We have all seen recently the impact that COVID-19 has had on global markets, in terms of stock prices, equity markets and of commodity markets.
Exacerbating this was the poor timing of Saudi Arabia and Russia’s spat over oil prices and both choosing to disagree on production levels, the disagreement lead to Saudi Arabia choosing to flood the oil markets with supply inevitably driving oil prices down significantly, with the WTI Crude Oil index reaching its lowest point in the last 5 plus years or so, trading in the low to mid $USD 20/barrel, also impacting the Brent Crude Oil index, which fell to its lowest point in the last 5 years or so to prices of the high $USD 20/barrel. Both events have lead to something quite astounding, with Bloomberg Green on the 23rd of March 2020 calculating that coal was officially the world’s most expensive fossil fuel.
Source: Bloomberg Green – Bloomberg 2020
This does not come as a huge surprise when the oil price has tanked off the back of a trade war between Saudi Araba and Russia, two of the largest producers of oil in the world. Additionally, international gas prices have also tanked with majority of long-term gas deals linked to an oil price index (likely Brent Crude) and the Japan Korea Marker – a major LNG (liquefied natural gas) index for Asia also falling with a supply glut due to reductions in demand from some of the largest demand centres such as China who went into a full lockdown earlier this year due to COVID-19.
According to Bloomberg calculations (Bloomberg 2020), the significant fall from grace in oil prices has meant that global crude benchmark is now priced below the Australian Newcastle coal index, which sat at $66.85 a metric ton on ICE Futures Europe on the 23/03, equivalent to $27.36 per barrel of oil with Brent futures that day ending at $26.98 per barrel.
If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.
The South Australian (SA) region has been separated from the remainder of the NEM regions due to the destruction of the main alternating-current (AC) interconnector between SA and Victoria (VIC).
What occurred:
On the 31st of January 2020 during wild storms that lashed eastern SA, western VIC, the 500kV main (AC) interconnection cable running through southwestern VIC was disconnected due to transmissions towers east of Heywood (Victoria) and west of Geelong (Victoria) collapsing in damaging storms and extremely strong winds.
When this occurred,
Interconnection flows quickly swung from exporting MW’s into VIC, to importing MW’s into SA.
Alcoa’s Portland aluminium smelter tripped which only exacerbated the problem,
A handful of wind farms were cut off from the market including McCarthur Wind Farm (420 MW) in Victoria, and the three Lake Bonney Projects in South Australian (~278.5 MW)
What does this mean:
Basically SA has been left to fend for itself, cut-off from the rest of the NEM
All MW’s (majority of all, with the small Murraylink direct-current interconnector still available) and frequency control services must be sourced from SA, locally.
Currently all SA generators are running hard and optimising portfolio’s for frequency control services (FCAS) prices rather than regional reference prices (spot price)
Additionally, a vast majority of gas-fired generation units including, Osbourne GT, Pelican Point, Torrens Island A and B units have and continue to receive market intervention notices from AEMO requiring them to be online
This is adding to the oversupply in the region with wind generation quite strong for this time of the year,
Not to mention, the wind generation, being a variable generation type, is not helping from a forecast perspective for AEMO, adding to the FCAS costs and requirements in the SA region.
Solution:
AEMO have indicatively provided a two week return time off the back of AusNet’s (interconnector owner) initial assessment and action plan to fix the interconnector.
AusNet’s solution is to construct temporary interconnection with power poles and lines to have arrived on site yesterday (03/02/2020).
Current weather forecast and impact on spot price:
Currently temperatures are set to be relatively mild for an SA summer at this stage.
However, temperatures are expected to reach the late 20’s and early 30’s towards the end of the week, historically, temperatures at these levels have encouraged higher demand and the need for imports from VIC, which will not be possible with the largest interconnector between the two regions out of action.
