2020: What's in store for the year ahead?

Just as energy issues dominated a large share of public discourse in 2019, the debate over energy policy, carbon reduction and ongoing political arguments around climate change means 2020 will be no different with energy front and centre of the national policy debate.

We begin 2020 with the Hon Angus Taylor MP continuing as Minister for Energy and Emissions Reduction. The Nationals party room leadership spill has meant the resignation of Resources Minister Senator the Hon Matt Canavan, and as at the time of writing Keith Pitt MP is expected to be appointed in his place.

Many of the issues affecting the industry remain unclear in terms of policy outcomes, although one factor remains constant: Government intervention is preferred over market solutions.

In terms of the election cycle itself, there are three elections this year: Northern Territory (22 August), ACT (17 October) and Queensland (31 October).

The AEC policy team has put together this list of industry issues that should be on your radar. It is by no means an exhaustive list or one that offers detailed analysis. But it is designed to highlight what we see as the key challenges and how they will play out in 2020.

The Energy Security Board’s Post-2025 National Electricity Market Design

The COAG Energy Council has asked the Energy Security Board (ESB) to develop a long-term, fit-for-purpose market framework to support reliability, to apply from the mid-2020s.  The breadth of the assignment means that the national electricity market (NEM) could experience fundamental change in its design in five years’ time. This will have implications for companies’ trading strategies, risk management policies and revenue streams, and may result in significant costs to update IT systems.

How’s it going to play out in 2020?

After consulting on an Issues Paper in September last year, the ESB has been distracted by the Coalition of Australian Governments (COAG) Energy Council asking the ESB to report back to its March meeting on the NEM’s reliability standard and also how to expedite renewable energy zone (REZ) connections. This means that progress on developing a shortlist of possible options has slowed, and there may need to be expedited consultation to meet the December 2020 deadline to make a recommendation to COAG.

It is likely that the ESB will consider a number of different options for the future NEM, including incremental change, introduction of capacity payments, and adopting a suitable overseas example.  Any recommendation will also need to consider changes which are currently being implemented or considered at present, including Five Minute Settlement, Coordination of generation and transmission investment implementation (COGATI) and Two-sided Markets.

COGATI

Through 2019 the Australian Energy Market Commission (AEMC) developed a major reform idea to change the NEM’s locational pricing arrangements. In the existing regional model generators and customers across an entire state receive and pay the one price (adjusted for loss factors) which is determined at the region’s reference node. Under the COGATI reform generators would instead receive their local (nodal) price and customers could elect to pay their local or a load-weighted regional price. Financial Transmission Rights (FTRs) would be available to hedge the difference between nodal and regional prices. Some FTRs would be grandfathered to existing generators, whilst others would be auctioned.

How’s it going to play out in 2020?

The AEMC intend to present governments with a final report to their work in March 2020. If the COAG Energy Council support that direction, they will return it to the AEMC as a rule change proposal in mid-2020. Even at that time, the reform will be largely conceptual, and the rule change process itself is where the detailed design, as well as the case for proceeding, will need to be made, which would take at least a year. The AEMC have stated that if they go ahead, they would provide at least 4 years notice. In practice this means implementation not before the middle of the decade, indeed possibly coinciding with ESB2025 reforms.

Whilst locational pricing is standard overseas, it remains highly controversial in Australia. The majority of market-exposed participants, especially renewable generators, appear to oppose the reform. Given this reaction, it is quite possible that COAG may not propose it as a rule change, or they could refer it to the ESB to be combined with their 2025 work.

Two-way market concept and demand response

How to transition to a two-way energy market and what it means for Distributed Energy Resources (DER) and Demand Response (DR) has become a central theme for energy planners, energy producers and the emerging distributed energy technologies. We can anticipate, and indeed we are already experiencing, an increasingly decentralised energy system.  A significant amount of electricity is already being generated at a smaller scale and some local areas are already energy hubs in a high level of decentralisation. The traditional one-way power flows from transmission through distribution to consumers in these hubs have become two-way flows.

These energy hubs create opportunities; opportunities for individual customers to reduce their power bills, opportunities to delay or remove the need for traditional network and generation investments and opportunities for the greater integration of renewables. They also create challenges; the lack of control of rooftop solar means that both energy supply and network assets need to be better adapted. The increasing penetration of storage solutions such as household batteries brings more accessible control for system operators if they interact with the system, and difficulties if they do not. More sophisticated Demand Response, such as home energy management systems that can adjust electricity usage in response to price signals or dispatch signals may be more or less reliable for balancing the grid depending on how they, and the end user, interact with the system.

