Network Service Providers (NSPs) operate in a regulated environment which sets a maximum limit on financial returns. However, the regulatory environment does not guarantee that firms will earn the regulated maximum or that they will recover the full value of any investment made.
This article argues that a combination of rapidly changing technology and changing consumer preferences – beyond the control of existing electricity market participants – have the potential to fundamentally alter the operating environment faced by NSPs. This will increasingly expose them to market risk, due to the need to respond to stagnating or declining demand, potentially undermining the market value of network assets.
This issue is compounded by the rapid increase in delivered energy prices which the Australian Energy Market Commission (AEMC) has forecast to reach an average of $300/MWh in 2013 and the associated likely incentive for retail customers to reduce energy consumption and consider off-grid energy solutions.
Electricity markets in Australia
Deregulated electricity markets in Australia and other developed countries, are primarily based around separating the monopoly elements (transmission and distribution assets, and NSPs) and contestable elements (market generators and electricity retailers) of the electricity supply chain. Monopoly elements are subject to price regulation, while contestable elements are priced using market mechanisms. In the eastern states, National Electricity Market (NEM) market participation is generally limited to larger businesses – for example, generators wishing to participate in the NEM as scheduled generators must be at least 5MW and generally only 30MW, and greater capacity generators are required to register with the NEM (with limited exceptions).
The impact is that the NEM generally focuses on the supply side with some limited demand side participation via load shedding. This failure to fully reflect possible demand side responses, which in themselves may encompass small-scale embedded generation, creates significant uncertainty for current and future investment in regulated assets. The recently released draft AEMC Report ‘The Power of Choice’ is a welcome addition to the landscape as it explores ways to enable demand side participation in the NEM.
Regulation of NSPs
The historic view of investment in regulated network assets, such as transmission and distribution networks, is that they have generally been secure investments offering a regulated rate of return on, and of, invested capital – reflecting the regulators’ (and not necessarily investors’) view of the risk weighted required rate of return on capital and appropriate period over which the return of capital will occur. This has been termed the regulatory compact between investors and regulators – that is, investment in long-life assets with monopoly characteristics will be subject to economic regulation limiting the maximum returns that can be earned but also reflecting the fact that regulators will not arbitrarily, or without fair compensation, reduce the value of the investment.
The reality of the regulatory compact is that economic regulation has never been intended to guarantee that investors will fully capture the regulated return on and of investment; but rather, provide the opportunity for investors in regulated assets to recover up to, but no greater than, that amount. The actual return earned will therefore be the lesser of: the regulated or market returns (determined by users’ willingness and ability to pay); and the willingness to pay for continued access to services provided by the assets.
NSP Asset Value Risk
At issue is the extent to which an investor can reasonably expect to achieve future revenues with a net present value equivalent to funds invested in regulated assets; given emerging technological trends (promising viable off-grid energy solutions) together with behavioural changes (such as environmental awareness), and sovereign risk of government-driven rule changes aimed at reducing prices.
The magnitude of the capital, at least partially at risk, is related to the existing regulated asset values determined by the Australian Energy Regulator (AER) together with forecast levels of capital expenditure. The Productivity Commission estimated the total asset value of the NEM network at around $60 billion in 2010, with an expected five-year investment program of more than $40 billion – or two-thirds of the existing regulated asset base value.
The price impact associated with the expected dramatic continued investment in network assets can be seen in forecasts for increased electricity prices. For 2013, average national delivered energy cost is forecast to be $300/MWh – an increase of over 37% in nominal terms compared to 2010 prices. Of this, around two-thirds is effectively a fixed, non-energy cost.
This is in contrast to the pricing structures used for residential and small commercial customers which are relatively heavily reliant on variable (energy) charges for revenue recovery rather than fixed (service) charges. For example, residential customer service charges are generally significantly less than $1 per day. Using the AEMC 2010/11 average electricity price of $224/MWh and an average consumption of 8MWh per annum, suggests an average annual bill of just under $1,800. A service charge of $0.75/day would imply a fixed cost per annum of $274 or around 15% of the average bill – well under the two-thirds that would be suggested by analysis of the actual fixed and variable shares of costs. In order for the service charge to reflect the fixed cost share, it would need to increase over 400% to around $3.24/day.
