Semi-scheduled and Intermittent Non-scheduled Generators urged to advise of De-ratings

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.

STATE OF THE ELECTRICITY MARKET – WINTER MARKET OVERVIEW

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.

Are you on your way to transitioning your Baseline?

As has been heavily documented the Safeguard Mechanism (which covers approximately 50% of Australia’s covered emissions) is one of the measures in place to help Australia meet its Greenhouse Gas Emissions (GHG) reduction targets of 28% under 2005 levels by 2030. Following the updates to the Safeguard Mechanism rules in March 2019 facilities should review their current arrangements to ensure they are best placed for the upcoming changes and are best positioned to meet their future obligations.

Edge has been working with clients to review what the changes could mean for them and provided positive outcomes for their environmental reporting and Safeguard baseline applications. We ensure clients are not only on the appropriate baseline for their facility today, but that they are future-proofed to complete the compulsory transition onto new calculated baselines; ensuring they are in the best possible position after 2020. We are also assisting clients with meeting their commitments if their baselines are exceeded, by assisting with the procurement of Australian Carbon Credit Units (ACCUs) for them to surrender to ensure they continue to meet their obligations.

If your company would like assistance in assessing your Safeguard Mechanism arrangements or require brokerage services for carbon units please get in contact with Edge on (07) 3905 9220

2019 Electricity Statement of Opportunities

Yesterday the Australian Energy Market Operator (AEMO) released its 2019 Electricity Statement of Opportunities (ESOO), which forecasts electricity supply reliability in the National Electricity Market for the next 10 years. An important change in this year’s ESOO is the inclusion of forecasting of reliability shortfalls that form part of the Retailer Reliability Obligation framework.

AEMO continues to forecast a fine margin between supply and demand in several regions. Although most margins are tight, Victoria is forecast to not meet the reliability standard for unserved energy.

AEMO has flagged Victoria as a significant risk of insufficient supply to meet demand that could result in load shedding. The key driver for this is the extended outage of a Loy Yang unit and a Mortlake unit that are currently scheduled to return to service in late December 2019. If these units do not return to service as planned and additional supply is not secured there may be load shedding in Victoria during extreme weather days.

Following the upcoming summer, transmission is highlighted as a key driver to improve reliability and is required to allow dispatchable generation to supply the expected demand.

The first tranche of unit retirements does not appear to affect unserved energy. Following the closure of Liddell Power Station, the current reliability standard is not breached.

New South Wales appears to be of concern post 2022 during extreme weather events when demand may not be met if supply is impacted by unplanned outages.

AEMO has also flagged nine actions to avoid consumers being impacted by load shedding during extreme weather events. The actions include:

  • Summer readiness plans;
  • Commissioning of targeted transmission lines;
  • Improved access to dispatchable resources;
  • Modification to the reliability standard;
  • Revised three-year strategic reserve;
  • Wholesale demand response;
  • Prioritise market reforms;
  • Refine notice and mechanism of closure of generators; and
  • Improve information transparency.

If you would like to know more about the 2019 ESOO, please contact Edge Energy Services on 07 3905 9220 or 1800 334 336.

Queensland Government direction to Stanwell lifted

The CEO of Stanwell was quoted yesterday in Reneweconomy.com.au stating that “bidding direction ended on 30 June 2019” in reference to the direction given to Stanwell form the Queensland Government in May 2017 to lower wholesale prices.

Spot prices have been soft since 1 July 2019 across the NEM and there is currently no evidence to suggest that Stanwell (and CS Energy) have immediately reacted to the lift of the direction.

When the direction was first given by the Queensland Government in 2017 to Stanwell, energy prices materially came down and generally speaking have been less volatile. Key assets such as Swanbank E and Wivenhoe have been utilised by Stanwell and CS Energy to stop prices spikes above $300.00/MWh.

There is now the potential for Stanwell and CS Energy to utilise their large generation portfolios to potentially increase earnings through higher energy prices. 

