Rewiring Incentives

The objective of the National Electricity Market (NEM), defined broadly as the set of markets and rules that orchestrate this grand physical system, is to keep the electricity grid running at the lowest possible cost—both instantaneously and for the long-term—while respecting the laws of physics. That’s a tough mandate. Supply and demand must be perfectly balanced every second to hold the system’s voltage and frequency within a narrow operational window. To achieve this balance as efficiently as possible, every five minutes the market operator solves a complex cost-minimisation problem that considers generator supply bids, demand, and physical system constraints, setting the ‘spot’ price for the coming five-minute interval.

At the same time the NEM’s infrastructure must allow market participants to manage their financial risks through rich derivative markets, while incentivising efficient long-term investment in new generation to replace assets as they age and meet new demand.

Add to this an additional complexity: the electricity sector is Australia’s single largest source of greenhouse gases, accounting for roughly one third of emissions. Meeting our legislated climate targets demands that the sector embarks on a transformation of enormous scale, from a primarily fossil-fuel based system to a net-zero grid where renewable energy sources dominate. 

That transformation is already well underway. Variable renewable generation has grown rapidly in the NEM, largely driven by policy instruments that sit outside the NEM’s framework such as the Renewable Energy Target (RET). In 2010 renewable penetration was only 8%: that figure is 43% today. At the same time, millions of households and businesses connected to the NEM have evolved from being passive consumers of electricity to active participants in the power system. They have installed their own private, small-scale solar and batteries systems, and begun reacting to prices in real-time, shifting energy-intensive activities, like charging an electric car, to the times during the day when solar makes energy much cheaper. 

All of these changes pose both challenges and opportunities for the NEM, which was designed in a different technological and economic era. 

In 1998 the NEM was launched to drive economic efficiency out of an electricity system that was largely constructed by central planners and vertically integrated utilities. And the NEM’s spot market was indeed stunningly successful at squeezing efficiency out of the existing fleet of generators. 

But the NEM has struggled to deliver the new generation required to replace the fleet it inherited from central planning. A great majority of the capacity added since the NEM’s inception has been driven by government policy independent of the NEM, or ‘out of market’ interventions. 

This inability to incentivise the delivery of new generation is a structural problem: prices in the spot and derivative markets are insufficient on their own to drive long-term investment because of a mismatch between the long-term financing needs of investors in electricity generation and the preference of consumers to sign shorter, more flexible contracts.

The recommendations we propose in the National Electricity Market Review are designed to ensure that the NEM is fit to deliver Australia’s electricity goals.

The key issue we identify and seek to resolve is that the links between the NEM’s short-term energy market, its medium-term derivatives market, and long-term investment signals are weakening. This is not the fault of a single policy failure nor a sudden design flaw, but rather the cumulative interaction of technological change, well intentioned climate policy intervention, and institutional inertia. 

Our recommendations respond to this reality not by reinventing the market, but instead by seeking to re-establish coherent economic signals across short, medium, and long-term markets. We lean on the strengths that each of these markets brings: short-term spot markets excel at efficiently dispatching electricity from generators to consumers (including generation owned and operated by consumers), medium-term derivative markets allow participants to manage their risk, and long-term investment markets provide credible revenue expectations that allow investment in the future of our electricity system. Our proposal for an Electricity Services Entry Mechanism (ESEM) provides a long-term investment signal that sits within the NEM’s market structure, and would for the first time fully integrate economic signals across the three time periods.  

This piece has three parts. First, we tell the story of how the NEM came to be and introduce its markets and the role that each of them play. Second, we consider how the NEM has changed over recent years and explain the challenges these changes bring. With this background, the third and final section presents an overview of the recommendations we deliver in the NEM Review.

The Australian electricity industry was vertically integrated and largely government-owned for much of the 20th Century. Over this period, the industry saw almost continuous gains in economic productivity, and the electrification of the economy also enabled enormous gains in broader economic activity and Australian living standards. 

