Regulated Electricity Prices: A look at network and wholesale costs

While there has been considerable focus recently on retail costs in the draft regulated Default Market Offer, network costs (the cost of the local distribution network and transmission network in a region) have also seen increases, along with wholesale costs. These two components account for the bulk of the end user bill. Network and wholesale electricity costs make up 33-48 per cent and 31-44 per cent of the DMO 7 draft prices respectively. 

Given the scale of the network and wholesale costs in the final power bill they will also need to be focused on particularly as the energy transition continues with older generation being replaced by renewables, storage and gas generation and new network investments to integrate these into the system.

Last week we looked at what makes up the retail costs and here we take a look at what has been happening with the network and wholesale cost components.

Overall price changes

Network prices are increasing across all distribution regions in every state except South Australia.  In eavery other state they are increasing for all customer types and tariffs except for those Energex residential customers with controlled load (CL). These increases range from 2.7 per cent or $20.50 of the $788 network charges for Energex residential flat rate customers and 11.6 per cent or $108.7 of the $1043 in network charges for Endeavour Energy residential customers with CL. Increases in the network costs are attributed to inflation, interest rates and growing network expenditures. 

Energy prices have also increased.  Average wholesale market spot prices increased across 2024, impacted by factors such as high demand, coal generator and network outages, and low solar and wind output that drove high price events across DMO regions. These high price events impact the price of wholesale electricity contracts for 2025–26. The wholesale cost increases range from 2 per cent to 11 per cent (up $85 for SA Power Network residential customers without CL).

 Regulatory Asset Base (RAB)

The regulator determines the revenue networks can recover from customers and this is based on a level of return on a network’s RAB. The RAB is the regulatory valuation of a network service provider's assets and a key input for the return on capital.  It allows for the recovery of network investments over the duration of their economic lives. The regulatory arrangements are in nominal terms and the RAB is adjusted for inflation each year.  The AER stated in its 2021 State of the Energy Market Report that “consumers will continue to pay for overinvestment in network assets [that occurred] from 2006 to 2013 for the remainder of the economic lives of those assets, which may be up to 50 years”.

Inflation can have a noticeable impact on the rates of returns for networks. During the 2015 to 2021 period, low interest rates and inflation reduced the allowed rates of return set for networks, but since 2022, higher inflation and rises in interest rates will increase the allowed rates of return and network costs in coming years[i]. For example, if inflation is three per cent, then a $10 billion RAB will be increased by $300 million.

There is an expectation the capital expenditure (capex) by electricity networks will increase in future years, which will increase the RAB. One factor will be transmission networks undertaking approved capex for Integrated System Plan (ISP) projects, such as EnergyConnect. The costs of the $2.28 billion project have already reportedly increased by around $1.5 billion[ii]. Transgrid issued an update[iii] on the new electricity transmission connection between South Australia and NSW which included a revised net project cost at $3.6 billion. To put this in context, Transgrid’s RAB was $8.8 billion as at 1 July 2023 and this one project represents over 40 per cent of this.[iv] And there are potentially other costs in distribution networks as they keep up with demand for connections of customer energy resources, such as household solar and batteries.

It will be important to ensure transmission projects are kept to budget to keep network costs down. So too will be managing capital spending on distribution networks, which account for the bulk of the network revenues. Integrating Consumer Energy Resources (CER) into the energy market well can help keep network costs lower, but doing this poorly could lead to significant costs.

Wholesale Cost Factors

Wholesale costs reflect the demand and supply balance and are being driven by the energy transition that is underway, which is capital intensive. Coal outages have been cited as a major factor and while coal plants remain important to ensuring reliability in the grid that is only part of the story.

Drivers of high price periods include tight supply conditions that can be driven by high demand, network outages, interconnector constraints, baseload outages and low renewable generation.  We also now see increasing periods of negative prices, with last financial year being the fifth consecutive year in which a record number of negative prices were set[v].

AEC analysis of plant availability in New South Wales, for example, showed it was more than 83 per cent. But overall there is less coal plant capacity available given the closure of plants like Liddell, and this will accelerate as plants come to the end of their technical lives. Renewables are variable and often cannot meet demand when less coal is available. When coal and renewable plants are not available it requires more expensive dispatchable plant to step in to meet demand. Variable renewable energy (VRE) needs a range of backup options, such as gas fuelled power generation, hydro, pumped hydroelectric storage (PHES) and large-scale battery storage as well as better connected grids to tackle this variability as coal leaves the system.

