Australian developers are hoping to tap into the voracious demand for clean energy from the big north Asian economies, and create a “solar fuels” export industry at a scale many would have thought unimaginable.
Proponents such as Renewable Hydrogen’s Andrew Want are talking of the prospect of developing massive solar arrays in the Australian outback at a scale of “multiple tens” of gigawatts.
“This is a great opportunity to create a solar industry which is not limited to the scale of our electricity network,” Want tells RenewEconomy at the sidelines of the 6th World Hydrogen Technologies Congress in Sydney.
“This plan is bolted on to the prospects of the biggest economic growth region in the world.”
As RenewEconomy reported on Wednesday, there is a big push in Australia to tap into Japan’s emerging “hydrogen” economy, and use Australia’s rich solar and wind resources to provide clean fuels to Japan and other countries.
Professor Ross Garnut and the Clean Energy Finance Corporation chief executive Oliver Yates say this could create an export industry that could rival coal and gas.
Japan is hungry for hydrogen and clean liquid fuels because it relies so heavily on imported fuels – now entirely coal, oil and gas – but knows it needs to rapidly decarbonise.
It believes the best option for a country with limited renewable energy resources – and a nuclear strategy stranded by the Fukushima disaster – is hydrogen.
It has set in motion a “hydrogen plan” that includes fuel cells in homes and buildings, a refueling network for hydrogen fuel cell vehicles, and then for large-scale power plants.
But as we noted on Wednesday, while the likes of Garnaut, Yates and others involved in the emerging hydrogen industry in Australia see this as a way to unlock Australia’s renewable energy resources, some Japanese industrials seem more focused on using fossil fuel as feedstock, particularly cheap brown coal from Victoria.
There is a belief, though, that when costs for carbon capture and storage are included, and a strong signal for clean energy emerges from the climate conference in Paris, then renewables will be the most logical power source.
Want and his associates – including some big corporate names from Europe and Asia – are working on a plan to begin exports of solar fuels by using electrolysis and existing infrastructure for ammonia exports to test the Japanese market.
They are planning a small MW-scale pilot plant near Karratha in the Pilbara, not far from the country’s biggest ammonia plant, which would generate electricity from a solar PV plant, and add water for electrolysis, which separates the hydrogen from the oxygen.
If this initial project is successful, it would be followed by a massive solar PV plant of around 100MW to 400MW.
It would then be an industry that Want says could be in the multiple tens of gigawatts, and use a combination of solar PV and solar towers and storage. (Want is also a director of solar tower developer Vast Solar, which has a demonstration plant in western NSW).
To put this into some perspective, the Pilbara has some of the world’s best solar resources, and a land area of more than half a million square kilometres – one third bigger than all of Japan. And it has major LNG infrastructure.
“We have energy-intensive economies immediately to our north, including Japan and Korea, which are struggling to find a way to decarbonise their industry,” Want says.
“This is massive growth opportunity. Australia has huge solar resources in the Pilbara, western WA, Queensland and South Australia. We have also got wind and tidal.
“Ten years ago – this idea was just not feasible. But there has been a big fall in the cost of solar technology, and in electrolysis, and there has never been a stronger industrial imperative to improve cost and efficiency.”
Want says Europe has recognised that the way to store energy for industrial scale use is through hydrogen, and Japan has come to the same conclusion.
Right now, almost all of hydrogen currently made comes from fossil fuel feed stock, with just 4 per cent by electrolysis converging on same technologies.Want says Japan’s hydrogen plan still assumes reliance on gas and coal for hydrogen production – but Australian promoters, taken aback by the scale of ambition from Kawasaki to use brown coal from Victoria as feedstock – are trying to talk them round to renewables.
“We have been constrained by what we could do within the local power system,” Want says. “But if you look at our trade relationships, and the need to decarbonise the global economy, that is where Australia can play a serious role.”
Financing projects at such a scale, once the concept is demonstrated, should not be a problem, given the massive shift of global funds from fossil fuels into clean energy, particularly into climate and green bonds
Want says a pilot plant could begin construction in 2016, and be in operation by 2018.
The creation of a solar fuels export industry would also lead to lower cost renewable energy generation for domestic use, as well as industrial gases. This, as Garnaut points out, could make Australia a natural site for clean energy-intensive industrial activity.
“This is not a five-year vision, it is a 20,30, 50 year vision,” Want says. “That is the timeframe that we saw for the development of the Pilbara iron ore reserves.
“If renewable hydrogen production can get down the cost curve and be of scale, we can remodel energy systems around hydrogen,” Want says.
