Summary

  • Australia’s draft Electricity Services Entry Mechanism (ESEM) would use public procurement and long-dated contracts to address a mismatch between project finance and buyers’ shorter contracting horizons.
  • The proposal distributes decisions and exposures across jurisdictions, an ESEM Administrator, a Financial Management Entity, the Australian Energy Regulator, AEMO and Market Customers. Annual cost recovery makes that allocation consequential to consumers.
  • The 2025 NEM Review said the mechanism should be self-limiting if the market closes the tenor gap. The 2026 draft adds a two-year planning cycle, contract recycling and proposed cost relief; the decisive question is what public evidence would cause procurement to shrink.

A power contract can outlast the political decision that created it. That is not, by itself, a defect: a generator, storage project or other electricity service may need a long revenue horizon before a lender will finance it. But the institution that writes or holds the contract can transfer risk for years, while the household or business that ultimately encounters part of the cost may never see the original decision.

That is why the proposed Electricity Services Entry Mechanism should be judged as an allocation system, not simply as a way to produce more contracts. It has to connect a public objective to a service need, a procurement decision, a counterparty, a risk limit and a billable cost. It also needs a credible account of when the market has taken enough of that work back.

The tenor gap is the reason for intervention

The independent 2025 National Electricity Market (NEM) Review described a familiar financing problem. Sellers of capital-intensive assets may seek contracts that run for 10 to 30 years, while buyers commonly contract over three to seven years. Shorter commitments can leave future revenue uncertain precisely where financing needs the longest view. The Panel proposed the ESEM to bridge that gap with standardised contracts for bulk energy, shaping and firming services.

The October 2026 package is still a proposal. DCCEEW is consulting on a draft Bill, a draft Rule and an explanatory paper; submissions close at 11:59pm AEDT on 13 October. Energy Ministers are expected to consider further decisions in December. A proposed mechanism should not be described as an operating scheme, and its future charges cannot yet be translated into a household-bill estimate.

The draft’s operating chain is consequential. Participating jurisdictions nominate reliability and emissions targets and scheduled-generator exit assumptions. The ESEM Administrator uses AEMO modelling, delivery-risk estimates and consumer considerations to prepare an indicative 15-year entry trajectory for each region, revisited every two years. It then plans procurement. The trajectory is a planning horizon, not proof that every target will result in a contract or that a contract will deliver the expected service.

A contract moves risk; it does not make it disappear

The proposal separates the Administrator’s planning and procurement functions from those of a Financial Management Entity (FME). The Administrator assesses tenders and recommends contracts. The FME enters into and manages those contracts, holds the counterparty position and recycles contracts back to the market before maturity. The consultation paper allows one entity to be appointed to both roles, so functional separation need not mean separate corporate owners.

This creates several distinct control points. Governments choose the objectives and assumptions. The Administrator translates them into volume and timing. The FME carries liquidity, working-capital and contract-management exposure. The Australian Energy Regulator (AER) is assigned oversight of the risk framework and an annual cost determination. AEMO applies the resulting charges and rebates through NEM settlement. Market Customers pay; downstream retailers may pass some costs through, while directly connected users are also within the proposed settlement design.

The draft risk framework is meant to identify what risk is accepted, mitigated or avoided, and to state methods, limits and triggers. Its listed concerns include Administrator or FME insolvency, liquidity sufficiency, consumer impacts, market liquidity and crowding out. That is a useful inventory. It is not yet a public result: it does not tell a reader what exposure is tolerable, which threshold changes a procurement decision, or how a realised loss would be apportioned.

Annual recovery is also more than bookkeeping. The FME proposes recoverable costs and their jurisdictional allocation; the AER verifies forecasts and determines annual recoverable amounts and rates; AEMO settles those amounts with Market Customers. The draft aims at non-profit recovery and links costs to service regions, with jurisdictional allocation principles. It does not establish a retail-bill forecast. The transmission from a wholesale settlement charge to a particular retail customer remains a separate question.

Cost relief must reward replacement, not paperwork

The proposed cost-relief scheme is intended to avoid penalising customers who arrange equivalent services outside the ESEM and thereby reduce what the mechanism needs to procure. Eligible Market Customers could receive input credits against relevant ESEM costs. But the consultation paper acknowledges that this part of the draft is less developed. The Rule’s criteria require a qualifying contract tied to a project that would reduce or replace an ESEM service, with equivalence and timing conditions. A long power-purchase agreement does not automatically earn relief.

The distinction matters. If the credit follows evidence that private supply replaces a defined regional need, the mechanism can leave useful activity outside its own contracts. If eligibility is opaque, customers may face a second layer of discretion: first in procurement, then in relief. Publishing applications, reasons, credited service, vintage and cost avoided would help show whether the scheme is rewarding substitution or merely distributing a discount.

The Panel’s 2025 report called the ESEM “self-limiting”: if market participants solve the tenor gap outside the architecture, it should eventually cease operating. That is a design intention, not a fixed sunset written into the current draft. The two-year trajectory review, recycled contracts and cost-relief proposal create possible feedback, but a review calendar is not an exit test. The question is what observable market evidence will lead the next trajectory to procure less.

An answer should distinguish continuity of electricity service from continuity of the mechanism that currently supports it. Reliability and emissions objectives may remain important while the state’s role changes. The public record should therefore connect each procurement to a named service gap and region; show forecast and realised costs, recycled positions and delivery; record private contracts that displace planned procurement; and state the threshold for reducing the next round. If a gap persists, the case for intervention can be renewed. If it closes, the service should continue without requiring the same public intermediary to do so.

That is a harder test than counting signed contracts, but a better one. The purpose of a bridge is to make the crossing possible. Its success is not measured by how long the bridge remains open.

Sources: DCCEEW’s October 2026 consultation package (draft Bill, draft Rule and consultation paper); Energy Ministers’ NEM Review status page; 2025 NEM Review final report, especially pp. 14–15 and 175–82.