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.
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.
For a growing number of large energy consumers, consideration is turning to whether entering standard vanilla retail gas agreements deliver the most effective outcome. For consumers who are located within the bounds of the Sydney, Brisbane or Adelaide Short Term Trading Market (STTM) markets, many may not be aware that there is an alternative way to purchase gas. Below, we consider how the STTM works and what the benefits are of exploring this option.
What is the STTM
The STTM is essentially a market for the trading of natural gas at a wholesale level at defined hubs between pipelines and distribution systems. The STTM is a day-ahead gas market operated by the Australian Energy Market Operator (AEMO) with hubs located in Sydney, Adelaide and Brisbane. This means that gas is traded a day ahead of the actual gas day. The market settles daily with “shippers” delivering gas and “users” consuming gas. An organisation may sell gas as a shipper and purchase gas as a user through the same STTM, however, it would do so at the daily market price.
Source: “Overview of the STTM for Natural Gas”, AEMO, page 1
Market participants are incentivised to ship and consume volumes of gas nominated through a pricing mechanism, which aims to keep the gas supply system balanced. Organisations are able to sell excess gas to its requirements on the open market the next day, as well as bid to purchase extra gas as and when required. This system allows participants more flexibility and choice in purchasing gas supplies. Furthermore, the STTM’s price transparency ensures that the price set by the market daily truly reflects the current supply and demand situation.
Each of the STTM hub settles independently of the other, however each hub operates under the same rules outlined by AEMO.
There are a range of drivers for some large gas consumers transitioning to purchasing and selling gas in the STTM. The main reasons are:
The STTM is an historically lower commodity cost;
Consumers can manage or avoid penalties under daily, monthly, and / or annual take or pay positions;
There is increased flexibility for both sellers and consumers; and
There are no long-term commitments.
These benefits can materially lower the cost of consuming gas. Depending on the nature of the organisation, there are a range of structures to access an STTM. Each structure requires varying levels of engagement from the consumer.
Engagement with Edge
To assist in transitioning your organisation to accessing the STTM, Edge are able to offer the following services:
Daily nominations and trading;
Monthly reconciliation;
Facilitation of short and long-term Gas Supply Agreements; and
Managing the STTM application.
Entering the STTM market is strategic decision for most organisations and can take anywhere between 3-12 months to transition. If you would like to know more, please contact us to understand if accessing the STTM market is the right decision for your organisation.
We note that there are also alternatives for consumers who are not within the STTM limits, however these options are not discussed for the purposes of this article. If you would like further information on your options, please contact your Manager Wholesale Clients or Edge on (07) 3905 9220.
As of 1 March, the new Capacity Trading Platform (CTP) and Day Ahead Auction (DAA) came online. This market arose after the Council of Australian Governments (COAG) Energy Council agreed to implement the legal and regulatory framework required to give effect to the capacity trading reform package, as recommended by the Australian Energy Market Commission (AEMC) as part of its Easter Australian Wholesale Gas Market and Pipelines Framework Review.
The reforms apply to the operators of transmission pipelines and compression facilities operating under the contract carriage model (collectively referred to as “transportation services”). The objective of the reforms is to encourage and facilitate trading of unutilised capacity on non-exempt transportation facilities. This is achieved by providing shippers with an incentive to trade spare capacity on a secondary capacity market (the CTP). If a shipper fails to sell any spare capacity prior to the nomination cut-off time, then its contracted but unnominated (CBU) capacity is then offered to other participants in an auction conducted a day ahead of the gas day (the DAA). In contrast to trades conducted by shippers prior to nomination cut-off time, the proceeds from the auction are retained by the service provider, which incentivises shippers to sell their spare capacity ahead of nomination cut-off time. (AEMO, Pipeline Capacity Trading: Overview, 2018).
According to the Australian Energy Regulator (AER) in the first two weeks of the DAA, 1.87 PJ of capacity was bought across multiple pipelines and compressors (Australian Energy Regulator, Gas Market Report, March 2019).
C&I Gas pricing
C&I gas contracts continues to be an opaque market. Contract prices have softened since the peak in 2016, however remain high and continue to put businesses under strain who are challenged with either absorbing higher costs or passing these onto customers.
