects;
(ii) Study proposals for facilities to be provided to projects constructed by the private
sector and make recommendations;
(iii) Coordinate projects constructed by the private sector;
(iv) Collect various fees related to licensing; and
(v) Assist in providing facilities to private entrepreneurs like tax and duties, foreign
exchange, land lease and acquisition per provisions in the law and regulations.
b. Project Promotion and Monitoring Section
Main Functions:
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(i) Promote private sector participation in hydropower development;
(ii) Prepare draft agreements between the Government and the private sector;
(iii) Provide technical assistance to small hydropower project implementation under
private sector development;
(iv) Monitor projects under operation;
(v) Coordinate between the Nepal Electricity Authority and private entrepreneurs;
and
(vi) Conduct works related to national grid and transmission lines.
2.2.3 Inspection Division
a. Project Inspection Section
Main Functions:
(i) Site inspection for compliance with license terms and conditions;
(ii) Study and recommend for cancellation of license;
(iii) Establish standards for hydropower surveys and generation, and inspect projects;
(iv) Conduct studies for power exchange policy and methodologies; and
(v) Inspect power projects for compliance with the Electricity Act and Electricity Regulation.
b. Electricity Inspection Section
Main Functions:
(i) Prepare guidelines for electricity generation and distribution;
(ii) Prepare safety standards for electricity development;
(iii) Inspect quality of service regarding electricity generation and distribution;
(iv) Conduct all necessary work related to electricity accidents;
(v) Collect royalties according to the Electricity Act and Electricity Regulation; and
(vi) Assist private entrepreneurs in obtaining facilities according to the Electricity Act
and Electricity Regulation.
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2.3 DOED Staffing
DOED has an authorized staffing level of 107 persons, of which 67 are classified as professional staff.
The balance is supporting staff. Of the 107 authorized positions, 106 are filled, as of 30 June 2012.
Professional staff, exclusive of the Director General and the three Deputy Director Generals in each
division, comprises the following occupational categories:
Table 1: Categories and Number of Professional Staff in DOED
Civil Engineers (Hydro) 29
Electrical Engineers 13
Mechanical Engineers 3
Geologists 4
Hydrologists 2
Environmental Specialists 1
Computer Specialists 7
Others 5
Total 64
There is no economist or financial analyst staff in DEOD.
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SECTION 3: Assessment of DOED Facilities and Capacity for Economic Analysis of Hydropower Projects
3.1 DOED Location & Physical Infrastructure
DOED is located at 576 Bhakti Thapa Sadak (4), Anamngar, Kathmandu, Nepal. It is housed in two, side-
by-side, 4-storied buildings with separate entrances at street level. The two buildings are connected by a
walk-way on the roof. Building facilities are rudimentary.
DOED houses a document center, but many files and documents permanently reside with staff because of
inadequate space for filing and storage. Each DOED staff has a computer and the availability of state-of-
the-art computers is not a constraint, according to senior DOED staff. However, DOED has no computing
network, although it has its own web site hosted by an outside entity and accessible by the public. Staff
does not have individual email addresses associated with DOED and relies on personal email addresses
registered with commercial internet service providers to conduct business. There are telephones, but the
system is archaic and consists of older equipment and the quality of telephone services is poor.
DOED owns no specialized software and uses commercial software for its work, such as word processors,
spreadsheets, and power point demonstrations. Computerized data storage is not well developed at DOED
and depends largely on paper work, files, and the physical storage of data.
3.2 Capacity Needs
DOED does not, at this time, have the full capacity to guide the development of Nepal’s power system or
to evaluate potential hydropower projects on an economic basis. DOED does not prepare long-term load
forecasts, develop least cost generation expansion plans, determine the economic viability of individual
generation projects, assess the financial impact of these projects on the operating entities, or estimate the
long-run cost of electricity. Rudimentary economic analysis is usually undertaken by local engineering
consulting firms contracted to prepare feasibility studies. However, the quality of these economic
analyses is often poor.
DOED is staffed with highly qualified technical staff that has the capability of assessing the technical
viability of generation projects. However, technical viability assessments are insufficient to ensure that
Nepal’s scare investment resources are efficiently utilized. To guide the development of Nepal’s power
system and to evaluate potential hydropower projects on an economic basis, DOED needs to establish an
Economic Planning Unit that has an ability to: (i) prepare long-term load forecasts, (ii) develop least cost
generation expansion plans, (iii) determine the economic viability of individual generation projects, and
(iv) to assess the financial impact of these projects on the operating entities. Each of these economic
planning functions is discussed below.
3.2.1 Load Forecasting
Load forecasting is the basis for all generation and system planning and the foundation of the rationale for
a hydropower project. It determines how much and when additional capacity is needed, whether it is
generation or transmission capacity and, in some cases, distribution. Accurate load forecasting can save
resources. Overly optimistic load forecasts lead to excess investment in capacity and wasted resources;
conversely, low load forecasts lead to losses in societal welfare.
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Load forecasts may be classified into 3 categories:
(i) short term: one hour to one week, usually used for trading in
electricity in a competitive environment;
(ii) medium term: one week to one year, mainly for budgeting and
maintenance planning purposes; and
(iii) long term: more than one year for generation and system planning.
For generation and system planning, long term load forecasts have horizons of up to 50 years.
DOED’s interest would primarily be in long term load forecasting, to which there are two main
approaches: (i) end-use modeling; and (ii) econometric modeling. The main features of these approaches
are explained as follows.
End-Use Modeling: This approach to load forecasting estimates energy consumption by using extensive
information on end use and end users, such as appliances, customer use, age, sizes of houses, etc. In
essence, end-use models explain energy demand as a function of the number of appliances in the market.
The end-use approach requires extensive information about customers and their equipment and is
sensitive to the amount and quality of data. This approach may not be suitable for Nepal at this time.
Econometric Modeling: This approach combines economic theory and statistical techniques for
forecasting electricity consumption. It uses data on electricity consumption (sales), income, prices,
weather, demographic variables, etc. Data in the form of time series are usually available from power
utilities and government agencies. Parameters of relationships between electricity consumption and these
variables are estimated using econometric techniques. Load forecasts are often developed by consumer
class (residential, commercial, industrial, etc.) and aggregated to total electricity demand.
Table 2 is an example with two consumer classes: domestic and non-domestic.
Table 2: Example of Sector Disaggregation of Electricity Consumption for Nepal
Year Domestic
Consumption
(MWh)
Non-domestic
Consumption
(MWh)
Total Electricity
Consumption
(MWh)
2012
2013
2014
2015
.
.
.
.
.
.
.
.
.
.
.
.
2042
Because of the small size of Nepal’s economy, electricity consumption forecasts could be made relatively
accurately focusing on only these two groups of consumers. Forecasting domestic consumption in column
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2 of Table 2 is based on population and household size, as shown in Table 3 below. Data on population,
its forecast, and household size are normally available from government statistical agencies. Variables in
columns 4, 5 and 6 of Table 3 are derived as follows:
Column 4: number of households = population ÷ household size
Column 5: electricity consumption per household: from econometric model
Column 6: total domestic electricity consumption
= number of households × electricity consumption per household
Table 3: Domestic Electricity Consumption
Year
Population
Household
Size
Number of
Households
Electricity
Consumption
per Household
(MWh)
Total Domestic
Electricity
Consumption
(MWh)
2012
2013
2014
2015
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
2042
The econometric model on which electricity consumption per household is based is normally of some
form of the general expression:
qd = f(pd, yhh, x) …(1)
where qd is electricity consumption per household; pd is the price of electricity to domestic consumers; yhh
is household income; and, x is a vector of all other relevant variables.
For non-domestic consumption (column 3 in Table 2), a more direct approach may be used. An
econometric model such as (1) may be developed that relates price, income and other variables to
consumption, such as:
qnd = g(pnd, y, x) …(2)
where qnd is total electricity consumption in the non-domestic consumer class; pnd is the price of
electricity to non-domestic consumers; y is gross domestic product; and, x is a vector of all other relevant
variables.
Tools needed for load forecasting are few: a spreadsheet program, such as Excel, and an econometric
software package, such as .Eviews, PCGive and SAS. There are number of free econometric software
packages available from the internet, such as EasyReg, Gretl and Matrixer.
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3.2.2 Least Cost Generation Planning
After determining what the demand for electricity will be with a load forecast, the supply side of the
equation is developed on the basis of a least cost generation plan. Least cost planning determines the
optimal schedule of generation capacity that needs to be put in place to meet the anticipated demand for
electricity. The optimal schedule is selected from a set of technically feasible, mutually exclusive
alternatives on the basis of the lowest present value of initial capital cost and all subsequent operating and
maintenance costs over a specified period of time. Alternatives can include:
(i) generation projects, such as hydropower; pumped storage; other renewables such as
solar, wind; thermal (natural gas, diesel, etc.);
(ii)
(iii) transmission projects for importing electricity from external sources; and
(iv)
(v) demand management (reducing demand by technical means).
Nepal has a large number of potential hydropower projects of differing sizes, locations, and cost.
Therefore, it is not possible to determine the least cost generation expansion plan without computing
power. There are a number of software packages on the market that develop least cost generation
expansion plans. One that this report recommends is the Wien Automatic System Planning (WASP) IV
Package developed by the International Atomic Energy Agency (IAEA) and is available to the
government of Nepal at no cost. IAEA also provides training in WASP IV at no cost to the government
through its technical assistance facility.
With the many potential hydropower projects in Nepal, a key issue is: which projects should be dedicated
to domestic electricity supply and which for export. For Nepal to have the greatest benefit from its own
hydropower resources, the subset of potential hydropower projects that form the least cost generation
expansion plan should be developed to supply Nepal. All other potential hydropower projects may be
allocated for the export of electricity. In this way, Nepal reaps the benefits of the cheapest power
available.
3.2.3 Benefit-Cost Analysis
Even though a power project forms part of a least cost generation expansion plan, there is also a need to
ensure that the economic benefits of the power project sufficiently outweigh their economic cost. Most
international financing institutions use economic internal rate of return (EIRR) and economic net present
value (ENPV) as the main measures of economic efficiency. Criteria for acceptance of a project used by
these institutions are EIRR > 12% and ENPV > 0 (discounted at 12%), measured in real terms. These are
criteria that should also be adopted by the government of Nepal.
In calculating the EIRR and ENPV, there is an assumption of perfect knowledge about future values of
costs, benefits and parameters. To incorporate uncertainty, ENPV calculations should be accompanied by
sensitivity and risk analyses. ENPV is preferred to EIRR because there is sometimes a problem with
multiple EIRRs.
Calculation of EIRRs and ENPVs are easily accomplished with a spreadsheet program, such as Excel.
Sensitivity analysis can also be undertaken in a spreadsheet. Risk analysis is normally carried out with
commercial software packages, such as ModelRisk and @Risk.
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3.2.4 Financial Sustainability
A key question involves whether a hydropower project is sustainable. Are there enough resources to
maintain the flow of expected project benefits over the life of the project? If a hydropower project is not
sustainable, economic benefits will not be realized and investment resources would not have been
adequately allocated to their best use. Another key question is whether the operating institution is in
adequate financial health to operate and maintain the project.
Project financial viability: The question of whether the hydropower project is profitable for the project-
operating entity is answered by the project’s financial internal rate of return (FIRR). In the FIRR
calculation, all financial costs under the hydropower project and revenues resulting from it are taken into
account. The FIRR is then compared to the weighted average cost of capital. If the FIRR is greater than
the weighted average cost of capital, then the project is deemed financially viable.
Institutional financial viability: Not only must the project in itself be financially viable, but the project-
operating entity must also be financially capable of implementing and operating the proposed hydropower
project. A financial analysis of the project-operating entity is needed to determine if it has the financial
capacity to implement and operate the proposed hydropower project efficiently and effectively. A
financial analysis comprises and assessment of the income statement, cash flow statement, and balance
sheet.
Risk analysis, similar to that in the benefit-cost analysis, should also be undertaken.
3.3 Staffing Needs
Staffing needs for an Economic Planning Unit in DOED are modest. It would comprise initially four staff,
with more if needed. The four staff would undertake the following functions:
Unit Head: supervision of Economic Planning Unit staff, development
of annual unit work plan, and training of staff.
Minimum educational requirement: master degree in
economics with specialization in econometrics.
Economist: load forecasting, economic modeling, shadow pricing of
data, least cost generation planning (with the engineer),
data collection, management and storage.
Minimum educational requirement: master degree in
economics with specialization in econometrics.
Engineer: least cost generation planning, review of feasibility studies,
data collection, management and storage.
Minimum educational requirement: bachelor degree in
engineering.
Financial Analyst: project financial analysis (FIRR), institutional financial
analysis and financial statement forecasting, data
collection, management and storage.
Minimum educational requirement: bachelor degree in
accounting.
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SECTION 4: Conclusions and Recommendations
1.1 Conclusions and Recommendations
DOED does not have the full capacity, at this time, to guide the development of Nepal’s power system or
to evaluate potential hydropower projects on an economic basis. For DOED to play a more meaningful
role in the development of Nepal’s power sector, this report recommends the following:
(i) establish an Economic Planning Unit within DOED with the responsibility to: (a)
prepare long-term load forecasts, (b) develop least cost generation expansion
plans, (c) determine the economic viability of individual generation projects, and
(d) to assess the financial impact of these projects on the operating entities;
(ii) staff the Economic Planning Unit with 4 suitably qualified professional staff: a
unit head, an economist, an engineer, and a financial analyst; and
(iii) acquire the WASP IV software program and other commercial software, such as
Microsoft Office or Open Office, Eviews or Easy Reg, and ModelRisk or @Risk.
