Issue 93, January 2013

Welcome to the first issue of the newsletter for 2013, writes Keith Orchison. If one calls 2012 a huge year for energy supply, how do you describe 2013?

Coping with heat

The Electrical Trades Union NSW has challenged politicians who talked of power network “gold plating” to repeat the jibe after peak demand in Greater Sydney and the rest of the State reached 13,051 MW on 8 January. The ETU says reductions in network investment and reliability standards “would mean future extreme heat days could be very different.”

Electricity demand in NSW on one of the hottest day for years reached 10,000 MW at 9am and climbed as the temperature pushed over 42 degrees in mid-afternoon, then stayed high until the early hours of the next morning. The record remains 14,820 MW on 3 February 2011, with the 2013 peak benefitting from industry and tertiary institutions being on holiday.

Curbing peaks

Given record temperatures across Australia this summer, the implementation of more demand-side management in the east coast electricity market (NEM) to alleviate system pressures and mitigate wholesale price spikes ought to be high on this year’s energy reform agenda, say carbon market analysts RepuTex.

They point out that it will take around four years to implement the price-based wholesale market demand response to which federal and State governments have given in-principle support. “The key to maximising the economic benefits from demand response measures lies in building into the market incentives for the sale and purchase of load reductions.”

‘No doubt’

Shadow environment minister Greg Hunt says the Coalition will move to scrap the carbon price within six months of winning office. “There is no doubt (about this),” he asserts. “It can be done quickly and painlessly.”

Hunt says legislation to abolish the tax will be introduced in the first sitting week of a new parliament.

Put off

Publication of the Australian Energy Market Commission report on power prices over the next three years, due to have appeared in late December, has been postponed. The rule-maker and chief adviser to energy ministers says the report will now be released early in 2013.

It says issues have arisen following initial analysis of network pricing methodologies. Some jurisdictions have recently changed the methodologies used to determine wholesale cost allowances.

Off and on

While Energy Australia has brought back a 370 MW unit at Yallourn power station, shut since mid-2012, as Victorian demand rises it has also had Delta Electricity (with which it has a gen-trader agreement) prepare to shut one of the two 500 MW plants at Wallerawang near Lithgow in the face of over-supply in the NSW market. The unit is to be taken off line in mid-January and is expected to remain mothballed for the remainder of 2013.


New projections

The federal government’s Bureau of Resources & Energy Economics has cut its projection of grid-connected electricity generation in Australia for the ‘Thirties. In a new edition of its power outlook, BREE forecasts that production in 2034-35 will reach 324 terawatt hours – 24 TWh less than its initial estimate published in late 2011.

The new forecast is lower even that BREE’s original modelling for production under a scenario of high gas prices (340 TWh).

The agency’s modelling assumes that rooftop solar PV production (not included in these numbers) will rise six-fold to 18 TWh in 2034-35.

(Rooftop PV generation is not traded through the east coast market. Instead, the installation owner receives a reduction in their energy bills. The market operator measures the contribution of rooftop PV generation as a reduction in energy demand on the basis that it cuts the community’s energy needs from the national grid.)

In the new outlook, BREE has slashed ‘Thirties generation from Victoria – down from 69 TWh to 40 TWh – while expecting to see a large increase in Tasmania (up from 15 TWh to 22 TWh).

It expects to see the same output in New South Wales as previously predicted (110 TWh), while Queensland will be higher (up by 6 TWh to 82 TWh) and South Australia marginally lower (down to 26 TWh).

The agency also now predicts Western Australia’s mid-Thirties generation will be lower than initially projected – down 5 TWh to 41 TWh.

Green boost

BREE has changed its tune over less than two years on the long-term outlook for renewable energy generation.

Its initial projection was for renewables to account for 84 TWh of power production in 2034-35.

Now it is asserting that green generation will reach 130 TWh on the back of large increases in wind power (up from 49 TWh to 64 TWh in 2034-35), solar power (up from an initial 4 TWh to 25 TWh) and geothermal energy (up from 14 to 17 TWh). It also expects hydro-electric generation to rise by 4 TWh, reaching 17 TWh annually just over two decades from now.

