Changes to Europe’s electricity-network rules are creating a potential new revenue market for equipment that can support grid stability. The opportunity comes as developers and system operators address the technical limits of power systems increasingly reliant on inverter-connected resources. At an energy conference in Athens on October 22, Miguel Ochoa, Europe Grid Director at SIGENERGY, said regulatory uncertainty was slowing the deployment of technologies designed to stabilise electricity systems.
Ochoa identified voltage regulation as a major challenge and pointed to grid-forming technology as a possible solution. The commercial opportunity extends beyond electricity sales and conventional balancing energy: equipment that provides voltage support, synthetic inertia, reactive power and other stability services may gain additional value as technical requirements become more detailed and system operators develop procurement mechanisms.
The issue is relevant to developers, engineering contractors and infrastructure investors in Southeast Europe, with potential implications for equipment procurement, grid-connection compliance and new contractual revenue streams. It also comes as the European Union prepares revisions to its Requirements for Generators network code, known as RfG 2.0, to update technical standards for modern generation and storage systems.
Grid stability requires technical services beyond electricity supply
Conventional electricity-market revenue is largely linked to energy delivered, available capacity and frequency-balancing services. Power networks also need technical characteristics that cannot be measured simply by the volume of electricity sold. Voltage stability depends partly on connected equipment’s ability to absorb or inject reactive power, while frequency stability requires a rapid response when generation and consumption become unbalanced.
Inertia and other fast-response characteristics help limit the speed of frequency changes after a disturbance. Historically, large synchronous power plants provided many of these functions naturally or through established controls. As systems rely more on inverter-connected technologies, engineered control systems and appropriately designed equipment must increasingly supply those services.
Grid-forming inverters can contribute to this transition. Conventional grid-following inverters typically synchronise with an existing grid-voltage waveform; grid-forming equipment can control its own voltage waveform and respond rapidly to changing electrical conditions. Depending on its design and available energy resources, it may support system strength, fast active-power response and local voltage stability.
Not every grid-forming device can provide every stability service, and products with different technical capabilities should not be treated as interchangeable. Even so, the technology creates opportunities for equipment manufacturers, engineering companies and electricity-asset owners.
Revised European generator requirements remain under development
The European Commission published a draft revision of the Requirements for Generators code on July 8, 2026, opening a consultation that closed on August 25. The proposed framework addresses the growing role of converter-connected generation, electricity storage and emerging technologies, including grid-forming capability. The European Network of Transmission System Operators for Electricity (ENTSO-E) had published detailed technical guidance on grid-forming requirements in November 2025.
The proposed code would strengthen the framework for defining how eligible installations must perform during disturbances and interact with electricity networks. The revised requirements have not yet entered into force. At the Athens conference, Ochoa said the revised European regulation could be issued in English in February 2027, with other language versions following by May; this is a reported expectation, not a confirmed implementation date.
The timetable matters because developers are choosing equipment today for projects expected to operate for decades. If future technical requirements differ from capabilities set out in current procurement contracts, developers could face additional engineering costs or equipment modifications. Installations designed with sufficiently advanced capabilities could, conversely, be better placed to meet future grid requirements.
The financial effects will depend on national implementation, the treatment of existing installations and whether additional technical capabilities qualify for remuneration. For investors, developers and equipment suppliers, regulatory requirements and commercial eligibility are therefore separate considerations.
Germany has begun paying for inertia-related services
The commercial potential is not entirely theoretical. On January 22, 2026, Germany’s transmission-system operators began market-based procurement of instantaneous reserve, a service intended to support local grid stability by responding rapidly to active-power imbalances. Qualified resources, including suitable synchronous equipment and grid-forming converters, can provide defined inertia-related services under the framework.
Remuneration uses a fixed-price mechanism that takes account of product type, location and service availability. The procurement framework distinguishes between positive and negative response products, as well as different availability requirements. Germany’s model shows that technical stability functions can be organised as standardised commercial services.
