The AER is seeking rule changes to enable it to more closely scrutinise the efficiency of investment in power networks, but as Edwin O’Young of Port Jackson Partners has demonstrated, this is by no means the only area of pressure on prices.

Speaking at the ‘Powering Australia 2011’ conference in Melbourne last week, O’Young said many factors will continue to drive retail electricity prices upwards over the next six years following increases of more than 35 per cent in inflation-adjusted terms over the past four.

Many of these cost increases are unavoidable and should be reflected in consumer bills, he said, acknowledging that it is of great importance to ensure that they do not increase more than is necessary – the same point being made by AER chairman Andrew Reeves.

O’Young says that, after 15 years of relative power price stability, average electricity prices have risen from around 15 cents per kilowatt hour in 2007 to 21 cents this year. This trend applies in particular to Sydney, Melbourne and Brisbane, the three main load centres.

The breakdown of the bill for New South Wales, for example, shows a marginal increase (0.3 cents) for wholesale power supply, a big rise (2.2 cents) for networks, a substantial shift (0.7 cents) in mandatory green power costs and a doubling (up 1.2 cents) of retailer operating costs and customer acquisition costs. This adds up to a rise from 16 cents per kWh in 2007 to 20.4 cents today.

What lies ahead, according to O’Young, is a very large increase in the wholesale electricity charge (rising 7.5 cents), a big jump in network charges (7.2 cents), a continuing increase in renewables costs (up another 0.1 cents) and a further rise in retailer costs and margins (up another 1.1 cents) to deliver an end-user bill of 36.3 cents per kWh in 2017.

He attributes the wholesale power rises to increasing coal prices as contracts for power stations come up for renewal, increasing gas prices as the east coast industry moves in to export mode, the impact of the Gillard government’s carbon price on the dominant fossil-fuelled generators, rising capital construction costs for new power stations and higher volatility in the competitive east market with a potential increase in the power price cap from today’s $12,500 per megawatt hour to $16,000.

O’Young points to the continuing huge rises in Chinese coal demand – forecast to increase by 60 million tonnes a year to 2020 – as well as high demand from India as important factors in new local fuel contracts. “While this is good news for our coal exporters, it is not good news for domestic power prices,” he warned.

With construction of new coal-fired power stations virtually impossible in the present environment and with gas expected to be the main fuel for new generation this decade, O’Young sees the east coast LNG developments driving domestic prices far beyond their present levels. “The current experience of independent power producers in Queensland,” he says,”is that they are simply unable to secure gas contracts for much more than 2-3 years and (seller) price expectations remain significantly above historic levels.”

A rise in gas prices of $4 per gigajoule, he points out, leads to an increase in generation costs of $28 per megawatt hour. “That is an increase in wholesale electricity costs of 45 per cent before a carbon price.”

O’Young says a $27 per tonne carbon price will add $26 per MWh to coal generation costs and around $14 to gas-fired power production.

To this he adds an increase of about 12 per cent in renewable energy charges over the next six years, but warns that if the federal government’s small-scale renewable energy scheme (promoting solar power) continues to expand at anywhere near the levels we are seeing today, the cost of retailers’ meeting their RET liabilities could be much higher.

The headache for politicians, federal and state, lies in O’Young’s summary of the situation: “Many things are unavoidable, including network costs, which are locked to 2015, and fuel costs that will rise as coal and gas prices are linked to export markets – and as the carbon price is factored in.”

Keith Orchison, director of consultancy Coolibah Pty Ltd and editor of Powering Australia yearbook, was chief executive of two national energy associations from 1980 to 2003. He was made a Member of the Order of Australia for services to the energy industry in 2004.

Original source (Business Spectator) Click here.

The first major meeting of the clean energy industry since the announcement of the Federal Government’s carbon pricing plan will take place at EcoGen 2011, to be held at the Brisbane Convention and Exhibition Centre from 5–7 September.

Approximately 500 Australian businesses will be required to pay for their carbon emissions under the plan, and much of the revenue collected will support investment in research, project development and employment growth in the solar sector.

Elements of the new legislation package of particular relevance to the sector include:

• The establishment of an Australian Renewable Energy Agency (ARENA) with responsibility for managing $3.2 billion in existing Federal Government funding for solar power technologies and initiatives to bring them to market, including the Solar Flagships Program and the Australian Solar Institute
• The commencement of a Clean Energy Finance Corporation (CEFC) to invest $10 billion in businesses launching clean energy projects, and in transforming existing manufacturers to meet demand for photovoltaic (PV) panels and other solar inputs
• A $40 million Remote Indigenous Power Program to connect remote Indigenous communities to solar power
• The expansion of the Australian Energy Market Operator’s future development of the electricity grid to prepare for greater integration with solar power.

The Australian Photovoltaic Association has said that the CEFC and ARENA will be of particular assistance for large‐scale PV project deployment, and that theRemote Indigenous Power Program among other initiatives will assist the off‐grid PV market.

Australian Solar Energy Society Chief Executive John Grimes said “While the details [of the plan] are still being worked out, it is likely big solar companies will be able to access loan guarantees and equity investments from the CEFC.”

“Big solar is a big winner in the Clean Energy Future Plan,” Mr Grimes said.

14 July 2011

Original source click here.

This week the new Australian Government will sit down again with various society representatives to restart the discussion on emissions policy, with a particular focus on the delivery of a carbon price signal into the economy.

