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Chapter 6: Liability and exemption framework

Table of contents

This chapter considers the liability framework for the Renewable Energy Target (RET), including which entities are liable, the calculation of individual liability, the surrender timetable for certificates and the shortfall charge. It also explores the exemption arrangements, including the self-generator exemption and the partial exemption for emissions-intensive, trade-exposed (EITE) industries.

6.1. The liability framework

The RET creates demand for renewable energy by requiring certain entities to surrender a set number of certificates – each equal to one megawatt hour (MWh) of renewable energy generation for compliance purposes – each year. If an entity does not surrender a sufficient number of certificates, it must pay an administrative penalty (a shortfall charge). The scheme also creates a number of exemptions from this liability – for EITE businesses and self-generators.

The liability framework determines which entities must acquire and surrender certificates. The Renewable Energy (Electricity) Act 2000 (Cth) (REE Act) defines liable entities as those that make a ‘relevant acquisition of electricity’, where a relevant acquisition refers to electricity acquired from the wholesale market (for example, from the National Electricity Market) or where an end-user acquires electricity directly from a generator. In practice, liable entities are primarily electricity retailers.

An acquisition is not relevant if the electricity was delivered on a grid with a capacity of less than

100 megawatts (MW).

Individual liability is determined by applying a percentage (set annually by the Minister) to an entity’s electricity acquisitions for that year. Entities acquit their liabilities by surrendering the required number of certificates to the Clean Energy Regulator by February of the following year, with interim quarterly surrenders required under the SRES. If a liable entity does not surrender a sufficient number of certificates required to acquit it’s RET liability, it must pay the shortfall charge.

6.1.1 Liable entities and calculating individual liability

As described above, an acquisition of electricity is not liable under the RET if the grid from which the electricity was acquired has a capacity below 100 MW. The Renewable Energy Sub Group’s 2012 report to the Council of Australian Governments’ Review of Specific RET Issues explains the rationale for these settings, noting:

To minimise costs of compliance and administration, liability under the RET is imposed on wholesale acquisitions of electricity, mainly by retailers who are best placed to manage RET liabilities … To reduce compliance and administrative costs, grids of less than 100 MW capacity are exempt from liability. (Renewable Energy Sub Group, 2012, p.41)

The Authority’s view is that increasing the grid generation threshold, for example, to match growth in population and aggregate electricity demand or to leave additional renewable capacity out of the calculation (as suggested by the Power and Water Corporation (sub.137, p.2)) could be inequitable as similar communities could be treated differently, depending on when their grid sizes grew.

The Authority’s view is that the liability definitions and thresholds generally appear to be functioning effectively and strike a reasonable balance between comprehensiveness and administrative simplicity. Liability and threshold arrangements have been in place since the commencement of the Mandatory Renewable Energy Target (MRET) in 2001 and liable entities are accustomed to them and have established systems and practices in place for compliance.

  • There should be no changes to the primary point of liability or the size threshold for coverage of grids.

6.1.2 Opt-in liability arrangements

A number of stakeholders proposed allowing large electricity users to opt-in to manage liability under the RET for the electricity they consume. For instance, the Australian Industry Greenhouse Network submitted that an opt-in scheme would provide for:

  • Market liquidity: through increasing the number of buyers and (possibly) sellers that are covered under the RET, leading to lower cost of compliance and efficient market outcomes
  • Flexibility: for energy users to evaluate the most cost efficient solution to manage their obligations under the RET. Large energy users should be able to evaluate how to best manage their aggregated liabilities to minimise the net cost to their business.

    (Australian Industry Greenhouse Network, sub.164, p.6)

Stakeholders supporting opt-in arrangements also identified other potential benefits. The Climate Markets and Investment Association submitted that:

Market participants have already started decoupling electricity and REC costs during the development of Power Purchase Arrangements (PPA). However, the current arrangement which mandates the wholesale purchaser of electricity to manage the RECs for all liable entities makes decoupling more difficult to agree. The ability for liable entities to opt-in would remove this complexity. (Climate Markets and Investment Association, sub.94, p.2)

The Association also noted that:

The limited number of wholesale market participants impacts the liquidity of the RET. The ability for liable entities to opt-in would create greater market liquidity and also provide project developers a greater range of participants with which to agree a PPA. (Climate Markets and Investment Association, sub.94, p.2)

The additional flexibility provided by opt-in arrangements may have benefits from an economic efficiency perspective. In some circumstances, electricity suppliers may have a reduced incentive to seek out opportunities for least-cost compliance with RET obligations as they are able to

pass-through RET costs to consumers. Allowing electricity consumers to opt-in would allow the party that has the clearest incentive to minimise costs of RET compliance to source and purchase certificates. This should encourage cost-effective compliance and reduce the overall costs of the RET. For similar reasons, opt-in arrangements have been allowed in other certificate-based schemes, such as the carbon pricing mechanism and the New South Wales Greenhouse Gas Reduction Scheme (GGAS).

In terms of costs, opt-in arrangements would lead to increased administrative and compliance costs associated with measurement, reporting and verification. It would also potentially increase uncertainty for existing liable entities regarding their own liability. These costs could be at least partly addressed through the design of the opt-in arrangements. A sufficiently high participation threshold should be set to ensure that the number of additional participants is manageable. Also, a sufficient period of notice of intention to opt-in should be required to provide certainty for existing liable entities. Finally, if a party has opted-in, then it should be clear that that party alone is responsible for compliance, with no recourse to the original retailer in the event of non-compliance.

On balance, the Authority considers that the benefits of providing for opt-in liability arrangements are likely to outweigh the costs if appropriately designed.

The Authority notes that key design features that need to be put in place for an opt-in scheme would include:

  • specification of which entities are eligible to opt-in for example, size threshold (specified in terms of electricity consumption), plus metering requirements;
  • deadlines for opting in (or out again, but not within a compliance year), and notification arrangements for electricity suppliers;
  • administrative processes to create a liability to surrender certificates for the relevant supply of electricity for the consumer, and removal of liability for that supply from the electricity supplier;
  • requirements for measurement, reporting and verification of electricity consumption by the opted-in entity; and
  • processes for the surrender of units by the opted-in entity.

A number of electricity users and retailers have commented that the model for opt-in for large electricity users under the GGAS was effective (see Box 7). For instance, Origin Energy Ltd submitted that:

[Opt-in] arrangements appear reasonable. Origin would welcome further engagement in the design of the opt-in arrangements to ensure that they are efficient for all parties involved. From a retailer’s perspective one of the key considerations is the notice period given regarding changes of retailer. We note that the large user provisions in NSW GGAS have worked reasonably well. (Origin Energy Ltd, sub.213, p.7)

Box 7

Greenhouse Gas Reduction Scheme opt-in arrangements

Under GGAS, large consumers of electricity were allowed to opt-in to assume scheme obligations for meeting emissions intensity benchmarks from liable electricity suppliers. To measure the amount of electricity consumption that is opted-in the GGAS used metering points with national metering identifiers administered by the Australian Energy Market Operator. The GGAS administrator received reports of annual electricity consumption at the relevant meters from both the electricity user and the retailer. In practice, both parties relied on electricity sales data, and resolution of any discrepancies did not prove difficult. The GGAS had around 32 default liable entities and 12 opted-in participants, and administration of reporting and verification under the GGAS was estimated to take approximately one month for two full-time staff.

