Global offshore wind: Philippines

Focus on the Philippines

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Market overview

The World Bank estimates the total technical potential for offshore wind in the Philippines to be 178GW. Much of the wind resource is thought to be located in water deeper than 50m, necessitating the use of floating offshore wind turbines.

In April 2022, the World Bank Group, in coordination with the Energy Sector Management Assistance Program and the International Finance Corporation, and the Department of Energy (DOE) launched The Philippines Offshore Wind Roadmap, which notes that, with the appropriate governmental policy support, the Philippines has the potential to install as much as 21GW of offshore wind capacity by 2040.

In 2023, the President of the Philippines, Ferdinand R. Marcos Jr., issued Executive Order No. 21 directing the DOE to draft a policy and administrative framework for offshore wind development and to commence work related to grid development.

As of April 2024, the DOE had approved 92 offshore wind energy service contracts (WESCs) with a combined potential capacity of more than 65GW. 

Currently, the Philippine Government is finalising key regulatory frameworks such as the permitting framework, marine spatial planning and port feasibility studies. The pre-feasibility study to determine which ports can service the offshore wind industry’s needs that is being carried out with the Asian Development Bank, is expected to be completed in 2024.

The Republic Act No. 9513, otherwise known as the Renewable Energy Act of 2008 (RE Act), establishes the framework for the accelerated development and advancement of renewable energy resources, and the development of a strategic programme to increase its utilisation.  Current regulations implementing the RE Act issued by the DOE no longer limit the exploration, development and utilisation of renewable energy (other than the drawing of water from its natural source) to Philippine nationals. This is a welcome development opening the renewable energy sector to foreign investors. Despite this, activities incidental to the exploitation, development, and utilisation of renewable energy (e.g., use of forest lands, foreshore, other public lands, drawing water from natural resources), are still not open to foreign investors or companies whose foreign ownership comprises more than 40% of its outstanding capital stock.

Philippines offshore wind projects

Based on a search of publicly available sources, the Philippines is thought to have at least 92 offshore wind farm projects with total capacity of 66.101GW that have been awarded a WESC by the DOE. It appears that these projects are at an early stage of development – they have neither been fully consented nor have they entered the construction phase and among them are the following: 

• The Guimaras Strait Wind Power Project (under development by Triconti Southwind Corporation) and Guimaras Strait II Wind Power Project (under development by Jet Stream Windkraft Corporation) that were among the first projects to obtain a WESC. The two projects will be located offshore Negros Occidental and Iloilo Province and have a total target capacity of 1.2GW.
• PetroGreen Energy Corp plans to build a 2GW offshore wind farm in Ilocos Norte. Domhain Earth Corp plans to build a project offshore Cagayan and Ilocos Norte with a capacity of 1.6GW. Both developers have secured a WESC.
• CleanTech Global Renewables Inc and The Blue Circle have obtained a WESC to develop a 1.2GW project in the bays of Bulalacao and Soguicay in Oriental Mindoro and also in Caluya in Antique.
• Corio Generation plans to bid in upcoming renewable energy auctions in the Philippines. It intends to develop up to five projects with a total capacity of 3GW off the coasts of Cavite, Batangas-Mindoro, IIoilo and Guimaras. Its pipeline comprises 2GW of fixed-bottom and 1GW of floating wind projects.
• BlueFloat Energy acquired WESCs for four sites in 2023, located in Central Luzon, South Luzon, Northern Luzon and Southern Mindoro. These sites are reported to be sufficient for more than 7GW of floating offshore wind capacity.
• Copenhagen Infrastructure Partners is developing three offshore windfarms. Its flagship project, Northern Luzon, was recently selected by the DOE as one of the frontrunners in the Philippine offshore wind market. The project has a targeted capacity of 2GW.
• Iberdrola signed an agreement with Triconti ECC Renewables and Stream Invest Holding AG in 2022, to construct five offshore wind projects with up to 3.5GW capacity in the coming years.
  
   

Development process

Developers must obtain a certificate of registration from the DOE.

