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7 February, 2017
The Indonesian power sector has to date been the most successful of the infrastructure sectors in attracting private sector investment, and debt financing from both international and domestic lenders. The State power utility, PT PLN (Persero), has since the very early private sector power generation projects of the 1990s developed a robust and bankable Power Purchase Agreement (PPA) model for large scale power projects. Whilst there have been the inevitable tweaks to the PPA model over the past 20 years (coming from both the PLN side of the negotiation table as well as the developer/lender side), the model for large scale power projects remains today a solid one, and one that is able to mobilise private sector equity and debt funding. Recent flagship projects that demonstrate the success of the current PPA model include the Central Java 2x1000MW project, the Sarulla Geothermal Project and many others.
However the Ministry of Energy and Mineral Resources on 19 January 2017 issued Regulation No. 10/2017 on Principles of Power Purchase Agreements (MEMR Reg. 10), which, for the first time in any material way, seeks to impose certain requirements as to what provisions must be built into PPAs in the power sector. Other power sector regulations have, from time to time, touched lightly on certain aspects of the PPAs (e.g., the mini-hydro regulations provide that if the developer fails to complete construction of the project within the required timeframe, the tariff under the PPA should be subjected to a discount as a form of penalty), but the key bankability and risk allocation points have been left to negotiation between PLN and the developers (and lenders). However with the passing of MEMR Reg. 10, PLN's freedom to negotiate terms has been curtailed.
What power projects are covered by MEMR Reg. 10?
The regulation applies to all power projects, including geothermal, biomass and hydropower plants.
However, the regulation does not apply to intermittent power projects (i.e., wind and solar, regardless of size), mini-hydro power plants (below 10MW), biogas power plants and waste-to-energy power plants. These categories of power plants will be subject to their own specific regulations.
Additionally, the transitional provisions of the regulation provide that these new PPA requirements will not apply to PLN procurement processes where bid closing has already occurred, where PLN has signed letters of intent with developers, or where the PPA has already been signed or where there is any amendment to an existing PPA.
For geothermal projects where the auction process to award the geothermal concession has already been completed, or projects where the winner has been declared, or where the PPA has been signed, they too will not be subject to the regulation.
For all relevant projects where the procurement processes are ongoing and bid closing has not occurred, the new requirements must be complied with. Accordingly, we suspect that PLN will soon be issuing extension notices for ongoing bid processes, to give PLN enough time to adapt the model PPAs contained within those bid packages to the requirements of MEMR Reg. 10.
What are the controversial changes under MEMR Reg. 10?
MEMR Reg. 10 introduces a number of new mandatory concepts which are certainly likely to give rise to concerns with developers and their lenders:
All projects must be on a Build-Own-Operate-Transfer (BOOT) model
Whilst coal projects have been traditionally awarded by PLN on a BOOT basis, with ownership of the projects having to be transferred to PLN at the end of the term of the PPA, other projects such as geothermal and hydro have been awarded on a BOO basis (with the developer retaining ownership of the project at the end of the concession, giving rise to the possibility of negotiating a renewal PPA or extension with PLN if the design life of the power plant permits).
Accordingly, with this mandated BOOT model, all potential "upside" for developers has been taken off the table, and all projects will need to be transferred to PLN for a nominal amount at the end of the term of the PPA.
Where PLN is unable to evacuate the power from the power plant due to force majeure affecting PLN, PLN is relieved of its payment obligations
This is a major bankability concern. As the PPAs are largely based on an availability concept (i.e., the generator's job is to be available for PLN to take the power if PLN wishes to do so), the early generations of PPAs provided that if the power generator was available, yet PLN was unable to evacuate the power for any reason (including due to force majeure affecting PLN), then the generator was nevertheless paid in full for its availability. In more recent years, PLN has negotiated a grace period into the PPAs – where, for instance, if the PLN grid is damaged due to natural force majeure events, PLN has a maximum 14-day period to rectify the damage (during which PLN is under no obligation to pay the generator for its availability). It is only if the grid is not repaired within this 14-day period that PLN must start paying the generator availability payments. So in this respect, PLN has in recent years sought to have the developers share the risk of PLN force majeure events – and developers and lenders have factored this risk into their financial models and been able to accept this risk sharing.
However, MEMR Reg. 10 indicates that PLN will not be obliged to pay deemed dispatch if disruption in the PLN grid is caused by force majeure events. Although Reg. 10 allows the PPA term to be extended in a force majeure event, this will not fully address lenders' concerns due to the revenue loss impact on the ability to service the debt. This latest change pushes the entire PLN force majeure risk onto developers, with developers having no way to manage or mitigate that risk. Insurance coverage for business interruption is typically tied to a casualty event affecting the generator's plant and equipment (not a casualty event affecting PLN's plant and equipment). So this gap in the risk allocation (and the lack of tools available for developers to plug the gap) raises large concerns over bankability.
