Energy multinational Shell says South Africa would be able to recoup the capital costs associated with a liquefied natural gas (LNG) import terminal within three to four years by using the gas to replace diesel at Eskom’s open-cycle gas turbines (OCGTs) in the Western Cape.

The electricity utility spent a whopping R10.5-billion on diesel fuel in 2013/14 to operate the Gourikwa and Ankerlig facilities, which together produced 3 621 GWh, translating into a load factor of over 19.3%.

In addition, following the recent collapse of a coal silo at the Majuba power station, in Mpumalanga, Eskom indicated that it might need to lean more heavily on the OCGT plants during the high-maintenance summer period.

Shell LNG business development manager John Shoobridge argued this month that the savings associated with switching the plants to gas should be more than sufficient to offset fears over the infrastructure costs associated with an LNG terminal, which he acknowledged would be significant.

The final cost would depend on the site and type of terminal selected, with Shell studying various possible locations after PetroSA confirmed that the ocean conditions off Mossel Bay were not suitable for a floating storage and regasification unit.

PetroSA had estimated the capital costs of such a terminal – which would have supplied gas to both its gas-to-liquids plant and Eskom’s Gourikwa plant – at between $375-million to $510-million. The national oil company indicated recently it was now interrogating alternative locations for a terminal.

Shoobridge suggested the terminal could be developed as a public–private partnership and indicated that Shell was already studying possible sites near Saldanha Bay, off the West Coast, at Coega, in the Eastern Cape, and Richards Bay, in KwaZulu-Natal.

“South Africa is very concerned about its balance of payments. Well . . . displacing the current amount of diesel that is being burnt at the OCGTs . . . can save us as much as $100-million per year,” he added.

The other potential spin-offs envisaged by Shell included creating capacity to increase gas-to-power output in the short term, while laying the infrastructure foundation for a future gas market based on domestic gas that could be mined offshore, or in the Karoo basin, where Shell is keen to explore for shale gas.

Shoobridge estimated that South Africa could develop LNG import capacity within three to five years and said the gas-fired power plants could be developed in parallel.

Gas-fired plants, he added, were far quicker to develop than either coal or nuclear and were generally half the capital cost of a coal-fired station and a fifth that of a nuclear plant for an equivalent size.

LNG imports had reportedly been incorporated into the Department of Energy’s Gas Utilisation Master Plan (Gump). However, the draft plan, which was expected to be released in June, had not yet been published.

Gas advocates believe Gump should be receiving priority, largely owing to the relative speed at which gas solutions can be deployed in the electricity sector.

Shell & Shale
Meanwhile, Shell also confirmed that the company had received notification from the Petroleum Agency South Africa (Pasa) that its applications for three exploration rights in the Karoo, which had been submitted in 2009, were being processed.

But Shell South Africa Marketing chairperson Bonang Mohale said it was also seeking clarity from both Pasa and the Department of Mineral Resources (DMR) on the precise meaning of the notifications.

Pasa confirmed in late October that it would proceed with the processing of shale gas applications received prior to February 1, 2011, from Shell South Africa Upstream, Falcon Oil & Gas and Bundu Oil & Gas Exploration.

But it said the moratorium on new applications remained in place and that the processing of pending applications was subject to a condition preventing actual hydraulic fracturing (fracking) “until the appropriate amendments to the regulations have been promulgated”.

The agency also requested the applicants to review and, where necessary, augment Environmental Management Programmes (EMPs), which could necessitate further public consultations.

Shell, which submitted applications for three blocks in a 90 000 km2 area, had already hosted two public consultation processes, leading to the generation of around 6 300 questions from the public. It had also submitted three EMPs, collectively involving documents running to over 80 000 pages.

Mohale said that, while the issuance of exploration rights was now probably “months, not years, away”, Shell had concerns about the nature of the commercial terms governing exploration and whether these were designed to encourage investment.

The true measure of “substantial progress” would be receipt of an exploration-rights agreement that had “good commercial terms” – terms that would emanate out of fracking-specific regulations that had been fully canvassed.

Pasa acknowledged that it had moved ahead in the absence of final fracking regulations, but stressed that the decision had been taken following extensive discussions with the DMR.

Mohale said the group was applying its mind to the notification letters and would be engaging with Pasa and the DMR to gain clarity. Likewise, it was continuing to raise its concerns with the DMR with regard to proposed amendments to the Mineral and Petroleum Resources Development Act, which the oil and gas industry had warned would not be supportive of new investment in the sector.

He expressed frustration at the fact that six years had lapsed since Shell first expressed interest in exploring for shale gas in the Karoo. However, he indicated that the multinational remained committed to its plan of drilling six exploration wells to ascertain whether or not there was in fact gas that could be commercially extracted.

Shell South Africa Upstream GM Jan Willem Eggink said there was a “good chance” that the programme, which would involve an investment of between $150-million and $200-million, would yield results. However, he also stressed that, as a “frontier exploration” programme, there was also the risk that no gas would be discovered.

Current estimates suggested that the Karoo basin could hold between 380-trillion cubic feet (tcf) and 485 tcf, but Shell and the other explorers argued that the actual size could only be truly determined through exploration.

Eggink said water and land remained the two major areas of anxiety for interested parties in the Karoo and gave assurances that Shell had strategies in place to deal with both concerns.

Its wells would be “sealed” to mitigate the risk of groundwater contamination, while any water used during exploration or development would either be imported into the area, or sourced in a way that did not compete with the farming activities.

Exploration well pads, meanwhile, would require an area of around 150 m2 for a single pad, together with an access road.

Should Shell proceed to development, it would probably drill up to 2 000 wells in an area. “Nowadays we can drill something like 30 wells from one of these well pads. So, 2 000 wells, if you have 30 wells per well pad, would require 60 to 70 well pads, spaced around 4 km apart.”

Eggink said that represented an area of about 30 km2, which was “roughly 1%” of the area for which it was applying.

“There are people that are highly concerned that the entire Karoo will be riddled with drilling rigs. There will be industrial activity, there will be trucks driving around, but it will be in a very focused area,” he concluded.