Operations Concessions for Electricity Distribution JANUARY 2025 Amol Gupta, David Loew and Isabelle Bui © 2025 International Bank for Reconstruction and Development/The World Bank 1818 H Street NW, Washington, DC 20433, Telephone: 202-473-1000 www.worldbank.org. Rights and Permissions The material in this work is subject to copyright. Because the World Bank encourages dissemination of its knowledge, this work may be reproduced, in whole or in part, for noncommercial purposes as long as full attribution to this work is given. The recommended citation is as follows: Gupta, A., Loew, D., & Bui, I. (2025). Operations Concessions for Electricity Distribution. Washington, DC: World Bank. Photo credit: World Bank Flickr/Shutterstock. Any queries on rights and licenses, including subsidiary rights, should be addressed to: World Bank Publications, The World Bank Group, 1818 H Street NW, Washington, DC 20433, USA. Fax: 202-522-2625; email: pubrights@worldbank.org. Acknowledgments This paper was prepared by a World Bank Energy and Extractives Global Practice team led by Amol Gupta (Senior Energy Specialist), David Loew (Senior Energy Economist), and Isabelle Bui (Senior Infrastructure Specialist). The paper was prepared under the strategic guidance and direction of Ani Balabanyan (Practice Manager, Energy Global Knowledge Unit). The World Bank team is grateful to Pedro Antmann (Energy Consultant and former World Bank staff) and Ludovic Delplanque (Senior Infrastructure Specialist) for their support. Deloitte Touche Tohmatsu India LLP provided extensive support for the preparation of this paper. Support for various case studies was provided by PwC Advisory SAS (for Côte d’Ivoire); Abdo, Ellery & Associados (for Brazil); Beatriz Couto Ribeiro, Energy Consultant (for Brazil); and Samuel Zimbe, Energy Consultant (for Uganda). The study was financed by the Public–Private Infrastructure Advisory Facility (PPIAF). The findings, interpretations, and conclusions expressed in this work do not necessarily reflect the views of the World Bank, its Board of Executive Directors, or the governments they represent. i Contents Abbreviationsv 1. Introduction 1 2. The Operations Concession Model in Electricity Distribution 5 2.1. Roles and Responsibilities of Granting Authority and Concessionaire 5 2.2. Comparison of the Operations Concession Model with Other Private Sector Participation Models in Electricity Distribution 7 2.3. Why Operations Concessions? 8 2.4. Setting the Operations Concession within a Broader Reform Context 10 3. Case Studies: Existing Operations Concessions 13 3.1. Côte d’Ivoire: Evolution of the Operations Concession over Time 13 3.2. India: Input-based Distribution Franchises 18 3.3. Lessons Learned from PSP Arrangements in Other Countries 22 4. Structuring Options and Parameters for Operations Concessions 25 4.1. Setting Baseline Parameters and Performance Targets 25 4.2. Award of Concession 26 4.3. Treatment of Assets and Liabilities 26 4.4. Tariff Subsidy Disbursement Mechanism 27 4.5. Power Procurement 27 4.6. Regulatory Requirements and Oversight 27 4.7. Managing Human Resource Issues 28 4.8. Contract Period 29 4.9. Support from the Government 29 4.10. Risk Mitigation 29 5. Limitations and Extensions 31 5.1. Limitations of the Operations Concession 31 5.2. Operations Concession as a Step toward Full Privatization 32 Appendix A: Other Country Cases 35 A.1. Uganda 35 A.2. Türkiye 39 A.3. Brazil 43 A.4. India: Distribution Franchise with Incremental Revenue Sharing Model 47 iii Operations Concessions for Electricity Distribution  ndexation Methodology for Input Rate Adjustment for Input-based Appendix B: I Distribution Franchise 49 Appendix C: Stakeholder Roles and Responsibilities 50 Appendix D: Operations Concessions in the Water Supply and Sanitation Sector 53 References54 Figures Figure 1.1: Cost Recovery for Utilities in World Bank Client Countries 2 Cost Recovery for Public and Private Distribution Utilities in World Bank Figure 1.2:  Client Countries 3 Transaction Structure of Typical Operations Concession in Electricity Figure 2.1:  Distribution5 Figure 2.2: PSP Trajectories Based on Sector Conditions 11  ombined Transmission and Distribution Losses Have Significantly Figure 3.1: C Reduced since 2011 16 Figure 3.2: Transaction Structure of IBDF Model 19 Figure 4.1: Political Risk Insurance by MIGA in Electricity Sector Concession in Cameroon 30 Figure 5.1: Conversion Options from Operations Concession to Full-Scope Concession 33 Figure A.1: Transaction Structure of the Umeme Concession 36 Figure A.2: Umeme’s Distribution Losses (%) 38 Figure A.3: PSP in Türkiye’s Power Distribution Sector 39 Transaction Structure of Privatization Followed for Power Distribution in Türkiye 40 Figure A.4:  Tables Table 2.1: Roles and Responsibilities of Public Utility and Concessionaire 6 Table 2.2: Comparison of PSP Models in Electricity Distribution 7 Table 3.1: Concessionaire Remuneration Mechanism for Domestic Sales in Côte d’Ivoire 15 Table 3.2: Electricity Sector Financials Returned to Sustainable Levels in 2023 17 Table 3.3: Capital Expenditure by Franchisees in their Areas 20 Table 3.4: Input Rate and Revenue for IBDFs in Ajmer, Operated by Tata Power 21 Table 3.5: AT&C Loss Improvement in Operational DFs 21 Table 4.1: Example Regulatory Obligations for an Operations Concession 28 Table A.1: Key Features of the Transaction/Concession Agreement of Umeme 36 Table A.2: Targets vs Actual System Losses for Power Distribution Utilities 41 Table A.3: Key Features of Transaction/Concession Agreements in Brazil 44 Table A.4: Salient Points of Odisha IBF-IRS Model 47 Table C.1: Stakeholder Roles and Responsibilities in an Operations Concession 50 Boxes Box 2.1: Importance of Capital Expenditure by the Concessionaire 10 Box 2.2: Is an Operations Concession a ‘Management Contract on Steroids’? 11 Box B.1: Input Rate and Tariff Indexation Methodology 49 iv Abbreviations ANARE Autorité Nationale de Régulation du Secteur de l’Electricité de Côte d’Ivoire ANEEL Agência Nacional de Energia Elétrica AT&C aggregate technical and commercial (losses) BNDES Brazilian Development Bank BST bulk supply tariff CEB Companhia Energética de Brasília CIE Compagnie Ivoirienne d'Électricité CI-ENERGIES Société des Energies de Côte d’Ivoire CIPREL Compagnie Ivoirienne de Production d'Électricité DF distribution franchise EECI Energie Électrique de Côte d'Ivoire EMRA Energy Market Regulatory Authority ERA Electricity Regulatory Authority EUAS Elektrik Üretim A.Ş. FY fiscal year GWh gigawatt-hour IBDF input-based distribution franchisee IBF-IRS input-based franchisee with incremental revenue sharing IPP Independent Power Producer kWh kilowatt-hour MIGA Multilateral Investment Guarantee Agency O&M operations and maintenance OECD Organisation for Economic Co-operation and Development ÖİB Özelleştirme İdaresi Başkanlığı PPA Power Purchase Agreement PSP private sector participation RPU revenue per unit SAIDI system average interruption duration index v Operations Concessions for Electricity Distribution SAIFI system average interruption frequency index SOGEPE Société de Gestion du Patrimoine du secteur de l'Électricité SOPIE Societe d'Operation Ivoirienne d'Électricite TEAS Turkish Electricity and Transmission Company TEDAŞ Türkiye Elektrik Dağıtım Anonim Şirketi TEIAŞ Türkiye Elektrik İletim A. Ş. TEK Turkish Electricity Authority TETAŞ Türkiye Elektrik Ticaret ve Taahhüt A.Ş. TOOR transfer of operating rights UEB Uganda Electricity Board UEDCL Uganda Electricity Distribution Company Ltd. UEGCL Uganda Electricity Generation Company Ltd. UETCL Uganda Electricity Transmission Company Ltd. WSS water supply and sanitation vi 1. Introduction In the 1990s, the World Bank and other development financiers supported a power sector reform framework emphasizing restructuring or unbundling of utilities, creation of regulators, private sector participation (both in terms of financing and managing the operations of power networks and utilities), and the establishment of competitive power markets. These reforms aimed to create commercially viable power utilities, without the continuing need for government ownership and financial support. Only a handful of developing countries have fully implemented such reforms, however. The World Bank report Rethinking Power Sector Reform in the Developing World (Foster and Rana 2020) highlighted that, from a sample of 22 developed and 88 developing countries, the uptake of power sector reforms in the developing world lags substantially behind that in Organisation for Economic Co-operation and Development (OECD) member countries. Barely a dozen of the developing countries surveyed had managed to implement the full 1990s reform package, with most countries stuck at an intermediate stage of reform. Similarly, only 22 of the 50 countries in the World Bank’s Power Markets Database1 involve the private sector in power transmission or distribution. Power distribution utilities in most developing countries continue to be state-owned monopolies. At the same time, data from the World Bank’s UPBEAT database2 show that less than 30 percent of electric utilities in low- and lower-middle-income countries recover their operating and debt service costs, suggesting an urgent need for further reform and performance improvement (Figure 1.1). Private sector participation (PSP) can be an effective component of power sector performance improvement when used to address some of the common challenges faced by state-owned utilities, including: zz Poor operational performance. Utilities in several developing countries continue to be marred by high technical and commercial losses and poor power reliability. PSP can help improve operational performance when investors are appropriately incentivized to reduce losses and bring in modern technologies and management approaches. zz Political economy and poor fiscal discipline. State ownership of utilities can make it more difficult to implement and sustain transparent and efficient tariffs and subsidies. When policy makers, regulators, and utilities are ultimately under the control of the same political entities, this lack of functional and financial separation can make it comparatively easy for governments to keep tariffs artificially low for political reasons, without compensating 1 The Power Markets Database, International Finance Corporation, World Bank Group, Washington DC (accessed January 31st, 2025), https://www.worldbank.org/en/who-we-are/ifc/power-markets-database. 2 UPBEAT (Utility Performance and Behavior Today) (database), World Bank Group, Washington, DC (accessed January 31st, 2025), https://utilityperformance.energydata.info. 1 Operations Concessions for Electricity Distribution Figure 1.1: Cost Recovery for Utilities in World Bank Client Countries 200% 150% Operating & Debt service cost recovery 100% 50% 0% 5K 10K 15K 20K 25K GNI per capita (current USD) Income group: Low income Lower middle income Upper middle income High income <40% of utilities recover operating and debt service costs <30% of utilities in LICs & LMICs Source: World Bank elaboration based on UPBEAT database. distribution utilities for their costs. While privatization is no guarantee for robust regulation, contractual requirements and the risk of deterring investors may provide greater incentives for governments to ensure utilities recover their costs (and earn returns) either through cost- recovering tariffs or by managing sector subsidies better. zz Managing capital investment programs. Electricity distribution networks are capital- intensive systems and require timely investments to maintain and upgrade assets to improve performance and integrate growing shares of variable and/or distributed power sources. State-owned utilities may have less ability to raise financing on their own balance sheets, instead relying on government guarantees or on-lending/granting of development loans to secure financing. Additionally, government-led capital programs may be less efficient and achieve worse value for money. Private investors may help unlock new sources of capital by bringing their own equity financing, better access to capital markets, and greater expertise in corporate financial management. 2 1. Introduction Recent evidence suggests that PSP has improved power distribution sector outcomes, albeit with some caveats (Alkhuzam, Arlet, and Rocha 2018; Doumbia 2021; Gassner, Popov, and Pushak 2009). Data for 2019 and 2020 from the World Bank’s UPBEAT database show that private distribution utilities and private transmission and distribution utilities (excluding private utilities in Nigeria) are more likely to be recovering at least their operating costs (Figure 1.2).3 Further, the experiences of countries such as India, Côte d’Ivoire, Brazil Türkiye, and Uganda—discussed in this paper—provide instructive examples of the benefits that well-managed PSP in the distribution sector can bring. Figure 1.2: Cost Recovery for Public and Private Distribution Utilities in World Bank Client Countries N=17 N=47 N=18 N=45 24% 28% 55% 53% Do not recover operating costs Recover operating costs 76% 72% 45% 47% Private Public Private Public 2019 2020 Source: World Bank elaboration based on UPBEAT (Utility Performance and Behavior Today) database. The experience has also shown, however, that PSP must be carefully managed and regulated to avoid abuse by private investors of what is by nature a monopolistic business. Private investors need to be bound by enforceable regulation or contracts with clearly defined performance targets, stipulated investment obligations, and a clear allocation of roles and responsibilities. PSP is also often accompanied by political controversy, as customers worry about price increases and government employees worry about their jobs, which has made some governments reluctant to embrace privatization. One model of PSP that is generating interest in developing countries, particularly low-income countries, is the operations concession. The operations concession is an alternative to full privatization, under which asset ownership largely remains with the government but operations (including retail electricity services) are managed by a private sector concessionaire. This approach has the potential to harness many of the efficiency benefits of privatization while being more politically acceptable and easier to structure transactionally. Nonetheless, the operations concession model is generally less understood in the electricity sector, both by World Bank clients and their financiers, than other, more familiar PSP approaches, even though the model has been applied more commonly in the water supply and sanitation sector (see appendix D). 3 The picture is less conclusive for 2021 data, though this is in part because many of the worst-performing public utilities had not yet published their 2021 financial data at the time of writing. 3 Operations Concessions for Electricity Distribution This paper presents a primer on the operations concession model and how it has been deployed in developing countries. The paper is targeted primarily at governments, financiers, lawyers, advisors, and other practitioners undertaking or considering PSP transactions in the power distribution sector in developing countries. The paper aims to provide a unifying language and framework for stakeholders to conceptualize this less common approach to PSP and takes stock of past experiences and lessons learned. Section 2 provides a summary of the model, distinguishing it from other common PSP approaches. Section 3 presents case studies from Côte d’Ivoire and India, two of the most prominent examples of operations concessions. Section 4 uses the learnings from these case studies and other PSP experiences to identify the key features of successful operations concessions and inform future iterations of the model. The annexes contain case studies of PSP approaches in Brazil, Peru, Türkiye, and Uganda. While these cases are not direct examples of operations concessions, they provide useful examples of how privatization has been reconciled with noncommercial public objectives such as employee compensation and access expansion. 4 2. The Operations Concession Model in Electricity Distribution 2.1. Roles and Responsibilities of Granting Authority and Concessionaire Under a power distribution concession, a public utility (the granting authority) awards a concession to a private investor (the concessionaire) for the distribution of electricity in a specified geographic area (the concession area), for a specified period. The defining feature of the operations concession model is that the concessionaire assumes responsibility only for operating and maintaining the electricity network and providing retail electricity services to consumers, while the public utility retains responsibility for power procurement and major capital investments. Figure 2.1 shows the typical transaction structure of an operations concessions in the power distribution sector. Figure 2.1: Transaction Structure of Typical Operations Concession in Electricity Distribution Power Generators/ Fuel Suppliers Responsibilities • O&M of assets • Customer related activities Other contracts PPAs, FSAs and • Investment of efficiency Payments for procurement improvement • Support to concession granting authority on power various regulatory requirements Responsibilities Bulk power supply Power supply • Power procurement Private • Regulatory compliances Public Utility Consumers Concessionaire • Public investments Tariff revenues minus Retail tariff concessionaire’s Tariffs determined remuneration compliances and based on public aspects* Interaction on limited utility’s costs submissions Regulatory Regulator * Discussed in more detail in Chapter 4; PPA=Power Purchase Agreement, FSA = Fuel Supply Agreement Source: World Bank elaboration. 