Threats to Gas Supply Deal

Aerial view of an LNG tanker docked at a coastal industrial facility with distinctive spherical storage tanks and infrastructure for natural gas.

Chris Bowen, the Energy and Climate Change minister, announced a plan to address looming supply issues for east coast homes and businesses by securing commitment from two big gas exporters (APLNG and Senex) to divert 300 petajoules of gas into the east coast domestic market by 2023. This amount is equivalent to about half of the annual East Coast domestic market demand or two years’ worth of industrial usage.

However, this new deal is already under threat from the Greens, who plan to challenge the government’s industry code of conduct in parliament. Should the coalition support the Greens’ motion, the deal could fall through, increasing the risk of gas supply shortages in the future.

The deal gives exemptions to APLNG and Senex from the $12/GJ price cap under the code of conduct. Chris Bowen stated that “This supply is critical for households, industry and gas power generation as the Bass Strait fields deplete”.

The gas price cap was introduced by the government last year, which triggered a freeze in new supply investments. After negotiations, the government revised the code of conduct, allowing exemptions for gas developers who committed to selling into the domestic market. Bowen has criticised the Greens for potentially disrupting the deal, highlighting the critical role gas will play in the energy transition and for grid reliability.

In related news, Australia’s annual climate change statement projects emissions to be 42% below 2005 levels by 2030, slightly below Labor’s election commitment of 43%.

Additionally, Chris Bowen has declined to specify the potential financial impact on taxpayers from the newly expanded Capacity Investment Scheme. The scheme involves the Australian government underwriting 32GW of new power generation through two auctions per year.

While industry experts anticipate this could cost billions annually, Bowen stated, “It is quite standard budget treatment to say we will not indicate our pricing expectations as we’re about to enter an auction”. He assured that the government’s strategy aims to maximise taxpayer benefits and maintain competitive bidding.

The scheme does not intend to “subsidising negative pricing”. Instead, it requires project proponents to state their minimum required profit and a maximum price point for sharing profits with the government. The government will retain control over bid acceptance and the total amount of gigawatts allocated.

AEMO’s Summer Readiness Briefing

Close-up of a document with the term 'El Niño' highlighted in pink.

On Monday the 13th, AEMO held their annual Summer Readiness briefing. The purpose of this report is to highlight risks and address how they will be combatted in the upcoming summer. The report highlights the well-known risks of El Niño, such as extreme peak demand due to heat (potential for POE10), and the potential for reduced wind generation. In addition to the following covered within the briefing:

  • Weather & Climate outlook
  • Electricity & Gas System Readiness
  • Network Readiness
  • Victorian Bushfire Readiness

The briefing also noted that scheduled generation availability is up across all states compared to last summer, it also points out the risk that several generators are on longer-term outages in the November–December period. Specifically, in coal generation, the following outages were highlighted:

  • QLD: Callide B1/B2, C3/C4, Gladstone 1/2, and Tarong 4
  • NSW: Bayswater 1, Eraring 2
  • VIC: Loy Yang A2, Newport, Yallourn 2

The report highlighted the effects of the positive El Niño, combined with a positive Indian Ocean Dipole (IOD) which would amplify the effects of the El Niño. The El Niño is currently expected to persist into Autumn with the positive IOD forecasted to last into at least early summer.

Additionally, there is also a number of planned high-impact network outages scheduled for the summer. However, AEMO highlights that these outages are only allowed to proceed if they do not pose any system security issues.

TransGrid presented a Bushfire Risk Management Plan which outlined the proactively management and mitigation of our exposure to bushfires. This includes risk of bushfires affecting transmission lines. Proactive management and mitigation involved vegetation management and identifying any high priority defects prior to the start of the season. Ultimately, TransGrid’s assessment indicated strong organisational preparedness for the 2023/24 bushfire season.

The report also notes needed increases in Reliability Emergency Reserve Trader (RERT) participants, specifically to the reliability gap outlined in the latest ESOO (118MW and 120MW in SA and Vic respectively).

Transmission Requires Community Engagement Realisation

Back view of two children and an adult walking towards wind turbines, the adult holding a colourful pinwheel up in the air

With the government ploughing ahead with the re-wiring the nation rhetoric and discussions about $10,000/km costs for land the attention of the AEMC and others have naturally been drawn to the requirement for community engagement.

