Only 1.9GW of solar was tendered versus 3.4GW in 4Q16.

While solar installations in India have picked up speed, tender and auction activity have been slowing down over the last couple of quarters. According to the Mercom's India Solar Project Tracker, about 1.9 GW of solar was tendered in Q1 2017 (1 GW of this was a retender) compared to 3.4 GW in Q4 last year. 

There was 1.3 GW of solar projects auctioned in Q1 2017 compared to 255 MW in Q4 2016, according to an exclusive report by Mercom Capital group. The slowdown in activity has been disconcerting to developers and manufacturers that have been positioning for much higher levels of activity based on India’s solar installation goal of 100 GW by 2022.

India needs to install 18 GW of solar per year through 2022 to reach the 100 GW installation target set by the Modi government. The pace of tenders and auctions must pick up quickly if the government wants to meet its solar installation goals and show the investment community and the industry that it is serious.

Companies who have invested hundreds of millions to expand to meet the demand and build projects are anxiously waiting for activity to pick up.

Here's more from Mercom Capital Group: 

Some of the reasons for decline in tender and auction activity include poor financial condition of distribution companies (DISCOM), transmission issues, weaker power demand and increases in captive generation by commercial and industrial companies. DISCOMs that are continuing to struggle financially are not taking on new generation that is more expensive than coal, which is leading to curtailment of solar and wind projects as well as payment delays to developers.

In some states, weak power demand is removing the urgency to speed up the pace of solar tenders and auctions. Increases in captive generation by industrial customers have compounded the situation since they are requiring less power generation from DISCOMs.

The World Trade Organization (WTO) ruling against India’s domestic content requirement (DCR) has resulted in continuous cancellations and postponements of planned DCR tenders.

The recent record low bid of Rs.3.30 (~$0.494)/kWh at the REWA solar park auction is playing a big role in the slowdown of auction activity as government agencies and states are stalling to renegotiate PPAs that are more expensive than the bids received at REWA.

For DISCOMs, coal is still the cheapest option available. According to Mercom’s December Solar Quarterly Report, DISCOMs have resorted to sporadic curtailment from some solar projects in Rajasthan and Tamil Nadu because cheaper power is available on the power exchanges. Even when there is demand, several states have complained that the DISCOMs are resorting to power cuts instead of buying power on the exchanges to save on costs.

Mercom has previously reported that power purchase agreements for 1.1 GW of solar in Jharkhand are yet to be signed because the state DISCOM is not accepting the quoted tariffs. According to Mercom’s India Solar Project Tracker, tariffs quoted in the state ranged from a high of Rs.5.59 (~$0.0824)/kWh to a low of Rs.5.08 (~$0.0749)/kWh. The state had tendered 1.2 GW of solar since December of 2015 in an effort to achieve its 2,650 MW solar target by 2020, but there has been no activity since. In this case the DISCOM was unwilling to sign the PPAs for tariffs above five rupees per kWh claiming it is not viable for the DISCOM. The situation will get even more challenging after the recent REWA auction. Due to aggressive renewable energy targets in some states like Rajasthan and Tamil Nadu, solar grew even at high tariff levels only to leave the states struggling with finances a few years later and finding it difficult to take on new solar generation.

“It has been disappointing with the delay in tenders. After September 2016, tenders have slowed down for IPPs. It is less likely we will see new tenders after the REWA bid as each bid is now being expected to meet the REWA numbers, which is ridiculous. The Kadapa Solar Park tenders are postponed as Andhra Pradesh has pulled out because they now have surplus power and their cash flow situation is bad. DISCOMs are currently of the belief that solar tariffs are falling, so let us wait, with states claiming that they are power surplus and don’t need any kind of power, let alone solar, stated a large developer while in conversation with Mercom.

