Document of The World Bank Report No: ICR2737 IMPLEMENTATION COMPLETION AND RESULTS REPORT (IBRD-48100 IBRD-77550) ON A LOAN IN THE AMOUNT OF US$80 MILLION TO THE REPUBLIC OF INDONESIA FOR A DOMESTIC GAS MARKET DEVELOPMENT PROJECT April 30, 2014 Sustainable Development Department Indonesia East Asia and the Pacific i CURRENCY EQUIVALENTS (Exchange Rate Effective – October 31, 2013) Currency Unit = Indonesian Rupiah Rp. 11,273 = US$ 1 FISCAL YEAR January 1 – December 31 ABBREVIATIONS AND ACRONYMS AAA Analytical and advisory activity IT Information technology ADB Asian Development Bank JBIC Japan Bank for International Cooperation AMDAL Analisis Mengenai Dampak Lingkungan Hidup km Kilometer (Analysis of Impacts on the Living KPKN National Treasury Offices Environment) LPG Liquefied petroleum gas bbl Barrel mmBtu Million British thermal unit BPH MIGAS Badan Pengatur Hilir Minyak dan Gas (Oil and mmcfd Million cubic feet per day (gas) Gas Downstream Regulatory Body) MOE Ministry of the Environment BPK Supreme Audit Board NCB National competitive bidding CAS Country Assistance Strategy NGO Nongovernmental organization CFAA Country Financial Accountability Assessment NPV Net present value CNG Compressed natural gas O&M Operation and maintenance CO2e Carbon dioxide equivalent PDO Project development objective ComDev Community development PGN PT Perusahaan Gas Negara (Persero) Tbk CQS Selection Based on Consultants’ Qualifications PIU Project implementation unit CR Current ratio PMC Project management consultant DO Development objective PSC Production-sharing contract DSCR Debt service coverage ratio QBS Quality-Based Selection ECO Environmental coordinating office QCBS Quality- and Cost-Based Selection EIAR Environmental impact assessment report RFP Request for Proposal EIB European Investment Bank ROR Rate of return EIRR Economic internal rate of return Rp. Indonesian rupiah EMP Environmental Management Plan RVP Regional Vice President EOI Expression of Interest SBD Standard Bidding Documents EPC Engineering, procurement, and construction SBU Strategic Business Unit FMR Financial monitoring report SCADA Supervisory Control and Data Acquisition FO Fuel oil SFR Self-financing ratio FY Fiscal year SO2 Sulfur dioxide GOI Government of Indonesia SPN Special Procurement Notice GPN General Procurement Notice TA Technical assistance IBRD International Bank for Reconstruction and tcf Trillion cubic feet Development TGI PT TRANSGASINDO ICB International Competitive Bidding TOR Terms of Reference IFC International Finance Corporation TSP Total suspended particulate IP Implementation progress IPO Initial public offering VAT Value added tax Vice President: Axel van Trotsenburg Country Director: Rodrigo A. Chaves Sector Manager: Nathan M. Belete Project Team Leader: Puguh Imanto ICR Team Leader: Tendai Gregan ii INDONESIA Domestic Gas Market Development Project (Loan 4810-IND, Loan 7755-ID) CONTENTS Data Sheet A. Basic Information B. Key Dates C. Ratings Summary D. Sector and Theme Codes E. Bank Staff F. Results Framework Analysis G. Ratings of Project Performance in ISRs H. Restructuring I. Disbursement Graph 1. Project Context, Development Objectives and Design 1 2. Key Factors Affecting Implementation and Outcomes 11 3. Assessment of Outcomes 22 4. Assessment of Risk to Development Outcome 28. 5. Assessment of Bank and Borrower Performance 29 6. Lessons Learned 32 7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners 34 Annex 1. Project Costs and Financing 35 Annex 2. Outputs by Component 36 Annex 3. Economic and Financial Analysis 62 Annex 4. Bank Lending and Implementation Support/Supervision Processes 69 Annex 5. Beneficiary Survey Results 71 Annex 6. Stakeholder Workshop Report and Results 72. Annex 7. Summary of Borrower's ICR and/or Comments on Draft ICR 73 Annex 8. Comments of Cofinanciers and Other Partners/Stakeholders 78 Annex 9. List of Supporting Documents 79 Map 80 iii A. Basic Information ID-Domestic Gas Country: Indonesia Project Name: Market Development Project IBRD-48100,IBRD- Project ID: P077175 L/C/TF Number(s): 77550 ICR Date: 04/30/2014 ICR Type: Core ICR REPUBLIC OF Lending Instrument: SIL Borrower: INDONESIA Original Total USD 80.00M Disbursed Amount: USD 61.77M Commitment: Revised Amount: USD 61.77M Environmental Category: A Implementing Agencies: PT Perusahaan Gas Negara (Persero) Tbk Cofinanciers and Other External Partners: B. Key Dates Revised / Actual Process Date Process Original Date Date(s) Concept Review: 07/02/2003 Effectiveness: 05/08/2006 05/08/2006 01/05/2011 Appraisal: 01/24/2005 Restructuring(s): 07/04/2011 02/01/2013 Approval: 12/13/2005 Mid-term Review: 06/30/2008 05/18/2010 Closing: 03/31/2011 10/31/2013 C. Ratings Summary C.1 Performance Rating by ICR Outcomes: Satisfactory Risk to Development Outcome: Low or Negligible Bank Performance: Moderately Satisfactory Borrower Performance: Moderately Satisfactory C.2 Detailed Ratings of Bank and Borrower Performance (by ICR) Bank Ratings Borrower Ratings Moderately Moderately Quality at Entry: Government: Satisfactory Satisfactory Quality of Moderately Implementing Satisfactory Supervision: Satisfactory Agency/Agencies: Overall Bank Moderately Overall Borrower Moderately Performance: Satisfactory Performance: Satisfactory iv C.3 Quality at Entry and Implementation Performance Indicators Implementation QAG Assessments Indicators Rating Performance (if any) Potential Problem Quality at Entry Project at any time No None (QEA): (Yes/No): Problem Project at any Quality of No None time (Yes/No): Supervision (QSA): DO rating before Satisfactory Closing/Inactive status: D. Sector and Theme Codes Original Actual Sector Code (as % of total Bank financing) Oil and gas 100 100 Theme Code (as % of total Bank financing) Infrastructure services for private sector development 25 25 Pollution management and environmental health 25 25 State-owned enterprise restructuring and privatization 50 50 E. Bank Staff Positions At ICR At Approval Vice President: Axel van Trotsenburg Jemal-ud-din Kassum Country Director: Rodrigo A. Chaves Andrew D. Steer Sector Manager: Nathan M. Belete Junhui Wu Project Team Leader: Puguh Imanto Noureddine Berrah ICR Team Leader: Aidan Tendai Padraic Gregan ICR Primary Author: Aidan Tendai Padraic Gregan F. Results Framework Analysis Project Development Objectives (from Project Appraisal Document) The objective of the Project is to improve economic efficiency and reduce pollution in Indonesia by expanding the use of natural gas in the Borrower’s domestic market. Revised Project Development Objectives (as approved by original approving authority) v (a) PDO Indicator(s) Original Target Formally Actual Value Values (from Revised Achieved at Indicator Baseline Value approval Target Completion or documents) Values Target Years Indicator 1 : PGNs gas sales in the project area (mmcfd) Value quantitative or 168 423 NA 650 Qualitative) Date achieved 12/31/2004 12/31/2010 12/31/2013 Comments The target sales were exceeded on schedule: by 31 Dec 2010 sales were 573 (incl. % mmcfd or 135% of the 2010 target. Gas sales at end of project were 153% achievement) above the target value of 423 mmcfd for end 2010. Indicator 2 : Cumulative number of consumers converted to gas. Value quantitative or 0 120 NA 598 Qualitative) Date achieved 12/31/2004 12/31/2010 07/31/2013 The target of 120 gas conversions was exceeded in December 2010, by which Comments time 444 conversions to gas had taken place; which exceeded the target by (incl. % 270%. By the close of the project, gas conversions were 498% of the original achievement) target value. Major air pollutants and greenhouse gases (GHGs) emissions reductions Indicator 3 : (1000 tons per year), SO2 Value quantitative or 0 56 NA 90 Qualitative) Date achieved 12/31/2004 12/31/2010 12/31/2010 Comments By the end of 2010, SO2 reductions amounted to 90,180 tons per year, which (incl. % exceeded the 2010 target by 161%. achievement) Major air pollutants and greenhouse gases (GHGs) emissions reductions Indicator 4 : (1000 tons per year), NOx Value quantitative or 0 68 NA 109 Qualitative) Date achieved 12/31/2004 12/31/2010 12/31/2010 Comments Actual reductions in annual NOx emissions for 2010 to 108,948 tons/year, (incl. % exceeded the target by 160%. achievement) Major air pollutants and greenhouse gases (GHGs) emissions reductions Indicator 5 : (1000 tons per year), TSP Value quantitative or 0 32 NA 51 Qualitative) Date achieved 12/31/2004 12/31/2010 12/31/2010 Comments Reductions in the annual volume of emissions of Total Suspended Particulates (incl. % were 51,230 tons per year in 2010, which were 160% of the 2010 target. achievement) Major air pollutants and greenhouse gases (GHGs) emissions reductions Indicator 6 : (1000 tons per year), CO2e vi Value quantitative or 0 1653 NA 2645 Qualitative) Date achieved 12/31/2004 12/31/2010 12/31/2010 Comments The increased use of natural gas, and displacement of other fossil fuels in (incl. % West Java, resulted in a significant reduction in annual CO2e emissions achievement) (2,645,376 tons/year) that exceeds the 2010 target by 160%. (b) Intermediate Outcome Indicator(s) Original Target Formally Actual Value Values (from Revised Achieved at Indicator Baseline Value approval Target Completion or documents) Values Target Years Part A of the Project: West Java gas distribution network expanded: Banten Indicator 1 : supply main line completed by 31 Oct 2006. Value (quantitative Banten supply mains Completed NA Completed or Qualitative) Date achieved 12/31/2005 10/31/2006 12/31/2009 The 100% completion of the 16", 41.5km Banten supply main line occurred in Comments November 2008, around 2 years after its original target date. Final acceptance (incl. % into service, following the construction defect liability period, occured on 24 achievement) December 2009. Part A of the Project: West Java gas distribution network expanded: Banten Indicator 2 : reticulation mains completed by mid 2007. Value Banten Banten reticulation (quantitative reticulation mains NA Completed mains or Qualitative) completed Date achieved 12/31/2005 07/30/2007 12/31/2009 A total of 58.6km of reticulation mains were completed in the Banten area, Comments with a mix of 4', 6" and 8" pipes. This represents 100% achievement of target. (incl. % Delays in procurement (contract signed 19 Jun 2007) affected construction achievement) timetable. Part A of the Project: West Java gas distribution network Indicator 3 : expanded:Jakarta/Karawang supply mains completed by 31 Dec 2006. Value Jakarta/Karawang (quantitative Completed NA Completed supply mains or Qualitative) Date achieved 12/31/2005 12/31/2006 12/31/2009 Comments The 100% completion of the Jakarta/Karawang supply mains occured in (incl. % December 2009, following the end of the defect liability period. achievement) Part A of the Project: West Java gas distribution network Indicator 4 : expanded:Jakarta/Karawang reticulation mains completed by 31 Dec 2008. Value Jakarta/Karawang (quantitative Completed NA Completed reticulation mains or Qualitative) Date achieved 12/31/2005 12/31/2008 12/31/2009 Comments (incl. % 100% achievement of target, but with a delay of 12 months. achievement) vii Part A of the Project: West Java gas distribution network expanded: All Indicator 5 : Offtake Stations built by Dec 2006 Value All Offtake (quantitative Offtake Stations NA Completed Stations built or Qualitative) Date achieved 12/31/2005 12/31/2006 10/31/2010 Comments Construction of the offtake stations commenced in January 2008 and was (incl. % fully completed by June 2009, with final acceptance into service occuring in achievement) October 2010, after the 12 month defect liability period expired. Part A of the Project: West Java gas distribution network expanded: SCADA Indicator 6 : installed and commissioned by August 2007. Value SCADA installed SCADA SCADA installed (quantitative SCADA and installed and and commissioned or Qualitative) commissioned commissioned Date achieved 12/31/2005 08/31/2007 08/31/2013 11/30/2013 The contract for the SCADA was signed on June 15, 2011. Changes in the Comments sub-contractor and technical specifications resulted in delays and the PGN's (incl. % request in January 2013 that funding for the SCADA system be switched from achievement) IBRD to PGN. Part B of the Project: Capacity Building of PGN: PGN restructuring plan Indicator 7 : adopted Not later than Value PGN restructuring June 20, 2006, (quantitative plan adopted in PGN restructuring or Qualitative) late 2006. plan adopted Date achieved 06/20/2006 10/01/2006 100% achieved. Minor delay in adoption of PGN restructuring plan, with Comments PGN subsequently restructured between 2007 and 2009 from being (incl. % decentralized (based on geographic management areas) to being centralized, achievement) apart from sales. Part B of the Project: Capacity Building of PGN: Safety and Integrity Indicator 8 : Management System set up and operational by mid-2009 Safety and Integrity Management System established in 2008 together Safety and with Integrity Value Environmental Management (quantitative Coordination System set up and or Qualitative) Office. On January operational by 12, 2009, a Health mid-2009 Safety and Environment Management Committee, established. Date achieved 06/30/2009 01/12/2009 100% achieved. Operational Integrity Management System (OIMS) Comments developed throughout 2008, with OIMS documentation, policies and training (incl. % provided. The HSEM Committee was transformed into a Division, charged achievement) with improving safety and integrity across PGN. Indicator 9 : Part B of the Project: Capacity Building of PGN: PGN’s capacity viii enhancement in targeted areas achieved by mid-2009 PGN’s capacity enhanced in selected areas through the completion of a Value PGN’s capacity large number of (quantitative enhancement in capacity building or Qualitative) targeted areas activities under the Long Term Technical Collaboration Services contract. Date achieved 06/30/2009 08/24/2009 Significant improvements were made in the areas of engineering and Comments planning, SCADA, gas marketing and utilization, operations, operation & (incl. % integrity management, gas pipeline system rules, IT systems, and achievement) management. Indicator 10 : Part B of the Project: Third Party Access (TPA) PGN submits Not later than recommendations June 30, 2006, for new TPA to Value procedures and BPH Migas in (quantitative implementation May 2007, and or Qualitative) plan of “Third draft Pipeline Party Access” System Rules later adopted by PGN. in 2007. Date achieved 06/30/2006 05/17/2007 Significant achievement & major market reform. New TPA regime approved Comments by BPH Migas in 2008, together with new pipeline pricing rules. In 2008 the (incl. % regulator approved new gas TPA regime, including new Pipeline System achievement) Rules. Part B of the Project: Rationalized gas pricing: Economic and efficient gas Indicator 11 : pricing policy framework by PGN Not later than March 31, 2006, the framework for economic and efficient pricing of gas, as Gas Pricing Study Value provided by the sent to Bank for (quantitative Gas Pricing Study review in February or Qualitative) under loan no 2006. 4712-IND, will be developed by PGN and submitted to the Bank for comments. Date achieved 03/31/2006 02/28/2006 Comments 100% achieved. The 2006 Gas Pricing Study suggested a broad framework (incl. % for rationalized gas pricing, based on economic and engineering efficiency achievement) considerations. ix Part B of the Project: Rationalized gas pricing: not later than June 30, 2006, Indicator 12 : the framework (pricing policy) should be submitted by PGN to the Ministry of Energy and Mining Resources for adoption. New gas pricing PGN submits Gas framework Pricing Framework (pricing policy) Value to BPH Migas and submitted by (quantitative Ministry of Energy PGN the Ministry or Qualitative) and Mining of Energy and Resources for Mining Resources consideration. for adoption. Date achieved 06/30/2006 05/17/2007 Comments In May 2007, PGN submitted a report on the Gas Transmission and (incl. % Distribution pricing methodology and implementation rules, for consideration achievement) by BPH Migas for adoption. Part B of the Project: Rationalized gas pricing: not later than September 30, Indicator 13 : 2006, draft methodology and implementation rules for transmission and distribution tariffs developed and submitted to the Bank for comments Draft methodology and implementation Draft methodology rules for Value and transmission and (quantitative implementation distribution tariffs or Qualitative) rules sent to Bank developed and for review. submitted to the Bank for comments. Date achieved 09/30/2006 03/20/2007 Comments 100% achieved, but with delay. Delay due to the February 2006 pricing study (incl. % recommendations needing to be translated into practical and operable achievement) framework. To do that PGN engaged a separate consultant. Part B of the Project: Rationalized gas pricing: not later than December 31, Indicator 14 : 2006, methodology and implementation rules presented to BPH Migas for adoption. New gas pricing New gas pricing methodology and methodology and Value implementation implementation (quantitative rules presented to rules presented to or Qualitative) BPH Migas for BPH Migas for adoption. consideration. Date achieved 12/31/2006 05/16/2007 100% achieved, but with a 5 month delay. BPH Migas. Between 2008-2013, Comments significant changes to gas pricing were made, via various decrees and (incl. % regulations issued by government and the regulator BPH Migas. Many of the achievement) recommendations made were adopted. x G. Ratings of Project Performance in ISRs Actual Date ISR No. DO IP Disbursements Archived (USD millions) 1 01/13/2006 Satisfactory Satisfactory 0.00 2 12/21/2006 Satisfactory Satisfactory 2.74 3 01/09/2008 Satisfactory Satisfactory 24.85 4 04/10/2009 Satisfactory Satisfactory 41.71 5 06/24/2010 Satisfactory Moderately Satisfactory 48.58 6 06/27/2011 Satisfactory Moderately Satisfactory 55.06 7 03/23/2012 Satisfactory Moderately Satisfactory 60.19 8 04/15/2013 Satisfactory Moderately Satisfactory 61.77 9 11/11/2013 Satisfactory Moderately Satisfactory 61.77 H. Restructuring (if any) ISR Ratings Amount Board at Disbursed at Restructuring Reason for Restructuring & Approved Restructuring Restructuring Date(s) Key Changes Made PDO Change in USD DO IP millions First extension of project 01/05/2011 S MS 53.15 closing date, by 36 months to March 31, 2014. Cancellation of $10.6 million from loan, with retroactive 07/04/2011 S MS 55.06 effect from December 21, 2010. Cancellation of $7.6 million from loan (effective February 1, 2013) and second extension 02/01/2013 S MS 61.77 of project closing date, from March 31, 2014 to October 31, 2013. xi I. Disbursement Profile xii 1. Project Context, Development Objectives and Design 1.1 Context at Appraisal Country and sector background 1. At the time of appraisal, Indonesia’s proven reserves of natural gas, estimated at more than 2.5 trillion cubic meters (about 90 trillion cubic feet), were among the largest in the region. In 2003, gas production amounted to about 87 billion cubic meters (about 3 trillion cubic feet), of which 58 percent was exported, mainly to countries in the region. However, gas consumption by power and small and medium sized industries as proportion of total energy consumption was among the lowest in the region. Until recently prior to appraisal, the laws and regulations governing the hydrocarbon sector sanctioned the dominance of PT Pertamina (Persero) and PT Perusahaan Gas Negara (Persero) Tbk (PGN). They also allowed the government to interfere in the sector in ways that inhibited efficient operation and limited participation of the private sector. Many of the issues the sector faced under the previous legislative framework were addressed by the 2001 Oil and Gas Law and the 2004 implementation rules and regulations. The law and regulations created an environment conducive to the removal of the barriers to competition and private sector entry and to the development of the gas sector and the domestic gas market. However, at the time of appraisal, the sector was still facing the following interrelated issues that hampered the rapid development of a domestic gas market: a) The structure of gas pricing in Indonesia was distorted, resulting in inefficient resource allocation. The price of natural gas in the domestic market was below its economic and market value reducing producers’ interest in developing this abundant resource for domestic use. The negative economic impact of this inadequate pricing system was compounded by the subsidized prices of petroleum products. b) The implementation of the new Oil and Gas Law was proceeding slowly because of delayed issuance of the implementation regulations. While the law provided the basis for a progressive liberalization of the gas market, its implementation had been slow because of the delayed issuance of the implementing rules and regulations. The Bank engaged the government on this pressing issue and the implementation regulations were enacted on October 18, 2004, paving the way for effective implementation of the law. c) PGN was not fully prepared to operate in the emerging competitive gas market. Under the new Oil and Gas Law, the three major segments of the oil and gas industry (production, transmission and distribution) would be unbundled, open access to network services would be allowed and eventually, a competitive gas market would be developed. To face these challenges, PGN planned for: (a) further restructuring, including strategic partnership with private sector to increasingly meet new investment requirements from its financial resources and standings, a major objective assigned to it by the government; and (b) strengthening its management and 1 operational practices and corporate governance to be ready to operate in the future competitive market. d) Production-sharing contracts (PSCs) were not conducive to gas development. More than 90 percent of Indonesia's oil and gas was produced by the private sector, mostly by international oil companies. Private sector investment in the sector was almost totally governed by PSCs. The fiscal and non-fiscal terms of Indonesia's PSCs were mostly in line with international practice. However, many existing contracts still did not have provisions for gas discoveries and therefore no predictable basis for forecasting the value to the producers of possible gas discoveries for domestic markets. e) The transmission and distribution infrastructure was underdeveloped. The country's transmission and distribution infrastructure was underdeveloped and that constrained the development and expanded utilization of this economically and environmentally attractive fuel. Progress toward a competitive gas market, as envisaged by the Oil and Gas Law 2001, required further development of gas transmission and distribution systems. 2. The broad objectives of the Government of Indonesia's (GOI’s) policy to reform the energy sector were: (a) efficiency and reliability; (b) transparency and competition; (c) minimization of the use of public funds; and (d) environmental soundness. GOI’s strategy with respect to the above gas sector issues includes the following: • Phasing out of the subsidies and rationalization of energy prices. The prices of petroleum products in Indonesia were heavily subsidized. Prior to the rapid increases in oil prices that began in 2003, the GOI had implemented phased increases in fuel prices that led to a reduction in fuel subsidies and more rational energy product prices. Following a Presidential Decree in December 2002, the subsidies for all products-with the exception of kerosene- were to be fully eliminated by the end of 2004. However, the unprecedented surge in global oil prices from 2003 widened the gap between domestic prices and current international prices and increased the amount of fuel subsidies. The government remained fully committed to addressing the oil product subsidy and gas pricing issues and to developing and implementing a rational gas pricing policy. Full removal of fuel subsidies would require more time than earlier planned and substitution of domestic gas for imported fuels would contribute to resolving this issue and benefit the economy and the environment. • Establishment of an appropriate legislative and regulatory framework. Many of the sectoral issues had stemmed from the previous inadequate legislative framework governing the energy sector. In November 2001, the government enacted a new Oil and Gas Law. The law gave Indonesia its first modern legal framework to fundamentally reform the oil and gas sector, through: (a) the gradual development of a competitive market; (b) the establishment of an implementing body for upstream activities and an independent regulatory agency for downstream activities; and (c) the unbundling of the traditionally vertically integrated oil and gas businesses. The issuance of the implementing rules and regulations on October 18, 2004 was a key step in speeding up the opening of the oil and gas sectors to competition and further private investments. 