Issue 184, August 2020
In one respect, so far, so good. Six months in to the full onset of the plague (aka Covid-19), the electricity and gas industry has been able to keep supply flowing without any untoward events (other than storms whacking community power lines). For the electricity sector on the east coast, in the largest demand region (New South Wales and Queensland account for almost two-thirds of NEM dispatch to the grid), the epidemic’s impact has resulted in usage falls in the two States of between three and five per cent and contributed to the market’s overall wholesale prices dropping to their lowest levels since 2015. Despite this, the end-user bad debt issue has retailers spooked. Meanwhile efforts to make the NEM fit for future purpose meander on, now led by a ministerial committee of the so-called National Cabinet, the CoAG Energy Council having being dropped. Somehow, the new committee has managed to turn agreeing to have the Energy Security Board continue its task of considering the redesign of the NEM in to a political mystery. More importantly, perhaps, the energy market operator’s latest grand plan for the green future of the NEM has now been published. The extent to which it can be adequately debated by national leaders in an environment overwhelmed by the health and economic challenges of the pandemic is a serious question. As well, the latest stage in the long-drawn out row about gas development in NSW rambles on against a backdrop of warnings that the southern States may face shortages by winter 2024.
“If approved, the Narrabri project would provide reliable, affordable, clean energy to support the one million homes, 33,000 businesses and 300,000 jobs in NSW that rely on natural gas” – Kevin Gallagher, CEO, Santos.
“The Narrabri project, if approved, represents an enormous opportunity for the region” – Australian Workers Union national secretary Daniel Walton, pointing to 200,000 people out of work in NSW as a result of the pandemic.
“Narrabri gas can’t come soon enough for NSW as we risk shortages in the medium and long term” – James Simonian, executive director gas wholesaler Weston Energy.
“The department has found it difficult to reconcile significant community concerns about Narrabri gas project with technical advice from experts” – David Kitto, director special projects, NSW Department of Planning.
“The fossil fuel industry cannot continue to expand. Allowing any new gas development is at odds with protecting Australians from the impacts of climate change; we must hasten the transition to renewable energy” – Climate Council’s Will Steffen.
“As Australia recovers from Covid-19, low gas prices will provide many growth opportunities ranging from manufacturers being able to create more jobs and Aussie-made goods to encouraging more gas generation to provide the firming needed to support significant growth in renewable energy investment” – federal Minister for Energy Angus Taylor.
As if our times are not strange enough, the defrocked CoAG Energy Council, now a committee of the federation’s National Cabinet formed to deal with the Covid-19 emergency, has managed to turn the apparently simple task of agreeing to let the Energy Security Board get on with its work on the redesign of the National Energy Market in to a media-fascinating mystery cloaked by “cabinet in confidence” secrecy.
The future of the ESB, whether its chair, Kerry Schott, will continue in her role and even when next ministerial the energy committee will meet were all late July topics for media speculation.
The initial three-year term for the ESB has ended and federal Energy Minister Angus Taylor has told journalists via a spokesman that the committee will meet again “shortly” to reach a decision on its future. The spokesman acknowledged the market design work is “highly important.”
Research undertaken for the Australian Energy Commission prior to the advent of the pandemic showed energy customer satisfaction had reached a four-year high.
In its new review of energy retail competition, published in mid-year, the AEMC found that the downside to this picture is that, when it comes to value for money, electricity and gas is still rated lower by householders and small business than services from other utilities such as water and telecommunications. Despite this, more than half power customers said they are satisfied with the value of their service and more than two-thirds of gas users rated their service as value-for-money.
“Customers clearly think there is still room for improvement,” says the commission CEO, Benn Barr. “We know the landscape has shifted since Covid-19, but these figures show things were improving in the market, with innovation still happening and the number of (supply) competitors continuing to increase.”
Three new electricity companies entered the market in 2019 and by March this year there were 35 retail businesses in the NEM.
The commission found, however, than customer switching rates have fallen to a three-year low of 19 per cent. “Lower rates,” says Barr, “could mean customers are more satisfied but could also mean there are fewer incentives to shop around.”
