What was different a decade ago for the energy markets in Australia?

Jim Snow   |   20th December 2018

Jim Snow, Executive Director Oakley Greenwood & Adjunct Professor University of Queensland Energy Initiative

As Oakley Greenwood clocks up 10 years of operations I thought it may be very interesting to:

• See what issues of concern were being discussed in the industry conferences of 2008 and early 2009 – especially focused on papers that were looking forward while also documenting the fundamental changes occurring, and again what these may mean for the industry, and
• Look at what projects OGW was undertaking in terms of providing expert advice.

As the Right Honourable Kevin Rudd was mid term in his first stint as Prime Minister and the Global Financial Crisis was in full swing, the market and the political scene was eyeing off Labor’s impending Carbon Pollution Reduction Scheme (CPRS), an expanded Renewable Energy Target (MRET) and COAG’s proposed National Strategy and legislation on Energy Efficiency.

The AEMC under the chairmanship of Dr John Tamblyn had just released its Scoping Paper for comment – Review of Energy Market Frameworks in light of Climate Change Policies (October 2008).  This paper dealt in length with risks associated with the increased incorporation of new intermittent generation sources into the NEM.

The Energy Networks Association, while battling away with the first 5-year review of the WACC by the AER (Issue paper released August 2008) under the chairmanship of Steve Edwell, noted in their submission to the AEMC one of the key risks from the CPRS was:

 “…the reliability risk with some associated energy sources, and the willingness of investors to commit to developments under the CPRS and MRET”.

They raised the issue of increases to energy prices and their flow-on effects, and the impacts of the growth in embedded generation (“EG” was the terminology of the day):

“With growth in EG in the distribution network there will be a requirement to have increased monitoring and flexibility in network configuration due to changing generation patterns. This will require increased use of monitoring, line regulators and remote switching equipment and in increased complexity in both planning and operating the network. ENA believes that there is a material risk of a reduction in reliability should a significant portion of additional generation requirement come from intermittent sources such as wind and solar power.”

In terms of AER outcomes, the electricity networks were about to enter a period of major regulated revenue increases that saw electricity prices rise markedly while household consumption fell in response. There was a large increase in spending on electricity infrastructure renewal of aging assets, and forced increases in reliability settings in some networks.

The industry was about to experience a price elasticity effect – something OGW was deeply involved with at the time as advocates that elasticity effects would indeed develop and there was a need for pricing reforms – we delivered a detailed paper in 2013 on these issues – Network Pricing Under a Revenue Cap.

And the AER would then move from a Weighted Average Price Cap form of regulation – where the networks would have to effectively manage price elasticity effects and associated volume losses – to a Revenue Cap form of regulation, effectively transferring the loss of volume risk from the networks to the customers – as we noted at the time it was almost perfect timing for the networks.

And in 2008 and 2009 we had started to ring the alarm bells about the impacts of air conditioning systems on the networks and published a paper in AIE Sydney April 2009, entitled Energy Industry Carbon Challenges: What’s Ahead?,- that among other things outlined the decline in network system load factors from 2004 to 2008 due to these devices being taken up in droves.

This was based on a plethora of regulatory work for the NSW Networks (especially EnergyAustralia and Integral Energy – now Ausgrid and Endeavour Energy) as we assisted them to develop their regulatory submissions, and as they moved from the state-based Regulator IPART to the new national regulator, the AER, as their prime Regulator. Peak demand growth was outstripping the energy demand growth, which was heading into serious decline from price elasticity effects, and in that paper we suggested we may well be entering a “death spiral” – a throw-away line at the time based on some personal gas industry experience of the 1970s and 1980s – this issue was then built upon and examined in a lot more detail by other experts and eventually entered the industry lexicon. An extract from that presentation:

Demand Elasticity?

• Economics says market demand will reduce if the supply price increases
  • The basis of much of the ETS – Garnaut
• Elasticities estimates do exist for Australia (NEMMCO)
  • -0.25 for Residential, -0.38 for Business
  • 25% increase in price – 6% to 10% decrease in volume
  • EnergyAustralia forecast 65% increase………and GFC fallout
• BUT peak demand unlikely to change
  • Hence why we have a decreasing load factor
  • This inevitably drives up price and will become a major political and commercial issue (“death spiral”), and
  • Peak forecasting becomes highly uncertain
  • EVT (extreme value theory) Issue – Melbourne summer outages, Sydney?
  • High prices, falling volumes and uncertain outcomes on hot days?

And there was what I consider a landmark presentation at the time by David Swift (AEMO) at the Tenth ACCC Regulatory Conference – The Regulation of Infrastructure in a time of Transition: The Challenges of Climate Change for Energy Markets (July 2009). This was a paper that really mirrored a lot of our work, summarised the key issues of the day well and started to ask the critical strategic questions as we moved into have a CPRS and an increased MRET:

Supplying Future Demand

The NEM faces transformational change over the next decade

• the CPRS is expected to put a price on carbon which will change operating behaviour by generators
• the 20% Renewable Energy Target and complementary subsidy schemes will drive additional investment especially in the first 5 years of the RET scheme
• the rising price of carbon will progressively change generator investment and retirement decisions
• greater potential role for energy storage in the longer term; and
• a possible change in the mix of centralised vs decentralised generators

The paper made the points that renewables would have an impact on retail prices (and market price volatility) as the generation mix was expected to “change markedly” and the market had to evolve to “manage the dispatch of this different generation fleet” which at the time was postulated to include more gas-fired generation, more stochastic generation (wind and solar), and a greater percentage of embedded generation, with more inter-dependence between gas and electricity markets. OGW was flat out modelling such matters – as were many other modelling groups.

