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Energy and Carbon Summer Reading Pack 2013


Table of contents Electricity: falling demand in the NEM........................... 3 Changes are ahead for Australia’s east coast gas markets....................................................................... 5 Financing solutions to lower your energy costs and climate change risks................................................ 7 Unearth hidden savings by building energy and carbon skills, systems and processes. Video interview................................................................. 9 EEO – insights from Energetics’ clients......................... 10 Could 2014 be the year of the battery?....................... 12 Comparing submissions on the Emissions Reduction Fund – what are the industry experts saying?............................................................... 14 Designing the Emissions Reduction Fund....................20 Contact Details...............................................................24



Electricity: falling demand in the NEM Electricity consumption across the Australian electricity markets is in decline. This paper discusses the causes of falling demand evidenced over 2013.

“Since 2009-10, electricity consumption in Australia’s largest interconnected electricity market, the National Electricity Market (NEM), has fallen by 4.5 per cent.”1 In November the NEM market operator, the Australian Energy Market Operator or AEMO, updated its 2013 Statement of Opportunities. The Statement of Opportunities is the long-term assessment of energy demand. Energy forecasts provide a key input into electricity infrastructure planning. The November update confirms the continuing downward trend in electricity demand. “In the first quarter of 2013-14 (July 2013 to September 2013), AEMO observed a variance of -3.5% in NEM-wide actual electricity consumption compared to the forecast.2” The falls are not only limited to the NEM. Australia’s other large electricity network, the South West Interconnected System (SWIS) which supplies south-west WA has recorded flat growth, despite the resources boom.3

What is driving these reductions? A number of reasons have combined to impact electricity demand growth and outlook: • A sustained growth in domestic rooftop PV installations through deliberate policy initiatives, such as the various state and federal rebates and reduced system installation prices. • Lower than expected growth in most industrial sectors, stemming from a downturn in manufacturing and a higher Australian dollar. • Impact of energy efficiency measures, such as improvements in energy efficient appliances and changes in building standards and regulations. • Reductions in electricity usage as consumers react to high electricity costs.

How does a reduction in energy demand flow through to wholesale electricity prices? Orthodox economic theory dictates that falling electricity demand should lead to falling wholesale electricity prices. There is no question that there currently exists an oversupply of generation capacity in the NEM. AGL have recently found that this ‘under-demand’ has produced about 9000MW in excess generation capacity in the NEM, equating to around 16% of the market.4 “These changes result in all regions except Queensland having adequate generation capacity over the 10-year outlook period.5 Queensland energy growth will be driven by LPG plant investment. Although wholesale electricity prices have fallen in recent times due to the fall in demand and the subsequent oversupply, the impact on total energy costs may not be so predictable. Recent commentary has sought to understand why electricity prices have been rising despite falling demand over a number of years.6 Energy price increases have substantially exceeded CPI. The introduction of a carbon price explains some of this increase, however network charges have exerted the greatest upward pressure on energy costs. This may continue. Therefore we need to understand the link between energy and network costs. For some time, it has been observed that the billions of dollars spent on network assets will have to be recovered7, despite the potential reduced need for this network capacity as energy usage falls Although the energy and network components are priced independently of each other, they are inextricably linked. Last week’s Grattan report8 asserts that network cost increases can offset the reduction in wholesale electricity costs, for some sectors. A large portion of network costs are recovered by the network operators based on electricity volume, so that if volume falls, prices will rise to offset the loss in usage. 4 Wood, T., Carter, L., and Harrison, C., 2013, Shock to the system: dealing with falling electricity demand, Grattan Institute, page 12 5 AEMO, 2013 ELECTRICITY STATEMENT OF OPPORTUNITIES, Executive summary, iii.

1 Wood, T., Carter, L., and Harrison, C., 2013, Shock to the system: dealing with falling electricity demand, Grattan Institute, page 3.

6 Wood, T., Carter, L., and Harrison, C., 2013, Shock to the system: dealing with falling electricity demand, Grattan Institute

2 2013 NATIONAL ELECTRICITY FORECASTING REPORT UPDATE For the National Electricity Market, page 2.

7 Jutsen, J: “Why electricity prices are rising – the horse has bolted”, ReNew economy, 24.8.2012.

3 Wood, T., Carter, L., and Harrison, C., 2013, Shock to the system: dealing with falling electricity demand, Grattan Institute, page 4.

8 Wood, T., Carter, L., and Harrison, C., 2013, Shock to the system: dealing with falling electricity demand, Grattan Institute, page 12



Electricity: falling demand in the NEM What is the outlook for 2014? On a final note, the other unknown which has the potential to apply downward pressure on wholesale electricity prices, is the expansion of PV installation into the commercial market. The rollout of PV has had a marked impact on energy demand from the grid – as highlighted in the AEMO forecasts, but to date this has only been limited to the residential market. The commercial and industrial market is yet to fully embrace this technology, which if repeated on the same scale as residential PV take-up, could have dramatic impacts on the energy supply market.

This problem is compounded by an overspend on the networks, which means their regulated asset base is inflated. A network operator’s revenue is determined to a large extent by this regulated asset base. Most of the network spend in recent times has been a response to the need to meet rising peak electricity demand – i.e., making sure the network can supply electricity in times of very high consumer demand. While most large commercial and industrial customers have paid significant fees for this demand availability, through the peak demand components on their network tariffs, many users are not being charged for this capacity and instances of cross subsidy may exist. An underlying driver of this peak network investment has been the saturation of residential air conditioning.

Energetics can provide further advice on how these developments may impact your future electricity costs and steps you can take to maximise the opportunities presented by these changing market conditions.

These are complicated issues which will require considerable thought on the part of policy makers.

Please contact one of our experts to discuss the approach your business should take.

David West

Mark Bourne

Principal Consultant

Senior Consultant

(02) 9929 3911

(02) 9929 3911



Changes are ahead for Australia’s east coast gas markets Addressing the escalating price of gas has become a priority for Australian business as prices in the eastern half of the country trend towards export parity net-back pricing. In this article we outline the key factors driving Australia’s evolving gas market and the steps business should follow to secure the best gas supply contract.

Many of Energetics’ clients are used to seeing gas prices in the range of $3 - $4/GJ (commodity only at the well head, excluding carbon). This compares to markets in our region that are paying around $15/GJ. Countries that import gas experience additional costs to those countries that produce domestically. Liquefying, shipping and then re-gasifying LNG adds around $5 - $6 per GJ. This means that an export parity price of $9 - $10/GJ is what domestic users of gas may be forced to pay for contracts in the future.

Contracting approaches Gas market dynamics are evolving Historically Australia’s east coast gas market has been isolated from international markets. However, $50 billion investment committed to building three LNG facilities in Gladstone and associated gas production and pipeline infrastructure (catching up with the $116 billion invested in west coast LNG) has changed all that. The first shipment of LNG to offshore markets is due in late 2014. This represents a key shift in the dynamics of the east coast gas market. Eastern state domestic gas prices will no longer be determined in isolation, but will instead be linked to international prices. And this means a jump from the low prices that our economy has grown to expect.

Prices are going up To date the gas market has not been transparent, with prices tending to be based on long-term contracts.

