Dramatic decline in electricity prices predicted as a result of the NEG

The AFR published an article last night which refers to the final design of the National Energy Guarantee (NEG) which was provided to the state and territory leaders on Monday. Within the article is a graph containing forecast NEM wholesale prices (real 2018 $/MWh) from FY18 to FY30, as seen below. The forecast comes from Acil Allen Consulting. Unfortunately, the graph is all that is provided and is therefore impossible for the market to understand what the assumptions are behind the modelling. When releasing forecasts that show dramatic changes in energy prices it should be explained in detail so that stakeholders can understand the key drivers behind the decline. By making the assumptions available, stakeholders are then empowered to make their own assessment on the accuracy of the forecast.

Source: Australian Financial Review.

The Federal Government is claiming that under the NEG households can expect to save an additional $150/year.

The NEG has gained support across the energy market and looks like it will be agreed on by the states and territories. Federal Energy Minister Josh Freydenberg is scheduled to meet with state and territory leaders on 10 August to gain approval of the policy. If successful the NEG will begin in 2020.

If you would like to understand more about the NEG and the potential impact it may have on your energy portfolio moving forward, please visit edge2020.com.au or alternatively you can call one of our team directly on 07 3905 9220 or on 1800 EDGE ENERGY.

Electricity cost forecasting – is it really that simple?

As the Australian generation fleet transition to lower carbon emissions we are seeing the regulatory framework catching up. The regulatory framework is not the only aspect which is changing. We are experiencing an increasing amount of direct power purchase agreements being written between large users and renewable developers.

Economic models are also struggling to catch up. Almost every month a new forecast is published showing that if we just implement the latest proposed change to the market, we will see a return to the good old days of lower electricity prices. Part of this fallacy comes from outdated forecasting models which still look at cost of production as the main input to power prices. Short term price spikes and managing the grid in a sub-five minute period is increasingly important. Most current forecasting techniques fail to capture these factors as well as transient market power where a generator is able to set prices for a period by changing the volume offered in bid bands.

Behaviour is difficult to predict over the long term so most models assume rational behaviour in the long run. This is essentially sensible (it is very difficult to measure irrational behaviour) however begs the question how to model rational behaviour. In the electricity market, we will generally see future costs (over a very long term) trend towards the cost of bringing new plant online. If the long term prices are higher than the cost of new generation, someone should fund additional generation providing a natural cap.

The issue in current forecasting is determining the cost of bringing a new plant online. Traditionally, this has been the total cost of the plant divided by the number of MWh it produced. This provided a neat number expressed in $/MWh and is the basis for levelised cost of electricity (LCOE). The issue with using this number is that price profiles are changing and could be negatively impacted by the type of generation being evaluated. If we look at a solar farm in Queensland, we can estimate the production and the cost of the solar farm. This is the LCOE however it may not be the value of the solar farm, or produce the best estimate of the cap on long term electricity prices. In the event a large number of solar farms are built in the same location, there will be a large production at that time of day and not at others (evenings, mornings and overnight). Other generation sources will be required to fill the gaps. These other sources could have a higher cost and will only be built once there is a price signal to do so. The cost of electricity will be low during daylight hours when all the solar farms should be in full operation. This means that the value of the generation from solar reduces as more is built. This is not captured in the LCOE of generators. A new methodology which looks at the dispatch weighted (when generation occurs) achieved price will have to be considered when evaluating future electricity prices.

The impact of changing long term electricity forecasts are important. Many new plant rely on a component of their generation to be funded from the electricity spot market. With large changes in the assumed cost of electricity as models react to short term announcements it is very difficult to bank a project. On the other side, where consumers are being provided with different assumptions on future prices, it is difficult for them to commit to a purchasing strategy leading to more short term optimisation.

If you are considering a large investment in the electricity market, please call us on 1800 334 336 to learn more about the determination of electricity costs and gain a deeper understanding of the traded market.

Have you exceeded your baseline under the Safeguard Mechanism?