Although we are seeing some extreme lows in spot price, there is the possibility we could see some extreme highs. It is dependent on:
AEMO’s intervention in the market with AEMO issuing FCAS targets to participants in the realm of $300/MWh for raise and lower services (due to the inability to source FCAS from outside of SA), and
Generators potentially looking to spike spot prices or increase the spot price with no doubt, gas generator running costs no doubt increasing every MWh the interconnector is out of action.
If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.
Electricity spot prices in Q419 (October to December) were softer than the prior two Q4’s in Calendar Year 2017 and 2018. Q419 prices continued to be relatively mild following on from Q319’s performance. We did start to see a little more volatility creep into the spot prices towards the end of the year mainly due the bushfire disaster around the NEM and also with heatwave conditions starting to form.
Figure 1: Historical prices for Spring/Summer
(Source: AEMO)
Throughout October and November 2019, we saw milder temperatures and above average wind generation in both VIC and SA with the Bureau of Meteorology (BoM) indicating that a longer than expected Negative SAM (Southern Annular Mode) event was resulting in cooler than expected temperatures and stronger and more frequent westerly winds which was only helping drive solid wind generation levels in the southern NEM regions. As a result, both VIC and SA experienced multiple negatively priced half hours during the daylight hours, with interconnector constraints really dragging down SA’s spot price causing an oversupply in the region; however, cooler temperatures in VIC drove peakier morning and evening peak prices, keeping its spot price for October at least relatively elevated.
SA did however receive a taste of Summer peak pricing and demand, with extreme temperatures leading to a max of 44.8 degrees in Adelaide 19/12. Overnight temperatures on the 19/12 were above 33 degrees in Adelaide at 7pm encouraging the use of air-conditioning and leading to a ramp spike in demand which encouraged a full hour of VoLL (value of loss load) pricing at $14,700/MWh.
Assisting VIC’s peak pricing was the continued downtime of AGL’s Loy Yang A2 unit and Origin’s Mortlake Unit 2 with Mortlake making a return in December 2019, and Loy Yang A2 back for Christmas, offline again shortly after, then offline again for the remainder of the 2019 calendar year. Assisting VIC’s spot price for the quarter was a surge in price in Tasmania for October 2019. With Basslink offline the entire month of September 2019, it would seem both the Basslink operator and Hydro Tas had to play catch-up, keeping the spot price elevated for majority of the October 2019 month, allowing Tas to come away with the highest spot price for October 2019 of all NEM regions.
QLD experienced relatively mild demand and temperatures for the Spring months, and with an already oversupplied market, the introduction of Clean Co and their remit from the QLD government to run down spot prices, and Shell’s take-over of ERM, challenging the market dynamics, resulted in softer than expected spot prices for October and November 2019.
NSW had an interesting run over Q419, sharing in the spoils of the elevated spot prices in VIC and Tas in October 2019 with multiple baseload generators out of action for maintenance, to then dealing with the bushfire crisis in late November through December 2019, resulting in demand losses and cutting generation off from the NEM. Snowy Hydro’s Upper Tumut Pumped Hydro and Tumut 3 Hydro units dispatched frequently throughout the quarter, particularly in December 2019 also choosing to spill at relatively weak spot prices around the $70/MWh mark. I do wonder if we will continue to see Snowy spill at such weak spot prices with water levels at lake Eucumbene starting to plateau at ~30% after a steady incline throughout the last Quarter.
Obviously, impacting all regions in December 2019 was the holiday season shutdown of workplaces and schools, driving lower demand throughout the month.
Figure 2: Average monthly spot prices in the NEM
(Source: AEMO)
Friday the 22nd of November saw The Council of Australian Government’s Energy Council meet in Perth to discuss the current and future state of Australia’s Energy network. The key focus for COAG’s energy council was energy security and reliability focussing on Summer 2020 in the near-term and potential changes required for future state surrounding those two variables and of course how to make energy more affordable. Additionally to this, the COAG Energy Council also threw its support behind a National Hydrogen Strategy as laid out by Australia’s chief scientist, Dr. Alan Finkel. AEMO presented to the council outlining how they have prepared for Summer 2020, however COAG’s Energy Council has put forward a call for the Energy Security Board to reassess and to re-jig the current reliability standard (a measure used to ensure enough spare capacity is in the grid to cope with extreme demand days).
