ASIAN DEVELOPMENT BANK PPA: PAK 17003

PROJECT PERFORMANCE AUDIT REPORT

ON THE

KESC FIFTH POWER (SECTOR LOAN) PROJECT (Loan 925-PAK)

IN

PAKISTAN

October 2001

CURRENCY EQUIVALENTS

Currency Unit – Pakistan Rupees (PRe/PRs) At Appraisal At Project Completion At Operations Evaluation (August 1987) (November 1998) (May 2001)

PRe1.00 = $0.0544 $0.0213 $0.0161 $1.00 = PRs18.396 PRs47.000 PRs62.000

ABBREVIATIONS ADB – Asian Development Bank CADPAD – computer-assisted distribution planning and design DFID – Department for International Development EA – Executing Agency EIRR – economic internal rate of return FIRR – financial internal rate of return IPP – independent power producer J EXIM – Export-Import Bank of Japan KESC – Karachi Electric Supply Corporation OEM – Operations Evaluation Mission PCR – project completion report PDP – power development program PPAR – project performance audit report PPTA – project preparatory technical assistance SCADA – supervisory control and data acquisition TA – technical assistance TOR – terms of reference WAPDA – Water and Power Development Authority

WEIGHTS AND MEASURES GWh (gigawatt-hour) – 1,000 megawatt-hours kV (kilovolt) – 1,000 volts kVA (kilovolt-ampere) – 1,000 volt-amperes km – kilometer kWh (kilowatt-hour) – unit of electrical energy MVA – megavolt-ampere MVAR (megavolt-ampere reactive) – 1,000,000 units of reactive power MW (megawatt) – 1,000,000 watts MWh (megawatt-hour) – 1,000 kilowatt-hours V – volt VA (volt-ampere) – unit of apparent power

NOTES

(i) The fiscal year (FY) of the Government and KESC ends on 30 June. (ii) In this report, “$” refers to US dollars.

Operations Evaluation Department, PE-574

BASIC DATA KESC Fifth Power (Sector Loan) Project (Loan 925-PAK)

Project Preparation/Institution Building

TA No. TA Name Type Person- Months

Amount ($)

Approval Date

411-PAK Power Development and Tariff Study ADTA 25 350,000 27 Aug 1981 835-PAK Tariff Study on WAPDA/KESC

Integration ADTA 27 475,000 18 Dec 1986

869-PAK Karachi Electric Supply Corporation Power Expansion

PPTA 4 75,000 6 Apr 1987

Key Project Data ($ million)

As per ADB Loan Documents

Actual

Total Project Cost 389.8 277.4 Foreign Exchange Cost 189.5 142.6 Local Currency Cost 200.3 134.8 ADB Loan Amount/Utilization 100.01 98.4 ADB Loan Amount/Cancellation 1.6 Amount of Cofinancing 112.2 85.2

Key Dates Expected Actual

Fact-Finding 23-Apr-6 May 1987 Appraisal 19-29 Aug 1987 Loan Negotiations 9-14 Nov 1987 Board Approval Dec 1987 24 Nov 1988 Loan Agreement Jan 1988 21 Dec 1988 Loan Effectiveness 21 Mar 1989 5 Feb 1990 First Disbursement 5 Nov 1990 Project Completion 31 Dec 1991 31 Sep 1997 Loan Closing 31 Dec 1992 31 Dec 1997 Months (effectiveness to completion) 33 92 Key Performance Indicators (%) Appraisal2 PCR2 PPAR3 Financial Internal Rate of Return for sector 11.1 4.5 16.5->50 Economic Internal Rate of Return for sector 12.7 5.7 23.7->50 Borrower Government of the Islamic Republic of Pakistan Executing Agency Karachi Electric Supply Corporation

ADB = Asian Development Bank, ADTA = advisory technical assistance, EIRR = economic internal rate of return, PCR = project completion report, PPTA = project preparatory technical assistance, PPAR = project performance audit report, TA = technical assistance, WAPDA = Water and Power Development Authority. 1 In currencies totaling $100 million equivalent. 2 Sector estimates using a time-slice approach for all the Karachi Electric Supply Corporation (KESC) investments. 3 Because of an approved reduction in project scope, the Project as finally implemented was of insufficient size to

achieve envisaged sector targets at appraisal. The EIRR for 11 kilovolts feeder subprojects ranged from 24 percent upward and the EIRR for the transmission component is calculated at 27.2 percent.

Mission Data

Type of Mission No. of Missions No. of Person-Days

Fact-Finding 1 36 Appraisal 1 50 Project Administration Inception 1 12 Consultation 3 26 Review 6 37 Special Review 3 43 Loan Administration 1 7 Power Sector 1 1 Project Completion 1 27 Operations Evaluation4 1 20

4 The mission comprised T.M. Hutton (Evaluation Specialist and Mission Leader) and D. Gianelly (International

Consultant).

CONTENTS

Page BASIC DATA ii EXECUTIVE SUMMARY iii SYSTEM NETWORK vii I. BACKGROUND 1 A. Rationale 1 B. Formulation 1 C. Purpose and Outputs 2 D. Cost, Financing, and Executing Arrangements 2 E. Completion and Self-Evaluation 2 F. Operations Evaluation 3 II. PLANNING AND IMPLEMENTATION PERFORMANCE 4

A. Formulation and Design 4 B. Achievement of Outputs 4

C. Cost and Scheduling 5 D. Procurement and Construction 5 E. Organization and Management 6 III. ACHIEVEMENT OF PROJECT PURPOSE 6

A. Operational Performance 6 B. Performance of the Operating Entity 8 C. Financial and Economic Reevaluation 10

D. Sustainability 11 IV. ACHIEVEMENT OF OTHER DEVELOPMENT IMPACTS 12 A. Socioeconomic Impact 12 B. Environmental Impact 12 C. Impact on Institutions and Policy 12 V. OVERALL ASSESSMENT 13 A. Relevance 13 B. Efficacy 14 C. Efficiency 14 D. Sustainability 14 E. Institutional Development and Other Impacts 15

F. Overall Project Rating 15 G. Assessment of ADB and Borrower Performance 16

VI. ISSUES, LESSONS, AND FOLLOW-UP ACTIONS 16 A. Key Issues for the Future 16 B. Lessons Identified 17 C. Follow-Up Actions 17 APPENDIXES 18

EXECUTIVE SUMMARY At project formulation, there was an urgent need for investment in the transmission and distribution systems of the Karachi Electric Supply Corporation (KESC). The network had not kept pace with generation expansion, was heavily overloaded, and prone to power failures. Transmission and distribution losses were around 18 percent, and future growth in demand for electricity threatened to increase loss levels in the absence of expanding transmission capacity and upgrading the existing distribution network.

The Asian Development Bank (ADB) formulated the Project as a sector loan to finance part of a three-year time-slice of KESC’s power development program for the period FY1989-1993. The purpose was to develop the transmission and distribution systems to absorb new generation from Bin Qasim, and to address problems of system losses, load management, and distribution efficiency. ADB’s loan was expected to play a catalytic role in mobilizing funding needed for the Project and KESC’s overall development program. The project scope included (i) upgrading and expansion of transmission lines and substation capacity, (ii) rehabilitation and expansion of the distribution system, (iii) upgrading of the system control and protection facilities, and (iv) consulting services for project implementation and to assist with computerization of KESC’s technical and financial operations. Selection and formulation of specific subproject proposals for implementation were part of the implementation consultants’ terms of reference. Subproject proposals were subject to ADB approval. Appraisal was completed in August 1987. A decision at loan negotiations in November 1987 to defer further loan processing until KESC’s financial position was stronger meant that ADB’s loan was not approved until 24 November 1988. The Project was completed in December 1997 with an overall delay of six years. The delay was caused by (i) the need for KESC to comply with key financial covenants before the loan could be declared effective; (ii) suspension of ADB’s loan from March 1991 to October 1992 because of a deterioration in KESC’s accounts receivable; and (iii) the need to update subproject proposals, which moved the physical start for the transmission component to July 1993. The final project cost of $277.4 million was 29 percent lower than the appraisal estimate of $389.8 million. Total disbursements under ADB’s loan in various currencies equivalent to $100 million amounted to $98.4 million (35 percent of the total project cost). An undisbursed balance of $1.6 million was canceled. Savings on the appraised project cost were induced by a decision to reduce the project scope, particularly with regard to distribution, and defer some components to ADB’s KESC Sixth Power (Sector Loan) Project. ADB’s loan financed 69 percent of the foreign exchange costs compared with an estimated 53 percent at appraisal. The balance of foreign expenditure was financed by the Export-Import Bank of Japan. The local currency portion of $134.8 million was financed by the Government of Pakistan.

Overall investment expenditure on KESC’s power development program was PRs17.2 billion during FY1989-1993, and PRs36.8 billion during FY1994-1998. Investment expenditure was largely to expand generation at Bin Qasim. Total expenditure under the Project was PRs9.4 billion, or 17.4 percent of KESC’s total investment expenditure for the extended program period FY1989-1998. Of the PRs9.4 billion, 71 percent was spent on transmission improvements and the balance on distribution expansion (primarily) and upgrading.

The Project at appraisal was technically well designed and appropriate for achieving its purpose. The performance of implemented subprojects has been satisfactory as attested by financial and economic internal rates of return that range from 16.5 percent to more than 50 percent.5

5 Using the time-slice approach adopted at appraisal, the recalculated financial internal rate of return is negative and

the economic internal rate of return is 1.6 percent. Because of the reduced project scope and inefficiencies that developed elsewhere in KESC’s system, the time-slice results do not reflect the viability of individual project components nor overall project performance.

The decision to downsize the scope of the distribution component meant the Project was insufficient in scale to achieve an overall improvement in KESC’s operating efficiency and financial position. KESC’s transmission and distribution losses increased from 18 percent in FY1987 to 34.3 percent in FY1998 and caused KESC’s profit performance to move from weak to negative. A first year loss of PRs0.5 billion was reported in FY1996. By FY1998, KESC became financially insolvent. Transmission and distribution losses continued to increase, and by FY2000 reached 40.2 percent, with an associated net loss of PRs12.8 billion. Contributing to the decline in KESC’s financial performance was the rising cost of fuel and power purchases, and increasing loan interest. Escalating nontechnical losses estimated at over 40 percent of transmission and distribution losses, also contributed to KESC’s overall financial deterioration, as did a problematic environment affecting revenue collection.

The negative aspects associated with implementation delays, the failure to reduce KESC’s overall transmission and distribution losses, and the subsequent financial insolvency of KESC tend to overshadow successful achievements at the subproject level. The positive impact of the Project was the completion of the transmission component to meet the availability of additional generation from Bin Qasim, without which power shortages would have been worse, and transmission losses higher. Subprojects for distribution rehabilitation, although insufficient in aggregate to meet sector targets and reduce overall KESC’s transmission and distribution losses, were individually successful. Distribution expansion targets were also met and helped spur economic growth.

Of the five evaluation criteria applied to judging the success of this Project, the rationale for the Project remains highly relevant. On the criterion for efficacy, the Project succeeded in its prime purpose to develop transmission to absorb new generation from Bin Qasim, but failed to effect an overall reduction in system losses. Because of the dominance and primary achievement of the transmission component, an assessment rating of at least partly efficacious is warranted. The financial and economic rates of return attest to the individual viability of subprojects, but not to their overall impact to improve the operational efficiency of KESC. The Project is, therefore, assessed partly efficient. The sustainability of the transmission benefits is assessed likely, while the sustainability of distribution subprojects is assessed less likely in the absence of investment in upgrading to match load growth. Institutional and other development impacts were negligible in terms of strengthening KESC’s computer-based management systems, but under the broader socioeconomic aims of reducing load shedding and expanding distribution coverage, achievement was significant. New connections, for example, were increased by 74 percent from 0.8 million in FY1987 to 1.4 million in FY1998. Taking these evaluation judgments into account, the Project’s overall rating is partly successful.

KESC’s recovery from financial insolvency is dependent on restructuring toward a more commercial and competitive orientation, external funding support including equity, and policy changes relating to the tariff setting and revenue collection from government departments and public sector enterprises. The operational viability of subprojects is dependent on improved load control facilities, staff training in technical skills, and enhancing technical efficiencies in the distribution network. Continued government attention, together with investment support, is also required to reduce nontechnical losses, which are currently estimated to be around 18 percent.

Three key issues for the future are identified:

(i) Consumer Charges. Consumer affordability and KESC’s financial performance are negatively affected by the actual tariff paid by consumers, which is twice KESC’s reported average revenue tariff. The difference is made up of a surcharge paid to the Government. As affordability of the actual tariff paid by consumers is a cause of political resistance against increasing tariffs, the issue of what is an appropriate level of surcharging needs to be urgently addressed, in light of KESC’s insolvency and the severe constraints imposed on KESC’s self-financing capacity.

