As the Australian generation fleet transition to lower carbon emissions we are seeing the regulatory framework catching up. The regulatory framework is not the only aspect which is changing. We are experiencing an increasing amount of direct power purchase agreements being written between large users and renewable developers.
Economic models are also struggling to catch up. Almost every month a new forecast is published showing that if we just implement the latest proposed change to the market, we will see a return to the good old days of lower electricity prices. Part of this fallacy comes from outdated forecasting models which still look at cost of production as the main input to power prices. Short term price spikes and managing the grid in a sub-five minute period is increasingly important. Most current forecasting techniques fail to capture these factors as well as transient market power where a generator is able to set prices for a period by changing the volume offered in bid bands.
Behaviour is difficult to predict over the long term so most models assume rational behaviour in the long run. This is essentially sensible (it is very difficult to measure irrational behaviour) however begs the question how to model rational behaviour. In the electricity market, we will generally see future costs (over a very long term) trend towards the cost of bringing new plant online. If the long term prices are higher than the cost of new generation, someone should fund additional generation providing a natural cap.
The issue in current forecasting is determining the cost of bringing a new plant online. Traditionally, this has been the total cost of the plant divided by the number of MWh it produced. This provided a neat number expressed in $/MWh and is the basis for levelised cost of electricity (LCOE). The issue with using this number is that price profiles are changing and could be negatively impacted by the type of generation being evaluated. If we look at a solar farm in Queensland, we can estimate the production and the cost of the solar farm. This is the LCOE however it may not be the value of the solar farm, or produce the best estimate of the cap on long term electricity prices. In the event a large number of solar farms are built in the same location, there will be a large production at that time of day and not at others (evenings, mornings and overnight). Other generation sources will be required to fill the gaps. These other sources could have a higher cost and will only be built once there is a price signal to do so. The cost of electricity will be low during daylight hours when all the solar farms should be in full operation. This means that the value of the generation from solar reduces as more is built. This is not captured in the LCOE of generators. A new methodology which looks at the dispatch weighted (when generation occurs) achieved price will have to be considered when evaluating future electricity prices.
The impact of changing long term electricity forecasts are important. Many new plant rely on a component of their generation to be funded from the electricity spot market. With large changes in the assumed cost of electricity as models react to short term announcements it is very difficult to bank a project. On the other side, where consumers are being provided with different assumptions on future prices, it is difficult for them to commit to a purchasing strategy leading to more short term optimisation.
If you are considering a large investment in the electricity market, please call us on 1800 334 336 to learn more about the determination of electricity costs and gain a deeper understanding of the traded market.
Following the close of the financial year 2018 NGER reporting period, responsible entities will need to determine if they have exceeded their baseline under the Safeguard Mechanism.
The safeguard applies to around 140 large businesses that have facilities with direct emissions of more than 100,000 tonnes of carbon dioxide equivalence (t CO2-e) per year. This covers around half of Australia’s emissions. The entity with operational control of a facility will be responsible for meeting safeguard requirements, including that the facility must keep net emissions at or below baseline emissions levels.
There are various methods for a facility to meet its safeguard requirement depending on its emissions, how it operated during the financial year and its expected operation in the future. Understanding the best way of meeting the baseline is critical to avoid having to overpay under the mechanism. Responsible entities have until 31 October 2018 to submit their financial year 2018 report and apply for any change to benchmark calculations. If a responsible entity still exceeds their baseline, they have until 28 February 2019 to secure Australian Carbon Credit Units (ACCUs) to offset their excess emissions.
Edge is able to provide entities with data that supports your NGER reporting requirements. Edge also works with various buyers and sellers of ACCUs and can assist with the sale or purchase of certificates if required. Finally, if your business has been caught with excess emissions, Edge can proactively design strategies to help mitigate costs under the mechanism.
If you would like to explore services relating to NGER reporting requirements and have any questions regarding the Safeguard Mechanism, call Edge on 07 3905 9220 or 1800 334 336 or speak with your Edge Portfolio Manager.
By Thomas Dargue, Edge Manager of Markets & Advisory
The electricity market was active throughout autumn and the transition into winter. Spot prices were largely stable as has been the case ever since the Queensland Government directed Stanwell Corporation to adopt strategies to lower wholesale prices and Snowy Hydro Corporation seem to be willing to draw down their dam levels to keep prices in New South Wales below $300.00/MWh for each trading period.
