Introduction

Commercial Buildings account for a large portion of global energy consumption and greenhouse gas emissions, but commercial building owners are also sustainability leaders, embracing energy efficiency and energy management, and adopting ambitious net-zero and renewable energy targets. 

Traditionally the commercial building sector has adopted targets and reported emissions on the basis of average annual emissions factors. That is, a building's reported emissions are based on the average annual emissions factors for the power grid in which they operate net of any renewable energy certificates purchased and surrendered in the year.

However, as the proportion of intermittent renewables increase in the power system, the emissions intensity of the power grid can change dramatically through the course of the day and seasonally over the course of the year. 

While the NSW Australia power grid, for example, still has significant proportions of power coming from fossil fuels (black in Figure below), the share of power coming from renewables (teal in Figure below), is increasing quickly, and there is an emerging contribution for battery storage (blue in Figure below). 

Even with today’s heavy reliance on fossil fuel generation in NSW, we can see solar generation reducing emissions in the middle of the day, based on the current policy settings (see Grid Decarbonisation below) this will increase dramatically by the end of the decade. 

Traditional renewable energy procurement does not require certificates to match the actual load of buildings and the actual associated grid emissions (and doesn’t even require certificates to be sourced from the same power grid, or the same calendar year as the corresponding building load). 

This creates the potential for an increasing mismatch between the building's reported emissions, which may notionally be zero, and actual energy emissions, which will show that the building is still dependent on fossil-fuel based energy sources for significant periods of time. 

In contrast to this traditional approach, the United Nations' 24/7 Carbon-free Energy Compact, envisions a future where "every kilowatt-hour of electricity consumption is met with carbon-free electricity sources, every hour of every day, everywhere”. 

That is, energy users should report on emissions based on actual grid emissions intensity in each interval, and should purchase certificates in such a way that carbon-free energy generation can be demonstrated to match load on an hourly basis. 

This ensures that ambitious targets and claims are accurate, and encourages the build out of energy storage and new sources of carbon-free generation that can produce power when renewables aren’t available (whereas traditional arrangements only encourage the build out of renewable energy generation).

This mismatch between traditionally reported building energy emissions and actual energy emissions are also significant in relation to other important trends in building energy decarbonisation. 

These trends are:

1. Electrification of space and water heating in buildings,
2. Provision of electric vehicle charging services,
3. Roof-top solar generation
4. Battery energy storage systems
5. Automated load management (demand flexibility) 

These trends change the volume and shape of power demand from the grid, amplifying the mismatch between reported and actual energy emissions. Without an accurate view of a building’s actual energy emissions, buildings following these trends may make very sub-optimal implementation decisions.

While the concept of 24/7 Carbon Free Energy is very much over the horizon for the commercial building sector, the energy transition represents a seismic shift in the global energy system and is only accelerating, so this concept is worth studying.

The 24/7 Carbon Free Buildings Project has been a collaborative project led by Gridcog, a specialist energy project modelling software business, with the close support of DeltaQ Consulting Services, a specialist building energy efficiency and services consultancy, with the support of the NSW Government.

This article will share more background on the project, the insights and findings that have been developed and will conclude with some recommendations and next steps.

Project background and methodology

The 24/7 Carbon Free Project was focused on three challenges:

1. The limits of net-zero. Meeting net-zero targets through green energy procurement and offsets is one pathway. Can ‘locational time matched emissions’ better enable building and grid decarbonization?
2. The imperative to electrify. Many buildings depend on gas for heating; what happens as and when we electrify buildings? What happens when we add EV charging to building? What will be the impact on future cost and emissions ?  
3. The waste of curtailment. Australia is rolling out new renewables at scale, AEMO is forecasting Australia will waste 80TWh of renewable energy a year by 2050. High renewable supply needs flexible demand-side participation. 

The objective was to consider these challenges by doing detailed modelling of five commercial buildings in NSW using real energy and commercial building data provided by three project partners: Charter Hall, Brookfield Properties, and Walker Corporation. 