Turnaround explained

BREE chose to focus on 2049-50 in its media statement announcing the new projections, but most analysts (other than those with a strong yen for green power) would dismiss this as a bridge (or two) too far – the equivalent of trying to forecast electricity supply developments in 2013 from the vantage point of 1976.

On the other hand, BREE’s 2034-35 modelling is an horizon that today’s policymakers, regulators and their advisers, as well as power suppliers, need to consider carefully, given its implications for investment in the ‘Twenties.

The modelling’s implications for NSW, for example, are that the State will need a substantial increase in transmission capacity to enable it to export power to Victoria in particular.

As BREE sees it, the competitiveness of Victoria’s brown coal generation will diminish following the introduction of carbon pricing and as a result of a fall in the price of renewable technologies, especially solar energy.

“Unless Victoria invests in the development of its own low-emission generation,” warns the agency, “it is projected to become more dependent on other States.”

BREE also believes that the market share of black coal generation will fall by an average of 2.2 per cent per year to the middle of the century.

The longer-term future of coal, it adds, is heavily dependent on developments in carbon capture and storage. It sees coal and gas-fired capacity fitted with CCS coming online from the mid-2030s.

BREE says that large-scale solar photovoltaic technology will be the lowest-cost source of power – in a policy environment with a cost on carbon – by the mid-2030s.

BREE sees use of gas for generation rising beyond its 2011 projections despite current forecasts of much higher prices for the fuel. It now foreshadows that gas generation will reach 85 TWh in 2034-35 versus 74 TWh initially forecast.

Biggest loser

Coal generation takes a battering in the new BREE outlook. Two years ago the federal agency said it expected to see black coal plants contributing 137 TWh in 2034-25 – its projection now is 100 TWh. Brown coal does much worse. BREE forecast in 2011 that the sector would still be producing 40 TWh a year in 2034-35. Now it projects only five TWh.

Gas outlook

Michael Fraser, CEO of AGL Energy, Frank Calabria, CEO energy markets of Origin Energy, and James Baulderstone, Santos vice-president, eastern Australia, will be keynote speakers at the “Australian Domestic Gas Outlook 2013” conference to be held in Sydney on 10-11 April.

David Byers, CEO of the Australian Petroleum Production & Exploration Association, and Paul Balfe, executive director of ACIL Tasman, will be among other leading speakers.

Government presenters will include Chris Hartcher, the NSW Energy Minister, and Mark McArdle, Queensland Minister for Energy & Water Supply, with Ian Macfarlane, the federal shadow minister for resources and energy, presenting the Coalition’s views on gas as a transition fuel for electricity supply and on the implications for gas markets of scrapping the carbon tax.

Tony Wood, energy program director of the Grattan Institute, will speak on what could drive further change in the gas market.

LNG impact

The Australian Energy Market Operator expects that LNG exports based around Gladstone will have a significant impact on the east coast market.

AEMO’s long-term gas review, issued in mid-December, warns that, if possible reserves are not developed in a timely way, potential supply shortfalls to both the export and domestic markets may be seen mid-decade.

The report says eastern and south-eastern Australia have gas fields currently in production that are reaching the end of their economic life, existing long-term domestic gas supply contracts nearing expiry and LNG exports expected to start in 2014.

AEMO warns that forecast domestic gas demand for a number of proposed large industrial projects currently exceeds the capacity of the pipelines to supply gas in Gladstone from 2013.

The Australian Energy Regulator, in its annual review of the east coast markets, says that AEMO’s report shows a 15 per cent reduction in reserve development could cause supply shortfalls to the LNG export and domestic markets from 2016.

“While a shortfall for LNG contract obligations could be alleviated by diverting Cooper Basin gas from the domestic market,” says AER,  “this diversion would likely affect the New South Wales domestic market.