5 Operations Concessions for Electricity Distribution Table 2.1 lists the key roles and responsibilities of the public utility and concessionaire under the operations concessions model. Table 2.1: Roles and Responsibilities of Public Utility and Concessionaire Concessionaire (private investor) Public utility (granting authority) ƒƒ Supply of power to consumers ƒƒ Continues to hold the power purchase ƒƒ Operations and maintenance of preexisting and agreements (PPAs) and supplies power (as a bulk new distribution network infrastructure supplier) to the concessionaire to meet energy demand in the concession area ƒƒ All customer-related activities, including metering, billing, and collections ƒƒ Filing of revenue requirement (including capital investments) for approval by the regulator* ƒƒ Capital expenditure/investments limited to metering, commercial management systems, ƒƒ Investment in new network infrastructure/assets customer care activities, and loss reduction and systems for load growth or expansion initiatives ƒƒ Supports public utility with information for regulatory filings, such as information regarding sales, investments and their justification, and performance against service standards Source: World Bank elaboration. Note: *In some cases, regulatory requirements may also be placed upon the private concessionaire. These are, however, usually limited in scope (for more details, see section 4 of this paper). The concessionaire is responsible for power supply to customers through the distribution network in its concession area and bills and collects revenue from consumers according to the retail tariffs approved by the regulator. The public utility remains responsible for the PPAs and supplies bulk power to the concessionaire to meet energy demand (including peaking requirements) to ensure reliable power to the end consumers in the concession area. The public utility also remains responsible for undertaking major capital expenditure, including for electrification and distribution system augmentation. The concessionaire may be required to undertake limited capital investment for operational performance improvement, primarily to reduce commercial losses. Among other aspects, this may include investments in metering, billing, collection, and customer care systems. In its simplest form, the operations concession remunerates the concessionaire by compensating for operations and maintenance (O&M) costs plus a margin. This remuneration is paid from the tariff revenue collected by the concessionaire. Further, the concessionaire also receives incentives (or penalties) for meeting (or missing) its performance targets, for instance, targets for achieving reductions in power losses. Lastly, for the limited capital expenditure it undertakes, the concessionaire may also recover capital expenditure-related charges (such as depreciation, financing costs, and a reasonable return on equity) during the term of the concession and receive the value of the undepreciated assets at the end of the term. Section 4 discusses in more detail the individual parameters of operations concessions as well as good practices in their design. 6 2. The Operations Concession Model in Electricity Distribution 2.2. Comparison of the Operations Concession Model with Other Private Sector Participation Models in Electricity Distribution The most common private sector participation (PSP) models used in the distribution sector are: zz Management contracts, under which a private company is contracted to fill key managerial functions at a publicly owned distribution utility. zz Operations concessions, under which a private investor (the concessionaire) takes responsibility for power distribution, billing, collections, and O&M. zz Full-scope concessions/privatizations, under which a private investor (the concessionaire) takes on all the responsibilities of the operations concession plus capital investment and is responsible for power purchase costs. zz Privatization through equity sale and perpetual licenses, under which a private investor takes on all the responsibilities described above for a full-scope concession, but without a time-bound concession agreement. Table 2.2 compares the main features of typical PSP models in electricity distribution, arranged from left to right in order of increasing allocation of control (and risk) to the private sector. Full- scope concessions and privatizations are treated jointly, as the differences between them tend to be minimal. Table 2.2: Comparison of PSP Models in Electricity Distribution Parameters Management Operations concessions Full-scope concessions contracts or privatizations (including through equity sale) Description An experienced A private investor (the A private investor (the management team is concessionaire) is given concessionaire) is given recruited to take over responsibility for service full responsibility for certain utility functions delivery in a concession utility operations and and positions area, including billing, service delivery in a collections, maintenance, specified area, including network improvements, responsibility for power operations; bulk power procurement and capital supplied by the public investments sector Contract Short-term Long-term concession Long-term concession management contract contract (typically 10+ contract (typically 25+ (typically three to five years) years); may be perpetual years) (without a finite-term concession contract) in the case of privatizations through equity sale and perpetual licenses 7 Operations Concessions for Electricity Distribution Parameters Management Operations concessions Full-scope concessions contracts or privatizations (including through equity sale) Incumbent utility Remains public Remains public Private (for the duration ownership of the concession) Capital expenditure All capital investments Concessionaire makes Concessionaire makes are undertaken by the incremental distribution all distribution system public sector system investments in investments in the the concession area, concession area; some usually limited to functions investments with a leading to loss reduction; social objective, such as state-owned utility retains electricity access, may still responsibility for major be financed directly by capital expenditure (e.g., the government electrification, network strengthening) Existing assets Remain with public While existing assets Existing assets can remain sector remain with public sector, public or be acquired the concessionaire is given by concessionaire; right the right to use or operate to use or operate legacy them for the duration of assets is given to private the concession concessionaire or the assets are sold outright to private investor Power procurement State-owned utility State-owned utility Concessionaire supplies bulk power to the concessionaire Operations and State-owned utility Concessionaire Concessionaire maintenance Remuneration Fee/commission paid Usually, an operating fee Regulated returns according to the terms plus incentive pay linked to of the management operational performance contract, often improvements (and based including performance on a formula set out in the bonuses for achieving contract) certain targets Source: World Bank elaboration. 2.3. Why Operations Concessions? The promise of the operations concession is its ability to harness private sector efficiencies— primarily better technology, management, governance, and capacity—while avoiding some of the challenges that have beset some full-scope concessions or privatizations, especially in developing countries. These benefits include: 8 2. The Operations Concession Model in Electricity Distribution zz More limited exposure to regulatory risk. Since full-scope concessions and privatizations entail a greater transfer of responsibilities to the private sector, these models require more mature regulation to allow policy makers sufficient oversight despite having ceded more control. Regulation under these models must appropriately remunerate (and even incentivize) private investors to make and manage long-term network investments and must provide clear and transparent tariff-setting methodologies. This requires a degree of regulatory maturity not yet possessed by the power sector in many developing countries. Operations concessions can manage some of the regulatory risks present in less mature sectors: Regulatory risk 1: Concessionaire’s remuneration linked to tariffs. The operations concession model detaches the concessionaire’s remuneration from the vagaries of tariff setting. Instead, terms for remunerating the concessionaire are typically governed by the concession agreement itself, which reduces complexity and investor risk compared with other PSP models. Regulatory risk 2: Liability for power purchase costs. The operations concession eliminates the risk emanating from power purchase liabilities by avoiding the concessionaire’s exposure to PPAs, which instead remain between the power producers and the public utility. This is especially significant because power purchases account for the majority of power sector costs in developing countries. Thus, any shortfall in meeting these obligations owing to inadequate tariff revenues (due to inadequate tariffs) can have an outsized impact on the concessionaire. Regulatory risk 3: Return on investment. Given the concessionaire’s limited mandate to invest in the network, its risk of receiving inadequate remuneration on capital expenditure-related remuneration is mitigated. This is particularly true because the capital expenditure-related remuneration (including return on equity) tends to be long term (given the typical asset life of approximately 20–25 years) and requires assurance over successive political regimes. zz Stakeholder resistance. Adoption of full-scope concessions or privatizations has often been hampered by political sensitivities and employee resistance. Consumers often associate privatization with price increases, while employees of formerly publicly owned utilities associate ‘private sector efficiency’ with job cuts and retrenchments. The history of global power sector development is replete with examples of privatization plans that were abandoned or watered down at least in part because of unexpectedly strong pushback from unions, the public, or other stakeholders. Examples include plans concerning Meralco in the Philippines in the 1990s, various distribution utilities in the Indian state of Odisha in the early 2000s, and more recently, in 2019, the renationalization of the Electricity Company of Ghana. The operations concession model may help better manage stakeholder concerns compared with other PSP approaches that give more control to private investors. First, transferring operations but not ownership of a public asset to a private company may simply be a less drastic step and therefore more palatable to defensive stakeholders. Second, with careful communication, the government can disconnect PSP from tariff issues in its messaging, emphasizing that the operations concession is largely a measure to boost operational 9 Operations Concessions for Electricity Distribution efficiency. Third, it may also help that the public sector continues to fund part of the capital expenditure and will require a smaller return (if any) on these investments compared with a private investor. Lastly, the operations concession gives the public sector more flexibility to retain at least some staff, for instance, by reassigning them to functions that remain under public control (managing capital expenditure programs, bulk power supply, etc.), though this does not eliminate the risk of job losses. Box 2.1: Importance of Capital Expenditure by the Concessionaire Even though capital expenditure by the concessionaire is limited under the operations concession, its importance should not be underestimated. Capital investments are crucial for enabling the concessionaire to put in place the right commercial management, customer interface, service interruption monitoring, and organizational resource planning systems. Further, they enable the concessionaire to replace low- voltage network equipment that is hindering service delivery and that contributes to technical losses. Thus, it is critical to remunerate this capital expenditure through formulas in concession agreements that reflect economic principles of electricity regulation. Capital expenditure under an operations concession remains limited, however, precisely because the operations concession model is designed for countries where sector regulations are not yet sufficiently mature, or current tariff levels are too low, to remunerate capital investment beyond the operating costs of distribution. Therefore, in these contexts, public or concessional financing is still required for major infrastructure expenditures, particularly those needed to improve electricity access. 2.4. Setting the Operations Concession within a Broader Reform Context Operations concessions may be most appropriate for countries/sectors that: zz Want to increase PSP in the distribution sector, to improve operational performance; zz Lack the political feasibility, buy-in from public and private stakeholders, and regulatory maturity necessary for more intensive forms of PSP; zz Lack a sufficiently large distribution system to attract investors; and zz Have sufficiently robust frameworks to ensure the sanctity of contracts and safeguard against political interference in the operations concession. As the objective of the operations concession is to improve the operational efficiency specifically of electricity distribution utilities, it can only be but one component of full sector turnaround. An operationally strong distribution utility will provide incentives for improvements in upstream segments of the electricity sector and may contribute to the financial health of the entire sector. But the operations concession should not be understood as a solution to underinvestment in generation or upstream network infrastructure, poor planning and procurement practices, weak regulatory frameworks, macro deterioration, or any other upstream factors that do not fall under the remit of a concession agreement. Addressing these issues and achieving full sector turnaround will require additional initiatives that complement the operations concession. Figure 2.2 places the operations concession in the context of a broader reform and privatization program. 10 2. The Operations Concession Model in Electricity Distribution Figure 2.2: PSP Trajectories Based on Sector Conditions Poor operational performance Improving operational in distribution but insufficient performance and • Political appetite.... • Political will for more PSP • Regulatory and policy • Regulatory/policy frameworks maturity... in place • Public acceptance... • Track record of utility • Investor interest... performance and regulatory discipline ...for full-scope concession • Investor interest Public Operations Full-scope utility concession concession Poor operational performance in distribution and conditions for fullscope concession met Source: World Bank elaboration. Box 2.2: Is an Operations Concession a ‘Management Contract on Steroids’? An operations concession should not be confused with a management contract. A management contract can be a short-term measure to address declining performance by filling key capacity gaps in the public utility and is thus more like a very hands-on consulting contract than an operations concession. The experience with management contracts in developing countries has been disappointing (see, for example, Foster and Rana 2020). The key differences between an operations concession and a management contract are: • Ownership and control. The operations concession operates as a separate (typically new) legal entity that has full independence to conduct its day-to-day business as it sees fit, subject to the terms of its concession agreement. This new entity is majority-owned by the private investor (the concessionaire) and has its own staff (some of whom may have been transferred from the public utility on a temporary or permanent basis). This contrasts with a management contract, which brings new managerial staff into an existing entity that is still ultimately under public sector control. This fundamental difference allows an operations concession to operate more independently, with less risk of public interference in day-to-day operations, and with significantly more control. • Remuneration. Under an operations concession, the concessionaire’s remuneration is usually directly linked to performance improvement (e.g., loss reduction) and return on limited investments, determined by a contractually stipulated formula. If performance targets are not achieved, the concessionaire may not realize any return (or may even realize a negative return). A management contract may include some performance bonuses for meeting certain targets, but a significant portion of the value of the contract will be based on fixed fees that are paid regardless of operational performance. 