ASIAN DEVELOPMENT BANK
PPA:NEP 18082
PROJECT PERFORMANCE AUDIT REPORT
ON THE
SEVENTH POWER PROJECT
(Loan 1011-NEP[SF])
IN
NEPAL
June 2004
NRe1.00
$1.00
=
=
CURRENCY EQUIVALENTS
Currency Unit – Nepalese rupee/s (Nre/NRs)
At Appraisal
At Completion At Operations Evaluation
November 1989
June 2000
March 2004
$0.035
$0.014
$0.0135
NRs28.40
NRs71.10
NRs73.55
ABBREVIATIONS
ADB
EA
EIRR
ETFC
FIRR
IPP
NEA
NRM
OEM
PCR
PPAR
PPTA
REDT
RRP
SWER
SDR
TA
TOR
VDC
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Asian Development Bank
Executing Agency
economic internal rate of return
Electricity Tariff Fixation Commission
financial internal rate of return
independent power producer
Nepal Electricity Authority
Nepal Resident Mission
Operations Evaluation Mission
project completion report
project performance audit report
project preparatory technical assistance
Rural Electrification, Distribution and Transmission Project
report and recommendation of the President
single wire earth return
special drawing right
technical assistance
terms of reference
village development committee
WEIGHTS AND MEASURES
GWh
km
kV
kWh
MVA
MW
–
–
–
–
–
–
gigawatt-hour (1 million kWh)
kilometer
kilovolt
kilowatt-hour
megavolt-ampere
megawatt
NOTES
(i)
(ii)
The fiscal year (FY) of the Government and the Nepal Electricity Authority ends on
15 July.
In this report, “$” refers to US dollars.
Director General, Operations Evaluation Department
Director, Operations Evaluation Division 2
Evaluation Team Leader
:
:
:
Operations Evaluation Department, PE-643
Eisuke Suzuki
David Edwards
Hong Wang
CONTENTS
Page
BASIC DATA
v
EXECUTIVE SUMMARY
vi
MAP
ix
I.
II.
III.
BACKGROUND
1
A.
B.
C.
D.
E.
F.
1
1
2
2
3
3
PLANNING AND IMPLEMENTATION PERFORMANCE
4
A.
B.
C.
D.
E.
4
5
5
7
8
Formulation and Design
Achievement of Outputs
Cost and Scheduling
Procurement and Construction
Organization and Management
ACHIEVEMENT OF PROJECT PURPOSE
A.
B.
C.
D.
E.
IV.
Rationale
Formulation
Purpose and Outputs
Cost, Financing, and Executing Arrangements
Completion and Self-Evaluation
Operations Evaluation
Operational Performance
Performance of the Operating Entity
Financial and Economic Reevaluation
Sustainability
Technical Assistance
9
9
11
13
15
16
ACHIEVEMENT OF OTHER PROJECT IMPACTS
16
A.
B.
C.
16
16
17
Socioeconomic Impact
Environmental Impact
Impact on Institutions and Policy
Hong Wang, Evaluation Specialist (Team Leader) was responsible for the preparation of this
report, and conducted document reviews, key informant reviews, and guided the fieldwork
undertaken by the consultants, Geoff Brown and Dilli Dahal. Vivien Ramos, Evaluation Officer,
supported the team with research assistance and Anna Silverio, Administrative Assistant,
provided secretarial assistance from Manila.
iv
V.
VI.
OVERALL ASSESSMENT
17
A.
B.
C.
D.
E.
F.
G.
17
17
17
18
18
18
18
Relevance
Efficacy
Efficiency
Sustainability
Institutional Development and Other Impacts
Overall Project Rating
Assessment of ADB and Borrower Performance
ISSUES, LESSONS, AND FOLLOW-UP ACTIONS
18
A.
B.
C.
18
19
20
Key Issues for the Future
Lessons Identified
Follow-Up Actions
APPENDIXES
1.
2.
3.
4.
Engineering Report
Operational Performance of the Nepal Electricity Authority
Financial and Economic Reevaluation
Report on Socioeconomic Survey
21
24
25
27
BASIC DATA
Loan 1011-NEP(SF): Seventh Power Project
PREPARATION/INSTITUTION BUILDING
TA No.
TA Project Name
837
Seventh Power
1267
Institutional Support for Distribution Planning
and Commercial Operations of NEA
KEY PROJECT DATA ($ million)
Type
PPTA
ADTA
Amount1 ($)
75,000
780,000
As per ADB
Loan Documents
Total Project Cost
Foreign Currency Cost
Bank Loan Amount/Utilization
Actual
64.0
42.7
51.0
40.5 (SDR)2
65.8
47.7
55.13
Bank Loan Amount/Cancellation
2.4
KEY DATES
Appraisal
Loan Negotiations
Board Approval
Loan Agreement
Loan Effectiveness
First Disbursement
Project Completion
Loan Closing
Months (effectiveness to completion)
KEY PERFORMANCE INDICATORS (%)
Financial Internal Rate of Return - Part A
- Part B
Economic Internal Rate of Return - Part A
- Part B
Expected
Actual
23 Jun–13 Jul 1988
16–20 Oct 1989
11 Jan 1990
28 Feb 1990
18 Sep 1990
18 Jul 1991
Sep 2000
9 Aug 1999
120
28 May 1990
Aug 1994
31 Aug 1995
51
Appraisal
18.8
4.5
22.2
13.5
BORROWER
Kingdom of Nepal
EXECUTING AGENCY
Nepal Electricity Authority
MISSION DATA
Type of Mission
Pre-Appraisal
Appraisal
Follow-Up
Loan Negotiation
Project Administration
Review
Loan Transfer
Project Completion
Operations Evaluation
Approval Date
24 Dec 1986
11 January 1990
No. of Missions
1
1
1
1
8
1
2
1
PCR
13.4
0.8
20.0
11.1
PPAR
11.8
Negative
24.6
19.2
Person-days
72
105
10
12
79
8
35
54
ADB = Asian Development Bank, ADTA = advisory technical assistance, NEA = Nepal Electricity Authority,
PCR = project completion report, PPAR = Project Performance Audit Report, PPTA = project preparatory technical
assistance, TA = technical assistance.
1
The approved amount of technical assistance.
2
SDR1,791,979 of the loan was cancelled on 9 August 1999.
3 $6 million worth of material was purchased under loan-financed contracts, but not used in the Project.
EXECUTIVE SUMMARY
The Seventh Power Project (the Project) was formulated to help the Nepal Electricity
Authority (NEA) improve the efficiency and reliability of its power system through rehabilitation in
urban areas, and to meet the growing energy demand in rural areas through electrification. This
was in line with the Government of Nepal’s objectives for power sector development, as
described in its Seventh Five Year Plan (fiscal year [FY] 1984–1985 to FY1989–1990). The
operational strategy for the Asian Development Bank (ADB) for Nepal at project appraisal in
1988 focused on (i) improvement in agricultural productivity, (ii) containment of factors that
cause deforestation, (iii) enhancement of industrial development, and (iv) development of
supporting physical and social infrastructure.
NEA began commercial operations in August 1985 and, at loan appraisal, had been in
operation for fewer than 4 years. Both ADB and the Government recognized the need to
develop NEA’s institutional capabilities, so an advisory technical assistance (TA) grant was
attached to the Project in order to improve NEA’s capacity for the planning of power distribution,
and to strengthen NEA’s newly created commercial department.
The main project objectives were to rehabilitate existing distribution networks in five
larger towns to improve the quality of electricity supply and to reduce system losses, and to
extend subtransmission and distribution networks to rural areas. The Project consisted of Part
A: rehabilitation of existing distribution networks in five larger towns, Part B: extension of
subtransmission and distribution networks to rural areas, and Part C: construction of a concrete
pole factory.
The Project was implemented largely as envisaged. Most significant was the use of loan
savings to extend the scope of rural electrification. The main factor contributing to the large loan
savings was participation of Chinese manufacturers in international competitive bidding after
1992. Other significant factors included depreciation of the dollar against special drawing rights
(SDRs), the ability of Nepalese manufacturers to bid for supply of project equipment such as
distribution transformers, and increased competitiveness of Nepalese installation contractors.
Furthermore, the price contingency was calculated on the assumption of a constant nominal
exchange rate, and was high. These factors, taken together, not only kept costs below or near
budgeted levels, but also allowed allocation of contingencies for the extension of rural
electrification.
The Project experienced significant delays. The loan was closed on 9 August 1999,
4 years after the original closing date. Construction of the project works was completed only in
2000. A major cause of implementation delay was ADB’s lengthy process for approval of NEA’s
request to use loan savings to extend rural electrification. Other delays were from (i) NEA
delays in meeting conditions for loan effectiveness and in mobilizing the consultant for project
implementation; (ii) the time required to fully evaluate the use of single wire earth return (SWER)
distribution technology; (iii) delays in award of contracts; and (iv) poor contractor performance.
Upon completion, the Project achieved the following physical outputs: (i) about 185
megavolt-ampere (MVA) of new 132 kilovolt (kV), 66 kV, and 33 kV substation transformer
capacity; (ii) more than 320 kilometers (km) of new 33 kV subtransmission line; (iii) almost 2,500
km of high voltage distribution line; (iv) more than 2,300 km of low voltage distribution line; and
(v) a new concrete pole factory with a daily production capacity of as much as 58 prestressed
concrete poles. Through the Project, electricity was provided to almost 1,000 previously
unelectrified load centers, providing access to electricity to more than 200,000 new customers.
vii
The quality and reliability of power supply in five major towns and two significant load corridors
were improved.
Sustainability of project benefits over the longer term will depend on the quality of
maintenance, and the availability of technical and financial resources to upgrade and reinforce
parts of the system that are loaded to their rated capacity. All work necessary to keep the
network operational has been done, but the quality of maintenance varies. Engineering
supervision of operation and maintenance is inadequate in some places.
NEA’s financial performance was not satisfactory from 1999 to 2003. This was mainly
because of NEA’s failure to increase tariffs to more sustainable levels. The average tariff for
FY2003 was NRs7.02/kWh—42% lower than envisaged. A further problem was NEA’s failure to
reduce system losses to the forecast levels. Actual losses for FY2003 were 24.5%, compared
with forecast losses of 18.7%. NEA now faces a difficult operating environment. The Maoist
insurgency in Nepal continues unabated, and NEA facilities are an ongoing target. Insurgency
damage for FY2003 cost NRs72.4 million. But the insurgency’s impact on NEA operations is
more important than the financial cost of physical damage. The insurgency impact involves both
the quantifiable costs of protecting NEA assets, and the less-quantifiable costs of having to
consider practical and political implications when making management decisions.
Electrification in urban areas and areas near sealed roads has affected local economies
positively because of its benefits to consumers’ lives, and stimuli for industrial and commercial
development. In remote areas, consumers’ benefits from improved lighting, access to radio and
television, and the use of fans would not be possible without electricity. Electricity has benefited
women greatly. But many poorer households in remote areas have not connected to electrical
power because the initial connection is too costly.
The Project, as originally designed, had no specific environmental objectives.
Construction has been environmentally benign, with most overhead lines located on road
reserves. Project beneficiaries have seldom complained about environmental issues. The
Project was expected to have an indirect environmental impact by utilizing Nepal’s indigenous
hydropower facilities to replace fuelwood and imported fossil fuels. But the Project seems to
have done little to reduce the use of fuelwood, although the use of kerosene, and small diesel
motors, has decreased.
The performance of both ADB and NEA is assessed as partly satisfactory. For ADB, this
assessment reflects a failure to take proactive and timely action to respond to implementation
problems that arose early in the Project, late decisions regarding the first loan extension, and an
aborted decision to transfer project administration to the Nepal Resident Mission (NRM). For
NEA, the partly satisfactory assessment is based on unsatisfactory progress over the first 5
years (through 1995), its failure to reduce losses to covenanted levels, and the poor financial
performance that continues to threaten the Project’s sustainability.
