Carbon price to transform energy networks

Infigen managing director Miles George
Infigen managing director Miles George

The successful passage of the Federal Government’s clean energy legislation through the Senate in November will transform Australia’s energy networks.

The Clean Energy Future Plan fixes the price of carbon at $23 a tonne from 1 July 2012, moving to a flexible price after three years. Under the new system around 500 of Australia’s largest polluters will be required to pay for their pollution under a carbon pricing mechanism (CPM).

A set price for carbon pollution will address industry’s concerns that a lack of certainty has hampered generation investment, but some power generators and retailers believe the cost will be passed on to users through increased electricity prices.

Research released by carbon analytics firm RepuTex in November indicated that the CPM will cost S&P ASX 200 companies $18.7 billion over a 10-year period between 2013-2022, with high-polluting medium and small capitalised materials and industrials companies faring the worst.

Peak industry body Clean Energy Council (CEC) chief executive Matthew Warren said the passage marked the beginning of a shift in the way Australians would generate, deliver and consume electricity.

“This is a historic day for Australia and for the energy sector more broadly. Not only does it signal to the world that our country is committed to playing its part in reducing its greenhouse gas emissions, it heralds a new dawn for Australian innovation in clean energy,” Mr Warren said.

“Our industry has been calling for the right policy environment and a carbon price is a crucial part of that.”

The establishment of the Australian Renewable Energy Agency (ARENA) and the $10 billion Clean Energy Finance Corporation as part of the package will give emerging technologies the boost they need to prove their potential as mainstream energy sources, Mr Warren said.

The clean energy legislation will provide an incentive for businesses and households to use energy more efficiently, he said, and emissions-intensive energy sources will have to pay for their pollution, allowing clean energy sources to compete on a level playing field.

“The clean energy sector is poised to unlock billions of dollars in investment that will provide employment for tens of thousands of people and shape Australia’s electricity market for decades to come,” Mr Warren said.

The Australian Coal Association (ACA) said the recently passed carbon price will handicap one of Australia’s largest exports at a time of great uncertainty. The ACA is seeking to have a number of issues with the carbon tax package addressed.

“The ACA supports action on climate change. However, the legislation passed today means a package of measures with fatal flaws becomes law,” the ACA stated.

“No other coal exporting country imposes a tax on fugitive emissions from coal mining. In doing so, the carbon tax will make Australia’s coal industry less competitive internationally, without delivering any environmental benefit by way of global emissions reduction.

“Not only has the coal industry been excluded from transitional assistance as an emissions-intensive, trade-exposed (EITE) industry, despite meeting the government’s own criteria, but the coal industry’s exclusion is enshrined in the legislation. Section 145 of the main bill permanently locks coal mining out of the transitional assistance arrangements, regardless of future market conditions or the outcome of any productivity commission reviews of the effectiveness and scope of the EITE arrangements.”

The ACA said that carbon capture and storage (CCS) has been shut out of more than $10 billion in funding, including via the $10 billion Clean Energy Finance Corporation.

“Treasury modelling of the Clean Energy Future package acknowledges the essential role of CCS in meeting Australia’s emissions reduction targets while underwriting the nation’s energy security and national competitiveness,” the ACA stated.

The association believes that a lack of involvement in CCS is inconsistent with the international recognition of the role of CCS by the International Energy Agency (IEA) and by international experts such as Dr Steven Chu, secretary of the US Department of Energy.

With the energy industry preparing itself for major structural change, Energy Source & Distribution looks at the views of government, associations and industry on the best way to prepare and implement the legislation.


 

Renewable sector project opportunity

The introduction of a carbon pricing mechanism (CPM) and the ongoing Renewable Energy Target (RET) will lead to significant increases in the share of renewables in the electricity generation mix, according to the Bureau of Resource and Energy Economics’ Major Electricity Generation Projects November 2011 report.

This investment will take time to come about, with only two major energy projects completed in the 12 months to October 2011, compared to 11 projects worth $3.13 billion in the previous year. Ten renewable projects are at an advanced stage of development. Of these, seven projects are wind-powered, representing 89 per cent of the announced capacity for advanced renewable electricity projects. Hydro-powered projects account for a further 7 per cent of planned capacity, and a solar thermal-powered project accounted for the remaining 4 per cent.

While electricity generated from renewable energy sources is expected to expand, the location of renewable energy resources in remote areas and the intermittent nature of many renewable energy sources will cause potential constraints.