These models would consider six project opportunities for each building:

1. Provision of Electric Vehicle charging services
2. Electrification of Domestic Hot Water (DHW)
3. Electrification of Heating Hot Water (HHW)
4. Addition of Thermal Storage (Chilled Water / Heated Water tanks)
5. Addition of distributed Solar PV Generation
6. Addition of distributed Battery Energy Storage Systems

For each project option, the model would provide a detailed discounted cashflow model, assuming the buildings were all meeting 100% net-zero emissions targets through certificate purchasing, and provide three perspectives on building energy emissions:

1. Market-based emissions (incorporating impact of certificate purchases)
2. Local emissions (based on annual average emissions factors)
3. Local interval-level emissions (24/7 CFE perspective)

The project proceeded over four phases over a period of approximately 12-months:

1. Engage: Recruit project participants, collect data, and run  industry forum
2. Develop: Develop, refine and validate modelling and optimisation methodology
3. Demonstrate: Develop and validate demonstration models with project stakeholders and industry experts
4. Share: Share insights and learnings back with the industry through report and  forums. 

Building electrification and load flexibility

A key focus of the project was examining the realistic options and costs for building electrification and load flexibility. This aspect of the project was delivered by DeltaQ Consulting Services.

Electric vehicle charging

We have used the National Construction Code (NCC) to inform our EV charging modelling approach. This includes using the minimum NCC requirements to reflect the initial EV charging capacity, scheduling some expansion of EV charging in 2030 (both number of bays and utilisation of bays) and then considering the load and power management guidance under the code.

Managing demand load is crucial to avoid excessive strain on the power supply system, and was something we incorporated into the emodelling. While the impact of maximum demand may result in additional costs the majority of electric vehicle (EV) charging infrastructure options can integrate Load Management Systems (LMS) to distribute power evenly. LMS can maintain consistent power output comparable to standard EV chargers and evenly distribute power among chargers during periods of lower power availability (or for other demand limiting requirements). According to Section J9D4(2) of the NCC2022, specific power requirements for electric vehicle chargers must be met in different classes of buildings to ensure readiness.

We consulted with a number of recent projects to determine indicative capex and opex costs for modelling purposes.

For each charge point, based on AC fast charging (Level 2) with a power capacity of 7-22 kW, the indicative CAPEX for supply and installation is $4,700 excluding GST per single charge station. This estimate excludes any major electrical reconfiguration works, load management systems, metering, shutdowns (such as after-hours installation and generators), controllers, and integration with site BMS systems. The CAPEX price covers simply the supply of the units plus standard installation.

For typical commercial buildings, the CAPEX for supply, installation, electrical reticulation, and shutdown costs for the first charge station is $24,200 excluding GST. This includes an estimate for electrical reconfiguration works and shutdowns. Additional units would be added at $4,700 per station thereafter.

The OPEX is $400 per installation per annum, irrespective of the number of stations. It is expected that EV maintenance would fall under the existing electrical site maintenance, with potential adjustments such as additional thermoscans and RCD testing of the EV boards.

Electrifying heating

To electrify our building stock, we need to understand the use of natural gas in buildings and then assess how we can provide the same heating outcomes but by deploying one or more of the various electric systems available.

Heated water is predominant across the built environment for both heating hot water (HVAC) and domestic hot water use. According to available literature, approximately 80% of commercial building gas usage is for providing heating hot water, while about 20% is for domestic hot water.

Electrifying buildings involves transitioning to an electric alternative (such as a heat pump); the transition requires careful planning and assessments; key electrification project considerations include physical space constraints, electrical capacity, infrastructure changes as well as the buildability impacts such as disruption (installation in occupied space).

Sizing for all electric buildings requires an assessment of the gas heating demand, then applying the suitably sized all-electric option. This can be done via an assessment of the metered gas demand and reverse engineering the required electricity to deliver the heating using the coefficient of performance (COP), taking into account the ambient temperature, which changes COP. 