(ii) Policy Reforms. Reflective of the differential between the tariff paid by consumers and the net tariff to KESC, electricity revenues paid to the Government exceed the revenues of KESC and are currently around PRs28 billion ($450 million equivalent) per annum. The surcharge paid to the federal and Sind governments is in effect a monopoly rent, but at the cost of lower investment and reduced availability of electricity in the Karachi area—possibly by as much as 40 percent. The situation poses a policy dilemma of continuing to support a monopoly structure, which suppresses expansion and thereby reduces the benefits of electricity to households and businesses that would otherwise prevail. Perpetuating support to a system that extracts high monopoly rents but leaves insufficient revenue to meet operating expenditures and provide a normal return on investment is also a governance issue. A closer look at restructuring is warranted. With the right balance on incentives, both power expansion and overall tax revenues to government can be larger than is the case at present. Future policy reforms affecting electricity surcharges need to bear in mind investment requirements so that revenue flows sustain and expand development.

(iii) Privatization. Privatization of KESC is unlikely before mid-2002, and may not

result in a full divestment of the Government’s holding. The present management practice is to support only essential investment in the interim period up to privatization. In this regard, the lessons of the Project are of paramount importance. The present level of technical losses of around 22 percent will escalate without adequate attention to upgrading the distribution system. Continuing expansion by way of new connections without upgrading existing overloaded distribution facilities will also further exacerbate power outages. Urgent attention to and continued investment in upgrading the distribution network prior to privatization are, therefore, recommended.

The key lessons derived from the Project are (i) the critical importance of scale and

timing for upgrading distribution systems to improve overall system efficiencies; (ii) the need for ADB to be more circumspect in appraising sector loan objectives and the likelihood of achieving them, particularly where target achievements depend on the availability of local funding and the capability of the power utility; and (iii) the need to replace KESC’s nonfunctional and obsolete computer system for identifying and selecting distribution feeders for upgrading in order to reduce distribution losses.

For follow-up, ADB is encouraged to take into account lessons identified and ensure that future sector loan projects are reviewed bearing in mind that the impact of changes in project scope can be critical for the achievement of project purpose. The Government should take immediate measures aimed at (i) providing KESC with support for upgrading the distribution system so as to contain and reduce technical losses until privatization; (ii) developing policies backed with financial support, which clarify how KESC will meet the demand for new connections in the interim period; and (iii) restructuring the electricity tariff so that the operations of KESC are financially sustainable. KESC should (i) continue to develop effective recovery mechanisms for dealing with nontechnical losses, outstanding customer accounts, errant staff, and contractors; (ii) in consultation with the Government, take steps to contain further increases in distribution losses; (iii) initiate a project to install capacitors on its low-voltage feeders; and (iv) take immediate steps to improve the technical skills of its staff to meet upgrading, servicing, and connection standards.

I. BACKGROUND

A. Rationale

1. The Asian Development Bank’s (ADB’s) loan complemented a sector loan approved in December 1986 to the Water and Power Development Authority (WAPDA),6 and was intended to help mobilize funding to meet investment requirements of the Karachi Electric Supply Corporation (KESC). Increased generation capacity of 630 megawatts (MW) to meet the forecast demand for electricity was planned from Bin Qasim (formerly Pipri) by 1992. Under KESC’s overall five-year power development program (PDP) FY1989-1993, a further increase in generation from Bin Qasim of 210 MW and West Wharf of 200 MW was also planned. To meet this increase, an expansion in transmission capacity was needed to carry the additional power to distribution load centers. Reinforcement of the existing transmission system; upgrading of KESC’s power management system to more effectively deal with load fluctuations; and the upgrading, relocating of transformers, and installation of capacitors on the distribution network were also necessary to contain the potential for future increased losses.7

B. Formulation

2. The Project was formulated to help meet the foreign exchange costs of a three-year time-slice, FY1989-1991, under KESC’s five-year PDP.8 System requirements were initially studied under ADB technical assistance (TA) in 1982,9 and reviewed under Canadian assistance in 1986. Recommendations for upgrading KESC’s transmission and distribution facilities to satisfy demand requirements through 1992 were made under ADB project preparatory technical assistance (PPTA).10 Fact-finding was completed in May, and appraisal in August 1987. At loan negotiations in November 1987, it was decided to defer further processing until KESC’s financial position strengthened. Such strengthening, to enable compliance with ADB’s financial covenants, was achieved through changes to the fuel adjustment charge, reduction in accounts receivables from seven to three months, and a 29 percent increase in the base tariff (para. 29). An ADB mission to update and reaffirm ADB’s appraisal was completed in September 1988, and ADB’s loan in currencies totaling $100 million equivalent was approved on 24 November 198811 in support of a total project investment of $389.8 million. ADB’s loan was made in coordination with major aid agencies.12 The Borrower was the Government of Pakistan, and the proceeds were relent to KESC under a subsidiary loan agreement.

6 Loan 824-PAK: WAPDA Tenth Power Sector Project, for $150 million, approved on 18 December 1986. 7 KESC’s transmission and distribution losses were around 18 percent, and a little more than half of these were

attributed to bottlenecks in transmission, and excessively loaded feeders in distribution. 8 KESC’s five-year PDP provided for a total investment of $1.3 billion (approximately PRs23.4 billion) for

(i) increasing generation capacity at Bin Qasim (4 x 210 MW units) and West Wharf (1 x 200 MW unit), (ii) expansion and rehabilitation of the transmission system, (iii) expansion and rehabilitation of the distribution network, and (iv) upgrading system protection and load despatch facilities. Total investment cost over the three-year project period FY1989-1991 was estimated at $803.3 million (PRs14.5 billion).

9 TA 411-PAK: Power Development and Tariff Study, for $350,000, approved on 27 August 1981. 10 TA 869-PAK: Karachi Electric Supply Corporation Power Expansion, for $75,000, approved on 6 April 1987. 11 Loan 925-PAK: KESC Fifth Power (Sector Loan) Project. 12 Prior to loan approval, two meetings were held in Islamabad in September 1985, and in Washington, DC in July

1986. The aid agencies in attendance included the Canadian International Development Agency, Department for International Development of the United Kingdom, Kreditanstalt für Wiederaufbau, and the World Bank. The aid agencies coordination meetings endorsed a core program of energy investments.

C. Purpose and Outputs

3. The overall purpose of the Project was to develop the transmission and distribution systems of KESC to meet increased generation from Bin Qasim, and address problems of system losses, load management, and system efficiency attributable to deficiencies in transmission and distribution. ADB’s loan was expected to play a catalytic role in mobilizing the balance of donor and commercial funding needed for the Project and KESC’s overall development program. The project outputs included (i) expansion and augmentation of transmission lines and substation capacity, (ii) expansion and rehabilitation of the distribution system, and (iii) upgrading of the system control and protection facilities. Selection of specific subproject proposals for implementation were made part of the implementation consultants’ terms of reference, and subject to ADB approval. Details of the PPTA consultant’s recommendations for expanding and upgrading KESC’s transmission and distribution facilities, which are the basis of subproject proposals, are provided in Appendixes 8 and 9 of ADB’s appraisal report. Further details of the Project’s outputs and expected impacts are provided in Appendixes 1 and 2.

D. Cost, Financing, and Executing Arrangements

4. The estimated total project cost at appraisal was $389.8 million equivalent, with a foreign exchange component of $189.5 million. ADB’s loan was to be used to finance 53 percent of the foreign exchange costs. Of the $89.5 million balance in foreign exchange cost, $12.2 million was expected to be financed by the Department for International Development (DFID) of the United Kingdom, $22.9 million by the Government, and $54.4 million by the Export-Import Bank of Japan (J EXIM). The local currency cost of $200.3 million equivalent was to be funded by KESC for $154.7 million, and J EXIM for $45.6 million. ADB’s loan was drawn from its ordinary capital resources to the Islamic Republic of Pakistan, and relent as a subsidiary loan to KESC with provision for interest at 11 percent per annum (inclusive of a foreign exchange risk fee) and a repayment period of 25 years (including a grace period of four years).13 KESC was the appointed Executing Agency (EA). An existing team of qualified full-time staff headed by a project manager, which had worked well under ADB’s earlier loans,14 was given the responsibility for implementation of the Project.

E. Completion and Self-Evaluation

5. ADB’s project completion mission inspected the Project in November 1998 and rated it partly successful. Rehabilitation and expansion of KESC’s transmission and distribution systems were found implemented as envisaged, though with reduced scope and delays. The benefits of the Project were judged sustainable, but the delays in project implementation were such that the benefits were considered insufficient to improve KESC’s overall performance. Using a time-slice approach, the financial internal rate of return (FIRR) was recalculated at 4.5 percent, and the economic internal rate of return (EIRR) at 5.7 percent. These lower-than-appraisal estimates15 were attributed to high transmission and distribution losses, and the high cost of power purchases from independent power producers (IPPs). Transmission and distribution losses, instead of falling, were observed to have increased from 18 percent in FY1987 to 34 percent in FY1998. It was stated that the overall financial performance of KESC had deteriorated, though 13 The opportunity lending rate in local currency was 15 percent, and in dollars 6.5 percent (excluding foreign

exchange cover). 14 Prior to ADB’s loan for the Project, KESC had received nine ADB loans totaling $201.5 million and four TA grants

totaling $0.68 million. 15 The appraisal estimates were 11.1 percent (FIRR) and 12.7 percent (EIRR).

no financial accounts or analysis of accounts was presented in the project completion report (PCR), and that KESC was unable to comply with ADB’s financial covenants. Because the Project was implemented and operational at loan closing, no follow-up actions were recommended. Attention was drawn to the need to recognize in power projects that where the achievement of project objectives is a direct function of the level of inputs, the implications of reducing the project scope should be carefully assessed. Continuation of the sector loan approach was recommended for similar projects in ADB’s other developing member countries. 6. The PCR assessment reliably evaluated the Project’s implementation performance and the impact of delays on achieving technical efficiency improvements. However, for a sector loan, KESC’s performance and policy reforms should have been evaluated as well.16 7. Factors affecting KESC’s declining financial performance were reflected in the PCR’s FIRR recalculation although KESC’s insolvency position was not mentioned. The recalculated EIRR of 5.7 percent was within ADB’s then benchmark range of 4-10 percent for rating a project partly successful. Because the recalculation excluded KESC’s investment in additional generation capacity for Bin Qasim units 3 and 4, and was based on projections after FY1998 for power generation that did not pertain to KESC’s development program, the EIRR was overestimated. If recalculated with these adjustments, the EIRR would have been negative and would have caused the Project to be rated unsuccessful. In this regard, the PCR rating was misleading.

F. Operations Evaluation

8. This project performance audit report (PPAR) reviews the findings of the PCR and presents the findings of the Operations Evaluation Mission (OEM) that visited the project area during 21 May-1 June 2001. Special attention is given to assessing the achievement of purpose; attainment of project and sector goals and intended developments from the Project; operational performance of KESC; and adequacy of design for meeting load expansion requirements, and avoiding and reducing system losses. Related to these aspects are planning issues for the intended privatization of KESC and environmental consequences of the Project’s operations. The PPAR is based on the findings of the OEM taking into account a review of the PCR, the appraisal report and material in ADB files, two years of additional actual operational data, KESC’s responses to OEM’s questionnaire, and follow-up discussions with ADB staff, KESC’s senior officials, representatives of other government agencies, electricity consumers, implementation consultants, and local equipment manufacturers. The assessment rating is based on ADB’s four-category assessment rating system.17 Copies of the draft PPAR were provided to the Government, KESC, and ADB staff concerned for review, and their comments were considered in finalizing the PPAR.

16 At appraisal, the Project was variously referred to as a sector loan or project. The concept of providing a sector

loan for transmission and distribution improvements covering a large number of subprojects that depended on detailed engineering analysis and design before specifying specific material and contract requirements, made the need for a sector loan approach self-evident. Funding for each subproject was made conditional on detailed appraisal and ADB approval. The terms of reference for the consultants were, however, as for a project, and cost estimates included provision for physical and price contingencies, which was unusual for a sector loan. Apart from a requirement to complete a separate TA study to integrate the tariffs of KESC and WAPDA, there was no requirement to support and evaluate sector policy reforms.

17 In September 2000, a four-category assessment rating was introduced: unsuccessful, partly successful, successful, and highly successful. The previous rating system, used for the PCR, was based on a three-category system of unsuccessful, partly successful, and generally successful. The new evaluation system removed the benchmark assessment links to EIRR estimates and gave more emphasis to the achievement of project purpose.

II. PLANNING AND IMPLEMENTATION PERFORMANCE

A. Formulation and Design

9. KESC’s PDP covering FY1989-1993 formed part of the national Government’s Seventh Five-Year Plan (1989-1993) for sustaining economic growth. The Project’s rationale (para. 1) reflected (i) investment requirements for power transmission and distribution to Karachi and its environs, (ii) the need to sustain investment expenditure on distribution upgrading, and (iii) ADB’s assistance strategy for improving operational efficiencies and mobilizing cofinancing to meet investment needs. 10. The Project was structured from KESC’s PDP to meet 49 percent of the total planned investment for the three-year time-slice FY1989-1991 (para. 2). The outputs were set against specific requirements for expanding and upgrading KESC’s transmission and distribution systems, and were defined as a subset of KESC’s PDP. Formulation and identification of project outputs were prepared on a least-cost basis. The OEM reviewed the feasibility and appraisal estimates for the PDP and Project, and found the technical solutions, system controls, and equipment specified appropriate for the projected load growth (Appendix 3).