But this central planning approach had downsides. Australia ended up with significant overcapacity of generation and transmission resources—a classic case of capital misallocation that often arises when market pressure is missing. 

Paul Simshauser said of this period that ‘New South Wales had invested in so much baseload capacity that it would take more than 20 years to clear, while Victoria’s excess baseload plant investments adversely affected that State’s Credit Rating.’ The market in the late 1990s was almost exclusively supplied by coal-fired and hydro generation. As planners allocated resources, rather than markets, the mix of resources was suboptimal.

Policy makers responded to the problems of centrally-planned electricity systems, which were the global norm until the 1980s, by successfully promoting microeconomic reform of the energy sector.

What followed was a great success of microeconomic reform. Over the late 1990s and early 2000s, Australia’s large state-owned vertically integrated Electricity Commissions were gradually separated into generation, transmission, distribution, and retail business. These businesses began participating in wholesale electricity markets, and transmission and distribution networks—deemed natural monopolies—were economically regulated. Those reforms delivered large efficiency gains by sharpening operating discipline, improving asset utilization, and materially reducing the cost of supplying electricity compared with the central-planning era.

Born in 1998, today the NEM links Queensland, New South Wales, the Australian Capital Territory, Victoria, South Australia and Tasmania (Western Australia and the Northern Territory operate their own separate grids). In the NEM’s blueprint, price signals were connected across three key timeframes: the short-term spot market, the medium-term derivative market, and the long-term investment market. 

The original NEM reform blueprint was interconnected across three timeframes

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NEM Review

Each of these components are crucial to the long-term functionality of the NEM, but as we’ll explore, they have not been successfully integrated to work together.

The centrepiece of the NEM is the short-term spot market. Every five minutes, sellers of energy submit bids for energy to the Australian Energy Market Operator (AEMO), which then determines the market clearing ‘spot price’ based on its forecast of instantaneous electricity demand. 

The ‘spot’ price for energy typically aligns with the short-run marginal cost (SRMC) of the marginal generator. Economists love this design because marginal-cost bidding guarantees we deliver electricity to consumers in the most efficient way possible. 

For example, if 50 percent of the generation in a five-minute period comes from variable renewable generators with zero marginal cost, and 50 percent comes from gas with a marginal cost of $50 per megawatt hour (MWh), the market will clear at a $50 spot price and all generators will receive this price for their generation. 

When demand gets close to exceeding available supply, prices temporarily rise above marginal costs, reaching as high as the NEM’s $20,300 price cap, creating powerful price signals that encourage generators to invest in capacity capable of serving demand during these periods. 

This mechanism is essential to the theoretical logic of how energy-only markets like the NEM can create a long-term investment signal. An energy-only market is one in which generators are paid solely for the electricity they produce and sell in the spot market. Energy investors operate with the expectation that they will recoup their investments by selling electricity in the periods where they can earn a price above their marginal cost.

In addition to the actual electricity supplied, AEMO procures a suite of ‘ancillary services’ and ‘essential system services’ via the spot market. These are services crucial to ensuring the electric grid remains stable and operates within its technical limits, such as ‘frequency control’ services that provide small, ultra-fast increases or decreases in net generation to ensure that supply and demand remain perfectly balanced between each 5 minute dispatch window.

The medium-term derivative market enables buyers and sellers to lock in future prices, rather than face spot market volatility. For instance, a retailer may purchase a contract guaranteeing a price of $60/MWh for the next year, as a hedge against price spikes—like the late-2025 New South Wales heatwaves, when prices repeatedly hit the $20,300 cap.

In energy-only electricity markets like the NEM, derivatives play a crucial role in maintaining system stability and enabling investment. Generators rely on these financial derivatives to secure stable and bankable revenue streams, while retailers use them to shield their customer bases from the inherent volatility of wholesale prices.