Raj Prabhu, CEO of Mercom Capital Group warned about this after the REWA auction in his statement: “Although this is the lowest tariff ever recorded in India, this auction has several special attributes which makes it hard to directly compare with previous low bids. The size and location of the projects, payment guarantees, deemed generation benefit, longer construction timeline, the recent solar module price crash, and yearly tariff escalation for 15 years - all make the low bids unique.” Prabhu continued, “The fear is that media, government officials and analysts will hype up the low bids and other states will then start pressuring developers to match bids from the REWA auction tariffs, which has happened in the past.”

Several other developers told Mercom that as of now Bihar, Jharkhand, Tamil Nadu, Rajasthan, and Maharashtra are the problem states. According to Mercom’s Solar Project Tracker, tendering activity has declined in these states with most of the old tenders being continually extended.

Solar sector is ballooning at a rapid pace.

Renewable energy generation in India continues to grow, accounting for ~16.10 percent of India’s energy mix, according to Mercom Capital Group. The country’s total installed generation capacity is 315,369.08 MW with renewables accounting for 50,745 MW of it.

Hydro power makes up 14.01 percent, with 44,189.43 MW of the total power generated in the country. Nuclear power has a total capacity of 5,780 MW and making up 1.83 percent of the energy generation.

Here's more from Mercom Capital Group:

The solar sector is witnessing installations at a rapid pace. The recent solar auction at the Rewa solar park witnessed record low tariff of Rs.3.30/kWh, closing in on thermal power tariffs. Solar accounts for 9,235.24 MW of the total installed capacity and 2.93 percent of overall power generation, an increase of 0.06 percent over a month.

The wind sector recently successfully implemented competitive bidding process to develop wind power projects of 1,000 MW at record low tariff giving a boost to future wind auctions. Wind currently accounts for 28,871.59 MW of the total installed capacity and 9.15 percent of overall power generation, an increase of 0.01 percent over a month. The installed capacity of small hydro has increased slightly with 4341.85 MW of total installed capacity.

Coal-based generation capacity in India stands at 59.77 percent of the total installed capacity of 315,369.08 MW as of January 31, 2016, according to the Central Electricity Authority (CEA). The total thermal power generation stands at 68.07 percent with a capacity of 214,354.89 MW. Thermal power numbers are declining as no new projects are being commissioned and thermal project developers have inhibitions about developing new projects due to the draft electricity plan 2017-2022. 

Total new capacity addition of 9GW is being expected come 2017.

Bridge to India said that key highlights in the sector over the year include record project volumes – both for capacity addition and issue of new tenders, improving power distribution company (DISCOM) financial position as a result of UDAY scheme, steep fall in equipment prices, improving M&A activity and India’s ratification of climate accord adding credibility to the country’s ambitious 100 GW target for 2022.

The year has been bountiful in all respects for the sector with most key indicators growing 2-3x over last year. The country added total solar capacity of 4.9 GW (estimated), an increase of 101% over 2015 and crossed the 10 GW cumulative installed capacity mark. New tenders were floated for 9 GW of grid connected solar projects including 900 MW for rooftop solar systems.

As solar tariffs fell below INR 5 (USD 0.07)/ kWh, solar power gained parity with other sources of greenfield power.

Falling cost has been instrumental in boosting solar demand from the DISCOMs despite total power demand staying relatively weak throughout the year.

Both Solar Energy Corporation of India (SECI) and National Thermal Power Corporation (NTPC) are expected to allocate substantial new capacity in 2017 attracting even more competitive tariff bids. "We expect the INR 4 tariff level to be breached in early 2017, which will be a radical moment for the entire power sector in India," it said in a report.

Here's more from Bridge to India:

Indian project developers asserted themselves strongly in 2016 winning over 90% of tendered capacity. All of the top 10 developers by pipeline capacity are now ‘home-grown’ IPPs and corporates. Successful sale of solar assets of Welspun (to Tata Power), SunEdison (Greenko), Punj Lloyd (IDFC Alternatives) among others and international IPO by Azure has helped instil confidence in the sector’s growth prospects. Falling module prices proved to be a gift that keeps on giving to aggressive bidders. Reduced Chinese demand in the second half of 2016 resulted in prices tumbling by 20% during the year.

