A federal study has, for the first time, quantified the actual cost of digitizing remote meter reading. By extension, its findings point to a pivotal decision for district heating operators.
In May 2025, the Swiss Federal Office of Energy (SFOE) published a study commissioned from E-CUBE Strategy Consultants on smart metering options in the context of the opening of the gas market. We recommend reading it, even if your network does not transport a single cubic meter of gas. Behind the technical question of choosing between remote meter reading and smart meters lies a much broader and more urgent lesson for all energy infrastructure operators in Switzerland.
The study’s key finding is stark in its clarity: in a fragmented market, the annual cost of smart metering ranges from 200 to 760 CHF per meter. The authors’ conclusion leaves no room for doubt: the main economic challenge lies not in the choice of technology, but rather in the ability to plan effectively in order to benefit from economies of scale.
Let us ask a question that may seem out of place: Which telecom provider do you use for your corporate network? We assume that you have a framework agreement, that your provider is based in Switzerland or at least within the European Union, that you have reviewed the data processing terms, and that you have obtained a service continuity guarantee. You haven’t overlooked anything because your company’s connectivity is a critical infrastructure.
Yet when it comes time to equip the substations in their heating networks, these same operators sometimes choose their IoT infrastructure the same way one might choose a mobile app—quickly, based on a quote, without asking the questions that really matter: Who hosts the data? Where is it located? What guarantees of reversibility are in place?
A connected infrastructure isn't just a tool. It's a strategic decision made once that shapes the next ten years.
The SFOE study confirms this in its own way: the current high costs in Switzerland are the result of a fragmented market in which each player has made its own decisions, without coordination, without economies of scale, and often without a long-term vision.
The study contains a sentence that warrants a second reading. The authors note that the challenges posed by smart metering are “all the more significant given that the number of heating customers (heat pump transition, district heating) could decline.” This serves as a warning for the gas market, but it explicitly identifies an opportunity for the district heating market.
Switzerland’s energy transition is leading to a clear trend: shrinking gas networks, expanding heating networks, and smart metering infrastructure that is becoming the nervous system of these networks’ management. CAD operators who build this infrastructure today—using reliable, interoperable solutions where data remains under their control—will be in a radically different position than those who improvise it in five years under regulatory pressure.
When a district heating network operator seeks to digitize its substations, the evaluation criteria typically focus on price, functionality, and sometimes ease of integration. Rarely, however, do they address two critical factors: long-term operational reliability and control over the data generated.
Reliability first. The OFEN study documents operating costs of up to CHF 600 per node per year in fragmented configurations. These costs reflect the reality of undersized equipment, unstable connectivity, systems lacking fleet monitoring, and repeated corrective maintenance. A reliable IoT infrastructure must ensure data upload rates, detect anomalies before they become incidents, and maintain fleet consistency over a decade.
Next, sovereignty. The data generated by a district heating network—load curves, supply and return temperatures, valve statuses, consumption figures—are strategic assets. They enable the optimization of supply, the establishment of different contractual arrangements with heat producers, compliance with regulatory reporting requirements, and, in the future, the monetization of flexibility on energy markets. This data must remain under the operator’s control, be hosted in Switzerland or the EU, and be exportable and reversible.
Control over a network's data is not a luxury reserved for large operators. On the contrary, it is essential for operational resilience for every operator.
Operators who choose to digitize their networks today using solutions built to last—based on a proven communications infrastructure and featuring software designed to leverage data—are establishing a lead that will be difficult to catch up to.
Those who wait will find themselves in a situation where their choices are constrained by regulations, delayed deployment costs, and the need to make up for lost time. The six-fold cost reduction highlighted by the study is not an abstract promise; it is the result of an early decision made with the right architecture and the right partners.
The gas sector offers us one final lesson, which may be the most valuable of all: markets that fragment into local solutions, lacking coordination or a shared vision, always end up paying a higher price. The district heating ecosystem has a window of opportunity to avoid repeating this mistake. That window will not remain open indefinitely.
We were surprised when we read this report. Thirty-two pages of rigorous analysis on the costs of smart metering, yet the authors do not devote a single line to these two fundamental questions: How often is the data transmitted? In what condition does it arrive?
This silence highlights a persistent blind spot in the public debate on the digitization of energy networks. Reading a meter once a day technically constitutes “smart metering.” However, a daily load curve that lacks quality control, outlier detection, or handling of communication gaps is raw data that no one can use with confidence.
For a district heating network, temporal granularity is not just a technical detail: it determines the ability to detect a temperature deviation in time to prevent overheating, to identify a customer whose usage patterns indicate a leak, or to produce a reliable monthly energy report that can be presented to various stakeholders. Let’s be clear: data collected every 24 hours without processing does not allow for any of this.
The real question isn't "How much does data collection cost?", but rather "How much is actionable data worth?". And those are not the same thing.
The energy data value chain consists of three stages, which the SFOE study condenses into a single process: collection, processing, and utilization. Processing, validation, cleaning, anomaly detection, and contextual enrichment are precisely what transform a stream of measurements into actionable insights. This is also what should justify the decision to invest in a software platform beyond a simple remote meter reading module.
Operators who choose their infrastructure solely based on collection costs overlook the layer that gives value to everything else. It’s a bit like evaluating a surveillance system based solely on the price of the sensor, without considering the ability to interpret the signals.
Link to the full study:https://www.bfe.admin.ch/bfe/fr/home/approvisionnement/approvisionnement-en-gaz/loi-sur-approvisionnement-en-gaz.html
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