The South Australian Government released their plan for their energy future. It contained a number of new strategies including:
100 MW battery farm
250 MW gas fired plan for emergency use only
200 MW of emergency plan until the gas plant can be brought online
Local power to direct plant and the interconnectors with Victoria
Energy Security Target under which a portion of electricity must be sourced from within South Australia
South Australian Gas Incentives which would provide an additional $24 million for local gas exploration which would primarily be made available for South Australian consumers
The South Australian Government is also planning to tender its consumption to allow a new private generator to be built. Part of the tender would require a synchronous renewable generator to be built.
Currently the policies are vague in detail though an expression of interest for the battery storage has already been issued with responses expected by 31 March 2017.
Edge continues to monitor the announcement to assess the impact on the market. Further analysis will be posted once details are released.
Engie announced on 3 November 2016 that they would close down their 1,600 MW Hazelwood power station in March 2017. The markets have reacted to the news of the closure by increasing the forward cost of electricity across the National Electricity Market.
The outlook from the Australian Energy Market Operator (AEMO) is not looking good for Victoria. If the state experiences hot weather next summer there may not be enough generation available to meet peak demand without further load reductions. Their medium term outlook is published at least weekly and the most current to 17 March 2017 shows that the 2017-18 summer could see reserve shortfalls if there is a warm summer.
Table 1: Medium Term Outlook for VictoriaSource: AEMO
Currently seven of the eight units at Hazelwood is running. Unit eight came off on Sunday 12 March 2017 with an unplanned outage citing a boiler leak. This would not have been part of the shutdown plan but boiler leaks can usually be repaired within a few days so Engie might have decided that it is not worth bringing back on.
The current plant is to take three units out of service on 27 March 2017, another three the next day and the final two units on 29 March 2017. Following this there will be a decommissioning of the plant and a rehabilitation of the site including the mine which can take up to four years.
Hazelwood is a source of heavy pollution in the electricity market and is part of an older generation of technology which needs to be replaced in order to reduce carbon emissions. It has been a very cost effective and reliable source of power for the past 52 years helping to stabilise Victorian power prices and provide support to the rest of the market since interconnection. It will also have a profound impact on the people working in the region.
The Australian Energy Market Operator (AEMO) published their Gas Statement of Opportunity on 9 March 2017. It highlighted that there could be insufficient gas to meet demand from both industrial users and power generators. The report highlighted that there could be insufficient gas as soon as the 2018-19 summer.
Following this report, the Prime Minister held a meeting with nine company leaders on Wednesday 15 March 2017. The gas companies committed to increase domestic supply if needed to meet demand. The Prime Minister is quoted as saying that the gas producers ‘understand the absolutely critical importance of maintaining their social license to be doing business in Australia’. He stressed that the Federal Government wanted to see the market come up with a solution but would not shirk from measures which would ‘protect Australian businesses, jobs and families’.
Yesterday the Federal Government announced funding to conduct a feasibility study into expanding the Snowy Hydro Scheme by adding an additional 2,000 MW of pumped storage hydroelectricity. This additional storage was part of the original design of the Snowy Hydro Scheme but considered unnecessary at the time. The feasibility study is scheduled to be completed by the end of 2017 and if the study is successful the upgrade could be completed as early as 2022.
The use of pumped storage hydroelectricity will add additional capacity to the system but no additional energy. It requires nearly double the amount of energy to push the water up to the higher dam than the amount of energy that is created when released into the lower dams. With New South Wales and Victoria suffering from lack of energy it is difficult to see where the additional power will come from to make this efficient.
Pumped storage hydroelectricity presents a number of desirable properties to the current energy market. It is the only true fast start synchronous technology. Wivenhoe pumped storage hydroelectricity in Queensland can go from being completely offline to 500 MW synchronised and providing frequency services in 11 seconds. For comparison, the best gas generator takes 8 minutes to start up and another five minutes to synchronise.
Pumped storage hydroelectricity will also be able to provide frequency control services even while not generating power. By keeping the turbine spinning but not converting to electricity it can be used essentially as a fly wheel while consuming virtually no water.
Hydros (pump storage and otherwise) typically have a normal operating life of around 100 years though truthfully no-one really knows what will make them stop working. They can also store a large amount of energy economically. Unlike a battery which will typically only be able to store energy for 1 to 2 hours at maximum capacity, a pumped storage hydroelectricity generator is only limited by the size of the upper dam capacity.
The other potential benefit of the Snowy Hydro development is in support of Australia’s Renewable Energy Target. Whilst pumped storage hydroelectricity is not a renewable source of generation, other parts of the Scheme (run of river hydros) is. If adding pumped storage hydroelectricity to the current run of river scheme is considered a major upgrade, the baseline for the run of river could be reset to zero. This means that the Snowy Hydro scheme would generate an LGC with each MWh of generation. This will be equivalent to approximately 6,500,000 extra LGCs coming into the market, or almost 20% of the total target of 33,000 GWh. Perhaps this is part of the Federal Government’s plan behind meeting the Australia’s Renewable Energy Target.