India’s rooftop solar segment also crossed the symbolic 1 GW mark in September this year, growing by 135% over last year. Attractive capital subsidies and substantial demand from public sector are expected to continue to provide great demand boost to the segment over the next few years.

All this positivity is somewhat tempered by growing incidence of delayed power purchase payments by many DISCOMs and curtailment risk, two risks which badly affected wind power sector during the year. Solar sector has so far been lucky to escape likely because of smaller capacity (9 GW vs 28 GW of wind power capacity) and much greater political attention. However, these risks pose significant challenges to the sector despite strong government support and UDAY scheme.

The global supply glut in modules consolidated the hold of Chinese suppliers in the Indian market as over 80% of all modules installed in India in 2016 came from China. The World Trade Organization (WTO) declared India’s policy for domestic content requirement illegal and the proposed policy to support local manufacturing seems to be getting delayed. As a result, several ‘Make in India’ plans announced by various Indian and international suppliers have come to a naught.

Looking forward to 2017, we expect total new capacity addition of over 9 GW (up 90% over 2016) and up to 8 GW of new utility scale capacity allocation by NTPC, SECI and states including Madhya Pradesh, Maharashtra and Tamil Nadu. As other international markets including China, Japan and Europe slow down, India will remain one of the fastest growing markets around the world. But we remain pessimistic about the new domestic manufacturing policy.
 

It has become highly dependent on coal and LNG.

The U.S. Energy Information Administration recently reported that as Japan's electricity generation mix shifted away from nuclear energy toward the increased use of coal and natural gas after the Fukushima accident, Japan became increasingly reliant on generating electricity using imported coal and liquefied natural gas (LNG). However, even as the imported cost of coal and LNG declined, Japan's electricity price increased. According to data from Japan's 10 major utilities, the average retail electricity price rose for four consecutive fiscal years (2011–14). In fiscal year 2015, as LNG prices fell by 37% and coal prices fell by 19%, Japan's retail electricity price fell by 2%.

Principal contributor Andrew Estes said that because Japan has little or no domestic resources of natural gas or coal, the country relies heavily on imports of these fuels. As nuclear generation was shut down following the incident at the Fukushima Dai-ichi plant, electricity generation from coal and natural gas plants increased. From 2011 through 2014, Japanese imports of LNG and coal increased by 8% and 9%, respectively.

Here's more:

In 2015, however, LNG imports decreased for the first time since 2009, as low coal prices led to increased imports of coal. LNG prices fell 37% from 2014 to 2015 as a result of oversupply in the global LNG market, but this price decrease was not enough to make LNG imports more economic than lower-priced coal, particularly as Japanese utilities dealt with stagnant or declining electricity demand. Continued price drops could lead to increased imports of LNG in the near future, as LNG supply continues to grow and transportation logistics provide access to new markets.

Ten regional utility companies currently supply more than 90% of the electricity in Japan. Each of these companies has been a monopoly in its region. Believing more competition could ease the price pressure on consumers, Japan initiated reforms aimed at deregulating the electricity sector in three phases by 2020. The first phase established an independent system operator to dispatch electricity across the national grid in 2015. On April 1, 2016, regional monopoly control of existing utilities was removed, so competition could enter the market and give consumers the choice of supplier. The removal of pricing regulations and unbundling of the utilities' transmission, distribution, and retail businesses are the final steps in deregulating Japan's electricity market by 2020.

Japan is looking to restart a portion of its nuclear fleet and increase coal capacity in order to continue lowering its electricity prices. Japan restarted two nuclear reactors at their Sendai nuclear plant in 2015. Two additional reactors at the Takahama nuclear plant had been restarted by early 2016. However, on March 9, 2016, a court-ordered injunction called for a shutdown of the Takahama reactors. Another reactor, Ikata Unit 3, was restarted in early August.

 

Capacity is projected to jump to 27.8GW by 2030.