AEMO recently released their Gas Statement Of Opportunity which reinforced the situation that domestic gas supply and demand balance is tight. AEMO highlighted that:
“Supply from existing and committed gas developments is forecast to provide adequate supply to meet gas demands until 2023. However, risks remain that any weather-driven variances in consumption or electricity market activity could increase gas demand, creating potential peak-day shortages as outlined in AEMO’s 2019 Victorian Gas Planning Report”.
Weather driven variances in consumption were observed in late January this year when the Cumulative Price Threshold was met and the Administered Price was activated VIC and SA. This highlight from AEMO is generally concerning as it suggests that there is unlikely to be any reprieve in gas prices in the near to medium term.
Recently, pricing for C&I customers has been observed between $11.00/GJ and $14.00/GJ subject to terms and conditions. Customers are increasingly looking at taking on more responsibility for their consumption in an effort to bring down the commodity price.
Gas Powered Generation
Gas powered generation in Q119 was 4% higher than Q118 with less generation from hydro, black coal and brown coal. There was a material increase in generation from solar and wind resources which was to be expected.
Average prices in the STTM hubs and the VIC gas market all increased in Q119 relative to Q118. Volumes were lower in the STTM markets, whereas the volumes increased through the VIC market. Gas fired generation in VIC averaged 75TJ/day in Q119, which was 23TJ/day higher than Q118. Less generation from brown coal and hydro generators was the primary driver behind this.
Regional analysis
Brisbane
Brisbane STTM gas prices were higher in Q119 relative to Q118. Prices were consistently higher and generally followed a similar pricing trend. Volumes exchanged through the STTM were marginally higher in Q118 relative to Q119.
Sydney
Sydney STTM gas prices were higher in Q119 relative to Q118 with a divergence in prices in the final week of the month. Volumes exchanged through the STTM were very marginally higher in Q118 relative to Q119.
Adelaide
Adelaide STTM gas prices were higher in Q119 relative to Q118. Q119 prices were consistently above that of Q118, with the exception of a few days at the beginning of February. Volumes exchanged through the STTM were very marginally higher in Q118 relative to Q119.
Victoria
VIC gas prices were higher in Q119 relative to Q118 with prices diverging in the final weeks of the quarter. Unlike the STTM markets, there was more volume traded through the VIC market in Q119 relative to that of Q118. On the 24th and 25th of January, there was a spike in gas volumes which was driven by higher demand from the Gas Powered Generators as a result of very high electricity prices.
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.
With expectations that CleanCo will be trading in the NEM by mid this year, things are getting into full swing. Last week CleanCo appointed its first two key executives – Miles George and Geoff Dutaillis.
Who are these new executives?
Miles George has been appointed the Interim Chief Executive Officer (CEO) at CleanCo. His role at CleanCo is to secure cleaner, more affordable, sustainable energy and secure supply of electricity for Queensland (QLD). He was previously the CEO and Managing Director of Infigen Energy. After leaving Infigen Energy in 2016, Miles continued as a strategic adviser until December 2017. During and after his time at Infigen, Miles has been the Chairman of the Clean Energy Council, a representative on the AEMC Reliability panel, an Expert panel member for AEMO and Director of the Australian Conservation Foundation.
Geoff Dutaillis has been appointed the General Manager of Transition. Geoff was most recently the CEO (Australia) of Wind Energy Holdings, a leading renewable energy company based in Thailand. The company has interest in various Australian wind farms. Geoff has also held executive positions at Infigen Energy as Chief Operating Officer (COO) from 2009 until 2013 and Lendlease more recently as Head of Sustainability.
What is the mandate for CleanCo?
CleanCo has the mandate to increase competition in the electricity market at peak times of demand when prices are generally at their highest. CleanCo is expected to transform intermittent renewable generation into firm financial products for customers and retailers while backing QLD’s renewable energy and low emissions generators.
Which of the existing generators are to be transferred from the current government owned corporations; Stanwell and CS Energy?
Initially, CleanCo’s portfolio will include a range of existing renewable and low emission energy generation assets including:
Wivenhoe pump storage hydro plant,
Swanbank E gas-fired power station, and
Barron Gorge, Kareeya and Koombooloomba hydro power stations.