2 • Restructuring of the Gas Sector. PGN had already unbundled its key transmission activities from its distribution operation. It had associated with several strategic partners to create a gas transmission subsidiary, and listed, in December 2003, about 39 percent of its shares in the Jakarta and Surabaya stock exchange markets. Further restructuring of PGN to allow greater private sector participation in its operation and preparation for future sales of its shares and assets was under way. • Production-sharing contracts. The new law and regulations provided for a competitive environment under which all gas producers could have direct access to consumers. The absence of a provision for gas discovery in the existing contracts was to be resolved gradually, on a case-by-case basis. Rationale for Bank Involvement 3. At appraisal, there were three reasons put forward for Bank involvement. 4. First, Bank involvement and assistance to PGN would significantly contribute to adequate and effective implementation of the sound legal framework and policies developed with Bank support during the preparation of the project. During project implementation, the Bank would continue the ongoing policy dialogue and cooperation with GOI and PGN on deepening the reform of the energy sector to ensure adequate implementation of the recommendations of the analytical and advisory and technical assistance activities jointly carried out to date. The project would focus mainly on: (a) designing and implementing an effective gas pricing policy; and (b) further restructuring of PGN to bring its corporate structure in line with the new Oil and Gas Law. Appropriate policies in gas pricing and the restructuring of PGN must be addressed “to improve the climate for high quality investments” to develop gas use in the domestic market. The Bank’s involvement would also assure that these two issues are addressed in a timely manner to meet the market needs according to international best practice and the government reform objectives. This would pave the way to further opening of the sector and attract private sector financing to meet the sizeable investment needs to develop it. 5. Second, the development of a comprehensive gas pricing framework in relation to the cost of production, transmission and distribution of gas will improve the transparency of payment and allocation of the rent. The revenues generated by the development of natural gas from the field to the final users will allow the government and the regulator to make informed decisions in setting prices after taking into account efficiency and equity. 6. Third, the GOI had secured US$500 million from private investors to Pertamina for further field development and US$485 million from the Japan Bank for International Cooperation (JBIC) to PGN for a transmission project to increase gas supply to West Java – the South Sumatera to West Java (SSWJ) transmission line and a distribution line in West Java. However, the government and JBIC agreed that additional investment alone is not enough to develop the domestic gas market. The Bank’s strong global knowledge and experience would be instrumental in addressing long term policy issues to develop and sustain the domestic gas market. It was agreed that the JBIC would rely on the Bank to address gas pricing issues to support its project. 3 Higher level Objectives to which the Project Contributes 7. The higher level objectives that the project contributed to included: i) increasing Indonesia’s national energy security by seeking to switch to using more of its abundant natural gas resources domestically, at a time when Indonesia’s falling oil production had resulted in it becoming a net importer of the oil and refined petroleum products it largely relies on for energy supply; ii) encouraging investment to increase the supply of gas to meet unmet domestic demand by addressing both: (1) the physical constraints that limited domestic gas production, transportation and distribution; and (2) regulatory and commercial factors constraining the development of the domestic gas market, including: market structure and competitiveness, Open Access arrangements for gas networks, and more transparent and economically efficient pricing of gas along the whole gas supply chain; iii) reducing the budgetary impact of subsidies on alternative fuels to gas, which were rising as a consequence of the rapid increase in global oil prices. 8. At appraisal, the objectives of the project were considered fully consistent with, and giving substantial support to, two of the five areas identified in the Country Assistance Strategy (CAS) as essential to raise investment and improve (energy) services: (i) fostering a competitive private sector; and (ii) expanding Indonesia’s infrastructure. The CAS, approved by the Board on October 29, 2003 (Report No. 27108-IND), focused on assistance to Indonesia to overcome the low rate of investment and to improve the weak public service, two major impediments to reducing poverty. 9. The development and implementation of a rational gas pricing policy was seen as key to improving the efficiency of gas utilization, increasing transparency, and creating a more attractive environment for private sector participation, and thereby increasing investment in the supply and utilization of natural gas. 10. The restructuring of PGN was essential to ease entry into the growing gas market and to increase private investment in the gas sector. It would align PGN's corporate structure with the new law and recent regulations, and prepare it to operate in a competitive environment. 11. The physical expansion of the gas infrastructure under the project would have a significant impact on alleviating infrastructure bottlenecks in Indonesia and improving quality of gas service in West Java. The project supported the reinforcement of PGN’s distribution system to increase potential supply to about 550 mmcfd, more than three times PGN’s gas sales in the West Java region at the time of appraisal. 1.2 Original Project Development Objectives (PDO) and Key Indicators (as approved) 4 PDO 12. There is inconsistency in the PDO in the PAD and in the Loan Agreement. In the Data sheet and Annex 3 of the PAD, the PDO was described as: “Natural gas utilization expanded and air pollutant emissions reduced in West Java.” (Ref. PAD B.2, Technical Annex 3). However, par. 2.1 of the PAD described the PDO as: “The objective is to improve economic efficiency and reduce pollution by substituting gas for more expensive and more polluting fuels, such as diesel, fuel oil and coal.” 13. The PDOs described above also differ from the PDO which is in the project’s Loan Agreement. The Loan Agreement states: “The objective of the Project is to improve economic efficiency and reduce pollution in Indonesia by expanding the use of natural gas in the Borrower’s domestic market.” (Loan Agreement, Loan No. 4810-IND, Schedule 2). 14. The Legal Agreement’s version of the PDO is legally binding between the Bank and the Borrower and therefore should be used for measuring the successful outcome of the project. Key Indicators 15. The key performance indicators focus on the following: • An increase in utilization of natural gas; • The reduction of air pollutant emissions; • Finalization of the gas pricing study and development and implementation of a rational natural gas pricing policy according to a schedule acceptable to the Bank; and • Finalization of the PGN’s restructuring study and development and implementation of a restructuring strategy according to a schedule acceptable to the Bank. 16. The project's PDO Indicators measure increases in gas sales and gas connections in the project areas, and reductions in specific air pollutants in the project area, relative to a projection of air pollution under a Business-as-Usual energy usage scenario without the project. 17. The project's Intermediate Outcome Indicators measure: (i) the physical delivery of new gas distribution infrastructure in the project area; (ii) further structural reforms and capacity building at PGN; (iii) the adoption of a new gas pricing framework built on sound principles of economic efficiency and the effective use of the that framework to determine gas prices. 18. Annex 2 discusses project outcomes and indicators in more detail. 1.3 Revised PDO (as approved by original approving authority) and Key Indicators, and reasons/justification Not Applicable. 5 1.4 Main Beneficiaries 19. The primary target group benefitting from the project was expected to comprise industrial, commercial, and residential energy consumers in West Java, who could switch to using gas instead of more expensive and polluting fuel sources such as diesel and fuel oil. The primary target group would have access to greater volumes of gas through a higher capacity and more robust and reliable gas supply network. They would also benefit from increased transparency in gas pricing, with a shift towards a pricing framework based on sound economic-engineering principles, and the different elements of the overall gas price (production, transportation, distribution) being exposed. 20. The largest beneficiaries of the primary target group would be large industrial users of gas, such as power stations, fertilizer and chemical factories, and other energy intensive industries that could substitute gas for other fossil fuels; primarily fuel oil and diesel. While small in number, accounting for only 1.3% of PGN’s customer base, industrial customers and power generation companies account for 97% of PGN’s gas sales (Table 1). The largest such customers are electricity generation companies, chemical and fertilizer manufacturers, ceramics, and metal manufacturers; which together account for 76% of PGN’s total sales to Industries and Electricity power plants (Figure 1) and 73.6% of PGN’s total gas sales in 2013. Table 1: PGN's Customer numbers and gas sales by customer type, 2013 Share of Gas Sales customer Share of total No. volume numbers gas sales Market segment Customers (MMSCFD) (%) volumes (%) Industries and electricity power plants 1247 784.0 1.4 96.8 Commercial & Small Medium Enterprises 1709 21.9 1.9 2.7 Households 88153 4.0 96.8 0.5 TOTAL 91109 809.9 100.0 100.0 Source: PGN 2013, Investor Presentation, 9M 2013 Update, pp. 14-15. 6 Figure 1: Share of PGN’s industrial gas sales by industry, 2013 (%) Basic Metal. 4 Textile. 2 Cement. 1 Wood. 0.06 Paper. 4 Others. 5 Glass. 6 Power plants. 39 Fabricated Metal. 6 Food. 8 Ceramic. Chemicals 11 . 14 Source: PGN 2013, Investor Presentation, 9M 2013 Update, p. 15. 21. Secondary beneficiaries of the project include: (i) the residential population of West Java, who would benefit from substantially lower levels of pollutants, including Sulphur Dioxide (SO2), Nitrogen Oxides (NOx), Total Suspended Particulates (TSP), and Carbon Dioxide equivalents (CO2e); (ii) natural gas producers, who would increase gas sales and gain a larger share of the large West Java energy market; (iii) owners of gas transmission and distribution lines, who would gain from increased gas throughput and revenues on an increased asset base; and (v) government. 22. The gains to government would be three fold. First, as the majority shareholder of PGN, increased gas sales and increased pipeline revenues increase the profitability and value of the government’s stake in PGN. Second, fiscal benefits arising from reductions in the level of fuel subsidy that would have otherwise been required if industrial users continued to use fuel oil and diesel rather than switching to gas. Third, the government received technical assistance in further reforming the gas sector, improving the capacity of PGN, and strengthening regulatory arrangements; all of which contributed towards the government’s policy objectives of increasing the efficiency and sustainability of the domestic gas sector and its contribution to wider economic policy objectives. 23. These primary and secondary beneficiaries were not explicitly identified in the PAD, but they are implicit in the design of the project and the formulation of the PDO. 1.5 Original Components (as approved) 24. The original project comprised two components: a) Distribution Infrastructure Expansion: This component, to be implemented by PGN, includes: (i) construction of class 300 steel pipelines 4–16 inches in diameter with a cumulative length of about 185 km along with control valves and corrosion control facilities; (ii) construction of class 150 steel pipelines of 4 to 16 inches in diameter with a cumulative length of about 71 km, along with control 7 valves and corrosion control facilities; (iii) installation of five off-take and two pressure regulation stations; (iv) installation of about 210 customer metering and regulating stations; (v) installation of a Supervisory Control and Data Acquisition (SCADA) system; and (vi) provision of radio and telecommunications equipment, information technology (IT) support, and emergency response equipment. The total cost of this component is US$108.63 million including contingencies and value added tax (VAT), with IBRD financing of US$77.00 million. b) Capacity Building: This component, to be implemented by PGN, involves assistance to PGN in upgrading its capabilities and staff skills in financial management, infrastructure planning, gas marketing, gas utilization, distribution system safety and integrity management, and gas transmission and compression. The total cost of this component is US$6.20 million, with IBRD financing of US$3.00 million. 1.6 Revised Components 25. The components were not formally revised, but that during implementation, several technical outputs and activities under the project’s first component were altered, without affecting the achievement of related objectives. These are discussed in Section 1.7 below. 1.7 Other significant changes 26. The project evolved over time during its implementation, with significant changes to its original technical design, scale and scope of activities, and disbursement allocations. 27. Changes to the technical design, scale and scope of activities occurred on several fronts. a) Pipeline lengths, routing, costs and Bank financing. During implementation the total length of pipelines to be financed by the Bank was reduced from the 256 km estimated at appraisal to 123 km. As a consequence, the relevant contract price for this work was reduced. This approximate halving of the pipeline costs funded by the Bank arose from: (i) a decision by PGN to use its own funds to rapidly build branch lines in the Greater Jakarta and Karawang area (IFB-8B) in order to expedite the connection of new customers; (ii) the need to re-align the route of a pipeline in the Jakarta area in order to satisfy the requirements of municipal planning authorities and gain the necessary work permit. b) Cost savings of approximately $10.6 million in the Bank loan arose from a combination of PGN’s decision to self-finance package IFB-8B (i.e. branch lines in the Greater Jakarta and Karawang area) and competitive bidding. These cost savings, which related to goods procurement, were later cancelled from the loan rather than reallocated to other categories under the loan, as discussed below. c) SCADA and Telecommunications systems. Major changes to the technical specifications of the SCADA and Telecommunications systems package (IFB-4) between appraisal and implementation resulted in a substantial increase in the cost of this package, a protracted procurement process, and a 36 month extension to the project’s implementation period. The specifications were changed to allow for: (i) the addition of a back-up master control station for system reliability; and (ii) open access architecture. 8 d) Relocation of the Serpong off-take station. Due to difficulties in finding suitable land at Serpong, during implementation the planned Serpong off-take station, which was evaluated during appraisal, was replaced by two off-take stations at Bitung (Bitung 2 and 3). 28. The changes to project Component 1 (Distribution Infrastructure Expansion) are summarized in Table 1. Table 1: Summary of revisions (a) to project activities under Component 1 Changes to Original activities (at Appraisal) Actual activities (a) Pipeline length Installation and commissioning of Installation and commissioning of approximately 185 km of Class 300 67.528 km of Class 300 steel steel pipelines, ranging from 4 to 16 pipelines, ranging from 4 to 16 inches diameter, plus control valves inches diameter, plus control valves and corrosion control facilities. and corrosion control facilities. Installation and commissioning of Installation and commissioning of approximately 71 km of Class 150 56.848 km of Class 150 steel steel pipelines, ranging from 4 to 16 pipelines, ranging from 4 to 16 inches diameter, plus control valves inches diameter, plus control valves and corrosion control facilities. and corrosion control facilities. Off-take and pressure Five off-take and two pressure Five off-take and two pressure regulation stations regulating stations. regulating stations, but with the planned Serpong off-take station replaced by two off-take stations at Bitung (BiBitungtung 2 and 3) due to difficulties in securing suitable land at Serpong. Customer Installation of 210 customer metering A total of 323 metering and connections and regulating stations. regulating stations were provided, with 71 installations of customer metering and regulating stations by PGN and 252 units provided by PGN for installation by the contractors engaged by customers. Supervisory control Installation and commissioning of Installation and commissioning of and Data Acquisition SCADA system for pressure and flow SCADA system for pressure and (SCADA) system control and monitoring by August flow control and monitoring by 2007. November 2013. Substantial changes were made to the originally devised SCADA specifications in order to allow for: (i) the addition of a back-up master control station for system reliability; and (ii) open access architecture. These changes significantly increased the costs of the SCADA systems over what was estimated at Appraisal and resulted in a 36 month extension to the project’s implementation period. Radio and Radio and telecommunications The specifications of the telecommunications equipment, IT support and emergency telecommunications equipment were equipment, IT response equipment. changed in line with the changes to support and the SCADA system. emergency response equipment. a. These revisions to the technical design and outputs did not require project restructuring. 9 29. In addition, structural reforms at PGN arising from its commercialization program resulted in some adjustments to the project’s implementation arrangements — principally the location of the Project Management Unit within the evolving PGN corporate structure. 30. Reallocations between disbursements categories were activities were requested by GoI but never counter-signed and put into effect. On January 8, 2008, the Ministry of Finance wrote to the Bank requesting that $10.6 million of the loan be reallocated between disbursement categories. The amendment sought to utilize costs savings from the procurement of goods contracts by putting them towards the increased costs associated with four works contracts. The proposed reallocation was agreed to by the Bank on February 11, 2008 and sent to the MoF for counter-signature. However, this proposed reallocation was ever actually countersigned by GoI and given effect. Instead, the Loan Amendment for the reallocation was caught up in the protracted budgetary approvals process in both 2008 and 2009 and never actually implemented. The government later decided to cancel this $10.6 million from the loan, as discussed below. 31. Loan terms amended, July 3, 2009. The Loan Agreement was amended on July 3, 2009 to transform it from a Variable Spread Loan (Loan No. 4810-IND) to a Fixed Spread Loan (Loan No. 7755-ID). This did not affect project design, implementation, costs, or outcomes. 32. A total of $18.2 million was cancelled from the loan (22.8% of the original $80 million loan value) in two stages, together with extensions in the loan’s closing date. 33. First closing date extension and first request for Partial Loan Cancellation. On December 14, 2010 the Ministry of Finance wrote to the Bank requesting the cancellation of US$10.6 million of the loan amount and extending the closing date of the project by 36 months to March 31, 2014. On January 5, 2011, the closing date of the project was extended to March 31, 2014, to allow sufficient time for the SCADA system (IFB-4) to be redesigned for open access and then procured, installed and commissioned. During early 2011 PGN sought to persuade the Ministry of Finance that the US$10.6 million in unused funds be reallocated towards the final contract payment for IFB-2, Greater Jakarta Distribution Mainline, rather than having this amount of the loan cancelled. However, after discussions between PGN and MoF, it was decided that MoF’s original partial loan cancellation request would remain unchanged. 34. First Partial Loan Cancellation. On July 4, 2011, US$10.6 million was cancelled from the loan, retroactive to December 21, 2010. The consequence of this cancellation was that PGN funded the additional costs of Works using its own finances, including the works on the Greater Jakarta Distribution Mainline (IFB-2). 35. Second Partial Loan Cancellation and second closing date extension. On October 30, 2013 another US$7.6 million of unneeded loan financing was cancelled (effective from February 1, 2013). In addition, since all investments were already completed, the project closing date was advanced from March 31, 2014 to October 30, 2013 in order close the loan ahead of time. 10 2. Key Factors Affecting Implementation and Outcomes 2.1 Project Preparation, Design and Quality at Entry 36. There was no review of quality at entry by the Bank's Quality Assurance Group (QAG). 37. However the ICR’s assessment is that quality at entry was good, for the following reasons. 38. First, the project responded to the priorities and wishes of the GoI and built on the lessons of earlier gas distribution projects in Indonesia by having: a) Extensive consultations with the GoI and PGN on: (i) the project’s design and implementation arrangements; (ii) how the project might support ongoing strategic structural reforms in Indonesia’s gas and electricity markets; (iii) inter-linkages with PGN’s least cost gas networks expansion plans, including major capital works co-financed by the Japan Bank for International Cooperation (JBIC); and (iv) the development of new gas supply fields and PGN’s efforts to secure additional volumes to meet to increased demand for gas in West Java. b) Gas pricing reforms and further restructuring of PGN as key issues to be addressed in order to accelerate the development of the domestic gas market. The Bank’s past lessons with gas distribution projects in Indonesia indicate the critical importance of ongoing Bank involvement in strategic energy sector policy development and the creation of an enabling environment that fosters commercialization of incumbent energy providers, market entry, and increased competition; c) A strong focus on expanding the capacity, efficiency, safety and reliability of gas infrastructure networks; and d) Improved access for customers to natural gas, a fossil fuel abundant in Indonesia, which is less polluting than diesel, fuel oil and coal. 39. Second, the design supported rapid start-up and by the time of project negotiations on October 24, 2005 the Goods and Works sub-projects had feasibility studies finalized, together with conceptual designs. In the second half of 2004 PGN had established a Project Implementation Unit (PIU) and a Procurement Committee, which were to later be supported by a firm acting as Project Management Consultant (PMC). PGN’s selection and appointment of the PMC in the second half of 2005 was designed to ensure that the procurement packages for the project were prepared ahead of the project being approved by the Bank’s Board. While arrangements to ensure rapid start up were generally good, there were still delays due to shortcomings in initial procurement and contracting, as described in Section 2.2. 40. Third, there were comprehensive public consultations on the project during preparation. PGN convened three public consultations in Jakarta and several consultations in project affected areas with representatives from most of the stakeholder groups: government agencies, property owners, local businesses, NGOs and academia. 41. Fourth, the key risks to the Development Objective, identified at appraisal, were comprehensive and the proposed risk mitigation actions were effective during 11 implementation. The key risks identified at appraisal were: (i) gas supply being lower than expected; (ii) customer conversions to gas being slower than planned; (iii) a lack of political commitment by government to rationalize energy pricing and phasing out subsidies on the prices of oil products; (iv) fraud or corruption resulting in cost overruns or poor quality outputs or subprojects. The two key risks to Implementation Progress identified during appraisal were: (i) potential delays in construction; and (ii) procurement delays. At the time of appraisal, the project’s overall risk rating was “Modest” and it was not expected to have any controversial aspects. 