The development of hydroelectric power in China—including the world's biggest hydropower plant at Three Gorges Dam—is substantially larger than planned expansions of hydroelectric power capacity in other countries of Southeast Asia. This is according EIA's recently published International Energy Outlook 2016.

EIA said in the report that the smaller countries in the region have announced plans to construct a combined total of 78 gigawatts (GW) of new hydroelectric generating capacity by the end of 2020. If those projects are completed, total hydropower capacity in the smaller countries will triple their combined 2012 capacity of 39 GW.

Here's more from EIA's outlook:

Many of the countries in Southeast Asia have access to the immense hydroelectric potential of the lower Mekong River, which flows through or borders China, Myanmar, Laos, Thailand, Cambodia, and Vietnam. Hydroelectric power potential in the Greater Mekong Region (which includes Mekong tributaries) is estimated to be between 175 GW and 250 GW.

China already has constructed 6 major dams along the upper portion of the Mekong, and as of 2010 another 71 Mekong hydroelectric dams were proposed for completion in other Southeast Asia countries by 2030 [175]. Vietnam, Indonesia, Bhutan, and Laos already have announced plans for significant additions to hydroelectric capacity in the Mekong region, as well as projects centered on other hydroelectric resources.

Vietnam has the most ambitious hydroelectric development plan in Southeast Asia, with plans to increase total hydroelectric capacity to 21.6 GW in 2020 and to 27.8 GW by 2030. One of the largest planned projects is Trung Son, to be located on the Ma River in northern Vietnam (which is not a Mekong tributary), with an expected capacity of 360 megawatts (MW).

China is on track in being the number 1.

Asia's giant may have failed in boosting its nuclear installed capacity, but it is still on the road to becoming the country with the most number of nuclear power plants, and it's even likely to outpace the United States.

A spokesperson from the Institute of Energy Research said that China is building nuclear reactors quickly and cheaply—about 5 years per reactor and $2000 to $2500 per kilowatt. By 2020, China should have 58 gigawatts of nuclear capacity. By 2050, China’s nuclear power should exceed 350 gigawatts, having spent over a trillion dollars in nuclear investment. In just ten years, China’s nuclear capacity will likely exceed that of the United States.

India, on the other hand, has been reported by World Nuclear News to have allocated an extra 30 billion rupees ($442 million) to boost nuclear power generation projects over the next 15-20 years in its 2016 budget, finance minister Arun Jaitley announced on 29 February.

"We need to diversify the sources of power generation for long-term stability," Jaitley said in his budget speech. "The government is drawing up a comprehensive plan, spanning over 15 to 20 years, to augment nuclear power generation. Budgetary allocation of up to 3000 crore rupees per annum, together with public sector investments, will be leveraged to facilitate the required investment for this purpose," Jaitley said in his budget speech. (One crore is equivalent to ten million).

Over to Malaysia, the local government is keen to develop a domestic nuclear industry, and the Malaysia Nuclear Power Corporation (MNPC) was set up in 2011 to focus solely on the development of nuclear in the country. Malaysia has one 1MW research reactor, which was build in the 1980s, but no other nuclear capacity is online. The original aim was to build two nuclear power plants in the country by 2021 and 2022; however, this was postponed as opposition against nuclear ignited in the aftermath of the Fukushima disaster in Japan in March 2011.

However, Georgina Hayden from BMI Research said that they have since seen an uptick in rhetoric towards nuclear, notably in 2014, when the government announced it aims to develop nuclear in the country by 2024/2025. It has been reported that site selections are underway and negotiations with international nuclear companies are ongoing - with Rosatom, Areva, Westinghouse amongst others being cited as contenders.

"Malaysia's push to develop nuclear power is driven by the government's desire to diversify the country's power mix away from a heavy reliance on thermal
energy sources and ensure long-term energy security. Malaysia relies on natural gas for nearly 55% of its electricity needs, and coal for roughly 34%," Hayden said.

