Boardroom Energy
Bulletin

In this week’s bulletin:

California: The heat is on – Summer heatwaves have arrived early in California – is the power system prepared?

ARENA should be funding babies, not giantsnow wind and solar are mature, where should the agency be allowed to look for low carbon innovation to support?

EVs: maybe we need a plan? – EVs are coming to Australia, albeit slowly, so now’s the time to think about when and where we charge them.

Chart of the week: renewable certificate prices – The renewable energy target has been met (hooray!). So why aren’t certificate price collapsing as supply continues to grow?

California: the heat is on

Despite its only being early summer, extreme heat conditions have already hit parts of the USA. Northwestern areas – Northern California, Oregon and Washington are the worst impacted, with temperatures running 20-30 degrees (Fahrenheit) above normal and peaking above 100 degrees F (around 38C). As in Australia, high temperatures stresses the power system as demand spikes but supply shrinks, as electric equipment performs less well under heat. Of these California is likely to be at the most risk of outages, given its reliance on imports from its neighbours and challenges in managing the energy transition.

The national electric reliability council (NERC) highlighted the elevated risks for California in its assessment of US power grid’s readiness for summer weather. California has added some supply-side resources since the extensive blackouts last summer, but much of this is solar PV and crunch time for California is typically in early evening as solar output fades. Around 600MW of batteries and 150MW of gas have been added in the last 12 months. Up to 800MW of new battery deployments are expected to be commissioned over July and August, too. But 43MW of old gas plant has retired. Meanwhile, the 1-in-10 forecast of demand (a reasonable benchmark for peak demand in a hotter than usual summer) has increased by 2,511MW. So, this summer threatens to be even tighter than last summer. Moreover, the western US is facing drought conditions and rainfall has been below normal for two years. So a hot summer could lead to reduced hydro output, too.

Part of the problem is that having realised it had underestimated the risk of blackouts last summer, the system operator, CAISO, backed up by the regulator (CPUC), has had limited time to ensure additional resources for the current summer. Most traditional generation takes years to plan, permit and build (although the first two of those can happen in advance of financial close). Batteries have the key advantage of being deployable quickly. In principle, demand response can be procured over short timeframes, although in practice this depends on the appetite of users not already enrolled in a DR program to participate. The underwriting of new resources in any case ultimately has to come from market participants which are an especially diverse bunch. There are three large integrated utilities that can at least be regulated into procuring new resources. But they are also sitting ducks for load defection, either to competitive retailers poaching individual customers or Community Choice Aggregators (CCAs), who can take whole towns away, if enough of them vote to switch. So it’s not clear that relying on the 3 big utilities is sustainable. Plus there are a few large municipal utilities over which CPUC has limited jurisdiction.

To be fair to California, it’s not alone. A hot summer is expected across much of the country as Figure 1 below shows, and NERC has identified a few other grids at risk, though not to the same degree as California.

Figure 1: summer temperature forecasts

Source: NOAA

These include the rest of the WECC, a regional grid that includes California as well as the Pacific Northwest and Rocky mountains areas, as well as ERCOT (Texas), New England and MISO (Midwest). ERCOT of course has had massive blackouts already this year, but summer risks are very different from winter. The widespread failure of generation and fuel supply issues that caused the winter power crisis are not the problem for summer, rather it is the need to meet its growing peak demand. However, ERCOT’s reserve margins for the summer are actually higher than the previous two summers, which passed without load shedding.

Notably, the power grids that are at risk have a range of market designs. ERCOT is an energy-only market like the NEM, while New England has a centralised capacity market and California is a mix of regulated and market procurement. So, it’s evident that the challenges of running a modern electricity grid, with a transition in supply, and increasing customer reliance on electric supply, apply across all types of markets.

 

ARENA should be funding babies, not giants

The irony of Australia’s adventures into developing new renewable technologies was that the race was over before it had begun. We established agencies like the Australian Renewable Energy Agency (ARENA) to find solutions to a problem that had already been solved, we just didn’t realise that at the time.

The Senate political “coup” (or maybe a set up) by Labor and the Greens to block expanding ARENA’s funding scope to include carbon capture and storage (CCS) technologies was cast as protecting the sanctity of supporting renewable energy. This completely misses the point. Renewables don’t need to be helped by ARENA any more than CCS does.

It’s rather quaint that the current argument about the future scope of ARENA is still framed in the language of a decade ago: protecting the fragile rights of a multi-billion dollar renewable industry that doesn’t need a leg up any more.

ARENA was created in 2012 as an amalgamation of a number of emerging renewable technology funding schemes. The idea by the then Gillard Government was simple enough: to decarbonise Australia’s energy supply we needed to develop a suite of new renewable technologies.

Government support was seen as critical for early-stage research and development, provided through ARENA. Commercialisation of new technologies would then be supported by the Clean Energy Finance Corporation.

