The NEM is a centrally dispatched, energy-only market divided into five regional spot markets, each corresponding to a participating state or territory. These are:

• New South Wales (including the Australian Capital Territory)
• Queensland
• South Australia
• Tasmania
• Victoria

Each region has a designated RRN, a specific transmission node where the regional spot price is calculated. All market participants in the region settle at the RRN price, adjusted for their marginal loss factors (e.g., MLF) to reflect electrical losses between their connection point and the RRN.

Spot prices reflect the marginal cost of supplying an additional unit of electricity at the RRN, taking account of network constraints, losses and system security requirements.

AEMO operates a co-optimised dispatch process in which Energy and FCAS, are simultaneously optimised to minimise total system cost while meeting all technical constraints. This means FCAS requirements can influence generator dispatch and spot pricing when FCAS scarcity or availability changes the marginal unit needed to meet demand.

Although each region has its own 5-minute price, all regions are physically interconnected. AEMO’s dispatch engine co-optimises generation across the entire NEM, subject to:

• interconnector limits
• thermal and stability constraints
• system strength requirements
• losses across inter-regional flows

When constraints bind, regional prices diverge, providing local price signals that reflect the actual supply–demand balance and network limitations within each region.

Regional spot prices are supported by deep financial contract markets, used by generators, retailers and large customers to hedge energy market risks. These contracts settle against the spot price, however, are independent financial instruments.

Market design and operation

The NEM operates as a centrally dispatched, real-time energy-only spot market in which AEMO determines generator and load dispatch every five minutes. All physical electricity is traded through this spot market, and participants settle financially at the regional spot price determined at the RRN. Unlike other market structures, bi-lateral contracts are not exposed to the operator and there is no capacity or balancing mechanism.

Spot market operations

Every connection point in the NEM must have a FRMP, which is the entity financially accountable for all electricity consumed or exported at that site. The FRMP is typically a Market Customer (e.g., a retailer) or a Market Generator, depending on the nature of the site. All market settlements for that connection point are conducted through the FRMP. Building on this, participants are further classified into operational categories (e.g., scheduled, semi-scheduled, non-scheduled) that define operational obligations within AEMOs central dispatch processes and their role in price formation.

Market participants interact with AEMOs central dispatch process through defined classifications, which determine their obligations, visibility and influence on price formation:

• Scheduled generators and scheduled loads: Must follow AEMO dispatch instructions and submit bids/offers for every five-minute interval based on a schedule.
• Semi-scheduled generators: Typically, wind and utility-scale solar, follow dispatch instructions only when they are “constrained,” but otherwise can operate up to their availability.
• Non-scheduled generators: small scale generation (e.g., community batteries) and not required to participate directly in central dispatch (but they still settle financially at the spot price and contribute to regional demand).
• Market ancillary service providers: Can only offer FCAS capacity which is co-optimised with energy offers.
• Market Customers (retailers and direct customers): Market Customers are treated as non-dispatchable and settle all electricity at the spot market; they are not required to “bid” load into central dispatch which is a key distinction from other markets.

The NEM is a gross pool market, meaning all electricity generated must be sold through the spot market, and all retailers and Market Customers must purchase from it. Physical bilateral trades are not permitted; instead, participants use financial contracts for hedging while physical dispatch and pricing are determined entirely through the centralised spot market.

AEMO uses the NEMDE to determine the least-cost combination of generation, load, and ancillary services to meet demand. This needs to consider available generation, transmission constraints, system strength requirements, physical plant and power system limits (de-rated for ambient temperature), and ancillary services.

The outcome of NEMDE is a dispatch price, calculated and published every five minutes at the commencement of each trading interval. Prices are determined using marginal pricing, where the spot price reflects the marginal cost of supplying the next increment of electricity at the RRN. This means the price is set by the most expensive offer required to meet demand after applying all network constraints, FCAS co-optimisation and loss factors.

Since October 2021, the NEM is one of the first electricity markets in the world to implement full five-minute settlement and remains one of the few markets globally to align dispatch and financial settlement at this granularity. This design places the NEM at the leading edge of incentivising fast-responding technologies such as batteries, flexible CER and demand response.

Spot prices in the NEM can be highly volatile, and several mechanisms exist to manage extreme price outcomes. The MPC sets the maximum spot price (currently $20,300/MWh in FY2025–26), while the MFP is set at –$1,000/MWh. Over a rolling seven-day period, AEMO monitors the CPT. If the cumulative sum of spot prices exceeds this threshold, administered pricing is triggered, capping prices within a defined band until conditions normalise. These mechanisms limit prolonged exposure to extreme prices while preserving scarcity signals needed for system reliability.

Financial contracts in the NEM

Although all electricity is physically settled at spot prices, the NEM supports a large and highly liquid financial contract market used by FRMPs to manage exposure to spot price variability. These contracts do not influence physical dispatch; rather, they are financial instruments that enable generators, retailers and large customers to stabilise revenues and energy costs and allow utilities to develop predictable tariffs into which CER products integrate.

Contracts are traded either bilaterally as OTC agreements or via exchange-traded markets such as the ASX. Typical contract types include:

• Swaps (fixed-price hedges): Lock in a fixed electricity price for a defined volume and period, providing a flat hedged price for energy based on the difference between a strike price and the spot price.
• Caps: Provide protection against extreme price spikes (e.g., above $300/MWh), offering retailers peak-price risk management and enabling peaking generators to earn fixed premiums.
• Tolling agreements (physical): The offtaker pays for the right to physically operate a generator or battery and receives the market revenues from its dispatch, while the asset owner receives fixed, lease-style returns and is shielded from market risk.
• PPAs / Financial offtake agreements: Long-term contracts supporting renewable project financing or retailer portfolios, typically structured as a fixed-for-floating difference payment against the regional spot price and will often include LGCs in addition to energy.
• Virtual PPAs / Virtual tolling (financial): Emerging structures that separate financial settlement from physical delivery. The offtaker does not control dispatch; instead, they receive (or pay) the financial difference between a proxy schedule, the contracted strike price and the spot price for the contracted volume. All asset risks remain with the owner/operator.