Recent involuntary load shedding across South Australia, Victoria and New South Wales has led to a discussion on the current operation of the National Electricity Market.
On 9 March 2017 Atlassian co-founder Mike Cannon-Brookes tweeted that Tesla’s battery division could solve South Australia’s power problems in 100 days. This would occur by building ten 100 megawatt hour battery farms which Tesla confirmed that they would be able to provide in the requested 100 days. Since then, other battery providers have offered to provide quotes for a similar product. Since the tweets started, Mike Cannon-Brookes has received several offers to help with funding and on Friday 10 March asked Tesla for seven days to sort out politics and funding.
Battery storage has come a long way over the last four years and is widely considered a potential solution to integrating renewable generation into the grid. The capacity of the proposed solution would be more than sufficient to meet the supply shortages seen to date in South Australia. During the last brown out in, 100 MW for one hour would have prevented involuntary load shedding.
The problem in the short term is how to integrate the batteries into the market. Batteries work on direct current while most of the market works on alternative current. This means that the batteries would need to include an inverter. It is not certain that the current prices quoted would include this. The quote also doesn’t include local costs such as connection to the grid and installation. There are other potential issues with integration of batteries in the market. It is uncertain how a utility scale battery would register and comply with strict frequency standards.
The proposal has sparked renewed debate on the role that technology can play in solving the issues we are facing in the current energy market.
In December 2016, Powerlink submitted a Revised Revenue Proposal to the Australian Energy Regulator (AER) for the 2018-2022 regulatory period. This was in response to the AER’s Draft Decision which was released in September 2016.
Powerlink’s Revised Revenue Proposal at a glance
The Revised Revenue Proposal is focused on responding to consumer concerns over electricity prices by driving increased efficiency and delivering cost reductions.
Powerlink continues to align with the AER’s guidelines and approach to meet the needs of customers while allowing for the continued delivery of reliable supply of electricity.
The AER’s Draft Decision accepted most of Powerlink’s January 2016 Revenue Proposal, including operating expenditure forecast and rate of return methodology.
The key element which was not accepted by the AER was forecast capital expenditure required for network investment.
Powerlink has not accepted the AER’s Draft Decision and the Revised Revenue Proposal responds to matters raised by AER and includes a revised capital expenditure forecast.
Key Points of Powerlink’s Revised Revenue Proposal Include:
Electricity prices
31% reduction in indicative transmission price in the first year of the regulatory period. This reflects a 3% increase from Powerlink’s January 2016 Revenue Proposal. (The cost of high voltage transmission represents approximately 9% of total delivered energy costs for a typical Queensland (QLD) residential electricity consumer)
Translates to between $25 and $41 savings (2.9%) for the average QLD residential household annual electricity bill. An increase from the $22 to $37 savings outlined in Powerlink’s 2016 Revenue Proposal.
Price Growth remains within CPI over the balance of the regulatory period
Maximum Allowed Revenue (MAR)
Original proposed MAR $4.02B (smoothed) – AERs Draft Decision proposed a reduction of 7.4%
Powelink’s Revised Revenue Proposal for MAR is $3.74B
7% lower than Powerlink’s January 2016 Revenue Proposal for the 2018-2022 period
0.6% higher than the AER’s Draft Decision due to revised capital expenditure forecast
Forecast Capital Expenditure
Original proposed forecast expenditure $957.1M – AERs Draft Decision proposed a reduction of 19.3%
Powerlink’s Revised Revenue Proposal for total capital expenditure forecast is $886M
7% lower than Powerlink’s January 2016 Revenue Proposal for the 2018-2022 period
15% higher than the AER’s Draft Decision
The costs/revenue and percentages have been referenced from both AER and Powerlink published documents. There may be minor differences which could be the result of rounding and / or advising costs in smooth, nominal or real terms.
AER’s Final Determination is due to be released by 30 April 2017.
You can find more information regarding Powerlink’s proposal and the AER’s decision here.
We are experts in the National Energy Markets. Find out how we can save you money on your energy charges by contacting us here or on 07 3232 1115.
A severe heatwave in South Australia yesterday culminated in increased usage that pushed demand beyond the capabilities of the generators. This led to outages in the network as the market operator commenced load shedding.
Demand was the highest it had been for three years with the maximum five-minute demand set at 3077.47MW at 6:15 p.m. market time. This is despite a continued uptake of residential solar photovoltaic (PV) systems.
There were some interesting announcements leading into the period. The Australian Energy Market Operator (AEMO) was aware this was an unusual event and published a market notice at 3:15 p.m. (market time) to be aware that temperatures would be high across SA, NSW and QLD.