If you would like to know more about the potential impact that the lifting of the direction may have on Australian energy prices, please contact Edge Energy Services on 07 3905 9220 or 1800 334 336.

Enhancements to RERT

The Reliability and Emergency Reserve Trader (RERT) is an existing intervention mechanism that allows the Australian Energy Market Operator (AEMO) to contract for additional reserves such as generation or demand response that is not otherwise available in the market. AEMO uses RERT as a safety net at times when a supply shortfall is forecast or where practicable for power system security.

RERT is classified as an emergency reserve or strategic reserve as it may only be used as a last resort to avoid unnecessary load shedding. This is typically required when the market is under pressure from extreme weather or during unexpected generation failure.

RERT can be additional generation or load curtailment that must be able to respond on request from AEMO. It cannot be available to the market including through any agreement or arrangement including demand side management agreement. The amount procured is to ensure AEMO meets the reliability standard in all regions.

Demand Side Participation or demand side response (DSR) comprises the largest component of RERT. DSR could be when factories or manufacturing processes adjust their production in order to reduce electrical load. Once enabled DSR is relatively simple to manage however the contract negotiations, setup and determination of volume and times are complex. Payments are made up of an availability fee and a dispatch fee which as it is linked to lost production is generally high.

Participants will normally require several hours or days notification and may also have minimum and maximum constraints on volume and time periods.

Enhancements to RERT

The AEMC has released new rules to reinforce the emergency reserve mechanism to protect reliability and encourage the long-term capacity of RERT services at the lowest cost and reduce the occurrences where AEMO is required to use higher cost safety net options.

The market is evolving so the emergency reserve framework needs to evolve to allow AEMO to be more flexible to meet the operational needs of a market with a Large number of smaller generators compared to the current grid made up of a small number of large generators.

New RERT Rules

Improve incentives for customers to reduce demand and minimise the need for emergency reserves

The rule is to incentivise more demand response. Retailers and demand response providers can reduce energy during generally high demand times by incentivising end users to reduce energy when most required.

Increased transparency

There is a recognition of the impact of the RERT on the market and consumers. AEMO will be required to provide regular update on the procurement, usage and cost associated with RERT. AEMO will introduce new reporting requirements to clearly explain the reason for RERT procurement.

Clarify the trigger

If AEMO forecast that there is not enough generation available to supply 99.99% reliability standard the RERT can be triggered. The procurement volume will be the amount AEMO considers is reasonable to fill the gap to meet the reliability standard.

Lead time to buy reserves increased to 12 months

The planned retailer reliability obligation RRO has two triggers. The three-year trigger requires retailers to bring dispatchable firm capacity to market if there is a supply gap three years out. If retailers have not filled the gap 12 months out then AEMO can use the RERT.

Encourage a lower-cost competitive market response

Through the rule changes, AEMO are seeking a lower-cost reliability response from market participants and through current market mechanisms (ie. generator recall) to avoid levers such as load shedding and use of emergency reserves.

Guidance to AEMO on costs

Providing AEMO with guidance as to costs when entering into emergency reserve contracts, along with aligning costs of the emergency reserve contracts with the customers who have caused the requirement for emergency reserve procurement, increasing transparency of costs, and assisting market participants and customers in planning for such costs.

AEMO with flexibility

AEMO has flexibility and discretion as to how the reliability standard is incorporated in its day-to-day operations, particularly through its modelling and forecasting of power system risks.

Benefits

As RERT procurement will be linked to the reliability standard there will be greater transparency as to when and how reserves will be used, this will assist in the planning for RERT costs by market participants and consumers.

Allowing AEMO more flexibility in the range of services it can procure, allows it to better incorporate these services into the day to day operation of the NEM.

Increasing the lead time for procurement of RERT from 9 months to 12 months will allow more RERT providers to participant and likely will result in lower costs to end users.

Changes also allow the cost associated with RERT to be aligned with customers who caused the need for RERT.