Government force majeure risk being shifted to the developers
MEMR Reg. 10 seeks to push responsibility for certain Government force majeure events onto the developers.
One of the fundamental principles of proper risk allocation is that risk should be allocated to the party best able to manage and mitigate the risk. In the context of a PPA, the only two parties to the agreement are a private sector developer, and a State-owned utility. Accordingly, the traditional risk allocation is that the State-owned entity should take responsibility for actions of the State. On this basis, the PPA models used in Indonesia to date have largely provided that:
- in the event of changes in laws or adverse Government action/inaction, the cost impacts to developers are passed on to PLN as a tariff increase, and any revenue loss (due to the plant having to shut down) are passed on to PLN as deemed dispatch payments; and
- where there is a prolonged stoppage of the project due to Government action/inaction (e.g., 180 days continuously), the developer has the right to terminate the PPA, and PLN must purchase the project from the developer for an amount equal to outstanding project debt plus lost future equity returns
However, Article 8 of MEMR Reg. 10 now provides that both PLN and the developers will take responsibility for Government force majeure events. Government force majeure is defined in the regulation as "changes in policies or regulations" (and therefore appears to capture changes in law), although somewhat confusingly, the same term is used elsewhere in the regulation to mean only "changes in government policy" (and not changes in law). Aside from change in laws and policies, the other form of "government force majeure" typically captured by the PPAs is the unjustified action or inaction of Government (e.g., delays in issuing permits and approvals and revocation of licences without cause).
Accordingly, following the strict reading of MEMR Reg. 10, it is still permissible for PLN (as it traditionally has done) to take responsibility for these unjustified actions or inactions of Government; however in the case of changes in laws and policies, the regulation appears to require both PLN and the developer to bear that risk, with the PPA to further detail how that risk is allocated. It may be then that PLN seeks to build some form of grace period, or cost buffer, into the effects of changes in laws and regulations. For example:
- In the event of a change in law or regulation that has a cost impact on the developer (where that cost impact exceeds X% of the tariff), the tariff will be adjusted
- In the event of a change in law or regulation that causes a shutdown of the power plant, PLN will pay deemed dispatch payments only if the effects of such event have not been rectified within X days after the occurrence of the change in law
However, Article 28 of MEMR Reg. 10 also deals with allocation of risk for changes in laws and changes in government policy. It provides that:
- where a change in law results in a higher cost impact to the developer, the tariff will be adjusted to compensate; and
- where a change in policy causes the power plant to stop operation, then both PLN and the developer are released from their obligations.
The treatment of change in law reflects the risk allocation treatment under the current generation of PPAs. However, the treatment of change in policies would appear to conflict with Article 8 – which appears to allow for a sharing of the risk of changes in government policy (as opposed to simply releasing PLN from its obligations). One reading of Article 28 which would result in it being consistent with Article 8 is that Article 8 applies to temporary shutdowns due to changes in government policy (e.g., if the plant is shut down for one month, then PLN does not need to pay deemed dispatch payments for the first 14 days, but thereafter has to start making deemed dispatch payments) whereas Article 28 applies to prolonged government events (e.g., if a government change in policy results in the plant being shut down for longer than 180 days, then the PPA can be terminated). The intent of Article 28 does at least appear to make clear that where the PPA is terminated due to a government change in policy, then PLN has no obligation to buy out the project.
So whilst the regulation appears to continue to give PLN freedom to (i) cover the cost increase and plant downtime consequences of unjustified Government actions or inactions, and (ii) cover the cost increase implications of changes in law, the position in relation to the loss of revenue caused by plant downtime due to changes in law and changes in government policy is somewhat unclear.
Statements made by the Government at public launch of MEMR Reg. 10 held on 2 February 2017 suggest that the Government's intention with respect to Article 28 was not to change the long-standing risk allocation that has existed under the current PPA model related to the compensation for changes in Government policy, but instead was to confirm that a power generator had the comfort of knowing it would be relieved from any liability in the event of such changes in Government policy. However the text of the regulation itself does appear to fundamentally change the risk allocation on this point – making it clear that PLN is similarly relieved from all obligations (which would include obligations to buy out the project) if such changes in Government policy occurred leading to a shutdown of the project.
Take or pay commitment from PLN is limited to the debt servicing period
For the PPA models to date, PLN has committed to a take-or-pay commitment (or guaranteed minimum availability payment) for the entire life of the PPA. This of course gives comfort to lenders that there will be sufficient revenues to meet debt service throughout the life of the PPA, but also gives comfort to the developers that they will see the target return on their equity investment.