Clearly what’s required here is coordination. Coordination of DER and DR resources is essential to convert a problem into a solution. There is also significant financial benefits that can accrue to customers through a market for their network support and energy management capabilities, along with a broader benefit of deferred or avoided network costs that the CSIRO estimate might lower household bills by as much as $400 per year if we can optimise these resources. With so much at stake for all concerned, whether they be end users with or without an interest in DER or DR, or networks, or grid scale generators or system operators, it is not surprising that issues will emerge as we seek to address the complexities thrown up by these challenges and opportunities. The two way energy market gives scope for the Uber(s) of energy to emerge. Disruption lies ahead, we are in for exciting times.  

How’s it going to play out in 2020?

ARENA’s Distributed Energy Implementation Program (DEIP) has established a number of work streams that start to address operational and market design to support a two way energy market. Similarly the Australian Energy Market Operator (AEMO)/Energy Networks Australia Open Energy Networks Project examines what the requirements might be. Retailers should stay engaged with and participate actively in these opportunities in the next twelve months to make sure their views are heard.

ESB’s review of the Reliability Standard

The Reliability Standard sets a probable level of unserved energy (USE) that is appropriate to balance the cost of providing reliability against the value customers put on not suffering an unexpected outage. If the reliability standard is tightened (i.e. the level of USE is reduced) then costs to consumers will increase, since more generation will need to be available in times of peak demand.

How’s it going to play out in 2020?

The ESB is required to report to the COAG Energy Council at its meeting on 20 March. As it was only given the task at the 22 November 2019 meeting, this has left little time to consider the topic, and there may be little change from the Reliability Panel’s last review on 30 April 2018. However, it is apparent that one of the issues is whether the measurement of USE, which is considered over a full calendar year, is appropriate, since outages have a temporal component to their inconvenience. For example, an hour-long outage in the middle of an autumnal night has little effect, whereas the same hour-long outage occurring at 6pm on a hot summer’s workday evening will have more impact on consumers. Thus there is a likelihood that an additional standard may be proposed to cater for these temporal differences.

Implementation of mandatory primary frequency response rule change

This rule change will impose an obligation on all capable generators and batteries to provide primary frequency response (PFR) at all times. This means they must be set up to vary from their preferred energy dispatch to support frequency whenever it goes outside a very narrow deadband. Unlike the existing Frequency Control Ancillary Services (FCAS) markets, there will be no financial compensation for service. It is expected to improve the frequency performance of the NEM which has been poor in recent years, but it is also expected to reduce the importance and value of the FCAS markets and to interfere with generators’ ability to achieve their preferred level of dispatch.

How’s it going to play out in 2020?

AEMO proposed the rule change in August 2019, and, given the primacy of system security and lack of other short-term options, the AEMC seem certain to make the rule in March 2020. They have however indicated their disquiet about its non-market characteristics and intend to impose a three-year sunset. The industry must find a replacement, presumably which includes a fair reward, by early 2023.

From mid-2020 generators and large-scale batteries will be subject to an implementation and compliance plan administered by AEMO. Those who consider themselves technically incapable, or where costs are large, will need to apply to AEMO for an exemption, and if rejected, launch a dispute.

Western Australia’s Wholesale Electricity Market Energy Transformation Strategy

WA’s Wholesale Electricity Market (WEM) is a discrete market in transition due to the influx of renewable energy generation, both large-scale and small-scale. The WA Government has outlined its Energy Transformation Strategy to embrace these changes, and there is the opportunity for NEM participants to learn from the WA experience, particularly in light of the Post-2025 NEM Design Review being conducted at present.

How’s it going to play out in 2020?

The WA Government has established an Energy Transformation Taskforce, led by Stephen Edwell.  Reporting directly to the Minister, the Taskforce has three work streams: Whole of System Planning, Distributed Energy Resources and Foundation Regulatory Frameworks.

It is intended that the first two work streams will be largely complete by the latter half of 2020.  Foundation Regulatory Frameworks (‘Delivering the Future Power System’ and ‘Improving Access to the Western Power Network’) is a larger piece of work, and involves making recommendations to the Minister regarding the future market arrangements (which are scheduled to be implemented in October 2022).

Energy Fairness plan

The Energy Fairness Plan was a pre-election policy commitment made by the Victorian Government to reform the retail electricity market. The first phase of reforms intend to ban door-to-door sales, telemarketing, ‘win-back’ offers and ‘save’ offers by energy retailers. The ban does not extend to unsolicited sales from solar companies. The Victorian Governments hopes that this ban will encourage customers to engage in the retail market in different ways, such as via Victorian Energy Compare, while also compelling retailers to develop new incentives for attracting customers.

The second phase of reforms intends to expand the powers of the Victorian regulator, the Essential Services Commission (ESC), to include information gathering powers, and increase the maximum penalties retailers face for non-compliance. The ESC will then be able to use the revenue raised from these penalties to fund litigation as part of its ‘Litigation Fighting Fund’.