42. There were considerable periods of time between the project’s conception (July 2003), to appraisal (January 2005), and then to approval (December 2005). These delays in project preparation arose from a range of factors, including: i) Delays during 2003 and 2004 in PGN completing a gas system optimization study, the results of which would affect the configuration and design the gas distribution system and consequently the scope, cost and timing of the project. ii) Difficulties in finalizing both the safeguards arrangements and the economic and financial evaluation of the project, due to the abovementioned delays in finalizing its scope, cost and timing; iii) Uncertainties in PGN securing sufficient volumes of gas following the government’s decision to reallocate gas previously earmarked for PGN to PLN, and the expiration of some existing gas contracts. In October 2003 the Government directed PGN to forego its planned supply contract to purchase about 160 mmcfd gas from the CNOOC field, and instead allow that source of supply be used by PLN, given PLN's critical need for gas to fuel its power plants. PGN subsequently had to negotiate and secure new supply contracts during 2004 and 2005. iv) The Initial Public Offering (IPO) of PGN shares in December 15, 2003; and v) The protracted period of time required to consult with and gain the support of a broad range of government and regulatory stakeholders on the design and scope of key aspects of the project’s technical component, in particular those relating to further restructuring of PGN, open access for gas networks, and gas pricing reforms. 43. Although project preparations, appraisal and negotiations took two and half years to complete, they resulted in a well-structured project that was tailored to meet the evolving needs of the gas sector and the government’s policy priorities. 44. The reform of gas and other energy markets in Indonesia, like elsewhere around the globe, takes a considerable period of time. Indonesia’s domestic gas sector, like other parts of its energy sector, has a range of serious, entrenched and fundamental and inter-related distortions. Some of these distortions benefit vested interests, who will seek to delay or stop reforms. Unravelling these distortions takes strong and sustained political will and requires careful consideration of the policy, economic and commercial consequences of various reform options before decisions can be made and reforms implemented. 45. Consequently, the preparation time of this project was more than reasonable in light of the scope of: i) the capital works contemplated and where they were located 12 in the densely populated West Java region; and ii) the institutional, regulatory and gas market reforms that the project supported. 2.2 Implementation 46. PGN had previous experience in implementing three previous IDA financed projects and as such was familiar with Bank procedures. In addition, PGN had several loans with Asian Development Bank (ADB), JBIC and others, which employ similar procurement arrangements to the Bank. Nonetheless, the PIU, Procurement Committee and PMC all needed to acquire or enhance their understanding of the fiduciary requirements, processes and procedures of the Bank – both ahead of and during implementation. 47. However, despite this readiness for implementation, shortly after the February 6, 2006 signing of the Loan Agreement and Project Agreement, the Bank’s March 2006 supervision mission found that implementation progress for both Goods and Works contracts and Consultancy Services contracts was between three to five months behind schedule. These early delays arose from a combination of sources, including: (i) the initial poor quality of bidding documents for the first Goods and Works packages (IFB-1 and IFB-5) resulting in a lengthy time period before the Bank could issue No Objections for the bidding documents; and (ii) the Project Management Consultant (PMC) initially being unfamiliar with the Bank’s requirements in relation to procurement procedures, guidelines and bidding documentation. 48. Supervision missions, and the June 2010 Mid-Term Review, highlighted a number of factors that affected project implementation, as detailed below. i) Strong competition for goods and works, combined with changes in the specifications of several large contract packages (e.g. IFB-1), and decisions by PGN to self-finance a large package (IFB-8B), generated significant savings. These savings were initially expected to result in the reallocation of funds across the various Loan Categories, but as discussed in Section 1.7 above, these savings were instead cancelled from the Loan. ii) Changes in the scope of works after bidding documents were issued risked delaying the implementation of the project. This was an issue for several major contract packages, including those for the Offtake Stations (IFB-3), Construction of Branch line in Banten (IFB-8A). Similarly, the complexity of the SCADA and Telecommunications package (IF-4), and several critical changes to its specifications resulted in long delays in the bidding documents being finalized and issued. iii) PGN was slow to formally approve the technical assistance reports by consultants and to then implement the findings and recommendations of the reports. These reports included recommendations on: planning; customer management; asset integrity, security and safety; and gas pricing reforms. 49. The implementation and outcomes of the project were positively affected by four things: i) The “dash to gas”, with a significant increase in the number of new customers who connected to PGN’s networks as a result of: a) reductions 13 in fuel oil and diesel subsidies for industry making gas a much more attractive fuel; b) PGN’s gas marketing activities; c) network upgrades and extensions, and the increased availability of gas; ii) The significant increase in gas supply volumes to West Java from fields operated by Pertamina SSWJ, Conoco Philips, and MEDCO. This new gas supply was critical to the achievement of the PDO; iii) Timely and smooth land acquisition at four of the five sites for meter regulating stations (IFB-3) and for distribution pipelines located along the right of way of roads; and iv) Broad support to reform gas regulatory and pricing arrangements. 50. There was no QAG review of the quality of supervision for this project. 2.3 Monitoring and Evaluation (M&E) Design, Implementation and Utilization 51. The KPIs used in the project, both at the PDO outcome level and the Intermediate outcome level, were appropriate and will remain relevant and suitable into the future. 52. The KPIs provide readily quantifiable measures of the physical PDO outcomes — specifically increases in gas sales and customer connections in the areas targeted by the project; together with reductions in major air pollutants and greenhouse gas emissions. 53. The KPIs for intermediate outcomes were also straightforward and useful: the Commissioning into service of gas transmission and distribution pipelines (length of pipes), number off-take stations and metering regulating stations. 54. However, the intermediate level KPIs in the results framework for Component 2 (Technical Assistance/Capacity Building), are in some cases weak because they do not effectively measure the successful implementation of the TA’s reform recommendations, but simply require a set of recommendations to be prepared and reviewed by PGN and others (e.g. Ministry of Energy and Mining Resources, BPH Migas) with a view towards their eventual adoption. 55. The design, collection and utilization of the M&E data for the project was carried out effectively by PGN throughout the project and served a useful means of tracking both progress and measuring impacts of the investments financed by the project. 56. In 2009 the rate of disbursements was slow, with only around 17% of the projected annual disbursements actually taking place. The slow disbursement rate in 2009 arose from the protracted delays in approval of the Indonesian budget, which held up approval of the project’s 2009 Supplementary Loan Agreement budget until late in the year. Once the 2009 Supplementary Loan Agreement budget was approved, disbursements re-commenced on December 4, 2009. 2.4 Safeguard and Fiduciary Compliance 14 57. At appraisal, it was determined that the project triggered two safeguards polices: OP/BP 4.01 (Environmental Assessment); and OP4.12 (Involuntary Resettlement). 58. Although OP4.12 was triggered, there is an inconsistency in the project documentation; specifically the PAD’s data sheet mistakenly omits the triggering of the OP4.12 but both the Loan Agreement and Project Agreement refer to the Land Acquisition and Resettlement Policy Framework dated January 31, 2005. This omission of OP4.12 from the PAD appears to be an editorial oversight, which did not affect either the project’s preparation or execution in relation to meeting the requirements of OP4.12. 59. The Environmental and Social Impact Assessment and Environmental Management Plan was established during project preparations, which includes Public Consultation and Disclosure as required under Indonesia's AMDAL (Analisis Mengenai Dampak Lingkungan Hidup) process and a framework on land acquisition, namely General Policy on Land Acquisition and Compensation. An Environmental Coordinating Office (ECO) was established within PGN to monitor environmental management and monitoring as required under the PAD. 60. The environmental and social impacts of the project are discussed below, together with a short assessment of compliance with the safeguards policy requirements. Environmental safeguards 61. At appraisal, the project was assigned an Environmental Category A because of its link to the JBIC-financed SSWJ transmission project. The SSWJ gas transmission project comprises: the SSWJ transmission line (32” to 24” diameter, 1064 km), the Bojonegara-Serpong gas transmission line (24” diameter, 70 km), and an associated distribution line (SSWJ Distribution Cilegon, 16” diameter). The Bojonegara-Serpong gas transmission line would to provide much of the new gas to be distributed in West Java area via the new distribution lines financed by this IBRD project. The Bank also monitored the land acquisition process of the JBIC and PGN- financed Bojonegara-Serpong Transmission line, due to its linkage to the project. 62. Based on the Environmental Impact Assessment Report (EIAR) prepared by PGN, the project was not expected to have any significant impact on natural habitats, forests or protected or sensitive areas. None of the impacts from the construction or operation of the pipelines were considered likely to be sustained or irreversible. The major negative environmental impacts would be temporary interference to the traffic in the project area and some temporary air and water pollution, as well as the removal of vegetation during the construction of the project. None of them, however, were assessed as likely to be major, sustained or irreversible. Positive environmental benefits would arise from significant reductions in air pollutants and greenhouse gas emissions, as a result of the switch by targeted customers to natural gas from other fossil fuels. 63. The environmental safeguards compliance of the project was satisfactory, with it being consistently in compliance with the environmental safeguard policies and environmental performance requirements. The Environmental Monitoring System (EMS) put in place operated effectively using a cooperative mechanism between contractors, PGN, local authorities, and local communities. As required under the EMS, PGN prepared and submitted quarterly reports to the Bank on environmental 15 management and monitoring that covered all project activities; and these reports were considered satisfactory by the Bank. In general, any adverse environmental impacts or concerns were reported and solved with the participation of relevant stakeholders. 64. During the course of project implementation, PGN also took positive steps to mainstream environmental management into its corporate activities. First, on February 1, 2008, the ECO was established as a division under vice presidency. Second, on January 12, 2009, PGN formally established the Committee for Health, Safety and Environmental Management (K3PL), which go beyond the project specific activities of ECO. Third, PGN sought to bolster its capacity in HSE management through staff recruitment and training. 65. Following the completion of construction works in June 2010 (i.e. Mid-Term Review), the Bank requested that bi-annual reports on environmental management and monitoring be prepared by PGN’s K3PL team in the period to the close of the project. In addition to post construction environmental management and monitoring, the bi-annual report was also expected to cover safety and emergency response incidents. Social safeguards — Land Acquisition 66. At the time of project appraisal, it was concluded that there would be no involuntary resettlement and no impact on indigenous people or cultural property under the project. The adverse environmental and social impacts of the project were considered to be minor. The gas pipelines of the project would be built primarily in largely urbanized or industrial areas, all alongside existing roads. Businesses, residents and other facilities along the roadsides could suffer some temporary (up to one day) disruption caused by construction activities. In addition, there could be increased risk of pedestrian injury from traffic accidents during construction because of physical obstruction or removal of walkways. To minimize these disruptions, PGN has standard operating procedures and prevention and mitigation measures in place. It also agreed to compensate any affected businesses for loss of income according to the General Policy on Land Acquisition and Compensation agreed with the Bank during project preparation. In addition, PGN has a strong commitment to social responsibility and has supported the communities along its transmission and distribution right-of-way. In 2002, a Master Plan for Community Development was drafted to provide corporate guidelines on community development (ComDev) programs. In conducting its ComDev program, PGN has worked closely with universities, nongovernmental organizations (NGOs), and local governments. These institutions will help PGN assess local need and play important roles in project implementation and in monitoring social outcomes. 67. Prior to and during the project, extensive public consultations were carried out. Consultation with the public at the local level is an important component of Indonesia's AMDAL process. During the project preparation, PGN convened three public consultations in Jakarta and several consultations in project affected areas with representatives from most of the stakeholder groups: government agencies, property owners, local businesses, NGOs and academia. During the project implementation, consultation was governed by the AMDAL and Environmental Management Plan (EMP) processes. 16 68. The land acquisition process used during implementation appears to have been satisfactory and in compliance with OP4.12, the General Policy on Land Acquisition and Compensation agreed to during preparations, and AMDAL. It used a normal transaction approach with market price as a basis for land value, similar to a willing- seller, willing-buyer transaction. An outline of land acquisition relating to the project’s Metering Regulation Station and distribution pipelines follows; together with a discussion of the land issues around the linked Bojonegara-Serpong gas transmission pipeline. 69. Meter Regulation Stations. Land was acquired for five meter regulation stations (IFB-3) in four locations and for the distribution pipelines. 70. Distribution pipelines. Gas distribution pipelines did not require any land acquisition because they were installed roadside rights of way. PGN obtained permission to use these rights of way from the Ministry of Public Works and from respective local governments. As agreed upon in the General Policy on Land Acquisition and Compensation in the market area, pipeline construction activities were carried out during non-business hours and mainly at night, in order to greatly minimize any potential negative economic impacts on local traders. This is a common practice followed by PGN for the installation of pipelines. 71. Linked Bojonegara-Serpong gas transmission pipeline i) Due to the linkage between the project and the PGN and JBIC-financed Bojonegara-Serpong gas transmission pipeline, the land acquisition processes for the Bojonegara-Serpong gas pipeline were carefully reviewed by the Bank project preparation. This Bank found these processes acceptable and as a condition of project approval required regular updates on this linked investment during project supervision; in particular its social safeguards aspects. ii) As required during supervision, PGN regularly provided the Bank with documentation on the Bojonegara-Serpong gas transmission pipeline. The land acquisition processes followed by PGN for the Bojonegara-Serpong line were in compliance with the plan agreed to during preparations; specifically: (1) PGN followed the procedure for land acquisition set out in the Indonesian Regulation for land acquisition for public purposes — i.e. President Regulation No. 36/2006 (and its revision, President Regulation No. 65/2007) and Regulation of Head of Land Agency No 3/2007 — even though gas provision is not categorized as a public purpose under President Regulation No. 65/2007. (2) Independent land appraisal was used to determine the land value of the affected areas, while the final figure for land price was arrived at through negotiation. iii) During supervision, there were no complaints regarding the level of compensation paid for land acquired for the Bojeonegara-Serpong transmission pipeline. 72. In conclusion, at the end of the project, the overall compliance with social safeguard policies triggered by the project was satisfactory. 17 Procurement 73. At the time of appraisal, the overall project risk for procurement was assessed as average. The key issues and risks around procurement were seen to be: (a) corruption and collusive practices — which are perceived as a nation–wide issue; (b) the tight implementation schedule and risks arising from procurement delays; in particular the potential financial risk to PGN from having to pay for gas through the SSWJ transmission line from the end of 2006 under a “take-or-pay” contract before three key elements of the Bank-financed distribution network expansion were completed. Specifically, without the Banten distribution mainline (IFB-1), greater Jakarta distribution mainline (IFB-2) and the new off-take substations (IFB-3), PGN could end up in the unenviable position of having to pay for gas that it was unable to actually sell to customers due to the lack of distribution infrastructure. 74. The design and implementation of the project were effective in limiting procurement risks. The project’s design included the following measures: (a) the development of an Anti-Corruption Plan and Strategy (discussed further below); (b) the hiring of external Project Management Company to assist in project implementation and management, including prequalification and bidding documents, bid evaluation, contract negotiation, contract management, and cost–schedule–quality control; (c) a procurement plan with a clearly defined scope and detailed procurement and construction schedule. The use of supply and installation (or EPC — Engineering, Procurement, and Construction) arrangements for most of the works was designed to reduce procurement risks, as was the use of ICB and Bank Prior-review. NCB was to be used for only four works packages. Consultant firms would be hired using competitive selection (QCBS or QBS) with Bank prior review; (d) the hiring of a firm to act as a Third Party Inspector, tasked with independent inspection and certification of goods and works. 75. During implementation, the overall procurement performance of the project was satisfactory and in compliance with the agreed procurement arrangements. The large and diverse range of subprojects required a mix of ICB contracting for goods for most works, the limited use NCB contracting (for four installation contracts), and these were generally well executed by the PIU using the Bank’s procedures. Financial Management 76. At appraisal, the financial management assessment for the project concluded that overall, the financial management risks are moderate and that it would be appropriate to accept the entity annual audited financial statements for Bank purposes, with appropriate disclosures on the use of the Bank funds. FM risk mitigation measures designed into the project included: (i) the adoption of quarterly Financial Management Reports (FMRs); (ii) external audits by leading private sector accounting firms; and (iii) strengthened procedures for validating and approving payments to contractors. 77. The financial management performance ranged between Moderately Satisfactory and Satisfactory throughout the Project implementation period. Quarterly FMRs submitted were acceptable to the Bank despite a few delays in timely submission. Audited financial statements and audit reports were generally submitted to the Bank on time and were of acceptable quality. None of the audits were qualified. Financial Performance and compliance with financial covenants 18 78. PGN’s financial performance was considered sound at the time of project appraisal, including through the years of the Asian financial crisis (1997-2000). 79. The 2003 Audited Financial Statements provide a snapshot of PGN’s business at the time of appraisal: a) Revenues and Expenditures. In 2003, PGN generated a total revenue of US$425 million, comprising (i) US$350 million (82.4 percent of the total revenue) from sales of natural gas through its distribution networks, (ii) US$74 million (17.4 percent of the total revenue) from fees earned for gas transmission services, and (iii) less than US$500,000 (less than 0.2 percent of the total revenue) from sales of liquefied petroleum gas (LPG). b) Assets. PGN’s total assets in 2003 were about US$1.08 billion, including current assets of US$418 million. Cash and cash equivalent represented 54 percent of its current assets, and short-term investments represented an additional 19 percent. The large cash account was the result of proceeds from the multilateral or bilateral loan borrowing, a US$150 million Eurobond issue, and a December 2003 public offering of about 39 percent of its shares. c) Liabilities. PGN’s long-term debt in 2003 was about US$330 million, mostly consisting of “two-step loans,” owed to the government for the funds borrowed from the ADB, JBIC, European Investment Bank (EIB), and World Bank for its capital expenditures. d) Equity. PGN’s total equity in 2003 was about US$390 million. 80. Due to the project’s central role in supporting PGN in adapting to the new and more competitive domestic gas market and in growing the size of that market, PGN’s financial performance was carefully monitored by the Bank through the project’s implementation period. 81. The project loan included three financial performance covenants, requiring PGN to: a) Generate sufficient revenue from its internal sources equivalent to at least 25 percent of its average three-year capital expenditures. b) Demonstrate that a reasonable forecast of its revenues and expenditures for each fiscal year would produce sufficient net revenue to be at least 1.5 times its estimated debt service requirements. c) Not incur any debt, if after the incurrence of such debt the ratio of debt to equity shall be greater than 75:25 during 2005-2009 and 70:30 thereafter. 82. Throughout the project implementation, and at the project’s close, PGN’s financial performance was strong and it remained in compliance with the financial covenants under the loan. At the end of 2012, PGN’s self-financing ratio was 135 per cent, its Debt Service Coverage Ratio (DSCR) 9.17 times, and its debt to equity ratio 30:70. 83. PGN’s 2013 Audited Financial Statements reveal a dramatic change in the size and scope of PGN’s business at the end of the project. In 2013 PGN’s revenues were 6.5 times the size of those in 2003, its assets over 4 times larger than ten years earlier, and its equity 7 times larger than in 2003. Profits in 2013 were close to US$0.9 billion, with a healthy profit rate of approximately 30% on revenues. In addition to 19 downstream gas transmission, distribution and sales, by 2013 PGN had also established an upstream Oil and Gas exploration business, as well investments in LNG processing. a) Revenues and Expenditures. In 2013, PGN generated a total revenue of US$3.001 billion, comprising (i) US$2.770 billion (92.3 percent of the total revenue) from sales of natural gas through its distribution networks, (ii) US$0.18 billion (6.0 percent of the total revenue) from fees earned for gas transmission services, and (iii) US$34.8 million (less than 1.2 percent of the total revenue) from exploration of Oil and Gas; and (iv) US$16.7 million from Other Operations (i.e. fibre optic rental for network services, construction and O&M services to customers), which accounted for 0.56% of total revenues. b) Assets. PGN’s total assets in 2013 were US$4.36 billion, including current assets of US$1.78 billion. Cash and cash equivalents (US$1.32 billion) represented 74 percent of its current assets, and short-term investments represented an additional 4.8 percent. c) Liabilities. PGN’s long-term debt in 2013 was about US$612 million, 84% of which were “two-step loans,” owed to the government for the funds borrowed from the ADB, JBIC, European Investment Bank (EIB), and World Bank for its capital expenditures. d) Equity. PGN’s total equity in 2013 was about US$2.73 billion. e) Profit. PGN’s net profit before tax for 2013 was US$0.894 billion (representing a profit rate of 29.8% on total revenues and a 32.7% return on equity). 