​Bloomberg released its Q1, 2016 report recently which showed the changes in brands who are recognized as Tier 1.
You can find the list further down below for the Panel Manufacturer's, who made the Tier 1 rating list.
However if you wish to find out more about what the Tier System is and how they are rated to meet Tier 1, keep reading below.

What is the Tier System, you ask?

Bloomberg New Energy Finance PV Module Maker Tiering System
Bloomberg New Energy Finance has developed a tiering system for PV module makers based on bankability, to create a transparent differentiation between the hundreds of manufacturers of solar modules on the market. Since this basic categorisation has been used as an advertisement by certain manufacturers, but should never replace a proper due diligence process in product selection, this document explains the tiering criteria and its limitations.

1. WHY DIVIDE THE PV MARKET INTO TIERS?
Bloomberg New Energy Finance is frequently requested by clients for a list of 'major' or 'bankable' suppliers - in common industry parlance, tier 1 suppliers - for use in manufacturing forecasts, preliminary competitor analysis, and other internal comparisons. It is very common for industry players to refer to 'tier 1' players, but these terms are seldom defined or described, which is unhelpful for firms outside the solar industry trying to get a basic overview. We strongly recommend that module purchasers and banks do not use this list as a measure of quality, but instead consult a technical due diligence firm such as OST Energy, Sgurr Energy, DNV GL, Black & Veatch, TUV, E3, STS Certified, Clean Energy Associates or Leidos Engineering. These would usually consider what factory the module comes from, as well as the brand, and give an informed opinion on whether the modules will perform as expected.
2. DEFINITIONS
​ 'Bankability' - whether projects using the solar products are likely to be offered non-recourse debt financing by banks - is the key criterion for tiering. Banks, and their technical due diligence providers, are extremely unwilling to disclose their whitelists of acceptable products. Bloomberg New Energy Finance therefore bases its criteria in what deals have been closed in the past, as tracked by our database -13,800 photovoltaic financings worldwide as of January 2016. We reserve the right to change these criteria at any time - particularly by requiring more information to consider a manufacturer tier 1. These tiers will be reviewed every quarter based on information added to Bloomberg New Energy Finance's database. Only project financings for over 1.5MW of capacity are included in the database. Portfolio financings count for tiering only for projects with defined locations, and where the debt is secured on all the assets together, ie, if one project in the portfolio underperforms the bank has a claim on the rest of the portfolio. We only tier manufacturers which actually own production facilities and sell under their own brands. Companies which outsource production under brand names are not tiered.
3. TIER 1
Tier 1 module manufacturers are those which have provided own-brand, own-manufacture products to five different projects, which have been financed non-recourse by five different (non development) banks, in the past two years.
These 1.5MW+ deals must be tracked by our database, ie the project location (sufficiently to identify the project uniquely), capacity, developer, bank and module maker must be in the public domain. One exception is manufacturers which have filed for bankruptcy or a form of insolvency protection, or experienced a major default on bond payments; these are removed from the tier 1 list until further notice. This classification is purely a measure of industry acceptance, and there are many documented examples of quality issues or bankruptcy of tier 1 manufacturers.
3.1. Tier 2
We do not publish a tier 2 list.
3.2. Tier 3
We do not publish a tier 3 list.

(This is sourced from http://about.bnef.com/content/uploads/sites/4/2012/12/bnef_2012-12-03_PVModuleTiering.pdf)

At Driftwind Electrical, we prefer our customers have as much information available to them to make an informed decision before purchasing a solar system. As you can see on our products page, http://www.driftwind.com.au/panels.html Driftwind Electrical recommend many of the Tier 1 panels that are listed in Bloomberg's List below and as advised earlier, this classification is purely a measure of industry acceptance, and there are many documented examples of quality issues or bankruptcy of tier 1 manufacturers. However we also highly recommend Lightway Panels, which do not have a Tier 1 rating but have proven to be a reputable PV Module Manufacturer and you can read further information on the Tiering system here http://www.solarchoice.net.au/blog/what-is-a-tier-1-solar-panel-tier-2-or-3/

Below is the list for the 2016 PV Module Manufacturer's who made the Tier 1 Rating. 