11  ase Studies: Existing Operations 3. C Concessions While several countries have instituted some degree of private sector participation (PSP) in their electricity distribution sector, the two countries that have most closely implemented the operations concession are Côte d’Ivoire and India. These cases are discussed in more detail in this section. Even though the contracts in these countries have been set up differently (because of local laws), they essentially mimic the framework presented in section 2. That is, the private investor incurs no risk from power purchase liabilities or tariff levels, and is expected to make only limited investments in terms of capital expenditure. 3.1. Côte d’Ivoire: Evolution of the Operations Concession over Time Background: Historical perspective and institutional framework Historically, the power sector in Côte d’Ivoire was managed by Ivory Coast Electric Power (EECI), a public company established in 1952. Increasing difficulties in financing power generation infrastructure to meet the growing demand for electricity, plus an overall lack of technical expertise in transmission and distribution led to an energy crisis in 1984. It also led the government to formulate laws to open the sector to private investors and allowed the government to delegate the management of electricity transmission and distribution to a private operator. In 1990, the government signed a 15-year concession agreement with a newly created operator, Compagnie Ivoirienne d’Électricité (CIE), controlled by Eranove (majority ownership), a French private investor, with the government retaining a minority stake. CIE was granted the operation and management of generation, transport, and distribution of electricity, but EECI remained the owner of electricity sector assets. In 1994, the Ivorian Electricity Production Company (CIPREL)—also controlled by Eranove—became the first private investor to enter the generation segment. This was followed in 1997 by the development of a 300 MW natural gas power plant by Azito Energy. Subsequent institutional reforms in 1998 and again in 2011 led to the dissolution of EECI and clarification of the responsibilities in the sector. As the sector became more complex with the entry of IPPs, three new entities were created in 1998: (i) the National Regulatory Authority for the Electricity Sector (ANARE), responsible for monitoring compliance with laws and regulations, settling disputes, and protecting public service users; (ii) the Electricity Sector Asset Management Company (SOGEPE), responsible for the management of state assets, financial flows, and the establishment of consolidated accounts for the sector; (iii) the Ivorian Electricity Operation Company (SOPIE), in charge of monitoring energy movements, studies, and planning, as well as project management of state investment works. The latter two entities were dissolved in 2011 and replaced by Société des Energies de Côte d’Ivoire (CI-ENERGIES). Today, CI-ENERGIES assumes 13 Operations Concessions for Electricity Distribution a key role in managing public assets in the electricity sector; supervising financial and energy flows, including monitoring the concessions; and, most importantly, investing in and strengthening electricity infrastructure. The concession of the public service of electricity: Contractual framework in place from 1990 to 2020 Scope of the concession4 CIE was granted responsibility for the operation and management of the generation, transmission, and retail and distribution of electricity across the country. The concession was awarded (noncompetitively, through negotiations) for 15 years and was extended twice—first in 2005 (for 15 years) and then again in 2020 (for 12 years, with the possibility of extending the agreement for a further three years). The main objectives of CIE include: (i) operation and maintenance of state- owned power plants, including six small hydroelectric plants and the Vridi 1 thermal power plant; (ii) operation and maintenance of the transmission network; (iii) management and maintenance of power distribution facilities and retail operations (commercial activities and customer service); and (iv) strengthening and renovation of electricity distribution facilities, mostly financed by public funds, to maintain optimal quality of service. Even though generation assets were included in the concession, the key generation plant (Vridi 1) was decommissioned during the first five years of the agreement, thus making the concession largely a transmission and distribution concession. Business model i) Financial flows CIE manages the entire financial flows in the sector through the tariff revenues it collects from its customers. From its collections, CIE keeps its own remuneration and provides the remaining funds to pay the IPPs and fuel suppliers and cover the budget of supervisory entities (e.g., regulator). The balance (if any) is paid as ‘royalties’ to CI-ENERGIES. It is critical to note, however, that even though CIE pays funds directly to the IPPs and fuel suppliers, it does so only as a ‘sector fund manager’. This delegation of financial flow management does not confer on CIE any financial commitment for a sector financial shortfall, which may lead to nonpayment of IPPs and fuel suppliers due to insufficient resources available from sector operations—as explicitly clarified through Decree 98- 399 of 15 July 1998 defining the rules for the management of financial flows in the electricity sector in Côte d’Ivoire. The decree also established the order of priorities whereby the funds collected by CIE (from the sale of power) are allocated first to cover CIE’s remuneration, and second to pay the private independent power producers (IPPs) and fuel suppliers. Supervision agencies and government are prioritized third and fourth respectively to receive payments. ii) Concessionaire’s basic remuneration until 2020 Until 2020, CIE’s annual remuneration was primarily based on the amount of energy sold in that year. The formula was based on a contractual fee per kilowatt-hour (kWh) of sales, with a different remuneration for domestic sales (initially set at 17 West African CFA francs per kWh, revised in 1994, following the currency depreciation, to 21 West African CFA francs per kWh) and export 4 Despite its name, the 1990 delegation was similar to an affermage, where the private investor’s responsibility is limited to managing the national electricity public service without bearing any risks in terms of investments, which remain with the public sector. 14 3. Case Studies: Existing Operations Concessions sales (initially set at 1.86 West African CFA francs per kWh and later revised upwards). The remuneration, however, declines for sales above a certain threshold (Table 3.1). Starting from 2005, the remuneration structure also included a revision factor, composed of several indices, that would lead to annual readjustments. The remuneration scheme provided incentives to the company to maximize its billing and collection rates. The company was expected to sell at least 2,092 gigawatt- hours (GWh) of energy annually (later revised to 4,000 GWh in 2005) and would be remunerated at a lower rate for sales above this level. Table 3.1: Concessionaire Remuneration Mechanism for Domestic Sales in Côte d’Ivoire Before 2005 From 2005* Energy sold domestically Remuneration level Energy sold domestically Remuneration level (GWh) (XOF/kWh) (GWh) (XOF/kWh) < 2,092 Between 17 and 21 < 4,000 20.4 > 2,092 50% of the above level 4,000–7,800 10.2 > 7,800 6.7 Source: World Bank elaboration. Note: * The numbers change across years based on escalation factors. E.g. in 2019, the remuneration was 21.9 XOF/kWh for sales up to 4000 GWh Note: XOF = West African CFA franc iii) Remuneration of energy access expenditure CIE helped increase in electricity access by managing a financing scheme for new grid connections. This allowed households to pay electricity connection charges over a long period of time instead of paying all of it at the start. The remuneration for this capital expenditure was based on a formula that allowed CIE a return on its investments, and any surplus collected from the consumers was deposited back with CI-ENERGIES. iv) Treatment of assets CI-ENERGIES makes available to CIE any assets needed to operate and maintain service but retains ownership of the assets. CIE is expected to return these assets in good condition at the end of the concession. The assets acquired or built by CIE for the purpose of the concession will be purchased by CI-ENERGIES at the end of the concession, at their residual value. v) Treatment of staff During the transition in 1990, former EECI personnel were transferred to CIE and kept their benefits. All EECI legacy staff have since retired. Evolution of the concession framework since 2020 The initial implementation of the concession was not without difficulties. Separating and assessing the costs related to different power sector value chain segments proved complex. In response, the government made some important changes to the contractual framework when it decided to extend CIE’s concession in 2020. 15 Operations Concessions for Electricity Distribution New remuneration model The new concession agreement provides for a new remuneration mechanism for CIE based on costs plus a margin, instead of energy sales. Eligible costs are the forecasted operating costs of running distribution operations. These are determined, by business segment, from a three-year business plan submitted to and approved by the regulator. The margin is set as a percentage of eligible costs—for example, for 2021–23, the margin was ~6 percent of eligible costs. The business plan is thus an important instrument and brings the concession under regulatory purview, albeit limited to the concessionaire’s own remuneration. There are still no regulatory risks around the level of tariffs (or subsidies) to the concessionaire, however, as the regulator’s review concerns only the concessionaire’s submission of its cost levels. The business plan contains performance indicators linked to bonuses and penalties. Segmentation of activities with clearer reporting One of the key features of the new concession agreement is the obligation for the operator to implement accounting principles to more clearly separate the costs (and revenues) of the sector from those of CIE. This allows for greater transparency and thus better control of the costs of each segment of activities. For example, the new concession makes a clearer separation of responsibilities between the granting authority and the operator regarding the financing of investments and the execution of works. According to the new agreement, if CIE were to conduct work on behalf of CI-ENERGIES, a specific and separate contract would need to be signed, and this would also stipulate the specific remuneration CIE would receive for managing that work. Performance of CIE and the electricity sector over the years Operational performance of the distribution sector in Côte d’Ivoire has improved significantly over the years and CIE is one of the best performing utilities in Africa. Combined transmission and distribution losses in the sector improved from almost 29 percent in 2011 to 15 percent in 2022 (Figure 3.1). Simultaneously, through government-led programs, electricity access increased from 48 percent in 2000 to more than 70 percent in 2023. Figure 3.1: Combined Transmission and Distribution Losses Have Significantly Reduced since 2011 30.0 28.8 25.6 26.0 25.0 24.0 24.9 23.3 22.9 21.9 21.4 21.2 21.1 20.0 19.7 19.7 16.9 17.5 16.3 15.0 15.0 10.0 5.0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Source: CIE. 16 3. Case Studies: Existing Operations Concessions Financial performance CIE has remained profitable throughout its concession. CIE’s revenues represent about 25 percent of electricity sales (the remainder is remitted to other sector entities). Its net income to revenue ratio has remained at 5 percent. This margin has remained substantially the same despite the new remuneration structure introduced in 2020. The electricity sector in Côte d’Ivoire has not, however, always been financially sustainable. From 2020 to 2022, because of rising sector costs and unchanged tariffs, the sector was unable to pay IPPs and fuel suppliers. The 2023 tariff increase has helped to put the electricity sector financials back on track (Table 3.2). Table 3.2: Electricity Sector Financials Returned to Sustainable Levels in 2023 Description (all figures in million FCFA) 2019 2020 2021 2022 2023 (+) Energy Sales - Domestic 530.2 554.4 609.8 657.5 747.0 (-) CIE remuneration (127.3) (131.2) (195.9) (211.2) (232.8) Revenues from unitlity management (129.9) (134.1) (170.8) (184.3) (201.1) Revenues from connections (23.7) (26.9) (26.8) Other revenues (1.4) 0.0 (4.9) (=) Domestic energy sales after concessionaire’s fees 402.9 423.1 415.3 446.3 514.2 (+) Other revenues 74.9 80.7 313.5 188.0 266.6 Revenues from export of electricity 74.6 80.4 55.4 91.2 66.2 Revenues from connections 40.7 45.6 49.07 Subsidies and other revenues 17.4 51.2 151.4 (=) Sector cashflows before IPP, fuel and other payment 477.8 503.8 528.8 634.3 780.8 (-) IPP and fuel supplier payments (439.0) (465.0) (536.5) (645.8) (698.9) (-) Category E expenses (Primarily debt service obligations) (98.1) (61.6) (68.9) (=) Sector Surplus 38.8 38.8 (105.8) (73.1) 13.0 Source: PwC analysis for World Bank based on CIE financial and accounting data Conclusion The presence of CIE in Côte d’Ivoire’s power sector has not only helped improve operational efficiency in electricity distribution but has also allowed Côte d’Ivoire to attract private capital in upstream electricity generation. Even during the years when regulatory discipline faltered (in the wake of increased sector costs that were not passed on in tariffs), CIE has maintained good operational performance. This is a testament to the operations concession model’s ability to insulate investors and network performance from broader sector risk. The new concession agreement improves the model by allowing CI-ENERGIES to better control the costs of CIE through an improved accounting framework. Lastly, the multiyear business plan methodology brings more regulatory supervision and clearer targets for efficiency gains. 17 Operations Concessions for Electricity Distribution 3.2. India: Input-based Distribution Franchises Background Electricity distribution utilities in most of the states in India are owned by the state governments and have a license to supply power exclusively within their respective areas. Section 14 of the Electricity Act (2003)5 allows power distribution utilities to appoint a third party (on a contractual basis, without the need to obtain a license) for power distribution operations in a specified area. In India, these contracts are called distribution franchises (DFs) and they operate in several urban areas, including Agra, Ajmer, Bharatpur, Bhiwandi, Bikaner, Kota, Malegaon, and Shil-Mumbra- Kalwa. Despite the different name, these contracts are essentially operations concessions (with some distinctions from the reference model presented in this paper). Input-based distribution franchise Multiple variations of the DF model have emerged in India over the years, with the input-based distribution franchise (IBDF) model the most prevalent. In June 2012, the Indian Ministry of Power issued standard bidding documents for the appointment of IBDFs (Ministry of Power 2012); the documents have been largely followed for various IBDF transactions across states, with some deviations to account for local conditions. Under the IBDF model, the franchisee (equivalent to the ‘concessionaire’ discussed in Section 2) is awarded a contract to undertake power distribution operations in a specified area (generally a town or city) within a public distribution utility’s license area. The public distribution utility (the ‘granting authority’ in the language of Section 2) continues to supply bulk power to the IBDF area at input points (transmission substations). The IBDF pays the public licensee for the bulk supply of power at an input rate (i.e., a price per kWh of electricity supplied). This rate is determined by a competitive bidding process through which the franchisee is selected, wherein the bidder proposes an input rate (in Indian rupees per kWh) for each year of the concession. In line with the standard bidding documents, the IBDF RFPs typically mandate an aggregate technical and commercial (AT&C) loss reduction trajectory to be met by the selected bidder. In practice, it is this expectation of loss reduction that is used to calculate the reserve value of the input rate in the bidding document. The IBDF benefits financially if it reduces AT&C losses beyond the given trajectory and suffers financially if it fails to do so. The bidding document also defines a minimum level of capital expenditure that the IBDF is required to invest in the franchise area over the first three to five years, based on the estimated necessary investment (as determined by the public utility) to bring down AT&C losses. This capital expenditure is limited to initiatives for loss reduction. Figure 3.2 summarizes the revenue streams and responsibilities of franchisees under the IBDF model. 