  • Several stakeholders also highlighted the importance of consultation on the detailed design features of an opt-in scheme to ensure that it is effective and taken up by potential participants. The Australian Industry Greenhouse Network submitted that:

… we recommend a thorough consultation process be carried out to determine an efficient RET opt-in scheme design that avoids duplication and minimises the administrative burden on both the end user and supplier/retailer to maximise value and uptake. (Australian Industry Greenhouse Network, sub.164, p.6)

Experience with the development of opt-in schemes for natural gas users and other large fuel users under the carbon pricing mechanism by the Department of Climate Change and Energy Efficiency suggests that, while conceptually relatively straightforward, opt-in schemes can entail considerable complexity in practice.

The Authority considers that further analysis and consultation by the Government will be important to establish the detailed design features of an opt-in scheme, and that the GGAS opt-in model provides an appropriate starting point for this detailed design work. In developing the opt-in approach it will be important to ensure that it is effective for large electricity users and retailers, while maintaining the environmental integrity of the RET and ensuring administrative costs are efficient. Some of the key issues that the Authority considers will need to be addressed are outlined in Box 8.

Box 8

Key design issues for Renewable Energy Target opt-in

Threshold: Setting a minimum size threshold for electricity users eligible to opt-in is likely to be an effective way to limit the number of participants. This would reduce administrative costs and enhance the workability of an opt-in scheme. The GGAS allowed for opt-in by large electricity users with over 100 gigawatt hours (GWh) of annual electricity consumption, including at least one site with over 50 GWh. The GGAS had 12 participants opting-in for New South Wales and the Australian Capital Territory and relatively low administration costs. However, some large electricity users have submitted that the GGAS threshold is too high and would exclude facilities that could effectively opt-in to manage obligations.

The Authority considers that in setting a threshold it will be important for the Government to strike an appropriate balance between allowing large consumers to manage their own costs more efficiently and the increased administrative burden associated with verifying opt-in arrangements and increased numbers of participants in the RET.

Notice Period: Providing an adequate notice period for opt-in will be important to minimise costs for both the Clean Energy Regulator and electricity retailers. Liable retailers will require sufficient time to cross-check information relating to metering points and to make adjustments to billing systems when a customer opts-in to manage their own liability under the RET. The Clean Energy Regulator will also need time to process applications and verify information. The GGAS functioned effectively with a

6 month notice period, and a requirement that opt-in be for full compliance years.

Measurement and verification of electricity consumption: Effective measurement and verification arrangements are important to ensure environmental integrity and to provide certainty of obligations for opt-in participants and other liable entities. Among other things, losses on distribution networks would need to be accounted for to ensure equivalent treatment for retailers and firms that opt-in.


  • Large electricity consumers should be permitted to opt-in to assume direct liability for Renewable Energy Target obligations. The Commonwealth Government should consult further with stakeholders to develop a detailed approach to opt-in that is efficient for both large electricity users and retailers. The Authority considers that the New South Wales Greenhouse Gas Reduction Scheme opt-in model would be an appropriate starting point for this detailed design work.

6.1.3 Calculating individual liability

The annual Large-scale Renewable Energy Target (LRET) and Small-scale Renewable Energy Scheme (SRES) targets are divided among liable entities on the basis of their reduced acquisitions of electricity. Reduced acquisitions relate to the electricity acquired on grids above 100 MW capacity, minus any reduction in liability (in megawatt hours) which is provided in partial exemption certificates (see Section 6.5.1). The annual targets are set as a percentage which is multiplied by an entity’s reduced electricity acquisitions in the compliance year, in order to determine the number of certificates that must be surrendered. The percentages are known as the renewable power percentage (RPP) for the LRET and the small-scale technology percentage (STP) for the SRES, and are explained in more detail below.

Large-scale Renewable Energy Target

The RPP is required to be set annually no later than 31 March in the Renewable Energy (Electricity) Regulations 2001 (Cth), and applies to the entire calendar year in which it is set. When determining the RPP, the Minister must take into consideration:

  • the LRET gigawatt hour target for that year;
  • the estimated total electricity sold on liable grids for that year;
  • any surplus or deficit of certificates from previous years; and
  • the amount of all partial exemptions.

Once the RPP is announced and partial exemption certificate (PECs) are received by liable entities, they are able to estimate their accumulated liability for the LRET at any point in the compliance year.

The RPP for 2011 was 5.62 per cent (approximately 10 400 000 LGCs) and for 2012 is 9.15 per cent (approximately 16 763 000 LGCs). The default RPP in 2013 is 10.42 per cent (approximately 19 088 000 LGCs). Annual fluctuations in the RPP are due largely to changes in the annual LRET target, which are prescribed in the REE Act.

Small-scale Renewable Energy Scheme

The STP is also required to be announced by 31 March of the compliance year, but is calculated somewhat differently to the RPP, as the SRES scheme has an uncapped target with a quarterly surrender of certificates (see Section 6.2 for surrender timing). The STP is largely based on the expected number of certificates to be created in the compliance year, adjusted for any differences between the estimated and actual certificates from the previous year, so that the STP tracks certificate creation.

Under SRES, a liable entity must surrender a set percentage of its STCs each quarter. As the actual electricity acquisitions for the compliance year are not known in the first three quarters, an estimate is used to determine how many STCs must be surrendered, based on the previous year’s liable electricity acquisitions multiplied by the STP for the compliance year. The actual SRES liability is trued-up in the fourth quarter when the actual compliance year’s liable electricity acquisitions are known.

Flexibility is provided if a liable entity believes their liable acquisitions this compliance year will be sufficiently different to last year’s actual acquisitions. If desired, the liable entity can apply to the Clean Energy Regulator to have a proposed amount, instead of the previous year’s liable acquisitions, used to determine quarterly surrender requirements in the first three quarters (with true-up still occurring against actual acquisitions in the fourth quarter). This revised estimate can only be provided once per compliance year. To prevent a liable entity from deliberately underestimating their STC surrenders in the first three quarters, penalties in the form of quarterly shortfall charges can be applied by the Clean Energy Regulator retrospectively to quarters in which the actual liability for the compliance year exceeded the proposed amount by more than ten per cent.

The STP for 2011 was 14.80 per cent and for 2012 is 23.96 per cent. The non-binding estimate for 2013 is 18.76 per cent, equivalent to 34 457 000 STCs. STP fluctuations are due to changes in the forecast number of certificates that are expected to be created and adjustments for any difference (surplus or deficit) between the forecast and actual certificate creation figures from the year before. Certificate creation in 2011 was greater than expected, meaning the 2012 STP had to be set higher to account for the resulting surplus.