The gas market is a seller’s market. There are fewer respondents to gas tenders leading to less room to negotiate favourable terms and conditions. Clients should expect to pay more and that contract terms will tend to be shorter as suppliers adjust to the changing nature of the market. One solution is to take shorter term contracts that match retailers’ current contracts with their suppliers, which will mostly expire in 2014. Longer term contracts have the expectation of export parity pricing built in. While this may only delay the inevitable large price increases, it allows time for more local volumes of unconventional gas to be proved, especially coal seam gas in NSW and shale gas in Victoria. This is similar to what has happened in the US. We are also seeing smaller gas producers, who are not aligned to the LNG export project companies, looking to supply consumers directly through the wholesale market and/or establish themselves as gas retailers. Watch for further developments and potential opportunities for your business.



Changes are ahead for Australia’s east coast gas markets The future of gas markets The changes coming to Australian gas markets should be considered against the backdrop of the growing global demand for gas. This demand is being met by a major structural change to the gas market - the development of technology allowing the economic extraction of so-called ‘unconventional gas’. The most common types of this are coal seam gas and shale gas. Proven and probable gas reserves in Australia have tripled between 2005 and 2012 – with the majority of this due to coal seam gas. Similar increases in proven reserves have been seen globally, with the US seeing a transformation of its industry due to the discovery and development of vast reserves of shale gas.

The rapidly evolving nature of the gas market will provide an interesting ride over the next decade. A big variable will be whether the US will lift restrictions on exports providing downward pressure on international prices.

Given energy prices are a politically sensitive topic, the extent of government intervention will be keenly watched by market participants. Reservation policies whereby a portion of gas is mandated by law to be sold domestically have been advocated by some in industry. Community concerns over the development of unconventional gas reserves will need to be addressed as will transparency in the market. This is beginning to be introduced but there is more to be done. Future carbon pricing policies will also play their part. There are many variables – but one certainty in the short to medium term is that prices are increasing. Energetics energy markets experts can provide forecasting and contracting advice and services

Please contact one of our experts to discuss the approach your business should take.

David West

Daisy Correa

Principal Consultant


(02) 9929 3911

(02) 9929 3911



Financing solutions to lower your energy costs and climate change risks With the carbon price yet to be repealed and the details of the Emissions Reduction Fund still unclear, climate policy uncertainty remains high. However, the fundamental drivers for implementing projects to reduce your energy use and greenhouse gas emissions have not changed. Energy prices are high and forecast to continue rising, businesses need to reduce their costs to stay competitive, and climate change risks continue to threaten business resiliency.

Today’s article considers how you can better position your business by implementing projects that reduce your energy costs and emissions using smart financing solutions. With previous sources of government funding, such as the Clean Technology Investment Program and the Clean Energy Finance Corporation, not currently available, now is a particularly compelling time to consider financing solutions. These financing solutions overcome cash flow, capital and technical risk barriers to your projects.

How to get projects ready for implementation and financing Before seeking finance for your projects, you need develop business cases that define their scope and assess project risks. The main elements you should consider when developing your business cases are shown in our framework. These business case elements include: • Technical – Define the technical requirements for the project. Assess whether the project is technical suitable for a site, including consideration of any possible interference with existing equipment and operations. Assess the complexity of the proposed project, maturity of suppliers for project implementation, and the level of risk of the project not achieving the desired energy and carbon savings once implemented. • Environment – Assess the likely impact of projects on the environment and the community. • Financial – Conduct financial analysis, including whole of life modelling, to determine the financial needs of the project and expected returns. Run sensitivity analyses to quantify project financial risks. Having a financial model of a project is required to determine suitable ownership and financing options. • Commercial – Undertake a commercial assessment of the viability of the projects and identify relevant state or federal legal or regulatory constraints. Consider possible guarantees, insurances and mechanisms that could assist in overcoming potential implementation hurdles.


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Financial • Viable finance approaches

Environmental • Community • Safety • Land use incl heritage

(e.g. Capital lease, PPA, EPC, etc.)

• Sources of funding • Budgets • Performance indicator

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Technical • Site requirements • Security considerations • Equipment suppliers • Implementation


Commercial • Policy framework • Legal / regulatory issues • Guarantees and insurances • Life of asset / exit issues


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With a completed business case, you are ready to determine which financing solutions suit your project.










f ra t an d m a n a g e m e nt





Financing solutions to lower your energy costs and climate change risks The best financing solution for your project The Australian market for energy efficiency equipment financing has become more mature in recent years. There are now a number of financing options offered by the big four banks, some energy services companies and other financiers. You should consider which option best fits the scope of the project, as defined in your business case, your risk preferences and your financial constraints. The options available include: • Capital and operating leases: rather than buying energy efficiency equipment yourself, you can lease this equipment for terms up to fifteen years. With a lease, this equipment can either be off balance sheet (operating lease) or on balance sheet (capital lease). • Targeted bank loans: a number of the banks now offer loan products specifically for energy efficiency equipment. Some of these banks have pools of money targeted at this market, and in some cases offer better terms for such loans compared to regular loans. • Energy Performance Contracts: project is implemented by an energy services company which guarantees the savings that will be achieved by the project over the life of the contract. This can include financing, or be combined with another financing option.

You should consider the following questions when selecting the right option for your project: • What are your capital constraints? Does the project need to be off balance sheet? • What repayment mechanism best matches your cash flows? • Do you need to own the asset, either now or at the end of the financing agreement? • What is the risk that the expected energy savings won’t be achieved? Who is best to manage this risk – you or an energy services company? • Do you need to contract for commissioning and maintenance of the equipment? If you already have a maintenance agreement in place, how will contracts for the new equipment tie in with this existing agreement?

There are financing solutions that will suit your specific projects and requirements. Review your projects today to better manage your energy costs and climate change risks.

• On-bill financing: financing is provided by or through your energy retailer. The repayments are incorporated as a separate line on your energy bills. • Environment Upgrade Agreements: these are similar to on-bill financing, however repayments are incorporated as a line on the building owner(s) council rates bills. • Range of Energy Service / Supply Agreements: external finance with a range of operating models; including Power Purchase Agreements and Build, Own, Operate and Transfer agreements. • Self-financing: financing directly from your cash flows.

Please contact one of our experts to discuss the approach your business should take.

Gilles Walgenwitz

Susie Kaye

Principal Consultant


(02) 9929 3911

(02) 9929 3911



Unearth hidden savings by building energy and carbon skills, systems and processes. Video interview. We recently interviewed Phil Shorten, a Principal Consultant with Energetics who leads our capacity building services. Phil conducts workshops with leadership teams to develop solutions to the challenges of rising energy costs, reducing greenhouse emissions and sustainable resource management.

Watch our video to learn more about building capacity using collaborative forums Phil has worked with businesses as diverse as Windsor Farm Foods, Aussie Fruit and Veg, Bradken Foundries, vineyards, fisheries, government and Xstrata Coal with the aim of embedding a whole of business management approach. We talk to Phil about the benefits he’s seen companies derive from bringing together the leadership team in a collaborative (multi disciplinary) forum.

Video chapters 00:07 – Objective of a leadership forum (workshop)

Over the past five years, Australian business has had to adjust t o the reality that energy is no longer cheap. On top of that, governments, investors and consumers have required better management of resources such as energy, waste and water and reductions in greenhouse emissions.

00:55 – What are the topics covered in a leadership forum and how does it typically run?

However, what many businesses may not realise is that significant savings in energy use remain. Below are some recent figures that outline the savings potential.

8:50 – Why should companies focus on energy and resource management now?