“While these figures are encouraging, we still haven’t seen the actual investment on the ground in terms of the construction and operation of new plants in recent years that is going to be needed to meet demand,” TheSydney Morning Herald reported Federal Minister for Resources and Energy the Hon. Martin Ferguson as saying following the release of the report.

One company expected to increase the electricity component of future merchant revenues is renewable generation developer, owner and operator Infigen. Speaking at the company’s annual general meeting in November, managing director Miles George said Infigen will also benefit from the RET.

“A REC (Renewable Energy Certificate) supply shortage is currently expected beyond 2014. At that time the current REC surplus will be exhausted, whilst obligations under the scheme will begin to increase more rapidly. The current lack of renewable energy capacity investment is expected to flow through to supply shortages at that time,” Mr George said.

He also said the company had a number of key competitive advantages, including an established operating base with efficient scale, no fuel price exposure, and an ability to enter into long-term contracts with firm pricing.

The company has an advanced pipeline of development assets providing scope to capture early-mover advantages.

“Stability in RET policy remains critical to underpin investment and contracting decision-making for the medium and long term,” Mr Miles said.

“We were pleased to hear Prime Minister Julia Gillard reiterate the Government’s commitment to the RET when she visited our Capital wind farm earlier this year. The Opposition Leader Tony Abbott last week confirmed that his party had no plans to change the bi-partisan target. Infigen remains well placed to benefit from opportunities to meet the mandated demand for annual increments in the uptake of renewable energy.”

To meet the 2020 RET target, Infigen estimates that a five-fold increase in installed wind capacity is required. The company recently completed construction of the 48.3 MW Woodlawn wind farm in New South Wales, adjacent to their Capital wind farm.

They also recently received development planning consent for the 100 MW+ Capital 2 wind farm in the capital renewable energy precinct on the eastern side of Lake George, north of Bungendore. Construction of Capital 2 wind farm could improve economies of scale for Infigen’s operations in the area, thereby reducing operating costs on a per megawatt basis. This precinct also houses the site of their potential
50 MW solar generation project.

Mr Miles said the company expects to drive investment in up to 1000 MW of new installed capacity each year.

“We are firmly committed to delivering sustained operating performance. We will continue to invest in developing the organisational capability to ensure Infigen is well placed to build on its position as a leading specialist renewable energy business,” he said.

 


Carbon generators adapt to change

A high-level panel of CEOs from businesses significantly impacted by the recently introduced carbon price shared their methods for implementing the pricing arrangement in November.

AGL CEO Michael Fraser, Delta Electricity CEO Greg Everett, GE Australia CEO Steve Sargent and Santos CEO David Knox met during CarbonExpo on the Gold Coast, and were moderated by Sky News political editor David Speers in a discussion on their prepartions for the introduction of a carbon price and the implications for businesses and industry.

Mr Sargent opened the panel discussion by explaining GE Australia had approached the issue of climate change in 2004 from a pragmatic perspective as well as by looking for opportunity. GE repositioned itself strategically in response to a potential carbon price.

“You will see a lot of companies start to think a little more about it and go through the same process of mitigating risk and finding opportunities,” Mr Sargent said.

Mr Fraser said that AGL has focused on their energy services business to help customers cope with the introduction of a price on carbon, and

agreed that many new businesses that will soon come into existence in response to the legislation.

AGL made its first substantial investment in renewables in 2005 with Victorian hydro power and since then has become Australia’s largest investor in renewable energy, with many billions more to be invested in the coming decade.

“This legislation is key to unlocking that investment,” Mr Fraser said.

Mr Knox said a price on carbon was the best way to effect change on the market, but he first needed to see the regulations in full before he could pass judgment.

“We of course need certainty and we need to know the scheme is going to stick, it’s going to stay and it’s going to be in place and we absolutely need to see the regulations,” Mr Knox said.

Mr Everett told the $23 per tonne carbon price is too low to change market behaviour, and said the market should decide the price.

“I don’t think anyone is going to rush out and make investments at $23 a tonne,” he said.


 

The Clean Energy Future Package – A checklist for understanding its impacts

The long-term financial impacts of the passage through Commonwealth Parliament of the Clean Energy Future package are likely to be profound, with all businesses potentially affected. While most businesses do not produce material quantities of greenhouse gas emissions, nearly all businesses will experience increases in the costs of core input commodities that are greenhouse intensive. Changes to the relative economics of greenhouse intensive products such as electricity will result in both winners and losers.

