ASIAN DEVELOPMENT BANK PCR: PHI 22275
PROJECT COMPLETION REPORT
ON THE
FIFTEENTH POWER (SECTOR) PROJECT (Loan No. 985-PHI)
IN THE
PHILIPPINES
December 1997 CURRENCY EQUIVALENTS (as of 10 November 1997)
Currency Unit - Peso (P)
At Appraisal At Project Completion $ 0.0456 P1.00 $0.0303 $1.00 = P21.94 P33.00
ABBREVIATIONS
Bac-Man Bacon-Manito DENR Department of Environmental and Natural Resources ECC Environmental Compliance Certificate EEl Engineering Equipment, Inc. EIA Environmental Impact Assessment EIRR Economic Internal Rate of Return FIRR Financial Internal Rate of Return FUCC First United Contractors Corp. of the Philippines GDP Gross Domestic Product Mak-Ban Makiling-Banahaw NPC National Power Corporation O&M Operation and Maintenance PGI Philippine Geothermal Inc. PHESCO Philippine Electrical Services Construction Inc. PMO Project Management Office PNOC Philippine National Oil Corporation WACC Weighted Average Cost of Capital WTP Willingness to Pay
WEIGHTS AND MEASURES
V (volt) Unit of voltage kV (kilovolt) 1,000 volts A (ampere) Unit of current kVA (kilovolt-ampere) 1,000 VA W (watt) Unit of active power kWh (kilowatt-hour) 1,000Wh MW (megawatt) 1,000 kW MWh (megawatt-hour) 1,000 kWh GWh (gigawatt-hour) 1,000 MWh
NOTES
(I) The fiscal year (FY) of the Government and NPC ends on 31 December. (ii) In this Report, $S refers to US dollars. CONTENTS
Page
BASIC DATA II
MAP vii
I. PROJECT DESCRIPTION 1
II. EVALUATION OF IMPLEMENTATION 1
A. Project Components 1
B. Implementation Arrangements 4
C. Project Costs 4
D. Project Schedule 5
E. Engagement of Consultants and Procurement of Goods and Services 7
F. Performance of Consultants and Contractors 7
G. Conditions and Covenants 8
H. Disbursements 8
I. Environmental Impact 9
J. Performance of the Borrower and the Executing Agency 9
K. Performance of the Bank 10
III. EVALUATION OF INITIAL PERFORMANCE AND BENEFITS 10
A. Technical Performance 10
B. Financial and Economic Performance 11
C. Attainment of Benefits 12
IV. CONCLUSIONS AND RECOMMENDATIONS 12
A. Conclusions 12
B. Recommendations 13
APPENDIXES 14 BASIC DATA
A. Loan Identification
1. Country Philippines 2. Loan Number 985-PHI 3. Project Title Fifteenth Power (Sector) Project 4. Borrower National Power Corporation (NPC) 5. Guarantor Republic of the Philippines 6. Executing Agency National Power Corporation 7. Amount of Loan $ 160.0 million 8. PCR Number 453
B. Loan Data
1. Appraisal - Date Started 8 May 1989 - Date Completed 31 May1989
2. Loan Negotiations - Date Started 12 Oct 1989 - Date Completed 13 Oct 1969
3. Date of Board Approval 14 Nov 1989
4. Date of Loan Agreement 18 Dec 1989
5. Date of Loan Effectiveness - In Loan Agreement 18 Mar 1990 - Actual 8 Mar 1990 - No. of Extensions
6. Closing Date - In Loan Agreement 31 Dec 1993 -Actual 1 Jul 1995 - Number of Extensions 2
7. Terms of Loan - Interest Rate Variable - Maturity (years) 20 - Grace Period (years) 4
8. Disbursements
a. Dates
Initial Disbursement Final Disbursement Time Interval 15 May 1990 14 May 1996 6 years
Original Effective Date Original ClIng Date Time Interval 18 Mar 1990 31 Dec 1993 3 years and 9 months
Actual Effective Date Actual Closing Date Time Interval 8 Mar 1990 1 July 1995 5 Years and 4 months
b. Amount ($ million)
Category Last Original Net or Revised Amount Amount Undisbursed Allocation Canceled Available Amount Subloan Allocation Disbursed Balance 87.00 153.88 - 153.88 153.59 0.29 II 22.00 - - - - - III 30.00 3.84 - 3.84 3.84 - IV 3.00 - - - - - V 18.00 2.28 - 2.28 2.28 - Total 160.00 160.00 - 160.00 159.71 0.29
9. Local Costs (Financed) - Amount ($) : Nil - Percentage of Local Costs Nil - Percentage of Total Cost Nil
C. Project Data
1. Project Cost ($ million) Appraisal Estimate Actual Vathnce Foreign Exchange Cost 160.0 194.2 34.2 Local Currency Cost 40.0 37.5 -2.5 Total Cost 200.0 231.7 31.7
iv
2. Financing Plan ($ million)
Appraisal Estimate Actual
Foreign Local Total Foreign Local Total (I) Implementation Costs (a) Borrower-financed - 40.0 40.0 27.1 37.5 64.6 (b) Bank-financed 142.0 - 142.0 157.4 - 157.4 (c) Other External Financing - - - - - (d) Total 142.0 40.0 182.0 184.5 37.5 222.0 (ii) IDC Costs (a) Borrower-financed - - - 74 - 74 (b) Bank-financed 18.0 - 18.0 2.3 - 2.3 (c) Other External Financing - - .. - - - (d) Total 18.0 - 18.0 9.7 - 9.7 Total 160.0 40.0 200.0 194.2 37.5 231.7
3. Cost Breakdown by Project Components ($ million)
Appraisal Estimate Actual Foreign Local Total Foreign Local Total (a) Geothermal Development 87.0 19.0 106.0 180.7 37.5 218.2 (b) Interisland Connections 22.0 5.0 27.0 - - - Operation & Maintenance Improve- (c) 30.0 15.0 45.0 3.8 38 38 ment (d) Small Island Power Supply 3.0 1.0 4.0 - - - (e) IDC on Bank loan 18.0 - 18.0 9.7 9.7 9.7 (f) Total 160.0 40.0 160.0 194.2 37.5 231.7
4. Project Schedule Appraisal
Estimate Actual
A. GeothtrnaI Power Development
(a) Subproject Appraisal and Selection First Mar 1990 Feb 1992 Last Jun 1990 Jul 1993 (b) Procurement Start Aug 1989 Dec 1989 Finish Jul 1990 Sep 1992 (c) Manufacture and Delivery First Aug 1990 Aug 1993 Last Nov 1992 Nov 1994 (d) Civil works Construction First Nov 1991 Apr 1994 Last Mar 1993 Feb 1998 (e) Equipment Installation First Nov 1991 May 1994 Last Mar 1993 Feb 1998 V
(f) Testing and Commissioning First Feb 1992 Mar 1994 Last Jul 1993 Feb 1998
B. Iriterisland Connections'
Feasibility Studies Oct 1989 n.a.2 (a) (b) Recruitment of Consultants May 1990 n.a.
Detailed Design and Survey Oct 1990 n.a. (c) (d) Procurement May 1991 na.
Manufacture and Delivery First Mar 1992 n.a. (e) Last Jul 1992 n.a.
Installation and Erection First Dec 1992 na. (f) Last Feb 1993 na.
Testing and Commissioning First Feb 1993 na. (g) Last Apr 1993 na.
C. O&M Improvement3
(a) Feasibility Studies Mar 1990 n.a. (b) Subproject Appraisal and Selection Dec 1989 n.a. (c) Recruitment of Consultants Jun 1990 na. (d) Procurement First Jun 1990 Aug 1990 Last Dec 1991 Oct 1991 (e) Supply and Installation First Dec 1990 na. Last Dec 1992 na.
D. Small Islands Power Supply4
Sep 1989 na. (a) Subproject Appraisal and Selection Dec 1989 na. (b) Procurement First Jul 1990 na. (c) Manufacture and Delivery Last May 1991 na.
First Nov 1990 na. (d) Installation and Erection Last Aug 1991 na.
Testing and Commissioning First Feb 1991 na. (e) Last Nov 1991 na.
1 Cancelled at the request of NPC.
2 na. = not applicable
2 Of the four components, Cl: Vehicles and C4: Training Center were canceled. Only the procurement of Non- Proprietary (C2) and Proprietary Spare Parts (C3) was undertaken.
Canceled at the request of NPC.
vi
D. Data on Bank Missions
Name of No. of Person- Specialization
Mission Date Persons days of Members1
Fact-finding 22 Feb- 4 40 a, b, d, e 3 Mar 1989
Appraisal 9-31 May 1989 6 138 a, b, c, d, e, f Review (First) 6-17 Aug 19902 2 12 a, g Review 21 Nov-2 Dec 1994 2 8 a, g Review 1 5-23 Jan 1996 1 3 a
1 a - senior project engineer, b - senior country officer, c - counsel, d - financial analyst, e - energy specialist, f - consultant, g - Sr. assistant (project administration).
