The NEM investment landscape has shifted quickly over the past six months. Battery revenues have fallen faster than was forecast, as mild weather, delayed coal retirements and the buildout of home batteries reduced scarcity pricing and compressed spreads.

BESS capacity reached 7.7 GW in Q2 2026 and is projected to reach 20.6 GW by 2030. Projects reaching investment decisions today are entering a tighter market than the one many were first modelled against.

For NEM investment, the question has changed. Developers need to decide how much duration to build, where to locate, and whether hybrid projects offer a better way to diversify risk and capture value in a changing market.

In August 2026, our Q3 Australia workshops covered the drivers behind the revenue fall, regional differences in volatility, the investment case for longer duration, and how hybrid offtakes, data-centre demand and network conditions reshape project value.

Modo Energy subscribers can access the full presentation at the end of this article.

Fewer scarcity periods drove two-thirds of the spread fall

Price spreads have narrowed across most mainland regions. Additional home batteries and grid-scale BESS have increased the capacity margin, reducing the probability of price spikes. Fewer scarcity events have therefore removed a large share of the merchant value batteries had captured in previous years.

The NEM-wide four-hour price spread fell from $309/MWh to $106/MWh (as of July 2026). Just under two-thirds of that fall came from fewer intervals above $300/MWh, rather than lower everyday spreads.

Everyday prices have also compressed. More batteries bidding into the same evening peak, lower demand through mild weather, and more coal capacity have reduced the underlying spread available to the fleet.

For investors, the market has changed in two ways. Scarcity value has become less frequent, whilst the ordinary daily spread has tightened. Batteries are still cycling, but each cycle now earns less.

The drivers of volatility are changing

Scarcity pricing has fallen, but volatility has not disappeared. The events that create upside are changing by region as the generation mix shifts and coal availability becomes more important.

Using Modo Energy’s forecast, we modelled four-hour battery revenues across 1,000 weather years and investigated the conditions that drove volatility in each region.

In South Australia and Victoria, winter wind droughts become the main source of volatility. Low renewable output tightens supply during periods when demand still needs to be met.

In New South Wales and Queensland, volatility is more exposed to outage risk. Higher demand and thermal unit availability determine how often the market clears into scarcity pricing.

Investors need to understand how these drivers affect the business case, because the upside is concentrated in a small number of high-value events. Asset design, location and contracting strategy then determine how much of that exposure they can capture.

Longer duration captures more scarcity value

As scarcity events lengthen, stored energy becomes the constraint. Shorter batteries capture the start of a price event, but longer batteries keep discharging as the event extends.

Across 2029 to 2050, four-hour batteries capture less than half of the annual value above $300/MWh. Six-hour batteries capture around half to two-thirds, whilst eight-hour batteries capture up to nearly 80%.

The incremental gain falls as duration increases, whilst capital cost rises. The decision between six and eight hours therefore depends on how investors value additional scarcity exposure against higher upfront capex.

Longer duration also preserves more exposure to tail events, especially extended renewable energy droughts that may sit outside the central forecast. Those periods are rare, but they can carry a large share of upside.

Longer duration also changes the cap contract case. A battery with more stored energy can sell and defend a larger cap position, because it can stay dispatched through more of the above-strike interval.

Demand for firmed green supply is reshaping offtakes

Growing demand for cleaner, firmer electricity is changing how hybrid projects are contracted. Physical tolls remain important for bankability, but data centres and other commercial and industrial loads are creating more appetite for products that combine renewable generation with storage.

That demand changes the offtake structure. A standalone BESS toll contracts flexible capacity. A swap retains exposure to merchant upside, but leaves the owner more exposed to lower merchant outcomes. The trade-off is more participation in market outperformance, with less downside protection than a toll. A hybrid PPA packages solar and storage into a cleaner product with a stronger link to customer load.

The commercial trade-off is different in each case. Tolls suit buyers that want dispatch control. Swaps suit parties willing to share market exposure. Hybrid PPAs suit buyers looking to procure green electricity with more shape than a solar PPA can provide on its own.

Data centres are becoming a larger source of demand for firmed green electricity. Most disclosed appetite is concentrated around Sydney and Melbourne, where the largest operators are already planning new capacity.

For developers, offtake design now sits closer to asset design. The contract determines which risks transfer, how much upside remains, and whether the project is valued as flexibility, merchant exposure or firmed green supply.

Transmission timing changes the NEM investment case

Transmission timing is central to the investment case for any asset. Delays to planned network upgrades can materially increase congestion, reducing access to price events and changing the revenue outlook at a specific connection point.

The chart shows how intraregional congestion evolves under different network buildout paths. Network augmentations can reduce constraints for a period, but rising renewable capacity and changing flows mean congestion reappears in different parts of the grid.

That makes connection risk more granular than a state-level forecast can show. Two projects in the same region can face different revenue outcomes depending on constraint exposure, network timing and nearby renewable buildout.

Modo Energy's nodal model captures these dynamics at five-minute granularity. It allows developers and investors to test how constraints evolve around a project, and how transmission timing changes the business case before capital is committed.