84. The project played a significant part in the transformation of PGN, by facilitating increased gas supplies into West Java, institutional and regulatory strengthening, and the introduction of gas pricing reforms. This is discussed further below and in Annex 2. Anti-Corruption Plan 85. To address perceptions about endemic corruption in Indonesia, and Anti- Corruption Action Plan was formulated as part of project preparations. The Action Plan identified potential risks of corruption and specified appropriate mitigation measures. Given that the project budget was dominated by expenditure related to building new gas infrastructure, the plan focused on reducing the potential of corruption around procurement. 86. Through the course of project implementation, PGN followed the Anti- Corruption Action Plan, with one exception early on in the project — the publication of contract award information in 2006 and early 2007. This was remedied in April 2007 when PGN published on its own website — and that of UNDB and dgMarket — a summary table of contracts awarded to then. Thereafter, PGN regularly submitted Anti-Corruption Implementation Progress reports to the Bank; review of which indicates that PGN was in compliance with the Anti-Corruption Action Plan agreed to with the Bank; including publication of data on contracts awarded. 87. There are no known issues of corruption relating to this project. 2.5 Post-completion Operation/Next Phase 20 88. Following completion and commissioning of new gas network augmentations in West Java, the operation and maintenance of assets was transferred to the operational division of PGN. 89. The sustainability of benefits arising from the project will be contingent on the gas infrastructure in the project area continuing to be capable of reliably meeting increased gas demands over time. Improvements in long term planning in Indonesia’s domestic gas market requires a stable and sensible policy framework, with a clear strategic vision by government, effective planning of and investments in gas networks, appropriate incentives and contractual arrangements for ongoing development of gas fields to supply domestic markets, and ongoing reforms to gas pricing and subsidies to alternative fossil fuels. The development of a more competitive gas market, as envisaged under the Oil and Gas Law, will also depend significantly on further reforms to Indonesia’s electricity sector, which could eventually substitute gas for the large volumes of diesel, fuel oil and coal currently used for power generation. 90. The capacity building provided by the Technical Assistance in the area of gas system planning will contribute to sustaining the outcomes of the project. Other technical assistance provided through the course of the project has also bolstered institutional capacity in the areas of: a) Operations and Asset Integrity Management; b) Quantitative Risk Assessment; c) Gas Transmission and Supply; d) Gas Marketing, Sales, and Customer relations; e) information technology and management information systems; f) The technologies utilized by gas consumers, including gas air- conditioning, gas engines, gas turbines, cogeneration, and steam boilers; g) Gas pipeline construction. For details, see Annex 2. 91. The broader gas sector reform agenda is also expected to contribute to sustaining reforms, including through: (i) implementation of recommended reforms to gas tariffs to improve economic efficiency; (ii) further commercialization of PGN, including potential further increases in the shareholding level of the private sector; (iii) implementation of regulatory reforms; and (iv) effective application of the Third Party Access regime for gas networks. 92. The ongoing engagement of the Bank in Indonesia’s energy sector has a range of strategic follow up operations to this project, including: a) technical assistance to on ways to further develop Indonesia’s domestic gas market; b) power sector investments in transmission (Power Transmission Project and proposed 2nd Power Transmission Project) and pumped storage hydro-generation (Upper Cisokan); c) the IFC’s investments in Medco Power Indonesia to own and operate gas and hydroelectric projects; d) the Bank’s Geothermal Clean Energy Project; e) Advisory services on electricity and fuel subsidies and a regulatory framework for the electricity sector; f) TA on the development of Public Private Partnerships (PPP) Framework and Policy; g) increasing access to modern energy services in rural and remote parts of Indonesia; and h) Advice on potential PPP candidate projects in the energy sector, particularly geothermal power. 1 1 World Bank 2012, “FY2013 – FY2015 Country Partnership Strategy for Indonesia”, World Bank Group, Washington DC, December 13, 2012, pp. 20–22. 21 3. Assessment of Outcomes 3.1 Relevance of Objectives, Design and Implementation 93. The project objectives and design remain highly relevant to the development priorities of Indonesia. The Bank’s Country Partnership Strategy (CPS) for Indonesia, covering the period FY2013 to FY2015 is aligned with the GoI’s Master Plan for Economic Development 2011-2025 (MP3EI), 2 which seeks to create economic growth, jobs, reduce poverty through creating conducive macro-economic and regulatory conditions for the acceleration and expansion of investments. This project contributes to those objectives because it has supported the ongoing energy sector reform agenda; key elements of which involve: harnessing private sector financing of new energy infrastructure, electricity and gas market development, and utilizing domestic gas supplies to support Indonesia’s economic growth and development. 3.2 Achievement of Project Development Objectives 94. The project has fully achieved its stated project development objective of “improving economic efficiency and reducing pollution in Indonesia by expanding the use of natural gas in the Borrower’s domestic market.” 95. The PDO Indicators focused on Component 1 of the Project. In addition, the project achieved its implicit and more fundamental objectives in Component 2 of the project that relate to improving the economic efficiency of the domestic gas market. The project’s technical assistance was instrumental in improving some aspects of the domestic gas pricing regime and in facilitating competition through the creation of a more effective open access regime for gas transmission. 96. Targets for all 6 PDO performance indicators have already been achieved and/or exceeded. Component 1 of Project Utilization of natural gas increased 97. The Project contributed to the dramatic increase in natural gas usage in West Java, by facilitating increased gas distribution capacity, and improved marketing of gas to new industrial customers that led to increased customer connections in West Java. Other factors leading to increased gas usage in West Java include new gas supply contracts being signed by PGN and reductions in fuel subsidies to industrial customers that resulted in “dash to gas”. 98. The PDO indicators show: a) PGN’s gas sales in the project area (mmcfd): The target for PGN gas sales was exceeded on schedule — by 31 Dec 2010 sales were 573 mmcfd or 135% above the 2010 targets. By the end of the project, PGN’s gas sales were 224% above the target value of 423 mmcfd for end 2010; 2 GoI 2011, “Master Plan for Acceleration and Expansion of Indonesia’s Economic Development 2011-2025”, Government of Indonesia (GoI), Jakarta, May 2011. 22 b) Cumulative number of consumers converted to gas. The target of 120 gas conversions was exceeded in December 2010, by which time 444 conversions to gas had taken place; which exceeded the target by 370%. By the close of the project, gas conversions were 498% above the original target value. Air pollutant emissions reduced in West Java 99. The large increase in the use of natural gas resulted in the displacement of fuel oil and diesel as energy sources, and in doing so reduced the levels of pollutants and greenhouse gas emissions. 100. The reductions in major air pollutants and greenhouse gases (GHGs) emissions (1000 tons per year) in the project area were: a) SO2: By the end of 2010, SO2 reductions amounted to 90,180 tons per year, which exceeded the 2010 target by 61%. b) NOx: Realized reductions in annual NOx emissions for 2010, 108,948tons/year, exceeded the target by 160%. c) TSP: Reductions in the annual volume of emissions of Total Suspended Particulates (TSP) were 51,230 tons per year in 2010, which were 160% of the 2010 target. d) Greenhouse Gases (CO2e): The increased use of natural gas, and displacement of other fossil fuels in West Java, resulted in a significant reduction in annual CO2e emissions (2,645,376 tons/year) that exceeds the 2010 target by 160%. 101. The achievement of these PDO targets was largely due to the timely delivery of the project’s gas supply infrastructure, combined with effective efforts to market gas as a fuel to large industrial customers. Component 2 of Project Gas market development and structural reform 102. The project was part of and supported a large scale transformation in PGN's business and the implementation of fundamental reforms to Indonesia's domestic gas market, which aimed to improve the economic efficiency of the gas sector, the broader energy sector, and the economy in general. These reforms to the domestic gas market presented PGN with both new opportunities and challenges. 103. The Oil and Gas Law 2001 resulted in PGN losing its self-regulated quasi- monopoly on domestic gas transmission and distribution; and facing the potential of increased competition as the domestic market opened up over time. In addition, PGN was also subject to new regulatory arrangements under which gas transmission and distribution tariffs would be set by an independent regulator. 104. The implementation of third party open access to gas networks would enable gas suppliers to directly market gas to consumers, thereby subjecting PGN to competitive pressures that could reduce its profit margins. 105. Opportunities arising from gas market reform included PGN being able to significantly increase its supply and sales of gas in the West Java market, via a combination of investments in new gas transportation infrastructure, securing new gas supply contracts, and effective marketing of gas to large scale customers. 106. PGN's ability to take advantage of these opportunities would be supported by: (i) the elimination of distortionary subsidies on fuel oil used by industrial customers; 23 (ii) corporate restructuring and capacity building, including further sales of PGN shares by the government to the private sector investors. Capacity building and structural reform of PGN 107. Capacity at PGN has been improved significantly via the technical assistance components of the project, including: (i) implementation of structural reforms at PGN; (ii) enhance planning, operations and marketing capability; (iii) enhanced HSE and environmental management processes and the mainstreaming of those processes throughout PGN. These are discussed further in Annex 2. Enhancement of Open Access regime implementation of gas pricing reforms 108. Two key market reform outcomes that the project supported were: i) the implementation of a new Third Party Access regime for gas networks; and ii) a new Gas Pricing framework. These reforms support improvements in the economic efficiency of the domestic gas market by facilitating competition. 109. By the end of the project, a number of critical market reform outcomes had been achieved. These are outlined below and discussed further in Annex 2. 110. New streamlined regulatory arrangements for Third Party Access to transportation lines were established in 2007 and 2008 and all PGN’s gas transmission pipelines now operate under Open Access arrangements. 111. There is limited implementation of Third Party (Open) Access on PGN's Gas Distribution networks -- with this being restricted to national interest and government programs. 112. Efforts to implement revisions to the existing third Party (Open) Access arrangements for Gas Distribution Networks have stalled, together with moves to unbundle PGN's distribution network assets. That is, the Energy & Mineral Resources Ministry Regulation No. 19, 2009 has not been effectively implemented because the government is still considering the matter. 113. There have some reforms to gas pricing, including: a) implementation of new regulations concerning the calculation of gas transportation and distribution tolls; b) increased transparency on gas prices; c) PGN shifting to regionalized and differentiated pricing on a nationwide basis from April 1, 2010; b) PGN implementing large increases in its selling prices to customers in West Java in 2012 and 2013 following increases to PGN's buying price of gas. 114. Further reforms to gas pricing are unlikely to be implemented until there is a consensus of views on key aspects of the pricing framework and a political will to scale back the range and number of special users' whose gas prices are determined by Minister of Energy and Mineral Resources. As of April 1, 2014, there appears to remain a divergence on views between Bappenas, SKK Migas (the successor to BP Migas), and BPH Migas on some aspects of the gas pricing regime. 115. However, the government has not abandoned the use of ministerial allocations that specific how gas reserved for domestic supply is to be split across domestic gas customers. Summary 116. The project was completed on time, within budget, and with successful implementation of all but one of the investment subprojects before the project closing 24 date. That final subproject, the SCADA and Telecommunications system (IFB-4) was commissioned into service one month after the project closing date. 117. The technical assistance in Component 2 of the project resulted in: i) substantial strengthening of PGN’s capacity in targeted areas, including safety, planning, and gas marketing; ii) implementation of further structural reforms at PGN; iii) changes to domestic gas pricing arrangements, particularly in relation to the setting of regulated gas transportation and distribution tariffs, so that they are more transparent and based on sound economic-engineering principles; and iv) the implementation of a new Open Access regime, which has been effectively applied to PGN’s transmission pipelines. A central element of this new regime is PGN’s Pipeline System Rules. 118. The Results Framework in the Data Sheet and Annex 2 further describe the outcomes, outputs and achievements of the two components of the project. 3.3 Efficiency 119. An ex-post economic analysis has been undertaken of the investment Component of the project (Component 1), using the same methodology as that employed at project appraisal. The input costs relate to the construction costs incurred and estimated lifecycle O&M costs. The economic benefits of the the project (cash flow from sales of gas by PGN) were estimated based on the assumption that the economic value of gas was equal to willingness to pay for gas. Other benefits of the project, such as energy efficiency and product quality improvement due to switching from oil products to gas, as well as environmental benefits of substituting cleaner gas for oil products, were not considered in the analysis. 120. The economic analysis for the project components was carried out using two scenarios: (i) with the project; and (ii) without the project. The 'with' project scenario includes the investment in West Java gas transmission and distribution networks, including the linked transmission pipeline investments financed by PGN and JBIC. The 'without' project scenario assumes that absent the project that increased volumes of fuel oil and diesel would be used by industries in West Java. 121. For the estimation of the economic indicators, namely ERR and NPV, the following assumptions were made for the ex-post analysis: • Actual costs at the end of the project are used. The transmission investment costs were US$433.76 million and the distribution investment costs US$81.76 million. Customer conversion costs were $10.3 million. • The volume of gas sales: o Actual data on the level of increased gas sales in the West Java area (SBU1) through the South Sumatera West Java 1 (SSWJ1) transmission pipeline has been used, covering the period 2005 to 2013. o For the period 2009 to 2022, it is assumed that the full 400 mmscfd capacity of the SSWJ1 pipeline is utilized to supply West Java (SBU1), 25 based on the fact that PGN’s contracted volumes into West Java exceed 400 mmscfd and that some of them must be flowing down the SSWJ2 pipeline. SSWJ1 was built first and only its capital costs and capacity are taken into account in the ex-post cost benefit analysis; consistent with the ex-ante cost-benefit analysis. Only later was the SSWJ2 pipeline built, adding another 400 mmscfd of potential capacity and bring the combined gas pipeline transfer capacity between South Sumatera and West Java up to 800 mmscfd. Consequently, SSWJ2 is excluded from this ex-post cost-benefit analysis. o For the period 2023 to 2025, gas volumes fall to 394 mmscfd, in line with PGN’s contracted gas for 2023s. • Gas prices o The ex-post analysis uses historic data on PGN’s Average Purchase Price of Gas and its Average Selling Price of Gas in the period 2004 to 2013. o Customers’ Willingness to Pay (WTP) for gas is assumed to be equal to the PGN’s Average Selling Price of Gas. This WTP assumption affects the calculation of project benefits. o For the period 2014 to 2025, it is assumed that PGN’s Average Purchase Price of Gas remains at its 2013 level ($4.49/MMBTU) as does its Average Selling Price of Gas ($9.20/MMBTU). 122. The ex-post economic cost-benefit analysis indicates that the project has a very high net benefit, valued at $2.7 billion in NPV terms with 10% discount factor. The Economic Rate of Internal Return (EIRR) is also high at 64.5%. For details, see Annex 3. 123. The drivers of these very strong results appear to be: (i) the substantial spread between PGN’s Average Purchase Price of Gas and its Average Selling Price of Gas; and (ii) the increased volumes of gas sold in West Java. 124. These very positive results vindicate the decision to proceed with the project and point to the large potential for further economic benefits to arise from future infrastructure investments in Indonesia's downstream gas sector. 125. No sensitivity analysis has been undertaken ex-post on how changes in key variables might impact the ex-post economic evaluation. 3.4 Justification of Overall Outcome Rating Rating: Satisfactory 126. The project achieved its project development objective of improving economic efficiency and reducing pollution in Indonesia by expanding the use of natural gas in the Borrower’s domestic market. The investments made under the project have a very positive EIRR. Improvements in gas supply infrastructure to West Java arising from the project contributed to a dramatic increase the number of connections and volume of gas sold, but this was complemented by upstream investments in domestic gas fields and upgrades elsewhere the gas transmission and distribution networks. The 26 overall result is measurably increased use of gas in West Java for commercial and industrial activities, and significant reductions in annual emissions of major pollutants and greenhouse gases arising from the switch to gas from other fossil fuels. 3.5 Overarching Themes, Other Outcomes and Impacts (a) Poverty Impacts, Gender Aspects, and Social Development 127. On a project of this nature, the measurement of poverty impacts, gender impacts and social development is both challenging and arguably unrealistic. 128. On relation to poverty reduction, the impact is likely to be minimal because there is only are tiny numbers of both household customers (less than 90,000) and small to medium sized commercial businesses (1709) that use piped gas, and these two types of consumers account for only 3% of PGN’s gas sales, but account for 98.6% of PGN’s total customer numbers. Households generally use bottled LPG for cooking, rather than reticulated gas. Approximately 97% of natural gas sold within Indonesia is consumed by the small number large industrial customers, which account for 1.4% of PGN’s customer numbers (see Table 1). 129. Gender and social development impacts are also difficult to quantify for the same reasons. 130. The project, by supporting increased gas supplies to industrial customers, and efficiency improvements in the domestic gas market, might have indirect impacts on poverty, gender and social development through the impact it has on the prices of energy intensive products, such as electricity, fertilizer and chemicals, public transportation, and metals. However, to fully assess any such impacts would be a large undertaking, involving surveys, economy-wide modelling, and detailed simulations of how changes in prices and economic activity resulting from the reforms impacted different types of households. (b) Institutional Change/Strengthening 131. The Domestic Gas Market Development Project was implemented through a time of major institutional change in Indonesia’s gas sector, and supported through the Second Component the project which strengthened the capabilities of PGN in several critical business areas, including: a) Operations and Asset Integrity Management; b) Quantitative Risk Assessment; c) Gas Transmission and Supply; and d) Gas Marketing, Sales, and Customer relations. 132. The institutional development aspects of the Domestic Gas Market Development project appear to have been appropriate, tailored to the needs and priorities of PGN, and resulted in the training of key staff across PGN’s Strategic Business Units and Management. The combination of in-country training and targeted overseas training has contributed to the adoption of new, more commercial, practices across PGN. 133. Component 2 of the project (Capacity Building of PGN) had three major Intermediate Results measures: a) PGN Restructure and its financial management, operation and planning capability strengthened; b) the design and implementation of a new “Third Party Access” regime covering PGN’s gas transmission and distribution networks; c) the implementation of rationalized gas pricing policy, covering both gas 27 commodity pricing and the regulated tariffs for gas transmission and distribution services. 134. In summary, the results across these three areas were mixed, with significant progress made with the PGN’s restructuring and capacity development in the areas of financial management, operation and planning; but limited progress made with the implementation of a new Third Party Access regime covering PGN’s gas transmission and distribution networks. It also appears that development and implementation of a rationalized gas pricing policy has stalled following the implementation of initial reforms in 2009 (Government Regulation No. 30, 2009 and Energy and Mineral Resources Regulation No. 19, 2009). Further discussion can be found in Annex 2. (c) Other Unintended Outcomes and Impacts (positive or negative) Not Applicable. 3.6 Summary of Findings of Beneficiary Survey and/or Stakeholder Workshops Not Applicable. 4. Assessment of Risk to Development Outcome Rating: Low 135. The installation of new gas transmission and distribution infrastructure in West Java has transformed the energy supply situation there by providing new and existing gas customers with access to significantly increased volumes of gas for industrial, commercial and residential use. By further tapping into the vast gas reserves of Sumatera, and providing the gas reticulation needed to get the gas to customers, PGN has been able to provide customers in West Java with access to one of the cheapest and cleanest fossil fuels. 136. With virtually all of the PGN’s new customers being industrial ones, it is unlikely that they will revert to using fuel oil, diesel or coal, in part because their factories and processes will need to be remodeled — involving considerable capital costs — and in part because absent fuel subsidies the price of natural gas is considerably less than alternative fossil fuels on a dollar per unit of energy basis. The government’s 2005 removal of distortionary subsidies on fuel oil for industrial customers appears to be irreversible, ensuring that natural gas will continue to be assessed against alternatives on basis that reflects their true costs. 