Distributed Generation Integration in Honduras: Regulatory Gaps, Tariff Challenges, and the Role of DERMS

Abstract

Distributed generation (DG) is reshaping distribution networks through bidirectional power flows, operational variability, and dependence on coordinated regulation, pricing, and control. This paper examines how regulatory architecture, grid-code requirements, tariff design, and Distributed Energy Resource Management Systems (DERMS) influence DG integration, emphasizing Honduras. A structured mixed-source review is applied, combining Scopus-based bibliometric analysis of 2438 records (2000–2026) with targeted synthesis of technical, regulatory, tariff-related, and institutional sources. The bibliometric results show sustained growth and a thematic shift from conventional voltage-control studies toward active distribution networks, DER coordination, storage, demand response, tariff reform, and digital energy management. The analytical synthesis shows that effective DG integration requires more than interconnection compliance: it depends on grid-support functions, cost-reflective and equitable tariffs, and operational tools capable of managing voltage deviations, reverse power flow, congestion, protection coordination, and limited visibility. DERMS is an enabling layer for voltage control, active and reactive power management, congestion mitigation, adaptive protection, and predictive operation. For Honduras, current regulatory progress should be complemented by phased modernization focused on observability, smart metering, data infrastructure, local flexibility, and progressive DERMS deployment. The study provides an integrated framework for aligning regulatory, economic, and operational dimensions of DG integration in emerging distribution systems.

1. Introduction

Although the transition from passive to active distribution networks is widely recognized, less attention has been given to how regulatory design, tariff reform, and DERMS deployment interact in emerging power systems with limited observability and constrained grid infrastructure. What were once designed as passive, radial, and predominantly unidirectional networks are increasingly evolving into active systems characterized by bidirectional power flows, operational variability, and stronger dependence on digital supervision and coordinated control. In this context, DG, especially photovoltaic-based generation, has intensified the need to move beyond conventional interconnection practices toward more advanced regulatory and operational frameworks that preserve system reliability, power quality, and economic sustainability.

One of the most visible dimensions of this transition is the evolution of technical interconnection standards. Earlier regulatory approaches were conceived under low DER penetration assumptions and focused mainly on safe interconnection requirements. More recent frameworks, however, have progressively incorporated interoperability, voltage and frequency support, fault-ride-through capability, and the active participation of inverter-based resources in grid operations. This shift reflects the gradual abandonment of the traditional “install and forget” paradigm and the recognition that DERs must act as active elements within modern power systems. At the same time, international experience shows that formal adoption of advanced standards does not automatically guarantee effective integration, since differences in institutional capacity, administrative procedures, communication infrastructure, and hosting capacity continue to shape integration outcomes across countries [1].

In parallel, the economic regulation of DG has also become a central issue in the literature. Traditional compensation mechanisms such as net energy metering and feed-in tariffs played an important role in the early expansion of DERs, but high penetration levels have exposed tensions related to equity, cross-subsidization, utility cost recovery, and long-term tariff sustainability. As a result, the debate has increasingly shifted toward more sophisticated pricing structures, including time-of-use tariffs, demand charges, value-of-solar approaches, and multi-part tariffs. This transition indicates that the successful integration of DERs depends not only on technical compatibility with the grid, but also on tariff arrangements capable of balancing prosumer incentives, distributive fairness, and network sustainability.

At the operational level, high DER penetration introduces additional challenges associated with voltage deviations, reverse power flow, congestion, protection miscoordination, reduced visibility of low-voltage networks, and the growing complexity of coordinating large numbers of heterogeneous resources. In response to these challenges, Distributed Energy Resources Management Systems (DERMS) have emerged as a promising operational layer for active distribution networks. Rather than acting only as monitoring platforms, DERMS can support coordinated voltage regulation, active and reactive power control, congestion mitigation, reverse power flow management, and even adaptive protection, operating in corrective, preventive, and predictive modes. Their relevance is especially pronounced in systems where conventional distribution management practices are no longer sufficient to deal with the scale and variability of distributed resources.

These issues are particularly important in emerging power systems facing structural infrastructure limitations [2,3]. In Honduras, the expansion of distributed renewable resources is taking place in a context marked by limited digitalization, high technical losses, restricted operational visibility, and insufficient modernization of transmission and distribution infrastructure [3]. Reported loss levels, voltage regulation challenges, and the growing participation of solar and wind resources indicate that the country faces not only a technical integration problem, but also a broader institutional and operational transition. In this setting, international lessons on grid codes, tariff reform, and smart grid management become especially relevant for identifying feasible pathways toward more resilient and actively managed distribution networks.

Existing studies have advanced the literature through specialized analyses of interconnection standards, tariff design, DER operation, DERMS architectures, and the technical conditions of the Honduran and Central American power systems. However, these contributions remain largely organized around individual analytical domains. To clarify this fragmentation and position the contribution of the present review,

Table 1. Positioning of the present study relative to representative literature on distributed generation integration.

Study	Primary Scope	Main Dimensions	Geographic Focus	Gap Relative to the Present Study
Rebollal et al. [4]	Review of standards and guidelines for microgrid and DER connection.	Interconnection, protection, grid support, and power quality.	International.	Does not integrate tariff regulation, DERMS, and the Honduran context.
Cambini and Soroush [5]	Analysis of grid-tariff design under increasing DG participation.	Tariffs, net metering, cost allocation, and multi-part tariffs.	General regulatory context.	Does not connect tariffs with grid codes, operational constraints, and DERMS.
Guzmán-Henao et al. [6]	Review of methods and challenges for DER integration and operation.	Modeling, optimization, technical constraints, and operation.	International.	Does not jointly address regulation, tariffs, DERMS, and Honduras.
Gavgani et al. [7]	Review of DERMS and transmission–distribution coordination.	DERMS architecture, control, optimization, and coordination.	International.	Does not examine tariffs or the regulatory conditions of Honduras.
Smith et al. [8]	Review of DER control and management strategies.	Automation, active network management, and DER control.	Australia and broader applications.	Does not provide an integrated regulatory–tariff–DERMS framework.
Ramos-Gómez et al. [3]	Modeling of DG integration in the Honduran power system.	Voltage, frequency, DG injection, and technical impacts.	Honduras.	Does not integrate grid codes, tariffs, operational challenges, and DERMS.
Gómez-Ramírez et al. [9]	Assessment of the Central American power system and green transition.	Infrastructure, renewable integration, stability, and regional challenges.	Central America.	Does not specifically examine DG regulation, tariffs, and DERMS in Honduras.
Present study	Mixed-source review combining bibliometric and targeted analyses.	Grid codes, tariffs, operational challenges, DERMS, and institutional readiness.	International evidence applied to Honduras.	Integrates these dimensions into a phased modernization pathway for Honduras.

compares representative studies according to their primary scope, the dimensions explicitly emphasized, their geographical focus, and the gap addressed by the present study.

As shown in Table 1, the representative literature provides substantial but predominantly domain-specific contributions. Standards-oriented reviews concentrate on interconnection and grid-support requirements [4], tariff studies focus on prosumer remuneration and network-cost allocation [5], and technical reviews examine DER integration, operation, and control strategies [6,8]. DERMS-focused research addresses advanced coordination and transmission–distribution interaction [7], whereas Honduras- and Central America-focused studies provide essential technical and regional evidence [3,9]. Nevertheless, these research streams do not jointly examine regulatory architecture, tariff design, operational constraints, digital readiness, and DERMS deployment within the Honduran context. The contribution of the present paper is therefore not to replace these specialized analyses, but to connect them through a common analytical framework and translate the resulting evidence into a phased modernization pathway for Honduras.

Against this background, this paper examines how differences in regulatory architecture, technical grid code requirements, tariff design, and DERMS-based operational strategies influence the effectiveness of DG integration in modern distribution networks. By combining international evidence with the Honduran context, the study seeks to clarify the interactions among regulatory, economic, and operational dimensions of DER integration and to discuss how these dimensions can support the transition from passive distribution systems to actively managed networks.

The main contribution of this paper is threefold: (i) to integrate regulatory, tariff, and operational dimensions of DG integration into a unified analytical framework; (ii) to compare international regulatory and pricing mechanisms with the Honduran context; and (iii) to propose a phased DERMS-oriented modernization pathway for emerging distribution systems.

This article is structured by detailing, in the subsequent section, the adopted research methodology, which integrates a comprehensive bibliometric mapping with a targeted analytical synthesis. Following this initial phase, Section 3 presents the results derived from the bibliometric analysis, highlighting the main geographical trends and identified thematic clusters, which demonstrate a transition from conventional voltage control studies toward active network management and digital resource coordination. Subsequently, the proposed research questions are addressed in specific, standalone sections from Section 4 to Section 7 aiming to sequentially analyze grid code architectures, the evolution of international tariff schemes, operational challenges under high resource penetration, and the deployment of distributed energy resource management systems as technological enablers. Finally, the manuscript examines the structural implications and barriers for the Honduran context in Section 8, concluding with final remarks and recommendations in the closing section of the document.

2. Methodology

This study adopts a structured mixed-source review design combining bibliometric analysis with targeted analytical synthesis. This approach was selected because distributed generation integration is not limited to technical interconnection requirements; rather, it involves the interaction between regulatory frameworks, tariff structures, operational constraints, digitalization, and DERMS-enabled coordination.

The review was guided by the following research questions, each of which is addressed in a dedicated section of the manuscript:

• RQ1: How do regulatory and grid-code frameworks affect DER integration in distribution networks? This question is addressed in Section 4.
• RQ2: How has the tariff regulation of distributed generation been addressed in the global literature? This question is addressed in Section 5.
• RQ3: What operational challenges emerge under high DER penetration in distribution networks? This question is addressed in Section 6.
• RQ4: How can DERMS support the transition from passive distribution systems to actively managed networks, particularly in emerging power systems such as Honduras? This question is addressed primarily in Section 7, with the implications for the Honduran case further examined in Section 8.

Accordingly, Section 4, Section 5, Section 6 and Section 7 provide the analytical responses to RQ1–RQ4, respectively, while Section 8 contextualizes these findings within the Honduran power system and develops the proposed modernization pathway.

To organize the review process, the methodology was structured into six sequential stages: review design, evidence search, relevance screening, core evidence selection, technical and institutional source identification, and final bibliometric mapping and analytical synthesis, as shown in Figure 1.

2.1. Route A: Bibliometric Analysis

Route A was developed to characterize the indexed scientific literature related to DG deployment, DERs, smart grids, regulation, grid codes, tariffs, and energy policy. The bibliometric corpus was retrieved from Scopus using the Article title, Abstract, and Keywords fields. The search was structured into three thematic blocks and combined using the Boolean operator AND, as follows:

TITLE-ABS-KEY (“distributed generation” OR “distributed energy resources” OR DER OR “photovoltaic generation”)

AND TITLE-ABS-KEY (“distribution network” OR “active distribution network” OR “grid integration” OR “smart grid”)

AND TITLE-ABS-KEY (“regulation” OR “grid code” OR tariff* OR “energy policy”)

The initial search retrieved 2716 records. Three filters were applied sequentially: publication period from 2000 to 2026, Energy subject area, and English language. After filtering, the final bibliometric corpus consisted of 2438 records. This dataset was used to analyze publication trends, geographical distribution, citation evolution, keyword co-occurrence, and temporal keyword dynamics. VOSviewer version 1.6.21 was employed to identify thematic clusters and temporal shifts in the indexed literature.

2.2. Route B: Targeted Analytical Synthesis

Route B complemented the bibliometric analysis through targeted searches addressing four areas: (i) DER interconnection requirements and grid codes; (ii) tariff and prosumer-compensation mechanisms; (iii) operational effects of DER on distribution networks; and (iv) DERMS functions and implementation requirements. The academic search included Scopus, IEEE Xplore, and ScienceDirect. Google Scholar was used only to locate accessible documents and perform backward and forward citation tracking; it was not considered a reproducible quantitative database.

Peer-reviewed articles, reviews, and conference papers were prioritized for technical, operational, and tariff evidence. For the Honduran case, laws, regulatory decisions, technical standards, tariff resolutions, and operational or statistical reports issued by CREE, ENEE, the system operator, the Secretaría de Energía, or other public institutions were prioritized. Consultation documents were used only when their provisional status was explicitly identified. The final search was completed on 16 August 2026.

2.3. Source Selection and Analytical Integration

Sources were included when they: (i) addressed distribution networks or the TSO–DSO interface with explicit distribution implications; (ii) examined DER interconnection, tariffs, grid performance, flexibility, or DERMS; (iii) provided identifiable technical, economic, regulatory, or implementation evidence; and (iv) could be directly linked to a statement or comparison in the manuscript. Case studies were additionally required to identify the network or jurisdiction, the DER technology or intervention, and at least one technical or economic outcome.

Sources were excluded when they focused exclusively on transmission or wholesale-market operation, discussed renewable energy without a documented distribution network connection, provided only promotional or unsupported claims, duplicated a more complete publication, or lacked sufficient information to verify authorship, date, method, or content. Superseded regulations were excluded from the description of the current framework but could be retained when necessary to explain regulatory evolution.

Numerical data were included only when the source, year, unit, geographical scope, and observed, simulated, or projected status were identifiable. When several values were available, the most recent final official source was used. Data with incompatible definitions were not aggregated. In particular, utility-scale solar and wind generation was not classified as DER unless its connection to a distribution network was documented, and total electricity losses were not described as technical losses unless the source provided that disaggregation.

The retained evidence was organized into five dimensions: bibliometric trends, interconnection and grid-code requirements, tariff structures, grid performance effects, and DERMS-enabled operation. Owing to differences in network characteristics, tariff definitions, and modelling assumptions, results were synthesized comparatively and no statistical meta-analysis was conducted. The resulting integration between the bibliometric and targeted analytical routes is summarized in Figure 2.

3. Bibliometric Analysis

This subsection presents the bibliometric results obtained from the Scopus-indexed corpus defined in Route A. The analysis aims to characterize the scientific landscape associated with distributed generation integration, active distribution networks, smart grids, tariff regulation, grid codes, and energy policy. The subsequent sections complement this overview with the technical, regulatory, and institutional evidence identified through Route B.

Figure 3 shows the geographical distribution of publications. The results indicate a marked concentration of research output in a limited group of countries. China leads the field with 478 publications, followed by the United States (294), India (241), Australia (131), Brazil (110), Canada (96), and Saudi Arabia (92). This pattern suggests that research on active distribution operation has been mainly driven by countries with stronger research capacity, higher DER deployment, and more active smart-grid or regulatory modernization agendas. Although Brazil appears as the most visible Latin American contributor, Central America remains weakly represented, reinforcing the relevance of context-specific studies for countries such as Honduras.