The Conversation
Yet again, electricity prices are set to be a key point of contention in an Australian federal election.
The Coalition responded quickly to Labor’s election commitment to an emissions trading scheme (ETS), with Prime Minister Malcolm Turnbull warning of “much higher electricity prices” and a “very big burden” on Australians.
Other ministers joined in. Treasurer Scott Morrison labelled the plan a “a big thumping electricity tax” and Environment Minister Greg Hunt branded it “Julia Gillard’s carbon tax on steroids”, warning of “even higher electricity prices for Australian families”.
The centrepiece of the Coalition’s climate policy, meanwhile, is the A$2.5 billion Emissions Reduction Fund. An important element of this scheme is the “safeguard mechanism”, which is due to kick in on July 1 this year. This has implications for the electricity sector and may also affect electricity prices.
National summary of retail electricity cost components – 2015 Residential Electricity Price Trends
These policies will affect the wholesale electricity market, in which electricity is bought from power generators and sold on to retailers and consumers.
As you can see from the figure to the right, the competitive component of the retail prices makes up about 50% of the typical household electricity bill, and the wholesale component typically makes up half of that. The other major cost is poles and wires.
So how exactly will the different climate policies affect electricity prices?

The safeguard mechanism (Coalition)
The safeguard mechanism will require Australia’s largest emitters to keep emissions below a baseline. This will prevent emissions reductions under the ERF being offset by increases elsewhere. Businesses that go over the baseline will have to pay.
The safeguard is based on the high point in annual emissions from the whole electricity sector between 2009-10 and 2013-14. Generators’ individual baselines and associated penalties o​nly come into play if the whole sector goes over the baseline.
As you can see in the figure below, emissions have fallen by almost 20 million tonnes per year since the first baseline year (2009-10), partially in response to years of declining demand.
Current projections for electricity growth suggest that the baseline won’t be breached for some years. As such, individual generators are unlikely to be penalised, and wholesale prices would not be expected to change dramatically.

Electricity sector emissions trading (Labor)
Labor’s electricity sector ETS is a “baseline and credit” scheme, based on a model proposed by the Australian Energy Market Commission (AEMC), which actually submitted the proposal to consultation on the safeguard mechanism.
This also places a baseline on the electricity sector, but it is calculated on the basis of emissions intensity (tonnes of emissions per unit of electricity generated) rather than overall emissions. Generators with emissions intensity below the baseline (for example, gas generators) would earn credit, so “cleaner” power plants would generate more credits.
Power plants that go over the baseline (for example, brown coal) would have to buy credits for the amount they go over. “Dirtier” plants would thus have to buy more credits.
This is substantially different to a carbon tax or the previous emissions trading scheme. Under these policies, all generators are penalised, some more than others, as you can see in the figure below.

Current projections for electricity growth suggest that the baseline won’t be breached for some years. As such, individual generators are unlikely to be penalised, and wholesale prices would not be expected to change dramatically.
​
Electricity sector emissions trading (Labor)
Labor’s electricity sector ETS is a “baseline and credit” scheme, based on a model proposed by the Australian Energy Market Commission (AEMC), which actually submitted the proposal to consultation on the safeguard mechanism.
This also places a baseline on the electricity sector, but it is calculated on the basis of emissions intensity (tonnes of emissions per unit of electricity generated) rather than overall emissions. Generators with emissions intensity below the baseline (for example, gas generators) would earn credit, so “cleaner” power plants would generate more credits.
Power plants that go over the baseline (for example, brown coal) would have to buy credits for the amount they go over. “Dirtier” plants would thus have to buy more credits.
This is substantially different to a carbon tax or the previous emissions trading scheme. Under these policies, all generators are penalised, some more than others, as you can see in the figure below.

This difference is important for electricity prices. Dirtier plants would be expected to increase their selling price to cover the financial penalty on their emissions. But cleaner plants, earning revenue from selling credits, could afford to sell their electricity more cheaply.
This is important, because cleaner plants (typically black coal or gas) set the price. Gas in particular would probably be significantly cheaper under this proposal. As such, the impact on wholesale prices would be small, or negative.
In fact, as the AEMC itself noted, the impact on the wholesale market could be an increase or decrease in prices (depending on where the baseline is set).

