This article was originally published in Gastech in September 2017.
In part 1, we considered market structure and lack of direct recourse (to the government or the utility), but there are other issues at play:
3. Integration with indigenous gas reserves: In markets where indigenous gas reserves already support some gas-fired generation, LNG can boost volumes to sustain larger, more efficient plants, helping to support economic growth and rising power demand. Where a domestic gas utility / government ministry has responsibility for the distribution of gas, it is more likely that LNG will be procured for the IPP market by that entity on a strategic basis. Often, a lack of transparency of price setting mechanisms in the gas sector makes it more difficult for IPPs to import LNG directly – the effect of competing with domestic gas and the impact that may have on power plant dispatch is too uncertain. However the opportunity to supply LNG to a government buyer is likely, in many instances, to be a more attractive proposition for LNG suppliers and avoids integration risk of a bundled LNG-to-power project.
4. Equity exposures in emerging market IPPs: Aside from macroeconomic risks that IPPs are exposed to (e.g. foreign exchange risk, currency convertibility, offtaker credit worthiness, political risk, etc), IPPs principally bear technology risk associated with power generation – this comprises the risk of availability of the plant’s entire generating capacity; and the risk that the plant’s heat rate is worse than the basis on which fuel charges are calculated. This is mitigated by technology selection, appropriate operating assumptions, the employment of an experienced O&M contractor, and long term service arrangements with the original equipment manufacturer. The allocation of O&M costs between fixed and variable charge components under the PPA can give rise to dispatch risk – i.e. the risk that the generator is not required to deliver sufficient electricity to recover its costs.
The main equity exposure exists during the construction phase. Until the plant has satisfied capacity, reliability and heat rate performance tests, it will not be considered to be in commercial operations and no payment will be due from the offtaker. Whilst this can be substantially passed down to a single point EPC contractor, the failure to achieve commercial operations by a contractual deadline under the PPA will result in the sponsors losing their equity.
5. Interface issues: When LNG supply, regasification and power generation elements of a power project are bundled together, equity exposures tend to increase – firstly, the integrated project is more capital intensive and therefore more equity is exposed to payment and performance risk of the offtaker. Secondly, where there are interface issues between LNG storage/regasification and power generation, interface risk can result in the need for either additional contingencies or sponsor completion support of one form or another. This can be avoided or mitigated by achieving a single point of construction responsibility for onshore regasification and power generation infrastructure.
The use of floating storage and/or regasification offers the ability to reduce the financing requirements for the power project. The risk of FSU availability is low, but is further mitigated by the ability to substitute the vessel if it is off hire for any significant period. Likewise, the ability to redeploy the vessel offers a means of mitigating power plant availability risk.
The key question for LNG exporters is whether they have the appetite to take exposure to the power sectors in emerging markets or whether they can find synergies with power sector developers that avoid the need for each party to take exposure in parts of the supply chain that are not their core business. Whilst integrated LNG-to-power solutions are very attractive to utilities and host governments, most investors would prefer to focus on their individual areas of expertise rather than to invest in an integrated solution.