137. To sustain the PDO benefits, the ongoing challenge for PGN is to ensure continued supplies of gas to meet the demands of its new customers. It appears that PGN’s shift upstream into oil and gas exploration and LNG development is part of broader strategy to secure gas supplies into the future. There remains considerable potential for further increases in the use of natural gas instead of fuel oil — particularly in power generation — with the associated benefits of reductions in pollutants and greenhouse gas emissions. PGN’s dramatic increase in scale, and access to private sector financing following its partial privatization, means that it should be well placed to finance future network capacity increases to develop and meet currently unserved demand for gas. 28 138. For Indonesia’s gas market to develop further, additional efforts are needed to consolidate and improve the gas Third Party Access Regime and the Gas Pricing arrangements. In addition, broader reforms are required to encourage investment in the development of gas for domestic consumption; particularly now given that Indonesia is a net importer of crude oil and refined petroleum products and the government is severely constrained in its ability to subsidize petroleum fuel prices. 5. Assessment of Bank and Borrower Performance 5.1 Bank Performance (a) Bank Performance in Ensuring Quality at Entry Rating: Moderately Satisfactory 139. The Bank’s performance in project identification, preparation and appraisal is rated moderately satisfactory. 140. The design of the project effectively accounted for structural changes in Indonesia’ domestic gas market and sought to address critical issues of strategic importance: (i) increasing use of Indonesia’s abundant natural gas resources to meet growing energy demands; (ii) providing access to cleaner fossil fuels with lower pollutants and greenhouse gas emissions; (iii) creating conditions conducive to further investment in the domestic gas market by providing greater clarity around Third Party Access arrangements, Gas Pricing, and the setting of regulated Gas Transmission and Distribution tariffs. 141. The implementation arrangements were suitable, with the PIU supported by a PMC, a TPI, and overseen by a Procurement Committee reporting to PGN’s senior management and Board. 142. The project’s design was focused, ready for rapid-start up and could be effectively implemented in the West Java, one of the most densely populated areas of Indonesia. 143. From a technical, financial and economic perspective, the investment subprojects were sound — targeting the largest gas consumption area of West Java; leveraging off the increased gas supplies coming from the linked SSWJ transmission pipeline project that PGN financed with JBIC; and being built to international safety standards. 144. However, for a variety of reasons discussed in Section 2.1 above, the project preparation was protracted – with nearly two and half years between project conception and final approval. 145. In addition, with the benefit of hindsight, it is open to question whether in preparing the project the Bank was able to engage as effectively as would have been desirable with some key stakeholders, in particular: (i) the downstream gas regulator, BPH Migas; (ii) BP Migas (the gas upstream regulator, now called SKK Migas); (iii) DG Migas (Directorate General, Oil & Gas); and (iv) Bappenas (State Planning Ministry). The modality of using a market reform project that was primarily implemented through the dominant downstream gas supplier, PGN, could at times have led to perceptions that some of the recommended reforms to gas pricing and open access arrangements, which arose from the project’s technical assistance component, might have favored PGN. The partial implementation of gas sector 29 pricing reforms, the continued use of government intervention in the allocation of gas to specific industries and its price, and the increasing degree of vertical integration in the gas sector are all indicators that some of the project’s key reform objectives did not gain full support across government. Nonetheless, significant the structural, regulatory and pricing reforms supported by the project did gain traction, with the reforms actually made being substantial steps along the road to improved efficiency in Indonesia’s gas and energy markets. (b) Quality of Supervision Rating: Moderately Satisfactory 146. The Bank’s supervision of this project was moderately satisfactory. 147. The project implementation performance assessments, as reflected in ISRs, Management letters, and Aide Memoires, provided a realistic overview the project throughout project implementation. The reporting of the project’s investment component appears to be timely and relevant, and the Bank’s reporting of changes in PGN’s financial performance and efforts to contract new gas supplies was very good. 148. While there were some implementation difficulties, the Bank team was pro- active in its supervision and implementation support to help identify and address the issues emerged. For example, in 2006 the Bank worked effectively with PGN’s newly appointed PMC to prepare terms of reference and evaluate proposals for key procurement packages. Following that intervention, the PMC gained confidence and competence in managing procurements in line with Bank procedures. 149. The Bank missed the opportunity to formally restructure the project after there were significant changes in Component 1 of the project. Instead, $18.2 million from the loan was cancelled. In missing to formally restructure the project, the Bank also missed the opportunity to revise the PDO in the PAD consistent with the PDO in the Loan Agreement. 150. However, one important area of weakness in the Bank’s supervision appears to be an inadequate level of reporting on developments in the critically important areas of: (i) gas policy and regulatory reforms; (ii) implementation of changes to the gas pricing methodology used by BPH Migas; (iii) reforms to the Open Access Regime; and (iv) further structural reforms and unbundling of PGN. These were all part of Component 2 of the project. The project’s ISRs do not provide information on Intermediate Outcome Indicators relating to Component 2 of the project, and as such there was little reported information on the outputs and outcomes of this important area of the project. 151. Towards the very end of the project, the Bank took steps to engage more effectively with a broad spectrum of stakeholders on issues relating to the efficacy of gas market reforms made so far and the need for further reforms. That was done through a separate technical assistance project (the Gas Development Master Plan (P129639)), which was completed in December 2013 – see Annex 3 for details. 152. Importantly, if the Bank team had very early-on made clear that the SCADA system and telecommunications systems specifications must have an open architecture that supported Third Party Open Access, some of the delays arising from the re-specification and re-tendering of those packages could have been avoided. Delays arising from the SCADA and telecommunications system re-specification, re- 30 design, tendering and construction and commissioning ultimately led to a 36 month extension in the project’s closing date. The understanding of the importance of open architecture that supported Third Party Open Access might have been lost as a result of changes in the composition and skill sets of the Bank’s project team, both between project preparation and supervision and across the supervision period. (c) Justification of Rating for Overall Bank Performance Rating: Moderately Satisfactory 153. The Bank responded to client requests in a timely manner and provided suitable advice on how to adapt to changes and address challenges that arose over time. Proactive engagement with the implementing agency helped to reinforce safeguards, procurement and fiduciary controls. 154. However, there appear to be weaknesses in the Bank’s supervision as it related to engagement with and oversight of the implementation of important reforms to the open access regime and gas pricing. 155. While strong early efforts were made to support PGN in hiring an individual consultant to advice on open access regime and gas pricing, the supervision reports of the Bank do not adequately report on how, whether, and to what extent the reforms recommended were actually implemented by government and the regulator and on the strategic policy consequences arising from the reforms or the lack of reforms. 5.2 Borrower Performance (a) Government Performance Rating: Moderately Satisfactory 156. There was generally strong government commitment to the project investment components, which contributed to the timely completion of the project. The government commitment and actions were probably much more critical to this project than most, as the underlying regulatory, legal, pricing structure and policies set by the government were indispensable to achieving the objectives. 157. The government has also demonstrated strong commitment to broader gas market reform and commercialization aspects of the project. The government has implemented some of the project’s recommended reforms to gas pricing, supported the development and implementation of a new Third Party Access regime for gas transmission. By 2013, the government had further divested shares in PGN, with the public holding 43.03% of PGN’s issued shares and the government 56.97%. 158. However, the GoI’s protracted budgetary process in 2009 put pressure on the project’s delivery, with disbursements in that year only being 17% of what was envisaged. The slow disbursement rate in 2009 arose from the protracted delays in approval of the Indonesian budget, which held up approval of the project’s 2009 Supplementary Loan Agreement budget until late in the year. Once the 2009 Supplementary Loan Agreement budget was approved, disbursements re-commenced on December 4, 2009. 159. The Indonesia-specific requirement that parliament reviews the annual budget of each donor-sponsored project creates challenges for effective and timely project 31 implementation. The removal of this parliamentary review requirement, if at all possible, would help to streamline project implementation while still allowing public accountability to be maintained via regular project performance reports, annual project audits, and annual financial statements from the Implementing Agency. 160. The government’s decision to cancel over 20% of the loan meant that PGN had to finance a larger share of the investments under the project using its own financial resources or with financing with a higher cost than the IBRD loan. This had no impact on the delivery and outcomes of the project because PGN was more than capable of increasing its contribution to the project, since over time its financial strength increased. It is understood that the GoI’s partially cancel the loan was made taking into consideration broader issues regarding the government’s overall debt levels and with regard to PGN’s growing corporate strength as a partially privatized gas utility. (b) Implementing Agency Performance Rating: Satisfactory 161. Despite an initial delay of 1 year, PGN was able to commission into service all the gas transmission and distribution infrastructure before the closure of the project — apart from the SCADA and Telecommunications package, which was commissioned in November 2013, one month after the project’s closure. 162. In addition, PGN was able benefit from the implementation and outcomes arising from the capacity building component of the project, including: (i) improvements to gas safety, system planning, and the project management of large infrastructure projects; (ii) gas system management and SCADA system implementation; (iii) greater transparency in the regulatory setting of gas transportation and distribution tolls; (iv) improvements in gas marketing; and (v) an improved Open Access regime. 163. PGN appears to have played a positive and effective role in convincing other important stakeholders, including BPH Migas and gas shippers and customers, of the merits of its Pipeline System Rules, which are a central part of the new Open Access regime. (c) Justification of Rating for Overall Borrower Performance Rating: Moderately Satisfactory Based on the GOI’s and the implementing agency’s performance to achieving the project objectives, overall Borrower’s performance is rated moderately satisfactory. 6. Lessons Learned a) Regulatory and policy reforms are critical to market transformation • In implementing a market reform project like this one, the supervision of the project needs to pay as much attention to fundamental policy, 32 regulatory and pricing reforms as it does to the delivery and commissioning of physical infrastructure and its impacts. • Further development of Indonesia’s domestic gas market depends critically on implementation of an effective regulatory regime, with incremental improvement to Indonesia’s sound Third Party Access Regime and major changes to the domestic gas pricing and gas allocation arrangements. • Significant changes to both these areas were proposed and partially implemented during the course of the project, based on the technical assistance provided by this project and the earlier Java-Bali Power Project. • It appears that the momentum for further major gas market policy and regulatory reforms stalled between 2009 and 2012. Reform momentum needs to be reinvigorated by clear policy guidance from government and with the implementation of further reforms that create an enabling environment for increased private sector investment. There are promising signs this is now happening, following additional and more effective gas policy engagement by the Bank with the government during 2013. b) Benefits of probity and transparency around procurement • The publication of contract award information can greatly contribute to improving perceptions of Indonesia’s endemic corruption; especially when this forms part of a broader Anti-Corruption Plan. • PGN discovered this to be the case after it published in April 2007 information on contracts awarded during 2006 and early 2007. • A positive benefit arising from improved confidence in the probity and transparency of procurement is that well qualified, genuine bidders will be more likely to submit proposals, thereby increasing the effective level of competition for goods, works, and services. c) Careful specification of complex market related infrastructure, such as the SCADA system, needs to take into account how that infrastructure will be used in the evolving market. • There should have been much greater clarity from the start that the SCADA system and telecommunications systems specifications needed to have an open architecture that supported Third Party Open Access, rather than a proprietary architecture more suited to system monitoring and control by a gas pipeline owner operating without Third Party Open Access to its networks. • If there had been that clarity, the bulk of the project’s delays arising from the re-specification and re-tendering of the SCADA system and telecommunications packages could have been avoided. • The understanding of the importance of open architecture that supported Third Party Open Access might have been lost as a result of changes in the composition and skill sets (especially, micro-economists, engineers, and IT professionals) of both the Bank and client’s project teams, both between project preparation and supervision and across the supervision period. Alternatively, there might have been inadequate communications between 33 various disciplines on why open architecture was needed and what was required to implement it. 7. Comments on Issues Raised by Borrower/Implementing Agencies/Partners (a) Borrower/implementing agencies See Annex 7. (b) Co-financiers Not Applicable. (c) Other partners and stakeholders Not Applicable. 34 Annex 1. Project Costs and Financing (a) Project Cost by Component (in USD Million equivalent) Appraisal Estimate Actual Percentage of Components (USD millions) (USD millions) Appraisal 1. Distribution Infrastructure 86.97 64.56 74.2% Expansion 2. Capacity Building 6.20 12.21 196.9% Total Baseline Cost 93.17 76.77 82.4% Physical Contingencies 6.80 0.00 0.0% Price Contingencies 4.31 0.00 0.0% Value-added tax (10%) 10.43 4.81 46.1% Interest during construction 7.40 0.00 0.0% Total Project Costs 122.10 81.57 66.8% Front-end fee IBRD 0.20 0.20 100.0% Total Financing Required 122.30 81.77 66.9% Note: In some places the PAD included physical contingencies, price contingencies, and value-added tax as part of Component 1 (with a total cost of $108.5 million), and in others they were listed as separate line items. Interest was consistently treated as a distinct cost at appraisal. (b) Financing Appraisal Estimate Actual Percentage Type of (USD (USD of Source of Funds Cofinancing millions) millions) Appraisal Borrower 42.30 20.00 47.3% International Bank for Reconstruction and 80.00 61.77 77.2% Development Total Financing 122.30 81.77 66.9% Note: Project beneficiaries (private companies/industries converting to gas from other fuels) also invested considerable amounts, including some costs that were originally expected to be covered by the Bank loan or PGN (i.e., installation of project-financed metering and regulating stations). The conversion-related costs borne by the companies were not systematically estimated at appraisal or recorded during implementation 35 Annex 2. Outputs by Component The project consisted of 17 packages, of which 16 packages were financed by the Bank: 12 for the procurement of goods, works and non-consulting services; and 4 for consultant services. The 17th package (IFB-8, Branch lines in Greater Jakarta and Karawang) was funded by PGN. 1. Goods, Works and Non-consulting services For each of the investment components, the overall budget allocation, total value of contracts (including any price adjustments and variation orders) and disbursement status are presented in Table A2.1. A short summary of each contract package follows. Table A2.1: Investment Components: budget, commitments and disbursements (US$ million) Pack IFB No. Description Revised Contracted Disburse Percentage Comments age Estimated Price ment disbursed Cost ($ mill) ($ mill) ($ mill) 1 IFB-1 Banten 12.92 12.44 12.39 100% Supply & distribution Installation mainline 2 IFB-2 Greater Jakarta 11.75 17.43 16.63 95% Supply & Distribution Installation Mainline 3 IFB-3 Off-take station 4.45 5.58 5.24 94% Supply & Installation 4 IFB-4 SCADA and 7.30 4.09 1.93 47% Supply & telecommunicati Installation, on Two Stage Bidding. Undisbursed Funded By PGN 5 IFB-5 Procurement of 4.51 4.33 4.28 99% Supply only pipes for service lines 6 IFB-5A Procurement of 1.32 1.24 1.22 99% Supply only Pipes For Service and Branch Lines (Additional) 7 IFB-6a Metering and 4.45 2.25 2.18 99% Supply only regulating stations (Banten) 8 IFB-6b Metering and 7.99 3.78 3.40 97% Supply only regulating stations (Greater Jakarta) 9 IFB-7 Special O&M 1.734 1.91 1.87 98% Supply only, tools and Mult- equipment contracts (Lots 1-6) IFB-7a SCADA & 0.010 0.06 0.06 104% Supply only Communication Tools 36 Pack IFB No. Description Revised Contracted Disburse Percentage Comments age Estimated Price ment disbursed Cost ($ mill) ($ mill) ($ mill) IFB-7b Pipeline and 0.079 0.03 0.03 97% Supply only Facility Tools IFB-7c HSE Equipment 0.03 0.03 104% Supply only and Tools ( IFB 7C ) 10 IFB-8a Branch lines 8.00 2.70 1.80 67% Small Works (Banten) Contract. WB Portion : 75%, PGN Portion : 25% 11 IFB-8b Branch lines 6.36 0.00 0.00 0% (Greater Jakarta and Karawang) 12 IFB-9a Customer 1.04 0.92 0.71 79% Small Works installation Contract (Banten) 13 IFB-9b Customer 0.905 0.80 0.63 77% Small Works installation Contract (Greater Jakarta and Karawang) TOTAL 72.818 57.76 52.57 91% IFB-1: Banten distribution mainline. The Banten distribution mainline was commissioned into service on 18 November 2008, approximately 1 year than originally scheduled under the contract. A total length of 36,348 meters of 16” diameter pipeline was laid, in accordance with six amendments to the original contract. The contract for the Banten distribution mainline originally planned for 41,950 meters of 16” diameter pipeline was to be installed, but during implementation changes in the routing of the pipeline reduced the length of pipe installed by 5.6 km (or 13.3%) from that originally planned. IFB-2: Greater Jakarta Distribution Mainline. Similar to the Banten Distribution Mainline, the Greater Jakarta Distribution Mainline experienced some delays in construction. The EPC contract for the Greater Jakarta Distribution Mainline envisaged that 60,089 meters of 10” to 16” diameter pipes would be laid within a year (19 Dec 2006 to 25 Nov 2007). That ambitious timetable for construction had to be extended by two years to 5 January 2010. Changes in the routing of the Jakarta distribution mainline meant its final as built length was 58,686 meters (97.7% of that originally contracted). IFB-3: Off-take stations and Regulation Stations. Five Offtake Stations were built: Cikande, Cimanggis, Walahar, Bitung 2, and Bitung 3. Two Regulation Stations were constructed: one at Bitung 2 and the other at Cikupa. The location of one of the off- take stations changed during the course of project implementation. Specifically, the originally planned Serpong off-take station was replaced by an extra off-take station at Bitung (Bitung 3) due to difficulties in securing suitable land at Serpong. The completion of IFB-3 on 12 February 2010 was around 12 months later than originally set out in the contract (10 January 2008 to 23 Jan 2009). 37 IFB-4: SCADA and telecommunication. The complex SCADA and Telecommunications package (IFB-4) underwent significant changes in its design specification that prompted a 36 month extension to the closing date of the project to March 31, 2013. In order to accommodate an open access system and improve reliability by having a second, back-up, Master Control Station, the design and bidding documentation for SCADA were altered from those originally drawn up by PGN. The SCADA system enables the system operator to monitor and control the flow and pressure of gas across the West Java Distribution Network via telecommunications signals sent from a Master Control Station. This assists PGN with system control and security, gas metering, and financial transaction settlements. The SCADA system comprises: 1 Master Control Station (MCS), 1 Back-up Master Control Station (BMCS), 10 Offtake stations, 20 Big Customers, 7 District Offices, the existing SCADA system for the SSWJ transmission connection (SSWJ SCADA system), 10 Automatic Meter Readers (AMR), 25 Pressure Monitoring Devices (PMD), and 2 OPC (Object Linking and Embedding for Process Control) Tunneling. Installation of the SCADA system commenced in July 2011, shortly after the contract was awarded. From January 2013, PGN took over the funding of IFB-4 from the World Bank. By November 2013, the whole SCADA and Telecommunications system had been installed and commissioned into service. IFB-5 and IFB-5A: Procurement of pipes for service lines. A total of 125.5 km of pipes between 4” and 10” diameter were acquired under IFB-5 (99km) and IFB-5A (26.5 km). The IFB-5 pipes were delivered between October 2006 and January 2007 and the supplementary order of IFB-5A pipes delivered between September and November 2007. These pipes were used in the construction of branch lines and for customer connections. The additional service pipes ordered under IFB-5A were required to meet increased customer demand for connections, arising from the new branch lines in the Greater Jakarta and Karawang area (IFB-8B). IFB-6A: Metering and regulating stations (Banten customers). The 88 MRS for customers in the Banten area were delivered between June and July 2007, after the contract was signed on 26 December 2006. IFB-6b: Metering and regulating stations (Greater Jakarta and Karawang customers). A total of 164 MRS were procured for customers in the Greater Jakarta and Karawang area. The MRS units were delivered between Nov 2006 and March 2008. The contract was closed on 3 May 2009 following the expiry of the warranty period. IFB-7: Special O&M tools and equipment. The procurement of special O&M Tools and Equipment was protracted, taking until June 2011 to complete. Part of the reason this package took a long time to tender and complete was that the specification of various tools and equipment required extensive consultations with PGN staff in SBUs, Operations, and mobile emergency units. A mixture of ICB and Shopping was used to procure the various lots of tools and equipment: ICB was used for IFB-7A (Special Tools for Operation and Maintenance); while Shopping was used for IFB-S7A (HSE Equipment and tools), IFB-S7B (Pipeline and Facility Tools), and IFB-S7C (SCADA and Communication Tools). 38 IFB-8A: Branch lines (Banten). The 26 branch lines around Banten, under IFB-8A, were completed by 31 October 2009, with minor outstanding works completed during the subsequent 12 month defect liability period. IFB-8B: Branch lines (Greater Jakarta and Karawang). Early during project implementation PGN decided to use its own funds to rapidly build branch lines in the Greater Jakarta and Karawang area (IFB-8B) in order to expedite the connection of new customers. The branch lines for Greater Jakarta and Karawang (IFB-8B) were completed by September 2009. IFB-9A: Customer connections for Banten. The installation of MRS and customer connections for all 35 new customers around Banten was completed by 12 June 2009, with minor outstanding works completed during the subsequent 12 month defect liability period. IFB-9B: Customer connections for Greater Jakarta and Karawang. The installation of MRS and customer connections for all 25 new customers in the Greater Jakarta and Karawang area was completed by 31 June 2009, with minor outstanding works completed during the subsequent 12 month defect liability period. 