2 Together with Loan No. 914-PHI: Fourteenth Power (Sector) Project.
Together with Loan No. 914-PHI: Fourteenth Power (Sector) Project and Loan No. 1288-PHI: Power Transmission Project.
VII
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97- 2564R I. PROJECT DESCRIPTION
1. The main objective of the Project was to support the power system expansion program of the National Power Corporation (NPC). The Project was designed to (i) provide additional power generating capacity with the construction of power plants consisting of modular power generating units that would further harness geothermal resources at selected locations in the Philippines;1 (ii) interconnect isolated island networks, many of which depended on high-cost diesel power generation, with N PC's main power grids to allow increased use of renewable indigenous resources for power generation, reduce reserve capacity requirements, and gain economies of scale benefits through integrated least-cost power generation expansion; (iii) improve operation and maintenance (O&M) of NPC's power generation and transmission facilities through the provision of spare parts and equipment, including some for a proposed new training center in Bataan; and (iv) construct small diesel power generating stations, selected from NPC's countrywide program, to address regional disparities in power supply, thus improving the quality of life in areas not served by N PC's main grids.
2. The Bank adopted a sector loan approach for the Project since (i) the Project was in line with the power sector policies and objectives of the Government and the Bank that gave importance to the use of indigenous energy sources for power generation, interconnection of isolated power networks, improving O&M, and improving the quality of life through the provision of electricity to isolated island communities; (ii) NPC's power system expansion program was considered well-conceived and represented the least-cost expansion strategy; (iii) NPC had shown its capability to undertake a sector loan project;2 and (iv) the subprojects envisaged under the Project were diverse, and provided a reasonable balance of power system expansion activities planned by NPC.
U. EVALUATION OF IMPLEMENTATION
A. Project Components
3. In line with the sector loan approach, adequate flexibility was provided for in the Project scope:
(i) Part A: geothermal power development through the installation of about six 20- megawatt (MW) modular geothermal generating units to be selected from NPC's countrywide program for 20 such units;
(ii) Part B: interisland connection through construction of one or two power transmission systems linking selected islands to the Luzon grid;
Geothermal fields under consideration were Maibarara and Mak-Ban II (Laguna), being developed by Philippine Geothermal Inc. (PGI), and Palinipinon II (Negros Oriental), Bacon-Manito II (Albay I Sorsogon), Mt. Apo I (Davao del Norte), Pinatubo (Zambales) and Natib (Bataan), being developed by Philippine National Oil Corporation (PNOC). Although Loan No. 728-PHI:Second Power System Development, for $33.0 million, approved on 20 December 1984, and Loan No. 823-PHI:Thini Power System Development, for $92.0 million, approved on 18 December 1986, had sector loan characteristics with several subprojects in various areas of NPC's activities, the first sector loan to NPC was Loan No. 914-PHI: Fourteenth Power, for $120.0 million, approved on 27 October 1988. 2
(iii)Part C: execution of about eight subprojects, comprising equipment and spare parts required for adequate O&M of NPC's power generation and transmission facilities; and
(iv) Part D: construction of about 15 small diesel power plants to be selected from NPC's countrywide program to augment power supply in areas outside NPCs main grids.
4. Based on the sector loan concept, it was agreed that NPC would adopt a phased approach to appraise in detail the various subprojects to be included in each part using technical, economic, and environmental criteria agreed upon with the Bank. NPC accorded Parts A and D of the Project high priority and, on 21 June 1989, the Bank approved advance procurement action for the modular geothermal power generating units in Part A and the diesel power generating units in Part 0 to speed up their manufacture and installation.
1. Part A: Geothermal Development
5. Part A supported harnessing geothermal resources that were given top priority in NPC's power generation program for 1989-1997 that consisted of 19 generation projects totaling 3,802 MW.1 In close coordination with the Philippine National Oil Corporation (PNOC) and Philippine Geothermal Inc. (PGI), NPC selected in Luzon, Negros and Miridanao seven promising locations 2 estimated to yield at least 400 MW at the first stage. Steam development at these locations was under way during appraisal, with PNOC and PGI undertaking the necessary surveys and drilling. The status varied from site to site: at some, such as Maibarara, the development was practically completed; at others, such as Makiling-Banahaw (Mak-Ban II), well advanced; and at others, such as Natib, the first drilling had been just completed. Based on the resource assessments prepared by PNOC and PGI, NPC formulated the first-stage package of 20 modular units of the standard size of 20 MW each. NPC was assisted in this work by geothermal specialists from ltal? where the modular unit approach had found wide application.
6. In its draft appraisal report for Part A, submitted to the Bank on 16 February 1990, NPC recommended installing four 20-MW modular geothermal generating units in the Mak-Ban geothermal fields operated by PGI about 70 kilometers (km) south of Manila. Three units were to be installed at a new power plant about 250 meters (m) east of the existing geothermal Plant A4 in the Mak-Ban Bulalao geothermal area, and one unit at a new power plant at Mak-Ban Maibarara geothermal area on the western flank of Mt. Makiling. NPC also recommended installation of one 20-MW unit at Botong and one 20-MW unit at Cawayan in PNOC's Stage II development of the Bacon-Manito (Bac-Man II) geothermal area that lies along the volcanic belt traversing the Bicol Peninsula in Albay and Sorsogon provinces, about 600 km southeast of Manila. The existing Bac-Man I power plant in Sorsogon consisted of a two-unit 110-MW geothermal power plant.
Ten geothermal power plants totaling 1858 MW, three coal-fired power plants totaling 1.200 MW, five oil-fired power plants totaling 519 MW and one 225-MW hydropower plant. 2 Maibarara (20 MW), Mak-Ban 11(60 MW), Palimpinon 11(80 MW), Bacon-Manito (60 MW), Mount Apo (60 MW), Pinatubo (60 MW) and Natib (60 MW). Linita Nazionale Geotermica, a subsidiary of Erite Nazioriale per I'Energia Elettrica (ENEL), the national power utility of Italy. Before Project implementation there were arready three geothermal plants (A, B and C) in operation, each consisting of two 55-MW generating units, in the Mak-Ban geothermal area. 7. On 21 November 1990, NPC advised the Bank that, based on PGI's analysis, steam availability at the Mak-Ban Bulalao and the Mak-Ban Maibarara geothermal areas was insufficient for four additional 20-MW units. Therefore, based on the forecast load growth in Mindanao (which depended on 896 MW of hydropower plants and 181 MW of barge-mounted gas turbines and diesel power plants), NPC considered the possibility of locating these four generating units at the Mt. Apo I geothermal field in Davao del Norte, Mindanao, that PNOC was developing. However, because of the need to undertake a more detailed environmental and social impact assessment of this proposal 1 and the resulting implementation delay, NPC, in December 1991, continued to conduct further feasibility studies at Mak-Ban, in coordination with PGI. Following these studies, NPC finally opted to locate the four generating units at Mak-Ban Bulalao. Since the power generating units to be procured were modular in nature, NPC had, meanwhile, continued with their procurement arid the Bank had approved contract award for the supply of six 20-MW units in August 1991 (see Appendix 1).
8. The resulting implementation plan, detailed in NPC's final appraisal report dated Apnl 1992, was to construct, as a first step, a two-unit 40-MW standby power plant (Plant D) at Mak-Ban Bulalao. The units were to operate when one or more of the existing units were shut down for maintenance; therefore, only additional piping and valves were required rather than new wells for additional steam. Plant D was to be located immediately east of NPC's existing Plant A and connected to it by a 69- kilovolt (kV) power transmission line. As a second step, NPC was to construct another two-unit 40-MW power plant (Plant E) for base load operation backed by the installation of more extensive steam supply faculties, including the drilling of new wells. Plant E was to be connected to Plant C through a 230-ky power transmission line. It was argued that, although this approach at Mak-Ban would increase the steam extraction rate by 12 percent, thus reducing the lifetime for which the power generating facilities (including the 330-MW of existing plant) could be operated at full load, it was justifiable given that the Philippines was suffering from severe electric power shortages. NPC proceeded to install the four 20- MW generating units at Mak-Ban on this basis.
