AEMO Suspends the Market

Below is the media release from AEMO after it suspended the National Electricity market at 14:05 today.

AEMO today announced that it has suspended the spot market in all regions of the National Electricity Market (NEM) from 14:05 AEST, under the National Electricity Rules (NER).

AEMO has taken this step because it has become impossible to continue operating the spot market while ensuring a secure and reliable supply of electricity for consumers in accordance with the NER.

The market operator will apply a pre-determined suspension pricing schedule for each NEM region. A compensation regime applies for eligible generators who bid into the market during suspension price periods.

In making the announcement AEMO CEO, Daniel Westerman, said the market operator was forced to direct five gigawatts of generation through direct interventions yesterday, and it was no longer possible to reliably operate the spot market or the power system this way.

“In the current situation suspending the market is the best way to ensure a reliable supply of electricity for Australian homes and businesses,” he said.

“The situation in recent days has posed challenges to the entire energy industry, and suspending the market would simplify operations during the significant outages across the energy supply chain.”

Edge wish to reiterate, this is not a physical supply issue. AEMO directed 5GWhs of physical generation into the market. If generators can operate when under direction, they do not have a physical reason to not generate (such as maintenance, overhaul etc), so the reduced availability we are seeing has to be a commercial trading decision to either price volume into higher price bands or to remove availability in the maximum availability bands of their bids. The availability is there, the generators are just not offering it via the spot market.

The market suspension is temporary, and will be reviewed daily for each NEM region. When conditions change, and AEMO is able to resume operating the market under normal rules, it will do so as soon as practical.

Mr Westerman said price caps coupled with significant unplanned outages and supply chain challenges for coal and gas, were leading to generators removing capacity from the market.

He said this was understandable, but with the high number of units that were out of service and the early onset of winter, the reliance on directions has made it impossible to continue normal operation.

The current energy challenge in eastern Australia is the result of several factors – across the interconnected gas and electricity markets. In recent weeks in the electricity market, we have seen:

A large number of generation units out of action for planned maintenance – a typical situation in the shoulder seasons.
Planned transmission outages.
Periods of low wind and solar output.
Around 3000 MW of coal fired generation out of action through unplanned events.
An early onset of winter – increasing demand for both electricity and gas.

“We are confident today’s actions will deliver the best outcomes for Australian consumers, and as we return to normal conditions, the market based system will once again deliver value to homes and businesses,” he said.

What does it mean for generators and end users.

Bidding and dispatch will continue as usual under the market rules.
Dispatch instructions will be issued electronically via the automatic generation control system as usual
If required AEMO may issue dispatch instructions in any other form that is practical in the circumstances.
Spot prices and FCAS prices in a suspended region continue to be set in accordance with NEM rules or under the Market Suspension Pricing Schedule.

The Market Suspension Pricing Schedule is published weekly by AEMO and contains prices 14 days ahead.

The market will continue to operate under the Market Suspension Pricing Schedule until the Market operator determines the market is able to return to normal conditions and the suspension is revoked.

Article by Alex Driscoll, Senior Manager – Markets, Trading, and Advisory

Federal Government King Review

Recently the Australian Government released findings of the King Review, accepting 21 of 26 recommendations to incentivise greenhouse gas (GHG) emissions abatement from industry.

The focus of the Expert Panel review was the development of rules to credit emissions reductions below Safeguard Mechanism baselines. Credits created under the proposed mechanism could be used to meet compliance obligations under the Safeguard Mechanism.

The panel recommended producing new credits generated under the scheme, known as Safeguard Mechanism Credits (SMCs). The SMCs would be different to the Australian Carbon Credit Unit (ACCU) offsets. SMCs would be for transformative abatement projects based on changes in emissions intensity rather than absolute emissions.

The proposed crediting mechanism would be similar to a baseline and credit framework scheme employed under current legislation however the baseline component of the framework does not account for absolute emission increases. The proposed mechanism will separate an emissions intensity crediting baseline that is focused on ‘transformative’ projects. The new credits will have lower environmental integrity due to the lower threshold for creation of credits for potential abatement projects. The creation of these credits will result in a two speed carbon price.

The Review observations that SMCs could be purchased at a price set by the market or at a fixed price. The price may also be linked to the existing ACCU price. As a result, lower quality SMCs would be expected to trade at a discount to ACCUs.

The Review saw the potential for LGCs to increasingly be considered for use in carbon markets due to their implicit carbon abatement value. It is not proposed to link LGCs in the new scheme.

Greenhouse gas King review

COVID-19 / NEM Impact Statement

COVID-19 has impacted us all in recent weeks. At Edge we have put plans in place that have allowed us to provide all services our clients require without disruption.