Many panels and speakers at this years’ All Energy conference in Victoria honed in on the requirements for the local communities to be brought into the fold regarding Renewable Energy Zones, Transmission and the benefit this could bring to those communities.

The AEMC have taken this a step further and on Thursday released the final requirements which are required for any transmission projects to get through the regulatory investment test (RIT-T). They are expecting for this engagement to be across all affected parties from councils to local landowners and will ensure they not only have clear information about the proposals but they are aware of the rights they hold.

Taking directly from the AEMC announcement the main changes being made include:

  • Stakeholders are to receive information that is clear, accessible, accurate, relevant and timely and explains the rationale for the proposed project.
  • Engagement consultation materials, methods of communication and participatory processes must be tailored to the needs of different stakeholders.
  • The stakeholders’ role in the engagement process must be clearly explained to them, including how their input will be taken into account.
  • Stakeholders are provided with a range of opportunities to be regularly involved throughout the planning of ‘actionable’ or ‘future’ Integrated System Plan (ISP) projects and Renewable Energy Zones (REZs).

This is timely given the announcement from Chris Bowen who was speaking at the Future Energy conference in Adelaide this week who amongst his optimistic speech stated that “a properly constructed renewable grid is a reliable grid… is one that we can count on in difficult times,” and that access to transmission or delays in building new infrastructure would be the main contributor to Australia not meeting its targets.

These targets are now set to 82% of Australia’s energy coming from renewable sources by the end of the decade, and GHG emissions cut by 45% (in comparison to 2005 levels) by the same time.

However, with the focus of the government squaring in on transmission as the key messaging to Australia missing its targets and not the lack of cohesive renewable energy strategy for the past 10 years or the governments approvals of new gas fields, you do wonder if that is part of the reason our Minister for Climate Change and Energy is ducking the hard questions at this years COP28 in Dubai which starts at the end of the month.

The announcement that he is dispatching his Assistant Minister, Jenny McAllister has not gone unnoticed, especially by the pacific islands our Prime Minister is trying to woo this week. With those nations key to Australia being announced as the COP31 hosts, Turkey is stating they would also be interested, they intend to firmly hold Australia to its climate promises and pointing the finger will not wash with their nations at the forefront of recent climate disasters.

 

Egypt’s Gas Woes: Blackouts, Regional Tensions, and Global Market Challenges

Offshore gas drilling platform at sea, visible against the horizon under a hazy sky.

Egypt’s increasing reliance on gas has led to struggles with blackouts as domestic gas consumption soared, particularly during summer when high demand for cooling drained domestic reserves. Despite a strong start earlier in the year due to surging pipelined gas imports from Israel, the recent war between Israel and Hamas has impacted regional gas supplies adversely. The tensions led to a redirection of Israeli gas supplies through Jordan, instead of the direct subsea pipeline to Egypt, causing a temporary halt in gas imports. However, as of early November, gas imports from Israel have resumed, albeit in smaller volumes.

The disruption to supplies came at a time where Egypt had already ceased exports of LNG due to high domestic demand, with abandoned plans to resume exports in early October. Egyptian PM Mostafa Madbouly’s announcement of zero gas imports from Israel was reflective of the harsh reality, as Egypt’s cabinet confirmed a drop in gas imports from 800 million cubic feet per day, contributing to a power generation deficit and prolonged blackouts.

According to Reuters, the attacks by Hamas towards central Israel have caused US owned Chevron to cease operating their Tamar field, which resides close to the Gaza strip. This field produces in the region of 40% of all Israeli gas.

Egypt’s status as an LNG exporter is likely in jeopardy, with its only other gas rich neighbour, Cyprus, without a pipeline to directly supply Egypt. These LNG exports are a crucial supply of foreign currency earnings for Egypt, as their debt to GDP ratio was expected to peak at 97% over the Q2/Q3 period.

With the EU cutting ties to Russian gas, there are few suppliers left outside of the United States to provide crucial energy fuel supplies to the EU. The EU will be forced to reassess its energy diversification strategy should it have shortfalls over winter.