– Mining, manufacturing and transport estimated that a further 11.4% of their total energy spend could be saved1.

3:28 – What are the benefits? 6:19 – Have there been some surprising results?

13:15 – Why should companies invest time and money in building skills, systems and processes in the area of energy management?

– Potential savings per annum across this sector were in the order of $2.1 billion2. – Companies reported that three practices in combination increase energy efficiency outcomes by 218%. Those practices are:

• Regular analysis of energy data

• Energy management included in policies and operational guides

• Senior management oversight of energy3.

Now is the time to re-examine your energy management capabilities as national energy efficiency skillsets are formally recognised through TAFE and grant funding can be accessed to support skills, processes and systems development in energy, waste, water and greenhouse emissions management. Grant funding is available through bodies such as the National Workforce Development fund, various industry sector innovation and R&D funds, as well as subsidised energy assessments available via NSW’s Office of Environment and Heritage and Sustainability Victoria

Contact Phil Shorten for more information

1 ClimateWorks Australia: “Industrial Energy Efficiency Data Analysis”,, May 2013.

Phil Shorten Principal Consultant

2 Ibid

(02) 9929 3911

3 ClimateWorks Australia: “Tracking Progress Towards a Low Carbon Economy”,, July 2013.



Insights from EEO Second Cycle The second five-year cycle of the EEO program is leading participating corporations to refine and improve their approach, and to benefit from first-cycle assessments.

This paper summarises some of the views held, and approaches taken, by Energetics clients and contacts located in a large number of participating EEO corporations across all industry sectors. The paper will address some of the administrative aspects of the program (including Department of Industry [DI] interactions with participants, verification, Assessment Plan submission/review etc), recent changes in the EEO program, the approach that Energetics’ clients are taking into the second cycle of EEO and some of the practical lessons learned by clients in the first cycle that inform their approach. Energetics recognises that different sectors have experienced significantly different economic conditions over the life of the EEO program, in particular in the past few years. As such, it is not unreasonable to expect that the opinion held of programs such as the EEO program may differ across sectors as a result. Furthermore, as a product of exposure to energy cost or historical factors, different industry sectors (or even individual participants) demonstrate greater or lesser resonance with the objectives of the program, with subsequent impacts upon the nature of their response. Where it makes sense, these industry-specific views are differentiated in this paper.

Administration of the EEO program Our clients have noted a clear change in the way that the DI EEO program team have approached EEO. This change most likely started in the latter years of the first cycle of EEO, and carried through more markedly to the first few years of the second cycle of EEO. A more collaborative approach has been noted, with the EEO team open to understanding current business systems and their ability to fulfil aspects of the Assessment Framework. Some clients have appreciated this amenability, and have benefitted from a flexible and helpful approach from DI. Others have clearly found the approach to be overbearing, most evidently during reviews of second-cycle Assessment Plans in 2012. There was a significant amount of feedback provided by DI about the contents of draft Assessment Plans. The feedback was regarded as meaningless or inconsequential, or requested information that was a requirement of assessments rather than the actual Assessment Plan (e.g. too much energy-use analysis detail was sought). Some of our clients want the DI EEO program team to administer the Act/Regulations, be clear about what is required and what is not, and not get into “grey” areas around what might suffice under the Assessment Framework. Others are more comfortable with the collaborative approach and progress based on a negotiated agreement with DI.

The verification program for participants of the EEO program has sparked interest for Energetics’ clients. Significant effort has been spent compiling data and information to demonstrate compliance with the EEO program for those participants subject to verification. This significant effort suggests two things: 1. Audit trial information is not assembled particularly well during the assessment periods. Most of the documentation exists, but not in a form that immediately lends itself to verification. 2. Participants take EEO verification very seriously, most notably driven by the fact that the CEO (or equivalent) is directly sent the outcomes of the verification audit.

Recent updates to the Regulations Recent updates to the Regulations have been considered by Energetics’ clients. Options for a more flexible approach to public reporting have been embraced by several clients. Other approaches relating to greater flexibility in the Assessment Framework have been less enthusiastically embraced, primarily because of the need to submit an amendment to an approved Assessment Plan in order to take advantage of specific options. In many cases, Energetics’ clients and contacts do not want to revisit Assessment Plans for two reasons. Firstly, because of the perceived effort required (as per the efforts in 2012 to achieve an approval status on secondcycle Assessment Plans) and/or secondly, because some participant representatives have insufficient authority under the current Assessment Plan to implement EEO, and fear a “watering down” of requirements will further diminish their influence. The extension of the Regulations to cover New Developments is relatively new. However, several things are clear among our clients and contacts: • Most new participants brought in because of this extension have had no exposure to EEO previously. • There is a strong desire to push specific tasks and accountabilities to construction partners such as Engineering, Procurement and Construction Management (EPCM) contractors. • Clients are hoping to limit the work required by sensibly revising only significant impacts to energy efficiency during concept and detailed design, and construction. This is particularly the case where interaction may be required between contractors and owners for decision-making.



Insights from EEO Second Cycle Approach to second cycle assessment There is a cohort of participants that have effectively “dusted off” first-cycle data analysis and project lists and are providing updates (via public and government reports) for these projects. In doing so, they avoid significant assessment activity in the second cycle. On the other hand, Energetics has observed many participants learning from the experience of the first cycle and employing strategies to improve performance. In many cases we see participants regarding EEO as a standalone program. As a result, the effectiveness of the program suffers because it is not able to absorb broader business opportunities. Discussions around whether an opportunity is “an EEO project” are frustrating, as most improvement projects can be included in EEO, and the program used as a conduit for business improvements. Despite some significant examples to the contrary, Energetics is yet to see EEO integrated into business improvement programs to the extent that might have first been anticipated. We note that, among our clients, the language of energy efficiency is being replaced by the language of energy productivity, namely shifting energy use KPIs from GJ/T (for example) to $/GJ. This is allowing conversations across multiple management levels in organisations, and we anticipate that this will elevate the discussion of energy improvement beyond narrow technical improvements to broader benefits. Much of the first cycle of EEO was characterised by positive business conditions and a growing economy featuring increasing commodity prices. These conditions impacted on the way that resource sector corporations delivered EEO in the first cycle. Energy efficiency projects were competing on a level playing field with capital that could be deployed to deliver volume. This competition for funds meant that while there were genuine opportunities to install new efficient equipment and implement practices while volume was being increased. Retrofitting opportunities were difficult as the improvement projects were competing with the value of new production. In the second cycle of EEO, changes in economic outlook continue to influence participants’ approach. As the focus on growth in the resources sector is replaced by a focus on improving the efficiency of existing operations, some clients reported a shift to more retrofit changes, which alters the project economics (e.g. production halts must be included as a cost). Overall, it may be said that participants have reined in the ambition of their EEO program, shifting focus to more pragmatic project delivery. Many participants reported during the first cycle that the list of identified opportunities was overwhelming, and that more opportunities did not mean more implemented projects. Now, rather than generating a list of +50 opportunities and trying to advance them all without success, participants are seeking to identify and deliver quick wins with low upfront cost. As an example, one corporation known to Energetics has four zero-tolow capital opportunities that they are pursuing. This can be compared to the outcomes for this participant in the first cycle of EEO, where more than 30 opportunities were being pursued at the equivalent stage. Apart from the influence of the business cycle described above, this change in approach reflects the experience of those tasked with delivering EEO. It is important for the reputation of the program that projects are seen to be delivered and savings realised. Experienced operators have realised this.

which in turn drove them to establish corporate strategies and targets. These corporate strategies and targets are now significant drivers. Identified opportunities have been shown to be more successful where they also address the broader corporate energy and emissions goals. The following sections address specific aspects of the Assessment Framework.