The brown coal exit (Labor)
Another component of Labor’s climate platform is a plan to finance the closure of brown coal power stations, an idea first proposed by ANU climate economists Frank Jotzo and Salim Mazouz.
In this proposal, brown coal plants would bid for the payment they would require to finance their own shutdown, with the cheapest bid being selected. The remaining plants would pay this cost, in line with their emissions.
Similar to the ETS, it would be expected that this cost would be reflected in increased offer prices to the market from the remaining generators. The direct costs would be temporary (a one-off payment) and small, relative to the overall wholesale price.
Indeed, Jotzo and Mazouz estimated it could cause a one-off rise of 1-2% in retail power bills. Analysis company Reputex found the impact could be between 0.2% and 1.3%.
However, Danny Price of Frontier Economics has suggested that the scheme could push up retail power prices by between 8% and 25%, as the result of a short-term price shock. But given the significant excess capacity in the market, and assuming that the market is indeed competitive, it is hard to see how such a increase would happen.
This point aside, the price argument misses the point of the scheme, which aims to deliver an “orderly transition” away from brown coal. The longer-term effects on supply and price of a brown coal exit will be similar, regardless of how the industry closes.
In fact, if it were left entirely to the market, the sudden retirement of an entire power plant might create even more of shock. This proposal is chiefly about ensuring an orderly, predictable transition.

50% renewable energy target (Labor)
The final element of Labor’s climate platform is a 50% renewable energy target by 2030. At this stage, not much detail has been unveiled other than shadow environment minister Mark Butler’s pledge that it will be “designed in a way that does not disturb investor sentiment around the delivery of the existing Renewable Energy Target” – something that a sector beset by uncertainty would welcome. As such, it is quite difficult to speculate on how electricity prices might react.

The current Renewable Energy Target is a certificate scheme that requires retailers to buy a certain amount of renewable energy. The cost of these certificates is passed on through electricity bills. However, as shown by the government’s own modelling, the interaction with the wholesale market results in a net saving to consumers.Interestingly, and as the AEMC points out, the electricity ETS is designed to be flexible and integrate with a renewable energy target. Indeed, such an ETS could drive investment in renewable energy, replacing current subsidies through the Renewable Energy Target. The 50% target could theoretically be achieved through the ETS alone, if the baseline was set at the right level.

A bipartisan approach?
As it stands, the government’s climate platform is unlikely to have any impact on electricity prices. However, it will also not have a major impact on the electricity sector’s emissions.
Labor’s policies will have an impact, but as the AEMC notes it may occur “without a significant effect on absolute price levels faced by consumers”.
The government’s current polices will require strengthening to further reduce emissions. To achieve this, the Grattan Institute and others including the Business Council of Australia have supported ideas that would turn the Liberal platform into something very similar to Labor’s.
Indeed, modelling commissioned by the government itself assumes that Direct Action will eventually morph into a similar baseline-and-credit ETS, in order to meet long-term climate commitments.
Political slogans aside, perhaps a bipartisan approach is possible, without a significant effect on power bills.
Dylan McConnel: Research Fellow, Melbourne Energy Institute, University of Melbourne. He received funding from the AEMC’s consumer advocacy panel.

This article is sourced from Renew Economy. You can read the original article here

Interest in energy storage is heating up across Australia, and thanks mainly to Tesla’s Elon Musk, the prospect of installing a battery at your home and having it provide power to your household equipment has become fashionable.Beyond the hype, there are a number of factors that are driving consumer-level interest in batteries, namely high retail electricity prices, the large gap between peak prices and off peak prices, the high penetration of solar coupled with the low feed-in tariffs offered by retailers, and an instinctive feeling that the big electricity utilities are not on your side.

Getting solar PV and a battery seems like the logical response to reduce electricity bills and loosen the grip of the grid, and the retailers that have been profiting from your escalating energy bills.