Implementation

The enhancements to RERT will be implemented over two stages, reporting commencing 31 October 2019 and the remaining components commencing 26 March 2020.

The timeframe is to allow AEMO to finalise internal processes and the RERT guidelines to be updated.

If you would like to know more about the enhancements to RERT and how your business may be affected, please call Edge on 07 3905 9220.

STATE OF THE ELECTRICITY MARKET – AUTUMN MARKET OVERVIEW

Alex Driscoll, Manager Wholesale Clients and Markets

The electricity spot prices in Q219 (April to June) were unsurprisingly lower than the preceding 3 months of Q119 (January to March). Although Q219 experienced some volatility, this was far from the extremes we saw in Q119 with VIC and SA hitting the market price cap in February.

Prices during Q219 were higher than Q218 in QLD, VIC and TAS, however lower in NSW and SA. Looking back across the last 10 years, prices have been higher for all regions.


Figure 1: Historical prices for autumn

(Source: AEMO)

It should be noted that prices in both 2012 and 2013 were affected by a carbon tax, which was subsequently repealed in 2014. Since 2015 there has been a steady price increase in all mainland NEM regions. In Queensland, the Government provided a direction to Stanwell Corporation and CS Energy to adopt strategies to reduce wholesale prices. Since the direction, there have been fewer price spikes (prices above $300/MWh), although average prices have continued to increase.

Spot prices and volatility were low during the first part of Q219 as a result of high availability, low demand and generators bidding volume in low price bands.  By the end of May, peak daily price increased as a result of operational demand increasing. This stems from rooftop PV rolling off and increased use of household appliances. Spot prices continued to increase through June as both rooftop PV and commercial solar were impacted by shorter daylight hours and intra-regional constraints. NSW price increases were primarily driven by demand increases attributed to colder temperatures.

Snowy Hydro continues to draw down its dam levels to cover cap contracts and supress prices below $300/MWh.

Q219 saw an increased level of generation from gas powered generators. Renewable generation increased by 66% to over 3GW from the start of the year. Operational demand continues to drop as a result of a reduction in energy intensive industries, energy efficiency and the increased uptake in rooftop PV.

Figure 2: Average monthly spot prices in the NEM

(Source: AEMO)

The Market Operator issued various directions to participants in SA during Q219 to maintain the power system in a secure operating state. Synchronous generating units were directed to operate or remain synchronised to maintain power system security.

Coal fired generation continued to reduce, with the lower level of generation driven by unit outages and the increase in market share from renewables. Hydro generation consistently increased over Q219 despite low dam levels in NSW, VIC and TAS. Increased generation from wind also continued over the quarter.

Higher spot prices and concerns over the stability of the grid have caused the forward curve to increase. Snowy Hydro continued to draw down on its dam reserves and with a dry outlook, the inflows could be lower than previous years

Looking forward

Figure 3: Calendar year 2020 forward contracts 

$/MWh NSW QLD SA VIC
04-July-19 83.72 73.00 97.00 101.00

(Source: ASX)

There is currently a large pipeline of committed projects waiting to enter the market. These projects are mainly renewable energy, diesel and batteries. Recent updates to the MLFs may reduce this pipeline. The integration of renewable energy generation into the market and the strategies of price setting coal and gas generation will determine if prices will reduce or if a more volatile market will be created. It is unlikely in the near term that spot prices will return to historical levels as renewable generation has not reached a level to consistently set prices at lower levels.

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.

High solar generation vs spot prices in Queensland

Alex Driscoll, Manager Wholesale Clients and Markets

Solar generation and its impact on spot price is a topic of major discussion, particularly in the ‘Sunshine State’ of Queensland where there is a continuous pipeline of solar generation development. This raises the question: is strong solar generation having an impact on spot prices, and if so, is it lowering or increasing prices?