Article sourced from Renew Economy
Australia’s energy markets are on the cusp of rapid change, but it is not just the prospect of individuals quitting the grid that represents the biggest challenge to industry incumbents: it’s the possible defection of whole towns and communities.
The creation of micro-grids is seen by many leading players as an obvious solution to Australia’s soaring electricity costs, where the grid has to cover huge areas, at the cost of massive cross-subsidies that support it.
The major network operators in Queensland, NSW, South Australia and Western Australia see micro-grids as an obvious solution to the challenge and cost of stringing networks out, sometimes more than 1,000km away from the source of generation.
In Western Australia and Queensland, these subsidies amount to more than $500 a household. The cost of service to regional consumers in Queensland is far above the cost of service to those in the south-east corner.
To address this, these states are proposing to take some small communities, and towns like Ravensthorpe in Western Australia off the grid. In New South Wales, some towns are taking the initiative themselves.
In northern rivers region, the township of Tyalgum revealed it is considering a micro-grid that would allow it to largely, or entirely, look after its own energy needs.
Indeed, the whole Byron shire is considering micro-grids as part of its efforts to become “zero net emissions” within the next decade, and to source 100 per cent of its electricity needs from renewables.
But micro-grids are not just about grid defection. While it will make sense for those towns and communities at the edge of the network to become self-sufficient and disconnect entirely, most micro-grids will remain connected to the network, helping to reshape a centralised grid to one focused on more efficient decentralised renewable power generation sources and storage.
Warner Priest, the head of emerging technologies at the Australian offices of German energy giant Siemens, says micro-grids are the innovative solution to our future smart grid needs.
In fact, he notes, they were the original model for shared generation, but like electric vehicles they were swept aside by the push to big, centralized, fossil fuel generation, transmission and distribution.
Now, through massive improvements in technology, it is becoming easier for remote and off-grid communities to look after their own energy needs without relying heavily on costly, imported energy derived from centralised fossil fuel sources.
New sub-divisions may find it more cost-effective to never connect to the grid, and micro-grids could also be useful within major cities, addressing areas where the network is constrained by inadequate or end-of-life network assets.
And within five to seven years, Priest says, these micro-grids could be completely renewable as new technologies such as on-site renewable hydrogen production become mainstream, replacing the non-renewable gas and diesel generation that is used as a micro-grid’s energy generation for when renewable energy sources are not available.
Siemens Australia is drawing up plans for one 50MW micro-grid in Australia that would – ultimately – include up to 10,000 homes.
It would comprise of some 40MW of rooftop solar (around ~4kW per home), an array of, centralised and decentralised battery storage, fossil fuelled gas generators, which could – within a few years – be replaced by renewable gas fuel such as hydrogen.
The attraction comes through cost, resilience, reliability and efficiency. Fossil fuels burned at the point of consumption are two to three times more efficient than those burned at centralised power stations. That means more energy is harnessed from the equivalent fossil fuel, with ~50 per cent of that energy being in the form of thermal energy that is used for both heating and/or cooling.
Priest says micro-grids are about integrating and balancing multiple loads and distributed generation resources within a smart micro distribution grid, using powerful software SCADA control systems (microgrid management systems), residential solar, wind energy, battery storage and other types of renewables and storage – such as hot water systems – ensuring that the use of fossil fuel gas and diesel is kept to a minimum.
A new report has highlighted the extraordinary expense Australia’s electricity networks have passed on to consumers to meet demand forecasts that never eventuated. It says the energy market is “not fit” for its stated purpose of providing a benefit to consumers.
The report, Zero Carbon Australia, Renewable Energy Superpower, by Beyond Zero Emissions, shows that networks on Australia’s main grid, the National Electricity Market – which excludes WA, the Northern Territory and off-grid areas like Mt Isa in Queensland – have spent $75 billion on network improvements and expansion in the past 10 years and passed these costs on to consumers.
The spending was justified on demand forecasts that have proven to be outrageously wrong. Indeed demand, far from growing, has barely changed over the past decade. But electricity bills have more than doubled, driven almost exclusively by these soaring network costs, compounded by exaggerated rates of return that benefited the networks and hit the consumer.
The spending is highlighted in this graph to the right. The report says the over-investment has been encouraged by the NEM structure, first by the move to “corporatise” utilities and then by distorting their business conditions.
It notes that the networks’ costs to consumers have been further exaggerated by “Weighted Average Cost of Capital” (WACC) — the interest yield on the assets they held – which is far above the market rate for low-risk assets.