Further, recent reviews of retail pricing (such as that undertaken by the Queensland Competition Authority (QCA)) have recommended adopting inclining block tariffs whereby unit electricity prices increase with consumption, thereby providing incentives to reduce consumption. While such tariff structures may provide an incentive to reduce consumption (and signal the economic cost of expansion to satisfy increasing peak demand), given the high fixed cost component of total electricity costs, they are unlikely to be cost reflective. Once the fixed cost component is recovered, prices should ideally reflect marginal cost which, in the first instance, will be directly correlated with time of use (peak power being more expensive) rather than total energy consumed.
Further, if inclining block tariffs are successful at reducing electricity demand, they will potentially result in under recovery of fixed costs and the need to increase prices in a self-reinforcing cycle. In a commercial sense, this could cause a classic death spiral as steadily increasing prices reduce demand, and require yet higher prices until the service is completely priced out of the market.
Options to reduce energy bills and go off-grid
Grid-connected electricity is often seen as an essential service where consumers have no choice but to utilise it. However, it is the energy used to power equipment that consumers require – this does not necessarily require connection to the grid, nor does it require the level of energy delivered over the grid.
A rapidly emerging option is solar PV (photo voltaic). Figure 1 shows the current levelised cost of energy (LCOE) for solar PV in Australia is approximately US$200/MWh. The graph suggests prices for solar PV panels will continue to fall as manufactures reap benefits of scale and learning, and technical efficiency improvements, predicting an Australian LCOE of $150MWh in 2015.
Figure 1: Residential PV price parity (size of bubbles refers to market size) (BNEF, 2012a). Note: LCOE based on 6% weighted average cost of capital, 0.7% /year module degradation, 1% capex as O&M annually, $3.01/W capex assumed for 2012, $2.00/W for 2015.
Even with the absence of feed-in tariffs, a LCOE of US$200/MWh is below current average residential electricity prices in the NEM, providing a real opportunity to lower electricity bills especially when combined with energy efficient lighting, white goods, heating/cooling and better insulated and designed dwelling units.
Current electricity pricing structures with relatively low connection fees provide the option for households to use the grid service as a backup to own generation using solar PV panels. However, were solar PV panels to become ubiquitous with households relying on the grid for backup supply at night and to cover peak demand, a change in pricing structure with greater reliance on fixed charges may be adopted. This in turn could lead to greater reliance on off-grid electricity supply options. Figure 2 outlines one possible off-grid solution which could currently be implemented requiring relatively limited changes in electricity use patterns.
Figure 2: possible off-grid solution which could currently be implemented
The above option is unlikely to be attractive to the majority of grid-connected customers. However, with expected declining costs for solar PV and rapid technological gains (e.g. energy saving, transport and small-scale generation), there may be emerging opportunities for entrepreneurs to deliver integrated off-grid solutions to either individual households or groups of households.
A logical initial target for such services would be low-rise unit developments. These have sufficient roof areas to support significant solar PV arrays; separate metered services to provide diversified usage benefits; and a single point of contact in the body corporate members to make negotiating a deal relatively simple. See Figure 3.
Figure 3: possible option for low-rise unit developments
The future market behaviour of electricity consumers will depend on the outworking of currently emerging factors including increasing environmental awareness, price sensitivity and technological changes often at a consumer level rather than at a large-scale industrial level.
Impact on NSPs
It is easy to respond to the risk of dwindling demand by offering price discounts to maximise revenue (or at least minimise the loss of revenue). Realistically, any such discount will need to be provided by network businesses. The contestable elements of the market are expected to already be at, or close to, marginal cost and therefore unable to offer significant discounts without some fundamental change in their underlying cost structure.