Fed Energy Minister Angus Taylor was seeking tougher reliability standards with the rapid influx of renewable generation that now makes up a significant chunk of Australian energy supply, whilst Victorian Energy Minister Lily D’Ambrosio wants tougher standards to deal with the ailing coal-fired generators in her region; either way both were seeking the same result.
There is however the push for higher reliability standards will lead to further ‘gold-plating’ of the network and inevitably higher energy prices for consumers. Probably one of the more surprising outcomes of the COAG Energy Council meeting was the vast support for a National Hydrogen Strategy as put forward by Dr. Alan Finkel and supported by Angus Taylor on the 22nd of November. $370 million dollars will be committed by the Clean Energy Finance Corp (CEFC) and the Australian Renewable Energy Agency (ARENA) to kick start and bankroll “electrolyser” projects, which can convert electricity to hydrogen and allow energy to be stored and transported. Mr Taylor’s support for a national hydrogen industry was met with some backlash however with the Energy Minister stating investment in the technology should be fuel neutral, ie. produced via any means including utilising coal-fired generation to produce the fuel rather than purely utilising renewable sources. The call however was also backed by the need for the hydrogen to have a certificate of origination attached to the sale of the commodity.
In December 2019, it was reported that the Australian Energy Market Operator (AEMO) has procured record volumes of energy reserves for what the Bureau of Meteorology (BoM) is forecasting to be another record Summer in terms of temperatures on the East Coast of Australia. The BoM is forecasting a hot and dry Summer 2020 leading to concerns, particularly for VIC and SA that the two regions could see a repeat of the conditions that inspired both regions in the Summer of 2019 to reach the market price cap after several hours at VoLL (Value of Lost Load) ~ $14,500/MWh ceiling on 24th and 25th of January 2019. The concern that we could see a repeat of these conditions has resulted in AEMO securing 1,600 MW of emergency reserves to assist in keeping the grid energised through summer 2020. The large volume of reserves has not come cheap with an estimated cost of $44 million of which is obviously not guaranteed to be required at all. AEMO has stated that almost 1,000 MW of the reserves secured is available in VIC and SA which have been identified as the “trouble zones” come Summer, with the remaining 600 MW located in NSW/QLD for those extreme conditions days.
The above spot price outcomes resulted in a significant decline in furtures pricing with all curves around the NEM regions and across multiple CAL and Quarterly products all falling away with weaker than anticipated expectations for Summer 2019/2020.
Looking Forward:
Figure 3: Calendar year 2020 forward contracts
$/MWh
NSW
QLD
SA
VIC
TAS
24-Jan-19
$ 70.32
$ 56.36
$ 66.35
$ 71.79
$ 84.96
(as at 31/12/2019)
(Source: ASX)
If you would like to discuss the electricity market outlook and potential impact to your electricity portfolio, please contact our Manager Wholesale Clients and Markets, Alex Driscoll on 07 3905 9220.
The World Economic Forum was held late last week in Davos (Switzerland) with foreign leaders all around the globe coming together to talk about the global economy and hopefully generate some fruitful action.
Probably one of the more market shifting proposed schemes put forward at the World Economic Forum was that of European Commission President, Ursula von der Leyen. Von der Leyen’s proposal is a daunting one from Australia’s point of view, as it could have a significant impact on the country’s vast economic dependence on exportation of minerals and goods.
The proposed scheme, labelled the ‘carbon border adjustment mechanism,’ would be a tax applied to carbon-intensive good from those countries that are not pulling their weight as to lowering emissions under the Paris climate accord.