2. Part B: Interisland Connections
9. NPC interconnected Leyte with Samar in 1983, Negros with Panay in 1990,2 and Negros with Cebu in 1993. The Leyte-Cebu (Stage I) and Leyte-Luzori interconnections, now under construction, are expected to be completed by 1998. During appraisal, system interconnections between Luzon and the major islands of Mindoro, Catanduanes, Masbate, and Marinduque were envisaged as potential candidates for financing under Part B of the Project. However, NPC's 1991 system planning studies showed that these interconnections would not be economically viable until after the year 2000. ln fact, they are not included even in NPC's 1997 Power Development Program that provides for the Leyte-Bohol, Leyte-Cebu (Stage II), and Leyte-Mindanao3 interconnections to be completed by 1999, 2000, and 2002 respectively. On 14 October 1991, NPC requested cancellation of Part B and reallocation of loan proceeds to have adequate funds to procure and install the six power generating units in Part A. On 25 November 1991, the Bank approved the cancellation of Part B and selected components of other parts of the Project (see paras. 11 and 12).
in September 1991, representations were made with the Philippine Government, NPC, and the Bank by non- governmental organizations pointing out that the proposed site at Mt. Apo was ecologically rich being a National Park, an ASEAN heritage site, and the ancestral homeland of the indigenous Bagobo, Ata, Kiangan, and Kaulos peoples. Loan No. 666-PHI: Negros-Panay interconnection Project, for $43.8 million, approved on 12 December 1983. TA No. 2653-PHI: Leyte-Mincianao Interconnection Engineering Project (Feasibility Study), for $575,000 and Loan No. 1471-PHI: Leyte-Mindanao Interconnection Engineering Project (Marine Survey and Detailed Engineering Design), for $5.3 million, both approved on 30 September 1996 4
3. Part C: Operation and Maintenance Improvement
10. Part C provided spare parts and equipment to improve NPC's O&M of selected power system facilities and for a proposed new training center at Batsan. Originally, NPC proposed to divide this part into the following components:
(I) Part Cl: Utility vehicles for system O&M;
(ii)Part C2: Nonproprietary spare parts, primarily of an electrical nature, including potential transformers, current transformers, air-break switches, electric motors, relays, and instruments;
(iii)Part C3: Proprietary spare parts from designated suppliers of existing equipment used for system O&M;
(iv) Part C4: Provision of equipment to operate nine training laboratories and a training simulator at the proposed Bataan training center.
11. NPC submitted appraisal reports for Parts Cl, C2, and C3 to the Bank by the end of September 1990, but following the award of contract to supply the six generating units in Part A (see para. 7), NPC requested cancellation of Parts Cl (vehicles) and C4 (training center). No procurement of Bank-financed goods and services under these components had taken place up to then. With respect to Parts C2 and C3, the Bank had already approved contract awards totaling about $7.1 million, but NPC requested that about $2.6 million of the contract awards be charged to a previous loan (Third Power System Development Project, see para. 2), to use loan savings under that loan fully, and by that limit the allocation under Part C to $4.5 million. The Bank agreed to this on 25 November 1991. Subsequently, the Bank agreed to a further request from NPC to reallocate additional funds from Part C to Part A and reduce the allocation for Part C to $3.8 million. A list of both proprietary and nonpropri- etary spare parts purchased for Parts C2 and C3 is in Appendix 2.
4. Part D: Small Island Power Supplies
12. The Bank reviewed NPC's bid documents to provide 47 small diesel power plants, in sizes of 150 kilowatts (kW), 250 kW and 500 kW, to 32 islands and approved them on 10 January 1990. However, in April 1990, NPC informed the Bank that NPC would not continue with the bidding because it could have a loan arranged by the Bank of America to finance the diesel power plants. The terms and conditions of that loan were more competitive as it included a 35 percent grant element provided by the United Kingdom.' On 25 November 1991, the Bank agreed to NPC's request to cancel Part D and reallocate the funds ($3 million) to Part A.
B. Implementation Arrangements
13. NPC, as the Executing Agency, set up a Project Management Office (PMO) in January 1990 to coordinate implementation of the Project. A Vice President of NPC, who was made the Project Director, headed the PMO. The Project Director was responsible for selection of the Project components, based on appraisal reports prepared by NPC staff. Full-time Project Managers,
Under the financing arrangements, the supply of the small diesel power plants was awarded to Dale Electric of the United Kingdom.
5
responsible for the day-to-day implementation of the various components, reported to the Project Director. NPC undertook appraisals of the various parts with Bank guidance, and submitted to the Bank appraisal reports for Parts A and C, for which proceeds of the Bank loan were used.
C. Project Costs
14. The total cost of the Project, as implemented, amounted to $231.7 million equivalent, whereas the appraisal estimate was $200 million (see the summary in Table 1).
Table 1: Appraised and Actual Project Cost ($ million in current prices)
Appraisal Actual Part Foreign Local Total Foreign Local Total A. Geothermal Power Development 87.0 19.0 106.0 180.7 37.5 218.2 B. Interisland Connections 22.0 5.0 27.0 - - C. Operation and Maintenance 30.0 15.0 45.0 3.8 - 3.8 Improvement D. Small Island Power Supply 3.0 1.0 4.0 - - E. Interest During Construction 18.0 - 18.0 9.7 - 9.7 Total 160.0 40.0 200.0 194.2 37.5 231.7
15. The increase in foreign exchange costs for Part A was due to the (i) contract award for the supply of the six power generating units being the equivalent of $145.7 million (about 67 percent higher than the appraisal cost estimate of $87 million); (ii) need to amend the contract because of the proposed location of four units reverting to Mak-Ban Bulalao from Mt. Apo (about $3 million); (iii) strengthening of the Japanese yen, in relation to the US dollar 1 (about $23 million); and (iv) extension of the contract to install one 20-MW generating unit at Botong plant (about $9 million). As a result, the actual foreign exchange cost increased to $180.7 million equivalent (208 percent of the appraisal estimate). Partly to accommodate this increase, the Bank agreed in November 1991 to cancel Parts B, Cl, C4, and D and reallocate loan proceeds.
D. Project Schedule
16. The actual implementation schedule and that envisaged at appraisal are compared in Appendix 3; key implementation dates for Parts A, C2 and C3, which were Bank-financed, are also shown in that Appendix.
17. The Project got off to a good start with the procurement of spare parts for Parts C2 and C3 commencing and proceeding on schedule. A draft appraisal report for Part A, which considered installing two 20-MW generating units each at Plant D and Plant E in Mak-Ban and one 20-MW generating unit each at Botong and Cawayan plants, was issued in February 1990. Subsequently, the question of steam availability at Mak-Ban caused NPC to reconsider this location and conduct studies
About 96 percent of the contract was denominated in Japanese yen () and 4 percent in Philippine peso (P). At appraisal the average monthly exchange rate was $1 = 138. The yen then depreciated to about $1 = 159 n April 1990 and subsequently gradua'ly appreciated to about $1 = 84 in June 1995. 6 on the possibility of installing the four units at the Mt. Apo field. Eventually, environmental and social concerns at the Mt. Apo site caused NPC to revert to the Mak-Ban site after resolving the question of steam availability (see paras. 7 and 8). The final appraisal report for Part A was submitted to the Bank in April 1992, almost two years behind the schedule made at appraisal.
18. Although the Bank approved advance procurement action in June 1989, the issuance of bid documents for Part A was delayed because NPC first preferred to bid for twenty 20-MW modular units simultaneously, including four units to be funded by the World Bank and ten units to be funded by other sources, besides the six Bank-financed units. However, because such a bidding would create problems with respect to eligibility criteria, in February 1990 NPC called for bids for the six Bank- financed units separately, about six months later than the appraisal schedule of August 1989. Following two extensions to the bidding period, NPC opened the bids on 15 June 1990. Although NPC received only three bids, the evaluation process was protracted due to representations made by one bidder and bid prices being much higher than the appraisal estimate. Despite several reminders to NPC, the Bank did not receive the bid evaluation report until 25 May 1991. Because of further representations by the same bidder, the Bank could not approve contract award until 22 August 1991 (13 months later than the appraisal schedule.)
19. The implementation schedule for Part A agreed upon during loan appraisal envisaged commissioning of the geothermal units between February 1992 and July 1993. The delay in deciding the location of four of the six units required substantial revision of the implementation schedule. While NPC's April 1992 appraisal report envisaged the Cawayan and Botong plants to be commissioned on schedule in June 1993, the commissioning of Plant D and Plant E was rescheduled for January and May 1994, respectively. Eventually, NPC commissioned the Cawayan unit on 21 March 1994 (9 months later than NPC's appraisal estimate and 17 months later than the Bank's appraisal estimate), and the four units at Plant D and Plant Eon 15 September 1995 and 20 May 1996, respectively (14 and 23 months later than Bank's appraisal estimates). The sixth unit, that at Botong, is scheduled for commissioning in April 1998, 4 years and 9 months later than the Bank's appraisal estimate.
20. While some implementation delays at all four locations were caused by inclement weather, including several typhoons in 1993 and 1994, other delays can be attributed to (i) late revision, delivery, and, sometimes unavailability of construction drawings; (ii) late delivery of some electromechanical equipment; (iii) the need for extra works not envisaged previously; (iv) pilferage of materials; (v) coordination and interfacing difficulties between civil and electro-mechanical contractors; and (vi)late delivery of steam supply. A dispute between NPC and the civil works contractor, First United Contractors Corporation of Philippines (FUCC), regarding payment for earthworks (see para. 27), also caused serious delay at the Botong plant where installation of the generating unit could start in July 1997 (see para 26).