“This scenario would present opportunities to further develop CSG reserves in New South Wales (in the Gunnedah, Gloucester and Sydney basins) and expand gas pipeline capacity to transport gas to demand centres.”

The AEMO report also shows that no new combined cycle gas turbine (CCGT) installations are required for at least a decade because of lower electricity demand growth, and competing investment in renewable generation to meet the mandated 2020 target. 

CCGT will require a higher carbon price and lower gas prices to compete with other generation sources, AEMO says. However, it projects an ongoing need for gas peaking generation during periods of high electricity demand.

Shelving OCGT

Tough market conditions have seen Energy Australia follow AGL Energy in shelving large gas-fired power station developments.

After AGL decided in October not to proceed with the first stage of its 1,000 MW Dalton peaking project near Gunning in NSW, Energy Australia has postponed development of a similar-sized generator in the Latrobe Valley at its Yallourn site.

The Yallourn plant was initially intended to be baseload to replace the brown coal units on the site, but more recently was envisaged as a peaking operation of between 600 and 900 MW.

However, low wholesale market prices and the continuing depressed outlook for south-eastern Australian power consumption have seen consideration of the Yallourn development put off until “much later in the decade,” according to Energy Australia.

“We will continue to monitor the market and, if there are significant improvements, we will review this decision,” says Mark Collette, group executive manager energy markets.

The announcement sparked a call from the Gippsland Trade & Labor Council for the re-establishment of the State Electricity Commission of Victoria. Energy production needed to be kept in the State, it said.

Meanwhile AGL says that it expects the 242 MW Diamantina power station near Mt Queensland to be fully operational in the first half of next year. The $570 million project is a joint venture with APA Group.

Changing pattern

The Australian Energy Regulator reports that, in the 10 years to June 2012, electricity generation businesses in eastern Australia invested in 4700 MW of gas powered generation compared with 750 MW of coal capacity. Kogan Creek power station in Queensland was the only major new investment in coal-fired generation in this period, it says, apparently overlooking upgrades to several existing coal generation units.

AER also points to more than 3000 MW of coal plant being shut down or periodically offline during the 2011-12, not including Victoria’s 1,450 MW Yallourn power station – which operated below capacity during the past winter  following a flood problem.

Record lows

The Australian Energy Regulator says that, after easing in 2010−11, spot electricity prices in the east coast wholesale market fell to near record lows in 2011−12 before the introduction of carbon pricing.

The AER reports that the power spot price in the east coast market exceeded $300 per MWh on 65 occasion and exceeded $5,000 per MWh only once—the lowest incidence since the commencement of the “NEM.”

It says that factors contributing to lower spot prices included electricity demand falling by 2.5 per cent in 2011−12, “continuing a declining trend since 2007−08.”
The situation, it adds, also reflected the impact of flatter economic conditions on commercial and industrial demand; the increasing use of rooftop solar generation; and customers’ adoption of energy efficiency measures such as solar water heating (partly in response to jurisdictional energy efficiency schemes).

“Additionally, consecutive summers of below average temperatures capped peak demand by reducing the use of air conditioners.”

The AER also notes that flatter forecasts of future energy use and peak demand growth, combined with further expected growth in renewable generation, are delaying the need for new investment in baseload and peaking capacity.  It says revised forecasts in 2012 deferred new investment requirements by at least four years in all “NEM” regions compared with projections in 2011.

Tough gig

The difficulties of making even short term forecasts of electricity demand are highlighted in a report prepared by the Australian Energy Market Operator for the Australian Energy Market Commission’s reliability panel.

The review shows that the energy forecast for 2011-12 for NSW, the largest east coast market sub-region, was out by 5.3 per cent or 3,824 GWh with the 2011-12 summer peak falling 1,686 MW below expectations.

In Queensland the forecast undershot by eight per cent or 3,922 GWh with the peak falling short by 1,297 MW.

In Victoria, the difference was 4,909 GWh and the peak 503 MW below expectations.