6.1.4 Timing of publication of the renewable power percentage and small-scale technology percentage

In submissions from stakeholders, a number of liable entities and large energy users proposed changing the timing of the publication of the RPP and STP, from 31 March of the compliance year, to before the commencement of the compliance year. These stakeholders noted that earlier publication of the percentages would reduce risks, facilitate planning for compliance with liabilities, and allow consumers to enter into price pass-through arrangements with electricity retailers prior to the commencement of the year. For instance, Qenos Pty Ltd stated that:

LRET and SRES liability is not finalised until 31 March each year. This makes it more difficult for a company to accurately determine its likely RET costs and introduces greater risk for liable entities. This higher risk generally results in higher costs, via the imposition of risk premiums of RET liability. This risk could be reduced, and companies would be able to better manage their RET obligations if the relevant percentages were able to be declared at or before the beginning of each calendar year. (Qenos Pty Ltd, sub.60, p.5)

Similarly, the Major Energy Users Inc. stated that:

Setting the RPP 3 months into the year in which it applies, provides no ability for incorporation into cost budgets. It would be more use if the RPP was set prior to the start of the year in which it applies to allow consumers to build the cost into its future budgets. (Major Energy Users Inc., sub.103, p.20)

The timing of the RPP and STP requires balancing certainty for industry participants with the accuracy of the percentages. The RPP and STP are based on forward estimates of a number of factors – including the estimated amount of electricity that will be acquired in relevant acquisitions and the estimated amount of all partial exemptions. They also rely on some inputs from previous years, such as the surplus or deficit of STCs. The earlier the RPP and STP are set, the less accurate they are likely to be and these inaccuracies will need to be accounted for in setting the next year’s percentages.

The RPP is able to be predicted with a relatively high degree of accuracy ahead of the compliance year, because the RPP does not follow certificate creation and the interim LRET targets are published within the REE Act. The STP is harder to predict with accuracy, as it involves the estimation of more variables, with a key area of uncertainty being the forward estimate of the number of STCs likely to be created in the compliance year. This factor is inherently difficult to estimate, regardless of timing.

The Clean Energy Regulator advised that there would be only a small loss of accuracy if the RPP was set earlier, provided this was not before November preceding the compliance year. An earlier announcement of the STP would be expected, however, to result in a less accurate estimate of the number of certificates expected to be created in the following compliance year. It would also result in a longer lag time between over and under surrendered certificates from previous years flowing through to the STP, due to less data being available. The overall effect of an earlier announcement of the STP is therefore greater certainty for liable entities ahead of the compliance year, but potentially wider variations in the STP between compliance years, as corrections from previous years flow through.

The Authority sees benefit in the percentages being announced before the commencement of the compliance year. Such a change would allow a liable entity to be able to estimate its cumulative LGC liability throughout the compliance year with a higher degree of accuracy, and to be more informed when managing its certificate purchases. An earlier announcement of the STP would also allow a liable entity to estimate the number of certificates it must surrender for the whole of the first quarter of the compliance year, based on its previous year’s reduced acquisitions.

Most stakeholders that responded to the Authority’s preliminary view that the RPP and STP should be set earlier were supportive of the approach. Australian Power and Gas submitted that:

APG strongly supports the Authority’s view to set the renewable power percentage and

small-scale technology percentage ahead of the compliance year…

By imposing a requirement on the Clean Energy Regulator… to set both the RPP and STP prior to the start of the compliance year (suggested by 1 December of the previous year) will greatly assist retailers with the management of their liabilities under the Schemes as well as their budgeting of certificate costs and negotiations in wholesale arrangements.

(Australian Power and Gas, sub.188, p.2)

The Authority’s view is that it is desirable for the percentages to be announced by 1 December of the previous year. In light of this recommendation, the Government may also wish to consider whether to continue setting the RPP and STP in regulations, which can have relatively long lead times, or whether another instrument such as a determination, may be preferred to set the RPP and STP.


  • No changes be made regarding the process for calculating individual liability.
  • The relevant renewable power percentage and small-scale technology percentage should be required to be set prior to a compliance year, and preferably by 1 December of the preceding year.

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6.2. Certificate surrender

Liable entities acquit their annual obligation by surrendering the required number of certificates to the Clean Energy Regulator.

Under the LRET, surrender occurs annually as part of a liable entity’s annual ‘energy acquisition statement’, which must be submitted on or before 14 February. The statement allows the Clean Energy Regulator to confirm that the entity has surrendered the appropriate number of certificates to meet its obligations. If the liable entity does not surrender the number of certificates required, a shortfall charge applies to the outstanding amount.

Surrender occurs quarterly under the SRES. The surrender is weighted toward the first quarter with a surrender requirement of 35 per cent of the STCs (due 28 April), followed by 25 per cent in the second and third quarters (due 28 July and 28 October respectively). The last quarter is around 15 per cent of the STCs (due 14 February) although this may vary as the liable entities’ actual electricity acquisitions are known by this time and there is a need to true-up in this quarter. According to the Enhancing the Renewable Energy Target Discussion Paper, the rationale for this approach was to provide more regular cash flow to small-scale certificate holders (Commonwealth Government, 2010). This was considered necessary as, if certificates cleared at a set price through the clearing house, there would be no impetus for liable entities to make regular acquisitions of small-scale certificates.

The timing of surrender affects liable entities and certificate holders in opposite ways. Any cash flow benefit to certificate holders is potentially at the expense of liable parties. There are also higher administrative costs as the liable entity must demonstrate compliance four times a year.

In submissions to the issues paper, some stakeholders advocated for more frequent LGC surrender, on the basis that it would improve market liquidity. Meridian’s submission stated that:

Forward prices for LGCs, with LGCs primarily being sold forward or through long-term off-take arrangements, tend to be set in a manner that reflects current spot LGC prices. Where the LGC spot price is suppressed or inflated during period of low liquidity, the LGC forward price will be similarly suppressed or inflated. Market participants with cheap access to cash can drive spot price outcomes through relatively small trades, in a manner which moves forward prices, in order to achieve more favourable pricing on larger contracts for forward delivery. For example, a well-positioned participant might deflate (inflate) spot prices in order to buy (sell) large forward volumes at deflated (inflated) pricing.

Amending the LRET such that LGCs are surrendered on a quarterly basis (with an annual shortfall assessment in the same way that STCs are surrendered) would eliminate these anomalies and market inefficiency. (Meridian Energy Australia, sub.159, pp.14-15)

Qenos, however, advocated for less frequent surrender of STCs, on the basis that it increased compliance costs (Qenos, sub.60, p.5). Qenos’ submission also advised that requirements to determine quarterly surrender based on the previous years’ consumption can create difficulties where electricity consumption varies significantly from year to year.

The Authority made a draft recommendation in its discussion paper that the current surrender timing (quarterly for SRES and annual for LRET) should be maintained. Feedback from stakeholders on the discussion paper has been generally supportive of the Authority’s justifications for maintaining the current regime. The Clean Energy Council advised:

Having consulted with a cross sector of the PV industry the very strong response was that a shift to annual surrender periods would have a strongly detrimental effect on the industry by hurting cash flow, particularly to smaller businesses. While some in the industry would like more frequent surrender periods, all agreed that the current quarterly surrender periods stuck a good balance between compliance costs and cash flow, and subsequently that no change to the current regime was necessary. (Clean Energy Council, email correspondence, November 2012)

Meridian Energy Australia wrote:

While Meridian stands by its suggestion [to increase LGC surrender to quarterly]…, it respects the Authority’s conclusion that “the potential for additional compliance costs for quarterly surrender of LGCs” dilutes the benefits of a change. (Meridian Energy Australia, sub.211, p.2)

The Authority’s final view is that the current surrender arrangements should be maintained.

The Authority also notes that recommended changes to the announcement of the STP (R.15) may help to reduce some of the compliance cost burdens of liable entities under the SRES, as they will have greater certainty of their first quarter liability earlier in the compliance year and may therefore be able to manage certificate purchases in a more economically efficient way.


  • The current arrangements for surrender of certificates (annual surrender for the Large-scale Renewable Energy Target; quarterly surrender for the Small‑scale Renewable Energy Scheme) should be maintained.

