What mix of technologies will power Australia’s energy networks in the future? Energy Source & Distribution talks to Professors Quentin Grafton and Arif Syed from the Bureau of Resources and Energy Economics (BREE) about the Australian Energy Technology Assessment results.
It can be a long wait between energy projections. Before the recently published Australian Energy Technology Assessment (AETA) report updated levelised cost of electricity across 40 technologies, the industry relied on EPRI’s 2009 results. Those numbers saw large-scale solar PV comprising only a few per cent of total energy generation in the decades to come. According to the AETA report, that amount has now jumped to between 15 and 20 per cent. With generators under pressure to reduce the risk of their energy technology investment decisions, and as renewables become more cost-competitive with fossil fuel technologies, the release of such information can prove timely and invaluable.
The AETA report provides judgments based on the best available information and technical advise. Deciphering the future energy mix is BREE executive director and chief economist Professor Quentin Grafton and Professor Arif Syed. The BREE modeling team have developed the report to be consistent with the Australian Energy Market Operator’s (AEMO) National Transmission Network Development Plan. The project technical committee included CSIRO’s Dr Alex Wonhas and Energy Change Institute to the Australian National University director Dr Ken Baldwin, and responded to submissions made by a stakeholder committee.
“We’ve got information from stakeholders, we’ve got results from WorleyParsons, it’s all been above board and we’ve been technology neutral all the way,” Professor Grafton explained to Energy Source & Distribution.
The report assists those making electricity generation investment decisions considering the types of technology to invest in, when and where to invest.
“So I think our numbers will provide considerable insight and guidance to those decisions that will be made by electricity generators,” Professor Grafton said.
“Now as they start to make those decisions over the next five-to-10 years, then that will of course have implications for the network.
“That will obviously feed into decisions about what people will be doing in terms of their network investments. It tells us, or it suggests to us, as best as we can in 2012, that the energy mix will be very different in 2050 than it is today and that means we will need to plan for a different energy generation.”
Professor Grafton emphasised the results are not a “crystal ball” and that projects out to 2050 are difficult to make. He does, however, believe the broad trends are clear. Renewables will become more cost-competitive with fossil fuel technologies in the years to come, however there will be a continuance of fossil fuel in the mix, even out to 2050.
Fossil fuel technology
Fourteen coal-based technology options were examined in the AETA report, encompassing different fuels (brown and bituminous), combustion technologies (pulverised coal, IGCC, and direct injection coal engine), options for carbon capture (post-combustion, new and retrofit oxy combustion) and different power plant scales (NEM, SWIS).
Estimated capital costs for pulverised coal technology without carbon capture and storage (CCS) include $3788/kW net for supercritical brown coal, $3124/kW net for supercritical black coal, $3381/kW net supercritical black coal (SWIS Scale), and $4930 for oxy combustion supercritical. With CCS added, costs jump to $7766/kW net for supercritical brown coal, $5434/kW net for supercritical bituminous coal and $5776/kW net for oxy combustion supercritical.
Professor Grafton said there is plenty of potential for carbon capture and storage.
“It’s not immediate; we certainly have it being deployed from the 2020s. So certainly our view of the world here in 2012, that it is a commercially deployable technology not now, but out to the 2025 and beyond,” he said.
The report highlights international plans to build a commercial-scale supercritical pulverised coal facility with mainsteam temperature of 700ºC by 2016. There are also efforts to develop and test materials needed to achieve mainsteam conditions of 760ºC and 34.5MPa in boilers and steam turbines. It is expected and assumed those conditions will be available in commercial-scale plants by 2030. It is estimated that moving to 760ºC and 34.5MPa will increase thermal efficiency by at least six percentage points compared to current technology.
Oxy combustion supercritical plants will benefit from the same technological improvement in the steam cycle as other PC coal-fired technologies. In addition, improvements to the CO2 compression systems, as well as more efficient processes to produce oxygen in the ASU will reduce the base plant’s auxiliary load, thereby increasing the overall thermal efficiency of the plant.
For brown coal plants, it is expected new coal drying technologies, using low-grade heat, will be used to dry the coal more efficiently. While an increase in thermal efficiency does not directly impact on post-combustion capture processes, it does result in a more efficient power plant that produces less CO²per MWh.
An expected decline in capital costs for integrated gasification and combined cycle (IGCC) technology is based on the predictions for improvements in reliability and flexibility of gasifiers, oxygen separation, and the use of hydrogen-fuelled turbines and fuel cells.
As direct injection coal engine (DICE) with coal water fuel (CWF) is an immature technology with no commercial plants, there is a low level of confidence associated with the capital cost estimate. The capital cost is estimated at $1600/kW in 2012 for the engine.
