Thoughts on Gas Pricing Mechanisms for South Africa

South Africa is a mineral rich country with an energy intensive economy. Its electricity sector, a vital part of its economy, relies heavily on coal to produce well over 85% of all its power from this indigenous resource. Lack of energy diversity means less energy security as the country’s electricity production is highly carbon intensive with over 800gCO2/kWh – a situation which has resulted in several environmental and economic problems.

The South African government, through the Integrated Resource Plan of 2019 (IRP 2019) and recent reductions in regulatory barriers to self-generation, has signalled an intention to lessen the state’s role in the electricity sector. Consequently, rapid diversification of the power sector now a possibility. A decade after the launch of the Renewable Energy Independent Power Producer Procurement Programme (REIPPPP) in South Africa, it is expected that a range of renewable energy technologies will lead the diversification. AIA believes that, in the short to medium term and until large scale battery storage becomes viable, South Africa will need to pair the rapid adoption of renewable technologies with natural gas usage – which would provide backup to renewable’s intermittency and take advantage of the abundant natural gas reserves in the Southern African region (Mozambique, Angola, Tanzania and potentially South Africa).

Reportedly, South African natural gas reserves and the Mozambican Pande and Temane onshore gas fields, that have serviced South African demand for the past 17 years, will start to decline by the middle of the decade. Whilst the South African government looks to develop offshore reserves, it will need to consider Liquified natural Gas (LNG) imports to close the supply gap, and meet the immediate power generation requirements and enable the introduction of new industrial users to the market. All  of these developments will likely see a greater role for LNG in South Africa’s energy supply mix.

Natural gas utilisation, for both industrial purposes and power generation, has been a hot topic in South Africa, so we at AIA decided to investigate and write on the complexities that exist in LNG and natural gas pricing, which would assist contractors in weighing the associated risks and benefits.

Natural gas is a commodity with a relative low energy density (and hence value per volume) when compared to commodities such as coal and oil. The fact that it requires very low temperatures to be transformed to a liquid, makes it difficult and expensive to transport in forms other than through pipelines networks, which require large upfront investment. Consequently, the global LNG market has remained fragmented and dominated by a small number of very large producers and gas consumers. This has limited the development of a liquid global LNG market and the different market players have therefore tended to opt for the use of pricing indices based on proxies such as the oil price.

An alternative approach has been to link LNG contracts to prices in other gas and LNG hubs. Traditionally, East Asia and Japan - in particular- as the biggest LNG market globally, has provided the key reference for LNG price formation. This led to the establishment, by S&P Global Platts of the JKM price marker in 2009. However, Japan has traditionally lacked a domestic pricing framework and so this price has itself tended to track the oil price. Elsewhere, countries with large domestic gas markets and production (such as the US and Western Europe) also saw the development of domestic gas hubs linked to liquid markets.   

With transportation differentials increasingly driving Asia-Europe price spreads, Atlantic traders are using European gas hubs' liquidity and financial instruments to trade arbitrage opportunities between Atlantic and Pacific basins. Ironically, this has established Europe as a global benchmark for LNG spot prices.  

Consequently, three gas benchmarks have come to play an important role in global LNG pricing. Each linked to the three largest gas consuming regions – the Far East, Western Europe and North America.   

1. Title Transfer Facility (TTF) - Netherlands 

Europe collectively consumes 20% of all traded LNG with two benchmarks, namely National Balance Point (NBP) in the UK and Title Transfer Facility (TTF) in the Netherlands. While TTF is primarily a Spot Market Driven market, it is likely to become the standard European LNG pricing benchmark.  

2. Japan / Korea Marker (JKM - Platts) 

Asia consumes over 50% of all traded LNG and has only one accepted benchmark, the Japan/Korea Marker LNG Price Assessment (JKM), which is also a Spot Market Driven pricing benchmark. The pricing for this benchmark is driven by the Japanese Crude Cocktail. The China Pricing Hub is potentially expected to come into operation sometime after 2025 and could pose a threat to the JKM benchmark. 

3. Henry Hub - USA 

The United States of America (USA) consumes around 20% of the global LNG trade. It has two liquid benchmarks because of its immense shale gas production upsurge, Gulf Coast FOB Hub (Platts) and Henry Hub. The emergence of a toll manufacturing LNG production model in the USA, with LNG buyers purchasing gas and then contracting with large liquefaction utilities to produce LNG, has seen Henry Hub emerge as a third global LNG pricing benchmark. 

A key question for both prospective and existing gas users in South Africa is:  what pricing benchmark is likely to apply to South Africa? We believe that this is likely to be a function of the preferences of gas suppliers,  and the large buyers and the balance of their relative bargaining positions.

In our view, South Africa, given its position as a sizeable gas market in the southern hemisphere and proximity to one of the world’s largest gas reserves, may find itself in a position to secure slightly more favourable gas pricing terms. It may be argued that South Africa, given the strong influence of coal in the energy mix currently, should be able to negotiate coal linked pricing. Japanese utility Tokyo Gas' LNG contract with Royal Dutch Shell, which was partly linked to coal prices, provides precedent for such price diversification negotiations.

However, in the short to medium term, it is likely that gas users may have to accept some form of oil indexed pricing. This view is based, not only on the traditional nature of gas contracting, but also the likely anchor customers that will underpin LNG importation initially. Sasol and power generators will likely provide anchor demand to motivate the development of LNG importation infrastructure in South Africa. Sasol, as a company that derives the bulk of its revenue from the production of chemical and fuel products with a strong correlation to the oil price, is likely to want to negotiate a pricing formula that is linked to global oil prices to hedge their risks. From a gas-to-power perspective, the National Government and the regulators have been reluctant to see South African electricity producers pass through changes in gas price to the electricity price on any large scale. Interestingly, this hesitancy was not evident in the recent Risk Mitigation IPP, where the Department of Minerals and Energy appeared to be willing to see the pass-through of gas prices changes into the electricity price. We are therefore of the view that large buyers and sellers of LNG in South Africa are both likely to opt for, or at least accept, an oil linked pricing formula for LNG in some form.  

Gas in South Africa is currently priced against a weighted basket of energy carriers that has included coal and electricity. A switch to a pure oil linkage will not only increase the price of gas to consumers, but also add a great deal of volatility to gas pricing in future. Gas buyers are going to need to carefully consider their business model and contractual arrangements to ensure that they will be in a position to adequately manage this new, more volatile cost environment.   

Food for thought: 

An interesting alternative to such an oil indexed pricing outcome would be for Southern Africa to develop its own gas pricing hub. While this is an intriguing possibility, there remains substantial issues to address for such an outcome to be a reality. This, however will be the subject of a further article in which we will unpack what steps are required to enable such a hub.