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6.3. Refund of over-surrendered certificates

Currently, any certificates that have been surrendered in excess of a liable entity’s actual liability are automatically held-over by the Clean Energy Regulator and are used to offset that entity’s liability in future years. Origin Energy raised concerns with the current provisions that prevent the Clean Energy Regulator from refunding over-surrendered certificates, particularly in cases where a liable entity ceases to trade but cannot recover the value of over-surrendered certificates. Origin Energy’s submission stated that:

Provisions in the LRET and SRES restrict or prevent the Regulator from returning surrendered certificates. In LRET and SRES any excess of certificates surrendered can be carried forward to offset future liabilities. However where a company ceases to trade “accepted” certificates cannot be recovered resulting in a financial loss to the company. (Origin Energy, sub.69, p.14)

Over-surrender of certificates is more likely under the SRES than under the LRET because a liable entity must surrender certificates based on the previous year’s liable acquisitions (or another estimate). A liable entity may therefore have over-surrendered certificates in a year in which they cease to trade because their estimated liability differs from their actual liability in a compliance year. This situation cannot be avoided without risking additional costs being accrued by the liable entity, as a shortfall charge may be applied if certificates are under-surrendered. By comparison, as the LRET scheme has annual certificate surrender, the liable entity knows its actual liability before it is required to surrender certificates in the February following the end of the compliance year.

The Authority considers that it is equitable to refund over-surrendered certificates in cases where a liable entity ceases to trade, or to transfer over-surrendered certificates where a liable entity is acquired by another entity which takes on a RET liability. Such a change would benefit liable entities by providing them with assurance that the value of over-surrendered certificates would not be lost if they ceased to trade. This assurance may be important if a liable entity is deciding between a possible over-surrender based on last year’s reduced acquisitions, or providing the Clean Energy Regulator with a proposed amount on which to base SRES quarterly surrenders, which may attract retrospective quarterly shortfall charges if actual acquisitions are higher than the proposed amount. The precise features of the refund arrangements should be developed in consultation with stakeholders.


  • The Clean Energy Regulator should be able to refund over-surrendered certificates to a liable entity that ceases to trade, or to transfer over-surrendered certificates if a liable entity is acquired by another entity which takes on a Renewable Energy Target liability.

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6.4. Shortfall charge

If a liable entity does not surrender the number of certificates required under the LRET or the SRES, a shortfall charge applies to the outstanding amount. The shortfall charge for both the LRET and SRES is fixed at $65 per MWh. Costs incurred by purchasing certificates are tax deductible, while the payment of the shortfall charge is not. Therefore, liable parties could purchase certificates up to a (tax effective) price of around $93, assuming a company tax rate of 30 per cent, before they were financially worse off than paying the shortfall charge.

The shortfall charges are not indexed, and therefore fall in real terms over time. This was a deliberate policy decision, reflecting the nature of the RET as a transitional measure to bridge the gap between fossil‑fuel and renewable energy costs in the short- to medium-term. It is expected that as the cost of renewable energy technologies decline, and the carbon price increases, it will allow renewable energy technologies to compete in their own right.

Stakeholders that commented on the level of the shortfall charge in their submissions had varied opinions on whether the current shortfall charge was appropriate. The Clean Energy Council, Climate Markets and Investment Association, and Windlab Systems Pty Limited were all of the opinion that the current shortfall charge was appropriate. Infigen Energy further advised that:

The current tax effective shortfall penalty price of $92.86 [per] MWh is appropriate and sufficient to enable the 41 000 [GWh] renewable energy target to be achieved – as long as investors and the industry have confidence that the LRET target will not be reduced or stretched out. (Infigen Energy, sub.111, p.6)

The Authority also received a number of submissions suggesting the current shortfall charge was either too high or too low. Major Energy Users Inc. stated in its submission that:

Historically, forecasts for the cost of providing renewable energy in the future show that renewable energy could cost much the same as non-renewable generation by 2030. This implies that the future cost of LGCs could fall from current levels. On this basis, the shortfall charge is probably too high. (Major Energy Users Inc., sub.103, p.20)

By comparison, CleanSight Pty Ltd, LMS Energy Pty Ltd and Evans and Peck advocated for a higher shortfall charge which is increased annually to account for inflation so that in real terms the level of the shortfall charge stays the same.

Whether the shortfall charges are set at the appropriate level depends on their desired role. The RET shortfall charge potentially performs two functions:

  • first, as an administrative penalty for liable parties that do not meet their obligations to surrender certificates; and
  • second, as a price cap to limit the overall cost of a scheme or mechanism.

If the charges are set very high they will not operate as a price cap in practice as it will rarely be more financially attractive to pay the charge than to purchase certificates.

If the shortfall charges operate as a price cap, they have the benefit of reducing price uncertainty for liable entities and ensuring the costs of the scheme are contained. It also makes explicit the policy response in the event of extreme pricing outcomes. For example, if the price rises, there will become a point where it is undesirable to continue to impose the cost of the scheme and a price cap provides an explicit indication of where that point is.

The disadvantage is that the amount of renewable energy generated is reduced if liable entities choose to incur shortfall charges rather than purchasing certificates from eligible generators.

To date, the price of certificates has never risen above $93 and therefore the shortfall charges have only been used when entities have mismanaged their liability or lacked sufficient funds to purchase certificates. Even if the price of certificates were to rise above $93, entities may choose to acquire certificates, rather than pay the shortfall charges, for reputational reasons.

At its current level, the shortfall charge operates more as an administrative penalty, rather than a price cap. It is high enough to dissuade entities from accessing it on a regular basis. However, it also provides a ‘safety valve’ that can be accessed in unforeseen circumstances (for example, in the event of a short-term lack of supply of certificates or finance).

The modelling work commissioned by the Authority indicates that the price of certificates is not expected to increase to a level where the LRET shortfall charge would operate as a price cap, except under scenarios where there is no carbon price or electricity demand is significantly lower than currently anticipated (see Appendix D). In response to the Authority’s draft recommendation to retain the shortfall charge, Sinovel wrote:

Sinovel is of the opinion that the shortfall charges should not be touched. The current shortfall charges are demonstrably high enough to stimulate new generation and with technology and scale gains likely to offset the reduction in resource quality over time this [is] likely to always be the case. The argument for stability over change has already been made in regards to other recommendations. (Sinovel, sub.219, p.3)

The Authority’s view is that the shortfall charge is set at an appropriate level given the current policy context. However, in the event that the carbon price or electricity demand is significantly lower than currently anticipated, there is a risk that the shortfall charge would not be high enough to encourage compliance, in which case the 2020 target of 41 000 GWh would not be met. The Authority will consider these issues in its 2016 review, or earlier if circumstances warrant.


  • The current settings for the shortfall charges should be maintained. However, the level of the shortfall charge should be reconsidered by the Authority as part of its 2016 review of targets beyond 2020, or earlier if circumstances warrant.

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6.5. Exemptions

There are two forms of exemptions under the REE Act. The first is a partial exemption for EITE activities; the second relates to self-generation (that is, where the end-user and generator are the same entity).

The broader the base for liability, the smaller the impact for any individual liable party. For this reason, it is generally more efficient and equitable to keep exemptions to a minimum.

The exemption framework does not affect the environmental effectiveness of the RET, because the number of certificates required to be surrendered under the scheme does not reduce by the extent of the exemptions. Instead, the exemptions have the effect of reducing or removing liability from some electricity users, and redistributing that liability to other entities that remain liable. Each exemption under the RET scheme is considered in more detail below.