Overall, the Project is rated successful. But TA achievements fell short of expectations
because of NEA’s lack of commitment to immediately implement TA recommendations, and to
provide sufficient counterpart funds to make the TA more effective. Overall, the TA is assessed
as partly successful.
The Project has yielded three main lessons. First, delays associated with abandoning
the use of SWER might have been avoided if a more substantive project preparatory
consultancy had been undertaken, and the technical feasibility of using SWER been researched
more thoroughly during appraisal. On one hand, innovation by consultants should be
encouraged. But a project of this size and complexity should include a full-scale project
viii
preparatory TA that includes investigation into the use of new and alternative technologies.
Second, annual review missions were insufficient during the first 5 years of project
implementation. Third, many problems associated with poor performance of the contractors
were not unique to the Project, and should be avoided in future. An ADB procedure to evaluate
performance of both international and local contractors, similar to evaluation procedures used
for individual consultants, would be useful. The performance of contractors would be recorded in
files for eligibility check before qualification for future contracts.
An issue relevant to ADB’s ongoing Rural Electrification, Distribution, and Transmission
Project (REDT) deserves particular attention. The rural electrification component of REDT will
probably further constrain NEA’s financial position, considering NEA’s poor financial
performance and the unlikelihood of significant tariff increases in the near future. It may be
useful to explore the possibilities of subsidizing initial connection charges for rural customers,
and reducing their costs of payment of electricity bills, to raise the tariff for rural electricity supply
to at least a break-even level.
Eisuke Suzuki
Director General
Operations Evaluation Department
I.
A.
BACKGROUND
Rationale
1.
Nepal’s Seventh Power Project1 (the Project) was consistent with the Government’s power
sector objectives as described in the Seventh Five Year Plan (FY1984–85 to FY1989–90). The
Seventh Plan included development of indigenous energy resources to substitute for imported
fuels, providing a reliable power supply, and reducing fuelwood consumption. The Project was to
help the Nepal Electricity Authority2 (NEA) improve the efficiency and reliability of its power
system through rehabilitation in urban areas, and meet the growing energy demand in rural areas
through electrification. The Project aimed specifically at (i) rehabilitating and expanding existing
distribution networks to meet continuing load growth, and (ii) electrifying rural areas that had no
access to electricity. The Asian Development Bank’s (ADB) operational strategy for Nepal at the
time focused on (i) improvements in agricultural productivity, (ii) containment of the causes of
deforestation, (iii) enhancement of industrial development, and (iv) development of supporting
physical and social infrastructures.
2.
NEA began commercial operations in August 1985. At loan appraisal, NEA had operated
for less than 4 years. At that time, NEA had no commercial department to provide a focal point for
its commercial and loss reduction activities. It was also recognized that detailed planning for
distribution development over the next 10 years was a major undertaking, beyond the capability of
the limited staff in NEA’s distribution and customer services departments. Work was limited to
specific multilaterally financed projects, and was hampered by a lack of basic system data and
geographic diagrams of the existing 11-kilovolt (kV) networks. Both ADB and the Government
recognized the need to develop NEA’s institutional capabilities. An advisory technical assistance
(TA) grant3 was attached to the project loan to support NEA in the development of institutional
capability.
B.
Formulation
3.
The Project was initiated through a small-scale project preparatory technical assistance
(PPTA)4 under which two consultants developed the project scope and conceptual design. The
PPTA was followed by an ADB appraisal mission in mid-1988.5 The scope of the project
components was described in some detail in the appraisal report.6 For the rehabilitation
component (Part A of the Project), the appraisal report identified the location and size of all
transmission and area substation equipment, and provided estimates of the lengths of
transmission and distribution lines to be installed. The rural electrification component (Part B) was
defined in more detail. The conceptual design included extensive use of single wire earth return
1
2
3
4
5
6
Loan 1011-NEP (SF): Seventh Power Project, for $51 million equivalent, approved 11 January 1990.
NEA, created under the National Electricity Act of 1984, is a government-owned corporation responsible for planning,
constructing, and operating all public power utilities in Nepal.
TA 1267-NEP: Institutional Support for Distribution Planning and Commercial Operations in the Nepal Electricity
Authority, for $780,000, approved 11 January 1990.
TA 837-NEP: Seventh Power Project, for $75,000, approved 24 December 1986.
Due to the Government’s slow pace in resolving key issues before loan negotiation, a short follow-up mission to
update the appraisal report was fielded in May 1989. The remaining issues were (i) transfer of the financial
responsibilities of the ongoing ADB projects to NEA, (ii) establishment of a commercial directorate in NEA, (iii)
commencement of a study on verification and valuation of fixed assets, (iv) submission of a schedule for liquidation of
Government arrears, (v) conversion of NEA’s accounts payable to the Government into equity, and (vi) an action plan
for timely preparation of audited financial accounts in accordance with the previous loan covenants. Loan negotiation
was eventually held in October 1989.
ADB. 1989. Appraisal of the Seventh Power Project in Nepal. Manila (Report LAP:NEP 18082).
2
(SWER) technology for electricity distribution, which the PPTA consultant considered an
economically effective way to distribute electricity in rural areas where demand is low. Because
this would be the first introduction of SWER technology into Nepal, it was considered necessary
that the project implementation consultant carried out a detailed technical investigation and
construction of a pilot SWER scheme in the Kathmandu Valley was included in the project scope.
In both cases the project cost estimates were based on comprehensive bills of quantities.
C.
Purpose and Outputs
4.
The main project objectives were to rehabilitate existing distribution networks in five larger
towns to improve their quality of electricity supply and reduce system losses, and to extend
subtransmission and distribution networks for rural areas.
5.
The Project’s rehabilitation component was to contribute to NEA’s loss reduction targets of
20% and lower from FY1994 onward, to improve the reliability of supply to consumers, and to
meet the growing demand for electricity. The Project also included extension and rehabilitation of
electricity supplies in two semi-industrial corridors that had poor reliability of supply and high
demand growth. Both corridors are along main roads to the Indian border. Thus, continuing
industrial development would support Nepal’s export trade with India. The Project’s rural
electrification component was to support the connection of about 83,500 new consumers in rural
areas. This would support the Government’s objective of bringing electricity to rural areas, and
substituting kerosene, diesel fuel and fuelwood by electricity generated from Nepal’s indigenous
hydroelectric resources.
6.
The Project, as defined at the time of appraisal, had three main parts:
(i)
Part A: Rehabilitation and extension of the subtransmission and distribution
networks in the towns of Hetauda, Birunj, Butwal, Bhairahawa, and Dharan; and in the corridors
between Hetauda and Birgunj, and between Butwal and Bhairahawa.
(ii)
Part B: Electrification of six unelectrified rural areas: Ilam-Damak, Dharan, Siraha,
Malangawa-Gaur, Bharatpur-Parasi, and Tamghas-Sandhikarka. The unelectrified areas were to
be supplied from the existing interconnected system, and would not require construction of new
generation plants.
(iii)
Part C: Provision of two concrete pole plants in central and eastern Nepal;
construction and maintenance equipment, and vehicles; and project support facilities.
7.
The attached TA (footnote 3) was to improve NEA’s capacity for planning of electricity
distribution, and to strengthen its newly created commercial department. It included (i)
preparation of a 5-year rolling distribution development plan to decentralize distribution planning
by establishing planning units in regional branch offices; and (ii) provision of on-the-job training in
consumer accounting, commercial policy development, and loss reduction.
D.
Cost, Financing, and Executing Arrangements
8.
At appraisal, the estimated project cost was $64.0 million, comprising $42.7 million in
foreign exchange and $21.3 million in local currency. ADB was to finance 80% ($51.0 million) of
the project cost, including all foreign exchange costs, and $8.3 million of local costs, from its
Special Funds resources. The loan terms included a 1% service charge, a 10-year grace period,
3
and a 40-year maturity. The Kingdom of Nepal was the Borrower, and NEA was the Executing
Agency (EA).
9.
The loan proceeds were made available to NEA under a subsidiary loan agreement. The
relending terms to NEA for rehabilitation of distribution systems, supply of materials and
equipment, and consulting services included a 10.25% interest rate, a 25-year repayment period
including a 5-year grace period.7 Loan proceeds for the rural electrification component were relent
to NEA at 1% interest. The Borrower assumed the foreign exchange risk of the entire loan.
10.
NEA set up a dedicated project implementation unit in Kathmandu, which was responsible
for overall project management, engineering and design, and for contract administration.
Subsidiary project offices were established in the eastern, central, and western regions. They
were responsible to the project implementation unit for stores management and supervision of the
implementation contracts. The regional project offices were also responsible for the operation and
maintenance of each subproject until its formal handover to the NEA local branch office.
E.
Completion and Self-Evaluation
11.
ADB’s project completion report (PCR), circulated in July 2001, rated the Project as
successful. But the PCR was prepared before local contractors had fully completed project
installation, so the final project cost had to be estimated.8 The PCR discussed many problems
during project implementation and concluded that the performance of the implementation
consultant, and some contractors and suppliers, was unsatisfactory. Accounts of the Project’s
environmental and social impacts were limited. The PCR did not assess the relevance, efficacy,
efficiency, sustainability, or institutional and other impacts of the Project. Lessons learned were
mainly with respect to administrative difficulties during project implementation. Recommendations
were made in terms of closely monitoring completion of the unfinished project components,
financial health of NEA, and attainment of project benefits. The PCR provided no information on
implementation of the attached TA.
F.
Operations Evaluation
12.
This project performance audit report (PPAR) reviews PCR findings and assesses the
Project in terms of relevance, efficacy, efficiency, sustainability, and institutional and other
developmental impacts. The assessment is based on a review of ADB documents, discussion
with ADB staff, and findings of the Operations Evaluation Mission (OEM). The OEM visited Nepal
from 25 February to 12 March 2004, and held discussions with representatives of the Ministry of
Finance, Ministry of Water Resources, Electricity Tariff Fixation Commission (ETFC), and NEA.
The OEM visited some project sites and districts electrified under the Project in the flat areas of
the western, central, and eastern regions.9 During the field visits, the OEM had discussions with
managers and engineers maintaining project facilities and carried out a reconnaissance-level
physical inspection of some facilities constructed under the Project. The OEM also carried out
socioeconomic surveys in Siraha, Chitwan, Nawalparasi, and Rupandehi districts. The views of
7
8
9
Both ADB and the World Bank required that the relending terms be on a commercial basis.
The PCR mission placed significant emphasis on correctly reporting project costs, and indicated dissatisfaction about
not being able to accurately quantify costs. But the estimate of the total project cost is probably reasonably accurate
because it was based on the noncompleted amount of the local construction contracts with fixed costs.
Nevertheless, there could be inaccuracies in the cost of individual project components since the allocation of some
equipment supply contracts to individual project components had to be estimated. Because the cost breakdown in the
PCR was comprehensive and the best cost assessment available, it is used in this report.
OEM’s planned travel to hill districts of eastern Nepal was restricted because of security problems.
4
concerned ADB departments and offices, and those of the Government and EA, were considered
when finalizing the PPAR.
II.
A.
PLANNING AND IMPLEMENTATION PERFORMANCE
Formulation and Design
13.
The Project was formulated to rehabilitate distribution networks in five major towns in
order to improve the quality of electricity supply and reduce system losses, and to extend
subtransmission and distribution networks to rural areas in the terai (flat plains) and hills
(mountains that are generally not covered by snow). The Project was expected to directly benefit
domestic consumers and commercial and industrial users in urban and semi-urban areas, as well
as users of the existing irrigation facilities that were using imported fuels, and about 84,000 new
consumers in rural areas. The Project conformed to the Government’s strategy for the power
sector in the short and medium term, and was in line with ADB’s operational strategy for Nepal.