B. Achievement of Outputs

11. Appendix 1 compares the actual outputs under the Project with what was envisaged at loan approval. The outputs from expanding transmission capacity, reinforcement of 220-kilovolt (kV) transmission, and installation of capacitor banks were by and large achieved. Outputs for rehabilitating and expanding the distribution system were substantially smaller than envisaged, reflecting a cutback in available funding and a change to meet distribution expansion at the expense of upgrading the existing distribution network (Table 1).18 Outputs for upgrading KESC’s system control and protection were substantially deferred.

Table 1: Distribution Expansion and Rehabilitationa

Item Approved Actual 11 kV Distribution Reinforcement 487 km 566 km 0.4 kV Overhead/Underground Lines 1,500 km 766 km 11/0.4 kV Transformer Capacity 922.5 MVA 439.5 MVA Capacitor Installation 260 MVAR Nil

km = kilometer, kV = kilovolt, MVA = megavolt-ampere, MVAR = megavolt-ampere reactive. a Comparative details for other project components are shown in Appendix 1.

C. Costs and Scheduling

12. As a result of the reduced scope, the actual project cost of $277.4 million equivalent was 29 percent less than the appraisal estimate of $389.8 million. The foreign exchange cost of $142.6 million was lower by 25 percent, and the local currency cost of $134.8 million equivalent 18 As of May 2001, over 30 percent of the distribution equipment procured under the Project remained in KESC’s stores

unused. The main reasons for incomplete implementation are (i) the local authorities have restricted road excavation for cable laying, (ii) KESC is reluctant to install further copper conductor given the high levels of theft, and (iii) KESC staff do not have the knowledge required to use some of the materials.

by 33 percent. The nonspecific nature of details for the project scope also accounts for some of the cost variations.19 Total disbursements under the ADB loan amounted to $98.4 million equivalent (35 percent of the total project cost). An undisbursed balance of $1.6 million equivalent was canceled. ADB’s loan financed 69 percent of the foreign exchange costs, compared with 53 percent envisaged at appraisal. ADB’s funding was largely applied to the transmission component. The balance of foreign expenditure was financed by J EXIM. The local currency portion of $134.8 million was financed by the Government. Anticipated cofinancing from DFID (para. 4), which was intended for upgrading KESC’s system control and protection, did not materialize. The appraisal costs are compared with actual costs in Appendix 4. 13. The Project was deemed substantially complete in December 1997, six years later than envisaged at appraisal. There were three extensions on the loan closing date from 31 December 1992 to 31 December 1997. Implementation was slowed by (i) the need for KESC to comply with key financial covenants before the loan could be declared effective in February 1990; (ii) suspension of ADB’s loan from March 1991 to October 1992 because of a deterioration in KESC’s accounts receivable position; and (iii) the need to update, after loan suspension, final subproject proposals for the transmission component, which extended the physical start to July 1993. A comparison of the actual implementation schedule with the appraisal schedule is shown in Appendix 5.

D. Procurement and Construction

14. Procurement was envisaged at appraisal to be undertaken in accordance with ADB’s Guidelines for Procurement. Other than for distribution, contracts were to be awarded on the basis of supply, delivery, installation, and commissioning. For distribution components of the Project, contracts were to be on the basis of supply and delivery only, with KESC responsible for installation and commissioning. Summary details of contract awards are provided in Appendix 2 of ADB’s PCR. 15. KESC reported that the international and domestic contractors and suppliers for the Project performed satisfactorily. Equipment and materials complied with KESC’s specifications and had no significant defects. All equipment inspected at the subproject sites visited by the OEM was functioning satisfactorily. 16. Nevertheless, OEM’s engineering inspection revealed that the design and quality of work undertaken by KESC for the distribution rehabilitation and expansion component were generally substandard. With appropriate design and quality, including proper connection practices, the reduction of technical losses by 4-5 percent through upgrading low-voltage lines and replacement and relocation of transformers could have been increased by an additional 1-2 percent. The installation of three-phase capacitor banks, if carried out, would have reduced technical losses by another 2 percent. KESC’s method of design and construction of distribution lines, particularly for 400 volts (V) and 230 V, has still to catch up with accepted international practice.

E. Organization and Management

17. Organization and management were consistent with agreed arrangements at appraisal and generally satisfactory, except for the need to extend the implementation period. Project implementation was satisfactory with respect to selection of consultants, awarding of contracts, and management by KESC. Recruitment of consultants was initiated in 1988, and a consortium of international and domestic consultants was contracted under an agreement concluded in August 1990. Because of the implementation delays, it was necessary to extend the

19 Consistent with the sector loan approach, detailed costings for subprojects were to be made during project

implementation.

consultants’ period of assignment under several amendments until project completion. Performance of the consultants, whose activities were restricted to transmission, was of a high order. Engineering and progress reports were submitted promptly, and supervisory responsibilities over contractor activities and advisory assistance to KESC were discharged effectively. The supervisory responsibilities of the consultants and their contribution to institutional strengthening through improving technical efficiencies, employee skills, and computer systems were considered by KESC appropriate and helpful.20 18. ADB provided adequate monitoring during project implementation with one inception mission, nine review missions (including three special review missions), three consultation missions, one power sector mission, and one project completion mission. Coordination and progress meetings were held during review missions with the Ministry of Foreign Affairs, KESC, and consultants to solve problems and minimize delays. 19. ADB’s loan and project agreements included covenants relevant to improving KESC’s operational performance and accountability. These included requirements for the following: (i) ensuring that the Project was managed by a project group, headed by a project manager from within KESC; (ii) all subprojects to be selected in accordance with criteria agreed with ADB; (iii) completing TA 835-PAK for a tariff study to integrate the tariff structures of KESC and WAPDA; (iv) reducing transmission and distribution losses to 15.5 percent by FY1995; (v) phasing out subsidies and complying with financial covenants; and (vi) submitting quarterly progress reports for execution of the Project. KESC’s compliance with loan covenants is summarized in Appendix 5 of the PCR. All covenants had been complied with at project completion, except those relating to transmission and distribution losses and financial performance (paras. 24 and 27).

20 The consultants assisted with the preparation of bid documents for distribution procurement but were not involved

in the supervision of contracts and work on distribution improvements.

III. ACHIEVEMENT OF PROJECT PURPOSE

A. Operational Performance

20. Operational performance is measured in terms of the Project’s achievements relative to expectations at appraisal and changes in scope to (i) help meet the incremental demand for power between FY1992 and FY1998, (ii) expand transmission to relieve overloaded subtransmission systems and reduce load shedding, (iii) expand distribution and improve distribution voltage levels and system reliability, and (iv) reduce system losses. The adequacy of maintenance is also reviewed. Indicators of KESC’s technical and financial performance are summarized in Appendix 6. 21. KESC’s installed generation capacity was projected at appraisal to increase to 1,920 MW by FY1992, and its energy sales to 6,283 gigawatt-hours (GWh). The actual installed capacity was 1,738 MW, or 91 percent of the target. Actual sales were 5,492 GWh or 87 percent of the forecast.21 Generation capacity was increased by a further 200 MW in FY1998 and old units retired to leave a total installed capacity of 1,756 MW. No further additions have been installed since 1998. 22. The transmission reinforcement and expansion helped reduce transmission losses and the frequency of load shedding, and increase energy available for sales. However, insufficient attention to upgrading the distribution network in the face of growing load demand and a surge in nontechnical losses resulted in KESC’s overall transmission and distribution losses almost doubling (Table 2).

Table 2: Operational Performance Indicators

Indicator Before Project (FY1987)

Projected (FY1992)

After Project (FY1998)

Installed Capacity (MW) 1,008 1,920 1,756 Energy Sales (GWh) 4,130 6,283 6,489 Customers Served (‘000) 823 1,145 1,435 System Voltage across 11 kV Lines (kV) 9.0-11.0 10.5-11.0 10.5-11.0a Distribution Voltage across Low-Voltage Lines (V)

170/180 220 210/220

Transmission and Distribution Losses (%) 17.9 16.5 34.3

kV = kilovolt, GWh = gigawatt-hour, MW = megawatt, V = volt. a Ideally, the measured voltage across 11 kV lines should be 11 kV +/- 0.55 kV to reduce transmission losses

to less than 2.5 percent. 23. For the distribution subprojects, rehabilitation and reinforcement improved feeder voltages from around 9 kV to 11 kV and helped offset overloading in low-voltage distribution. The installation of additional feeders from grid substations expanded the availability of electricity and resulted in 612,000 new connections for a 74 percent increase between FY1987 and FY1998. Voltage at residential and commercial connections was typically increased from 170-180 V to the designed level of 210-220 V.22 Overall, electricity reliability decreased, however, with more frequent feeder trippings due to a mixture of imbalanced loads, increased loadings, and overall poor state of the distribution network.23

21 In addition to own generation, KESC purchased power from WAPDA. In FY1992, power purchased from WAPDA

amounted to 575 MW compared with 780 MW forecast at appraisal. 22 At lower voltage, appliances and machinery do not run at their design specification and burn out with continued

use. 23 Reaching 700 per month over some 6,600 11 kV feeders.

24. The Project was expected to reduce KESC’s overall transmission and distribution losses from 17.9 percent in FY1987 to 16.5 percent by FY1992, and to 15.5 percent by FY1995. Actual losses, which also include nontechnical losses, increased to 26 percent by FY1992, and to 34 percent by FY1998.24 Several reasons explain this: (i) delays in rehabilitation of the distribution network, which as a result, accentuated the impact of ongoing load growth; (ii) reduced investment in distribution rehabilitation; (iii) canceling the installation of capacitors in the distribution system; (iv) poor design, construction, and connection practices; and (v) an increase in nontechnical losses.25 The net effect was that the final project scope as implemented, was insufficient to achieve the project targets set for KESC’s overall system. Appendix 3 discusses further the operational and technical performance of the Project and the KESC system. 25. Maintenance was not addressed at appraisal. The OEM observed from subproject sites and substations visited that maintenance for distribution operations generally failed to follow accepted international practice and was affected by shortages of equipment, particularly meters, fuses, transformers, and connectors. Discussions with KESC revealed the lack of a systematic approach to maintenance.

B. Performance of the Operating Entity

26. At appraisal (FY1987 being the last available full-year accounts), KESC’s financial performance was considered unsatisfactory, due largely to factors beyond its control. KESC reported an operating profit after depreciation and interest of PRs340 million, or 8.7 percent of total revenues. Liquidity was affected by a dividend provision of 85 percent of profit before tax, a high level of arrears from provincial government agencies, and a reluctance by the federal Government to approve tariff increases. Prior to approval of ADB’s loan, the Government introduced several measures to restore financial viability. These included (i) reductions in the price of natural gas and fuel oil for generation, (ii) a revision of loan terms on government debt, (iii) implementation of recommendations to integrate the tariff structures of KESC and WAPDA, and (iv) a holiday period on dividend payments. 27. The main indicators of KESC’s financial performance are summarized in Table 3 (see also Appendix 6). KESC’s PDP for FY1989-1993 projected (i) a total investment of PRs23.4 billion, (ii) an increase in total operating revenue by 22 percent a year in nominal terms, (iii) an increase in operating profit before depreciation and interest by 20.8 percent per annum, (iv) a debt service ratio ranging from 1.8 to 3.1, and (v) a rate of return on historical assets increasing from 10 to 14.5 percent. Actual total PDP investment expenditure—which, because of delays, did not include funding under the Project of PRs5.3 billion—was PRs17.2 billion, or 74 percent of that planned.26 Actual operating revenue increased at 16.8 percent per annum, and gross operating profit in FY1993 was PRs3.1 billion compared with PRs5.7 billion forecast. Except for FY1991, KESC’s debt service ratio remained until FY1996 slightly above the loan covenanted level of at least 1.3, but not near as high as projected at 3.1 for FY1993. Because of a switch in accounting practice to value assets on a current basis, the OEM could not monitor the rate of return on historical assets. 28. Over the longer period FY1987 to FY2000, KESC’s profit performance relative to operating revenue and return on equity moved from weak to negative. Net operating profit after depreciation and interest began to deteriorate after FY1990, reaching a first-year loss of PRs0.5 billion in FY1996, which increased to PRs12.8 billion in FY2000. Gross operating profit did not deteriorate until after FY1995 when the higher cost of fuel began to have a negative effect. After FY1995, interest costs also rose steeply, and KESC was unable to meet the full 24 Eighty percent of losses in transmission and distribution were identified at appraisal as due to distribution. 25 Transmission and distribution losses were 40.2 percent in FY2000, of which nontechnical losses were estimated at

around 18 percent. 26 Total expenditure under the Project for FY1989-1993 was less than 1 percent of KESC’s total PDP investment, and

over the investment period FY1989-1998 was 17.4 percent.

financial cost of its operations and debt servicing. By FY1998, KESC was financially insolvent. ADB’s financial covenants to ensure (i) a current ratio of not less than 1, (ii) a debt service ratio of at least 1.3 times net revenues, and (iii) a self-financing ratio of at least 0.25 from FY1991 were not complied with.