Analysis by the Australian Energy Market Operator shows that gas usage has remained steady throughout the shutdowns caused by the Covid-19 pandemic – and there are indications that the decline in global demand has led to a short-term fall in local prices.
AEMO says the pandemic-caused decline in Australian business demand for gas appears to have been offset by the winter’s rise in residential demand from large numbers of people staying home.
However, the market operator is not stepping back from its pre-pandemic forecasts of a tight supply/demand balance on the east coast from the mid-Twenties as offshore Victorian gas production falls away, contributing to an increase in wholesale prices over the next 3-5 years. In its latest planning paper, AEMO forecasts a 35 per cent fall in southern supply from existing and committed gasfields over the next five years.
AEMO says that stakeholders interviewed as part of its latest analysis are “firmly of the view that additional (southern market) gas supply and more participants are required to drive liquidity in the next two years.”
The operator also reports that the pandemic shutdowns have had only a “modest” impact on NEM electricity demand in the second quarter of 2020 – operational demand across the market averaged a two per cent fall when measured against the same period of 2019.
There were large reductions in commercial usage, AEMO says, and large rises in residential requirements. There was also a rise in the estimated use of rooftop solar PVs. The largest business demand reductions were in Queensland and NSW.
When the estimated use of rooftop solar is not included, coal-fired generation continued to provide by far the bulk of power supply to the Covid-constrained NEM in the 30 days from the end of June.
Data published on the Open NEM website record power sent to the east coast grid in the period from 30 June was 16,917 gigawatt hours – with black and brown coal plants delivering 69.3 per cent of supply (8,933 GWh of black coal production and 2,790 GWh from brown coal units).
Open NEM shows that supply in this time from gas-fired units was 1,882 GWh (11.1 per cent), hydro 1,492 GWh (8.8 per cent) and wind farms 1,403 GWh (8.3 per cent). Utility-scale solar farms provided 397 GWh while the estimated use of rooftop PVs was 694 GWh. (Rooftop solar generation is not traded through the NEM mechanism.)
Overall data for the market mask the importance of coal in the three States that make up most of its demand/supply: Victoria, NSW and Queensland.
In the 30-day period, black coal generation provided 88 per cent of power sent to the NSW grid by in-State plants – with black coal units in Queensland sending their State grid 75.9 per cent of its power. In Victoria, brown coal units provided 72.3 per cent of the State’s power production. These three States delivered 86 per cent of the NEM’s grid-connected power production in the 30 days.
Energy Security Board chair Kerry Schott has warned that the east coast’s coal-fired generation businesses are “working on very tight margins” with falling wholesale power prices making some plants uneconomic.
Schott, speaking at a Clean Energy Council webinar panel discussion in July, said the problem for coal generators is “fundamentally one of economics” as the advent of more renewable energy in the NEM results in their units being run for a smaller number of hours a day. She added: “They are heading in to quite commercially difficult territory.”
She flagged that closure of more coal-burning operations posed a problem for the market. “It’s more of a new entry problem rather than a coal closure problem. How do we get the essential services we need and the capacity we need as they go?”
AGL is spending a billion dollars a year on maintenance for its generators fired by coal and gas, its chief executive, Brett Redman says.
In a briefing on the company’s plans to pursue a target of net-zero emissions by 2050, Redman also committed to keeping the 2,225 megawatt Loy Yang A power station in Victoria operating until its scheduled closure date of 2048 – and the 2,640 MW Bayswater plant in the Hunter Valley until 2035.
“Loy Yang is more or less the lowest cost source of energy in the (east coast power) market today and this means, I think, that it’s got decades to go providing the stability that is baseload generation,” he told journalists, adding that the company has not changed its basic plan, announced by his predecessor, to run coal-fired plants to the end of their economic lives.
Queensland Natural Resources, Mines & Energy Minister Anthony Lynham claims that his government’s progress on the State’s transition to renewable power “is nothing short of remarkable.”