There were concerns surrounding reserves for SA most of the day. AEMO operates with three Lack-of-Reserve (LOR) levels.
LOR1: If the largest unit fails there will be a LOR2 condition
LOR2: If the largest unit fails, there will be a loss of power
LOR3: There is an actual loss of power. There is no solution in which all demand can be met
There were several LOR1 conditions during the day but AEMO didn’t respond. More interestingly was a LOR2 warning at 5:13 p.m. (market time) stating that AEMO was aware of an actual LOR2 condition forecast until 7:00 p.m. (market time). Required contingency was 200 MW but there was only 114 MW available. AEMO decided not to intervene but wanted to seek a market response. As we now know, the LOR2 turned into an LOR3 as wind generation reduced.
Figure 1: SA Generation and Demand 08/02/2017
The orange area represents the available generation for the state with the grey and yellow being the maximum support from the interconnector. The blue line is SA (five-minute) demand. The heat didn’t dissipate as the day wore on. Electricity demand continued to rise with the addition of domestic air conditioners as residents were returning home. The drop in the orange availability represents the reduction in wind. As wind kept reducing in capacity, there was insufficient power in the state to meet demand and there were rolling brown-outs.
Figure 2: SA wind generation and spot prices 08/02/2017
The 30-minute wind generation data shows the drop in availability. Wind generation is affected during hot weather as there isn’t enough energy in warm wind.
There are wide reports that additional power stations were available but didn’t run. Torrens Island A and Pelican Point each had a unit which was not available. It is unlikely there was enough gas going to the power stations to start another unit.
It is very questionable what market response AEMO was expecting at 5:13 p.m. since all available generators were on (except one unit at Pelican Point and one at Torrens Island A). From the outside, it looks like they were hoping LOR2 would not become LOR3.
With temperatures forecast at similar levels today, more outages can be expected. With the political backlash, it is unlikely there would be an appetite to curtail residential customers again. This could mean that AEMO and the Government may prefer to take the risk with business and commercial customers instead.
If you’re looking for stability in your energy pricing, please contact our energy procurement experts here or on 07 3232 1115.
A commitment by the Federal Government to reduce emissions by 2030 will see a Climate Change Review conducted this year. The government is focused on meeting our international emissions reduction commitments while also maintaining energy security and affordability. The focus of this review is to look at a range of options to reduce emissions by 26 to 28 percent below 2005 levels.
The review will consider the integration of climate change and energy policy, the impact of state-based policies on the national approach, the role of the Emissions Reduction Fund and its safeguard mechanism, complementary polices, and potential goals beyond 2030.
While the review does not explicitly mention the Renewable Energy Target (RET), there could be consequences for the RET. There is currently a concern that there will not be enough new renewable generation built in time to meet the 2020 target. This has led government backbenchers and some business people to call for the RET to be abolished. In the past, reviews into the RET scheme have caused the prices of Large-Scale Generation Certificates (LGCs) to reduce. Despite assurances that the current RET scheme will not be affected, discussion surrounding climate change policy may still affect the price of LGCs as the market factors in uncertainties.
The Climate Change Review is expected to be concluded by the end of 2017.
If you’d like to discuss what this means for your energy portfolio, please contact us here or on 07 3232 1115
Increased electricity demand in both Queensland and New South Wales during January 2017 has had a significant impact on electricity prices for this period.
Queensland maximum and average demand was 8 percent higher than January 2016, while New South Wales was 9 percent higher compared to the previous year.
Higher demand helped in setting record prices for both states. The Queensland spot price averaged $197.65/MWh for January 2017. The previous record for January was set in 2013 when the price was $155.90/MWh. New South Wales reached $82.69/MWh eclipsing the previous January record of $66.95/MWh set in 2001.
Higher spot prices are currently expected to continue for the foreseeable future with forward contracts for both regions currently trading above $80.00/MWh on the Australian Stock Exchange.
If you want to discuss your energy arrangements, get in touch with expert energy consultants by contacting us here or on 07 3232 1115.
Today the Australian Financial Review (AFR) has released a misleading news article which states that ERM Power has chosen to pay the penalty price of $65/LGC instead of paying the current market price of $90/LGC. This article has been released following an ERM Power announcement to the ASX yesterday.
Even at $90/LGC it is more efficient for ERM Power to purchase LGCs then pay ‘penalty price’. ERM are utilising the flexibility of the scheme to surrender LGCs in future years where they can off-set earnings.
ERM Power has a number of tax losses which they want to bring forward by paying ‘penalty price’ (which is not tax deductible) now and using the tax losses for other earnings. Over the course of the next three years, ERM Power is then able to purchase and surrender LGCs and gain future tax credits when they have earnings to offset. This frees up $37 million now which would otherwise have sat as tax credits against future earnings.