Figure 4 presents the keyword co-occurrence map generated with VOSviewer. The network reveals three main thematic clusters. The first cluster, Voltage & Grid Operation, includes terms related to voltage control, reactive power, electric inverters, distribution grids, and power-system control, reflecting the technical–operational impacts of high DER penetration. The second cluster, Policy, Tariffs & Smart Grids, groups terms associated with energy policy, tariff regulation, demand response, electric utilities, costs, investments, and smart grids, highlighting the regulatory and economic dimension of DER integration. The third cluster, DERMS & Energy Resources, connects distributed energy resources, electric power distribution, energy storage, photovoltaics, electric vehicles, optimization, and energy management systems, indicating the growing role of digital coordination and flexibility-oriented operation.

The annual evolution of publications and citations is shown in Figure 5a. The number of documents increased steadily after 2010, with a clear acceleration from the mid-2010s and the highest publication activity in 2025. Citations follow an even sharper upward trend, particularly after 2016, indicating that DER integration has gained visibility and consolidation within the power systems literature. This growth is consistent with the increasing relevance of DERs, prosumers, smart grids, tariff reform, and active distribution network operation.

Figure 5b complements this interpretation by showing the temporal evolution of keywords. Earlier studies were more strongly associated with conventional technical topics, such as electric power systems, voltage control, reactive power control, and power electronics. More recent terms are linked to distributed energy resources, energy storage, electric vehicles, demand response, energy management, and active distribution networks. This shift indicates that the field has evolved from a mainly interconnection- and voltage-control perspective toward a broader framework involving DER coordination, smart-grid operation, tariff design, and digital energy management.

Overall, the bibliometric results reveal three main patterns: (i) a geographical concentration of research in a limited number of countries, (ii) sustained growth in publications and citations after the mid-2010s, and (iii) a thematic transition from conventional distribution-system studies toward smart-grid governance, DER coordination, storage, demand response, and energy management. These findings support the central premise of this review: active distribution operation should be understood as a multidimensional process involving technical standards, tariff regulation, operational flexibility, and DERMS-enabled coordination.

4. Regulatory Architecture and Grid Code Evolution

4.1. How Do Regulatory and Grid-Code Frameworks Affect DER Integration in Distribution Networks?

4.1.1. From Basic Interconnection to Active Grid Support

The integration of DG into modern power systems has driven a global transition from relatively simple interconnection regulations toward more sophisticated standards focused on interoperability and active grid support. Among these, the IEEE 1547 [10] standard has become one of the most influential references governing the interconnection of Distributed Energy Resources (DERs), particularly in North America, while IEC standards and national grid codes play equally important roles in other jurisdictions [11]. Nevertheless, the influence of IEEE 1547 extends well beyond North America, serving as an international benchmark for the development and modernization of regulatory frameworks across diverse power systems.

The body of literature reviewed reveals a clear evolution in the technical requirements governing DG integration, largely driven by the continuous increase in photovoltaic penetration across distribution networks. Countries and regions such as Brazil, Egypt, Saudi Arabia, and Dubai have progressively adopted and adapted internationally recognized standards—including IEEE 1547 [10], IEC 61727 [12], and IEC 62116 [13]—as the foundation for national regulations tailored to their respective technical, institutional, and operational conditions. In some cases, such as Saudi Arabia, these standards are regarded as strategic instruments for achieving the national objectives established under the Vision 2030 agenda, whereas in Egypt, compliance with the prescribed technical testing requirements has already become mandatory for the interconnection of DG units [11,14,15,16].

However, this regulatory evolution also reflects the growing tension between traditional interconnection philosophies and the emerging operational requirements of modern power systems. Early versions of standards such as IEEE 1547 were developed under the assumption of low DER penetration and therefore focused primarily on basic interconnection criteria, without requiring DG units to actively respond to grid disturbances, as their impact on overall system operation was considered negligible [4,17]. As DER deployment increased, regulations and standards were progressively updated, as in the case of IEEE 1547-2018 [10], which incorporated advanced operational requirements, interoperability provisions, and explicit grid-support capabilities, such as ride-through mechanisms and other functions to help regulate voltage and frequency variations in the network [10,17]. This shift represents a significant conceptual transition: from a framework focused solely on safe interconnection to one oriented toward active integration, in which the power system and DERs exchange information securely and effectively to improve stability and resilience under high-penetration scenarios. According to [17] in line with this shift, equipment certification standards such as UL 1741 [18] have also evolved toward new requirements enabling the testing of certain advanced functionalities in so-called “smart inverters.”

4.1.2. Institutional and Regulatory Barriers Beyond Technical Compliance

While this technical evolution has strengthened the minimum criteria for DG interconnection, convergence toward international standards alone does not guarantee efficient integration, nor does it eliminate the institutional or administrative challenges that determine its real-world effectiveness. Several studies support this observation: in Brazil, for example, although interconnection procedures are comparable to those in the United States, the authors in [19] highlight that processes regulated by the Brazilian Electricity Regulatory Agency (ANEEL) and the Distribution Procedures for Electricity in the National Electric System (PRODIST) may involve longer approval timelines, creating economic and technical constraints that hinder the expansion of microgeneration. Likewise, in [20], the authors emphasize that differences in technical requirements, administrative procedures, and connection criteria among distribution companies increase the complexity of distributed generation integration processes.

Complementarily, in [21], the authors identify regulatory limitations affecting the adoption of new business models, particularly due to restrictions on the participation of energy aggregators. These entities are unable to aggregate portfolios of small residential prosumers to participate in electricity markets or demand response programs, with such opportunities remaining primarily available to large consumers. This situation is not exclusive to Brazil. Studies conducted in Poland and Spain demonstrate that barriers to the integration of DERs extend beyond purely electrical considerations and include complex administrative procedures, limited hosting capacity in distribution networks, and insufficiently flexible regulatory frameworks [22,23]. Overall, these findings demonstrate that successful distributed generation integration depends not only on compliance with technical requirements but also on the existence of efficient administrative processes, robust institutional structures, and regulatory frameworks capable of enabling new operational and commercial models.

The Spanish case further introduces an additional relevant technological and regulatory dimension. Although Spain has a highly developed regulatory framework aligned with European standards, several studies indicate that challenges persist, limiting the evolution of distributed generation toward more flexible and integrated operational schemes. According to the authors in [24], from a regulatory perspective, the current framework prioritizes self-consumption schemes while maintaining restrictions on the development of microgrids and other decentralized operational models. For example, geographical limitations on collective self-consumption and capacity restrictions hinder the consolidation of energy communities and larger-scale distributed generation clusters. Furthermore, the limited deployment of energy storage systems and the inability of prosumers and microgrids to fully participate in ancillary service markets or Virtual Power Plants (VPPs) schemes restrict the exploitation of the advanced capabilities enabled by current technologies [24].

From a technical standpoint, Spain has been a pioneer in renewable energy integration through a centralized control scheme via the Renewable Energy Control Center (CECRE) (see Table 2), requiring larger installations to comply with strict voltage-sag ride-through requirements established under Operating Procedure PO 12.3, which demands control equipment and, in some cases, FACTS devices to ensure system stability. However, according to [23], certain requirements associated with communication infrastructure have not evolved at the same pace as technological advancements. In particular, the mandatory use of GSM Machine-to-Machine (M2M) equipment for telemetry transmission through the Inter-Control Center Communications Protocol (ICCP) excludes more modern and efficient communication alternatives, such as VPN or ADSL-based solutions, increasing implementation costs and limiting interoperability with advanced digital platforms. These findings indicate that regulatory modernization does not solely rely on strengthening technical interconnection requirements but also requires adapting regulatory frameworks and communication infrastructures to the ongoing digital transformation of power systems.

According to the authors in [25], China has adopted a tiered regulatory strategy, in which technical and operational requirements for distributed generation are established according to voltage level and, consequently, the potential impact of each installation on the electrical grid. Under this approach, installations connected at 10 kV are subject to more stringent requirements, including real-time monitoring and closer integration with control centers, whereas low-voltage systems (380 V and 220 V) are governed by considerably less demanding requirements. In the latter case, the Chinese standard GB/T 33593-2017 [26] establishes that voltage variations must comply with GB/T 12325 [27], allowing deviations of ±7% for users connected at 380 V and from −10% to +7% for users connected at 220 V [28].

Nevertheless, the comparative analysis conducted by [28] reveals that this differentiated regulatory approach creates significant gaps in the requirements applicable to low-voltage users. In contrast, German and U.S. standards impose stricter requirements and demand enhanced technical capabilities at the Point of Common Coupling (PCC), including active power control, voltage support capabilities, and grid communication functionalities. While VDE and IEEE standards establish these capabilities as general requirements for distributed generation, the Chinese regulatory framework applies them primarily to installations with higher system impacts, leaving a substantial portion of low-voltage systems with limited or nonexistent technical obligations.

In this regard, the Chinese regulatory model prioritizes the supervision of installations with greater influence on system operation, whereas the regulatory frameworks of Germany and the United States adopt a more comprehensive approach by establishing minimum technical capabilities for a broader range of distributed generation installations, regardless of their size. This approach aims to facilitate grid support capabilities and promote more coordinated system operation. Similarly, comparative studies in [19,22,23] suggest that institutional capacity and regulatory architecture may play a role as significant as electrical parameters themselves in determining the effectiveness and long-term sustainability of distributed generation deployment.

Table 2. Comparative Overview of Regulatory Frameworks and Technical Requirements for DG Integration.

Country or Region	Applicable Standards	Main Technical Requirements	Operating Modes	Stability and Grid Challenges	Hosting Capacity or Penetration	Source
International (IEEE)	IEEE Std 1547-2018, IEEE 2030 [29]	Interoperability, voltage and reactive power regulation, dynamic voltage and frequency support, power quality compliance.	Grid-connected and islanded (intentional and unintentional).	Synchronization, response to Electric Power System (EPS) faults, and cybersecurity.	Requires additional technical requirements for higher Distributed Energy Resource (DER) penetration levels.	[10]
Saudi Arabia	IEEE 1547, IEEE 1547.4 [30], IEEE 2030, Saudi Building Codes (SBC 201, 401, 601, 602, 1001).	Voltage and frequency regulation, real and reactive power sharing (PID), voltage and speed droop control, voltage limits.	On-grid, intentional island (off-grid), and radial feeders.	Voltage instability in island mode, phase load imbalance, harmonic distortion, voltage sags, and aging conductors.	Target of 3450 MW (4% renewable energy) by 2020; DG integration reduces losses by up to 84%.	[11,31,32]
Brazil	ABNT NBR 16149 [33], 16150 [34], ABNT IEC 62116 [35], ANEEL Resolutions 482/2012 and 687/2015, INMETRO Standards 004/357.	DC component injection (<0.5%), adjustable power factor (0.90–0.95), TDD (<5%), reverse polarity protection, and fault ride-through (FRT) for >6 kW.	Primarily grid-connected microgeneration; island mode for specific inverters.	Islanding prevention, low-voltage power quality degradation, certification bureaucracy, and lack of qualified personnel.	Microgeneration up to 100 kW and minigeneration up to 1 MW; high solar irradiation (1200–2400 kWh/m2).	[16,19,31]
China	GB/T 19939-2005 [36], GB/T 19964-2012 [37], GB/T 20046-2006 [38], NB/T 32004 [39], DL/T 1040 [40], State Grid regulations.	Active and reactive power control, LVRT capability, harmonic limits, and voltage imbalance limits.	Grid-connected (high-, medium-, and low-voltage systems).	Provincial climate variability, bidirectional power flow, unplanned islanding risks, and current overloads.	Global PV leader; target of 70 million kW of distributed PV by 2020 with dispatch-support systems.	[4,19,25,31,41]
Spain	UNE 206007-1 [42], RD 413/2014, RD 244/2019, RD-Law 15/2018, IEC 61727, RD 1663/2000, DSO codes.	Voltage sag response (PO 12.3), reactive power control, real-time telemetry (CECRE), and over/undervoltage protection.	Self-consumption (with/without surplus), grid-connected (FENIX demonstration), and intentional island mode.	Obsolete communication systems (GSM/M2M), intermittency management, and standardization of bidirectional metering equipment.	Installed PV capacity of 4687 MW (2017); integration of 168 MW in networks with 320 MW peak demand.	[4,23,31]
Great Britain	ENA Engineering Recommendation G83 [43], G59 [44], EREC G98/G99 [45,46], GB Distribution Code [47].	DC injection limits, harmonic distortion limits, flicker (1.0/0.65), and Loss of Mains (LoM) protection based on RoCoF and Vector Shift.	Parallel operation with low-voltage grid; island mode requires specific safety studies.	Low system inertia, cascading trips due to legacy protections, and reverse power flow toward transmission.	High penetration (>35% of total capacity); G83 applies up to 16 A per phase (3.68 kW single-phase/11.04 kW three-phase).	[4,31,41,48]
Poland	PN-EN 50160 [49], IEC 61727, EN 50438 [50], DSO Grid Codes.	Over/undervoltage protection (0.85–1.15 Un) and frequency protection (47–51 Hz), reactive power regulation cosφ(P), DC injection <1%.	Grid-connected (VPPs, distributed generation, and civic energy projects).	Aging grid infrastructure, Rapid Voltage Changes (RVC), and individual harmonic management.	Limited regional capacity (e.g., ENEA 743 MW); target of >50% zero-emission generation capacity by 2040.	[16,22,31]
Germany	VDE-AR-N 4105 [51]	Active power reduction (40% PM/Hz) under overfrequency (50.2–51.5 Hz) and cosφ(P) regulation.	Grid-connected.	Frequency stability and voltage control in low-voltage networks.	Not in source	[31]
Belgium	Local DSO codes	Immediate overvoltage protection (1.06 Un) and frequency protection (49.5–50.5 Hz).	Grid-connected.	Protection coordination to avoid mass disconnections.	Not in source	[31]

Table 2. Comparative Overview of Regulatory Frameworks and Technical Requirements for DG Integration.