MEMR Reg. 10 states that the take-or-pay period within the PPA is for a "certain period" (i.e., something less than the full term of the PPA), and goes on to clarify that the "certain period" is determined by "considering" the repayment period for the financing. So this indicates that PLN may only be committed to a take-and-pay concept for the debt period (to ensure lenders are covered), whilst developers will then take the risk on whether or not PLN dispatches the plant after the debt is repaid.
This take-or-pay model is not entirely new. On a number of the larger hydropower PPAs, the take-or-pay commitment of PLN is structured such that it only applies during a presumed debt service period (e.g., for the first 15 years of a 30-year hydro PPA), and following the debt service period, the PPA is a "take-and-pay" concept (i.e., the developers are only paid if PLN chooses to dispatch the plant). So in these projects, the sponsors have had to take a leap of faith that at the end of 15 years, the hydro plant should be positioned well in the merit order dispatch list, and therefore have a degree of comfort that despite the lack of any take-or-pay commitment from PLN, PLN will nevertheless dispatch the plant due to the cheap tariff.
So whilst nothing relating to this issue is going to give lenders any cause for concern (because the take-or-pay will cover the debt servicing period), it will require developers to consider whether they are willing to risk their equity returns on a discretion of PLN whether to dispatch the plant or not.
Again, at the public launch of the regulation held on 2 February 2017, the Government commented that all the regulation required was that in determining the take-or-pay period to apply under the PPA, "consideration" be given to the debt service period, and that PLN was still free to agree to provide the take-or-pay commitment for the full term of the PPA.
Accordingly it will be interesting to see what interpretation is given to aspect of the regulation in the future PPA negotiations.
New performance penalties for failing to meet ramp rates
The existing generation of PPAs typically only penalize developers for failing to meet the availability targets – i.e., if the availability target (e.g., 80%) is not met (e.g. actual performance was only 78%), then PLN will only pay the developer for the 78% of actual availability, and will penalize the developer a further 2% for the 2% shortfall between the guaranteed availability and the actual availability. So the developer would receive net 76% for that month.
In the most recent base-load PPAs, PLN has sought to introduce penalties for failing to meet reactive power requirements, as well as failing to comply with frequency requirements.
MEMR Reg. 10 also now requires the PPA to have a penalty regime for failing to meet ramp up and ramp down instructions from PLN dispatch centres.
Embedded restrictions on selling shares in the power generation company
PLN's PPAs (and related Sponsor Agreements) have typically imposed requirements on the project sponsors to maintain ownership of a certain percentage of shares in the power generator until the project's commercial operation date (and often for a period 5 years following the commercial operation date).
MEMR Reg. 10 now embeds certain shareholding retention obligations – prohibiting the transfer of ownership in power generators prior to the plant achieving commercial operation. What is not entirely clear is whether a transfer of shares between the founding sponsors of the project is permitted (e.g., if Company A and Company B are the two founding 50%:50% sponsors of the project, but then Company B is unable to fund cost overruns etc. and Company A steps in to fund such that Company B is diluted to 40% and Company A increases to 60%). We believe that because the ownership of the power generator has not changed (i.e., it is still collectively owned by the founding sponsors), such flexibility should be permitted under the PPA without breaching the restriction.
After commercial operation, the transfer of shares in the power generator is only permitted with the approval of PLN (and must be reported to the Government). In the existing generation of PPAs, there is generally full freedom of the sponsors to sell their shares in the power generator after the fifth anniversary of commercial operation. We do believe that there is flexibility in the wording of the regulation to allow for a "pre-approval" mechanism to be built into the PPA to deal with these changes of shareholding – for example, if a sponsor wishes to sell, the sponsor should offer the shares to PLN, and if PLN chooses not to exercise its right to buy those shares, the sponsor is free to sell the shares to a third party (at a price not less than that offered to PLN) and PLN is deemed to have approved such sale.
A transfer from a sponsor to its (at least) 90%-owned affiliate entity is permitted (therefore giving sponsors the flexibility to structure their ownership of the power generator to meet their internal corporate and tax requirements).
Conclusion
Clearly the broad principles set out in MEMR Reg. 10 will need to be translated by PLN and developers into detailed contractual provisions in the PPAs themselves. The Government has indicated in its public statements on the regulation that the main aim of the regulation was not to impose any changes to the existing PPA model used by PLN, with the exception of making a BOOT model compulsory for all the power projects falling within the scope of the regulation. The wording of the regulation however appears to have much further reach.
Whilst some of these broad principles do ring alarm bells in terms of the future bankability of the Indonesian PPA model, it is hoped that the flexibility given by "the devil being in the details" can be used to ensure that this new generation of PPA is still a model on which, like the PPA generations that preceded it, private sector investors and developers are willing to invest the billions of US dollars needed to achieve Indonesia's electrification goals.