Following the close of the financial year 2018 NGER reporting period, responsible entities will need to determine if they have exceeded their baseline under the Safeguard Mechanism.

The safeguard applies to around 140 large businesses that have facilities with direct emissions of more than 100,000 tonnes of carbon dioxide equivalence (t CO2-e) per year. This covers around half of Australia’s emissions. The entity with operational control of a facility will be responsible for meeting safeguard requirements, including that the facility must keep net emissions at or below baseline emissions levels.

There are various methods for a facility to meet its safeguard requirement depending on its emissions, how it operated during the financial year and its expected operation in the future. Understanding the best way of meeting the baseline is critical to avoid having to overpay under the mechanism. Responsible entities have until 31 October 2018 to submit their financial year 2018 report and apply for any change to benchmark calculations. If a responsible entity still exceeds their baseline, they have until 28 February 2019 to secure Australian Carbon Credit Units (ACCUs) to offset their excess emissions.

Edge is able to provide entities with data that supports your NGER reporting requirements. Edge also works with various buyers and sellers of ACCUs and can assist with the sale or purchase of certificates if required. Finally, if your business has been caught with excess emissions, Edge can proactively design strategies to help mitigate costs under the mechanism.

If you would like to explore services relating to NGER reporting requirements and have any questions regarding the Safeguard Mechanism, call Edge on 07 3905 9220 or 1800 334 336 or speak with your Edge Portfolio Manager.

AEMO Release Inaugural System Plan

This morning AEMO released their inaugural Integrated System Plan (ISP). The plan is an evaluation of the likely changes that will be occurring over the next 20 years across the NEM. The ISP builds on the work of AEMO’s annual National Transmission Network Development Plan, and has been developed in response to the COAG Energy Council’s decision in 2017 to adopt the recommendations made in the Independent Review into the Future Security of the National Electricity Market, specifically pertaining to the need for a strategic national plan. AEMO have used probabilistic scenario based analysis and system optimisation to project the reliability and security needs of the power system while simultaneously identifying the lowest cost combination of resources to meet system and consumer needs. The ISP also incorporates projected Federal emissions policy and State renewable policies.

AEMO’s analysis has identified the following fundamental changes occurring in the energy sector:

Grid demand is flattening due to the growth of rooftop photovoltaic (PV) and increasing use of local storage, as well as overall increases in energy efficiency. This is true even with the anticipated electrification of the transport sector over the period.
Over the next 20 years, approximately thirty percent of the NEM’s existing coal power stations will be approaching the end of their technical lives, and will likely be retired, which highlights the importance of mitigating premature retirements as these resources currently provide essential low-cost energy and system support services required for the safe and secure operation of the power system.
The investment profile and capabilities of various supply resources have changed and are projected to continue to change radically.
In particular, costs of new renewable plant continue to fall, and advances and availability of storage technologies, particularly pumped hydro, flexible gas-powered generation and distributed energy resources (DER) are emerging as core components to a low cost and reliable energy future.

The ISP finds that a portfolio approach of supply resources includes both retention of existing resources and continued growth of utility-scale renewable generation, energy storage, DER, flexible thermal capacity, including gas-powered generation, and transmission development to be the most efficient approach.

AEMO has identified three “Groups” which distinguish actions that a recommended to be taken in the near, medium and longer term.

Group 1: Near-term construction to maximise economic use of existing resources

Immediate action is required to maximise the economic use of existing low-cost generation. Investment is also required to facilitate the development of projected new renewable resources to replace retired and retiring resources, and to provide essential system security.

Immediate investment in transmission should be undertaken, with completion as soon as practicable, to:

- Increase transfer capacity between New South Wales, Queensland, and Victoria by 170-460 MW.
- Reduce congestion for existing and committed renewable energy developments in western and north-western Victoria.
- Remedy system strength in South Australia.