Its regulatory environment is still immature.

Vietnam's plan to review new coal-fired power projects and potentially shift its power mix to incorporate greater renewable energy and gas is unrealistic, as the regulatory environment for renewables is underdeveloped, domestic gas production remains in decline, and cheap coal is widely available.

As such, coal is expected to play the dominant role in the power mix by 2025, contributing roughly 45%.

According to BMI Research, Vietnam's power sector is expanding rapidly as the country's bright economic outlook and improving electrification rates drive power demand, and progress in the regulatory environment for the power sector strengthens investor interest in the market.

"We have seen a notable build-up of the project pipeline as companies look to take advantage of the attractive returns on offer; in particular, the pipeline for coal-fired power facilities has swelled significantly. In fact, Vietnam has the largest amount of coal-fired power capacity in various stages of development in the Asia region (excluding the two largest coal power markets in Asia - China and India), according to our Key Projects Database," it said in the report.

Here's more from BMI Research:

This growing dependence on coal-fired power generation aligns with Vietnam's Power Development Programme, which envisages coal's share in the power mix increasing to roughly 60% by 2030 (revised in April 2015). However, the announcement in January 2016 that the government will review the development of all new coal plants contradicts the Power Development Programme and is sending mixed messages regarding Vietnam's future energy agenda.

Furthermore, the government will increase its focus on shifting the power mix towards cleaner sources, notably gas and renewable energy, in a bid to reduce emissions. This rhetoric is undoubtedly catalysed by the global agreement reached at the UN COP21 conference in December 2015.

We believe Vietnam's plan to potentially shift its power mix to lessen coal use and incorporate greater renewable energy and gas is unrealistic. As such, we expect coal to play the dominant role in the power mix by 2025, contributing roughly 45%. 

Vietnam's regulatory environment for renewables remains underdeveloped, which will hinder the expansion of the sector and result in only marginal growth over the coming decade. The renewables project pipeline is limited due to the feed-in tariff structure, which is too low, meaning that project developers can not secure attractive returns on their investment

Capacity expansion is aggressive, but headwinds in demand side persist.

Vietnam is poised to significantly transform its electrical power generation mix over the next two decades as it modernises the country's agrarian economy to become a more industrialised nation. According to EIA, to accommodate greater industrial expansion and to support energy security goals, Vietnam is significantly increasing its total electricity generating capacity. “As part of its capacity expansion, Vietnam plans to add substantial coal-fired capacity and also plans to build the first nuclear reactors in southeast Asia and the first offshore wind farm in Asia,” EIA explains.

However, according to ADB in its recent assessment report, Vietnam in its next stage of development will face the following challenges in meeting the rapidly rising demand: coping with the rapid change in energy supply structure; maximising the use of domestic energy resources efficiently and lowering imports, adopting new technologies; mitigating environmental impacts and achieving the set targets in sustainable green development; enhancing energy efficiency; strengthening institutional capacities; diversifying energy supply, including that of renewable energies; and increasing energy prices to its socially and environmentally acceptable level to cover full costs. 

BMI said that this growing dependence on coal-fired power generation aligns with Vietnam's Power Development Programme, which envisages coal's share in the power mix increasing to roughly 60% by 2030 (revised in April 2015). However, the announcement in January 2016 that the government will review the development of all new coal plants contradicts the Power Development Programme and is sending mixed messages regarding Vietnam's future energy agenda.

Furthermore, the government will increase its focus on shifting the power mix towards cleaner sources, notably gas and renewable energy, in a bid to reduce emissions. This rhetoric is undoubtedly catalysed by the global agreement reached at the UN COP21 conference in December 2015

But its untapped potential is still mired in issues.

According to CARE Ratings' recenty published outlook on India's wind power projects, the total installed capacity of renewable power projects as on March 31, 2015 aggregates to 35.77 GW (excluding 41.27 GW of large hydro projects) against the total potential capacity of 249.19 GW. 