WESC or WEOC

Offshore windfarm developers must also secure either a WESC or a wind energy operating contract (WEOC) to engage in the exploration, development, and utilisation of renewable energy for commercial purposes. 

WESCs and WEOCs are entered into between the Philippine Government (through the Secretary of the DOE) and the developer. These agreements grant the developer the right to explore, develop and utilise the wind resource within a particular area during a designated period. 

A WESC covers the (i) pre-development stage, which involves the conduct of preliminary assessment and feasibility study up to financial closing and declaration of commerciality of the project, including the identification of the proposed production area, and (ii) development/commercial stage, which involves the development, construction and commercial operation of the project, production and utilisation of renewable energy resources. A WEOC only covers the development/commercial stage.

Bond/Guarantee

Developers must post a bond or other guarantee in an amount not less than the minimum expenditure commitment for the first contract year of the project. Developers are also required to maintain a valid and subsisting performance bond annually until the project’s pre-construction phase.

Registration and Endorsement

In addition, wind developers must register with the Board of Investments and secure a Certificate of Endorsement from the DOE, through the Renewable Energy Management Bureau, on a per project basis.

Further, Developers are required to enter into the following regulated agreements:

• a Connection Agreement with the National Grid Corporation of the Philippines (NGCP), who is the system operator;
• a Transmission Service Agreement with the NGCP;
• a Metering Service Agreement with the NGCP;
• a Market Participation Agreement with the Independent Electricity Market Operator of the Philippines (Market Operator); and
• a Renewable Energy Payment Agreement with the National Transmission Corporation (TRANSCO), if the developer supplies power through the Green Energy Auction Program (GEAP).

These agreements are based on Energy Regulatory Commission (ERC) approved template agreements. These agreements, together with the supporting rules and regulations¹, govern the sale, supply, delivery, pricing and payment of the electricity to be generated from offshore wind projects.

Support regime and offtake

Routes-to-market

The Philippines has a liberalised, commercially active and mostly private-sector driven electricity industry operating in a competitive market environment. There are multiple routes-to-market for generators, including:

1. the wholesale electricity spot market (WESM), which operates as an energy-only gross pool with net settlement. The WESM operates in Luzon, Visayas and Mindanao and is a nodal market with locational marginal pricing where prices are determined at each grid injection and offtake point. Offshore wind generators will be dispatched on a “must dispatch” preferential basis;
2. power supply agreements with distribution utilities (including private investor-owned utilities and electricity cooperatives), which are licensed to sell electricity within their distribution franchise areas to captive customers under the contestability threshold (currently under 500kW). Distribution utilities are required to procure power through “least cost” modelling via competitive supply tenders and to secure ERC approval of such power supply agreements;
3. power supply agreements with end-users opting to source their power requirements under the Green Energy Option Program (GEOP) and who meet the GEOP contestability threshold of 100kW;
4. corporate power purchase agreements (CPPAs) with contestable customers (where the current contestability threshold is 500kW). Note that generators must obtain a retail electricity suppliers licence for this purpose and must supply balancing services;
5. Green Energy Auction Program (see discussion below); and
6. Renewable Energy Market for the sale of renewable energy certificates (see discussion below).

Green Energy Auction Program (GEAP)

The GEAP is a competitive auction process where renewable energy developers submit bids to supply renewable energy capacity. Winning bidders are paid on a pay-as-bid basis and this price is known as the Green Energy Tariff (GET), which is payable pursuant to a Renewable Energy Payment Agreement (discussed below).

The concept of this auction system was first introduced by the DOE in 2015 when it declared that upon full subscription of the existing FIT installation targets, succeeding rounds for installation targets would be made through an auction system to be adopted by the DOE. The DOE first implemented the GEAP in December 2021 pursuant to Department Circular No. 2021-11-0036 (Revised GEAP Rules). The Revised GEAP Rules sets the framework for the procurement of renewable energy supply by end-users connected directly or indirectly to the grid.

During the auction process, the DOE will publish the Green Energy Auction Reserve (GEAR) Price, which amounts to a ceiling price for bids. The GEAR Price is determined by the ERC. In lieu of a GEAR Price, a price determination methodology – to be formulated by the ERC – is being considered for the third GEAP auction round.

