Philippines: Energy Sector Assessment, Strategy, and Road Map

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• Publisher: Asian Development Bank
• Year: 2018
• Print ISBN:
  9789292613624
• eBook ISBN:
  9789292613631
• Topic: Politics & International Relations
• Subtopic: Energy Industry
• Index: Politics & International Relations

This energy sector assessment, strategy, and road map documents the status and strategic priorities of the Government of the Philippines in the energy sector. It highlights sector performance, development constraints, government plans and strategies, past support of the Asian Development Bank (ADB) and other development partners, and the strategy for future ADB support in the energy sector. It also provides sector background information for investment and technical assistance operations. The assessment is based on a systematic review of the Philippines' energy sector and consultations with the government and other development partners.

IV Core Sector Issues

A. Electric Power Subsector

1. Generation

41. In 2016, the Philippines generated 90.8 terawatt-hours of electricity²⁷ (Figure 4). By December 2016, the total installed in the Philippines’ generating capacity had reached 21,423 megawatts (MW)—a year-on-year increase of 2,665 MW (16.2%).²⁸

Figure 4: Power Generation by Source in the Philippines, 1991–2016

TWh = terawatt-hour.

Source: Government of the Philippines, Department of Energy.

42. In the 1970s and 1980s, the country’s power sector experienced deteriorating service, perceived mismanagement, and high debt levels. An extended period of negligible capacity development compounded by the shelving of the 620 MW Bataan nuclear power project led to power shortages from 1989 which, at their height saw multiple 10-hour to 12-hour outages in Mindanao during 1990–1991 and frequent rotating brownouts lasting 8–10 hours in Luzon in 1992.²⁹

43. The Electric Power Crisis Act was passed in an effort to alleviate the crisis and was followed by an expansion of the private sector-oriented Build–Operate–Transfer Law that saw a surge in the construction of power stations by the private sector in the mid-to-late 1990s. The NPC signed around 22 government-backed PPAs with private sector independent power producers from 1991 to 1993, amounting to 2.65 GW of capacity. By 1997, the number of PPAs signed with private sector investors had reached 37. A significant block of generation capacity was developed around 2001 to utilize natural gas from the newly developed offshore Malampaya field.

44. These major capacity developments and corresponding PPAs coincided with a period of optimistic electricity demand forecasts. When the forecast demand did not materialize, parts of the Philippines—mainly in Luzon—were left with significant excess capacity and corresponding PPA-related costs. Coupled with the 1997 Asian Financial Crisis, this led to considerable debt accumulated in the sector. As demand grew and reserve margins decreased, excess coal-fired capacity decreased and reserve margins are now roughly tracking demand growth (Figure 5).³⁰

Figure 5: Supply and Reserve Margins in Luzon, 1987–2016

GW = gigawatt.

Source: Government of the Philippines, Department of Energy.

45. Today, the overall energy mix of the Philippines for electricity generation is relatively diverse with significant indigenous fuel supply, mainly natural gas, some coal, and varied renewable energy resources.

46. Historical resource development policies have led to each main island region (Luzon, Visayas, and Mindanao) being characterized by a different fuel mix for power generation and exposed to different risks (Figure 6). Natural gas sourced from the large Malampaya fields is a dominant feature of the Luzon region. Geothermal energy concentrated in Leyte and Negros is a distinctive feature of the Visayas region and accounts for around half of the power generation in that region. Highly seasonal hydro-based generation is the defining feature of the Mindanao power system. These signature resources are supplemented by coal-fired capacity that accounts for 40%–50% in each of the three regions. Oil-fired capacity remains a significant feature of the Mindanao generation mix but its peaking role in Luzon and the Visayas has diminished in recent years due to much-improved capacity margins and the rise of solar and wind energy.

Figure 6: Generation in the Main Philippine Grids, 2016

TWh = terawatt-hour, WESM = Wholesale Electricity Spot Market.

Source: Government of the Philippines, Department of Energy. 2017. 2016 Power Statistics—Gross Power Generation by Plant Type. https://www.doe.gov.ph/sites/default/files/pdf/energy_statistics/bgross_power_generation_by_plant_2016.pdf.