However, let’s remove the emotion for a minute and take a close look at the economics of the decision whether or not to get a solar PV and battery system. The key mistake that many people make is to treat this as an all or nothing decision. The nothing option is easy — resigned to the view that your electricity bills are all too boring and complex to do anything about, combined with the likelihood that you don’t know who to trust — you simply do nothing.
On the other hand the all option involves purchasing a large solar PV system and a battery to generate, store and use as much of your own electricity as possible. (For example, at today’s prices a 5kW solar PV system and a 12kWh battery might cost about $20,000 and a smaller 2.5kW solar PV system and 3kWh battery might cost about $10,000.)
You would think that an experienced installer or your electricity retailer would know what kind of savings these systems will generate but the reality is nobody can tell you with sufficient certainty. There are so many variables to take into account, including the crucial element of exactly how you as a consumer use electricity throughout the day and across the seasons.
Your retailer might have some insight into this if you have a digital interval meter, or smart meter, but they are not using this information to figure out what your savings could be. And considering that they make more money when you consume more from the grid they really have no incentive to help you cut your grid consumption.
The fact is that right now the typical payback period for energy storage can be as high as 30 years, and given that most decent battery systems come with a 10-year warranty, and power converters probably last about this long too, you’d be right to conclude that a payback period in excess of 10 years is a poor financial outcome.
The mistake though is to treat this as an all or nothing decision, instead of taking an incremental approach to the analysis.
There are some simple things that you can do today to cut your electricity bill, but beyond these simple, low investment options, you also need to decouple solar from storage because put simply, solar is relatively cheap and proven technology, whereas storage is expensive and nascent. There is no logical reason that you have to do the two together, and separating the two and running the numbers proves this.
Sellers of solar and storage equipment will typically look at your current bill and situation and compare this against the scenario where you install a solar PV system and possibly also a battery storage system that will store excess solar generation and supply this to your home during peak times.
To keep the economics simple we’ll just focus the simple payback period, that is, how many years it will take to pay back your investment. (Although this is not the most robust way to analyse investment decisions, it is the simplest metric to look at, and the one most commonly used to compare and express the economic benefits of these systems.)
​
Absolute Approach

​The “absolute approach” compares the result of doing something to the current state, that is, “buy system X or do nothing”. The table above shows that it seems to make good sense to get solar, as an investment of $4,000 provides savings of $600 each year, and you’ll make your money back in just under 7 years. Getting solar and storage together is not as good though, since an investment of $10,000 saves you $850 each year, and you only make your money back in 12 years.
Personally I feel like a 12-year payback period is a little too long, but I’ll leave it to you to decide whether you’d just go for solar or get solar and storage at the same time.

The problem though is that this analysis is fundamentally flawed for 2 key reasons.
​
The first issue is that adding a battery should be looked at incrementally. The battery adds $6,000 on top of the solar system and returns an additional $250 each year ($850 less $600), for a payback period of 25 years. Looked at in this way you would be right not to get the battery system. The mistake in the analysis above is that it looks at decisions in an all or nothing way, when in fact you need to look at each decision incrementally.
The second problem is that this analysis misses a key opportunity, and that is, you can easily, and generally for no upfront cost, save money by first switching to a better electricity tariff either from your current retailer or a new retailer * that offers a better tariff for your level of usage. For example, in New South Wales, the government website Energy Made Easy compares all available tariffs against one another and shows you how much you could save by switching. Switching generally costs nothing, and for our example household, can deliver large savings.

Incremental Approach

Adding in the option of switching tariffs and then taking an ‘incremental approach” to the analysis shows us that switching tariffs or retailer * can save $750 each year. After doing this, even getting solar looks like a borderline decision, and adding storage is definitely out of the question for now.
This appears to be bad news for solar and storage, but that is not the point. The point is what is good for consumers is to first take advantage of low cost and easy ways to save money on energy. The next step is to gather good data about how you use energy and work with someone you trust to give you the right advice, specific to your circumstances. The final step is to possibly invest in solar and storage technology to help you further reduce your bills and reliance on the grid.
For most people with average to high electricity bills, and good north or west facing roof space, solar will make sense today. However, storage is still too expensive for the mainstream consumer who wants to cut their energy bills. But all of this will change as battery costs continue to come down, the technology improves, additional revenue streams for the battery become apparent, and grid prices continue to rise.

Article by Darren Miller 
Darren Miller is Co-Founder & CFO at Mojo Power.