Table 3. Financial Performance of KESC (PRs billion)

Fiscal Year Ending 1987 1991 1993 1995 1997 1998 1999 2000

Gross Revenue 3.9 7.3 9.9 12.7 16.3 22.5 23.8 26.0 Fuel Costs 1.4 2.7 4.5 5.3 11.0 11.7 9.3 13.9 Other Operating Expenditure 0.9 1.5 2.1 3.3 6.5 10.4 14.3 15.1 Gross Operating Profit a 1.7 2.9 3.1 3.7 (1.7) 0.0 (0.4) (4.0) Profit Before Tax 0.3 0.7 0.6 0.2 (6.8) (6.9) (7.4) (12.8) Appropriationsb 0.3 0.9 0.1 0.1 (1.2) (1.2) 0.1 0.1 Net Fixed Assets 10.5 20.8 21.1 23.8 27.0 43.3 45.0 43.8 Long-Term Loans 6.5 14.1 12.3 23.0 38.0 42.5 53.2 51.1 Total Assets 13.2 28.0 30.2 40.9 59.5 67.1 69.6 66.2 Performance Indicators Current Ratioc 1.3 0.9 0.8 1.4 0.8 0.7 1.0 0.5 Debt Service Ratiod 1.3 1.0 1.5 1.3 (0.5) (0.1) (0.4) (0.7) Self-Financing Ratioe 0.2 .. .. 0.2 <0 <0 <0 <0 Operating Expenditure/Revenue (ratio) 0.6 0.6 07 0.7 1.2 1.0 1.1 1.2 Return on Operating Revenue (%)f 8.8 10.4 5.8 1.5 (42.9) (31.0) (31.6) (51.1) Return on Equity (%) 11.9 15.7 9.2 3.5 (449.8) ----------insolvent--------- Equity to Total Assets (%) 21.8 17.0 20.2 13.2 2.5 (6.2) (12.4) (32.5) Average RevenueTariff (PRs/kWh) 0.9 1.4 1.7 2.2 2.8 3.5 3.8 3.9

.. = near zero, kWh = kilowatt-hour. a Before depreciation and loan service costs. b Covering provision for dividends and tax. c Ratio of current assets to current liabilities. d Profit before depreciation and interest, and after tax and dividends divided by interest plus loan repayments. e Net sum of funds from internal resources divided by average capital expenditure. f Profit before tax divided by operating revenue. 29. Adjustments in KESC tariffs resulted in an average annual increase of 12 percent between FY1987 and FY2001 compared with an average inflation rate of 9 percent per annum.27 Reflecting these adjustments, the average revenue per kilowatt-hour (kWh) increased 4.5 times from PRs0.93/kWh to PRs4.21/kWh. By way of contrast, the average unit cost, excluding depreciation and interest, increased 8.6 times from PRs0.55/kWh to PRs4.75/kWh due mainly to rising fuel costs and the higher cost of energy purchases from IPPs. Erosion of KESC’s operating margin was also accentuated by the loss of operational efficiency resulting from growing system losses. Overall, KESC’s weakening financial performance is attributed to (i) reduced investment and attention to improving system efficiencies, particularly in distribution; (ii) growing nontechnical losses; and (iii) insufficiency of the net revenue tariff to KESC (para. 55).

C. Financial and Economic Reevaluation

30. At appraisal, the EIRR and FIRR were calculated taking into account all KESC investment additions (planned and under construction), including the Project, during the time-slice FY1987-1992. The investments included a planned increase in generation of 830 MW at

27 As measured by the national consumer price index to FY2001. The last tariff adjustment in March 2001 provided

for an estimated average increase of 8 percent. The previous adjustment in 1998 provided for an average increase of 20 percent.

Bin Qasim 3, 4, 5, and West Wharf 1 and all rehabilitation and expansion works in transmission and distribution. The benefits included all incremental energy revenue up to FY1995, which was thereafter held constant through FY2015. Associated operation and maintenance expenditures, including fuel costs, were estimated up to FY1993 and thereafter held constant through FY2015. The base case EIRR of 12.7 percent and FIRR of 11.1 percent were sensitive to variations in energy sales, tariffs, fuel prices, and capital costs.28 31. The PCR extended the completion year of the Project and repeated the approach adopted at appraisal, taking into account actual costs and revenues from FY1991 to FY1998.29 The PCR’s lower FIRR of 4.5 percent largely reflects differences in scheduling, accountability for capital invested,30 and incremental sales.31 The lower EIRR of 5.7 percent arises because of the same factors.32 32. Reestimates of the time-slice calculations based on all investment additions from FY1987 to FY1998 are less than zero (FIRR) and 1.6 percent (EIRR). However, because of the reduced project scope to address system losses and subsequent insufficiency of investment in distribution upgrading to achieve an overall reduction in system losses for KESC, the time-slice approach is not an appropriate methodology for assessing the financial and economic viability of the Project. Estimates for typical individual subprojects visited by the OEM, which range from 16.5 percent to more than 50 percent for the FIRR, and from 23.7 percent to more than 50 percent for the EIRR, attest to the viability of the subprojects. Comparison of the subproject estimates with the time-slice estimates calculated at appraisal and in the PCR is shown in Table 4. Appendix 7 provides details of the methodology, assumptions, sensitivity, and workings underlying the FIRR and EIRR calculations.

Table 4: FIRR and EIRR Estimates (percent)

Item Appraisal PCR PPARa

FIRR 11.1 4.5 16.5->50 EIRR 12.7 5.7 23.7->50

EIRR = economic internal rate of return, FIRR = financial internal rate of return, PCR = project completion report, PPAR = project performance audit report. a For individual subprojects.

D. Sustainability

33. The sustainability of reduced transmission losses, improved voltage reliability, and reduced outages depends on generation sufficiency and optimal load management. Generation sufficiency to meet load growth has been achieved through power purchases from IPPs and WAPDA. The transmission line capacity developed under the Project is sufficient to meet the

28 For example, a 10 percent increase in fuel costs without a corresponding increase in the electricity tariff reduced

the appraisal FIRR from 11.1 percent to 6.0 percent. 29 The computation did not account for KESC’s earlier investment in generation for Bin Qasim units 3, 4, and 5 from

which incremental energy increases were derived. 30 Qasim generation units 3, 4, and 5 were commissioned in FY1990 and FY1991; Qasim 6 was commissioned in

FY1998. 31 The PCR’s projected incremental sales increased from around 800 GWh in FY1998 to 4,000 GWh in FY2001. The

increase reflected energy increases not linked to KESC’s investment additions but largely to forecast increases in the purchase of power from IPPs and WAPDA. Actual incremental sales attributable to the time-slice investments were around 800 GWh, and if used in the PCR would have resulted in a much lower FIRR and EIRR.

32 Another difference in the computation method involved the pricing of incremental sales. At appraisal, incremental sales were valued at willingness to pay. For the PCR, incremental sales were valued at the average tariff adjusted to economic prices (Appendix 7).

load growth for several years. However, transformer capacity is near maximum on most distribution feeders, and higher transformer capacities will be needed to meet peak demand and avoid transformer failures with attendant load shedding. Capacitors on 11 kV circuits are needed to counter reactive power loads and reduce technical losses in distribution. Assuming that future power purchases match load growth requirements and that the appropriate investments are made in load management and distribution upgrading, the technical benefits of the Project are sustainable. However, it is very uncertain that the needed investment in distribution upgrading and system control facilities will be available. KESC’s own investment capacity is severely constrained by its financial insolvency, and although KESC is currently subject to restructuring, funding for upgrading is not included. While privatization under the restructuring program is planned for June 2002, there is likely to be considerable delay. In the interim period to privatization, which may not result in full divestment of the Government’s holding (para. 57), only minimum investment is being undertaken. This is insufficient to counter increasing losses with ever-higher power demand. Without further investment for distribution upgrading, the sustainability of the Project will be compromised. 34. Although the sustainability of KESC’s investments is very uncertain, the Government appears committed to sustaining efforts for a recovery of nontechnical losses. KESC’s initiatives with pilot projects for monitoring and metering all consumers have met with promising success. Other initiatives for recovery through technical solutions, including improved cabling that cannot be tapped, are being pursued. Provisional capital cost estimate for reducing nontechnical losses to an international level is around $130 million,33 and it will take two or three years to fully implement these initiatives. 35. Parallel to the urgent need to reduce transmission and distribution losses and restore investment to a viable level, there is a need to adjust electricity tariffs so that the revenue available to KESC is in line with its long-run average costs. KESC’s institutional capacity depends on a continuing commitment to enhancing operational efficiencies through more effective management of information and technical systems.

33 Estimate based on consultations with KESC engineers and the international implementation consultants.

IV. ACHIEVEMENT OF OTHER DEVELOPMENT IMPACTS

A. Socioeconomic Impact

36. The project components, which were part of the Government’s Seventh Five-Year Plan to reduce power shortages, were premised on the need to eliminate the potential for future increased technical losses, avoid load shedding, and meet forecast power demand. No measure of the socioeconomic factors was evaluated at appraisal or during implementation. Electrification of new areas formed part of the power demand projection, but the Project’s emphasis was to improve the supply system to better cope with anticipated aggregate demand rather than expand the system to allow new connections. 37. Notwithstanding the Project’s limited social objectives, connections under KESC’s PDP increased by an average of 5.2 percent per annum, from 0.8 million in FY1987 to 1.4 million in FY1998. This rate exceeds the average growth rate of the workforce, and indicates the extent to which expansion of electrification is meeting social demand. 38. Construction works are estimated to have employed more than 3,000 people and to have helped build resource capacity in technological, construction, and management skills. Wages and salaries, together with local procurement of materials, amounted to an estimated PRs2.8 billion. The new and expanded grid stations created permanent positions for approximately 40 technical and 120 nontechnical staff. KESC employed some 12,000 persons in FY2001. 39. The Project was gender neutral, yielding no particular social or economic benefit to women through its implementation.

B. Environmental Impact

40. The appraisal did not specifically address environmental aspects. During the OEM’s visit to selected project sites, no adverse environmental impacts of any significance were observed. The transmission lines were at or above minimum height clearances and were constructed, in the main, across clear areas. The substations were fenced off and noise from transformers was not audible outside the substation fence boundaries. Personnel safety measures against accidental high-voltage electrocution were incorporated into all new substation and transmission line designs.

C. Impact on Institutions and Policy

41. The technical scope of the Project followed recommendations made under ADB’s TAs approved in August 1981 and April 1987 (footnotes 4 and 5). Project support for institutional strengthening was addressed through loan covenants (paras. 19 and 28), and the provision of computers, software, and training. The setting of financial covenants was aimed at enhancing the financial viability of KESC to make it self-sustaining. The financial targets for current ratio, debt service ratio, and self-financing ratio were signals for adjusting tariffs where noncompliance with these ratios was imminent. The need to adjust electricity tariffs was premised on the need to offset cost inflation, and on an inherent presumption of overall transmission and distribution losses falling slightly. With both technical and nontechnical losses increasing amidst public awareness, and arrears and circular debt problems mounting, political justification for adjusting

tariffs became increasingly difficult. Even so, adjustments were made in excess of cost inflation (para. 29). 42. Using project funding to meet distribution expansion requirements at the expense of upgrading the existing network undermined the Project’s financial institutional strengthening aims. Computerization was intended to enhance technical planning and load management, and improve billing, accounting, and management information systems. The computerization component was, however, deferred to ADB’s KESC Sixth Power (Sector Loan) Project and later canceled because of KESC’s funding constraints. Recommendations were prepared by the implementation consultants for adoption of SCADA and CADPAD programs,34 and the provision of computer hardware for load forecasting, transmission and distribution planning, and system monitoring. Again as a result of funding constraints, the implementation of recommendations was deferred. The consequence of not modernizing operational load control systems has left KESC with obsolete, nonfunctioning, and inefficient manual systems, so that weaknesses in distribution evident at appraisal essentially remain. 43. The Appraisal Mission found that KESC had the capacity and capability to implement the distribution components of the Project without any assistance by consultants. This turned out not to be the case. The Project required an annual quantum of distribution work more than four times that previously undertaken by KESC. As time was of the essence for achieving distribution efficiencies that would benefit KESC’s overall system, the appointment of distribution consultants was essential. The consultants’ help would have resulted in more efficient use of KESC’s resources and would have strengthened its capacity to manage the larger amount of contracting inputs required. The negative consequence of not appointing distribution consultants led to the failure to implement subprojects as planned, and equipment and materials intended for distribution upgrading (to reduce technical losses) being used instead to meet distribution expansion. 44. The Project introduced new materials and equipment, but KESC staff were not familiar with their use or able to gain this knowledge.35 ADB’s close coordination with other aid agencies and financing institutions was an influencing factor in their participation in KESC’s PDP (footnote 7), but ADB’s review and consultation missions appear to have been largely in relation to progress on project implementation and concern for adherence to loan covenants, rather than policy reforms. The recent restructuring program supported by ADB reflects the urgent need for policy reforms related to ownership, tariffs, and IPPs to restore the financial viability of the power sector.36

34 Computer-assisted distribution planning and design (CADPAD) and supervisory control and data acquisition

(SCADA). 35 TA is needed to train KESC staff on the use of modern materials and methods to increase reliability and quality of

electricity supply. Future assistance should include establishment of a distribution training facility specifically aimed at increasing the capability of cable jointers and overhead mechanics (para. 61).