AEMO attributes the differences against forecasts – totalling more than 14,300 GWh across all east coast States – to three main causes: (1) structural changes in the economy, including the contraction of manufacturing, in part due to the high Australian dollar; (2) changing consumer demand patterns, reflecting responses to high power bills; and (3) the uptake of rooftop solar PV systems.

The operator says it is continuing to refine the forecasting process, but warns that accuracy is limited by uncertainties relating to the economic outlook, electricity prices, structural changes in the economy (“with some sectors behaving very differently to others”) and policy assumptions.

Ray of light

The Energy Networks Association says cyclical investment by its members in Queensland and New South Wales has peaked.

As well, says ENA, as capital markets recover from the global financial crisis, the cost of long-term debt is expected to fall.

The association claims that adjustments to reliability standards in Queensland are allowing net businesses to find cheaper ways to deliver power – while in New South Wales customers can expect “no real increase” in network costs over the next six years.

Moving in cycles
In its 2012 annual review of the energy markets, released late in December, the Australian Energy Regulator says determinations for the 2009-14 regulatory cycle are expected to see networks revenues rise (in real terms) by 44 per cent compared with the previous five-year period, while investment rises by 27 per cent in transmission and 60 per cent in distribution – and operating and maintenance costs increase by 48 per cent in transmission and 28 per cent in distribution.

The regulator predicts that power network charges will plateau in 2013 and throughout the remaining years of current regulatory determinations, particularly for customers in NSW, Queensland and South Australia.

Charges for some NSW networks are forecast to fall in real terms
in 2013−14.

Additionally, says the AER, its new decisions and draft decisions made in 2012 reflect a significant shift in cost drivers that will ease pressure on network charges in the future. “In particular, forecast industrial and residential energy use, including peak demand, have been revised down and forecast input costs are also flatter.”

In one of its key decisions in 2012, AER deemed that a softening in forecast peak demand growth in Queensland should contribute to transmission investment requirements for 2012−17 being 16 per cent less than in the previous period.

The regulator says that around 20 to 30 per cent of the $60 billion
of electricity network capacity in the east coast market is idle 99 per cent of the time. “While this capacity is drawn on for less than 90 hours a year, the associated network charges are fully passed on to retail energy customers.”

HV outlook lowered

The Australian Energy Market Operator has also substantially reduced its view of generation and transmission capital outlays over the next two decades.

In its new “national transmission development plan,” AEMO foresees only half as much new generation capex  over 20 years as it did in its 2010 outlook and it has cut the high voltage network outlay virtually in half too – down from $7.4 billion to $4.4 billion.

The operator says that the carbon price regime, new investment in renewables to meet RET requirements, a changing fuel mix and lower energy requirements will change the operation and output of power stations.

Not alone

The decline in Australian east coast demand for electricity is not a local phenomenon.  Reports from large, developed economies overseas paint similar pictures.

The US Energy Information Administration reports that American electricity production fell in 2011 after two years of decline in 2008 and 2009 followed by a slight recovery in 2010.

A key factor in the American situation is use of power by manufacturing. Until 2010 this sector consumed a quarter of US power but demand has dropped 18 per cent as industrial processes become more efficient and factories shift out of the country.

In the European Union, says the EU Commission, there has been a decline in industrial and services sector demand over the period 2008 to 2010-11 while residential consumption is growing again after falling 5.2 per cent between 2007 and 2009.

In analysis released early in January, the Bank of America predicts that power demand in Germany, Europe’s biggest economy, will fall two per cent in 2013 after a similar decline in 2012 over 2011.

Callide CCS moves on

What federal Energy Minister Martin Ferguson describes as “one of the world’s most significant carbon capture and storage demonstration projects” moves in to a new phase in 2013.

The federal government is giving an extra $13 million to the $208 million Callide oxyfuel project at Biloela, Queensland, to enable its demonstration period to be extended to November 2014.

Ferguson says he is confident that the activity can have a positive impact on broader Australian efforts to promote CCS technologies.

The development comes as the International Energy Agency argues that “perhaps the most critically important short-term issue” for CCS is establishment of practical incentive policies, suggesting that those used to promote renewables might provide a template.