We are working diligently to understand the impacts COVID-19 could have on the energy markets in the short and longer term. As more information comes to light, we will provide further updates on the impacts to the market and our clients.

As we are only a few weeks into this pandemic we will try and provide an understanding of the impact COVID-19 could have on the market.

Oxford economics, a team of 250 economists, has recently published a paper providing a high-level update on the impact of the pandemic on the world economy. Their initial work predicts a short, sharp recession to the global economy with major national economies going into deep recession during the first half of 2020. It is modelled that over the full year global growth will drop to zero.

Oxford economics are predicting, based on historic experience, a strong bounce back in activity once social distancing measures are relaxed. It is forecast that businesses that can get through the first half of 2020 should be prepared for a strong second half of 2020, with global growth forecast above 4%.

Overseas experience

As China was the first country to close-down as a result of COVID-19 we can learn from their recent energy experience and translate it into the Australian market.

In January and February energy production dropped significantly with thermal power dropping 8.9%, hydro dropping 11.9% and nuclear and wind dropping to a lesser extent at 2.2% and 0.2% respectively. On the flip side Solar generation increase by 12%.

Early indications are that thermal and hydro station dropped production the most due to reduced staffing level causing lower operational hours. Renewables were impacted the least due to their non-dispatchability.

It is estimated that during the height of the Chinese lockdown period over the 27 days, demand decreased by 16%.

At Home in Australia

Generation

Large generation portfolio’s including the likes of Stanwell and AGL have publicly acknowledged they have put plans in place to ensure generation meets demand, this includes stockpiling coal to ensure security of fuel supply. Smaller generators on the other hand may not have the staff to guarantee operation of their units over the long term due to illness.

Energy Price Impacts

With the additional impact of lower energy demand in Asian countries such as China, Australia’s liquefied natural gas demand significantly reduced, resulting in excess domestic gas supply particularly on the east coast of Australia. Although majority of the LNG facilities on the east coast reside in QLD, we have seen an increase in gas generation and a decrease in bid prices in regions more dependent on and abundant with gas-fired generation, such as South Australia. We are seeing approximately 600 MW more of gas-fired generation in March 2020, compared to March 2019, bid in at prices below $50/MWh. Assisting this is the collapse in natural gas prices in the Adelaide Short-term Trading Market, which has traded at the mid to high $5/GJ range for March 2020, compared to the significantly higher price range of $10 – $11/GJ we witnessed back in March 2019. Both of these variables are introducing cheaper supply in the energy markets both for heating (in homes) and electricity generation. With interconnection remaining relatively unconstrained this is resulting in lower prices across all NEM regions.

AEMO

AEMO has put in place its pandemic response plan so the market operator can continue to operate the NEM and WEM efficiently and safely. Key actions in the pandemic plan include limiting contact with key staff such as control room and other business critical staff.

Demand

Following the initial breakout of COVID-19 in Australia and the early shutdown of some businesses, demand fell by about 600MW in NSW or about 8% of average demand. This was reflective of all states. Over the recent week the steep reductions in demand experienced at the start of COVID-19 have flattened out as a result of two possible reasons. In some regions such as Victoria, demand has increased. The first reason for this change in demand is consumption has moved from businesses to individual homes. Across Australia average demand is currently only 7% below last month’s average. The demand change is also attributed to seasonal change which has resulted in a reduction in load associated with cooling.

Change in demand – daily profile

The chart below illustrates the change in demand across the day and compares a summer profile and a transition to an autumn profile. The top line is early February with the bottom-line showing demand from Monday the 23^rd March.

The chart shows morning peak has reduced slightly however the demand over the evening peak has dropped significantly.

Impact of large users

It is expected that large users would be impacted significantly by the virus however this does not appear to be the case. With parts of the world such as South Africa shutting down mines and industry following government direction the supply / demand balance is falling in the favour of Australia. Add to this the favourable exchange rates, the export potential of commodities from Australia remains strong. The Australian mining industry is also designated as an ‘Essential Service’ so at this stage they are sheltered from future lock downs. This positive news for the mining sector which will benefit mining rich states with demand expected to reduce to a lesser extent than other states.

Renewables

If the trends overseas are reflected in Australia the current installed capacity of renewable generation will continue to operate at strong levels providing staffing is available to operate and control the assets.

There will be a likely slowdown in the development of renewable projects as a result of the restrictions on travel, meetings and specialist staff available for construction, connection, commissioning and final approvals.

This slowdown will impact the future mix of generation assets across Australia, the current trend in carbon emission reductions and the supply and price of environmental products.

LGCs

Edge has modelled the impact of a 10% reduction in demand with a business as usual generation profile for large scale renewable generators to understand the impact this downturn may have on LGC supply and price.