This shortage is likely to drive up LNG prices globally, with the Asian market also having fewer options to choose from. The question remains as to whether Australian LNG suppliers will be able to take advantage of a market with fewer competing sources.

Australia’s Safeguard Reforms: New Amendments and the Path Forward for Emission Regulations

Interlocking metal gears with words such as 'RULES', 'REGULATIONS', 'COMPLIANCE', 'STANDARDS', and 'POLICIES'

On Friday the Department of Climate Change, Energy the Environment and Water released the amendment to the Safeguard rule which was largely expected, but still another blow to large emitters. This came into force as of the 7th October 2023 which was the day after it was registered.  

In the latest update to the regulation default emission intensity numbers have been updated and new production variables established. This will be another blow to those Safeguard entities who will now be set to international best practice standards for the default emission intensities.  

Further to the above and also on Friday, the Climate Active certification process had a paper released, following its roundtable and workshop earlier this year. In this consultation paper they are looking to strengthen the certification process which has slipped against industry standards since its inception in 2010.  

One key concept the reforms are looking to address is that currently there is no mandatory gross emission reductions (i.e. reduction of emissions prior to offsetting) required under the legislation.  

The proposals are looking to enforce that “meaningful direct emissions reductions” are undertaken and strategised before offsetting occurs. It would also look to ensure they are tracking their performance against meaningful targets to assist them in this. This requirement will form part of the audit and will be required for them to meet and maintain their Climate Active certification.  

Interestingly they are including all scopes (1, 2, and 3) within their boundary and emission reductions although the “boundary” for this will surely be amended to allow for those outside of their direct control, especially for those within the Scope 3 targets.  

The second part of the consultation paper is looking to tighten the availability of international credits as per the Chubb review paper in late 2022. The proposal will be met by the green lobby as a half measure I am sure as they are stating that vintage requirements on international certification is put in as 5-Years which is loose to say the least. But let’s see if that has any impact at all on price or requirements before we make that call.  

The other interesting proposal is that any ACCUs used as a voluntary requirement will count towards Australia’s national emissions reduction target under the Paris Agreement. It does make you wonder how we will meet these targets at all if this is a scramble for a few voluntary certificates.  

What will be a real key item to watch is if this could this be the first step towards vintage limits on all Carbon Credits, and if so, what will that do to an already tightening supply market. With Safeguard reforms coming in and baselines declining the market is anticipating strength and vintage limits may be the catalyst to the government $75/tonne cap.  

Consultations close on this paper on the 15th December with implementation of changes from 2024 expected.  

Could We Finally Have a Post-2030 Plan?

Wind turbines at sunset overlooking a coastal landscape

You would be forgiven for missing the nuances released in the multiple papers released by the Department of Climate Change, Energy, the Environment and Water in late September. Under the heading of ‘Australian Hydrogen News’ there was a glimmer of hope we may indeed have some post RET certainty on the horizon.

In what was the smallest of the 4 papers, was the Renewable Energy Guarantee of Origin (REGO) scheme paper, which is associated with tracking renewable electricity generation.

Following on from the December 2022 paper which set out a framework for the REGO scheme, this paper is seeking views on timing, implementation and design of the scheme which is looking like it will come into effect in January 2025.

But it goes further, it strongly insinuates, that the aim of this new legislation is to provide certainty that the scheme will allow for the creation of renewable energy certificates, as per the current LGC and STC legislation but with additions post 2030. Thus, the REGO scheme will enhance the Renewable Energy Targets (RET) post 2030 when it will supersede the current legislations, but co-exist for the 5 years prior, “noting there are benefits to moving towards a single, enduring certificate creation framework.” and further it confirms the CER will continue to be the body which will administer it.

This news will be welcomed by many as the concerns around a combined “carbon equivalent” scheme both brought back memories of the old carbon taxes as well as concerns for the demand of ACCUs under the safeguard reforms exacerbating that value of carbon. If you were to include the Scope 2 emissions into that demand mix the governments proposed ceiling of $75/certificate (escalating annually) would in no doubt be reached.