Group 2: Developments in the medium term to enhance trade between regions, provide access to storage, and support extensive development of Renewable Energy Zones (REZs)

The ISP shows that an interconnected energy highway would provide better use of resources across the NEM, through both access to lower-cost resources and realising the benefits of diversity from different resources in different locations with different generation profiles.

Action should be taken now, to initiate work on projects for implementation by the mid-2020s which would:

- Establish new transfer capacity between New South Wales and South Australia of 750 MW.
- Increase transfer capacity between Victoria and South Australia by 100 MW.
- Increase transfer capacity between Queensland and New South Wales by a further 378 MW.
- Efficiently connect renewable energy sources through maximising the use of the existing network and route selection of the above developments.
- Coordinate DER in South Australia.

AEMO will coordinate work with project proponents on a design for transmission networks to support strategic storage initiatives (Snowy 2.0 and Battery of the Nation).

Group 3: Longer-term developments to support REZs and system reliability and security

In the period from 2030 to 2040, a significant amount of the NEM’s coal-fired generation is expected to reach end of technical life and retire. As noted, given the scale of the investment and building time required, it will be important to retain existing coal-fired generators until the end of their technical life to maintain reliability.

In the longer term, to the mid-2030s and beyond, the capability of the grid should be enhanced to:

- Increase transfer capacity further between New South Wales and Victoria by approximately 1,800 MW.
- Efficiently connect renewable energy sources through additional intra-regional network development.

If you have any questions regarding AEMO’s ISP or how you can best position your company in response to the changing energy market please get in contact with Edge on 07 3905 9220 or 1800 334 336.

ACCC’s recommendations aim to restore electricity affordability

Malcolm Turnbull was in Brisbane today promoting “lower energy prices” on the back of the public release of the ACCC’s “Restoring electricity affordability and Australia’s competitive advantage”. The 398 page report is extensive and contains 56 recommendations across the spectrum of the energy market. Edge highlights a couple of key recommendations below.

Recommendation 1

The NEL should be amended to prevent any acquisition or other arrangement (other than investment in new capacity) that would result in a market participant owning, or controlling dispatch of, more than 20 per cent of generation capacity in any NEM region or across the NEM as a whole.

The provision should be designed to prevent market participants circumventing the 20 per cent cap, including by way of ownership structure or contractual arrangements.

Recommendation 2

The Queensland Government should divide its generation assets into three generation portfolios to reduce market concentration in Queensland. The three portfolios should be of a similar size with a mix of generation assets to maximise competition in the wholesale market.

Once created, the Queensland Government should ensure that the three portfolios are separately owned and operated to maximise competition in the wholesale electricity market. The sale of any portfolios should be in line with recommendation 1.

Recommendation 4

The Australian Government should operate a program under which it will enter into low fixed-price (for example, $45–50/MWh) energy offtake agreements for the later years (say 6–15) of appropriate new generation projects which meet certain criteria. In doing so, project developers will be able to secure debt finance for projects where they do not have sufficient offtake commitments from C&I customers for later years of projects. This will encourage new entry, promote competition and enable C&I customers to access low-cost new generation.

The program should operate for at least a four-year period, with support provided for qualifying projects. To qualify, a project proposal must:

have at least three customers who have committed to acquire energy from the project for at least the first five years of operation
not involve any existing retail or wholesale market participant with a significant market share (say a share of 10 per cent or more in any NEM region)
be of sufficient capacity to serve the needs of a number of large customers
be capable of providing a firm product so that it can meet the needs of C&I customers.

Recommendation 5

The National Energy Guarantee seeks to provide a settled policy framework under which new investment is encouraged in a way that enables achievement of the objective of reducing carbon emissions at low-cost while promoting investment in a manner that ensures demand for energy is met.

The ACCC agrees that this is an important policy objective and, with the policy incorporating appropriate safeguards for competition in the contract market, recommends that governments commit to develop and implement the National Energy Guarantee.

Recommendation 6

The NEL should be amended so as to require the reporting of all OTC trades to a repository administered by the AER. Reported OTC trades should then be disclosed publicly in a de-identified format that facilitates the dissemination of important market information without unintentionally revealing the parties involved.