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SECTION 5: Training Course on Economic Analysis of Hydropower Projects
The details of the training programs delivered in Kathmandu, training materials, presentations, etc. made
by the Project Evaluation and Monitoring Specialist during the training under the TA is placed at
Annexure-VII
The presentations made by the Project Evaluation and Monitoring Specialist are placed at Annexure-
VIII.
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CHAPTER-V
Legal Aspects in Hydropower Project Development and
Project Documentation
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SECTION 1: Review of Legal Documentation and Support to Team of Expert in Accomplishing TA Objective
1.1 Introduction
As per the Term of Reference and way forward agreed in Inception Report and to implement the TA
objectives, the legal consultant was required to undertake following task
1) Review legal aspects of the documentation related to the development of at least three private
hydropower projects under consideration by DOED. The consultant will assist in identifying
legal issues that need to be addressed.
2) Assist DOED staff in handling the legal issues during negotiations with the private companies
on developing potential hydropower projects.
3) The consultant will assist in negotiations, primarily with the terms of the power Development
agreement.
4) The consultant will assist in other areas as needed.
5) The consultant will organize various consultative meetings with DOED personnel.
6. The consultant will organize and conduct workshop and seminar to enhance the negotiation
and reviewing skill of the above agency professionals.
To implement the approached as mentioned in Inception Report and to improve and streamline regulatory
frame work for development of hydro electricity project, the legal consultant undertook the following
tasks
1.2 Task perform during Inception Mission
The legal consultant was involved in CDTA Fact Finding Mission from the Asian Development Bank
(ADB) since May 27, 2011. The legal consultant assisted International consultants and DOED in
organizing the stakeholder meeting and participated in these meetings with the officials of the Ministry of
Energy (MOE) and Department of Electricity Development (DOED), and other development partners.
During the Inception Mission legal consultant assisted in conducting a half day inception workshop and
presented the legal issues on institutional capacity of DOED in the power sector development in Nepal
and also help recommend, and prepare the work plan on capacity development.
1.3 Task performed after Inception Mission:
a. Review of Laws, Regulation and Hydro policy:
As per TOR, the consultant reviewed the relevant legal aspects of the documentation related to
the development of some of private hydropower projects under consideration by DOED in line
with current Electricity Act, regulation and hydro policy. The legal consultant also identified
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some of the legal issues that are needed to be addressed by DOED during PDA negotiation which
was also discussed and analyzed during capacity development program conducted in Nov 2011
and May 2012.
b. Capacity Building Workshop from Oct 30 to - Nov 30, 2011
In order to enhance the negotiation capacity and reviewing skill of the personnel of DOED, MOE
and NEA, a capacity development workshop on Private Sector's Participation in Nepal's Hydro
Project was organized in DOED Building from Oct 30- Nov 30 2011.
The purpose of above mentioned program was to give detail knowledge and international
prospective to participants on the following issues in developing hydro project/selecting project
developers:
vi. Provide guidelines and procedure for the preparation of Request for proposal
documents for soliciting Bids from Independent Power procedure and evaluation
of Bid received
vii. Legal framework for IPP selection and development of Regulations for IPP
Selection
viii. IPP Project Development Process
ix. Method and process of Procurement
v. Grounds for going for Unsolicited Proposal
The program was mainly led and organized by International Hydropower Policy Specialist. Legal
Consultant assisted and was closely involved with the international consultant in conducting and
completing the said training program. The program was conducted in adult teaching method,
making participants to participate in discussion on the issue and concern related to identifying and
selecting IPP. In addition to providing logistic support for the training program, the legal
consultant also coordinated with DOED in inviting and selecting participants for the program.
Legal consultant discussed and presented issue in the training program that DOED may confront
with during PDA negotiation with private sectors developer. Legal consultant assisted in
organizing the workshop in coordination with DOED in term of finalizing the participants and
providing other logistics. Legal consultant coordinated and facilitated and provided logistic
support in organizing and completing one month Capacity Development (CD) program in Nov
2011.
c. Coordination and facilitation in field Trip program:
As part of capacity building of manpower from MOE, DOED and NEA, the consultant assisted in
preparing and organizing filed visit trip to Laos and Philippines. The legal consultant coordinated
with DOED and Capacity Development Coordinator for the TA in facilitating the success of the
trip.
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d. Facilitation in handing over of the training related equipment to DOED:
The legal consultant also facilitated and assist Capacity Development Coordinator in handing
over the training related equipment such as laptop, photocopy machines etc. During the whole TA
period, Legal consultant coordinated between ADB, DOED and team of consultants for
progressing of project activities and had organized various consultative meetings with DOED and
MOE personnel.
e. Capacity Development Program in 7th May to 18th May 2012
In order to complete the assigned task under this TA, the Legal consultant facilitated and assisted
in organizing two CD programs. The legal consultant coordinated between DOED and
International consultant in finalizing the training date for May Workshop, coordinated with
DOED in finalizing training program and date, and coordinated with DOED in finalizing the list
of participants, modalities of the workshop and any other related matter. Two CD programs were
organized in May 2012.
In both training programs in May, the legal consultant presented issues to be address while
negotiating PDA and PPA. The issues discussed in the workshop relate mainly with defining the
right and obligation of the parties, necessary terms and condition of contract, default clause,
termination clause and penalty clause. The discussion also focused on dispute resolution clause.
Techniques of negating with opponent, issues to be addressed are the other issues which was
discussed with participant,
i. 7th May- 11th May 2012 CD Program
One week training program on " Economic Analysis and of the Hydro Project" was
conducted by Project Evaluation and Monitoring Specialist for 50 participants from
DOED, MOE and NEA. The program was conducted in morning and afternoon sessions.
Each session was attended by 25 participants.
Following issues were presented and discussed in the said program:
i. meaning and scope of economic analysis,
ii. meaning of least cost analysis,
iii. concept of economic cost,
iv. benefit and sustainability of cost analysis.
Legal consultant assisted in organizing and conducting the said program, provided
logistic support and was part of training program with the Project Evaluation and
Monitoring Specialist in providing local context and existing legal and policy matter
relating to hydro development. The program was conducted for five days. Evaluation of
the program was done by the participants and they like the program very much.
ii. 13th May- 18th May 2012 CD Program
One week training program on "Project Documentation for “Hydropower Development
Financing through Independent Power Producers" was conducted by the Hydropower
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Policy & Planning Specialist along with Legal consultant for 50 participants from
DOED, MOE and NEA. The program was conducted in the morning and afternoon
sessions each day. Each session was attended by 25 participants.
The Hydropower Policy & Planning Specialist along with Legal consultant made
presentations on “General Considerations in IPP Hydro project Agreement
documentation”. Presentations and discussions were held on:
vi. Tentative list of Project Agreement Documents
vii. Model MOU
viii. Main feature of Model PDA
ix. Model Power purchase agreement
x. EPC contract
iii. Presentation of issues in Model Project Development Agreement by Legal
consultants
Legal consultant assisted in organizing and conducting the said program, provided
logistic support and was part of training program with Project Evaluation and Monitoring
Specialist in providing local context and existing legal and policy matters relating to
hydropower development. The program was conducted for five days.
The issues that have been identified by the legal consultant and were discussed and
analyzed in the training program were as follows:
i. Issue on the Terms of Concession agreement
ii. Issues regarding Commercial operation date
iii. Issue regarding Change of law
iv. issue on Sovereign Guaranty
v. Issue of performance guarantee to be placed by developer
vi. Issue regarding repatriation of interest, principal and other
amount earned by the developer
vii. Issue regarding default and compensation
viii. Issue regarding Force Majeure Event
ix. Issue regarding condition of termination of the Agreement
x. Issue regarding Dispute settlement clause
The participants did evaluation of the program and from the evaluation it was found that
they liked the program very much. The Legal consultant facilitated the distribution of per
diem, providing of food and other stationary and providing photocopies of the training
material to the participants. The legal consultant also delivered his inputs as per the TOR
and the CD program was conducted successfully and participants insisted that such
capacity building program to be continued in future as well.
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1.4 Summary of the Activities completed by the Legal Consultant against the items listed in the
TOR
2. Review legal aspects of the documentation related to the development of at least three private
hydropower projects under consideration by DOED. The consultant will assist in identifying
legal issues that need to be addressed.
This task was completed before CD program was conducted. The Legal consultant reviewed the
some of the limited documentation provided by DOED in identifying the issues that need to be
addressed during PDA negotiation. The legal consultant also reviewed Model PDA as prepared
by DOED. The issues that have been flagged by the legal consultant during the review of project
documents were as follows:
i. Issue on the Terms of Concession agreement
ii. Issues regarding Commercial operation date
iii. Issue regarding Change of law
iv. issue on Sovereign Guaranty
v. Issue of performance guarantee to be placed by developer
vi. Issue regarding repatriation of interest, principal and other amount earned by the
developer
vii. Issue regarding default and compensation
viii. Issue regarding Force Majeure Events
ix. Issue regarding condition of termination of the Agreement
x. Issue regarding Dispute settlement clause
These issues were discussed and analyzed during the CD program conducted in November 2011
and May 2012.
2. Assist DOED staff in handling the legal issues during negotiations with the private
companies on developing potential hydropower projects.
3. The consultant will assist in negotiations, primarily with the terms of the power
Development agreement.
These two tasks were not completed as DOED did not conduct any negotiation with any private
hydro developer during this TA period.
4. The consultant will assist in other areas as needed.
The legal consultant assisted and provided support for the completion of the project activities as
and when required. The activities completed are mentioned above.
5. The consultant will organize various consultative meetings with DOED personnel.
This tasked is completed as the Consultants assisted in conducting and organizing stakeholder
meeting, consultation meeting with DOED and MOE officials.
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6. The consultant will organize and conduct workshop and seminar to enhance the
negotiation and reviewing skill of the above agency professionals.
This task is also completed as the legal consultant assisted International consultants in organizing
capacity development program in Nov 2011 and May 2012.
1.5 Conclusions and Recommendations
After working with DOED personnel and conducting of CD programs, it seems that DOED may not have
the full capacity, at this time, to negotiate PDA documents with private sector. They also need to evaluate
and gauge the underlying legal issues and their ramifications in the long run. In order for DOED to play a
more effective and meaningful role in the development of Nepal’s power sector through private sector
participation; the following recommends are being made:
i. establish strong legal cell within DOED with the responsibility to:
(a) prepare the list of legal issues that need to be addressed during PDA
negotiation
(b) determine the level of flexibility available to negotiating team for negotiating
PDA with private developer
(c) the benefits and incentive that DOED may provide to developers to encourage
them to invest in the large hydro project in Nepal
(d) to assess and analyze the legal impact of such negotiated PDA on the future
prospective developer;
(ii) staff the legal cell of DOED with qualified legal experts, having sufficient experience
in negotiating project documents and also have a provision of hiring external legal
export on case to case basis; and
(iii) acquire the relevant legal resources and computer network to access international
legal resources in order to enable the members of the legal cell to equip and update
with pertinent legal issue relating to project development documentation.
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CHAPTER-VI
Training, Equipment Procurement, Project Coordination
and Implementation
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SECTION 1: Training, Field Visit, Equipment procurement and Coordination
1.1 Training Needs Assessed
Capacity Development needs assessment carried out during the Fact Finding Mission and finalized during
the Inception Mission, at the very outset of the project implementation, inter-alia highlighted the need for
imparting various training programs to the professionals of the Nepal Power Sector stakeholder
organizations. However, given the limited budget under the TA, as against the training needs assessed
during the Inception Mission; it was felt that only a select few training programs could be imparted under
the TA. These included the in-country training programs to be imparted by the Hydropower Policy &
Planning Specialist, Project Evaluation and Monitoring Specialist; and the Legal Expert within Nepal
relatively to a larger number of professionals and a few External Training programs outside the country
for select senior professionals from the MOE, DOED, ETFC and NEA.
1.2 In-county Training Programs
A brief overview of the training programs held for the professionals of MOE, DOED and NEA and ETFC
within the country is given below. The details thereof are contained in Chapters II-V above. The training
materials and presentations made during these training programs are given in the Annexure of this report.
i. Training Program on “Private Sector Participation in Nepal Hydropower Sector” from
October 30 - Nov 30, 2011
This capacity development training program on “Private Sector's Participation in Nepal's
Hydropower Sector” was delivered by the Hydropower Policy & Planning Specialist along
with the and Legal Consultant between October 30- Nov 30 2011. The program was
organized in DOED for the participant from the DOED, MOE and NEA.
ii. Training Program on “Economic Analysis and of the Hydro Projects” from May 7- 11,
2012
One week training program on “Economic Analysis and of the Hydro Projects” was
conducted by Project Evaluation and Monitoring Specialist along with the Legal Consultant
for 50 participants from DOED, MOE and NEA.
iii. Training program on "Project Documentation for Hydropower Development Financing
through Independent Power Producers" May13 – 18, 2012
The one week training program on "Project Documentation for Hydropower Development
Financing through Independent Power Producers" was conducted by the Hydropower Policy
& Planning Specialist along with Legal Consultant for 50 participants from DOED, MOE and
NEA during May 13-18, 2012.
