Evolving Middle Eastern power market
The Middle East power market, particularly in the Gulf Cooperation Council, is currently undergoing a transformation as the region shifts to more renewable energy.
The region has been attracting some of the lowest tariffs for electricity globally.
The GCC countries are Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and the United Arab Emirates.
Advances in the procurement process for independent power projects have led to increased efficiencies throughout each stage of project development.
Rising electricity demand and the ongoing energy transition suggests that IPPs will continue to be at the forefront of government strategy. There are also indications that certain states are looking ahead to an even more liberalized future through the adoption of spot markets.
The procurement model
The development model for IPPs has largely been similar across the Middle East. The government procuring authority prepares a list of pre-qualified bidders to whom draft project documents (such as the power purchase agreement, natural gas supply agreement and land lease agreement) are issued, together with terms for the technical specifications and parameters for the financing.
Bidders then hire a contractor (typically on a lump-sum turnkey basis) and arrange financing before submitting a bid to the government. Often, but not always, the lowest bidder wins.
Of course not all countries in the region are the same. The countries comprising the Gulf Cooperation Council are generally viewed as having efficient, transparent and reliable IPP procurement programs.
The process in one of the Emirates, Abu Dhabi, is a good example, as demonstrated by the Shuweihat S2 IWPP project. The EPC contract was signed, and the project was successfully financed, in the midst of the global financial crisis in 2008 and 2009.
Part of Abu Dhabi’s continued success comes from seeking efficiencies in the bidding process in response to the move toward renewable technologies in the region. With abundant oil and gas reserves, natural gas has historically been used to meet the significant power generation requirements for both space cooling and water desalination in the Middle East. However, as states look to decarbonise, investment in renewable generation has risen significantly.
In developing its renewable energy program, Abu Dhabi has tried to accommodate smaller renewable players. It recognized that bidders for gas-fired power projects were largely European or Asian utilities or other large energy companies, with big balance sheets and large, experienced business development teams. These teams could afford to incur larger development costs.
Developers in the renewables sector are not necessarily able to do this. Abu Dhabi has therefore looked to reduce development costs in a number of ways, such as by issuing a financing term sheet and EPC term sheet with the bid package. This ensures that bidders themselves will not need to spend time and money preparing these documents. It also has the added benefit of ensuring that bids are more consistent in their terms and risk allocation, which ultimately saves time in post-bid negotiations and facilitates efficient closing of the transaction.
The procurement models adopted in the region have, in part, helped to create significant reductions in the levelized cost of energy for solar photovoltaic in particular. This has meant that the Middle East has been able to capture some of the lowest tariffs for renewables recorded to date. For example, in April 2020 a consortium of EDF Renewables and JinkoSolar was named the preferred bidder for the 1,500-megawatt Al Dhafra PV project in Abu Dhabi, bidding US$13.50 a megawatt hour: a tariff reported to be the world’s lowest for solar power by Abu Dhabi Power Corporation.
Underpinning the development of renewables in the region is the “Pan-Arab Strategy for the Development of Renewable Energy, 2010–2030.” Adopted at the third Arab economic and social development summit by the League of Arab States in 2013, it includes commitments to increase the region’s installed renewable power generation capacity from 12,000 megawatts in 2013 to 80,000 megawatts in 2030.
The scale of development anticipated in the region will mean investment, research and development into other technologies needed to integrate renewables into the local energy system, such as storage and green hydrogen.
In relation to storage, the Middle East Solar Industry Association (known as MESIA) in its “Solar Outlook Report 2020,” notes that storage using lithium batteries and molten salt are beginning to be used in conjunction with solar projects. For example, the Al Dhafra PV project included an optional bid for the provision of battery storage, with this being said to attract substantial market interest.
The development of concentrated solar power has been limited in the region due to dust and humidity affecting system efficiency, but MESIA notes that hybrid CSP and PV systems may unlock intermittency issues in future. MESIA also sees potential for floating solar PV in the region, particularly because of its positive impact by reducing water evaporation.
Green hydrogen may become an important export from the region. The first proton exchange membrane electrolyzer is expected to be installed in Mohammed bin Rashid Al Maktoum solar park in Dubai by DEWA and Siemens in 2020.
Another first-of-its-kind project in the region that demonstrates the commitment to the energy transition is the upcoming subsea cable project being developed by The Abu Dhabi National Oil Company and Abu Dhabi Power Corporation. The project will reportedly allow ADNOC to reduce the carbon footprint of its offshore facilities by up to 30% by replacing offshore gas-fired electricity generation with more efficient electricity supply from Abu Dhabi Power’s onshore operations. The intention is to use project financing for the project under a long-term concession contract based on the capacity of the cables.