The physical electricity system interacts with the spot and forward financial markets

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NEM Review

In addition to efficiently managing risk, the derivative market also helps to ensure that sufficient generation capacity will be available to meet demand. Generators contract their capacity to secure a stable revenue stream which better enables them to finance their business operations and investment in new generating assets. In this way the derivatives available within the NEM create a decentralised market for capacity, as well as energy.

In the original conception of the NEM, the short and medium derivative markets detailed above were thought to be sufficient to spur long-term investment. The thesis was that long-term contracts between suppliers and customers, along with suppliers’ expectations of future prices in the derivative and spot markets, would incentivize investors to build the right capacity to meet future electricity demand. 

However, this thesis was never fully tested. From the early years of the NEM, new resource development has been heavily influenced by out-of-market government policy interventions, rather than pure market price signals. For the past decade, the vast majority of investment in new generation relied on government policy support.

One reason for high levels of government intervention is climate policy, which manifested several times as (often short-lived) energy policies.

The only federal climate policy with any longevity has been the Renewable Energy Target (RET), operating since 2001, which provides upfront subsidies for solar PV, as well as a certificate trading scheme to incentivise installation of large-scale wind and solar generation.

In the early 2020s, Australian governments began contracting directly with new renewable energy and storage projects. This meant that governments (either through taxpayers or on behalf of consumers) were underwriting new generation projects by holding reverse auctions with developers, and paying any residual costs not funded by the market. The most prominent of these policies is the Capacity Investment Scheme (CIS), a Commonwealth Government policy to underwrite 32 Gigawatts (GW) of new renewables and batteries.

These new investment schemes solved project financing for investors but weakened market wide price discovery and liquidity because they relied upon a single buyer, not an integrated derivatives and spot market. They were designed to drive new investment but in a manner that departed from the original intent of the NEM’s design across the short, medium and long-term timeframes.

The reality is that the NEM’s medium-term derivatives market may have always operated across timeframes that were insufficiently short to provide enough certainty to encourage sufficient new investment in an environment where technology has shifted so rapidly.

Policy support for renewables was, in part, a workaround for what we call the ‘tenor gap’.

The tenor gap refers to a structural mismatch between the financing needs of investors in electricity generation, who seek long-dated revenue certainty to guarantee sufficient revenue to recoup their investments, and the preference of retailers and other market participants, who prefer to contract only a few years ahead.

This reluctance from both parties to meet the other’s preference does not reflect a shortcoming of renewable assets themselves. Rather, it reflects uncertainties over future demand, technology costs, regulatory settings, and competitive dynamics. 

But existing policy responses have struggled to resolve these uncertainties and the tenor gap that results.

The tenor gap is created by a mismatch between buyers and sellers' preferred contracting timeframes

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NEM Review

More fundamentally, climate and energy policies to date have been successful in accelerating the replacement of coal-fired electricity with renewable energy, but they have not delivered a corresponding investment framework for the full set of services and infrastructure required to keep a renewable energy grid both secure and reliable. 

Solar and wind generation, due to their inherent volatility, typically require complementary investments in other technologies to keep the grid stable by providing a set of ‘essential system services’. One of these is referred to as ‘inertia’–literally the inertia of multi-tonne spinning rotors inside coal and gas plants which, because they are electromagnetically tied to the grid, controls fluctuations in frequency. With the retirement of coal-fired generation that provided this inertia historically, there is a need for other technologies that can provide inertia such as synchronous condensers–large spinning machines that provide inertia instead of energy–or emulate it, such as grid forming inverters.

To make the problem clear, consider what sources of funds are available to would-be synchronous condenser investors: since these large turbines do not themselves generate energy, they cannot earn a return from the energy-only market, and are not incentivized by government interventions targeting megawatt hours.

Renewable-heavy grids also require complementary generation or storage technologies that can help to smooth out variable renewable generation and make sure demand can be met at all times. These are called shaping (shorter-duration storage) and firming (very long-duration storage or back up capacity) assets.

