Distributed solar generation in the Middle East
With the commercial case for distributed generation set to improve, Alan Whitaker and Hisham Abunassar explore its impact on commercial and industrial consumers, regulators and single buyers in the Middle East.
What is distributed generation?
Distributed generation (“DG”) (also called on-site, decentralised, behind-the-meter or embedded generation) is the generation of electricity at or near the point of final consumption, rather than energy transmitted over the electric grid from a large, centralised power generation plant.
DG is typically installed before the meter which is used to measure the consumer’s electricity consumption. It therefore acts to reduce the volume of electricity consumption for which the consumer has to pay the grid tariff.
DG is not new. Countries around the world have allowed or licensed this form of generation for decades. Strong economies of scale in conventional power generation technology have typically meant that electricity from the grid is lower cost and uptake has been limited to consumers who are far from the central network or have non-cost reasons (such as wanting to lower their carbon footprint) for using DG.
The business case for DG is improving rapidly
Rising retail tariffs, mainly driven by the removal of subsidies, and falling solar and battery costs are rapidly improving the commercial case for DG from solar PV. Figure 1 illustrates this for Dubai.
Figure 1 – Retail tariff and levelized cost of solar PV at different scales ($/MWh, real 2020 money)
Note: Utility PV assumes bifacial tracker technology, while Commercial PV assumes monofacial fixed mount technology
For an industrial or commercial consumer, the cost of energy from commercial-scale on-site solar generation is lower than the retail tariff. A battery with 2h of storage capacity adds ~$42/MWh, increasing the levelized cost substantially.
However, an LCOE vs. retail price comparison does not tell the whole story. In practice, even with a battery, a distributed system will not always be able to generate when the consumer requires it to. Hourly modelling of the demand and solar profiles is needed to properly understand the business case.
Some consumers can make substantial savings on their energy bills
We have used our BID3 power system model to derive the optimal supply mix from PV, battery and grid electricity sources. We modelled several test cases with different combinations of technology cost and grid use (Figure 2).
Figure 2 – Test cases for the DG solar, battery and grid optimisation model
Case 1 considers a grid-connected consumer seeking only to minimise its costs. In moments where on-site supply is not sufficient to meet demand, the consumer imports from the grid at the standard retail tariff. Battery and PV capital costs are those currently seen in the market.
Case 2 considers a consumer pursuing self-sufficiency. For example, it may want to tell its customers that its energy is “100% from renewable sources”. In this case, there is no alternative electricity supply and the customer needs to shed load if on-site supply falls short.
Cases 3 and 4 are the same as 1 & 2, but the capital costs of PV and battery technologies reduce by 31% and 42% respectively.
The sale of electricity in excess of demand in each hour has not been considered.
Figure 3 shows the average supply cost and the share from each source, in each case.
Figure 3 – Average cost of energy in different cases ($/MWh, real 2020 money)
At today’s PV and battery costs, a commercial consumer with a peak demand of ~10MW willing to use a mixture of on-site and grid electricity (Case 1) would optimally build ~12MW of PV capacity, which provides 33% of its energy. 10% of the PV generation is curtailed (wasted). The consumer realises an average cost of $96/MWh – a saving of 18% on the grid tariff.
If the consumer wants to be self-sufficient in electricity (Case 2), a much larger PV capacity (42MW) is needed. This is six times larger than the average demand (7MW). In many hours there is an excess of power which is either wasted (20%) or stored (58%) for later use. A storage capacity of 119MWh is needed, which is equivalent to 17 hours of average demand. This allows the consumer to cover demand during periods where solar output is consistently low and demand is consistently high. Only 1% of the consumer’s demand is not met. The consumer’s overall cost of energy is $149/MWh.
Lower technology costs (Cases 3 & 4) lead to an increased share of energy from PV, and lower overall supply costs.
It is not clear that DG is the “right answer” from a system perspective
Retail prices have already incentivised C&I-scale and, to a lesser extent, residential-scale investment in places like Dubai and Jordan, but a system perspective suggests that utility-scale projects may offer lower overall costs. As Figure 1 showed, the levelised costs of C&I solar PV projects are higher than for utility-scale projects. Transmission and distribution costs add ~$20/MWh for utility projects, but this does not change the overall picture.
Arguably, though, central planners are not building utility-scale solar fast enough. Smaller-scale, embedded projects could provide a way to get capacity connected quickly – it’s not the lowest cost solar, but it’s better than not enough solar. This argument depends on how one expects solar costs to evolve. A rapid system transformation today may not make sense if solar costs are halved by tomorrow.
Regulators will need to ensure DG is properly incentivised
Whatever the regulator’s views of the ‘right’ solution are, it will want to make sure that effective rules and incentives are in place to deliver it.
The retail tariff is one of the main price signals affecting the business case for embedded generation. In the Middle East, some or all of the following distortions mean this signal is far from perfect:
- Fixed vs. variable costs: Although tariffs are based on actual total costs, they tend not to reflect the utility’s underlying cost structures. Most of a power system’s costs are fixed – consisting of capital and fixed O&M payments. In Abu Dhabi, for example, these account for ~75% of system costs, growing to ~85% by 2030. These fixed costs mainly depend on total system demand in a small number of hours each year. However, for most retail tariffs, fixed charges are low or non-existent, and variable charges do not depend on time of use. The net effect is that the costs avoided by the consumer through its embedded generation are greater than those avoided by the utility.
- Erosion of the consumer base: Higher volumes of embedded generation mean lower volumes of grid consumption. In the short term this can increase retail prices as the utility’s costs need to be recovered from a smaller demand. So, the more some consumers benefit from low-cost embedded generation, the more other consumers lose out from higher retail costs.
- Average cost vs. value of electricity: Generally retail tariffs are set so as to recover the system’s actual costs, as it stands, rather than the marginal costs of a notional, efficient system. The retail price may, therefore, be higher than the true marginal value of grid electricity, tipping the scales in favour of embedded generation.
- Subsidy decreases the retail price and discourages embedded generation. It can be injected throughout the electricity value chain, but is often seen in fuel prices and at the distribution/retail stage. Cross-subsidies between consumer types are also common.
In an ideal world, regulators would seek to improve the retail price signal. The following reforms could be considered (in order of increasing difficulty of implementation):
- Removal of cross-subsidy between consumer groups
- Remove (or avoid) net metering arrangements 1 . Grid exports should be paid based on their value to the system, net of any use-of-system costs
- Change retail tariff structures to reflect underlying utility cost structures (i.e. higher fixed costs and lower variable (per unit) costs; time-of-use pricing)
- Base retail tariffs on the marginal value of electricity, rather than average costs
- Liberalise wholesale and retail markets
Given the difficulty and time needed for these reforms, some regulators and utilities are considering a shorter-term solution: restricting the licensing of DG projects.
The economics of DG are going to continue to improve in many markets under the current retail tariff regime of volume-based charging based on average production costs, where charges do not depend on time of use.
DG will become a key issue for regulators and single buyers. They will need to carefully design wheeling, licensing and net-metering arrangements in order to harness the benefits of DG without adversely affecting the wider consumer base.
- 1. These allow consumers to offset electricity consumed at one time with electricity exported to the grid at another. ↩