With the benefit of hindsight it was a slightly naïve approach because the two dominant renewable technologies, wind and solar PV, were already being deployed at scale and enjoying global economies of scale and sustained falls in their cost. The problem faced by any rival renewable technology, like waves power or solar thermal, is trying to catch them.

Out of necessity ARENA became creative with how it allocated its resources, supporting deployment and the lessons learned by managing high levels of intermittent generation, off grid applications, while always on the lookout for infant technologies that could support and firm renewables and provide key ancillary services. Enter batteries, pumped hydro and hydrogen. As a result the scope of ARENA is implicitly shifting, opening up the potential for supporting development of green steel and cement technologies and transport fuels.

Given this background, the idea of opening up ARENA’s scope to other non-renewables abatement technologies like carbon capture and storage, passes and fails different tests of ARENA’s role.

On one hand, as gas is going to be used to firm renewables for at least the next decade and probably beyond, decarbonising the gas supply chain through capturing and sequestering the carbon dioxide produced at well heads and even in the gas turbines is clearly a credible abatement technology.

However, CCS is not an infant technology. It’s been used by the oil and gas industry for decades, and has been the subject of extensive Government funding for most of this century including more than half a billion dollars this year. The Global CCS Institute has received $315 million from the Australian Government.

CCS can no longer pretend it’s an infant technology needing ARENA’s support. It should have the backing of multi-billion-dollar industries who should be investing in the technology to protect the value of their proven resources in a decarbonising world.

EVs: maybe we need a plan?

The trouble with electric vehicles (EVs) is that they are a double-edged sword. Continued weak sales of new EVs in Australia is disappointing, reflecting a slower than most developed economies switch to new, more sustainable and more efficient transport technology.

But it also delays concerns about how the electricity grid will cope with tens of thousands of EV owners coming home each evening and trying to charge their cars at the same time, slap bang in the middle of the evening peak in demand.

The NSW Government wants to accelerate EV uptake by waiving stamp duty on EV and hydrogen vehicles costing up to $78,000, with an additional $3,000 rebate for the first 25,000 EVs purchased at under $68,750.

Pure EV sales in Australia have been tracking around one per cent of total new car sales, compared to 8 per cent in the UK, 2.5 per cent in the US  and 4 per cent in Canada. Oh, and 47 per cent in Norway.

Australia has a few natural headwinds in the global EV market: a relatively small and remote market which has historically missed out on a number of more exotic models sold in Europe and North America; perceived range anxiety by Australian consumers even if most daily commutes fall well within the most modest EV ranges.

New EV sticker prices in Australia 2021 and comparative ICEs

EV makeEV price (car only)ICE equivalent price
MG ZS$42,175$20,260
Hyundai Ioniq$48,490$23,400
Mini Cooper SE Classic$55,650$35,150
Nissan Leaf e+$60,490$25,950
Tesla Model 3 standard$62,900
Kia Niro$64,136$23,480
BMW i3$71,900
Tesla Model 3 Performance$100,000
Jaguar ipace 400$114,515
Audi etron 50$121,325
Porsche Taycan Turbo$338,500

Source: Carsales

The EVs that are sold here come at a steep premium to their internal combustion engine (ICE) equivalent. Budget EVs start at around $42,000 plus on road costs, more than double the price tag of their ICE equivalent. Lower running costs are still struggling to overcome such a big price difference. The circa $5,000 on offer from the NSW government will help, but on its own only marginally bridge this yawning gap for consumers.

The gap shrinks for higher priced cars, which reflects the underlying reality that EVs are still primarily a luxury purchase, parked and re-charged in some of the most affluent postcodes in Australia led by Sydney’s North Shore and eastern suburbs: Vaucluse, Watsons Bay, Mosman and Bondi.

In the same way that the skewed uptake of residential solar PV into retiree and young home buyer suburbs has created big voltage problems in parts of the NEM,  a surge in EV sales resulting in demand spikes in these well-heeled neighbourhoods could create a similar but opposite problem.

Origin Energy has been collecting data from some of its residential and commercial EV customers and wants matching incentives for smart chargers to shift the EV charging load into the middle of the day when solar is abundant, or at least to later at night when demand has eased.

If sales do take off in Australia as EV enthusiasts dream about, then Origin is predicting annual EV charging demand of around 22 terawatt hours (TWh). The total demand of the NEM in a year is around 200 TWh. But cramming this new spiky load into the hour after most cars return home for the day, which is what plugging an EV into a dumb power point will do, will make already challenging evening peaks even harder to supply.

According to analysis commissioned by ARENA, this may mean more daytime charging at work places by fleet vehicles to avoid local hotspots in the streets of Vaucluse or Toorak. That means more distributed charging will be needed in workplaces and retail venues to take advantage of daytime oversupply of electricity.

That suggests a more strategic approach to EVs that is less populist and as much focussed around grid optimisation as the cars themselves. This lesson was ignored when rooftop solar PV took off a decade ago. It would be a remarkable policy own-goal to make the same mistake twice.