The Callide project is a joint venture between CS Energy (owned by the Queensland government), the Australian Coal Association’s low emission technologies scheme, Xstrata Coal, Schlumberger and Japanese companies.

The project’s director, Chris Spero, says Callide’s construction and commissioning phases are complete and it is now heading in to a period of technology demonstration, which include storing captured carbon dioxide.

Going commercial

The international commercial sector presents a significant opportunity for pursuing demand management, according to American analysts Pike Research.

A new report predicts that the number of commercial facilities, like shopping centres, taking up “demand response” programs will more than double to 1.4 million between now and 2018.

Globally, commercial building consume 23 per cent of electricity supply. In the US, during extreme weather, they can account for as much as 50 per cent of peak demand.

While America’s commercial sector has long been the most active in the DR area, says Pike, owners of buildings in Australia, Canada, New Zealand, Britain, France, South Africa and China are increasing their pace of adoption of demand controls – while South Korea, an early adopter in this area, is speeding up its involvement.

In 2012, Pike Research adds, the Asia Pacific accounted for 190,000 commercial buildings converted to DR.

Hasten slowly

The New South Wales Business Chamber doesn’t want to see retail energy price deregulation introduced quickly in the State.

It says its December quarter business conditions survey finds that 49 per cent of respondents see rising energy costs as having a significant or very significant impact on their activities. “Any action to deregulate markets must not result in higher prices than would have been the case under a regulated market,” the chamber asserts.

The Business Chamber says it  supports full deregulation only if there is adequate competition throughout the entire State. “Any move towards deregulation should be gradual, with appropriate checks and balances along the way.”

PVs and peaks

The Australian Energy Regulator has reminded onlookers that rooftop solar PV is not a solution to peak power problems. It points out that in the east coast mainland regions, summer demand typically peaks in late afternoon, when rooftop PV generation is declining from its midday levels and is operating at 28−38 per cent of capacity. Maximum demand in Tasmania typically occurs on winter evenings, when rooftop PV generation is negligible.

Meter attack

The Queensland government claims that a roll-out of smart meters in the State could cost consumers between $1.8 billion and $2 billion.

Energy Minister Mark McArdle says the cost of meters is an important part of the reforms proposed by the federal government. He has asked his department to provide an estimate of the cost because, he says, one is not available from Canberra.

30-year horizon

The Queensland government aims to release a discussion paper on the State’s electricity needs, looking out to the 2040s, in the first half of the new year, followed by a strategy document after July.

Energy Minister Mark McArdle says the government aims to “put the entire electricity supply chain under the microscope.”

An initial scoping paper for the exercise, released in mid-December, says that the Queensland industry employs 1.8 per cent of the State workforce and contributes more than $5.8 billion (2.4 per cent) to gross State product. The paper also notes that natural resource processing accounts for 28 per cent of State power demand, with mining consuming another 10 per cent – residential and commercial use each account for 26 per cent of consumption, with the latter sector including 400,000 small businesses.

The government says the State population could reach seven million in 30 years’ time, up from 4.5 million now and 2.4 million three decades ago.

While the project has an horizon of 2042, its immediate target will be the period from 2013 to 2019.

Eyes on the vertical

The Australian Energy Regulator is signalling that it is keeping an eye on the activities of large, vertically-integrated “gentraders” in the east coast power market.

The AER says that three retailers – AGL Energy, Origin Energy and
EnergyAustrala – now jointly supply 76 per cent of retail electricity customers and 85 per cent of gas customers in eastern Australia.

“These entities increased their market share in generation from 11 per cent in 2007 to 35 per cent in 2012,” it says. “They are also expanding their interests in upstream gas production, both to supply their retail customers and to provide fuel for their gas powered generation interests.”

The regulator comments that, while it makes commercial sense for these companies, vertical integration “reduces liquidity and contracting options in hedge markets and this affects energy costs for independent retailers.”