Article sourced from One Step Off the Grid

The benefits of Reactive Power Control (RPC)
​
While reactive power has no value in powering electrical devices, it does perform valuable functions to help power move more efficiently. An RPC setting of 0.9 lagging or lower is mandatory on all exporting inverters rated above 2kVA and up to 30kVA and connected to Ergon Energy’s main network (not SWER or isolated networks).

A lagging fixed power factor ‘absorbs’ reactive power to reduce the amount of voltage rise attributed to the power generated by the PV system. Although it operates whenever the array is generating, it will only impact the generation amount (kW) when the PV system is generating at its maximum. For example, with a 0.9 lagging setting on a 5kVA inverter, the kW capacity is only reduced when it exceeds 4.5kW.

By throttling back the kW capacity at peak PV generation times, the voltage rise to the network attachment point is reduced, thereby reducing the likelihood of the inverter’s maximum voltage trip point being reached. This in turn means the inverter will not trip off as often as it may have, which will result in more kWh being generated over a typical day, as illustrated by the green line in Figure 1.

RPC also benefits the local network and neighbouring PV systems, in that the reduced upward pressure on the network voltage will allow other PV systems sharing the transformer to operate without tripping off (other than in necessary circumstances), or at least operate for longer before tripping off. As more of your customers have RPC enabled, more inverters will operate more effectively.

A key benefit of RPC enablement is that PV applications on premises on Ergon Energy’s main network which include RPC and undergo assessment are more likely to be approved. Also, the higher proportion of inverters with RPC on a local network, the more applications we’ll be able to approve on that network. Installers are encouraged to activate RPC on existing PV systems to help address voltage-trip issues.

In a small proportion of cases, where there is a robust local network and few or no other PV units connected, the total kWh generated by a PV system with RPC may be a few per cent less annually than it would be without RPC. We’re confident that RPC provides holistic benefits for PV customers, the network and the PV industry. To minimise any downsides, we have allowed for dynamic RPC settings under the new (draft) Connection Standard that is currently open for feedback. 
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Ergon and the Clean Energy Council (CEC) work together on best practice
We have an ongoing focus on driving higher standards of work practice and compliance with our requirements. The CEC’s support means we can refer repeated or serious non-compliances with distributor requirements by installers for consideration under the CEC’s demerit points system. Non-compliances will be rated as Minor, Medium or Major and demerit points allocated as relevant, entirely at the CEC’s discretion.

An example of a Minor non-compliance is replacing an inverter without lodging an application. Failing to set RPC or export limitation as per the contract would be a Medium non-compliance.  A Major non-compliance would be failing to set the maximum voltage trip point as required. Referrals to the CEC will be a last resort and will only occur after we have consulted with the installer, reiterated our requirements and given them every chance to comply.
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Managing older inverters that are no longer compliant
If an inverter needs replacement under warranty and is no longer compliant with the IEC 62109 standard required from 11 July 2015, it can be replaced with the same brand, series and model of inverter. However, the application for such an inverter replacement cannot be lodged online with Ergon Energy and must be lodged using the PDF application form (by email or fax).

If an inverter rated above 2kVA and connected to Ergon Energy’s main network doesn’t have RPC capability and needs to be replaced, its replacement must have RPC, even if under warranty.

If an inverter rated above 5kVA is connected to single-phase premises, or one phase of a multi-phase premises, and needs to be replaced, the new inverter capacity must be either limited to a maximum of 5kVA on a single phase or spread as evenly as possible over multiple phases.

Where phase imbalance between multiple inverters exceeds 5kVA, and one or more of the inverters need to be replaced, the new configuration should ideally result in the total inverter capacity being divided evenly between multiple phases, or the imbalance being reduced to no more than 5kVA.

A reminder that when it comes to the 44c Feed-in Tariff (FiT), the capacity of any replacement inverter/s must not exceed the original inverter kVA rating, otherwise 44c FiT eligibility will be lost.
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Battery applications are essential
Ergon considers a Battery Energy Storage System (BESS) to be any energy storage device that requires an AS 4777 accredited inverter to feed electricity to a grid-connected electrical circuit, even if the battery is not capable of exporting to the grid.

Under the electricity legislation, all customers must apply to connect a battery and gain our agreement before installation. Adding a battery to an existing PV unit without seeking agreement means the customer is in breach of the electricity legislation, and we may take action that includes disconnecting the battery from the network.