2. Consulting services The four consultancy contracts funded under the project are listed in Table A2.2. These contracts were to support the delivery of physical infrastructure and to build capacity within PGN. Three of the four contracts were for consulting firms, and one was for an individual consultant. Table A2.2: Consulting services: budget, commitments and disbursements (US$ million) Package Description of Estimated Cost Contracted Disburse Percentage Selection assignment ($ mill) Price ment disbursed Method / ($ mill) ($ mill) Contract Type 14 Project 5.45 5.447 5.143 94% QCBS / Time Management Based Consultant (PMC) Contract 15 Long Term 3.50 3.829 3.482 91% QCBS / Time Technical Based Collaboration Contract Services (LTCS) 16 Third Party 1.62 0.322 0.321 100% QCBS / Time Inspection (TPI) Based Contract 17 Gas Pricing 0.036 0.051 0.051 100% SSS / Framework Individual Consultant TOTAL 10.606 9.649 8.998 93% Project Management Consultant (PMC). The PMC contract was an integral part of PGN’s effective delivery of the project. The contract was signed on February 10, 2006, following a QCBS selection process being followed in the lead up to project being approved by the World Bank Board. The PMC assisted PGN across a range of preparatory matters – including field surveys, preliminary engineering, and 39 preparation of bidding documents – and project management matters, such as contract supervision, schedule changes, and quality assurance. The Long Term Technical Collaboration Services (LTCS) contract was signed in May 2006. The consortium that won the PMC contract was also awarded the LTCS contract. The objective of the LTCS contract was to strengthen PGN’s capability in planning and operating the gas distribution system by providing: (i) seconded technical experts; (ii) training and assessment of staff; (iii) consultancy services; and (iv) advising on and transferring technology to PGN. The LTSC contract focused on seven key areas: 1. Engineering and planning; 2. Operations and Integrity Management System; 3. Quantitative Risk Assessment; 4. Gas Transmission; 5. Review of IT requirements; 6. Risk Management Review; and 7. Training. By the Mid Term Review in June 2010, implementation of the LTCS contract was complete; with the exception of the reviews of Risk Management and IT Requirements, both of which were dropped. That was in line with the plan outlined in the inception report of the LTCS consultants. • Risk Management was excluded from the final scope of work after the consultant’s inception report found that PGN’s Risk Management Department had already initiated its own work on this topic due to delays in the procurement process for the LTCS contract. • The consultant’s Review of IT Requirements was restricted to: (i) diagnostic analysis of PGN’s IT system; (ii) providing assistance in designing an IT system that would cover all aspects of the gas business. Tasks related to procurement and implementation of a new IT system were dropped from the contract. PGN replaced these tasks with other technical services using its own resources to fund further IT related work (design of an IT Master Plan and related activities). A summary of the deliverables and outcomes under the LTCS contract is provided in Table A2.3. Table A2.3: Capacity building, deliverables & outcomes from LTCS contract No. Focus Area Deliverables Outcomes 1 Engineering Reports and documentation on: SCADA system commissioned in and planning • Infrastructure planning; 2013, with open access architecture to • System Control and Emergency facilitate Third Party Access. The Response Philosophy; SCADA system is an integral part of • Specifications for SCADA Systems improvements implemented by PGN in and Emergency Response the areas of System Control and Arrangements. Emergency Response. 2 Operations Reports and documentation on: Implementation of Improved and Integrity • Distribution System Safety & Integrity Operations and Integrity Management Management Management; System. System • Operation & Integrity Management 40 No. Focus Area Deliverables Outcomes System (OIMS); • Gas Transmission. 3 Quantitative Reports and documentation on: New HSE Risk Assessment Risk • Quantitative Risk Assessment methodology adopted as part of HSE Assessment Methodology (HSE). reforms in PGN. 4 Gas Reports and documents on: (i) Gas Improved gas system planning and transmission Transmission and Supply; (ii) Gas marketing and increased gas sales. utilization, which focus on growing the demand for natural gas by industrial and commercial sectors. 5 Review of IT • Diagnostic analysis of PGN’s IT Enhancements to PGN’s IT systems so requirements system: (i) building consensus to align that they can better meet the needs of business requirements for IT and the the business, improve accountability, IT services delivered; (ii) assessment and improve customer services. of PGN’s existing IT Organization, Databases, Software tools, and IT Network Infrastructure. • Providing assistance in designing an IT system that would cover all aspects of the gas business. 6 Risk None. This task was dropped from the contract Improvements in PGN’s risk Management following PGN initiating its own work on this management arrangements, as Review area. reflected in its Audited Financial Statements. 7 Training On-job training in customer research and Increased customer connections marketing, focusing on gathering data from 38 through better marketing and meeting existing and potential customers about gas customers’ needs. Enhanced customer demand and service expectations in the period 24 service by PGN. November 2006 to 22 November 2007. In-house training lectures: Enhanced capabilities of staff in a) Gas Marketing and Customer Service fundamental areas of gas business that Training (Bogor, 19-21 Feb 2008). facilitate better understanding of b) Gas Utilization Training (Batam, 23-25 Apr customer’s needs and PGN’s ability to 2008 (SBU III); Surabaya, 24-25 Apr 2008 effectively market gas to new (SBU II)). Covering gas air-conditioning, customers. gas engines, gas turbines, natural gas conversions. c) Gas Utilization Training for Gas Turbine Cogeneration and Steam Boilers. Training for SBU I held at customer site (PT Centex factory). d) Gas Marketing and Customer Service Training (Part II), (Palembang, 3-4 Dec 2008). e) Basic Knowledge of Natural Gas Training (Mega Mendung, 28-30 Jan 2009). Overseas training on special subjects: (i) Gas Improved Gas Distribution Operation Distribution Operation & Maintenance, (ii) & Maintenance by PGN. Improved Pipeline Construction Course. (Tokyo Gas ability of PGN to supervise quality of Company, Japan). construction of gas pipelines. The contract for Third Party Inspection (TPI) of goods and services delivered was part of the Anticorruption Plan for the project. After competitive selection (QCBS), the contract with the Third Party Inspector was signed on April 19, 2007. The TPI service was effective in ensuring that the goods delivered under the various procurement packages met the tender specifications. 41 Gas Pricing Framework and Third Party Access The project sought to make fundamental reforms to Indonesia’s: (i) the Third Party Access arrangements for gas transmission and distribution; and (ii) gas pricing framework. The implementation of these two particular reforms was one of the main rationales for the project, and considered essential to: improving the efficiency of gas utilization, increasing transparency of gas supply chain costs, unbundling the gas sector, and creating a more attractive environment for increased private sector investment in the supply and utilization of natural gas. As such, these reforms were key pillars to giving effect to the policy objectives in the Oil and Natural Gas Law 2001 and Government Regulation 36/2004 (Oil and Gas Downstream). The project financed technical assistance to advise PGN on the Third Party Access arrangements and gas pricing framework. PGN awarded a contract to an individual international consultant in March 2006. The consultant advised PGN on gas pricing issues and methodology and open access arrangements for its gas transmission and distribution networks. The work of this individual consultant built on and distilled other consultancy work prepared as TA under Loan 4712-IND (Java-Bali Power Restructuring and Strengthening Project); specifically: (i) Gas Pricing and Utilization Study; 3 (ii) PGN Restructuring and Privatization Study. 4 The individual consultant delivered three inter-related reports: (A) Indonesian Gas Structure Industry Issues; 5 (B) Third Party Access to Indonesian Gas Networks; 6 and (C) Gas Pricing Framework and Methodology and Implementation Rules for Transmission and Distribution Tariffs. 7 3 Nexant Ltd. 2006, “Gas Pricing and Utilisation Study”, Draft Final Report, Prepared for PGN by Nexant Ltd (in association with Pendawa Consultama Sejati) [Contract 001200.PK/911/UT/2005], Nexant Ltd., Bangkok, February 2006. 4 PWC 2006, “PGN Restructuring and Privatization Study — Final Report”, report to PGN by PriceWaterhouseCoopers, PWC, Jakarta, 20 October 2006. 5 Cameron, P. 2007a, “Indonesian Gas Industry Structure Issues”, Final Report, prepared for BPH MIGAS and Ministry of Energy & Mineral Resources, (Author: Peter Cameron), Report No. MI980/03, MERCADOS Energy Markets International, Madrid, 20 April 2007 6 Cameron, P. 2007b, “Open Access to Indonesian Gas Networks”, Final Report, prepared for BPH MIGAS and Ministry of Energy & Mineral Resources, (Author: Peter Cameron), Report No. MI980/02, MERCADOS Energy Markets International, Madrid, 20 April 2007. 7 Cameron, P. 2007c, “Gas Pricing Framework and Methodology & Implementation Rules for Transmission and Distribution Tariffs”, Final Report for PGN, prepared for PT Perusahaan Gas Negara (Persero) Tbk., (Author: Peter Cameron), Report No. MI980/04, MERCADOS Energy Markets International, Madrid, 16 May 2007. A second, near identical, version of this report was also prepared for BPH Migas and the Ministry of Energy & Mineral Resources: Cameron, P. 2007d, “Gas Pricing Framework and Methodology & Implementation Rules for Transmission and Distribution Tariffs”, Final Report for BPH MIGAS and Ministry of Energy & Mineral Resources, (Author: Peter Cameron), Report No. MI980/01, MERCADOS Energy Markets International, Madrid, 16 May 2007. 42 These three reports provided PGN, the regulator BPH Migas, and the Ministry of Energy and Mineral Resources with concise summaries of existing regulatory arrangements, the range of reform options available, and recommendations on how to effectively implement significant reforms to gas pricing and third party access arrangements. The findings and recommendations of each report are briefly summarized below, before an assessment of is made of the extent to which the recommended reforms were implemented, the outcomes arising from the reforms made, the scope for further reform efforts in these areas and the possibility of future Bank involvement with those efforts. I. What further gas market reforms were recommended? A. Indonesian Gas Structure Industry Issues As well as implementing new arrangements for Open Access and Gas Pricing, five other key issues in Indonesia’s gas sector were identified as requiring further attention: 1. Avoiding increased vertical integration and reduced competition; 2. Safety Standards in Gas Transmission and Distribution; 3. Allocations; 4. Destination Clauses in Gas Supply Agreements; and 5. Support for Regulator. I. Avoiding increased vertical integration and reduced competition After reviewing Indonesia’s gas market reforms, Third Party Access arrangements, gas pricing framework, and regulatory regime (as it stood in early 2007), a critical risk was identified: the “danger that the reforms may actually lead to increasing vertical integration and reducing competition.” 8 Producers (either directly or through subsidiaries or affiliates) could have incentives to build their own transportation and own distribution networks and have their own trading company selling gas directly to consumers. This danger was seen as arising from two things. First, there being insufficient separation of gas transportation and trading under Indonesia’s gas laws regulations, which allowed a corporate body with either a transport or trading license to obtain a Special Right for transport or distribution. That is, it was possible for a trading company to build and operate a gas transport pipeline, and for a transporter to act as a trader. In these circumstances, the gas producer’s own transport pipeline could be used deny access to any third party by a range of complex means. Second, the regulations requiring open access to be negotiated were silent on what would happen if the parties failed to agree on terms for access. “The result of these two things may be that gas market players are encouraged to integrate vertically and there is little in the regulation to stop that happening.” 9 8 Cameron, P. 2007a, p.2. 9 Cameron, P. 2007a, p.3. 43 To mitigate the danger of vertical integration and reduced competition, four sets of reforms to the regulatory regime were recommended: 1. Separation of Transport and Trading. Introduce a regulation clarifying that high pressure transmission operators (or any affiliate or subsidiary) may not engage in trading, and traders (or any affiliate or subsidiary) may not have any high pressure transmission activity. This excludes the distribution level (where it is normal to have a period of exclusivity and combined distribution and trading/supply for a time). 2. Transparency across the Gas Chain, with regulations implemented to oblige transparency and disclosure of information by gas producers, transporters, distributors and traders. 3. Separate Pricing at Each Point of the Gas Chain: a. Price disclosure at all levels of the gas chain; b. Publication of contract prices, even in unregulated segments of the market where gas companies may freely negotiate prices with consumers. In particular, it was recommended that there be publication of: (i) All contract prices from producers to traders; (ii) Maximum prices from traders to consumers; (iii) Transmission tariffs to all traders; (iv) Distribution tariffs (where there is distribution open access) or the maximum distribution margin (where there is not yet distribution open access). 4. Regulated Open Access and Pipeline System Rules. a. Implement regulated open access, with the transporters and traders (shippers) to negotiate and agree on the Pipeline System Rules between themselves, and then submit them to the regulator (BPH Migas) for approval. In assessing whether to approve the negotiated Pipeline System Rules, the regulator should have regard to: (i) Frequency of the commercial balancing regime; (ii) The opportunities for new shippers to gain access to capacity; (iii) The opportunities to stay in balance; and (iv) Non-discrimination of the balancing regime. b. Transparency: Make the Pipeline System Rules freely available to any trader (shipper) who is considering using the pipeline. II. Safety Standards in Gas Transmission and Distribution To improve the safety and security of the gas sector in Indonesia, as clearly intended under the law and regulations, it was recommended that a philosophy and culture of safety be built into gas industry practice (if it is not already there). Three recommendations were made to strengthen gas safety and security in Indonesia: 1. Technical standards for gas transmission and distribution be independently regulated and aligned to international standards; 44 2. Laws be reformed to assign legal liability for unsafe practices and gas incidents to both gas corporations and the individual directors of gas corporations, with penalties to include significant fines and imprisonment; and 3. The regulator’s decision to a grant license to either a gas transmission or a gas distribution company should take into account the proven experience in safe gas installation by: the gas company itself, its competent staff, its competent subcontractors, or a competent affiliate company or partner. III. Allocations In the past BP Migas sometimes issued instructions on how gas was to be allocated by gas producers to various sectors (e.g. 50% to PLN, 40% to PGN and 10% to others), but such practices are generally considered to be anti-competitive and have been abandoned in many countries that formerly used them (including communist countries). Indonesian law obliges 25% of gas production to be assigned to domestic use, but is silent on where that 25% of gas production should go. A law and policy of retaining a share of gas for domestic use is common in countries with small but developing gas markets and large export volumes. However, how exactly that domestic share of gas is split among various gas users is left to the market (through supply, demand and price) rather than via allocations by regulation or ministerial decree. It was recommended that with Indonesia’s shift to a competitive gas market, the allocation of gas to particular domestic users should be decided by the market, and not through regulation or ministerial decree. IV. Destination Clauses in Gas Supply Agreements Another recommendation was that clauses in Gas Supply Agreements that restrict the sale of gas to certain specified geographic areas (i.e. so called Destination Clauses) be declared illegal and abolished because they are considered anti-competitive. The abolition of destination clauses, together with increase transparency and publication of location specific gas prices, are two ways of promoting competition and efficiency. V. Support of the Regulator. It was recommended that the regulator (BPH Migas) be supported and empowered so that it could properly and effectively regulate the downstream gas industry. B. Third Party Access to Indonesian Gas Networks Following the passing of the Oil and Natural Gas Law 2001 (Law 22), the regulatory regime for open [i.e. third party] access was partially developed through Government Regulations and BPH Migas Regulations; in particular: • Government Regulation No. 36/2004 – Oil and Gas Downstream; • Elucidation of Government Regulation No. 36/2004; 45 • BPH Migas Regulation No. 1, “Guidelines of Special Rights for Transport of Natural Gas through Transmission Pipelines”, BPH Migas, Jakarta, 10 December 2004; • BPH Migas Regulation No. 2, “Guidelines of Special Rights for Transport of Natural Gas through Distribution Pipelines”, BPH Migas, Jakarta, 10 December 2004. Several aspects of a gas Open Access regime were already established in Indonesian law and regulation in 2007; specifically: • There was a requirement for open access for both to transportation and distribution pipes; • The transport and distribution business was to be regulated to the extent that there was open access; • Existing users and the pipeline owner were not to suffer from the open access and a user of open access was required to pay the owner of the transport or distribution pipeline; • A distribution company had an exclusive right to build distribution networks within its distribution area for 25 years, providing it conformed with the development plan and there was sufficient capacity to allow open access; • It was possible to extend the Special Right time period. However, other key aspects of the Open Access regulatory regime required further development or clarification, in particular: 1. The Pipeline System Rules necessary to give effect to an Open Access Regime; 2. The clear separation of responsibilities between traders and transporters, with: a. The transporter being responsible for physical balancing; and b. Traders being responsible for commercial balancing; 3. A regular commercial balancing regime; 4. Commercial incentives for traders to stay in balance. For each issue in turn, the existing regulation in 2007, plus recommendations for an improved open access framework are summarized in Table A2.4. Table A2.4: Open Access: key concepts, gas access regime in 2007, and proposed reforms Key Concepts Issue Existing Regulation (2007) Recommended or Options reforms Distribution Existing Regulation: Exclusivity for: exclusivity • Exclusivity for distribution • Sales to small- for 25 years (provided scale: 25 years Distribution enough capacity to meet • Sales to large- the market) scale: 12 years 46 Key Concepts Issue Existing Regulation (2007) Recommended or Options reforms Options for Trading: • Gradual market opening • Immediate complete open access Licensed area Options: A natural network • Small area, large enough to develop network • Large • A natural potential network area Development Existing Regulation: targets • Company submits design plan and time schedule as part of the tender for a distribution area Handover at end of Options: License holder license term • License area reverts to the compensated: state • By government, or • License period is extended to allow for investments in • By new the final years licensee • License holder is compensated for the current value of the assets Types of access Existing Regulation: Regulated access • Negotiated open access Existing Practice: • Regulated open access Booking capacity Options: Mixture of contract • Contract carriage and common carriage • Common carriage • Mixture of contract and common carriage Open Access • Market carriage Reserving capacity Options: • Up to • Up to contracted amount contracted amount • First-come-first-served • Use-it-or-lose- • Overbooking allowed it • Use-it-or-lose-it • Secondary • Secondary trading allowed trading allowed (after approval by transporter) Pipeline Regulatory Options: ----- 47 Key Concepts Issue Existing Regulation (2007) Recommended or Options reforms System Rules approvals • Transporter and traders prepare Pipeline System Rules and • Regulator approves Balancing period Options: Monthly • Quarterly • Monthly • Daily • Hourly Recovering Options: Transporter takes unaccounted for • Transporter buys gas and from an inventory gas passes cost onto traders for each trader proportionately which each trader has to keep up • Transporter retains a pre- agreed % from each trader’s gas inputs • Transporter takes from an inventory for each trader which each trader has to keep up Charges for Options: Simple premium or commercial • Simple premium or discount on gas balancing discount price (after a tolerance band) • Range of premia & discounts • Balancing spot market C. Gas Pricing Framework & Transmission and Distribution Tariffs As with Third Party Access, by early 2007 Indonesia already had in place significant regulations regarding gas pricing and gas network tariffs, arising from the Oil and Natural Gas Law 2001, Government Regulations and BPH Migas Regulations. Specifically: • Oil and Natural Gas Law 2001; • Government Regulation No. 36/2004 – Oil and Gas Downstream; • Elucidation of Government Regulation No. 36/2004; • BPH Migas Regulation No. 4, “Guidelines to Determine Transportation Tariffs”, BPH Migas, Jakarta, 7 February 2005; • BPH Migas Regulation No. 3, “Guidelines to Determine Tariffs for Households and Small-Scale Consumers”, BPH Migas, Jakarta, 7 February 2005. 