47. Luzon which accounts for around 73% of total generation in the Philippines has three large combined cycle gas-fired power plants in Batangas (Sta. Rita, San Lorenzo, and Ilijan) of 2,880 MW aggregate installed capacity. These plants operate largely in a baseload regime due to the high take-or-pay gas quantities specified in the Malampaya gas supply. This results in distortion of the merit order and displacement of coal. As a result, coal units have had to play the principal “swing” role in responding to load growth, seasonal demand patterns, diurnal demand cycles, variations in hydropower output, and temperature-dependent loads. The cost of electricity generated from the Malampaya natural gas is significantly higher than the cost of an equivalent amount of electricity from existing or new coal-based capacity, resulting in an upward pressure on Philippine electricity prices. A more economic dispatch of the gas power stations would suggest the natural gas-based generation being concentrated in higher demand periods and during periods of planned or unplanned capacity outages.

48. The government has sought to maximize the use of indigenous renewable resources since the enactment of the Renewable Energy Law in 2008. The DOE subsequently launched the National Renewable Energy Program (NREP) in 2011 which established targets and a road map by which to achieve them. The Philippines introduced a feed-in tariff (FiT) in 2015 which spurred the development and commercialization of 0.68 GW of solar capacity, 0.43 GW of wind, and 0.20 GW of biomass, adding to the existing 1.69 GW installed capacity for geothermal and 3.18 GW for hydropower.³¹ Despite these achievements, significant renewable energy potential remains untapped.

2. Demand

49. Total electricity consumption reached 888 kilowatt-hour per capita in 2016.³² Compared to other developing countries in Asia, economic development in the Philippines has been less energy-intensive (measured in electricity consumption per gross domestic product per capita) because of higher contributions to growth by the services sector. Nevertheless, development is coupled with electricity consumption and the demand continues to increase along with economic growth.

50. The DOE predicts peak demand for electricity in Luzon to grow by 4.78% annually from 2016 to 2040—from 9,726 MW in 2016 to 14,501 MW in 2025, reaching 29,852 MW by 2040.³³ On face value, projects under development by the private sector are more than sufficient to meet the expected demand growth: the DOE reported a pipeline of 19,934 MW of capacity under development.³⁴ This is comprised of 4,264 MW of “committed” projects due to go online from 2017 to 2022 and 15,670 MW of “indicative” projects from 2017 to 2025.³⁵

51. The rate of peak demand growth for electricity in the Visayas is expected to be higher than in Luzon. The DOE projects peak demand in the Visayas to grow by 6.85% annually from 2016 to 2040—from 1,878 MW in 2016 to 3,427 MW in 2025, and 9,210 MW by 2040 (footnote 35). The DOE reported a pipeline of 4,095 MW of capacity under development by the private sector comprising 468 MW of “committed” projects and a further 3,627 MW of “indicative” projects (footnote 36). During 2016, the Visayas region rapidly transitioned into a state of oversupply following the addition of 323.9 MW of solar power plants in Negros and Leyte and two coal-fired plants totaling 285 MW in Panay.

52. Expectations for robust demand growth in Luzon and Visayas are mirrored in Mindanao. Historically undersupplied and subject to demand curtailment (power outages), recent additions of coal-fired capacity have eased curtailments and otherwise unmet demand leading to significantly increased electricity usage. Peak demand in Mindanao reached 1,653 MW in 2016.³⁶ This is expected to grow by 7.54% every year from 2016 to 2040 to reach 3,456 MW by 2025 and 10,225 MW by 2040 (footnote 35). Despite the improved supply and demand situation, Mindanao’s hydropower supplies are subject to variation due to water availability, particularly in El Niño years. Hydropower accounted for 52% of generation capacity in 2013, but even the current share of 27% is high enough to pose a risk of seasonal power shortages in future El Niño years. On the other hand, 1,289 MW of new capacity could come online by 2019 if all currently “committed” projects materialize and the DOE is tracking a further pipeline of 3,627 MW of capacity as being “indicative” (footnote 36).