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1.3 External Training Programs
In addition to the In-country training programs, two external training programs were conducted
during the TA project implementation period. These include, the one held for the senior level
officers of MOE, DOED, ETFC and NEA at Asian Institute of Management (AIM) in Manila,
Philippines. The other one was organized for the official from the above organizations at
Administrative Staff College, Hyderabad India.
i. Training Program at Asian Institute of Management (AIM), Manila; March 19-
23, 2012
The participants arrived in Manila on Sunday March 18, 2012 and the training
program started on Monday March 19, 2012. The week long training program on
“Project Planning and Management” for 20 senior most professionals of MOE,
DOED, ETFC and NEA was organized at AIM, Manila. The topic covered included
Project Conceptualization, Project Evaluation, Project Implementation Mechanisms,
Project Financing, Project Risk Management, Environmental Impact Assessment,
Sustainability Impact Assessment and Project Monitoring, Power Industry and Power
Trade Systems.
In addition to the above topics, specific case studies on hydropower projects
including the Kali Gandaki, hydropower project in Nepal were discussed threadbare.
The aim was to expose the participants to the challenges faced in developing
hydropower project and how these challenges have successfully been overcome by
the concerned stakeholder organizations and governments in difficult circumstances.
During the visit to ADB headquarter in Manila; presentations were made by the ADB
staff about lender’s concerns while financing large hydropower projects in difficult
situations, such as, those prevailing in Nepal and also other aspects that the lenders
are concerned about while financing project in underdeveloped countries. A briefing
was done on ADB Private Sector Infrastructure Investment by representative of the
PSIF Division and the participants got the opportunity to interact with on ADB
operations staff as well.
During the training program, field visit to the various organizations including the
Electricity utilities, such as, National Power Corporation (NAPOCOR) and Manila
Electric Company (MERALCO); Energy Regulatory Commission and Caliraya-
Botocan-Kalayaan (CBK HEP), the pump Storage project. At each of these field
visits, the concerned organizations made presentation about their operations and
shared their experiences with the participants.
The participants left for the field visit to Nam Theun 2 hydropower project in Lao
PDR on March 25, 2012.
Due to the large size of the training materials, the same have been put up in Volume-
II with appropriate titles of this report.
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ii. Training at Administrative Staff College of India (ASCI), Hyderabad
A week long training program on “Power Sector Regulation for Nepal Electricity
Tariff Fixation Commission” for 10 participants from MOE, DOED, ETFC was
organized at Administrative Staff College of India (ASCI), Hyderabad from October
1-5, 2012. However, due to some personal problems two of the participants could not
attend the training, therefore leaving the effective strength of the batch to 8
professionals only. The participant arrived in Hyderabad on September 30 and
returned to Kathmandu on October 6, 2012.
The training program covered the following topics:
Power Sector Regulations: overview of concepts and issues
Power Sector Regulation in South Asia
Power Sector Regulation in Nepal: Existing Laws, Practices and Rules
Independent Regulation: Institution and Processes
Licensing: Conditions, Monitoring and Compliance
Regulating Tariffs and Multiyear Tariffs
NEA Tariff Case study Introduction
Tariff setting: Average Revenue Requirement in Generation
Transmission and Distribution
Consumer Redressal Mechanism
Stakeholder Consultation and Outreach
Hydropower Regulation and Tariffs
Retail Tariff Design
NEA Tariff Fixation and Presentation on Case Study
Development of Regional Markets
In addition to the class room training, visits were organized to the Andhra Pradesh
Electricity Regulatory Commission, where the commission made presentation on its
functioning and the process of tariff fixation by the commission; followed by
discussion about the various issues and challenges in tariff fixation. Another visit to
the Consumer Centre of the Andhra Pradesh Central Power Distribution Company
Limited in Hyderabad was organized to help participants see, as to how the company
has streamlined its procedures to provide efficient services to its consumers in a time
bound manner and how it has put in place an effective consumer redressal mechanism
to address the consumer complaints.
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Due to the large size of the training materials, the same have been put up in Volume-
II with appropriate titles of this report.
1.4 Field Visit to Nam Theun 2 Hydropower Project
In order to help the Nepal power sector professional appreciate as to how an underdeveloped
country facing several challenges, somewhat similar to those being faced by Nepal, could
successful implement a large (1070 MW) hydropower project; a field visit to the Nam Theun 2
(NT 2) Hydropower Project in Lao was organized back-to-back with the training program at
AIM, Manila for the 20 participants who attended the training at AIM. The participants arrived
in Vientiane in the late evening of March 25, 2012.
On Monday March 26, 2012; the field visit to Lao started with a courtesy meeting with the
Country Director ADB Lao Resident Mission. This was followed by a meeting with the
Secretary Ministry of Energy and Mines, Lao DPR and with the Department of Energy Business
in the Ministry of Energy and Mines, who made a presentation to the participants about the
approach taken by the Lao government in facilitating the project to happen despite all odds.
These included policy initiatives, government support in various forms for smooth formulation
and implementation of the project.
In the afternoon, the participants visited the Nam Thuen Power Corporation (NTPC) Head Office
in Vientiane where a presentation giving an overview of the development and implementation of
the NT2 project was made by the NTPC management. The participants were also briefed about
the field visit to the project site. Then the journey to Thakek began. After an overnight stay in
Thakek, the participants arrived at the project site on March, 27. A presentation about the project
technical aspects and an overview of how the power station works was given to the participant at
the NTPC Visitor Center. This was followed by a visit to the power house including a tour of
erection bay, turbine floor and control room, followed by a Environmental presentation by
NTPC. Discussions focused around water quality, monitoring, green house gases, wildlife rescue
in the reservoir; followed by a visit to environment monitoring laboratory. A presentation on
resettlement of project affected persons was also made.
The afternoon session comprised of a visit to the village set up by NT 2 as part of their
resettlement plan for the project evacuees and the village community centre, the school, and the
hospital. The participant got an opportunity to interact with the villager and find how
comfortable they feel in the new environment. Thereafter the participants were taken to the
Bouama view point (reservoir) Observation.
On March 28, the participants drove back to Vientiane via regulating dam, aeration weir, and
downstream tunnel. A detailed presentation on environmental aspects and downstream
environmental management program being implemented by NTPC was made to the participant at
the NTPC Thakek office, after which the participant drove back to Vientiane for catching the
flight back to home.
The field visit to NT 2 was an eye opening exercise for the Nepalese participants, as they could
see for themselves as to how a small country with limited resources, difficult financial situation,
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challenging social conditions and environmental concerns; was able to overcome all the hurdles
and implement the NT 2 project. In addition to this, the participants realized as to how a small
country could collaborate with its neighbor i.e. Thailand and allow the EGAT, the Thai
electricity utility to operate the NT 2 plant from their own control room in Thailand. Tasting the
successful implementation and operation of the NT 2 power plant, Lao is contemplating
additional power export oriented projects; not only to export the energy to Thailand but to other
countries in the region, thereby increasing it earning from energy export to support the faster
economic development.
Taking a leaf from this experience, Nepal could immensely benefit from adopting an open
approach, as done by Lao in developing it hydropower resources, meet its own energy demand
and export the surplus energy to the neighboring countries in the region.
Due to the large size of the training materials, the same have been put up in Volume-II with
appropriate titles of this report.
1.5 Procurement of Equipment In order to help the Ministry of Energy government of Nepal and Department of Electricity Development
have the latest tools for an effective functioning of these organizations, the TA had a provision of
purchasing some hardware, software and office equipment. Given the size of the budget, at the advice of
DOED (the nodal agency designated by the GON for the TA), ADB procured the following equipment at
a total cost of NR 1,381,990 following the ADB procurement procedures.
i. One Digital Photocopy Machine (Heavy Duty), Make RICOH, Model MP 2000
ii. One Canon Multifunction PRINT, COPY, SCAN, FAX
iii. Ten Dell N5110 Laptops
iv. Software Microsoft Office 2010, one each for the laptops, as requested by the DOED
The equipment was handed over tot the DOED under the supervision of the ADB Nepal Resident Mission
Representatives and a formal handover/takeover receipt was obtained and submitted to the ADB.
1.6 Coordination of Activities performed under the TA The Capacity Development Coordinator performed all the activities listed in his TOR for smooth
implementation of the TA. These included organizing and participating in the Mission meetings with the
stakeholder organizations, organizing the Inception Workshop, preparation of the Inception, Interim and
Final Reports. Day to day coordination with the Consultant team, for finalizing the work plans, their
implementation and follow up with stakeholders. Election of Training Institutions in consultation with
ADB and stakeholders Organizing for conducting external training programs at AIM, Manila; ASCI
Hyderabad; Field visit to NT 2 Lao; and arranging all necessary logistic support for successful
implementation of these programs. Purchase of equipment etc.
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Annexure A
Guidelines for Determination of Tariff for IPPs
The following guidelines are provided for the determination of bulk power purchase tariffs for
hydropower IPPs set up to sell electricity produced to the utility and for export under a Power Purchase
Agreement (PPA).
A.1 Hydrological Risk
Hydrological risk is defined as the risk of variability of water flows, and therefore of the effective energy
output of the hydro IPP. This risk shall be absorbed by the Government or the power purchaser. For
judicious assessment of this risk, ‘Mean Flow/Month’, based on monthly average water flow, will be
determined from available hydrological data. This will entail determining mean water flows from the data
collected at certain specified points upstream of the plant location. Energy production corresponding to
the mean flow shall be called ‘Mean Flow Energy Production’ and the corresponding plant capacity shall
be called ‘Mean Flow Capacity’. In practice the actual energy production and capacity may vary from the
mean flow levels due to:
i. Variation of water flow from the mean flow/month (a factor beyond the control of
hydroelectric power generator).
ii. Availability of the plant for electricity generation (within the control of hydroelectric power
generator).
The principle to be adopted is that the hydroelectric generator (IPP) will be made immune to factors
which are beyond its control (i.e., variability of water flow), but fully responsible for factors within its
control (i.e., the availability of the plant). Accordingly, the matrix shown in Table1 for the allocation of
hydrological risk shall be followed.
A.2 Water Flow Monitoring
To enable monitoring of water flow independently, monitoring sensors will be set up by the relevant
Government Agency with properly calibrated, automated sensors and data loggers. The monitoring
sensors will be sited at the nearest location upstream of the plant site where total water flow passing
through the plant turbines is available.
Table 1: Hydrology Risk Allocation Matrix ____________________________________________________________________________
Hydro Variation Availability Status* Risk Mitigation
____________________________________________________________________________
a. Actual - Capacity of the hydroelectric - hydroelectric IPP will be paid for
water IPP available is equal to the energy generation corresponding
flow/month Mean flow Capacity level to Mean Flow (i.e., the power
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less than purchaser absorbs the loss)
the Mean - Capacity of the hydroelectric - Hydroelectric IPP is not paid to
Flow/Month IPP is not available wholly the extent that capacity is not
or partially (i.e., is less than available
Mean Flow Capacity)
___________________________________________________________________________
b. Actual - Capacity of the hydroelectric - Hydroelectric IPP will be paid for
Water IPP available is equal to the energy generation corresponding
flow/month Mean Flow Capacity level to ’Mean Flow Plus’ (i.e., Mean
more than Flow Energy production plus 10%
the Mean of the value of energy generated
Flow/Month above the mean flow; e.g., if the tariff is Rs /kWh, then the
production up to the Mean Flow
Energy Production level will be
paid at the rate of Rs /kWh, and
any additional production will be
paid at the rate of 0.1 x Rs
/kWh) as a production bonus,
so that both the producer and
purchaser share the benefit of increased production
.................................................................................. - Capacity of the hydroelectric Hydroelectric IPP is paid equal to
IPP is not available wholly the actual energy generation up
or partially (i.e., is less than to the Mean Flow Energy
Mean Flow Capacity Production level only
__________________________________________________________
c. Actual - Hydroelectric IPP is - Hydroelectric IPP will be paid for
Water available equal to the Mean the energy generation
flow/month Flow Capacity level corresponding to the Mean Flow
equal to the Energy Production
Mean ----------------------------------------------------------------- Flow/Month - Capacity of the hydroelectric - Hydroelectric IPP will be paid
IPP is not available wholly equal to the actual energy or partially (i.e., is less than generation up to the Mean Flow Mean Flow Capacity) Energy Production level only
____________________________________________________________ * Plant availability status shall be confirmed from the electronic record of each machine and the
relationship of the energy generation with the variation from Mean Flow/Month shall be ascertained at the
time of the PPA.
A.3 Incorporation of a Company
Each hydroelectric IPP will be required to form a company in accordance with the Nepal laws and the
Companies Ordinance (or ACT), 19??? for the specific purpose of hydropower generation.
A.4 Tariff Options
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The tariff for sale/purchase of electricity from the hydropower IPP may be arrived through:
i. Competitive bidding (solicited proposals)
ii. Negotiations (unsolicited proposals)
iii. Up-front tariff-setting.
A.4.1 Tariff through Competitive Bidding on Solicited Proposals
This would entail determination of tariff on the basis of competition in accordance with the Policy for
Power Generation Projects, (year????). The bidding process may be structured along either of the
following two options:
i. Bidders may be required to submit their competitive proposals for the tariff
ii. A benchmark tariff may be offered up-front, and bidders invited to quote
a discount on the benchmark price.