The situation, it argues, may pose a barrier to entry and expansion for both independent generators and retailers. “A vertically integrated business with significant market share in generation, “the regulator claims, “may have the ability and incentive to manipulate spot prices to harm its competitors in the
retail market.”

River of gold

Australia’s upstream oil and gas industry says it expects tax payments from new projects to contribute between $6.3 billion and $7 billion annually to governments between now and 2025.

In its annual review of the industry, the Australian Petroleum Production & Exploration Association cites modelling by Deloitte Access Economics of the benefits to flow from almost $200 billion in current project investment, including seven LNG projects.

APPEA says taxation payments will increase to $12.8 billion in 2020 and total around $93.6 billion (in net present value terms) by 2025. It says $61.2 billion will be corporate taxes and $32.4 billion will be production taxes.

The association warns that a high cost local environment and the emergence of new LNG competitors in East Africa, North America and elsewhere will make it much harder to win future market share for Australian LNG exports and attract investment than has been the case over recent years.

Chasing certainty

The Climate Change Authority has used the need to build investor confidence as a key reason for sustaining the renewable energy target at its controversial 41,000 GWh level in 2020.

In a report confirming its draft recommendations, the CCA presents its argument like this: “Confidence, including in the sustainability of important policy frameworks, is critical in persuading investors (and their financiers) to continue with their plans for long-term investments in renewable generation. Shocks to confidence, from whatever source, tend to be followed by curtailments and deferrals of investment plans, as witnessed in the mining sector of late.”

The agency adds: “The Australian electricity market is already facing considerable uncertainty, not least in response to the future of the carbon price arrangements. In its recommendations, the Authority has sought to avoid adding to these uncertainties in ways that could increase risk premiums required by lenders and investors in renewable energy.”

The CCA argues: “Adjusting the target (up or down) will entail significant risks. In particular, lowering it risks undermining investor confidence – and could exacerbate existing uncertainty surrounding climate change policy.”

For sale

New Zealand’s largest integrated energy company, Meridian Energy, is reported in the business media to be preparing to sell its half-share of Victoria’s Macarthur wind farm, the largest wind generation project in the southern hemisphere, due for commissioning in July.

The other half of the Macarthur development is owned by AGL Energy.

Apart from its involvement in the $1 billion Macarthur project, Meridian is also building the Mt Mercer wind farm (a $260 million development) and operates another at Mt Millar in South Australia. The Mt Mercer project is due for commissioning in December 2014.

The NZ government is expected to offer a 49 per cent stake in Meridian to investors during 2013 as part of its program of part-privatisation of its energy assets.

Meanwhile Origin Energy is examining options on its Stockyard Hill wind farm in Victoria.  The 547 MW project is budgetted to cost about $900 million.

The company says it is in discussions “with a number of companies to explore the best way to develop Stockyard Hill.”

The discussions have focused on how other companies might construct the wind farm on Origin’s behalf or provide equity and financing options for the project’s development.

In the event that another company purchases the project, Origin says it will purchase all the energy it eventually generates.

Big dry

Meridian Energy’s annual meeting in December was told that the company’s southern lake catchments in New Zealand, feeding it’s hydro-electric generation, had inflows at their lowest level for 79 years in 2011-12, 20 per cent less than the previous financial year and 10 per cent less than in the drought of 2008.

CoAG commitment

While the Prime Minister’s claim that energy reform will deliver a $250 a year reduction in power bills for households and small businesses by 2014 won the media headlines, the Council of Australian Government’s meeting in mid-December also produced six other electricity-related steps.

One is a job for the AEMC: to develop new national framework for reliability standards for implementation by the AER by the end of 2013.

CoAG also launched a review of the AER’s resources, operations and independence over the next 18 months.

First ministers agreed to establish a national “Consumer Challenge Panel” to improve the engagement of consumers in energy policy and pricing outcomes.

Yet again, they agreed to deregulation of retail prices where effective competition exists, with jurisdictions to work towards this where effective competition does not yet exist.

