Providing the fuel for Thailand’s economic growth engine, the energy sector continues to expand in order to meet the growing demands of the country. Domestic primary energy consumption is weighted heavily towards fossil fuels, which accounted for 98% of primary energy consumption in 2014. Natural gas has become the fulcrum upon which energy development is now focused in both the hydrocarbon and electricity segments, with the fuel representing 44% of total primary energy usage. Oil and gas exploration and production has become increasingly focused on natural gas over the years as crude oil production has plateaued and the power generation sector has become ever-more reliant on gas for over half of all power production. Static crude oil production from mature fields has resulted in a shift away from the fuel for usage outside of the transportation segment, as the country becomes increasingly reliant on imports to meet growing demand. Less-expensive coal and lignite maintain an 18% share of the primary energy segment, while hydropower and other renewable energy technologies, along with imported electricity, made up the remaining 2% of the total energy mix in 2014. The ratio of natural gas within the country’s primary energy mix is likely to soon be nearing its high-water mark as domestic supplies wane. In light of this situation, the government has begun to place a new emphasis on energy diversification and a concurrent reduction in overall consumption.
Driven by continued industrial and financial growth, total primary energy consumption in 2014 increased by 2.6% from that in 2013 to a level of 2053 barrels of oil equivalent per day (boepd). Domestic demand continues to outstrip supply, as total primary energy production in 2014 decreased by just 0.4% over 2013 levels to 1073 boepd. As a result, energy net imports increased 4.4% to 1171 boepd, with commercial energy imports accounting for 57% of primary industrial and commercial energy consumption.
Concerted efforts by foreign oil majors including Chevron, Mitsui, Petronas, Total and ExxonMobil, along with domestic operators including state majority-owned PTT Exploration and Production (PTTEP), yielded significant gains over the past decade which have only recently begun to decline. Fuelled by large discoveries, crude production peaked in 2009 at an all-time high of 154,041 boepd.
Since then, maturing fields have slowly tapered off each year to 138,758 barrels per day (bpd) produced in 2014, down 7% on the 149,481 bpd recorded in 2013. In addition to the slow decline inherent in maturing fields, the dip in output was amplified by temporary shutdowns of the Bualuang and North Jamjuree fields. The losses incurred there offset fresh output from two new fields – the offshore Manora (8000 bpd initially since November 2014) and the onshore Wichienburi Extension (4000 bpd initially since December 2014). Data from the Ministry of Energy (MoE)’s Energy Policy and Planning Office collected for the first six months of 2015 indicates that production is on pace for a slight rebound and averaged 142,554 bpd up to the end of June 2015. This was largely due to increased production from newer and smaller plays balancing out the incremental losses from the major legacy fields.
The majority of Thailand’s most productive fields are located in the Gulf of Thailand and include the Chevron-operated Benjamas field, the Songkhla field run by Coastal Energy Company International subsidiary Nucoastal, the Jasmine field run by the UAE state-owned investment firm Mubadala Development Company, the Bualuang field operated by Ophir Energy, and the “Big Oil Project” composed of the Plamuk, Kaphong, Surat and Yala fields initiated by Unocal Corporation prior to its 2005 merger with Chevron. As evidenced in the overall downward production trend over the past five years, all but two of these established fields are in decline. However, the offshore plays are complemented by several smaller onshore fields led by the largest single active producing field, Sirikit, which is operated by PTTEP.
With a 29% share each of domestic production, Chevron and PTTEP control the bulk of the country’s indigenous production. Other significant players include Mitsui, whose holdings contribute a 9% share of national petroleum output, along with Total and Petronas, each with a 7% share, followed by Hess and British Gas (BG), each with a 5% share. The most productive active play currently is the Sirikit field owned by state majority-owned PTT Siam, a subsidiary of the diversified national energy conglomerate PTTEP, which remains 65.3% held by the Thai government. After experiencing a temporary drop-off in production in 2014 to 27,948 bpd, the field rebounded to 28,031 bpd through the first half of 2015, and has the potential to continue its upward trend with enhanced oil recovery and other advanced drilling and exploration techniques.