News Wrap

In case you haven’t noticed, there are now two quite distinct parallel debates on energy policy in Australia. One is political, the other is technical. They only accidentally have anything to do with each other.

Exhibit A is the return of Barnaby Joyce to the Nationals leadership this week. Joyce’s political success is targeted at his base in regional Australia, railing against political correctness and urban elites, flat whites and other more exotic types of coffee.

Climate change is a perfect foil for him. Joyce will make it hard for the Coalition to back a net zero target by 2050 and might well wheel back to the ridiculous pantomime of trying to build a coal fired power station in Queensland. But his political mischief has almost nothing to do with the engineering and mechanics of Australia’s energy systems. It’s as detached as the idea of a gigantic renewable power station running a 3000 kilometre undersea cable to supply Asian consumers with renewable energy, even if they haven’t asked for one. The $53 billion dream factory has now been blocked by the Federal Government on environmental grounds. Cue the outrage. Actual impact on the real world: zero.

The NSW Government is still rolling out its feel-good green programs, now offering rebates and cutting stamp duty for the bargain end of the new electric vehicle market. The EV cheapies cost up to $78,000 each. You can see the problem here. EV sales are flat because they’re still an expensive, luxury car purchase. Origin pointed out the grid problems created by a hot EV market powered by un-smart chargers. Kind of like the grid problems created by a hot rooftop solar PV market and dumb inverters.

Still on the political track and the Federal Government’s attempt to expand ARENA’s funding scope was blocked by Labor and the Greens in the Senate on the basis that CCS isn’t renewable. How very dare they. Maybe the bigger problem is that CCS isn’t very infant, and if gas companies want to cut their emissions, they should pay for it themselves. Politics at 100, impact at zero.

In the real world of the electricity market, the Australian Energy Regulator is getting stroppy at generators who are using various bidding strategies to push up chronically low wholesale electricity prices so they don’t go broke. Don’t they know there is an election looming?

Chart of the week – renewable certificate prices

The Clean Energy Regulator (CER) belatedly published its quarterly carbon market report for Q1 this week. This report covers demand, supply and prices for a range of environmental certificates. One interesting area is the price for large scale renewable energy certificates (LGCs). Last week, the  CER formally declared the renewable energy target had been met. The target, which was set in 2009 and tweaked after a protracted review in 2015 was to deliver 33,000GWh of electricity in 2020 from new renewable generators (i.e. excluding the mature Snowy and Tasmania hydro schemes). The target which converts to a liability for retailers and some large users to procure LGCs each year, now plateaus until 2030 – this gives the last generators built to meet the target 10 years’ worth of certificate “earnings”. Meanwhile, the ongoing boom in renewables – even if it is stuttering a little so far this year – means that the CER expects supply of certificates to top 40,000 this year and continue to grow thereafter.

It seems straightforward economics that with demand fixed and supply growing that the price would quickly collapse and head towards zero. This hasn’t quite worked out as chart 1 below shows. Early expectations for low prices for compliance years post 2020 have been superseded by rising forecasts, converging on the $30-$40/MWh range. There are a couple of reasons for this.

As chart 2 shows, the latest prices are still well below spot prices for 2015-2018. Over this period, LGCs traded close to their effective cap, determined by the value of the shortfall charge. This wasn’t especially relevant to large retailers who could underwrite whole projects to meet their liability and didn’t need to rely on the spot market except to tweak their positions. Several small and second-tier retailers however chose to pay the shortfall charge instead. They are now reversing their positions as they can either buy cheaper spot or found it became worth their while to write a PPA and cover several years’ liabilities. They can surrender these cheaper LGCS and get their shortfall charge refunded within a three year limit. So, this process has effectively delayed demand into the current year and potentially next year. The CER estimates 3.4m LGCs will be used in this way in 2021. With future prices forecast to be cheaper than the current price there remains an incentive to continue this approach, so this phenomenon may take a few years to unwind. Meanwhile some large retailers have been badly burned due to having to pay a high price to underwrite early renewables projects and have endured major write-downs.

The other reason is that demand is also being increased over and above what’s required by retailers for compliance through voluntary surrender. This is where governments and some corporates have their own renewable targets. To demonstrate the additionality of their actions, i.e., that they are genuinely supporting extra renewables, they have to voluntarily surrender the associated LGCs, rather than use them for any liability they have themselves or sell them into the market. The CER expects 5m LGCS to be voluntarily surrendered. Almost half of these are from the ACT government’s 100 per cent renewables scheme.

Emerging initiatives such as the Guarantee of Origin for hydrogen and the Corporate Emissions Reduction Transparency report may further increase demand for LGCs, while mature schemes such as GreenPower are likely to plateau or even decline. LGC prices remain materially higher than other domestic offset units, so any party seeking to source a generic offset is unlikely to buy LGCs at the current time.

Chart 1: LGC spot and forward prices 2019-2021

Source: CER

Chart 2: LGC spot and forward prices 2015-2021

Source: CER