Once a tariff has been arrived at through competitive bidding based on either of the processes mentioned
above, it shall not be subjected to further review by the Government. The bidding process will be
structured and administered by the Government in consultation with the power purchaser, Ministry of
Finance, and other concerned agencies. The bidding documents (including various formulae, formats,
etc.), along with evaluation criteria, will be also finalized by the Government in consultation with the
same agencies, so as to define a common standard for the preparation and comparison of quotations. The
lowest evaluated levelized tariff would be recommended by the relevant Government Agency to the
government for acceptance.
A.4.2 Negotiated Tariff for Unsolicited Proposals and Up-front Tariff
Multiplicity of entities and states of negotiations will be avoided in the determination of power purchase
tariffs for IPPs. If an IPP wishes to submit an unsolicited proposal and wants to settle tariff through
negotiations, the Government Agency will determine the tariff in consultation with the IPP, the power
purchaser(s) and other stakeholders. Projects opting for up-front tariff determined by Government will not
require any further negotiations, approvals, or clearances with respect to the purchase price of the
electricity produced. In the determination of an acceptable negotiated tariff for an IPP, the following
parameters shall be taken into account.
A.4.2(a) Technical Parameters
The net energy available for sale will be determined after taking into account electrical efficiency,
auxiliary loads, transformation efficiency, etc., and plant availability. Plant availability factor should be
determined judiciously, taking into account suitable provisions for anticipated maintenance and forced
outages. Once a contract (PPA) has been entered into, the parameters adopted at the time of the agreement
shall not be changed for the duration of the contract.
A.4.2 (b ) Financial Parameters
126
It is proposed that the following parameters, principles, and assumptions may be adopted for calculation
of the up-front or indicative hydroelectric IPP tariff:
i. Debt: Equity Ratio
• For the purposes of determination of tariff, equity equal to 20% of
the total cost of the project would be the benchmark.
ii. Internal Rate of Return/Return on Equity
• Tariff should be determined allowing reasonable Internal Rate of
Return (IRR) on equity investment. Certified emission reduction
(CER) credits earned by qualifying projects under the Clean
Development Mechanism (CDM) will be reflected in the project’s
revenue stream at a realistic prospective price and accounted for in the
IRR calculation, as per government guidelines.
• IRR be calculated over the life of the Implementation Agreement
(IA), starting from the date of construction start (i.e., start of payments
to contractors).
• IRR should be equal to long-term interest rates based on market
forecast, plus a premium of x %, to be determined by Government.
• For BOOT projects, the investor’s equity will be allowed to be
redeemed after completion of debt servicing. The redemption in equity
will be in equal installments from the time debt servicing has been
completed till the end of the concession period. The effect of exchange
rate variations will be compensated for in determining equity
redemption. The projects will be transferred to the GON at the end of
concession period at a notional cost of NRs 1.
• For BOO projects, there will be no redemption of equity.
iii. Interest on Loans
For unsolicited proposals, tariff determination will be a two-step
procedure. Initially, an indicative tariff will be estimated, taking into
account expected financial returns and carbon revenues, at the time of
award of LOS so as to enable an IPP to achieve financial close. At this
stage, interest rate ceilings may also be indicated with incentive provided
for the IPP to arrange better terms of financing. After financial closure,
the tariff will be finally fixed such that the project’s debt service cost
component equals actual debt servicing plus the incentive. The same
methodology applies to up-front tariff determination by the Government
at the LOS stage (i.e., before financial close). For foreign loans, the
ceiling rate may be taken as LIBOR plus a suitable spread for ten year
loans with two-year grace period. IPPs will be given an incentive to
arrange better terms of debt financing. If the IPP succeeds in arranging
better terms by the time the project achieves financial close, the overall
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impact of reduction in debt servicing will be shared, in the case of
competitively determined tariffs for solicited projects and negotiated
tariffs for unsolicited projects, on a yearly basis in the following ratio:
Power Purchaser/Govt: IPP = 60:40
However, for projects opting for the up-front tariff, no such sharing will
be required and the project sponsor shall be entitled to retain the full
benefit of any concessional financing obtained below the prescribed
interest ceiling. The benefit of carbon financing will also be exempt from
this provision, as explained earlier, and shall be shared separately with
the project sponsor in the form of ‘green’ credit payments (i.e., as
defined in the CERA). Wherever a floating interest rate regime is
adopted, local loans may be indexed to changes in relevant benchmark
interest rates. Likewise, foreign loans may be indexed to changes in
relevant benchmark interest rates, such as LIBOR, etc., and variation in
Nepalese Rupee to the US Dollar. Loans will be arranged by IPPs
without GON guarantee.
iv. Capital Cost
Estimation of an IPP’s capital costs for unsolicited, negotiation-based
proposals or up-front tariff determination is a challenging task.
Government should determine them after thoroughly assessing market,
vendor, and IPP provided information.
v. O&M Cost
The operation and maintenance (O&M) cost comprises of fixed a
variable components. NEA (?) should access information from the same
sources as for the capital costs to arrive at a judicious determination of
O&M costs, both fixed and variable.
vi. Other Incentives
All fiscal and financial incentives provided to IPPs by the G0N, as given
in the policy (see Section 8.6) shall be applicable.
A.5 Tariff Structure and Features
Bulk power tariff for export or grid-connected IPPs will be denominated in US dollars per kilowatt-hour
(US$/kW) or Nepalese Rupees per kilowatt-hour (NRs/kWh). The tariff will be determined by
Government on the basis of the principles and parameters given above. The tariff will be based on an
energy charge, and since it will be arrived at by providing for full cost recovery and appropriate return on
equity (ROE)—inclusive of carbon credit revenue, along with full protection against hydrology risks and
additional-bonus payments, as applicable and noted above—the tariff will enable the IPP to meet its
revenue requirements. The tariff will not be broken down into capacity payments and energy payments
because it is difficult for IPPs to guarantee capacity availability and also because the Government (power
purchaser) will be fully covering resource (Hydro) variability risks. The energy-based tariff in NRs/kWh
will be broken down into two components:
i. Non-escalable energy component
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This will be based on non-escalable costs divided by the energy (kWh)
sold. Non-escalabe costs comprise of:
• Debt service
• Return on equity (ROE).
ii. Escalable energy component
This component will be based on the following costs divided by the electricity
(kWh) sold:
• Fixed O&M costs
• Variable O&M costs.
A.6 Water Use Charge
A water use charge will be payable by the generation company to the Government for the use of water
resources by the power project to generate electricity. The water use charge will be fixed at Rs 0.15/kWh
and shall be adjustable annually for inflation as per table 2.
A.7 Benchmark Currency Rate
The Benchmark Currency Rate, as a reference, will be the Interbank rate for US dollars (US$) prevailing
30 days before the required date of submission of bids. For unsolicited proposals or up-front tariff
determination, it will be the interbank lending rate as on the date of signing of the Engineering-
Procurement-Construction (EPC) contract by the IPP.
A.8 Indexation
Indexation of various components of tariff and adjustment for foreign exchange rates (‘true up’) will be
automatic, based on predetermined formulae and reference parameters. IPPs will not have to approach
Government frequently for tariff indexation; only yearly submissions may be required. Various costs
component shall be indexed as shown in table 2.
Table 2: Indexation of IPP Tariff
____________________________________________________________________________
Item Index
-------------------------------------------------------------------------------------------------------------------------------
Non-escalable Component
Debt service Floating interest rates
Variation in exchange rate for US$ with respect to the
benchmark currency rate for FEC
…………………………………………………………
Return on equity
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(ROE) Variation in exchange rate for US$ with respect to the
benchmark currency rate for FEC of equity
-------------------------------------------------------------------------------------------------------------------------------
Escalable Component
Fixed O&M costs Indexed with Wholesale Price Index (WPI) w.e.f. COD
………………………………………………………..
Water use charge Indexed with Wholesale Price Index (WPI) w.e.f. COD
____________________________________________________________________________
FEC: Foreign exchange component.
A.9 Evaluation of IPP Tariffs
Based upon guidelines provided above, detailed power purchase tariff tables will be prepared by
Government. The tariff will be evaluated on the basis of the cost of energy production levelized over the
life of the project, or at least 20 years, and the schedule shall be suitably front-loaded to cater to the
project’s debt servicing requirements.
A.10 Transparency and Visibility of Calculation of Tariff
Government shall provide complete soft and hard copies of its assumptions, inputs and methodology used
in the determination of IPP tariffs, along with the complete tariff computation and model, to the IPPs as
well as the public domain. This would enable better understanding of tariff decisions by all concerned.
A.11 Transmission and Interconnection
It is proposed that the construction of transmission lines for evacuation of power from IPPs set up for
connection to the utility grid or for direct export should be the responsibility of the power purchaser,
unless the IPP, of its own choice, undertakes to install such infrastructure on a mutually agreed upon
transmission charge with the power purchaser subject to the provisions of Section 8.2.2.
A.12 Compliance with GON Policies
The concerned Government Agency (ies) shall comply with and ensure that the IPPs comply with the
policies and guidelines of the Government of Nepal as issued, modified, supplemented, and revised from
time to time by the government.
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Annexure B
Hydropower Pricing
1.0 Need for Hydropower Pricing
Water resource is the only natural resource Nepal has in abundance. Converting this renewable natural
resource to its beneficial uses has become imperative for Nepal to take a quantum jump in the race for
economic development. Hydropower is one such beneficial use. Widespread electrification in the country
based on hydropower will not only provide the base for industrialization of the country but also become
one of the tools for social equity and justice (especially in the improvements of health and education
through quality supply of electricity and support to the rural economy). Excess hydropower can be shared
with other countries of the region and thus, can become another link in the integration of the economies of
the countries of the region. For these reasons proper hydropower pricing is necessary so that it is both
affordable and competitive in the domestic as well as export markets. Use of a renewable, natural
resource has some value that can be termed “opportunity cost”. Therefore, hydropower price must also
reflect the full cost associated with its development including the renewable, natural resource use cost.
Furthermore, export of hydropower creates substantial secondary benefits in the importing country in
addition to the direct benefits of the power. There is a need to assess such secondary benefits by the
exporting country and reflect them in the pricing mechanism. These considerations have led to the need
for a study in hydropower pricing from Nepal’s perspective.
2.0 Electricity Tariff The terms, “cost”, “price” and “tariff” should be understood. Costing involves determining the value of
resources used in the production of goods or the provision of a service. The process of Cost valuation in
pricing is to act as a benchmark against which pricing and production decisions can be made. Thus, cost
of electricity refers to the cost of generating and delivering one unit (kWh) of electricity from a
hydropower plant to an agreed delivery point. Pricing refers to the process of determining a figure at
which products or services will be exchanged in the marketplace. The focus of pricing is on the income
received from the exchange of the good. Hydropower price refers to wholesale price, which is the price at
which the electricity producer sells electricity to the utility company or a distributor. Tariff, on the other
hand, is basically the retail price or the price charged by the utility to the final consumer. Energy
generated from hydropower has to be ultimately sold to the consumers (after deducting the system losses).
If the power market cannot afford the electrical energy, no hydropower generation can take place.
Therefore, knowing the present electricity tariff structures of Nepal and India will be beneficial in
understanding the electricity market situation.
3.0 Assessment of Costs of Hydropower Projects
3.1 Cost components of Hydropower Projects
Hydropower pricing is basically a function of the costs of the hydropower project. Costs of a hydropower
project consist of four parts:
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3.1.1 Associated costs
Associated costs are costs that are associated with the need to produce hydropower, such as costs of
engineering structures and equipment as well as their operation and maintenance costs. Associated costs
of a hydropower project during the construction phase are the costs for the following:
• Compensation and right-of-way for land and built-in property,
• Preparatory works such as camps, construction power supply and access roads within the site
area,
• Dam or head-works, waterways, powerhouse and switchyard,
• Electrical and mechanical equipment,
• Reregulating structure in case of storage project,
• Transmission line and substation, if they are integral part of the project, and Engineering,
management and administration.
Associated costs during the operation phase are simply the costs for operation and maintenance,
replacement and administration of the project. Sometimes, associated costs include some part of induced
and external costs when project design itself takes these aspects as an integral part. Fish ladder provided
for migration of fish, gate provided for release of minimum flow downstream of intake, equipment
provided in power station/ switchyard for local electricity supply are some of such examples.
3.1.2 External costs
External costs are costs that may be needed for the smooth construction and operation of the project
though they may also serve other purposes, such as new infrastructure development required for
accessibility to the project site. External costs of a hydropower project during the construction phase may
consist of the following:
Infrastructure costs such as upgrading of existing and construction of new transportation and
communication lines to provide accessibility to the project site,
Local development and rural electrification, and
Watershed management. Similar to the induced costs, no external costs are involved in the
operation phase unless some of them such as watershed management spill over in the
operation phase.
3.1.3 Opportunity cost of water
Opportunity cost of using water, the natural resource, in a hydropower project should be added to the total
cost to reach the full cost.
The Costs of a hydropower project occur during two phases. Phase one- during the construction phase of
the project, and Phase two, during the operation phase. Most of the costs are borne during the construction
phase, some in the operation phase and some of the costs in both the phases. For example, costs for
engineering structures and equipment are borne during the construction phase while their operation and
maintenance costs are borne during the operation phase. Costs for environmental mitigation measures
may continue in both the phases.