The requirement should be implemented to align with (or be eligible for) any OTC reporting requirements under the NEG.

The AER, AEMC and AEMO should have access to the underlying contract information, including the identity of trading partners.

Recommendation 7

The AEMC should introduce market making obligations in South Australia, which require large, vertically integrated retailers to make offers to buy and sell specified hedge contracts each day, in order to boost hedge market activity. The parameters of a market making obligation should have regard to:

the size of the South Australian market
the distribution of generation ownership in the region
the benefits to market liquidity and efficiency of regular trading activity
the burden of the requirements on obligated entities
any impact on the incentives of intermittent generators to invest in firming technology.

After an appropriate period of time (for example, after two years) the mechanism should be assessed for its effect on market activity, liquidity and risk to determine if it should be continued, amended or removed in South Australia and, potentially, extended to other NEM regions.

Recommendation 11

The governments of Queensland, NSW and Tasmania should take immediate steps to remedy the past over-investment of their network businesses in order to improve affordability of the network. With appropriate assistance from the Australian Government, this can be done:

in Queensland, Tasmania and for Essential Energy in NSW, through a voluntary government write-down of the regulatory asset base
in NSW, where the assets have since been fully or partially privatised, through the use of rebates on network charges (paid to the distribution company to be passed on to consumers) that offset the impact of over-investment in those states.

Such write-downs would enhance economic efficiency by reducing current distorting price signals. The amount of the write-downs and rebates should be made by reference to the estimates of over‑investment by the Grattan Institute, and should result in at least $100 a year in savings for average residential customers in those states.

Recommendation 21

In relation to wholesale demand response, a mechanism should be developed for third parties to offer demand response directly into the wholesale market. Design of the mechanism should commence immediately, building on work undertaken in the AEMC’s Reliability Frameworks Review. The mechanism should:

promote competition through allowing the widest range of businesses to directly offer demand response services
not allow retailers to limit the ability of their customers to engage a third party demand response provider (to the extent it is not inconsistent with the retail contract)
ensure load and generation response are valued appropriately based on the benefit they provide to the wholesale market
limit technical requirements placed on the customer that may inhibit take up or scope of these services (for example, requirements for multiple meters at the customer site).

Recommendation 24

The SRES should be wound down and abolished by 2021.

By in large the recommendations made in the report should help to put downward pressure on electricity prices. Mr Turnbull said today that if prices do not come down after implementation of selected recommendations that alternative actions will be taken.

The full report can be found on the ACCC website here.

If you have any questions on how you can achieve better pricing outcomes on your energy please get in contact with Edge on 07 3905 9220 or 1800 334 336.

STATE OF THE ELECTRICITY MARKET – AUTUMN MARKET OVERVIEW

By Thomas Dargue, Edge Manager of Markets & Advisory

The electricity market was active throughout autumn and the transition into winter. Spot prices were largely stable as has been the case ever since the Queensland Government directed Stanwell Corporation to adopt strategies to lower wholesale prices and Snowy Hydro Corporation seem to be willing to draw down their dam levels to keep prices in New South Wales below $300.00/MWh for each trading period.

Stable spot prices doesn’t mean that the market has been uneventful. In Queensland utility scale solar is expected to grow from only having Barcaldine Solar Farm (25 MW capacity) to more than 2,000 MW installed by the end of 2019. In November 2017 Kidston Solar Farm (50 MW capacity) started generating and since April 2018 we have seen the addition of Sun Metals, Clare, and Longreach solar farms with a combined capacity of 248 MW. Other solar farms are being commissioned at the moment including Hamilton, Whitsunday and Hughenden which means that Queensland will soon have 453 MW of utility scale solar. This is in addition to the small scale solar installed already in Queensland which is more than 2,000 MW and continuing to grow.

New South Wales continue to struggle with sufficient capacity.