1. Leadership 6. Communicate Outcomes

2. People

Compliant EEO Assessment 5. Decisionmaking

3. Data Analysis

4. Opportunities

Leadership The value of conspicuous leadership in energy efficiency in participating corporations has been obvious and will be maintained in the second cycle. Drawing parallels with the methods used to communicate safety messages through businesses, leadership is a low-cost, high-return step that assists in the development of a culture that fosters energy efficiency. Communicating the outcomes of the EEO process reinforces the value and relevance of the program and engages staff in the process. Successful execution of Key Element 1.1 supports execution of 1.2. When leaders can see the value that the program brings to the company, they are more likely to make staff and resources available when assessments and project delivery commence. With this in mind, many senior managers have made energy management a priority in the second cycle. The leadership has extended from company heads to senior and line-item managers, looking to energise their teams and realise cost savings.

If you’re not looking at cost reduction, you’re in the wrong business. EEO participant

During the first cycle, EEO and NGER drove businesses to set up systems and resources to manage energy more strategically,



Insights from EEO Second Cycle People

Information, data and analysis

In general, participants are more discerning when deciding who should take specific roles with in the delivery team for EEO. The list of contributors invited to participate in opportunity identification workshops is informed by lessons learned in the first cycle.

Data quality and access remains a significant issue in many corporations. However, Energetics has noted greater participant confidence in regard to the Key Requirement.

In the second cycle, opportunity identification workshops are primarily attended by operations and maintenance personnel, and the role of environmental engineers is limited to that of a coordinator. This is driven by the desire to deliver practical projects more closely aligned to core business drivers (e.g. production, quality etc). Participants have realised that those working most closely with process equipment are best able to judge the feasibility and value of an opportunity as the opportunities are raised during the workshop. Linked to the delivery focus, multi-site opportunities are now identified in site workshops, but delivered at the corporate level, to match the corporate decision making process. For example, an opportunity involving the tuning of settings used on a comminution circuit was raised in a recent site workshop. Since this opportunity had the potential to apply to multiple sites, corporate head office was able to take a coordinating role in both the evaluation and delivery of the project across multiple sites.


The first cycle identified shortcomings in the coverage and accuracy of data, but formulating a business case for new sub-metering remains difficult. The potential opportunity must be large to provide enough savings to cover the sub-metering and possible subsequent energy efficiency project. Metering projects have not been widely implemented as a result. Beyond this problem, the data that is available is frequently of poor quality and difficult to use. Many remote sites do not have a comprehensive SCADA systems and rely on data historians attached to the meters and sub-meters to collect data. As these can be interrupted, damaged or misused, and are not well monitored, the data is frequently incomplete or corrupted. As with the sub-metering business cases mentioned above, the costs of solving these problems far outweigh the benefits. The first cycle drove more metering projects across some sectors, but in many cases these were not informed by experience and so the planning of the data that should be collected was absent. This has meant that the data being collected now may not be fit for purpose. Some meters are measuring the wrong parameter, but more frequently they are measuring at the wrong resolution, meaning the amount of data is overwhelming and unworkable, or inadequate. Ideally businesses would have identified data needs during the first cycle, then allocated budget and implemented appropriate sub-metering for the second cycle.


Insights from EEO Second Cycle Commercial clients in particular have benefited from the growth in energy analysis capabilities and are taking lessons into the second cycle. There has been increasing sophistication in the analysis of representative sites, lowering the cost of assessment while still delivering bankable projects. There has also been improved internal communication regarding future developments and site closures, ensuring less effort is wasted.

Opportunity identification and analysis The process of opportunity identification has matured from the first to the second cycle. Workshops are more targeted, with fewer disinterested attendees. The style of projects being pursued is characterised by two schools of thought, but with broadly the same outcome. Because of the intense competition for capital, participants are pursuing the highest value opportunities. For some this means the low-to-zero capital projects (including behavioural change and operational improvements), while others are using the opportunity to design large capital projects that deliver more significant savings. An increased focus on productivity is likely to characterise the approach among a significant number of Energetics’ clients in the second cycle of EEO. For example, monitoring and improving blowdown events in the oil/gas sector, or waste in manufacturing processes, directly impacts upon the specific energy use indicator, reflecting improved energy efficiency or final product delivery. Couching EEO as a whole of business improvement opportunity denominated against energy consumption has gained traction, and elevates the discussion from environment and engineering teams to financial controllers and senior management.

Decision making Parallel decision making is out of favour in the second cycle of EEO, with more companies seeking to use existing decisionmaking processes to drive energy efficiency projects where they exist. Comparison of the merits of individual projects across operations, borders and activities has helped businesses make wiser investments. Energetics has delivered many carbon and energy abatement cost curves on the back of EEO assessments, providing decision making support by comparing opportunities in disparate locations and activities. Often, though certainly not always, these tools are used to set internal (and sometimes external) targets, built from the ground up of real opportunities.

Communicate outcomes Few corporations have had the opportunity to go to the board or communicate outcomes in the second cycle. However, many have identified that this was done poorly in the first cycle and are looking to improve for the second cycle. As noted in the Leadership section, many corporations view communicating of outcomes as a valuable opportunity to demonstrate leadership and are investigating ways of incorporating this into their normal reporting and communication channels. Ideas being discussed at the moment include using the CEO’s blog more frequently or using the existing safety communication channels to also communicate efficiency messages.

Energetics has noted an increasing appetite for improvements to be measured against business as usual. This approach lends itself to recognising energy efficiency improvements while actual energy use increases (i.e. where an increase in energy use is offset by a proportionately greater increase in production).

For more information contact our EEO experts

Brian Innes

Graham Winkleman

General Manager – Business Development

Principal Consultant

(08) 9429 6400

(03) 9691 5500



Could 2014 be the year of the battery? In a paper presented to the 2nd Summer Study into Energy Efficiency and Decentralised Energy in early in 2013, Energetics explored a number of questions related to energy storage. These included whether the time is right to consider energy storage, whether it is cost effective and the implications for other network users.

Energy storage was a hot topic in 2013, and there were some exciting developments. As well as the establishment of targets for electricity storage in Germany and California, some innovative funding options were introduced into the market. Serious studies that explored the economics of battery storage showed that batteries have not quite arrived except in particular circumstances such as remote renewable power generation.

These themes were explored many more times in 2013, with an emerging picture that energy (primarily electricity) storage is close but not quite there. But the impact of solar PV and other forms of distributed generation on business models is already being felt by network operators and generators. Batteries will only increase that impact. The economic status quo is well presented in the following graph, which was included in a talk given by Markus Hoehner CEO of the International Battery and Energy Storage Alliance at the San Francisco InterSolar conference in July. The graph shows the current situation in Germany, where the installation of an appropriately sized battery to support solar PV is cost effective in the residential market i.e. the solar PV system with battery has a positive net present value (NPV). However, the NPV is lower than the NPV of a solar PV only system and so the storage system is not yet adding value. Interestingly, that situation would be different if the cost of the electricity rises or if the cost of the batteries fell from the current €2250/kWh to around €900/kWh.