If you have any questions regarding CleanCo or any other matter relating to energy, please contact Edge Energy Services on 07 3905 9220 or 1800 334 336.
Domestic gas prices have increased again as Queensland continues to export most domestic gas overseas in the form of Liquefied Natural Gas (LNG). Outages in early 2018 had limited output from the LNG facilities, however all trains are now available.
The increase in total gas extracted on the East Coast of Australia is the largest contributor to the increase in gas prices. Before LNG demand, domestic gas could be extracted from cheap resources. However, as more gas is extracted from Roma, Queensland, the price of extraction has increased, which is then passed onto consumers. With the ability to sell gas overseas, producers are also looking to obtain a similar price domestically when the cost of transport has been taken into account (so called netback prices).
The Australian Energy Regulator (AER) has published the average daily production of gas by production point. This shows the large increase, particularly for Roma. The volume is necessary to justify the very high fixed costs of liquefying and exporting gas.
Source: AER
Overall, prices were lower at the start of 2018 and the Federal Government has been quick to point to its domestic gas policy, whereby producers could be forced to sell gas to domestic consumers ahead of exporting it in the event of a shortage. The inference is that without the domestic gas policy, prices would have been higher. A more obvious driver would be lower export of LNG as one of the export facilities was undergoing planned maintenance. With all facilities now back online, the prices have crept back up and are now higher than the same period in 2017 for all regions.
The Australian Labor Party (ALP) announced that it would look to further strengthen the domestic gas policy by forcing producers to sell locally before exporting if prices were too high. This goes beyond the current policy which requires a shortage for the gas policy to apply. The ALP has not indicated what they consider to be “high prices” for the policy to apply. Additionally, producers are concerned about uncertainty at a time when the gas market needs further investment. The current state of the electricity market should serve as a warning of what happens when there is little investment certainty.
Regional analysis
There are regional differences in the gas prices, which are mainly based on the different usage of gas. In Queensland, gas is mainly used for LNG export while in Victoria it is predominantly used by residential and commercial customers, particularly for heating. In South Australia and Tasmania, gas is still mainly used for gas powered generation (GPG).
Gas usage in 2017 by sector and region
Residential / commercial
Industrial
GPG
LNG
Regional gas consumption (PJ)
Queensland
<1%
8%
3%
89%
1,377
New South Wales
37%
42%
21%
0%
130
South Australia
11%
23%
66%
0%
101
Tasmania
5%
33%
62%
0%
15
Victoria
55%
30%
15%
0%
228
Total
10%
14%
10%
66%
1,851
Source: AEMO
Queensland
With lower exports in early 2018, gas prices at the Brisbane hub have been lower than the previous year. Once the outage at an LNG facility was completed in June, prices went back to their elevated levels and have subsequently been sitting above the 2017 prices. In the short term, there is limited opportunity for production of gas to stop, which means that shut downs of facilities will tend to lower prices.
Since the increased LNG production, prices in Queensland have remained steady, consistent with prices in 2017 before the shutdown. There is little gas used outside of LNG in Queensland, therefore making it the main driver.
New South Wales
Gas is primarily used in industrial process in New South Wales, providing a flat demand across the year.
From the above graph, it is apparent that prices have been stable across most months. There were slightly lower prices until approximately June 2018 as cheaper gas flowed from Queensland. Prices have started trending up since then.
South Australia
Gas in South Australia is predominately used by gas powered generators. These tend to operate more in both summer and winter when demand for electricity is generally higher.
South Australian gas prices have been modest throughout the year. Higher demand for gas generation in February increased prices overall, however the largest change was again in June when the Queensland LNG facility started exporting again after its outage.
There is still a large swing component of gas demand in South Australia due to residential/commercial demand. Even though this only represents 11% of overall consumption it tends to be very concentrated for a few days per year.
Tasmania / Victoria
There is no separate Tasmanian gas market with most contracts based on the Victorian prices.
Victoria also has the largest proportion of gas being used by residential/commercial consumers. This creates a large swing in gas demand throughout the day and throughout seasons. Unlike South Australia which uses a lot of gas for power generation, Victoria mainly relies on coal. This means that prices are typically lower in summer and higher in winter.