Now the REGO scheme will not be changing any requirements under the RET scheme before 2030. But it is likely to remain in place until at least 2050, as such the investment certainty the market has been looking for may soon be in place. The two will co-exist with the RET liability still being required to be met by the LGC / STC component of your liability, but any voluntary surrenders above that level could be met via the REGO scheme. This could be beneficial as the changes could allow many more of these REGO certificates to be produced and thus hold the price at a softer level than the under demand LGC market. With voluntary surrenders also able to be moved out of this LGC market the demand for these certificates could also be reduced, with the hope these additional certificated could bring the value back to pre-social licence demand levels.

The changes being proposed will allow all electricity generation to be eligible to produce a REGO. This would include below baseline generation. It is noted whilst the REGO may be produced under this certain accounting methodologies, such as GreenPower would not use any of these certificates and schemes such as RE100 are likely to make changes which include further exclusion provisions for older generation power stations.

Another interesting inclusion into the REGO scheme is the further information around the inclusion of STC’s. With the increase in aggregated VPPs and orchestrated DERs the likelihood is post 2030, when most STC deeming periods expire, there is an opportunity to include these smaller schemes within the larger REGO scheme which could in turn create further issues. The reason being is a REGO will have a time stamp and the likelihood of us moving to a hourly matching requirement, is becoming much stronger in some industries. As such the consideration that the REGO is produced when 1MW is reached will not ultimately “match” the offtake it is matching which may cause issues for some stakeholders. However, it has to be assumed that if that is such a strong consideration for your internal stakeholders, they will not be matching their offtake from an aggregated small site portfolio?

One throw away comment in the paper but directly linked to this is “once the REGO scheme is in place with locational and temporal attributes, this could be used as the basis for further refinements to the NGERs market-based methodology.” Could we see post 2030 a requirement for NGERs reporting to move to hourly matching and if so at what cost to businesses? This is absolutely one to watch for in future papers.

Another interesting area being discussed is around offshore generation or export of generation which may be outside of Australia’s territorial waters. Whilst the paper defers a decision on this to the future paper “Electricity and Energy Sector Plan” they cannot defer for long as Sun Cables development shows the scenario will be emerging possibly before the legislation.

The one area they did elaborate on in slightly more detail is the position around how storage will have eligibility within the scheme. We are all acutely aware that no renewable grid can exist without significant increases in storage capability but with this comes significant opportunity for the owners of these facilities to participate in schemes such as this. The Department have on a high level proposed that the certificates produced will be “proportional to the certificates surrendered relative to the charging debit”. A fair definition, but as with all things the devil is in the detail, and we will be watching for the subordinate legislation which will outline this more comprehensively.

Overall, the paper offers little additional substance to what we knew in December, it offers slight clarifications but with the anticipated enactment of the legislation in 2024, and commencement on the 1st January 2025 businesses need to be aware of the changes being discussed and that they are not only applicable to the Hydrogen Industry, regardless of where the Department have decided to place them in consultation.

Powering Up: How Australia Is Revolutionising Its Electricity Grid

The launch of the Very Fast FCAS markets on 9 October 2023, 1300 (market time) will add two new FCAS markets, “very fast” Raise Contingency FCAS, and “very fast” Lower Contingency FCAS. These markets will enable frequency control by providing full active power response within 2 seconds, as opposed to the existing 6 seconds with the “fast” services. With the ability to respond to changes in power supply and demand within a second, these markets will provide a much-needed boost to the resilience of the National Electricity Market (NEM). As we move towards a future increasingly powered by renewable energy sources, the importance of maintaining a stable and secure power supply becomes even greater.

However, not everyone is convinced that the introduction of Very Fast FCAS markets is a positive development. Some critics argue that the increased competition created by these markets could drive down prices, potentially leading to lower revenues for generators and less investment in new capacity. There are also fears that the faster response times required by Very Fast FCAS markets may introduce technical challenges and increase the risk of errors or failures in the system. Furthermore, some stakeholders worry that the introduction of Very Fast FCAS markets represents a case of “scope creep,” where changes to the Market Ancillary Services System (MASS) exceed the original intent of the review and encroach on other areas of the NEM.

Despite these concerns, many see the benefits of Very Fast FCAS markets outweighing the drawbacks. By preparing for these changes now, businesses can take advantage of the opportunities presented by a more responsive and agile power grid.