The estimated costs of several fossil fuel-based electricity technologies differ from previous studies, primarily as a result of a carbon price and higher projected market fuel prices. The report incorporates the carbon price projected by Treasury into the levellised cost of electricity (LCOES), as well as provides results without a carbon price due to uncertainty surrounding its future. The BREE has also provided a model allowing users to change the carbon price if they “have a different view of what it might be beyond 2015”, allowing for some degree of customisation.
Five gas-based technology options were examined, encompassing different combustion technologies (OCGT, CCGT), different options for carbon capture (new, retrofit) and different power plant scales (NEM, SWIS). Recent heavy-duty gas turbine designs have advanced hot gas path materials and coatings, advanced secondary air cooling systems, and enhanced sealing techniques that enable higher compression ratios and turbine inlet temperatures that reach over 1371°C. Improvements in efficiency and reductions in capital costs of gas technology options are not likely to be as marked as for an emerging technology.
AETA project manager and senior BREE economist Professor Arif Syed said the results showed closed-cycle technology is cost-competitive with renewables out to 2050, both in terms of LCOE and also in terms of the energy projections, constantly increasingly up to 2050. But Professor Syed said it was necessary to keep in mind market factors.
“Suppose all renewables become very cheap, we can’t just ‘project okay’ from today all renewables (for) generation, because there is no stability and there is no storage. So for all those reasons, CCGT and even black coal, they continue very long (in usage) and CCGT continues up to 2050. And CCGT is cost competitive in itself as well,” Professor Syed said.
With an intermittency issue associated with some renewables, backup options that produce greenhouse gases will remain competitive options.
“You can have it coming from coal-fired generation, you can have it coming from gas and potentially other sources. If it comes from gas relative to coal, then there’s a saving or reduction in GHG and carbon emissions,” Professor Grafton explained.
“So although gas of course does emit greenhouse gas emissions, no question about it, it emits fewer greenhouse gas emissions and in some cases, depending on the technology, up to 45 per cent less in the actual energy generation phase of it. So that’s the saving there.”
Estimated costs of solar photovoltaic technologies have dropped dramatically in the past two-to-three years as a result of a rapid increase in the global production of photovoltaic modules. By 2030 some renewable technologies, such as solar photovoltaic and wind on-shore, are expected to have the lowest levelised cost of energy (LCOE) of all of the evaluated technologies.
The three solar thermal technologies considered in the report included compact linear fresnel, parabolic trough and central receiver tower. Based on US reports, the cost of a 100MW trough system with six hours storage is estimated to cost $8950 per kW installed. As concentrating solar power plants increase their share of the utility market and their installed capacity expands, costs are expected to continue to decrease.
Solar/coal hybrid capital costs were $3395/kW net, envisaged from a 750MW supercritical black coal-fired power plant operates in conjunction with a 125MWt solar field contributing 40MWe to output.
The integrated solar combined cycle was $2150/kW net, estimated from a plant modeled on a single Alstom GT26 gas turbine with a three-pressure reheat HRSG and a nominally sized solar field multiple of 1.2 with no thermal storage.
There have been significant increases in solar PV installation in recent years with significant price reductions per kW as large scale manufacturing facilities reduce production costs. A number of recent US reports were utilised to provide the basis for the sizing and costs associated with the PV fixed plate technology. Capital costs for solar PV fixed are $3380/kW net, $3860/kW net for solar PV single axis tracking and $5410 for solar PV dual axis tracking.
Professor Syed said he was surprised by how much these results differed from the energy industry’s prior understanding of solar costs.
“All of us were thinking that (solar), particularly large-scale solar PV not rooftop, people (thought) 2 per cent and 1.5 per cent share. And now, that is by 2050, that will be 15-20 per cent share. So that’s a big change,” he said.
“In the last three years the prices have really reduced at a very fast rate, even between 2011 and 2012 the prices fell down substantially.”
There is an increasing trend to develop larger scale on-shore wind projects in Australia, with the recent 400MW Macarthur Wind Farm as an example. It is expected that 100+ MW wind farms will become more common over the forecast period with an ongoing trend towards deployment of fewer, larger capacity machines. The capital cost for an on-shore wind farm is $2530/kW net.
Off-shore wind farms are estimated to have a capital cost of $4451/kW net. Operations and maintenance for off-shore wind facilities presents a number of challenges not associated with the operation and maintenance of on-shore wind farms.
It is expected that advances in a number of areas will continue to drive the capital cost of wind facilities down through the forecast period.
The global wave power industry is still immature and commercial production of wave energy is very limited. Ocean and wave technology capital cost is estimated to be $5900/kW net.
Biogas and biomass electricity generation technologies in 2012 are some of the most cost competitive forms of electricity generation, and are projected to remain cost competitive out to 2050. Capital costs ranged from $3000/kW net for landfill gas to $5000/kW net for biomass waste.