In a recent article published in the international peer-reviewed journal Sustainability Accounting, Management and Policy, we established a ‘checklist’ for companies to use in assessing the impacts of a carbon price on their business. As the central feature of the Clean Energy Future policy package is the introduction of a carbon price, this checklist has significant application for Australian businesses.

Carbon pricing and economic theory

An emissions-trading scheme can be analysed using standard economic ‘partial equilibrium’ analysis. The most critical question requiring assessment is who bears the incidence of the tax equivalent (i.e. the cost of buying permits in a trading scheme). If the incidence lies with producers, rather than consumers, there will be a greater impact on profitability within the industry. If the incidence lies with consumers, prices will increase and ceteris paribus, there will be a greater impact on consumer standard of living.

This theoretical underpinning of our checklist is critical. Only a few hundred Australian businesses will have a ‘direct’ liability under the Clean Energy Future legislation. And of these few hundred, only a very small number will have a large direct liability. In fact, only 20 Australian companies that reported on emissions through the National Greenhouse and Energy Reporting (NGER) Act 2007 in 2008/2009 had Scope 1 emissions greater than five million tonnes. The total direct emissions from these 20 companies were more than 230 million tonnes or more than 40 per cent of Australia’s total emissions. It is clear that only a limited number of large companies would be materially and directly impacted by a carbon tax or emissions-trading scheme.

However, all businesses will be impacted because they use goods and services that resulted in the production of greenhouse gas emissions when they were created. The most obvious of these production inputs is electricity and gas.

As Table 1 demonstrates, the production of electricity alone produces more than half of the greenhouse gas emissions likely to be covered by the Clean Energy Future carbon price.

Establishing an emissions ‘footprint’

Currently, most publically reported GHG emissions data utilise the Scope 1 and Scope 2 emissions methodology. Scope 1 emissions are emissions produced directly by the company in producing its good or services. For example, a power generator produces Scope 1 emissions when it burns coal to create electricity. Scope 1 emissions are also often referred to as ‘direct liability’ emissions. Scope 2 emissions are those emissions associated with consuming energy that has ‘embedded emissions’ (including electricity, steam, heating or cooling). For example, Scope 2 emissions for a supermarket include the emissions associated with electricity used for lighting, heating and cooling. These emissions are classed as ‘indirect liability’ emissions. Together, Scope 1 and Scope 2 represent a gross estimate of the direct and readily identifiable indirect emissions, which would potentially incur a direct or indirect cost in an emissions trading environment. Importantly, this does not take into account the other costs that an entity may face through increases in input costs associated with commodities that are energy intensive. For example, a company that uses significant amounts of cement (an emissions intensive product) is likely to see significant increases in costs but may not have significant Scope 1 or Scope 2 emissions.

A checklist for analysing the impact of carbon pricing

In our article, we established the following checklist utilising the emission reporting and economic concepts articulated above:

1. What is the carbon price? As the carbon price is essentially the ‘tax’ being considered, it is necessary to outline assumptions in relation to this basic assumption.

2. What are the businesses’ Scope 1, Scope 2, supply footprint and equity emissions? Scope 1 and Scope 2 emissions will provide an estimate of the business’ direct liability (taxation or permit acquisition costs) and indirect liability (energy price increases) while equity emissions provides an assessment of the potential liability associated with equity investments. Supply footprint emissions allow efficiency comparisons of businesses within an industry (i.e. comparisons of the emission intensity of products and/or services).

3. What is the assumed rate of carbon pass through for energy products? An assessment of this variable will allow assumptions to be made in relation to the proportion of higher costs incurred by energy producers that will be passed through in energy procurement costs. For further information on this variable, see Nelson, Orton and Kelley, (2010), “The impacts of carbon pricing on deregulated wholesale electricity and gas markets”, AGL Applied Economic Research Working Paper No.20 (available at www.aglblog.com.au)

4. Are there technologies available that would reduce Scope 1 emissions? If new lower emitting technologies are available, the rate of pass through is likely to be significantly lower. In turn, this issue when considered in the energy sector will impact on the pass through of Scope 2-related costs for other businesses.

5. What is the domestic elasticity of demand for the product? An assumption made in relation to the domestic elasticity of demand for a product allows an estimate of the incidence of the carbon price (or tax equivalent) to be made in relation to consumers and producers.

