IPPs re-negotiation: where to begin?

The power sector inquiry report has proven to be a great equalizer: in that it has agitated IPP sponsors across the board. Projects from 1994 and 2002 policy have been criticized as have been CPEC IPPs. The issue is sensitive and is subject to negotiation with the stakeholders. The flak, however, falls on regulators and decision makers in power at the time these projects were approved.

IPPs like any commercial decision makers pounced upon the opportunity to make good returns within legit means. The adverse outcome is twofold. One is that energy (mainly electricity) is becoming expensive and the other is investment climate is not conducive for risk taking. For latter, it is important to give signal to investors that they must take risk to make returns. Thus, negotiation with IPPs is important. But there won’t be enough savings to have any meaningful impact on the cost of electricity i.e. consumer tariffs. Not to mention lowering electricity cost is imperative for better investment climate as at such high cost manufacturing is becoming infeasible.

On reducing tariff or cost of electricity, facts must be reviewed holistically. Under 2015 policy, numerous new projects came online and others are on the way. Majority of new projects are government owned and a few are under CPEC. Cost of production (fuel) has reduced significantly in dollar terms due to better plant technology (higher efficiencies) and better choice of fuel (RLNG, coal versus FO). The upcoming plants would cause less strain on foreign exchange (due to local coal, nuclear, hydel etc). Apart from coal, rest have less strain on environment due to low carbon footprint.

Thus, it is better to have new projects that drain foreign exchange less, are better for environment and boast lower cost of production. The problem is the speed at which projects are coming online, and in their tariff structures where debt payment must be repaid in early days. Capacity payments is growing while the energy consumption is not growing in tandem. Demand is low and capacity to evacuate is weak. Growing capacity payments are indexed in dollars and further inflate in PKR due to currency devaluation. This makes energy expensive as saving on fuel is more than offset by higher capacity charge. Demand is also a function of price. At higher price, demand growth is to be lowered. Thus, dollar indexation must be revisited in many cases.

The capacity payment in NTDC system was Rs185 billion in FY13 and has increased to Rs640 billion in FY19. The increase is due to combination of new capacities and currency depreciation. The capacity payment is expected at $6.5 billion (Rs1,030bn at 155 PKR/USD) in FY20. This is going to increase to $11.3 billion by FY25. In current terms currency parity, this amount would be Rs1,765 billion. This is going to drive cost to unsustainable levels.

The number has grown till FY19 (from FY13) based on new plants in RLNG, imported coal, renewable, nuclear and hydel projects. Now onwards, bigger new addition contributors are nuclear, Thar coal and hydel projects. The debt component of new plants is to paid by in first 10-12 years of project life. The tenor of these loans must be extended.

For example, total capacity of CPEC projects is 5,677 MW. If debt repayment is extended to 20 years, the saving per unit is going to be 68 cents. The debt cost is high too. For some its LIBOR plus 4.5 percent. Reducing the margin of debt to 2 percent will save another 16 cents per unit. There is insurance cost of 6 percent too. All these negotiations have to between G to G (govt of Pakistan with govt of China). Some say that request has already been made to do so.

Similar are the numbers for government own projects. Out of Rs1,045 billion payments (on PKR/USD at 155) in FY21, Rs528 billion (50.5%) is of government own projects and Rs191 billion (18.3%) in CPEC. Thus, 68.8 percent of payment in FY21 is to CEPC projects and government. The toll will remain same till FY25. Thus, government must first negotiate with itself and then with CPEC projects. The share of 1994 and 2002 policies will reduce from 13 percent (Rs134bn) in FY21 to 6 percent (Rs109bn) in FY25.  Actions on these is important for better investment climate and fair treatment, but savings on them are peanuts.

The other leg of the problem, not (really) touched by any government is the T&D losses and poor recovery of bills by DISCOs. These are big companies by size and are not at SME standards on operations. The leakages are suffocating the economy. In FY18, T&D losses were 18.3 percent and revenue collection was at 88 percent. Global average of T&D is 8 percent. In 1991, Bangladesh T&D losses were 31 percent while that of Pakistan was 20 percent. Today, Bangladesh is at 11 percent while Pakistan is still close to 20 percent. The annual savings of reducing T&D losses to 11 percent and improving the recovery to 98 percent can save $675 million and $1,033 million, respectively.

In a nutshell, reduction in T&D losses ($675mn), improvement in discos collection ($1,033mn) and changes in CPEC debt ($394mn) collectively can save $2.1 billion or 1.62 per unit savings.  Government own projects numbers are in addition to that. Moreover, many industries are relying on captive power generation, these must be moved to grid by incentivizing on pricing to increase grid consumption to lower capacity payment per unit.

Sources reveal that government is mulling over options to not take out profits on its own projects. The potential saving is around Rs70 per year in two years’ time. Government owned plants have 17 percent guaranteed returns. In addition, options to extend government projects debt tenor are being discussed too. Some say that government is asking CPEC to be revisited as well. All these can be done in good faith and will go a long way towards making energy affordable. However, the catch is in T&D losses and revenues of DISCOs. The savings are huge. But it’s a governance issue and a tough nut to crack.