However, the growing role of renewable energy especially solar PV should see batteries providing the most cost effective options for grid support and for the supply of peak capacity. Australia, more than most, should benefit from these developments as we have a relatively high penetration of solar PV, and significant demand in remote and fringe area of the grid.

Action is being taken to try to drive down the cost. As with the situation with solar PV, Germany is leading the way.

NPV PV system and battery prices – Germany NPV PV system depending on battery system prices 15,000

10,000 Today 5,000


-5,000 Storage is the better choice

Storage pays off



kW 00



kW 3,




kW 2,



kW 60 2,




kW 2,



kW 20 2,





NPV only PV (GER)




kW 80 1,




kW 1,




kW 1,





NPV PV System incl. Storage (GER)





kW 1,



kW 80

€/ 0 60

kW 0


kW 40

€/ 0 20





Source: EuPD Research 2013


Could 2014 be the year of the battery? Setting targets Since 1 May 2013 the German government has provided an energy storage subsidy, which provides a grant to lower the upfront cost of installing an energy storage solution in a PV system up to 30kW in size. The subsidy equates to euro €600/kW, or a maximum of 30% of the eligible costs, for a battery-based energy storage system installed in a new PV system. Just as the German support for solar PV helps drive down the cost of solar PV, so should the support for storage drive down the cost of batteries. Germany is not the only jurisdiction promoting energy storage. On 17 October this year, the California Public Utilities Commission (CPUC) established an energy storage target of 1,325 megawatts by 2020, with installations required no later than the end of 2024. The objectives of the proposal were the optimisation of the grid, the integration of renewable energy and the reduction of greenhouse gas emissions to 80 percent below 1990 levels by 2050, as per California’s goals. The recommendation built on work by the Electric Power Research Institute (EPRI) and by DNV KEMA Energy & Sustainability (DNV KEMA). For instance, the work by the EPRI1 showed that the majority of storage scenarios considered had a benefit to cost ratio above 1.0. These scenarios covered three different general use cases, including transmissionconnected bulk energy storage, short-duration energy storage to provide ancillary services, and distribution-connected energy storage located at a utility substation. Lux Research anticipates that the residential market will lead the way in uptake, riding on the shoulders of rooftop solar PV’s phenomenal growth globally.2 But they also see California’s proposal having an immediate and lasting impact on the grid storage market3, which Lux Research estimated will be worth $10.4 billion in 2017 rising from just $200 million last year. Citi also explored the coming boom in energy storage.4 Germany provides a good example of the trend. The high solar penetration rates are inevitably steering Germany towards power storage to stabilise the grid and to mitigate the need for capacity payments to keep conventional power plants available, but off-line. Citi saw batteries as being more economically efficient for addressing peak demand than alternatives like capacity payments to generators. The challenge is to realise this potential growth, and a couple of developments during the year may point the way.

have gone solar using another route, this financing model is now being applied to the energy storage market. Perhaps a more interesting development is in New Zealand, where Vector6 is offering a trial run of leases to its customers to install rooftop solar and battery storage for around the same cost as relying entirely on the grid. The solution integrates highly efficient battery storage and smart controllers with traditional solar panels. It enables homeowners to maximise their economic returns by maximising the use of electricity from the solar PV modules. Vector sees solar PV and storage as being good for the network, and for its business7. Rough calculations suggest that the levelised cost of the solar PV/storage package is around NZ$0.21/kWh. The current average tariff is around NZ$ 0.25/kWh. All drivers point to the growing importance of energy storage. The broad global trend of winding back feed-in-tariffs for small-scale solar power make it less desirable to export power generated by solar panels and consumers will look to batteries to allow them to get maximum value from the solar panels. The cost of batteries should continue to fall, encouraged by the setting of targets in Germany, California and elsewhere. Finally, the expanding penetration of solar PV into the networks will drive network operators to look for storage based solutions to better manage their networks. Many of these factors are in play in Australia.

Innovative funding Stem Inc, based in California offers an energy storage solution that reduces costs by shifting load from peak to off-peak periods. The key is an algorithm which integrates data from various sources and applies machine learning to provide highly precise energy usage forecasts and so optimise the use of the stored electricity. Their market is the industrial and commercial sector. In October this year, Stem is offering a leasing option for the storage system with zero upfront payment.5 The company has secured funding to allow up to 15 MW of energy storage to be deployed. Just as solar leasing and related models have broadened the solar market, presumably bringing in a large number of customers who wouldn’t

Storage in Australia? In the first week of December 2013 solar power installations in Australia reached 3GW in total. This follows the passing of the one-million solar power systems milestone in April. One in seven Australian dwellings now has a solar PV system. In South Australia, the figure is one in four. The state with the largest volume of solar PV is Queensland with almost 1 GW of installed capacity. According to SunWiz8, businesses are purchasing solar power with approximately 5% of recently installed systems exceeding 8kW in size.

1 “Cost-Effectiveness of Energy Storage in California”, EPRI, June 2013 2 “Finding the Perfect Partner in the Global Grid Storage Market”, Lux Research, March 2013 3 “The energy storage holy grail”, Braden Reddall and Nichola Groom, Climate Spectator, 22 August 2013 4 “Battery storage – the next solar boom?”, Citi Research, April 2013 5

6 7 “Culture shock: Network offers solar storage leases to customers”, Giles Parkinson, RenewEconomy, 14 June 2013 8 “Special Announcement: Australia reaches 3GW of PV”, available from http://www.



Could 2014 be the year of the battery? Analysis also performed by SunWiz showed that at midday on 29 September, solar power contributed around 9.3% to electricity demand in the National Electricity Market, and 28% of South Australia’s demand. The penetration of solar PV in South Australia is similar to the levels seen in Germany where PV power can cover more than 30% of demand on sunny days.9 These numbers are important in the light of the research done by Citi4 which highlighted the need for network operators to look for storage based solutions to better manage their networks when the penetration of solar is relatively high. Like other countries, batteries are not yet cost effective for businesses. Typical levelised costs for battery storage ranges starts from around $0.20/kWh after accounting for the efficiency of storage and constraints on the depth of discharge. For instance the capital cost of the recently developed GE Durathon Battery is around $1500/kWh for a large system which equates to about $0.30/kWh of the anticipated life of the battery. This figure is higher than typical electricity prices and also higher than the differential between peak and off-peak power costs. So a battery will not provide a cost effective option for load shifting or for displacing purchased electricity.

However, the prices for batteries coupled with renewable energy generators such as wind are comparable to the cost of power at remote off-grid sites such as mines that use diesel generators. Australia also has a relatively large number of electricity users on the fringe of the networks, especially in remote areas of Queensland, NSW and Western Australia. A study commissioned by the Clean Energy Council10 argued that fringe and remote electricity systems would seem to be ideal first candidates for energy storage deployment.

The modelling discussed in the report showed that a material opportunity exists for storage to support fringe and remote electricity systems. The report also states that the total commercial market for storage in Australia could be approximately 3,000 MW by 2030.

2014 will be an interesting year should current trends accelerate.