5 The Electricity Act, 2003. (2003). An Act to consolidate the laws relating to generation, transmission, distribution, trading, and use of electricity and generally for taking measures conducive to development of the electricity industry, promoting competition therein, protecting interests of consumers and supply of electricity to all areas, rationalization of electricity tariff, ensuring transparent policies regarding subsidies, and promotion of efficient and environmentally benign policies. Government of India, New Delhi. https://powermin. gov.in/en/content/electricity-act-2003. 18 3. Case Studies: Existing Operations Concessions Figure 3.2: Transaction Structure of IBDF Model Revenue Stream Responsibilities Utility • Stable energy input to the • Input rate received from the DF franchisee area Payment for • Support for franchisee operations input energy • Revenue cycle management Input energy • Revenue from sale of power • Reduction of losses • Incentives for arrears collection* • O&M activities and limited capex • Compliance to Standards of DF Performance Source: World Bank elaboration. Note: The model also allows DFs to procure power from alternative sources in the event of a shortfall in bulk supply from the public utility. In practice, however, there has been no such instance. The input rate determined at the time of award of a IBDF contract is subject to an adjustment over the contract period, with changing sales mix and retail tariffs (see appendix B). *Arrears collection refers to existing receivables that are past due their normal period (e.g., over 90 days). The IBDF can keep a portion (e.g., 20 percent) of the legacy customer receivables it is able to collect on behalf of the public utility. For simplicity, the utility revenue stream does not show this item. Salient transaction features of the IBDF zz Contract period. The contract period of various IBDF transactions in India has ranged from 15 to 20 years. zz Performance targets. In the IBDF arrangement, the private investor’s return depends primarily on its ability to improve operational efficiency in the quickest possible time frame. IBDF contracts are awarded through competitive bidding, using the input rate (for bulk supply of power) as the financial bid parameter. RFPs prescribe a minimum (or reserve value of the) input rate trajectory, which is based on a mandated AT&C loss reduction trajectory. Bidders calculate and quote their best possible input rate based on their assumptions, including the AT&C loss reduction trajectory. DFs are also required to adhere to performance/customer service-related regulations as prescribed by the concerned electricity regulatory commission. Additionally, different IBDF transactions in India have provided performance targets to franchisees, on parameters such as: � Consumer metering targets; � AT&C losses and collection efficiency; � Incentive to collect from consumers past arrears owed to the public utility; and � Minimum amount of capital expenditure in the first five years of the concession. Capital expenditure India’s IBDF model is a slight departure from the operations concession model as it does expect the franchisee to put in some specific amount of capital expenditure (referred to as ‘minimum capital expenditure required’). As in the operations concession model, however, the franchisee typically incurs only modest capital expenditure, and mostly toward loss reduction initiatives. It is important 19 Operations Concessions for Electricity Distribution to note that no additional remuneration is provided to the franchisee for these investments, and it is expected to have factored these costs and returns into its computation for input rate at the time of bidding. For franchisees in the towns of Kota, Bharatpur, and Ajmer, in the Indian state of Rajasthan, the capital expenditure undertaken was as per Table 3.3. Table 3.3: Capital Expenditure by Franchisees in their Areas Parameter Units Kota Bharatpur Ajmer Starting period of IBDF - Sep-2016 Dec-2016 Jul-2017 Min. Capex required in first 5 years according to the Rs. Cr. 151.5 47.7 37.6 tender conditions Actual Capex undertaken (through March 2024) Rs. Cr. 342.0 85.5 156.3* Actual Capex undertaken (through March 2024) US$, millions 40.7 10.2 18.6* Share of Capex undertaken (through FY24) Customer care centers % 3 13 8 AMI/smart metering % 33 14 29 Installation/augmentation of distribution transformers % 11 10 10 HT network strengthening (11kV and above) % 52 34 54 Others % 0 28 0 Source: World Bank elaboration based on financial and accounting data from distribution franchisees. Note: *Figure to June 2024. zz Treatment of employees. In most of the IBDF transactions in India, employees of the public utility were either transferred internally to other locations of that public utility or could elect to work on a deputation with the franchisee, at terms not inferior to their original conditions. However, very few employees stayed with the franchisees after the initial deputation period. zz Treatment of assets at end of the contract period. On termination or expiry of the agreement, the franchisee hands over possession of new assets acquired to the public utility. The public utility compensates the private investor for these investments, at the depreciated value of the assets. Franchisee remuneration The franchisee’s remuneration is the difference between the tariff revenues it collects and its costs. The tariff revenues are based on the rates set by the regulator (usually for the public utility’s entire license area), and the costs include the input rate it pays for the power; operations and maintenance (O&M) costs; and investments in capital expenditure. Any changes in regulated tariffs are reflected in adjustments to the franchisee’s costs (through changes to the input rate) to ensure that its compensation remains unaffected by changes in tariff levels. Table 3.4 illustrates the figures for the input rate and revenue from the sale of power for IBDFs in the town of Ajmer in the Indian state of Rajasthan. 20 3. Case Studies: Existing Operations Concessions Table 3.4: Input Rate and Revenue for IBDFs in Ajmer, Operated by Tata Power Item Units FY21 FY22 FY23 Public utility’s power purchase Rs./kWh 4.66 4.69 5.14 cost per kWh of energy purchased (AVVNL) Franchisee’s energy input and sales figures Franchisee’s energy sales B1 GWh 460 488 548 Franchisee’s distribution loss B2 % 11.1 10.1 9.0 Franchisee’s Energy Input B3=B1/(1-B2) GWh 518 543 602 Average billing rate (based on C=C1*10/B1 Rs./kWh 9.02 8.77 7.55* tariff by the regulator) Franchisee’s revenue C1 Rs. Cr. 415.0 428.2 413.9 Input rate paid by Franchisee’s D=D1*10/B3 Rs./kWh 7.49 7.33 6.32 Franchisee’s payment for input D1 Rs. Cr. 387.5 398.0 380.8 energy to public utility Source: World Bank elaboration based on discussions and interactions with Tata Power; figures for public utility’s power purchase cost are drawn from Power Finance Corporation reports on performance of distribution utilities. Note: *Significant reduction due to additional subsidies provided to consumers by the state government, thus lowering franchisee’s revenue and balanced by subsequent reduction in its input rate to be paid to the public utility. Performance of IBDFs As at 2025, several DFs are operational in India. These DFs have recorded reductions in AT&C losses since the contract was awarded—in some cases, the improvements are dramatic (Table 3.5). Table 3.5: AT&C Loss Improvement in Operational DFs City/town of concession Year of transaction AT&C loss at Recent AT&C losses,* concession award (%) FY22 (%) Bhiwandi 2006/07 64 10 Agra 2010/11 61 13 Bharatpur 2016/17 32 13 Kota 2016/17 32 19 Bikaner 2017/18 28 14 Ajmer 2017/18 17 10 Shil-Mumbra-Kalwa 2019/20 54 39 Malegaon 2019/20 50 39 Source: World Bank elaboration based on investor reports of Torrent Power, CESC, and Tata Power. Note: *AT&C losses include losses and collection efficiency, and are calculated as (1-billing efficiency) X collection efficiency. 21 Operations Concessions for Electricity Distribution Conclusion The IBDF model has faced less political and social resistance than other privatization attempts in India, leading to attempts to establish IBDFs in more than 20 cities and towns by various state governments across the country. Not all these efforts were successful, however, especially those made early on. IBDF contracts that were awarded to investors without prior experience in the power sector have largely been prematurely terminated, indicating the need for private investors with a long-term presence and interest in the sector. Learning from the failures, the IBDFs awarded over the last decade have largely avoided these challenges through the imposition of more rigorous selection criteria. 3.3. Lessons Learned from PSP Arrangements in Other Countries While there have been only a few operations concessions in electricity distribution around the world, some other examples of successful PSP provide valuable lessons for structuring successful operations concession agreements and managing risks associated with PSP. Examples and lessons learned from PSP in power distribution in Uganda, Brazil, and Türkiye are summarized here and presented in more detail in appendix A. Uganda The Ugandan government signed a 20-year full-scope concession in 2005, leading to the creation of Umeme (an entity owned 100 percent by private investors). The concession is ring-fenced to within 1 km of the distribution network, which has itself grown substantially over the years (and hence so has the concession area). Even though the agreement was structured as a full-scope concession, Umeme was shielded from the regulatory risk of non-cost-reflective tariffs by being allowed to adjust its payment for power purchases. It is a testament to the application of sound regulatory principles, however, that Umeme had to resort to this provision only for the initial period (until 2012), after which tariffs were raised to cost-reflective levels. This concept of safeguarding the concessionaire from the full burden of power purchase costs is like the provisions that exist in operations concessions. Further, the concessionaire was provided a stabilization period (for more details, see appendix A) at the beginning of the concession, with relaxed performance conditions, which not only allowed the concessionaire to settle in but also allowed time for the application of new tariff regulations. Electricity access in Uganda increased from 9 percent in 2005 to more than 47 percent in 2022 (World Bank 2024), with Umeme chiefly responsible for these new connections. Despite this, Umeme has often come under political attack owing to what is perceived as an excessive return on investment (20 percent annual return on investment net of cumulative depreciation) allowed by its concession agreements. This has not only led Umeme to scale back the level of its annual investments in recent years, but has also been a factor in the government’s decision whether to renew the concession. Brazil Brazil’s power sector underwent major restructuring in the 1990s, when most of its distribution companies were privatized in response to the sector’s steadily deteriorating performance and 22 3. Case Studies: Existing Operations Concessions ballooning fiscal burden. Some distribution networks that were initially deemed too risky or remote to be attractive to private investors were privatized during a second wave of liberalization in the late 2010s. Both waves of privatization followed a full-scope concession model, in which concessions were auctioned to private bidders. Nonetheless, the Brazil case offers instructive insights for countries considering any model of PSP in their distribution sector. In particular: zz A strong track record policy and regulatory discipline track is crucial for attracting the private sector to power distribution. zz Operational performance of privatized grids generally improved even as tariffs remained largely stable (adjusted for inflation), suggesting that efficiency gains can create enough of a business case for private investors without the need for higher prices. zz The second wave of privatization successfully attracted bidders to concessions for isolated grids in remote rural areas, suggesting that even ‘last-mile’ grids can be appropriate targets for PSP, with the right conditions in place. zz Lastly, the right mix of incentives and obligations ensured that Brazil was able to achieve large gains in rural electricity access even in areas under private concession. Türkiye With the passage of the Electricity Market Law of 2001, Türkiye implemented major power sector reforms. These included privatizing its electricity distribution sector, establishing wholesale electricity markets and, later, introducing competition in retail electricity supply. This privatization exercise was implemented over 2008–13, when 21 distribution companies were established and improvements to tariff regulations were implemented. The privatization model adopted by Türkiye was akin to a full-scope concession and was referred to as a transfer of operating rights (TOOR). One of the salient features of the TOOR model was that the assets (both legacy and new assets) remained under the ownership of a public entity even though the new assets were financed by the private sector. This was to accommodate the existing legal provisions in Turkish law, which mandated government ownership of assets intended for delivering public goods such as electricity. The Türkiye example, which is among the more recent privatization success stories, provided important learnings: zz Valuation of legacy assets is of little consequence to the privatization process, and countries need not get bogged down in lengthy and time-consuming asset enumeration and valuation exercises. Instead, in cases where fixed asset registers are unavailable, PSP can be implemented by providing right-of-use of legacy assets while maintaining their ownership by the public utility. zz A multiyear tariff system was adopted before the privatization, and in the first regulatory control period (2006–10) tariffs were determined by the government to ensure clarity for the incoming investors. Subsequently, from the second control period (2010–15) tariffs were set by the regulator, the Energy Market Regulatory Authority (EMRA), maintaining the economic principles as established earlier. Among other success factors, this strong regulatory discipline contributed to the success of the privatization process in Türkiye. 23 4 Structuring Options and Parameters for Operations Concessions This section presents desirable features for operations concessions in power distribution, based on both theoretical considerations and practical experience of the model thus far. It is hoped that this content will guide practitioners involved in discussions on private sector participation (PSP) in distribution in developing countries, particularly those countries considering introducing new (or improving existing) operations concessions. 4.1. Setting Baseline Parameters and Performance Targets The operations concession needs to be bound by an enforceable contractual framework, with clearly defined obligations for performance improvement and incentives for better outcomes. Some performance targets may be linked directly to the concessionaire’s remuneration, whereas others may simply stipulate contractual performance requirements. Performance targets can include: zz Improvement in distribution losses; zz Improvement in collection efficiency; zz Rollout of consumer and network metering; zz Collection of legacy customer receivables (to be distributed between public utility and concessionaire);6 and zz Improvements in reliability parameters such as system average interruption duration index (SAIDI) and system average interruption frequency index (SAIFI). As these indicators are, however, dependent on the amount of capital expenditure the public utility is willing undertake, they should not constitute a basis for remuneration of the concessionaire in the initial period. The operations concessions model is generally most suited to developing countries, but many of these countries lack timely and reliable operational data. The experience of PSP implementation in low-income countries demonstrates how setting baseline parameters in the absence of reliable data can lead to protracted disputes between the private sector, the government, and the regulator and to the failure of PSP altogether. Instead, it is advisable to initially set minimum performance standards on loss reduction only. The concession agreement may provide for a less steep loss reduction trajectory in this initial period (for example, the initial three to five years) of 6 The term ‘legacy customer receivables’ refers to the value of unpaid bills outstanding before the concession was awarded. The granting authority may set an incentive for the collection of existing receivables, as is the case in India’s distribution franchises (DFs). 