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 or contact your Edge Portfolio Manager.
In a media statement released 30 August, the Queensland Government confirmed their intention to establish CleanCo, Queensland’s third publicly owned electricity generator. CleanCo will have a strategic portfolio of low and no emission power generations assets, and will build, own and operate new renewable generation. It is understood that CleanCo will take control of assets including Wivenhoe, Barron Gorge and Kareeya hydro power stations and the Swanbank E gas power station, courtesy of a restructure of the two current publicly-owned electricity generators – CS Energy and Stanwell Corporation. CleanCo is expected to be trading by mid-2019.
Domestic gas prices on the east coast of Australia have been through a huge transitional period as a result of the introduction of the LNG export market from Curtis Island. Whilst there have been a broad range of changes, one of the key factors increasingly influencing price that domestic consumers pay is the price of oil. Domestic contracts are now being offered at oil linked pricing which effectively means that if the price of oil increases so will the price of your gas (and vice versa). For large gas producers this is nothing new as hedging commodity prices is part of their core business. For consumers however this may be more challenging depending on the products they produce.
Other factors that are now impacting Australian gas prices are:
Climate change policies in Asia as gas is a widely used fuel for clean electricity generation. This is particularly important when considering China due the huge demand and current reliance on coal generation.
Manufacturing levels in Japan
US production levels and construction of pipelines
Renewable energy technology developments
Turning our attention to domestic gas influences the Northern Territory Chief Minister Michael Gunner has recently announced that the 135 recommendations made in the recent inquiry into fracking in the NT would be implemented, allowing on-shore fracking to take place in the territory. The 135 recommendations made in the inquiry mitigate the risks associated with onshore gas development to acceptable levels, and in some cases claim to eliminate the risks completely. New gas developments will require environmental management plans which will be assessed by the NT Environment Protection Authority and signed off by the environment minister. There will also be area’s where fracking will not be allowed. These include indigenous protected areas, special environmental areas, cultural and agricultural areas of significance to the Northern Territory. There is a number of studies to be completed before fracking production can begin including strategic environmental and baseline assessments. At this stage it is estimated that exploration will begin in 2019 and production in 2021.
On 21 May Santos Rejected Harbour Energy’s (Harbour) offer to purchase 100% of shares at US$5.21 per share. In an effort to get the deal over the line Harbour offered $5.25 per share if Santos was willing to extend certain oil price hedging arrangements. The final offer from Harbour had a number of conditions which included Santos assisting with debt raising and hedging a significant portion of Santos oil-linked products as well as FIRB approval. Once the offer was rejected Santos shared its view on how superior shareholder value could be realised through executing the current strategy.
Australian Industrial Energy will see Port Kembla in NSW developed into an LNG import terminal. The Andrew Forest venture recently reached significant milestones. These include receiving backing from Japanese energy giant JERA and signing a memorandum of understanding with 12 potential customers (according the AFR). Project development is still subject to approvals.
AEMO recently released its Victoria Gas planning report update that painted a concerning outlook in respect of depletion of offshore gas fields reserves. The data provided to AEMO from producers in the Gippsland basin forecast production to reduce to 38% below the 2018 production forecast and 68% for Port Campbell. In response to this outlook gas producers and other market participants are investigating additional supply and capacity.
Regional analysis
Narrowing our focus, Edge take a closer look at gas generation in each region and the local gas trading hub. As we know the Federal Government threatened LNG producers with the Australian Domestic Gas Mechanism late last year if they didn’t allocate more gas to domestic consumers. The threat appeared to have worked with each of the LNG producers advocating that they had made gas available.
When we take a closer look at whether a relationship exists between gas generation and gas hub prices we realise that it is difficult to discern. Limitations in access to pipeline capacity, contractual arrangements and sophistication of users are potentially key drivers behind this.
The following graphs display average gas generation from 1 January 2017 to the end of May 2018 on a regional basis as well as the average gas price for the same period.