6. Is the business import-export competing? Export-import competing businesses are generally price takers and as such the incidence of taxation is likely to almost solely sit with producers (unless competitor countries implement the same carbon pricing regime).

7. Will the business receive some form of compensation? Most emissions trading schemes propose some form of transitional assistance (such as the provision of free permits). The value and duration of such assistance needs to be considered in any analysis.

8. Does the business use carbon-intensive goods? While Scope 2 emissions provide a useful guide to the additional costs likely in relation to energy procurement, it is necessary to consider how the costs of other carbon-intensive input products (e.g. cement) may change for businesses that use significant quantities.

9. Does the business have any upside value? A company that has already invested in lower emitting production equipment will experience a cost advantage relative to its competitors. As prices rise to reflect the costs of its competitors, the company will increase its profit as revenues increase by more than costs. This needs to be considered in any analysis.

Analysing the impacts of the carbon-pricing mechanism, established as part of the Clean Energy Future package, on an individual business is not easy. It requires a range of emissions footprints to be calculated and a number of variables to be estimated. The checklist established in our paper provides companies with a simple way of navigating through this complexity.

The full analysis underpinning development of the checklist can be found in Nelson, Wood, Hunt and Thurbon (2011), Improving Australian greenhouse gas reporting and financial analysis of carbon risk associated with investments, Sustainability Accounting, Management and Policy Journal, Vol. 2 Iss: 1, pp.147 – 157.

 


The terrible teens – some challenges ahead for electricity networks

The start of a new decade in 2010 marked a period of turmoil for electricity networks, as an era of significant growth and investment in those networks translated into inevitable price outcomes, at the same time as household disposable incomes were being impacted by increases in housing costs and the Federal Government sought to introduce a tax on carbon emissions. The reasons for the increased investment and the value it has delivered, and will continue to deliver, have been lost in the clamour to blame someone for electricity price rises. The response from politicians and the media has been very predictable and, given that price rises appear to be here to stay, sets the scene for a very challenging decade ahead.

A key consideration, and driver for the focus on rising electricity prices, is the impact of housing costs. Data recently released by the Australian Bureau of Statistics (i) shows that the biggest increase in household weekly expenditure on goods and services between 2003-04 and 2009-10 was in housing costs (chart S4), and that the percentage of expenditure on housing costs for low- income households was well over double that of high income households (chart S3).

Which means that many households where incomes are comparatively low are doing it tough, therefore price increases for non discretionary, essential services such as electricity have a very real impact, despite the relatively low percentage of household expenditure which electricity (part of domestic fuel and power) makes up.

The impact of the carbon tax, combined with price increases attributable to the network component which are already factored into retail electricity prices due to decisions made as part of the regulatory process, together with increases which may arise as west coast gas prices translate to the east coast and electricity generation, means that the focus on electricity prices rises will continue for the rest of the decade.

One of the most significant challenges for electricity network companies flowing from the focus on the network component of electricity price rises is the rule-change proposal put forward by the AER, for consideration by the Australian Energy Market Commission (AEMC). The AER’s position, underpinning its proposal, is:

• there is significant information asymmetry: that is, the AER does not understand the network business or the information presented in the price-setting process;

• the price-setting process gives network companies an incentive to inflate their forecasts and the current rules give them the ability to do so;

• network companies take advantage of the rules and inflate their forecasts, then spend less than the forecasts and receive the incentives;

• the AER want the discretion to use their own forecasts and not rely at all on the forecasts provided by the network companies; and

• the AER seeks to change the process for determining the return on network investments (WACC)

If the rule-change proposal were to be adopted by the AEMC and the rules changed accordingly, the implications for network companies would be enormous.

The current rules were established via an extensive process involving consultation with industry and policy makers and numerous reviews such as those conducted by the Productivity Commission and the Export Infrastructure Taskforce and were designed to encourage efficient investment in essential infrastructure. The increases in investment in electricity infrastructure over the last five years reflects the need to respond to factors such as increasing demand, the need to replace ageing assets, and meeting the requirements for connection of renewable generation. It also may reflect under investment in essential infrastructure under the regulatory regime that existed before the adoption of the national regime, including the establishment of the AER.