Stable spot prices doesn’t mean that the market has been uneventful. In Queensland utility scale solar is expected to grow from only having Barcaldine Solar Farm (25 MW capacity) to more than 2,000 MW installed by the end of 2019. In November 2017 Kidston Solar Farm (50 MW capacity) started generating and since April 2018 we have seen the addition of Sun Metals, Clare, and Longreach solar farms with a combined capacity of 248 MW. Other solar farms are being commissioned at the moment including Hamilton, Whitsunday and Hughenden which means that Queensland will soon have 453 MW of utility scale solar. This is in addition to the small scale solar installed already in Queensland which is more than 2,000 MW and continuing to grow.
New South Wales continue to struggle with sufficient capacity.
To date Snowy Hydro has increased its output when prices looked like it was going to go above $300.00/MWh. This strategy has appeared to be successful with only two prices above this level ($300.80/MWh and $301.06/MWh on 25 July 2017 at 18:00 and 18:30 respectively) since the start of 2017. This defence of prices has come at a large cost to the dam levels with the main dam, Lake Eucumbene, dropping below 30% full which is the lowest level since 2011. In early June 2018, constraints prevented much of Snowy Hydro’s portfolio from being dispatched and the New South Wales prices spiked to $2,428.77/MWh and $2,447.89/MWh on 5 June at 17:30 and 18:30 respectively. The high prices followed large cloud cover reducing generation from solar farms and the removal of several large coal plant due to planned or unplanned outages. These outages persisted and there was another price spike on 7 June 2018 at 19:00 where prices in New South Wales reached $2,464.52/MWh. On both days where the prices were high, AEMO had warned that there were insufficient reserve of generation and Tomago Smelter had demand curtailed under their agreement with AGL.
Victoria was comparatively quiet during autumn. Spot prices remain high in a historical context with the period from 1 April to 30 June averaging $94.92/MWh – more than $10.00/MWh higher than New South Wales over the same period.
Victoria use to enjoy an abundance of cheap generation from their brown coal generators however have seen more imports from South Australia and New South Wales since the closure of Hazelwood Power Station. Victoria has an old fleet of highly polluting power stations and need an orderly transition to avoid suffering intermittent issues seen in South Australia.
Tasmania continues to manage their dam levels to avoid the constraints on local manufacturing plant which was experienced during the last extended outage on Basslink. There was trouble on the interconnector again with no flow between 24 March 2018 and 5 June 2018 following an accident during maintenance. The highly specialised nature of the underseas cable means that parts take a long time to procure and then be installed. Overall the state managed to supply electricity throughout the period. The reliability of Basslink is a further cause for concern as Tasmania is trying to become the “battery of the nation” by using its abundant pumped storage hydro sites to effectively store energy while there is excess renewable generation and produce electricity when there is less renewable generation being produced. If the electricity cannot be reliably transferred in and out of Tasmania, the investment decision is less attractive.
South Australia had more price periods affected by market intervention during May 2018 than any other time in the past. More than half (61%) of the time, the prices were affected by directions from AEMO.
Some of this is due to Pelican Point coming off 23 April 2018 and not returning until 23 May 2018. An intervention price occurs when AEMO has directed a participant (typically a generator) to dispatch in a different way to its bidding. This was typically used to direct a gas or diesel power station to operate through periods where the owner expected it to not be commercially viable to operate. This was done to strengthen the grid by securing sufficient synchronous generation remains online at all times. AEMO then calculates how the market would have settled if they hadn’t issued the direction. This calculation doesn’t take into account the fact that bidding may have been different if the direction hadn’t been issued. Participants could have chosen to turn on voluntarily or wait for higher prices. As such, this will distort the pricing signal provided in the market. Even though spot prices tend to be lower during these directions, participants that are directed are entitled to compensation which is ultimately paid for by the consumers. When the price signal is taken out of the spot market and put directly onto retailers (who pass the costs on), there is little incentive to solve the issue. The total amount of interventions have increased dramatically as the system is getting weaker however it also seems to be part of a new direction from AEMO. To put the number of interventions into context, there were roughly 20 times more intervention periods in May 2018 (5,451) than the 10 years prior (228) to the appointment of the CEO Audrey Zibelman.