Queensland
From the graph we can observe that gas generation in 2018 (to date) is largely in-line with 2017. The consistent level of generation is interesting given the significant decline in spot electricity prices in Q118 relative to that of Q117. On face value the lower spot prices in 2018 would result in less generation from gas power stations. What changed however between Q117 and Q118 was SwanBank E power station returned. The gas combined cycle power station ran consistently throughout Q118 averaging 237 MW of generation. Lower spot prices in the Brisbane STTM are a driven by lower demand and potentially increased supply as a result of the LNG producing increasing availability of gas to domestic consumers.
New South Wales
NSW gas generation was significantly down for the first 5 months of 2018 relative to the same period in 2017. Lower gas generation in NSW was largely the result of less volatility in the electricity spot market. If we look at the bid stacks of the large gas power stations in NSW, Tallawarra was the most motivated to produce energy offering up to 210 MW at below zero dollars. This strategy could not be observed at Uranquinty or Colongra.
Victoria
Unlike NSW and QLD generation from gas powered power stations increased in January and February 2018 relative to the same months in 2017. The closure of Hazelwood power station in late March 2017 meant that the 1,225 MW (average generation of Hazelwood in Q117) was no longer available. Less baseload generation in the region resulted in higher electricity prices which meant that gas power stations were dispatched more regularly. Despite the increases in generation there was a decline in VIC gas market prices.
South Australia
Gas generation in SA has been heavily impacted by the increased level of intervention in the SA market by the market operator. The market operator has been constraining off wind generation and calling on gas generation which has increased overall generation from gas plant. This increased generation however has not translated into higher gas prices as we can see from the graph these 2018 prices are trending below 2017 prices.
When observing each of the regions and the time periods selected it is fair to say that generation from gas fired power stations and spot prices in the gas hubs do not drive average price outcomes.
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 or contact your Edge Portfolio Manager.
Edge attended the Gas Energy Australia 2018 National Forum held at the Gold Coast on 17 and 18 May 2018.
There were a number of prominent speakers at the forum including Senator Canavan, the Commonwealth Minister for Resources and Northern Australia; Tony Wood, Energy Policy Director at the Grattan Institute as well as Ian Macfarlane from the Queensland Resources Council.
Senator Canavan highlighted the improvement in the gas prices during the first four months of 2018 compared to the same period in 2017. He attributed part of the 24% reduction in prices at the Wallumbilla gas hub to the conversations the Federal Government had with key gas producers last year and the potential for a domestic reserve policy being enacted. The Senator also highlighted some of the challenges in communicating the value of having gas being produced right across Australia. He noted that it costs around $2.00/GJ to transport gas from Queensland to Victoria and only between $2.50/GJ and $3.00/GJ to transport gas from Queensland to Japan. The Senator had praise for the Northern Territory Government for allowing more exploration. The is a potential for 1 billion barrels of oil to be extracted in the Northern Territory which would alleviate some of the energy security issues that Australia is facing.
The Senator also spoke about some of the issues in the electricity market. He confirmed that the current renewable energy target would be closed off to new participants starting after 1 January 2021. He described the renewable energy target as one of the worse policies ever.
Tony Wood of the Grattan Institute agreed that the cost of the renewable energy target did not justify the carbon reduction. He also reflected that energy policy would continue to be political and it was up to industry to drive it forward.
Ian Macfarlane agreed with previous speakers on the renewable energy target. He described having to implement the original scheme as a “hospital pass” handed down from previous ministers. He also went on to talk about the importance of the gas industry and how the industry needs to be better at engaging the wider population. He mentioned the importance of countering the rhetoric from activists trying to stop the industry growing particularly on social media where the gas industry historically was underperforming.
If you would like to know more about the outcomes of the forum, please contact Edge on 07 3905 9220 or 1800 334 336.
Edge presented at the Gas Energy Australia 2018 National Forum which was held on the Gold Coast on 17 and 18 May 2018. The presentation was aimed at showing the opportunities the changes in the current electricity market held for gas producers. As the electricity market continues to adopt more renewable energy, there is an opportunity to firm this energy by supplying power when the relevant renewable source is not operating.
With an increasing demand for firmed renewable products this is a perfect time for gas producers to consider power generation in support of the renewable industry. It is possible to partner up and deliver the types of products that consumers want, and retailers are able to pass through.
If you would like to know more please contact Edge on 07 3905 9220 or 1800 334 336.