Unlike a thermal or nuclear power plant, a hydropower project is very site specific. A particular site for a
hydropower project will produce a specific amount of power and energy that no other site can duplicate.
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That means the design and consequently, the associated costs of a hydropower project are very much
dependant on the site. Induced costs and external costs also are dependent on the particular site selected.
Remoter site may mean higher infrastructure cost, storage site may mean higher resettlement cost, pristine
site may mean higher environmental mitigation cost, etc.
In addition there are two other types of the costs that are usually overlooked but are essential from the
viewpoint of hydropower development.
3.1.4 Conception/Project formulation cost
It involves site identification through field reconnaissance, field investigation, prefeasibility study,
feasibility study and preliminary engineering design to bring it to the construction phase. These costs are
treated as a part of the overhead cost or sunk cost of the concerned organization.
3.1.5 Decommissioning cost.
When the economic or commercial life of a project is over it needs to be decommissioned so as to bring
the ground situation back to its previous condition. However, in a hydropower project with large civil
works construction that totally changes the landscape, that is not a practical solution, but the generating
equipment can be decommissioned after its life is over. Decommissioning cost becomes more important
in thermal plants compared to hydropower plants because their lives are shorter than hydropower plants.
This implies that in an economic analysis the inclusion of such cost will benefit hydropower plant when
compared to a thermal plant. As in the conception cost, seldom is the decommissioning cost included in
the particular project cost.
3.1.6 Induced Costs
Induced costs of a hydropower project during the construction phase may consist of the following:
Resettlement and rehabilitation,
Environmental impact mitigation measures, and
Relocation of existing infrastructure such as transportation and communication lines, water
supply structures, public buildings, etc.
Usually there are no induced costs involved during the operation phase unless some of them such as
environmental mitigation measures spill over in the operation phase.
Land acquisition, compensation, resettlement and rehabilitation play a vital role in the development of a
hydropower project. Government support is crucial in each step for its satisfactory conclusion. A
generally accepted approach to compensation is that it is based at market price and is distributed well
before the start of the project. A better and more standard approach is to come up with a compensation
package based on the willingness to accept (WTA) principle. In other words, the displaced should be paid
the amount at which they would be willing to relocate elsewhere. Given that the real estate market and
market for land are not very efficient in areas where hydropower projects might be built, it would be
difficult to come up with market prices in most cases. The underlying objective in both principles, i.e.,
“WTA” and “compensation at market price” is that people displaced by a hydropower project must be
resettled and rehabilitated in a better manner than their previous living condition and environment. Such
resettlement and rehabilitation must be completed well before the completion of the project.
Employment generation schemes must be a part of the rehabilitation process for those who are bereft of
their livelihood due to the project. These are necessary in order to gain the acceptance and goodwill of the
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people towards the project. A hydropower project is usually situated in a remote and underdeveloped area
inhabited by economically weaker and underprivileged part of the society. In such a situation, it becomes
more imperative that these activities should be done in a satisfactory manner for the sake of social justice
as well as for smooth construction and operation of the project.
134
Annexure-I
Terms of Reference of the Consultants
Scope of Work:
As per the ADB implementation strategy, the energy sector capacity development advisor and capacity
development coordinator were to participate in the TA inception Mission as Mission members and
consult with the Ministry of Energy, the DOED and the ETFC to identify their capacity development
needs and arrange programs based on those needs. This would be followed up by the initiation of
implementation of various activities based on the above needs identified and agreed upon by the GON.
The scope of work of the five consultants is given below:
Capacity Development Coordinator (International)
Among other tasks, the consultant will:
(i) Provide an inception report within 1 month of the start of the assignment outlining the activities
to be carried out and the timeframes in consultation with the MOE and the DOED;
(ii) Coordinate the activities of the hydropower planning specialist and the project evaluation and
monitoring specialist;
(iii) Finalize the capacity development plan with guidance from the energy sector capacity
development advisor;
(iv) Prepare an interim report; and
(v) Prepare progress reports on the activities and the lessons learned, and prepare a final report.
Energy Sector Capacity Development Advisor (International)
Among other tasks, the consultant will:
(i) Consult with the MOE, the ETFC, and the DOED to identify priority areas for capacity
development programs; programs should include gender mainstreaming components;
Identify training programs and exchanges for MOE, DOED and ETFC and the institutions
providing such services;
(ii) Prepare cost estimates for training programs;
(iii) Advise the capacity development coordinator in finalizing the capacity development plan; and
(v) Provide inputs to the inception, interim, final, and progress reports.
Hydropower Policy & Planning Specialist (International)
Among other tasks, the consultant will:
(i) Review the existing hydropower development plans;
(ii) Identify up-to-date planning tools for hydropower development and provide recommendations
for procurement, including hardware requirements;
(iii) Update the input database for hydropower planning for Nepal, focusing on river-basin-wide
planning;
(iii) Update the plans in consultation with the stakeholders;
135
(iv) Train MOE and DOED staff in using planning tools;
(v) Review the barriers to implementing PPP models in hydropower identified during the recently
concluded ADB TA on promoting private participation in Nepal's electricity sector, and
propose an action plan to overcome those barriers; and
(vii) Provide inception, interim, and final reports on the assignment.
Project Evaluation and Monitoring Specialist (International)
Among other tasks, the consultant will:
(i) Review the methods that DOED currently employ to evaluate potential hydropower projects;
(ii) Recommend possible modifications to these evaluation methods;
(iv) Identify and help DOED procure effective tools for economic and financial analyses and
evaluation of hydropower projects;
(iii) Carry out economic and financial analyses and evaluate already identified potential hydropower
projects to be developed by private sector;
(v) Assist DOED staff in negotiating with the private companies on the terms of developing the
hydropower projects;
(iv) Design and implement a tool for monitoring project implementation;
(vi) Train DOED staff in using tools for economic and financial analyses and evaluation and
monitoring of hydropower projects; and
(viii) Provide inception, interim, and final reports on the assignment.
Legal Expert (National)
Among other tasks, the consultant will:
(i) Review legal aspects of the documentation related to the development of at least three private
hydropower projects under consideration by the DOED;
(ii) Assist DOED staff in handling the legal issues during negotiations with the private companies
on developing potential hydropower projects; and
(iii) Provide inception, interim, and final reports on the assignment
136
Annexure-II
Schedule of Meetings and Persons Met during Fact Finding Mission (March 2011)
Date STAKEHOLDER MEETINGS TEAM
ATTENDEES
March 6, 2011 Team Meeting, Priyantha Wijayatunga, ADB PW/AS/SZ
March 7, 2011 Priyantha Wijayatunga, ADB PW/AS/DNR/SZ
March 7, 2011 Mahendra Nath Aryal, Chairman, ETFC PW/AS/DNR/SZ
March 7, 2011 Sanjaya Sharma, DDG, DOED PW/AS/DNR/SZ
March 8, 2011 Mikul Bhatia, Tomoyuki Yamashita, WB AS/DNR/SZ
March 8, 2011 Team Meeting, Priyantha Wijayatunga, ADB PW/AS/DNR/SZ
March 9, 2011 Anup K. Upadhyay, Joint Secretary, MOE AS/DNR/SZ
March 9, 2011 Sriranjan Lacoul, Joint Secretary, MOE AS/DNR/SZ
March 9, 2011 Inge H. Vognild, Embassy of Norway AS/DNR/SZ
March 9, 2011 R.C. Pandey, General Manaager, NEA AS/DNR/SZ
March 10, 2011 Nutan Sharma, Sr. Divisional Engineer, ETFC AS/DNR/SZ
March 10, 2011 Sanjaya Sharma, DDG, DOED; Madhu Bhetuwal, Sr.
Divisional Enginneer AS/DNR/SZ
March 11, 2011 Sher Singh Bhat, Director, NEA AS/DNR/SZ
March 11, 2011 Sandip Shah, VP & Country Director, SN Power AS/DNR/SZ
AS = A. Subbiah; DNR = D. N. Raina; PW = P. Wijayatunga; SZ = S. Zaidi
137
Annexure-III LIST OF OFFICIALS MET DURING THE INCEPTION MISION
(May 2011)
Ministry of Energy
Mr. Balananda Poudel, Secretary
Mr. Anup K. Upadhyaya, Joint Secretary
Mr. Sriranjan Lacoul, Joint Secretary
Department of Electricity Development
Mr. D. B. Singh, Act Director General
Dr. Sanjaya Sharma, Dy Director General
Mr. K. D. Adhikari, Superintending Engineer
Department for International Development (DFID)
Mr. George Davies, Team Leader
Mr. Jeffrey C. Fine, Acting Director
Ms. Federica Cimato, Economist
138
Annexure-IV
LIST OF OFFICIALS PRESENT IN THE WORKSHOP
Ministry of Energy (MOE)
1. Mr. Balananda Poudel, Secretary, [email protected]
2. Mr. Sriranjan Lacoul, Joint Secretary, [email protected]
3. Mr. Pravin Raj Aryal, Senior Divisional Engineer, [email protected]
4. Mr. Sagar Raj Goutam, Senior Divisional Engineer, [email protected]
5. Mr. K. M. Soti, Senior Divisional Engineer, [email protected]
6. Mr. Bishnu Prasad Regmi, Law Officer, [email protected]
7. Mr. C. B. Shrestha, [email protected]
Department of Electricity Development (DOED)
8. Mr. D. B. Singh, Act Director General, [email protected]
9. Dr. Sanjaya Sharma, Dy Director General, [email protected]
10. Mr. Angira Acharya, Dy Director General, [email protected]
11. Mr. K. D. Adhikari, Superintending Engineer, [email protected]
12. Mr. Sudesh Kumar Malla, Superintending Engineer, [email protected]
13. Mr. Sundar Shyam Shrestha, Superintending Engineer, [email protected]
14. Mr. Dinesh Ghimire, Senior Divisional Engineer, [email protected]
15. Mr. Nabin Raj Singh, Senior Divisional Engineer, [email protected]
16. Mr. Chiranjeewee Chataut, Senior Divisional Engineer, [email protected]
17. Mr. Sandeep Kumar Dev, Senior Divisional Engineer, [email protected]
18. Mr. Gokarna Raj Pantha, Senior Divisional Engineer, [email protected]
19. Ms. Mon Devi Shrestha, Engineer, [email protected]
Water and Energy Commission Secretariat (WECS)
20. Mr. Sanjaya Dhungel, Senior Divisional Engineer, [email protected]
Electricity Tariff Fixation Commission (ETFC)
21. Mr. Nutan Sharma, Senior Engineer, [email protected]
Nepal Electricity Authority (NEA)
22. Mr. Sher Singh Bhat, [email protected]
23. Mr. Anil Rajbhandari, Manager, [email protected]
24. Mr. Rajan Dhakal, Ast Manager, [email protected]
Consultants:
25. Mr. Peter Choynowski, Economist, [email protected]
26. Mr. Sadiq Zaidi, Hydropower Expert, [email protected]
27. Mr. D N Raina, [email protected]
28. Mr. Gandhi Pandit, [email protected]
Asian Development Bank (ADB):
29. Mr. Tika Limbu, Energy Economist, [email protected]
30. Mr. MD Shahid Parwez, Program Implementation Officer, [email protected]
139
Annexure-V
Presentation in the Inception Workshop
Due to the large size of the training materials and presentations, the same have been
put up in Volume-II with appropriate titles of this report.
Attached in separate Folder Titled Presentations made at IW
140
Annexure-VI
141
Annexure-VII
TRAINING COURSE
IN THE
ECONOMIC ANALYSIS
OF HYDROPOWER PROJECTS
7 – 11 May 2012
Sponsored by the Asian Development Bank Technical Assistance
TA 7628-NEP: Energy Sector Capacity Building
142
Peter Choynowski
Energy Economist Telephone number: 1-613-523-2660
Email address: [email protected]
Areas of Expertise
Restructuring and regulatory reform
Energy policy analysis and development
Least cost system development planning
Energy pricing and tariff design
Demand analysis and forecasting
Economic and financial project evaluation
Energy sector assessment
Financial analysis
Ex-post evaluation and results-based management
Graduate studies: MA (economics) and MSc (financial economics)
30 years experience in Canada and Asia with electric utilities and with ADB
143
PURPOSE OF THIS COURSE
To provide a basis for understanding key economic concepts as they relate to the
analysis of hydropower projects
To provide an ability to undertake a rudimentary economic analysis of hydropower
projects
144
SCOPE OF THE COURSE
1) What is economics and economic analysis?
2) Scope of economic analysis as it relates to hydropower projects
3) Least cost analysis
4) Concept of economic cost
5) How to identify, quantify and value economic benefits
6) Benefit-cost analysis
7) Sustainability
8) Sensitivity and risk analyses
145
WHAT IS ECONOMICS
AND ECONOMIC ANALYSIS?
