By Antonio Ruffini, Editor, ESI Africa magazine
South Africa’s Energy Intensive User’s Group (EIUG), whose members account for 44% of the country’s electricity usage, estimates that if there were no constraints on supply 2,000 MW of demand would return to the grid immediately.
Even with such supressed demand, the national power company Eskom has to run mid-merit and peaking plant, such as its gas turbines at estimated costs of R2.50/kWh, over extended non-peak periods.
During the first half of 2012, Eskom undertook buyback contracts with energy intensive customers, whereby it paid these groups to take production capacity off line. It repeated this process in early 2013, though the National Energy Regulator of South Africa (Nersa) has opposed funding for this practice going forward in its multi-year price determination (MYPD3) ruling covering the next five years, starting on 1 April 2013. The concept of a national utility paying a consumer in the productive economy to keep its plants off-line is usually not recommended. However, under the current circumstances it has made sense, at least until additional base load capacity comes online.
“Luckily for Eskom and the country, the commodities markets have been soft and it paid South African producers to accept a buyback deal,” Mike Rossouw, the chairman of the EUIG, says. “Had the commodities markets been booming buybacks would not be a worthwhile proposition.” The deal works for Eskom in that it is able to take demand off the grid, to keep its system able to supply the remaining demand, and at a cost that is significantly less than having to run mid-merit and peaking power plant. “Of course, once the new capacity comes up and the crisis is over, such deals would have fallen away.”
Rossouw says that “to fully understand the main issues affecting South Africa’s electricity sector one needs to consider the time element, the substance of the issue and the policy behind it.”
Another example of the above challenge is the pricing of electricity over the five year multi-year price determination (MYPD3) period from April 2013 to 2018. Like many groups across South Africa, the EIUG disagreed with some of the assumptions behind Eskom’s 16% a year tariff increase request over this period. Rossouw and the EIUG proposed that a 10% annual increase over the five year period is sufficient to sustain Eskom. The main difference between the EIUG’s and Eskom’s pricing models was that Rossouw does not believe a stand-alone credit rating in five years with a targeted 8% return on assets is justified for what is essentially a public utility monopoly. This is while energy intensive industries in South Africa, the heart of the country’s economy, are becoming internationally uncompetitive at existing electricity prices, let alone those after the proposed increases. The regulator Nersa essentially agreed with the EIUG as large industrial and mining users of electricity will instead now see an annual increase of 9.6% a year over this period.
A presentation by economist Brian Kantor and former MD of Credit Suisse London, David Holland, at one of the public hearings held for submissions on the proposed increase in January 2013 indicates how, following electricity price increases to date, Eskom’s existing real rate of return already had achieved an internationally competitive level of 3.3% by March 2012. This is similar to the average of the long-term real returns of the world’s largest 100 electricity companies over the past decade. The argument was that if the 3.3% rate of return which Eskom was achieving at ZA61c/kWh was maintained, this would be sufficient to justify investment in additional capacity.
Rossouw says that “part of the reason Eskom was able to reduce its MYPD2 final year’s tariff increase from 25% to 16% is that the utility is already in a good position, but that move did create a concern related to policy predictability.”
He also believes that the days are past when electricity usage represented a straight line curve corresponding with economic activity in South Africa. Partly this is the natural effect of a diversifying economy no longer entirely reliant on primary industries. In addition, electricity prices are now at a level where they influence demand. “But at the same time there has been no deep analysis on the effects of the pricing of electricity on demand.”
In terms of efficiency, Rossouw argues that Eskom is a long way off the efficiency it should be achieving in terms of its plants’ availability according to nameplate ratings. Eskom previously achieved utilities of more than 88% availability; whereas its current utility is below 80%.
Eskom CEO Brian Dames did note that in Eskom’s pricing application it had assumed an annual price increase of 10% for coal, and that the power company would have to find a compact with coal producers to keep increases to those levels or below. Rossouw believes that Eskom should focus on the costs related to its coal management that are within its control. This involves controlling the quality of coal it receives, the highest risk coal being that bought on short term contracts, which it trucks in from small suppliers. The calorific quality of the coal used has a strong influence on the feed rates and power output. Ash content increases the probabilities of boiler tube abrasion. At the same time, Eskom has to double handle coal at its own stockyards in attempts to achieve the desired quality, which in turn increases costs. Rossouw says that “coal companies cannot expect to operate at a loss and this in light of Eskom demanding cost reflective tariffs.”
In essence, Rossouw believes that Eskom can manage the coal process from the pithead of its supplier mines to the boilers more efficiently than it currently does.
Something that did not impact the MYPD3 price application is the longer term concern Eskom has over securing the supply of over two billion tonnes of coal beyond 2018, which has led to talk about strategic national resources.
On this, Rossouw has the following to say: “Large scale coal operations near the power stations remain the way to go, with conveyors being the preferred option for moving the coal. Large volume long distance conveyors are possible. Rail lines are the next option, and there is also the possibility of pumping pulverised coal through pipelines over long distances.”
Thus the model for South Africa’s steam coal sector has not in essence changed.
Rossouw adds: “Only a part of the country’s coal fields produce steam coal that is of good quality and can be exported to international markets. Then there is a lower quality coal that is not exportable and which Eskom power stations are designed to use.” In the past there was no overlap between the coal that can be used for the local and export markets, and while there is now some overlap, something that is in part responsible for Eskom getting coal at the bottom end of its specified quality range, Rossouw argues that this overlap is not large or significant enough to threaten the original model. He supports the view that sufficient monitoring should take place to ensure that coal of the correct quality is delivered to the power stations. “Also”, says Rossouw, “consideration should be given to these contracts being awarded to those suppliers that can comply with Eskom’s exact specifications and at the very least Eskom should insist that the coal is de-stoned prior to leaving a mine, which will save significantly on transport costs.”
