Social safeguard designs initially underestimated the resettlement impacts, omitted right-of-way compensation requirements, and proposed unsuitable mitigation measures such as voluntary land donations. As a result, the project was non-compliant with social safeguards requirements for 26 months. Safeguards implementation came into better shape, following the reconduct of detailed measurement survey of losses and execution of a resettlement corrective action plan in 2018. Although some issues remained pending as of project physical completion in 2019, these were eventually resolved with the resumption of discussions between ADB and the EA in 2020. The experience highlights the importance of an accurate assessment of potential impacts and EA/IA safeguards capacity and EA/IA training and capacity building to ensure proper safeguards design and implementation. Context-sensitive issues such as the suitability of voluntary land donations, should be carefully weighed and agreed with the EAs/IAs at the early stage of project implementation.
The ADB grant-financed module 1 was completed more than two years ahead of the KEXIM loan-financed modules 2 and 3. However, because of the interdependence of the three transmission modules, module 1 cannot be operationalized without the completion of modules 1 and 2. The risk of procurement and implementation delays in the co-financed components should have been considered in the project design. When project components can be made technically independent, this option should be used to avoid delayed benefits.
Cost overruns initially led to the removal of one transmission line, but a shorter line was added once it was confirmed it could be completed using the project’s available financing envelope. These overruns were caused mainly by higher than envisaged materials costs. For example, between 2009 and 2011 copper prices increased by about 54%, aluminum by about 44%, and steel by about 30%. The overruns could have been mitigated by a thorough assessment of the relevant international market conditions and the incorporation of results into the project cost estimates.
The project had two turnkey contracts procured through international competitive bidding: (i) an ADB-financed $12.6 million contract, open to contractors from all ADB member countries, and (ii) the KEXIM-financed $34.82 million contract, open only to contractors from Korea. The ADB-financed contract, once awarded, was implemented smoothly. However, the KEXIM-financed contract encountered difficulties to the contractor’s limited experience in the Lao PDR, which caused delays in conducting surveys, fine-tuning technical designs, obtaining various approvals, and preparing the contractor environmental management plan.
Extended five times, the completion of this project was 5.5-year behind schedule. Delays occurred because of low project readiness and weak procurement capacity of the executing agency. As a result, against the procurement plan to award all transmission works contracts in quarter 4 of 2012, the ADB-financed contract for module 1 was awarded in quarter 2 of 2014 while the contracts for modules 2 and 3 financed by the government of Korea through the Korean Export and Import (KEXIM) Bank was awarded in quarter 2 of 2016. Contract awards could have been accelerated if the project was design or procurement ready at approval. In future, ADB and the government should identify and mobilize adequate resources to prepare detailed engineering designs and corresponding safeguards documents to launch procurement as early as possible.
The project has been annually audited by independent external auditors. However, APFS covering only the physical implementation period may not capture all project-related expenses and loan disbursements. To facilitate the reconciliation of ADB records with the APFS on which the auditors have provided a qualified opinion, financial auditing was continued until project financial closure.
Not all safeguards monitoring reports were submitted under this project and the ADB loan disbursement records and latest audited project financial statement (APFS) remained unreconciled at project completion review mission. These non-compliances may have been mitigated through the participation of safeguards and financial management staff in review missions.
The need for some project outputs can decline over time, leading to changes in scope. Such changes should be documented and reflected in the DMF to ensure that they are properly considered and would not compromise the validity and reliability of project monitoring reports and performance evaluation.
Since some of the capacity building-related components under output 2 were linked to the transmission line and substation components under output 1, no separate arrangements for consultant engagement were made for output 2. With the project management unit (PMU) focusing on output 1, the two output 1-related capacity building activities were implemented. The others were not also due to the changed needs during implementation, but this was not brought to ADB’s attention. In the absence of consultants, the EA should have included staff from relevant divisions in the PMU to at least help in output 2 progress reporting.
In the initial stages of the project, the absence of a safeguards consultant resulted in the EA unable to submit some semiannual safeguards monitoring reports. This was timely rectified and based on the monitoring reports produced during implementation, the project did not come across safeguards issues significant enough to alter its outcome or outputs.
Although it traversed mostly rural and agricultural land, the construction of a new transmission line under this project was objected to by some locals. The objections were manifested between April 2017 and March 2018, delaying construction by 226 days. The issue was cleared when the High Court came out with a verdict in favor of the executing agency (EA). The experience highlights the importance of engaging in extensive stakeholder consultations and information dissemination early enough to address issues and concerns that may impede implementation. Mitigation measures, including minimizing the slack time and cost implications of objections and complaints, should also be mapped out and implemented as soon as possible.