The Project was a continuation of ADB’s long-term involvement in the Nepal power sector.10
14.
The extent of SWER to be included in the Project was described in detail. The terms of
reference (TOR) for the project implementation consultant included a detailed technical
investigation to determine the appropriateness of using SWER technology in Nepal. A
comprehensive study into the use of SWER technology in the project areas was undertaken at
project inception. Technical problems were found to make successful implementation of SWER
difficult. The high population densities in the terai project areas make the use of SWER
technology problematic and potentially uneconomic.11 The hill areas in the Project have lower
population densities and are better suited to the use of SWER. But ground conditions were found
to be such that designing a suitable earth connection would be difficult, making the use of SWER
technology potentially hazardous, particularly during the dry season. In retrospect, these technical
issues should have been addressed at the project design stage.
15.
Once the decision was made not to use SWER technology, it became necessary to revise
the design of the rural electrification components. The implementation consultant reviewed the
conceptual designs for the six rural electrification areas, and proposed revised designs using
conventional three-phase distribution. The review used the best costs available at the time, and
reformulated each subcomponent to meet ADB’s financial and economic criteria.12 As a result,
some villages were deleted from the Project, and others added. The number of households that
could potentially be connected to the rural electrification scheme increased because of the
technical reformulation. The consultant’s report estimated that, after 10 years, 144,600 new
consumers would benefit from the rural electrification.
10
Of 15 major towns where earlier ADB studies indicated an urgent need for rehabilitation and expansion of existing
distribution networks, 4 were rehabilitated under the Fifth Power Project (Loan 670-NEP[SF] for $20.0 million,
approved 14 December 1983). Two more towns were rehabilitated under the Sixth Power Project (Loan 708-NEP[SF]
for $28.1 million, approved 20 November 1984). Electrification of five previously unelectrified rural areas was also
completed under the Sixth Power Project. ADB is now financing further rehabilitation of distribution networks, and
electrification of 22 rural areas, under the Rural Electrification, Distribution and Transmission (REDT) Project (Loan
1732-NEP[SF] for $50 million, approved on 21 December 1999).
11
SWER technology is applied most successfully in areas of low population density with few distribution substations per
km of line. Safety considerations limit the total load on an SWER circuit. The need for an isolating transformer at the
connection to the conventional distribution network means that circuit lengths of less than about 10 km are seldom
economical. The project consultant found that, while short-term use of SWER on the terai was technically possible,
the forecast load growth indicated that long-term SWER use might not have been sustainable.
12
A positive financial internal rate of return (FIRR) and a minimum economic internal rate of return (EIRR) of 10% were
required for the rural electrification subprojects.
5
16.
Soon after redesign of the rural component of the Project, and tendering of the main
equipment supply contracts, it became apparent that equipment costs would be lower than
estimated at appraisal. This was mainly due to participation of Chinese contractors in the
international competitive bidding process after 1992. At the same time, depreciation of the US
dollar against the special drawing rights (SDR)13 meant that the loan in dollar terms had
increased. Hence, an additional $26 million was available. To utilize the loan savings, ADB
agreed with NEA proposals for additional rural electrification in 22 areas.14 The rehabilitation
component of the Project was largely implemented as designed at appraisal. But only one
concrete pole manufacturing plant, instead of the two plants envisaged, was considered
necessary and built.
B.
Achievement of Outputs
17.
The Project included installation of the following electricity reticulation: (i) about 185
megavolt-ampere (MVA) of new 132 kilovolt (kV), 66 kV, and 33 kV substation transformer
capacity; (ii) more than 320 kilometers (km) of new 33 kV subtransmission line; (iii) almost 2,500
km of high-voltage distribution line; and (iv) more than 2,300 km of low-voltage distribution line. As
a result of the Project, electricity was reticulated to almost 1,000 previously unelectrified load
centers, providing electricity access to more than 200,000 new customers. In addition, new 11 kV
and 400 V distribution lines were constructed or rehabilitated to improve the quality and reliability
of supply in five major towns and two significant load corridors.15 Furthermore, a new concrete
pole factory was built, with a daily production capacity of as many as 58 pre-stressed concrete
poles. A pilot SWER scheme, designed to supply up to 600 domestic customers, was constructed
in the Kathmandu Valley using project funds, but was abandoned soon after the decision not to
use SWER technology in the Project. The standard of construction observed by the OEM was
generally good. But a number of engineering issues and problems were identified (discussed in
Appendix 1).
C.
Costs and Scheduling
18.
The actual project cost was $65.8 million. Loan disbursements of $55.1 million included
$53.7 million in foreign exchange cost16 and $1.4 million equivalent in local currency. The
Government funded the remaining local currency cost of $10.7 million equivalent. An undisbursed
$2.4 million equivalent was canceled on loan closure. The disbursement of $4.1 million higher
than the appraised loan of $51.0 million was caused by depreciation of the dollar against the
SDR.
19.
Table 1 compares project cost estimates at appraisal with actual costs at completion. Most
significant is the $19.7 million for extension of the rural electrification component. This
extension—more than 25% of the total project cost—is explained in the PCR as having been
made possible by Chinese contractors’ participation in the bidding, which reduced bid prices. All
13
In 1994, the exchange rate was $1.45: SDR vs $1.25: SDR at appraisal—a 16% depreciation of the dollar against
SDR.
14
ADB’s decision was based on a technical and economic study that NEA prepared, using the same methodology that
the consultant used in the inception study.
15
The OEM was unable to quantify the extent of the distribution line rehabilitation undertaken under Part A of the
Project, but visited three of the rehabilitated areas during the field visit.
16
Material valued at $6 million was purchased under loan-financed contracts, but was not used in the Project.
6
project components had cost overruns, except for the original rural electrification component.17 A
substantial component of the project cost was material procured under international competitive
bidding, so participation of Chinese manufacturers in these material supply contracts was
undoubtedly a contributing factor. Other significant factors were Nepalese manufacturers’ ability
to bid to supply project equipment such as distribution transformers, and increased
competitiveness of Nepalese installation contractors. Furthermore, the price contingency was
calculated assuming a constant nominal exchange rate. These factors, combined, not only kept
costs below or near budgeted levels, but also allowed allocation of contingencies to the scope
extension in rural electrification.
Table 1: Summary of Appraised and Actual Project Costs
($ million)
Item
Part A
Part B
Components
Appraisal Estimate
Foreign Local
Total
6.0
1.9
7.9
24.0
9.2
33.2
24.0
9.2
33.2
Foreign
7.3
33.7
22.0
11.7
3.0
Actual Cost
Local
Total
1.7
9.0
15.0
48.7
6.0
28.0
9.0
19.7
1.3
4.3
Rehabilitation
Rural Electrification
Original Scope
Extension
Part C
Concrete Pole Plant/Tools &
2.2
0.5
2.7
Equipment
Part D
Consulting Services
1.7
0.3
2.0
2.2
0.1
2.3
Physical Contingencies
1.7
0.6
2.3
Price Contingencies
6.8
4.4
10.2
Taxes and Duties
1.7
1.7
NEA Project Management
0.3
0.3
Interest During Construction
1.3
2.4
3.7
1.5
1.5
Total
42.7
21.3
64.0
47.7
18.1
65.8
NEA = Nepal Electricity Authority.
Source: ADB. 2001. Project Completion Report on the Seventh Power Project in the Kingdom of Nepal. Manila.
20.
The loan was approved on 11 January 1990, with an original closing date of 31 August
1995. After three extensions, the loan was closed on 9 August 1999. NEA completed
construction of project works in September 2000, after successfully resolving a few difficult
right-of way issues.18 A comparison of the appraisal schedule with the actual project
implementation is given in Appendix 8 of the PCR. A major cause of implementation delay was
the lengthy process within ADB to approve NEA’s request to utilize loan savings for the
extension of the rural electrification component.19 The extended project scope required a
second round of procurement, which did not begin until early 1996. Other delays arose from (i)
delays by NEA in meeting the conditions for loan effectiveness,20 (ii) delays in mobilizing the
17
Cost overruns in Parts A and C may partly reflect the fact that large portions of these components were implemented
using turnkey contracts rather than material supply and local installation where successful bidders were mostly
Chinese and Nepalese manufacturers. The cost overrun in Part C was in spite of the fact that only one of the two
pole plants included in the original project scope was constructed.
18
Project land acquisition was minimal. Compensation for right-of-way of distribution and transmission lines was not
included in Nepal’s standard rules and regulations at project implementation. Rights-of-ways were obtained at no
cost, mainly through consultation with affected people. No complaints regarding the issue of right-of-way were
reported during the field visit.
19
NEA originally made this request in August 1994, and approval took 14 months. A review mission fielded in
September 1994 expressed concern about delays in implementing the original scope and recommended that
approval be deferred until NEA’s implementation performance improved. A subsequent review mission in June 1995
noted improved implementation performance and recommended that the request be granted.
20
The loan did not become effective until 18 September 1990, 8 months after Board approval.
7
project consultant,21 (iii) the time required to fully evaluate the SWER technology, (iv) delays in
award of contracts, and (v) poor performance of some international contractors. A further delay
was because ADB did not approve the first extension of the loan closing date until 17 November
1995. That delay stopped project work for 3 months, because contractors would not continue after
ADB’s original letters of credit expired.
D.
Procurement and Construction
21.
The Project required 89 different contracts, and project works stretched over almost 700
km from east to west. Bid documents for most project turnkey and equipment contracts as scoped
at appraisal were issued in December 1992. Bids were opened in February 1993, but the first
contracts were not awarded until August 1993; some contracts were not awarded until mid 1994.
Delays were due to the volume of contracts to be processed, and to an exceptionally large
number of representations from unsuccessful bidders. In its PCR, NEA alleges that some
representations were made on the basis of forged documents supporting the complainant’s ability
to complete the contract works. Most of these representations were received before or
immediately after ADB received the bid evaluation reports, and before the bid results were made
public. At the time, there was a strong suspicion that somebody was prematurely leaking the
results of NEA’s bid evaluations to bidders, but there is no record that ADB took action in
response.
22.
Some contractors performed poorly. First, at least two contractors, after receiving most of
their contract payments following successful acceptance inspection at the contractor’s works, did
not dispatch the materials to the sites. The matter was resolved in one case, but the equipment
was never dispatched in the other case, and the contractor’s bank guarantee was forfeited.
Second, an international turnkey contractor was paid the amount of the contract in foreign
currency after equipment had been delivered. But the contractor was unable to repatriate
sufficient funds back to Nepal to complete the erection work because of its own government’s
controls on foreign currency. This caused delays. Third, the contractor for supply and delivery of
conductors defaulted, claiming that his costs had increased due to a steep rise in the cost of
aluminum. The contractor was bound by a fixed-price contract, so the claim could not be
considered. The contract had to be terminated, and the supply of material was re-bid. Finally,
single-phase customer meters were found on arrival at site not to meet the specified accuracy
requirements. As a result, the contractor sent a team of four technicians with two test benches to
Kathmandu to retest and adjust all meters over an 8-month period. This delay led to such an
acute shortage of meters that many rural households had to wait more than a year before
provision of a requested connection. Such irregularities affected only a few contracts, but had a
serious impact on project completion since all required material had to be made available before
full completion of erection works.
23.
The supervision of contractors was also unsatisfactory in some cases. Personnel who did
factory inspections sometimes did not fully understand project requirements, and accepted
equipment that did not fully meet project needs. In other cases, contractors delivered the wrong
equipment, even after factory inspection. Other delays were caused by inadequate supervision
due to a lack of qualified personnel assigned to the Project, and by landowners refusing the
contractors access during the monsoon season to prevent crop damage. The PCR also noted that
21
The consultant was appointed in 1989, before loan approval. When the loan became effective, 1 year after contract
negotiations, it was necessary to renegotiate parts of the consultant’s contract and approve changes in personnel.