9 “Recent facts about photovoltaics in Germany”, Harry Wirth, Fraunhofer ISE, Sep 12, 2013

For further information contact

Dr Gordon Weiss Principal Consultant (02) 9929 3911


10 “Energy Storage in Australia, Commercial Opportunities, Barriers and Policy Options”, Clean Energy Council, November 2012


Comparing submissions on the Emissions Reduction Fund – what are the industry experts saying? Different approaches taken by ERF submissions More than 150 submissions were received by government in response to the terms of reference published for the design of the Emissions Reduction Fund. Common themes include: - the challenges raised by the imposition of penalties where emissions exceed business-as-usual baselines - the need to protect the international competitiveness of Australia’s industry - the need for simplicity. The key policy question yet to be addressed is the role of a market based mechanism to reduce the cost of compliance. Looking across submissions, we see suggestions that carbon trading is not only the most pragmatic response, but also the most cost effective. Questions are also raised about the role of complementary measures. For example, how does an ERF work with other energy policy measures such as the Renewable Energy Target?

With such a diverse collection of stakeholders, a variety of submissions was to be expected. Some examined the specific elements of the ERF relevant to them, while others chose to address more general issues. For instance, the submission by the Property Council prepared by ACIL Allen Consulting provided a comprehensive review of the many issues that the Government must address in the design of the ERF. In particular, their submission provided detailed recommendations on the operation of the reverse auction to ensure efficient operations and price discovery. However, the submission did not make recommendations about baselines and penalties despite discussing the issues to be addressed. ClimateWorks and the Minerals Council of Australia (MCA) also framed their submissions in more general terms. ClimateWorks explored the likely sources of abatement that could be purchased by the Fund, and noted that “the major focus areas include capture of waste methane from coal mines, increased deep retrofitting of commercial buildings and industrial facilities, and carbon farming and forestry. These could represent over 140 MtCO2e of annual abatement in 2019-20 with the right mix of incentives.” They also highlighted the importance of other policy measures to complement the Government’s Direct Action plan to effectively reduce emissions in each sector of the economy. Energetics has highlighted this same issue in our own revision of the national greenhouse emissions forecast1, where we stressed the importance of existing measures and especially the Renewable Energy Target in delivering abatement. In this paper we consider the submissions made by the major stakeholders as outlined in Table 1. Certainly the National Generators Forum, the Business Council of Australia, the Australian Petroleum Production and Exploration Association and the Minerals Council of Australia represent organisations that are responsible for most of Australia’s greenhouse emissions.

Table 1: the submissions reviewed Organisations representing major energy users

Other industry associations

Energy suppliers

Advocacy groups

Australian Industry Group (Ai Group)

Institute of Chartered Accountants


The Climate Institute

Australian Industry Greenhouse Network (AIGN)

Australian Landfill Owners Association (ALOA)

Pacific Hydro

Carbon Markets Institute (CMI)

Business Council of Australia (BCA)

Australian Local Government Association (ALGA)

Energy Supply Association of Australia (ESAA)

Sustainable Business Australia (SBA)

National Generators Forum (NGF)


Australian Petroleum Production & Exploration Association (APPEA) Minerals Council of Australia (MCA) Energy Users Association of Australia (EUAA) Property Council

We also reviewed the Clean Energy Finance Corporation’s (CEFC) submission.

1 Weiss, G: “Big shifts in energy use over 2012 deliver dramatic falls in Australia’s greenhouse gas emissions”, Energetics, 29.7.2013.



Comparing submissions on the Emissions Reduction Fund – what are the industry experts saying? Key issues to be resolved Is the ERF meaningful without penalties? Many of the submissions looked at the question of penalties for exceeding baselines. Some stakeholders strongly supported penalties, and saw them as an essential part of the operation of the Fund. For instance, The Climate Institute believes that baselines should be binding and penalties for non-compliance should apply. Pacific Hydro also believed that the ERF must include penalties. Several other stakeholders gave qualified support for penalties but highlighted the challenges confronting the Government. Both the BCA and the AIGN noted challenges with the setting of businessas-usual baselines. The AIGN noted that “‘business-as-usual’ encompasses a diverse variety of commercial activity and can be assessed in various ways; establishing a business-as-usual baseline is perhaps more complex than it first appears. There are numerous options for baseline measurement. All potential options, including absolute emissions and emissions intensity, present different opportunities for industry sectors, and different administrative costs.” In their submission, the Minerals Council stated that the use of business-as-usual (BAU) baselines for the levying of penalties must not see firms lose international competitiveness. The use of NGER reporting provides a useful tool for Government, but should not be seen as the sole criterion for an economy-wide emissions management regime. MCA sees a range of measures that will influence the business-as-usual baseline such as declining ore grades, deeper operational requirements and changing geological profiles that will not be captured by NGER. Many other stakeholders saw specific problems that must be addressed. For instance, the ESAA noted that using site level baselines risks penalising early movers. APPEA raised a number of points related to setting appropriate baselines for new facilities with specific reference to LNG production. In this case, there are a limited number of LNG trains in the world and so even establishing industry best practice will be difficult. APPEA also suggested that the mechanism to apply to emissions above the threshold should be consistent with the Government’s stated objective of applying it only to emissions above business-as-usual, and not as a mechanism for raising revenue. This could mean implementing a process of warnings, followed by a request to explain how compliance will be achieved and only if the response is unsatisfactory would penalties be applied. The EUAA questioned the use of NGER. They believed that large industrial energy users would prefer to have thresholds based on scope 1 emissions and be site/facility based rather than industry based. Concerns also relate to the use of emissions intensity factors. The relationships between various emissions intensity factors are not correlated and variations could occur from other factors - a baseline should account for these variations. The CEFC also saw challenges with adapting NGER to equitably recognise growth, changes in product mix and existing energy efficiency performance (perhaps focussing on emissions intensity). Sustainable Business Australia (SBA) commented that an emissions baseline should be established for each sector, typically on a CO2/unit of production basis. The participants would earn credits if emissions were below their baseline and surrender credits if emissions exceed the baseline. SBA effectively recommended the use of a trading scheme.


Protecting international competitiveness Most submissions support Australia reducing global greenhouse gas emissions in line with global efforts and require the mechanisms to support Australia’s future economic growth and maintain the global competiveness of Australia’s industries. Further, the ERF must provide for reductions in greenhouse gas emissions at lowest cost. Not surprisingly, stakeholders that represent Australian businesses see the protection of international competitiveness as a key consideration in the design of the ERF. This theme was addressed by the AIGN who believe that Australia’s climate policy approach should not disadvantage operations in Australia by exposing trade-exposed industries to costs not faced by competitors in other countries. Others who adopted this position included the Ai Group and the Minerals Council. A related question is the use of international offsets to address Australia’s obligations. Several stakeholders felt that international offsets can be used to offset emissions when a business exceeds its baseline (Ai Group, AIGN, CMI and APPEA). Ai Group added the qualifier that international offsets cannot be bought by the ERF. The National Generators Forum thought that the ERF should include as many abatement options as possible, including international permits to maximise the opportunity for low cost abatement. BCA felt that the Green Paper should examine the role that domestic versus international abatement could have in reducing Australia’s emissions. The Minerals Council (MCA) noted the challenges ahead in designing the ERF and the importance of delivering abatement in an economically efficient manner. They saw the need to position Direct Action “in the context of a comprehensive and integrated energy policy; that is, integrated with the development of the proposed Energy White Paper and the review of the Renewable Energy Target.” Importantly, the MCA saw a role for the Productivity Commission in providing guidance on a design for Direct Action that is at lowest cost and does not adversely impact the competitiveness of different sectors of the economy. This position was supported by the Ai Group, The Climate Institute and the Business Council of Australia (BCA). It will be interesting to see how the Government responds to this recommendation, given its criticism of the previous Labor Government’s failure to refer the NBN to the Productivity Commission.