25 Operations Concessions for Electricity Distribution the operations concession, typically known as the transition or stabilization period. Following the transition period, as management information systems are incorporated and reliable data are generated by the concessionaire, the performance parameters can be set, usually by the regulator, based on actual performance. Incentives for overachieving on loss reduction and collection targets should be factored into the formula for determining compensation of the concessionaire. Ideally, meeting these targets guarantees some baseline investor return, whereas underachievement leads to penalties. 4.2. Award of Concession A competitive bidding process should be followed for the selection of the concessionaire. Different bid parameters are available depending on the prevailing regulatory set-up and the objectives of the transaction, including: zz A fee, usually calculated as the operations and maintenance (O&M) charge plus a margin, charged by the concessionaire to the public utility. The lowest fee (or margin over the allowed O&M charge) receives the highest score in the competitive bidding process. zz A per unit (kilowatt-hour [kWh]) price for bulk power supplied in the concession area by the public utility that the concessionaire promises to pay to the public utility, often referred to as the ‘input rate’. The highest rate receives the highest score. zz Performance improvement trajectory for distribution losses and collection efficiency (beyond some stipulated minimum trajectory defined in the bid documents). The most ambitious trajectory receives the highest score. This trajectory also becomes the basis for calculating the concessionaire’s remuneration. While the three options presented above may seem different, in essence they follow the same principle: the concessionaire receives its remuneration (which comprises an O&M charge, a margin, incentive pay, and capital expenditure-related charges on limited investments) and remits the remaining amount collected from tariff revenues to the public utility (generally used by the public utility to discharge other sector liabilities, particularly those related to power purchases). 4.3. Treatment of Assets and Liabilities For the period of the operations concession, the public utility transfers the right to use preexisting assets to the concessionaire, while retaining ownership of those assets. Existing assets, as well as new assets created or acquired by the concessionaire during the concession period, should be transferred to the public utility at the end of the concession. For the limited new assets created/ acquired by the concessionaire in service of operating the concession, the public utility pays the residual (depreciated) value to the concessionaire at the close of the concession period. As discussed in several places in this paper, the concessionaire undertakes limited capital investments, limited mostly to investments needed to meet its performance targets. This may include capital expenditure such as: 26 4 Structuring Options and Parameters for Operations Concessions zz Metering and associated infrastructure, for loss reduction; zz Operational technology interventions (such as distribution-level SCADA/ADMS) for reliability improvement; zz Establishment of customer care centers; zz Technology upgrades in commercial management systems; and zz Meeting safety/statutory requirements around civic infrastructure. In practice, the list may change, as the public utility may be allowed to capitalize some O&M items. At the start of the concession, no long- or short-term liabilities should be transferred from the public utility to the concessionaire, since the concession does not involve the transfer of assets. 4.4. Tariff Subsidy Disbursement Mechanism The government may provide consumer subsidies on some or all retail tariffs. Under an operations concession, this would not affect the concession if the remuneration model has been set up as an O&M charge plus a margin. In such cases, the government may either provide the subsidy as a direct transfer to consumers or provide the subsidy to the public utility (to discharge sector liabilities). In either case, the concessionaire continues to bill customers on regulated (subsidized) tariffs. If, however, the concession has been set up as an input rate for bulk power (see section 4.2), a change in subsidies would necessitate an adjustment to the per unit (kWh) rate for energy. 4.5. Power Procurement The public utility should remain responsible for the purchase of power and onward supply of bulk power to the concessionaire to meet its energy demand, including peaking requirements. In many operations concessions, provisions have been added in concession agreements to allow the concessionaire to procure power directly from the market, if bulk supply from the public utility is insufficient to meet energy demand (e.g., in the case of India’s input-based distribution franchisees [IBDFs]). Such provisions have not been used in practice, however, and should be avoided so as not to introduce unnecessary complexity into the model. 4.6. Regulatory Requirements and Oversight For the most part, operations concessions should be governed by the concession agreement and are outside of regulatory purview. There may be circumstances, however, where regulatory aspects affect concessions. In particular, since it is acting on behalf of the public utility, the concessionaire is expected to adhere to all existing regulations that relate to the business activities under the concession, as well as any new regulations that come into force following the award of the concession. These could include regulations listed in Table 4.1. 27 Operations Concessions for Electricity Distribution Table 4.1: Example Regulatory Obligations for an Operations Concession Regulation Description Grid code/distribution ƒƒ Technical regulations for planning and operations of the network code ƒƒ Key provisions include procedures and conditions for network planning, connection/disconnection to grid, metering arrangements (type, standard, calibration, location, sealing, etc.), scheduling, and dispatch, among others Standards of ƒƒ Standards of performance may include provisions for providing timely performance services to consumers for connections/disconnections, maintaining power quality, and resolving supply outages, as well as penalties or customer compensation for nonadherence Consumer grievance ƒƒ Regulations defining customer grievance redressal mechanisms, including redressal provisions for timelines to resolve complaints, and penalties for nonadherence In cases where the network is expanding rapidly, O&M costs can rise quickly and there may be a need to revisit how the O&M fee paid to the concessionaire is determined. The government may decide to have the O&M fee determined in advance by the regulator (which may consider both actual costs and efficient costs as determined by the regulator) for several years ahead. Further, even the limited capital expenditure by the concessionaire may still have some impact on sector costs and thus would need to be preapproved. For both these aspects—O&M fee and capital expenditure—a multiyear business plan may be submitted by the concessionaire (either directly or through the public utility) and approved by the regulator. Such direct regulatory oversight, if legally possible, can benefit the operations concession model by enhancing scrutiny of the concessionaire’s performance, through regular public disclosures. In the case of indirect regulatory oversight, wherein the public utility reports to the regulator, the concessionaire submits whatever documentation is required by regulatory procedure (e.g., capital expenditure plans, as discussed above) to the public utility for onward submission to the regulator. Lastly, the regulator may also act as a first resort for dispute resolution (such as adjudication) in the event of differences arising between the public utility and the concessionaire. 4.7. Managing Human Resource Issues Managing human resource issues remains one of the most critical challenges in any type of PSP arrangement, including operations concessions. For international investors, it can be beneficial to retain employees of the public utility who have domain experience of the local electricity sector. Willing employees of the public utility may be deputed (in the form of temporary secondments of public employees to the private company) to the concessionaire at employment terms not inferior to those currently offered by the public utility (to be ensured through tripartite agreements, with the government as the third party). Employees who do not wish to be deputed can instead be transferred to other areas of the government or to another state-owned enterprise in the sector. In addition to preparing payroll for deputed employees according to the applicable salary structure and entitlements in their parent organization, the concessionaire should also be required to make applicable contributions toward the pension/retirement fund of such employees 28 4 Structuring Options and Parameters for Operations Concessions (based on actuarial studies). After an adjustment period (for example, at some stage between 12 and 24 months, but no later), willing employees may be fully transferred to the payroll of the concessionaire at mutually agreeable employment terms. Understanding the cost impact of a complete transfer of employees to the concessionaire would be important, as the employees of the public utility may be on a defined benefit plan (often unfunded) and hence there may be retirement liabilities to consider from years of service prior to the start of the concession. 4.8. Contract Period The tenure of an operations concession must be sufficient to enable turnaround on operational parameters and must also allow time for tariff regulations to mature. A period of at least 10 years is desirable since: zz It takes time for a new operator to establish a foothold and get up to speed with the nuances of operating a distribution network, and it takes time to wind down an expiring concession. Short concession contracts with frequent handovers may result in more time being spent on ramping up/down incoming/outgoing concessionaires. zz Some necessary network investment under the purview of the public utility may require multiple years for implementation. These investments are complementary to the loss reduction initiatives and incentives of the concessionaire. Provisions may be stipulated for early termination in the event of default by the concessionaire, and performance can be formally evaluated at regular intervals (for instance, every three years). Concessionaire default may be triggered by severe underperformance on operational improvement targets or noncompliance with laws and regulations. 4.9. Support from the Government In addition to predictable and transparent enforcement of the concession agreement by government, operations concessions may also need national or local government support for: zz Dealing with power theft and payment delinquency; zz Timely payment of electricity bills by government departments and state-owned enterprises (late payment from such entities may need to be factored into performance targets during competitive bidding or the drafting of the concession agreement); and zz Natural disasters and other force majeure events. 4.10. Risk Mitigation In an operations concession, the concessionaire’s remuneration has seniority over other sector costs and obligations. This provides strong payment risk mitigation to the concessionaire. Certain risks may remain, however, including: 29 Operations Concessions for Electricity Distribution zz Delay or nonpayment of compensation in the event of concession termination zz Expropriation of new assets created/acquired by concessionaire zz Breach of contract, and zz Foreign exchange convertibility or transfer restrictions on dividends or termination payments (for foreign entities). The concessionaire may choose to include risk cover from an entity such as the Multilateral Investment Guarantee Agency (MIGA), part of the World Bank Group, for some of the above risks. As an example, MIGA issued a guarantee in 2014 covering an equity investment in a full-scope concession in Cameroon, many aspects of which are relevant for operations concessions. AES Sonel held the electricity transmission and distribution concessions for the entire country, servicing about 800,000 customers, as well as a generation concession covering about 933 megawatts of generation (mostly hydropower). AES Sonel was owned by AES Corporation (56 percent) and the Cameroonian government (44 percent). Energy Cameroon Holding B.V., Netherlands (a wholly owned subsidiary of Actis Energy 3 Funds and other international co-investors) subsequently acquired AES Corporation’s share in the concession. MIGA coverage protects the investors from transfer restriction, war and civil disturbance, and breach of contract (Figure 4.1). Figure 4.1: Political Risk Insurance by MIGA in Electricity Sector Concession in Cameroon Political Risk Insurance by MIGA in Cameroon: Project Structure Project overview • AES Sonel hold a generation Actis 3 Actis Energy concession (~933 MW of existing CDC Group Co-investment generation) and transmission 3 Fund Scheme LP and distribution concessions 89% equity 8.7% equity 2.3% equity • Acquisition and subsequent investment by Actis into AES Sonel Actis Energy • AES Sonel becomes ENEO in Cameroon Holding 2014 (Mauritius) 100% equity Cover details Energy Cameroon Cooperatief BA (Netherlands) • Amount: $300 million 56% equity • Tenor: 15 years • Risks: Breach of Contract, AES Sonel 44% equity Government of Expropriation, Currency (Cameroon) Cameroon Inconvertibility and Transfer Restriction, War and Civil Disturbance • Issued in June 2014 Generation Transmission Distribution WORLD BANK GROUP GUARANTEES Source: MIGA 2024 30 5 Limitations and Extensions 5.1. Limitations of the Operations Concession Based on the theoretical framework and case studies presented in the preceding sections of this paper, some of the key limitations of the operations concession model include: zz Continued reliance on public investment. The operations concession model leaves significant capital investment in the hands of the public sector. In developing countries, the public sector is often capital-constrained, which means there is a risk that necessary public investment does not materialize. This may lead already underperforming power systems to deteriorate further, through no fault of the concessionaire. zz Higher potential for political influence. Given that the relationship between the concessionaire and the public utility is mostly managed through contractual provisions, a higher degree of political influence remains possible with an operations concession than with a full-scope concession. While this can be advantageous in terms of mitigating public and stakeholder concerns around the impact of private sector participation (PSP), it also provides more avenues for any sector governance challenges in electricity distribution to persist. zz Lost opportunity to leverage concessionaire’s balance sheet for private investment in generation. The distribution segment is the most important link for ensuring a financially sustainable electricity sector and attracting private investment in new renewable electricity generation. Private investors in generation may not, however, factor performance improvements in the distribution segment into their risk assessments if they are still selling to an intermediary public off-taker utility, as is the case in the operations concession model. This may lead to unrealized investment in generation that would have occurred if the off- taker were also a (well-performing) private utility. zz Lower asset base for investor remuneration. Though it shields investors from many of the risks of a full-scope concession, an operations concession may nonetheless encounter challenges in attracting interest from private investors. The comparatively low levels of capital expenditure in an operations concession provide a lower base for investor returns. Especially in small countries with small distribution systems, the ticket size may not be sufficient to attract many investors. 