They committed also to implement the national energy customer framework (NECF) by January 2014 in those States yet to pursue this step.

Lastly, they told their energy ministers’ committee to develop a package of reforms necessary to adopt in full the recommendations in the AEMC “Power of Choice” report.

Underlining the difficulties confronting the CoAG agenda, a briefing paper released by the Standing Council of Energy & Resources ministers (SCER) after it met in Hobart the week following the first ministers’ meeting, included this: “The Queensland government has participated actively in this process, but is in the middle of its own electricity sector review. Accordingly, it has reserved its position on matters that are the subject of that review. All other jurisdictions have however agreed to progress the reforms outlined in this package.”

Queensland holds 22 per cent of the east coast’s electricity accounts and is home to almost a third of household power consumption in the NEM.

Deregulation momentum

Federal Energy Minister Martin Ferguson has welcomed the decision to deregulate electricity and gas prices in South Australia from February.
At present the only State with retail price deregulation is Victoria, which claims to be the most competitive power region in the world as measured by the rate at which customers switch between retailers.  There are 12 retailers competing for household accounts in Victoria and 25 per cent of customers switch supplier each year.

When the SA step is implemented, three million of the east coast’s nine million household electricity customers will be in a free market.

Meanwhile, the O’Farrell government is waiting on an AEMC report on competition in NSW before making a decision on retail price deregulation.

Ferguson says the move by the Weatherill government in SA is progress on a key plank of the CoAG reform package and on the number one reform step in the white paper he released late in 2012.

Also welcoming the SA decision, Origin Energy managing director Grant King says there is now momentum on the east coast towards full price deregulation – which, he argues, has been demonstrated in Victoria to deliver more choice and innovative products and services to consumers.

Cameron O’Reilly, CEO of the Energy Retailers Association, says the SA decision is not “radical” but “sensible” and will restore some energy sector faith in the energy market reform process.

Noting that an attempt by the SA regulator to anticipate wholesale electricity prices in advance had ended up in court, O’Reilly says setting regulated tariffs (still pursued in NSW and Queensland) “will always be problematic” when volatile wholesale prices, monopoly network charges and the cost of green schemes, including a carbon price, are taken in to account.

“Take price regulatory risk away and a lot more players are prepared to enter the retail market,” he adds.

Deregulation in SA was first recommended by the AEMC four years ago.

The new decision affects 550,000 households in SA – of whom 200,000 are still on standing contracts -- plus many small businesses.

The South Australian move will be accompanied by the introduction of price monitoring, a function to be carried out by the State's current regulator, ESCOSA.

In a sign of the political sensitivity of the step, the SA Energy Minister, Tom Koutsantonis, threatened to “immediately introduce regulation at the first sign of collusion or other anti-competitive behaviour” by retailers.

AGL Energy, which is the dominant retailer in SA, reacted to the Weatherill government move by offering current “standard contract” customers a 9.1 per cent power bill reduction to stay with it – and a 4.5 per cent reduction to small business customers. 

The offer is estimated to represent a $180 a year reduction in electricity costs for households taking advantage of it.

Can do better

The Paris-based Organisation for Economic Development has given the current outlook for the Australian economy a tick, rating it as “positive,” while calling for more to be done in energy reform.

The OECD says enhancing the efficiency of the Australian energy market will boost growth while preserving the environment. Price controls remain an important area of unfinished business in energy reform, with all jurisdictions, apart from Victoria, continuing to cap electricity tariffs for households and small and medium businesses, it points out. (The report precedes the SA decision.)
Faster progress towards removing retail price regulation will encourage consumers to respond to the true production costs, as the effectiveness of any carbon price signal is conditional on its reaching consumers, it adds.

The OECD calls for speedier installation of advanced metering infrastructure (“smart meters”), saying this is “critical,” as it will allow better demand management through time-of-use pricing.

The organisation also points to the need to strengthen power transmission networks, saying some analysts express doubts about whether the recent attempts to remedy the shortcomings of the development framework will be sufficient

Last word

Where are we? Why are we here?