Country or Region	Applicable Standards	Main Technical Requirements	Operating Modes	Stability and Grid Challenges	Hosting Capacity or Penetration	Source
International (IEEE)	IEEE Std 1547-2018, IEEE 2030 [29]	Interoperability, voltage and reactive power regulation, dynamic voltage and frequency support, power quality compliance.	Grid-connected and islanded (intentional and unintentional).	Synchronization, response to Electric Power System (EPS) faults, and cybersecurity.	Requires additional technical requirements for higher Distributed Energy Resource (DER) penetration levels.	[10]
Saudi Arabia	IEEE 1547, IEEE 1547.4 [30], IEEE 2030, Saudi Building Codes (SBC 201, 401, 601, 602, 1001).	Voltage and frequency regulation, real and reactive power sharing (PID), voltage and speed droop control, voltage limits.	On-grid, intentional island (off-grid), and radial feeders.	Voltage instability in island mode, phase load imbalance, harmonic distortion, voltage sags, and aging conductors.	Target of 3450 MW (4% renewable energy) by 2020; DG integration reduces losses by up to 84%.	[11,31,32]
Brazil	ABNT NBR 16149 [33], 16150 [34], ABNT IEC 62116 [35], ANEEL Resolutions 482/2012 and 687/2015, INMETRO Standards 004/357.	DC component injection (<0.5%), adjustable power factor (0.90–0.95), TDD (<5%), reverse polarity protection, and fault ride-through (FRT) for >6 kW.	Primarily grid-connected microgeneration; island mode for specific inverters.	Islanding prevention, low-voltage power quality degradation, certification bureaucracy, and lack of qualified personnel.	Microgeneration up to 100 kW and minigeneration up to 1 MW; high solar irradiation (1200–2400 kWh/m2).	[16,19,31]
China	GB/T 19939-2005 [36], GB/T 19964-2012 [37], GB/T 20046-2006 [38], NB/T 32004 [39], DL/T 1040 [40], State Grid regulations.	Active and reactive power control, LVRT capability, harmonic limits, and voltage imbalance limits.	Grid-connected (high-, medium-, and low-voltage systems).	Provincial climate variability, bidirectional power flow, unplanned islanding risks, and current overloads.	Global PV leader; target of 70 million kW of distributed PV by 2020 with dispatch-support systems.	[4,19,25,31,41]
Spain	UNE 206007-1 [42], RD 413/2014, RD 244/2019, RD-Law 15/2018, IEC 61727, RD 1663/2000, DSO codes.	Voltage sag response (PO 12.3), reactive power control, real-time telemetry (CECRE), and over/undervoltage protection.	Self-consumption (with/without surplus), grid-connected (FENIX demonstration), and intentional island mode.	Obsolete communication systems (GSM/M2M), intermittency management, and standardization of bidirectional metering equipment.	Installed PV capacity of 4687 MW (2017); integration of 168 MW in networks with 320 MW peak demand.	[4,23,31]
Great Britain	ENA Engineering Recommendation G83 [43], G59 [44], EREC G98/G99 [45,46], GB Distribution Code [47].	DC injection limits, harmonic distortion limits, flicker (1.0/0.65), and Loss of Mains (LoM) protection based on RoCoF and Vector Shift.	Parallel operation with low-voltage grid; island mode requires specific safety studies.	Low system inertia, cascading trips due to legacy protections, and reverse power flow toward transmission.	High penetration (>35% of total capacity); G83 applies up to 16 A per phase (3.68 kW single-phase/11.04 kW three-phase).	[4,31,41,48]
Poland	PN-EN 50160 [49], IEC 61727, EN 50438 [50], DSO Grid Codes.	Over/undervoltage protection (0.85–1.15 Un) and frequency protection (47–51 Hz), reactive power regulation cosφ(P), DC injection <1%.	Grid-connected (VPPs, distributed generation, and civic energy projects).	Aging grid infrastructure, Rapid Voltage Changes (RVC), and individual harmonic management.	Limited regional capacity (e.g., ENEA 743 MW); target of >50% zero-emission generation capacity by 2040.	[16,22,31]
Germany	VDE-AR-N 4105 [51]	Active power reduction (40% PM/Hz) under overfrequency (50.2–51.5 Hz) and cosφ(P) regulation.	Grid-connected.	Frequency stability and voltage control in low-voltage networks.	Not in source	[31]
Belgium	Local DSO codes	Immediate overvoltage protection (1.06 Un) and frequency protection (49.5–50.5 Hz).	Grid-connected.	Protection coordination to avoid mass disconnections.	Not in source	[31]

4.1.3. Comparative Technical Requirements Across Countries

This suggests that, while institutional and regulatory architecture can be as determinant as the electrical parameters themselves, the latter also reveals substantial differences across countries that merit specific analysis. When comparing the technical specifications adopted across different countries, significant differences emerge in the main interconnection requirements for distributed generation. As partially summarized in Table 2—where the case of Brazil is detailed—limits on direct current (DC) injection vary across regulations: most standards, including Brazil’s ABNT 16149, the United States’ IEEE 1547, and the Egyptian code (EDC), limit the DC component to 0.5% of rated current [10,14,16], whereas IEC 61727 and the Chinese standard GB/T 19939 allow values of up to 1% [41]. Brazil also explicitly establishes a maximum disconnection time of one second when this limit is exceeded [16].

Regarding power quality, most standards establish a 5% limit for Total Demand Distortion (TDD), although standards such as Germany’s VDE-AR-N 4105 and the United Kingdom’s EREC G83 adopt more stringent criteria for harmonic control. Concerning voltage regulation, this capability was not initially considered within IEEE 1547:2003 [52] as a function that distributed generation should provide at the PCC. However, subsequent revisions (2014 and particularly 2018) not only introduced this capability but also required active participation through active and reactive power control [16,41]. In contrast, some local grid codes, such as those currently implemented in Dubai, still impose restrictions that limit the full utilization of advanced inverter functionalities, potentially constraining large-scale solar photovoltaic integration [15].

More broadly, comparative assessments of international standards indicate that, despite a general consensus regarding fundamental parameters (such as voltage and frequency thresholds, minimum reconnection times, and the use of the PCC as the reference point for measurements), significant differences remain in their implementation depending on voltage level, network topology, and national regulatory context [4,41]. These discrepancies become increasingly critical under high distributed generation penetration scenarios, where the traditional “install-and-forget” approach becomes clearly inadequate. This limitation is illustrated by the case of Great Britain, where insufficient visibility, control capabilities, and data standardization have directly affected system resilience and operational stability [48].

Consequently, recent grid codes have evolved toward requiring active participation from distributed generation and Energy Storage Systems (ESS) in maintaining system stability by incorporating functionalities such as active power–frequency regulation (P/f), reactive power–voltage control (Q/V), fault ride-through capability, and dynamic voltage support [15,31,53]. This transformation reflects the transition away from the traditional “install-and-forget” paradigm and the recognition that DERs must operate as active participants within the power system.

However, studies conducted under regulatory frameworks such as the Italian CEI 0-21 standard indicate that these same stabilizing functionalities may compromise the effectiveness of anti-islanding protection in low-voltage networks [53]. By reducing local frequency and voltage deviations following disconnection from the main grid, distributed generators may sustain an unintentional islanded condition for longer periods, thereby increasing risks to equipment and maintenance personnel [53]. The literature suggests that the solution does not lie in eliminating advanced functionalities, but rather in the coordinated redesign of protection, control, and communication schemes for networks with high distributed generation penetration.

4.1.4. Grid Support Functions, Smart Grids and Virtual Power Plants

This coordinated redesign is not an end in itself, but a necessary step within a broader regulatory and technological transformation. Indeed, the regulatory and technological evolution of distributed generation is progressively converging toward the Smart Grid paradigm, in which distributed energy resources move beyond passive operation to assume an active role in power system stability [4,10]. According to authors in [23], recent regulatory frameworks incorporate grid support requirements that require inverters and distributed generators to participate in voltage regulation through Volt/VAR and Volt/Watt control functions, frequency regulation through frequency-droop schemes, and dynamic support during disturbances, including Low Voltage Ride-Through (LVRT) and High Voltage Ride-Through (HVRT) capabilities, as well as emerging functionalities such as synthetic inertia and fast voltage support [53].

Within this context, standards such as IEEE 2030 define an interoperable architecture that integrates power systems, communication technologies, and information infrastructures to enable bidirectional energy and data exchange [11,32]. These smart grids incorporate Advanced Metering Infrastructure (AMI), smart meters, and communication systems that enable real-time monitoring, active demand management, integration of energy storage systems and electric vehicles, as well as enhanced resilience and fault recovery capabilities [11,54].

Building upon this infrastructure, VPPs have emerged as coordinated platforms capable of aggregating distributed energy resources, energy storage systems, and flexible loads to operate as a single integrated entity. According to authors in [55], depending on their objectives, VPPs may be oriented toward economic optimization through participation in electricity markets (commercial VPPs) or toward the provision of ancillary services and flexibility support for system operators (technical VPPs). Their operation relies on Industry 4.0 technologies, including the Internet of Things (IoT), cloud computing, artificial intelligence, big data analytics, and blockchain, enabling applications such as Peer-to-Peer (P2P) energy trading, Vehicle-to-Grid (V2G) schemes, and M2M interactions within a highly digitalized energy ecosystem [55].

Therefore, the transition toward VPPs and Smart Grids represents a paradigm shift in distributed generation integration, where DERs are no longer considered merely as locally connected generation sources or loads, but rather as coordinated assets capable of providing flexibility services and active support to the power system. However, the effective utilization of these capabilities depends on the ability of regulatory frameworks to evolve consistently with technological advancements, addressing administrative barriers, institutional coordination challenges, interoperability among digital platforms, and the adaptation of protection and operational schemes.

Overall, comparative evidence indicates that international regulatory frameworks are converging toward increased interoperability, automation, and active participation of distributed generation in power system operation. Nevertheless, significant differences remain regarding interconnection standards, control strategies, protection requirements, communication infrastructures, and institutional capabilities across countries. These factors ultimately determine the security, reliability, and efficiency of DER integration. Table 2 summarizes the main regulatory standards, technical requirements, operational modes, and stability-related challenges identified across the different regulatory environments analyzed.

Figure 6 synthesizes the relationships identified throughout this section between regulatory architecture, technical grid-code requirements, interoperability, grid-support functions, and DG integration outcomes.

4.1.5. Honduran Regulatory Framework

From the perspective of DER classification, the Honduran regulatory framework presents an evolving structure aimed at establishing a differentiated regulatory treatment for self-producers and generation plants connected to distribution networks through separate regulatory instruments. Currently, the Technical Standard for Self-Producers (NTUAP) constitutes the primary regulatory instrument in force governing the integration of distributed generation resources intended for self-consumption with the possibility of exporting surplus energy [56]. In parallel, the Electric Energy Regulatory Commission (Comisión Reguladora de Energía Eléctrica CREE) has developed a proposed Technical Standard for the Connection and Operation of Generation Plants in Medium-Voltage Distribution Networks, which has undergone a public consultation process and remains under regulatory evaluation, but has not yet entered into force [57].

Taken together, these instruments reflect a regulatory trend toward the development of a differentiated framework in which self-producers and distributed generation facilities primarily oriented toward energy commercialization would be subject to specific regulatory regimes tailored to their operational, commercial, and technical characteristics. The NTUAP classifies users into Type A, B, and C categories according to their commercial characteristics, voltage level, and installed capacity, whereas generation facilities primarily intended for energy sales are addressed through an independent regulatory framework [56]. This approach differs from the prevailing trend observed in many international regulatory frameworks, where segmentation is generally based on voltage level or connection capacity, regardless of the commercial purpose of the resource. For example, studies in Europe [4,25,53] indicate that standards such as CEI 0-21 [58] and CEI 0-16 [59] in Italy, VDE-AR-N 4105 and the BDEW guidelines [60] in Germany, as well as the CENELEC TS 50549-1 [61] and TS 50549-2 [62] standards, primarily distinguish between low and medium voltage connections. Similarly, IEEE 1547 [10] establishes a unified technical framework for DER interconnection in distribution networks by incorporating performance categories based on grid operational requirements (such as voltage support capabilities, reactive power control, and response to disturbances) rather than classifying resources according to user type or fixed capacity thresholds.

The distinction between these approaches extends beyond the classification structure itself and also encompasses the regulatory purpose of such segmentation. Under the NTUAP, the categories determine administrative and technical aspects such as distribution utility response times, authorization validity periods, and the depth of interconnection studies required [56]. By contrast, the categories defined in IEEE 1547 are intended to establish the functional requirements that equipment must satisfy in order to contribute to system stability and reliability under both normal and abnormal operating conditions [10]. Furthermore, whereas the Honduran classification is assigned automatically based on predefined project characteristics, IEEE 1547 delegates to the authority responsible for interconnection requirements the determination of the performance capabilities required according to the specific characteristics of the network and the penetration level of distributed resources.

Among the cases reviewed, certain conceptual similarities can be identified with the Honduran approach. Authors in [25] argue that China distinguishes between user-side projects (prosumers ranging from 1 kW to 1 MW) and centralized generation projects (from 1 MW to 20 MW), applying progressively more demanding technical and administrative requirements as installed capacity increases. However, according to authors in [41], the Chinese model complements this segmentation with voltage-level-specific technical standards and more stringent requirements regarding monitoring, telemetry, and integration with grid management systems.

In this context, the Honduran case is noteworthy for combining technical criteria associated with voltage level and installed capacity with an explicit regulatory separation based on the functional purpose of the installation, distinguishing self-consumption with surplus compensation from generation primarily intended for energy injection and commercialization. At the same time, the complementary adoption of IEEE 1547 to address technical aspects not explicitly developed within the national regulatory framework helps maintain consistency with widely recognized international standards and facilitates the incorporation of future advanced DER capabilities without requiring frequent modifications to the national regulatory framework [56,57].

A notable feature of the NTUAP is the incorporation of steady-state electrical studies, which allow distribution utilities to verify that energy injected by users does not exceed circuit nominal capacities or adversely affect network operation. This assessment considers both the aggregated distributed generation connected to the circuit and the evolution of short-circuit power. To determine the maximum generation capacity that may be integrated at the point of common coupling, the regulation establishes two assessment scenarios: minimum demand and maximum demand at the point of common coupling. These demand values are derived from records corresponding to the previous twelve months. In addition, existing distributed generation and planned generation projects at the point of common coupling are considered. To evaluate the evolution of short-circuit levels, the regulation introduces a relationship that incorporates the product of the generator short-circuit contribution factor, the nominal apparent installed capacity of the generating equipment, and the short-circuit power at the point of common coupling. This approach seeks to ensure the proper performance and reliability of the electrical system (RCC ≤ 0.1) [56].