Lynham says that since 2015 there have been 39 large-scale renewable projects starting operations or committed for development. They represent $6.6 billion in capital costs.
However, when he talks about 20 per cent of Queensland’s electricity supply being provided by renewable energy by the year’s end, he is referring to capacity, not production. In the 12 months to the end of July, during which power despatched to the grid by the State’s generators totalled almost 59,500 gigawatt hours, less than 4,000 GWh came from wind and solar farms. (Another 4,200 GWh was estimated use of rooftop solar PV).
Meanwhile, the Australian Energy Market Operator issued a notice at the end of July warning nine solar farm projects in North Queensland, with some 1,000 MW capacity, that their output could be cut to zero on occasions because of grid strength issues.
The Clean Energy Council says that the problem needs to be addressed quickly, declaring it will “render planning and investment in the region harder and less likely.”
Federal Energy Minister Angus Taylor is waving a new report from the Australian Energy Market Operator to draw attention to what should be good news for east coast households and businesses:
“Energy prices reached their lowest levels in five years during the second quarter of 2020.”
At the same time he is pushing energy retailers to ensure that falling costs are “adequately” reflected in their bills. “It is their responsibility to pass on savings,” he says.
For electricity, Taylor says, AEMO analysis shows that NEM wholesale electricity prices were between 48 and 68 per cent lower in the past quarter than in the same period 2019. He attributes this to lower gas and coal prices and new renewable energy supply.
“With wholesale costs making up around a third of residential electricity bills and far more for industry, these price falls are expected to provide relief for families and businesses.”
(The Australian Energy Regulator records that the first quarter of 2020 marked the first time since 2015 that wholesale electricity prices fell below $110 per megawatt hour in all east coast regions.)
In media interviews, Taylor acknowledged that many residential customers, nonetheless, are seeing their bills rise, pointing to large numbers spending more time at home because of the pandemic and to increased use of energy for heating as the situation is occurring in winter. He is also urging householders to shop around for the best-cost bill plans, noting that, in NSW, best-deal prices are now $600 a year lower than a year ago.
The Australian Energy Council, representing retailers, says they are “passing on as many savings as they can” but they are also currently dealing with higher network charges.
AER chair Clare Savage comments that it is “vital energy companies remember their social obligations at a time like this.”
As the pandemic appears to move in to its second phase, the energy retail sector is expressing concern that it may be left to “carry the can” for the whole supply chain in dealing with stressed customers.
“Retailers cannot control costs from other parts of energy supply,” the Australian Energy Council said in a statement at the end of July. “We need a collaborative response from all parties to find ways to share costs and avoid the risk of future financial contagion among retailers.”
This concern is reinforced in the annual review of retail energy competition by the Australian Energy Market Commission. AEMC says retailers are telling it they expect their bad debts to double as one of the consequences of Covid-19’s impacts. The commission is concerned about the “over-arching position” of the retail sector – and it sees the need for new measures to prevent consumer energy bills “blowing out” if their retail supplier goes out of business.
The AEMC’s chief executive, Benn Barr, says the risk of a retailer failing is now greater due to the extra-ordinary economic pressure the sector faces as a result of the pandemic.
The best-case scenario, Barr adds, is to avoid multiple retail failures altogether “because that would take us back a decade to when customers had the option of only a handful of large players.”
Some retailers have told the commission they expect their level of bad debts to double – and a relatively small rise in non-paying users could quickly put smaller retailers in a position where they can’t meet their own bills.
Barr notes that retailer profit margins have fallen by a third since 2017-18 and says this may have placed some in a less secure financial position when the pandemic struck.
In a commentary published at the end of July, the Australian Energy Council says that retailers are playing a key role in both the economic crisis “likely to impact for years to come” and the health crisis, “for which access to energy at a household level is vital.”
AEC declares there is an “emerging and growing challenge” in management of the number of customers faced by payment problems and the increased debt levels retailers are being called on to bear.