The economy likely to feel the brunt of this proposed tax-scheme would be China, with the scheme’s proposed first target industries being steel, cement and aluminum. Von der Leyen did however message the scheme could expand into the mining and resources sectors.
Although Australia’s most prominent trade partner in the resources sector is China, Europe was a big receiver of coal exports from Australia in 2019 and could very well be in the firing line with constant debate between Australian politicians and other world leaders as to whether Australia is indeed pulling their weight per the Paris agreement.
If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.
Current weather conditions are placing an increased reliance
on the diminishing water catchments across Australia. These water catchments
store water for use by various parts of the local community including drinking
water for residents, irrigation and Electricity generation.
Stanwell recently announced water sustainability is a top
priority for its Tarong Power stations located within the South Burnett region.
Water is an essential necessity for thermal power stations to make electricity. The water is used for steam production and cooling.
Tarong power station consisting of 4 X 350MW thermal units
and a 443MW supercritical unit. These units obtain their water from two
sources, the primary source is Lake Boondooma and secondary from a pipeline
using water from Lake Wivenhoe or recycled water produced under the Western
Corridor Recycled Water Scheme.
Stanwell corporation is focusing on mitigating the impact on
the South Burnett community by reducing the usage of water from Lake Boondooma
to ensure the South Burnett community have access to drinking water. Initial
initiatives used at the power station to reduce the reliance on Lake Boondooma water
include the use of recycled water from the ash dam and stormwater.
Tarong Power Station have access to water from Lake Wivenhoe if Lake Boondooma drops below 34%, currently the Lake Boondooma’s level is 22.95% as of the (Source: SEQWater 2020). Lake Wivenhoe water also comes at an added cost. Water is currently the highest operating cost for Tarong Power Station.
An alternative to using Lake Wivenhoe water is the use of
purified recycled water from the Western Corridor Recycled Water Scheme. The
scheme is not currently in operation, however when operating and supplying
water to Tarong Power Station it will add significantly to the costs of
generation.
Tarong Power Station first used purified recycled water from
the Western Corridor Recycled Water Scheme in June 2008 following a similar
water supply limitation brought on by the 2008 drought.
As a result, the increasing marginal cost to generation
caused by the higher water cost, Tarong Power Station may change its operation
and reduce generation or dispatch its units at higher prices. Under either scenario
this may increase the cost of wholesale energy in Queensland.
If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.
The SA Government (South Australian Minister for Energy and Mining) has the power (under South Australian Legislation) to trigger a Retailer Reliability Obligation (RRO) upon informant from AEMO of a one-in-two year peak demand forecast shortfall event as published in the South Australian Gazette 17 December 2019, with the AER confirming and publishing the notice 9 January 2020. For the avoidance of doubt this means that unlike all other regions which require the Electricity Statement of Opportunity (ESOO) to predict an unserved energy event, SA can act independently without approval as such from the AER.
The RRO was trigged for South Australia on the 9 January 2020 for the following periods:
First Quarter (Q1) for Calendar Year 2022
First Quarter (Q1) for Calendar Year 2023.
The periods of concern according to AEMO’s forecasting includes:
each weekday from 10 January 2022 – 18 March 2022 for the trading periods between 3pm and 9pm EST;
**(Peak demand expected to be 3,030 MW)
each weekday from 9 January 2023 – 17 March 2023 for the trading periods between 3pm and 9pm EST
**(Peak demand expected to be 3,046 MW)
A T-3 Instrument has been created and the Market Liquidity Obligation (MLO) of the SA region’s largest generation businesses, Origin, AGL and Engie have been called upon and are to begin trading exchange-listed (ASX approved products) for Q12022 and Q12023 from 7 February 2020.