One of the concerns the EIUG has relating to South Africa’s power sector is the approach taken related to the implementation of the integrated resource plan (IRP2010). It was meant to be a living plan and a roadmap, not a prescribed list, and it is important to update it. “It should have been updated in 2012, and it seems that the update which will happen this year will only be a partial one.” Furthermore the role of the IRP in light of the revisions to the Energy Regulation Act needs to be determined as Section 34 gives the minister vast powers to determine the new capacity for the country.
Since the time of the original IRP a lot has happened in the gas sector, which needs to be factored into the planning. With little known alternatives in 2010 a nuclear programme was proposed in IRP2010 but with the proviso that alternative options must be further studied. The whole nuclear programme and the extent of it appear to be under a cloud of uncertainty. Thus a lot of the good work related to the clarity provided by IRP2010 and its intention as a living plan is being undone.
In terms of other policy aspects of the power sector in South Africa, Rossouw says that while there will always be a place for Eskom there is a need for independent power producers, and by that he means base load IPPs. “However, while one cannot envisage South Africa’s electricity sector without Eskom, it must not get a free ride and it must return to the efficiencies it last achieved during the 1980s and 1990s. At the moment it is not close to that level of performance.”
Rossouw believes that the existence of other generation plants with which Eskom’s efficiencies and costs can be compared will provide the necessary incentives for improvement. At the moment Nersa has no basis for comparison as it uses theoretical figures when allocating costs it deems justified. “There is a plan to attempt to apply metrics to power stations about what is appropriate for them to cover costs assuming efficient operation,” he adds.
Regarding the current legislation under consideration on the independent system and market operator, Rossouw says that, “while such an operator is a good idea, it is the wrong time for it. At the moment, it would not make any difference to how the system operates.”
Rossouw believes that due to a fear of not getting support from government Nersa lacks the courage to fulfil its mandate. “This goes back to how the third tier of government rejected the regional electricity distributor model, and snubbed central government’s plans in so doing. It was the regulator’s duty to test the arguments used by the South African Local Government Association (Salga) and the municipalities, which use electricity to cross-subsidise other costs, as to the constitutionality of the then proposed regional electricity distributors (REDs). It should have taken this argument to court: that the duty to supply electricity does not equate to the right to supply electricity. If municipalities do not have the ability to supply electricity effectively, Nersa has the right to withdraw their licences. Nersa should either demand that municipalities provide an efficient and cost effective service or, where the municipality is unable to do this, replace it with an alternate supplier.”
The spectre of carbon taxes also looms over the electricity sector, something that it can ill afford. In his February 2013 budget address, South Africa’s finance minister Pravin Gordhan said that carbon tax would be phased in from 2015. The national treasury’s current plan is to initiate the first carbon-tax phase between 2015 and 2020, starting with a tax at a rate of R120 a tonne of CO2 equivalent, increasing by 10% a year during the first implementation period.
A basic tax-free threshold of 60% was proposed, as well as offset percentages of 5% to 10% to allow emission-intensive and trade-exposed industries to invest in projects outside their normal operations to help reduce their carbon tax liabilities. That translates into an actual carbon-tax cap of around R48 a tonne at the start of 2015.
Regarding carbon tax the argument is fairly clear-cut according to Rossouw: “If the aim of carbon taxes is to change behaviour, well, the increased electricity price is already changing behaviour, and working on the basis that we want more economic activity and job creation and not less, the only effect of such taxes will be shut down more production”. He further says that, “A carbon tax at this stage will not change behaviour, other than to drive energy intensive industries out of business.” If the sole aim of implementing a carbon tax is for South Africa’s national treasury to find more income for the fiscus, it will not work as it will almost certainly reduce productive economic activity and the tax base, resulting in an overall loss of tax revenue.
“The EIUG is not implying that one should never consider a carbon tax, but rather to look at the timing and consider the results. The realistic timeframe for South Africa to reduce its carbon footprint is one of decades, not years,” Rossouw says. “We have to stick to the art of the possible, as to assume that South Africa can dramatically change the nature of the electricity supply industry by 2025 is not realistic.”
South Africa has already headed itself in the direction of lower emissions through its IRP2010 planning and the commitment to 3,725 MW of renewables, some of which went into construction in 2013. “The renewables programme is already a tax as it raises the electricity price and comes to an effective pricing of R150/tonne of carbon dioxide. This is in addition to an environmental levy already being paid of R35/tonne of CO2.”
When asked how much in the way of renewables South Africa can afford, Rossouw’s response is no more than that already committed in the Renewable Energy Independent Power Producer Procurement Programme. “Taking into account that the power shortfall is base load requirements, and at their very best renewables will fall into the mid-merit to peaking category, this form of power will not solve the problem of security of supply. Renewables have a role such as for use by various sectors to displace some utility energy or off the grid supplies. As the EIUG we do not believe grid connected utility scale renewable energy is the best economical solution for South Africa at this point in time.”
The bottom line is that South Africa’s energy intensive users are under severe pressure, of which electricity cost increases are a contributing factor. Without South Africa’s power sector making the right decisions to ensure a more competitive environment, the country’s economy is in trouble.