This approach exhibits important points of convergence with international practices used to assess DER integration. Several authors indicate that, although regulatory criteria and terminology vary across jurisdictions, the execution of pre-interconnection impact studies is a widely adopted practice to ensure that the integration of new distributed resources does not compromise network operating limits [4,10,19,48]. Within the European context, the study conducted in Poland [22] states that such analyses are commonly addressed through the concept of hosting capacity, defined as the maximum amount of generation that can be connected without compromising system reliability or power quality. To determine this limit, distribution system operators evaluate variables such as voltage profiles, voltage unbalance, losses, harmonics, and feeder loading levels, identifying the point at which distributed generation penetration begins to produce technically unacceptable impacts. Similarly, the IEEE family of standards contemplates the execution of system impact studies to identify potential effects on network operation and protection before authorizing new interconnections [10].

Nevertheless, whereas hosting capacity approaches are generally based on dynamic assessments of network performance and the progressive identification of operational constraints associated with increasing penetration levels, the NTUAP adopts a more explicit and deterministic framework based on limits calculated from historical demand, circuit nominal capacity, and the short-circuit contribution of connected resources [10,56]. In both cases, the regulatory objective is essentially to ensure that DG deployment does not cause thermal overloads, voltage regulation problems, or adverse impacts on protection schemes. However, the Honduran framework stands out for incorporating specific quantitative criteria directly into the regulation, thereby providing stakeholders with clear rules for evaluating interconnection requests and determining the admissible generation capacity at each point of connection [56].

From the perspective of distribution system protection and control, the NTUAP introduces an explicit and quantitative short-circuit constraint based on the short-circuit ratio [56]. A distinctive feature of this formulation is the use of technology-dependent contribution factors (1 for inverter-based resources and energy storage systems, 6 for asynchronous machines, and 8 for synchronous generators), which reflect their differing fault current characteristics. This level of specificity facilitates protection coordination studies and aligns with practices observed in European standards such as Italy’s CEI 0-21 [53]. However, the regulation also assigns responsibility to the user: if the installation results in excessive fault levels or equipment overstressing, the user must mitigate the impact or upgrade network components.

In contrast, international frameworks generally adopt more flexible or system-oriented approaches. For example, according to authors in [41], distributed generation in Texas is typically limited to a fraction of the feeder short-circuit contribution, whereas under the United Kingdom’s G83 framework manufacturers are required to specify fault current contributions to support network-level assessments. IEEE 1547, rather than imposing fixed numerical thresholds, requires that DER integration does not compromise protection system performance [10]. Compared with these approaches, the NTUAP relies on a fixed and conservative threshold, which simplifies compliance but may limit integration under high-penetration scenarios.

A particularly relevant aspect of the Honduran framework is the explicit incorporation of ESS within the regulatory definition of self-producers [56]. The NTUAP allows the registration and operation of storage systems alongside generation resources and requires detailed specifications of both power capacity (kW) and energy capacity (kWh). Although this inclusion represents a step toward more flexible resource integration, the regulation remains fundamentally oriented toward individual interconnection rather than coordinated operation. Unlike more advanced regulatory approaches that enable aggregation mechanisms such as VPPs [31], the NTUAP emphasizes protection and disconnection requirements aimed at preventing energy injection under abnormal operating conditions. While these provisions enhance system security, they also reflect a paradigm closer to passive integration than to the active and interoperable operation envisioned by smart grid frameworks such as IEEE 2030 [11].

With respect to administrative processes, the NTUAP seeks to mitigate some of the bureaucratic barriers identified in international experiences. While countries such as Brazil report significant delays in interconnection procedures [19], the Honduran regulation establishes explicit response timelines for different user categories [56]. Likewise, in contrast to Poland, where the authors in [22] argue that legislative and institutional barriers hinder DG deployment, the NTUAP incorporates transparency mechanisms requiring distribution companies to publish georeferenced and periodically updated technical information to support pre-feasibility assessments [63]. Nevertheless, recent regulatory oversight evidence suggests that the implementation of these mechanisms still faces practical challenges: according to a CREE oversight report covering the fourth quarter of 2025, the self-producer user database submitted by the distribution utility presented significant non-compliance across several fields required by the regulation, including georeferencing information, user classification, and installed capacity [63]. This indicates that, although the regulatory design incorporates a deliberate effort to improve procedural efficiency and reduce information asymmetries, its practical effectiveness depends on institutional capacity to ensure continued compliance with these requirements on the part of distribution utilities.

Overall, the NTUAP may be characterized as a procedurally structured and technically detailed regulation that combines explicit mathematical criteria for capacity allocation and fault contribution with efforts to streamline administrative processes. However, its reliance on historical demand, static capacity limits, and conservative protection thresholds, together with the absence of interoperability requirements and real-time operational coordination, suggests a regulatory architecture that may constrain the scalable and adaptive integration of distributed generation. This positions the Honduran case as a representative example of how regulatory design, beyond formal alignment with international standards, critically determines the effectiveness of DG integration in modern distribution networks.

4.1.6. Central American Regulatory Framework Perspective

Guatemala, Panama, and Nicaragua were selected for this comparative analysis because they form part, together with Honduras, of the Central American Electrical Interconnection System (SIEPAC) and its associated institutional framework, the Regional Electricity Market (MER) [64], suggesting a regionally interconnected network infrastructure of comparable scale. Within this context, the regulatory frameworks governing distributed generation integration across the region exhibit a gradual convergence in technical requirements, despite persistent differences in regulatory implementation—particularly regarding interconnection mechanisms and the degree of sophistication of operational requirements—through specific regulatory instruments that define differentiated interconnection procedures, capacity-based protection requirements, and provisions intended to preserve power quality and ensure the secure operation of distribution networks. Furthermore, all three countries incorporate, to varying degrees, internationally recognized standards such as IEEE, IEC, ANSI, and UL to complement their national technical requirements, particularly with respect to anti-islanding protection, equipment certification, power quality, and inverter interconnection [65,66,67].

Despite these common regulatory trends, each country has adopted a distinct approach to distributed generation regulation, as summarized in

Table 3. Comparative Overview of DG regulatory framework and interconnection requirements in Central America.

Variable	Guatemala	Panama	Nicaragua	Honduras
Regulatory instrument	NTGDR [67]	Self-Consumption Procedure (ASEP) [65]	NGDRA + Technical Annex [66,68]	NTUAP [56]
Application threshold/tiering	≤5 MW (general application)	Tiered: ≤500 kW/500–2500 kW/>2500 kW	Grid impact study required if >1 MW	Type A/B/C classification by voltage and capacity
User classification	GDR (sells to market) vs. UAEE (self-consumption)	Not explicitly distinguished by commercial type, but by capacity tier	GDR (parallel-operation generation)	Type A/B/C—non-commercial
Anti-islanding protection	Mandatory (anti-islanding relay)	Mandatory (automatic device)	Mandatory, disconnection < 2 s	Mandatory (disconnection criteria)
Supplementary international standards	ANSI, IEEE, IEC (supplementary)	Not explicitly specified in the source	IEEE 1547, IEEE 519, UL 1741 (mandatory)	IEEE 1547 (complementary)
Minimum power factor	0.85 (≤11 kW)/0.90 (>11 kW)	>0.90 (when output >10% of rated)	Not specified in the source	Not directly applicable (SCCR, not PF)
Short-circuit criterion	Required in study; no fixed numerical threshold; Scc used as reference for flicker	Required in study (>2500 kW); no fixed threshold; Scc used for flicker	Quantitative threshold: contribution ≤ 10% of feeder’s maximum Icc	Quantitative threshold: SCCR ≤ 0.1 (technology-based factors: 1/6/8)
Aggregate penetration limit	Not specified in the source	10% of annual peak demand/2% of annual consumption of the concession area	Not specified in the source	Based on historical demand (min./max.) at the PCC

. Guatemala emphasizes the mitigation of network impacts through interconnection capacity assessments and progressively more stringent protection requirements based on installed capacity, distinguishing between renewable distributed generators oriented toward energy sales and self-producers with surplus energy intended for self-consumption. Panama, in contrast, adopts a tiered approach based on installed capacity, with remote supervision and disconnection control requirements for larger installations [65]. Nicaragua, for its part, has adopted one of the most prescriptive technical frameworks in the region by explicitly requiring compliance with internationally recognized standards such as IEEE 1547 and UL 1741, and by establishing precise quantitative thresholds for multiple technical parameters [66,68].

A particularly relevant aspect for comparative purposes is the treatment of short-circuit current contribution. While Guatemala and Panama require the evaluation of this parameter as part of interconnection studies, neither regulation establishes a fixed numerical threshold for the maximum admissible contribution, instead using the system’s short-circuit capacity primarily as a reference for calculating flicker tolerances. Nicaragua and Honduras, by contrast, do establish explicit quantitative limits: the Nicaraguan NGDRA restricts the aggregate contribution of distributed generators to a maximum of 10% of the feeder’s maximum short-circuit current, while the Honduran NTUAP defines a Short-Circuit Current Ratio that must not exceed 0.1, differentiated according to generation technology type [56,66,68]. This divergence reproduces, at a regional scale, the same contrast between deterministic regulatory frameworks and system performance-oriented approaches discussed in Section 4.1.5.

Taken together, these regulatory frameworks reflect a regional trend toward strengthening the operational security and reliability of distributed generation interconnection through increasingly comprehensive technical requirements. Nevertheless, they remain predominantly focused on the individual interconnection of distributed energy resources, with only limited incorporation of advanced aggregation mechanisms, interoperability requirements, and flexibility services characteristic of Smart Grid architectures. Within this regional landscape, the Honduran regulatory framework, described in detail in Section 4.1.5, shares with its Central American neighbors this predominantly individual approach, while distinguishing itself—together with Nicaragua—by adopting a deterministic, quantitative criterion for assessing short-circuit current contribution, in contrast to the study-based, threshold-free approaches of Guatemala and Panama. This suggests that, beyond country-specific particularities, the Central American region faces, in a generalized way, the same challenge identified in the Honduran case: the need to evolve toward regulatory models capable of supporting advanced DER functionalities, real-time operational coordination, and aggregation mechanisms consistent with the ongoing transition toward Smart Grids and VPPs.

5. Tariff Regulation of Distributed Generation

5.1. RQ 2: How Has the Tariff Regulation of Distributed Generation Been Addressed in the Global Literature?

5.1.1. From DG 1.0 to DG 2.0

The large-scale integration of distributed energy resources has shifted from being a secondary objective to becoming a central issue in global energy policy. Recent academic literature shows that the tariff regulation of DG has evolved from an initial phase of basic incentives known as “DG 1.0”, based on mechanisms such as Net Energy Metering (NEM) and fixed Feed-in Tariffs (FiT), toward a more advanced stage of market integration referred to as “DG 2.0” [5,69].

This transition addresses the need to correct economic and technical imbalances that arise when prosumers use the electricity grid as a kind of “virtual battery” without proportionally covering the costs of its infrastructure [5,70]. One of the central issues in the international debate is equity and cross-subsidies. Studies conducted in Australia and Sweden indicate that preferential tariffs and benefits granted to small generators may produce regressive effects, as lower-income households ultimately subsidize the advantages obtained by owners of solar systems [71,72].

In Germany, this issue is examined from a territorial perspective, showing that tariff schemes based on consumption volume disproportionately affect rural regions with high wind energy penetration and low population density [73].

5.1.2. Equity, Cross-Subsidies, and Utility Cost Recovery

To reduce the decline in revenues of distribution companies, a process known as the “death spiral”, an economic vicious cycle where tariff increases, necessary to cover fixed costs in the face of falling energy sales, incentivize more consumers to adopt DG, further reducing utility revenues [5,69,74]. Several studies propose the adoption of two-part or multi-part tariff structures [74,75,76]. These schemes seek to differentiate energy consumption charges from capacity or power charges, ensuring that prosumers contribute to the cost of the backup provided by the grid regardless of their net energy balance [76,77]. At the same time, more innovative approaches propose the implementation of dynamic pricing and homeostatic control mechanisms to encourage users to participate as “active loads” within the system [78,79].

Experiences in countries such as Colombia, Brazil, and Chile show that time-of-use (TOU) tariffs, when properly designed, not only strengthen the economic sustainability of the system but also contribute to the stability of critical technical variables, such as frequency in isolated microgrids [79,80,81]. Currently, the discussion focuses on finding a balance between the regulatory simplicity necessary to ensure clarity and transparency and the level of precision required to accurately reflect the real value of energy [69,82]. While some researchers promote simple mathematical models that facilitate user participation [82], others argue that only through the detailed separation of ancillary services and loss-related charges can an efficient and equitable integration of DG be achieved in the long term [5,69].

5.1.3. International Tariff Models and National Experiences

Germany is cited as a historical leader in DG penetration due to its FiT and a favourable connection regime that grants priority access to renewable energy [69,83]. While authors in [69,83] highlight the success of its incentives in achieving a rapid transition reaching more than 30% renewable energy in 2015 [73,74] introduces a methodological critique regarding regional equity. According to [73], the volumetric charge model and shallow connection scheme have penalized rural areas with a high density of wind farms but low population, increasing local tariffs to finance grid expansion. This has forced a transition toward direct market sales to minimize excessive cost socialization [83].

The Australian case reflects a debate between technological promotion and social justice. Paper in [72] provides a strong economic critique of premium FiTs, describing them as a form of “regressive taxation” in which tenants and low-income households subsidize the benefits of wealthier property owners. Conversely, ref. [78] proposes an advanced technical solution: the use of fuzzy logic to implement dynamic tariffs that change every 30 min according to weather conditions and demand, aiming for technical stability rather than solely fixed financial incentives.

Brazil is the country most extensively covered in the reviewed literature, with a strong focus on the long-term sustainability of its current regulatory framework. NEM remains widely adopted and has significantly reduced distribution utility revenues (EBITDA), raising concerns regarding future investment capacity [74,75]. Consequently, there is broad consensus in the literature regarding the need to transition toward a two-part tariff structure that separates energy charges from demand (kW) charges [70,76]. However, ref. [76] warns that such a transition may adversely affect consumers by extending distributed generation investment payback periods by up to 13 years. Similarly, ref. [70] argues that this reform should not be interpreted as a “solar tax,” but rather as a necessary correction to cross-subsidies arising from prosumers using the grid as a “free battery.” In parallel, the White Tariff (TOU) has been studied as a demand-side management mechanism, particularly in the rural sector [84]. Rather than providing a direct incentive through compensation for exported energy, the tariff encourages consumers to reduce electricity purchases during peak-price periods. This price signal has indirectly promoted the adoption of distributed photovoltaic generation, as consumers install solar systems to offset their own consumption during high-cost hours, effectively shifting demand away from peak periods and reducing exposure to elevated electricity prices [84].