In addition, the Department of Climate Change, Energy, the Environment, and Water is currently seeking feedback on its proposed Renewable Electricity Guarantee of Origin (REGO) scheme, which was originally proposed in Q4 2022, and aims to provide a stable framework for investors in the renewable energy sector.

The REGO scheme builds upon the existing Large-scale Generation Certificate (LGC) model but includes several key improvements. Firstly, it allows for greater transparency in reporting Scope 2 electricity emissions, making it easier for companies to demonstrate their commitment to sustainability. Secondly, it provides a long-term vision for the integration of offshore energy generation, improved electricity storage solutions, and distributed energy resources. Finally, it enables policymakers to adapt to changing market conditions and implement new policies as needed.

Another important development in the NEM is the Australian Energy Market Commission’s (AEMC) draft report on the Retailer Reliability Obligation (RRO). The RRO was introduced in 2019 to address concerns about the reliability of the power grid as the NEM transitions away from traditional fossil fuel-based generation towards cleaner, more intermittent sources of energy. Under the RRO, retailers must hold sufficient supplies of reliable generation and demand management resources, such as battery storage, pumped hydro storage, and demand response mechanisms, to meet customer demand during periods of peak usage.

While the RRO has been successful in encouraging retailers to invest in reliable resources, certain issues remain that need to be addressed. For instance, the current triggers for the RRO can create perverse incentives for retailers to over-invest in expensive peaking generators rather than cheaper, more efficient alternatives. Additionally, there are concerns that the RRO does not adequately account for the variability of renewable energy sources, leading to unnecessary expenditure on backup generation.

To address these problems, the AEMC’s draft report proposes several changes to the RRO. One suggestion is to replace the existing T-1 trigger, which is based solely on forecast demand, with a hybrid trigger that takes into consideration both forecast demand and actual supply. This change should help prevent situations where retailers are incentivised to overspend on backup generation due to overly conservative demand forecasts. Other recommended adjustments include allowing retailers to use non-generation sources of supply, such as demand response, to meet their obligations, and introducing an explicit mechanism for determining the reliability standard. Feedback on the draft is due by 2 November 2023, with the final report expected to be released in February 2024.

Overall, the launch of the Very Fast FCAS markets, the development of the REGO scheme, and the proposed modifications to the RRO form part of a broader effort to create a more reliable, resilient, and sustainable power grid for all Australians. While there may be disagreement around the specifics of each proposal, few dispute the urgent need for reform if we are to achieve our climate goals while keeping the lights on and the economy humming.

Strikes at Chevron LNG Plants

Last-minute talks broke down at Chevron’s LNG projects, and Unions have initiated three weeks of strike actions, causing the European gas price to surge. Chevron’s Wheatstone and Gorgon LNG plants contribute approximately 7% of global LNG supplies and 47% of Western Australia’s domestic gas. The strikes are planned to average 10 hours a day until Thursday, at which point the strikes will escalate to two full weeks of 24-hour strikes.

The Dutch TTF gas futures (European benchmark gas prices) jumped 8.2% in the first 15 minutes of market opening; a direct result of the strikes. However, the impact of the strikes in the short term is softened because storage levels across Europe are reportedly at record levels for this time of year. Sources from the Union said there were five days of mediation prior to Friday morning without reaching an agreement. The Union indicated Chevron apparently had demanded “special concessions” in bargaining – “a demand which we have put through the shredding machine”.

An energy analyst indicated that the initial action is of a lower level, causing costs and inefficiencies but not significantly impacting production. However, there would be a major impact should the strike escalate on Thursday.

A spokesman for Chevron said, “Throughout the process to date, we’ve made generous, good faith offers and concessions in an effort to finalise enterprise agreements.” “Unfortunately, following numerous meetings and conciliation sessions with the Fair Work Commission, no agreement has been reached as the unions are asking for terms significantly above the market.” The spokesman also stated that Chevron remains committed to attaining an agreement which will achieve a market-competitive outcome in the interests of both Chevron and its employees.

Edge believes the impact of the strikes won’t significantly affect the Australian gas and electricity market as full-scale shutdowns of the Chevron Wheatstone and Gorgon plants are unlikely. This is because it could trigger a domestic energy crisis in WA, prompting government intervention to end the strikes.

