ASEAN
aims to achieve 30%
and 45% shares of renewable energy (RE) in total
primary energy supply (TPES) and installed capacity by 2030, respectively, yet
remains around 16 percentage points short of meeting the 2030 RE share target
in TPES, indicating the need for urgent action. The key bottleneck to the slow
deployment of RE and other energy transition projects in ASEAN is not the
availability of technology or capital, but rather the bankability of these projects,
fragmented regulations, and other factors stemming from the
high risk perceived by private investors. Thus, it is
crucial to meet the conditions for bankability from the private investor's
perspective. One critical criterion set by the private investor in assessing
the bankability of a project is whether
risk allocation is fairly distributed between the project company and the
contractor, including off-takers, particularly to ensure expected
revenue with a limited margin associated with an energy transition project over
the longer payback period. In this context, the cost of an energy transition
project in ASEAN includes all costs required to cover risks arising before and
after implementation. For ASEAN and other developing countries, off-taker
and currency risks are viewed as two critical risks for private
investors.
In addition
to derisking mechanisms, the choice of contractual agreement type (which
indicates the financial project structure) provides complementary mitigation
measures to address off-taker risks and enhance the bankability of energy
transition projects in the region. A Power Purchase
Agreement (PPA) offers long-term certainty to private investors by
setting an electricity price between the electricity generator and consumers
for the duration of the project. Compared with the engineering,
procurement, and construction (EPC) contract agreement type, the PPA- based independent
power producer (IPP) offers the project owner an advantage by avoiding
high upfront capital costs and shifting construction and operational risks to the
private project developer. The next critical question is how to design a PPA
to unlock the bankability of energy transition projects in ASEAN. The
bankable PPA is required to ensure
the certainty of expected revenue for private investors and to establish clear
risk allocation and institutional arrangements to cover debt
financing during the agreed project period, typically 15 to 25 years. The
expected revenue is closely linked to the pricing mechanism set under the PPA,
which is central to it. The choice of pricing mechanisms is aimed either
at revenue certainty (fixed, take-or-pay, and market) or at market efficiency
(CfD, auction, and charges) and needs to be coordinated between regulators and
private investors.
Moreover,
the pricing mechanism set under the PPA affects the second critical factor of
bankability: the
risk allocation between the parties to the agreement. Most ASEAN Member States (AMS) applied fixed or flat price
mechanisms aiming to ensure revenue certainty to boost the deployment of clean
energy technologies, in particular for the previous energy transition projects,
such as Vietnam's
fixed FIT to boost solar deployment in Vietnam during 2017-2021,
the previously applied Philippine
FIT under the Renewable Energy Act 2008, and Indonesia's
previously applied IPP scheme.
Fixed
FIT schemes are well-suited to early-stage RE deployment by shifting most of
the risks to the government and state-owned utility companies, but impose a
heavy burden on the fiscal budget. As a result, two new pricing mechanisms
under the PPA in several AMS have now moved to competitive auction-based
pricing and bilateral negotiated pricing. For example, the
Philippines’ Green Energy Auction (GEA-5), which set a Green
Energy Auction Reserve price of around PHP 11.00/kWh and utilized the Renewable Energy Payment Agreement
(REPA), the new PLN Indonesia procurement
ceiling, and Vietnam’s Direct Power Purchase
Agreement (DPPA). Although
the auction ceiling price aims to open competition among energy developers,
setting it at the right level is crucial. These examples show a shift from
fixed-price schemes, although regulatory structures and mechanisms still differ
considerably across AMS.
Similar to the ceiling price, the
bilateral negotiated pricing mechanism offers a complementary pricing scheme that
might be suitable for data centers and assigned industrial customers to
purchase electricity directly from specified private energy developers, such as
Malaysia’s Corporate Renewable Energy
Supply Scheme (CRESS)
and the Philippines’ RCOA contestable customer
contract and Contract
for Difference (CfD). Although the bilateral negotiated price scheme is
complementary to the previously stated pricing scheme, it also entails two key
risks: high transaction costs and limited standardisation and transparency in
price mechanisms.
Although the central purpose of the pricing mechanisms under the PPA scheme is to reallocate risk and enhance the bankability of energy projects, the administrative task of designing the PPA contract could increase the project's cost of capital. Clear preparatory work and PPA contract drafting can reduce potential capital costs. As market conditions and the electricity system in AMS vary, regional cooperation could instead pursue a standardized PPA framework that includes common core terms (risk allocation, termination, and others), along with tailored parameters that reflect each AMS’ market conditions. This would also facilitate the cross-border transmission project. Last but not least, setting the right PPA risk pricing and allocation is the key to unlocking private capital mobilized to narrow the ASEAN energy transition investment gap.
Cover image credit: Magnific