The proposed changes would essentially see the AER ‘stand in the shoes’ of network companies and make its own determination of appropriate operating and capital expenditures. The risks associated with that degree of discretion and the lack of accountability for the resulting outcomes, with any impact potentially not being evident until years after the relevant investment decision, seem excessive.

A second challenge for electricity networks during the ‘terrible teens’ is dealing with the growing gap between average energy consumption and maximum peak demand. The existing gap means that electricity network owners must invest billions of dollars in infrastructure assets that are used for short periods of time, over a maximum elapsed which can be measured in hundreds of hours.

The resulting inefficient utilisation of those assets translates to additional costs across the total network, which ultimately contribute to price rises, adding more pressure to customers who are already facing financial hardship. It is also clearly contrary to efforts to improve the efficiency of electricity use, by means such as mandating the use of energy efficient light globes and energy ratings on appliances and changes to building codes.

Electricity network companies across Australia are engaged in activities to curb peak demand by a range of means, including direct control of electric hot water heating and direct control of air conditioners, with relevant incentives provided to customers to participate in those activities.

There is, however, no universally agreed strategy or series of activities targeting the peak-demand challenge. The solution, which requires customers to change their electricity consumption behaviour, lies in a combination of the introduction of interval meter, capable of measuring peak demand and communications enabled; an electricity pricing structure that incorporates a reflection of peak-demand cost drivers; provision of the means by which customers are able to respond to price signals; and a communications platform which links the necessary technology components and conveys the pricing signals.

Such a solution would enable greater customer choice as to how they use electricity and enable them to respond to pricing signals, thereby reducing their electricity costs (by shifting consumption from times of high prices to times when prices are lower) and potentially reducing their overall electricity consumption, contributing to a reduction in greenhouse gas emissions.

The technology to achieve that is available today, with electricity network companies conducting pilots and trials to test that technology and test customer responses, and the Energy Networks Association developing policy positions for input into a range of reviews, such as the AEMC’s Power of Choice – giving consumers options in the way they use electricity (ii). However, a universally agreed strategy or solution is many years away, as the results from pilots and trials provide clear messages capable of guiding decision making.

A third challenge is adapting electricity networks to deal with the drive to reduce carbon emissions in accordance with the Federal Government’s emissions-reductions targets. An outcome of that drive is the dramatic increase in the number of domestic photovoltaic installations, which carries a corresponding increased workload for electricity company employees and contractors who provide connection services and meter installations, with demand often exceeding the availability of those specialist resources.

In addition, the increased level of photovoltaic installations places demands on the physical electricity infrastructure that may exceed its capabilities (given its original design characteristics – deliver energy in one direction) and require additional monitoring and control, or in many cases upgrading of the network to accommodate the installation.

And looming large are the potential impacts, both negative and positive, of increased take up of electric vehicles.

The elements of the third challenge have a common link with the elements of the second challenge – the need for a communications platform which enables the monitoring and control of parts of the network, the low-voltage network, which have in the past not been monitored or controlled by remote means.

Linking the second and third challenges to the first is the need for additional investment in the technology which will be required to enable the existing electricity infrastructure and associated systems and interactions to reduce peak demand, provide customer choice and accommodate a growing demand for local, renewable generation.

That investment could be expected to be placed in jeopardy if it is seen by potential investors as too risky, and, given that electricity network companies are regulated monopolies, the electricity rules and their application and interpretation by the AER set the investment climate. The AEMC’s judgement, as it considers the AER’s rule change proposal, can be expected to have a major impact on future investment in electricity networks and the ability of their owners to meet the challenges of the terrible teens.

(i) 2009/10 Household Expenditure Survey

(ii) Issues Paper, July 2011.


 

Everyone pays for uncertainty

As I write this the Federal Government’s clean energy package has just been passed by the Senate with support from Green Senators, having earlier negotiated a more difficult path through the House of Representatives with independent backing. In some ways this is a remarkable outcome, given the then majority Kevin Rudd led Government was unable to have its Carbon Pollution Reduction Scheme (CPRS) passed in 2010 in more propitious economic circumstances.

Amongst the members of the Energy Retailers Association of Australia (ERAA) there are mixed views about the Clean Energy Future package. While most companies support the notion of a market-based approach to pricing carbon, there remain a number of concerns about the actual implementation of the current package, particularly given we are only eight months away from the proposed 1 July 2012 start date.

While it could be said the debate about pricing carbon has been going on for a number of years and the major retailers and generators are as well prepared as any companies, the fact is that necessary economic reforms that should accompany carbon pricing have not yet been implemented.