Figure 1: Number of prices affected by intervention from AEMO
If the intervention continues, the spot prices will remain lower however the cost to the consumers could increase.
Overall spot prices were lower than the summer period with the cheapest spot prices being in the North and the East. Queensland had the cheapest prices followed by New South Wales and Victoria. Tasmania managed to end the period with lower prices than South Australia despite Basslink being cut off for part of the period.
Figure 2: Average monthly spot prices in the NEM
The more stable spot conditions saw the forward prices decrease across all the traded regions. The largest fall was in Victoria where prices reduced $8.97/MWh for calendar year 2019 contracts. New South Wales also reduced $8.43/MWh as spot prices remained stable. The forward prices are now similar across Victoria, New South Wales and Queensland however South Australia continues to trade higher than the other regions. This is in part due to expectations that the spot prices are likely to stay higher than elsewhere and partly as firm contracts are more difficult to get as many renewable generators are unable to offer firm prices. Recently Snowy Hydro has been acquiring power purchase agreements with renewable generators and released a tender for up to 800 MW of additional renewable generation. It is likely that Snowy Hydro will use its pump storage hydro plant to firm up the renewable generation offering more firm contracts.
Table 1: Calendar year 2019 forward contracts
NSW
QLD
SA
VIC
1 March 2018
76.58
64.05
94.36
82.9
31 May 2018
68.15
62.64
87.00
73.93
If you would like to discuss the electricity market outlook and potential impact to your electricity portfolio, please contact our Manager of Markets & Advisory, Thomas Dargue on 07 3905 9226 or on 1800 EDGE ENERGY.
The Energy Security Board (ESB) released a new version of the proposed National Energy Guarantee (NEG) following feedback from a variety of interested parties. The ‘Draft Detailed Design of the National Energy Gurantee: Consultation Paper’was released 15 June 2018. Also included was a paper by the Federal Government setting out the proposal for key areas of legislation which will be set at a Federal level. To support the papers a number of technical working papers were released to explore key aspects of the NEG.
The new version remains focused on reducing emissions in line with Australia’s commitment under the Paris Agreement and ensuring reliability. In addition to these key priorities, a third priority was to ensure that electricity remained affordable going into the future.
In regard to emissions, the largest change from the original version is a voluntary decoupling of the electricity contract written and the emissions levels. A retailer will still need to purchase contracts to keep emissions below a set threshold, however the emissions will no longer have to come from the same contracts that they have purchased electricity from. In theory, a retailer can purchase the output of a coal fired power station however not take on the emissions. That retailer would then be exposed to the emissions at the spot market which could be met through a separate contract with a renewable generator for only the emissions component.
In practical terms, the current proposed NEG is for all intents and purposes a cap-and-trade scheme. A retailer will be provided a cap on emissions. If they exceed that cap, they will have to purchase emissions credits from a low emitting source. If they are under the cap, they can sell their over commitment to other retailers. There will be the option to carry forward a limited amount of a previous compliance year’s over-achievement, for use in a later compliance year.
Reliability will come from AEMO’s forecast of supply adequacy. Each year, AEMO estimates supply adequacy for the following 10 years. If a material gap is identified, AEMO will notify liable entities (likely to be retailers and large users 5MW or greater) that there may be a reliability obligation. If the material gap is still present 1 year out, AEMO may start procuring demand response or additional generation. At this stage all liable entities must disclose their contract position to the AER. If a period with a projected reserve gap has demand above a one-in-two-year event, AER will monitor compliance against the reliability target. Each liable entity must demonstrate that they have procured sufficient qualifying contracts (such as fixed price contracts of a suitable nature, demand side management, or firm generation) to cover their position during peak demand. It is proposed that a reliability gap will also trigger liquidity obligations for vertically integrated retailers to make financial contracts available to the market via the central exchange. Furthermore, it is proposed that large users may transfer their reliability obligation to their retailer, but will have to ensure that their Electricity Sale Agreement addresses this. If a liable entity has insufficient qualifying contracts, penalties may apply. The level of penalties is undecided however a suggestion has been made to link to AEMO’s cost of procuring responses.