India has wind potential of around 102.77 GW out of which the total installed capacity as on March 31, 2015 was 23.44 GW with an untapped potential of about 77%. A major part of capacity addition and exploitation of wind potential in the future is expected from private sector projects.

"The overall installations of wind power projects are better during FY15. Going forward, considering the wind power projects in pipeline with various IPP’s it is expected that the capacity additions would grow between 2000 MW to 2500 MW during FY16 - FY17. During 5MFY16, the total wind capacity additions remained at 645 MW," CARE Ratings said.

Here's more from CARE Ratings: 

Huge untapped potential in wind power is attributed to lower Plant Load Factor (PLF) in comparison to fossil fuel, nuclear and hydropower plants. Furthermore, due to the limitation of grid infrastructure, it has been found that the amount of energy produced from wind farms could not be effectively transmitted to consumers causing wastage of energy.

However, the financing structure of wind power projects in India is still bound in uncertainty due to aforementioned issues though the untapped potential is huge the extent to which the same can fructify still remains uncertain.

As on January 2014, states like Maharashtra, Rajasthan and Tamil Nadu had utilized their overall wind energy potential by more than 50%. Karnataka, Madhya Pradesh, Gujarat and Andhra Pradesh on the other hand has estimated wind potential of 13.6 GW, 2.9 GW, 35.1 GW and 14.5 GW, spread across 26, 7, 40
and 32 wind farmable sites out of which it has been able to utilize only 17%, 13%, 10% and 4% respectively of capacity.

Power use has been surging by 7.7% a year.

According to the U.S. Energy Information Administration, from 1998 to 2012, the energy consumption of buildings in China grew by about 7.7% per year, much faster than China's average annual population increase, which was less than 1% per year.

This consumption growth was driven by growing incomes and modernization that significantly increased the use of electricity and other forms of energy. In an effort to reduce energy consumption in residential and commercial buildings, China has implemented various energy efficiency policies and programs, including building energy codes, green building ratings, minimum energy performance standards, voluntary ratings programs, and energy-efficiency retrofits in existing buildings.

Here's more from EIA:

China issued the first building energy code in 1986 for residential buildings in the northern part of the country where space heating demand is highest. These codes required a 30% reduction in space heating energy consumption compared with reference buildings from 1980. The stringency of these codes has increased over time. 

There are currently three energy codes for residential buildings in four climate zones (severe cold climate or cold climate, hot summer/cold winter, and hot summer/warm winter) as well as one code for commercial buildings. Urban residential and commercial codes are mandatory, while rural residential energy codes are voluntary.

China launched a green building labeling system referred to as the Three-Star Rating Building System in 2006. Under this program, buildings are rated from one to three stars according to criteria that include use of land, energy, and water, in addition to material efficiency, indoor environmental quality, and operational management. In addition to building design, the Three-Star Rating Building System measures a building's performance and awards a rating after one year of building operation.

China adopted the first minimum energy performance standards in 1989 for products such as refrigerators, room air conditioners, clothes washers, and televisions. Since then, China has implemented additional minimum energy performance standards for other major appliances, lighting, and cooling and heating equipment.

In 1998 China established a voluntary energy efficiency labeling program, similar to the U.S. ENERGY STAR® program. In 2005, the Chinese government introduced a mandatory energy information label, similar to the European Union categorical energy label. Under this program, appliances are categorized based on their level of energy efficiency performance.

The Chinese government has paid particular attention to retrofits and renovation of existing buildings. The purpose of this program is to bring existing buildings to the level of code required for new construction. In 2011, the government strengthened its obligation by requiring a 10% reduction in energy consumption per square meter for commercial buildings and a 15% reduction for large commercial buildings with more than 20,000 square meters of floor area by the end of 2015. Under the Green Building Action Plan of 2013, more than 400 million square feet in residential homes and all eligible commercial buildings in the northern heating zone are anticipated to be retrofitted by the end of 2015 and 2020, respectively.

