Energy Market July 2026: Why Rising Power and Gas Prices Are Becoming a Portfolio Management Issue

July has changed the starting point for energy procurement

European energy markets moved sharply higher in July 2026. For the real estate industry, however, the key issue is not simply that electricity and gas became more expensive. What matters is where along the forward curve prices increased and which delivery periods are relevant for a specific property portfolio.

German Power Cal-27 rose by 12.1% within four weeks to €104.24/MWh. The increase was even stronger for the near-term winter period: Q4 2026 reached €139.46/MWh, up 22.0% over the same period.

Gas moved more aggressively still. THE Gas Cal-27 increased by 20.0% to €43.64/MWh, while Q4 2026 rose by 35.7% to €59.94/MWh.

For asset managers, property managers, residential portfolio owners and institutional investors, this changes the procurement discussion. The relevant question is no longer simply whether energy prices are “high” or “low”. Portfolio decisions need to take account of contract maturities, delivery years, open volumes, consumption profiles and the proportion of future demand that has already been hedged.

Small market movements can translate into material portfolio costs

A movement of a few euros per megawatt-hour may appear limited when viewed in isolation. At portfolio scale, however, the impact can quickly become material.

The four-week increase in German Power Cal-27 represented an additional wholesale cost of approximately €11,250 per GWh of annual consumption. Compared with the level twelve months earlier, the difference was approximately €21,840 per GWh.

For a real estate portfolio requiring 5 GWh of electricity for delivery in 2027, the July movement alone therefore represented a theoretical increase of around €56,000. Compared with twelve months earlier, the difference was approximately €109,000.

These calculations reflect wholesale price movements only. Grid charges, levies, taxes, balancing and supply costs, as well as supplier margins, are not included.

From a real estate economics perspective, that distinction is important.

Higher energy costs can increase service charge budgets and total occupancy costs for tenants. Where costs cannot be fully recovered, they may also affect property-level cash flow and NOI directly.

Energy procurement should therefore not be treated purely as an operational task within facility or property management. For larger portfolios, market movements can reach a scale that becomes relevant to asset management, budgeting and business planning.

Annual contracts do not show the full market picture

One of the most important features of the current market is the significant spread between different delivery periods.

German Power Q4 2026 was priced at €139.46/MWh at the end of July. Q2 2027, by comparison, stood at only €87.35/MWh. The winter quarter was therefore approximately 60% more expensive.

Gas showed a similar pattern. Q4 2026 traded at €59.94/MWh compared with €40.84/MWh for Q2 2027.

An annual baseload contract averages these different periods into a single figure. For portfolio management, however, this can hide economically relevant information.

Companies using tranche-based procurement strategies should therefore monitor quarterly products as well as annual contracts. The quarterly curve shows more clearly which delivery periods are carrying the greatest market risk.

This matters particularly for property portfolios with strong seasonal demand.

Residential portfolios, hotels, hospitals, care facilities and other heat-intensive assets can have a very different consumption profile from logistics, office or retail portfolios. Where demand is concentrated in the winter months, exposure to expensive winter quarters may be considerably greater than an annual average price suggests.

Near-term delivery periods are carrying the largest risk premium

The July increase was not evenly distributed across the forward curve.

German Power Cal-27 stood at €104.24/MWh at the end of July, compared with €86.82/MWh for Cal-28 and €77.87/MWh for Cal-29. Cal-29 was therefore around 25% below the front-year contract.

The gas market displayed an even more pronounced structure. THE Gas Cal-27 stood at €43.64/MWh, compared with €31.37/MWh for Cal-28 and €27.21/MWh for Cal-29.

The market is therefore assigning a significantly higher risk premium to near-term delivery periods than to later years.

Several factors contributed to this pattern in the power market: high temperatures and increased cooling demand, reduced availability of French nuclear generation, periods of weaker wind output and a gas market that increased even more sharply than electricity.

These factors primarily affected the front of the curve and the winter quarters. Later delivery years reacted much less strongly.

For real estate portfolios, this forward-curve structure is strategically relevant.

A portfolio that procures its full energy requirement shortly before delivery is structurally exposed to front-year market conditions. A multi-year procurement approach, by contrast, can spread decisions across different delivery years and market windows.

The objective is not necessarily to secure the lowest possible price. It is to avoid allowing a single market period to determine the energy budget for an entire portfolio.

Gas remains a particular risk factor for real estate

Gas prices have a direct connection to the heating costs of a large part of the existing European building stock.

At the end of July 2026, German gas storage facilities were 46.84% full. At the same point in 2025, the level was 60.79%; in 2024 it had been 89.19%.

The gap to the previous year was therefore approximately 14 percentage points.

This does not in itself indicate an immediate supply shortage. It does, however, increase the volume that needs to be injected before the heating season and therefore makes the market more sensitive to additional demand, cold weather or supply disruptions.

Global LNG availability also remains important. European gas pricing increasingly depends on competition for flexible LNG cargoes, meaning that geopolitical developments and Asian demand can influence European forward prices even when physical supply within Europe remains stable.