The first GEAP awarded 1,866.2MW of capacity across solar (1,490.4MW), onshore wind (273.2MW), hydro (99.2MW) and biomass (3.4MW) projects. Prices were constrained by a low ceiling price (Php 6.0584/kWh for onshore wind) and resulted in winning bids between Php 3.8583 /kWh and Php 5.7555/kWh for onshore wind.

The second GEAP auction round awarded only 3.58GW of capacity out of a 11.6GW target.  Capacity was awarded to solar, onshore wind (1,462.4 MW), biomass and hydro projects. In this round, the GEAR Price for onshore wind was lower than the first round at Php 5.8481/kWh.

At the time of publication of this report, the third and fourth GEAP auction rounds are in process and focusing on geothermal, impounding hydro, pumped storage hydro, run-of-the-river hydro, and Integrated Renewable Energy and Energy Storage System (IRESS) sources.

The DOE has been preparing for the fifth round of the GEAP auction for offshore wind capacity which could reach 3,000 to 6,000MW to commence in the middle of 2025. 

According to reports, the Government is still assessing the overall size of the tender, and whether to launch separate tenders for fixed-bottom and floating offshore windfarms. We understand that the DOE is currently considering the GEAR Price for offshore wind and it is uncertain whether the ERC will use a similar methodology as that used for previous GEAP rounds. 

Renewable Energy Payment Agreement (REPA)

Payment arrangements that existed for the FIT programme also apply to the projects awarded through the GEAP. Payment of the GET is funded through the FIT-All Fund, which is discussed below.

Successful bidders in the GEAP auctions must enter into a REPA with TRANSCO. TRANSCO is also the FIT-Allowance Administrator. The REPA governs the payment arrangements for the GET. The pro-forma REPA is issued by the ERC and is not subject to negotiation. It has a term of 20 years.
TRANSCO is a payment agent; it is not an offtaker or consumer of the electricity generated by the project. The REPA is not a power purchase agreement and does not contain the level of detail, risk allocation or compensation mechanisms that might be expected in a power purchase agreement.

FIT-All Fund

Payment of the GET is funded from the Feed-in-Tariff Allowance (FIT-All) Fund. The FIT-All Fund is composed of FIT-All proceeds and WESM proceeds.

The FIT-All is a uniform charge (in Php/kWh) billed to all on-grid electricity consumers who are supplied with electricity through the distribution or transmission network. The FIT-All proceeds are collected by: (i) TRANSCO from consumers who are directly connected to its system; (ii) distribution utilities from consumers connected to their respective systems; and (iii) retail electricity suppliers from their respective customers. The FIT-All is set by the ERC on an annual basis upon petition by TRANSCO, as the administrator of the FIT-All Fund.

On the other hand, the WESM Proceeds are determined and paid in accordance with the WESM billing and settlement procedures and remitted by the customers to the Market Operator, which is responsible for remitting the same to the FIT-All Fund.

Opt-In Mechanism

Under draft DOE guidelines, distribution utilities and other mandated participants of the renewable portfolio standard programme (Opt-In Participants), may procure energy from the GEAP pool of winning bidders under a particular auction round and thereby carve out the energy capacity from the FIT-All.

Where the opt-in mechanism applies to an upcoming auction round, the DOE, through the Green Energy Auction Committee (GEAC), will establish eligibility requirements for the Opt-In Participants, including parameters such as credit rating, financial ratio and the form of security deposit. An Opt-In Participant that intends to participate must enter into an opt-in participation agreement with TRANSCO and the Market Operator.

In all cases, the winning bidder will be paid its offered price after the opt-in and the corresponding Renewable Energy Certificates (RECs) generated from the “opt-in capacity” generation shall accrue in favour of the Opt-In Participant. The GET corresponding to the opt-in capacity volume will be payable by the Opt-In Participant and not from the FIT-All Fund.

At the time of publication of this report, the DOE has not yet officially released the issuance on the guidelines for the Opt-In Mechanism under the GEAP.