Energy demand in Chinese buildings is expected to continue to grow as a result of urbanization, further increases in per capita disposable income, and demand for more comforts and services. Upgrades of building energy efficiency performance standards, new technology development, education and awareness programs, enforcement of energy efficiency policies, and improved compliance could each play a role in reducing the future rate of consumption growth.

5GW of new capacity will come online by 2022.

Indonesia ranked third in the world in both geothermal electricity production and geothermal generating capacity in 2014, behind only the United States and the Philippines. The country is located at the convergence of several tectonic plates in Southeast Asia, giving it significant geothermal potential, although most of its potential reserves remain unexplored.

According to US Energy Information Administration, Indonesia's Ministry of Energy and Mineral Resources estimates that the country holds a potential 29 gigawatts (GW) of geothermal capacity reserves, only 5% of which is currently being used. Indonesia's current geothermal capacity of 1.3 GW consists of plants clustered around Java, Bali, North Sumatra, and North Sulawesi.

EIA's latest report on Indonesia said that geothermal currently makes up less than 3% of Indonesia's total electricity generation capacity, but Indonesia plans to increase geothermal capacity by 2025 as part of a plan to increase electrification in the country.

Here's more from EIA:

Despite a doubling of its total electricity generating capacity in the past decade, Indonesia still has a low electrification rate compared to countries with similar income levels. In 2014, about 84% of Indonesia's population had access to electricity compared to less than 68% in 2010, according to state electric utility Perusahaan Listrik Negara. Indonesia's latest energy policy aims to achieve nearly complete electrification of the country by 2020. In recent years, electricity capacity additions have not kept pace with electricity demand growth, leading to power shortages in grid-connected areas. Inadequate infrastructure as a result of insufficient investment and regulatory hurdles contributes to lower electrification rates, primarily in eastern Indonesia.

Fossil fuels power most of the electricity generation in Indonesia (88%), while renewables, primarily in the form of hydropower and geothermal resources, account for the remainder. Indonesia intends to use domestic fuel sources and diversify its fuel portfolio to include more renewable power. Plans to increase renewable energy use to at least 23% of the energy portfolio by 2025 depend heavily on further developing the country's geothermal and hydropower resources.

Indonesia has included several geothermal power plants in its fast-track program, which is meant to accelerate the development of more than 27 GW of total power capacity in the next several years. Indonesia has focused on geothermal in particular, signing an agreement with New Zealand in 2012 for joint development of geothermal energy projects.

About 5 GW of new geothermal capacity is slated to come online in Indonesia by 2022, including the 330-megawatt Sarulla power plant, potentially the world's largest geothermal power plant. Successful completion of these geothermal projects could result in Indonesia becoming the world leader in both geothermal electric capacity and generation.

One impediment to unlocking the country's vast geothermal resources has been the definition of geothermal development as a mining activity, which restricted new projects in conservation areas. Indonesia passed a law in 2014 that eliminated this limitation on geothermal development while streamlining the permitting process and alleviating land acquisition issues. The law also attempted to raise private sector investment in geothermal projects by making the price more closely match development costs.

Zero in on the ASEAN power grid, analysts say.

According to the latest report by the International Energy Agency, given the challenging geography, funding cross-border connections can be a major hurdle. Power system investment needs are significant compared to the existing ASEAN asset stock and to global investment needs.

IEA projections show that the total power sector investments required – excluding interconnections – may reach USD 1.3 trillion by 2040. The current APG plan is estimated to cost USD 20 billion.

Here's more from IEA:

It is evident that public spending is limited and will not suffice for the timely development of the envisaged electricity infrastructure.

The completion of some interconnections is more realistic than that of others because of existing business scenarios. These projects enjoy funding from multilateral development banks, bilateral agencies and the private sector.

However, other APG projects lack economic viability although they have regional benefits and can be seen as a regional public good. ASEAN needs to invest more directly in the APG, provide public guarantees to attract more private and foreign direct investment and avoid funding strategic regional interconnections solely
from its own budgetary resources.