As with anything, the cost of both the emissions and the reliability components
of the NEG is likely to be passed on to consumers.
Modelling done to justify the introduction of the NEG assumes that the certainty brought by the NEG will reduce the risk premium of new power stations and cause more trading to occur. Both these factors would likely bring down energy prices (compared to business as usual). However, if the market does not see this as a much more stable investment environment, a reduction in wholesale prices is unlikely to materialise.
The NEG will expose consumers to both emissions and reliability costs. In terms of the emissions component, for most consumers this will be another pass-through cost added to their bills. Any trigger of a reliability gap could drive the cost of acquiring qualifying contracts (such as financial contracts) much higher in the relevant period. Whilst the liquidity obligation aims to counter this, we have concerns around how this will be enforced. It is critical to protecting against extortionate costs under this component. The current version of the NEG discusses a number of ways of addressing this and the ESB recommends creating a new repository for contracts as well as a market liquidity obligation. The repository would be able to report on all over-the-counter (non-exchange traded) products including volume and price. This may only be reported in aggregate for the market instead of identifying the parties to the deal. Very little detail is provided regarding the register. The market liquidity obligation would require large vertically integrated retailers to make contracts available where there is a reliability gap. The retailers must offer to buy and sell contracts at a maximum spread so that prices can’t be set too high for buyers and too low for sellers. As with the repository there are few actual details on the liquidity obligation.
The emissions component has the potential to be highly variable from retailer to retailer. Each retailer will look at the generation they have produced and what emissions contracts they have purchased. If they haven’t purchased sufficient contracts for their entire load, they will assume to have procured the rest at spot. The spot emissions is calculated as the total emissions intensity of all generation less the generation volume already contracted in the emissions registry. A retailer or consumer is unlikely to know in advance how much will be forward sold and therefore the emissions costs can be highly uncertain. The retailer is likely to pass through this cost directly to the consumers, who ultimately wears the risk.
It is critical for all consumers who are agreeing electricity contracts with their retailers to understand how things such as the NEG are managed by their retailer and passed through. For the more sophisticated purchasers there is an opportunity to proactively manage some of this exposure themselves.
The Federal Government will continue to make laws regarding three key areas of the NEG. The key areas are:
Setting emissions targets
Treatment of emissions-intensive trade-exposed industries; and
The role of external offsets
There is a separate paper exploring these issues. The emissions targets are proposed to be expressed in tonnes of CO2-e/MWh. The target will be to meet a 26% reduction on 2005 levels by 2030. This is the target which was set at the Paris Agreement. There has been some criticism that if electricity only meets their proportion of the reduction, all industries will have to make the same reductions. The criticism is that it is much more economical to meet a greater share of the obligation from the electricity sector where alternatives to carbon emissions are cheaper than in other sectors.
The Federal Government is proposing to keep emissions-intensive trade-exposed industries exempt from the NEG obligations. This is to maintain international competitiveness.
This means that the rest of the electricity market will be required to purchase
additional volume to make up for the exemptions.
The paper also discusses the role of external offsets including the Australian Carbon Credit Units (ACCU) which are currently part of the Federal Government’s safeguard mechanism. They have also opened up to the possibility of allowing a limited number of overseas certificates be used for surrender.
There are still some large outstanding issues with both the ESB and the Federal Government’s papers. The ESB is pushing ahead to get a decision from the COAG Energy Council in August 2018. To facilitate this date, the turn-around time for comments are limited. The Federal Government is seeking comments by Friday 6 July 2018 and the ESB wants their comments by 13 July 2018. The commencement date of the NEG is due to be 1 July 2020.
If you would like to understand more about the NEG and the potential impact it may have on your energy portfolio moving forward, please visit edge2020.com.au or alternatively you can call one of our team directly on 07 3905 9220 or on 1800 EDGE ENERGY.
The Australian Energy Market Commission (AEMC) has released its schedule of reliability settings which outlines the maximum price for electricity for both an individual dispatch interval as well as the maximum cumulative price. The current maximum price of $14,200/MWh will increase to $14,500/MWh and the cumulative price threshold will increase from $212.800 to $216,900.