To date Snowy Hydro has increased its output when prices looked like it was going to go above $300.00/MWh. This strategy has appeared to be successful with only two prices above this level ($300.80/MWh and $301.06/MWh on 25 July 2017 at 18:00 and 18:30 respectively) since the start of 2017. This defence of prices has come at a large cost to the dam levels with the main dam, Lake Eucumbene, dropping below 30% full which is the lowest level since 2011. In early June 2018, constraints prevented much of Snowy Hydro’s portfolio from being dispatched and the New South Wales prices spiked to $2,428.77/MWh and $2,447.89/MWh on 5 June at 17:30 and 18:30 respectively. The high prices followed large cloud cover reducing generation from solar farms and the removal of several large coal plant due to planned or unplanned outages. These outages persisted and there was another price spike on 7 June 2018 at 19:00 where prices in New South Wales reached $2,464.52/MWh. On both days where the prices were high, AEMO had warned that there were insufficient reserve of generation and Tomago Smelter had demand curtailed under their agreement with AGL.

Victoria was comparatively quiet during autumn. Spot prices remain high in a historical context with the period from 1 April to 30 June averaging $94.92/MWh – more than $10.00/MWh higher than New South Wales over the same period.

Victoria use to enjoy an abundance of cheap generation from their brown coal generators however have seen more imports from South Australia and New South Wales since the closure of Hazelwood Power Station. Victoria has an old fleet of highly polluting power stations and need an orderly transition to avoid suffering intermittent issues seen in South Australia.

Tasmania continues to manage their dam levels to avoid the constraints on local manufacturing plant which was experienced during the last extended outage on Basslink. There was trouble on the interconnector again with no flow between 24 March 2018 and 5 June 2018 following an accident during maintenance. The highly specialised nature of the underseas cable means that parts take a long time to procure and then be installed. Overall the state managed to supply electricity throughout the period. The reliability of Basslink is a further cause for concern as Tasmania is trying to become the “battery of the nation” by using its abundant pumped storage hydro sites to effectively store energy while there is excess renewable generation and produce electricity when there is less renewable generation being produced. If the electricity cannot be reliably transferred in and out of Tasmania, the investment decision is less attractive.

South Australia had more price periods affected by market intervention during May 2018 than any other time in the past.
More than half (61%) of the time, the prices were affected by directions from AEMO.

Some of this is due to Pelican Point coming off 23 April 2018 and not returning until 23 May 2018. An intervention price occurs when AEMO has directed a participant (typically a generator) to dispatch in a different way to its bidding. This was typically used to direct a gas or diesel power station to operate through periods where the owner expected it to not be commercially viable to operate. This was done to strengthen the grid by securing sufficient synchronous generation remains online at all times. AEMO then calculates how the market would have settled if they hadn’t issued the direction. This calculation doesn’t take into account the fact that bidding may have been different if the direction hadn’t been issued. Participants could have chosen to turn on voluntarily or wait for higher prices. As such, this will distort the pricing signal provided in the market. Even though spot prices tend to be lower during these directions, participants that are directed are entitled to compensation which is ultimately paid for by the consumers. When the price signal is taken out of the spot market and put directly onto retailers (who pass the costs on), there is little incentive to solve the issue. The total amount of interventions have increased dramatically as the system is getting weaker however it also seems to be part of a new direction from AEMO. To put the number of interventions into context, there were roughly 20 times more intervention periods in May 2018 (5,451) than the 10 years prior (228) to the appointment of the CEO Audrey Zibelman.

Figure 1: Number of prices affected by intervention from AEMO

If the intervention continues, the spot prices will remain lower however the cost to the consumers could increase.

Overall spot prices were lower than the summer period with the cheapest spot prices being in the North and the East. Queensland had the cheapest prices followed by New South Wales and Victoria. Tasmania managed to end the period with lower prices than South Australia despite Basslink being cut off for part of the period.