6.5.1 Emissions-intensive, trade-exposed activities

Businesses carrying out eligible EITE activities may apply annually for a PEC under the RET.

These exemptions were introduced in 2009 when the RET was expanded, and took force in 2010.

A PEC application must be made to the Clean Energy Regulator by 30 March (or by 29 April for certain EITE activities).

The general rationale for providing assistance to EITE activities is that these businesses are competing in an international setting where their competitors do not face a similar impost. EITE businesses are unable to pass on the additional cost of the RET to their customers, to remain competitive, and must absorb the additional cost of the RET. This may cause EITE businesses to move the activity to a country that does not have a RET (or other such cost imposition), which is undesirable from an Australian industry perspective.

The partial exemption framework under the RET is similar to, but not the same as, the Jobs and Competitiveness Program under the carbon pricing mechanism. The information and data required to determine the assistance are largely the same – for example, the same list of EITE activities applies and the energy and production data required is the same. The resulting exemption, however, is calculated differently. This is primarily because the RET exemption focuses on electricity use, while the Jobs and Competitiveness Program focuses on emissions.

The RET partial exemption framework works by first identifying EITE activities. Eligible trade-exposed activities are assessed for their overall emissions intensity on the basis of historical data, regardless of the extent to which those emissions are related to electricity use. Under the RET, activities that are classified as highly emissions-intensive receive an assistance rate of 90 per cent, while activities that are assessed as moderately emissions-intensive receive an assistance rate of 60 per cent. There are currently more than 30 eligible EITE activities, including aluminium smelting, integrated production of lead and zinc, manufacture of newsprint, carton board manufacturing and petroleum refining.

An EITE business can apply to the Clean Energy Regulator for a PEC. The Clean Energy Regulator calculates the value of the PEC taking into account the assistance rate and a range of other inputs including:

  • electricity use per unit of output for the activity – each activity has a specified electricity baseline, the value of which is predetermined from historical data and is set in the Regulations;
  • output – the quantity of relevant product is submitted to the Clean Energy Regulator by the EITE organisation every year; and
  • proportion of electricity use from a given site that is related to the EITE activity and thus could be eligible for a PEC – this is only relevant if multiple activities or processes are carried out on the one site.

A PEC is awarded to an EITE business as a volume of electricity (in megawatt hours) for which they are not liable under the RET. The volume of partial exemptions is significant. In 2011, partial exemptions of around 27.5 million MWh of electricity were exempted from RET liability, equal to approximately 13 per cent of the total relevant acquisitions of electricity for the RET in 2011. This equates to an exemption worth approximately $184 million at the average 2011 price of $38.80 per LGC and $30.30 per STC. EITE exemptions result in increased costs for other RET liable entities, because they must share the RET liability for the electricity exempted in the PECs. As a rough guide, dividing the value of the 2011 partial exemptions by the reduced number of liable acquisitions (estimated to be 180 million MWh), the exemption would have been expected to add approximately $1.02 per MWh to the price of non‑exempt electricity consumption.

The existence and level of the emissions-intensive, trade-exposed exemption

The Authority received over 20 formal submissions plus additional feedback regarding the current level of the EITE partial exemption. A number of the submissions stated that the RET places a substantial burden on EITE industries that are struggling to remain viable in current economic conditions, and emphasised the importance of continuing, or expanding, the current exemptions for those industries to maintain viability. For example, the Australian Aluminium Council stated that:

…even with the existing exemptions, RET costs the aluminium industry approximately $80 million per annum or $40 per tonne of aluminium at a time when the Australian aluminium industry is loss making and the viability of most facilities is under question and requiring severe cost reduction strategies in order to survive. (Australian Aluminium Council, sub.73, p.8)

Conversely, a small number of submissions supported reviewing exemptions and reducing, or removing, them if appropriate. For instance, the Australian Network of Environmental Defender’s Office New South Wales submitted that:

Both the EITE partial exemption and the ‘self-generator exemption’ should be reviewed, with a view to further limiting or phasing out these exemptions, and increasing their transparency. (Australian Network of Environmental Defender’s Office NSW, sub.141, p.3)

Treatment of the Mandatory Renewable Energy Target for emission-intensive, trade-exposed exemptions

As currently framed, the partial exemption only applies to an EITE entity’s liability above the original MRET – EITE businesses are fully liable for their share of RET costs for the first 9 500 gigawatt hours of renewable energy created under the RET (and have been since the commencement of the MRET in 2001). The partial exemption for EITE industries was announced in 2009 in the context of the then proposed Carbon Pollution Reduction Scheme.

The purpose of the partial exemption above the first 9 500 GWh target was to recognise that EITE industries would be affected by a carbon price in the context of other cost pressures, such as the global recession (Commonwealth House of Representatives 2009). While legislators provided EITEs with a partial exemption from the liability associated with the expanded RET, they considered it was reasonable to require all businesses to make some contribution towards renewable energy generation (Commonwealth House of Representatives 2009). This position was reiterated by the Senate Standing Committee on Environment, Communications and the Arts, which held an inquiry into the Renewable Energy (Electricity) Amendment Bill 2010 and found that:

In relation to the proposition that EITE activities should receive exemption for their liabilities under the former MRET, there was no evidence presented to the inquiry that the industries were significantly or disproportionately disadvantaged by that scheme. On that basis, there would seem to be no particular reason why they should now be exempted from liability for their share of the former target. (Commonwealth Senate, 2010, paragraph 4.17)

However, given the concerns expressed by the aluminium and cement industries and the emissions intensity and export oriented nature of the aluminium industry in particular, the committee would expect that the matter of the exemptions for EITE activities will be covered in the 2014 statutory review of the scheme. (Commonwealth Senate, 2010, paragraph 4.19)

The Authority received feedback from EITE industries and peak bodies that advocated for the extension of partial exemptions for EITE industries to the MRET liability. Advice from the Australian Aluminium Council stated:

…the RET imposes significant costs on our industry today, in a commercial environment where the low aluminium price and high Australian dollar make facilities extremely vulnerable to the imposition of additional costs. (Australian Aluminium Council, sub.177, p.1)

The Authority recognises that the MRET proportion of the RET imposes significant costs to EITE industries, particularly the aluminium industry, which has the highest electricity acquisitions and accounted for 65 per cent of the partial exemptions awarded in 2012. Assuming an STC price of $32 and an LGC price of $48.26 (used in the Authority’s modelling), the MRET related costs on EITE industries would be approximately $66 million in 2012. In principle, the justifications for EITE industries receiving a partial exemption (being higher costs imposed by the carbon price and international competitiveness concerns) apply to the MRET component as they do to the expanded RET. The trade effectiveness of Australia’s EITE industries will be influenced by all policies and inputs that increase the costs of EITE production, including the MRET liability.

The Authority also recognises that extending the partial exemption arrangements to the MRET will result in higher RET costs for all other liable entities, because they would need to pick up those costs in order for the target to still be met. Based on the STC and LGC prices estimated above, the cost of the RET for all liable electricity would increase by approximately $0.36 per MWh. The extent of the costs and benefits of such a change in EITE liability require careful consideration in the context of international competitiveness for EITE industries and electricity costs for all electricity users, which the Authority considers cannot be conducted comprehensively within the timing of the RET review.