Renewable Portfolio Standards (RPS)

The RPS refers to a market-based policy that requires mandated electric power industry participants, such as distribution utilities for their captive customers, retail electricity suppliers for the contestable market, generating companies to the extent of their actual supply to their directly connected customers, among others, to source an agreed portion of their energy supply from eligible renewable energy sources.

The National Renewable Energy Board has the authority to set the minimum percentage of generation from eligible renewable energy sources, as well as to determine to which sector the RPS will be imposed on a per grid basis. In 2022, the DOE increased the minimum percentage to 2.52 per cent starting in 2023 for grid-connected areas. The target share of renewable energy in the total generation mix is 35 per cent by 2030. The DOE hopes to increase the share of renewables in the Phillipine power mix to 50 per cent by 2040.

RECs are issued to track the compliance of mandated participants in the RPS. The ERC approved and adopted the REC Price Cap at PhP241.56/MWh in April 2024, which shall be reviewed every two years or when there are significant events or information that are vital and relevant to the setting of the REC price cap, whichever comes earlier.

REC trading

The RE Act mandates the establishment of a Renewable Energy Market (REM) for the trading of RECs, which is an essential mechanism designed to incentivise the development of RE facilities aimed at the encouragement of investment in RE technologies. The REM is a sub-market of the WESM. REM interim commercial operations commenced in August 2022 and, as at the time of publication of this report, remain in interim commercial operation status.

During interim commercial operations, the RE Registrar can perform its functions, including acceptance of applications for REM registration, issuance of RECs under the FIT and non-FIT compliance mechanisms, and the adjustment, validation, or confirmation of RECs received by the REM participants. However, the REM does not yet involve any financial transactions (i.e., trading of RECs) until such time as the DOE declares full commercial operations of the REM.

Full commercial operation of the REM is expected once certain regulatory structures are put in place, including the approval of a REC price cap by the ERC and the preparation and approval of the structure and level of transaction fees. Presently, the DOE cannot commit to a date or time for when the REM will be fully operational. 

Feed-in Tariff (FIT)

Offshore wind projects in the development process are not currently eligible for a FIT under the FIT System.

The FIT System was one of the mechanisms under the RE Act aimed at incentivising RE developers to enter the market by providing them a guaranteed, above-market price for renewable energy produced. The FIT System offered guaranteed payments applicable for 20 years. The FIT System was subject to installation caps and determined on a first-come first-served basis. This meant that priority was given to RE developers who could demonstrate that their project was near completion and ready for commissioning. Once the installation caps were fully subscribed, the FIT System would no longer apply. 

As of August 2024, all of the installation caps of renewable energy resources, except for run-of-river hydropower, have been fully subscribed.

Competitive Renewable Energy Zones (CREZs)

The DOE has introduced the CREZ programme to encourage the development of remote renewable energy resources through proactive transmission planning. The programme identifies geographic areas with high concentrations of cost-effective renewable energy potential and strong developer interest. By proactively focusing transmission expansion to these resource areas, the DOE aims to overcome development obstacles such as transmission access, energy curtailment, land permitting and regulatory barriers. There is no requirement for offshore wind projects to be built in the CREZs, but it may offer an advantage for grid connection.

In the 2024 Transmission Develoment Plan (TDP), it was noted that “the huge potential for offshore wind development is on top of the CREZ capacity earlier established.” As such the NGCP pointed out several modifications in the green transmission system which require exploring further network modifications such as the: (a) development of a 500kV backbone extension both in the western and eastern side of northern Luzon, (b) locating the new 500kV substation closer to offshore wind locations instead of connecting at the Laoag 230 Substation, and (c) use of 500kV backbone within Mindoro island instead of 230kV design only, among others. It was further acknowledged that “[a]s tapping the offshore wind resources would require massive transmission backbone development, further coordination with the DOE will be undertaken in updating the transmission build-out. The coordination would include the necessary inclusion of offshore wind in CREZ and update of the generation expansion plan that will serve as guide in the prioritization of generation projects and transmission projects.”