NEA initially insisted the original contract should stand unchanged. As a result, a dispute developed between NEA
and the consultant, which was only resolved after ADB intervention. Consequently, the consultant was not mobilized
until July 1991.
8
the impact of monsoons on line erection was not adequately considered when planning
construction works.
E.
Organization and Management
24.
The large number of contracts and widespread project areas made the Project particularly
hard to organize and manage. NEA set up a project implementation unit in Kathmandu with
overall project responsibility, especially for contract administration. Subsidiary project offices,
responsible for construction supervision, were established in the western, central, and eastern
regions. Separate project stores were maintained in each subsidiary office. The Project retained
responsibility for project works until they were formally handed over to the relevant branch offices.
This approach was considered appropriate for a project of this magnitude and complexity.
25.
At project completion, about $6.0 million worth of equipment procured through loan funds
had not been used in the Project. That equipment was eventually transferred to NEA stores. This
was 9% of the total project cost, and 12% of the rural electrification component. Much of the
equipment was later used to construct further rural electrification works outside the scope of the
Project, which may not have been subject to ADB’s financial and economic approval criteria or
safeguard policies. Furthermore, equipment ordered under each contract had to be allocated
among different subcomponents. This required a complexity of project accounting that may have
been overlooked. Future projects of this type should have better inventory control.
26.
NEA satisfactorily complied with covenants related to project and corporate organization,
although with some delay in internal audit function. Other loan covenants included (i) electricity
losses reduced from 26.5 % in FY1990 to 20% from FY1994 onward, (ii) a self-financing ratio of
at least 23% from FY1998, (iii) a 6% rate of return on the gross book value of fixed assets from
FY1991, and (iv) a debt service ratio of 1.2 from FY2001. Total system losses remained high
throughout project implementation, and are currently 24.5%. According to the PCR, at loan
closure in 1999 NEA achieved the required ratios of self-financing and debt service coverage, but
its return on rate base was only 5.4%.22 NEA’s financial performance has deteriorated since then,
to the extent that NEA has not made a pre-tax profit since FY2000 (Appendix 2). Audited
accounts were consistently submitted late throughout project implementation.
27.
The project implementation consultant remained on the Project from mid-1991 until mid1995 when the time provided in its contract was expended. According to the PCR, the
consultant’s performance was not satisfactory. The PCR noted that revised designs for rural
electrification were incomplete and misleading. The consultant was also blamed for delays in
several activities, including tender invitation for procurement and erection works.
28.
The PCR assessment of the consultant’s performance relies on NEA assessment in its
PCR, and is not supported by evidence in ADB files. An ADB review mission in June 1992, 12
months after consultant mobilization, noted a communication problem between the consultant and
NEA. The back-to-office report of the next review mission, in May 1993, noted that the situation
seemed to have been resolved, and that communication between the two parties was good. The
OEM reviewed the consultant’s engineering design report on the first phase of the Project, and
22
There are discrepancies between the financial indicators for FY1999 as reported in the PCR and in the report and
recommendation of the President (RRP) for the REDT loan. Most significant is the self financing ratio, which is
reported as 28% in the PCR but only 9% in the RRP. The returns on rate base in the two reports also differ but are
not comparable because in the RRP it is measured against the revalued fixed asset base, rather than the book
value.
9
considered its standard high. This design report was used as a template for subsequent NEA
reports seeking approval for scope extensions of rural components.23
29.
Throughout the Project, ADB sent review missions roughly on an annual basis. These
missions were particularly important before 1996, when project progress was considered
unsatisfactory. Extension of the loan closing date, and extension of the project scope to include
more rural electrification, appear to have been rolled together.24 But these were two separate
issues, and should have been treated as such. Then in mid-1996 it was decided that project
administration would be transferred to the Nepal Resident Mission (NRM). The decision was
reversed in January 1997, mainly because of constraints in resources at NRM.25 Fifteen boxes of
project documents were transferred from Manila to Nepal, then returned to Manila 6 months
later. For preparation of this report, only three boxes of project files could be located. Significant
documents, which would have given better understanding of problems during the Project, were
missing. For example, no documents could be found relating to the demobilization of the project
implementation consultant in July 1995.
30.
Project implementation suffered from a lack of more proactive supervision when the
Project was in difficulty during the early years. In such circumstances, relying on annual review
missions for feedback on project performance is unsatisfactory. Regular monthly or quarterly
review meetings with the EA, and possibly the consultant, would have been better. This could
have provided ADB and the Borrower earlier warning of difficulties, allowing corrective action
before the situation deteriorated.26 The improvement in performance after 1995 seems to have
been due to a change of NEA project manager, rather than to changes in how ADB administered
the Project.
III.
A.
ACHIEVEMENT OF PROJECT PURPOSE
Operational Performance
1.
Rehabilitation Components and Subtransmission
31.
Project’s rehabilitation components were undertaken in strategic locations that were
important to the national economy, either through proximity to main border crossings with India or,
for Dahran, to important agricultural export industries such as tea. Therefore, the rehabilitated
systems have been subject to high load growth, and will probably reach their technical design
capacity well before expiration of the life of the assets. Indeed, some subcomponents of the
Project reinforced distribution work completed under the Sixth Power Project. Some power
transformers installed under the Project have already been replaced with larger units. The Project
has ensured that customers in the area continue to receive a power supply of acceptable quality.
23
The one NEA person the OEM spoke with who had worked with the consultant considered the consultant’s work
satisfactory.
24
ADB approval for both extending the loan closing date and the project scope was given on 14 November 1995, at a
time when little progress had been made on installation of the first phase of rural electrification. The PCR suggests
that the main reason for the delay in approving the scope extension was NEA’s failure to provide all required
information. But the OEM review of the project files indicates that progress on the Project was the major concern.
25
Another reason was the large number of procurement packages and representations associated with the Project. It
was decided that the Project would be managed more efficiently from ADB headquarters.
26
The OEM was informed that NRM started monthly meetings with project managers/directors of ADB-assisted projects
to discuss ongoing problems in late 1993. The monthly meetings afterward were intensified by discussing all issues
identified in project review missions. The status of each project was reported to concerned departments at ADB
headquarters. But the project files include no records of the monthly meetings, nor of correspondence between NRM
and ADB headquarters.
10
This is particularly important for industrial customers, who are an important stimulus for continuing
economic growth. Sustainability over the longer term will depend on the quality of maintenance,
and on availability of technical and financial resources to upgrade and reinforce parts of the
system that become loaded to their rated capacities. Until now, all work necessary to keep the
network operational has been done.
32.
Maintenance quality varies across the network and, especially for area substations, is
dependent on the enthusiasm and ability of the local maintenance staff. In places where
housekeeping was good, maintenance was clearly proactive and of high standard. In other
situations, only the minimum maintenance necessary to keep the equipment operational is done.
Of concern is the fact that many staff have little regard for the proactive avoidance of failure in
day-to-day network operations. For example, the low-voltage, molded case circuit breakers on
distribution substations are not designed for exposure, and are mounted in weatherproof cabinets.
But the cabinet doors are routinely left open, or sometimes even removed, so that staff can
operate the circuit breakers from the ground using a stick. OEM members also saw a number of
instances where temporary repairs had become permanent, either because replacement parts
were not available, or through failure to return to the sites to make more permanent repairs. Other
sustainability concerns are largely outside the control of management and staff. The 11-kV indoor
circuit breakers used throughout the Project are no longer manufactured, so spare parts cannot
be obtained. One substation switchyard and control room was flooded to about 1 meter during the
2003 monsoon season.
33.
Engineering supervision of operation and maintenance is inadequate in some places. The
OEM requested data on the demand and energy growth for all transmission and subtransmission
substations constructed under the Project. This information should be readily available, because
substation operating staff routinely record it hourly. The necessary data for many substations was
provided, although after difficulty, but data for other substations were not available. In another
instance, the OEM found load data recorded in a substation log that was clearly erroneous, as it
was inconsistent with other data recorded in the same log. Inconsistent data appeared to have
been reported to management on a weekly basis—with no one questioning its accuracy—since
the substation was commissioned.
2.
Rural Electrification
34.
The Project’s rural electrification components generally appear to have been installed
according to the revised design. But operationally, those components also suffer from many of the
same problems as the rehabilitation components, particularly in maintenance quality. Service
drops between the low-voltage reticulation and the customer metering points do not have proper
connectors, and connections are made by simply twisting the service drop conductors around the
distribution line conductors. Over time, this will cause loose and high-resistance connections that
will, in turn, cause low voltage for customers and higher system losses. In one case, a weight
appeared to have been attached to the service drop conductor in order to improve the connection
quality. Illegal connections are endemic in some areas. Many of these connections were easy to
detect and, in some villages, the OEM noted at least one illegal connection on each span. Other
illegal connections may also be present, but are attached more skillfully, so they appear
11
legitimate. Most poles adjacent to residences had outside lights, probably illegal, connected to the
low-voltage conductors.27
35.
About 95% of the customers in less-accessible rural villages is residential. NEA claims
that 90% of these customers pays the minimum lifeline charge of NRs80 per month, but many do
not fully use their entitled 20 units per month. But, based on an inspection of billing records in only
one location, the OEM believes the average customer consumption could be higher, particularly in
the summer when many households use fans. Nevertheless, few remote residential customers
paid more than NRs200 per month. This equates to consumption of 36 units at an average tariff of
NRs5.6 per unit. NEA’s average generation cost for electricity generated from its own plants in
FY2003 was NRs4.03 per unit. But NEA pays large independent power producers (IPPs) an
average of NRs6.1 per unit, which the OEM considers a reasonable proxy for the marginal cost of
generation.28 On this basis, revenue from electrification of remote villages is insufficient to cover
even the generation cost, and does not provide for other costs resulting from the Project,
including system losses, operation and maintenance, and the cost of servicing NEA’s debt to the
Government. Therefore, from a financial perspective, the electrification of remote villages is
unsustainable at existing tariff levels. The current tariff structure contains some cross-subsidies
among various consumer categories, but they are relatively restricted. Considering the
importance of rural electrification in both political and economic terms, NEA will do its best to keep
these rural systems operational.
3.
Concrete Pole Factory
36.
The concrete pole factory in Amlekhganj, in southern Kathmandu, continues to produce 8-,
9-, and 11-m prestressed concrete poles of good quality. By January 2004, the factory had
produced more than 77,600 units. The factory is financially independent. It sells its poles to NEA
at a transfer price that provides an adequate margin over its own operating costs, but is
significantly lower than purchasing from the private sector (Table 2).
Table 2: Performance of the Pole Factory
Poles
8-meter
9-meter
11-meter
Total Production
to January 2004
45,316
23,910
8,416
Current Production
Cost
(NRs)
2,014
2,712
4,210
Transfer Price
to NEA
(NRs)
2,520
3,270
4,945
Market Price for
NEA
(NRs)
3,474
3,964
8,000
NEA = Nepal Electricity Authority, NRs = Nepalese rupees.
Source: Nepal Electricity Authority.
B.
Performance of the Operating Entity
37.
Appendix 2 compares NEA’s financial performance from1999 to 2003 with performance as
forecast in the 1999 report and recommendation of the President (RRP) for the Rural
27
When asked about this, an NEA staff explained that village development committees paid for the street lights. But the
installation quality of many outside lights was poor, indicating they had not been installed professionally.
Furthermore, the monthly tariff for an unmetered street light is NRs1,860 per kVA, equivalent to NRs74 for a 40-watt
bulb. This is high compared with the NRs80 minimum charge payable by low-use consumers.
28
NEA’s reported average cost of generation does not include IPP payments. Regardless, rural electrification
introduces new load to the network. Therefore, financial analysis should be based on NEA’s marginal generation
cost. This cost will vary by season, but NEA’s average IPP cost seems a reasonable proxy for the average marginal
financial cost.