Installers that connect multiple batteries to a grid-connected electrical circuit without an application are likely to be referred to the Clean Energy Council. If you have failed to lodge application when previously installing batteries, please do so by 29 February 2016. Industry members lodging these retrospective applications will not be referred.

Only Uninterruptable Power Supplies or batteries connected to a non-grid-connected electrical circuit are exempt from our application requirements and you can find more details on our connecting batteries to the network webpage.
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Clarification of applicant responsibilities
If you are applying for network connection of a PV system or other micro EG unit on behalf of the owner of the premises, it is important that you remind the customer that they will be responsible for paying certain costs associated with the installation as well as an ongoing metering charge via their electricity retailer. Where we replace the meter, the customer will pay a fee.
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Merger of Ergon Energy and Energex
The Queensland Government has announced that the corporate services of Ergon Energy and Energex will be merged in 2016. The field services will remain as separate entities under their existing brands. Network differences will still exist in some cases so some differences will continue for installers, however these will be well communicated. More details can be found on the State Government website.
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Review of Connection Standard up to 30kVA​
The updated draft Standard has now been released for further industry consultation. Thank you to those who have so far made submissions to the Review.  You can view the updated draft and email your feedback to i.tech.enquiries@ergon.com.au until 25 March 2016.

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Helpful links
Ergon Energy ‘Solar PV’ web page

Ergon Energy ‘Battery storage’ web page

Ergon Energy ‘Electric vehicles’ web page

Joint Ergon Energy/Energex Connection Standard for Small Scale Parallel Inverter Energy Systems up to 30kVA

Standard for Connection of Embedded Generators [>30kVA] in the Ergon Energy Distribution Network
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Solar Support Team
Need advice? Please feel free to call our Solar Support Team on 1300 553 924 between 8:00am and 5:00pm Monday to Friday or email us at energysystems@ergon.com.au.

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This time next year, Victoria, South Australia and New South Wales will terminate a number of their rooftop solar feed-in tariff programs, putting to an end the premium tariffs in these three states. For the households currently on these premium tariffs, now is a good time to start thinking about what this means, and what they should do.
First, a look at the tariffs that will be scrapped – and when:

• Victoria’s Transitional and Standard Net metering programs end on 31 December 2016,
• South Australia’s Customer Group 4 Net metering program ends on 30 September 2016 and
• New South Wales $0.60/kWh and $0.20/kWh Solar Bonus Scheme ends on 31 December 2016.

It’s important to note that Victoria and South Australia are only ending a select few of their feed-in tariff payments; this is not the completion of these state’s entire feed-in-tariff program. Victoria’s Premium Net metering program will last until 31 December 2024 and South Australia’s Customer Group 1 Net metering program lasts until 30 June 2028.
Even more importantly, South Australia and Victoria have opted for net metering policies, which means that, when the feed-in tariff programs end, no metering changes are necessary. In these cases, the net meter can continue to operate as normal and customers can negotiate with their retailers to sell back exported energy at an agreed rate.

In Australia, the utility lobby says that the payback time to take a suburban home off grid is nearly 30 years. But soaring fixed network charges, and plunging battery storage costs, are rapidly changing the equation. In northern Queensland, the pay-back time may be as little as 7.5 years.
Steve Madson, the head of Country Solar, is feeling pretty pleased with himself.
Five days after installing a 10.8kWh Samsung lithium-ion battery storage system in his suburban Townsville home in north Queensland, and three days after (temporarily) flicking the switch from the grid, Madson is watching the rain fall – and the charge in his battery storage system is still going up.
“Last night was the first rains for the year in Townsville and it was very welcome, because many suburbs in town have power outages because of the rain,” Madson tells One Step Off the Grid. “I decided to make sure I drained my battery to see how much charge I could put in with a rainy, overcast day.
“I have 5KW of solar on my roof currently and I will lift that to 6.5KW in the coming weeks. Right now, my pool pump is running, two fridges and all standby equipment is on – and my battery is charging and has come from 6 per cent to 18 per cent in the pouring rain!!!”
That was Madson speaking at 10am. By the end of the day, despite the rain and the cloudy weather, the battery storage system had charged to 65 per cent. It would have been fully charged if he hadn’t left the pool pump on, but he was keen to test the system.
The result is good news for Madson, because in the next few weeks he intends to take his home permanently off the grid, and judging by the number of inquiries his business is receiving (about 50 a week), he expects many others to follow.
That’s because for an all in cost of around $25,000, consumers can get a 10.8kWh battery storage system and around 7kW of rooftop solar. In north Queensland, that’s enough to take a home off grid, and deliver a payback of 7.5 years. That’s one reason why Madson decided that he’d better lead by example.