Conversely, network operators have long-life assets whereby regulated price reflects the long-run cost of providing the service with the in-situ assets. This provides them with the ability to offer discounts without risking the continued provision of services although, where revenues are expected to be below the long-run cost of supply, some new investments are unlikely to occur.
The magnitude of discount required for retail customers can be estimated from the above discussion of the LCOE for new solar PV installations (noting that other technological changes may have just as great an impact). Assuming a LCOE of $200MWh in 2013 for solar PV compared to the AEMC estimated cost of $300MWh for grid-delivered electricity, suggests that a discount of up to $100MWh could be required (although less than this would be expected with the actual discount depending on the negotiating power of the parties and the consumer’s reasons for installing the solar PV arrays, e.g. to go off-grid or to take advantage of grid-delivered electricity’s continued low connection fees). Figure 4 shows the breakup of the $300MWh 2013 electricity price by cost category.
Figure 4: breakup of the $300MWh 2013 electricity price by cost category
The total transmission and distribution charges within the $300MWh forecast, 2013 electricity price for retail customers is only around $133MWh. Any pressure to provide major discounts to the retail customer group would materially impact on network revenues and could lead to the need for a significant asset impairment adjustment to the carrying value of assets for accounting purposes.
In the longer term, if assets are oversized for the future expected demand, there could also be pressure to optimise the regulatory asset base to ensure it reflects the expected demand for services.
NSP demand mitigation strategies
In order to mitigate the loss of value associated with future reductions in demand for network services, NSPs could:
- Assess their short-term capital expenditure and categorise into: ‘necessary replacement’; or ‘expansion’ to meet emerging base demand and peak demand. It is essential to critically assess capital expenditure drivers such as reliability standards and identify savings in all categories with particular focus on peak demand capital expenditure.
- Develop long-term engagement plans with stakeholders, identifying asset underutilisation risk and plan for action – leading to more flexible pricing structures and service offerings based on different standards, discounts, discriminatory pricing.
- Change pricing structures over time to reflect emerging market conditions and understand key stakeholders such as regulators (should direct price regulation remain a requirement in the future).
- Enhance service offerings – which requires sophisticated connection assets capable of differentiating customers (e.g. turning off a particular customer or a customer’s circuit or, separating essential and non-essential supply). Utilise smart metering and other technology and communications frameworks, and their resulting information, to develop service offerings to meet demand. Work with retailers to resolve possible tension over risk management of energy supply and ensure an optimum outcome for both parties.
- Introduce new services and go beyond the meter to ensure incentive to remain connected to the grid and thereby support value of assets. Aim to make users value grid connection sufficiently highly to pay a price as close as possible to the regulated price. Beyond-the-meter services also offer the potential to maximise the average utilisation of the network while minimising peak demand on network.
- Expand electricity distribution and transmission services in the long term to include all energy sources. NSPs may no longer be regulated as access prices will be limited by presence of close substitutes.
Where to from here?
The above discussion highlights that technological and demand changes beyond the control of existing electricity market participants have the potential to fundamentally alter the operating environment faced by NSPs. These changes may expose the supply side of the NEM to stagnating or declining demand.
Strategically, the most important thing for NSPs is to take a long-term view recognising the ongoing changes they face. Preservation of business value will require NSPs to be proactive in managing stakeholders and being open to providing services beyond the meter to ensure the continued relevance of network connection services.
 Productivity Commission Electricity Regulation Review 2012, p8
 AEMC, Possible Future Retail Electricity Price Movements: 1 July 2011 to 30 June 2014, Final Report, 25 November 2011, p20
 Reconsidering the Economics of Photovoltaic Power, M. Bazilian et al. Bloomberg New Energy Finance, 2012, p13
 AEMC, Possible Future Retail Electricity Price Movements: 1 July 2011 to 30 June 2014, Final Report, 25 November 2011 pg 18
 AEMC, Possible Future Retail Electricity Price Movements: 1 July 2011 to 30 June 2014, Final Report, 25 November 2011 pg 18