In recent years, the ASX and other electricity exchanges have introduced a suite of “shape-based” derivative products, including Morning Peak and Evening Peak contracts. These contracts hedge narrow, high-value daily time intervals that increasingly drive system pricing, typically the early-morning ramp and the evening peak when residential demand is high and renewable output, particularly solar PV, is limited. These shaped products provide retailers and large customers with more granular hedging options that better align with evolving intraday price volatility.

All electricity futures, options and other hedge products are financial derivatives. Trading or advising on these instruments requires an AFSL or reliance on an authorised representative arrangement. This ensures compliance with financial services law and provides appropriate consumer, conduct and credit-risk protections for participants engaging in derivative contracting.

Hedging and CER

As distributed portfolios grow and integration with retailers and wholesale markets deepens, CER is increasingly being incorporated into wholesale market operations and hedging strategies. Rather than operating solely for self-consumption or customer tariff optimisation, CER fleets are now treated as part of a retailer’s or aggregator’s broader wholesale risk position. This typically occurs through one of three pathways:

• Spot-optimised CER: Portfolios are dispatched or controlled in response to real-time spot prices, providing value during high-price periods by increasing energy exports or reducing demand. Under this model, the retailer retains typically responsibility for financial hedging to protect customers from price volatility, market risks, and comply with retail protections. CER contributes incremental value which is shared with the customer but does not displace the retailer’s core hedge requirements.
• Forward-contracted CER: CER portfolios can be integrated into a retailer’s forward contracting position, reducing the volume of financial contracts required. In this structure, CER behaves analogously to an integrated generation asset, with value created by avoiding external hedge purchases and reducing exposure to high spot prices. Using risk-adjusted forecasts of CER output, a retailer may:
  • lower its hedge cover requirements,
  • optimise hedge books around expected CER dispatch, and
  • treat CER output as a partial physical substitute for a forward contract.
• CER-backed contracts: Larger CER assets that can settle directly with the spot market are beginning to underwrite financial contracts on exchanges like the ASX, including cap products, morning and evening peak hedges, and other shaped off-takes. This provides CER owners with more stable, forward-contracted revenue streams, which can lower financing costs and improve investment certainty, ultimately reducing costs to customers.

In wholesale electricity markets, a physical hedge refers to a generation or controllable load resource that naturally reduces exposure to spot prices by producing electricity, or avoiding consumption, during high-price periods. Unlike a financial hedge, which settles purely through difference payments, a physical hedge reflects actual physical supply or load reduction.

When applied to CER, the term “physical hedge” is often used informally to describe a CER asset or portfolio that provides a similar risk-offsetting effect as a financial contract, by generating, reducing load, or shifting consumption during high-price periods. While CER portfolios typically cannot offer the same firm output as utility-scale generation, well-coordinated CER fleets can provide partial hedging value and complement financial hedging strategies.

Certain NEM participants with significant demand-side capability (e.g., large loads, aggregators, DRSPs) are required to provide demand side participation data to AEMO via the DSPIP. This data supports system security, forecasting and operational planning by providing AEMO with visibility of CER-enabled demand response and flexible load that may respond to price signals or dispatch instructions.

Electricity retail markets

Electricity retailing in the NEM is (outside of regional Queensland) fully contestable market and households and businesses can choose their electricity retailer. Retailers purchase electricity from the wholesale market (directly, supported by off-market hedges) and bundle this with network charges, environmental scheme and other costs to provide end-use customers with a final tariff.

The retail sector is structurally separated from network business operation under the NER and jurisdictional rules, ensuring DNSPs and TNSPs do not compete in energy retailing or influence retail offers.

The NEM retail market remains moderately concentrated, dominated by the three large “gentailers”, Origin Energy, AGL, and EnergyAustralia, who collectively serve ~70% of the market across the eastern states. However, market share has gradually shifted toward tier-two retailers, digitally native retailers and specialised CER-focused providers. Emerging customer interest in more advanced CER configurations such as BESS, EV smart charging and EMS has contributed to a more diverse competitive landscape, with retailers increasingly differentiating through innovation, digital services and CER-integrated products and services.

Competition varies by jurisdiction. Victoria has the highest number of active retailers and the most dynamic pricing environment; this is partly due to near universal smart meter availability. NSW and SA also support vigorous competition, while parts of regional Queensland have limited contestability for small customers though large-use customers are contestable. Despite these regional differences, retail switching rates in the NEM remain comparatively high by international standards, reflecting strong consumer choice and ongoing competitive pressure.

Historically, the large gentailers were vertically integrated, holding substantial and often balanced portfolios of both generation and retail load. This structure enabled them to internally manage wholesale market risks using their own generation assets as a natural hedge against retail exposure. Over the past decade, smaller retailers led the development of CER-integrated products and propositions, leveraging demand response and other CER products to offset wholesale volatility. Emerging retailers increasingly offer models where customers can assume spot market exposure, greatly increasing the value of flexible CER operation.

Further information on retail market performance, including market share, churn, hardship indicators and customer movement, is published quarterly in the AER’s Retail Energy Market Update and through the Victorian Essential Services Commission’s Energy Market Dashboard. These sources provide detailed and up-to-date insights into retail market dynamics across the NEM.