21. Delay in payment for land acquisition was particularly a cause for delay at Mak-Ban because affected landowners sometimes prevented construction personnel from entering the site of Plant 0 in 1994 and 1995; they also prevented the construction of the steam pipeline to Plant E from October 1995 to March 1996. Twenty-two affected households with a population of 145 persons, consisting mostly of laborers and construction workers, security guards, farm workers, sari-sari store operators, and their dependents, were compensated. Eighteen households were resettled permanently. The total compensation cost was P3 million. 7
E. Engagement of Consultants and Procurement of Goods and Services
22. Before Project appraisal, geothermal specialists from Italy had assisted NPC prepare engineering studies and bid documents for the twenty 20-MW modular units (see para. 18). During Project appraisal, it was agreed that there would be no need to engage consultants to assist NPC with either construction or installation work for Parts A and D because NPC had the necessary technical experience in implementing both geothermal and diesel plants. It was also agreed that NPC would not need consultants to assist in the procurement of vehicles or spare parts under Parts Cl, C2, and C3. However, it was agreed that NPC would require some assistance from consultants in the laying of submarine cables in Part B and in the training center design and implementation in Part C4; since it did not implement these parts, NPC did not engage the services of any consultants for them.
23. NPC called bids for twenty 20-MW modular geothermal generating units in three separate packages. The Bank loan financed one package, consisting of six units to be supplied, installed, and commissioned on a turnkey basis. 1 International competitive bidding with postqualification was followed for this package, in accordance with the Bank's Guidelines for Procurement. 2 Civil works construction in Part A was carried out by local contractors engaged by NPC according to the Government's standard procedures and financed by NPC. Spare parts were procured using international shopping procedures for non-proprietary spare parts in Part C2, and by direct purchase for proprietary spare parts in Part C3, following the Bank's Guidelines for Procurement.
F. Performance of Consultants and Contractors
24. Before appraisal, Italian consultants (see para. 5) assisted NPC formulate the future geothermal development in the Philippines based on their extensive experience of geothermal development in their own country. They recommended the use of modular units of a standardized size of 20 MW each, indicating advantages in terms of cost and time over conventional custom-built plants with 55-MW units. It was expected that the economies of scale benefits of the bigger custom-built plants would be more than offset by the reduced unit costs resulting from manufacture of standardized modular units, and that the construction period would be reduced as welt. A review of the adaptability of the modular approach to the geothermal fields in the Philippines by a staff consultant from New Zealand during appraisal confirmed its viability. Unfortunately, both the costs and construction period eventually proved to be significantly underestimated.
25. Four main contractors were involved in construction of the power plants in Part A. They were (i) the Japanese joint venture, responsible for the manufacture, supply, and installation of the electromechanical equipment; (ii) FUCC, responsible for most civil works at the Cawayan power plant and part of the Botong power plant; (iii) Philippine Electrical Services Construction Inc. (PHESCO), responsible for completion of civil works at the Cawayan and Botong power plants; and (iv) Engineering Equipment Inc. (EEl), responsible for civil works of Plant D and Plant E at Mak-Ban. PGI was contractually responsible for the supply of steam to Plant D and Plant E, while PNOC took that responsibility for the Cawayan and Botong power plants.
The two other packages were (i) four units bid in accordance with World Bank Procurement Guidelines, and (ii) ten units bid in accordance with NPC's Procurement Guidelines. Three bids were received from two member countries. In August 1991, the Bank approved award of contract to a Japanese Consortium consisting of Mitsubishi, Marubeni, and Kanerriatsu.
26. The Japanese joint venture performed satisfactorily by supplying and installing the equipment as specified. Among the local civil works contractors, EEl performed satisfactorily in constructing Plant D and Plant E. The main cause for delay in completing the Botong plant was the need to rebid the civil works contract after FUCC abandoned the site. FUCC started work at the site in August 1992 and encountered a hard rock formation posing problems to its earthmoving equipment in September 1992. A dispute arose as to the rates to be paid for excavation in that rock. As a result, FUCC abandoned the almost completed Cawayan site and the Botong site on 1 November 1993. Through legal action, FUCC attempted to stop NPC from taking over the works, but an amicable settlement was reached through arbitration and NPC was eventually able to rebid on 19 April 1995 for completion of the civil works at these two sites. NPC gave PHESCO, the lowest evaluated bidder, notice to proceed on 8 September 1995. Following several extensions to the contract, due mainly to bad weather, PHESCO's contract expired in May 1997. The works are not yet complete at Botorig, and as a result NPC imposed on PHESCO liquidated damages; PHESCO is contesting this. Nevertheless, PHESCO is carrying out the remaining civil works simultaneously with the installation of the last generating unit, and expects to complete the works by April 1998.
27. Steam supply from the PNOC geothermal fields to the Cawayan plant was not adequate dunng commissioning because of silica deposition in the wells. Therefore, the plant could generate only 15 MW (75 percent of capacity). However, PNOC reworked the wells and drilled additional ones so that by 1 June 1995, about 13 months after start-up, the plant could generate at full capacity. Steam supply from the PGI fields at Mak-Ban has been satisfactory although delays were encountered because the local population did not allow PGI to lay the necessary pipes at times (see para. 21).
28. Manufacturers engaged to supply spare parts for Parts C2 and C3 performed generally satisfactorily.
G. Conditions and Covenants
29. All conditions of loan effectiveness were achieved ahead of schedule. As a result, the loan became effective in March 1990. As shown in Appendix 4, NPC substantially complied with the Bank's loan covenants. One exception was the rate of return on average net revalued fixed assets in1995 when 7.3 percent was achieved, slightly below the covenanted target of 8 percent. NPC submitted adequate quarterly progress reports throughout the project execution.
30. Another exception was the failure to solve social issues in a timely manner. At Plant D landowners set up barricades six times between January 1994 and May 1995 demanding payment for lands acquired for the construction of the plant. The steam supply at Plant E was delayed because of right of way problems that were eventually solved in March 1996. NPC gave compensation according to its corporate guidelines (see para. 21).
H. Disbursements
31. Contract awards for Parts C2 and C3 began in August 1990 with disbursements starting soon afterwards. Disbursements for Part A started only in late 1991 following contract award for the six generating units in August 1991. Major disbursements for this contract occurred in 1993 and 1994. With the cancellation of Parts B, Cl, C4, and D and a reduction in Bank funding of Parts C2 and C3, the actual disbursement schedule substantially deviates from that estimated at appraisal (see summary in Table 2 and a detailed comparison in Appendix 5). Table 2: Disbursement Performance ($ million) Year ppraisal Estimate Actual Disbursements 1990 32.0 (20%) 027
1991 48.0 (30%) 11.82
1992 48.0 (30%) 6.86
1993 32.0 (20%) 43.20
1994 85.81
1995 9.53
1996 2.23
Total 160.0 (100%) 159.71
I. Environmental Impact
32. The purchase of nonproprietary and proprietary spare parts for Parts C2 and 03 did not have any significant impact on the environment. For the geothermal power generating units in Part A, NPC prepared an environmental impact assessment (EIA) to meet the requirements of the Bank and the Department of Environment and National Resources (DENR). DENR is responsible for issuing an environmental compliance certificate (ECC) before construction starts on any environmentally critical project. The EIA covered the steam gathering system, construction and operation of the geothermal power plants, and the associated transmission line facilities. DENR issued the ECC for Cawayan and Botong on 13 January 1992, and for Plants D and E on 29 June 1992 (after the Location of the four units at Mak-Bari had been decided).
33. Mitigating measures incorporated in the design and operation of the geothermal power plants to minimize adverse effects include (i) ducting of uncondensed gaseous effluents to a cooling tower for further condensation before discharge into the atmosphere, (ii) reinjection of power plant effluents such as cooling tower blowdown into the geothermal reservoir, and (iii) storage of toxic solid wastes in a special repository after mixing with cement. Because of these measures, the operation of the plants is considered environmentally sustainable.
J. Performance of the Borrower and the Executing Agency
34. NPC, as the Executing Agency, was responsible for appraising Project components proposed for Bank financing and undertook the necessary studies. The appraisal of Part A took longer than anticipated, because of the need to resolve the location for four of the six geothermal units.