12
Electrification, Distribution and Transmission Project
(REDT). NEA has consistently
underperformed when compared with ADB’s performance expectations. 2000 was the only year in
which NEA made a profit. This is primarily because NEA has not increased its tariff to the levels
envisaged. NEA’s average revenue for FY2003 was NRs7.02/kWh compared with the RRP
forecast of NRs10.09/kWh. A further problem is NEA’s failure to reduce system losses to the
forecast levels. Actual losses for FY2003 were 24.5% vs the forecast 18.7%. Another issue
affecting NEA’s financial position is the large amount of electricity arrears owned by the
Government and municipalities.29
38.
NEA currently faces a difficult operating environment. The Maoist insurgency in Nepal
continues unabated and NEA facilities are an ongoing target. Insurgency damage in FY2003 was
NRs72.4 million. More important than the monetary cost of physical damage is the impact of the
insurgency on NEA operations. This impact arises from both the quantifiable cost of protecting its
assets and the less-quantifiable cost from having to take practical and political considerations into
account when making management decisions. An example of this difficulty is the current
requirement for customers to travel to the nearest branch offices to pay their monthly electricity
bills.30 This was made necessary by the removal of bank branches from rural villages because of
the insurgency. NEA cannot send its staff to collect accounts directly from customers because the
staff would obviously be carrying money and thus, be high-risk insurgency targets.
39.
ETFC sets NEA’s tariffs, which were last revised in September 2001. NEA filed for a tariff
review in mid-2003, requesting a seasonal tariff that would reduce electricity costs in the wet
season when river flows are higher. This request was declined; ETFC rejected the concept of
seasonal tariffs. NEA is preparing a new tariff filing for likely submission in April 2004. The
Government assurances for REDT include semiannual tariff reviews by ETFC, but such reviews
are not occurring, at least not in a meaningful way. The perception that tariff rates are high
appears widespread in Nepal. The high cost of electricity was a recurring theme in the focus
groups discussions that OEM organized. NEA staff and other government officials complained to
OEM that electricity tariffs in Nepal were already high compared with those of other countries in
the region. This political climate and the extent of government representation on ETFC make
significant tariff increases unlikely in the short term. The ETFC chairperson told OEM that NEA
should improve its financial performance through efficiency gains rather than relying on tariff
increases. But while there is undoubtedly scope for NEA to improve its operating performance,
the potential impact of such improvements on NEA’s financial performance is limited by the fact
that most NEA costs are outside of its management’s direct control. A high interest rate is one
such cost. NEA is lobbying aggressively to reduce the interest rate on its subsidiary government
loans.31
40.
NEA is making continuing efforts to improve efficiency of its operations. It has
disaggregated internally into four business groups (generation, transmission and system
operation, distribution and customer services, and engineering services). Each group now
operates as a profit center. Managers of the generation, transmission, and distribution groups
29
As a result of policy dialogue with ADB, the Government paid part of the arrears in December 2003. The Government
also made a provision in the finance ordinance in January 2004 to directly deduct one sixth of the grants given to
municipalities for payment of electricity arrears. NEA is also maintaining dialogue with municipalities to agree on the
amounts of arrears. The OEM was informed that, as of March 2004, 25 of 58 municipalities had agreed on the
amount of arrears to be paid to NEA.
30
OEM was told that travel to and from the nearest branch office to pay the monthly electricity account takes some
customers a day and costs more than NRs50 for public transport—when in many cases the bill itself may be only
NRs80.
31
The Government is not free to adjust these interest rates, which are specified in NEA’s loan covenants with ADB and
other lenders (see footnote 7).
13
must sign performance contracts that will reward them according to the extent to which they
achieve key performance objectives. Within the distribution and customer services group, 19
branch offices have been designated as “distribution centers” and operate as profit centers
outside the regional office structure. Distribution center managers are given incentives to achieve
results, measured by key performance indicators. According to NEA, a recent audit of distribution
center performance was encouraging.
41.
High losses on the NEA system are an ongoing problem. NEA’s losses, including
electricity consumed for its own use, totaled 24.5% in 2003, down from 27% at appraisal but still
significantly higher than the covenanted target of 20% from FY1994 onward. It is widely accepted
that NEA’s nontechnical losses are excessive, and that any initiative to reduce losses must target
those losses as first priority. Current initiatives include the inclusion of targets for loss reduction in
management contracts for the distribution centers; and a scheme, supported by the Danish
Government, to sell electricity at discounted wholesale rates to consumer cooperatives, which will
assume ownership of the local distribution networks and responsibility for their operation.32 The
Government also recently introduced the Electricity Theft Control Act 2058 and the Electricity
Theft Control Regulations 2059, which treat electricity theft as a criminal offence and give NEA
new powers to deal with the problem. Such initiatives are to be applauded, but OEM found that
illegal connections were easy to locate in many rural areas, and that NEA staff accompanying the
OEM simply accepted such connections as a fact of life.
42.
NEA will no longer contribute to the capital cost of rural electrification programs because
they are seen as uneconomic. But rural electrification is an important priority of the Government,
which has a rural electrification budget of NRs590 million for FY2004. From now on, the
Government will contribute 80% of the capital cost of rural electrification programs to NEA as
equity, with beneficiaries funding the remaining 20%.33 In addition to the Danish Government
scheme, ADB’s current REDT project includes $18.4 million for rural electrification. But accessible
rural areas are now fully electrified, and rural electrification schemes in less-accessible areas are
failing to recover the cost of generation. The operation and maintenance of these programs will
put increasing pressure on NEA’s financial resources, and will force reliance on subsidy support
from NEA’s urban domestic consumers.34 The Government is aware of the problem and is looking
to the ongoing TA35 for recommendations on how to manage it over time.
C.
Financial and Economic Reevaluation
43.
The financial and economic reevaluation of the Project is discussed in detail in Appendix
3. Reevaluations were carried out separately for the urban rehabilitation and rural electrification
components, using the same approach used at appraisal and in the PCR. The period of analysis
was FY1992–FY2021. Given the recent power demand and forecast growth, the facilities
rehabilitated or installed under the Project’s urban and rural components are expected to be
loaded to full capacities by 2006. After that, further reinforcements will be required to meet the
load growth.
32
By March 2003, 170 applications have been received for the program, and 18 contracts signed. It is hoped that the
scheme will reduce theft, because consumers will be less likely to steal from their neighbors. But success of this
scheme will depend on the ability of the small local cooperatives to operate and maintain the network sustainably.
33
The beneficiary contribution does not have to be in cash; it can be in labor, supply of wooden poles, and other “inkind” contributions.
34
NEA’s current tariff is designed to avoid cross subsidy among different customer groups, but the tariff structure does
not prevent cross subsidies within customer groups. In FY2003, domestic customers accounted for 36% of sales and
37% of revenue.
35
TA 3552-NEP: Management Reforms and Efficiency Improvements for NEA, for $0.8 million, approved 27 November
2000.
14
44.
Incremental electricity sales in each urban rehabilitation scheme from 1998 to 2003,
estimated in the Feasibility Study Report of 1992, were checked against NEA’s overall load
increases during the same period and found reasonably realistic. Thus, those data were used in
the reevaluation. NEA has estimated that about 200,000 new connections in rural areas were
made under the Project from 1998 to 2003. This is about 2.4 times the target number of new
connections estimated at appraisal.
45.
The financial cost of power for the urban component is assumed to be $0.055/kWh. That
is in line with NEA’s supply at 33-kV distribution levels from its own generation plants. Rural
electrification introduces new load to the network, so the financial cost of electricity for rural
supply is derived from NEA’s marginal generation cost. A reasonable proxy for this would be
NEA’s average purchase cost of NRs6.1/kWh from IPPs. The economic cost of power supply is
given by the opportunity cost of exporting power to India,36 which at the time of OEM was
$0.066/kWh. The system loss, excluding transmission at the distribution level, is assumed to be
15%.
46.
NEA’s current average tariff of NRs7/kWh is used as the financial benefit indicator for the
urban component. But a rural electrification scheme would not produce this yield because of the
high proportion of low-use and lifeline domestic customers. Economic benefits are assumed to be
derived mainly from (i) displaced use of kerosene for lighting and of diesel generators for power
and (ii) induced electricity consumption. For displaced consumption, the average economic value
of electricity consumption to displace kerosene lighting with wick lamps is estimated as $0.2/kWh,
and displacement of power generated by diesel generators, as $0.15/kWh. For induced
consumption, the willingness to pay for both residential and industrial consumers is assumed to
be the weighted average of the unit cost saving and the existing tariff.
47.
Table 3 summarises results of financial and economic analyses at project appraisal,
completion, and post-evaluation.
Table 3: Summary of Financial and Economic Revaluations
Item
Urban Rehabilitation
Rural Electrification
Appraisal
18.8
4.5
FIRR
(%)
PCR
13.4
0.8
PPAR
11.8
Appraisal
22.2
13.5
EIRR
(%)
PCR
20.0
11.1
PPAR
24.6
19.2
EIRR = economic internal rate of return, FIRR = financial internal rate of return, PCR = project completion report,
PPAR = project performance audit report.
Source: Appendix 3.
48.
The reevaluated economic internal rate of return (EIRR) for the urban component is
comparable to the appraisal estimate. The EIRR estimate for the rural component was more
favorable, mainly because of the large increase in the number of new connections compared with
estimates at appraisal and PCR. The lower recalculated financial internal rate of return (FIRR) for
the urban component resulted from inadequate adjustment of tariffs to more sustainable levels.
Depreciation of the Nepalese rupee against the dollar also affects the FIRR.37 The FIRR for the
36
Under the Power Exchange Agreement with India, the annual power exchange between Nepal and India is now
about 50 MW. Both countries recently agreed to gradually increase the exchange level to 150 MW.
37
The Nepalese rupee has depreciated 159% since appraisal in1988.
15
rural components is negative since the average revenue of NRs5.6/kWh from rural consumers is
insufficient to even cover the marginal generation cost of NRs6.1/kWh.
D.
Sustainability
49.
Electricity demand in many project areas, including remote areas reticulated for the first
time, is high compared with the forecast at appraisal. Table 4 compares the current peak load at
selected area substations constructed under the Project with the available forced cooled
transformer capacity. The loads shown include distribution network losses and, in many cases,
are undoubtedly elevated due to the level of electricity theft. Nevertheless, none of these
substations have been in service for more than 5 years.
Table 4: Substation Loads
Commissioning
Transformer
Year
Capacity
(MVA)
Itahari
8
2000
Inaraua
8
1999
Bisnupur
8
1999
Parsa
8
2000
Ilam
3
1999
Chanauli
8
2000
Kawasoti
8
2000
Parasi
8
2000
Palpa
8
1999
Gajuri
3
2001
Gwh = gigawatt hours, MVA = megavolt amps.
Source: Nepal Electricity Authority.
Substation
Energy Supplied
FY2003
(GWh)
42.0
16.5
7.9
23.1
7.0
16.6
14.6
13.0
9.0
3.8
Peak Load
FY2003
(MVA)
7.5
5.7
3.2
6.8
1.3
5.6
4.5
2.7
2.9
1.6
Peak Load
(% of capacity)
94%
71%
40%
85%
43%
70%
56%
34%
36%
53%
50.
Ample evidence shows that a reliable and good-quality supply of electricity stimulates
industrial and economic development in areas with good road access. For example, NEA supplies
more than 20 industries at 11 kV in the region served by the Kawasoti area substation.38 The
main sustainability problem in these areas is the availability of capital to increase capacity as the
existing distribution system becomes overloaded. Indeed, much of the electrification installed
during the Sixth Power Project has already been reinforced. For accessible areas with potential
for commercial and industrial development, NEA should take a longer-term view of future load
requirements in planning future additions of capacity. The situation is different in areas without
good road access, because significant industrial development is unlikely.