Increasing Large-scale Solar Penetration in the NEM

It is no secret that solar generation has increased dramatically over the last 12-18 months. From 1 January 2018 to 30 June 2018 (inclusive) the average daily production of large-scale solar generation in Queensland was only approximately 14.2 MW, only accounting for 0.085% of total Queensland generation.

(Source: AEMO)

For the six months between 1 July 2018 to 31 December 2018 (inclusive), the average daily production of large-scale solar generation in Queensland increased to 125.3 MW and accounted for 1.9% (an increase of > 1% on the previous 6 months) of total Queensland generation during that period.

(Source: AEMO)

Fast forward to 2019, and generation volumes from large-scale solar generators has continued to increase, reaching a maximum of 917 MW on 08/05/2019 at 11:30. From 1 January 2019 to 30 June 2019 (inclusive) the average daily production of large-scale solar generation in Queensland increased to 205.6 MW and accounted for 3% (an increase of an additional 1% on the previous 6 months) of total Queensland generation.

(Source: AEMO)

The Rooftop (Photovoltaic) Reckoning

So far, we have only evaluated large-scale generation and its penetration in Queensland, however there is another solar photovoltaic beast infiltrating the NEM, namely Rooftop PV (small-scale home and business installations). If we look at similar timelines, home and business owners are deciding to take more control of where their energy comes from, with multiple household and business rooftops opting to install solar panels on what would be wasted space (and opportunity). It is important to understand, rooftop PV falls within AEMO’s (Australian Energy Market Operator) category of distributed energy resources which is subtracted from native demand to determine operational demand.

The general trend for rooftop PV is that its contribution to the energy mix is growing constantly. The maximum volume between 1 January 2018 to 30 June 2018 (inclusive) reached 1.4 GW, with the period 1 July 2018 to 31 December 2018 (inclusive) recording a maximum of 1.78 GW. That is an increase of almost 400 MW in six months. On average, rooftop PV reduced native Queensland demand by 345 MW each day on 30-minute demand figures across the entire 2018 Calendar Year.

(Source: AEMO)

(Source: AEMO)

Roughly year-to-date, we have not seen the same strong performance from rooftop PV. However, summer 2020 could provide a new rooftop PV maximum for Queensland and NEM wide with the Australian Photovoltaic Institute recording on average for the period of 1 January 2019 to 31 March 2019 (inclusive), an additional 16,200 reported installations.

(Australian PV Institute Solar Map, funded by the Australian Renewable Energy Agency, accessed from pv-map.apvi.org.au on 4 July 2019)

Impact to Spot Price

As the graph below depicts the calendar year, daily average half hourly pricing from 2013 to YTD 2019 (excluding 2017 as an outlier with bidding direction from Queensland government to GOCs). Despite the growth and increase in both average (half-hourly) rooftop PV and large-scale solar generation, spot prices have also increased. This is not to say that solar is to blame for the increase in prices, as price has not increased in all hours of the day.

To summarise the changes:

  • The morning peak has remained roughly the same across the years with a sharper ramp-up depicted in earlier years.
  • Evening peak has shifted further into the evening than earlier years depicted and is not as strong.
  • The off-peak hours have become increasingly more valuable in comparison to earlier years.
  • However, the biggest and possibly strangest movement is the daylight hour prices, or solar hours have roughly remained the same (apart from 2014/15).

(Source: AEMO)

We cannot conclusively say that the increase in solar generation is the sole reason for prices heading on an upward trajectory since 2014 (as the table below depicts), however it would be fair to say the increase in solar has played a part in it. The addition of the strong solar penetration has changed the dynamic of the market, causing thermal generators and other fuel types to re-think how they will recover the costs of their 15, 20, 30-year investments. Thermal generators will likely start by displacing the price curve and increasing bids in the off-peak periods. The evidence is clear in that the off-peak periods are now increasingly more valuable than they were 3-6 years ago.