“Retailers have limited scope to recover costs,” the lobbying group argues, pointing out that they carry all the risk of non-payment of bills and of cash flow issues.
The current moratorium on discontinuing supply for non-payment will “have significant flow-on impacts” on retailers, it says, “and this risk cannot be under-estimated.”
It adds that the smallest retailers in the market “may face existential challenges.”
In the longer term, AEC suggests, there may need to be a rethink about “what is the most efficient means of delivering electricity to customers and where the risks of (consumer) non-payment should lie.”
The Australian Energy Regulator says network distributors are progressively making their tariffs more cost reflective, a step it praises for “incentivizing energy customers to switch usage away from times of high demand” to non-peak periods and to “operate distributed energy resources in ways that minimize network stress.”
The AER says network businesses have told it they expect more than half of customers in NSW, Tasmania, the ACT and the Northern Territory will be on cost-reflective tariffs by 2024-25.
In its annual “state of the market” report, the regulator comments that pricing reform has progressed slowly, with most DBs initially adopting “opt in” models for transferring customers to cost-reflective tariffs and more recently starting to require them to “opt out” of new regimes.
AER adds that the limited penetration of smart meters in the residential and small business markets is also limiting uptake of new tariffs. Penetration in Victoria, where it was controversially forced by the State government, is 96 per cent – but in NSW it is 34 per cent and only 10 to 15 per cent elsewhere in the NEM.
After a decade of being incentivized through feed-in tariffs, households selling electricity from rooftop solar arrays to the power system may face paying a fee to continue doing so.
The stalking horse for the change, which has unsurprisingly caused ire in the green power activist corner, is an application by SA Power Networks to the Australian Energy Market Commission for a rule change. The distribution business argues the present FiT arrangement is seeing pressure being placed on the grid because of voltage issues.
SA Power Networks claims the fee would be between $10 and $30 a year.
The proposal is supported by the St Vincent de Paul Society and the Australian Council of Social Services.
The Victorian branch of the Construction, Forestry, Maritime, Mining & Energy Union says it is concerned by an approach using only non-dispatchable renewable sources, supplemented by hydro power and battery storage, for the State’s energy transition. It declares that this “will lead to major blackouts, unaffordable electricity and the future shutdown of Victoria’s industry, resulting in massive job losses.”
The branch’s secretary, Geoff Dyke, has contributed a paper to the Energy Policy Institute’s 2020 public policy series in which the union calls for Victoria’s ban on nuclear energy to be lifted “to allow sufficient time to replace existing generation with reactors.”
Dyke writes that energy decisions for Victoria need to be made with system reliability, State economic viability and Victorian jobs in mind as the government pursues the “very challenging” target of net zero greenhouse gas emissions by 2050.
He says the CFMMEU’s preferred option for the Latrobe Valley is to see high efficiency, low emissions generation with 100 per cent carbon capture and storage replace the existing fleet of brown coal power units. HELE plus CCS technology would become the more viable, he adds, if a major brown coal-based hydrogen industry were to be established in Gippsland “adjacent to Australia’s best carbon sink in Bass Strait,” also further benefitting the State economy by enabling more offshore gas and oil production.
With respect to nuclear energy, he says his branch believes a “just transition” of Gippsland’s workers towards modern technology is “realistically achievable” while this is not the case with renewables. It will be “sheer madness” not to include nuclear power in the State’s energy mix, Dyke adds.
Opinion polling undertaken by JWS Research for the Minerals Council of Australia – in preparation for a pro-nuclear information campaign – shows that 40 per cent of respondents support use of the technology in electricity supply with 29 per cent neutral or unsure.
JWS is reported by the Australian Financial Review to have told the MCA that support could rise to 55 per cent if the community has better information about safety issues and the reliability of nuclear power and its zero-emissions credentials are promoted.
Perhaps the most fundamental question to be asked about the NEM now is whether it is still a market as conceived in the 1990s?
The endless talk of the “transition” skips lightly over this point, something not missed in some business quarters – where there is fretting that the costs to consumers (especially large ones) may play second fiddle to the yearning to pursue climate change concerns through increasing government intervention.