The start of a new year, especially one that includes the next major review of power network capex and opex plans for most of the rest of the decade along with a federal election, where energy issues are likely to be on centre stage, deserves some reflection.

The short answer to the two questions above is that we enjoy some of the world’s safest, most reliable and most affordable electricity supply because, on the east coast, where the vast majority of consumers are to be found, we have developed ample power generation and linked it to users by a high quality delivery system.

That we nonetheless have energy problems is undeniable.

After many years of stable prices, both electricity and gas bills have risen sharply – and consumers don’t like it, so politicians (including the Prime Minister) have their knees jerking furiously.

We also have a seriously muddled approach to decarbonisation – in 2012 a leading commentator on the industry described the policy environment as a “dog’s breakfast.”  This is a situation crying out for careful, long-term bipartisan management – instead it is often a hotbed of invective, populism and contention.

Perhaps most seriously in the medium term, success in achieving LNG exports from Queensland is bringing with it a bad-tempered debate about access to onshore gas resources, the prospect of much higher domestic gas prices and, in the main sub-market, NSW, significant issues of supply as existing contracts for accessing fuel interstate run out.

All of this is playing out against a background where, for the first time, demand for electricity is in decline, mainly for economic reasons, and suppliers are struggling to keep their feet commercially.

That this is tricky ground is also undeniable and that we can expect the public ferment on the issues to continue through 2013 and probably beyond is hardly rocket science.

This is why it is important to try to understand the context of the situation better. Planning based on misunderstandings is a recipe for more, not fewer, problems.

Nowhere in the energy sector is this more important than for energy networks – and it was interesting in December to see Andrew Reeves, chairman of the Australian Energy Regulator, setting out in a public forum on regulatory issues to address the background.

The AER, and its sibling, the Australian Competition & Consumer Commission, are players in our Great Energy Game at present because they are engaged in a rearguard action to ward off efforts by State governments to separate them.

Appreciating this is necessary context, too, in assessing what the leadership of either organisation says in 2013-14 ahead of an independent review of the AER to which the Council of Australian Governments agreed in mid-December.

Leaving this aside, there are several points Reeves made in his talk that are worth keeping to the fore as the debate moves on in 2013.

The first, and perhaps the most important, is that the regulations under which today’s networks operate were introduced by governments in 2006 “at a time when there was a perception that investment in critical infrastructure may be insufficient to support economic growth.”

As Reeves says, “a set of rules were put in place that were explicitly intended to promote network investment.”

They did. They facilitated an outlay (up to 2014) of more than $42 billion on the east coast.

Think about this. 

Three years before the great economic conflagration we are now enduring, Australian governments collectively agreed to a process designed to create one of the largest sectoral investments (outside of the big mines and the LNG projects) in the nation’s history in order to support economic growth.

Now a different set of politicians, sooled on by media reports, are setting out to put the system in to reverse because of this “wasteful” set of developments.

Reeves, I think, makes another good point about this: “While certainty for investment is a critical consideration, it is equally important for the (regulatory) framework to support investment that is necessary, efficient and valued by consumers.”

As he says, and as the Productivity Commission has emphasised in its own network review, to be finalised early in 2013, the focus of policymakers needs to be on the long-term interests of consumers with respect to price, reliability, service and safety.

The same test can be, and should be, applied to policies intended to pursue decarbonisation of the Australian economy.

No objective judgement of the events of 2010-2012 can conclude that the current state of carbon policies meets this test.

The worrying thought is that the febrile political environment of 2013 does not lend itself to the needed strategic mindset and good decision-making that is essential for energy supply to 2020 and beyond.

Martin Ferguson sees retail price deregulation for households and small businesses as the number one reform step recommended in his recently-published energy white paper. But the foot-dragging by State governments outside Victoria on the issue – it has taken South Australia since 2008 to adopt the AEMC recommendation to deregulate, a step it will take in February – is emblematic of the “dog’s breakfast” that is still a long, long way from being cleaned up.

Keith Orchison
13 January 2013


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