Comparing submissions on the Emissions Reduction Fund – what are the industry experts saying? A key message repeated across a number of submissions was that whatever is implemented, it must allow Australia to meet its international emissions reduction commitments at least cost. This was sought by the Ai Group, APPEA and SBA, all of which supported a trading scheme. Simplicity in the operation of the scheme Most stakeholders recommended that the ERF be simple. For instance, the Institute of Chartered Accountants believed that the Fund needs to strike the right balance between robustness and simplicity. APPEA noted that the CFI is not a good model for the ERF as it is too cumbersome and the Government must streamline the process. The MCA used the current NGER scheme as its benchmark and it felt that a more streamlined version of the existing NGER measurement, verification and auditing arrangements should be a default method for pre-qualification for auctions or compliance requirements post-auction.

Making it all work A closer look at types of abatement Of those submissions that dived into the detail on how the mechanism could work, two areas received particular attention: • Banding of emissions reduction. Banding would mean that separate pools of funds would be available for different sources of abatement. This was approached from both ends of the spectrum, where for instance, the CMI suggested that the ERF should incorporate banding to support a diverse portfolio of low cost abatement projects, whereas the Australian Local Government Association advocated banding to ensure that long term projects such as landfill capture are competitive in the reverse auctions. • The challenge of supporting long term abatement and promoted contracts for abatement that extend well beyond 2020. For the purpose of gaining widespread coverage of emissions sources, the CEFC and others thought banding could be used to address concerns about non-delivery of contracted abatement. By offering separate auctions for ‘guaranteed’ and ‘nonguaranteed’ abatement, provision is made for the more speculative projects to still participate in the auctions but in a way that does not distort the price of abatement offered for more certain abatement. So ‘guaranteed’ abatement would include

make-good provisions should abatement fall short, and because it reduces the Government’s risk, result in high auction prices. Recommending a trading scheme Many different stakeholders acknowledged the value of a trading scheme in reducing the burden to be carried by the ERF. The CEFC proposed a scheme that would include the ERF for the funding of voluntary actions to reduce emissions and a mandatory baseline and credit scheme derived from NGER. The Carbon Markets Institute remarked that a baseline-and-credit mechanism linked to the ERF should provide incentives for companies to operate below their baseline and costs for companies exceeding their baseline. Any penalties could be in the form of purchasing ACCUs, a cash contribution to the ERF or purchasing international permits. Others promoting a trading scheme included the Ai Group and AGL (at the least, trading within corporate groups) and the ESAA. Many submissions advocated the use of recognised offsets to reduce the level of emissions reported by organisations. Offsets should include Australian offsets generated under the CFI including the use of Australian Carbon Credit Units (ACCUs) purchased on market. For example, this position was supported by the AIGN, APPEA and the ESAA. The ESAA suggested that a range of provisions could be used to meet targets, including trading of offsets generated when emission levels or the use of credible international emissions reduction units. Australia has been debating its response to climate change for more than a decade, and fighting elections over climate change for much of that time. The Direct Action plan is the latest chapter in this story. The government insists it has a mandate to implement the Direct Action plan. Within the principles laid out in Direct Action, there is potential for a scheme that addresses the concerns of business for equity and certainty. A baseline and credit scheme could provide robust mechanisms to meet the national abatement target and ensure that Australia maintains its global competitive advantage for future generations. No single policy will, in isolation, enable Australia to meet its 2020 emissions reduction target. The Carbon Markets Institute (CMI) felt that the ERF needed a variety of complementary measures such as a baseline-and-credit mechanism, private sector investment and the possible purchase of international units to meet the target.

For further information on the Direct Action policy contact

Dr Gordon Weiss

Dr Peter Holt

Principal Consultant

Principal Consultant

(02) 9929 3911

(02) 9929 3911



Designing the Emissions Reduction Fund The Federal Government has begun the process of fleshing out the Direct Action plan to define the mechanisms that will reduce Australia’s greenhouse gas emissions by 5% in line with our international obligations. Energetics has been proactive in speaking with our clients to get their views on Direct Action and in particular the Emissions Reduction Fund which is the centrepiece of the Plan. This paper is a condensed version of a recent five-part series on the Emissions Reduction Fund, published in Climate Spectator. Energetics reports on the views of our clients and, informed by these, propose options for the ERF. These options are in keeping with the principles of Direct Action, will allow Australia to drive down its emissions and provide business with the certainty that it craves.

Climate change policy in Australia is set to change. The new government intends to repeal the Clean Energy Future package (with the carbon tax at its centre) and replace it with the Direct Action plan. The debate now centres on the design of the Direct Action plan and how it will be legislated. The plan includes a number of elements including support for solar energy (one million solar roofs), energy employment hubs and renewable energy. But the major element is the Emissions Reduction Fund which will purchase greenhouse gas abatement in pursuit of the national emissions reduction target of 5% compared to 2000 emissions levels. Written in 2010, Direct Action exists essentially as a set of principles – some of which appear problematic and, at times, contradictory. It has been called the “do nothing” policy option, but this would benefit no one. There is no certainty in this option, as Australia’s international obligations will eventually require action to reduce emissions. We instead have an opportunity to design a scheme that is meaningful, equitable and positions Australia for future prosperity. In this paper, Energetics will summarise the views of businesses on the Fund and outline a number of the challenges that the designers of the Emissions Reduction Fund (ERF) must address.


Direct Action: key principles: 1. ERF. “Abatement will be purchased via a market mechanism to achieve the lowest price of carbon abatement. A reverse auction mechanism will be used to competitively procure lowest cost emission reductions.” 2. The Fund will use the existing NGER Act to measure overall company carbon emissions. 3. Businesses that reduce their emissions will be able to offer this CO2 abatement for sale to the government. 4. Small businesses and other entities not currently covered by NGER (can) ‘opt-in’. 5. The Clean Energy Regulator will…approv(e) the methodologies, and … ensure that the methodologies support genuine and verifiable emissions reductions. 6. Long-term contracts for abatement will be available to assist organisations to secure finance to undertake projects. The payment will depend on delivery. 7. Businesses that undertake activity with an emissions level above their ‘business as usual’ levels will incur a financial penalty. The value of penalties will be on a sliding scale at levels commensurate with the size of the business and the extent to which they exceed their ‘business as usual’ levels. 8. Provision will be made to ensure penalties will not apply to new entrants or business expansion at ‘best practice.’


Designing the Emissions Reduction Fund Both before and after the recent election, Energetics sought the views of the business community on the features of the Emissions Reduction Fund that would make it workable and acceptable. Some of the findings included: • A bias towards achieving equity rather than simplicity • Strong support for the protection of international competitiveness • An acceptance of the need for penalties for exceeding a fair baseline • A clear desire for a market based mechanism There are three major risks: • “additionality” - the requirement that the abatement project is beyond business-as-usual. In the absence of support from the ERF, the project does not meet investment benchmarks.