How’s it going to play out in 2020?

The Victorian Government intends to introduce these reforms to Parliament in the first half of 2020. Whether the State Government chooses to undertake consultation or not will ultimately impact how these reforms play out. Industry stakeholders are currently encouraging government to carry out consultation so all parties can better understand the reforms and provide feedback to mitigate any unintended consequences.

Consumer Data Right

The Consumer Data Right (CDR) was recommended by the Productivity Commission in 2017, to provide households and small to medium enterprise (SME’s) with a right to efficiently and conveniently access specified data about them held by businesses. Up until late 2019, government attention has been focused on the banking sector. The CDR will be implemented for the big four banks by mid-2020, and is estimated to increase compliance costs by more than $86M annually in the sector.

Energy is next cab of the rank, and with anticipated compliance costs of approximately $10M each year, represents one of the most significant implementations in recent years.

How’s it going to play out in 2020?

In 2020, the Australian Competition and Consumer Commission (ACCC), Treasury, AEMO, and industry will work together to develop a framework to enable third parties to access consumer data, leading up to an implementation date in the second half of 2021. These third parties are expected to utilise the CDR to offer customers optimized energy solutions that meet their needs. This creates both opportunities and risks for retailers. Retailers who develop innovative products that align with their customers energy use will succeed, whilst those who do not adapt their product and service offerings might find their market segment diminish.

Advocates of the CDR consider that access to data, and data portability, is the key to delivering better consumer outcomes in the energy sector. If implemented effectively, the CDR could deliver a solution to the “confusopoly” customers see today.

“Big stick” implementation

The government’s “Big Stick” will come into force on 10 June 2020. Between now and then, the ACCC is required to develop and publish compliance guidelines to clarify what is widely regarded as a vague and duplicative set of obligations.

Electricity businesses will need to act quickly – the ACCC have committed to releasing draft Guidelines in early March, with a final unlikely to be published before May. Given small customer pricing will likely to be amended on 1 July, retailers in particular will need to ensure their pricing decisions comply with the new laws almost immediately after the obligations become known.

How’s it going to play out in 2020?

Other elements of the Bill will likely take some time to be understood. The ACCC has yet to provide any insight on its interpretation of the key obligations, nor whether a transitional period of ‘no action’ will be undertaken to ensure electricity businesses are reasonably able to comply with the obligations before enforcement action commences.

Regulatory Investment Test for Transmission

Finally, there are a number of interconnector projects being mooted, based on analysis AEMO has conducted for the Integrated System Plan (ISP), the next edition of which will be published later this year.  The ESB has also undertaken work to identify how transmission projects can be expedited, and has recommended that the initial phase of the Regulatory Investment Test for Transmission (RIT-T) process, the Project Specification Consultation Report, be taken as given, if the project is listed in the ISP. The following stages, the Project Assessment Draft Report (PADR) and the Project Assessment Conclusions Report (PACR) will still need to be completed before the project can be submitted to the Australian Energy Regulator (AER) for approval, but they will be able to use the ISP assumptions as the basis for their analysis.

Name of Project

MW

Cost

$/MW

Approval Status / PADR status

Expected date of next stage

Expected commissioning date

Queensland to NSW Interconnector (QNI)

690 North

1,120 South

$230m

$0.25m

PACR published

RIT-T to be assessed Q3 2020

2021-22

Victoria to NSW Interconnector (VNI) Minor

170MW

$80.5m

$0.47m

PADR published

PACR expected 2020

2022

Project EnergyConnect (aka RiverLink)

800MW

$1.53b

$1.91m

RIT-T completed

ElectraNet and TransGrid will submit applications for project funding to the AER for assessment, with a decision on project costs expected from the AER in mid-2020.

2023-24

HumeLink

2,570MW

$1.35b

$0.53m

PADR published

PACR 1H 2020

2025-26

QNI Medium

 

 

 

 

PADR 10 Dec 2021

2026-27

QNI Large

 

 

 

N/A

N/A

After the development of a Medium QNI upgrade, a larger QNI upgrade could be needed in the 2030’s - depends on future renewable development in Queensland and New South Wales, and respective state policies for renewable generation.

VNI West

380-1,930MW

$815m-$1,855m

$2.14m-$0.96m

RIT-T just starting

PADR 30 June 2021

2026-27

Marinus Link

750MW

$2.76b

$3.68m

PADR published

TasNetworks will be receiving feedback on the PADR as part of the RIT-T consultation process

As early as 2027-28 if a decision to proceed was made by 2023-24.

Western Victorian Regulatory Investment Test for Transmission

1,500MW

$370m

$0.25m

PACR published

Not specified

2025

PSCR->PADR->PACR->RIT-T