On top of this, a large portion of solar generation is being built north of the Calvale and Wurdong substations in Queensland and is having little effect (unless new infrastructure is built) on middle of the day spot prices. This is due to contingent and operational constraints placed on the power lines by AEMO so as to not overload the lines, forcing generation north of this constraint (solar inclusive) to constrain off. Nonetheless, there are a multitude of factors impacting the price in Queensland and solar generation’s impact on prices should not be overlooked. However, one thing is for certain, spot prices have been increasing since 2014 (see below table) and in the near term show little sign of slowing.

Calendar Year ($/MWh)
QLD 2013 2014 2015 2016 2018 2019 YTD
Avg Spot Price  $    68.41  $    50.91  $    51.96  $    67.32  $    74.82  $    80.64

(Source: AEMO)

If you would like further information on the impact of solar generation, please contact your Manager Wholesale Clients or Edge on (07) 3905 9220.

Retailer Reliability Obligation Final Rules Package

Yesterday the Energy Security Board (ESB) provided an overview of the final package of proposed amendments to the National Electricity Rules (NER) (final Rules) to implement the Retailer Reliability Obligation (RRO or the Obligation) and takes into account stakeholder feedback. It should be noted that South Australia is undertaking a separate process in relation to how the national framework may have to be amended or altered to take into account the framework that will apply in South Australia (including that the South Australian Minister may trigger the RRO sooner than under the national framework).

The RRO originated from the National Energy Guarantee. As outlined in the ESB’s Final Rules Package, the RRO builds on existing spot and financial market arrangements in the National Electricity Market (NEM) to facilitate investment in dispatchable capacity and demand response. It is designed to incentivise retailers, on behalf of their customers, to support the reliability of the power system through their contracting and investment decisions. The Obligation has three key drivers that will work together to lower electricity prices, namely:

  • increased contracting unlocking new investment
  • increased contracting in deeper and more liquid contract markets to reduce the level and volatility of spot prices, and
  • increased voluntary demand response.

The RRO is scheduled to come into effect on 1 July 2019. Large customers who have consumption greater than 50 GWh/annum will have the option to opt-in, thereby taking the responsibility away from their retailer.

If you would like to know more about the potential impact that the RRO may have, please contact Edge Energy Services on 07 3905 9220 or 1800 334 336.

LNP Inertia Continues

In a surprise outcome the LNP maintained leadership over the weekend noting that it remains unknown whether or not the LNP will form a majority government. Energy and climate were at the heart of this election with Labor putting forward material initiatives that would increase investment in renewable energy generation (increased funding to the CEFC) and reduce emissions through the extension of the safeguard mechanism, amongst a number of other initiatives. The LNP are less ambitious and maintain the emissions reduction target of 26-28% below 2005 levels by 2030. The LNP will extend the Climate Solutions Fund by providing additional funding to the Emissions Reduction Fund which is the reverse auction of ACCU’s managed by the Clean Energy Regulator.

In terms of energy generation and transmission the LNP has pledged support for Snowy Hydro 2.0, the Underwriting New Generation Investment program and Marinus Link (Interconnector between TAS and VIC, part of the Battery of the Nation plan).

The futures markets (energy and environmental certificates) had priced in a Labor victory. The result over the weekend may put upward pressure on forward prices (energy & Enviro) as there will be less new renewable generation invested in over the coming years. That being said, state based renewable energy targets remain in place as per the following:

QLD – 50% Renewable by 2030

NSW – No target

VIC – 25% by 2020 and 40% by 2025

SA – No target

Tas – 100% by 2022

The larger demand states are QLD, NSW and VIC who are still heavily reliant on coal powered generation. NSW is the only state of these three whereby there is no target. Given that QLD and VICs renewable energy targets remain in place there should not be a material decline in new renewable generation development in these regions. For NSW, at least for the time being, new renewable generation will be a function of price. Currently NSW prices are at a level whereby a solar or wind developer should be able to secure funding and a PPA.

If you would like to know more about the potential impact that our LNP government may have on Australian energy prices, please contact Edge Energy Services on 07 3905 9220 or 1800 334 336.