Economics is the study of how people choose to use resources
Economic analysis is a method of choosing how to best allocate and use these
resources because …
Resources are scarce
For a country, scarce resources may include capital such as land, buildings,
machinery and equipment, as well as, labor, natural resources, and technology
Important choices may involve how to combine resources to produce goods and
services, or how to vote and shape the level of taxes and the role of government
How to utilize resources that are available in the most efficient manner such that
well-being, whether an individual’s own or society’s, is maximized
146
COMPONENTS OF ECONOMIC ANALYSIS
Economic analysis of hydropower projects comprises key 4 areas:
• analysis of alternatives
• comparison of costs with benefits
• sustainability
• sensitivity and risk analyses
These 4 key areas of economic analysis demonstrate:
• the economic viability of the hydropower project
• financial viability for attracting financing from
ADB, the World Bank, bilateral development institutions,
and the private sector
147
1. ANALYSIS OF ALTERNATIVES
• after determining the scope of the project on the basis of demand and other
factors, what are the alternative, mutually exclusive ways of meeting the
objectives?
• alternatives can include
– generation projects (hydropower; other renewable
such as solar, wind; thermal (natural gas, diesel, coal,
etc.))
– connection to a power grid through transmission and
distribution upgrading
– demand management (reducing demand by technical
means, electricity pricing, etc.)
• engineers provide technically feasible alternatives
• the least cost option is the preferred alternative
• the least cost option is the alternative with the lowest present value of initial
capital cost and all subsequent operating and maintenance costs over a specified
period of time
148
Example of Least Cost Analysis
of Rural Electrification Project
• village of 6,000 people, 1,200 households, 100 kWh per month; population
growth rate @ 1.5% pa; income per capita growth rate @ 1% pa
• energy sources: kerosene, charcoal, wood, small gasoline gensets
• expected system losses: 8%
• expected system load factor: 60%
Year Load Forecast
Energy
Sales
(MWh)
Energy
Generated
(MWh)
Peak
Demand
(MW)
2012 1440 1555 295.9
2013 1476 1594 303.3
2014 1513 1634 310.9
2015 1551 1675 318.6
2016 1589 1717 326.6
2017 1629 1760 334.8
… … … …
2029 2191 2366 450.2
… … … …
2044 3173 3427 652.1
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Year POWER SUPPLY ALTERNATIVES*
Hydropower Diesel Grid Connection
Capital
Cost (mil Rs)
O&M
Cost (mil Rs)
Total
Cost (mil Rs)
Capital
Cost (mil Rs)
O&M
Cost** (mil Rs)
Total
Cost (mil Rs)
Capital
Cost (mil Rs)
O&M
Cost*** (mil Rs)
Total
Cost (mil Rs)
2012 153.00 153.00
2013 102.00 102.00 63.75 63.75 425.00 425.00
2014 2.55 2.55 32.68 32.68 13.89 13.89
2015 2.55 2.55 33.50 33.50 14.24 14.24
2016 2.55 2.55 34.33 34.33 14.59 14.59
2017 2.55 2.55 35.19 35.19 15.33 15.33
… … … … … … … … … …
2029 2.55 2.55 31.88 47.33 79.21 20.11 20.11
… … … … … … … … … …
2044 2.55 2.55 68.55 68.55 29.13 29.13
* costs assume no inflation, that is, costs are in constant rupee terms
** includes cost of diesel fuel
*** includes cost of energy generated
Assumptions:
• hydro cost per kW=$4000;
• hydro O&M cost=1%;
• diesel cost per kW=$1500;
• diesel O&M cost=Rs20 per kWh;
• grid connection capital cost=$5 million;
• grid connection O&M cost=Rs8.5 per kWh;
• exchange rate=Rs85 per US$;
• all costs tradables-border prices
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Present Value and Discount Rate
∑
where PV = present value
C = economic cost
r = discount rate
t = time
n = terminal period
• discount rate (r) is the real economic opportunity cost of capital; real meaning
“taking out the effects of inflation”
• discount rate is high in countries where capital is a scarce resource, such as,
Nepal
• ADB, World Bank and other donors use a discount rate of 12%; MOE/DOED
should use the same to be consistent
151
Year POWER SUPPLY ALTERNATIVES
Hydropower Diesel Grid Connection
Capital
Cost
(mil Rs)
O&M
Cost
(mil Rs)
Total
Cost
(mil Rs)
Capital
Cost
(mil Rs)
O&M
Cost
(mil Rs)
Total
Cost
(mil Rs)
Capital
Cost
(mil Rs)
O&M
Cost
(mil Rs)
Total
Cost
(mil Rs)
2012 153.00 153.00
2013 102.00 102.00 63.75 63.75 425.00 425.00
2014 2.55 2.55 32.68 32.68 13.89 13.89
2015 2.55 2.55 33.50 33.50 14.24 14.24
2016 2.55 2.55 34.33 34.33 14.59 14.59
2017 2.55 2.55 35.19 35.19 15.33 15.33
… … … … … … … … … …
2029 2.55 2.55 31.88 47.33 79.21 20.11 20.11
… … … … … … … … … …
2044 2.55 2.55 68.55 68.55 29.13 29.13
PV = 234.4 PV = 349.0 PV = 501.6
• we see that the least cost alternative is the hydropower project with a present
value of Rs 234.4 million
• the hydropower project is the preferred option in an economic sense
152
The Concept of Economic Cost
• there is a difference between economic cost and financial cost
• economic costs are real claims on a nation’s resources
• financial costs are generally cash payments
• economic costs also include negative externalities such as pollution, resettlement
• economic costs do not include sunk costs or transfer payments
– sunk costs are not incremental to the project
– transfer payments such as taxes, subsidies are movement of
resources from one agent in the economy to another
• economic analyses (such as, least cost and benefit-cost) are done from a country
perspective with economic costs, not from the perspective of the firm with
financial costs
153
Economic Cost of Land
• land is productive or unproductive
• if productive, it adds to a country’s income
• use of productive land for a power project is an economic cost to the country by
the amount of foregone production over the life of the project
• if unproductive and adds no income to a country and likely never will, the
economic cost of the land is be zero
154
Economic Cost of Labor
• all projects have labor components
• economic cost of labor is its opportunity cost (the output of labor foregone)
• labor can be categorized as skilled or unskilled
• labor is employed or unemployed
LABOR Employed Unemployed
Skilled market wage rate reservation wage
rate
Unskilled opportunity cost zero
• minimum wages are financial costs, not economic costs
155
Shadow Pricing:
Examples of Economic Cost Calculation
Case 1: diesel generators imported from the UK to Nepal, a traded good
Item Cost (US$) Is it an economic cost?
Generators (fob) 2,500,000 yes
Shipping 200,000 yes
Insurance 15,000 yes
Import duties 125,000 no
Sales tax 250,000 no
Cost of feasibility study 300,000 no
Transport to site 50,000 yes
Installation 175,000 yes
Financial Cost 3,115,000
Economic Cost 2,940,000
• import duties and sales tax are transfer payments
• feasibility study is a sunk cost (also not a financial cost)
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Case 2: construction of bridge to hydropower site, a non-traded good
Item Financial Cost
(NRs) Economic Cost
(NRs)
Materials - wood 15,000,000 15,000,000
Materials - other 6,500,000 6,500,000
Sales taxes 2,200,000
Labor - skilled 8,000,000 8,000,000
Labor - unskilled 4,000,000
Land 6,800,000
Resettlement 1,275,000 900,000
Total Cost 43,775,000 30,400,000
• sales taxes are transfer payments
• unskilled labor is unemployed labor paid the mandatory minimum wage
• land is unproductive and always will be
• resettlement was overpaid relative to economic cost
157
The Numéraire
• all project inputs and outputs can be classified as traded or non-traded
• traded input and output prices are set by international markets; e.g. the diesel
generators imported from the UK
• non-traded input and output prices are set by domestic markets; e.g. the bridge to
the hydropower site
• domestic market prices are often distorted by
– indirect taxes and subsidies
– government interventions
– market imperfections: monopolies
– others
• domestic prices levels are usually not the same as international price levels which
are assumed undistorted
• in an economic analysis where prices may come from international and domestic
markets, need to find a conversion factor to normalize
158
Conversion Factors
• in general, a conversion factor is the ratio between economic value of a project
input or output and its financial value
• conversion factors can be calculated for and applied to
– specific project inputs or outputs
– groups of items
– economy as a whole: standard conversion factor (SCF)
• current SCFs are available from
– ADB
– World Bank
– own calculation
• own calculation: see ADB “Guidelines for the Economic Analysis of Projects”,
available at www.adb.org
159
• quick and easy calculation:
where M = imports (cif)
X = exports (fob)
TM = import taxes/duties
SM = import subsidies
TX = export taxes/duties
SX = export subsidies
• shadow exchange rate factor (SERF)
160
• need to choose a yardstick: international/border (say, US dollar) prices or
domestic (Nepal rupee) for the economic analysis
• if local currency (Nepal rupee), then
Local Currency Traded Non-traded
Border prices convert US$ price with
official exchange rate
adjust domestic price with
SCF
Domestic prices
convert US$ price with
official exchange rate,
adjust with SERF
no adjustment
• if foreign currency (say, US dollar), then
Foreign Currency Traded Non-traded
Border prices no adjustment
adjust domestic price with
SCF, convert with official
exchange rate
Domestic prices
(usually not done) n/a n/a
• if good is a composite of traded and non-traded components, make the
appropriate adjustment to each component and re-aggregate
• traded and non-traded are not to be confused with imported and domestically
produced
161
Summary of Procedure for Shadow Pricing Costs
1. Select currency (local or foreign)
2. Convert costs into selected currency where needed
3. Shadow price costs to arrive at economic cost
4. Select numéraire (border or domestic)
5. Adjust by SCF or SERF, as appropriate
162
Least Cost Analysis
For Large-Scale Integrated Power Systems
• power generation options for large-scale integrated power systems are numerous
– hydropower
– other renewable
– nuclear
– combined cycle
– gas turbine
– diesel
– coal-fired
– heavy oil
– demand-side management
– other
• Nepal has a large number of potential hydropower projects of differing sizes,
locations, and cost
• not possible to determine the least cost generation expansion schedule without
computing power
163
• there are a number of software packages that develop least cost generation
expansion schedules on the market
• Wien Automatic System Planning (WASP IV) Package: designed to find the
economically optimal generation expansion policy for an electric utility system
within user-specified constraints
• inputs include
– load forecasts
– capital costs of projects
– fuel costs
– non-fuel O&M costs
– cost of energy not served
– loss-of-load probabilities
– other
• output includes the present value of the least cost generation expansion schedule
164
How to Select Hydropower Projects
for the Export of Electricity
• Nepal has many potential hydropower projects of differing sizes, locations, and
cost
• which should be dedicated to domestic electricity supply and which for export?
• for Nepal to have the greatest benefit from its own hydropower resources, the
subset of hydropower projects that form the least cost generation expansion
schedule should be developed to supply Nepal
• all other hydropower projects may be allocated for the export of electricity
• royalties in terms of “free” electricity from export projects need to be considered
165
2. Benefit-Cost Analysis
• why a benefit-cost analysis?
• need to ensure that the economic benefits of the power project outweigh their
economic cost
• if not, Nepal’s scarce resources may be used elsewhere more efficiently
• most international financing institutions use economic internal rate of return (eirr)
as the measure of economic efficiency
∑
where B = economic benefit
C = economic cost
eirr = economic internal rate of return
t = time
n = terminal period
• another measure is economic net present value (ENPV)
∑
• both EIRR and ENPV should be calculated
• if EIRR > 12% and ENPV > 0, accept the project
166
Economic Benefits of Hydropower Projects
• Step 1: identify the economic benefits of the hydropower project
• hydropower projects produce electricity that is incremental or non-incremental
• valuation of the electricity from the hydropower project depends on this
distinction
Project Output: Electricity
Incremental electricity produced in additional to the
case without the project
Non-incremental
electricity produced substitutes for
alternative sources in the economy or
imports
• hydropower projects can produce electricity, some of which is incremental and
some is non-incremental
• Example
– some hydropower project electricity goes to displace diesel
generated electricity (non-incremental output)
– balance of hydropower project electricity goes to supply unserved
demand (incremental output)
167
• Step 2: quantify the economic benefits of the hydropower project and distinguish
between consumer category, if possible
Total hydropower project output = incremental output
+ non-incremental output
• “total hydropower project output” figure comes from data about the hydropower
project
• “non-incremental output” figure is estimated from data on the energy market and
the power system
• Example
– market data: number of equivalent kWh displaced whose source
was kerosene, gasoline/ diesel generators, etc.