The new iteration of the Australian Energy Market Operator’s “integrated system plan” – the first one appeared in 2018 – has been mainly greeted in the media with attention to a shift away from fossil fuels in the NEM but it also drew rumblings from the Energy Users Association of Australia about cost burdens, centred it appears on “more gold-plating” of network systems.
The association, which represents some 100 large commercial and industrial users of electricity and gas, also warns that the operator’s scenarios “should not be seen as an automatic green light” for preferred power investment, adding that what it canvasses is “not without risk with significant changes in technologies and usage patters still to full play out.”
It was notable that federal Energy Minister Angus Taylor, in a media statement about the AEMO publication, felt the need for cautionary words about transmission.
“Any investment in the grid must make economic sense,” Taylor said. “It is critical to avoid over-investment and ‘gold-plating’ of the network because it is consumers who have to pay for this as part of their electricity bills.”
It made political sense for Taylor to cast this thought in terms of householders but his comment that “the last thing we want to is burden them with unnecessary costs” can’t have been made without his government’s appreciation that not getting the large commercial and industrial sector back to “normal” comes with ongoing employment problems and ongoing welfare costs for a stressed federal budget.
Multinational business, of course, is now wrestling – here, in Europe and in North America – with its need to be seen to be much more environmentally aware and pro-active (hence the growing embracement of net-zero by 2050 corporate plans), so it is not going to talk down a major lunge in the NEM towards variable renewable energy backed by pumped hydro and large-scale investment in battery storage.
Contrary to some media headlines – for example “New grid report forecasts rapid transition away from coal-fired power” and “Coal power plants face early retirement in a 20-year grid revamp” as well as, most egregiously, “AEMO’s nail in coal’s coffin” in Australia’s foremost financial newspaper” – the ISP (one more addition to the energy alphabet soup) actually underscores the need to move carefully.
AEMO chief executive Audrey Zibelman told The Australian newspaper: “There is a risk of coal units retiring early. The challenge is how do we manage the exit of older units so we don’t see price volatility and encourage new investments to avoid scarcity and provide consumers with an affordable price of energy.”
As her magnum opus makes clear (on careful reading), a well-organized transition will see 26,000 megawatts of wind and solar farms needing to be developed by 2040 to replace 15,000 MW of coal generation being retired at the end of their working lives (starting with Liddell in the Hunter Valley in 2022-23). Going much faster down this path would require 50,000 MW of wind and solar farms developed in a global investment environment that, for at least the next decade, is going to be difficult, to say the least.
Ensuring that there is a substantial amount of dispatchable generation in the mix – to sustain the reliability and security of the grid – will also require investment in gas-fired generation, and the southern States’ gas problems are well known.
Whether from late in the ‘Twenties and through the ‘Thirties nuclear power could play a role in the transition is anyone’s guess and it is not something Zibelman & Co at AEMO are contemplating (in fairness because this route is banned by legislation at present).
What exercises the likes of EUAA and others is whether or not the big ticket transition projects – Snowy 2.0, the new links from Tasmania to Victoria and so on – can be developed as currently budgetted? Our recent history of very large infrastructure projects of all kinds suggests not.
One of my friends wise in these matters declares that what we are dealing with in the case of the ISP is “a megaproject of megaprojects” and, he asserts, most megaprojects come home at about two to 2.5 times their original cost estimates.
This thought seems to be borne out by numbers for the interconnector between South Australia and Victoria now being fast-tracked: it was budgeted at $1.5 billion when first mooted and is now reportedly being considered to cost as much as $2 billion or even more.
There is a line in the Australian Energy Regulator’s new “State of the Energy Market” report that I think hits home in considering all this. “If well managed, the transition can deliver significant benefits,” it says.
And AEMO itself has a caveat tucked away in its “roadmap” report – “If planning and investment occurs in an unco-ordinated manner or is done inefficiently, customers and investors will experience the risk and cost of excess investment.”
30 July 2020