35. NPC provided all local and part of the foreign funds, and other resources for implementing Part A. In addition, NPC provided in-house management and technical services to supervise civil works and the erection of equipment in Part A. The difficulties that NPC faced in locating the geothermal power generating units were partly because NPC had to rely on analyses provided by PGI on steam availability. Through its own choice, NPC did not have the benefit of a consultant to assist in Project implementation. However, NPC's performance in project management and coordination could have been better, NPC could have avoided some delays with timely provision of construction drawings and planning of interface work between civil and electromechanical contractors. NPC should also have (i) resolved all land acquisition problems at Mak-Ban before allowing civil works to commence (as required in the Loan Agreement), thus avoiding the delay due to contractors being unable to enter the 10 site (see para. 21), and (ii) better defined the specific scope of civil works required for the Botong unit at Bac-Man II so that the delay due to the protracted dispute and subsequent litigation could have been avoided (see pars. 26) NPC undertook the procurement of nonproprietary and proprietary spare parts for Parts C2 and C3 in a satisfactory manner.
K. Performance of the Bank
36. The Bank generally responded satisfactorily to the requirements of the Project. The Bank provided guidance to NPC on the appraisal report format and economic analysis methodology for Part A. The review of tender documents and subsequent bid evaluation reports for the six geothermal units under Part A was attended to in a timely manner although there were protracted representations from one bidder. The procurement of nonproprietary and proprietary spare parts for Parts C2 and C3 required the Bank to process about 150 packages for disbursement of loan funds individually. This could have been avoided if the Bank had arranged for NPC to operate an imprest account. The Bank fully used the flexibility inherent in the sector loan approach by deleting Part B (when NPC's appraisal showed that the proposed interisland connections might become economically viable only after the year 2000) and Part C (when NPC was able to arrange a more favourable bilateral financing for the small diesel power plants), and by using the loan savings to help meet the higher-than-estimated cost of Part A. NPCs respective requests for the cancellation of components and reallocations of loan proceeds were processed promptly. Although the Bank conducted formal review missions only in August 1990, December 1994, and January 1996, the proximity of the Bank to NPC Headquarters allowed a close monitoring of Project implementation.
Ill. EVALUATION OF INITIAL PERFORMANCE AND BENEFITS
A. Technical Performance
37. To date five of the six units have been put into operation (two units each at Plant 0 and Plant E in Mak-Ban and one unit at the Cawayan plant in Bac-Man II) with a total installed capacity of 100 MW. The sixth unit at Botong is due for commissioning by April 1998. Table 3 summarizes the generation statistics for each plant.
Table 3: Generation Unit Plant Factors (percent) Bac-Man II Mak-Ban
Cawayan Plant D Plant E
Year Average Range of Average Range of Average Range of Plant Monthly Plant Monthly Plant Monthly Factor Plant Factor Factor Plant Factor Factor Plant Factor
1994 52 5-71
1995 55 0-97 62 31-97 - -
1996 68 0-100 61 20-100 77 32-100 1997 (January to June) 87 75-100 76 55-100 87 46-100 11
38. The first power plant to come into operation was the 20-MW Cawayan plant in March 1994, but its output was limited to 15 MW due to steam supply constraints (see para. 27). The plant was not operational for one month in 1995 because of typhoon damage to the plant, and for two months in 1996 due to landslide damage to the steam pipes.
39. The first 20-MW unit at Plant D came into operation on 7 July 1995 and the second one on 7 August 1995. Full-load generation of both units was achieved in March 1996. The 20-MW units at Plant E became operational on 2 and 9 April 1996. As mentioned in para. 8, Plant D was expected to serve as a standby that would be operated when any of the existing plants needed to be shut down for maintenance, and Plant E was expected to operate as a base load plant. However, in practice, due to technical problems with the existing base-load plants (Plants A, B and C), Plant D and Plant E were operating as base-load units with a combined average plant factor of 81 percent in the first eight months of 1997.
B. Financial and Economic Performance
40. The financial and economic viability of the as-built Project was analyzed based on conditions prevailing in mid-1997 when the Project was substantially complete (see Appendix 6). All costs and benefits were expressed in constant 1997 prices, applying the Philippine Consumer Price Index to local currency expenditures and the international Producer Price Index (G-5 MUV Index 1) to foreign exchange expenditures incurred between 1991 and 1997. A standard conversion factor of 0.82 was used in the economic analysis. Power generation figures were based on actual generation up to June 1997, and the plant generation estimates presented in NPC's 1997 Power Development Program for the period 1998 to 2010. The latter estimates are only about 70 percent of the actual generation in 1997, and therefore conservative.
41. At Project appraisal, the financial and economic analyses were done using a time-slice approach based on NPC's Power Expansion Program for the period 1989-1997. The only parts implemented under the Project were Part A (six modular geothermal units), and Parts C2 and C3 (non- proprietary and proprietary spare parts). Also, because of the 1992-1993 power crisis, and the subsequent entrance of the private sector into the power generation business, 2 the power development program changed drastically from that envisaged at Project appraisal. Therefore, a time-slice approach is not considered appropriate to assess the financial and economic performance of the Project as implemented. Also, because of the cancellation of Parts B, Cl, C4, and D, the analysis in Appendix 6 takes into account only Part A. One cannot meaningfully quantify the benefit of Parts C2 and C3 consisting of the procurement of spare parts. The financial analysis of Part A gives a financial internal rate of return (FIRR) of 10.1 percent. This is considered satisfactory compared with the weighted average cost of capital (WACC) of 5.2 percent. The economic internal rate of return (EIRR) is also considered satisfactory at 14.7 percent, compared with the opportunity cost of capital of 12 percent.
42. Steam prices in the steam purchase agreements between NPC and PGI, and NPC and PNOC have been assumed to increase at the pace of general inflation. 3 Should there be an adverse change in steam availability from 1998 onwards, the FIRR will match the WACC when annual steam
Manufacture Unit Value Index of the G-5 countries consisting of France, Germany, Japan, United Kingdom and United States. Based on the President of the Philippines' Executive Order No. 215 of 10 July 1987. subsequently legislated as Republic Act No. 6957 of 9 July 1990. This is a conservative assumption, as NPC is in the process of renegotiating downwards its steam prices with PGI and PNOC. 12 availability is reduced to 73 percent of the projected generation; the EIRR would decrease to 12 percent if the steam availability is reduced to 83 percent.
C. Attainment of Benefits
43. NPC's peak demand and electricity sales increased at average annual rates of 6.1 percent and 5.8 percent, respectively, from 1988 to 1997, compared with the appraisal forecast of 7.9 percent for both parameters (Appendix 7). These lower actual growth rates can be attributed to the severe power supply shortages that arose due to generating capacity deficits from 1989 to 1993. At the height of the power crisis in 1992 and 1993, Luzon experienced brownouts of 4-8 hours per day, and Mindanao up to 12 hours. These brownouts caused unemployment and economic losses estimated at $600 million to $800 million a year, equivalent to about 1.5 percent of the annual gross domestic product (GDP). Due mainly to the power crisis, the country's GOP growth fell from 6.2 percent in 1989 to -0.6 percent in 1991 and 0.3 percent in 1992. The solution of the power crisis in 1994 can be attributed largely to the Government's successful efforts to mobilize private sector investment in power generation. With the stabilization of the power situation in 1994, the economy posted increasing annual GDP growth rates, reaching 5.7 percent in 1996. The Project benefits, which are evident from the financial and economic analyses, have contributed toward the economic upturn. The Project has also helped reduce oil and coal dependence as it uses an indigenous energy source. The Project has brought the geothermal power generating capacity in NPC's grids up to 1,303 MW, representing 12 percent of the total installed capacity in 1996 and making the Philippines the second largest geothermal power producer in the world.1
IV. CONCLUSiONS AND RECOMMENDATIONS.
A. Conclusions
44. The sector loan approach provided adequate flexibility to deal with unforeseen circumstances and allowed to adjust the Project scope accordingly. This proved to be particularly important when faced by the major cost overrun on the geothermal power units in Part A.
45. Part B of the Project was canceled because the potential interisland connections were found by NPC not to meet the subproject selection criteria agreed with the Bank, particularly the economic viability due to the small loads involved compared with the required investments. Parts C2 and C3 were implemented successfully and contributed to improving the O&M of NPC's power plants and transmission lines. Parts Cl and C2 were canceled to bridge the financing needs of Part A. Part D was canceled because NPC received better financing terms from bilateral sources for the small diesel power plants. As a result, the respective Bank financing was reallocated to Part A as well.
46. It was evident in 1989 that the country was heading toward a power crisis in the foreseeable future, mainly because the Government had mothballed the 620-MW Bataan Nuclear Power Plant. Had NPC completed the geothermal power plants by early 1993, as appraised, they would have made up about 20 percent of that mothballed power generating capacity, and the effect of the power crisis would have been reduced sooner. Due to delays caused by indecision by NPC
In 1996 the United States had an installed capacity of 2,827 MW, Mexico 753 MW, Italy 632 MW and Japan 414 MW. 13
regarding location of four of the six geothermal power generating units, some technical problems, and inclement weather, the first five units were commissioned between March 1994 and April 1996, and the last is scheduled for commissioning by April 1998.