The maximum price sets the highest cost a generator can be paid in any period and consequently what a consumer can be exposed to. It is escalated each year in line with CPI to encourage new peaking plant to enter the market if needed.
The cumulative price threshold aggregates the trading intervals over the last seven days. If they add up to more than the cumulative price threshold, the prices received by a generator and paid by a retailer will be $300.00/MWh, until the day after the aggregate of the last seven days drop back below the cumulative price threshold. This is put in place to ensure retailers are not exposed to unlimited price risk if there are local issues in a region.
The market floor price (minimum price a generator can receive) has not been escalated and is staying the same at -$1,000/MWh.
All changes take effect 1 July 2018 and more details can be found on the AEMC’s website here.
If you would like to understand how these changes will affect your energy prices please contact Edge on (07) 3905 9220 or 1800 334 336.
Quarterly forward contracts from Q118 to Q219 declined across all mainland regions in the National Electricity Market (NEM) yesterday. The largest decline was in the illiquid South Australian market where Q219 prices dropped by $9.75/MWh. Queensland contracts are currently the most affordable which is driven by the surplus of firm capacity in the region and a direction from the Queensland Government last year to Stanwell Corporation to lower wholesale prices. New South Wales contract prices have declined since the beginning of 2018 driven by lower than expected spot price outcomes in the region. Snowy Hydro corporation have been instrumental in reducing volatility in the region aggressively defending the $300.00/MWh cap price. VIC contracts have softened in the last week potentially raising interest for participants to hedge volume who have been on a hold.
The following prices are end of day closing prices from the ASX.
Table 1. QLD Forward Contracts ($/MWh)
Queensland
27/3/2018
26/3/2018
Daily Change
Daily Change (%)
Q118
$70.36
$70.67
-$0.31
-0.44
Q218
$67.50
$67.50
$0.00
0.00
Q318
$66.05
$67.73
-$1.68
-2.54
Q418
$67.02
$68.73
-$1.71
-2.55
Q119
$81.00
$82.70
-$1.70
-2.10
Table 2. NSW Forward Contracts ($/MWh)
New South Wales
27/3/2018
26/3/2018
Daily Change
Daily Change (%)
Q118
$71.80
$72.00
-$0.20
-0.28
Q218
$77.00
$77.50
-$0.50
-0.65
Q318
$77.00
$78.75
-$1.75
-2.27
Q418
$70.65
$71.60
-$0.95
-1.34
Q119
$81.81
$83.10
-$1.29
-1.58
Table 3. SA Forward Contracts ($/MWh)
South Australia
27/3/2018
26/3/2018
Daily Change
Daily Change (%)
Q118
$116.15
$116.15
$0.00
0.00
Q218
$98.25
$108.00
-$9.75
-9.92
Q318
$89.00
$91.00
-$2.00
-2.25
Q418
$84.00
$85.75
-$1.75
-2.08
Q119
$120.00
$120.00
$0.00
0.00
Table 2. VIC Forward Contracts ($/MWh)
Victoria
27/3/2018
26/3/2018
Daily Change
Daily Change (%)
Q118
$102.75
$103.00
-$0.25
-0.24
Q218
$83.50
$86.50
-$3.00
-3.59
Q318
$82.75
$84.76
-$2.01
-2.43
Q418
$76.00
$78.78
-$2.78
-3.66
Q119
$98.43
$100.85
-$2.42
-2.46
If you would like to know more about energy costs and the state of the energy market, please contact Edge on (07) 3905 9220 or 1800 334 336.
The Australian Financial Review has reported Alinta as the preferred bidder for the Victorian brown coal station Loy Yang B, offering in the range of $1 to $1.3 b for the power station which accounts for roughly 20% of coal capacity in Victoria. There is another interested party, China Resources which are believed to have made a higher bid, however would require approval from its Chinese parent company as well as Australia’s Foreign Investment Review Board (FIRB). Alinta already has FIRB approval.
Current owner ENGIE is expected to make a decision regarding the sale a next weeks board meeting in Paris.
It is conceivable that more contracts will be made available in Victoria after the sale is announced. ENGIE would have been cautious in signing up new contracts without knowing the future ownership of the power station and Alinta will not be able to sell contracts before the sale is confirmed. This could ultimately put downwards pressure on contracts in Victoria.