By focusing primarily on emissions-free energy volumes, policies have assumed that shaping, firming, and essential system services would emerge organically or continue to be provided implicitly. As large fossil-fuel generators exit, however, these services must be supplied explicitly by storage, flexible demand and other technologies, each with its own capital and risk profile. 

The absence of long-dated, technology-neutral signals for these services compounds the tenor gap, leaving investors exposed to uncertain future revenues and increasing reliance on short-term market outcomes and ad hoc interventions. 

In this sense, climate policies have addressed the carbon intensity of electricity supply without resolving the deeper coordination and risk-allocation challenges associated with financing the infrastructure and services needed to support a reliable, low-emissions system.

The past decade has seen a stark rise in renewable energy technology in the NEM, both at the grid scale–think large wind farms–and at the consumer scale–household solar, batteries, and electric vehicles. This is partly due to the climate policies we’ve already discussed, and partly an inevitable consequence of impressive price declines that have made these technologies attractive across the globe.

These are positive trends, but they do present challenges for the operation of the spot market and the associated derivative markets. If the market doesn’t adapt, price signals in these markets will further weaken, risking further out-of-market intervention, which would again weaken the spot and derivative markets. 

At present, most household energy resources are invisible to the market operator. Large generators such as coal plants or wind farms are required to provide AEMO with detailed commitments of their available generation, and the final decision on whether they may inject power at a given time or not falls to AEMO. This is not currently true for resources such as rooftop solar, household and community batteries, and electric vehicles; they generate or consume when they like, without AEMO having any forewarning or ability to see their behaviour. 

They do, however, often shift their output or consumption in response to the prices that emerge from the markets AEMO can control. This ‘invisible’ behaviour undermines the efficiency that the spot market is supposed to guarantee by causing the prices to be set based on incorrect assumptions about demand and supply. When large volumes of these resources respond outside the dispatch framework, their actions affect prices without bearing the full system consequences, creating a form of free-riding and posing a risk to the safe operation of the electricity system.

This was less of a problem when just a few homes had solar panels or electric vehicles, but it’s no longer something we can ignore.

To be clear, these resources can be of significant value to the broader system if they can be properly managed by market processes. Visibility and coordination of consumer resources is becoming more and more valuable as renewable energy becomes a larger feature of the electricity grid. The challenge is for the market’s rules to evolve so that the NEM and its participants benefit from this new technology. 

When the NEM was introduced, almost all of the energy resources could produce electricity on demand up to their available capacity. Energy was stored in large coal-bunkers and gas pipelines. If energy demand increased, a coal or gas plant could reliably increase supply to meet it. But as wind and solar become the dominant sources of generation, output is increasingly determined by weather conditions rather than controllable plant decisions. This shift makes the system less predictable, with supply fluctuating across hours, days, and seasons. The system becomes one that is predictably variable—for instance, the sun’s output is predictably stronger in summer than winter—and unpredictably volatile—a sudden drop in wind speeds can cause output to fall without notice. 

Weather dependency results in greater price extremes. Periods of high renewable output produce extended periods of very low or negative spot market prices, while periods where wind and solar are scarce, such as are common in winter evenings, cause prices to spike as high as the market price cap. 

Price variation of this sort is not a shortcoming of the market; it is in fact a key feature of an energy-only market. Variable pricing provides sharp signals for the right resources to be dispatched at the right time and, with a well functioning derivative market, signals to firms what resources will be needed in the future. 

However, for this to work as planned, it is critical that derivative contracts to manage risk evolve along with the changing spot market.

Unfortunately, despite the profound changes already occurring in the physical system, the derivative market which provides the financial contracts required to manage risk has not evolved at the pace of the risks that participants face. 

While uncertainty in the physical system is now largely to do with the availability of supply, the derivative markets continue to be dominated by contracts for managing price risks due to changes in demand. 