– power system data: displacing diesel- generated electricity in a
power station by old generators
• “incremental output” is the difference between the above two, that is,
Incremental output = total hydropower project output
– total non-incremental output
• incremental and non-incremental output is then allocated to “domestic” and “non-
domestic” consumer categories
168
• Step 3: value the economic benefits of the hydropower project
• incremental output
– valued at demand price
– what consumers are willing to pay
• non-incremental output
– valued at supply price
– what it costs to produce by alternative means
169
Figure 1: Valuation of Non-incremental Output
Case of the Unconnected Household
• Figure 1 is for a single household not connect to electricity supply using another
energy source
• household consumes q* kWh of electricity equivalent at the price of the alternate
energy
• difference between the price of the alternate energy (less any taxes, plus any
subsidies) and the cost of project electricity is the resource cost saving, the net
economic benefit of project electricity
170
Figure 2: Valuation of Non-incremental Output
Case of the Power Station
• Figure 2 is for a power station (say, diesel) that supplies electricity to the grid
• power station supplies q* kWh of electricity at the same cost
• difference between the cost of diesel-generated electricity (less any taxes, plus
any subsidies) and the cost of project electricity is the resource cost saving, the net
economic benefit of project electricity
171
Figure 3: Valuation of Incremental Output
Case of the Unconnected Household
• Figure 3 is for a single household as in Figure 1 but to be connected to a
hydropower source
• household consumed q* kWh of electricity equivalent at the price of the alternate
energy
• at the tariff, the household consumes q1 kWh or an incremental amount of q1 – q*
kWh
• gross economic benefit is the area beneath the household demand curve between
q1 and q* – willingness to pay (WTP)
• if household model used in load forecast, that is,
p = α + βln(q/y)
then, WTP = q1(p1 – β) – q*(p0 – β)
172
• this valuation approach may be used for households connected to the grid but the
power system is supply constrained and households consume only q* kWh
• for future new households where all consumption is incremental,
WTP = q1(p1 – β)
• WTP is the economic benefit that arises in the primary market
• incremental electricity also creates economic benefits in the secondary market,
for example:
– induces greater learning and higher household incomes
– increases demand for other social services
– introduces new technologies such as communications
• primary and secondary market economic benefits may be captured together by
calculating consumer’s surplus (CS)
CS = – β(q1 – q*)
173
Figure 4: Valuation of Incremental Output
Case of Electricity Exports
• exported electricity is a tradable good and perfectly price elastic because exports
do not affect the price received (pe)
• economic benefit is the revenue generated by the exports, that is,
Revenue = pe(q1 – q*)
174
Figure 5: Valuation of Incremental and Non-incremental Output:
Case of the Non-domestic Electricity Market
• Figure 5 represents market demand for electricity in the non-domestic consumer
category using grid supply and another energy source
• identification, quantification and valuation of hydropower project output follows
Figures 1 and 3
• non-domestic market consumes q* kWh of electricity from the grid and
q1 – q* kWh from auto-generation; difference between the price of the alternate
energy (less any taxes, plus any subsidies) and the cost of project electricity for the
q1 – q* kWh is the resource cost saving
• at the tariff, non-domestic market consumes q2 kWh or an incremental amount of
q2 – q1 kWh which is valued as willingness to pay,
WTP = q2(p2 – β) – q1(p1 – β)
175
Shadow Pricing Economic Benefits
• resource cost savings can be tradables (imported fuel) or non-tradables (wood,
charcoal)
• if local currency (Nepal rupee), then
Local Currency Traded Non-traded
Border prices no adjustment adjust domestic price with
SCF
Domestic prices adjust with SERF no adjustment
• if foreign currency (say, US dollar), then
Foreign Currency Traded Non-traded
Border prices
convert domestic price
with official exchange
rate for US$
adjust domestic price with
SCF, convert with official
exchange rate
Domestic prices
(usually not done) n/a n/a
176
• consumer’s surplus is usually non-tradable
Consumer’s surplus Local currency Foreign currency
Border prices adjust domestic price with
SCF
adjust domestic price with
SCF, convert with official
exchange rate
Domestic prices no adjustment n/a
• export revenue (say, in US$) is usually a tradable
Export revenue Local currency Foreign currency
Border prices convert with official
exchange rate no adjustment
Domestic prices
convert US$ price with
official exchange rate,
adjust with SERF
n/a
177
Example of EIRR Calculation
of Rural Electrification Project
Local currency; domestic price is numéraire; SERF = 1.1
Year
Energy
Sales
(MWh)
Hydropower Project Costs Economic Benefits Net
Economic
Benefits (mil Rs)
Capital
Cost (mil Rs)
O&M
Cost (mil Rs)
Total (mil Rs)
Resource Cost
Savings (mil Rs)
Consumer’s
Surplus (mil Rs)
Total (mil Rs)
2012 1440 168.30 168.30 -168.30
2013 1476 112.20 112.20 -112.20
2014 1513 2.81 2.81 19.97 16.94 36.91 34.11
2015 1551 2.81 2.81 20.47 17.37 37.84 35.03
2016 1589 2.81 2.81 20.98 17.80 38.78 35.98
2017 1629 2.81 2.81 21.51 18.25 39.75 36.95
… … … … … … … … …
2029 2191 2.81 2.81 28.92 24.54 53.46 50.66
… … … … … … … … …
2044 3173 2.81 2.81 41.89 35.54 77.43 74.63
EIRR = 13.41%
ENPV = 32.13
• how hydropower project costs were shadow priced:
– traded good costs: converted to local currency, where needed
– traded good costs: taxes, import duties, etc. subtracted; subsidies
added
– non-traded good costs: taxes, import duties, etc. subtracted;
subsidies added
– traded good costs: adjusted by SERF
• how economic benefits were shadow priced:
– resource cost savings: taxes, import duties, etc. subtracted;
subsidies added
– resource cost savings: adjusted by SERF
– consumer’s surplus: no adjustment
• EIRR > 12% and ENPV > 0, then project is acceptable
178
Local currency; border price is numéraire; SCF = 0.91
Year
Energy
Sales
(MWh)
Hydropower Project Costs Economic Benefits Net
Economic
Benefits (mil Rs)
Capital
Cost (mil Rs)
O&M
Cost (mil Rs)
Total (mil Rs)
Resource Cost
Savings (mil Rs)
Consumer’s
Surplus (mil Rs)
Total (mil Rs)
2012 1440 153.00 153.00 -153.00
2013 1476 102.00 102.00 -102.00
2014 1513 2.55 2.55 18.15 15.40 33.56 31.01
2015 1551 2.55 2.55 18.61 15.79 34.40 31.85
2016 1589 2.55 2.55 19.07 16.18 35.26 32.71
2017 1629 2.55 2.55 19.55 16.59 36.14 33.59
… … … … … … … … …
2029 2191 2.55 2.55 26.29 22.31 48.60 46.05
… … … … … … … … …
2044 3173 2.55 2.55 38.08 32.31 70.39 67.84
EIRR = 13.41%
ENPV = 29.21
• how hydropower project costs were shadow priced:
– traded good costs: converted to local currency, where needed
– traded good costs: taxes, import duties, etc. subtracted; subsidies
added
– non-traded good costs: taxes, etc. subtracted; subsidies added;
adjusted by SCF
• how economic benefits were shadow priced:
– resource cost savings: taxes, import duties, etc. subtracted;
subsidies added
– consumer’s surplus: adjusted by SCF
179
3. Sustainability
• is the hydropower project sustainable; are there enough resources to maintain the
flow of project benefits?
• sustainability comprises 3 dimensions:
– financial viability
– institutional capacity
– environmental impact
• if a hydropower project is not sustainable, economic benefits will not be realized
180
Financial Viability of the Project
• economic viability depends on the financial viability of the hydropower project
• financial viability is not the same as economic viability
• financial analysis of a project examines the adequacy of returns to the project-
operating entity and to the project participants, whereas economic analysis
measures the effect of the project on the national economy, as a whole
• is the hydropower project profitable for the project-operating entity?
• will the hydropower project add or subtract from the project-operating entity’s
net worth?
• these questions are answered by the project’s financial internal rate of return
(FIRR)
• in FIRR calculation, all cash expenditures incurred under the hydropower project
and revenues resulting from it are taken into account
181
Example of FIRR Calculation
of Rural Electrification Project
Year
Energy
Sales
(MWh)
Hydropower Project Costs*
Revenue*
(mil Rs)
Net
Financial
Benefits
(mil Rs)
Capital
Cost
(mil Rs)
O&M
Cost
(mil Rs)
Taxes/
Duties
(mil Rs)
Royalties
(mil Rs)
Income
Tax
(mil Rs)
Total
Cost
(mil Rs)
2012 1440 153.00 22.95 175.95 -175.95
2013 1476 102.00 15.30 117.30 -117.30
2014 1513 2.55 0.13 1.13 2.73 6.54 22.69 16.15
2015 1551 2.55 0.13 1.16 2.89 6.73 23.26 16.53
2016 1589 2.55 0.13 1.19 3.06 6.93 23.84 16.91
2017 1629 2.55 0.13 1.22 3.23 7.13 24.44 17.31
… … … … … … … … … …
2029 2191 2.55 0.13 1.64 5.63 9.95 32.87 22.92
… … … … … … … … … …
2044 3173 2.55 0.13 2.38 9.83 14.89 47.60 32.71
FIRR = 5.74%
* costs and revenues assume no inflation, that is, costs are in constant rupee terms
• tax/duty rate: 15% on capital; 5% on O&M
• royalty rate: 5% of revenues
• income tax rate: 30% of operating income
• FIRR alone gives no information about financial viability
• need to calculate the weighted average cost of capital (WACC)
182
Example of WACC Calculation
• hydropower project is undertaken by a domestic, private sector entity that
finances with its own funds (equity) and borrows on the local and foreign markets
PS
equity
Domestic
loans
Foreign
loans Total
Amount (millions Rs) 117.30 102.64 73.31 293.25
Weighting 35% 40% 25% 100%
Nominal cost 15% 10% 8%
Tax rate 30% 30%
Tax-adjusted nominal
cost 15% 7% 5.6%
Inflation rate 6% 6% 2%
Real cost 8.5% 0.9% 3.5%
Weighted components 3.0% 0.4% 0.9% 4.3%
WACC = 4.3%
• WACC calculation assumes return on equity (ROE) is 15%
• tax-adjusted nominal cost = nominal cost*(1-tax rate)
• real cost = (1+tax-adjusted nominal cost)/(1+inflation rate) - 1
183
Year
Energy
Sales
(MWh)
Hydropower Project Costs*
Revenue*
(mil Rs)
Net
Financial
Benefits
(mil Rs)
Capital
Cost
(mil Rs)
O&M
Cost
(mil Rs)
Taxes/
Duties
(mil Rs)
Royalties
(mil Rs)
Income
Tax
(mil Rs)
Total
Cost
(mil Rs)
2012 1440 153.00 22.95 175.95 -175.95
2013 1476 102.00 15.30 117.30 -117.30
2014 1513 2.55 0.13 1.13 2.73 6.54 22.69 16.15
2015 1551 2.55 0.13 1.16 2.89 6.73 23.26 16.53
2016 1589 2.55 0.13 1.19 3.06 6.93 23.84 16.91
2017 1629 2.55 0.13 1.22 3.23 7.13 24.44 17.31
… … … … … … … … … …
2029 2191 2.55 0.13 1.64 5.63 9.95 32.87 22.92
… … … … … … … … … …
2044 3173 2.55 0.13 2.38 9.83 14.89 47.60 32.71
FIRR = 5.74%
WACC = 4.3%
• since FIRR (5.74%) is greater than WACC (4.3%), the project is financially
viable
• if FIRR < WACC, project subtracts from the value of the project-operating entity
and is not financially viable
• at ROE= 20%, WACC = 5.9% and, with FIRR = 5.74%, project is not financially
viable
184
• can change royalty rates to test sensitivity of FIRR
Royalty Rate FIRR
5% 5.74%
10% 5.36%
• private sector’s main interest in financing a hydropower project is with FIRR;
economic viability is secondary, if at all
185
Financial Viability of the Project-Operating Entity
• project-operating entity must be financially capable of implementing and
operating the proposed hydropower project
• a financial analysis of the project-operating entity is needed to determine if it has
the financial capacity to implement and operate the proposed hydropower project
efficiently and effectively
• the financial analysis comprises assessment of
– the income statement
– cash flow statement
– balance sheet
• detailed financial statements using international accounting standards are
prepared to illustrate
– past performance (past 10 years)
– forecast future performance (next 5 –10 years)
186
Income Statement
• the following information and analyses should be provided with the income
statement:
– load forecast: basis for revenues
– operating revenues: include description of tariffs
– operating costs: provide assumptions for projections in each
operating cost category
– depreciation rates: may be addressed in balance sheet
– non-operating section: describe assumptions for forecasts of other
income and expenses; relate forecast interest expenses to loans
outstanding
– taxes on income: provide basis for income tax charges
– appropriations from new income: state basis for appropriations and
assumptions on future dividends, etc.
• the following comparators and ratios are useful for analyzing income
statement information:
– growth rates
– operating ratio
– return on average invested capital
187
Cash Flow Statement
• the following information and analyses should be provided with the cash flow
statement:
– sources of funds: operating income including depreciation and
interest; equity capital, loans, etc.
– application of funds: capital expenditure, debt service; dividend
payment, change in working capital, etc.