5.1.4. Additional Lessons from Flexible and Emerging Tariff Schemes

Chile has transitioned from a Net Billing model (Law 20.571) toward proposals of greater technical complexity [79]. Chilean literature reveals a duality between simplicity and optimization. Ref. [82] proposes a simple algebraic tariff model to ensure regulatory transparency and cost recovery in the face of declining energy sales. In contrast, ref. [79] advocates for an energy homeostasis approach, where buildings act as “active loads” that adjust their consumption in real time through economic penalties and incentives, maximizing self-consumption and storage use.

The United States is used as a reference for the transition toward DG 2.0 models [69]. The traditional NEM model in states such as California has generated the well-known “duck curve,” forcing regulators to reduce tariffs for higher consumption blocks to prevent unsustainable price spirals [69]. To address this, standby charges and the concept of the Value of Solar (VOS) have been implemented, aiming to compensate users only for the actual benefit they provide to the grid and to prevent non-participants from paying for prosumers’ infrastructure [69,77].

Italy is well known for its transition from massive subsidies to cost-causality-based regulation. After ending its FiT schemes between 2013 and 2016, current discussions focus on the design of multi-part tariffs. The work in [5] proposes models that include connection charges and variable components reflecting energy losses avoided or caused by DG. Unlike Germany, Italy applies a shallow connection scheme to encourage DG in hard-to-reach rural areas, thereby postponing the need to build new centralized capacity [5,85]. Sweden stands out for a flexible regulatory model in which each distribution company designs its own tariffs under general guidelines [71,85]. Unlike most European countries, Sweden uses deep connection charges, requiring prosumers to pay for the necessary grid reinforcements [85]. Nevertheless, ref. [71] identifies an equity issue: the exemption rule for plants smaller than 1500 kW creates cross-subsidies that force other consumers to cover up to 5% of the annual revenues of electricity companies.

The Colombian approach in the literature focuses on Non-Interconnected Zones. Given the dependence on diesel in rural areas, the literature proposes TOU tariffs designed to encourage consumption during peak solar radiation periods. This method seeks not only economic sustainability but also technical improvements, reducing system frequency variability by 13.3% [81].

Ecuador is evaluated from the perspective of its regulatory evolution and technical structure, under regulation ARCONEL-042/18, the country applies a self-consumption scheme for installations up to 100 kWp, operating on a monthly net metering model where injected surpluses roll over as energy credits valid for up to two years, to ensure technical balance, each user’s installed capacity is strictly capped based on historical consumption [86]. Following the repeal of its Feed-in Tariff model in 2016, however, the country fell into a regulatory gap regarding surplus valuation. Literature points out that the Organic Law lacks clear rules for individuals to commercialize excess power, while the current framework lacks mechanisms for peer-to-peer or community energy trading, ultimately restricting microgeneration growth [86,87].

In Spain, self-consumption regulation is governed by Royal Decree-law 244/2019, which recognizes both individual and collective self-consumption arrangements, either with or without surplus energy [86]. In the surplus category eligible for compensation, the value of injected energy is credited to the prosumer at a price agreed upon with the retailer, which is typically lower than the purchase price, a strict limit is applied, the monthly financial balance cannot be negative, meaning that if the valuation of injected energy exceeds the cost of energy consumed during that billing period, the prosumer forfeits the remaining difference [86].

Romania promotes the integration of prosumers up to 400 kW under Law No. 184/2018 and regulatory updates issued by the national authority ANRE, users with capacities up to 200 kW operate under a net metering system where energy surpluses are converted into credits valid for offsetting future bills over a period of up to 24 months [86]. A distinctive feature of the Romanian framework is the exemption from green certificate obligations for installations up to 400 kW, a measure designed to simplify administrative procedures and foster small-scale connections to the national power grid [86].

In the case of Bangladesh, this country’s regulation is based on Net Energy Metering, formally implemented in late 2018 to incentivize private investment and reduce reliance on fossil fuels [88]. The model enables prosumers to receive the same rate for each injected unit as they pay for consumed energy, with any surplus carried forward as a credit to the following month, despite this setup, the framework imposes critical technical constraints, exports cannot exceed 70% of the authorized load or 70% of the local distribution transformer’s capacity [88]. Literature warns that while attractive for prosumers, this scheme erodes utility revenues, requiring periodic rule revisions to maintain the economic balance of the system [88].

In India, distributed generation is promoted through ANERT’s “Solar Connect” program for systems ranging between 2 kW and 50 kW [89]. The model uses net metering with a compensation rate for net surpluses of approximately Rs. 3 per kWh, its viability relies on high levels of state and central subsidies, which can cover up to 30% of the installation cost [89]. Studies indicate that without these subsidies, the payback period for low-consumption users would exceed 10 years, making the model heavily dependent on government support [89].

Iran’s approach centers on market restructuring and privatization through technology-differentiated Feed-in Tariffs, the government provides incentive pricing such as 8 cents/kWh for wind energy compared to 1.62 cents/kWh for conventional plants alongside long-term, interest-free government loans to establish renewable facilities [90]. Despite these incentives, the primary barrier remains the lack of clear regulations regarding grid connection points and siting, which creates legal uncertainty for private investment [90].

Mauritius promotes Small-Scale Distributed Generation (SSDG) to reduce its 79% reliance on imported fossil fuels [91]. National analysis utilizes the Levelized Cost of Energy (LCOE) to compare technologies, determining that solar photovoltaics are financially more attractive to prosumers than vertical-axis wind turbines, this dynamic creates a latent methodological conflict: while prosumers favor solar power for its return on investment, the utility company prefers wind generation due to its superior “hosting capacity” and grid injection stability [91].

Malaysia transitioned in November 2016 from a Feed-in Tariff system toward a Net Energy Metering program designed to encourage self-consumption, under this framework, energy is consumed locally first, with any excess exported to the grid at a displaced or blended generation cost and credits remaining valid for 24 months [92]. The Malaysian regulation is particularly notable for its strong focus on technical constraints, warning that penetration levels above 40% in residential areas can compromise voltage quality [92].

The Netherlands has traditionally relied on a price cap regulation focused on the operational efficiency of Distribution System Operators, incorporating productivity benchmarking “x-factor” and quality benchmarking “q-factor” [93]. Recent reform proposals lean toward locally differentiated tariffs using a z-factor, which would allow higher charges in areas with dense concentrations of distributed generation, a primary concern highlighted in the literature is that the current framework delays necessary grid modernization investments required to transition toward a smart infrastructure capable of supporting large-scale prosumer integration [93].

South Africa stands out for its exploration of advanced Peer-to-Peer energy trading schemes within microgrids that integrate commercial prosumers and residential consumers [94]. Operating under a Time-of-Use tariff structure, the model optimizes energy flows by dispatching power from batteries during peak-price periods, thereby minimizing electricity purchases from the central grid [94]. From a methodological perspective, this strategy successfully reduces the daily operating cost from $6.24 to $2.65, resolving inefficiencies from previous regulations that forced the curtailment of excess energy [94].

International literature shows that tariff regulation for DG has evolved from simple compensation mechanisms toward more differentiated and cost-reflective regulatory approaches. While early schemes such as NEM and FiT were designed primarily to stimulate DER adoption, more recent models seek to balance prosumer incentives with issues of equity, utility cost recovery, and efficient grid use. This evolution has led to a broad diversity of pricing arrangements, ranging from time-of-use tariffs and demand charges to value-based compensation schemes and dynamic pricing strategies. In this context, a comparative summary is useful to systematize the main regulatory and pricing mechanisms identified in the literature.

Table 4. Tariff, Remuneration, and Connection Cost Mechanisms for DER Integration.

Tariff Model/Regulation	Description	Countries of Application/Study	Source
Net Energy Metering (NEM)	Compensation between consumed and injected energy; the grid acts as a “virtual battery.”	Brazil, Ecuador, Italy, U.S. (California, New York), Romania, Bangladesh, India, Mauritius, Malaysia.	[5,69,70,75,87]
Net Billing	Imported and exported electricity are measured separately and valued at different prices	Honduras; other international applications	[95,96,97]
Feed-in Tariff (FiT)	Guaranteed fixed payment for each kWh injected into the grid, usually above market price.	Australia, Germany, Ecuador (historical), Iran.	[69,72,74,83,87]
Time-of-Use (TOU)	Differentiated tariffs by time blocks (peak, off-peak, intermediate) to manage demand.	Brazil (White Tariff), Chile, Colombia, U.S, South Africa.	[69,77,79,81,98]
Binomial Tariff/Demand Charge	Separation of billing into a variable charge (energy—kWh) and a fixed/power charge (demand—kW).	Brazil (proposal), Chile (BT-4.3/AT-4.3), Italy, U.S. (standby).	[5,70,76,77,79]
Value of Solar (VOS)	Compensation based on the actual value that solar energy provides to the grid (loss avoidance, etc.).	U.S. (Austin, Minnesota).	[69]
Dynamic Feed-in Tariff	Adjustment of the injection tariff at short intervals (e.g., 30 min) according to grid and climate conditions.	Australia (New South Wales).	[78]
Stand-by Charges	Additional fixed charges for prosumers to cover grid infrastructure maintenance.	U.S. (New York, California).	[69,77]
Multi-part Tariff	Includes fixed connection charges, net variable charges, and components for energy losses.	Italy, Netherlands.	[5]
Shallow Connection	The prosumer only pays for connection equipment; network reinforcements are socialized.	Germany, Italy.	[73,83,85]
Deep Connection	The prosumer assumes the total cost of connection and necessary upstream network reinforcements.	Sweden, Honduras (proposal), Spain.	[73,83,85]
Exemption Rule (1500 kW)	Total or partial exemption from network charges for plants below a specific capacity.	Sweden.	[71,73]
Homeostatic Control	Dynamic adjustment of load and generation through price signals based on system frequency.	Chile (proposal), Colombia.	[79,81]

presents an overview of the principal tariff models, their defining characteristics, and the countries in which they have been applied or discussed.

5.1.5. Honduras Transitory Tariff Overview

At the regional level, Honduras has achieved significant progress through the proposal promoted by the National Electric Energy Company (ENEE), in its capacity as the distribution utility, which has been approved by the CREE. This initiative establishes a transitional tariff to compensate for energy surpluses injected into the distribution network by self-producing users. The tariff is updated on a quarterly basis, taking into account ENEE’s generation costs and the injection characteristics corresponding to each tariff category. During its initial implementation phase, the approach focused particularly on the injection characteristics of photovoltaic solar parks connected to the Honduran National Interconnected System (SIN). Consequently, these tariffs must be periodically updated in accordance with the injection profiles of this type of user [95].

This tariff is calculated based on the avoided cost of energy, which represents the economic savings achieved by a distribution utility when it does not need to generate or procure electricity from traditional sources, as is the case in Honduras, where generation is predominantly based on fossil fuels. The main purpose of this approach is to quantify ENEE’s savings through the substitution of high-cost thermal generation during periods of peak solar availability.

To perform this calculation, an hourly weighting is applied to distribute the value of injected energy according to solar availability: 41.19% during peak hours, 46.93% during intermediate hours, and 11.88% during off-peak hours. This distribution is based on the characteristic solar injection curves of the Honduran SIN. Additionally, deductions are applied to the tariff corresponding to administration, operation, and maintenance (AO&M) costs, as well as to the capital recovery of the network infrastructure used as backup by users [95].

The General Electricity Industry Law establishes that surplus energy billing is carried out through the Net Billing mechanism. This system applies differentiated prices between the injection tariff and the consumption tariff, with the former generally being lower, as is the case in Honduras. During the second quarter of 2026, the tariff for surplus energy generated by a residential user is 83.84 USD/MWh, while the consumption tariff reaches 215.04 USD/MWh [95,96,97].

The proposed Honduran model departs from pure NEM schemes that studies [69,74,87] reports as being implemented in countries such as Brazil, Mexico, and Ecuador. According to the literature [69,70,73,76], under traditional NEM, the grid operates as a “virtual battery” with 1:1 compensation, which often results in prosumers not adequately remunerating the physical infrastructure of the network. According to [73], in Brazil, for instance, the implementation of NEM led to an erosion of distribution utility revenues, threatening their investment capacity. In contrast, the Honduran proposal seeks to mitigate this risk through the introduction of a network usage charge. This approach aligns with the transition toward the “DG 2.0” phase, which aims at a more equitable market integration based on the actual value that energy provides to the grid [69].

The authors in [69,73] warn that when prosumers reduce their reliance on grid consumption through DG but do not pay fixed capacity charges, a “death spiral” may emerge: a cycle in which tariffs increase to cover fixed costs, incentivizing more users to install solar panels and further aggravating the financial instability of the utility. By implementing a network infrastructure usage charge applied to injected energy, Honduras seeks to avoid regressive cross-subsidies, where, according to studies in [70,72], lower-income households end up subsidizing the network used by prosumers. This mechanism shares similarities with binomial tariff proposals developed in Brazil [75] and multipart tariff schemes implemented in Italy [69], which aim to more efficiently allocate costs and benefits associated with DG through the differentiation of capacity, network usage, and energy charges.

More broadly, international literature reports a transition from traditional NEM schemes toward tariff mechanisms with more accurate economic signals on infrastructure usage. These include backup charges and binomial tariffs, applied in jurisdictions such as California and New York, where users contribute to grid cost recovery through fixed capacity-based and variable energy-based components [77]. Likewise, other approaches such as bidirectional distribution tariffs seek to ensure that users contribute to grid financing both when consuming energy and when using the infrastructure to inject surplus generation, while maintaining incentives for energy efficiency and proper sizing of photovoltaic systems [69].

In a complementary manner, some countries have adopted mechanisms aimed at reflecting the temporal or system value of injected energy. FIT schemes, widely implemented in Germany, Denmark, and Spain, remunerate exported energy through pre-established prices, while more recent models such as the VOS implemented in Austin, Texas, explicitly quantify the benefits that DG provides to the system, including avoided generation, transmission, and distribution costs [5,69,83]. On the other hand, authors in [78,98,99] report that dynamic feed-in tariffs developed in Australia and TOU schemes applied in Brazil introduce hourly price signals that incentivize injection or consumption during periods of higher system value, contributing to congestion management, peak demand reduction, and deferral of infrastructure investments. In this context, the Honduran scheme can be interpreted as an approach primarily oriented toward grid cost recovery and mitigation of cross-subsidies, aligning with an international trend that seeks to balance the financial sustainability of distribution utilities with the promotion of distributed generation.