“In order to fully exploit the inflated yields, and hence maximise profits, network businesses have sought to expand their ‘poles and wires’ asset base. To do this, network businesses over-hyped future demand from the grid, in order to be granted expansion approval by the Australian Energy Regulator (AER).”
This next graph shows those demand forecasts, and what actually eventuated. As the report notes, some $75 billion was invested in transmission and distribution network upgrades, causing the regulated asset base to double to $77 billion by 2014.
The demand forecasts have proved ludicrously wrong. This graph to the right shows how the 2010 forecasts have been wound back. Even the 2014 forecast may be optimistic. And total demand is virtually the same as in 2005. But networks had a strong incentive to produce such optimistic forecasts, because the more they could build, the more revenue they could receive.
“Because network revenue is guaranteed by the regulator, consumers must pay for this new capacity whether they use it or not,” the report notes. “Clearly the demand did not rise in line with projections, but declined.”
The network response to this has been to reject outright any proposals that they should take a write-down on the inflated value of the assets. For the next five-year period, they have attempted to continue their spending spree, and have taken the extraordinary step of taking the Australian Energy Regulator to court after it rejected their spending proposals.
Now, the NSW networks have also flagged a potential “solar tax”, to hit households that export solar back into the grid with extra charges. They flag similar fees for households using battery storage and electric vehicles.
Network spending on electricity have not been the only way that utilities have bled customers. The report says history is being repeated with Australia’s gas system, also governed by the Australian Energy Market Commission according to the National Gas Rules.
“The supply network is being expanded and new unconventional gas supplies are being developed, at great cost, to satisfy projected demand,” it notes.
“Warnings are being sounded that consumers will withdraw from the gas system even more dramatically than the electricity system as a result of rising gas prices and substitution of efficient electric appliances.”
This is known as the “death spiral” and it is likely to happen in the electricity network too, as the plunging cost of solar and battery storage offer alternatives. Which is one reason why networks, not just resisting calls to write down the value of those inflated assets, are talking about compulsory fees even for those who leave the grid, as well as a special tax on the use of solar, battery storage and electric vehicles.
The report says that in the retail market, consumers are also being squeezed. It found that deregulated markets have not resulted in the benefits being promoted by the utilities.
This figure above illustrates how. It shows Victoria has the highest retail “margins” of any state.
“The ultimate judgement of market success lies in the value to consumers,” the report notes. “The retail component of Victorian power bills is the most costly in the country and therefore the least successful, no matter what proxy metrics are used to say otherwise.
“Essentially the national energy market structure is not fit for its stated purpose of delivering energy services in the interests of consumers.
“The sector ring fencing and growth focus does not match contemporary technical solutions or customer desires. Unless it is reformed Australia’s domestic energy supply will grow increasingly uncompetitive.”
This article has been sourced from Renew Economy
Welcome to PV Industry Alert - Issue 24
Maximum voltage trip point settings
The new AS 4777.2–2015, was released on 9 October 2015, replacing the existing AS 4777.2–2005 and AS 4777.3–2005, with a 12-month transitionary period applying, during which either version of the Standard can be used.
One change introduced is new overvoltage (Vmax) settings. Accordingly, we’ve modified the Embedded Generating Unit Installer’s Confirmations on page two of our Form A to reflect both options, so please ensure you complete this section. The options available are:
Single-Stage Vmax (AS 4777.2–2005)
Vmax set to 255V (2 seconds)
Two-Stage Vmax (AS 4777.2–2015)
Vnom-max set to trip at 255V
Overvoltage 1 set to trip at 260V (2 seconds)
Overvoltage 2 set to trip at 265V
We attempt to check maximum voltage trip point settings on new installations, as well as those we investigate for supply quality issues. In order for us to confirm the installation operates correctly, we need to know which voltage setting methodology is in use. If we don’t have this information on the Form A, we will issue a Form B to obtain the relevant trip point settings information.
This requirement is also reflected in the current version of the joint Ergon Energy/Energex Connection Standard for Small Scale Parallel Inverter Energy Systems (Connection Standard).
A prompt response to options and offers is essential
If you have received an “options letter” from Ergon Energy after having submitted your connection application, we request that you respond in a timely manner with advice on the option that best suits your customer’s needs. This will ensure that we can make a subsequent connection offer within the required timeframe, which you will have 20 business days to accept.
If you have any questions upon receipt of the options letter please call the Solar Support Team to discuss any concerns you or your customer may have.