The Jobs and Competitiveness Program is the EITE industry assistance measure under the carbon pricing mechanism, and is due to be reviewed by the Productivity Commission in 2014-15. As the rationale for the RET EITE partial exemption and the method of calculating its value is based on the Jobs and Competitiveness Program, the Authority considers that it would be more appropriate if the Productivity Commission also considered the level of RET EITE assistance arrangements as part of the Jobs and Competitiveness Program review. The existence and level of the RET EITE exemption (including the MRET liability) are best assessed in the context of carbon price assistance, as the Jobs and Competitiveness Program and EITE exemption measures work together to provide a level of protection against carbon leakage, whereby Australian industries move offshore to avoid the burden of greenhouse gas reduction policies.

Following the release of the discussion paper, the Australian Aluminium Council raised concerns that the proposal that the Productivity Commission review the EITE exemption under the RET in 2014-15 was ‘too late’. Their feedback stated:

Our initial submission highlighted that the RET imposes significant costs on our industry today, in a commercial environment where the low aluminium price and high Australian dollar make facilities extremely vulnerable to the imposition of additional costs. There is potential that significant damage will be caused to the sustaining investment in, and even ongoing operation of, Australia’s aluminium smelters and alumina refineries before the proposed review in 2014-15.

…we ask that the final report recommend the EITE exemption be extended to cover the MRET component from 2013. This change could, if necessary, then be reviewed more broadly in 2014-15 by the Productivity Commission as per the original recommendation. (Australian Aluminium Council, sub.177, p.1)

Similar sentiments were raised by CSR:

CSR is disappointed that this has not been addressed in this review, where electricity intensive industries suffer a considerable burden from RET when international commodity prices are extremely low and competing economies do not have such Government imposts. The matter should be addressed now, not in two years. (CSR, sub.195, pp.2-3)

On this issue, the Authority notes that the Securing a Clean Energy Future policy statement notes that ‘once the carbon pricing mechanism has been released, firms may make a request to the Government to have the impact of the mechanism on their sector assessed’ (Commonwealth Government, 2011, p.112). The Government has since released guidelines which set out when such requests will be referred to the Productivity Commission and the terms of reference for the reviews. The guidelines state that the aim of a Productivity Commission review is to:

…establish whether the introduction of the carbon pricing mechanism, taking into account associated assistance arrangements, is having a materially adverse and unexpected impact on the competitiveness of the industry that the firm is operating in, that is likely to persist in the medium to long term. (Commonwealth Government 2012)

In order for the Government to refer an industry assistance review to the Productivity Commission, the industry is required to provide evidence of adverse impacts as a result of the carbon pricing mechanism, with such evidence able to include, but not limited to, ‘analysis demonstrating that the direct or indirect carbon costs arising from the carbon price mechanism comprise a significant proportion of revenue (or value added), and a demonstrated inability to either pass-through these costs to customers nor take action to abate them’ (Commonwealth Government 2012).

The Authority considers that the relevant considerations for EITE assistance under the RET are much the same as under the carbon pricing mechanism, as the purpose of both EITE assistance measures is to reduce the impact of the schemes on the competitiveness of EITE industries. Along with the recommendation for the Productivity Commission to consider RET EITE assistance as part of the Jobs and Competitiveness Program review, the Authority’s view is that the guidelines for whether an industry can request an earlier review of the Jobs and Competitiveness Program should also take into consideration evidence of adverse impacts of the RET on the competitiveness of the EITE industry, when determining whether to refer the matter to the Productivity Commission. This would provide EITE industries that are concerned about the level of assistance provided under the RET a possible recourse to have their assistance levels reviewed sooner.


  • The level of the emissions-intensive, trade-exposed exemption under the Renewable Energy Target should be considered by the Productivity Commission as part of its broader review of the Jobs and Competitiveness Program.
  • The Commonwealth Government should take into consideration the impact of the Renewable Energy Target on the competitiveness of an emissions-intensive, trade-exposed industry in any request to the Productivity Commission’s review of the level of industry assistance under the carbon pricing mechanism and the Renewable Energy Target.

6.5.2 Technical amendments to the emissions-intensive, trade-exposed partial exemption framework

The Authority has considered a number of technical amendments to the operation of the EITE partial exemption framework, including flexibility regarding the use of PECs and alignment of reporting requirements under the PEC scheme and the Jobs and Competitiveness Program.

Partial Exemption Certificate flexibility

As previously described, the exemptions for EITE businesses are issued in the form of PECs, which remove RET liability for the volume of electricity (in megawatt hours) which is specified in the PEC. EITE businesses are not usually liable entities under the REE Act, so the PEC also nominates a liable entity (typically the EITE business’s electricity retailer), against which the exemption can be recognised.

Because the electricity retailer’s annual RET liability is reduced by the volume of electricity specified in the PEC, it is assumed that the full reduction in liability is passed through to the EITE customer.

In reality, however, the value of the PEC is negotiated between the EITE business and its electricity retailer, and may be influenced by assumptions regarding the price of renewable energy certificates, as well as any differences in bargaining power. There is therefore a risk that a liable entity does not pass the full value of the exemption through to the EITE business. Such a situation could undermine the objective of providing the EITE assistance, which is to reduce the RET burden of the EITE business, not the electricity supplier.

A number of submitters requested that PECs be made ‘tradeable’ in some way. The Australian Industry Greenhouse Network submitted that:

One option to ensure the full opportunity value of PECs is realised is through access to an open market – potentially by formally linking the value of a PEC to the value of a LGC. This will lead to more efficient price discovery, avoid value destruction and allow the intent of the PEC to be met. (Australian Industry Greenhouse Network, sub.164, p.6)

Although many submissions requested that PECs be treated in the same way as certificates, PECs operate differently from certificates. Certificates can be surrendered to meet obligations under the RET, whereas a PEC reduces the overall amount of generation acquired by a retailer that is subject to RET liabilities, rather than directly meeting RET obligations. Consequently, PECs and certificates are not directly interchangeable. Furthermore, if PECs could be used to meet liabilities in the same way as certificates, this would reduce the amount of renewable generation that is achieved by the RET, which would reduce the environmental effectiveness of the scheme.

The Authority’s view is that an EITE business could potentially obtain greater value for their PECs if they could be traded with any liable entity, rather than just the electricity retailer that sells electricity to the relevant EITE firm. This approach would create a market for PECs, with multiple sellers and buyers, and would allow liable entities to compete for PECs based on their willingness to pay. By doing so it could reduce the effect of any differences in bargaining power between an EITE business and their electricity retailer, as the EITE business would have the option to not trade their PECs with their retailer if they believed that could get better value elsewhere.

The Authority included a draft recommendation in its discussion paper to introduce tradeability of PECs. The draft recommendation was generally well received, particularly by EITE industries and their peak bodies. The Australian Aluminium Council advised:

The Council supports the Authority’s recommendations that large electricity consumers should be able to opt-in to assume direct liability for RET obligations and that the Partial Exemption Certificates should be tradable. These initiatives would strengthen the market-based, least-cost aspect of the RET, within the policy’s other limitations. (Australian Aluminium Council, sub.177, p.2)

Some stakeholders advised that PEC tradeability, while a good idea to improve flexibility for large energy users, may not be necessary if large energy users can opt-in to manage their own RET liability. In such cases, a liable entity which is also an EITE business may choose to offset it’s RET liability using its own PECs. Notwithstanding that this may occur, the Authority considers that PEC tradeability remains important in its own right, as the threshold for opt-in may exclude some EITE businesses from managing their own RET liability. Some EITE businesses may also find it more economically efficient to trade their PECs irrespective of whether they have opted-in, particularly if their liability in a compliance year is less than the value of their PEC, which is based on the previous financial year’s production.