Regarding physical integration, the regulatory framework establishes that self-producers must comply with technical requirements to ensure distribution grid stability. Likewise, they must carry out any necessary reinforcements in the grid infrastructure when energy injections from these users negatively affect system performance. According to authors in [72,85], countries such as Sweden and Australia apply deep connection charges, under which the costs of grid reinforcements required to accommodate new energy injections are allocated to the connection applicant. The specialized literature indicates that this approach constitutes a relevant economic signal for distributed generation developers, who must incorporate potential grid expansion or reinforcement costs into their economic feasibility analyses [73,83]. Furthermore, reviewed studies do not explicitly distinguish between small- and large-scale installations within the general concept of DG but rather focus on cost allocation based on the technical requirements derived from each connection request [73,83,85]. In this sense, the main objective of these mechanisms is to incentivize a more efficient spatial allocation of distributed energy resources and reduce the need for additional infrastructure investments [73,83].

The use of time blocks in Honduras to value energy injection shows similarities with the Colombian approach, where TOU tariffs are applied to flatten the demand curve and take advantage of peak solar radiation periods [81]. However, Honduras primarily uses this system for the financial valuation of surplus energy, whereas proposals in Chile explore more advanced energy homeostasis mechanisms, treating the prosumer as an “active load” that dynamically responds to system frequency [79]. The proposed Honduran regulation aligns with global literature by prioritizing financial sustainability of the electricity system and equity between users with and without distributed generation. The surplus energy compensation mechanism for self-producers is an important step toward distributed generation in Honduras. However, the current framework focuses mainly on energy valuation and utility cost recovery, without explicitly recognizing ancillary services, voltage support, congestion management, or local flexibility. Although storage is permitted, its role remains mostly limited to backup supply. Future regulation should therefore recognize the operational value of distributed generation, storage, and controllable loads.

For analytical clarity, the mechanisms summarized in Table 4 were grouped according to their principal regulatory function. Net energy metering, net billing, feed-in tariffs, value-of-solar mechanisms, and dynamic feed-in tariffs determine the remuneration of exported energy. Time-of-use, binomial, demand-based, standby, and multi-part tariffs determine how consumers contribute to energy, capacity, and network costs. Shallow and deep connection charges instead determine how the costs of connecting and reinforcing the network are allocated. These categories are complementary and should not be interpreted as mutually exclusive alternatives.

Honduras currently applies a transitional net-billing approach because imported and exported electricity are valued separately. The mechanism provides formal remuneration for surplus renewable electricity while retaining differentiated network-related charges. More complex structures, such as time-varying export tariffs, demand charges, or flexibility payments, would require reliable interval metering, cost-of-service analysis, and adequate settlement arrangements before implementation.

6. Operational Challenges of High DER Penetration

6.1. Transition from Passive to Active Distribution Networks

Distribution networks were historically designed with a radial, unidirectional architecture, in which power flowed from the transmission system to distribution systems to end users, Figure 7a. The growing penetration of self-producers, particularly those based on inverter-based technologies such as photovoltaic generation, substantially changes this paradigm, transforming the grid into an active, bidirectional, and dynamically variable infrastructure. In this context, Distributed Energy Resource Management Systems (DERMS) have been introduced in order to manage and coordinate distributed energy resources, enabling their efficient integration and operation within the network, as shown in Figure 7b.

This structural transition introduces significant operational challenges. First, the massive presence of distributed energy resources alters voltage profiles in feeders, increasing the likelihood of overvoltages in scenarios of high irradiance and low local demand. The ability of inverters to inject or absorb reactive power offers mitigation mechanisms; however, their effectiveness depends on coordinated control strategies and technical operating limits [100,101].

Regarding protection systems, the electronically limited short-circuit current contribution of inverter-based resources modifies the fault response of distribution networks. Lower fault-current levels, combined with bidirectional power flows, can compromise the selectivity and coordination of conventional protection devices, increasing the risk of nuisance tripping, delayed operation, or failure to detect faults. Therefore, networks with high penetration of inverter-based DERs require adaptive protection schemes, enhanced monitoring, and greater information exchange among protection and control devices [100,102,103].

The dynamic stability of the system is also affected by the partial replacement of synchronous generation by converter-based resources, which do not inherently provide conventional rotational inertia. Reduced effective inertia and fast inverter responses can induce oscillations or unexpected transient behavior, especially under contingency conditions. Moreover, the simultaneous disconnection of multiple DER units may amplify frequency and voltage deviations, reducing operational resilience [100,102,104].

Likewise, the bidirectionality of power flows represents a fundamental change in the operational logic of distribution networks. While localized generation can reduce technical losses in certain scenarios, it also complicates expansion planning, protection coordination, and congestion management in substations. Operating under these conditions requires more sophisticated analysis models and monitoring systems capable of anticipating rapid variations in DG [101,103].

Under high penetration scenarios, even normal operating events can cause transformer overload and voltage deviations when there is no centralized coordination of distributed resources. Contingency operations become more complex due to the heterogeneous response of multiple distributed units, especially in the absence of coordinated control mechanisms.

Finally, power quality can be compromised by the introduction of harmonics, flicker, and voltage fluctuations associated with the operation of electronic converters. Although technical standards establish regulatory limits, the massive aggregation of inverters can generate cumulative effects that require advanced monitoring and active mitigation strategies. The convergence of these impacts shows that the main operational challenge lies not only in the individual presence of self-producers but also in the simultaneous coordination of multiple heterogeneous resources within the same distribution network. As penetration increases, complexity ceases to be strictly an electrical problem and becomes a systemic management issue. In this context, DERMS is emerging as an operational platform aimed at integrating real-time monitoring, control, and optimization, allowing active network operation to scale under high DG penetration.

6.2. Structural Limitations of Distributors in the Face of Massive DER Integration

Beyond the immediate technical impacts, the massive penetration of self-producers reveals profound structural limitations in the traditional operating model of distribution system operators (DSOs). The historical architecture of distribution networks, conceived under a radial topology and predominantly unidirectional flows, was not designed to operate in environments with high penetration of DG and simultaneous variability of multiple resources. The localized injection of power from different nodes modifies voltage and current profiles, potentially inducing overvoltages, congestion in specific sections, and unforeseen variations in transformer loads [6,105]. In unbalanced three-phase systems, a typical condition in distribution networks, intensive DER integration can accentuate voltage asymmetries and increase technical losses if adequate planning and control mechanisms are not implemented [6].

These physical constraints are exacerbated by limitations in modeling and planning. The problem of DER integration is inherently nonlinear and nonconvex, involving binary and continuous variables in unbalanced systems, which requires multiple three-phase load flows for scenario validation [6]. The computational demands associated with these analyses reduce the scalability of traditional planning approaches, making it difficult to simultaneously evaluate technical, economic, and environmental objectives under variable generation and demand conditions [6].

At the same time, the transition to active networks exposes weaknesses in the digital and operational architecture of many distributors. Effective management of thousands of distributed resources requires granular observability, integration between SCADA systems, outage management systems (OMS), geographic information systems (GIS), and advanced analytical tools [7]. However, in many contexts, particularly in emerging economies, low-voltage monitoring infrastructure is limited, SCADA systems were designed for passive operation, and real-time visibility of distributed resources is insufficient. Interoperability issues, communication latency, and cybersecurity vulnerabilities are additional barriers to effective coordination [7,106].

Traditional protection architecture also faces structural constraints. The bidirectionality of flows and the variable contribution of DERs modify fault current levels and directions, affecting the selectivity of conventional schemes and requiring adaptive protections supported by communication and distributed logic [106]. Likewise, the aggregation of DERs at the substation level introduces challenges in coordination between DSOs and transmission system operators (TSOs), potentially influencing power flows and the stability of the upper system in the absence of structured information exchange mechanisms [7].

In addition to these technical and operational constraints, there are economic and regulatory limitations. The penetration of DG puts pressure on traditional cost recovery models based on billed energy. In revenue cap regulatory schemes, the reduction in net consumption can erode the distributor’s allowed revenues, even when the fixed costs associated with infrastructure, maintenance, and backup remain constant [8]. This decoupling between the volume of energy sold and investment needs compromises the financial sustainability of the network operator and can discourage the technological modernization required to safely integrate DER. The absence of harmonized regulatory frameworks and remuneration schemes that recognize ancillary services, flexibility, or local support also introduces institutional uncertainty and limits the creation of adequate incentives for the coordinated participation of distributed resources [8,106].

Taken together, these limitations show that the massive integration of DERs is not simply a matter of local technical adjustment, but rather a structural transformation that simultaneously affects the physical infrastructure, digital architecture, operational coordination, and economic sustainability of distributors. As the number of self-producers grows, the challenge evolves from individual connection management to the systemic coordination of thousands of heterogeneous resources, which requires advanced tools capable of integrating real-time monitoring, control, and optimization.

6.3. Dynamic Hosting Capacity and the Need for Time-Series Assesment

A further challenge associated with increasing DER penetration is that the technical capacity of a distribution feeder to accommodate additional generation cannot be adequately represented by a single static penetration limit. The concept of hosting capacity refers to the amount of DER that can be integrated into a distribution network without violating predefined operational criteria such as voltage limits, thermal loading, protection coordination, and power-quality requirements. Recent literature shows that hosting capacity is highly dependent on feeder topology, load behavior, DER location, generation profiles, and the operating state of voltage-regulation equipment [107,108].

Traditional deterministic approaches generally evaluate a limited set of worst-case operating conditions. However, this approach can either underestimate available network capacity or overlook short-duration constraints that emerge from the simultaneous variability of demand and renewable generation. Consequently, recent research increasingly favors probabilistic and time-series hosting capacity methods capable of representing uncertainty in photovoltaic production, demand, energy storage operation, and emerging loads such as electric vehicles [107].

This distinction is particularly relevant for active distribution networks because the maximum admissible DER capacity is no longer exclusively determined by the physical characteristics of conductors and transformers. Advanced inverter control, energy storage, coordinated voltage regulation, network reconfiguration, and demand flexibility can actively increase the amount of DER that a feeder can accommodate [107,109]. Therefore, hosting capacity should increasingly be interpreted as a dynamic operational quantity rather than as a fixed technical threshold.

For distribution system operators, this creates a transition from traditional connection studies toward continuously updated network assessments. Such an approach requires granular measurements, accurate network models, forecasting capabilities, and distribution-system state estimation. These capabilities would allow operators to distinguish between structural network limitations requiring reinforcement and temporary constraints that could instead be managed through operational flexibility [108,110].

7. DERMS as an Operational Enabler

7.1. Core Functions of DERMS

The increasing penetration of distributed energy resources (DER) has transformed distribution networks into more dynamic and operationally constrained systems, where voltage deviations, reverse power flows, miscoordination, and peak demand growth become critical concerns. In the analyzed literature, these impacts are directly associated with the variability of DER output, the bidirectional nature of power exchange, and the limited suitability of conventional control and protection schemes originally designed for passive networks.

In this context, DERMS emerges as an operational mitigation layer capable of coordinating distributed resources while respecting system constraints. This functionality is achieved through coordinated interaction between a commercial ADMS and a DERMS prototype based on real-time optimal power flow (RTOPF) [111], while the concept is extended to a utility-grade DERMS capable of managing DER [112], aggregators, and demand response resources, taking grid constraints into account.

This shows that DERMS is not limited to simple DER dispatch but rather functions as a supervisory decision-making layer that links grid operational objectives with controllable field resources.

7.2. Voltage Regulation and Congestion Mitigation

One of the most relevant mitigation functions of DERMS is voltage regulation. As authors reported in [111,112], high penetration of DERs can cause a significant increase in voltage at the interconnection point, while peak demand conditions place additional strain on voltage quality and grid efficiency.

To address this, DERMS deploys coordinated control actions over both legacy assets and inverter-based resources. The ADMS performs Dynamic Voltage Regulation (DVR) through load tap changers and voltage regulators, reducing feeder voltages by means of Conservation Voltage Reduction (CVR), while DERMS complements this action by controlling reactive power in residential PV inverters and active power dispatch in battery energy storage systems (BESS). This coordinated strategy is especially relevant because it shows that voltage mitigation in active networks is no longer based on isolated device operation, but on the joint optimization of conventional grid equipment and flexible DER [111].

DERMS can also support congestion and peak-load mitigation through active power management. Demonstrated an experimental ADMS–DERMS framework in which a commercial SurvalentONE ADMS performed dynamic voltage regulation using legacy utility equipment to reduce feeder demand through conservation voltage reduction, while a prototype DERMS dispatched distributed BESS to track phase-specific feeder-head power targets. Their results showed that coordinating voltage reduction with BESS dispatch reduced the battery power required for peak-load management and extended the duration of load reduction achievable with the same storage capacity [111].

The reported results indicate an average load reduction of 90 kW with DVR alone and up to 800 kW of additional reduction through BESS injection, which supports the idea that DERMS can provide measurable operational value beyond conventional voltage control schemes [111].

However, the same study also shows that this capability is constrained by the state of charge of the batteries, since tracking performance degrades once the reserve SOC limit is reached. This limitation is important because it reveals that DERMS effectiveness depends not only on control sophistication but also on the actual availability of flexible resources.

Another key contribution of DERMS lies in the management of reverse power flow and thermal constraints. Reverse power flow under conditions of high distributed energy resource (DER) generation and low demand is explicitly identified as a significant operational challenge for grids that were not originally designed for bidirectional operation [112].

In response, Utility DERMS is described as capable of resolving overloads and voltage violations through the optimal coordination of traditional grid assets and DER, including flexible contractual mechanisms such as curtailment during critical conditions. This means that DERMS can operate not only as a real-time controller, but also as a flexibility orchestrator that reduces or defers the need for infrastructure reinforcements.

7.3. Protection and Operational Security

From the protection perspective, the analysed material highlights that high DER penetration can render traditional protection settings inadequate because DER contributes different fault current characteristics than conventional synchronous sources, potentially causing relay misoperation and loss of selectivity.

In this regard, it assigns the DERMS a more advanced role through adaptive protection, in which protection parameters are adjusted in real time based on the status of distributed energy resources (DER) and the grid’s current operating conditions [112].