36 Loans 1807-PAK/1808-PAK(SF): Energy Sector Restructuring Program, for $350 million, approved on 14 December 2000.

V. OVERALL ASSESSMENT

A. Relevance

45. The Project’s rationale to support the Government’s Seventh Five-Year Plan to meet investment requirements for power transmission and distribution to Karachi and its environs was consistent with ADB’s assistance strategy for improving operational efficiencies and mobilizing cofinancing to meet investment needs in the power sector. Without the Project, KESC’s transmission system would have been insufficient to evacuate new generation from Bin Qasim to load centers. Technical losses would also have been higher and extensive overloading would have resulted. Voltage reliability across the low-voltage lines would have remained poor and caused consumer appliances and electric motors designed for 220 V to burn out. Higher operating costs would also have resulted. The rationale for the Project, at appraisal and currently, is assessed highly relevant.

B. Efficacy

46. Project implementation followed arrangements envisaged at appraisal except for delays, reductions in scope, and a variation in project purpose relating to the distribution component. Actual achievements under the Project were mixed. The Project increased transmission capacity to carry more than 1,000 MW of new generation to meet expanding demand requirements, and reduced transmission losses across KESC’s total system. However, the reduced investment in distribution rehabilitation made it impossible to reduce KESC’s overall system losses in the face of growing load demand. KESC’s financial performance improved in line with forecasts up to FY1990, but thereafter followed a deteriorating path as system losses, the cost of fuel and power purchases, and interest costs mounted. Sales revenues did not keep pace with operating, administration, and debt-servicing expenditure so that ADB’s financial covenants, which aimed at enhancing KESC’s self-financing capacity, could not be met. Measures aimed at institutional strengthening and computerizing KESC’s load management and distribution planning, billing, accounting, and personnel management systems were cancelled for lack of local funds so that weaknesses identified at appraisal essentially remain. On balance, the Project is assessed partly efficacious in terms of achieving its stated purpose and targets.

C. Efficiency

47. The FIRR/EIRR estimates for rehabilitation of three 11 kV feeders and investment in transmission range from 16.5 percent to over 50 percent and are indicative of the viability of subprojects implemented under the Project. Implementation delays, reduction in the scope of the Project, and mounting system losses decreased the collective impact of project components to improve the overall operational efficiency of KESC. Balancing the satisfactory indicative FIRR/EIRR estimates for inspected project components, against failure of the Project in achieving an overall reduction in KESC’s transmission and distribution losses, the Project is assessed partly efficient.

D. Sustainability

48. KESC’s operations, of which the Project is a small part, are not sustainable without a major restructuring and measures that include a substantial infusion of equity capital, reducing system losses, improving administrative efficiencies, enhancing the skills of technical staff, reducing indirect taxes on the electricity tariff, and introducing workable regulatory policies for adjusting electricity tariffs. Although the current economic environment for restructuring is weak, a total collapse of KESC is unlikely, particularly with the continuing financial support under ADB Loans 1807-PAK/1808-PAK(SF) for energy sector restructuring (footnote 31). Transmission capacity is sufficient and the project benefits of transmission are largely dependent on operational attendance, for which minimum maintenance servicing is required, and sufficient trained personnel are available. The sustainability of distribution benefits is unlikely without a stronger emphasis on investment in distribution upgrading. Overall, the sustainability of project benefits is mixed with sustainability of the transmission component assessed as likely, and that for the distribution component less likely.

E. Institutional Development and Other Impacts

49. The envisaged improvements in the computer-based management systems of KESC were not achieved. The Project partly achieved its socioeconomic aim of reducing load shedding and blackouts, improving distribution voltage in load centers, and expanding distribution coverage. While it was not an intended purpose of the Project to meet distribution expansion requirements, downstream benefits from electricity sales to about 600,000 new connections can be assumed to have helped spur economic growth. Overall, institutional and other impact benefits of the Project are assessed less than moderate.

F. Overall Project Rating

50. The Project was technically well designed at appraisal and appropriate for achieving its purpose. Success was impaired by implementation delays, the nonavailability of local funding, a problematic environment affecting revenue collection, and a decision to downsize the scope of the distribution and load management components. This decision on the distribution component meant that the Project was insufficient in scale to achieve targeted sector objectives.37 51. The negative aspects associated with implementation delays, the failure to reduce KESC’s overall transmission and distribution losses, and the subsequent financial insolvency of KESC tend to overshadow successful achievements at the subproject level. The positive impact of the Project was the completion of the transmission component to meet the availability of additional generation from Bin Qasim, without which power shortages would have been worse, and transmission losses higher. Subprojects for distribution rehabilitation, although insufficient in aggregate to meet sector targets to reduce KESC’s overall transmission and distribution losses, were individually successful and attest to the collective viability of the Project. Distribution expansion targets were also met. New connections, which increased by 74 percent from 0.8 million in FY1987 to 1.4 million in FY1998, contributed to spurring economic growth. 52. Of the five evaluation criteria applied to judging the success of this Project, the rationale for the Project remains highly relevant. On the criterion for efficacy, the Project succeeded in its prime purpose of developing transmission to absorb new generation from Bin Qasim, but failed to effect an overall reduction in system losses. Because of the dominance and primary achievement of the transmission component, an assessment rating of at least partly efficacious 37 Downsizing the scope of distribution upgrading and load management after loan approval proved critical to the

achievement of project targets for reducing KESC’s technical distribution losses and strengthening KESC’s financial position. Mounting nontechnical losses, which were an unanticipated external factor not addressed under the Project, also contributed to KESC’s worsening financial performance.

is warranted. The FIRRs and EIRRs attest to the individual viability of subprojects, but not their collective impact to improve the overall operational efficiency of KESC. The Project is, therefore, assessed partly efficient. The sustainability of the transmission benefits is assessed likely while the sustainability of distribution subprojects is assessed less likely in the absence of investment in upgrading to match load growth. Institutional and other development impacts were negligible in terms of strengthening KESC’s computer-based management systems. Under the broader socioeconomic aims of reducing load shedding and expanding distribution coverage, the achievement was significant, and the impact is assessed moderate. Based on these evaluation judgments, the Project’s overall rating is partly successful.

G. Assessment of ADB and Borrower Performance

53. ADB’s overall performance is assessed partly satisfactory. The technical feasibility of the Project was reviewed, and project design was consistent with least-cost development considerations. Commitments for cofinancing from J EXIM were influenced by ADB’s participation, but there was no catalytic impact outside of the Project for KESC’s wider investment program. Procurement and contracting were carried out in accordance with competitive bidding procedures and with appropriate supervision. Monitoring through review missions was adequate. Detracting from ADB’s performance was (i) an error of judgment made at appraisal pertaining to KESC’s capacity to implement the Project as a sector loan and without assistance by consultants for the distribution components (para. 43), and (ii) not fully addressing the technical implications of approving changes in project scope for achieving the overall project purpose. 54. The Borrower’s performance is assessed as unsatisfactory. Contrary to obligations under the Loan Agreement, KESC’s institutional and financial performance has deteriorated. Revenues in the form of surcharges on the electricity tariff have been exacted at the expense of allowing KESC to be financially insolvent. Despite the many concerns prior to loan approval and loan effectiveness, and during the 18-month loan suspension, the precariousness of KESC’s financial position appears to have been underestimated, and commitment from the Borrower seems to have been lacking.

VI. ISSUES, LESSONS, AND FOLLOW-UP ACTIONS

A. Key Issues for the Future

1. Surcharge on KESC Electricity Tariffs 55. Consumer affordability and KESC’s financial performance are negatively affected by the actual tariff paid by consumers, which is twice KESC’s reported average revenue tariff. The difference is made up of a surcharge paid to the Government. As affordability of the actual tariff paid by consumers is a cause of political resistance against increasing tariffs, the issue of what is an appropriate level of surcharging needs to be urgently addressed. This is particularly so in light of KESC’s insolvency and the severe constraints imposed on KESC’s self-financing capacity by the low net revenue tariff available to KESC.38

2. Policy Reforms 56. Reflective of the differential between the tariff paid by consumers and the net tariff to KESC, electricity revenues paid to the Government exceed the revenue of KESC and are currently around PRs28 billion ($450 million equivalent) per annum. The surcharge paid to the federal and Sind governments is in effect a monopoly rent, but at the cost of lower investment and reduced availability of electricity in the Karachi area—possibly by as much as 40 percent. The situation poses a policy dilemma of continuing to support a monopoly structure, which suppresses expansion and thereby reduces the benefits of electricity to households and businesses that would otherwise prevail. Perpetuating support to a system that extracts high monopoly rents but leaves insufficient revenue to meet operating expenditures and provide a normal return on investment is also a governance issue. A closer look at restructuring is warranted. With the right balance on incentives, both power expansion and overall tax revenues to government can be larger than is the case at present. Future policy reforms affecting electricity surcharges need to bear in mind investment requirements so that revenue flows sustain and expand development.

3. Privatization and Need for Continued Upgrading of Distribution 57. Privatization of KESC cannot be effected before mid-2002, and may not result in a full divestment of the Government’s holding. The present management practice is to support only essential investment in the interim period up to privatization. In this regard, the lessons of the Project are of paramount importance. The present level of technical losses of around 24 percent will escalate without adequate attention to upgrading the distribution system. Continuing expansion by way of new connections without upgrading existing overloaded distribution facilities will exacerbate power outages. Urgent attention to and continued upgrading of the distribution system are, therefore, recommended. To effect this upgrading, a decision relating to using existing materials in store for expansion and upgrading is needed (footnote 13). The impact on system losses of meeting expansion requirements from new customers prepared to invest on their own account in materials and equipment also needs to be further considered.

38 KESC’s present average revenue of PRs4.21/kWh (6.8c/kWh) is considerably less than tariffs in other developing

member countries. Average tariffs in FY1999-2000 in US cents per kWh were 11.9 in the Philippines, 8.5 in the People’s Republic of China, 10.1 in Sri Lanka, and 13.6 in Thailand.

B. Lessons Identified

58. The key lessons derived from the Project are (i) the critical importance of scale and timing for upgrading distribution systems to improve overall system efficiencies (paras. 11, 22, and 24); (ii) the need for ADB to be more circumspect in appraising sector loan objectives and the likelihood of achieving them, particularly where target achievements depend on the availability of local funding and the capability of the power utility (paras. 11 and 43); and (iii) the need to replace KESC’s nonfunctional and obsolete CADPAD system for identifying and selecting distribution feeders for upgrading, in order to reduce distribution losses (para. 42).

C. Follow-Up Actions

59. ADB should take into account the lessons identified and ensure future power sector loan projects are reviewed with an understanding that the impact of changes in project scope can be critical to the achievement of project purpose. 60. The Government should take urgent measures aimed at (i) restructuring the electricity tariff so that the operations of KESC are financially sustainable (para. 56), (ii) providing KESC with support for upgrading its distribution system so as to contain technical losses until privatization (para. 57), and (iii) developing policies backed with financial support which clarify how KESC will meet the demand for new connections in the interim period without jeopardizing technical efficiency (para. 57). 61. KESC should (i) initiate as soon as possible a request for funding to install capacitors on its low-voltage feeders (para. 16); (ii) take immediate steps to improve the technical skills of its staff to meet upgrading, servicing, and connection standards (paras. 16 and 25, and footnote 30); (iii) continue to develop effective recovery mechanisms for dealing with nontechnical losses, outstanding customer accounts, errant staff, and contractors (para. 34); and (iv) in consultation with the Government, take steps as soon as possible to contain further increases in distribution losses (para. 57).

APPENDIXES

Number Title Page Cited on (page, para.)

1 Approved and Actual Project Scope 19 2, 3 2 Purpose, Targets, and Actual Outcomes 21 2, 3 3 Technical Review and Recommendations 23 4, 10 4 Project Cost 27 5, 12 5 Implementation Schedule 28 5, 13 6 KESC’s Key Performance Indicators 29 6, 20 7 Financial and Economic Performance of the Project 30 10, 32

Appendix 1, page 1

APPROVED AND ACTUAL PROJECT SCOPE

Item Approved Actual Part A: Transmission Reinforcement and Expansion (see also subtargets Appendix 2) New Grid Stations 7 a 4 b Extension of Existing Grid Stations 5 c 14 d Additional Transmission Lines and Connections 8 e 13 f Connection of Grid Substations 8 g 4 h Reinforcement of Transmission 220 kV 2 Substations i 2 Substations j Reinforcement of Transmission 132 kV 4 k 2 l Capacitor Banks of 4 MVAR each 50 94 m Part B: System Control and Protection Upgrading

Installation of Signaling Equipment 2 Substations Completed Upgrading of Protection System Signaling 19 Lines Completed n Improvement of Telecommunications Repeaters 5 Lines

Telephone System Data Speed 600 Baud

Completed n Completed o Deferred p

Standardization of RTU Data Upgrade 34 Substations Deferred p Upgrading of Load Despatch Center New LDC

Connection to WAPDA Deferred p

Deferred p Part C: Distribution Rehabilitation and Expansion

11 kV Distribution Reinforcement 487 km 566 km 0.4 kV Low Voltage Distribution Rehabilitation

and Expansion q -0.4 kV Overhead and Underground Lines -11/0.4 kV Transformers Capacity

1,500 km 922.5 MVA

766 km 439.5 MVA

Capacitor Installation 260 MVAR Deferred r Computer Hardware and Software Completed s

Part D: Consulting Services

Consulting Services for Computerization Completed Consulting Services for Transmission Completed Consulting Services for Distribution Partially Completed t

km = kilometer, kV = kilovolt, kVA = kilovolt-ampere, MVA = megavolt-ampere, MVAR = megavolt-ampere reactive, RTU = Remote Terminal Unit, LDC = Load Despatch Center, WAPDA = Water and Power Development Authority. Footnotes: See page 2. Source: Asian Development Bank appraisal report, Karachi Electric Supply Corporation completion report, and

Operations Evaluation Mission follow-up.