Simply put, we know the heating requirement, the efficiency coefficient, and ambient temperature, we can calculate the electricity required to power the heat pumps. This is illustrated in the two Figures below showing example summer and winter load profiles for a Commercial Office building.

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Air-Source Heat Pumps

Load flexibility

A building's grid demand has the flexibility to ‘shift’ to time of low grid intensity. If the HVAC services are intelligently operated, electricity demand from the grid can be temporarily reduced or time shifted. Alternatively, if the building has space and infrastructure, then storage can be used for shifting load.

Load flexibility can generally be achieved by allowing thermal conditions within the building to drift within tolerance levels. Buildings typically operate to the edges of their agreed lease conditions and do present the opportunity for flexible demand during certain seasons. For example, in warmer months (when a building will typically operate to achieve internal temperatures at the upper limit), there is the option to “pre-charge” the building with cooler internal conditions. In practice, this looks like reducing the internal temperatures, then allowing temperatures to drift back to the upper limit.

The above scenarios demonstrate the extent of load flexibility that exists for a building with no additional infrastructure or capital outlay other than adjusting HVAC control.  Alternatively using on site storage (battery or thermal chilled water storage).  Addition of thermal energy storage infrastructure via water (chilled and/or heating) tanks provide highly effective methods to enable further shifting of energy for the largest contributors to building peak demand (chillers and heat pumps). The disadvantages to deploying this technology is due to both cost and spatial impacts (large volumes of space are typically required for meaningful energy shift).

Furthermore, storing energy, either thermal (cooling or heating) or electrical and the releasing the stored energy will have associated losses, termed ‘round-trip-losses’.  Round trip losses refer to the energy lost during the process of storing and then retrieving thermal energy. These losses occur due to inefficiencies in the storage and retrieval process and can affect the overall efficiency of the system.

Australia’s energy transition

Planning the transition

Since 2018 AEMO’s Integrated System Plan (ISP) is a bi-annual report setting out pathways for the long term design of the electricity transmission system that underpins Australia’s National Electricity Market (NEM).

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The goal of the ISP is to find an optimal transmission system development plan that is aligned with Federal and State Government policies, including policies related to emissions reduction and renewable energy deployment. As show in the Figure below, this policy environment is complex and fragmented. NSW has been the focus of this project and has one of the more ambitious goals.

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In relation to the focus of the 24/7 Carbon Free Buildings project, the recently released 2024 ISP said that Demand-side participation is crucial in Australia's transition to a net zero economy. 

Demand side participation refers to the actions taken by electricity users to adjust their usage patterns in response to market or network price signals, or other forms of incentives or drivers (potentially including targets related to reducing interval-level grid emissions). This can involve reducing, shifting, or increasing electricity consumption to help balance supply and demand on the grid.

The 2024 ISP highlighted the significant role of Distributed Energy Resources (DER), such as solar systems, batteries, and electric vehicles, and the importance of electrification of buildings and load flexibility to manage the increased demand for electricity. The plan noted that effective coordination of DER and electrical loads can offset the need for additional grid-scale investment, reducing costs for consumers and reducing emissions. 

However, as shown in the Figure below, the expected contribution of capacity from flexible ‘Demand-side participation’ is currently assessed to be very small, with no material increase on historical trends, and is, for example, much lower than the expected contribution from flexible gas generation. This points to one of the key challenges the project is trying to address, which is enabling more contribution of system capacity from commercial buildings.

If we are looking for a preview of how the NSW system will look in 2030, we can look TBC.

Adding an interval-level emissions perspective to economic modelling

While the ISP provides a development plan for the transition system, many academic and industry economic modellers develop complementary and alternative plans. 

For example, energy project developers and investors will engage economic consultants to model energy markets under different scenarios, often informed by the ISP, to predict future energy market prices to support project investment decisions.