With the triggering of the RRO, the South Australian Minister has made a T-3 instrument (under NEL Part 7A 19B (1)):
Q1 2022: This T-3 Reliability Instrument applies to the South Australian region of the National Electricity Market for the trading intervals between 3pm and 9pm Eastern Standard Time each weekday during the period 10 January 2022 to 18 March 2022 inclusive. The Australian Energy Market Operator’s one-in-two year peak demand forecast for this period is 3,030 Megawatts.
Q1 2023: This T-3 Reliability Instrument applies to the South Australian region of the National Electricity Market for the trading intervals between 3pm and 9pm Eastern Standard Time each weekday during the period 9 January 2023 to 17 March 2023 inclusive. The Australian Energy Market Operator’s one-in-two year peak demand forecast for this period is 3,046 Megawatts.
With the T-3 instrument created by the SA Energy Minister, this has triggered the MLO, effectively a market making obligation on the parties identified above to reasonably offer liquid exchange-listed products for the identified shortfall periods.
Obligated MLO participants such as Origin, AGL and Engie will from 7 February 2020 begin offering exchanged-listed products for both Q12022 and Q12023.
The triggering of the RRO means retailers and large load consumers can start procuring volume for their forecast demand for Q12022 from as early as 7 February 2020, and no later than 31 December 2020, the T-1 instrument implementation date (13 months prior to the shortfall period identified).
If you would like to know more, please contact Edge on 07 3905 9220.
A new market notice within the National Electricity Market (NEM) posted by the Australian Energy Market Operator (AEMO), one we have not see before was issued to all market participants on the 23/12/19. The market notice requested and served as a reminder for all semi-scheduled and intermittent non-scheduled generators to ensure they update their market availability bids, update their SCADA Local Limit or, if unavailable, advise AEMO control room to implement a quick constraint to the reduced available capacity level; and update intermittent generation availability in the EMMS Portal to reflect reduced plant availability as is required under the National Electricity Rules (NER), per NER 3.7B(b).limits.
This was an interesting constraint for AEMO to issue as it was due to extreme heatwave conditions across the south east coast of Australia, and as with most generating plant, under extreme heat, some form of derating on its physical capacity and output can occur. On the 23/12/19 AEMO’s weather service provider was forecasting extreme high ambient temperatures across all NEM regions, hence AEMO’s market notice to these participants to remind semi-scheduled and intermittent non-scheduled generators to advise AEMO of any reduction in available capacity caused by temperature derating.
Particularly interesting is that the often “set and forget” approach to renewable generators such as solar and wind generators, as classified by AEMO as semi-scheduled generation is being watched with greater scrutiny, particularly after the events of 2016 in SA where a state wide blackout was triggered by a severe weather, damaging more than 20 towers, downing major transmission lines, and with multiple wind farms currently shouldering some of the blame for the state going black due to the wind farms switching off when the transmission lines went down.
Semi-scheduled: A generating system with intermittent output (like a wind or solar farm), and an aggregate nameplate capacity of 30 MW or more is normally classified as a semi-scheduled generator unless AEMO approves its classification as a scheduled generating unit or a non-scheduled generating unit. AEMO can limit a semi-scheduled generator’s output in response to network constraints, but at other times the generator can supply up to its maximum registered capacity (AEMO 2014).
If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.
The federal government recently announced an agreement to underwrite new gas turbines in Victoria and Queensland to provide relief from expected high peak prices. The operation of these assets, below the usual short run marginal cost of current open cycle gas turbines (QLD – $106 / MWh – AEMO 2019) will potentially limit the likelihood of high prices or price volatility over the morning and evening peaks resulting in reduced average spot outcomes.
Under the new generation underwriting plan, which was proposed by the ACCC, the government will assure an amount of the electricity generated will be purchased for a set period into the future.
The Victorian generator will be located at Dandenong, south-east from Melbourne’s CBD and the Queensland asset will be located near Gatton, 90km west of Brisbane.
The 132MW Queensland generator is proposed by Quinbrook Infrastructure Partners, while the 220MW Victorian asset is proposed by the APA group.