Moreover given the stated position of the Federal Coalition, currently leading easily in opinion polls, is to repeal the Clean Energy Future legislation, the bipartisanship that gives investors the confidence to make long-term decisions on investment is lacking. In the short term this makes it quite difficult for retailers and generators to know how to price forward-energy contracts over coming years. With uncertainty comes a risk premium everyone has to pay.

Chief amongst the incomplete energy reforms is the phasing out of retail price regulation in the states and territories, an essential pre-condition for the pass through of the costs of the Clean Energy Future package. While governments may claim that the Australian Energy Market Agreement (AEMA) has been amended to ensure pass through, in practice this lies entirely in the hands of state governments and regulators, except in the deregulated state of Victoria.

The apparent ease with which South Australia and the Australian Capital Territory (ACT) were able to ignore the recommendations of the Australian Energy Markets Commission (AEMC) to phase out retail price regulation after reviews of effective competition in both jurisdictions underlines the reasons for retailer nervousness. While price regulation can in the right circumstances still ensure cost reflective pricing and competition, it is an added risk in the uncertain environment of the carbon tax.

Added to this is the apparent hostility of the Coalition states to carbon pricing and the examples of Queensland and Western Australia, where retail energy pricing has become a political football. Earlier this year the Barnett Government rejected a recommendation from its independent Office of Energy to implement a pricing path for retail gas prices on the basis that it was too high for community tolerance. Such examples of state-based political interference in pricing decisions set worrying precedents for all retailers.

While pass through remains the major concern for all retailers, there are also concerns about a blow-out in hardship and debt arising from the Clean Energy Package. In recent years we have seen price rises in a number of states driven largely by network investment or poorly designed small-scale renewable energy schemes, in which the stand out was the NSW Solar Bonus Scheme.

These have helped to undermine community support and tolerance for further price rises and made energy hardship a greater focus of regulators. Price rises to date have had little to do with wholesale energy costs, which will be driven upwards by the Clean Energy Package as Australia’s largely coal-fired generation fleet meets its carbon obligations. The Federal Government has sought to offset these rises with tax cuts and pension increases for impacted consumers using the carbon tax revenue.

The concern for retailers is that this compensation is not delivered through energy concessions linked to the higher bills the way many state-based policies are. As such, there is a real risk that consumers will have spent their carbon tax compensation delivered by fortnightly tax cuts and pension increases by the time the higher electricity and gas bills arrive. As such retailers could face a real risk of higher consumer debt and greater pressure on hardship policies.

While pass through and higher debt remain retailers’ greatest concerns, other issues also have the potential to impact the retail market. Energy retailers will have to purchase the carbon permits for the emissions of small gas customers which could put a strain on cash flow and discourage gas competition, especially in a state like Victoria where there are active smaller retailers, and where providing gas or duel fuel contracts is critical to competitiveness.

An additional consideration is what the Clean Energy Future Package will mean for GreenPower, the marketing of which will become more complex when energy prices already include a carbon component, and for which community willingness to pay a higher premium must be in doubt. The confused state of custodianship from state and territory jurisdictions puts GreenPower in greater jeopardy.

Further concerns relate to the plans of the Federal Government, and potentially the states, to require retailers to provide more itemised information on bills for customers. In the case of the Federal Government there are active proposals for retailers to include inserts in the final quarter bills of 2012 which provide information on the impact of the carbon tax on bills, the estimation and wording of which will be quite complex. This comes on top of requirements within the National Energy Customer Framework (NECF) for retailers to engage in bill benchmarking, something that will strain retailer billing systems and add to costs, for questionable benefit in terms of likely consumer response.

On the whole, the collective retailer view of the Clean Energy Package is one that recognises a market-based approach to pricing carbon is probably the way to go, but which in practical terms is clouded by a range of implementation concerns about the direction and operation of current policies. Until these concerns can be readily addressed, the ERAA will not be seeking to endorse or oppose the Clean Energy Package. Our core objective is to ensure that retailers do not face greater business risks as a result of the Clean Energy Package.


 

Planning the plant of the future

By Scott Clenaghan, GE Energy Industrial Solutions Sales Leader, Australia and New Zealand.