31 Operations Concessions for Electricity Distribution 5.2. Operations Concession as a Step toward Full Privatization The operations concession can be an effective model to improve distribution performance while giving governments additional time to develop appropriate regulatory frameworks, establish a track record of regulatory discipline, and prepare credible financial accounts or operational performance data. Once these basic foundations are in place, a government may consider moving to a full-scope concession. Operations concessions may even be initiated with a concession agreement that features an option to convert to a full-scope concession after a specified period. In such cases, there would be no need to run another selection process, and there may even be greater interest from the private sector in bidding for the original operations concession. Key considerations for conversion to full-scope concession To be considered for conversion to a full-scope concession, it is critical that the operations concession first meets certain minimum performance criteria as defined in the concession agreement. After the operations concession has been operating for a sufficient period of time (five years, say), the granting authority may decide to initiate the process of its conversion to a full-scope concession, with a license to operate directly under the regulator’s supervision and control. The conversion to full-scope concession would primarily involve decisions about transferring legacy assets and liabilities of power purchases, and the exact arrangement could follow one of two options: zz Option 1: Full licensee, with no role for public utility. In this approach, the roles and responsibilities of the public utility may be transferred entirely to the concessionaire, allowing the concessionaire to operate independently under a license from the regulatory authority. These roles would include power procurement, undertaking capital expenditure in networks, and any other activity previously performed by the public utility. PPAs (and other liabilities and contracts such as fuel purchase agreements) would be transferred to the concessionaire, which would also be brought under full regulatory purview for tariff setting and performance monitoring. zz Option 2: Full-scope concession, with continued role for public utility as a bulk power supplier. This approach is suitable where unresolved regulatory issues continue to affect the electricity sector and require the continued involvement of the public utility as a single buyer of power and supplier of bulk power to the concessionaire.7 This is likely the case when applications of the tariff methodology have improved but tariff levels remain below sector costs, thus necessitating the need for government subsidies to pay for power and fuel purchases (which may be politically easier to provide to the public utility). As in option 1, however, the concessionaire is responsible for full capital expenditure and operates under a license from the regulator. For legacy assets, either of the following two approaches may be adopted: zz Option 1: Legacy assets transferred to full-scope licensee. The legacy assets may be transferred to the concessionaire at a value based on the approved regulated asset base. Under such 7 Although the concessionaire may be given the option to procure any incremental generation. 32 5 Limitations and Extensions an approach, however, the tariff should be set at level that accommodates expectations of a return on invested private capital. zz Option 2: Legacy assets remain with public utility. The public utility may continue to own the assets on its books while providing the concessionaire the right to use them (with or without a right-to-use charge). This method would typically be used when the government wishes to pass on the benefit of lower tariffs to consumers by foregoing asset return expectations. The options for conversion of an operations concession to a full-scope concession are summarized in Figure 5.1. Figure 5.1: Conversion Options from Operations Concession to Full-Scope Concession Options for conversion to full-scope concession/license Option 1: Full licensee, with no Option 2: Public utility continues role for public utility to act as bulk supplier of power Option 1: Assets transferred to Complete transfer of roles, assets, Awkward division of responsibilities concessionaire and liabilities to the that creates regulatory complexity concessionaire and should be avoided unless Options required for legacy reasons for transfer of assets Option 2: Assets remain with A holding company structure may Assets remain with the public entity, public entity be created to park legacy assets, with the concessionaire given the which can have tax advantages right to use them Source: World Bank elaboration. Other considerations: zz Employees. At the time of conversion, either the concessionaire invites the employees of the public utility to join the concessionaire on employment terms and conditions no less than their existing terms and conditions, or the government provides an option to transfer the employees to some other department. zz Subsidy. Tariff subsidies may be provided by the government: (i) to the concessionaire to offset lower tariffs for certain consumer groups; (ii) to the public utility in the event it acts as a single buyer, thus reducing the price of the bulk supply to the concessionaire; or (iii) as a direct benefit transfer to consumers. zz Tenure. The tenure of the concession and/or the license may be extended to span a longer period (for example, 25 years) than the initial duration, subject to renewal or extension according to applicable regulations. Despite these considerations, it is not necessary that operations concessions convert to full- scope concessions, or even that they serve as precursors to more intensive models of PSP. Deciding whether to proceed to a full-scope concession should be based on the performance of the operations concession, what the government’s objectives are in deepening PSP, and whether the preconditions for fuller privatization are in place. For instance, in countries in which 33 Operations Concessions for Electricity Distribution an operations concession produces significant efficiency gains and positive sector outcomes while the public utility manages upstream functions effectively, additional efficiency gains need to be weighed against transaction costs, stakeholder resistance, and other risks. In such cases, continuation of operations concessions through extensions beyond the initial terms may be the preferred choice. 34 Appendix A: Other Country Cases A.1. Uganda Background Uganda’s power sector reforms began with the enactment of the Electricity Act 1999, subsequently leading to the unbundling in 2001 of the Uganda Electricity Board (UEB) into the Uganda Electricity Generation Company Ltd. (UEGCL), the Uganda Electricity Transmission Company Ltd. (UETCL), and the Uganda Electricity Distribution Company Ltd. (UEDCL). At the time of unbundling, UEB’s successor companies were close to insolvency. In 2002, the Ministry of Energy and Mineral development (MEMD) released the new National Energy Policy, while the Ministry of Finance, Planning and Economic Development’s (MoFPED) Privatization Unit drove the concession process for the generation and distribution segments. In 2003, Eskom Uganda was awarded a 20-year concession agreement for the operation of UEGCL generation assets. In 2005, a concession for the operation of the power distribution business was awarded to Umeme Ltd., also for a 20-year period. At the time of the concession award in 2005, 56 percent of Umeme’s shareholding was by Globeleq Holdings (Conco) Limited and 44 percent by Eskom Enterprises (Proprietary) Limited. On June 28, 2012, Umeme was converted to a public company under the Companies Act, and 39.92 percent of its shares were listed on the Uganda Securities Exchange through an initial public offering. Key features of the Umeme concession Figure A.1 shows the transaction structure of the Umeme concession, involving a set of agreements with government and public utilities. 35 Operations Concessions for Electricity Distribution Figure A.1: Transaction Structure of the Umeme Concession Government of Uganda Lease Agreement Transaction UEDCL leased its 4. Support power distribution Fees Agreement assets to Umeme Limited to operate for UEGCL UETCL UEDCL 20 years State Owned State Owned State Owned Support Agreement Generation Company Transmission Company Distribution Company Lists out the obligations/ rights of Umeme and Lease and Government of Uganda Lease Asset Rent Agreement Eskom Uganda Power Sale Bulk Supply Assignment Power Sale Agreement Power Sale of Tariff Agreement Private Concessionaire For sale of power from UETCL to Umeme at a Bulk Supply Tariff (BST) UMEME ERA Distribution and Supply License Granted by Regulator Private Concessionaire License to Umeme for supply of (for Distribution electricity in concession Authorized Area: Distribution License of Umeme defines Power Tariff and Supply area for 20 years its area of operations as 33 kV and below network, falling Supply of Electricity) within 1KM of urban power distribution network of UEDCL, at the time of concession award Consumers Contract Period: 20 Years (till 30-Mar-2025) Source: World Bank elaboration. Table A.1 summarizes the key features of the Umeme transaction/concession agreement. Table A.1: Key Features of the Transaction/Concession Agreement of Umeme Particulars Description Roles and Granting authority (public utility) responsibilities ƒƒ UETCL to supply ‘available supply’ of power (amount UETCL declares available to of parties Umeme from time to time) to Umeme at a bulk supply tariff (BST). BST is determined by Electricity Regulatory Authority (ERA) in accordance with its tariff setting methodology. ƒƒ Handover of assets to Umeme Limited without transfer of ownership. Concessionaire (private investor) ƒƒ Operation of distribution network and supply of electricity to consumers in its concession area. ƒƒ Distribution license of Umeme defines its area of operations as 33 kV and below network, falling within 1 km of urban power distribution network of UEDCL, at the time of concession award. Contract period ƒƒ The concession was agreed for a period of 20 years. Support from ƒƒ Subsidies: Provided by Ugandan government to UETCL for purchase of electricity government from generation companies. UETCL then sells electricity to distributors like Umeme at a lower rate to mitigate high tariffs. From 2005 to 2012, the government provided US$800 million in subsidies through UETCL. 36 Appendix A: Other Country Cases Particulars Description ƒƒ Investments: The government committed to finance investment of US$3 million in poles and transformers to be incorporated in the distribution system. Special provisions period In 2005–06, Uganda experienced a severe drought that compounded an unfavorable supply–demand balance, leading to renegotiation of the contract in 2006. Under renegotiation, a special provisions period was defined until additional power was made available. During this period, Umeme was provided the following key guarantees: yy Energy to meet 95% of unconstrained demand; and yy Recovery from government for higher actual distribution loss (up to 38%) and lower actual collection efficiency (up to 80%) than targets. Treatment of ƒƒ UEDCL leased assets to Umeme without transfer of ownership. At the end of the assets concession period, Umeme is required to return control of the distribution assets, including new investments, to UEDCL. ƒƒ Umeme was required to pay monthly rent to UEDCL, in consideration of the leased assets. UEDCL did not transfer any loans to Umeme. Instead, monthly rentals are set to cover the debt service obligations of UEDCL. Performance ƒƒ Loss improvement: Loss reduction targets are set by ERA while determining retail targets tariffs. Performance better than targets results in positive impact on Umeme’s profitability, while performance below targets results in negative impact on its profitability. ƒƒ Minimum distribution investments: Investment of US$65 million was to be made by Umeme in the first five years for restoration and reinforcement of the power distribution system. Umeme was required to invest US$5 million of this sum before the end of the initial period (22 months from transfer date). ƒƒ Quality of service: Umeme was required to provide service in accordance with ERA’s Quality of Service Code Regulations and Grid Code. Key areas of service under the regulations include: yy Access: period taken to connect new consumers; yy Customer service: meter readings, timely complaints resolution, meter replacement; and yy Reliability of supply: system average interruption duration index (SAIDI), system average interruption frequency index (SAIFI), notice of planned/unplanned outages. Handling of ƒƒ Umeme was required to hold talks with employees and labor unions to discuss employees employment with the company. As per the agreement, UEDCL and UETCL shall not encourage any employee to stay with them over accepting employment with Umeme. Source: World Bank elaboration; subsidies total as reported by the Ad-hoc Committee on Energy on the Performance of the Electricity Sub-Sector in Uganda. Umeme’s performance since inception Umeme has been able to reduce its distribution losses from 38 percent in 2005 to 18 percent in 2021; however, the losses continue to be more than the target set by ERA. Over the same period, 37 Operations Concessions for Electricity Distribution the collection rate improved from 80 percent in 2005 to 99 percent in 2021 (reaching 100 percent in 2020). Figure A.2 captures the target versus actual distribution losses of Umeme. Figure A.2: Umeme’s Distribution Losses (%) 40% 38 35 35 35% 34 34 34 33 30 32 30% 31 32 28 26 28 25% 24 26 26 21 23 20 19 20% 18 18 20 17 17 16 19 15% 17 16 15 15 14 14 10% 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Target by ERA Actual Source: World Bank elaboration based on Umeme annual reports and ERA statistics. Note: ERA = Electricity Regulatory Authority. From 2005 to 2021, Umeme invested US$765 million, leading to a twofold increase in power distribution network, a threefold increase in energy sales, and a fivefold increase in consumers connected to the grid since inception of the concession. Umeme’s operating cost per customer decreased from 220,000 Ugandan shillings in 2005 to 150,000 Ugandan shillings in 2021. 38 Appendix A: Other Country Cases A.2. Türkiye Background to sector reforms The power sector in Türkiye was managed by a vertically integrated utility until 1993, when the Turkish Electricity Authority (TEK) was unbundled into the Turkish Electricity Generation and Transmission Company (TEAS) and the Turkish Electricity Distribution Company (TEDAŞ). Enactment of Law No. 3096 in 1984 allowed private sector participation (PSP) in the electricity sector using models such as build–operate–transfer (BOT), transfer of operating rights (TOOR), and auto-production (self-generation). The first attempt to privatize the power distribution sector was made in 1996, using the TOOR model, enacted under Law No. 3096. The process had to be annulled, however, owing to numerous lawsuits filed by NGOs and labor unions. The second set of reforms in the Turkish electricity sector commenced with the passage of the new Electricity Market Law of 2001. Several enabling actions were taken to prepare the sector for reforms, such as unbundling TEAS into three companies for generation (EUAŞ), transmission (TEIAŞ), and wholesale trading (TETAŞ) activities; establishing the independent Energy Market Regulatory Authority (EMRA); and launching wholesale power trading through the day-ahead balancing market. The second attempt to privatize the power distribution sector was made post-issuance of the Electricity Market Law of 2001. TEDAŞ was transferred to the Privatization Administration (ÖİB) and restructured into smaller regional distribution companies (Discoms)—21 in total, with 20 operated by TEDAŞ and a single region (Kayseri) already in private hands. A separate distribution company was established in each of these regions, and TEDAŞ signed a TOOR agreement with each of these distribution companies in 2006. These distribution companies were then privatized between 2008 and 2013, through a block sale of their shares to private entities, with the key criterion being the (highest) price offered by the private partner. Figure A.3: PSP in Türkiye’s Power Distribution Sector Pre-Privatisation Post-Privatisation TEDAS Law 3096 of In 1999 BOT/TOR • Govt. committed • 21 Private Discoms, 1984 allowed models were given to competitive • State owned covering the entire BOT in energy private contract electricity market power country distribution sector status by parliament, removing them from Wholesale • Post privatisation of utility in country Low 4046 of under close market estb. Discoms, losses have Private concessions 1994 estb. in smaller regions supervision of Govt. • Govt. reduced significantly Privatization • Power Administration included • Market TEDAS in Cost distribution in competition smaller regions privatization based of Aktas, • Regulator program tariff Kayseri, (EMRA) estb. regime Cukurova and Twh Kepez operated 300 under 19% 18% concession 250 contracts by 16% 200 15% private entities Contracts signed Tenders floated but contested by 150 NGOs/ labour • Power input for Distribution unions; could not TOOR tenders floated Contracts 13% 100 Regions under for individual signed from TEAS (G&T TOOR model be completed entity) Distribution Regions 50 1st Privatisation Attempt 2nd Privatisation Round 0 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 Electricity Consumption (Twh) T&D Loss (%) Source: World Bank elaboration. 