What the market says Australia’s largest energy users and emitters have been tracking, managing and reporting their greenhouse emissions for years. Leading companies have developed national energy efficiency programs, invested in greenhouse mitigation technologies and increasingly, renewable energy options. In this section, we report on the feedback received from a survey of some of Australia’s largest energy users, as well as the poll results from our Direct Action webinar series. More than 20 senior business representatives with responsibilities for energy and carbon management participated in a survey assessing their design preferences across key aspects of the government’s Emissions Reduction Fund. The questions covered five major design issues: • the type of baseline to be applied • penalties and how they will be imposed

• participation – voluntary vs compulsory whilst being equitable

• voluntary versus mandatory participation in the Fund

• delivery in a simple and robust way.

• types of emissions reduction projects that should be allowed into the Fund auction process

Trying to manage all three elements concurrently will be a balancing act.

• the timing of funding awarded, and the use of revenues raised through the operation of the Fund. The results are summarised in Figure 1.

Simple Funds only available for entities exposed to a cost impact Penalties based on absolute measures Non-market mechanism sets penalties rate

Consistent and equitable Funds from penalties available to all abatement activities Penalties based on relative measures Market based mechanism sets penalties rate

Figure 1: Direct Action survey feedback The overwhelming feedback shows that business favours a scheme that is equitable even if it results in a degree of complexity. Australian companies believe in a ‘fair go’ and look for certainty to conduct business. This informs their view on climate policy.



Designing the Emissions Reduction Fund Baselines, penalties and trading schemes Our polling shows that business is prepared to accept appropriate penalties for underperforming businesses, provided there is a level playing field. There is also a clear message that the level of penalties should be determined by a market-based mechanism, and that funds raised from the levying of penalties for exceeding the baseline should be recycled to support all forms of abatement activities. Direct Action speaks of penalties for businesses that produce emissions above their ‘business as usual’ levels. Yet there is limited information available on the type, form and extent of penalties. Surveyed businesses overwhelmingly (73%) indicated that penalties should be set at a level that matches the cost of efforts to reduce emissions.

Which of the following statements best matches your position? There should be no penalties for exceeding the baseline.

12% 15%


There should be penalties that are set at a level below the cost to achieve emissions reductions. Penalties should be set at a level that matches the cost of action to reduce emissions.

Figure 2: Business feedback on the application of penalties The role of the baseline (and how it is defined) is central to the operation of the Fund. The baseline: • dictates the extent to which a facility is potentially liable to pay penalties • establishes the volume of abatement (along with the pool of money available) which can be sold to the ERF. Direct Action proposes that baselines will be adjusted to reflect changes in production. Across the briefings held, this principle was well received with strong support for site-specific baselines. Businesses want to see baselines derived from emissions intensity rather than absolute emissions levels, and emissions intensities used to determine the baselines should be site-specific where possible. If designed correctly, intensity based emissions baselines can create a level playing field.


However, concern was expressed as to how a baseline can be set for a new entrant where there is no existing site intensity factor. Deriving the historic average baseline from National Greenhouse and Energy Reporting (NGER) data is easy. Businesses and government have this information. But NGER data does not provide the appropriate denominators (e.g. unit volume, ROM tonnes, etc) for establishing site-specific emissions intensity nor does it take into account adjustments to reflect changing business activity. Also, defining and maintaining baselines at the site or facility level poses challenges, as businesses differ so much in age, type of activities, underlying foundations and the technologies used are often very different. Finally, the use of site-level baselines can disadvantage businesses that have already taken action to reduce emissions. These companies are likely to have lower than average baselines, and fewer low cost abatement opportunities. Site-level baselines may not be equitable. Following the establishment of robust and appropriate baselines, shifting straight into baseline and credit emissions trading makes sense and is relatively simple. Open to companies that create emissions reductions below their baseline, they could sell offsets into the ERF, provided the government is not the only buyer.

Show me the money The Direct Action plan clearly spells out principles for an Emissions Reduction Fund which would purchase abatement from the market via a reverse auction. Two principles are stated: the Fund should only purchase realised abatement, and abatement must be beyond business as usual. Worthy aims, but the devil is in the detail. “Additionality”, the requirement that the emissions reduction measure be beyond business-as-usual, means that without support from the ERF, the project would not meet the business’ investment benchmarks. However, what does a business need to do to show a measure is genuinely beyond business-as-usual, given every business is free to set its own financial hurdles? Also, demonstrating additionality for every measure may create an administrative burden that discourages businesses and especially small businesses from participating. Businesses are concerned about monitoring, verification and compliance. The proposed approach of using forward contracts to purchase abatement as it is realised provides some payment certainty, but it will carry transaction costs and an administrative burden. Continued uninterrupted emissions reductions over time are hard to quantify and the risk of non-delivery is real. Further, as many abatement measures have long payback periods (eg. renewable energy generation), business participation in the auction process may be limited by cash flow and the need for assistance with capital expenditure.


Designing the Emissions Reduction Fund How to do Direct Action Energetics’ proposes a structure for the Fund that addresses the concerns raised by business and provides certainty, remains true to the principles outlined in the Direct Action plan, and considers a number of drivers. The lack of bipartisan support for the mechanism to achieve the national emissions target is driving investment away from Australia. Given Labor’s support for an emissions trading scheme, Energetics believes that a failure to implement a scheme that largely satisfies the policy objectives of the current Opposition merely introduces uncertainty sometime in the future. Further, the Government needs to implement a scheme that can deliver abatement reductions deeper than the current target in keeping with our international obligations. We believe Direct Action must consist of two components. The first is a reward and penalty system centred on site baselines developed from industry-wide activity-based emissions intensities. Sites or facilities that achieve emissions below their baseline can offer the abatement for sale to the Fund or to any other buyer such as corporations whose emissions exceed their baseline. Sites or facilities that achieve emissions above their baseline must either pay a penalty or purchase verified abatement from other participants. The level of the penalties will be set at the current price offered by the Fund plus a margin.

Several features will ensure that the scheme can evolve with Australia’s changing international obligations. 1. The baselines can be adjusted to reflect changing international obligations. The mechanism is to adjust the emissions intensity factors used to generate the site or facility baselines. These adjustments can be made on a sectoral basis. 2. Participants liable to pay a penalty, or the ERF itself should it be facing a shortfall in abatement, can supplement domestic abatement by purchasing approved international offsets. The scheme defines a market for abatement which offers an economically efficient means to address changing obligations. It is essentially a baseline and credit trading scheme with a secondary mechanism to generate abatement beyond what is needed to meet the baseline targets. Australia has been debating its response to climate change for more than a decade, and fighting elections over climate change for much of that time. The Direct Action plan is the latest chapter in this story. The Government insists it has a mandate to implement the Direct Action plan. Within the principles laid out in Direct Action, there is potential for a scheme that addresses the concerns of business for equity and certainty. A baseline and credit scheme could provide robust mechanisms to meet the national abatement target and ensure that Australia maintains its global competitive advantage for future generations.

The second is a project based program generating abatement for sale to the Fund and to other participants. The abatement generated by the project would be determined by approved methodologies. Abatement can be offered to sale to the ERF or to any approved participant in the reward and penalty system. Projects that have a payback of less than two years will be considered to be ‘business as usual’ and cannot sell abatement to the Fund. Beyond this, there will be no requirement to ensure financial additionality.

For further information contact

Dr Gordon Weiss

Dr Peter Holt

Emma Fagan

Principal Consultant

Principal Consultant


(02) 9929 3911

(02) 9929 3911

(03) 9691 5500



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