Electricity Price Optimization for Heating: What It Takes to Pay Off in Housing Portfolios

Electricity price optimization for heating means linking the operation of heat pumps, buffer storage and circulation pumps to the cheapest hours on the electricity market. For housing companies, this measurably lowers heating-related electricity costs, provided the system, the available data and constraints such as Legionella protection all line up. If even one of these conditions is missing, the effect stays marginal.

For individual single-family homes, this is by now well documented. For a portfolio of several multi-family buildings with central heat generation, shared hot water preparation and different types of systems, the calculation looks different.

In a portfolio, the economic benefit depends mainly on two things: how well the system can be controlled, and how much heat it can store temporarily. Add to that the comfort obligations you have to meet toward your tenants.

Three questions decide whether electricity price optimization is worthwhile for a housing portfolio at all, and at what scale:

What can electricity price optimization achieve in the heating operations of multi-family buildings?

Electricity price optimization shifts a heat pump's electricity use into the hours when the wholesale price is low, and throttles it when electricity is expensive. Current market prices already show why that matters: the average day-ahead wholesale price stood at €89.32/MWh in 2025, up 13.8 percent from 2024, according to the Bundesnetzagentur's 2025 electricity market data.

What matters here is less the average than the swing within a single day. The daily price spread, the gap between the day's highest and lowest price, ran at around €130/MWh in 2025. On top of that, the year brought 573 hours of negative prices, up from 457 hours the year before, while prices climbed above €300/MWh in 40 hours. That is exactly where the savings potential sits: a heat pump that runs deliberately during the two to three cheapest hours of the day ends up paying a very different electricity price than one that simply runs continuously.

Since January 1, 2025, all electricity suppliers have also been required to offer at least one dynamic tariff whose price tracks exchange prices, and since October 2025 even on a quarter-hourly basis. For housing companies, that means the tariff alone doesn't get you there, it only opens the door. Whether it actually translates into lower operating costs depends on whether the heating system can respond to these price signals in the first place.

For which heat pumps and operating situations does electricity price optimization pay off?

Electricity price optimization pays off above all where a heat pump runs with sufficient storage capacity and the operator has genuine influence over when consumption happens. Pure gas or district heating supply without electrical loads simply doesn't offer this lever, because there's no controllable electricity consumption left to shift.

In the existing building stock, that's still the exception: heat pumps account for only 4.2 percent of Germany's total housing stock, according to the 2022 census. In newly built multi-family buildings with at least three residential units, though, the heat pump became the most common heating technology for the first time in 2025, with a 52.7 percent share. For housing companies, that means electricity price optimization becomes relevant first in new-build and modernization projects, while in older stock the system technology usually needs upgrading before optimization can take hold at all.

Once a portfolio spans several buildings, or includes a central large-scale system with more than 30 kW of output and over 30,000 kWh of annual consumption, the regulatory environment shifts too.

Special-contract customer instead of standard module: systems above 30 kW of output and 30,000 kWh of annual consumption count, in energy-industry terms, as special-contract customers with registering capacity measurement (RLM, meaning quarter-hourly load profiles). That's a different regime from the standard modules under Section 14a of the German Energy Industry Act (EnWG) for individual consumption devices. Anyone scaling electricity price optimization across an entire portfolio needs to factor in this distinction from the start, as an analysis by Solarize on full balancing for commercial customers shows.

Even within suitable buildings, there are limits: with very small buffer tanks, sharply fluctuating occupancy, or systems with no remote access at all, operation can barely be shifted reliably without risking residents' comfort. If you already run your system operation on a predictable schedule today, you've already laid the groundwork for this.

How do dynamic electricity prices, buffer storage and load shifting interact in a heat pump?

The buffer tank is the link: it absorbs heat when electricity is cheap and releases it when the heat pump pauses because prices are high. A typical size is 30 to 50 liters of storage volume per kW of heating output, enough to bridge lockout periods or price peaks for around six hours without any noticeable loss of comfort.

Lawmakers have since made this flexibility a fixed part of the system: since January 1, 2024, Section 14a EnWG has required controllable consumption devices such as heat pumps with a connected load of 4.2 kW or more to be controllable by the grid operator. In return, operators receive reduced grid fees under Module 1 of around €110 to €200 a year, and since April 1, 2025, time-variable grid fees under Module 3 as well. For housing companies, this adds a layer of complexity: grid-serving control and market-driven load shifting run in parallel. Anyone who doesn't keep the two cleanly separated in operation risks having them cancel each other out.

With central hot water preparation, though, Legionella prevention sets a hard limit on how far load can shift.

Hygiene before price window: DVGW Code of Practice W551 requires central domestic hot water systems to maintain a storage outlet temperature of at least 60°C and a circulation return temperature of at least 55°C. This constraint applies regardless of the electricity price, and it limits how far hot water charging can be shifted into cheap but awkwardly timed price windows.