These models will take into account the current transmission network, and planned changes or expansion of the transmission network, the current electricity generation portfolio including planned retirements of power stations and planned investment in new power stations and then simulate the energy market down to 30-minute intervals over multi-decade time-scales. 

This simulation will include each power station bidding to supply energy to meet load based on short-run marginal costs (mostly expected fuel costs for gas and coal fired power stations), and will take into account congestion and losses associated with the transmission network. By simulating the energy market operations, these models will predict a wholesale energy price in each half-hour interval. We can see a summarised view of these prices forecasts in the Figure below. The chart shows the ‘underlying’ wholesale price (prices below $300/MWh), and the additional ‘volatility’ associated with high prices in each year (prices can be as high as $16,000/MWh, but this only occurs in a relatively small number of periods each year).

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One of the key activities of this project was to take the output from one of these models and derive future interval-level emissions intensities. Gridcog worked with Endgame Economics and used the raw output from their ‘2024 Q2 Orderly Transition Model’. 

This raw data includes the ‘bid stack’ for each individual power station in the NEM and the expected electricity output from each power station dispatched to serve load in each state of the NEM, including NSW. Gridcog then derived the emissions intensity of each power station, and developed a methodology to take into account the ‘interconnectors’ between each state. Based on this detailed analysis, we derived the expected emissions intensity of the grid in each half-hour interval.

This analysis is summarised for NSW in the Figure below. This Figure shows the average daily ‘shape’ of grid emissions intensities for each year from 2024 to 2050. This shows, for example, that in the early years emissions intensity peaks in the early morning with a smaller evening peak, but as the energy transition continues into the future, the daily emissions intensity profile ‘flattens out’.

It is very important to note that it is based on an ‘orderly transition’, including an expectation that coal-fired power plants all retire in line with current plans, and it assumes that all policy goals are met. So it shouldn’t be used to rationalise that no action is required to achieve 2050 net-zero goals. It is also important to note that the ‘shapes’ shown below are average daily profiles for each year, and there is significant day-to-day and month-to-month variation within these years.

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We can see the relationship between wholesale energy prices and emissions intensities in the Figure below. This shows an expectation that emissions will rapidly decline in the period to 2035 (in line with NSW policy goals).

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24/7 Building energy Models and Results

Gridcog provides advanced software for energy project modelling. After a period of research and investigation, a number of changes to the software’s energy and emissions modelling and optimisation algorithms were made to accommodate the requirements of the 24/7 Carbon Free Buildings project. 

Then, following the process of collecting base gas and electricity meter data from project partners, analysing market price and emissions data (see Section above), and undertaking the modelling of building electrification options (see Section above), detailed models were created in Gridcog for each building and project option.

Modelling Overview

The Gridcog models incorporate six main sets of input data and integrate those across six scenarios for each of the five buildings, as illustrated in the Figure below.

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For each building we created a model covering the period 2025 to 2040. All modelling was in 2024 dollars (real) and, in general, based on 2024 electrical and gas half-hour loads, cast forward flat into the future.

For each building we modelled Electric Vehicle charging services reflecting the National Construction Code requirement for new builds starting in 2025, with an increase in the number of EV bays scheduled in 2030. 

In the Baseline scenario for each building we represented the following loads:

• EV Charging Sessions
• Chilled Cooling Water
• Domestic Hot Water (Gas)
• Heating Hot Water (Gas)
• Remaining Building Load

For Domestic Hot Water and Heating Hot Water we model fuel combustion, cost and emissions associated with this energy use. 

This is illustrated in the screenshot below for one of the buildings.

The monthly site energy profile for the baseline scenario for one of the buildings is shown below, with electricity (blue) and gas (brown) energy consumption.

We assumed that each building had committed to achieving net-zero energy emissions from 2025 and would purchase certificates to offset 100% of the buildings energy emissions at a cost of $40 per Megawatt-hour (MWh). This ensures that efforts to reduce emissions, for example to eliminate gas combustion in the building, can be reflected in an improved financial position commensurate with that price per MWh.

