The Australian Energy Market Commission just rejected a proposal to create a new electricity market for inertia services. For commercial energy users, this decision avoids $5-10 million in implementation costs plus ongoing annual expenses that would have appeared as new charges on your electricity bills.
If you’re unfamiliar with inertia or why anyone wanted to create a market for it, here’s what actually happened and why it matters for your energy costs.
When a large generator suddenly trips offline, the electricity grid’s frequency starts changing rapidly. Inertia slows down that rate of change, giving the grid time to stabilise before blackouts occur.
Think of it like a flywheel effect. Traditional coal and gas generators have massive turbines spinning at high speed. When something goes wrong on the grid, those spinning masses resist sudden changes through sheer momentum.
This happens automatically, instantly, and has kept the grid stable for decades. But coal plants are retiring, which creates a problem the industry needs to solve.
Solar and wind generators don’t have spinning turbines. They convert sunlight and wind directly into electricity through inverters. When you replace coal plants with renewables, you lose the natural inertia those spinning turbines provided.
The Australian Energy Market Operator started issuing system strength and inertia shortfall declarations in 2017. South Australia faced the problem first because it retired thermal generation faster than other states.
The grid needs a certain minimum level of inertia to maintain stability. Fall below that threshold, and the risk of cascading blackouts increases.
The Australian Energy Council proposed creating a real-time spot market where inertia would be traded like electricity. Generators and battery operators providing inertia services would receive market payments. Those costs would be recovered from energy users through ancillary service charges.
The logic was that a market mechanism would encourage innovation. Battery systems with grid-forming inverters can provide synthetic inertia. Gas plants can operate as synchronous condensers. A trading market would let different technologies compete to provide the service at lowest cost.
Sounds reasonable in theory. The AEMC analysed whether it would work in practice.
The AEMC’s analysis found three problems with implementing an inertia spot market right now.
First, the upfront costs would be $5-10 million plus millions more in annual operating expenses to design, implement, and run the market. Those costs get recovered from electricity consumers through regulated charges.
Second, the expected benefits under current grid conditions would be modest. The AEMC concluded costs would significantly outweigh benefits, making consumers worse off overall.
Third, transmission networks are already addressing inertia requirements through existing procurement frameworks without needing a new market mechanism.
Transmission networks install synchronous condensers when they procure system strength services. These large spinning machines provide inertia as a co-benefit at low additional cost.
South Australia’s ElectraNet deployed four synchronous condensers at an approved cost of $166 million. This investment lifted renewable generation limits from 1.3 GW to 2.5 GW and avoids estimated market intervention costs of $34 million annually.
NSW’s Transgrid installed synchronous condensers at Buronga substation as part of the EnergyConnect interconnector. Victoria has similar installations at multiple locations.
Battery systems with grid-forming inverters also provide synthetic inertia. AEMO contracts these services through existing mechanisms. The technology is developing rapidly but needs more real-world testing before large-scale deployment.
The existing frameworks deliver required inertia without adding another layer of market complexity and cost recovery mechanisms.
When our team analyses commercial energy contracts, we break down where costs actually come from. Every electricity bill includes consumption charges, network charges, environmental scheme costs, and ancillary service charges.
Network charges recover transmission and distribution infrastructure costs, including investments like synchronous condensers. You’re already paying for these through regulated returns.
Ancillary service charges recover costs for frequency control, system restart capability, and network loading control. An inertia spot market would have added another ancillary service component with its own settlement mechanisms and cost structures.
The AEMC’s decision means one less variable charge component appearing in your electricity bills. Contract structures remain simpler. Cost forecasting stays focused on known variables rather than adding spot market price volatility for inertia services.
Yes. The AEMC’s decision is “not right now” rather than “never.” They’ve tasked the Reliability Panel with monitoring system indicators annually to identify when conditions might justify implementing an inertia market.
Several factors could change the equation. If coal plant retirements accelerate faster than expected, inertia requirements might increase. If grid-forming inverter technology matures and becomes cost-competitive, a market mechanism might unlock investment. If transmission networks struggle to procure sufficient inertia through existing frameworks, a spot market might deliver better outcomes.
The AEMC’s approach maintains flexibility without premature investment in market mechanisms that don’t currently deliver net benefits to consumers.
The Improving Security Frameworks rule change implemented in 2024 strengthened how transmission networks procure inertia and system strength services. These reforms need time to demonstrate results before adding another layer of market complexity.
AEMO will enhance transparency through its Transition Plan for System Security. Networks will improve communication about procurement decisions and how they assess system needs. Innovation trials continue testing grid-forming inverter capabilities.
This creates a foundation for potential future implementation if an inertia market becomes justified. The technical and regulatory groundwork progresses even though the market itself gets deferred.
Energy regulation changes constantly as the grid transitions from coal to renewables. Rule changes affect network charges, contract terms, and cost structures. We monitor AEMC determinations, AER decisions, and network proposals to identify how changes affect commercial energy costs before they appear in your bills.
When new charges emerge, we analyse which clients face exposure and what procurement strategies reduce impact. When proposed charges get rejected like this inertia market, we explain what cost increases you just avoided.
The inertia spot market rejection shows the AEMC weighing implementation costs against consumer benefits. Not every proposed market mechanism proceeds, but transmission networks continue investing in grid stability through existing frameworks.
Our approach involves tracking which infrastructure costs are unavoidable versus which can be managed through contract structure, tariff selection, and consumption timing. The energy transition creates complexity, but it also creates opportunities for businesses that understand how regulatory changes affect their specific circumstances.
Nothing immediately changes from this decision. Your current energy contracts remain valid. Network charges continue recovering infrastructure investments through existing mechanisms.
But the decision illustrates why commercial energy procurement requires ongoing attention to regulatory changes. Proposed market mechanisms that get rejected avoid cost increases. Infrastructure investments that proceed create unavoidable charges. Understanding the difference matters for long-term energy strategy.
We handle this complexity for clients by monitoring regulatory developments, analysing cost impacts, and negotiating contracts that balance price certainty against market exposure. The goal is protecting your business from unnecessary costs while capturing savings opportunities the energy transition creates.
Our specialists track regulatory changes, analyse cost impacts, and negotiate contracts that protect you from unnecessary charges. We handle the complexity of energy procurement so you can focus on running your business.
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Disclaimer
This article provides general guidance based on available energy market data. Energy market conditions and tariff structures vary by location and are subject to change. For specific energy procurement advice tailored to your business, contact our team.
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