Figure 2: Average monthly spot prices in the NEM

The more stable spot conditions saw the forward prices decrease across all the traded regions. The largest fall was in Victoria where prices reduced $8.97/MWh for calendar year 2019 contracts. New South Wales also reduced $8.43/MWh as spot prices remained stable. The forward prices are now similar across Victoria, New South Wales and Queensland however South Australia continues to trade higher than the other regions. This is in part due to expectations that the spot prices are likely to stay higher than elsewhere and partly as firm contracts are more difficult to get as many renewable generators are unable to offer firm prices. Recently Snowy Hydro has been acquiring power purchase agreements with renewable generators and released a tender for up to 800 MW of additional renewable generation. It is likely that Snowy Hydro will use its pump storage hydro plant to firm up the renewable generation offering more firm contracts.

Table 1: Calendar year 2019 forward contracts

	NSW	QLD	SA	VIC
1 March 2018	76.58	64.05	94.36	82.9
31 May 2018	68.15	62.64	87.00	73.93

If you would like to discuss the electricity market outlook and potential impact to your electricity portfolio, please contact our Manager of Markets & Advisory, Thomas Dargue on 07 3905 9226 or on 1800 EDGE ENERGY.

National Energy Guarantee – A Cap And Trade Scheme

By Stacey Vacher, Edge Managing Director

The Energy Security Board (ESB) released a new version of the proposed National Energy Guarantee (NEG) following feedback from a variety of interested parties. The ‘Draft Detailed Design of the National Energy Gurantee: Consultation Paper’was released 15 June 2018. Also included was a paper by the Federal Government setting out the proposal for key areas of legislation which will be set at a Federal level. To support the papers a number of technical working papers were released to explore key aspects of the NEG.

The new version remains focused on reducing emissions in line with Australia’s commitment under the Paris Agreement and ensuring reliability. In addition to these key priorities, a third priority was to ensure that electricity remained affordable going into the future.

In regard to emissions, the largest change from the original version is a voluntary decoupling of the electricity contract written and the emissions levels. A retailer will still need to purchase contracts to keep emissions below a set threshold, however the emissions will no longer have to come from the same contracts that they have purchased electricity from. In theory, a retailer can purchase the output of a coal fired power station however not take on the emissions. That retailer would then be exposed to the emissions at the spot market which could be met through a separate contract with a renewable generator for only the emissions component.

In practical terms, the current proposed NEG is for all intents and purposes a cap-and-trade scheme. A retailer will be provided a cap on emissions. If they exceed that cap, they will have to purchase emissions credits from a low emitting source. If they are under the cap, they can sell their over commitment to other retailers. There will be the option to carry forward a limited amount of a previous compliance year’s over-achievement, for use in a later compliance year.

Reliability will come from AEMO’s forecast of supply adequacy. Each year, AEMO estimates supply adequacy for the following 10 years. If a material gap is identified, AEMO will notify liable entities (likely to be retailers and large users 5MW or greater) that there may be a reliability obligation. If the material gap is still present 1 year out, AEMO may start procuring demand response or additional generation. At this stage all liable entities must disclose their contract position to the AER. If a period with a projected reserve gap has demand above a one-in-two-year event, AER will monitor compliance against the reliability target. Each liable entity must demonstrate that they have procured sufficient qualifying contracts (such as fixed price contracts of a suitable nature, demand side management, or firm generation) to cover their position during peak demand. It is proposed that a reliability gap will also trigger liquidity obligations for vertically integrated retailers to make financial contracts available to the market via the central exchange. Furthermore, it is proposed that large users may transfer their reliability obligation to their retailer, but will have to ensure that their Electricity Sale Agreement addresses this. If a liable entity has insufficient qualifying contracts, penalties may apply. The level of penalties is undecided however a suggestion has been made to link to AEMO’s cost of procuring responses.

As with anything, the cost of both the emissions and the reliability components
of the NEG is likely to be passed on to consumers.

Modelling done to justify the introduction of the NEG assumes that the certainty brought by the NEG will reduce the risk premium of new power stations and cause more trading to occur. Both these factors would likely bring down energy prices (compared to business as usual). However, if the market does not see this as a much more stable investment environment, a reduction in wholesale prices is unlikely to materialise.