These meetings will take place over the next year as a number of policy ideas are considered, but given we are at the start of the process this presents an opportunity to look again at the options. Of course a carbon price is one part of a broader policy framework, which needs to cover a number of very different sectors and also respond to commercial realities such as the development and demonstration of emerging technologies. Whatever the result, the policy approach adopted needs to trigger the implementation of emission reduction projects throughout the economy, with the lowest cost result being delivered by doing the most attractive projects first and progressively moving from left to right across the abatement curve.

This isn’t the first time Australia has visited the climate policy issue, but it is clear that the subject remains high on the national agenda, not just because of the pressing nature of the underlying problem but also, somewhat ironically, because a number of countries in the region, both trade competitors and customers, are starting to move forward with new policy ideas. Although there is no immediate threat, Australia runs the risk of longer term price exposure simply because of the actions of others. Inaction is therefore not an option.

The goal of a carbon price is to create a change in the economy, whereby the market begins to differentiate between goods and services on the basis of their carbon footprint. The carbon price, initially experienced by the emitter or fuel provider (e.g. by paying a tax or purchasing allowances from the government), is passed through to the consumers of the products provided. The result is that the cost of most goods and services will rise, but a new cost ranking will emerge which in turn will change the purchasing patterns of consumers. Products with a high carbon footprint will be less competitive, either forcing their removal from the market or driving the manufacturer to invest in projects to lower the footprint. The extra costs borne by the consumer need to be offset – this would be done by the government recycling the funds its raises from the pricing mechanism back to the consumer through some other mechanism, e.g. a personal tax reduction, a decrease in sales tax / VAT / GST etc..

In terms of the carbon price itself, there are really only four direct options:

1. A cap-and-trade system. This is the approach now operating in the power and industrial sectors in the EU. By design it delivers a specific environmental outcome (through the overall cap) and does so at the lowest overall cost to the economy by driving participants to progressively implement projects from left to right across the abatement curve. Once mature, allowances are typically auctioned by the government into the market with the funds being recycled back to the consumers purchasing the goods and services from the sectors covered by the system. Early on, as the economy begins adjusting to the carbon pricing mechanism, the government may allocate some or all of the allowances for free.
2. A carbon tax. This operates in much the same way as a cap-and-trade approach, although is arguably less efficient in delivering a clear environmental outcome. There is no cap. But it does establish the new capital flow through the economy and does force price differentiation on the basis of relative carbon footprints and market response.
3. A baseline-and-credit approach. In this approach the government establishes a baseline emissions for each sector on a CO2/unit of production basis. The participants can earn credits by exceeding the baseline or have to surrender credits if they fall short. The credits are tradeable and can be banked as in the cap-and-trade approach. However, there are a number of drawbacks with such an approach;
   1. The environmental outcome in terms of absolute emissions is uncertain as it depends on the level of production.
   2. It is complex to manage as it requires accurate benchmarking across many different sectors. Because of the trade of credits, benchmarks should also represent an equivalent effort when comparing sectors.
   3. With credits only issued after a given period of emissions, forward trade becomes very limited. The resulting market lacks liquidity which in turn means poor price discovery.

   The approach doesn’t set up the same flow through the economy as illustrated above. One reason is that there is no immediate constraint on emissions as production increases, which can mean a weak price signal. There is also no net change in the cost of goods and services, but only a limited redistribution around a mean. It is unlikely that whole sectors will lose market share (e.g. cement against some other building product) as each sector really only competes with its own benchmark. As such, the market plays much less of a role in driving change.

4. A project mechanism. This is operating today in many developing countries as they use the carbon price opportunity delivered through the CDM to start the process of reducing emissions through targeted projects. However, it is not a mechanism to decarbonise the economy on a large scale, with say the national government operating as the credit purchaser. It effectively reverses the capital flow shown above. The government buys from the emitters, which means it must raise taxes to extract this money from the consumer. The consumer might get some of this back through a lower cost of goods and services as efficiency should have increased as a result of the projects but it means that the market does not determine the way forward – rather the government does through its selection of projects to fund. It will also be a major exercise for the government to establish the necessary evaluation boards to assess projects etc. Finally, this approach will result in a somewhat random attack on the abatement curve, rather than the comprehensive and ordered attack that a carbon price, ideally via cap-and-trade, would deliver.

There is also the indirect approach, in other words creating an implicit carbon price within certain sectors of the economy by implementing a regulation of some kind. There is huge scope here, but each regulation will typically target a specific point on the abatement curve, rather than the more ordered left to right approach that delivers a lowest cost outcome. Examples include low carbon fuel standards, efficiency standards, renewable energy requirements, emission performance standards and so on. However, it is well suited to some sectors where a direct response to a carbon price may be limited.

A particular disadvantage of this approach is that it is often done in tandem with a direct carbon price mechanism, such as cap-and-trade, for example the renewable energy standard in the EU that operates in the same space as the emissions trading system (ETS). The two are not really compatible in that the renewables requirement results in certain projects to taking place that are further up the carbon abatement curve than would otherwise be the case with the ETS acting on its own. This results in two outcomes – it forces the carbon price to a lower level than it would normally be and it drives up the total cost of the solution for the economy as a whole.

In the wake of a deep recession and in the midst of a tough political environment, governments without comprehensive climate policy may well look to a variety of proxy approaches to deliver emission reductions across the economy. These will certainly deliver something, but matching the efficiency and order imposed by establishing a very market responsive approach will be difficult. It will also cost the economy more than is necessary, a difficult route to justify in the current global economic conditions.

Original source: The Energy Collective