This is especially significant from a methodological standpoint, because it extends DERMS beyond voltage and power flow management into the domain of secure system protection, which is a much stronger claim for positioning DERMS as a comprehensive operational mitigation tool.

7.4. Centralized and Hierarchical Architectures

The studies analysed also reveal that mitigation using DERMS can be implemented across different control architectures. It features a hierarchical structure in which the ADMS sends enable signals and power references to the DERMS via a MultiSpeak interface, while the DERMS themselves are organized into a coordination layer and local distributed resource controllers [111].

In contrast, a centralized DERMS architecture for the utility company is described, featuring global visibility of grid constraints and coordinated interaction with distributed resources and aggregators [112].

From a comparative perspective, centralized architecture offers broader system awareness and stronger optimization capability, whereas hierarchical architecture provides better modularity and can preserve local controllability. This distinction is valuable because it suggests that DERMS is not a single technological configuration, but a family of control approaches adapted to different operational needs.

7.5. Multi-Timescale and Predictive Operation

Another key strength of DERMS is its ability to operate across multiple time scales. The coordinated ADMS-DERMS system operates in real time, with simulation steps that reflect rapid-response control behavior [111].

DERMS goes beyond immediate corrective action by incorporating planning and predictive functions through a forecasting module that anticipates future violations using load and generation forecasts [112].

Consequently, DERMS-based mitigation should not be understood as exclusively corrective. Rather, the literature supports a threefold interpretation of DERMS actions as corrective, preventive, and predictive, depending on whether the system reacts to an existing violation, acts to preserve operating margins, or anticipates near-future constraints.

Overall, the reviewed documents support the argument that DERMS constitutes a fundamental operational mitigation tool in active distribution networks. Its value lies in the coordinated control of voltage, active and reactive power, network congestion, reverse flows, and even protection settings through architectures that may be centralized or hierarchical and that can operate in real time or under predictive logic. At the same time, the literature makes clear that DERMS effectiveness is bounded by resource availability, model accuracy, and uncertainty associated with flexible DER and third-party aggregators. Therefore, DERMS should be understood not merely as a monitoring platform, but as an enabling operational framework for mitigating the technical impacts of high DER penetration in modern distribution systems.

7.6. Forecasting, State Estimation, and Data-Driven DERMS Operation

As DER penetration increases, effective coordination increasingly depends on the ability of the operator to estimate both the present and near-future state of the distribution system. Unlike conventional generation, distributed photovoltaic resources and flexible demand are strongly influenced by local weather conditions, customer behavior, and spatial diversity. Consequently, DERMS operation requires forecasting tools capable of estimating load, renewable generation, and potentially available flexibility across multiple temporal horizons [110].

Forecasting alone, however, is insufficient when distribution network observability is limited. Distribution system state estimation can combine measurements from SCADA, advanced metering infrastructure, feeder sensors, and other field devices with network models to reconstruct electrical variables that are not directly measured. This becomes increasingly important at low-voltage levels, where the number of monitored nodes is often significantly lower than in transmission systems [108].

Combining forecasting and state estimation creates the basis for a more predictive DERMS architecture. Instead of waiting for an overvoltage or transformer overload to occur, the system can anticipate a potential constraint and determine an appropriate control action before the violation materializes. Possible actions include modifying inverter reactive-power output, dispatching battery storage, adjusting flexible loads, or limiting active-power export during critical intervals. In this sense, the accuracy and availability of operational data become as important as the optimization algorithm itself.

The increasing use of data-driven techniques, machine learning, and artificial intelligence is also expanding the analytical capability available to DSOs. These techniques can support short-term renewable generation forecasting, anomaly identification, estimation of unmeasured operating conditions, and more adaptive DER coordination [110]. Nevertheless, their implementation depends strongly on data quality, communication infrastructure, computational capability, and the availability of representative historical datasets.

7.7. Interoperability and Smart Inverter Coordination

Another essential requirement for large-scale DERMS deployment is interoperability. A DERMS may identify an optimal operating point, but its practical value depends on whether commands and measurements can be reliably exchanged with heterogeneous DER devices, aggregators, utility platforms, and smart inverters. This becomes increasingly complex as thousands of DER installations from different manufacturers and with different communication capabilities are incorporated into the same distribution network.

Modern smart inverters provide functions that extend considerably beyond simple active-power conversion. These capabilities include Volt/VAr, Volt/Watt, frequency–watt control, active-power limitation, and other grid-support functions that can contribute to voltage regulation and increase DER hosting capacity [109]. When these functions are coordinated rather than configured independently, DERMS can use inverter flexibility as an operational resource while maintaining network constraints.

Communication standards are therefore becoming a fundamental component of DER coordination. IEEE 2030.5 [113], for example, supports two-way information exchange between utility DERMS, aggregators, and individual DERs, including the communication of operating schedules and inverter control commands [114]. Such interoperability reduces dependence on proprietary interfaces and facilitates the integration of heterogeneous devices into scalable DERMS architectures.

For developing electricity systems, interoperability has an additional strategic advantage: adopting standardized interfaces can reduce technological lock-in during future grid modernization. Rather than deploying isolated control platforms that require extensive custom integration, utilities can progressively connect advanced meters, smart inverters, storage systems, and aggregators through standardized information models and communication mechanisms.

7.8. Cybersecurity as an Operational Requirement of DERMS

The digitalization required for DERMS introduces an additional category of operational risk that is less significant in conventional passive distribution systems: cybersecurity. Coordinating large numbers of remotely connected DERs expands the cyber-physical attack surface from centralized utility infrastructure toward thousands of geographically dispersed endpoints [115,116].

Potential vulnerabilities include false-data injection, unauthorized modification of DER control commands, denial-of-service attacks, compromised user credentials, malware, and communication failures. Because DERMS relies on continuous information exchange, attacks affecting data integrity or availability could interfere with state estimation, forecasting, voltage-control decisions, or active-power dispatch. In high-penetration scenarios, coordinated manipulation of multiple DER units could potentially create effects at feeder or system level rather than remaining confined to a single installation [115].

Recent DERMS cybersecurity research therefore emphasizes defense-in-depth architectures, secure identity and access management, anomaly detection, communication authentication, and emerging zero-trust approaches [115]. Cybersecurity should consequently not be treated as an external information technology function added after DERMS deployment. Instead, it must be incorporated into the operational architecture from the design stage, considering the confidentiality, integrity, availability, and accountability of DER measurements and commands.

This aspect becomes particularly important when DERMS interacts with third-party aggregators or customer-owned resources. The utility may depend on assets that it neither owns nor directly maintains, making secure interfaces, authorization mechanisms, and clearly defined responsibilities essential conditions for reliable operation.

8. Implication for Honduras

8.1. Current DER Deployment, Trends, and Grid Performance Indicators in Honduras

Available official evidence indicates that DER integration in Honduras is advancing primarily through regulatory formalization, although the available data do not support the calculation of a consistent annual deployment growth rate. CREE reported 313 registered self-producers connected to the National Interconnected System by 2021 [117]. In 2025, CREE estimated that approximately 70 generating plants were connected to distribution networks [118]. These figures describe different populations—the former refers to self-producing users, whereas the latter includes generating companies connected to distribution networks—and should therefore not be interpreted as a single deployment series.

According to [119], as of March 2026, approximately 1484 users had generation equipment connected to the distribution network, of which only 683 corresponded to officially reported projects. Among these, only 369 projects had available information on installed capacity in kW, totaling approximately 60.01 MW, with an average capacity of 162.63 kW. The discrepancy between the total number of identified users and those with complete technical information highlights an important data-quality limitation. CREE has also reported inconsistencies in self-producer identification and bidirectional-meter records, which constrain the construction of a reliable historical series of installed capacity and injected energy [63]. Although the available information does not allow these discrepancies to be attributed to a specific cause, they are relevant from a regulatory perspective because incomplete characterization of DER deployment may limit the ability of operators and regulators to adequately assess technical impacts and plan their medium-term integration.

The available records also show how the 1484 users are distributed across the categories established by the NTUAP, with 80.5% classified as Type A, 17.55% as Type B, and the remaining 1.87% as Type C. This distribution indicates a clear national trend toward the predominance of residential and commercial low-voltage users, which constitute the segment integrating the largest share of DG equipment. This concentration is also reflected in the breakdown by service level: among the 369 projects with available capacity data, 350 users correspond to low-voltage general service, representing approximately 57.21 MW, while 11 residential users account for approximately 0.09 MW. Thus, approximately 98% of the projects with known capacity are located in low-voltage networks, compared with only eight users connected at medium voltage, accounting for approximately 2.71 MW. Given the numerous and geographically dispersed nature of low-voltage users, their continued growth could represent an increasing monitoring challenge for distribution management and SCADA systems, as discussed in Section 6.2.

Type B and Type C users, on the other hand, are connected to medium-voltage networks, where operator visibility and monitoring capabilities may be comparatively greater, facilitating the individual assessment of these installations. However, greater observability does not necessarily imply the absence of significant operational impacts. In particular, the lower number of medium-voltage users should not be interpreted as an indicator of proportionally lower operational relevance, since their individual generation capacities can be considerably higher.

This distinction becomes particularly evident in the observed reverse power flow conditions. Based on [120], reverse power flow peaks of up to 4.9 MW have been identified in circuits located in the northern region of the country, associated with reported DER projects classified as Type C users, which are connected at medium voltage and have generation equipment exceeding 1 MW according to the NTUAP [56]. Although Type C users represent only 1.87% of the identified users, their high individual generation capacity can translate into substantial operational impacts on the distribution network and potentially exert a significant influence on feeder operating conditions. Therefore, the low number of Type C users should not be interpreted as evidence of low operational risk.

The comparison between the documented national capacity and these local operational effects is particularly relevant. Although the 369 projects with available information account for approximately 60.01 MW of installed capacity nationwide, the observation of reverse power flow peaks of up to 4.9 MW in individual circuits indicates that aggregate national capacity alone does not adequately capture the spatial concentration or operational impact of DER deployment. This distinction between national penetration and local network impact is particularly relevant for distribution planning, hosting capacity assessment, and the future deployment of DER management and monitoring tools.

Regarding overall grid performance, official information reports total electricity losses, including technical and non-technical losses, of 34.5% in 2024 [121]. This aggregate value should not be interpreted as technical losses alone, nor should it be attributed to network conditions associated with DER penetration. It is therefore presented solely as contextual information on the overall performance of the Honduran distribution system.

CREE’s distribution-quality standard identifies SAIDI and SAIFI as feeder-level reliability indicators, although a consistent national historical series was not identified in the public sources reviewed [122]. Building on these indicators and considering the operational challenges discussed in Section 6.1 and Section 6.2, future assessments of DER integration in Honduras should additionally consider total and technical losses, voltage-limit violations, feeder and transformer loading, reverse power flow, hosting capacity, and DER curtailment. Together, these indicators could provide an operational baseline for evaluating the effects of increasing DER penetration and for assessing future smart-metering, flexibility, and DERMS initiatives.

Taken together, these findings indicate that the documented deployment of DERs in Honduras remains limited at the national scale, but its distribution across the network already presents relevant operational challenges. The predominance of low-voltage users highlights the growing importance of monitoring a large number of geographically dispersed resources, whereas the presence of high-capacity medium-voltage projects demonstrates that a small number of installations can produce substantial localized impacts, including reverse power flows. Consequently, the operational challenges discussed in Section 6.1 and Section 6.2 are not merely hypothetical; available evidence indicates that they are already emerging within the Honduran distribution network. At the same time, the limitations in the available deployment data underscore the need for improved information management and monitoring capabilities to support more reliable assessment and planning of DER integration.

8.2. Regional Perspective on Distributed Generation Deployment: Comparison with Honduras

A direct quantitative comparison of DG deployment among Central American countries is constrained by differences in national classifications, reporting practices, reference dates, and availability of technical information. The regional comparison therefore focuses specifically on distributed generation rather than the broader DER category, as the available official statistics primarily concern distribution-connected generation and self-consumption. Since the categories used by national institutions are not considered directly equivalent, the reported figures are used to contextualize the documented scale and development of DG in Honduras rather than to construct a normalized penetration indicator or quantitative ranking. The comparison focuses on Guatemala and Panama, while Nicaragua is excluded because its distributed-generation regulatory framework has already been examined in Section 4.1.6.

Guatemala provides the most comprehensive official statistical characterization among the countries considered. According to the National Electric Energy Commission (CNEE), approximately 162 MW of Renewable Distributed Generation (GDR) had been connected to the National Interconnected System through distribution networks by 2024, including hydroelectric, photovoltaic, biogas, and biomass technologies In parallel, the CNEE reported 12,002 Users with Self-Production and Energy Surplus (UAEE), representing approximately 96.3 MW of installed capacity across the three principal distribution companies [123]. The CNEE records also show an increase in GDR capacity and the number of UAEE between 2023 and 2024 [123,124]. These data indicate a measurable scale of distribution-connected generation and self-production, while also demonstrating a relatively high level of institutional visibility. GDR and UAEE are nevertheless distinct classifications and are therefore not treated as additive measures of total DG capacity.

Panama provides a complementary regional reference through its official statistics on self-consumption. According to the National Energy Strategy 2020–2030 (ENISIN), by July 2022 the country had 1836 distributed-generation installations for self-consumption, with 61.73 MW of installed capacity, predominantly based on solar photovoltaic technology [125]. The information was provided by distribution companies and incorporated into the SNE’s official diagnosis of the electricity sector. Subsequent official information reported more than 3325 customers participating in self-consumption schemes, corresponding to approximately 102.268 MW of installed capacity by February 2024 [126]. Although these observations should not be used to calculate a formal growth rate because the sources use different reference periods and descriptors—installations in 2022 and customers in 2024—they provide evidence of an expansion in the documented scale of self-consumption generation. The ENISIN also established a target of at least 1700 MW of DG by 2030, equivalent to approximately 14% of electricity demand [125]. This target is not interpreted here as evidence of current DG penetration, but rather as an indication of the scale that distributed generation was expected to reach within the country’s energy-planning horizon. The strategy also associates this development with a broader transition toward a more decentralized electricity system and greater participation of consumers as prosumers [125,126].