Mr Taylor (Minister for Energy and Emissions Reduction) has previously said the government had been “hard-nosed” with these projects and each of them would have to prove commercially viable and benefit the jurisdiction in which they were going to operate.
Both projects are expected to commence construction next year once private sector finance has been secured.
If you would like to know more, please contact Edge on 07 3905 9220.
Alex Driscoll, Manager Wholesale Clients and Markets
Electricity spot prices in Q319 (July to September) were relatively in line with Q3 2017 and 2018, however much higher than prices seen from 2014 to 2016 inclusive. Although, Q319 prices were softer than any other quarter for the year (2019) in majority of the NEM regions. The past three months have seen multiple negative price events in SA and QLD due to mild demand, constrained interconnectors and strong renewable generation volumes in solar (rooftop PV and large scale) and wind.
SA’s Q319 price is on a downward trajectory from the massive jump-up it experienced in 2016, taking with it NSW and QLD which both had lower Q319’s in comparison to the last 2 years. Whilst VIC and Tasmania’s Q319 regained in price post a slump in Q318.
Figure 1: Historical prices for autumn
(Source: AEMO)
Throughout Q319 both QLD and SA experienced multiple negative price events and settlement periods. These events in QLD were lead by a combination of transmission line works on the QNI restricting its flow into NSW, low demand, strong solar rooftop PV and large-scale solar generation and interesting bidding behavior by QLD thermal generation.. Fuelling the low and negative price events was market participant bidding behaviour. It can be seen in the bid stacks, that around mid-August 2019, Stanwell Corp shifted an additional ~500 MW of generation to a bid band of < $0/MWh, leaving a good 3,000 MW exposed to prices less than $0/MWh. On a mild demand day in QLD with strong Rooftop PV, operational demand is lucky to reach 5,000 MW; add QNI in at 1,000 MW and the result is Stanwell bidding half of QLD demand + QNI at below $0/MWh.
SA’s multiple negative price events were also due to transmission line constraints restricting flows into VIC, and soft operational demand which was impacted significantly by strong solar rooftop PV and strong wind generation figures with an average volume of 600 MW. There were multiple weekends which resulted in several hours per day of negative pricing with Friday the 27th of September resulting in ~11.5 hours of negative half hourly pricing. The strong wind generation levels also meant AEMO had to issue directions to Pelican Point and Osborne gas fired power stations multiple times throughout the quarter for grid stability.
VIC and NSW prices across Q319 were both lifted by the Basslink outage which occurred on the 24th of August and lasted through to the 29th of September, resulting in no flows across the Basslink interconnector in either direction. During this time, VIC was heavily reliant on megawatts from NSW particularly during periods of low wind generation, whilst both regions were struggling with ailing baseload thermal plant issues and maintenance which was planned for the yearly shoulder period. The flip side of this? Tas was spared from the high price spikes experienced in VIC during this time which lead to a softened Q3 and September spot price for the region.
Figure 2: Average monthly spot prices in the NEM
(Source: AEMO)
Water levels at Snowy Hydro continued to increase at Lake Eucumbene over the quarter with levels now sitting at ~28.81 %, which is above the levels recorded the same time last year. The increased inflow of water volumes lead to a higher spill rate from Snow Hydro at Tumut, Upper Tumut (both NSW) and Murray (VIC) hydro plants. Additionally, issues with baseload thermal plant particularly in NSW and VIC lead to multiple gas peaking plants running to cover generation gaps at a higher price (due to higher cost of fuel).
Tas Hydro was able to conserve a fair amount of water in their dams over the period of the Basslink outage with storage volumes higher than they were a year prior, leading into the warmer months and Summer of 2019/2020.