Appendix 1, page 2

Footnotes a 66 kV and 132 kV at West Wharf, 132 kV at Mauripur North, Deh Kharkharo, Site II, Korangi East, and Deh Surjani.

Total transformer capacity 280 MVA. b 132 kV at Surjani, Malir, Queens Road, and Lyari. Total transformer capacity 160 MVA. c At Gulshan, Balouch Colony, Hub Chowki, Defence, and Civil Centre. Total transformer capacity 260 MVA. d At Gulshan, Hub Chowki, Defence, Civil Centre, Civil Aviation Authority (CAA), Dhabej, Export Processing Zone,

Landhi, Liquatabad, Orangi Town, Baldia, Clifton, Garden East, and Jacob Line. Total transformer capacity 800 MVA. e Covering 132 kV links: West Wharf-Queens Road; West Wharf-Garden East; Korangi East-Korangi Town; Gizri-

Queens Road; and looping in at Site II; Mauripur North, Deh Kharkharo, and Deh Surjani. Total 28.8 kilometers (km) cable, 34 km overhead.

f Covering 132 kV links Korangi West-Korangi South, Valika-North Karachi, Pipri West-Landhi, Korangi West-Gizri-Queens Road, Lyari-Site, Garden East-Jacob Line, Site II-Liquatabad, Site GT-Site, Malir-CAA and looping in at University Road, Surjani, Korangi South, Korangi West. Total 44.7 km cable, 31.2 km overhead.

g 132 kV line feeder additions at Queens Road, Gizri, Korangi Town, Langhi, and modifications to four other stations. h For sites with existing 132 kV switchgear, line feeder additions at Gulshan, Jacob Lines, Valika, and Site. Also circuit

breakers added on 132 kV cabled tee to Malir, at the transmission line tee point. i Involving 220 kV connection Baldia-West Wharf (22.3 km of double circuit), installation of 1 x 250 MVA interconnecting

transformers at Baldia and West Wharf, and associated 132 kV switchgear at Baldia and West Wharf. j Involving 220 kV connections Landhi-Korangi Thermal Power Supply (KTPS), KTPS-Queens Road and looping in

Korangi West (total 34.5 km of double circuit), installation of 1 x 250 MVA interconnector transformer at Baldia and 2 x 250 MVA interconnector transformers Queens Road, and associated 132 kV switchgear at Baldia and Queens Road.

k Involving installation of 132 kV lines between Gulshan-Korangi Development Authority (KDA) (11.5 km), Baldia-Valika (11.8 km), and Landhi-Pipri West (17 km) and 66 kV looping from Gadap to Malir.

l 132 kV Landhi-Pipri West (17 km) and 132 kV looping CAA to Malir. m 376 MVAR added at grid substations following decision not to add on 11 kV feeders. n Extensive power line carrier and protection signaling equipment addition completed at all substations. o Telephone access to all substations added through power line carriers. p Loans 1314-PAK/1315-PAK(SF): KESC Sixth Power (Sector Loan) Project, for $200 million, approved on

22 September 1994. q The two components 0.4 kV rehabilitation and distribution expansion are summed here as no distinction is drawn by

KESC as to where equipment was applied. At appraisal, rehabilitation included 1,000 km lines and 322.5 MVA transformer capacity and expansion, 500 km lines, and 600 MVA transformer capacity.

r Addition of distribution capacitors was indefinitely deferred. s Computer-assisted distribution planning and design software purchased and training completed, now obsolete.

Specification for other computerization completed. t At appraisal, the scope included also advice and assistance during distribution implementation, but this was later

deleted.

PURPOSE, TARGETS, AND ACTUAL OUTCOMESa Overall Donor-Assisted Program/Project

Purpose/Scope Targets Actual Outcomes and Impact 1. Sector • Expand power generation capacity through existing and

new plants • Increase generation capacity by 830 megawatts (MW) by FY1993 630 MW added

200 MW at West Wharf deferred 210 MW at Bin Qasim 6 commissioned in FY1998

• Reinforce and expand transmission capacity • Expand the Karachi network in pace with load growth Completed

Capacity for full generation dispatch installed

• Improve system reliability and power distribution

efficiency through rehabilitation and reinforcement of existing transmission and distribution systems

• Eliminate load shedding and reduce system losses to 15.5 percent by FY1995

Not achieved. Losses were 31.1 percent by FY1995 and 34.3 percent by FY1998 Load shedding common in FY1997

2. Project

• Augment and expand the Karachi Electric Supply

Corporation’s (KESC’s) transmission and distribution capacity to meet the anticipated growth in power requirements through the end of FY1991, and for a three-year time-slice of KESC’s power development plan for FY1989-1993

Part A: Transmission Reinforcement and Expansion • Install 50 capacitor banks of 4 megavolt-ampere reactive (MVAR)

each at 11 kilovolt (kV) grid stations • Construct and reinforce transmission involving

– 44.6 kilometers (km) of 220 kV lines – 120.1 km of 132 kV lines – 5 km of 66 kV lines – 7 new substations – 5 existing substations

• 94 x 4 MVAR capacitor banks installed

• Constructed: – 62.9 km 220 kV – 155.9 km 132 kV – 4 new substations – Extended 15 substations

Part B: Distribution Rehabilitation and Expansion

• Rehabilitate 500 11 kV feeders (487 km) • Rehabilitate 0.4 kV feeders (1,000 km) and extension for new load

(500 km) • Rehabilitate 0.4 kV network with addition of 322 megavolt-ampere

(MVA) transformer capacity and add 600 MVA for load growth • Install an additional 260 MVAR of 11 kV capacitors

• 566 km 11 kV feeders • Total rehabilitation and

extension 0.4 kV, 766 km • Added transformer capacity

439.5 MVA • No distribution capacitors added

a Although similarity in format exists, this comparison is not intended to represent a logical framework. A logical framework was not prepared for the Project at appraisal.

Appendix 2, page 1

Purpose/Scope Targets Actual Outcomes and Impact

• Upgrade system control and protection facilities Part C: System Control and Protection Facilities • Install protection systems and associated communications (power

line carrier systems) on all 132 kV and 220 kV lines • Improve telephone communications with power stations • Increase data rates to 600 baud and standardize data collected at

all substations • Build a new load despatch center • Improve operational communications with the Water and Power

Development Authority

Component deleted Derived improvements from transmission resulted from • Added carrier systems with

protection equipment • Improved telephone access to

power stations

• Improve system reliability and reduce losses • Eliminate load shedding and reduce sector system losses to

15.5 percent by FY1995 Not achieved. Losses were 31.1 percent by FY1995 34.3 percent by FY 1998 Load shedding common in FY1997

• Computerization/Training Part D: Consulting Services

• Involve KESC in computer studies; select and acquire computer hardware and distribution planning software for future KESC studies

• Develop a strategy and acquire hardware and software suitable for future commercial and financial operations

Completed Recommendations rendered redundant by changing circumstances

• Improve financial and economic viability • Financial internal rate of return (FIRR) of 11.1 percent • Economic internal rate of return (EIRR) of 12.7 percent

For subprojects FIRR is 16.5->50 percent EIRR is 23.7->50 percent

3. Project Activities/Inputs

• Procurement and delivery of equipment and materials • Construction of transmission lines and substations • Rehabilitation/extension of 11 kV feeders and associated

0.4 kV lines • Upgrading of system control and protection • Supervision and training

• Project costs (equipment and consulting services, excluding contingencies, taxes, and duties): – Transmission Reinforcement and Expansion: $109.1 million – System Control and Protection: $12.4 million – Distribution Rehabilitation and Expansion: $95.6 million – Consulting Services: $4.0 million

• Taxes and duties, physical and price contingencies, and interest

during construction: $168.8 million • Financing plan

– ADB: $100.0 million – Government/KESC: $177.6 million – Other external: $112.2 million

Project costs Transmission: $112.7 million Protection: nil Distribution: $85.5 million Consultants: $5.8 million Taxes, duties, physical and price contingencies, interest during construction: $73.5 million Financing ADB: $98.4 million Government/KESC: $86.8 million Other external: $92.2 million

ADB = Asian Development Bank.

22

Appendix 2, page 2

Appendix 3, page 1

TECHNICAL REVIEW AND RECOMMENDATIONS A. Transmission Rehabilitation and Expansion 1. The objective was to transmit the planned increase of 630 megawatts (MW) from 3 x 210 MW generators at Bin Qasim (units 3, 4, 5) to the load centers in Karachi. The package of measures proposed to transport the power from Bin Qasim included seven new grid stations, expansion of five existing grid stations, additional transmission lines, reinforcement of the transmission network to 220 kilovolts (kV), expansion of the existing 132 kV network, and installation of 50 capacitor banks of 4 megavolt-amperes reactive (MVAR) each on the 11 kV network.1 2. Transmission lines inspected by the Operations Evaluation Mission included new and refurbished 132 kV circuits and new 220 kV circuits. While some were built on lattice towers, most used monopoles (sectored steel poles), which were more suitable for the narrow urban corridor requirements. The transmission lines were built to accepted design and construction standards, although the use of copper conductor should be reviewed. All-aluminum alloy conductor is used elsewhere in similar corrosive atmospheres with good results. 3. The 220 kV gas-insulated switchgear substation visited featured double 220 kV bus and two 250 megavolt-amperes (MVA) 220 kV/132 kV interconnecting transformers. The design and construction complies with accepted standards. Provision has been made for local computer control and remote control and monitoring, but implementation of the related communications and system control and data acquisition (SCADA) facilities was deferred.2 Operation of the substation and overall transmission system efficiency would be improved by the addition of a SCADA system. 4. Two 132 kV/11 kV grid substations were inspected. The first was a new substation featuring an indoor design with conventional equipment. This is a good solution for avoiding pollution problems while maintaining low cost. The main and transfer 132 kV bus system is conservatively designed. Removal of the transfer bus and use of a “three-switch mesh” arrangement would have provided a more cost-effective solution. At the second substation, 4 MVAR 11 kV capacitor banks had been added for reactive compensation. One of these was outdoors in direct sunlight and rated only to 40oC. The method of installation should be amended for future additions. 5. In all transmission substations visited, power and interconnecting transformers had no oil bunding or separation facilities. These are needed to mitigate the environmental effects of oil spillage. Also, transformers should be located in fire-resistant vaults to minimize damage in the event of a transformer fire. The one substation seen with barriers between transformers used concrete construction. This can be easily damaged by heat and rendered ineffective. Fire barriers should be of metal or refectory brick construction.

1 Transmission expansion was also to be sufficient to carry future generation from Bin Qasim unit 6 of 210 MW and

West Wharf of 200 MW. Bin Qasim unit 6 was commissioned in FY1998. The planned additional generation from West Wharf was cancelled. Additional generation requirements were met through purchases from the Water Power and Development Authority and independent power producers.

2 Loans 1314-PAK/1315-PAK(SF): KESC Sixth Power (Sector Loan) Project, for $200 million, approved on 22 September 1994.

Appendix 3, page 2

B. Distribution Rehabilitation and Expansion 6. This project component aimed at reducing the high technical energy losses in the distribution network, and improving voltage and reliability. To achieve these objectives, the need for a computerized load flow and feeder optimization program was identified. Feeders with reactive loadings were to be upgraded with short capacitors to counter the inductive voltage losses caused by fans, air conditioners, and fluorescent lighting. The installation of short capacitors was a key design feature. For the secondary 0.4 kV lines, the need for extensive reconditioning and transformers was envisaged. Envisaged modifications included replacing phase cable with heavier cable, adding distribution transformers and relocating these to even the load between phase wires, and installing metering equipment. 7. The consultants of the Karachi Electric Supply Corporation (KESC) formulated the distribution subprojects, completed the procurement process, and then had no further involvement with the distribution work. While the Project was completed in 1997, much of the distribution component was not implemented. As of May 2001, approximately 32 percent ($30 million) of the distribution materials purchased had not been used and were held in KESC’s stores system (Table A3.1). The main reasons for incomplete implementation are (i) the local authorities have restricted road excavation for cable laying, (ii) KESC is reluctant to install further copper conductor given high levels of theft, and (iii) KESC staff do not have the knowledge required to use some of the materials.