Electricity Grid Faces Challenges Amid El Niño’s Return, Warns AEMO

Australia’s electricity grid is bracing for potential disruptions this summer, particularly in Victoria and South Australia. The Australian Energy Market Operator (AEMO) has expressed concerns about the imminent El Niño, which is anticipated to bring about a season of extreme heat and wind-less days.

This latest warning from AEMO (2023 ESOO) presents a very concerning picture. The slow pace of transitioning from old coal plants to cleaner energy sources, coupled with potential coal and gas shortages, has heightened the risk of blackouts. AEMO’s annual 10-year outlook emphasizes the urgency of investments. With nearly two-thirds of Australia’s coal power fleet expected to shut down by 2033, the need for swift action to ensure uninterrupted power supply is paramount.

The challenges of transitioning to a greener economy are becoming more evident. The scenario in NSW, following the proposed 2025 closure of the massive Eraring coal generator, is particularly urgent. AEMO strongly recommends postponing such retirements to avoid blackouts. Contrasting their optimistic report from February, the upcoming summer may see Victoria and South Australia facing with power shortages. These shortages can be attributed to a mix of factors, including periods of low wind, recurring generator breakdowns, and the gas plant shutdown.

The latest AEMO report indicates that roughly 3.4GW of new generation and storage capacity is projected by this summer. Furthermore, initiatives like Snowy 2.0 in NSW and the Borumba pumped hydro project in Queensland are aimed to bolster capacity by 2032-33. However, there are concerns as projects like Snowy 2.0 confront delays and rising costs.

With the re-emergence of the El Niño pattern, the electricity grid is anticipated to be under significant stress, especially following three comparatively milder summers due to La Niña. The growing popularity of electric vehicles and electric heating, notably in states like Victoria, will add to the strain on the grid.

Sarah McNamara, the CEO of the Australian Energy Council, perceives this both as a challenge and an opportunity. She is optimistic that the market can overcome these obstacles with the appropriate price signals to stimulate investment.

In conclusion, while the journey to a low-emission economy might be lined with challenges, with the right strategies and investment, Australia can ensure a reliable and sustainable power supply for its citizens.

And the Best Horror Story of 2023 Goes to…

No need for Stephen King, the ESOO (Electricity Statement of Opportunities) is this year’s horror bestseller, and it comes out this week.

In WA this week we have seen the power of the AEMO reports. With the WA WEM ESOO showing the government’s ambition to phase out coal by 2030 would result in shortfalls. This week the WA government scrambled to cover the shortfall and quickly announced the Muja 6 plant was given an extension until at least April 2025 under ‘reserve outage mode’ conditions. With WA planning to remove 1,366MW from the system by 2030, the transition was showing shortfalls of just below 1GW by FY26 and a terrifying 4GW by FY33. The noises coming from the state are therefore all about how to “manage the transition” and no longer how to meet the targets.

Over in the NEM (National Electricity Market), even before the release of the ESOO this week, this was the week in which we saw announcements in Victoria and an expected announcement from NSW looming. The question is no longer will Australia meet its Net-Zero target, but by how far we will miss it and what impact will closures have before renewable uptake comes onto the grid?

The Victoria government has pre-empted its requirements and moved forward to strike the “structural transition deal” with AGL to continue the operations at Loy Yang until 2035. Despite the pressure from certain board members, even they have to concede that the uptake in renewables is not at pace to orderly transition the market away from coal.

Energy Australia followed this announcement with the news that through its “Climate Transition Action Plan” the Yallourn power station will close in 2028, with the Point Piper remaining available until 2040.

This has been flanked by the NSW government strategically leaking, no doubt to soften the announcement, that the Eraring plant will remain online. The question now is in what form and at what cost.

With Australian renewable uptake at one of its lowest levels in years, hindered by the huge subsidies in the US and massive European demand. Increasingly vocal opposition to transmission upgrades, especially from rural communities, and no certainty on policy post the RET expiry in 2030, there is no doubt this week’s ESOO will make scary reading.

With the COP28 looming at the end of November, I think the hot potato in Canberra is going to be who goes, as there is no doubt when the ESOO is published we will be back in the naughty chair.

The question, therefore, is not will we miss our energy transition and therefore climate targets, but rather by how much?”