We then model the following alternative scenarios as illustrated in the figure below, and described further in the following sessions:

1. Electrify DHW 
2. Electrify DHW+HHW
3. Electrify DHW+HHW+Thermal Storage
4. Add Solar and Battery Storage (with Thermal Storage)
5. Add Solar and Battery Storage (without Thermal Storage)

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For the heating electrification options (DHW and HHW) we used the output from the building electrification and load flexibility modelling to represent some degree of ‘flex’ of these new electrical loads. The flex potential was determined to be relatively minimal without the additional of thermal storage tanks.

For each scenario and each of the five buildings we also modelled the cashflow position of both the Electricity Retailer (financially responsible market participant) and the Customer (building owner). This is illustrated in the Figure below showing the cash inflows and cash outflows for the two participants for one of the buildings in Scenario 6.

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This reflects a typical unbundled commercial supply arrangement in NSW, including the following:

• Retailersome text
  • Cash inflowssome text
    • Retail revenue from Customer (rates indexed to wholesale prices)
    • Export revenue from Market
  • Cash outflowssome text
    • Import costs from market
    • Share of stationary battery costs
• Customersome text
  • Cash inflowssome text
    • Value of any renewable energy certificates associated with on-site PV system
  • Cash outflowssome text
    • Network-use-of-service costs (network tariff)
    • Capex and opex costs associated with electrification and distributed energy resources
    • Retail costs to Retailer (rates indexed to wholesale prices)

The reason we have reflected some share of the stationary battery costs to the Retailer is that with a standard retail supply contract a lot of the value of a stationary battery accrues to the wholesale market participant. While there are a number of commercial models to share this value back with the Customer, we wanted to keep the commercial arrangements consistent between scenarios and so instead we attributed some of the cost back to the Retailer. Similarly for reasons of simplicity and consistency between scenarios, we did not reflect any value from the battery providing any ancillary market services (such as frequency control), which would be reflected in a model that was more focused on a battery investment decision. 

Modelling Results

Detailed modelling results were provided to each of the project partners that contributed detailed building data and insights and feedback to inform the modelling. We have shown information on load analysis, cost analysis, and emissions analysis for one of the buildings below. We will draw some general conclusions based on the findings across all the buildings in the conclusion to the article (next Section).

Load Analysis

We can see the interval-level load analysis for Office 1 in the Figure below for a sample week in Winter. 

The first chart at the top, representing the Baseline, shows total energy use inclusive of gas associated with domestic hot water (DHW) and heating hot water (HHW), reflected in the large morning peak energy requirements, EV charging sessions, and the balance of the electrical load in the building.

The second chart in the middle, representing the Scenario with electrification of DHW, HHW, and the installation of Thermal storage, shows the change in the electrical load shape with the removal of the gas-use from the building, the energy efficiency benefit of switching to heat pumps for heating and the load flexibility benefit of the thermal storage. 

The third chart at the bottom shows the correlated wholesale energy prices [orange] and grid emissions intensity data [brown] for this week.

This is contrasted with the same building and scenario for a sample week in Summer in the Figure below. The difference in the load shapes is less pronounced because most of the benefit of electrification is reflected in the removal of the winter space heating requirements.

We can also examine these two weeks with the addition of roof-top PV generation and a stationary battery. In this case the building could only accommodate 47kW of roof-top generation (which is not unusually small for tall buildings) [yellow in chart below]. We also modelled the addition of a 1.2MWh stationary battery [purple in chart below].

Cost Analysis

The cost analysis was done on a raw undiscounted cash flow basis, because it is not intended to reflect a full financial model. The absolute cash flows for Building 1 for each key scenario are shown in the Figure below for both the Customer and the Retailer. This is the total cash flows over the period from 2025 to 2040. 