39 Operations Concessions for Electricity Distribution Key features of TOOR model Under the TOOR model, the private entity owns the distribution company, but without ownership of distribution network assets. Instead, TOOR contracts transferred only operating rights of assets to private entities, leaving the ownership of assets with the government. Successful bidders then purchased the distribution companies through newly set up SPVs. Figure A.4 depicts the overall structure of privatization adopted in Türkiye. Figure A.4: Transaction Structure of Privatization Followed for Power Distribution in Türkiye • EMRA Approves Revenue Regulator Requirement and Tariffs of (EMRA) Distribution Companies • Distribution Companies are governed by regulations issued by EMRA Step-1: Transfer of operating Distribution Companies rights for assets TOOR Dist. Comp 1 Dist. Comp... Dist. Comp 21 Contract TEDAŞ signed TOOR agreement with each Distribution Co. in 2006 TEDAŞ SPVs hold 100% ownership of respective Distribution Companies (Owner of Assets) Step-2: Privatization of utilities SPVs Share Purchase • SPVs were established by SPV 1 SPV... SPV 21 Agreement (SPA) the successful bidders • Share Purchase Agreement (SPA) signed between TEDAŞ and New SPVs Received proceeds Privatization • New SPV Companies from privatization and Administration become new owner of the transferred it to organized tenders for Treasury Privatization privatization Distribution Companies Administration (OIB) Source: World Bank elaboration. Some key features of these agreements or contracts entered into between TEDAŞ and the 21 distribution companies/special purpose vehicles (SPVs) are as follows: zz Ownership of existing and new assets. Under the TOOR agreement, TEDAŞ owns not only the existing assets but also any new assets created by the private entity. zz Transfer of rights to assets. The distribution company cannot transfer, alienate, or hypothecate to another party, whether partially or completely, the operating rights arising from the TOOR contract. zz Contract term. Concessions were awarded for a 30-year period or until the end of the license period of the distribution company. In the event that the period of the distribution license in question expires, or the distribution license (by EMRA) is revoked for any reason prior to its expiration date, the contract stands terminated. Rights on the distribution facilities are transferred back to TEDAŞ upon expiry of the TOOR contract. 40 Appendix A: Other Country Cases zz Termination due to nonperformance. Under the TOOR contract, TEDAŞ has the right to audit the distribution company on a yearly basis. TEDAŞ has the right of termination on account of nonperformance. zz Investments. All investments by the private investor during the contract period are to be recovered through the tariffs determined by independent regulator EMRA. At the time of expiry of the contract, the investments not yet recovered via the tariffs shall be paid by TEDAŞ to the private investor, within one year at the latest. zz Treatment of employees. Government officials had the right to move to another government agency just after the date of takeover. If they preferred to stay with the distribution company, they were required to resign from their government post and sign a new employment contract with the distribution company. Other workers were required to stay with the distribution company, but with certain protections from layoffs in place. zz Performance targets. No performance target was defined in the tender documents for privatization. EMRA sets performance targets for distribution companies under its tariff setting mechanism. Performance improvement following privatization Privatization led to reduced losses and improved performance of utilities in Türkiye (Table A.2). The collection rate in privatized regions increased from about 90 percent just before privatization to 99.5 percent within three years of privatization. Companies were even able to collect more than 90 percent of the overdue receivables outstanding on the privatization date. By 2016, 19 of the 21 distribution companies had been able to reduce their actual theft and loss rates below the target set by the regulator. Table A.2: Targets vs Actual System Losses for Power Distribution Utilities Distribution 2013 2014 2015 2016 2017 2018 2019 Company Target Actual Target Actual Target Actual Target Actual Target Actual Target Actual Target Actual AYDEM 8.9% 7.6% 8.5% 7.9% 8.1% 7.0% 7.9% 5.7% 7.5% 5.3% 7.2% 5.5% 6.7% 5.6% BAŞKENT 7.9% 7.9% 7.9% 7.7% 7.9% 7.0% 8.0% 7.0% 7.8% 6.1% 7.6% 6.1% 7.3% 5.9% SAKARYA 7.0% 6.6% 6.6% 6.8% 6.3% 6.7% 7.4% 6.6% 7.3% 6.4% 7.3% 6.5% 7.3% 6.0% KAYSERİ 10.0% 6.9% 10.0% 6.9% 10.0% 5.3% 7.4% 5.9% 7.2% 6.0% 7.0% 6.6% 6.9% 6.0% MERAM 8.3% 7.1% 8.3% 7.3% 8.3% 7.3% 7.9% 6.6% 7.7% 5.8% 7.7% 6.7% 7.3% 6.2% OSMANGAZİ 7.2% 7.9% 7.2% 7.8% 7.2% 7.6% 7.8% 5.8% 7.9% 7.0% 7.6% 6.4% 7.4% 6.6% ÇAMLIBEL 7.0% 7.6% 6.9% 7.7% 6.9% 7.1% 7.9% 6.0% 7.8% 6.6% 7.6% 5.1% 7.3% 4.8% ULUDAĞ 6.9% 7.0% 6.9% 6.9% 6.9% 6.9% 7.6% 5.6% 7.5% 4.1% 7.2% 4.2% 6.7% 4.8% ÇORUH 10.2% 9.4% 10.2% 9.0% 10.2% 9.3% 9.4% 9.3% 9.1% 8.1% 9.0% 7.9% 8.7% 7.4% YEŞİLIRMAK 9.4% 10.5% 9.0% 8.3% 8.8% 7.9% 8.5% 8.2% 9.0% 7.4% 8.1% 7.6% 7.9% 7.1% AKEDAŞ 10.0% 6.7% 10.0% 6.8% 10.0% 5.0% 7.5% 7.2% 7.1% 5.5% 7.2% 7.3% 7.1% 6.5% FIRAT 11.1% 9.5% 10.6% 9.5% 10.1% 10.4% 9.7% 10.6% 11.0% 11.0% 10.5% 10.3% 10.5% 9.9% 41 Operations Concessions for Electricity Distribution Distribution 2013 2014 2015 2016 2017 2018 2019 Company Target Actual Target Actual Target Actual Target Actual Target Actual Target Actual Target Actual TRAKYA 7.7% 6.1% 7.7% 6.3% 7.7% 7.4% 7.2% 5.5% 7.3% 5.1% 7.1% 4.4% 6.9% 4.5% AKDENİZ 8.1% 11.3% 8.0% 8.5% 8.0% 7.0% 9.7% 6.3% 8.7% 6.7% 7.6% 5.8% 7.3% 5.9% BOĞAZİÇI 10.8% 9.9% 10.3% 9.2% 9.8% 9.4% 9.6% 9.6% 8.0% 6.7% 8.0% 6.0% 7.6% 8.0% GEDİZ 7.7% 9.7% 7.3% 8.4% 7.0% 7.4% 8.5% 7.3% 8.3% 7.3% 7.8% 6.6% 7.7% 7.6% DİCLE 71.1% 75.0% 59.0% 74.1% 49.0% 72.1% 71.6% 76.6% 71.8% 64.8% 69.2% 54.9% 66.0% 51.3% ARAS 25.7% 27.6% 21.4% 26.2% 17.7% 26.6% 31.7% 25.7% 29.4% 24.6% 25.7% 23.6% 25.0% 21.6% VANGÖLÜ 52.1% 65.8% 43.3% 61.0% 35.9% 59.7% 60.2% 56.4% 60.4% 53.3% 57.3% 49.2% 54.7% 47.6% İSTANBUL 6.6% 7.6% 6.6% 7.2% 6.6% 7.0% 7.6% 6.8% 7.6% 6.1% 7.5% 6.0% 7.3% 5.1% A.Y.EDAŞ TOROSLAR 11.8% 15.2% 11.3% 13.2% 10.7% 12.5% 13.6% 12.1% 13.3% 11.4% 12.3% 11.9% 11.7% 11.8% Source: World Bank elaboration based on TEDAŞ and EMRA data. 42 Appendix A: Other Country Cases A.3. Brazil Background Power sector reforms began in Brazil in the late 1990s, with the aim of introducing competition and privatization to the sector and to address deteriorating efficiency. The National Privatization Program launched in 1990 (through Law No. 8,031/90, and later improved by Law No. 9,491 of September 9, 1997)8 aimed to privatize multiple sectors across Brazil, including iron, steel, mining, and petrochemicals. The following key laws were enacted to establish the framework for public–private partnerships and concessions in the country: zz Public Utility Services Concessions Act (Law No. 8,987 of 1995)9 set the general conditions for private companies to operate public utilities in the country, bidding processes to be followed, term/period of the concessions, and contractual obligations of the parties. zz Power Concessions Law (Law No. 9,074 of 1995)10 established the conditions for contracting, extending, or granting concessions, particularly for the power sector. This law also facilitated the entry to the sector of IPPs and promoted open access to transmission and distribution systems, thereby encouraging competition. zz Law establishing National Electric Energy Agency (ANEEL) (Law 9,427 of 1996)11 established Brazil’s power sector regulator and laid down general rules for concessions, permissions, and authorizations for electricity services. zz Law 9,648 of 199812 introduced power sector reforms to enable privatizations in the sector, including the unbundling of vertically integrated utilities by restructuring Eletrobras; establishing a wholesale electricity market (MAE); assigning coordination of the dispatch system to the National Electric System Operator (ONS); and introducing PPAs (known as ‘initial contracts’) between power distribution companies and power generators. With the issuance of these laws and these reforms, the first of wave of privatizations of power distribution utilities in Brazil took place between 1995 and 2000, with several utilities privatized across various states. The second phase of electricity sector reforms was initiated in 2004, with the issuance of Law No. 10,848. Among other changes, this law amended Law No. 9,427 of 1996 (establishing ANEEL) 8 Law No. 8,031/1990, improved by Law No. 9,491 of September 9, 1997, which amends procedures related to the National Privatization Program, repeals Law No. 8,031 of April 12, 1990, and provides other provisions. Brasília, DF. https://www.planalto.gov. br/ccivil_03/leis/l9491.htm. 9 Law No. 8,987 of February 13, 1995, which provides for the regime of concession and permission for the provision of public services as provided in Article 175 of the Federal Constitution, and provides other provisions. Brasília, DF. https://www.planalto.gov.br/ ccivil_03/leis/l8987cons.htm. 10 Law No. 9,074 of July 7, 1995, which establishes rules for the granting and extension of concessions and permissions for public services, and provides other provisions. Brasília, DF. https://www.planalto.gov.br/ccivil_03/leis/l9074cons.htm. 11 Law 9,427 of December 26, 1996, which establishes the National Electric Energy Agency (ANEEL), regulates the regime of public electric energy service concessions, and provides other provisions. Brasília, DF. https://www.planalto.gov.br/ccivil_03/leis/l9427compilada.htm. 12 Law No. 9,648 of May 27, 1998, which amends provisions of Laws No. 3,890-A of April 25, 1961; No. 8,666 of June 21, 1993; No. 8,987 of February 13, 1995; No. 9,074 of July 7, 1995; No. 9,427 of December 26, 1996; and authorizes the Executive Branch to promote the restructuring of Centrais Elétricas Brasileiras (Eletrobras) and its subsidiaries, and provides other provisions. Brasília, DF. https://www.planalto.gov.br/ccivil_03/leis/L9648cons.htm. 43 Operations Concessions for Electricity Distribution to transfer certain powers, in regard to regulation of concessions, from the granting authority or government to ANEEL. These reforms aimed to restore investor confidence and promote private sector participation. Following these changes, the second wave of privatizations of power distribution utilities took place between 2016 and 2020 through competitive bidding processes. Key concession features Table A.3 sets out the key features of transaction/concession agreements in Brazil. Table A.3: Key Features of Transaction/Concession Agreements in Brazil Particulars Description Concession ƒƒ Privatization involved selling company shares through competitive bidding. award ƒƒ Concessions were formalized via contracts, with essential clauses of the contract defined by Law No. 8,987 and Law 11,07913 for public–private partnerships. ƒƒ Article 15 of Law No. 8,987 allowed for bidding criteria to include lowest tariff, highest offer, best technical proposal with fixed price, or a combination of these. In the case of the privatization of the distribution concessions in Brazil, the modality adopted was highest price offered for the shares.14 ƒƒ In the first wave of privatizations, state governments held competitive bidding auctions for their respective utilities. In the second wave of privatizations, the state governments hired the Brazilian Development Bank (BNDES) to coordinate the auctions. Contract ƒƒ Law 9,074 of 1995 assured the concession duration required to amortize investments, period and limited to 30 years, and open to extension for no more than a similar period, at the extensions discretion of the granting authority. ƒƒ For concessions awarded before 1995, Law 9,074 of 1995 allowed for regrouping of the concessions with extension for a single term equal to the longest remaining concession or 20 years, whichever was the longer. ƒƒ For concessions awarded between 1995 and 2001 (to expire between 2025 and 2031) the federal government released Technical Note No. 14/2023/SAER/SE on June 22, 2023 outlining the proposed guidelines for extension of these concessions. These guidelines suggest techno-commercial conditions for deciding upon the extension requests, such as minimum efficiency criteria (like average duration or frequency of interruptions and company’s ability to service debt), possible economic surplus/ payment to the government, social obligations toward energy efficiency/development of populations in need, and digitalization of networks. Support from ƒƒ Debt restructuring of state government: BNDES collaborated with state governments government through the Support Agreement for the State Privatization Stimulus Program (“Pepe”), advancing financial resources (loans or debt restructuring at subsidized interest rates) to states committed to privatizations and holding as collateral the shares of companies to be privatized. 13 Law No. 11,079 of December 30, 2004. It establishes general rules for bidding and contracting public–private partnerships within the scope of public administration. Brasília, DF. https://www.planalto.gov.br/ccivil_03/_ato2004-2006/2004/lei/l11079.htm. 14 The criterion of lowest proposed tariff was more commonly used in generation and transmission auctions. In the distribution sector, it was employed in only two cases: for Companhia Energética do Piauí (CEPISA) and Companhia Energética de Alagoas (CEAL). These companies were heavily indebted (with zero equity) and were auctioned off at a symbolic value. 44 Appendix A: Other Country Cases Particulars Description ƒƒ Easing of regulatory targets: Temporary easing of regulatory parameters was allowed for certain privatizations in the second wave of privatizations. This included moving the deadline for achieving system average interruption duration index (SAIDI) and system average interruption frequency index (SAIFI) targets. Treatment of ƒƒ The right to economically exploit the public service of electric energy was transferred to assets the private entity under a concession regime. ƒƒ This transfer did not entail a change in ownership of the assets, as they remained integral components of the concession. Throughout the contractual period, the private entity used these assets to deliver electricity distribution services to consumers. ƒƒ Ownership of assets to revert to the granting authority upon contract expiration, with compensation to private entity for nonamortized assets, if any. Performance ƒƒ Performance targets are set by ANEEL in accordance with its various rules and targets regulations. Concession contracts have a broader clause stating that the distributor will face penalties for any noncompliance with laws, regulations, or contractual terms related to energy service and installations, as per current legislation and regulations. ƒƒ Article 16 of Law No. 9,427 (establishing ANEEL) provides that concession contracts may stipulate a minimum annual investment commitment required from the concessionaire. Employees ƒƒ Employees’ employment relationship with the company remains valid following benefits privatization. As management of the company passes to private control, hiring or dismissing employees is, however, at the sole discretion of the executives. ƒƒ To break down corporate and labor union resistance while improving capital/labor relationship, the following methods were adopted: yy Privatization offered employees 10% of the total capital at a discount over the average unitary price fixed for the company’s share; and yy During the second wave of privatizations, employees and government/granting authority signed collective bargaining agreements (also known as acordos coletivos de trabalho). Agreements like the one for privatization of Companhia Energética de Brasília (CEB) included a provision for one year of stability for employees following the privatization. Electricity ƒƒ The concession contracts provided a framework for adjusting tariffs over time, using a tariffs price cap method, wherein tariffs could be adjusted when the ‘economic and financial equilibrium’ of the contract was affected by an increase in costs. ƒƒ The economic clauses of the concession contracts included mechanisms for ordinary tariff revisions every four or five years; extraordinary tariff revisions for unforeseen changes; and annual tariff adjustments based on the variation in inflation or efficiency factor. ƒƒ At the time of privatization, a specific rate of return was not explicitly established. Instead, concession contracts included tariff tables in their annexes, which were used to assess bids submitted by prospective investors. Source: World Bank elaboration. 