51.
The rural electrification component of the Project includes some previously unelectrified
towns along the east-west highway that will probably benefit from ongoing industrial and
commercial development. But all of Nepal’s more accessible areas have now been electrified, and
the financial sustainability of project components that serve less-accessible areas is unlikely.
Nevertheless, NEA will probably keep all parts of the Project operational because of the
Government’s commitment to rural electrification, and the benefits of electrification to individual
consumers.
38
The Kawasoti substation is in western Nepal, adjacent to the main east-west highway. The substation was built
through the rural electrification component, not only to supply new load but also to support the overloaded 11-kV
distribution network built under the Sixth Power Project. The transformer capacity installed under the Project was
only 3 MVA, but a larger transformer was installed within 1 year of commissioning the substation.
16
E.
Technical Assistance
52.
The attached TA was implemented from July 1990 to July 1991, when a distribution and a
commercial consultant spent a year in Kathmandu working full time with NEA. The distribution
consultant (i) proposed a structure for distribution planning and developed a schedule of
distribution requirements, (ii) established a drawing office and started the development of system
diagrams, (iii) developed procedures to establish and operate a management information system
and a 5-year rolling plan, (iv) developed the structure for a technical standards committee, and (v)
ran a training course on distribution planning. The commercial consultant (i) undertook a
diagnostic review of NEA’s consumer accounting and billing processes, and (ii) developed a plan
to introduce computerized billing, using commercial billing software. The consultants fulfilled their
TOR requirements, but TA achievements fell short of expectation because of the lack of NEA
commitment to immediate implementation of TA recommendations, and insufficient counterpart
funds to make the TA more effective.39 Overall, the TA is assessed as partly successful.
IV.
A.
ACHIEVEMENT OF OTHER PROJECT IMPACTS
Socioeconomic Impact
53.
The OEM conducted a socioeconomic survey to assess the impact of electrification on
individual domestic consumers, particularly consumers that had no electricity before the Project
(Appendix 4). In summary, electrification in urban areas and areas near sealed roads has positive
impacts on the local economy because of benefits to the lives of individual consumers, and stimuli
for industrial and commercial development. This economic development improves the lives of
domestic consumers so much that many consumers in such areas pay more than the minimum
“lifeline” electricity cost. In remote areas, consumers’ benefits from improved lighting and use of
radio, television, and electrical fans would be impossible without access to electricity. Women
have been the greatest beneficiaries of electricity. But many poor households in remote areas
have not connected to electrical power because the initial connection cost is so high.
Furthermore, NEA will not supply electricity to houses with thatch roofs because of high fire risks
(although some such households illegally connect to neighbors’ electricity). The industrial use of
electricity in remote areas is limited largely to rice and oil mills that were diesel-powered before
electrification. A key project objective at appraisal was to use electricity as an energy source for
irrigation, particularly for shallow well pumps. This did not materialize, mainly because of the cost
of providing a mains connection to each pump site. With diesel engines, there is no connection
cost and one engine can service a number of pumps because it can be moved from site to site.
B.
Environmental Impact
54.
The Project was appraised in 1989 and had no specific environmental objectives. The
appraisal report noted, however, that the design would take international environmental and
safety considerations into account “relevant to the location of transmission and distribution lines
and of substations.” Construction of the Project has been environmentally benign, with most
overhead lines located on road reserves. As noted in Appendix 4, there have been few
beneficiary complaints about environmental issues. But there were some concerns about the
safety of 11 kV lines constructed in urban areas. In such cases, NEA took appropriate steps to
39
An example was cancelation of a planned seminar on distribution planning for regional planning staff because NEA,,
citing budgetary constraints, would not allow the staff to travel to Khatmandu. In order to keep up the momentum,
ADB wanted to continue both components of the consultancy for 12 more months under a new TA, if NEA would use
savings from the Fifth Power Project to purchase and implement a pilot billing system. But NEA would not agree.
About 4 years later, savings were used for a pilot billing system.
17
alleviate the concerns and allow the Project to proceed. The Project was also expected to have
an indirect environmental impact by utilizing Nepal’s indigenous hydropower facilities to replace
fuelwood and imported fossil fuels. The Project seems to have done little to reduce fuelwood use,
although it has substituted somewhat for imported fossil fuels through reduced use of kerosene
and small diesel motors. But NEA operates high-cost diesel generation plants at times of peak
loads, and the additional electricity demand caused by the Project requires increased generation
from these sources. The engineering report in Appendix 1 also discusses possible design
improvements that might further reduce the environmental and safety consequences of future
projects.40
C.
Impact on Institution and Policy
55.
Objectives of the institutional development TA have, by now, mostly been achieved,
although more slowly than envisaged at appraisal, and with additional help from ADB and other
donors. First, NEA now has a computerized billing system in the larger branches that generate
70% of its revenue. With help of local consultants, NEA has enhanced the original billing software
and is now rolling out the enhancements. Under the REDT project, NEA will purchase upgraded
billing software with state-of-art technology, which it plans to install in all but its smallest branches.
Second, distribution planning is still centralized in Kathmandu, even though detailed design of 11kV distribution network extensions is undertaken at the branch level. NEA has purchased a
computerized geographic information system, and has incorporated records of its network assets
down to the 11-kV level. NEA has also purchased, with ADB funding, software for analysis of
distribution systems, and is interfacing the two packages. Both systems are available only in
Kathmandu, which may limit benefits from the geographic information system.
V.
A.
OVERALL ASSESSMENT
Relevance
56.
The Project conformed to Nepal’s needs for power sector development and ADB’s
strategy for assistance at appraisal to support the development of integrated power supply in
urban and rural areas. The Project has remained relevant to the achievement of sector
development objectives for both the Government and ADB. However, there was a design
weakness related to the introduction of SWER. Overall, the Project is assessed as relevant.
B.
Efficacy
57.
The Project achieved its primary objectives of improving quality and reliability of power
supply in areas with rapid growth demand, and of extending the availability of a reticulated
distribution system. But project goals in terms of NEA’s system loss reduction and financial
sustainability, envisaged at appraisal, have not been fully achieved. Overall, the Project is rated
efficacious.
C.
Efficiency
58.
Full completion of the Project took more than 10 years. During the early stages, ADB
considered it an at-risk project. While credit should be given for the fact that significantly more
rural electrification was achieved than envisaged at appraisal, this was made possible by factors
40
The need to design the Project to minimize environmental impact when things go wrong was not specifically noted in
the appraisal report.
18
largely outside the control of project participants. Although the rural component is not viable
financially, the Project has achieved more favorable EIRRs than estimated at appraisal. Overall,
the Project is rated as efficient.
D.
Sustainability
59.
The rehabilitation component and the pole factory are considered highly sustainable. The
rural electrification component is sustainable only with a significant and continuing subsidy, which
was not envisaged at appraisal. Overall project sustainability is considered less likely on the basis
of NEA’s weak financial position and continuous resource injections required to ensure continued
operation of project facilities.
E.
Institutional Development and Other Impacts
60.
Through the Project, NEA gained enough experience in distribution planning and design
so that external engineering and project implementation consultants were no longer required
during later project implementation and for future ADB–funded distribution projects. The Project
also facilitated economic growth in project areas by providing reliable power. The institutional
development and other impacts of the Project are rated significant.
F.
Overall Project Rating
61.
Overall, the Project is rated successful. This assessment recognizes the Project’s success
in terms of physical achievements and socioeconomic impact at project levels, but also takes into
account the requirement for ongoing subsidies to sustain the rural electrification component.
G.
Assessment of ADB and Borrower Performance
62.
Despite the much-improved implementation performance by NEA and ADB after 1995, the
performance of both ADB and the EA is assessed as partly satisfactory. For ADB, this
assessment reflects failure to take proactive and timely action to respond to implementation
problems early in the Project, as well as late decisions regarding the first loan extension, and the
aborted decision to transfer project administration to NRM. ADB’s partly satisfactory performance
reflects the inadequate attention that the project department gave to project administration. For
the EA, this assessment is based on the unsatisfactory project progress over the first 5 years
through the end of 1995, its failure to reduce losses to covenanted levels, and the poor financial
performance that continues to threaten the Project’s sustainability.
VI.
A.
ISSUES, LESSONS, AND FOLLOW-UP ACTIONS
Key Issues for the Future
63.
NEA’s most pressing problem is its deteriorating financial performance. NEA’s cash
operating surplus for FY2003 was only 42% of what ADB forecast in 1999 (Appendix 2). More
than 77% of this surplus was required to pay its interest liability. NEA is well aware of this
problem, and argues strongly for relief from these interest charges. But the more fundamental
cause of NEA’s problems is failure to raise electricity tariffs to more sustainable levels. The
average internal electricity tariff in FY2003 was only 70% of the level assumed in ADB’s 1999
forecast, and will not change significantly in FY2004, since no application for a tariff increase has
19
been submitted to the ETFC.41 Tariff setting in Nepal remains a political issue, because all ETFC
members are government appointees. The prevailing view, both within the Government and NEA,
is that the current average tariff level of NRs7.02 (about $0.10) is high, compared with that in
other developing countries in the region. In OEM’s view, significant tariff increases are highly
unlikely in the near future. Insurgency problems, which seemed to escalate during the OEM,
make it even more difficult for the Government to make meaningful tariff adjustments.
64.
There is little doubt that system losses are excessive, and contribute significantly to the
current level of electricity tariffs. Total losses in FY2003 were 553 GWh—almost 25% of NEA’s
electricity generation. The cost of these losses is estimated at NRs2,500 million, assuming an
average generation cost of NRs4.50/kWh, or NRs3,300 million using a marginal generation cost
of NRs6.0 per kWh. Using the marginal generation cost, each 5% reduction in total losses would
save NEA about NRs660 million in generation costs. A reduction in losses from 25% to 15%
would mean an average tariff reduction of NRs0.87/kWh, or 12% if applied to all domestic tariff
reductions. Thus, NEA must continue to vigorously address electricity losses, if it seriously wants
to reduce tariffs.42
65.
Assuming no change in NEA’s operating position, the rural electrification component of
ADB’s REDT project will strain NEA’s financial position and further reduce its ability to meet its
loan covenants. REDT will fund the installation of rural electrification costing $24.6 million or
NRs1,720 million. Incremental electricity sales resulting from REDT are estimated to eventually
reach 90 GWh. Based on NEA’s current operating situation, REDT will, at best, generate enough
revenue to cover the cost of the incremental generation.43 But, consistent with ADB’s financial
covenants, the rural electrification component will create an incremental annual revenue
requirement of about NRs420 million.44 Considering the relatively high initial connection charges
and the transaction costs of making monthly journey to pay electricity bills (Appendix 4),
possibilities of subsidizing the initial connection charges and reducing costs of payment for rural
customers should be explored so the tariff might be raised at least to a break-even level for rural
supply.
B.
Lessons Identified
66.
The decision not to proceed with the use of SWER technology, while justified on technical
grounds, caused delays early in the Project because it necessitated a redesign of the rural
electrification component. These delays may have been avoided if a more substantive PPTA
consultancy had been undertaken, and if the technical feasibility of using SWER had been more
thoroughly researched during appraisal. In this case, the staff consultant who did the project
preparation suggested the use of SWER, but was not required to carry out technical investigation
of proposed alternative technologies in the TORs. On one hand, innovation by consultants should
be encouraged. But on the other hand, for a project of this size and complexity, a full scale PPTA
should be mounted and the TORs should include investigation into the use of new and alternative
technologies.
41
The most recent tariff increase became effective on 17 September 2001.
NEA noted that the insurgency problem makes loss reduction initiatives more difficult to implement.