• the following comparators and ratios are useful for analyzing cash flow
information:
– growth rates
– debt service coverage
– self-financing ratio: percentage of capital expenditure financed by
internal sources
188
Balance Sheet
• the following information and analyses should be provided with the balance
sheet:
– assets: fixed assets and current assets
– liabilities: long-term debt and deferred liabilities; current
liabilities; equity
• the following comparators and ratios are useful for analyzing the balance sheet:
– growth rates
– current ratio
– quick ratio
– debt-equity ratio
– debt as percentage of total capitalization
– net tangible assets as percentage of longterm debt
– accounts receivable outstanding on a monthly basis
• detailed guidelines for financial analysis may be found in Guidelines for the
Financial Governance and Management of Investment Projects Financed by the
Asian Development Bank, January 2002, on the ADB website
189
Institutional Capacity
• assessment of institutional capacity focuses on identifying functions, structures
and capacity of the project-operating entity
• assess the institution’s capacities for project implementation
• ensure project-operating entity has the technical and managerial capacities for
project implementation
• assess the institution’s capacities for operating the project
• identify the specific institutional deficiencies
• develop specific institutional strengthening measures
190
Environmental Impact
• general principle: current generations should meet their needs without
compromising the ability of future generations to do the same
• need to prepare an Environmental Impact Assessment (EIA) report
• environmental effects, whether costs or benefits, should be explicit to inform
policymakers and stakeholders
• EIA is an input into economic analysis: least cost analysis and EIRR calculation
• environmental costs include
– aquatic habitats and water quality (oxygen concentration, nutrients)
– terrestrial biodiversity and deforestation
– soil erosion and sedimentation
– water and groundwater pollution
– hydrology issues (changes in flow of rivers, flooding)
– human settlements and livelihoods
– environmentally related health risks
191
4. Sensitivity and Risk Analyses
• assumption so far: perfect knowledge of costs and benefits
• but, we do not have perfect knowledge about the future
• changes in values of costs and benefits can change the decision whether to
proceed with the project or not
• sensitivity analysis to ENPV and FIRR
• sensitivity and risk analyses can improve project design for mitigating against
major sources of uncertainty
• risk analysis particularly important for large hydropower projects
• main sources of uncertainty:
– capital cost
– electricity demand
– project output (kWh generated)
– fuel costs
– SCF or SERF
– electricity tariff
192
Sensitivity Analysis
• for ENPV
Assumption ENPV
(millions Rs.) Sensitivity
Index
Base Case 32.13 -
Increase in capital cost 10% 8.16
-7.5 15% -3.83
Decrease in kWh demand 10% 3.14
-9.0 12% -2.66
Increase in SERF 10% 22.04 -3.1
Increase in capital cost &
decrease in kWh demand 10% -20.83 -16.5
• sensitivity index = (% change in ENPV) ÷ (% change in variable)
• best to use ENPV for sensitivity because EIRRs may not be unique
• switching value: the change in the variable required for the project decision to
shift from acceptance to rejection
193
• for FIRR
Assumption FIRR (%)
WACC = 4.3% Sensitivity
Index
Base Case 5.74 -
Increase in capital cost 10% 5.04
-1.2 15% 4.72
Decrease in kWh demand 10% 5.01
-1.6 12% 4.62
Decrease in tariff 10% 5.01 -1.6
Increase in royalty rate 20% 5.67
-0.1 100% 5.36
Increase in capital cost &
decrease in kWh demand 10% 4.34 -2.4
194
Risk Analysis
• a quantitative risk analysis is recommended for large hydropower projects, for
hydropower projects with EIRRs close to 12%, and for high risk projects
• risk analysis incorporates different ranges for key variables and estimates the
probability that the EIRR will exceed a critical value (12%)
• software for risk analysis is available but expensive; a free sample program may
be obtained from www.vosesoftware.com
• key variables for risk analysis for the rural electrification project
– capital cost: triangle distribution (90%, 100%, 150%) of the
estimated cost for the minimum, mode and maximum values
– diesel cost: triangle distribution (18, 20, 27) for the Rs per liter cost
for the minimum, mode and maximum values
– consumer surplus beta value: normal distribution (28, 4) for the Rs
per kWh benefit for the mean and standard deviation
• risk simulation results in a probability of 55.5% that the EIRR will exceed 12%
• need to assess whether this probability is high enough (normally, probability
should be in excess of 80%)
195
NAM THEUN 2 HYDROELECTRIC PROJECT
(Lao People’s Democratic Republic)
Project Description
• development, construction, and operation of a 1,070-megawatt (MW)
hydroelectric power plant on the Nam Theun River (tributary of the Mekong river)
• 450 sq. km. reservoir formed by a 39m dam
• export of 5,354 GWh of electricity to Thailand; about 200–300 GWh to be
supplied to electricity consumers in the Lao PDR
• Project developed by a private company, the Nam Theun 2 Power
Company Limited, owned by a consortium comprising Electricité de France
International of France (35%), the Electricity Generating Public Company of
Thailand (25%), the Italian Thai Development Public Company
Limited of Thailand (15%), and the Government of the Lao PDR (25%)
• Project structured as a build-own-operate-transfer with a concession period of 31
years, of which the operating period is 25 years
• at the end of the concession period, project facilities will be transferred to the
Government free of charge
196
Rationale
• harness Lao PDR’s vast hydroelectric power potential to ensure long-term
sustainable economic development
• Project supports two key national development objectives:
(i) promotion of economic and social advancement by providing reliable and
affordable electricity supply, and
(ii) earn foreign exchange from electricity exports.
• Project was an integral part of the Government’s development framework, which
aimed to achieve the country’s medium- and long-term economic growth and
poverty reduction objectives
• electricity exports began in 1971 which provided an important source of foreign
exchange earnings
• in 2003, electricity exports accounted for about 30% of total export earnings
• closer regional cooperation opened up opportunities to promote electricity
exports and satisfy increasing domestic consumption
• abundance of hydroelectric power resources and the location of the Lao PDR
between rapidly developing neighboring countries gave it a comparative advantage
in developing hydroelectric power potential
197
Analysis of Alternatives
Thailand
• generation expansion plan of the Thai power system was modeled with the
Project as a candidate competing with a range of fossil-based alternatives
• base-case analysis concluded that the Project should be included in the least-cost
generation expansion plan from 2010, and that CCGT capacity would be the next
best alternative to the Project
• base, high, and low scenarios were developed for power demand, natural gas
prices and project cost, and probabilities assigned to each outcome
• the cost–risk analysis found that the probability-weighted accumulated present
value of real resource savings as a result of the development of
the Project was higher than the CCGT-based alternative
Lao PDR
• Power System Development Plan for Lao PDR analyzed 33 separate
hydroelectric power projects and two thermal projects
• projects were initially evaluated solely on the basis of their weighted average cost
of generation
• environmental and social impact assessments were then incorporated for the
short-listed projects and ranked according to their relative economic performance
adjusted for social and environmental impacts
• Nam Theun 2 ranked first among all candidates evaluated
198
Benefit –Cost Analysis
• EIRR and ENPV measured on a regional basis (Lao PDR and Thailand together)
Year
Net
Power
Demand
(GWh)
Economic Benefits ($ mil) Economic Costs ($ mil)
Net
Economic
Benefit
($ mil)
Thai
Rev
Thai
CS
Lao
RCS
Lao
CS
Loss
Total Capital O&M Dividends Total
2004 - - - - - - 74.9 - - 74.9 (74.9)
2005 - - - - - - 220.2 - - 220.2 (220.2)
2006 - - - - - - 206.5 - - 206.5 (206.5)
2007 - - - - - - 231.6 - - 231.6 (231.6)
2008 - - - - - - 192.5 - - 192.5 (192.5)
2009 550 42.8 0.1 1.7 (5.1) 44.6 109.3 4.4 - 113.7 (69.0)
2010 5271 288.0 5.5 11.4 (5.1) 299.8 7.4 18.3 - 25.7 274.1
2011 5200 283.6 5.4 12.3 (5.1) 296.1 - 18.3 - 18.3 277.8
2012 5215 283.6 5.4 13.3 (5.1) 297.1 - 18.3 - 18.3 278.8
2013 5225 283.6 5.4 14.0 (5.1) 297.8 - 18.3 - 18.3 279.5
2014 5225 283.6 5.4 14.0 (5.1) 297.8 - 17.6 - 17.6 280.3
2015 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2016 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2017 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2018 5225 283.6 5.4 14.0 (5.1) 297.8 - 23.2 - 23.2 274.6
2019 5225 283.6 5.4 14.0 (5.1) 297.8 - 23.2 - 23.2 274.6
2020 5225 283.6 5.4 14.0 (5.1) 297.8 - 23.2 - 23.2 274.6
2021 5225 283.6 5.4 14.0 (5.1) 297.8 - 23.2 - 23.2 274.6
2022 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2023 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2024 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2025 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2026 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2027 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2028 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2029 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2030 5225 283.6 5.4 14.0 (5.1) 297.8 - 16.9 - 16.9 280.9
2031 5225 283.6 5.4 14.0 (5.1) 297.8 - 23.2 - 23.2 274.6
2032 5225 283.6 5.4 14.0 (5.1) 297.8 - 23.2 - 23.2 274.6
2033 5225 283.6 5.4 14.0 (5.1) 297.8 - 23.2 - 23.2 274.6
2034 5225 283.6 5.4 14.0 (5.1) 297.8 - 23.2 1186.3 1209.6 (911.7)
ENPV= 389.4
EIRR= 17.5%
199
DISCUSSION
SESSION
200
Annexure-VIII
Presentations Made by the Project Evaluation and Monitoring Specialist at the
Training Program
(To be attached and/or copied herein. Available in Peter’ Folder Nepal
Final Report)
201
Annexure-IX
Peter’s Exercise-I
Project Name: Lower Hongu Khola Small Hydropower Project
Output capacity (MW): 23.5
Annual generation (GWh): 134.35
Total project cost (2007, $
mil): 49.145
Least Cost Analysis: LHKSHP vs Diesel ($ and border prices)
Energy LHKSHP Diesel
Produced Capital O&M Total Capital Fuel O&M Total
Year
by
LHKSHP Cost Cost Cost Cost Cost Cost Cost
(GWh) (mil $) (mil $) (mil $) (mil $) (mil $) (mil $) (mil $)
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
202
2034
2035
2036
2037
2038
2039
2040
PV =
PV =
Assumptions
Social opportunity cost of
capital 12%
LHKSHP capital cost (mil $) 36.0
LHKSHP capital cost phase-in:
Year 1 25%
Year 2 40%
Year 3 35%
LHKSHP O&M cost (% of
capital cost) 2.0%
Diesel capacity required (MW) 20
Diesel capital cost ($ per kW) 1,200
Diesel capital cost phase-in:
Year 1 35%
Year 2 65%
Diesel station own use rate 3%
Diesel cost ($ per liter) 0.40
Diesel efficiency (kWh per
liter) 4.0
Diesel O&M cost ($ per kWh) 0.01
203
Annexure-IX
Peter’s Exercise-II
Project Name: Lower Hongu Khola Small Hydropower Project
Output capacity (MW): 23.5
Annual generation (GWh): 134.35
Total project cost (2007, $ mil): 49.145
Least Cost Analysis: LHKSHP vs Diesel ($ and border
prices)
Energy LHKSHP Diesel
Produced Capital O&M Total Capital Fuel O&M Total
Year
by
LHKSHP Cost Cost Cost Cost Cost Cost Cost
(GWh) (mil $) (mil $) (mil $) (mil $) (mil $) (mil $) (mil $)
2007
9.000
9.000
2008
14.400
14.400 8.400
8.400
2009
12.600
12.600 15.600
15.600
2010 134.350 36.000 0.720 0.720 24.000 13.851 1.344 15.194
2011 134.350
0.720 0.720
13.851 1.344 15.194
2012 134.350
0.720 0.720
13.851 1.344 15.194
2013 134.350
0.720 0.720
13.851 1.344 15.194
2014 134.350
0.720 0.720
13.851 1.344 15.194
2015 134.350
0.720 0.720
13.851 1.344 15.194
2016 134.350
0.720 0.720
13.851 1.344 15.194
2017 134.350
0.720 0.720
13.851 1.344 15.194
2018 134.350
0.720 0.720
13.851 1.344 15.194
2019 134.350
0.720 0.720
13.851 1.344 15.194
2020 134.350
0.720 0.720
13.851 1.344 15.194
2021 134.350
0.720 0.720
13.851 1.344 15.194
2022 134.350
0.720 0.720
13.851 1.344 15.194
2023 134.350
0.720 0.720
13.851 1.344 15.194
2024 134.350
0.720 0.720
13.851 1.344 15.194
2025 134.350
0.720 0.720
13.851 1.344 15.194
2026 134.350
0.720 0.720
13.851 1.344 15.194
2027 134.350
0.720 0.720
13.851 1.344 15.194
2028 134.350
0.720 0.720
13.851 1.344 15.194
2029 134.350
0.720 0.720
13.851 1.344 15.194
2030 134.350
0.720 0.720
13.851 1.344 15.194
2031 134.350
0.720 0.720
13.851 1.344 15.194
2032 134.350
0.720 0.720
13.851 1.344 15.194
2033 134.350
0.720 0.720
13.851 1.344 15.194
204
2034 134.350
0.720 0.720
13.851 1.344 15.194
2035 134.350
0.720 0.720
13.851 1.344 15.194
2036 134.350
0.720 0.720
13.851 1.344 15.194
2037 134.350
0.720 0.720
13.851 1.344 15.194
2038 134.350
0.720 0.720
13.851 1.344 15.194
2039 134.350
0.720 0.720
13.851 1.344 15.194
2040 134.350
0.720 0.720
13.851 1.344 15.194
PV = 32.627
PV = 117.866
Assumptions
Social opportunity cost of capital 12%
LHKSHP capital cost (mil $) 36.0
LHKSHP capital cost phase-in:
Year 1 25%
Year 2 40%
Year 3 35%
LHKSHP O&M cost (% of capital
cost) 2.0%
Diesel capacity required (MW) 20
Diesel capital cost ($ per kW) 1,200
Diesel capital cost phase-in: Year
1 35%
Year 2 65%
Diesel station own use rate 3%
Diesel cost ($ per liter) 0.40
Diesel efficiency (kWh per liter) 4.0
Diesel O&M cost ($ per kWh) 0.01
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