The series shown in each chart are:

• Retail gas [yellow]
• Retail electricity [blue]
• Wholesale electricity [orange]
• Renewable energy certificates [green]
• Project capex and opex [teal]
• Network-use-of-service (network tariff) [red]

For each chart the net cash flow position is also shown, for example in the Baseline scenario the net position of the Retailer is approximately $1,000,000 representing gross profit over the 15 year modelling period.

In the following charts we show the relative annual cash flow position for each scenario, which is the difference or savings against the baseline.

We can see that in Scenario 3 (first Figure below), electrifying and flexing DHW and HHW, the financial outcome for both the Customer (building owner) and Retailer (reflecting the value created in the wholesale energy market) were improved.

In Scenario 4 (second Figure below), we can see that while adding thermal storage did improve the energy and emissions outcomes for the building, this did not sufficiently compensate for the relatively high project Capex costs associated with implementing Thermal storage

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However we do see a positive financial outcome from the DER investment in Scenario 6, as shown in the Figure below (noting as mentioned above the modelled cost sharing between Customer and Retailer for the stationary battery).

Emissions Analysis

We have analysed energy emissions with three emissions models:

1. Market Emissions (based on average annual emissions factors), including a modelling assumption that 100% of energy emissions are offset with voluntary certificate purchasing
2. Local Emissions (excluding certificates)
3. Interval-level Local Emissions 

We have derived annual average emissions factors and interval level emissions factors using the data approach described above in the ‘Australia’s Energy Transition’ Section.

When we look at the Baseline scenario for Building 1, we see the emissions profile shown in the Figure below. Notable is the overall reduction in building emissions overtime, due to the decarbonisation of the power system (noting, as mentioned in the ‘Australia’s Energy Transition’ Section, the assumption that NSW meets its policy goals and decarbonization targets), with the commensurate increase in the proportion of the buildings emissions associated with gas.

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When we look at these emissions excluding the voluntary certificate purchasing (Local Emissions), the total emissions over the 15-year project duration is 15.8 Mt CO2e.

This is not materially different to the 24/7 emissions as calculated using the Interval-level Local Emissions model, which are 15.4 Mt CO2e. 

One key reason for this is that commercial property load shapes are naturally relatively well aligned with grid-emissions intensity. Building loads tend to peak in the middle of the day, when solar irradiance is high, and load is relatively lower during the very early morning and later afternoon/early evening.

This positive alignment can start to change as well electrify building heating, because we are increasing electrical load during winter mornings. However this is more than offset by removing gas combustion emissions from the building.

We can see this in the Figure below showing the same building with electrification of Heating Hot Water and Domestic Hot Water with the addition of Thermal Storage and the associated load flex.

When we look at these emissions excluding the voluntary certificate purchasing (Local Emissions), the total emissions over the 15-year project duration is 11.4 Mt CO2e. Again this is not materially different to the 24/7 emissions as calculated using the Interval-level Local Emissions model, which are 11.1 Mt CO2e. 

The final scenario we’ll look at is the addition of a small amount of roof-top solar (47kW) and a large stationary battery (1.5MWh). In this case the lifetime emissions reduces 11.1 Mt CO2e, which is a reduction of around 4,400 tonnes CO2e when compared to the baseline. 

The main contributor to the reduction in emissions in the removal of gas from the building and the decarbonization of the power grid. In the final year of the model (2040) the emissions in the baseline are around 300 tCO2e/year, with the majority coming from gas and only 70 tCO2e/year coming from electricity (on a Local Emissions basis). 

This is reduced from 300 tCO2e to 45 t CO2e in the final scenario, which is an 85% reduction (on an Local Interval-Level Local Emissions basis).

NABERS Analysis

The National Australian Built Environment Rating System (NABERS) is a performance-based rating system for buildings, measuring their environmental impact and efficiency. It provides independent assessments of energy, water, waste, and indoor environment quality in commercial buildings. 