43
See paragraph 35. Furthermore, alternative approaches give similar results. NEA’s current average tariff is NRs7.02 /
kWh, but a rural electrification scheme would not yield this because of the high proportion of low-use and lifeline
domestic customers. Thus an average rural electrification tariff of NRs6/kWh, equal to the assumed marginal
generation cost, is a reasonable assumption.
44
The analysis assumes that revenue from the rural component of REDT will cover only the incremental cost of energy,
and no significant reduction of electricity losses below current levels.
42
20
67.
The main implementation problems arose during the first 5 years of the Project. The
Project was administered from ADB headquarters in Manila, and the project files show little
evidence of any useful input from NRM, even though the Project was considered problematic.
Under those circumstances, annual review missions were insufficient and the mechanism for
project monitoring at NRM was less than effective (footnote 26). Implementation problems might
have been reduced if an NRM officer had taken a more proactive role in monitoring the Project
between review missions. Regular monthly or quarterly meetings could have been held with
NEA’s project implementation unit, and proper documentation of those meetings might have
helped keep the ADB project officer in Manila informed of problems as they arose. This may have
allowed quicker corrective actions, and allowed the addressing of problems before they
developed into significant issues.
68.
Problems associated with poor contractor performance are not unique to the Project, and
should be avoided in the future. An ADB procedure for evaluating performance of both
international and local contractors, similar to that used for individual consultants, would be useful.
The performance of contractors would be recorded in files for eligibility check before
prequalification for future contracts.
C.
Follow-Up Actions
69.
Proper and regular maintenance of the project facilities deserves special attention
(Appendix 1). In particular, NEA should undertake a technical assessment of the problem of
unavailable spare parts for the Indian-manufactured 11-kV indoor switchgears, and ensure that
resources are sufficient for continued operation of project facilities. Otherwise, no specific followup actions are suggested. But issues and lessons identified in this PPAR are highly relevant to
the successful implementation of the ongoing REDT project.
Appendix 1
21
ENGINEERING REPORT
A.
Subtransmission and Distribution Lines
1.
The prestressed concrete poles, which were either manufactured at the pole factory
constructed under the Seventh Power Project or purchased from private sector manufacturers,
are proving a cost-effective alternative to the steel poles traditionally used in Nepal. The poles
used in the Project were still in good condition and showed no sign of deterioration. Concrete
poles should be little affected by the climatic conditions and could last more than 50 years.
Unfortunately, concrete poles are much heavier than their steel alternatives, and transport
difficulties mean that they are not suited to the hill area. These poles were used extensively for
the 11 kV distribution lines installed by local contractors.
2.
Most 33 kV subtransmission lines were constructed under a turnkey contract, using steel
poles. These poles are not adequately protected against corrosion, and already have a surface
coating of rust. They are particularly vulnerable where the poles enter the ground because of
the presence of stagnant water. The standard design is to extend the concrete foundation above
the ground and to slope the top of the foundation with grout so that water will run away—but
often, this was not done.
3.
Steelwork that was galvanized was generally still in good condition. But there was no
consistency with respect to the corrosion protection of steelwork exposed to the elements.
Ungalvanized steel pole lines often had galvanized crossarms, while concrete pole lines often
had ungalvanized steel crossarms. All steelwork exposed to the elements, including poles,
should be galvanized or otherwise adequately protected against corrosion.
4.
Lines built under the Project were generally well-designed and -constructed. This was
not always the case with new construction undertaken by branch offices after the Project. For
example, the branch office has recently completed an extensive new rural electrification project
east of Janakpur, possibly using materials left over from the Project. Poles were not upright and
crossarms were not straight, because crossarm stays were not used.
B.
Area Substations
5.
The design of area substations was generally adequate, and while some substations
were well-maintained, the quality of maintenance varied. Obvious indicators of unsatisfactory
maintenance practices were poor housekeeping and graveled switchyards overgrown with
weeds. The purpose of a graveled switchyard is to protect personnel during a system fault, but if
weeds overgrow the gravel, it becomes ineffective. The key factor affecting maintenance
appeared to be the ability and enthusiasm of the substation managers. The Parsa substation
was flooded to a depth of about 1 meter during the 2003 monsoon season. While the substation
is still operational, remedial maintenance, such as regraveling of the switchyard, is ongoing.
6.
Power transformers contain large quantities of oil, but their foundation pads were not
bundled to stop oil flowing to the ground in the event of a leak. As area substations are
invariably manned, the pads should be bundled with water draining away through a normally
open drain valve. In the event of an oil leak, the operator could contain the oil by closing the
water drain valve. It was also noted that the power transformers were not fixed to the pad and
could topple in an earthquake. Earthquakes are rare—but not unknown—in Nepal, and
providing suitable earthquake clamps would be a relatively inexpensive form of protection.
22
Appendix 1
7.
The Indian-manufactured 11-kV indoor switchgear used in area substations throughout
the Project is no longer manufactured, and the Operations Evaluation Mission (OEM) was
advised that spare parts were no longer obtainable. Although all units that the OEM observed
appeared in good condition and were still operational, their maintenance will become an
increasing problem in the future. Considering the number of these units, the Nepal Electricity
Authority (NEA) should undertake a technical assessment of this problem to determine the
extent to which suitable replacement parts can be procured from other sources.
8.
Some of the power transformers installed under the Project had already been replaced
with larger units, having been loaded to their rated capacity within 5 years of installation. The
problem appears to be that all parts of the distribution system had been designed for a forecast
10-year load. The use of a longer planning horizon, when determining the appropriate capacity
of power transformers, should be considered, particularly in areas where high load growth is
forecast.
9.
The load recorded in the log of the Bisnupur substation was inconsistent with the 11 kV
current levels, and apparently was out by a factor of two. The incorrect load reading seems to
have been included in the weekly reports that the operator submitted ever since the station was
commissioned, but the error had not previously been noted. The length of time over which this
situation continued suggests inadequate engineering supervision.
C.
Distribution Substations and Low Voltage Distribution
9.
The decision not to proceed with the single wire earth return (SWER) system was
appropriate. Internationally such systems are generally used only in areas where population and
load densities are much lower than the areas reticulated under the Project. Individual customer
loads in Nepal are generally much lower than in developed countries, but this is offset by far
higher population densities, even in rural areas. Although a SWER system might have been
technically feasible, and possibly cheaper, its continuing operation could well have been
problematic. The stated purpose of using SWER technology was to reduce costs, but alternative
cost-saving opportunities could have been considered. For example, two-wire lines and singlephase transformers do not have the technical problems of single-wire systems and may have
been feasible for many spur lines. Also NEA uses a standard two-pole platform structure for its
distribution substations, regardless of transformer size, so an alternative design for smaller
transformers could have been considered. Also, the use of surge arrestors on every
transformer, irrespective of size, is not normal practice in many countries—especially when all
high-voltage transformer bushings are already fitted with surge gaps.
10.
The distribution substation design included molded case circuit breakers (MCCB) to
protect the low-voltage circuits of each transformer. This allows the low-voltage circuits to be
isolated without having to pull the high-voltage transformer fuses. The MCCBs were designed
for indoor use, but were housed in metal cabinets mounted on the poles beside the
transformers. The doors of these cabinets were invariably left open, or were missing, to allow
operation of the MCCBs from the ground, using a stick. The MCCBs will clearly deteriorate
when exposed to the elements. In some cases, the MCCBs had already been bypassed.
Cabinet doors should be kept locked. If necessary, the cabinets should be mounted closer to
the ground to allow easier access. The existing arrangement also facilitates electricity theft
because it allows easy isolation of low-voltage distribution lines, enabling illegal connections to
be made safely.
Appendix 1
23
11.
Proprietary connectors to secure service drops to low-voltage distribution lines are
generally not used. Instead, the service drop conductor is simply twisted around the line
conductor. Such connections can become loose over time, causing low customer voltage and
increased losses. Furthermore, a loose neutral conductor is a safety hazard because the neutral
voltage may rise above ground potential on the load side of the loose connection. In one case, a
small weight appeared to have been hung over the service drop conductor, apparently to ensure
a better connection.
12.
The OEM observed a number of cases where temporary repairs had been made to
distribution substations, but they had apparently become permanent either because of a lack of
parts or failure to return to make more permanent repairs.
24
1999
Forecast
Actual
Energy
Energy Available (GWh)a
Total Energy Sales (GWh)b
Losses (%)
Average Tariff (Rs/kWh)c
Income Statement
(NRs million)
Electricity Sales
Other
Total Operating Revenue
Operating Expenses
Cash Operating Surplus
Depreciation (on Asset
Book Value)
Interest
Other
Expenses/Adjustments
Profit Before Tax
2000
Forecast
Actual
2001
Forecast
Actual
2002
Forecast
Actual
2003
Forecast
Actual
1,475
1,113
24.5
4.98
1,475
1,114
24.5
5.05
1,606
1,235
23.1
5.90
1,701
1,269
25.4
5.70
1,746
1,354
22.5
8.41
1,868
1,407
24.7
6.23
2,195
1,779
18.9
10.09
2,066
1,540
25.5
6.52
2,284
1,856
18.7
10.09
2,261
1,708
24.5
7.02
5,421
349
5,770
3,009
2,761
700
5,397
385
5,782
3,180
2,602
976
7,122
370
7,492
3,300
4,192
682
6,856
356
7,212
3,605
3,607
949
11,043
457
11,500
4,910
6,590
824
8,169
593
8,762
6,313
2,449
1,119
15,675
500
16,175
6,424
9,751
1,388
9,476
460
9,936
7,508
2,428
1,420
16,858
523
17,381
6,963
10,418
1,992
11,276
521
11,797
7,292
4,405
1,830
1,312
498
1,141
895
1,327
(739)
1,244
655
1,445
(1,631)
1,188
4,008
4,344
(3,264)
1,396
5,409
4,839
(3,400)
3,410
2,708
499
168
2,030
757
4,263
(2)
3,956
(717)
3,532
(656)
GWh = gigawatt hours, kWh = kilowatt hours, NRs = Nepalese rupees.
a
Includes local generation, purchases from independent power producers, and purchases from India.
b
Includes sales to India.
c
Tariff from internal sales only.
Source: Asian Development Bank (1999 forecast), Nepal Electricity Authority.
Appendix 2
OPERATIONAL PERFORMANCE OF THE NEPAL ELECTRICITY AUTHORITY
Appendix 3
25
FINANCIAL AND ECONOMIC REEVALUATION
A.
Background and Basic Assumptions
1.
The financial and economic evaluations of the Seventh Power Project at appraisal and in
the project completion report (PCR) were carried out separately for the components on urban
rehabilitation and rural electrification. The project performance audit report (PPAR) largely
followed the same approach. The period of analysis covered FY1992–FY2021. The economic
life of the Project is assumed to be 23 years, from 1998 to 2021. All prices and costs are
expressed in 1999 constant values.
2.
For financial analysis, capital costs were net of interest during construction. For
economic analysis, taxes and duties were excluded and local costs (nontradable) were
converted to border price using a standard conversion factor of 0.90. Incremental operation and
maintenance costs were estimated annually at 2% of accumulated capital costs for both the
rural and urban components.
3.
Given the recent demand for power, and forecast growth scenarios, the facilities
rehabilitated or installed under the urban and rural components are expected to be loaded to full
capacity by 2006. After that, further reinforcements will be required to meet the load growth.
Once the full capacity of the distribution facilities is reached, project benefits are kept constant
until the end of the evaluation period.
B.
Urban Rehabilitation Component
4.
Incremental electricity sales in each urban scheme from 1998 to 2003, estimated in the
Feasibility Study Report of 1992, were checked against the overall load increases of the Nepal
Electricity Authority during the same period. The figures were found reasonably realistic, so they
were used in the reevaluation. After 2003, incremental sales are projected to increase at 10%
per annum until 2006, when project facilities reach their full load capacity, then remain constant
afterward.