Table A3.1: Remaining Distribution Equipment Stock Levels, May 2001a

Item

Quantity Remaining in

Stock

Percentage of Procurement

Approximate Valueb ($’000)

Poles for 11 kV, 0.4 kV 10,734 47 4,973 Copper Conductor 4,287 km 44 13,200 0.4 kV Cable 51.6 km 23 1,440 11 kV Cable 63.1 km 17 1,896 11 kV Ring Main Units 55 22 1,054 11 kV Vacuum Circuit Breaker Panels

132 26 3,739

Ground Rods/Clamps 23,400 sets 88 1,118 Other Items 3,130

Total 32 30,548

km = kilometer, kV = kilovolt. a Source: KESC submission to the Operations Evaluation Mission. b In 1996 dollars, when procured.

8. The 11 kV and 0.4 kV overhead system in Karachi uses bare copper conductor. This is inappropriate given the reported level of copper conductor theft (10 tons/year) and the common practice of power theft through applying hooks to 0.4 kV lines. KESC is aware of this and is taking steps to remedy the problem. Further development and rehabilitation should use covered aluminum conductor for 11 kV and either covered aluminum conductor or aerial bundled conductor for 0.4 kV. This may require the use of bimetallic fittings.

Appendix 3, page 3

9. Generally, the overhead construction is substandard. This is particularly so for the jointing and connection of conductors, as connections are made by twisting or splicing the wires. Twisted connections are mechanically weak and often result in high resistance joints. These heat when load is applied, increasing technical loss, and frequently fail, resulting in feeder outages. While KESC has many conductor joints and connectors in stores, staff are not familiar with their use, and the need for training is evident. 10. Load imbalance is a significant problem for KESC to address. With the present vertical 0.4 kV construction, the lowest phase is always highest loaded due mostly to ease of access for both legal and illegal connection. This leads to overloading of equipment and higher losses than for a balanced system. Use of aerial bundled conductor would assist load balancing and reduction of losses, as would regular reviews of loading and connections. 11. Pole-mounted substations are generally well built, but there are several ways KESC could improve their design and construction. For example, 11 kV cables should be securely fastened to the poles by cable supports, rather than the full weight of cable applied to the termination. The practice of leaving cable retermination loops at the feet of poles should be abandoned, as these are likely to introduce cable faults in the future. Those loops seen were exposed to the sun and the bending radius used is well below the recommended minimum. Low-voltage cables should be secured to avoid the radiators, the hottest part of a transformer. Low-voltage switch boxes should be redesigned to ensure that they can be securely closed. 12. Indoor substations viewed were generally of good design. They are spacious and allow access for working and equipment replacement. However, 400-volt (V) switchboards, of open-framed design, are considered to be hazardous and oversized. Use of type-tested metal-clad switchboards is recommended. Solid links used in fuseholders, while providing ability to meet overloads, provide no protection for 400 V cables. Cable faults generally result in transformer tripping and where transformer protection relays have been removed by theft or vandalism in feeder tripping. KESC should ensure that all cables are correctly fused to reduce outages and equipment damage. 13. Maintenance of all distribution transformers, and pole-mounted substations, appears inadequate. The transformers are generally highly loaded and burn out at the very high rate of 12 percent of the total population per year. KESC should increase load monitoring and preventive maintenance to achieve lower overall operating and maintenance costs through reductions in transformer rebuilds and feeder faults. C. Power Factor Correction 14. The power factor of distribution system loads was to have been improved under the Project through the addition of 260 MVAR of 11 kV capacitors. KESC installed some distribution capacitors but discontinued this when various technical problems were experienced. Instead, 94 banks of 4 MVAR capacitors were installed only in grid substations. This resulted in a reduction of transmission losses by 2 percent and increased transmission capacity by around 160 MW. However, at full generation dispatch, total losses increased by around 2.4 percent. Had capacitors been added within the distribution network as intended at appraisal, distribution losses would have been reduced by around 2.7 percent. It is recommended that any further capacitor additions be in the distribution system.

Appendix 3, page 4

Table A3.2: Installed Capacity of KESC, 1987-2000

Fiscal Year Megawatts (MW) 1988 1,108 1989 1,108 1990 1,318 1991 1,738 1992 1,738 1993 1,738 1994 1,738 1995 1,738 1996 1,738 1997 1,550a 1998 1,756 1999 1,756 2000 1,750

a Reduced capacity due to the retirement of 2 x 33 MW units and 1 x 66 MW unit. Source: Karachi Electric Supply Corporation (KESC).

Appendix 4

Project Component

Expansion and Augmentation 24.79 6.30 31.09 37.57 3.44 41.01Extension of Grid Substations 5.86 1.87 7.73 24.63 2.60 27.23Additional Lines 29.17 3.04 32.21 21.92 10.87 32.79Connection of T/L to Substations 4.71 0.89 5.60 10.07 1.59 11.66Reinforcement 20.17 6.94 27.11 0.00 0.00 0.00Reactive Power Compensation 3.75 1.60 5.35 0.00 0.00 0.00

Subtotal (A) 88.45 20.64 109.09 94.19 18.50 112.69

System Control and Protection UpgradingLoad Despatch Centers and Computer Equipment 4.25 1.01 5.26 0.00 0.00 0.00Protection Equipment and Telecom Improvements 6.71 0.40 7.11 0.00 0.00 0.00

Subtotal (B) 10.96 1.41 12.37 0.00 0.00 0.00

11 kV Reinforcement and Rehabilitation 14.48 6.39 20.87 ) 0.4 kV Rehabilitation 8.38 9.67 18.05 ) 44.21 40.99 85.20Capacitor Installation 2.62 1.10 3.72 )Distribution Expansion 23.23 29.45 52.68 )Computer Equipment and Systems 0.31 — 0.31 0.28 0.00 0.28

Subtotal (C) 49.02 46.61 95.63 44.49 40.99 85.48

Consulting Services 3.00 1.00 4.00 3.96 1.80 5.76

Taxes and Duties — 75.96 75.96 0.00 47.32 47.32

Physical and Price Contingencies 16.67 23.10 39.77 0.00 0.00 0.00

Interest During Construction 21.40 31.54 52.94 0.00 26.18 26.18

Total 189.50 200.26 389.76 142.64 134.79 277.43

— = no provision, KESC = Karachi Electric Supply Corporation, kV = kilovolt, T/L = transmission line.

Transmission Reinforcement and Expansion

Distribution Rehabilitation and Expansion

($ million)

TotalAppraisal Estimate

ForeignForeignExchange CostCurrency Cost Exchange Currency

PROJECT COST

Local TotalActual

Local

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV I II III IV

Appraisal scheduleActual schedule

IMPLEMENTATION SCHEDULE

Loan suspended for further award of

contracts

Load Dispatch Center

deferred to Sixth Loan

Contract for transmission

awarded

Final contracts for distribution awarded

Loan approval

Loan effectiveness Consultants

appointed

Loan approval

Consultantsappointed

Loan effectiveness Installation

started Commissioning

Appendix 6

Item

Gross Energy Generation (GWh) 4,772 5,518 5,722 6,292 7,889 7,299 7,458 7,318 6,613 7,745Total Energy Purchases (GWh) 600 355 558 704 763 1,462 1,869 3,030 4,007 3,701Total Energy Available for Sale (GWh 5,058 5,524 5,931 6,555 8,126 8,262 8,837 9,854 10,150 10,934

Total Energy Sales (GWh) 4,130 4,508 4,765 4,969 5,879 5,632 5,640 6,385 6,131 6,430Sales Growth (% per annum) 2.1 9.2 5.7 2.1 8.8 2.2 0.0 13.2 4.1 4.9

Projected Transmission and Distribution Losses (% 17.9 17.9 18.0 17.0 16.5 15.5Actual Transmission and Distribution Losses (% 17.9 18.5 19.1 23.6 27.1 31.1 35.3 34.3 38.6 40.2Actual Total Systems Losses (%) 23.1 23.2 24.1 29.0 32.1 35.7 39.5 38.3 42.3 43.8

Total Connections ('000) 823 897 961 1,091 1,204 1,301 1,382 1,435 1,500 1,666Connection Growth (% per annum 7.7 9.0 7.1 13.5 5.1 4.0 3.1 3.8 4.5 11.1Average Sales Revenue (PRs/kWh 0.9 1.0 1.1 1.4 1.7 2.2 2.8 3.5 3.8 3.9

Gross Revenue (PRs billion 3.9 4.7 5.5 7.3 9.9 12.7 16.3 22.5 23.8 26.0Gross Operating Revenue (PRs billion 3.9 4.6 5.4 7.2 9.7 12.4 15.8 22.1 23.3 25.0Gross Operating Profit (PRs billion 1.7 2.2 2.0 2.9 3.1 3.7 (1.7) (0.0) (0.4) (4.0)

Fuel Costs (PRs billion) 1.4 1.6 2.0 2.7 4.5 5.3 11.0 11.7 9.3 13.9Cost of Power Purchases (PRs billion 0.2 0.2 0.3 0.5 0.7 1.4 3.4 6.1 9.2 9.7

Depreciation (PRs billion 0.9 1.0 0.8 1.1 1.5 1.7 1.7 2.1 2.7 2.8Interest (PRs billion) 0.4 0.4 0.6 1.2 1.3 1.7 2.1 3.7 3.0 5.5

Profit Before Tax (PRs billionb 0.3 0.6 0.7 0.7 0.6 0.2 (6.8) (6.9) (7.4) (12.8)Dividend-Tax Provision (PRs billion 0.3 0.4 0.2 0.9 0.1 0.1 (1.2) (1.2) 0.1 0.1

Total Equity (PRs billion 2.9 3.5 4.0 4.7 6.1 5.4 1.5 (4.2) (8.6) (21.5)

Net Fixed Assets (PRs billion 10.5 10.9 11.0 20.8 21.1 23.8 27.0 43.3 45.0 43.8Current Assets (PRs billion) 2.2 2.3 3.3 5.1 6.3 8.8 11.7 16.5 19.5 16.7Total Assets (PRs billion) 13.2 15.9 19.2 28.0 30.2 40.9 59.5 67.1 69.6 66.2

Profit Before Tax/Equity (% 11.9 18.1 18.1 15.7 9.2 3.5 (449.8) ________ insolvent ________

Profit BeforeTax/Operating Revenues (% 8.8 13.7 13.5 10.4 5.8 1.5 (42.9) (31.0) (31.6) (51.1)

Long-Term Liabilities/Equity (% 3.0 2.9 3.0 3.5 2.7 5.4 28.8 ________ insolvent ________

Equity/Total Assets (%) 21.8 21.9 21.0 17.0 20.2 13.2 2.5 (6.2) (12.4) (32.5)

Current Assets/Current Liabilities (ratio 1.3 1.0 1.1 0.9 0.8 1.4 0.8 0.7 1.0 0.5Current Liabilities/Total Liabilities (% 13.4 14.4 15.6 19.5 25.3 15.4 24.6 35.9 28.6 46.6Long-Term Liabilities/Total Assets (% 64.8 63.7 63.4 63.5 54.5 71.4 72.9 70.3 83.7 85.9Debt Service Ratioc 1.3 1.6 1.5 1.0 1.5 1.3 (0.5) (0.1) (0.4) (0.7)Self-Financing Ratiod 0.2 0.4 0.6 .. .. 0.2 <0 <0 <0 <0

.. = near zero, GWh = gigawatt-hour, kWh = kilowatt-hour, KESC = Karachi Electric Supply Corporation.a Estimates released in October 1988.b After depreciation and interest.c Profit before depreciation and interest and after tax and dividends divided by interest plus loan repayments.d Net funds from internal sources divided by the average capital expenditure calculated over three years for the current fiscal year, previous fiscal year, and next fiscal year.Sources: KESC and mission estimates.