47. Although Part A continues to be economically and financially viable, and Parts C2 and C3 have helped improve NPC's O&M, the Project is rated as only partially successful, given the major cost overrun and implementation delay.
B. Recommendations
1. Project-related
48. The preparation of a project performance audit report is recommended by the end of 1998 when adequate operational data for the Botong plant should also be available. The Bank should closely monitor progress on that plant to ensure its commissioning by April 1998.
2. General
49. The modular concept introduced in Part A was recommended by NPC's consultants with extensive experience in geothermal power development, on the grounds of flexibility, favourable cost and short implementation period. The concept was reviewed and endorsed by a staff consultant engaged by the Bank during appraisal. However, the actual cost turned out to be much higher, and implementation quite complex. This demonstrates the risks related to new technologies and highlights the need for a very rigorous review of such technologies, as well as for an appropriate provision in the cost estimates (through contingencies in project loans and flexibility in scope in sector loans). 14
APPENDIXES
Number Title Page Cited on (page, para.)
Summary of Bank-Financed Contract Procured under International Competitive Bidding 15 3, 7
2 Procurement of Spare Parts under Part C 16 4, 11
3 Implementation Schedule 18 5, 16
4 Status of Compliance with Loan Covenants 19 8, 29
5 Actual Disbursements 21 8, 31
6 Financial and Economic Analysis 22 11,41
7 Projected and Actual Energy Sales and Peak Demand 26 12, 43 SUMMARY OF BANK-FINANCED CONTRACT PROCURED UNDER INTERNATIONAL COMPETITiVE BIDDING
Contract Amount Cat.! Contract Description! Date of Contract # Contractor/Country Original Supplementary Total Bid Evaluation (on 30 Aug. 1991) (in Sep 1992) -s (71 01/ Six 20-MW Modular 19,383,368,000 394,8571000 19,778,225,000 25 May 1991 0138 Steam Turbine Generators P 135,185,000 135,185000 Mitsubishi Corp./Japan $ 145,784,000 a 3,217,544 a
a DoHar equivalent of the foreign exchange cost financed by the Bank.
-c CD a x -5 PROCUREMENT OF SPARE PARTS UNDER PART C
CssaJfication PCSS E.A.s Contract - Contract Amount of Parts PIantJRegon NoiDate No. Description ContractorlCountly L!C (Forex) $
Pop. Tawi-Tawi DeseI Plant 0004! tO. M-012084-OM Parts for Cumrnins Diesel Gerleet arid Cooling Cummns Diesel Sales Corp.! $ 16067 16.067 SIGMD, Mindanac Regional Center 4Aug90 Water Pump Assembly SIN 56,818 Pop. Manila Thermal Plant 0008/ I 0. C-012141-AA Bearings Marubeni Corp.! Y 7,500,000 Metro Manila Regional Center 4Aug90 JPN Pop. Cebu Thermal Power Plant I 0025/ 1,0 V-012694-OM color Port Gate Aeembly Keystone Southeast! 5$ 18,358 10849 Visayas Regional Center 18Dec90 SIN 3,265 A-op. Siargao Elec. Co. 0029/ 1.0. M-012597-OM Spare Parts Moteurs Leroy-Sorrier-Opt Aceol FF 19,300 Mindanao Regional Center 27Dec90 FRA 1,252 Pop. Cebu Diesel Power Plant II 0045! 10. V-012931-OV Spare Parts Honeywell Pte, Ltd.! $ 1252 Visayas Regional Center 12Feb91 SIN 4,750 t'bn-Prop. Palimpinon Geothermal Power Plant 0050! I 0. V-012782-EJ Micro Switch Honeywell Pte. Ltd.! $ 4750 Visayas Regional Center 12Feb91 SIN 2,768 Pop. Cebu Thermal Power Plant I 0076/ I 0. V-01 31 04-SO Rotor Stein Industrie SN FF 14,900 Visayas Regional Center 7May91 FRA 14,211 Pop. Binga Hydroelectfl0 Plant 0082/ 1.0 N-013079-GE Detector Riva Hydroart S PA.! DM 22,040 N. Luzon Regional Center 7May91 ITA Pop. Arnbuklao Hydroelectric Plant - 0063/ 1.0 N-013139-GE Parts for Butterfly & Rotary Valves Vevey Eng'g. Works Ltd.! SwF 573,660 438.318 N. Luzon Regional Center 7May91 SWI R'op. Magat Hydroelectric Plant 0089! 1.0. N-0131 19-GE Parts for hydraulic turbine intrumentation/ Voest-Alpine/ S 865,275 874-43 N. Luzon Regional Center 4Jun91 governor PHI 1187,200 9,132 f'bn.Prop. Power Plant Barge No. 4 0091 / .0. V-01 3137-AD Parts fOr oil mist detector Racomser, Inc.! Y Visayas Regional Center 4Jun91 PHI l\bn-Prop. Bataan Thermal Power Plant 0100/ SP9ODLS-997 On-line condenser tube cleaning and debris Teprogge Gessellschaft) CM 824,336 521,350 N. Luzon Regional Center 24Jul91 fItter systems GER 37,545 Pop. Palimpinon Geothermal Power Plant 0101/ 1.0 V-013209-DM Parts for control/actuator of main stop valve Kanematsu Corp.! V 5,046,056 Viseyas Regional Center 24Jul91 JPN 4,183 Nbri-Prop. Cebu Thermal Power Plant I 0104/ 10. V-013175-JR Spare Parts GEC Alsthom Measurements Ltd.! L 2384 Visayas Regional Center 26Jul91 UKG Pop. Power Plant Barge No. 4 0105/ 1.0. V-013353-AD Parts for Hitachi Sulzer Diesel Engine Doap AG SwE 34042 26,268 Visayas Regional Center 26Jul91 wi Pop. Bataan Sub-Area 0107) 1.0. N-013343-DM Parts forgas/oil circuit breaker Sumitomo Corp 1 V 15,758,270 118,350 N. Luzon Regional Center 26Jul91 JPN 31,874 Pop. Power Plant Barge No. 1 0109/ 1.0. v.000075-FM Paris for Hitaohi-Sul2er I6ZV 40/48 Duap Ag SwF 48,684 Visayas Regional Center 28Jul91 diesel engine SWI A-op. Palimpinori Geothermal Power Plant f. 0110/ 1.0. v-ooOoi 6-RP Hydraulic speed governor/speed signal 4anematsu Corp / V 9,181 827 68317 Visayss Regional Center >< 25Jul91 amplfier and parts JPN 93194 Pop. Magat Hydroelectric Plant 0112! I 0. N-Ui 3113-GE Parts for turbine governor electronic Voest-Alpine Martirnert Coristruotioril S 1,053,534 N. Luzori Regional Center 26Jul91 controller AUT R'op. Panay Diesel Power Plant 0119) 1.0 V-000200-IP Parts for PDE Model 16PC2-5 arid RBC ABB Turbo Systems, LId I SwF 282,614 197886 visayas Regional Center CD 29Jul91 VTR 400 euhaust gas turbo charger SWI 84785 A-op. Puerto Princesa Diesel Power Plant - 01201 1 0 6-00011 8-IP Parts for SPC 2.SV-L4 & 12 PC SE M.T. Pielstick/ FF 419,964 29Jul91 FRA
Contract Amount Classification PCSS E.A.s Contract L/C (Forex) $ of Parts Plant/Region NoiDate No. Description Contractor/Country
S 3714423 323787 Pop. Agus I Hydroelectric Plant 0121/ I a M000290-GE Various parts Elm EnergieversorgUng Gmbl-l1 Mindanan Regional Center 29Jul91 AUT V 15219800 123839 Nbn-Prop Nueva Viscays-Quinno Sub-Area 0122/ 1.0 N-000059-EJ Parts for unload tap changing Tomen Corporation) N Luzon Regional Canter 29Jul91 transformer JPN 12156 12,156 Nbn-Prop. Panay Sub-Area 0123/ i a V-000352-DM Turner air break switch California International Tradirig/ $ Visayas Regional Center 29Jul91 USA 366,000 2749 l'4n-Prop, Palimpinon Geothermal PP (NOC) 01241 I 0 V-000289-DM Motor Toshiba Corporation/ V Visayas Regional Center 29Jul91 JPN SwE 3304 2246 Nbn-PTop Camarines Notle Sub-Area 0125/ 1.0. V-000288.ES Protection switch AOB Relays AG! S Luzon Regional Center 29Jul91 SWI 3192 3,192 Nbn-Prop. North Davac Sub-Area 0127/ 0 M-000354-RP Lightnir.g arrester W.S. Industries India) Ltd.! $ Mindanao Regional Center 6Aug91 IND FE 2,825,961 496,869 Pop. Visayas Diesel Plants 0130/ I 0.V-000347-IP Partafor Pi&stick diesel engine SEMI, Pielstick) Visayas Regional Center 6Aug91 ERA SwF 13212 8762 Nbn-Prop. North Davao Sub-Area 0131) 0 M-000471-RP Potential transformer Breckwoldt Gmbkf Mindanao Regional Center 6Aug91 GER -S DM 31,050 19,341 Nbn-Frop. North Davao Sub-Area 0132/ 10. M-000355-PP Capacitor vottage transformer Passoni & Villa/ Mindanao Regional Center 16Aug91 ITA L 23,929 42,261 thn-Prop Puerto Pnncesa Diesel Power Plant 0133/ 1.0. S-000121-IP Parts for 8PC 2SV-L4 and I2PC HNG Sparest S. Luzon Regional Center 16Aug91 UKG SwF 290422 196891 Pop. Cebu Diesel Power Plant I 0134/ I a V-000331-IP Exhaust gas turbocharger BBC-VTR4 ABB Turbo Systems Ltd.! Visayas Regional Center 16Aug91 SWI DM 36300 24879 n-Prop, North Davao Sub-Area 0136/ I E M-300365-RP Transformer KG If itz Messwandler GmbH/ Mindanao Regional Center 16Aug91 GER V 8,509,040 69,067 Pop. Lanac Sur S/A 0137/ 0 M-000388-JR Parts for extinguisher chamber of gas Kanematsu Corporation/ Mindariaci Regional Center 16Aug91 circuit breaker JPN PM 66,279 4-4,895 Nbn-Prop. North Davao Sub-Area 0140/ 10. M-000315-RP Current transIormer Pahmeyer and Co. GmbH) Mindanao Regional Center 1Oct01 GER SKR 417,730 72,352 Pop. Negros Oriental S/A 0141/ 1.0 V-000474-JR On-load tap changers ABB Components AB/ Visayas Regional Center 1Oct91 SWE L 117408 215,993 Pop. DIesel Power Plant S/C 0142/ lU V-000351-IP Various partsfor Pielatick diesel eriginer HNG Spares! Visayes Regional Center 1Oct91 UKG CD 0 >c Breakdown of Spare Parts Procurement, Propnetary (Prop) 2593217 Non-Proprietary (Non-Prop) 823735 Total 3,416952 CD r) IMPLEMENTATION SCHEDULE
