From the role of nuclear to the position of gas, IRP debate heats up

20th January 2014

By: Terence Creamer

Creamer Media Editor

  

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Much of the initial commentary on the draft update of the Integrated Resource Plan (IRP) has focused on the potential delay, downscaling or even abandonment of South Africa’s proposed new nuclear build programme. But more comprehensive responses are beginning to surface on the 20-year electricity blueprint as the February 7 comment deadline approaches.

As would have been anticipated, the proposed revisions to the nuclear build programme, together with the suggested $6 500/kW price cap for any new nuclear capacity, continues to receive significant attention.

The update itself describes the nuclear decision as being “particularly volatile”, owing to shifts in underlying assumptions, not least being the lowered demand assumptions. The document ventures that demand will be in the 345 TWh to 416 TWh range by 2030, as opposed to the 454 TWh expected in the current plant. “From a peak demand perspective this means a reduction from 67 800 MW to 61 200 MW (on the upper end of the range), with the consequence that at least 6 600 MW less capacity is required.”

But University of Cape Town Energy Graduate School of Business and National Planning Commission member Professor Anton Eberhard highlights that even this moderated demand assumption remains “aspirational”, having been aligned to the National Development Plan’s expectation of average yearly growth of 5.4%. In reality, South Africa’s economy is growing far slower, while electricity demand has declined to 2006 levels.

Energy Intensive User Group (EIUG) chairperson Mike Rossouw believes the final IRP requires a “more realistic return-to-growth profile” than is contained in the update, as well as a commitment to regular updates of the demand assumptions.

Similarly, Frost & Sullivan consulting manager for energy and environment Johan Muller argues that the demand uncertainties underline the importance of revising and amending the IRP every two years. “The key will be to avoid a situation where there is an oversupply of generation and resultant debt that cannot be serviced,” Muller adds.

South African Wind Energy Association (Sawea) CEO Johan van den Berg, meanwhile, says the latest modelling appears to be more robust and nuanced. Nevertheless he questions whether it fully grasps changes that have taken place in the electricity environment, or whether the “old order” is still assumed in assumptions. “We need to fine-tune our IRP modelling assumptions,” Van den Berg avers.

Nuclear Industry Association of South Africa (Niasa) Knox Msebenzi takes a slightly different tack, however. He argues that demand has been “suppressed artificially” through measures placed on large power consumers and that demand will “bounce back” once economic growth recovers.

“The long-term outlook remains that of sustained demand growth,” Msebenzi asserts, while acknowledging that electricity price increases have led to increasing energy efficiency and decreasing energy intensity. “Eskom has, thus, reached the point where it can no longer increase prices at will, as it will be punished by decreasing demand.”

Msebenzi is also critical of the update’s proposal that long-term commitments be eschewed in favour of building only the minimum generation capacity required. Such an aversion to long-term commitments will “preclude new nuclear construction” and South Africa will turn to shorter lead-time technologies, which Niasa argues could well have a higher levellised cost of electricity (LCOE) than nuclear. This, in turn, could result in the price of electricity increasing “unnecessarily” , while stifling economic growth.

By contrast, the EIUG’s Rossouw sees the update’s preference for ‘decisions of least regret’ as a “big positive”, while again underlining that a “realistic demand forecast is critical”.

Nuclear Debate
Rossouw is also supportive of the suggested $6 500/kW capital-cost cap for any new nuclear capacity, while Eberhard says the update contains a “sensible decision tree around nuclear”.

“Essentially it says if electricity demand is lower and nuclear prices are higher, then we don’t need nuclear. [But] whether decisions take this rational path remains to seen,” Eberhard comments, while noting that the capital costs associated with the new nuclear plant being planned for Hinkley Point, in the UK, are around $7900/kW.

The revised ‘base case’ in the IRP draft update continues to include nuclear. However, it proposes only 6 660 MW of nuclear capacity (including Koeberg) by 2030, instead of the 11 400 MW anticipated under the current IRP. Total nuclear capacity in 2050 ranges from 0 MW to 30 400 MW.

Muller believes the proposal to delay and scaleback nuclear, as well as to set a capital-cost cap is a sound one, particularly in light of the current project management issues at Medupi and Kusile, as well as the possibility that shale gas could be a “potential game changer if managed correctly”. Muller adds that the impact of other types of gas should also not be discounted.

However, Niasa’s Msebenzi believes the cap places too much emphasis on the overnight costs of nuclear, while failing to take account of nuclear LCOE being more sensitive to the yearly percentage weighted average cost of capital (WACC). “It is clear that the proposed cap on the overnight cost for nuclear is largely meaningless and should, for all the power sources, rather be replaced by a cap on the LCOE, which will be determined by the combined effects of WACC, overnight costs, external costs and system costs,” he argues.

A number of other assumptions included in the update, Msebenzi adds, “drastically overestimate” the LCOE of nuclear and “drastically underestimate” the LCOEs of coal, solar photovoltaic (PV) and wind.