“(Biogas) is competitive now and they are competitive into the future. There are constraints on that in terms of fuel source and where you would be able to locate them. Certainly they are absolutely cost-competitive at the moment,” Professor Grafton said.
An opportunity for a significant increase in power generation from solid biomass fuel is by co-firing in an existing power plant. A number of coal-fired plants in Australia have already operated in co-firing mode, but, a range of technical difficulties have been encountered and this has largely been discontinued.
Recent and future advances in fracturing technology offer the potential for step change reductions in per-well and therefore – due to the major capital cost of wells – electricity generation costs. Fracturing technologies stand to benefit from the major research and development expenditures in development of vast US and Canadian (and other worldwide) shale gas resources. Improvements in resource exploration and assessment methods will also reduce costs.
“Certainly the geothermal ones are into the future and quite a number of the technologies come out later in the 2020s or a bit later than that,” Professor Grafton said.
Nuclear power plants offer a more immediate form of generation, but are sensitive to finance conditions due to the high capital costs and lengthy construction times. WorleyParsons estimate the average overnight capital cost for four first-of-a-kind (FOAK) nuclear power plants in the US based on AP1000 Gen III technology is $4210/kWe. With standardisation of design, it is projected that Nth-of-a-Kind (NOAK) versions of this power plant technology will cost $3470/kWe in the US. It is possible that commercial fusion technology could become a reality by 2050. The LCOE analysis for nuclear technologies does not include disposal/storage of spent fuel or provision for decommissioning of plant
It is expected further technological advances will be made in relation to three areas of nuclear technology over the next 40 years: high temperature gas and metal reactors, fuel neutron reactors, and nuclear fusion.
Among the non-renewable technologies, combined cycle gas (and in later years combined with carbon capture and storage) and nuclear power offer the lowest LCOE over most of the projection period. They both remain cost competitive with the lower cost renewable technologies out to 2050.
The investment decisions made by independent generators today will have repercussions on the future energy network. Professor Grafton has briefed the team preparing the Energy White Paper about the implications of AETA’s numbers. The AETA report also feeds into the BREE’s long-term energy projections, which will be published in December.
BREE will provide comparisons to their 2011 report at the Eastern Australia’s Energy Market 2012-25 in Sydeny on 17-19 October.
Providing transmission certainty for generators
The Australian Energy Market Commission (AEMC) called for comment in August on proposed arrangements to manage generation and transmission investment in the National Electricity Market.
The proposals were released by the AEMC’s Transmission Frameworks Review, which looks at ways to encourage cost-efficient investment into the future.
Under current arrangements customers pay the full cost of transmission network investment and generators make investment decisions which are not fully exposed to the cost of transmission in different locations.
AEMC chairman John Pierce said the review’s Second Interim Report included choices for generators and transmission businesses to restructure their contractual relationship as well as proposals for significant strengthening of national transmission planning.
“Essentially our proposals are for a more market-oriented approach to providing transmission services – and to redirect some investment risk from customers to generators.
“We consider that the combined costs of generation and transmission should be taken into account when investment and operational decisions are made.
“Generators would be able to choose to pay for enhanced rights to the transmission network (which transports power sold by generators to consumers). This charge would reflect the long-term costs of providing transmission network services and reflect the different costs of providing access to the network in different locations,” Mr Pierce said.
The Second Interim Report suggests that the proposed regime for ‘optional firm financial access’ would give generators greater certainty of access to transmission, reducing their financial risks and contributing to lower operational costs over time.
The AETA report states that the levelised cost of energy (LCOE) is the most commonly used tool for measuring and comparing electric power generation costs. It reflects the minimum cost of energy at which a generator must sell the produced electricity in order to break even. It is equivalent to the long-run marginal cost of electricity at a given point in time because it measures the cost of producing one extra unit of electricity with a newly constructed electricity generation plant. The AETA LCOEs are restricted to only utility-scale or large-scale technologies.
The calculation of LCOE requires a significant number of inputs and assumptions. All components costs and factors are converted into common units to develop the LCOE in terms of $/MWh. LCOE numbers are only generated for technologies where it is expected that the technology is commercially available.
LCOE provides a generalised cost estimate and does not account for site-specific factors that would be encountered when constructing an actual power plant. As a result, the costs associated with integrating a particular technology in a specific location to a specific electricity network are not considered.
Technologies with an established track record during the phases of both construction and operation, and with relatively stable costs during their lifetime may be regarded as less ‘risky’. To the extent that a long term, stable income can be assured over a project’s life, risk is further reduced. By contrast, technologies with historical cost overruns, costly delays during construction, and fuel cost volatility generate additional risks, real or perceived.
Higher perceived risks will in turn demand higher rates of return on investment.