With carbon tax legislation now passed, businesses, especially those in the energy sector, face commercial pressures to become more efficient. As Australia and the rest of the world transitions to a low-carbon future, energy companies need to understand what efficiencies they need to harness. Amidst rising operational costs, the implementation of effective equipment maintenance strategies is set to have the greatest impact on the efficiency and reliability of Australia’s energy infrastructure in the coming years.

One of the most effective ways to reduce the carbon footprint of a plant is to ensure that all machinery is operating at its optimum level. If machinery is out of sync, not working in the most efficient way or damaged, not only will operation costs be higher than normal, so will energy costs.

At its most basic level, equipment maintenance is the key element to getting the most out of industrial plants. Getting the balance right in system maintenance can positively affect plant efficiency and bottom line. In order to strike this balance, there are a number of factors operators must consider if they are to ensure the longevity of the equipment in their plant.

Employing an effective maintenance strategy

Motors are the driving force behind production systems across a wide variety of industry sectors – from manufacturing to mining, oil and gas, and water supply, so it is critical that plant managers select a maintenance strategy that will ensure decreased downtime of critical motor systems. Decreasing downtime will reduce maintenance costs meaning that increased savings can be pushed back into wider operations.

At present, there are a number of different maintenance strategies that are being deployed by plant managers across Australia. These include:

• Run to failure/reactive maintenance: Assets are fixed when they fail, but plant managers do not perform regularly scheduled maintenance. Plants that implement this strategy forfeit capital and spend considerable time and effort having periodic maintenance and equipment removal.

• Preventive maintenance:
Plants schedule planned maintenance actions aimed at the prevention of breakdowns and failures. This approach does not consider specific operating conditions and can lead to unnecessary maintenance costs, or the under-maintenance of assets.

• Predictive:
Plants monitor the condition of assets on an ongoing basis to forecast future performance and predict when maintenance should be scheduled.

According to a recent US Department of Energy study, 55 per cent of those responsible for industrial plant maintenance admitted to characterising their program as “reactive” and 31 per cent as “preventive” only (i). It’s a familiar story. We’re seeing this here in Australia as well. We often see that the tipping point to predictive maintenance is the costly breakdown of motors, pumps and related systems. But it doesn’t have to be this way.

The step towards a predictive maintenance strategy

Plant managers that practice a predictive maintenance strategy benefit from extended equipment life expectancy and lower the probability of unplanned outages. When you consider that every hour of unplanned downtime cost energy plant operators $US100,000(ii), the importance cannot be ignored. Predictive, rather than just reactive or preventive maintenance of existing equipment can save plant operators money in the long term, and also help prevent the development of serious hazards.

Against this backdrop, through our ongoing research and development efforts and industry-wide engineering training programs, we have identified four key areas for improvement that plant operators can make to ensure long-term efficiency of the plant:

1. Create a system that captures repetitive failures so that appropriate corrective changes can be made. Keep up to date records of all your maintenance programs as well as root-cause-analysis of any maintenance performed.

2. Conduct both preventive and predictive maintenance on your systems. Regularly take non-intrusive measurements – such as vibration analysis, infrared (IR) analysis and insulation readings – and compare these measurements so that equipment failure can be predicted.

3. Deploy a repair/replace policy. If a motor fails, the maintenance manager must decide whether the motor should be replaced or rewound.

4. Power-quality problems can wreak havoc on high-tech controls and electrical devices such as transformers, switchgear, switchboards, power panels, motor control centres and variable frequency drive systems. Consider utilising a power system study to maintain (and upgrade if necessary) your power-delivery infrastructure.

Failed or damaged assets can cost hundreds of thousands of dollars a day in lost production revenue and increased operating and maintenance expenses. Converting to a predictive maintenance strategy will give plant managers greater control. In order to serve a low carbon future, it is essential the wider industry works together to find new ways to minimize the risk of equipment failure, operate more efficiently and extend the life of equipment. Importantly, reducing risk now will increase both efficiencies and profits. As one year comes to an end and another one begins, plant operators must start to evaluate the strategies and processes they have in place to ensure the long term reliability of Australians’ vital energy infrastructure. In doing so, not only will efficiencies and profits increase but we’ll be helping the wider industry realize our goal of a low carbon future.

(i) http://eere.pnnl.gov/femp/publications/O&MBestPractices.pdf

(ii) Industrial Productivity Training Manual, 1996 Annual IAC Directors’ Meeting, Rutgers University, U.S. Department of Energy Office of Industrial Technologie