He has taken delivery of one of the first Samsung 10.8kWh systems, the first scaleable grid-connected Samsung system in the world, and in his case, the first to be used in an off-grid application.
“This unit is the first of its kind installed in the world, we have this unit currently still connected to the grid whilst we learn all the features and functions though we plan to be off grid completely at the start of December.”
And Madson does not anticipate problems with going off grid. His 6.5kW of rooftop solar PV will produce more than 24.5kWh per day in winter, more than his home usage of 18kWh a day. In summer, the system will produce an average of 38kWh per day, more than covering his increased usage of 30kwh per day.
“I have a swimming pool, an aquaponics vegetable garden, we are in a hot humid environment so the house is air-conditioned with inverter split system air cons,” Madsons says.
“Because of the grid service fees my initial back up power will be a backup LPG generator, although I will purchase an electric vehicle early in the New Year and that will remove the need for the backup generator.” Here is a screenshot of his solar power output, his battery storage status, and his load, from Wednesday.

Madson says he would prefer to stay connected with the grid, but the connection charges make no sense, given the rising fixed network charges imposed by the local operator. (See this for more details of Queensland fixed charges).
“When home energy storage with lithium-ion battery technology started to become a reality I was getting really excited, both for myself having a new toy but also for the greater good of the community,” Madson says.
“For years I have been told the reason electricity prices are so high is because solar does not influence peak demand, that peak demand in sunny North Queensland where I live happens in the early evening these days and that is due to air-conditioning loads.
“I wondered if solar storage households like mine be connected to the grid and used as a filter to level grid demand. Wouldn’t the ability to help the grid by feeding from your home energy storage system or EV solve the greatest problem in the history of the centralised power network?”
Apparently not. The Ergon network they have increased the daily service charges and added metering charges which, when added up, amount to around $600 a year.
“That leads me to believe they will continue to increase fixed charges and lower the rate of electricity. But even if it remains at $600 a year over the expected 15 year life of my (storage) investment,  that is $9,000 of fixed charges and $9,000 buys me a lot of extra redundancy to ensure I won’t need the grid.”

Madson says the $25,000 cost of such a bundle should deliver a payback of around 7.5 years, given the high network fees and electricity charges.
That is little more than half the cost ($42,000) and one quarter of the pay-back time (29 years) suggested by the Energy Supply Association of Australia earlier this year, when it sought to throw cold water on battery storage following the publicity surrounding the unveiling of the Tesla Powerwall.
“With our electricity prices, these battery storage systems are already delivering fantastic returns. The modelling (of the utilities) is all wrong,” Madson says. (Although it should be pointed out that homes in southern states, particularly Victoria, would need much more battery storage to get through their winters).
The response by the utilities industry, particularly the move to jack up fixed charges, has left Madson confused and regretting a missed opportunity.
“If we worked as a community connected to the grid, using home energy storage systems and EVs to smooth out demand and supply, everyone in Australia would benefit and networks and retails would be much more profitable.
“And it would mean the road to the state target of 50 per cent renewable energy would be accelerated. Instead, the opposite will happen as a wave of people leave the grid on the back of unfair fixed charges.”
Madson says it would be more efficient to stay connected to the grid and a peer to peer system allowing people to build what they deem enough, and retain the ability to buy and sell electricity with my neighbours when circumstances change ( like family come to stay and energy requirements increase for a week).
“If the electricity grids rolled this model out people could lease their roof tops to investors to trade electricity, they would make money, the grid would make money in transport fees and we would see 100% renewables in just a few years.”

This article is sourced from One step off the grid

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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.
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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.
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“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.