Rapid population growth combined with ambitious industrial and economic expansion programmes have led to a growing need for power in the Middle East. As a result, demand for electricity in the region is forecast to treble by 2050.

Since the 1970s, regional production of electricity has been predominantly fueled by oil and gas. Utility companies in this sector are now looking at alternative fuel sources, and renewable sources are at the core of diversification plans.

The drive to integrate alternative energy sources into utility networks is set to accelerate in 2020 as governments seek to address the rising demand for power. Integrating greater contributions from variable renewable energy technologies such as wind and solar photovoltaic (PV) into power systems is essential for decarbonising the power sector while continuing to meet the growing demand for energy. However, doing so is not without challenges, as production from solar and wind in particular is intermittent.

The integration of intermittent energy supply into a power system, while technically manageable, requires skill, planning, political will and considerable investment.

Lowering consumer prices

Many GCC states are focused on launching renewable energy schemes in order to benefit from cheap solar energy to boost their energy security in a time of regional and international volatility. The GCC has to date awarded 7,935MW of solar PV and 450MW of wind power.

The tender processes for renewable energy independent power projects (IPPs) have seen record-breaking tariffs significantly lower than those for conventional energy.

This year, the Fujairah F3 IPP secured the lowest tariff for a combined-cycle gas turbine power plant at $cents4.56 a kilowatt-hour (kWh), while the Al-Kharsaah solar PV IPP secured a bid at $cents1.745/kWh.

These tariffs, the lowest electricity dispatch tariffs secured – where cheapest power is dispatched first – will assist in minimising the overall electricity system cost to consumers, allowing for some peak power to balance the system and meet demand requirements.

Energy system integration coupled with digital innovation is expected to help energy providers to effectively manage peak loads, ensure supply security and optimise grid efficiency, thereby creating a robust platform for smart energy. The majority of costs relating to grid upgrades are sunk costs to be carried by the investor, which is either public or private, or the grid operator. 

The technological and operational capabilities that this requires fall within the domain of a private sector operator. Accordingly, governments are increasingly considering divesting transmission and distribution (T&D) assets, passing on the technical and operational efficiencies brought in by the private sector directly to the end consumers, with the additional benefit of secure funds for government through asset recycling.

Recovering costs

These system upgrades would need to be factored in to the capital expenditure investment plans that potential bidders for the T&D companies must consider. The onus then lies with countries to strengthen their regulatory regime in the power sector and develop market acceptable recovery or payment mechanisms.

The expectation of lower returns due to underdeveloped recovery mechanisms could disincentivise potential private sector entities to bid for or invest in such assets.

Oman, through the Authority for Electricity Regulation (AER), provides for the recovery of sunk costs in T&D systems through the maximum allowable revenue (MAR), if deemed efficient. 

AER has followed a retail price inflation (RPI) minus expected efficiency improvements (X) revenue cap regulation, defining the maximum allowed revenue for each year of the price control period and adjusting it to reflect the potential cost savings of the regulated companies, due either to increased efficiency or technological improvements. The computation of the MAR is transparent and based on published rules.

Another method used for transmission lines is the annuity model – a fixed annual payment covering cost and return on investment. Given that there is no demand risk on offer, concessionaires are willing to invest in rapidly changing markets.

While regulatory reform is one lever for recovery of investment in grid upgrades, utilities need to combine other levers – different technologies and processes – which include:

• Connecting renewable energy assets: these assets are unlikely to be located near existing generation assets, which further necessitates the need to incentivise investment in new connections, transmission and distribution lines;
• Procurement of flexible generation: to manage the electricity system, there will also be a need to procure ‘flexibility’ services from generators or demand side response from large customers. This may require new systems, processes and potentially investment in ‘peaking’ plant or battery storage; 
• Enhanced coordination between transmission and distribution systems, linking integration to other developments such as electric vehicles, roof-top solar panels, smart metering and grid management. 

Together, these levers would ensure grid flexibility and stability, enabling the integration of new technologies ranging from battery storage to electric vehicles while establishing new, commercially attractive business models for a smarter, greener sector. 

About the author

TM Sudarshan is an assistant director in Deloitte’s Government and Infrastructure team. Based in Dubai, he focuses on energy, infrastructure and public sectors

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