The gas references were very much supported by the anticipated impacts of both carbon pricing on costs of generation from coal and the move to far more intermittent renewable “stochastic” generation – be it in the distribution or the transmission system. The Gas Markets Leader Group was at the time also developing new initiatives such as the Short Term Trading Mechanism (STTM) – so this call was starting to be heard.  OGW was busy sourcing major gas contracts for potential new power stations and some new transmission lines – and working out the interaction that would likely occur with the NEM.

The challenge for AEMO though, as laid out in the Swift paper, was “to dispatch the energy markets and maintain security”, as there was among other things, “progressive displacement of conventional plant”.

But of great interest in this paper for me at the time, was the first major warning bells being rung regarding the relative impacts of the forecast levels of wind generation expansion in South Australia – it was riveting data/analysis indeed as we had been focused on these issues in our own consulting work. Some 700-odd MW in 2008 (1,504 MW in 2009 when the paper was written) rising to potentially 3,500 MW in 2016/2018 as the high case, and 2,400 MW as the median case (it is some 1,930 MW[1] and still being developed). The:

“Projected volatility of generation will need to be managed: – operationally to ensure security, and financially by participants”.

The rest of the paper outlined the then-recent experience in SA in terms of the volatility of wind generation in great graphical detail with accompanying calculations. In the January 2009 “heat wave” in SA, native demand was peaking at some 3,400 MW with wind peaking at some 500 MW but with very low overlaps with the demand peaks and with very high rates of change when wind did come on and off the grid.

The key point for me was that the peak days in the heat wave had very low coincident rates with wind generation – it just could not be relied upon to meet peak demand, and this confirmed to us what we had been formulating for some time:

“Statistics indicate a firm contribution to summer peak demand of 3% of rated capacity (for wind at peak demand in SA)”

Essentially most heat waves came with low winds (typical of high pressure cells) was my takeaway – and this was set to cause all sorts of issues once the implications started to become apparent as we had been actively advising at the time:  what generation would run at peak and how would system security and dispatch manage this mix, how can you have firm generation backing these intermittent renewables and what impact would this level of duplication have on costs to the NEM?

Swift went on to offer some changes that may need to occur and a remark that the “inefficiencies from the 5 minute/30 minute issue may need to be addressed”. He also explored greater dynamic use of demand-side markets (using smart meters that at the time were intended to be “rolled out in some states”), and the relative impact that embedded renewable generation would have on the NEM and distribution entities. These were issue very close to our heart as demand-side and pricing experts – pricing reform was top of the agenda. David’s paper then dedicated a whole section on network services adaptation – from multiple applications for new connections of renewable generators at transmission and distribution levels, to regulatory changes that may need to occur to ensure investments kept up with the changes – that they had the right incentives, etc. He made the observation that

“Network pricing does not allocate the costs of services to users as well as the market  – does not generally reward those who enhance transfer capability or sanction those who reduce it, Network costs will have to rise to extend the network, reduce congestion and enhance its capability in DSM and embedded generation – even greater need to maintain drive for efficient outcomes”.

And this was again the circle back to our work, focus and concerns at the time as a consultancy working with networks on their strategies, pricing and regulatory submissions. He also started to postulate that “forecast errors in demand are likely to increase as demand is more responsive” – again another key focus at the time of OGW as it was so important for network regulatory outcomes, elasticity effects, pricing reform, etc. We were also putting forward the case for forecasting reform and how this could be achieved, and that it was a classic market failure.  It was being done very poorly at the time as we observed in our review of several forecasting systems – and this remains the case despite best endeavours, although has improved a little over the course of the decade but could so easily be remedied.  The delay in improving forecasting defied logic to us – it was a key failure of the market reforms that were otherwise so insightful and effective.

The Swift paper also examined the potential impacts on Retailers’ pricing as renewable volatility grew, and as we started to see large negative prices appearing in the NEM in SA (complete with great graphical evidence). OGW was at the time making the case that it was all about Retail price structures as this was the price customers actually see, not network prices – a point that seemingly continues to elude the market reforms.

So, at the time OGW grappled with client projects focused on:

• Network regulatory issues
• Pricing and forecasting issues
• How the dispatch mix would change under a CPRS or in fact any carbon pricing system
• Demand response/DSM – this has been a constant for us since the early 1980s in fact
• Potential impairment of assets in this new market and as system load factors declined
• Where investment would come from – big cash flow generators like the major Retailers, Chinese/Asian investors?
• Arbitrage opportunities with the CPRS/NEM/MRET
• New business opportunities from the changes (and there were many),
• Gas availability (even then) – we noted that “eastern Australia has gas limitations for power generation that are becoming severe” and struggled to gain gas for some new intended gas-fired generation projects and saw our first “oil netback” prices for gas – and tried to negotiate our first “power netback” pricing structures with gas producers
• Was the CSG LNG industry financially sustainable or were the risks way to high – there was intense interest at the time from large investment houses but we were a bit sceptical about CSG delivery at those volumes at reasonable cost
• A lot of work on advanced metering infrastructure – the “National Smart Meters Program” and the cost/benefits of such infrastructure, how it should be specified (one way or two communications were a major discussion point), and would it be the holy grail for more dynamic pricing to customers and encourage or enable DR.

But, it seems that we are still grappling with many of these same issues today.  And while the momentum for a number of these changes has increased, answers and the willingness to implement changes on other  – pricing and forecasting reform, as prime examples – have languished.

But the underlying economic impact and investment issues, and overall system security matters moved to centre stage, and the price impacts were not avoided in that decade.  Politically, this and the reduction of carbon across the energy chain remain highly active and sensitive issues. Time to peer into the next decade – but that is another paper for the New Year – best of the season to you all.

Jim