45 Operations Concessions for Electricity Distribution Post-privatization Before the privatization initiatives of 1995, private entities accounted for only 4 percent of Brazil’s energy distribution. By 2022, however, private capital participation had surged to 76.9 percent, significantly transforming the sector. This shift brought improved operational efficiency, modernization of infrastructure, and technological advancements, enhancing service quality for consumers. In general, these results were achieved without major increases in tariffs. Further, rural electrification was expanded significantly in private concession areas, and even isolated grids in challenging, remote parts of the country were successfully tendered. Nevertheless, although the initial auctions attracted various private investors to the sector, the process was marked by several years of reorganization, transfers of ownership, and consolidations, entailing significant regulatory complexity and a need for sustained public involvement. Of the initial companies that invested in distribution concessions in the 1990s, only Energisa and Iberdrola remain in the segment today. Meanwhile, groups such as Enel, Equatorial Energia, EDP, and State Grid have acquired control of some privatized concessions. 46 Appendix A: Other Country Cases A.4. India: Distribution Franchise with Incremental Revenue Sharing Model The distribution franchise with incremental revenue sharing (DF-IRS) model adopted by a large distribution utility, Central Electricity Supply Utility (CESU), for 15 divisions in the Indian state of Orissa, was a blend of rural revenue collection franchise and the urban input-based distribution franchisee model (IBDF, discussed in chapter 3 of this paper). It was focused primarily on loss reduction through the application of metering and various interventions in consumer-related processes and only limited interventions in network- and infrastructure-related aspects of the business. Even though it was less successful than the IBDF model, the DF-IRS model was also a version of the operations concession and provides some learnings for the development of a more robust operations concession model. At the core of the DF-IRS model was the revenue sharing mechanism. Incremental revenue was calculated separately for each DF division as the difference between the actual revenue, as collected by the franchisee, a base rate of revenue collection, worked out based on the current level of energy input and the base year revenue per unit (RPU). RPU refers to the total revenue collected per unit of energy supplied by CESU at input points on an annualized basis. According to one of the requirements of the request for proposal, the quoted percentage share of the incremental RPU was to be shared with CESU annually during the period of franchise operations. Table A.4 sets out some of the salient features of the DF-IRS. Table A.4: Salient Points of Odisha DF-IRS Model Parameter/aspect Description Contract period ƒƒ Five years; renewal of contract depends on review of performance. Capital expenditure ƒƒ Investments include consumer metering, minor repair and maintenance works in Low Tension (LT) network, laying of Arial-bunched cable and LT capacitor banks, capital expenditure for improving consumer services. Operations and ƒƒ Responsibility for O&M of assets rests with the franchisee. maintenance (O&M) Revenue per unit (RPU) ƒƒ RPU forms the core of the DF-IRS model. The franchisee was expected to improve the RPU from current levels (base year) by means of reducing losses and improving collection efficiency in the respective franchise areas. ƒƒ Base RPU for subsequent years was indexed according to the retail supply tariff approved by the regulator in each year (as in the IBDF model). Revenue share with ƒƒ The business model considered retention of base revenues by the public utility concessionaire attributable to the agreed baseline of RPU. ƒƒ DF was to pass on a share of incremental revenues to CESU according to the quoted percentage set out during the bidding process. 47 Operations Concessions for Electricity Distribution Parameter/aspect Description Clause relating to ƒƒ Achievement of minimum AT&C loss reduction in first few years of operation operational efficiency based on defined trajectory; reduction of AT&C losses to 15% by the end of the targets contract period. ƒƒ Franchisee required to not underperform loss reduction trajectory by more 5% in two or more consecutive years. Receivables ƒƒ No separate treatment of collections against the arrears pertaining to pre- takeover period. ƒƒ Collections against receivables (including legacy receivables) affects the RPU in the same manner as the collections against current demand (i.e., collection of historical receivables is treated as current revenue for the sake of RPU calculation). Meter rent ƒƒ Meter rent collected from meters installed by public utility and franchisee was deducted from total collections to determine the energy charges for computation of RPU. ƒƒ Meter rent collected from meters installed by franchisee only was retained in full by franchisee. Service connection ƒƒ Deducted from total collections to determine the energy charges for charges computation of RPU. ƒƒ Service connection charges collected for new connections performed by franchisee were directed to the franchisee’s account. Electricity duty, tax, ƒƒ Deducted from total collections to determine the energy charges for security deposit computation of RPU. Consumer services ƒƒ Responsibility for customer-related activities such as metering, billing, collection, disconnection/reconnection, and complaint management rested with the franchisee. Subsidy ƒƒ No consideration in concession agreement. Additional power ƒƒ No such provision in concession agreement. Source: World Bank elaboration based on the request for proposal issued by CESU. CESU followed a quality- and cost-based selection method, with weights for both technical and financial capabilities. Bidders were allowed to bid on more than one electrical division, up to a maximum of five divisions. Five private companies were selected for multiple divisions. Performance of DF-IRS A target was set for the franchisees to reduce AT&C losses to 15 percent within the initial five-year period. No franchisee was able to achieve this target. Starting from a baseline of high AT&C losses of more than 50 percent in the base year, most of the DFs were able to reduce AT&C losses by only 2–4 percentage points annually. 48 Appendix B: Indexation Methodology for Input Rate Adjustment for Input- based Distribution Franchise The revenue of a distribution franchise (DF) is dependent on the applicable electricity tariff rates and consumer mix in its area. These parameters are not, however, under the control of the franchisee. The retail tariffs charged to consumers are determined by the electricity regulatory commission, uniformly for the entire license area of the public utility, and not separately for the DF area. Accordingly, a tariff adjustment ratio is determined as described in Box B.1. Box B.1: Input Rate and Tariff Indexation Methodology The input rate for bulk supply of power, paid by the private franchisee to the public utility, is indexed annually as follows: RIE = EI * AIR * TA Where: RIE = Revenue for energy input EI = Energy input AIR = Annualized input rate TA = Tariff adjustment ratio = Average billing rate for current year/Average billing rate for base year of concession 49 Appendix C: Stakeholder Roles and Responsibilities The roles and responsibilities for various stakeholders across different stages of implementation of the operations concession are shown in Table C.1. Note that this is not an exhaustive list and roles and responsibilities may vary depending on the context and the structure of the concession agreement. Table C.1: Stakeholder Roles and Responsibilities in an Operations Concession Stakeholder/ Structuring Remedial Termination stage of Preparation and award of Implementation actions (if (or extension) implementation concession required) Government Political Enter into a Payments for electricity Additional In case of consensus government consumption from state- law and ordertermination Administrative support owned enterprises and other support if at the natural decisions agreement to government agencies required end of term assure: Law and order support Support or public Decisions on utility event of employee ƒƒ Broad wherever required process of support to the adjudication to default, provide issues Tariff subsidy support (to capital for concession the public utility) to protect resolve minor buyback of the ƒƒ Payments for vulnerable groups; may also issues undepreciated electricity provide general budget assets consumption support according to the by government existing arrangements if the departments tariff levels are not cost- and state- reflective owned Provide support for major enterprises capital investments, ƒƒ Termination especially related to network payments expansion and electricity access Public utility Baseline Preparation Monitoring of performance Implement In case of studies and of concession according to the key capital project termination, other relevant documents and performance indicators support to take back data support bid process established in the concessionaire operations management concession agreement to reduce from the Allow access Continue making payments technical losses concessionaire to bidders to the power producers Invoke for necessary (using part of the tariff contractual due diligence revenues) penalties for exercises during In a vertically integrated not meeting key bidding process utility, manage power system performance Sign the operations indicators concession (particularly Implement major capital those related to agreement projects loss reduction) 50 Appendix C: Stakeholder Roles and Responsibilities Stakeholder/ Structuring Remedial Termination stage of Preparation and award of Implementation actions (if (or extension) implementation concession required) Handover of Review and approval of operations of capital investment schemes the utility to the proposed by concessionaire concessionaire Support concessionaire in Meeting regulatory approval of Multi- conditions year Plan (MYP) and other precedent and aspects subsequent Continue receiving subsidy obligations from the government (to outlined in the ensure payment to power concession producers/fuel suppliers) agreement Invoicing of the power supplied to concessionaire as per terms of concession agreement Initiate process for conversion to full-scope concession at the end of five years, subject to successful performance by concessionaire Takeover of assets from concessionaire at end of term/termination as per applicable terms Concessionaire Limited role Participate in the Day-to-day operations for Implement Handover of procurement electricity services remedial operations process Maintain payment/ actions as (and assets) at Set up special performance securities stipulated by termination/ purpose vehicle outlined in the concession the granting expiry for implementing agreement authority Provide all data the concession Meet initial capital (consumer, expenditure network, etc.) and access to Preparation of capital information and schemes, annual/three-year communication rolling capital investment technology plan, tariff orders systems (such Meet key performance as commercial indicators mandated under management concession agreement systems) Provide information to concession granting authority for invoicing of power supplied to concession area Apply for regulatory approvals for various aspects as per the process outlined in concession agreement 51 Operations Concessions for Electricity Distribution Stakeholder/ Structuring Remedial Termination stage of Preparation and award of Implementation actions (if (or extension) implementation concession required) Load forecasting and scheduling/forecasting of power purchase requirement for concession area Meet customer service/ supply standard outcomes, as mandated under concession/regulations from time to time Regulator Participate in Provide relevant Continue to apply economic Reassess the May be consultations, inputs to the regulations for determining KPI targets for entrusted with typically concession the allowed revenue subsequent computations led by the agreement requirement of public utilityperiods to of termination government and resultant tariffs account for payments Provide regulatory oversight external through the of the concessionaire on circumstances appointment limited parameters of of third-party setting targets on aggregate agencies (if technical and commercial provided for in losses, and collection the regulator’s efficiency; operations and role in the maintenance charges; and concession capital expenditure plan agreement) Monitor redress of consumer grievances and adherence to other standards of performance Review proposal for conversion to full-scope concession/license as per request from granting authority Source: World Bank elaboration. 52 Appendix d: Operations Concessions in the Water Supply and Sanitation Sector The operations concession model has been applied more extensively in the water supply and sanitation (WSS) sector than in the electricity sector. This is explained by several factors: zz If a source of sweet crude water (river, lake, water wells, etc.) is available, the WSS utility is run under a vertically integrated localized model. Production cost is a small share of the total cost of service delivery, making water transportation over long distances uneconomic. This is fundamentally different to the power sector, in which electricity generation may account for a very large share of the total cost of service delivery, particularly in systems running on imported fuel. zz The main operating expenditures in the WSS sector are labor costs (usually more than 50–60 percent of the total cost of service delivery), electricity used for water pumping and running water potabilization and wastewater treatment plants, and chemical products used for potabilization. The main sources of losses are leakages in water pipes (technical losses), which may reach high values, and the costs incurred to repair them may be significant. zz Nontechnical losses may occur in the WSS sector (mainly in the medium and high consumption segment). Incentives to commit fraud and theft are, however, lower than in the electricity sector, simply because water bills are significantly lower in value than electricity bills. zz Consumers are less willing to pay for WSS than electricity supply. Willingness to pay for sanitation services is even lower than for water services. This makes financing medium and large investments in the sector (particularly those in sanitation) through tariff revenues almost impossible. These factors mean there are obvious advantages to hiring private companies (operations concessionaires) to operate and manage WSS services focused on maximizing efficiency and enhancing governance by optimizing labor costs and reducing losses (by monitoring medium and large customers using smart metering, and detecting and repairing major leakages in water pipelines, without having any responsibility for medium and large investments). Concessionaires recover all operating costs incurred for service delivery (all internal costs due to vertical integration) and their own remuneration through tariff revenues. Medium and large investments are implemented using concessional financing from the government. Note that the situation is drastically different if potable water is produced through desalination of seawater. In this case, production costs are much higher, and unbundling of water production and distribution may happen. 53 References AlKhuzam, Ahmad F., Jean Arlet, and Silvia Lopez Rocha. 2018. “Private Versus Public Electricity Distribution Utilities: Are Outcomes Different for End-users?” Let’s Talk Development (blog), May 3, 2018. https://blogs.worldbank.org/en/developmenttalk/private-versus-public-electricity- distribution-utilities-are-outcomes-different-end-users. Brazil, Ministério de Minas e Energia. 2023. Nota Técnica nº 14/2023/SAER/SE. Concessões vincendas de distribuição de energia elétrica. Doumbia, Djeneba. 2021. “Do Private Sector Participation and Competition in Power Markets Help in Improving Electricity Sector Outcomes?” Let’s Talk Development (blog), June 18, 2021. https://blogs.worldbank.org/en/developmenttalk/do-private-sector-participation-and- competition-power-markets-help-improving. Foster, Vivien, and Anshul Rana. 2020. Rethinking Power Sector Reform in the Developing World. Washington, DC: World Bank. https://hdl.handle.net/10986/32335. Gassner, Katharina, Alexander Popov, and Nataliya Pushak. 2009. “Does Private Sector Participation Improve Performance in Electricity and Water Distribution?” Trends and Policy Options No. 6. World Bank, Washington, DC. http://documents.worldbank.org/curated/en/102161468160178940/ Does-private-sector-participation-improve-performance-in-electricity-and-water-distribution. India, Ministry of Power. 2012. “Standard Bidding Document for Appointment of Input-based Urban Distribution Franchisee.” https://powermin.gov.in/sites/default/files/uploads/SBD_for_ appointment_of_input_based_urban_distribution_Franchisee.pdf. MIGA. 2024. https://www.miga.org/project/eneo-cameroon. World Bank. 2024. “Access to Electricity (% of Population).” World Bank Open Data (website). World Bank Group. https://data.worldbank.org/indicator/EG.ELC.ACCS.ZS. 54