NABERS ratings help building owners and tenants understand their buildings' operational efficiency, enabling them to improve performance, reduce environmental impact, and achieve cost savings. Widely recognized in Australia, NABERS promotes transparency and drives improvements in the sustainability of the built environment.

While NABERS was not a particular focus of the project, we did examine the impact of the modelled projects on commercial buildings NABERS performance. This analysis is shown in the Figure below for one of the buildings. Where we can see that this emissions reduction in our analysis is currently not necessarily reflected in improved NABERS ratings.

Conclusions and Next Steps

The 24/7 Carbon Free Buildings Project explored the importance and feasibility of aligning commercial building energy use with the real-time emissions intensity of the power grid, while considering project opportunities around heating electrification, electric vehicle charging, thermal storage, load flexibility and distributed energy resources including roof-top solar and battery storage.

The key findings from the project include:

1. Mismatch Between Reported and Actual Emissions: Traditional renewable energy procurement strategies can potentially lead to a mismatch between reported and actual energy emissions. This can be mitigated by adopting locational time-matched emissions reporting.

2. Impact of Electrification: Electrifying heating systems and providing electric vehicle charging services are crucial steps in reducing a building's reliance on fossil fuels. The transition to electric heating systems, such as heat pumps, offers substantial energy efficiency and emissions reduction benefits.

3. Load Flexibility: Enhancing load flexibility through strategies such as thermal storage and intelligent HVAC control can further reduce emissions by shifting energy consumption to times of lower grid intensity, but the load flexibility capacity available in commercial buildings may be relatively limited.

4. Buildability Challenges: There can be significant ‘buildability’ challenges associated with these project opportunities, particularly in relation to physical space and electrical capacity. The space issues are particularly acute in relation to implementing thermal or battery energy storage in buildings.

5. Financial and Emissions Benefits: Investing in these projects provides both financial and emissions benefits. The analysis demonstrated that these investments can lead to significant emissions reductions and improved financial outcomes.

6. Emissions Model: For commercial buildings, where loads are already relatively well aligned with low-emissions intensity in solar-heavy grids, there is not a significant difference between emissions calculated based on average annual emissions factors and interval-level emissions factors. Deriving the interval-level emissions factors for the power grid was complex and time-consuming, and should this emissions model be adopted on a more widespread basis, there would be value in a central authority such as AEMO or the Clean Energy Regulator providing this data.

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To build on the success of the 24/7 Carbon Free Buildings Project, the following steps are recommended:

1. Policy Advocacy and Incentives:

• Peak bodies in the commercial building sector should set a clear policy direction in relation to 24/7 carbon-free energy, noting that in some sectors such as data centres it is becoming an industry norm, and in others like the production of green fuels such as hydrogen it is becoming a legislated requirement. While the additional complexity must be acknowledged and considered, peak bodies should consider whether the standards for commercial buildings should be lower?
• Consider how the design of rating schemes such as NABERS properly recognise the value of electrification and load flexibility to support the wider energy system transition.

2. Technology Adoption:

• More work should be done to explore and validate the load flexibility capacity within commercial buildings. This project took a relatively conservative approach to the potential available flexible capacity in buildings. If more flexibility could be unlocked this would significantly help support the decarbonisation of the power grid and reduce the dependence on gas generation for flexible capacity to balance renewable generation. 
• More support should be provided to the property industry to accelerate the electrification of heating in commercial buildings. This was the biggest driver of emissions reduction after the assumed decarbonisation of the power grid. 

3. Pilot Projects:

• This project represented a ‘virtual pilot’ across five buildings. Additional pilot projects should be in diverse commercial building settings to explore and address the technology adoption and buildability challenges identified by this project. Use the results from these pilots to inform broader policy and industry strategies.

By taking these steps, the commercial building sector can play a pivotal role in accelerating the transition to a carbon-free energy future, enhancing sustainability, and meeting ambitious emissions reduction targets.