53. Outside of the three main grid-based regions of Luzon, Visayas, and Mindanao, total off-grid demand amounted to 209.86 MW in 2015 (around 1.6% of total) (footnote 35). On smaller islands and isolated grids, power provision by new power providers, independent power producers, and qualified third parties is increasingly being encouraged but the NPC-Small Power Utilities Group still acts as the main provider in these regions. However, many of the areas served by the NPC-Small Power Utilities Group still do not get reliable and 24-hour electricity services. As of July 2017, of the 123 NPC-Small Power Utilities Group existing power plants nationwide, 76 are operating less than 24 hours per day, indicating unmet demand. Some small island electric cooperatives also operate diesel generator sets that may only provide 4 hours to 6 hours of electricity per day.³⁷ Much of the off-grid demand lies on the islands of Masbate, Palawan, and Mindoro, and there are tentative plans by the NGCP to interconnect the latter to the main Luzon grid as discussed further in the succeeding section.

3. Transmission

54. Grid infrastructure across the Philippines will face increasing pressure for expansion and reinforcement to support demand growth. Grid development is invariably complicated by the difficulties of securing rights of way. Regional misalignments of supply and demand have become a prominent feature over the last 2 years, most notably in the Western Visayan regions of Panay and Negros where the addition of significant renewable energy capacity (mainly solar) has created grid congestion that limits the potential benefit of renewable energy resources in these locations.

55. The quality and strength of the grid within the Philippines is also subject to significant regional variation. Luzon, representing around 73% of total load requirements within the Philippines, has inherently been at the focus of grid infrastructure improvements. In 2016, transmission and distribution losses in Luzon were 7.87%, compared to 11.81% in Visayas and 13.68% in Mindanao (Figure 7).³⁸

56. As the concessionaire responsible for managing, operating, and investing in the transmission grid, a heavy burden of responsibility rests on the NGCP to fulfill its mandate with the Energy Regulatory Commission (ERC) also playing a pivotal role in having to approve major capex projects. Projects in the NGCP’s most recent Transmission Development Plan (2014–2015) published in December 2016 underscore the differing stages of development of each of the three main regional grids.

57. The NGCP’s focus in Luzon is on strengthening the transmission system and improving reliability and resilience through extensions of the existing 500-kilovolt (kV) transmission backbone from around the main load center of Metro Manila and into the generation heartlands of Western Luzon and Batangas. The NGCP is also due to undertake a looping of the Northern Luzon 230 kV backbone which evacuates power generated by hydro assets in the region and the Burgos wind projects on the northern tip of the island. The arrival of the country’s first supercritical plant planned for operation in 2018, the Pagbilao Expansion (420 MW), requires an extra high voltage substation. It is likely that the NGCP will need to undertake sustained grid investment (approved by the ERC) to facilitate the entry of several other large coal-fired projects over the coming years.

Figure 7: System Losses in the Philippines

Source: Government of the Philippines, Department of Energy..

58. In the Visayas, the NGCP is focused on alleviating grid constraints due to excess capacity from the raft of coal-fired and solar generation projects that came online during 2016 and to allow for further projects to enter the system. Under the FiT program, Negros saw the addition of 279 MW of solar capacity during March and April 2016 which amounts to 57% of the total solar capacity under the program on an island where peak demand reached 316 MW in 2016. The must-dispatch status solar is afforded and the variability of generation has posed grid management challenges.

59. The situation in the Visayas has led to the NGCP having two main priorities within the region. First, they intend to procure additional ancillary services, particularly regulating reserves (frequency response) to manage the effects of fluctuations in supply due to solar generation variability. Second, they intend to advance the Cebu–Negros–Panay 230-kilovolt backbone project which is comprised of three phases:

(i)	Phase 1. This involves an expansion of the Negros–Panay submarine interconnection from 180 MW (138 kV) to 330 MW (230 kV).
(ii)	Phase 2. This entails upgrading of the Negros overground transmission network to 230 kV to improve grid stability and support capacity additions.
(iii)	Phase 3. This is an expansion of the Negros–Cebu submarine interconnection from 180 MW (...

Table of contents

• Front Cover
• Title Page
• Copyright Page
• Contents
• Tables and Figures
• Acknowledgments
• Abbreviations
• Currency Equivalents
• Weights and Measures
• I. Introduction
• II. Overall Sector Context
• III. Institutional Context
• IV. Core Sector Issues
• V. Sector Strategy
• VI. Energy Sector Road Map and Results Framework
• Appendix: Energy Sector Problem Tree
• Footnotes
• Back Cover