- 1990 1991 1992 1993 1994 1995 1996 1997 TaskName T 1 T 2 13 (4 1 1 2 (3 (4 1(2 13 I 4 .i...L _I 4 1 1 2 t 3 i 4 JII1ThT4 1 1 2 13 1 12 1 31 4 L Board Approval • 14111
Loan Eftectweness -- • 18)3
Loan Closing Date 31/12 0 31)7 & GEOTHERMAL POWER DEVELOPMENT
SubprojectappasaI and selection I ______Procuremeni— ______
Equipment design, manufactuflng and delive,y ______
CIVIl worki construction
Planned —
Actual
Bac-Man II - Cawayan F ______
Bac-Man II- Botong F ______
Mac-Ban D ______F Mac-Ban E
Installation, erection & comlsslonlng
Planned______
Actual -
Bac-Man II- Cawayan ______
Bac-Man IF - Botong c
Mac-BanD I Mac-BanE
B. INTERISLAND CONNECTIONS
Planned______
Cancelled 0 25111 C. 0 & M IMPROVEMENTS
Planned______x PartsC2andC3 I I C.) 0. SMALL ISLANDS POWER SUPPLY
Planned______
Cancelled - ______0 25/11 19
Appendix 4, page 1
STATUS OF COMPLIANCE WITH LOAN COVENANTS
Covenant Status
1. Provision of adequate local funds for the Project. Complied with. Ref.: LA 985; Section 4.02
2. Submission of annual financial statements, Complied with. audited by auditors acceptable to the Bank, not later than six months after the end of each fiscal year. Ref.: LA 985; 1288, Section 4.07
3. Self-financing ratio, on a three-year moving Complied with. average basis, of not less than 20 percent. Ref.: LA 985; 1288, Section 4.12
4. Debt-service ratio of at least 1.0 times in 1986 Complied with. and 1987, and 1.3 times from 1988/1995 onwards. Ref.: LA 985; 1288, Section 4.13
5. Rate of return on average net revalued fixed Complied with in 1988, 1989, assets in operation of at least 8 percent. 1992, 1993, 1994, and 1996. In Ref.: LA 985; 1288, Section 4.14 1995 the rate of return was 7.3 percent.
6. Accounts receivable of no more than equivalent Complied with. of three months' sales. Ref.: LA 985; Section 4.15
7. Revaluation of fixed assets by independent Complied with in 1996-1997. appraiser as of 31 December 1984 and every four years thereafter. Ref.: LA 985; Sch. 6, para. 20; 1288, Sch. 6, para. 10 Complied with. 8. Relief of NPC from financial and legal obligations related to the nuclear plant. Ref.: LA 985; Sch. 6, para. 15 Complied with. 9. Annual discussion with the Bank of the results of tariff reviews and the proposed measures to maintain the tariffs at adequate levels. Ref.: LA 985; Sch. 6, para. 11 Appendix 4, page 2
Covenant Status
10. Maintenance of accounts payable to PNOC and Complied with. other suppliers at levels consistent with sound commercial practices. Ref.: LA 985; Sch. 6, para. 16
11. Annual submission of NPC's three-year budget, Complied with. together with the corresponding financial projections and power expansion program Ref.: LA 985; Sch. 6, para. 18
12. Budgetary provision for plant maintenance of at Complied with. least 1 percent of the reconstruction cost of such plant. Ref.: LA 985; Sch. 6, para. 25
13. All land, properties, rights-of-way, easements, Slow payment of acquired land licenses, and other rights or privileges that may caused delays at the Bac-Man be necessary to enable the carrying out of the Plants D and E when land Project to be acquired or made available in owners refused the contractor sufficient time to avoid delay in the entry to the site. implementation of the Project. Ref.: LA 985; Sch. 6, para. 27
21
Appendix 5
ACTUAL DISBURSEMENTS ($ million)
Year Quarter Quarterly Cumulative Annual
1990 I - - II 0.044 0.044 Ill - 0.044 IV 0.229 0.273 0.273
1991 I 0.397 0.670 II 0.671 1.341 III 0.630 1.971 IV 10.120 12.091 11.818
1992 1 -1.087 11.004 II 1.606 12.610 III 4.746 17.356 IV 1.591 18.947 6.856
1993 I 0.549 19.496 II 21.525 41.021 III 17.728 58.749 IV 3.395 62.144 43.197
1994 I 2.812 64.956 II 1.822 66.778 III 41.519 108.297 IV 39.660 147.957 85.813
1995 I 6.464 154.421 II 2.141 156.562 III - 156.562 IV 0.925 157.487 9.530
1996 I - 157.487 II 2.227 159.714 2.227 0.286 160.000
a CcIIod Appendix 6, Page 1
FINANCIAL AND ECONOMIC ANALYSIS
1. The only parts implemented in the sector loan were Part A (implementation and commissioning of six modular geothermal units in four power plants) and Parts C2 and C3 (procurement of non-proprietary and proprietary spare parts). Also, because of the 1992-93 power crisis, and the subsequent entrance of the private sector into the power generation business, the National Power Corporation (NPC) power development program changed drastically from that envisaged at Project appraisal. Therefore, application of a time-slice approach (as presented in the Appraisal Report) is not considered appropriate to assess the financial and economic analysis of the Project as implemented.
2. Part A, as built, can be meaningfully subjected to a financial and economic evaluation. Economic and financial rates of return were calculated on the basis of assumptions described in Table 1. The economic and financial analyses cover the period from 1991 (when the actual Project implementation commenced) to the end of economic life of the power plants (estimated at 25 years as at Project appraisal). All calculations are based in constant 1997 prices. Electricity generation figures are based on actual generation up to 1997, and the plant generation estimates presented in NPC's 1997 Power Development Program for 1998 to 2010. These estimates are only about 70 percent of the actual generation in 1997.
A. Financial Analysis
Incremental Inflow
3. The incremental inflow was estimated as the energy sales attributable to the Project assuming transmission losses of 6.9 percent throughout the project life. The applied tariff was the actual average NPC system tariff for 1994 through 1996 converted to 1997 prices and P2.34 per kilowatt-hour (kWh) thereafter.
2. Investment Cost
4. An investment cost of P6,535 million (1997 price level), of which 81 percent is foreign currency. includes the actual cost of Part A before interest during construction (IDC).
3. Fuel Cost
5. The Philippine Geothermal Inc. (PGI) and the Philippine National Oil Corporation (PNOC) will supply NPC with steam. PGI operates the geothermal fields for the Mac-Ban power plants and the average steam price is P0.606 per kWh based on a unit steam price of $0012 per kWh plus operating expenses. PNOC operates the fields for the Bac-Man power plants and the steam price is P0.914 per kWh on a take-or-pay basis at 75 percent plant factor. Steam consumed above the specified plant factor is paid at 65 percent of the basic unit price.