For the period of 2041-2050, further extension of the 500kV network will be implemented to accommodate bulk generation capacities. On the southern part of Luzon, the 500kV backbone will be extended to Tublijon, Sorsogon to accommodate Onshore and Offshore wind capacities.

Among the additional proposed projects for the enhancement of transmission lines covering the period of 2031-2040 are: the (a) Alas-Asin 500kV Substation which aims to accommodate several offshore wind power plant projects located at the Manila Bay and offshore of Mariveles, and (b) Calatagan 500kV Substation which aims to accommodate several offshore wind power plant projects located at Calatagan Bay and offshore of Northern Mindoro.

Meanwhile, additional transmission projects in the Visayas region which will accommodate the entry of power plants under CREZ in the area are expected to commence during the period of 2031-2040 include the: (a) Babatngon–Calbayog 230kV Transmission Line Project which involves extending the 230kV backbone in Samar Island by constructing a 230kV Transmission from Babatngon going to the Calbayog Substation, and (b) Barotac Viejo–Sta. Barbara 230kV Transmission Line Project which involves extending the 230kV backbone in Southern Panay by constructing a 230kV Transmission Line from Barotac Viejo going to the Sta. Barbara Substation.

Further, major island interconnection projects relevant to offshore wind projects in the upcoming years include the Batangas–Mindoro Interconnection Project which aims to link Mindoro Island to the Luzon Grid through a 28.5km submarine cable and a total of 31.5km overhead transmission Line. Stage 1 will involve the development of a 230/69kV Substation in Calapan, Oriental Mindoro, with a total transformer capacity of 2x100 MVA that will connect to the existing 69kV transmission network in Mindoro through a total of 8.5 km overhead transmission line. Moreover, the submarine cable and the overhead transmission lines will be designed at 500kV voltage level, but will be initially energised at 230kV in preparation for the Stage 2 project which aims to cater the full development of bulk renewable energy (Onshore and Offshore) projects on the island. Stages 1 and 2 of the Batangas–Mindoro Interconnection Project are estimated to be completed in September 2027 and December 2030, respectively.

Tax incentives

Offshore wind developers are entitled to the following incentives under Section 15 of the RE Act, in relation to the Bureau of Internal Revenue Regulations No. 7-2022:

• an income tax holiday for the first seven years of the project’s commercial operations;
• duty-free importation of renewable energy machinery, equipment, and materials within the first 10 years from the issuance of an RE Developer certification from the DOE;
• a cap of 1.5 per cent of the net book value on civil works, equipment, machinery, and other improvements;
• a net operating loss carry-over, which allows the developer to carry over its net operating loss during the first three years from the start of commercial operations as a deduction from gross income for the next seven consecutive taxable years immediately following the year of such loss;
• a ten per cent corporate tax rate, which is applicable after the seven-year income tax holiday, provided that the developer passes on the savings to the end-users in the form of lower power rates;
• accelerated depreciation if a developer fails to receive an income tax holiday before full operation;
• a zero VAT rate for the sale of power generated from wind. In addition, developers are entitled to zero-rated VAT on their purchases of local supply of goods, properties and services needed for the development, construction and installation of their projects; and
• tax credits on domestic capital equipment and services equivalent to 100 per cent of the VAT and custom duties that would have been paid on the machinery, equipment, materials and parts, had these items been imported.

To be entitled to the above incentives, developers must register with the DOE, through the Renewable Energy Management Bureau. 

Challenges

Risk of construction delay

At 20 per cent of expected project costs, the performance bonds required of bidders in previous GEAP auctions have been onerous in comparison to other jurisdictions. 

Further, if construction of the project is delayed beyond 365 days from the required commercial operations date, the performance bond may be drawn in full and the GEAP award is revoked. At 365 days, this compares unfavourably with other jurisdictions active in the offshore wind industry. Should the GEAP award be revoked, the developer would not be entitled to the GET or to enter into a REPA with TRANSCO. The developer would need to fall back on one of the other routes to market discussed above.

Developers are entitled to extensions of time for force majeure, but the definition of force majeure contained in the regulations is not as comprehensive as we might expect, leaving uncertainty as to whether any extensions of time might be available if there are delays due to infrastructure or grid readiness.