The contracts that are available to manage variable supply–such as ‘Power Purchase Agreements’ (PPAs), which provide a fixed price for all of a generator’s output–are mostly negotiated between two parties and do not create tradeable contracts that allow other market participants to use them as risk management tools. Furthermore, they value electricity supply at a constant price, irrespective of the value of the energy in the spot market.

Availability of existing products is thinning too. Many coal-fired generators, traditionally a major source of derivative supply, have exited the system, taking this supply with them. 

There are many factors that may have held back this development, but one of great significance is the rise of government-backed Contracts-for-Difference (CfDs) for renewable generation, which are one of the ways that current climate policies are enacted in practice.

The result of this particular government intervention has been a crowding out of private players within the NEM’s derivatives market. When a new wind farm signs a CfD with the government (or a central agency operating on the government’s behalf), a fixed price is guaranteed for all its future output. This leaves new generation fully committed, and unable to trade their future generation with the market. As a result, derivative market liquidity thins, and market signals become less reliable or effective. Smaller retailers who relied on buying hedges from generators can no longer find counterparties, making it difficult for them to manage risk. 

The sum of these trends is that, left unchecked, we face a situation where hidden resources degrade short-term spot market price signals and a deteriorating derivatives market hurts medium-term price signals. We find ourselves in a cycle where out-of-market government intervention becomes more important for driving new investment, which further exacerbates these problems. 

To prepare the NEM for the future, we need to reaffirm the integrity of the short and medium-term markets that already exist, and ensure that long-term investment incentives are integrated into and support, rather than hinder, this framework.

Our recommendations are a response to the challenges we’ve identified, outlined above, across the short, medium, and long-term incentive horizons. The package of reforms we propose are about repairing and strengthening the NEM’s existing framework, rather than discarding it in favour of the fundamentally different designs sometimes advocated for. What you’ll read here is a summary of the 12 recommendations we make in the final Review. 

The NEM Review's envisages the short, medium, and long term markets being fully integrated

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NEM Review

The overarching philosophy of these reforms is to integrate, for the first time, the three time horizons into a coherent, connected set of markets that mutually support each other. Together they restore operational visibility where it matters, deepen the contracting layer that manages volatility, and introduce a market-linked long-term mechanism that fills the tenor gap without permanently crowding out private risk taking.

Our recommendation in relation to the spot market is to expand the set of resources that are required to be visible to, and able to participate in, the dispatch process. Recall the challenge that invisible consumer resources pose: prices can only be efficient if all materially price-responsive resources provide transparent bids and offers to the market. Put simply, our recommendations would have the effect of making more resources that respond to price visible in the dispatch process by creating thresholds above which any resource, or aggregation of resources must provide real-time visibility of its availability and price responsiveness to the market operator. This ensures that dispatch decisions and price formation are informed by the full set of materially price-responsive resources, even where those resources are not otherwise scheduled in the traditional sense.

These recommendations aim to stabilise operational outcomes without dulling the price signals that remain essential to the NEM’s energy-only market design.

Our recommendations respond to degradation of the derivatives market by focusing squarely on liquidity and access to contracts that allow for the risks associated with participating in a NEM with more volatile prices to be managed. 

One fix we suggest is a permanent market-making obligation for a small set of core derivative products. In practice this would require a group of large participants to regularly quote buy-sell prices for a standard set of hedge products so other parties can reliably manage risk even when the market would otherwise be too thin.

This recognises that derivatives markets exhibit public-good characteristics: without sufficient depth and participation, even willing buyers and sellers may be unable to transact efficiently. This logic is well established in financial-market design, but has received comparatively little attention in electricity-market reform debates.

Derivatives markets are not static institutions. As the physical system shifts toward firmed renewables, the relevant risks are evolving. Standardised contracts that fail to reflect these changing risks will naturally lose relevance, pushing participants toward bespoke bilateral arrangements that fragment liquidity and exclude smaller players.  

