One year ago this month marked a watershed in the Nigerian electricity industry. It was in August 2013 the Nigerian electricity sector effectively became private sector led with the final payments made by core investors for privatised PHCN successor companies (Gencos and Discos). What makes that moment historic is not so much about the technical change of baton, but so much about the change of course and our collective hope for a better electricity industry.
The government have since put the proceeds of about US$3 billion in its back pocket while expecting another US$5.6 billion – US$5.8 billion from the on-going privatisation of Nigerian Integrated Power Plants Projects (NIPPs). The new investors in the privatised power assets have also carted away their prizes (in different categories as we shall later see) which were formally handed over to them November 1, 2013. But one year after that defining moment, the intended and ultimate beneficiaries of the reform – consumers, are still dancing disco in darkness. One must admit though that in spite of today’s challenges, the future has never been brighter and our destination has never been so close.
Out of the total expected purchase consideration from privatised PHCN successor companies of US$3.092 billion, about US$2.77 billion in dollar and dollar equivalent has so far being paid to government with approximately 47% from the distribution companies (Discos) and the balance of 53% from generation companies (Gencos) – both thermal and hydro. Cumulatively therefore, proceeds from investors from the concluded and on-going power sector privatisation programme is expected to hit about US$8.697 billion.
But how do these assets compare in terms of acquisition cost? Ranking the privatised power plants based on their respective acquisition cost and capacities, as imperfect as it seems, throws up interesting perspectives. While the average acquisition cost of all PHCN successor power plants stands at US$0.64 million per megawatt of installed capacity (excluding annual payments to government by the two hydro power plants) or US$0.37 million/MW (excluding the two hydro plants), that of NIPPs is US$1.12 million/MW. This is expectedly so because PHCN power plants under the former PHCN are not as new as NIPPs and should ideally be priced lower. On the basis of installed capacity, the PHCN power plants thus; Hydro – Shiroro (US$0.19 million), Kainji (US$0.34 million) and thermal – Sapele (US$0.20 million), Afam (US$0.28 million), Ughelli (US$0.31 million), Egbin( US$0.43 million- adjusted for 30% equity held by the government), and Geregu I (US$0.63 million – adjusted for 49% equity held by the government). A closer scrutiny however reveals that available capacity paints a different and perhaps better picture because it translates to immediate cashflow and higher time value of money from day one, ceteris paribus. The thermal power plants log table changes on the basis of available capacity as follows; Egbin – US$0.52 million, Ughelli – US$0.9 million, Geregu I – US$0.94 million, Sapele -US$2.23 million and Afam – US$4.54 million while the two hydro power plants maintain their position as follows; Shiroro – US$0.25 million and Kainji – US$0.54 million
In the case of the NIPPs, it appears investors in Alaoji, Calabar and Olorunsogo have secured very attractive acquisition deals prima facie, subject to other quantitative and qualitative factors. Based on per megawatt of installed capacity, the three plants rank thus: US$0.798 million, US$0.986 million and US$0.996 million respectively. At the other end of the table are Geregu II, Gbarain and Omotosho with US$1.36 million, US$1.34 million and US$1.29 million in that order. In between are Omoku -US$1.20 million, Benin – US$1.14 million, Egbema – US$1.09 million and Ogorode – US$1.05 million.
A note of caution here – an analysis based solely on quantitative factors tells only one side of the story and may not accurately reflect latent value capture by the new investors. Other equally important and specific considerations that could add, defer or destroy value in any of these acquisitions include gas accessibility and infrastructure, corporate governance, quality of management, power evacuation infrastructure, access to and cost of capital, plant efficiency and type, the level of project completion by the government (NIPPs), the relative CapEx requirement to ramp up to full capacity and availability of ancillary assets such as proximity to waterways that present opportunity for other revenue streams.
Therefore, an analysis that mirrors all these variables, though in some cases difficult to measure, provides a better comparative assessment of the relative attractiveness of the acquisitions. In the final analysis, regardless of the fact that payback period may or definitely will differ across power plants, acquisitions made in the Nigerian power sector is, incontrovertibly, good long term investment decision.
Digressing a bit, it bears noting, and strongly too, that out of the total purchase price paid so far for privatised PHCN power assets, financed largely with debt of up to 70% (probably more), about 80% of the acquisition debt is dollar denominated – for the obvious reason of pricing but the unpleasant flipside is the likelihood of foreign exchange risk crystallisation. It requires little thought to conclude that in the event of a significant drop in the value of the naira, the Nigerian Electricity Regulatory Commission (NERC) will come under intense pressure from investors to adjust tariff in order to meet increased debt burden.
A quick back of the envelope calculation shows that the cost of naira exchange rate devaluation of about 19% over a period of seven years, on the average, is higher than the cost of naira denominated loan priced at 16% over the same period. Is this exchange rate scenario far-flung? Perhaps but not without precedent – macro-economic crisis in Argentine did lead to about 70% collapse of peso in 2001/02 which subsequently triggered electricity tariff freeze and the resulting crisis in the power sector .
Though it may well be argued that economic structures and relations differ and therefore such an exchange movement as witnessed in Argentina is not likely to replicate itself in this environment, it is nonetheless probable. That there is no absolute certainty in foresight is an unimpaired truth but the consequences for not appropriating the benefit of hindsight has the capacity to fatally incapacitate. It is better to be proactive today rather than seek to socialise losses in future while current profits are privatised. Investors should bear in mind that most electricity regulators, globally, are also regulated (albeit by a different kind of regulator), oftentimes less by balance sheet equation and more by the ballot box and social considerations.
Therefore, it may be prudent for lenders and borrowers in the Nigerian power sector to re-assess their risks and consider converting a portion or the entire dollar denominated loans to the local currency since industry cashflow is denominated in naira anyway.
Ubohmhe Glenn Olowojaiye