Local infrastructure and supply chain

As is to be expected of a new market, port and vessel availability is limited. Despite the Philippines’ strong industry, a comprehensive local supply chain is not yet available and many project components will need to be imported.

Grid capacity will also require upgrades to accommodate new connections. NGCP has mapped out a detailed plan to develop and augment additional transmission infrastructure, but some of these transmission projects have been delayed in recent years. If delays persist or a material portion of these transmission projects are not delivered, the build out of offshore wind projects will be hampered or projects may face increased grid related curtailment.

The five-year time frame for pre-development is typically insufficient as it is likely that many of these projects will not have a grid connection for the next 10 to 15 years. Based on public sources, investors in the offshore wind industry have proposed to the DOE that delays in the availability of critical infrastructure be declared as “force majeure” events.

Procurement and Chinese technology

Consistent with the international offshore wind market, we expect a multi-contracting procurement approach to be adopted in the Philippines. In addition, sponsors may also consider whether some of the EPC contracts should be subject to further onshore/offshore splits to effect tax efficiencies. While multi-contracting is not new to Asia, we have seen other sponsors offer additional support when compared with the approach taken in markets such as Europe. The approach is dependent on sponsors’ ability and track record to deliver a multi-contract package, including the management of all of the associated interface risks, without the need for any specific completion support or similar enhancements from equity, over and above making provision for standby debt and standby equity as part of the finance strategy.

Building on the experience from the Philippines onshore wind market, we anticipate Chinese technology to also play an increasingly prominent role in the development of offshore wind projects in the Philippines. While the use of Chinese suppliers in the sector is becoming an increasingly prevalent global trend, when it comes to the use of Chinese turbines in particular, the terms of the turbine supply contract will need to be suitably robust, particularly from a defects and performance warranty perspective.

REPA

As discussed above, the REPA is not a power purchase agreement and developers should not expect the risk allocation that might be expected from power purchase agreements elsewhere in the region. The REPA is a regulatory agreement and should be viewed in the context of the surrounding regulations.

Key issues that distinguish the REPA from a comprehensive power purchase agreement include:

• no guaranteed minimum offtake specified in the REPA, but note that wind projects have “must dispatch” status;
• no deemed commissioning / dispatch, including where curtailment occurs due to grid congestion or failures;
• no change in law cost adjustment or any other compensation for governmental force majeure related events;
• no compensation on termination;
• no indexation for inflation or foreign exchange movements; and
• no international arbitration.

The pro-forma REPA for the GEAP auction round for offshore wind is expected to have different terms to the REPAs used in previous GEAP rounds, but the template has not yet been finalised.

FIT-All Fund

Historically, the FIT-All Fund has experienced some periods of potential shortfall. The underfunding situation has abated in recent years, an expected consequence when WESM prices exceed GET prices. Given that offshore wind will inevitably involve higher GETs, this could put a funding strain on the FIT-All Fund which may increase the funding gap for electricity consumers to fill.

Financing market

The majority of domesic project finance has been undertaken by the local Philippines banks, so the international commercial banks, export credit agencies (ECAs) and multilaterals will be less familiar with the regulatory environment and documentation.  These local Philippines banks will also deliver signficant local currency liquidity and are likely to have greater experience with Chinese OEMs from their domestic onshore wind market experience. Nonetheless, we expect international commercial lenders, multilaterals (including development finance insitutions and ECAs) to also play a significant role in the financing of offshore wind projects in the Philippines, having regard to their international experience banking such technology.

Offshore Power in the Future

Despite RE coming with a high price tag due to the limited financing options, energy experts are steadfast in pursuing sustainable energy projects since this will help the country in the long run. The DOE is sticking with targeting the production of the first energy from offshore wind by 2028. It is working with the Department of Environment and Natural Resources (DENR) to coordinate on potential offshore sites and possible environmental impact of the project. The DOE and DENR have signed a memorandum of agreement concerning the grant of authority to use offshore areas for the development of offshore wind projects. The DOE and the Philippine Ports Authority are also working together on repurposing ports for the use of offshore wind projects.