Resolving power sector woes|Translate into Urdu IDAWN Article 23-09-2024

THE task of the country’s population has been reduced to keeping power sector entities afloat, by bearing unaffordable tariffs. And yet the sector’s financial viability remains in doubt. How did we get here? The reasons include incompetence, misgovernance and unadulterated theft. The terms were poorly negotiated with investors.

Agreements with private IPPs were drafted with limited professional input, stained by issues of patronage and lack of transparency. The issues include currency mismatch — payments to them were denominated in dollars against revenue streams in rupees — generous concessions (for example, sovereign guaranteed returns on equity of 15 per cent in dollar terms and income tax exemptions during the contracted period), and the government covering all risks.

What’s more bizarre is that government-owned power plants, managed by non-professionals, were established on the same terms as those bestowed on privately owned ones. ‘Circular debt’ is the outcome of these fundamental issues that have rendered the economy uncompetitive and thus a huge constraint to sustainable growth.

Examples of incompetence include the slow pace of expansion of transmission and distribution (T&D) systems compared with the installed capacity of generation. Their capacity today is merely 22,000 MW (add to it the Lahore-Matari transmission line operating at 40pc of its designed capacity), resulting in 50pc of the generation facility being unutilised but still receiving capacity payment. This liability has become excruciating, with the idle capacity payment increased from 60pc to 85pc under the 2015 policy.

The currency mismatch has induced tariff increases following the sharp adjustment in the rupee’s value — from the rate when agreements were signed — and higher interest rates. This contributed to reduced demand, for reasons including the closure of several textile units and the shift off-grid by some with their own power arrangements. Sluggish growth and subdued demand necessitated that obligations for capacity payments be discharged by raising the rate per unit for recovery from fewer consumers, a subject of widespread debate, if not anger. The burden is made more painful by taxes of almost 30pc of the electricity price.

To address the inadequacies of T&D systems, several reforms are required.

The result is that whereas capacity utilisation costs are 30-35pc globally, ours are now 62-70pc. More importantly, 50pc of capacity payments are to government-owned generation plants. Of the remainder, 35pc goes to Chinese-imported, coal-fired, dollar-indexed projects, with the unit cost much higher than that of local coal-based plants. Other sectoral issues have been over-invoicing by IPPs, with the Central Power Purchasing Agency looking the other way, supplemented by Nepra’s lack of regulatory oversight. Several public sector Gencos are old and outdated plants, resulting in inefficient fuel consumption, with low utilisation (2.7pc in the case of Jamshoro) but with a bloated idle workforce.

To address the issues, the starting point should be the Gencos commissioned by the public sector. The old ones should be quickly phased out, thereby not only minimising the payout on capacities but also enabling the operation of efficient units. The terms should be renegotiated for the remaining, with lending banks (contract period, invoicing currency considering that even local resources are being priced in foreign currency, the dollar-indexed rate of return on equity, etc.). Public sector Gencos being dollar-based and dollar-indexed, the government cannot expect to negotiate different terms for privately owned IPPs. In fact, the government should take the entire associated debt onto its balance sheet to be serviced through general revenues, instead of burdening the economy’s competitiveness through high tariffs.

The decision to extend the tenure of the contracts of IPPs set up under the 1994 policy was a poor one. The sustainable choice is to persuade them — the contracted period having been completed and the debt paid off — that generated energy would be procured in rupees. and only if it is at competitive rates.

The units established under the 2002 and 2006 policies, mostly by Pakistanis, should be persuaded to accept upfront a significant percentage — not the full dues — of capacity-related commitments for the remaining contracted period of roughly two to three years, with their debt obligations discharged. Thereafter, their contracts should be renegotiated along the lines proposed for the 1994 policy.

However, for Chinese IPPs launched in 2016-17 (guaranteed 20pc in dollars), a different treatment will be required as they would resist any revision in the contracts, arguing that their contracts factored in the lessons learned from the projects commissioned under the 1994 and 2002 policies. Two possible options could be: a) extend the contract period, and b) the release of some capacity to be freely traded in the market. Finally, taxes on bills should be lowered, employing several other options to control the fiscal deficit. These interventions will enable, in the medium (three to five years) term, full exploitation of rapid technological developments in renewable energy options.

These efforts should be complemented by adequate and timely investments to address the technical inadequacies and governance issues of T&D systems.

To this end, several reforms are required in service delivery, including: a) simplification of the tariff structure, which is littered with several bands for each consumer category and encumbered by a host of cross-subsidies; b) examining the potential to outsource Discos’ management and installation of smart meters (the prepaid variety) to tackle the 17pc technical and distribution losses, corruption, consumer theft of electricity and the weak effort to collect bills amounting to some Rs600 billion (factors constraining this option, especially the single-buyer, single-seller in the value-chain, were discussed in the ‘Privatisation of Discos’ in these columns); c) pricing energy on a marginal cost basis to stimulate demand and contribute to capacity payments (the scope will depend on the transmission system’s capacity); d) forcing public sector defaulters to pay up or get disconnected; e) withdrawing concessional electricity provisions; and f) adopting transformer-based load-shedding, instead of the present feeder-based one.