The Authority does not consider that there are material costs associated with making PECs tradeable. However, the Authority acknowledges that there may be some current contracts between electricity suppliers and EITE businesses that do not allow for pass-through of RET related costs to the EITE customer. While these contracts are expected to be few in number, PEC tradeability may impose costs on the electricity supplier if their EITE customer chooses to trade their PECs with a different liable entity or requests payment for the PECs, even though no RET costs were ever being passed on. In such cases, the electricity supplier would be required to pay for the costs of the RET for the liable electricity acquisitions, with no reduction in liability that would otherwise be provided by PECs. This may result in a significant increase in RET costs for the electricity supplier, and a windfall gain for the EITE customer.

Under the carbon pricing mechanism, the Clean Energy Regulations 2011 require a minimum pass‑through rate of the carbon price between an electricity retailer and certain very large energy users, before the large energy user is eligible to receive free carbon units. The average pass-through of carbon pricing mechanism related costs need to be more than 0.7 carbon units per MWh before the large energy user is eligible to receive free carbon units. To demonstrate compliance, the EITE business and its contracted electricity supplier are required to provide the Clean Energy Regulator with a written statement that the pass-through rate is expected to exceed the minimum threshold for the life of the contract or until 30 June 2021 years, whichever is earlier.

The Authority considers that an approach to ensuring that PECs are not tradeable in circumstances where EITEs are not actually bearing the costs of the RET should be developed.

The Authority recognises that there may need to be some administrative changes to issuing and surrendering PECs, to ensure their trading is efficient and transparent, and to assist liable entities to demonstrate compliance as easily as possible. Those changes would be expected to incur some additional administrative costs for Government. On balance, however, the Authority’s assessment is that the benefits of allowing additional flexibility for EITE entities outweigh the administrative costs.


  • In cases where the RET costs are passed through to emissions-intensive, trade-exposed businesses, partial exemption certificates should be tradeable, and thereby able to be used by any liable entity to reduce liable electricity acquisitions.

Alignment of Jobs and Competitiveness Program and partial exemption certificate processes

Currently EITE entities are required to submit separate applications to the Regulator to receive PECs under the RET and to receive free carbon units under the Jobs and Competitiveness Program. Applications are due by 31 October of the relevant carbon pricing mechanism (financial year) compliance year, and RET applications are due by 30 March of the RET (calendar) compliance year.

The requirements for data used in the Jobs and Competitiveness Program and PEC applications are similar. Both PEC and Jobs and Competitiveness Program applications require provision of information about the amount of production in the previous financial year. Although PEC allocations are made on a calendar year basis and free carbon units are allocated on a financial year basis, both processes use production information from the last completed financial year (that is, both PEC allocations for the 2013 calendar year and Jobs and Competitiveness Program allocations for the 2012-13 application year rely on production information from the 2011-12 financial year). The PEC application also requires additional information about the amount of liable electricity consumed at the site in the previous year.

Auditing and assurance requirements for PEC and Jobs and Competitiveness Program applications are generally the same. However, in some cases where an application is in relation to a new site or a significant expansion to an existing site, entities are able to use estimates of future production. In these cases more stringent audit and assurance requirements are applied to the estimates for PEC allocation than those applied to Jobs and Competitiveness Program allocations.

A number of submitters requested that EITE processes for the Jobs and Competitiveness Program and RET be aligned to reduce compliance costs. For instance, Amcor Packaging Australia submitted that:

All EITE businesses must apply to the Clean Energy Regulator for [PECs] for each EITE activity, based on prior year’s actual production. The application for assistance must be audited by a registered auditor as per the REC Regulations.

Now that the carbon pricing mechanism has been introduced with a similar [Jobs and Competitiveness Program] application procedure, the application process for the 2 forms of assistance should be harmonised and streamlined so only one application and one 3rd party audit of the energy and production data is required. (Amcor Packaging Australia, sub.55, p.5)

The timing differences between PEC and Jobs and Competitiveness Program applications mean that it is unlikely that a single application could be made for both. The key driver of timing differences is the date by which liabilities can be determined for the RET, which cannot be done accurately until after the setting of the RPP and STP. Even if the date for publication of the RPP and STP is brought forward to December before a compliance year, as proposed by the Authority, this will not be sufficiently early to allow for a single application. It is unlikely that liable entities would wish to take the alternative approach of delaying decisions on Jobs and Competitiveness Program free carbon unit allocations to allow a single application to be made.

As much of the information used is the same between the applications, however, it should be possible to streamline the two application processes to minimise duplication of work and allow sharing of information between applications. A potential limitation that may need to be addressed is that the eligible applicants for the RET and Jobs and Competitiveness Program will often be different entities, which may create legal impediments to sharing information between applications. In addition, the concept of a ‘site’ at which electricity is consumed that is used as a basis of RET allocation is not exactly the same as a ‘facility’ that is used for allocation under the Jobs and Competitiveness Program, and there may be benefits to matching these two definitions to align the scope of information to be given in applications.

Opportunities also exist to streamline audit and assurance processes between the Jobs and Competitiveness Program and PEC applications. In particular, the audit and assurance requirements under the RET and the Jobs and Competitiveness Program for estimates of future production could be matched, as there do not appear to be any reasons for more onerous requirements to be applied under the RET. Consistent with the improvements recommended above for application processes, there may also be opportunities to seek permission for the sharing of data between the audit processes where different legal entities are involved in providing the data, and to removing differences between the definition of site and facility to align the scope of audit and assurance requirements. The cost savings for consolidating audit requirements where possible are likely to provide a noticeable reduction in compliance costs for EITE businesses.

In response to the discussion paper and preliminary views of the Authority, Rio Tinto and CSR advocated greater alignment where it would reduce administrative burden. CSR submitted:

All efforts to remove red tape and streamline processes are supported. (CSR, sub.195, p.3)

The Authority understands that the Clean Energy Regulator is already examining a number of the opportunities under the current legislation for the proposed alignment identified above, and encourages the Government to implement administratively efficient options.


  • The Commonwealth Government should consider opportunities for efficiencies through the alignment of application processes and data requirements for emissions-intensive trade-exposed industries under the Jobs and Competitiveness Program and Renewable Energy Target.

6.5.3 Self-generator exemptions

The second form of exemption under the RET applies to entities that generate their own electricity.

To be exempt, a self-generator (on a grid of greater than 100 MW capacity) must:

  • produce and use the electricity for themselves with no take-off from a third party; or
  • in cases where the self-generator is the primary, but not the only, user, the electricity must be used within a one kilometre radius of its production by the entity that generated it.

The self-generator exemption has been included in the MRET since its commencement in 2001. It was retained with the expansion of the RET and the inclusion of the EITE exemption in 2009.

Limited information is available on the amount of self-generation that occurs in Australia, as parties that fall under the self-generator exemption are not required to report the volume of electricity produced under the REE Act. The Explanatory Memorandum to the Renewable Energy (Electricity) Bill 2000 estimated the impact of self-generation to be ‘between 4-5 [per cent] of generated electricity, with up to 75 [per cent] of this electricity being consumed internally (that is, by the self-generating business itself)’ (Commonwealth Government, 2000, p.8). While it is difficult to accurately estimate the true impact of self-generation, electricity produced by self-generators would only comprise a small proportion of the total electricity generated in Australia.