48 However, further reforms to the gas pricing framework and gas network tariffs were recommended. Existing Gas Pricing Framework (May 2007) The gas pricing policy in Indonesian law and regulation in early 2007 covered the following: 1. Prices to consumers are to be according to “a fair, healthy, and transparent competition” (Government Regulation No. 36/2004, Article 72); 2. Tariffs for transportation shall be regulated by BPH Migas. Several components of that tariff regulation were set out in BPH Migas Guidelines; 3. Prices to Household and small-scale customers shall be regulated by BPH Migas according to technical-economical principles (of cost recovery) but also reflect Government policies. Several components of that tariff regulation were set out in BPH Migas Guidelines; 4. In setting the tariffs, BPH Migas must pay attention to the interest of all the parties involved: gas owners, pipeline companies and consumers (explanation to Government Regulation 36/2004, Article 9, Clause c). In summary, the Gas Pricing Framework that existed in 2007 had the following elements: • Tariff setting powers: The company proposes tariffs and the calculations, and they are then reviewed and approved by the regulator; • Tariff policy: o Regulated tariffs: Transport (including distribution), plus households and small-scale consumers; o Unregulated tariffs: All others • Components of the gas chain: o Production: Unregulated; o Transport: Regulated o Sales:  Industry – unregulated  Households and small-scale consumers - regulated Recommended changes to Gas Pricing Framework The following recommendations were made to change Indonesia’s 2007 gas pricing framework: • Separate pricing and costing for each part of the gas chain (production including processing, transmission, distribution, sales); • Distribution o A bundled final price of the Distribution and Sales Charge (use of distribution pipes plus sales); o Pass through of all other costs; • Cost reflective tariffs for households and small-scale consumers, gas companies should not have to subsidise these consumers; • Cost of Service methodology for regulated tariffs; 49 • The Regulator needs to define how and if the CPI-X formula for regulated household and small-scale consumers will be applied. • Published tariffs at all levels (production, transport, sales); • Tariff review periods; o Transport and distribution – every three years; o Sales to household consumers – every three years; o Sales to large-scale consumers – when necessary; • Automatic price adjustments o Sales to large-scale consumers – monthly or quarterly; o Sales to household consumers – annual; o Automatic pass through of:  Gas cost;  Transport cost;  Non gas costs. Existing Framework for Regulation for Gas Network Tariffs (May 2007) • Depreciation – straight line; • Asset lives o Economic life; or o Period of security of the gas supply; • Asset valuation –by a valuation company (therefore current cost); • Rate of Return – IRR; • Transportation and distribution tariffs o Postage; or o Distance. Recommended changes to Gas Network Tariff Regulatory Framework The following recommendations were made to change the regulatory framework for establishing gas transmission and distribution network tariffs: • Design principles – Cost of Service approach; • Cost calculation – forecast costs; • Operating costs o Forecast actual costs; o Other costs passed through; o Unaccounted for gas:  Recovered through the balancing regime where there is one; or  Tariffs where there is not yet open access; • Asset lives – 20 years; • Transportation tariffs – zonal; • Distribution tariffs – postage. For each area and issue in turn, the existing regulation plus recommendations for a revised framework and transmission and distribution tariffs are summarized in Table A2.5. Table A2.5: Gas network tariffs: issues, regulatory regime in 2007, and recommended reforms 50 Area Issue Existing Regulation Recommended changes (2007) or Options Pricing Tariff setting Existing Regulation: ----- Policy powers • Company, approved by regulator Tariff policy Existing Regulation: • Tariffs reflect costs (at • Regulated tariffs: least approximately) o Transport • No subsidies o Household • Pass through of other and small- costs scale • Separate transportation consumers tariffs • Unregulated tariffs: • Regulated tariffs - Cost o All others of service • Published tariffs (all production prices by KPS, transport by transporter, sales by trader) Tariff review Options: Transportation: Every three period • When necessary years • Annual review Distribution: Every three • Five yearly years • Other Industry sales: When necessary Household and small users sales: Every three years Automatic Options: • Industry sales: Monthly Price Regular pass through of • Household sales: Annual adjustment allowable costs plus • Automatic pass through inflation adjustments: costs: • Monthly - Gas cost • Quarterly - Transport cost • Annual - Inflation - Non gas costs - Correction Components of Options: Separate pricing and costing gas price • Single bundled price for each part of gas chain • Separate pricing and costing for each part of gas chain Production Existing Regulation • Market prices • Market prices • Gas cost passed through to final consumer Options: • Published prices • Gas cost passed through to final consumer • Gas cost bundled with other tariffs Transportation Existing Regulation: ----- • Regulated transport tariffs 51 Area Issue Existing Regulation Recommended changes (2007) or Options Distribution Options: Bundled final price of • Separate regulated Distribution and Sales and distribution tariffs pass through of other costs • Bundled final price of Distribution and Sales and pass through of other costs • Single bundled final price Sales price: Existing Regulation: Free market pricing Industrial users • Free market pricing • Published maximum prices for consumer Options: groups • Individually • Individual discounts negotiated per allowed consumer • Published prices for consumer groups, discounts • Prices based on cost of service • Prices based on cost of competing fuel or gas trader Sales price: Existing Regulation: • Cost reflective tariffs Household and • Regulated pricing • No subsidies small users Regulated Costs to be Annual operating costs ----- Tariffs included Depreciation Methodolog Rate of Return y Cost Drivers Capacity ----- Commodity Customer Design Options: Cost of service principles • Cost of service approach • Incentive approach • Hybrid approach • Regulated average prices • Regulated average prices Transport and Distribution: • Individual prices Individual prices regulated Existing Regulation: • Sales: Individual prices per service Cost Options: Forecast costs calculation • Historic costs • Forecast costs • Benchmarking 52 Area Issue Existing Regulation Recommended changes (2007) or Options approach Operating costs Options: • Historic costs • Forecast actual costs Forecast actual costs • Standard costs o Best practice o Activity Based Costing • Long Run Marginal Costs • Estimated % of capital Other costs (eg taxes) passed cost through • Mixture of approaches • Other costs (e.g. taxes) Unaccounted for gas through balancing regime where passed through there is open access; • Other costs borne by gas company Unaccounted for gas through • Unaccounted for gas tariffs where open access is through tariffs not yet operating (see Open • Unaccounted for gas Access reform through balancing recommendations) regime Depreciation Existing Regulation: • Straight line Asset lives Existing Regulation: 20 years (being approximate • Economic life or length of license and most • Period of security of contract periods) gas supply Asset valuation Existing Regulation: Current cost, either: • Current cost • Replacement cost or o Replacement • Modern equivalent cost assets o Modern (Note: possible Indonesian equivalent tax implications) assets o Inflation adjusted original cost Rate of return Existing Regulation: • Internal Rate of Return (IRR) Allocation Options: Two part tariff (both methodology • Volumetric (all capacity and commodity) for cost commodity) recovery • All capacity • Two part tariff o Fixed variable (variable costs to commodity) o Seaboard 53 Area Issue Existing Regulation Recommended changes (2007) or Options (50% to capacity, 50% to commodity) Transportation Existing Regulation: Either Postage or Distance tariff classes • Postage or (but Zonal recommended, • Distance which can be one zone for a o Exact distance pipeline) o Zonal o Entry / exit Regulated Distribution Existing Regulation: Postage (can be by license Tariffs tariff classes • Postage or area, District or company Methodolog • Zonal Business Unit) y II. Implementation of reforms A number of the recommended changes to both the open access regime and gas pricing methodology were implemented in the period 2007 to 2013, as with the key reforms summarized in Table A2.6. Table A2.6: Summary of key reforms in Open Access and Gas Pricing, 2007-2013. Policy reform Reforms implemented area Third Party Access • Ministry of Energy & Mineral Resources Decree on Gas Master Plan – Transportation (MESDM No. 1321/2005) pipelines • PGN Gas Management System • PGN Pipeline System Rules 2007 • Indonesia Open Access Arrangement • BPH Migas Regulation No. 15/2008 • Ministry of Energy & Mineral Resources Decree No. 19/2009. • Ministry of Energy & Mineral Resources Decree No. 30/2010. Third Party Access • Ministry of Energy & Mineral Resources Decree on Gas Master Plan – Distribution (MESDM No. 1321/2005) pipelines • BPH Migas Regulation No. 15/2008 • Ministry of Energy & Mineral Resources Decree No. 19/2009. Gas pricing • Government Regulation No. 30/2009 • Ministry of Energy & Mineral Resources Decree No. 19/2009. • Ministry of Energy & Mineral Resources Decree No. 30/2010. • BPH Migas Regulation No. 22/2011 • BPH Migas Regulation No.16/P/BPH Migas/VII/2008 (Toll Fee (Tariff) of Gas Pipeline) • BPH Migas Rule No.12/BPH Migas/II/2008 (Special Right Auction of Gas Pipeline) • BPH Migas Regulation No. 08/2013 54 The full set of laws and regulations governing the Third Party Access and downstream Gas Pricing is available at the BHP Migas website. 10 Four of the key new reform instruments are summarized below. Minister of Energy and Mineral Resources Decree No. 19/2009 • Sets the structure of natural gas trading, transmission and distribution business and licensing. • Provides special rights and licensing for dedicated downstream. • The price setting authority and mechanism for piped natural gas differs by customer class: o Residential gas customers’ prices are regulated by BPH Migas. o Special users’ are subsidized industries whose gas prices are determined by the Minister of Energy and Mineral Resources. o General users’ gas prices are determined by gas companies and reflect market forces. General users consist of non-subsidized industries and power plants. Minister of Energy and Mineral Resources Decree No. 3/2010 • Upstream has a mandate to serve domestic demand by 25% of natural gas production. • Domestic gas utilization priorities for national oil and gas production, fertilizer, electricity and industrial uses. • Exemption for existing Gas Sales & Purchase Agreements, Heads of Agreement, Memoranda of Understanding or negotiations in progress. Government Regulation No. 30/2009 • Amended Government Regulation No. 36/2004 by changing its clause 72 from stating that “the prices of oil and gas, except gas for residential and small customers, are to be determined by a healthy, normal and transparent business competition” to stating “ the price of fuel and gas is to be regulated/determined by Government”. • GR 30/2009 was one reaction to critics of gas market liberalization and concerns that the reforms were in contravention of the Indonesian Constitution clause that states “commodities and natural resources are important to the welfare of the people and controlled by the state”. Master Plan for Gas Transmission and Distribution • The development and regular updating of the National Gas Network Master Plan is a requirement stipulated in Ministry of Energy & Mineral Resources Decree on Gas Master Plan (MESDM No. 1321/2005). • The current Gas Network Master Plan, covering 2012 to 2025, was issued on September 6, 2012 (Keputusan Menteri Energi dan Sumber Daya Mineral, No. 2700 K/11/MEM/2012). 11 10 See http://www.bphmigas.go.id/en/regulation.html 55 • The Master Plan maps gas fields, pipelines, power plants, major industrial gas consumption centers, gas monitoring stations, refineries, LNG plants, and gas supply franchise areas. Tabulated information is also provided on pipeline diameters, lengths, pipeline capacities and pipeline utilization. • Importantly, the Master Plan provides specific information on the access arrangement by type of pipeline (gas transportation or distribution), for both existing and planned pipelines. Access arrangement Pipeline type Transportation Distribution Existing Planned Existing Planned    Open Access      Dedicated upstream     Dedicated downstream     Self use • It is evident that a significant number of new gas pipelines are planned, many of which notionally will have open access arrangements, as required under Government Regulation 36/2004 and BPH Migas Regulation No.12/2008. However, if a planned new pipeline’s capacity is fully utilized under the related foundation Gas Transportation Agreement, the existence of an open access regime on the pipeline will be largely irrelevant because third parties will have limited opportunity to actually ship gas through the new pipeline. Reforms to the Open Access regime During the project implementation period, two significant reforms to the gas network open access arrangements were: (i) the development of PGN’s Pipeline System Rules and their approval by the regulator; and (ii) refinements to regulations concerning Special Rights that are designed to encourage further development of new open access transmission pipelines and open access gas distribution areas. 12 Since the development of the Pipeline System Rules was a key recommendation of the project’s technical assistance in 2007, it is discussed further. PGN Pipeline System Rules 2007 • PGN’s Pipeline System Rules (“the Rules”) provide the general terms and conditions relating to Third Party Access to PGN’s gas transportation networks. The Rules provide a detailed framework for gas transportation, nominations, allocation, attribution, measurement and stock transfer that apply to each Shipper who seeks to move gas through the Pipeline System. 11 Available at http://www.esdm.go.id/regulasi/kepmen/doc_download/1273-keputusan-menteri-esdm-no2700- k11mem2012.html 12 Special Right Auction of Gas Pipeline: BPH Migas Regulation No.12/BPH Migas/II/2008. 56 • The Rules must be obeyed by both Transporter (PGN) and Shippers. In the event of any inconsistency between the Rules and any Gas Transportation Agreement between the Shipper and Transporter, the provisions of the Rules prevail (Clause 34 of Rules). • Key parts of the Pipeline System Rules are: (1) Operating philosophy for the pipeline; (2) Obligation on the transporter to operate on an Open Access Basis; (3) Gas management system; (3) Technical Rules, including on gas quality and safety standards; and (4) Legal and Miscellaneous Rules, including dispute resolution. • The Pipeline System Rules were developed by PGN in consultation with gas Shippers and other interested parties, and submitted to the downstream gas sector regulator BPH Migas for approval. • The Rules were approved by by BPH Migas and now form a critical part of the Indonesia Open Access Arrangement for gas transportation pipelines. Reforms to gas pricing 1. Gas commodity pricing • Some reforms to domestic gas commodity pricing were made after the publication of Minister of Energy and Mineral Resources Decree No. 19/2009. • It appears that many of the pricing reforms recommended in 2007, as part of the project’s technical assistance, have been implemented. Specifically: geographically divergent gas prices are now set; there is greater transparency on what makes up end user gas prices; and there is greater transparency on the setting of gas pipeline tariffs. • The Government of Indonesia continues to play a dominant role in setting domestic gas prices and in allocating that gas among competing uses. The total volume of Indonesia’s domestic gas supplies is still heavily influenced by: upstream Production Sharing Contracts; the government’s policy that 25% of gas produced in Indonesia be allocated to domestic usage; the opportunity costs of LNG exports; gas infrastructure constraints; government decisions on how domestic gas is allocated among various users; and government decisions on which users receive subsidized gas prices. In addition, the continued subsidization of fuel oil, diesel, coal and other fossil fuels for certain consumers is likely constraining further development of Indonesia’s domestic gas market. • Consequently, Indonesia remains in a situation of underlying domestic gas demand being unmet due to a lack of sufficient gas supply coming to market. While there have been dramatic changes to Indonesia’s domestic gas consumption – arising from the reductions in fuel subsidies in 2005, combined with investments in gas infrastructure, and structural and market reforms – the domestic gas market remains underdeveloped. • The wide and growing spread between PGN’s average gas purchasing price and its average sale price to customers is reflective of Indonesia’s domestic 57 gas supply-demand balance situation, and distortions in the domestic energy market. In 2012, PGN’s Average Selling Price of $8.54/MMBTU exceeded its Average Gas purchase price of $3.93/MMBTU by $4.61/MMBTU. This price spread has grown over time and is one of the reasons that PGN has quickly grown into a very profitable gas company. 13 Another reason for the rapid increase in PGN’s profitability and revenues in the period 2005 to 2013 is the large increase in the volume of gas sold domestically following the development of new gas infrastructure in West Java. • Further of expansion of Indonesia’s gas production capacity, pipeline and storage capacity, and LNG regasification capacity would contribute to improving gas supply, changing the demand-supply balance, and thereby domestic gas prices. • Additional reforms to gas pricing in Indonesia could spur an increase in domestic gas supplies and the usage of gas. Further increases in the use of gas would help reduce localized pollution and greenhouse gas emissions. There is also scope to review the extent to which gas sector unbundling has occurred, and how effectively this has contributed to: increased competition, transparency, and efficiency gains. Such a review could also assess: (i) how gas sector efficiency gains have been shared between gas suppliers, pipeline owners, gas consumers, and others; and (ii) the scope for and benefits of greater gas pipeline interconnection within Indonesia and with East Asia. 2. Pipeline tariffs • BPH Migas is empowered to set the tariffs for transporting gas through pipelines. These tariffs are also referred to as toll fees. • In setting gas pipeline toll fees, BPH Migas is obliged to consider the economics of pipeline owner, and the interests of the shippers and consumers (Government Regulation No 36, 2004, Article 33). • The regulator uses a cost-of-service rate making methodology to establish the toll fees (BPH Migas Rule No. 16/P/BPH Migas/VII/2008). Using this methodology BPH Migas seeks to establish toll fees that are fair, transparent, accountable and affordable, by taking into account the economics and engineering aspects of gas pipelines. = ℎℎ • Under the cost-of-service ratemaking, the toll fees are designed taking into account a pipeline's cost of providing services, including the ability of the pipeline owner to earn a reasonable return on its investment (BPH Migas Regulation No.8/2013). 13 In contrast, during 2005 the spread was $2.45/MMBTU; with PGN’s Average Selling Price being $5.00/MMBTU and its Average Gas purchase price being $2.55/MMBTU. 58 = + & + + + + • BPH Migas establishes the allowable rate of profit in the above Cost of Service calculation after assessing the profitability of the gas pipeline enterprise as follows: = ℎ × . III. Summary of gas pricing and open access reforms In summary and conclusion, it appears that project’s technical assistance contributed to significant reforms in the areas of domestic gas pricing and open access to gas pipeline networks. The form and content of the new pricing and open access regimes implemented since 2007 reflect, in large parts, many of the findings and recommendations made in the project’s technical assistance reports. At the end of the project: 1. New streamlined regulatory arrangements for Third Party Access to transportation lines were established in 2007 and 2008 and all PGN’s gas transmission pipelines now operate under Open Access arrangements. 2. There is limited implementation of Third Party (Open) Access on PGN's Gas Distribution networks -- with this being restricted to national interest and government programs. 3. Efforts to implement revisions to the existing third Party (Open) Access arrangements for Gas Distribution Networks have stalled, together with moves to unbundle PGN's distribution network assets. That is, the Energy & Mineral Resources Ministry Regulation No. 19, 2009 has not been effectively implemented because the government is still considering the matter. 4. There have been some reforms to gas pricing, including: a) implementation of new regulations concerning the calculation of gas transportation and distribution tolls; b) increased transparency on gas prices; c) PGN shifting to regionalized and differentiated pricing on a nationwide basis from April 1, 2010; b) PGN implementing large increases in its selling prices to customers in West Java in 2012 and 2013 following increases to PGN’s buying price of gas. 5. Further reforms to gas pricing are unlikely to be implemented until there is a consensus of views on key aspects of the pricing framework and a political will to scale back the range and number of special users’ whose gas prices are determined by Minister of Energy and Mineral Resources. As of April 1, 2014, there appears to remain a divergence on views between Bappenas, SKK Migas (the successor to BP Migas), and BPH Migas on some aspects of the gas pricing regime. 59 6. The government has not abandoned the use of ministerial allocations that specific how gas reserved for domestic supply is to be split across domestic gas customers. For example: a. On February 7, 2013, the government set the allocation of domestic LNG for FSRU terminals across Indonesia. PGN’s FSRU at Lampung received an allocation of 10 LNG cargoes per year for 10 years starting in 2015. b. Subsequently, on May 13, 2013, SKK Migas issued a new allocation of 644 cargoes of LNG to the domestic market over the period 2013- 2021. PGN’s FSRU Lampung was allocated 18 LNG cargoes per year starting from 2016, with the supply to come from BP Tangguh, Chevron IDD and Eni Muara Bakau. The allocation set only the amount of the cargoes, with the commercial terms of transactions to be negotiated between gas suppliers and customers. 7. A degree of vertical integration has been allowed to take place, with: a) PGN investing in gas exploration; and b) PLN and several gas producers in Sumatera have successfully gained licenses to develop their own open access transmission or distribution pipelines to directly sell gas to large gas customers within some of PGN’s existing distribution areas. To date there is little interest in significantly expanding the small number (15) of low pressure distribution networks (Gas Kota or City Gas networks) that service household customers. IV. Follow on reforms to Indonesia’s domestic gas market There is considerable scope for further World Bank technical assistance in Indonesia’s domestic gas market, particularly in the critically strategic areas of: (i) gas pricing; (ii) further industry restructuring; (iii) gas infrastructure financing in greenfield areas; and (iv) further transitioning more towards market based means of balancing the energy security need for adequate petroleum fuel supplies for domestic use versus the opportunity cost of foregoing long term revenues arising from exporting LNG at high global prices. Indeed, the Bank is already seeking to re-engage with Government of Indonesia on matters of gas sector policy, as part of the Bank’s broader strategic engagement. Specifically, in 2012-2013 the Bank provided technical assistance under the Gas Development Master Plan. That TA was undertaken in partnership with the Government of Indonesia (DG Oil & Gas, and BAPPENAS) with funding from Australia’s bilateral program (formerly referred to as AusAID INDII). The activity was designed by the Bank through discussions with key stakeholders in Indonesia's gas sector including the Ministry of Energy and Mineral Resources, BAPPENAS, the upstream, and downstream gas sector regulators, the private sector and others. In December 2013 that TA work produced 10 policy notes, a gas planning and optimization model, and a benchmarking and final report in order to assist the Government with increasing domestic gas supply, relieving transportation bottlenecks, improving the pricing regime, relieving the demand supply imbalance, identifying policy gaps, and making recommendations for each of the TA areas. 60 During the first half of 2014, the Government was seeking to formalize the recommendations through the issuance of two ministerial and one Presidential decree in the following three areas: 1. Gas demand and supply balance; 2. Gas infrastructure financing and tendering; and 3. Gas pricing. During March 2014, the Government was forming three task forces at SKK MIGAS (upstream regulator); DG MIGAS (Directorate General, Oil & Gas); and Bappenas (State Planning Ministry) for getting the decrees issued by end April 2014. Bappenas, which is chairing the Steering Committee, has requested a more detailed study and analytical underpinning to support the gas pricing decree. The Bank, in conjunction with Australia, has sought to meet that request. 