Against an estimated $183.2 million, the total project cost at completion amounted to $202.1 million. The cost increase was prompted by minor modifications to the technical design of the project components. The modifications also required a longer implementation period than estimated at loan appraisal. The modifications enhanced system stability and reliability and made the project more relevant. They were addressed through loan reallocations and a 6-month extension in loan closing.
Although none of the 37 contracts under this project experienced any implementation delays, the performance of the contractors could have been better with respect to the quality of work and the technical specifications and construction standards. Specific issues were (i) design-related, affecting certain circuit-breakers, concrete poles for distribution lines, the size of pre-cast foundations, cross-arms, and system earthing; and (ii) construction-related, such as the stringing of transmission and distribution lines, installation of self-supporting insulated wire distribution lines, compaction of ground, installation of pre-cast foundations for steel lattice towers, anchor bolts for substation equipment, and grouting. These issues were either partially resolved or recommended for better technical specifications in future tranches of the MFF. Employing national and international best practices will be key to improving the quality and technology in future tranches. Encouraging contractors to improvise where possible and introduce new technology standards, incorporating lessons learned and issues identified in the technical specifications for the initial tranche, and prompting the project management units to be more proactive in using the project management consultant to develop the capacity of the operational staff on new technology and standards will also be helpful.
This MFF’s tranches 2 and 3 were supposed to be approved in November 2017 and March 2018, respectively. However, the restrictive approach taken by Azerbaijan to public external borrowing, which was absent at appraisal time, led to the deferment of these tranches. It might have been possible to push through with these tranches if they were processed close to the start of tranche 1, with the locations and routes identified upfront and thoroughly analyzed for potential construction and safeguard impacts. Overlapping processing and implementation of the first and subsequent tranches would have maintained the implementation momentum and maximize the benefits from the MFF.
Unaddressed comments from the executing agency (EA) for the Toktogul rehabilitation works, the Electric Power Plants (EPP) joint-stock company, left questions regarding the quality of the dam safety assessment component of this project. A report on this assessment was provided and accepted by the EA in-charge of the soft components and which also managed the assessment, the Ministry of Energy and Industry (MOEI). An unclear communications chain complicated matters, as the consultant disregarded EPP’s comments unless received via MOEI. In future, careful and adequate thought should be given to selecting the most appropriate EA, considering as well likely organizational changes that could impact implementation. For example, frequent changes in the government’s ministerial structures under this project hindered continuity and the smooth implementation of some components.
Often, not enough attention is given to developing indicators that are precise and can be easily assessed in post-project evaluations. In this project, the impact indicators of increased exports and increased domestic supply did not foresee the high growth in domestic demand that prevented the export target from being achieved. In this case, total supply, i.e., exports plus domestic supply, would have been a better indicator. Similarly, the output indicator of reducing commercial losses to 10% by the end of the project was poorly selected because KESC’s identifying losses is only the first step. The second step would be to introduce a targeted loss reduction program. It should also be noted that the design and monitoring framework wrongly categorized total distribution losses, including technical and commercial, as commercial losses. Recurrence of these shortcomings in future projects should be avoided as it could hamper and impact on the reliability of performance evaluations.
This project experienced some implementation delays and had two loan extensions. Toktogul’s rehabilitation was delayed by almost 2 years due to a lack of responsive bidders during the initial bidding. The establishment of the Kyrgyz electricity settlement center (KESC) was delayed by 3 years because of difficulties, including disagreements, in developing the implementation consultant’s TOR and incompatibility between the KESC server hardware and the metering and data acquisition software. Two lessons emerge from this experience: (i) contracts need to be carefully packaged, i.e., the initial Toktogul HEPP contract should have been broken into separate lots, while the two separate KESC packages for server hardware and metering software packages should have been combined to improve compatibility; and (ii) clear consultants’ TORs should be developed and agreed by all relevant stakeholders well before implementation, especially when there are complex issues to be resolved.
Utilizing loan and grant savings, a works contract to rehabilitate the 500-kilovolt switchyard at the Toktogul hydroelectric power plant (HEPP) was added to the scope of this project. The additional scope required a supplementary initial environmental examination (IEE) that included the handling of asbestos-containing material, which was not covered by the EMP and therefore needed to be addressed. The executing agency and the project management consultant for the Toktogul HEPP experienced some difficulty in doing this because precise requirements were not specified in the EMP. It would have been useful for ADB to conduct a training on asbestos handling in addition to ADB’s Safeguard Policy Statement. In ongoing and future projects, training and advice on ADB’s safeguard policy should be strengthened and made responsive to issues and concerns that emerge during project implementation.