1989 1991 1993

KESC's KEY PERFORMANCE INDICATORS

1995 20001997 1998 19991987 1988 a

Appendix 7, page 1

FINANCIAL AND ECONOMIC PERFORMANCE OF THE PROJECT A. Methodology of Appraisal Report 1. The financial internal rate of return (FIRR) and economic internal rate of return (EIRR) for the Project were calculated based on all investment additions (planned and under construction) for the time-slice FY1987-1992.1 The investments included a planned increase in generation of 830 megawatts (MW) at Bin Qasim 3, 4, 5, and West Wharf 1 not funded under the Project, and all transmission and distribution expansion. The time-slice considered all derived incremental energy revenue up to FY1995 after which incremental revenue was held constant through FY2015. Operation and maintenance (O&M) expenditures, including fuel costs, were projected up to FY1993 and thereafter held constant through FY2015. Projections for incremental energy sales were based on the load forecast of the Karachi Electric Supply Corporation (KESC) for FY1988-1993. Transmission and distribution losses were projected to decline from 18 percent in FY1987 to 17 percent in FY1992 and to 15.5 percent in FY1995. 2. The FIRR calculation included direct taxes and duties on capital items, which the EIRR excluded. O&M costs were calculated as a fixed percentage (1 percent of incremental generation and 1.5 percent of incremental transmission and distribution) of capital costs net of taxes and duties. Fuel costs were calculated separately from O&M based on FY1987 fuel prices and projections to FY2000 by the World Bank.2 All benefits and costs were valued in financial terms, excluding financial charges, depreciation, and taxes, and in terms of the projected incremental sales for KESC at a tariff level of PRs1.14/kilowatt-hour (kWh) in FY1991 rising to PRs1.31/kWh in FY1995, and thereafter held constant. The EIRR was determined by valuing all costs and benefits in economic terms. Capital, fuel, and O&M costs were adjusted to remove taxes and duties. Local currency expenditures were observed to be mostly nontradables and expressed in border price terms by applying a standard conversion factor of 0.9. The incremental energy benefits were valued based on consumers’ willingness to pay (PRs1.6/kWh) and converted to border prices by applying the standard conversion factor of 0.9.3 The FIRR obtained was 11.1 percent and the EIRR 12.7 percent. B. Methodology of the PCR 3. The time-slice reestimates of the FIRR and EIRR, for the project completion report (PCR) followed the same approach as at appraisal, but used a different time-slice period because of the delays in project implementation, namely FY1991-1998. Actual information relating to capital expenditure, operating costs, incremental sales, and tariffs up to FY1998 was used, and thereafter projected. Differences between estimates were largely explained by

1 The nature of the transmission line, substation, and distribution subprojects was such that a meaningful FIRR and

EIRR for the project time-slice FY1989-1991 could not be calculated for the Project alone. A time-slice analysis, taking into account expenditures on all development and rehabilitation for KESC’s overall least-cost power development program for FY1987-1992, was instead adopted.

2 The projections from 1986, based on the World Bank’s projections for the price of crude oil, provided for an increase of 3 percent in real terms from 1987 to 1990, a further 21 percent by 1995, and another 43 percent by 2000. The actual price of crude oil increased from $13.60/barrel in 1986 to $22.00/barrel in 2000, or 62 percent.

3 Inherent in this approach to valuing benefits is the assumption that the demand for energy is supply constrained, and the electricity tariff is less than willingness to pay.

Appendix 7, page 2

underlying differences in schedule, capital invested, and incremental sales. The most significant differences were the assumptions for imputing incremental sales and economic pricing.4 C. Methodology of the PPAR 4. The time-slice approach to evaluating the financial and economic viability of a project is appropriate only to the extent that the project represents a major incremental investment and that the benefits and operating costs associated with the project cannot be readily separated from operating activities of the rest of the system. Several factors suggest that the time-slice approach was not an appropriate methodology for this sector loan: (i) the project investment represented only 17 percent of KESC’s total capital investment during FY1989-1998;5 (ii) the sub-investments, except for the 220 kilovolt transmission reinforcement, had an isolated impact on the total system; and (iii) delays in implementation in the face of growing load demand meant that efficiency improvements from the Project were outweighed by system losses generated elsewhere in KESC’s system. Under such circumstances, it is better to evaluate individual project components and assess their impact on avoiding or reducing energy losses. 5. The Operations Evaluation Mission calculated individual subproject FIRRs and EIRRs for subprojects that it visited, using material and labor cost data provided by the Water and Power Development Authority (WAPDA) for postevaluation in 1999 of Loan 824-PAK: WAPDA Tenth Power (Sector Loan) Project. Details of the calculations are prepared on a best estimate basis for the cost of cable/conductor and rehabilitated transformers, and engineering estimates for load and energy savings. The results are summarized in Table A7.1, alongside the time-slice estimates at appraisal and project completion. The project performance audit report (PPAR) results are considered indicative of the viability of components implemented under the Project.

Table A7.1: Comparison of FIRR and EIRR Estimates (percent)

Item Appraisal PCR PPAR FIRR 11.1 4.5 16.5->50 EIRR 12.7 5.7 23.7->50

EIRR = economic internal rate of return, FIRR = financial internal rate of return, PCR = project completion report, PPAR = project performance audit report.

6. Table 7.2 provides details of the FIRR and EIRR estimates for individual subprojects visited at Rustan, Mohammadi, Malir, and North Karachi by the Operations Evaluation Mission.

4 The incremental sales estimates for appraisal are based on an increase of 830 MW in generation capacity and

reduction in system losses (para. 1). Actual achievement under KESC’s power development program was 630 MW rather than 830 MW. The PCR took into account the increase in system losses from 20 percent in FY1990 to 33 percent in FY1998, but projected an increase in generation capacity after FY1998 that was attributable to generation purchases from independent power producers and WAPDA. Economic pricing for appraisal was based on willingness to pay at appraisal and the average financial tariff for the PCR. The PCR valued economic revenue benefits at 90 percent of the average revenue benefits to KESC.

5 At appraisal, project investment was expected to be about 62 percent of KESC’s total capital investment program for FY1989-1993.

Appendix 7, page 3

Table A7.2: Results of FIRR and EIRR Estimates for Subprojects

(Visited by the Operations Evaluation Mission)

Rehabilitation FIRR (%) EIRR (%)

11 kV feeder, Rustana 16.5 23.7 11 kV feeder, Mohammadib 22.7 32.0 11 kV feeder, Overhead at Malirc > 50 >50 132/220 kV Transmissiond — 27.2

— = not calculated, EIRR = economic internal rate of return, FIRR = financial internal rate of return, kV = kilovolt. a Involved addition of a 3.2 kilometers (km) underground cable and reduction of overloading of

three existing feeders by redistributing load. b Involved addition of a 3 km underground cable and reduction of overloading of three existing

feeders by redistributing load. c Involved replacing corroded overhead conductor on a 3 km feeder with new conductor. d Reinforcement including investment in new and existing substations.

7. To demonstrate the small impact of the subprojects on the overall viability of KESC, reestimates of the FIRR and EIRR are computed in Table A7.3 using the time-slice approach adopted at appraisal and project completion. Incremental sales take into account the actual increase in generation capacity of 630 MW and the deterioration in transmission and distribution (T&D) losses between FY1987 and FY1998. After FY1998, T&D losses are held constant at 34.3 percent to FY2015.6 The projected economic revenue benefits after FY2000 are evaluated at PRs9.01/kWh. The significantly higher economic tariff than at appraisal and for the PCR reflects the Operations Evaluation Mission’s finding that the average tariff paid by consumers is about twice the reported average revenue tariff to KESC. The difference reflects a surcharge paid to the Government. The economic tariff includes an upward adjustment on the average revenue paid by consumers of 15 percent to reflect consumers’ willingness to pay.7 Incremental generation and system losses are assumed to remain at the same levels to FY2015. Incremental financial revenue benefits are evaluated at a value of PRs7.86/kWh in FY2001.8 The time-slice FIRR and EIRR reestimates so obtained are respectively negative and 1.6 percent. Table A7.4 provides a summary account of the base data used for the time-slice approach at appraisal, project completion, and postevaluation.

6 Although T&D losses increased further to 40.2 percent by FY2000, this increase is attributed to nonproject factors. 7 The appraisal estimate included an upward adjustment factor of 20 percent. 8 This estimate is based on the premise that the average tariff revenue of PRs4.21/kWh for FY2001 is 55 percent of

the total electricity charge paid by consumers. The total charge paid by consumers is estimated to be about 87 percent of consumers’ willingness to pay.

Appendix 7, page 4

Table A7.4: Comparison of Base Data for Appraisal, PCR, and PPAR (Used in Time-Slice FIRR and EIRR estimates)

Year

Capital Investment (PRs million)a

Incremental Sales (GWh)

Economic Tariff (PRs/kWh) (at 2001 prices)

Appraisal PCR PPAR Appraisal PCR PPAR Appraisal PCR PPARb

1987 0.64 1988 2.22 2.74 53 6.49 1989 4.71 4.27 366 6.65 1990 3.67 5.59 775 6.86 1991 2.62 2.91 3.41 1,853 743 3.08 6.97 1992 1.28 1.27 1.78 1,853 523 1,373 3.08 3.19 6.76 1993 3.57 2.15 2,796 910 1,829 3.08 3.19 6.71 1994 3.58 3.81 2,812 1,118 1,729 3.08 3.19 6.71 1995 8.15 7.46 2,829 663 912 3.08 3.19 7.12 1996 9.21 10.26 2,829 1,052 843 3.08 3.19 7.23 1997 1.07 9.03 2,829 671 660 3.08 3.19 8.08 1998 8.59 6.28 2,829 1,520 718 3.08 3.19 7.50 1999 2,829 2,706 718 3.08 3.19 8.57 2000 2,829 3,416 825 3.08 3.19 8.65 2001 2,829 4,063 841 3.08 3.19 9.01 Total 15.14 38.35 56.78 29,117 16,642 12,385

EIRR = economic internal rate of return, FIRR = financial internal rate of return, GWh = gigawatt-hour, KESC = Karachi Electric Supply Corporation, kWh = kilowatt-hour, PCR = project completion report, PPAR = project performance audit report. a Nominal values. b The estimated net average tariff to KESC in FY2001 was PRs4.21/kWh. This rate reflects the average increase

in March 2001 of 8 percent applied to KESC’s reported average revenue tariff for FY2000 of PRs3.89/kWh. The estimate excludes additional charges paid by consumers, collected by KESC and paid to the Government, which together are assumed to equal on average 45 percent of the electricity charge paid by consumers.

Item 1997

Generation Without-Project (kGWh) 5.4 5.9 5.9 5.9 5.9 5.9 5.9 5.9 6.5 7.2 7.1 8.3 8.3 8.3 8.3Transmission and Distribution Losses (%) 18.3 19.2 20.1 21.0 22.0 23.0 24.1 25.2 26.3 27.5 28.7 29.9 31.1 32.4 35.3Revenue Sales Without-Project (kGWh) 4.39 4.7 4.7 4.7 4.6 4.5 4.5 4.4 4.8 5.2 5.1 5.8 5.7 5.6 5.3

Generation With-Project (kGWh) 5.4 5.9 6.3 6.8 7.0 8.0 8.7 8.4 8.3 8.8 8.8 9.9 9.9 9.9 9.9Transmission and Distribution Losses (%) 18.3 18.3 19.1 20.4 23.6 26.0 27.1 27.1 31.1 31.2 35.3 34.3 35.3 35.3 35.3Revenue Sales With-Project (kGWh) 4.4 4.8 5.1 5.4 5.3 5.9 6.3 6.1 5.7 6.1 5.7 6.5 6.4 6.4 6.4

Incremental Sales (kGWh) 0.0 0.1 0.4 0.8 0.7 1.4 1.8 1.7 0.9 0.8 0.7 0.7 0.7 0.8 1.1

Incremental Benefits (2001 prices) Financial Benefits (PRs billion) Incremental Revenues 0.0 0.3 1.9 4.3 4.1 7.4 9.8 9.9 5.3 5.4 4.0 4.9 5.0 6.0 4.2Economic Benefits (PRs billion) Transmission Savings a 0.0 0.0 0.2 0.2 0.2 0.2 0.3 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.4 Incremental Revenues 0.0 0.2 2.3 5.2 5.0 9.1 12.0 12.0 6.2 6.4 4.6 5.7 5.8 7.0 9.3

Incremental Costs (2001 prices) Capital Costs (PRs billion) Financial 3.7 8.5 12.9 15.5 7.8 3.5 4.0 7.5 12.9 17.1 13.6 8.6 0.0 0.0 (17.3) c

Economicb 3.3 7.6 11.4 13.6 7.0 3.2 3.6 6.4 11.1 14.7 11.7 7.4 0.0 0.0 (15.1) c

Fuel Cost (PRs billion) Financial 0.0 0.1 0.4 0.9 0.8 1.6 2.4 2.6 1.3 1.4 1.5 1.4 1.1 1.8 1.3 Economic 0.0 0.0 0.3 0.8 0.8 1.5 2.2 2.3 1.1 1.2 1.4 1.3 1.0 1.6 1.1Operation and Maintenance (PRs billion) Financial 0.0 0.0 0.3 1.3 1.2 2.1 2.9 3.2 1.9 2.1 2.5 2.7 2.9 3.8 1.9 Economic 0.0 0.0 0.2 1.2 1.1 1.9 2.6 2.8 1.7 1.9 2.2 2.5 2.6 3.4 1.7

Net Benefits (PRs billion) Financial (3.7) (8.3) (11.6) (13.5) (5.7) 0.2 0.5 (3.3) (10.8) (15.1) (13.6) (7.8) 1.0 0.4 18.3 Economic (3.3) (7.5) (9.5) (10.3) (3.6) 2.7 3.9 0.7 (7.4) (11.0) (10.3) (4.9) 2.7 2.4 22.0

Financial internal rate of return (FIRR) = -4.6%

Economic internal rate of return (EIRR) = 1.6%

KESC = Karachi Electric Supply Corporation, kGWh = 1,000 gigawatt-hours.a On existing generation.b Residual value equal to 15 percent of the sum total of capital costs FY1987-1998.c Time-slice analysis (FY1988-1998) of KESC's operations.

20001996 19981993 19991994 1995Appendix 7, page 4

Table A7.3: Financial and Economic Internal Rates of Return

20151987 1988 1989 1990 1991 1992