The contrast with Honduras becomes particularly relevant when considering the completeness of the available statistical information. As discussed in Section 8.1, the Honduran dataset shows a notable gap between the number of identified generation users and the subset of projects for which detailed technical information is available, including installed capacity. In comparison with the more consolidated statistical records available for Guatemala and the clearly reported self-consumption data available for Panama, the Honduran dataset presents a substantially lower level of technical characterization, which limits the direct comparability of its reported figures with those of the other countries.

This difference is important when interpreting the relative scale of DG deployment. The documented 60.01 MW in Honduras should be understood as the installed capacity associated with the projects for which capacity information was available, rather than as an estimate of the total DG capacity connected to Honduran distribution networks. Therefore, the lower documented capacity in Honduras, relative to the figures reported for Guatemala and Panama, should not be interpreted directly as evidence of lower actual DG deployment. Part of the observed difference may result from incomplete project identification, differences in national statistical classifications, different reference dates, and the absence of installed-capacity information for a substantial portion of the identified Honduran users.

Overall, the comparison indicates that distributed generation and self-consumption have reached a measurable scale in the Central American countries examined, while the availability and consistency of information used to characterize these resources differ substantially. Guatemala and Panama provide regional points of reference against which the Honduran case can be contextualized, particularly in terms of documented deployment and statistical visibility. However, their reported figures should not be treated as directly equivalent indicators of DG penetration. The Honduran case is characterized by a substantial number of identified generation users and approximately 60.01 MW of documented capacity, combined with a significant gap in the availability of technical information. Therefore, the principal value of the regional comparison is to contextualize the documented development of DG in Honduras relative to neighboring countries while recognizing the limitations associated with differences in classification, reporting practices, reference dates, and statistical coverage.

8.3. Structural Conditions of the Honduran Power System

The Honduran electricity system has a technical configuration characterized by structural limitations stemming from a historical lag in investment in transmission and distribution infrastructure. As indicated in the baseline analysis, the reforms implemented in the 1990s prioritized the development of electricity generation, neglecting the expansion and modernization of the power transmission networks. This situation has resulted in a system with limited operational capabilities, particularly in terms of monitoring, control, and flexibility.

In terms of infrastructure, the transmission grid consists of approximately 1328 km of 230 kV lines, 1050 km of 138 kV lines, and a complementary 69 kV network of around 694 km, indicating a substantial physical infrastructure that is, however, insufficiently modernized to meet current requirements for digitalization and advanced control [127]. Limited digitalization restricts operational visibility and real-time control capabilities, resulting in a predominantly reactive operation.

8.4. Main Barriers to Der Integration

These structural limitations are reflected in critical operational problems. Among these, energy losses stand out, reaching approximately 34.87% in 2024 as a result of insufficient infrastructure and network element saturation [128]. Furthermore, the lack of advanced monitoring limits the operator’s ability to detect and correct abnormal operating conditions before they affect system stability [9].

Voltage regulation poses another key challenge. The limited modernization and expansion of transmission infrastructure in power infrastructure have made it difficult to adequately control critical electrical variables, and imbalance events, such as line disconnections, have caused massive losses in photovoltaic generation, reaching up to 169 MW in a single event, thereby exacerbating frequency and voltage instability [9]. This behavior highlights the system’s vulnerability to disturbances and the need to incorporate more sophisticated control tools.

Added to this is the increase in distributed energy resources (DER), particularly solar and wind, which already account for nearly 20% of total generation. The integration of these intermittent sources introduces bidirectional power flows and greater operational variability that the current grid cannot adequately manage without a robust control infrastructure. In the absence of effective coordination, the growing penetration of DERs can exacerbate stability problems rather than contribute to system improvement [9].

In this context, international lessons from emerging economies are particularly relevant for Honduras. Countries such as China, India, and Brazil have led modernization efforts based on smart grids to address issues of grid overload, infrastructure obsolescence, and poor operational visibility [129]. In the case of Brazil, the use of roadmaps for the implementation of smart metering and demand response programs stands out, while India has made progress through pilot projects focused on monitoring and improving the performance of the energy sector [129]. Taken together, these cases show that the adoption of smart management methods is essential for operating electricity systems in transition efficiently and safely.

Based on the regulatory, tariff-related, and operational evidence discussed above, the Honduran case presents a set of interconnected gaps that go beyond individual interconnection requirements. These gaps involve regulatory design, tariff valuation, digital infrastructure, operational visibility, storage integration, and the absence of coordinated DER management mechanisms.

Table 5. Identified Regulatory and Operational GAPS for DER Integration in Honduras.

Dimension	Current Honduran Approach	Identified Gap	Recommended Modernization Action
Interconnection and capacity assessment	The NTUAP establishes deterministic criteria based on historical demand, circuit capacity, and short-circuit contribution limits [56].	Limited use of dynamic hosting capacity assessment and scenario-based evaluation under increasing DER penetration.	Introduce feeder-level hosting capacity studies considering voltage profiles, loading, losses, protection constraints, and time-varying DER output.
Grid-code functionality	The national framework incorporates technical requirements for self-producers but remains mainly oriented toward safe interconnection and protection [56,57].	Limited explicit requirements for interoperability, real-time communication, coordinated voltage support, and advanced inverter functions.	Gradually align national requirements with active grid-support functions, including reactive power control, voltage support, ride-through capability, and interoperability.
Tariff and compensation design	Surplus energy is compensated through a Net Billing mechanism based on avoided energy cost and differentiated injection and consumption tariffs [95,96,97].	The current tariff design focuses mainly on energy valuation and cost recovery, without explicitly remunerating flexibility, ancillary services, or local grid support.	Develop complementary mechanisms to value voltage support, congestion mitigation, storage operation, demand response, and local flexibility services.
Storage integration	Energy storage systems are allowed within the self-producer framework, with registration of power and energy capacity [56].	Storage is not yet clearly integrated as an operational flexibility resource for grid services or DER coordination.	Define regulatory and market roles for BESS, including peak reduction, voltage support, backup, flexibility provision, and participation in DERMS-based operation.
Observability and data infrastructure	The system still faces limited digitalization, restricted monitoring capability, and insufficient real-time visibility [9,127,128].	Lack of granular operational data limits active network management, hosting capacity assessment, and predictive control.	Prioritize smart metering, feeder sensors, data platforms, GIS/SCADA integration, and standardized data exchange protocols.
DER coordination and DERMS deployment	DERMS is not yet deployed as a coordinated operational platform for distributed resources in Honduras.	Absence of a centralized or hierarchical mechanism to coordinate DERs, storage, controllable loads, and distribution constraints in real time.	Implement DERMS through phased pilots, beginning with high-impact feeders, microgrid demonstrations, and local flexibility programs.
Institutional and market readiness	Regulatory progress exists, but operational, tariff, and digital modernization remain fragmented.	Limited coordination between regulation, distribution planning, tariff design, and operational modernization.	Establish an integrated DER roadmap linking CREE, ENEE, distribution operators, self-producers, storage providers, and future aggregators.

summarizes the main gaps identified for Honduras and links them to possible modernization actions.

The gaps summarized in Table 5 indicate that DER integration in Honduras should not be addressed only through additional interconnection rules. Instead, it requires a phased modernization pathway capable of combining regulatory refinement, tariff evolution, digital infrastructure, operational visibility, and DERMS-based coordination.

8.5. Phased DERMS-Based Modernization Pathway

Based on these experiences, the implementation of DERMS in Honduras can be approached through a phased strategy. In the first phase, Honduras should advance system digitalization through smart metering infrastructure and sensors capable of collecting and processing operational data, following data analytics-based solution architectures such as those observed in China [129]. This stage is essential for improving operational visibility and laying the groundwork for active grid management.

In a second phase, progress should be made toward local control of distributed resources through the integration of smart ancillary services and BESS, in order to mitigate the intermittency of solar and wind generation present in the Honduran system. Subsequently, the development of microgrid pilots and local energy management schemes would reduce dependence on congested transmission lines and validate decentralized operation strategies in real-world environments. Finally, a full-scale DERMS implementation phase would unify distributed resources under a management system capable of coordinating power flows, providing stability support, and incorporating advanced functions such as virtual inertia in response to disturbances.

8.6. Constraints and Expected Benefits

However, this process faces technical, economic, and regulatory barriers. From a technical and economic standpoint, a historical lack of investment has left the infrastructure vulnerable and with low transmission capacity, especially between the north and south of the country. On the regulatory front, it is necessary to develop policies that recognize and value ancillary services and storage within the electricity market, creating incentives for private participation. Likewise, coordination between local and regional planning, especially in relation to SIEPAC, along with the adoption of smart grid technologies, is a fundamental enabling condition for ensuring the future stability of the supply [129].

Regarding the expected benefits, the adoption of DERMS in Honduras could improve system stability through coordinated control strategies, virtual inertia support, and a better response to frequency disturbances. Additionally, it would promote the optimization of grid usage, reducing congestion on transmission lines by promoting a less centralized and more geographically distributed generation pattern. Finally, it would increase the system’s resilience and operational efficiency by improving visibility, potentially contributing to technical loss reduction, and strengthening the capacity to support system resilience and disturbance management through more sophisticated supplementary control schemes.

A quantitative cost–benefit assessment of DERMS deployment in Honduras cannot yet be established from the evidence reviewed because project-specific CAPEX, OPEX, communication costs, avoided reinforcement costs, monetized reliability benefits, loss reduction, curtailment reduction, and flexibility service values are not consistently available. Therefore, economic assessment should form part of future feeder-level pilots. Such evaluations should compare implementation and lifecycle costs with measurable benefits, including avoided network investments, loss reduction, reliability improvement, increased DER hosting capacity, and the economic value of local flexibility. This approach would allow future DERMS expansion to be based on demonstrated technical effectiveness and economic proportionality rather than on assumed system-wide benefits.

8.7. Implications for Hosting Capacity, Digitalization, and Cybersecurity in Honduras

For Honduras, these developments suggest that the transition toward active DER management should not begin exclusively with the acquisition of a centralized DERMS platform. A more sustainable approach would first establish the technical conditions required for reliable DER coordination: improved network models, feeder-level observability, standardized DER registries, time-series measurements, and progressively more detailed hosting capacity studies.

Dynamic hosting capacity assessment could be particularly valuable in circuits where photovoltaic self-generation is growing but the actual operational margin remains uncertain. Instead of applying only generalized connection thresholds, feeder-specific studies could identify when limitations are caused by voltage, transformer loading, reverse power flow, or protection constraints. This would allow reinforcement investments to be prioritized where physical upgrades are truly necessary, while other feeders could potentially accommodate additional DER through smart inverter functions, storage, or flexible operating limits [107,109].

Likewise, improving low-voltage observability would provide a foundation for future state estimation and predictive DERMS operation. Advanced metering infrastructure and strategically located feeder sensors could gradually provide the data needed to reconstruct distribution network conditions, identify reverse-flow events, and improve renewable generation forecasts [108,110]. This is particularly relevant considering the information and monitoring limitations already identified for the Honduran distribution system.

Finally, digitalization should be accompanied by cybersecurity requirements from the earliest pilot stages. Future DERMS, smart meters, aggregators, and remotely controllable inverters would create new communication paths into critical electricity infrastructure. Pilot projects in Honduras should therefore evaluate not only electrical performance but also communication reliability, authentication, access control, incident detection, and recovery procedures. Incorporating these requirements early would reduce the risk of creating a digitally more capable but simultaneously more vulnerable distribution network [115,116].

Taken together, these considerations suggest that DERMS implementation in Honduras should be understood as part of a broader digital and operational transformation of distribution networks. Hosting capacity analysis would define where and under what conditions additional DER can be connected; improved sensing and state estimation would establish operational visibility; forecasting would anticipate constraints; interoperable smart inverters and BESS would provide controllability; and cybersecurity would protect the information and control infrastructure linking these components.

9. Conclusions

This review shows that effective DER integration depends on the alignment of technical interconnection requirements, tariff design, grid performance monitoring, and operational coordination. International grid codes have evolved from passive disconnection requirements toward interoperability, voltage and frequency support, ride-through capability, and active participation by inverter-based resources. Tariff design has likewise progressed from undifferentiated volumetric compensation toward mechanisms that separate the value of exported energy, network use, capacity, and temporal or locational system conditions.

For Honduras, the available evidence indicates a transition toward greater regulatory recognition of DER, but not yet a statistically measurable national deployment trend. Official documents report 313 self-producers connected to the SIN by 2021 and approximately 70 generating plants connected to distribution networks in 2025. These figures describe different populations and cannot be combined. Furthermore, inconsistencies in self-producer registers and bidirectional-meter data prevent the construction of a reliable historical series of installed capacity and injected energy. The first recommendation is therefore to establish a validated DER registry and standardized reporting system before setting penetration targets or assessing tariff impacts.

Grid performance evidence also supports a monitoring-first approach. Honduras recorded 34.5% total technical and non-technical electricity losses in 2024, while feeder-level SAIDI, SAIFI, voltage, loading, reverse-flow, and DER-curtailment data remain insufficiently consolidated in the public evidence reviewed. These findings support prioritizing smart metering, feeder sensors, data validation, GIS/SCADA integration, and feeder-level hosting capacity studies. The purpose of these measures is not only to accommodate additional DER but also to establish a defensible baseline against which future interventions can be evaluated.

The 2026 transitional tariff represents an important step from unremunerated or administratively uncertain injections toward formal net billing. Nevertheless, the current mechanism primarily values exported energy and network cost recovery. International evidence supports evaluating time-of-use, two-part, multi-part, dynamic export, and local flexibility mechanisms, but their adoption in Honduras should be conditional on cost-of-service studies, distributional impact analysis, reliable interval metering, and settlement capability. The evidence does not support the immediate implementation of a complex tariff without these prerequisites.

DERMS may provide coordinated voltage control, congestion management, forecasting, and dispatch of storage or controllable resources. However, the review does not demonstrate that national DERMS deployment would automatically reduce losses or prevent blackouts in Honduras. A more defensible recommendation is a phased pilot on feeders selected according to measurable constraints and adequate telemetry. Pilot performance should be evaluated using voltage compliance, feeder loading, reverse-flow duration, curtailment, reliability, controlled DER capacity, and implementation cost.

Accordingly, the recommended sequence is: (i) validate DER and network data; (ii) establish feeder-level performance baselines; (iii) conduct hosting capacity and tariff impact studies; (iv) test local flexibility and DERMS functions through limited pilots; and (v) scale only those measures that demonstrate technical effectiveness, economic proportionality, and equitable user impacts. This sequence links each recommendation to a finding of the review and avoids assuming benefits that have not yet been empirically demonstrated in Honduras.