The 10% reduction in demand could reduce the RPP percentage by 0.32%. The likely effect of a reduced percentage and business as usual renewable production will be surplus LGCs in the short term and reduced prices for LGCs.

STCs

With the downturn of the economy it is expected that less roof top solar will be installed resulting in a reduction in the current surplus of certificates carried forward since 2017. The reduction is expected to reduce the STP below 20%.

If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.

Water – a top priority for Tarong Power Station

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.

Gas power stations for Victoria and Queensland

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.

Predicted Shortfall of LGCs for 2019

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.

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.

Gas Market Update

The Queensland State Government increased the petroleum royalty rate by 2.5% to 12.5% in the 2019/2020 budget, claiming that it will increase revenue by $467 million over the four years ending 2022/2023. The increase received condemnation from LNG producers and their investors. In the announcement, Queensland Treasury drew comparison to royalties in the USA and Canada. The resources sector at large has claimed that the higher tariffs put future investment and jobs at risk.

AGL announced during the week that it anticipates first gas to be delivered from its proposed LNG import terminal in the second half of FY22. Originally, AGL indicated that gas would be delivered during FY21, however it is understood that environmental requirements as set by the Victorian Government have caused delays. AGL announced that the floating storage vessel, Hoegh Esperanza would be utilised for the job. It is estimated that the LNG import terminal will be able to send between 80-100TJ/gas per day.

Hydrogen

The COAG Energy Council Hydrogen Working Group has released 9 issues papers which are to help develop the National Hydrogen Strategy. The nine papers released are:

Hydrogen at scale
Attracting hydrogen investment
Developing a hydrogen export industry
Guarantees of origin
Understanding community concerns for safety and the environment
Hydrogen in the gas network
Hydrogen to support the electricity systems
Hydrogen for transport
Hydrogen for industrial users

The hydrogen strategy revolves around producing hydrogen from renewable energy sources to create “clean” hydrogen. Australia has recognised its competitive advantage in producing clean hydrogen due to the solar and wind (renewable electricity required in production of clean hydrogen) resources. The market for hydrogen is currently small relative to other energy sources such as gas and coal however with increasing appetite for low emissions fuel it is anticipated that this will grow. The potential size of the market is unknown. Unsurprisingly parties that stand to benefit from hydrogen becoming a more widely used fuel source anticipate huge growth whereas the more moderate are generally in a wait and see phase.

Currently cost of producing hydrogen remains high and makes the fuel uncompetitive as well as having no commercial scale shipping capacity. Hydrogen production costs for different technology options according to the International Energy Agency are summarised below:

Source: International Energy Agency. “The Future of Hydrogen, seizing today’s opportunities” June 2019 p.g. 52

It cannot be understated how substantial the task is to deliver on the COAG Energy Councils vision of Australia becoming a major clean hydrogen player. The table below provides a high-level timetable for actions to 2030 as prescribed by the COAG Energy Council.

Gas Powered Generation

Gas powered electricity generation has been, is, and will continue to be critical to ensuring reliable electricity supply in the NEM. Recently, gas has started to become displaced by new renewable generation in the NEM. Gas however remains critical at times of tight supply and demand balance. The graph below summarises the daily gas used for gas powered generation (Source Australian Energy Regulator) dating back to Q308.

Source: AER

On aggregate we can see that gas generation reached its minimum level since Q308 in Q418. This is primarily driven by new renewable generation in the form of wind and solar. Queensland gas demand has declined after Q414 on the back of Swanbank E mothballing. We also note the rise in SA which corresponds with the closure of Northern coal power station in SA. As the energy market continues to transition to intermittent renewable fuel sources and a 5-minute market, there is interest in adapting existing gas power stations to be able to respond more quickly.

Regional analysis

Brisbane

Gas prices in the Brisbane STTM were marginally higher in Q219 relative to Q218, averaging $8.72/GJ. There was no material change in volumes traded through the STTM.

(Source: AEMO)

Sydney

Sydney Q219 average STTM price was $9.79/GJ, which was $1.26/GJ higher than the Q218 average price. Prices during Q219 were highest at the beginning of the month.

(Source: AEMO)

Adelaide

Adelaide Q219 average STTM price was $10.45/GJ which was $2.29/GJ higher than the Q218 average price. Sustained higher prices as well as a spike during June contributed to the higher average price.

(Source: AEMO)

Victoria

Victoria Q219 average gas price was $9.54/GJ which was $1.36/GJ higher than the Q218 average price. Prices were higher earlier in the quarter then converged in May. In late June gas prices softened, potentially on the back of less demand from electricity generators due to high wind.

(Source: AEMO)

If you would like to know more about what is happening in the gas market and how your business may be affected, please call Edge on 07 3905 9220.