The location and technical performance of an installation affect its value: an asset that supports stability locally cannot necessarily provide equal value at every point on the transmission network. Revenue depends on where the service is required, which technical standards apply and how the system operator procures it. Comparable markets are not already in place throughout Southeast Europe, but Germany’s arrangements offer regulators and transmission operators a practical example to consider when developing procurement structures.
Southeast European operators face evolving technical requirements
The issue is particularly relevant to Greece, Romania, Bulgaria, Croatia and Slovenia, where transmission and distribution operators must accommodate changing generation and consumption technologies. Technical standards and service procurement also matter in Serbia and Montenegro, where transmission requirements and regulatory alignment will affect the bankability of future investments.
In Greece, IPTO will need to assess how the growing share of inverter-based resources affects system stability and grid operation. Transelectrica faces similar questions in Romania about the technical characteristics and control capabilities of connected installations. In Croatia, HOPS and distribution-system operators will need to consider how advanced grid-support functions can be incorporated into operational and connection requirements.
Serbia’s legal framework already recognises non-frequency ancillary services and provides for their procurement through transparent, non-discriminatory and market-based procedures, subject to regulatory conditions and possible exceptions. This offers a potential regulatory basis for more clearly defined technical services. However, legal recognition is not the same as an established procurement market that provides predictable revenue.
Developing a commercial market requires system operators to identify specific needs, define technical products, and establish qualification and payment arrangements. The eventual pace of development will differ among countries, depending on how quickly operators identify system needs and create procurement mechanisms.
Verification and contracts will determine the commercial value
The transition changes the work required of equipment suppliers, independent engineers and project supervisors. A manufacturer’s marketing specifications alone cannot establish grid-forming performance; investors and system operators need evidence of how an installation operates under defined electrical conditions. This may require power-system studies, dynamic simulation models, protection coordination, inverter control settings, site acceptance tests and commissioning measurements.
For existing installations, determining whether advanced functions can be enabled may require detailed review of hardware capability, software, contractual warranties and grid-code obligations. It is also important to distinguish mandatory technical compliance from optional commercial services. A system operator may require specified reactive-power capability as a condition of connection, but that requirement does not automatically entitle the installation to additional revenue.
Commercial value arises when a qualifying service receives separate remuneration under applicable rules or contracts. For lenders and investors, this distinction helps prevent uncontracted stability-service revenues from being included prematurely in financial models. Independent technical assessment can also have a role when new services are introduced.
As grid-forming requirements develop, investors may need to distinguish equipment that meets minimum connection obligations from installations able to provide additional contracted stability services. That distinction could affect procurement strategies, acquisition due diligence and long-term operational planning. A project with documented grid-forming capability, validated dynamic models and suitable controls may be easier to adapt to evolving technical standards.
Any valuation premium would depend on demonstrable avoided costs, greater operational certainty or additional contracted revenue. Developers must also account for the possibility that providing a stability service imposes operating restrictions or reduces the ability to earn revenue elsewhere. Contracts will need to address availability, technical performance, service priority, liability and interactions between different operational obligations.
Introducing advanced services could increase demand for specialist engineering, testing, independent certification and long-term technical supervision. These activities are commercially distinct from building conventional generation capacity. The decisive investment distinction is whether capabilities can be converted into enforceable contracts and predictable cash flows.
System-stability capability is becoming an investment consideration
Electricity assets are increasingly assessed not only by installed megawatts and expected generation, but also by their technical contribution to stable network operation. For Southeast European developers, an immediate priority is to understand future technical obligations before entering long-term equipment commitments. Regulators and system operators must distinguish services required for network security from additional services that merit competitive remuneration.
Germany’s paid inertia procurement shows that such markets can operate, while discussions in Greece on October 22 highlighted that the required technical and regulatory arrangements remain unresolved in parts of Southeast Europe. The commercial opportunity depends on demonstrating that an asset can provide a specific stability service at a location where it is needed, under a contract that gives the capability financial value.
The developments also reflect a broader shift in potential sources of value for the electricity industry: securing infrastructure for digital customers, monetising controllable consumption and delivering measurable technical services to system operators, alongside producing, storing and trading electricity.