For property portfolios, the relevant question is therefore not simply where spot gas trades today.

More important is the price of the delivery period that corresponds to the portfolio's actual procurement need and how much of that demand remains unhedged.

Energy costs are increasingly becoming an ownership issue

At the same time as wholesale markets are changing, the allocation of energy-related costs between occupiers and owners is evolving.

This is particularly important for residential real estate.

Germany's CO₂ Cost Allocation Act already means that carbon costs are not automatically passed through to tenants in full. In residential buildings, costs are divided between landlords and tenants according to a stepped model based on the building's specific carbon emissions. For non-residential properties, carbon costs are generally shared equally.

The 2026 changes to German heating legislation add another dimension. For certain newly installed fossil-fuel heating systems in rented existing residential buildings, future cost-sharing provisions will extend beyond carbon costs.

This changes the economics of heating-system decisions.

A fossil heating system is no longer simply a CapEx decision. Asset managers also need to consider how operating costs, carbon exposure and other energy-related charges may be distributed during the asset's remaining holding period.

Energy procurement, technical decarbonisation and long-term cash-flow planning are therefore becoming increasingly interconnected.

What higher energy prices mean for NOI

Not every increase in energy prices translates directly into lower NOI.

Depending on lease structures, property type and local regulation, a significant proportion of energy and heating costs may be recoverable through service charges.

The analysis should therefore go beyond the utility invoice.

Higher energy costs can increase tenants' total occupancy costs. This may affect the competitive position of a property, particularly where service charges are already high or the building has poor energy performance.

At the same time, some cost components remain with the owner or are increasingly shared between landlord and occupier.

This creates several layers of financial impact.

Higher energy prices can increase operating expense budgets. Non-recoverable components can reduce cash flow directly. Rising occupancy costs may affect tenant demand and retention. Over the longer term, inefficient buildings may also face additional CapEx requirements and greater transition risk.

For asset managers and institutional investors, energy procurement and decarbonisation should therefore be assessed together rather than as separate workstreams.

What asset managers and property managers should review now

The current market does not automatically mean that all open volumes should be fixed immediately.

Equally, simply waiting for prices to decline is not a procurement strategy.

The starting point should be a clear picture of the portfolio's remaining exposure.

Real estate companies should consolidate all energy contracts across the portfolio, including supply points, contract maturities, termination dates, delivery periods, annual consumption volumes, load profiles and already secured volumes.

The next step is to build a delivery-year matrix.

This should show, for example, what percentage of expected electricity and gas consumption for 2027, 2028 and 2029 has already been contracted and what volume remains open.

That exposure can then be compared with budget assumptions and defined risk tolerances.

For asset management, the key question is which cost range remains acceptable within the business plan.

For property management, the operational priority is different: which contracts need to be tendered or renewed, by when, and with which data quality?

For larger portfolios, concentrating all properties and all volumes into a single procurement date can create unnecessary timing risk. Staggering procurement decisions can reduce the probability that an entire portfolio is contracted during one temporary market peak.

Procurement strategy matters more than price forecasting

The July market move is another reminder that professional energy procurement should not be built around short-term price predictions.

It is not possible to forecast reliably whether Power Cal-27 or Gas Q4 2026 will be higher or lower several weeks from now. Weather, gas storage, power plant availability and geopolitical events can all move the market quickly.

Other factors are controllable.

These include the procurement horizon, the number of purchasing windows, the proportion of volume fixed at each stage, contract structures, tender design and the rules governing procurement decisions.

This is the distinction between market monitoring and procurement management.

A professional strategy does not attempt to answer: “When will the market reach its lowest price?” It answers a different question: “How do we prevent one market date from determining the energy budget of an entire real estate portfolio?”

That distinction becomes more important as portfolio sizes increase.

Energy procurement is becoming part of portfolio management

July 2026 demonstrated how quickly market conditions can change.

The structure of the increase is particularly relevant. Near-term electricity and gas contracts, especially the winter quarters, rose considerably more than later delivery years. At the same time, regulatory developments are increasing the importance of understanding which energy-related costs ultimately remain with the property owner.

For professional real estate organisations, it is therefore no longer sufficient to tender an energy contract shortly before expiry.

Energy exposure should be managed at portfolio level.

That requires transparency over consumption, contract maturities, open volumes, delivery years, budget assumptions and procurement decisions.

The strategic task is not to predict the energy market.

It is to structure energy price risk so that it remains compatible with the portfolio's NOI, cash flow, operating cost budget, asset strategy and decarbonisation pathway.

Data basis

Market data and calculations in this article are based on the NeoBid Energy Market Report 07/2026, using wholesale market data as of 31 July 2026 and regulatory information available as of 20 August 2026. The report draws on sources including EEX, EPEX, SMARD/Bundesnetzagentur, AGSI/Trading Hub Europe, the German Federal Government and EU institutions.