4. Operation and Maintenance Costs
6. Operation and maintenance costs are based on the actual in 1994-1996 and budget (P0.06 per kWh) in 1997 and thereafter. 23
Appendix 6, Page 2
5. Financial Rate of Return (FIRR)
7. The FIRR of 10.1 percent for Part A of the Project is calculated as shown in Table 2. This is considered acceptable when comparing with the weighted average cost of capital (WACC) of 5.2 percent.
B. Economic Analysis
1. Value of Benefits
8. The viability of Part A has been analyzed from a broader national perspective. The economic analysis was based on: (i) a standard conversion factor of 0.32 applied to all local costs, except purchase of steam; and (ii) an economic benefit to the consumer of P3.72 per kWh. The consumer willingness-to-pay (WTP) was based on the cost of operating of private generator sets, which were purchased by several more affluent households, commercial establishments, and industries to provide for power during the 1992-1 993 power crisis. The following assumptions were made in the calculation of WTP: (i) all residential consumers in the bracket 500-kWh per month and above used a 3.5-kilovolt-ampere (kVA) generator set to supply power; (ii) 80 percent of the commercial consumers would use a 9-kVA generator set to supply power; (iii) 100 percent of industrial consumers would use a 1 12-kVA generator set to supply power; and (iv) the premium that each of these categories of consumers was willing to pay is calculated by deducting the retail tariff from the cost of self-generation.
2. Incremental Benefits
9. Benefits are assumed to be incremental since the four geothermal plants constructed for the Project were to partly substitute for the mothballed Bataan nuclear power plant, which in turn was to meet incremental deamand.
10. The distribution losses used in the computation of EIRR were based on the legal amount distribution utilites are allowed to pass on to the consumers. The weighted average of the distribution losses of Meralco and other electric cooperatives reduced from 16.5 percent in 1994 to 11.3 in 1997 and will be constant at 10.7 percent thereafter.
3. Fuel Cost
11. The steam, although paid in pesos, is linked to the exchange rate with the US dollar. As such it is considered a tradeable good, and no standard conversion factor has been applied.
4. Operation and Maintenance Costs
12. The standard conversion factor of 0.82 was applied to calculate the economic costs after an estimated average taxNalue Added Tax of 5 percent was deducted from the financial costs. Distribution costs for Meralco and other distribution cooperatives was estimated at P0.46 per kWh.
5. Economic Internal Rate of Return
13. The EIRR for Part A of the Project of 14.7 percent is calculated as shown in Table 3. This is found acceptable when comparing with a discount rate of 12 percent.
Table 1: AssumptiOns
Item Unit Sum 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2020 Inflation and Foreign Exchange Local (Consumer Pnce Index) 15.7% 89% 7.6% 9.1% 8.1% 8.0% 7.0% 7.0% International (G-5 MLJV Index) 2.2% 4.3% -0.3% 3.7% 8.3% -2.5% 2.4% 2,4% Exchange Rate PI$ 27.50 25.50 27.10 26.40 25.70 26.20 29.50 29.50
Investment Cost-Constant 1997 Pmn 6,643 255 208 1,517 2,830 561 157 671 443 Local Cost-Constant 1997 Pmn 1,333 - 55 227 328 301 101 168 152 Local Costs-Current Rnin 1117 - 35 161 252 255 93 188 152 $mn 41 - 1 6 10 10 4 6 5
Foreign Cost - Constant 1997 mn 5.310 255 153 1,289 2,502 260 56 503 292 Foreign Costs - Current $ mn 181 8 5 43 86 10 2 17 10 Pmn 4.882 217 133 1.171 2.265 244 58 503 292
Note: For 1992-1 997: costs are 1995 and thereon are constant at 1997 level. Costs for 1997 and 1998 estimates
Capacity and Generation Capacity MW 20 60 100 100 120 120 120 120 Bacon Manito II 20 20 20 20 40 40 40 40 Cawayan 20 20 20 20 20 20 20 20 Botong - - - - 20 20 20 20 Mak-Ban D&E 40 80 80 80 80 80 80
Utilization 52% 61% 70% 83% 67% 47% 47% 47% Bacon Manito 52% 55% 68% 87% 67% 72% 72% 72% Mak-Ban D&E 0% 65% 70% 82% 69% 35% 35% 35%
Generation - 76 180 542 729 706 498 496 496 Bacon Manito Il 76 96 120 153 219 254 252 252 Mak-Ban D&E - 84 422 576 487 244 244 244
Transmission Losses - - 6.8% 6.8% 6.8% 6.8% 6.8% 6.8% 6.8% 8.8%
Sales to Distribution Litlilities GWh - - 71 168 505 679 658 464 462 462 >
- - 16,5% 15.1% 13.4% 113% 10.7% 10.7% 10.7% 10.7% Distribution Losses CD Sales to Consumers - - 59 142 437 603 588 414 413 413 >< Steam Costs Pmn - - - 130 203 409 469 515 388 388 388 a)
Operation and Maintenance Costs P mn - - - 5 11 30 37 36 25 25 25 (0 CD Willingness-to-Pay P/kWh 3.72 3.72 3.72 3.72 3.72 3.72 3.72 3.72 C,)
Distribution Costs PIkWh 0.46 0.46 0.46 0.46 0.46 0.46 0.46 0.46
WholesaleTarift(current) P/kWh 1.47 1.66 1.72 1.86 1.80 2.05 2.34 2.34 2.34 2.34 2.34
Table 2: Financial Internal Rate of Return
Net Item Present 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2020 Value
Incremental Revenue Sales to Distribution Utlities GWh 2685 - - 71 168 505 679 658 464 462 462 Wholesale Tariff s/kWh 2,80 256 2.42 2.42 2.13 2.23 2.34 2.34 2.34 2.34 2.34 SalesRevenue Prnn 5.584 - - - 171 358 1.125 1.590 1.540 1.086 1.082 1.082
6,310Incremental Costs 255 208 1,517 2,966 775 596 1,177 995 413 413 413 Investment Cost mn 4,153 255 208 1,517 2,830 561 157 671 443 Steam Costs mn 2,023 - - 130 203 409 469 515 388 388 388 Operations and Maintenance Costs mn 133 - - - 5 11 30 37 36 25 25 25
Net Cash Flow Pmn (746) (255) (208) (1,517) (2,795) (417) 530 412 545 673 668 668
Discount Rate 12% Internal Rate of Return 10.1% 01
Table 3: Economic Internal Rate of Return
Net Item Present 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2020 Value
Incremental Benefits Sales to Consumers GWh 2,125 - - - 59 142 437 603 588 414 413 413 Willingness-to-Pay PIkWh - - - 3.72 3.72 3.72 3.72 3.72 3.72 3.72 3.72 Sales Benefits Rmn 7905 - - - 219 530 1,627 2,241 2186 1,542 1,536 1,536
Incremental Costs mn 7118 255 198 1,476 2,933 784 772 1,416 1,230 598 598 598
Investment Cost Rmn 4,014 255 198 1,476 2,771 507 139 641 416 - - -
Steam Costs Rmn 2,023 - - - 130 203 409 469 515 388 388 388
Operations and Maintenance Costs Pmn 104 - - - 4 8 23 29 28 20 20 20
Distribution Costs Pmn 977 - - - 27 66 201 277 270 191 190 190 o -o Net Benefits P mn 786 (255) (198) (1,476) (2,713) (254) 855 826 956 943 938 938 CD Discount Rate 12% Internal Rate of Return 14.7%
26 Appendix 7
PROJECTED AND ACTUAL ENERGY SALES AND PEAK DEMAND
Average Item 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 Growth %
Projected Energy Saies (GWh) 21180 22855 25,169 27,198 29629 31,757 34,065 36,545 39,248 42,150 7.9 Peak Demand (MW) 3,684 3,989 4,367 4,720 5,139 5511 5908 6,338 6,807 7,309 7.9
Actual Energy Sales (GWJ1) 21,180 22244 22,915 23,626 23,769 24,691 28,449 30,791 33,112 35,290 5.8 Peak Demand (MW) 3,684 3,909 3,974 4,081 4,295 4,676 4,814 5,328 5,781 6,266 6.1
Difference Energy Sales (GWh) - 611 2,254 3,572 5,850 7,066 5,616 5,754 6,136 6,860 Peak Demand (MW) - 80 393 639 844 835 1,094 1,010 1026 1,043
45,000 r . . -' 10,000
9,000 40,000
8,000 35,000
7,000 30,000
6,000
25,000
5,000 (3
20,000
4000
15,000 3,000
10,000 2,000
5,000 1.000
1988 1989 1990 1991 1992 1993 1994 1995 1996 1997
'0 Projected Sales $ Actual sales X Projected Peak Load )4- Actual Peak Load