Imagine for a moment that you are the head of a large group of network operators, faced with a decision about what to do about rising peak electricity demand. And you are presented with a choice: invest $2.6 billion over five years on upgrading your network – the route you would normally take; or spend a comparable amount on solar power and energy storage, distributed throughout the network.
This was the question posed by Professor John Bell, of the Queensland University of Technology, and Warwick Johnston, a leading solar analyst with Sunwiz, when they sought to find out if there was a better way than the traditional response of building more poles and wires to cope with rising peak demand.
Using Queensland network operator Energex as an example, and its forecast peak demand growth of 1.25GW over the five years to 2014/15, the study analysed the existing approach of spending $2.6 billion augmenting the grid, or investing a comparable amount in either 25GWh of storage, or 1.25GW of solar PV and 10GWh of storage.
The study concluded that a combination of battery and solar PV produced a far better outcome, because of the ability to generate revenue from the energy produced, and the use of battery storage to resell energy. Over a five year period, the net present value (NPV) of the poles and wires solution was negative $2 billion, while the NPV of the solar/storage solution was negative $750 million. But because these could produce revenue over a 20-year period, the solar/storage had a positive NPV of $2 billion over a 20 year period.
Bell and Johnston say the main take-home messages from this are that the integration of distributed PV and battery storage into the existing energy system has the potential to be cost effective now, and it underpins the case for reform of the National Electricity Market, to ensure that distributed generation is fairly treated and that network providers are encouraged to opt for the solutions that have greater market benefit, rather than simply being least upfront cost.
Interestingly, this is a theme picked up by the Australian Energy Market Operator in the latest update of its National Transmission Network Development Plan (NTNDP) that has been released on Wednesday. The AEMO has been pushing its NEMLink proposal, which is designed to reinforce the backbone of the National Electricity Market, and transform it into a truly national market (except WA) rather than a series of interconnected regional markets.
However, under the strict guidelines of the current regulatory framework, AEMO says that it cannot justify the investment, even though its studies conclude that on a broader economic perspective (such as the increased build out of renewables and other generation, avoided losses etc), it would deliver a net benefit of $3.5 billion.
“Traditionally, transmission augmentation occurs around known load and generation centres, but we are now seeing new generation based in more remote areas, and the nature of load profiles is changing along with the nature of the market," it writes. “We need to take a new approach to future investments in transmission to maximise the benefits of this new generation.”
The AEMO report looks specifically at how to meet the expected build out of wind generation over the next decade, and potentially geothermal and solar thermal in the decade after, and how to best plan for the deployment of gas as a significant transitional fuel source (it notes it might be cheaper to build gas pipelines rather than transmission lines in some cases). And it also looks at how to manage the inevitable growth of rooftop solar PV, and the anticipated boom in interest in electric vehicles.
While the AEMO takes a more conservative approach that Bell and Johnston, the report has recognised the potential of new technologies such as solar PV and EVs to alter demand and network spending patterns. On PV, the report said it has the potential to moderate peak demand; and it’s not just the number of electrons that are produced by the panels and at what time (subject to considerable debate among readers of this web site), it is because the owners of solar PV and other “own-use” generation are showing significant changes to their own consumption patterns.
The study found that the scale of small-scale solar over the next 20 years would result in a significant contribution to energy produced, particularly on clear days, and the combination of rooftop solar PV and owners matching their consumption with their output would also help reduce maximum demand, to the point where network investment could be delayed, especially in those areas with high PV uptake. However, it did not look at storage, a key component of the Bell/Johnston analysis.
The study also looked at a scenario where there was a high level of EV uptake in a city such as Sydney to learn the potential impact on the grid, particularly at peak times. In winter, because the peak is later, when people would presumably plug in their cars and their heaters at the same time when they got home, the impact was more dramatic. But in both cases, where 50 per cent of the EVs had controlled charging schemes – plugging in at 11pm or 2am – the impact was much reduced.
The findings underscored the need to have incentives to encourage customers to charge the cars at certain times, to impose standards for charging points to do the same, and the ability for remote control of charging points. And the report also recognised the potential to use plug-in vehicles as a source of power during those demand peaks and actually reduce network loading at peak times. This technology (sometimes referred to as vehicle-to-grid) is still in the early stages of development, the report finds, but it has the potential to provide more dynamic demand and supply characteristics.