The NEG will expose consumers to both emissions and reliability costs. In terms of the emissions component, for most consumers this will be another pass-through cost added to their bills. Any trigger of a reliability gap could drive the cost of acquiring qualifying contracts (such as financial contracts) much higher in the relevant period. Whilst the liquidity obligation aims to counter this, we have concerns around how this will be enforced. It is critical to protecting against extortionate costs under this component. The current version of the NEG discusses a number of ways of addressing this and the ESB recommends creating a new repository for contracts as well as a market liquidity obligation. The repository would be able to report on all over-the-counter (non-exchange traded) products including volume and price. This may only be reported in aggregate for the market instead of identifying the parties to the deal. Very little detail is provided regarding the register. The market liquidity obligation would require large vertically integrated retailers to make contracts available where there is a reliability gap. The retailers must offer to buy and sell contracts at a maximum spread so that prices can’t be set too high for buyers and too low for sellers. As with the repository there are few actual details on the liquidity obligation.

The emissions component has the potential to be highly variable from retailer to retailer. Each retailer will look at the generation they have produced and what emissions contracts they have purchased. If they haven’t purchased sufficient contracts for their entire load, they will assume to have procured the rest at spot. The spot emissions is calculated as the total emissions intensity of all generation less the generation volume already contracted in the emissions registry. A retailer or consumer is unlikely to know in advance how much will be forward sold and therefore the emissions costs can be highly uncertain. The retailer is likely to pass through this cost directly to the consumers, who ultimately wears the risk.

It is critical for all consumers who are agreeing electricity contracts with their retailers to understand how things such as the NEG are managed by their retailer and passed through. For the more sophisticated purchasers there is an opportunity to proactively manage some of this exposure themselves.

The Federal Government will continue to make laws regarding three key areas of the NEG. The key areas are:

Setting emissions targets
Treatment of emissions-intensive trade-exposed industries; and
The role of external offsets

There is a separate paper exploring these issues. The emissions targets are proposed to be expressed in tonnes of CO2-e/MWh. The target will be to meet a 26% reduction on 2005 levels by 2030. This is the target which was set at the Paris Agreement. There has been some criticism that if electricity only meets their proportion of the reduction, all industries will have to make the same reductions. The criticism is that it is much more economical to meet a greater share of the obligation from the electricity sector where alternatives to carbon emissions are cheaper than in other sectors.

The Federal Government is proposing to keep emissions-intensive trade-exposed industries exempt from the NEG obligations. This is to maintain international competitiveness.

This means that the rest of the electricity market will be required to purchase
additional volume to make up for the exemptions.

The paper also discusses the role of external offsets including the Australian Carbon Credit Units (ACCU) which are currently part of the Federal Government’s safeguard mechanism. They have also opened up to the possibility of allowing a limited number of overseas certificates be used for surrender.

There are still some large outstanding issues with both the ESB and the Federal Government’s papers. The ESB is pushing ahead to get a decision from the COAG Energy Council in August 2018. To facilitate this date, the turn-around time for comments are limited. The Federal Government is seeking comments by Friday 6 July 2018 and the ESB wants their comments by 13 July 2018. The commencement date of the NEG is due to be 1 July 2020.

Energy Security Board published issues papers on the National Energy Guarantee

The Energy Security Board has prepared ‘issues papers’ for the jurisdictions and the Technical Working Groups. There is a total of 14 papers covering topics across the implementation of the National Energy Guarantee. They include topics such as emissions registry, treatment of exceptions and forecasting.

The papers have been made publicly available here on the COAG Energy Council website. Once the jurisdictions and the Technical Working Groups have made more detailed technical working papers, these will be available for public consultation. This is expected to be in mid-June.

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

Edge attends Gas Energy Australia 2018 National Forum

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 presents firming options at the Gas Energy Australia 2018 National Forum

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.