Any downward pressure on price would be a welcome relief in Victoria. Prices for electricity on the Australian Stock Exchange for calendar year 2018 delivery in Victoria has increased more than 50% from 1 January 2017 to the end of October 2017. The announcement is not expected to reverse this increase, however could provide some relief.
If you would like to understand how the announcement affects your portfolio, please contact Edge on (07) 3232 1115.
On Tuesday 24 October, Queensland Treasurer Curtis Pitt and Energy Minister Mark Baily announced a new suite of measures to create electricity savings for Queenslanders under the Palaszczuk Government’s Affordable Energy Plan.
One of the initiatives announced will be the removal of Ergon’s non-reversion policy. The non-reversion policy prevented customers who transferred away from Ergon Retail from returning. The Government believes that removing this policy will give customers in regional Queensland more choice when selecting a retailer. Not only will regional customers be able to shop around, but they will now have the ability to test the water and return to Ergon Retail should they wish to do so. Coupled with this announcement, Ergon Retail are now offering ‘EasyPay Rewards’ whereby regional customers could earn discounts of up to $75 for residential households and $120 for small businesses every year.
Other initiatives under the Affordable Energy Plan included:
Rebates of up to $300 to purchase an energy efficient fridge, washing machines or air conditioner, providing bill savings of up to $50 a year for an energy efficient washing machine or fridge or $135 a year for an air conditioner. Up to 100,000 Queensland households are expected to take up the offer.
An Asset Ownership Dividend of $50 a year for every household bill over the next two years, starting from January 2018 and evident on bills from the second quarter of 2018.
Another 4000 regional households can save up to $200 through the expansion of the Energy Savvy program.
Support for primary producers by delivering an additional 200 energy audits to agricultural customers through an expanded Energy Savers Plus program in partnership with the Queensland Farmers’ Federation, as well as providing a 50% co-contribution (up to $20,000) to implement audit recommendations.
Support for Queensland jobs and industry by providing energy audits for large customers including manufacturers, with a 50% co-contribution to implement recommendations (up to $250,000 per customer). This is expected to deliver savings of 10% to 40% for large industrial customers.
No-interest loans to help those Queenslanders who don’t have access to the upfront capital required to invest in solar and battery technologies to help reduce their bills and be part of a clean energy future. Queenslanders will be able to apply from March 2018, with savings of up to $700 per year expected for those who take up solar.
The initiatives are planned to be available from 1 January 2018, with calls for applications for Ergon’s EasyPay Rewards open now.
QLD energy retailers have been requested by the QLD Premier to pass on lower electricity prices to customers or face public shaming and increased competition through a new government owned retailer.
The lower electricity prices are driven by the QLD Governments intervention in the market which consists of ordering Stanwell Corporation (state owned) to lower wholesale prices, the $770 million subsidy for non-solar households for QLD Solar Bonus Scheme and the recommissioning of the Swanbank E Gas power station. Premier Palaszczuk promised to name and shame retailers who did not commit to the pledge by this Friday. Moving forward, Ms Palaszczuk confirmed that her government and the QLD Competition Authority would be monitoring retailers on a quarterly basis. If it is found that retailers are not passing on the savings then she would order a re-entry by the government into the retailing sector.
The Federal Government has released its Powering Forward Plan which seeks to reduce electricity prices while still delivering reliable energy and meeting Australia’s international commitments on carbon reduction. The plan is wide ranging and includes direct subsidies to vulnerable households as well as improved transparency in the gas market.
The Plan will look at putting obligations on the retailers to secure a minimum amount of synchronous generation. It was also confirmed that the Government would not be implementing the Clean Energy Target proposed by Finkel, however will obligate retailers to purchase an amount of low-emissions generation. The targets have not been set at this stage.
It was also reported that renewable generators which were built after 2020 would not be eligible to receive large-scale generation certificates. Any renewable generation built before 2020 would still be eligible (subject to current eligibility criteria) to create certificates out to 2030.
The market responded with increased prices. Until there is further clarity, the market will remain nervous.
If you would like to know more about this announcement and how your business may be affected, please call one of our team members on 07 3232 1115 or contact your Edge Portfolio Manager.