With the increase in invoked constraints in QLD both inter and intra-regionally, QLD’s experienced 2 x five-minute VoLL spikes on the morning Wednesday 25th September. These VoLL spikes of $14,000/MWh and $13,998/MWh however were not so much due to market participant bidding or reflective of a market supply and demand squeeze, rather they were caused by both inter and intra-regional transmission constraints and limits imposed by AEMO. Transmission work was being carried out on lines impacting the QNI, forcing it to flow into NSW, whilst the QLD Central to Southern constraint was imposed, winding back generation north of Gladstone and Calvale. This meant that there was not sufficient enough generation in central QLD to satisfy demand, resulting in the bid stack climbing to $14,000/MWh to trigger multiple gas peakers and Wivenhoe who all reside south of Gladstone.
Also in this quarter we saw the release of AEMO’s 2019 ESOO which called out some imminent concerns for Summer:
Forecasted tightly balanced supply and demand in several regions heading into Summer 2019/20, with VIC the only region forecasting an elevated risk of expected unserved energy (USE) currently not exceeding the 0.002% threshold (at 0.0026%).
Potential risk to Summer 2019/20 if the Loy Yang A2 and Mortlake 2 remain on outage during the Summer period; AEMO are predicting 60% chance VIC’s Mortlake won’t be back for Summer 2020 and 30% AGL’s Loy Yang A2 won’t be back in time either.
AEMO currently working to secure the maximum permissible reserves via the Reliability and Emergency Reserve Trader (RERT) to ensure Victoria’s reliability of supply meets the reliability standard for this summer.
The above lead to a rally in the futures curves particularly in Q419 and Q120 in VIC, SA, NSW and Tas. These are all regions that would feel the pinch of tightly balanced supply and demand with thermal baseload plant in the two major regions, NSW and VIC currently experiencing reliability issues. At this stage, MTPASA and market intel depicts that both Loy Yang A2 and Mortlake 2 will be online mid to late December 2019 just in time for Summer.
Looking Forward:
Figure 3: Calendar year 2020 forward contracts
$/MWh
NSW
QLD
SA
VIC
TAS
08-Oct-19
$ 88.81
$ 72.67
$ 99.90
$ 103.09
$ 98.13
(Source: ASX)
The BoM is predicting a warmer than average Spring/Summer which should transpose to greater demand. This in turn could result in a greater need for supply generally resulting in higher spot prices. This should mean when the sun is beaming in QLD and the wind is howling in SA that the price should remain relatively high, enticing the generators to produce electricity and green certificates which have been a hot commodity in Q319. Despite this, NSW and VIC thermal plant are currently underway preparing for summer in what is generally coined their “summer readiness plan” utilising the shoulder period of the year to prepare plant for the warmer months. Transmission line work is likely to cease as we head into Spring/Summer also.
If you would like to discuss the electricity market outlook and potential impact to your electricity portfolio, please contact our Manager Wholesale Clients and Markets, Alex Driscoll on 07 3905 9220.
LGC’s remain relatively elevated at ~$50/certificate. Volumes are being traded whilst liquidity is still being indicated as reasoning for increased prices for CAL19 certificates market.
The Clean Energy Regulator came out on Thursday 31 October and announced based on forecasts and certificates created thus far this year, there is likely to be a shortfall in CAL19 certificate creation by 2 million certificates which has resulted in an uplift in prices.
Despite this, we are seeing continued strong wind and solar generation around the NEM which will continue to have a positive impact on creation levels, with fewer interconnector constraints and transmission constraints intra-regionally impacting energy flows. Tas Hydro’s fleet of run-of-river hydro continues to run hard with a significant volume of water in storage no doubt being reserved for Summer of 2019/2020. Additionally, Snowy Hydro’s water catchment levels also continue to increase leading into Summer.
The Bureau of Meteorology is still predicting a warm and dry Summer 2019/202 which should result in greater demand levels around the NEM allowing for greater generation volumes from renewable sources.
If you would like to know more about the LGC market or need to procure LGC’s for your portfolio, please contact Edge on 07 3905 9220.