5.
For financial analysis, the actual average tariff rates are used until 2003, adjusted for
inflation at 5% annually until 2006. Economic benefits are assumed to be derived from (i)
displaced use of kerosene for lighting and diesel generators for power and (ii) induced electricity
consumption. The proportion of the displaced: induced energy use is assumed to be 60: 40. For
displaced consumption, the average economic value of electricity consumption to displace
kerosene lighting with wick lamps is estimated to be $0.2/kWh, and to displace power
generation with diesel sets, $0.15/kWh. For induced consumption, the willingness to pay, for
both residential and industrial consumers, is assumed to be the weighted average of the unit
cost saving and the current tariff. One should note that other economic benefits resulting from
reduction in system losses—such as improvements in health and productivity of household
members—were not considered in the analysis because available information was insufficient to
quantify them.
6.
The financial cost of power was assumed to be $0.055/kWh, which was in line with the
Nepal Electricity Authority’s (NEA) cost of supply at 33-kV distribution levels from its own plants.
The economic cost of power supply is derived from the opportunity cost of exporting power to
India, which was $0.066/kWh at the time of the Operations Evaluation Mission. The system loss
at the distribution level was assumed as 15%.
26
Appendix 3
7.
With these assumed costs and benefits, the financial and economic reevaluation of the
urban rehabilitation component resulted in a financial internal rate (FIRR) of 11.8% and an
economic internal rate of return (EIRR) of 24.6% (Table A3).
C.
Rural Electrification Component
8.
NEA has estimated that about 200,000 new connections in rural areas were made under
the Project from 1998 to 2003. This is about 2.4 times the target number of new connections
estimated at appraisal. About 98% of the new connections are rural residential and commercial
consumers; the other 2% are industrial users.
9.
According to the latest NEA information, 60% of the rural residential users consume less
than 20 kWh/month at the lifeline tariff of NRs4/kWh. The others consume an average of 60
kWh/month at a tariff of NRs7.5/kWh. Industrial users consume an average of 1,200
kWh/month. Given these as the current level of electricity consumption of project beneficiaries,
project facilities under rural electrification are expected to reach their full capacity by 2006, at an
annual sales increase of 10%. Sales are assumed to remain constant afterward.
10.
Rural electrification adds new load to the network, so the financial cost of electricity for
rural supply should be based on NEA’s marginal generation cost. A reasonable proxy for this
would be NEA’s average purchase cost of NRs6.1 per unit from independent power producers.
Assuming the proportion of the displaced: induced energy use for the rural component to be
40:60, similar indicators for other costs and benefits described in paras. 5 and 6 above were
used. The financial and economic reevaluations of the rural component (Table A3) result in a
negative FIRR, and an EIRR of 19.2%. The negative FIRR for the rural component is because
the average revenue of NRs5.6/kWh from rural consumers is insufficient to cover even the
marginal generation cost of NRs6.1/kWh. The significant EIRR improvement, compared with
appraisal estimates, was caused by the large increase in the number of new connections.
11.
Table A3 summarises results of financial and economic analyses at project appraisal,
completion, and post-evaluation.
Table A3: Summary of Financial and Economic Revaluations
Component
Urban
Rehabilitation
Rural electrification
FIRR
(%)
Appraisal
PPAR
EIRR
(%)
Appraisal
PCR
PCR
PPAR
18.8
13.4
11.8
22.2
20.0
24.6
4.5
0.8
Negative
13.5
11.1
19.2
FIRR = financial rate of return, EIRR = economic rate of return, PCR = project completion report, PPAR = project
performance audit report.
Source: Report and Recommendation of the President, Project Completion Report and Project Performance Audit
Report for Loan 1011-NEP (SF): Seventh Power Project.
27
Appendix 4
REPORT ON THE SOCIOECONOMIC SURVEY
A.
Background
1.
Nine village development committees (VDCs) were visited to assess the socioeconomic
impacts of the rural electrification component of the Project.1 The impact assessment was made
in a rapid assessment mode, using mostly qualitative techniques, such as focus group
discussions (FGD). Table A4.1 gives the regions, districts, and VDCs visited, and the number of
participants in the FGDs.
Table A4.1: Region, District, VDCs and the Number of Participants in FGD
Region
Districts
Eastern
Siraha
Central
Chitwan
Western
Nawalparasi,
Rupandehi
Total
4
VDCs
Ram Nagar Michaiya,
Bishanpur
Jutpanini,
Pithuwa,
Pipale
Badahara Dubaulia,
Dev Gaun,
Motipur,
Semalara
9
No. of Male
Participants
8
10
11
10
9
10
9
10
No. of Female
Participants
8
5
4
5
5
5
3
2
Total No. of
Participants
16
15
15
15
14
15
12
12
72
42
114
FGD = focus group discussions, VDC = village development committees.
FGD was conducted together with participants from Motipur.
Source: Operations Evaluation Mission.
a
B.
Survey Findings
1.
Socioeconomic Background of Participants
2.
Almost all participants had some education. Agriculture was the main source of income
for most; few are in services or other business. About 90% of the households have bungalowtype houses. Only 5 to 10% of the houses have thatched roofing.
2.
Status of Rural Electrification
3.
Few participants know how rural electrification started in their areas. In the initial stage of
electrification, only a few households could connect to electricity, largely because meter boxes
were not available. Table A4.2 gives the current number of households based on the 2001
census and the estimated number of households connected to the electricity in the sample
VDCs (except for Motipur). Electricity coverage in the sample VDCs is generally higher than in
other rural areas of Nepal.
1
Loan 1011-NEP (SF): Seventh Power Project, for 51 million equivalent, approved on 11 January 1990.
28
Appendix 4
Table A4.2: Number of Households Connected to Electricity
Sample VDCs
Households
(no.)
Ram Nagar Mirchaya
Bishanpur
Jutpani
Pithuwa
Pipale
Badahara Dubaulia
Dev Gawa
Semalar
Total
1,710
855
2,310
1,925
2,380
1,200
875
1,505
12,760
Estimated households
connected
(no.)
1112
200
1,848a
1,829a
2,142a
228
149
1,430)b
8,930
Household
electrification
(%)
65.0
23.4
80.0
95.0
90.0
19.0
17.0
95.0
70.0
no. = number, VDC = village development committees.
a
From 20 to 40% of the households in each of these VDCs use electricity by illegal connection.
b
Some areas were already electrified before the Seventh Power Project.
3.
Electricity Usage
The extent of electricity use depends on the socioeconomic conditions of households. In
4.
the sample VDCs, the beneficiaries mainly use electricity for the following purposes:
(i)
Lighting. Every beneficiary household uses electricity for lighting every day. The
time of use ranges from 3 to 4 hours per day. In some areas like Chitwan and
Rupandehi, beneficiaries also use electricity for about 1 hour each morning.
(ii) Television and radio. Almost 80% of the households in Chitwan have television
sets and radios. In Rupandehi District, more than 90% of the households have
televisions, but only 5 to 10% of the households in Siraha and Nawalparasi districts
have televisions.
(iii) Electric fans. Use of electric fans during the summer (April–August) is common in
all the sample areas that have connection to electricity. The electric fans are used
for 4 to 10 hours per day, depending on the temperature.
(iv) Ironing clothes. The use of electric irons is limited to about 10% of the
households in Chitwan and Ruapnadehi districts. Electric irons are rare in other
areas.
(v) Cooking. Almost no participants, in any sample VDC, cook with electricity. Most
households use firewood or dung cakes for cooking. Firewood, in different forms, is
easily available within most village vicinities. The community forestry also supplies
some firewood to its members at cheap prices. The firewood can be purchased in
the market, or from local people. Depending on the distance from the forest area, a
kilogram of firewood costs from NRs0.90 (in Semelar) to NRs2.50 (in Badhara
Dubaulia). A family of 5 to 6 people can cook one meal (lunch or dinner) with 2 to 3
kilograms of firewood, which is much cheaper than using electricity. The
participants consider electricity expensive for cooking, compared with firewood,
kerosene, or gas.
(vi) Irrigation. Only a few households use electricity for irrigation. Shallow tube well
irrigation, using diesel-fueled pumps, are still used extensively. The advantage of
using diesel pumps is that they can be carried to different sites easily. One diesel
pump can be used at least in four different places in 1 day. In Badahara Dubaulia
alone, more than 100 diesel pumps used for irrigation.
Appendix 4
29
(vii) Storing water. Few households use electric pumps for storing drinking water.
Electricity is used to pump water from deep wells into storage talks for
consumption by 10 to 15 nearby households only in Pithuwa of Chitwan District.
Pithuwa has 20 such wells. But the electricity to pump the water is obtained by
illegal connections, or “hooking.” FGD participants felt that the Nepal Electricity
Authority should provide meter boxes free of charge for such public wells.
(viii) Rice and oil mills. From 4 to 13 rice and/or oil mills are run by electricity in each
sample VDC. There are 20 to 25 rice and oil mills in Motipur and Semalar of
Rupandehi District. Participants noted that running rice and oil mills on electricity is
cheaper than by diesel.
(ix) Poultry farms. Poultry farms are mushrooming in most of the sample VDCs as a
result of electrification. In Pipale alone, about 100 households have poultry farms.
Some of the poultry farms have a capacity of raising 20,000 to 25,000 chickens.
Owners of poultry farms also use electricity to make chicken feed. These
businesses not only provide employment, but also a good income for some
families. Participants all agreed that poultry farming would be almost impossible
without electricity. Also, furniture factories, saw mills, and beer breweries in Siraha
District use electricity.
4.
Electricity Consumption
5.
Except for factories and poultry farms, electricity consumption for domestic customers is
low. Most households consume 20 to 50 units of electricity per month. Few households use
florescence lights, because the installation cost is high. Normally. 15- to 40-watts bulbs are used
at home. From two to six bulbs are generally used in a household, depending on its income.
Normally, electricity is used for 3 to 4 hours a day. In some areas of Chitwan and Ruapndehi,
households also use electricity for about 1 hour in the mornings. Electricity consumption is
higher in all sample VDCs during the summer because of the use of electric fans.
5.
Main Beneficiaries
6.
Women have largely benefited from electricity use because (i) electricity makes cooking
easier after dark, (ii) electric lights make it easier to go to the bathroom during the night, (iii) rice
and oil mills are closer to homes, so that women can sleep later in the morning, and (iv) more
women can watch television, either at home or in a neighbor’s home. Students have also
benefited from electricity, mainly because they can study longer.
6.
Major Complaints
7.
All participants considered the electricity tariff high. In all sample VDCs, few consumers
want to consume more than the minimum of 20 units so that the lifeline tariff of Nrs4/kWh can
be applied.
8.
In all sample VDCs, only a few households (30–40%) produce enough food for a year.
The others must rely on other activities. Many poor people, although willing to use electricity,
could not afford it because of high initial cost for connection. The installation cost is from
NRs2,000 to NRs3,000, depending on the distance to the connection point. Many rural people
feel that meter boxes should be made available free of charge, so they can afford electricity use
in their homes at the lifeline tariff.
30
Appendix 4
9.
Paying electricity bills has recently become a serious problem for rural people. Because
of the Maoist insurgency, bill payment centers have been moved to either the district
headquarters or large towns. Rural customer must visit such centers to pay monthly bills. In
some areas, customers must pay more than NRs50 for bus fare, plus spend an entire day to
pay a monthly bill of about NRs80.
Management Response on the Project Performance Audit Report (PPAR)
on the Seventh Power Project in Nepal (Loan 1011-NEP[SF])
On 23 July 2004, the Director General, Operations Evaluation Department, received the
following response from the Managing Director General on behalf of Management:
“Management takes note of the lessons identified in the PPAR and will take them into
account for the design of similar future ADB projects.”