Overall, an increase in extreme price periods (either high or low) suggests a tighter supply-demand balance and one that is harder to accurately predict. Furthermore, increased volatility makes hedging more challenging and likely more expensive because risk levels are higher. It is important to note that it is the contracted price that consumers pay. As highlighted by the Australian Energy Market Operator’s (AEMC) Electricity Statement of Opportunities (ESOO)[vi], if the expected investments in new generation, storage and transmission are not delivered on time, we can expect not just future reliability risks but elevated price volatility.

As noted by the Australian Energy Market Commission (AEMC)[vii] the transition is “not a smooth, linear replacement of one energy system with another. Two systems — the old and the new — are co-existing, and it’s complicated”. It requires significant investment and careful coordination.

DMO 7

Looking at the overall costs in the DMO and the contribution of network and wholesale costs shows:

New South Wales

DMO customers without controlled load (CL) are expected to have a total price increase of $159 or 8.8 per cent in the Ausgrid region. Network costs increase by 9.6 per cent (an increase of $63 to a total of $720 on customer bills (44 per cent more than retail costs); a total price increase of $174 (7.8 per cent) for Endeavour Energy with network costs accounting for $77 of the increase; a total of $200 or 8 per cent for Essential Energy customers with network costs increasing by $89. Residential customers with CL the total increases are Ausgrid $205 (8.3 per cent), $249 (8.9 per cent) Endeavour and $243 (8.3 per cent) for Essential Energy customers. Network cost increases are $74, $109 and $89 respectively.

In the biggest state, New South Wales network costs have increased the most. Network costs increased across all New South Wales regions with inflation and interest rates leading to a higher rate of return. The state’s Renewable Infrastructure Roadmap and transmission cost increases have also contributed.

Wholesale costs for all customer types also increased across each NSW region driven by changes in contract prices. Base future contract prices increased $7.70/MWh and cap contracts are up by $7.20/MWh.

Queensland

In South East Queensland customers without CL will see a price increase of $119 (5.8 per cent), and of that just over $20 is from network charges. Customers with CL will have a $61 increase (2.5 per cent) with networks actually seeing a cost reduction of $42.

There has been a small increase in wholesale costs for all customer types driven by contract price changes (based futures contract prices are up $3.50/MWh while cap contract prices have barely moved (up 0.30/MWh. Queensland has been helped by significant volumes of base and cap contracts bought at lower prices in 2023.  With higher wholesale prices now in the state, the AER notes that they could further impact its final price determination.

South Australia

South Australian customers without CL should expect to see a price increase of $114 or 5.1 per cent, while those with CL will see an overall DMO price increase of $121, or 4.4 per cent.

Network costs have fallen for all residential customer types which are driven by a forecast reduction in the allocation of transmission costs to the flat tariff and the return of previously over-recovered revenues.

Wholesale cost increases have been driven by movements in contract prices and the shape of the load profiles used. Base futures increased $2.80/MWh, while cap contract prices have risen $3.20/MWh. With more renewables in its mix South Australia’s load profile is peakier during the evening which increased hedging costs.

Conclusion

As the energy grid continues to transition, we should expect to see wholesale costs decline, whilst network costs will increase. To date, reductions in the DMO have focused on reductions in retailers’ costs and margin, but as we noted last year there is little left to squeeze. How the AER sets the DMO in future years will be critical to building confidence in industry and allow them to set cheaper market offers.

[i] 2024 Electricity and gas networks performance report

[ii][ii] EnergyConnect: Key transmission project’s $1.5b blowout points to bill shock pain

[iii] EnergyConnect update | Transgrid

[iv]https://www.aer.gov.au/system/files/AER%20-%20Transgrid%202023-28%20-%20Final%20Decision%20-%20Attachment%202%20Regulatory%20asset%20base%20-%20April%202023.pdf

[v] https://www.aer.gov.au/system/files/2024-11/State%20of%20the%20energy%20market%202024.pdf

[vi] 2024-electricity-statement-of-opportunities.pdf

[vii] Energy security in the transition | AEMC