“Therefore nuclear capacity was suppressed or even absent in most of the scenarios of the IRP. However, once one corrects these flaws, nuclear easily outperforms all its competitors. Therefore, nuclear should neither be scaled down nor be delayed,” he avers.

Unambitious on Gas
On the face of it, gas appears to be a material beneficiary of the revisions made in the IRP update, with a target of 3 550 MW set for closed cycle gas turbines, up from 2 370 MW in the current plan.

But Frost & Sullivan’s Muller describes it as an “unambitious target that could be higher”. However, a higher target is dependent on a system-wide solution. “Finding a stable supply of gas, whether in the form of shale gas, or whether from Mozambique, will be vital for this target to be met.”

He adds that the gas market is in “a chicken-and-egg situation regarding investment”, since the market and infrastructure is currently geared towards a coal-based system with few major investors willing to make the leap of transition to a gas based system.

Gigajoule Group CEO Johan de Vos is even more strident, arguing that the IRP fails to fully recognise the economic, environmental, construction and operational benefits of natural gas. “At present natural gas power stations are being constructed at between $0.8- and $1.3-million per installed megawatt, depending on technology. This is substantially cheaper than coal or nuclear power stations. Typical construction times of two years make it even more competitive, if the interest during construction is accounted for.”

De Vos describes the recent discoveries in the Rovuma basin, of northern Mozambique, as “truly remarkable”, with proven reserves of around 170-trillion cubic feet. “Studies for a pipeline from these discoveries to the south, indicate that it is feasible and economical to flow around 400-million gigajoule a year, supplying around 5 000 MW to the regional grid. For such a pipeline, the estimated investment would be around $5-billion, with a three-year construction period.”

He argues that any revised IRP should be committing to the purchase of at least 5 000 MW of gas power, which would provide the “catalyst” for the development of a pipeline from the massive reserves in the Rovuma basin. The project, he adds, could be pursued with firm and clear pricing and a rand-denominated transportation tariff.

Rossouw believes a detailed study is required to firm up the potential for gas, while Eberhard proposes that the plan comprise a mix of offshore sources and liquefied natural gas imports in the near term, which could be supplemented by shale gas as the reserves are proved.

Renewables rethink?
There are also mixed reactions to the update’s proposed changes to the renewables mix, with its greater emphasis on solar, both PV and concentrated solar power, and less emphasis on wind.

“This did come as a surprise, since wind is a very viable energy option,” Muller says, while acknowledging that solar is starting to make more sense as capital costs fall.

“My view is that the best technology should be picked for the circumstances, which will typically hold that a combination of wind and solar will be used,” he adds, arguing that government should rather pose an open question and let the market decide the technology.

Eberhard adds that the issues need further interrogation, adding that he suspects the assumed learning curves for solar may have been a “little too aggressive”.

Sawea’s Van den Berg says the modelling underpinning the new IRP disregards some of the major changes that have taken place in the domestic renewable-energy sector over the past few years, particularly the success of independent power producers (IPPs) in delivering projects. “The modelling proceeds implicitly as if all energy plants will be built on the country’s balance sheet. The enormous risk and opportunity costs of Eskom building are disregarded for modelling purposes,” he says.

Van den Berg adds that, at an average of 74 c/kWh in the third renewables bidding round, wind is now almost 30% below the likely cost of electricity to be supplied by Medupi. “This tells us that, all other things being equal, the more wind power we install, the more money we save.”

Coal Consensus?
One area of emerging consensus from the update, though, surrounds the issue of the performance of the Eskom fleet and a proposal that a procurement programme be pursued for fluidised-bed-combustion coal generation instead of the so-called Coal 3 mega-project.

“Going for a number of smaller coal IPPs, preferably with off-the-shelf designs, is clearly less risky than another mega Eskom coal plant,” Eberhard asserts.

Muller adds that, if put to the private sector, ways will be found to ensure South Africa’s coal resources are put to efficient and cost effective use. “Again, rather than prescribing the technology types, it would be interesting to see what would happen if government said to the private sector: "We have need of X amount of megawatts, here are the available resources, let us know what you propose."

There is less agreement, though, on whether there is indeed potential to extend the life of the Eskom fleet.

Rossouw cautions that such a move will depend on whether exemption is given to the retrofitting of flue-gas desulfurisation at the plants, while Eberhard adds that adequate coal sources will have to be secured.

Muller says much hinges on the specifics that emerge from a cost-benefit analysis that will need to be undertaken at each power station. “In general, Eskom is not in the position to mothball any power stations at the moment, so the questions on whether to extend the lifetime of the fleet is a moot point: the power stations (subject to safety standards) must be run until new power generation plants come online.”

The Department of Energy, which published the draft update on November 25, aims to promulgate a final updated IRP during March 2014.

Edited by Creamer Media Reporter

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