This program’s results framework and targets were closely aligned with PLN’s key performance indicators (KPIs), which were based on PLN’s RUPTL, 2015–2024 and Indonesia’s National Medium-Term Development Plan (RPJMN), 2015–2019. PLN has established KPIs in its corporate plan and has regularly reflected these in its annual reports. The close alignment between the PLN’s KPIs and the program’s results framework and targets encouraged the PLN to achieve the DLI targets. Power utility companies in other countries would benefit from similar arrangements that are beneficial for the attainment of both the program and corporate performance targets.
completion, six of the seven safeguard PAPs were achieved. The implementation of the safeguard PAPs has improved the capacity of PLN, especially at the unit level, to manage environmental and social impacts. By excluding 190 circuit-kilometer (ckm) of medium-voltage lines in the indigenous peoples’ area and 428.19 ckm of medium-voltage lines and 284.98 ckm low-voltage lines in the key biodiversity areas, the PAPs minimized the risks to ADB safeguards compliance. But the exclusion also eliminated indigenous peoples’ access to program benefits. In the upcoming review of ADB’s Safeguard Policy Statement, the provisions for this modality could consider how significant risks associated with government-funded programs could be better addressed.
The RBL modality tested in Indonesia through this program came out successful and easier to implement with lower transaction costs. It was flexible enough and allowed the PLN to select investments based on its changing requirements even during program implementation. Therefore, it is well suited to large power systems where demand and the technology available can change within a short time. By focusing on aggregate outputs and result areas as opposed to monitoring each contract, the program was able to support PLN in an effective programmatic manner.
Monitoring the progress against targets of PLN’s broader Sumatra program, which the RBL supported, was not considered part of the RBL administration responsibility. Therefore, the threats posed by the lack of financing for the broader program and the subsequent removal of some of its major components were not sufficiently tracked down and addressed under the RBL. It is important for future RBL programs to include in their monitoring all associated interventions that could have an impact on their implementation to enable necessary actions to be taken promptly to address deficiencies and/or avoid negative unintended consequences.
Some of the DLI targets and baselines set during program preparation were found to be conservative or inconsistent. Adjustments were made during implementation to make them more realistic. The target on energy sales was significantly affected by external factors beyond PLN’s control, including lower economic growth than anticipated under the PLN’s Power Supply Business Plan (RUPTL), energy subsidy removal, and the changing costumer consumption behavior. The experience has highlighted the importance of (i) setting DLIs that are within program control and not vulnerable to external factors, (ii) setting ambitious but achievable targets based on historic trends and EA/IA capacity, and (iii) having enough flexibility to adjust to changes in the external environment.
Through the Indonesia Resident Mission, ADB ensured that lessons learned from program implementation were used in the design of PLN subsequent RBL programs. Building on the program’s success in improving warehouse and waste management in Sumatra, ADB and the PLN transitioned this PAP into a DLI in the RBL programs for Sulawesi and Nusa Tenggara and Kalimantan, Maluku, and Papua. Adjusting DLI targets and verification protocols as needed is also a lesson learned that found useful application in subsequent programs.
By using disbursement-linked indicators (DLIs), non-DLI targets, and program action plans (PAPs) under the results-based lending (RBL) modality, the program successfully instituted mechanisms that strengthened the capacity and encouraged performance improvements from Indonesia’s State Electricity Company, PLN (Perusahaan Listrik Negara), in both technical and administrative areas. Improvements spanned: (i) the procurement monitoring system, where inconsistencies in reporting were identified and addressed through regular procurement monitoring; (ii) the planning and implementation capacity of PLN, which (a) made the preparation of subsequent RBL programs easier, (b) enhanced coordination among PLN divisions, and (c) enhanced PLN’s ability to continue to access debt capital markets and the bank debt market (PLN has supportive relationships with banks and investors so has access to multiple channels of commercial financing); (iii) PLN’s processes for the recording, collection, calculation, and reporting of data used to measure and track the DLIs and non-DLIs, particularly the management reporting information system and its primary sources of data; and (iv) warehouse and waste management. Because of the stronger evaluation culture developed by the RBL, the program also helped PLN recognize the need to update its internal regulations on the disposal of Non-Operating Fixed Assets (ATTB), particularly transformers, to speed up safe disposal.