61 Annex 3. Economic and Financial Analysis Project Economic Analysis Methodology at Appraisal Economic Costs The ex-ante economic costs of the project included: (a) total investment costs for gas transmission pipelines (partly financed by the JBIC) and for gas distribution network (partly financed by the Bank); (b) O&M costs related to the transmission and distribution facilities; (c) expenditures for gas purchases; (d) cost associated with gas losses incurred during transmission and distribution, and (e) conversion investment costs to be undertaken by customers for fuel switching. All the costs excluded taxes and duties and financing costs. The conversion factor was considered as 1.0 when estimating the economic costs from financial costs because the distortions in the exchange and wage rates in the overall costs were not considered significant enough to justify the use of shadow prices. Detailed assumptions considered in the ex-ante cost analyses were as follows: • The investment costs for the transmission and distribution components of the project was estimated at US$408.79 million and US$109.52 million; • The annual incremental O&M costs were assumed to be 2 percent of the investment costs for transmission and distribution components of the project. • Gas losses were assumed to be 2 percent of the annual quantity of gas received from producers. • Under the gas purchase agreement between Pertamina and PGN, Pertamina would sell the gas to PGN at the inlet of the transmission line for US$2.00 per mmBtu for the first year, and the price would be indexed at 2.2 percent for the ensuing years. Although this reflected a financial cost, it was assumed to be the average incremental economic cost (AIC) of the exploration, development and production, given the proximity of this value to the AIC calculated for Indonesia as part of the Bank’s sector analytical work in 2000 (that is, US$1.90–2.25 per mmBtu). This gas purchase price was used to estimate the gas purchase costs for the project. Economic Benefits The ex-ante economic benefits of the project (cash flow from sales of gas by PGN) were estimated based on the assumption that the economic value of gas was equal to the future market prices of oil products to be replaced by gas. Oil product prices were based on the Bank’s projection of oil price during appraisal at US$26 per bbl. Other benefits of the project, such as energy efficiency and product quality improvement due to switching from oil products to gas, as well as environmental benefits of substituting cleaner gas for oil products, were not considered in the estimate. Detailed assumptions ex-ante benefit analysis were as follows: 62 • The volume of gas sales: Although the carrying capacity of the transmission is 450 mmcfd and the capacity of the distribution system was 550 mmcfd, the evaluation of the project benefits was based on the gas purchase agreement signed between PGN and Pertamina. According to the agreement, Pertamina would supply gas to PGN from June 2006 according to the following schedule: 150 mmBtu for the first year, 200 mmBtu for the second year and 250 mmBtu from the third year up to 2018. It was assumed that after 2018, the gas supply would remain at 250 mmcfd level and the price would be the same as that in 2018. At the time of appraisal, PGN had already secured other sources to supply the West Java market, of which about 160 mmcfd could be distributed by the system expanded under the project. • According to PGN’s gas market survey prior to appraisal, the fossil fuels to be replaced by gas from the proposed project would be fuel oil (18 percent), automotive and industrial diesels (72 percent and 10 percent, respectively). • The prices of fuel oil and diesel are estimated at US$3.74 per mmBtu (fuel oil), US$6.23 per mmBtu (automotive diesel) and US$6.03 per mmBtu (industrial diesel) based on the Bank’s recent long-term forecast of crude oil prices available at appraisal: US$26 per bbl. • Customer conversion costs were estimated by PGN at about US$10.3 million. Methodology at project completion The ex-post economic cost benefit analysis used an identical methodology to that used at appraisal, except that: • Actual costs at the end of the project are used. The transmission investment costs were US$433.76 million and the distribution investment costs US$81.76 million (see Tables A3.1 an A3.2). Customer conversion costs were $10.3 million. • The volume of gas sales: o Actual data on the level of increased gas sales in the West Java area (SBU1) through the South Sumatera West Java 1 (SSWJ1) transmission pipeline has been used, covering the period 2005 to 2013. o For the period 2009 to 2022, it is assumed that the full 400 mmscfd capacity of the SSWJ1 pipeline is utilized to supply West Java, based on the fact that PGN’s contracted volumes into West Java exceed 400 mmscfd and that some of them must be flowing down the SSWJ2 pipeline. SSWJ1 was built first and only its capital costs and capacity are taken into account in the ex-post cost benefit analysis; consistent with the ex-ante cost-benefit analysis. Only later was the SSWJ2 pipeline built, adding another 400 mmscfd of potential capacity and bring the combined gas pipeline transfer capacity between South Sumatera and West Java up to 800 mmscfd. Consequently, SSWJ2 is excluded from this ex-post cost-benefit analysis. 63 o For the period 2023 to 2025, gas volumes fall to 394 mmscfd, in line with PGN’s contracted gas for 2022. • Gas prices. o The ex-post analysis uses historic data on PGN’s Average Purchase Price of Gas and its Average Selling Price of Gas in the period 2004 to 2013. Average PGN Gas Average PGN Average Gas Purchase price Gas Selling price Price Spread ($/MMBTU) ($/MMBTU) ($/MMBTU) 2004 2.55 4.75 2.20 2005 2.55 5.00 2.45 2006 2.69 5.00 2.31 2007 2.60 5.49 2.89 2008 2.37 5.49 3.12 2009 2.78 5.49 2.71 2010 2.79 6.35 3.56 2011 3.20 6.85 3.65 2012 3.93 8.54 4.61 2013 4.49 9.20 4.71 Source: PGN Annual Reports and Investor Briefings 64 o Customers’ Willingness to Pay (WTP) for gas is assumed to be equal to the PGN’s Average Selling Price of Gas. This WTP assumption affects the calculation of project benefits. o For the period 2014 to 2025, it is assumed that PGN’s Average Purchase Price of Gas remains at its 2013 level ($4.49/MMBTU) as does its Average Selling Price of Gas ($9.20/MMBTU). Results of ex-post economic cost-benefit analysis • The ex-post economic cost-benefit analysis indicates that the project has a very high net benefit, valued at $2.7 billion in NPV terms with 10% discount factor. The Economic Rate of Internal Return (EIRR) is also high at 64.5%. • The drivers of these very strong results appear to be: (i) the substantial spread between the Average Purchase Price of Gas and the Average Selling Price of Gas; and (ii) the increased volumes of gas sold. • These very positive results vindicate the decision to proceed with the project and point to the large potential for further economic benefits to arise from future infrastructure investments in Indonesia’s downstream gas sector. 65 Table A3.1: Actual investment cost of the transmission component Financial Cost Conversion Economic Price Local Foreign Total Factor Local Foreign Total (million (million (million (million (million (million (million No. Item US$) US$) US$) US$) US$) US$) US$) Pagardewa-Labuhan Maringgai(Onshore)/Full Turnkey (CP- 1 1) 0.00 174.74 174.74 1.00 0.00 174.74 174.74 2 Labuan Maringgai - Cilegon (Offshore)/Full turnkey (CP-2) 0.00 159.44 159.44 1.00 0.00 159.44 159.44 3 Cilegon - Cimanggis (Onshore)/Full turnkey (N/A) 0.00 0.00 0.00 1.00 0.00 0.00 0.00 4 West Java/Cilegon Distribution/Full turnkey (CP-4) 0.00 28.53 28.53 1.00 0.00 28.53 28.53 5 Compressor Package (CP-5) 0.00 42.42 42.42 1.00 0.00 42.42 42.42 6 Project Management Consultant (JOE CONNUSA) 0.00 28.63 28.63 1.00 0.00 28.63 28.63 7 O&M Consulting Services (N/A) 0.00 0.00 0.00 1.00 0.00 0.00 0.00 8 Administration Cost (N/A) 0.00 0.00 0.00 1.00 0.00 0.00 0.00 9 VAT (N/A) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 10 Land Acquisition and Compentsation (N/A) 0.00 0.00 0.00 1.00 0.00 0.00 0.00 11 Price Escalation (N/A) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 12 Physical Contigency (N/A) 0.00 0.00 0.00 1.00 0.00 0.00 0.00 13 Total 0.00 433.76 433.76 1.00 0.00 433.76 433.76 66 Table A3.2: Actual investment cost of the distribution component Financial Cost Conversion Economic Price Local Foreign Total Factor Local Foreign Total (million (million (million (million item (million US$) US$) US$) US$) (million US$) US$) (million US$) A. Infrastructure 1.72 45.70 47.41 1 1.72 45.70 47.41 B. Technical Assistance 0.00 11.94 11.94 1 0.00 11.94 11.94 C. Building and Land 0.05 12.58 12.64 1 0.05 12.58 12.64 D. Physical Contingency 0.00 7.33 7.33 1 0.00 7.33 7.33 E. Price Contingency 0.00 2.44 2.44 0 0.00 0.00 0.00 F. VAT 0.00 0.00 0.00 0 0.00 0.00 0.00 Total Project Cost 1.77 79.99 81.76 0.87 1.77 77.55 79.32 67 Table A3.3: Results of Ex-post Economic Cost-Benefit Analysis Investment Cost O&M Year Gas Supply Gas Sales Transmission Distribution Consumer Transmission Distribution Gas Purchase Subtotal Benefit WTP Net Benefit Conversion Cost (mmscfd) (MMbtu) (million US$) (million US$) (million US$) (million US$) (million US$) (million US$) (million US$) (million US$) (million US$) 2004 0 - 2.87 0 0 0 0 0 2.9 - (2.87) 2005 0 - 2.60 0 4.4 8.7 1.6 0.0 17.3 - (17.31) 2006 0 - 258.47 3.81 2.5 8.7 1.6 0.0 275.1 - (275.09) 2007 74 25,910,896 46.36 27.98 3.4 8.7 1.6 67.4 155.5 142.3 (13.24) 2008 237 82,669,680 59.76 22.61 0 8.7 1.6 196.1 288.7 453.9 165.12 2009 400 139,552,000 24.53 9.91 0 8.7 1.6 387.9 432.7 766.1 333.47 2010 400 139,552,000 26.83 6.95 0 8.7 1.6 390.0 434.1 886.2 452.06 2011 400 139,552,000 10.44 8.42 0 8.7 1.6 447.0 476.2 955.9 479.74 2012 400 139,552,000 1.91 2.09 0 8.7 1.6 549.1 563.4 1,191.8 628.35 2013 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2014 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2015 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2016 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2017 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2018 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2019 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2020 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2021 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2022 400 139,552,000 0 0 0 8.7 1.6 627.1 637.4 1,283.9 646.43 2023 394 137,390,435 0 0 0 8.7 1.6 617.4 627.7 1,264.0 636.26 2024 394 137,390,435 0 0 0 8.7 1.6 617.4 627.7 1,264.0 636.26 2025 394 137,390,435 0 0 0 8.7 1.6 617.4 627.7 1,264.0 636.26 Total 433.76 81.76 10.3 0 0 PV @ 10% 763,224,033 301.0 50.0 7.8 3353.5 6077.2 2723.64 EIRR 64.54% 68 Annex 4. Bank Lending and Implementation Support/Supervision Processes (a) Task Team members Responsibility/ Names Title Unit Specialty Lending Noureddine Berrah Task Team Leader EASEG Steve Burgess Senior Social Development EASSD Specialist Migara Jayawardena Senior Infrastructure Specialist EASEG Leiping Wang Senior Energy Specialist EASEG Eka Putra Energy Specialist EACIF Rajiv Sondhi Senior Financial Management EACIF Specialist Yogana Prasta Operations Adviser EACIF . Farida Zaituni Operations Analyst EACIF Ninin Dewi Social Assessment Specialist EACIF (Consultant) Julia Hanniawaty Team Assistant EACIF Sri Oktorini Team Assistant EACIF Anthony Toft Chief Counsel LEGEA Raj Soopramanien Senior Counsel LEGEA Xiomara Morel Senior Financial Officer LOAG1 Yuling Zhou Senior Procurement Specialist EASEG Mohammad Farhandi Financial Specialist EASEG (Consultant) Salahuddin Khwaja Gas Distribution Engineer EASEG (Consultant) Cristina Hernandez Program Assistant EASEG Teri Velilla Program Assistant EASEG Supervision/ICR Noureddine Berrah Consultant EASIS Former TTL Ninin K. Dewi Consultant EASIS Consultant Christina I. Donna Financial Management Specialist EASFM FM Supervision Puguh Imanto Energy Specialist EASIS TTL Senior Energy Migara Jayawardena Senior Energy Specialist LCSEG Specialist Salahuddin Khwaja Consultant EASCS Consultant Yan Li Consultant SASDA Consultant Procurement Zhentu Liu Senior Procurement Specialist EASR2 Superision Sr Financial Management Rajat Narula EASFM FM Supervision Specialist Environmental Ina Pranoto Senior Environmental Specialist EASIS Safeguards 69 Yogana Prasta Operations Adviser EACIF Operations Adviser Eka Zarmen Putra Operations Officer CFPTO Operations Officer Vivianti Rambe Consultant EASID Consultant Dhruva Sahai Sr Financial Analyst EASWE Former TTL Elvi Yani Dewi Nasution Energy Specialist EASIS Energy Specialist Schaefer Senior Finance Rajiv Sondhi Senior Finance Officer CTRLA Officer Leiping Wang Lead Energy Specialist SASDE Former TTL Farida Zaituni Consultant EASIS Consultant Yuling Zhou Lead Procurement Specialist EASR2 FM Supervision Tendai Gregan Energy Specialist EASNS ICR Author (b) Staff Time and Cost Staff Time and Cost (Bank Budget Only) Stage of Project Cycle USD Thousands (including No. of staff weeks travel and consultant costs) Lending FY03 0 16.54 FY04 15.25 234.35 FY05 37.63 197.06 FY06 4.75 40.31 Sub Total 57.63 488.26 Supervision/ICR FY06 3.20 18.31 FY07 13.98 67.33 FY08 11.70 69.88 FY10 7.86 54.24 FY11 12.66 67.51 FY12 23.80 63.13 FY13 12.32 25.43 FY14 12.92 19.63 Sub Total 98.44 385.46 Total: 156.07 873.72 70 Annex 5. Beneficiary Survey Results Not Applicable. 71 Annex 6. Stakeholder Workshop Report and Results Not Applicable. 72 Annex 7. Summary of Borrower's ICR and/or Comments on Draft ICR (a) Borrower Completion Report Note: The Borrower submitted a 36 page report, which is archived in the project files. The following executive summary is the borrower’s own. Executive Summary The utilization of natural gas in Indonesia is still constrained by some inter-related issues among others the underdeveloped of the natural gas transmission and distribution infrastructure. This Indonesia Domestic Gas Market Development Project which intended to expand the use of natural gas in the West Java market under Loan No. 4810-IND addressed such matter. The intermediate result of this project also addressed other aspects such as PGN Restructuring, third party access and gas pricing which expected to support the expansion of West Java Gas Distribution network. The Loan Agreement and Project Agreement have set the indicators of the Project Development Objectives to be fulfilled and milestones to be achieved. The achievement of such indicators and milestones was sourced from project reports and documentation and consultation with relevant PGN internal sources of information such as PGN’s Strategic Business Unit, Corporate Finance, HSE, HRD, and Organization and Business Process Division. Overall, the project outcome as stated in the Project Agreement has been achieved as indicated based on actual data in 2010 by the increasing of PGN’s gas sales in West Java (573 mmscfd), increasing of the number of customers converted to gas (444 customers) and the significant reduction of major air pollutants and greenhouse gas in the form of: (i) SO2 (135,000 tons per year), (ii) NOx (163,000 tons per year), (iii) TSP (76,000 tons per year), (iv) CO2e (3,964,000 tons per year). All such achievement were “highly satisfactory” and exceeds the target stated in the Project Agreement. However the timeframe to complete the major milestone was extended compared to the original plan due to adjustment to the actual conditions encountered during the implementation period. As for the achievement of other aspects such as PGN Restructuring, third party access and gas pricing were “moderately satisfactory”. As an achievement, PGN has strengthened its capability in planning and operating the distribution system, improved its organization structure, implemented some degree of third party access for the key transmission activities and limited third party to support national interest and government program for some distribution activities. With regard to the gas pricing, PGN has completed the study on Gas Pricing Framework and Methodology & Implementation Rules for Transmission and Distribution Tariffs and has submitted such report study to World Bank and BPH Migas for consideration. Currently the government plans to revise the open access and unbundling regulation stipulated in the Energy Ministry Regulation No. 19 Year 2009 in order to make the implementation of such scheme to become more effective. PGN is still looking forward for such revised regulation. 73 During the implementation of the project, there are some obstacles which related to the commercial and technical aspects of the project. Recommendation in this report addressed such aspects for further improvement in the project implementation. Lessons Learned The following are the lessons learned from the implementation of the contract packages under the project: a. For EPC Pipeline Installation, Offtake Stations and SCADA & Telecommunication and PCC Branchline Installation, Customers Attachment & MRS Installation Contract Packages: • Detail Investigation about the road regulation (for example: regarding road backfilling material) is required to be performed prior to the bidding process and should be incorporated in bid document. • Approval of crossing method (include the requirement of pipe casing) from relevant authority is required to be obtained and defined prior to the bidding process and should be incorporated in bid document. • All information regarding interface works including location of connection point (location of Offtake Station), location of the customers & premises (for SCADA installation) and Supporting Facilities of existing customers (electricity, SCADA houses, AC, etc.) should be defined prior to the bidding process and incorporated in bid document. • Status of permit and principal permit of the pipeline route which shall be obtained by the Employer should be cleared prior to the bidding process and defined in the bid document. • Detail soil investigation along the route (include under road crossing) should be performed in order to minimize the claim due to unforeseen condition. • Conceptual Design and overall plan should be fixed prior to bidding process. • Land Acquisition of the Offtake Station should be fixed and cleared prior to Bidding process. • Target schedule of gas-in for each customer should be defined clearly in bid document. • There was one contract package which was cancelled due to the nominated bidder requested an escalation of bid price due to the long period between the bid submission and bid award. b. For Line Pipe Procurement and MRS Procurement Contract Packages: • Quantity of procured pipe and MRSshould be calculated in detail for each diameter/size based on the actual requirement. • Specification of pipe and MRS (including the capability of manufacturer) and target schedule should be examined carefully prior to bidding process. • Qualification of local vendor shall be evaluated in detail during bidding process. • Spare part material for MRS shall be prepared with sufficient quantities. c. For Special Tools Procurement Contract Packages: 74 • The Contract has been divided into several packages for each kind of tools & equipment which resulted in a long time for completion for this contract. Findings and recommendations Table A7.1 summarizes the findings and recommendations from the implementation of each contract package under the project. Table A7.1: Findings and Recommendations of PGN Findings Recommendations There are some changes ocurred during In order to prevent avoidable changes ocurred contract execution which resulted in during contract execution which caused by several Contract Amendments and changes in conceptual planning/design as a adjustment of Contract Price. variation and/or claims raised by the contractor due to insufficient or ambiguity of the data provided in the Bid Documents, then: 1. The detail survey (including soil investigation and establishing data required to determine the construction method) shall be conducted and survey data shall be provided in sufficient detail in the bid document. 2. Status of permit and principal permit of the pipeline route which shall be obtained by the Employer should be cleared prior to the bidding process and defined in the bid document. 3. Conceptual design and overall planning of the project shall be fixed prior to incorporation in the bid document. 4. The condition of existing facilities which are interfacing with contractor’s works shall be defined clearly in the bid document. 5. For procurement contract, the detail investigation of the manufacturers capacity, design/sizing of the equipment to be procured and the required special tools to be provided shall be conducted and defined clearly in the bid document. For EPC contract which the procurement In order to ensure the quality of procured of the main materials such as line pipes materials which will eventually influence the and ball valves are included under quality of the delivered facility, it is contractor’s scope of works, there are recommended that the main materials is some degree of difficulty in ensuring that procured by the employer, should the contract the quality of materials procured comply type is an EPC contract then such materials with the employer’s requirements. will be provided as free issue materials. If it is unavoidable to include the scope of main materials procurement into contractor’s scope of works, then the detail requirement related to the quality of materials (including raw materials, workmanship, stockist, 75 Findings Recommendations acceptance tests, etc) shall be defined in the bid documents. There is payment for contract The procedure and time required for the amendment which was delayed and approval of contract amendment both from impacted to the contractor’s cash flow PGN’s management and World Bank shall be since under PGN’s internal rules the made as simple and efficient as possible. payment cannot be conducted prior to the execution of contract amendment. There are some difficulties in Careful selection of contract type by accommodate justified changes as a considering the proper allocation of risks, variation since the selected contract typeincluding stipulation related to the cost is inappropriate and cannot anticipate adjustment due to escalation considering and accommodate such kind of changes. economic situation in Indonesia. Poor performance of the contractor. The selection of the contractor during bidding process shall be improved in order to obtain a qualified contractor. There are some delay of the works which The conditions of contract shall include an supposed to be able to be anticipated early warning mechanism that allow both earlier and managed to avoid greater loss parties to recognize any events which may in the execution of the project. impact to the cost and/or time for completion. So that the anticipation and mitigation plan can be provided and executed as soon as possible. The conditions of contract shall also include a mechanism that allow employer to do step in process in the case of the contractor can not perform the works in accordance with the contract to the extent of such poor performance will jeopardize the completion of the works. There are some difficulties in performing For interfacing works with the customer the works which are related to the facility, the status of customers shall be fixed customers due to the changes of prior to incorporation in the bid document. customers status and matters related to the access, permit and interfacing works Considering that the customer attachment with the customer facility. installation works required close coordination with SBU’s customers, it is recommended that in the future that the contract for such kind of scope of works is handling by SBU instead of the project group. Conclusion Development of gas infrastructure while supported by effective gas pricing policy will potentially give significant impact to overcome many problems such as the low rate of investment and to improve the weak public service. It also strengthened PGN’s gas distribution infrastructure and increase company revenue which further will be utilized for infrastructure development in accordance with government programs to reduce oil fuel subsidy. Gas infrastructure development also has a significant rule in reducing environment problem, especially air pollution and greenhouse gas emissions. 76 This project raised the opportunity for many industries, especially in West Java, to easily utilize gas for their operation which eventually increasing the economic efficiency by using cheaper, cleaner fuel and reducing its production cost. This project also gave PGN an institutional strenghtening by restructured and improve PGN’s financial management, operation, planning, and safety management system that help PGN to serve better. (b) Borrower Comments on Bank ICR Two documents are required for the completion process of Domestic Gas Market Development Project: Implementation Completion and Result Report (ICR) at the World Bank side and Borrower Completion Report at the PGN side. The Borrower Completion Report which contains records of project achievements, as well as project evaluation for future improvement, has been submitted to the World Bank. The sections below are the review and comment on the draft of ICR prepared by the World Bank for project ratings: We agree with the “Satisfactory” rating for the outcomes and Bank/Borrower performance. The ratings are supported with the record of fulfilled PDO indicators and Intermediate Outcome Indicators. The project was completed on time, within budget, and with successful implementation. However, the detail explanation in the section 5 (Assessment of Bank and Borrower Performance) provides different performance rating compared to the rating in the Table of Ratings Summary (page iv). Some ratings provided in the Section 5 are “Moderately Satisfactory”. 77 Annex 8. Comments of Cofinanciers and Other Partners/Stakeholders Not Applicable. 78 Annex 9. List of Supporting Documents All documents filed in IRIS, WBDocs and Project Portal, such as aide memoires, reports, email correspondences, etc. Cameron, P. 2007, “Open Access to Indonesian Gas Networks”, Final Report, prepared for BP MIGAS and Ministry of Energy & Mineral Resources, (Author: Peter Cameron), Report No. MI980/02, MERCADOS Energy Markets International, Madrid, 20 April 2007. Nexant Ltd. 2006, “Gas Pricing and Utilisation Study”, Draft Final Report, Prepared for PGN by Nexant Ltd (in association with Pendawa Consultama Sejati) [Contract 001200.PK/911/UT/2005], Nexant Ltd., Bangkok, February 2006. PGN 2013 Audited Financial Statement. PWC 2006, “PGN Restructuring and Privatization Study — Final Report”, report to PGN by PriceWaterhouseCoopers, PWC, Jakarta, 20 October 2006. World Bank 2012, “FY2013 – FY2015 Country Partnership Strategy for Indonesia”, World Bank Group, Washington DC, 13 December 2012. 79 MAP 80 81 82 83 84