We recommend developing a new, enduring industry-led process where generators, consumers, and other participants work together to facilitate contract evolution. Private participants are best placed to lead the market’s development: they understand their own risks better than a regulator can, and they have risk management expertise that government bodies lack. Rather than assuming that a single set of products can serve indefinitely, the continual nature of the process acknowledges that contract markets must evolve alongside technology, or risk becoming a bottleneck rather than a facilitator of efficient outcomes.

The centerpiece of the Panel’s long-term reform recommendations is the proposal for a new Electricity Services Entry Mechanism (ESEM): a long-term, market-linked investment incentive framework designed to complement—rather than replace—the existing spot and derivatives markets.

The ESEM would procure a limited set of clearly defined electricity services—initially bulk zero-emissions energy, shaping and firming—through competitive processes similar to reverse auctions for CfDs used around the world today. However, instead of the winning projects being issued revenue underwriting or CfDs, the projects would bid and then be awarded standardised, tradeable financial contracts. These contracts would provide long-dated revenue certainty for new entrants only in those future years where market participants are demonstrably unwilling or unable to contract, thereby directly addressing the tenor gap. 

For example, consider a potential new wind farm, whose investors will only agree to front the required capital if they can secure a 14 year contract for the sale of the wind farm’s generation, but the local energy retailer is only willing to guarantee purchases for 3 years at a time. The investors can sign a contract with the retailer for the first 3 years that guarantees a certain price per MWh of generation, and, through the ESEM’s competitive procurement process, they sign a similar contract with the ESEM administrator for the years 4 to 14 of the project’s life. 

Crucially, the ESEM is not intended to shield projects from all market risk: it would intervene only where the market cannot manage risk efficiently, leaving short- and medium-term exposures to be priced and managed through existing wholesale and derivatives markets.

A conceptual schematic of the ESEM

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NEM Review

A defining feature of the ESEM is that it is explicitly designed to recycle risk back into the market over time. As contracts minted through the ESEM get closer to maturity, they would be progressively sold back into the derivative market and be available for trading among market participants, strengthening price discovery and derivatives market depth rather than crowding them out. 

Let’s return to our example. When that first 3 year contract between retailer and generator gets close to running out, the ESEM administrator sells the next batch of contracts (i.e. years 4 to 7) back into the market. Our example retailer is now happy to buy the contracts at the fair market price, hence committing to purchase the wind farm’s output for the next period of its (financial) life, since the contract now fits within their planning horizon. Whether the administrator makes a gain or a loss depends on if the contract terms are considered favourable compared to other contracts available at the time, including those being offered by new projects. 

The ESEM also finally creates long-term investment signals for the full suite of services required to maintain reliability and security in a firmed-renewable system by separating bulk energy, shaping and firming into distinct but complementary services. Bulk energy contracts support the delivery of zero-emissions supply; shaping contracts reward resources that shift energy across intraday and seasonal periods, such as batteries and pumped hydro; and firming contracts support long-duration capacity capable of being dispatched during extended periods of low renewable output.

The quantities of each service to be procured would be set by the ESEM body independently from the Government. Think of this body like an RBA for energy. This contrasts with conventional capacity markets that entrench Government preferences. Additionally, by procuring standardised, tradeable contracts that can be returned to the market as generators and customers become able to manage risk themselves, the ESEM avoids locking in permanent government ownership of risk, while overcoming the limits of purely private contracting under conditions of profound structural change.

The significance of our work in this Review lies not in any single recommendation, but in the way we reframe the debate about what good electricity market design looks like in a decarbonising system. Rather than giving in to arguments that the NEM’s structure as originally conceived fundamentally fails in the renewables era, we show how the NEM and its supporting institutions must evolve alongside the physical system to effectively deliver reliable, clean electricity for Australia’s future.

Tim Nelson, Paula Conboy, Ava Hancock & Phil Hirschhorn led the independent review into Australia’s National Electricity Market. You can read that review in-full here.