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Eskom presents its cost recovery application to Gauteng stakeholders in Soweto
Friday, 11 May 2018: Eskom has today presented its case in Soweto to recover a variance in revenue between what was allowed under the third multi-year price determination (MYPD 3) process and what was actually spent in the three years (2014 – 2017), which amounts to R66bn. Senior executives presented Eskom’s capacity situation and context for decisions taken during this period, thus showing reasons how costs were incurred as Eskom was implementing its mandate of supplying electricity.
 
Calib Cassim, Eskom’s Acting Chief Financial Officer explained that the Regulatory Clearing Account (RCA) application under review is based on the MYPD 3 regulatory methodology and decision and principles followed by the National Energy Regulator of South Africa (NERSA) on the RCA decision for 2013/14. “Variances can be linked to two key sources, which are increases in costs due to a changing environment and assumptions made for purposes of the MYPD3 revenue decision which did not materialise. The RCA methodology allows for certain elements of Eskom’s revenue and costs to be in favour of Eskom where our costs were higher than anticipated and in favour of the consumer in instances where we spent less than planned. A case in point is less usage of the open-cycle gas turbines (OCGTs) in 2016/17 due to the improvement in our power stations performance and new generating units from our new build programme starting to contribute to the electricity grid. This has led to a claw-back in favour of the customer totalling R1259 million”.
 
Thava Govender, Group Executive for Generation explained how the country’s energy policy decisions to exclude Eskom from building new generation capacity in the late 1990s and the requirement in preceding years for Eskom to keep the lights on at all costs led to higher usage of plant and OCGTs while Eskom was waiting for its build programme to bring new plant on line. “As the de facto supplier of last resort, our mandate required us to use whatever resources we had in order to keep the lights on. The electricity system was constrained and a decision was taken to delay maintenance, which then led to deterioration of plant, most of which was already in midlife. This is unfortunately the time when you need to do more intrusive maintenance but we had to balance demand and supply and didn’t have the opportunity to do maintenance. We did manage in subsequent years to remove the requirement to keep the lights on at all costs from our shareholder compact and resumed with proactive maintenance. However, it must be noted that even in retrospect we believe that there is little we could have done differently as a supplier of last resort given the conditions we faced in those years. In this regard, Eskom has agreed to implement the approach to sacrifice the additional OCGT costs and recovering at coal cost equivalent. The costs we have applied for in this RCA were prudently incurred in the implementation of our mandate to supply reliable electricity,” he said.
 
Dan Mashigo, General Manager for the Primary Energy Division zoomed into coal and other primary energy costs that were incurred versus what NERSA allowed. “Balancing demand and supply meant that our coal-burn volume per power station increased as we ran all our plant flat out, beyond design parameters for which level the coal supply contracts were established. In its MYPD 3 revenue decision NERSA made a determination for the average benchmark coal price to be lower than Eskom’s actual price for the previous year. It was also lower than the coal price that Eskom applied for in its revenue application. NERSA’s methodology caters for this price variance through a risk-sharing mechanism. In these RCA applications Eskom has applied the methodology. In NERSA’s Decision on Eskom’s RCA application for 2013/14, NERSA agreed with Eskom’s approach,” Mashigo explained.
 
Gerrie Bronkhorst, General Manager for Capital Expansion gave a picture of how the country’s late decision in terms of building new generation capacity meant that Eskom had to go into building mega projects as quickly as possible with very little planning time. This then led to problems arising during the building time, which also meant delays and cost movements, which impacted available capacity and funding. “The investment decision to build Medupi (and other stations) was needed by not later than 1999 to meet increasing demand by 2007. What happened was that Eskom was given a go-ahead to build only in 2004, which was already too late. Eskom took on the task and finalized a business case for the new build in December 2006. We have created risk-adjusted schedules to provide a more realistic view on schedule and funding and continue to focus on bringing new capacity on line.”
 
ENDS