This is where KUGU EOS Strompreisdynamik comes in: the system links ongoing heating operation to dynamic electricity prices, so load shifting can actually be put to use for savings, without comfort or hygiene taking a hit.

What do housing companies need: data, controllability, responsiveness?

Without quarter-hourly consumption and generation data, no price signal can be meaningfully linked to system operation. And this is exactly where the biggest bottleneck sits today: by the end of 2025, only 5.5 percent of Germany's roughly 56.5 million metering points were fitted with a smart metering system, according to an analysis of the smart meter rollout. Among the legally mandated installation cases, the 20 percent target quota was slightly exceeded at 23.3 percent, but for the broader base of existing portfolios that still means data availability remains the exception rather than the rule.

Four conditions decide whether electricity price optimization actually works across a portfolio:

These four points are connected. If the data exists but no one can act on it, you're left with observation that changes nothing. If the system can act but reacts too slowly, the short price windows are already gone by the time it responds. And without clearly defined constraints, comfort risks appear that housing companies simply can't afford to take with their tenants. Following this connection through consistently is what data-based heating control is built on.

Why does manual electricity price optimization hit its limits in portfolio operations?

Manual electricity price optimization tends to fail in practice because of the sheer number of systems that need controlling at once, combined with incompatible system environments. Energy management systems and heat pumps from different manufacturers often don't communicate on a shared standard, and storage units or wallboxes rarely slot into a common control setup without extra effort. Industry experts point to exactly this as the central practical bottleneck for automated control. For a single building, this can still be balanced by hand. For a portfolio with dozens of systems, it no longer can, reliably.

Studies on the savings potential of dynamic tariffs for heat pumps show just how wide the gap is between simply picking a tariff and actively controlling the system around it: without intelligent load control, savings often sit at just 1 to 4 percent, while Fraunhofer IEG reports savings of up to around 30 percent for single-family homes running an energy management system with active load shifting, a figure that doesn't carry over directly to multi-family housing portfolios given their different building and usage patterns. The gap is still telling: a system that reliably turns price signals into system behavior saves noticeably more than simply choosing a dynamic tariff.

Economically, this usually comes down to an investment decision. Heat pump contracting for housing companies is calculated, according to a sample calculation by Ritterwald, at around €125,000 per central system, or €5,000 per residential unit for monovalent systems. Unlike private owners, housing companies can draw on funding rates of no more than 35 percent of investment costs, which makes the degree of automation in operation all the more important for amortizing the investment over its service life. There's regulatory movement to account for too: the Building Energy Act (GEG) will be replaced by the new Building Modernization Act (GModG) in 2026, and the current 65 percent renewable energy requirement gives way to a bio-quota that rises gradually starting in 2029. That adds short-term uncertainty to investment decisions. It changes little, though, about the economics of a heat pump that's already installed, as long as its electricity consumption is automatically linked to price signals. If you want to capture that fully, automated efficiency in operation is hard to do without.

Why the Tariff Alone Isn't Enough

Storage capacity, controllability and data availability together decide whether a cheap price window can actually be put to use. A dynamic tariff does little on its own as long as the system can't respond to it. That same heat pump, paired with a buffer tank and automated control, turns that very tariff into real savings.

For housing companies, that translates into a concrete first step: sort the portfolio by suitability first, in other words, where heat pumps and buffer tanks are already in place and where the metering infrastructure cooperates. Start automation where data availability and controllability already exist. Regulatory uncertainty around the upcoming Building Modernization Act is no reason to wait, because the economics of a heat pump that's already installed depend on how you run it, a factor no new piece of legislation is going to change.

Frequently Asked Questions About Electricity Price Optimization for Heating

At what connected load does the control obligation under Section 14a EnWG apply to heat pumps?

At 4.2 kW of connected load, the control obligation under Section 14a EnWG kicks in, and has done so since January 1, 2024. In return, operators receive reduced grid fees under Module 1 of around €110 to €200 a year, plus time-variable grid fees under Module 3 since April 2025.

How long can a buffer tank bridge heat supply during price peaks?

Around six hours is what a correctly sized buffer tank can bridge without residents noticing any difference. The rule of thumb is 30 to 50 liters of storage volume per kW of heating output.

What minimum temperature does Legionella prevention require for hot water circulation?

60°C is the minimum storage outlet temperature that DVGW Code of Practice W551 requires for central domestic hot water systems, alongside a circulation return temperature of at least 55°C. This threshold applies regardless of the electricity price and limits how far load shifting can go when charging hot water.

From what system size do housing companies count as special-contract customers with RLM?

From 30 kW of measured output and 30,000 kWh of annual consumption, you count, in energy-industry terms, as a special-contract customer with registering capacity measurement. A different regime then applies than the standard modules under Section 14a EnWG for individual consumption devices.

What funding rates can housing companies use for heat pump contracting?

35 percent of investment costs is the maximum funding rate housing companies can draw on for heat pump contracting, less than private owners get. With investment costs of around €125,000 per central system, that makes the system's operation all the more decisive for its economics.