Oman has been an early adopter of private investment in the power generation sector, beginning the privatization process in 2004. Since then, the country has achieved complete liberalization of the generating sector and has continued toward further privatization of the transmission and distribution sectors.
Oman Electricity Holding Company (known as NAMA) raised US$1 billion of capital in 2019 by selling 49% of its shares in the Oman Electricity Transmission Company (known as OETC) to State Grid Corporation of China. This forms part of the plans for the privatization of OETC, which NAMA says it has implemented in order to “support the government’s objectives of attracting foreign direct investment into the country and promoting private sector participation as part of the wider nation-building process.”
NAMA also intends to divest up to 70% of government shareholding in each of Oman’s Muscat Electricity Company, Majan Electricity Company, Mazoon Electricity Company and Dhofar Power Company. Before the COVID-19 pandemic, the speculation was that NAMA was in the process of discussing government subsidization with potential bidders and that it expected bids to be entered for the Muscat Electricity Company by the third quarter of 2020. In the case of the other three distribution companies, the understanding is that once the initial 70% has been divested, NAMA plans to sell the remaining 30% of government-owned shares of these companies through an initial public offering.
The energy procurement-and-supply model in Oman is also subject to a considerable overhaul through the intended introduction of a spot market for the commercial trading of power in Oman. The spot-market initiative aims to improve the efficiency and transparency of the operation of the electricity sector and to provide opportunities for diverse generation sources that do not compete in the Oman Power and Water Procurement’s normal tender process for water and power supply. OPWP would play the role of market operator and purchaser, purchasing energy from generators who supply to a pool and managing that pool.
Once the Omani spot market goes live, existing power purchase agreements will remain valid and the obligations under them will be honored through the end of their respective terms. Current generators will not be forced to operate as merchant generators immediately upon the activation of the spot market.
However, current generators have been obliged to enter into a consultation process as a result of an amendment to generation licenses. Generators are being required to provide structural, technical and other data to OPWP. Naturally, generators will want to understand better how OPWP will administer the new rules, dispatch generators and handle the transition to a more market-based model.
Despite having launched a consultative process in 2017, the Omani spot market appears to be some way off from being implemented, and there remain many unanswered questions about how it will work.
As of early June 2020, it also remains to be seen how the market will react to recent reports that OPWP threatened to hold back certain payments due to generators under existing contracts. Certain generators have issued notices to the Capital Markets Authority in Oman indicating that certain payments under power purchase agreements may not be honored. The state-owned power purchasers in the GCC have a strong reputation for honoring their payment obligations and any move by OPWP to default on its payment obligations to generators would of course affect sentiment and the ability to attract foreign investment in the future.
The financial crisis shifted the way most bidders in the GCC fund their projects.
Before the crisis, most bidders for GCC projects would fund through a combination of equity bridge loans (to reduce the electricity tariff) and senior facilities provided by commercial banks, perhaps with export credit agency support. Financings typically provided tenors falling just short of the term of the power purchase agreement.
After the financial crisis, bidders in the region started turning slowly to mini-perm structures, where the senior debt must be refinanced a short time after completion of construction. This brought more liquidity to the market, as, in the aftermath of the financial crisis, not all banks were prepared to lend on a 15- or 20-year basis to a single-asset project company.
There are generally two types of mini-perm structures: “soft” and “hard.” A soft mini-perm is generally one where, from the target refinancing date, the senior debt is prepaid under a mandatory-prepayment or cash-sweep mechanism, with a margin ratchet applying. A hard mini-perm is less complicated, from a documentation perspective. It provides for a balloon repayment on the target refinancing debt, thereby putting the project into a non-payment event of default if that balloon payment is not made.
The more competitive pricing that may be offered for a hard mini-perm must be balanced against the different consequences between a hard and soft mini-perm, as the lenders would not typically have a right to enforce security if a soft mini-perm is not refinanced by the target refinancing date. That said, sponsors will be no less motivated to refinance as, under both structures, the dividends would cease to be payable in the event of a failed refinancing.
Governments were generally open to these new financing arrangements and have become more and more comfortable with the passage of time. This may be driven, in part, by a degree of confidence that the projects are well structured and well operated, and therefore well placed to refinance successfully in either the bond or bank debt market.
Certain jurisdictions such as Saudi Arabia and Abu Dhabi also benefit from strong sovereign credit ratings, which facilitates refinancing in the bond market. Refinancing risk largely remains with the foreign investors.