The Authority’s preliminary view, as outlined in the discussion paper, was that the self-generation exemption imposes higher RET costs on other liable entities, and is therefore undesirable from a first principles basis. EITE industries, which have the greatest exposure to higher electricity costs that cannot be passed onto customers without reducing their competitiveness, are already protected from the full impacts of the RET through partial exemptions. EITE industries therefore do not, of themselves, appear to require a further self-generation exemption. The Authority also found that the original justification for including the self-generation exemption was unclear – publicly available documentation on the policy’s development did not set out the rationale for the original inclusion of the self-generation exemption, except to say that self-generation may use more efficient technologies.

The Authority’s discussion paper provided a draft recommendation that the self-generation exemption should be retained for currently exempt self-generators, but that the exemption should not be extended to new self-generation projects. Considerable feedback was provided by stakeholders on this draft recommendation, and further issues were identified regarding the effect of repealing the exemption for new self-generators. These issues are addressed below.

Environmental considerations

Several stakeholders commented on the fact that large-scale self-generation typically produces fewer emissions than coal-based electricity generation, and creating a RET liability for new self-generators would significantly reduce the economic benefits of investing in those less emissions intensive technologies. In its response to the discussion paper, AGL advised:

The [Climate Change Authority] proposes to remove the exemption from RET liability for new self-generation on the grounds that there is no strong case for this exemption to exist particularly given the carbon price will encourage less emissions-intensive self-generation where it is cost-effective to do so.

The considerable uncertainty that currently exists around the future of the carbon price discourages significant investment in and the development of low emissions-intensive energy generation. With this uncertainty largely muting the price signal that the carbon price would otherwise create, cost-effective, low emissions-intensive self-generation is strongly incentivised by the exemption from RET liability that current exists. (AGL, sub.181, p.2)

The Major Energy Users Inc. further advised that:

Self-generation is most commonly focused on maximising the efficiency of conversion of the fuel used (thereby reducing carbon emissions) and maximising efficiency of energy use is a state policy of all State and Federal governments. Applying the RET to self-generation will make such projects less commercially viable (even non-viable) and perversely reduce the ability of enterprises implementing actions to achieve what the entire process of efficiency targets and carbon emissions reduction. Therefore applying the RET to self-generation is a self-defeating exercise. (Major Energy Users Inc., sub.210, p.14)

Stakeholders raised concerns that investment in cogeneration technologies in particular would not occur if the self-generation exemption was not available to new self-generators. Cogeneration technologies capture waste heat from onsite electricity production and use that heat for other industrial purposes, such as to heat water. Cogeneration technologies are typically high cost electricity generation investments. Stakeholders advised that cogeneration technologies would never be taken up if RET liability applied to the electricity produced by those units, because it would further reduce the economic benefits of investing in the technology, despite its high energy efficiency outcomes.

The Authority considers that it would be a perverse outcome if the application of the self-generation exemption prevented the uptake of lower emissions technologies, reducing the environmental effectiveness of the RET.

Threshold issues in relation to the self-generation exemption

Removing the self-generation exemption would involve substantial administrative complexities and therefore costs. Although conceptually straightforward, implementation of the self-generator exemption would require substantial amendments to the operation of the REE Act and its administration by the Clean Energy Regulator.

As described previously, no RET liability is currently imposed on an entity which is connected to a grid above 100 MW capacity that consumes its own generation with no off-take, or is the primary consumer of the self-generation and consumes the electricity within one kilometre of where it is produced. Based on this definition, electricity produced from small generation units such as household or commercial solar photovoltaic (PV) is covered by the self-generation exemption. This means that removing the self-generation exemption would automatically impose a RET liability on new small-scale generation units, unless the REE Act explicitly stated otherwise. Other new medium to large solar and other generators which would have otherwise obtained the self-generation exemption would also be liable for the RET.

Currently, the self-generation exemption is effective at constraining the number of liable entities to those which are large electricity users or acquirers (such as electricity retailers). This reduces the administrative burden of the RET, because the many small self-generators (such as household PV) and other medium to large commercial generators are not required to manage their own RET liability.

The Authority considers that applying RET liability to electricity produced by household PV units and other small self-generators is undesirable, due to the relatively high administrative costs that would be imposed on those parties, and the additional costs to government of administering the scheme to those parties if they were considered liable entities. Therefore, any repeal of the self-generator exemption for new self-generators would need to include a threshold on the size of the generation unit or amount of electricity produced. The Authority considers that the development of such a threshold would require considerable analysis to determine its effects on the parties who may become liable for the RET. The choice of threshold would also invariably involve some degree of arbitrariness, particularly around which parties are ‘just in’ versus ‘just out’.

There would also be increased costs for both the Clean Energy Regulator and potentially liable entities to monitor and enforce the threshold and new liability requirements.  

On balance, the Authority considers that, given the small proportion of electricity estimated to be produced by self-generators, and complications regarding the setting of an appropriate threshold to determine which new self-generators would need to be assessed for the exemption, it is likely to be more environmentally effective and economically efficient if the self-generation exemption continued in its current form.

Self-generator offtakes

As previously discussed, to be eligible for the self-generator exemption on a grid above 100 MW capacity, the self-generator must not provide any offtakes to third parties, or must be the primary consumer of the electricity generated and consume that electricity within one kilometre of where it was generated.

In submissions to the issues paper, several stakeholders raised concerns that the current definition of self-generation prevents any offtakes for third parties. The Australian Aluminium Council submitted that:

In many resource projects there are related services (e.g. emergency services, telecommunications) or communities that have few alternatives for electricity other than the self-generated electricity supply for the resource project. The company is left with a perverse incentive to either incur a significant RET liability (by supplying electricity to the services and communities), or seek to save costs by disconnecting related services that use a minor amount of electricity. (Australian Aluminium Council, sub.73, p.6)

This concern was reiterated by the Chamber of Minerals and Energy of Western Australia (sub.106, p.2).

The Authority considers that, while it is not an objective of the RET to ensure electricity is provided for remote community purposes, it is economically inefficient for small organisations in remote locations to develop their own electricity generation sources when a self-generator can supply the incidental electricity at low cost and lower emissions. It is also a perverse social and policy outcome if services that benefit the community, particularly emergency services, are not established or must incur higher costs due to self-generators not being able to provide incidental electricity offtakes. Notwithstanding this position, the Authority acknowledges that any change to allow electricity offtakes while retaining the self-generation exemption should be limited and transparent. Providing a wide definition of allowable offtakes would reduce the equity of the RET by extending exemptions to other electricity users, to the detriment of those liable under the RET.

The Authority therefore recommends that the Department of Climate Change and Energy Efficiency, in consultation with the Clean Energy Regulator and affected stakeholders, develop an approach for defining when incidental offtakes in remote locations may be allowed without disqualifying the

self-generator from the exemption it would otherwise receive. Considerations for allowable offtakes may include the size of the offtake relative to the amount of electricity generated by the self-generator, the purpose of the offtake, and the remoteness of the location.


  • The self-generation exemption should continue in its current form.
  • Arrangements should be developed to allow for incidental electricity offtakes under the self-generation exemption which provide community benefits in remote locations.

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