The only other major contributing field to show steady growth in recent years is Ophir Energy’s Bualuang Field, which has increased its output each year from 7200 bpd in 2012 to 12,572 bpd in 2015. A number of other major finds on the down slope of the production cycle include Benjamas, which averaged 19,968 bpd in the first half of 2015, along with the Big Oil Project producing 22,078 bpd (down from 28,281 bpd in 2012), Songkhla, producing 11,276 bpd, and the Jasmine field (9745 bpd).
Global hydrocarbon price drops are affecting the energy mix as well, although lower prices have had some helpful effects on the sector in terms of lower costs. “The recent global drop in oil prices has had a positive net effect on the downstream petrochemicals sector, as 60-70% of the cost of production is related to the price of crude oil,” Atikom Terbsiri, CEO and president of Thai Oil, told OBG.
As domestic production of oil and gas flattens, the energy sector is looking to the next round of blocks to be auctioned by the government to drive a new wave of exploratory investment. The 21st bidding round will be the first to take place since the 20th concluded in 2007. The current selection of blocks up for bidding has, however, faced multiple delays as the government considers substantial amendments to the bidding, tax and legal structure of future contracts for oil and gas (see analysis).
While these proposed amendments are debated, the long-awaited release of new territory has already garnered significant interest from the sector, in spite of the modest potential for a new massive find. In all a total of 29 concessions will be up for bidding – 23 onshore blocks in the central and northeast provinces and six more in Gulf of Thailand – with a combined total area of 66,464 sq km. Petroleum potential for all prospects in total is estimated by the MoE at 28.3bn-141.6bn cu metres of natural gas and 20m-50m barrels of oil. The offerings are significantly less than the previous bidding competition in 2007, when the Department of Mineral Fuels (DMF) offered 65 exploration blocks (56 onshore and nine offshore) but ultimately awarded only 28.
Eleven of these onshore blocks are located in the hydrocarbon-rich Khorat Plateau in north-east Thailand, which is believed to still hold significant gas reserves of approximately 141.5bn cu metres, with much of the area still largely unexplored. Three sizeable gas fields have already been discovered in the Khorat Plateau, with the Nam Phong and Sin Phu Horm commercial gas discoveries estimated to have proven recoverable reserves of about 48bn cu metres. The six offshore blocks are situated in the attractive tertiary basins of the Gulf of Thailand, home of the country’s largest oil- and gas-producing zone to date. Block G1/57 in particular will likely garner significant attention due to its prime location just to the north of the productive Jasmine and Benyen oilfields, which produced a combined 13,171 bpd of crude oil from 56 wells as of August 2015. Other offshore blocks are also located adjacent to the oil and gas fields in the southern part of the Gulf of Thailand. Although the 21st round of bidding is expected to spur on new exploration and development activities, one attractive offshore region remains absent from the proceedings – the maritime boundary area currently under dispute between Cambodia and Thailand. Although the Malaysian Joint Development Area (JDA) has proven lucrative for both participants, complications have arisen over the negotiations on a proposed joint development zone between the two countries that continues to undermine progress on the project.
Foot On The Gas
Natural gas production in Thailand did not begin on a commercial level until the Erawan field was brought on-line in 1981. Over the ensuing three-and-a-half decades, Erawan has proven itself as a reliable stalwart for the upstream gas sector even as numerous new legitimate gas plays have been discovered. Exploration and production activity has been increasingly driven by the country’s increasing reliance on the fuel, which has come to dominate the electricity sector as the country has transitioned away from more polluting coal and oil and as with gas consumption has grown markedly in the industrial and transport sectors. Domestic production has increased many times over since 1990 as more than a dozen major plays were commercialised, bringing output from just 631m standard cu feet per day (scfd) in 1990 to 4073m scfd by 2014. This indigenous supply accounted for 80% of total gas usage for the year, with the remaining 20% imported from Myanmar (843m scfd) and further complimented by incoming liquefied natural gas (LNG) shipments totalling 182m scfd.
Domestic natural gas production is heavily dependent upon two major fields located in the Gulf of Thailand: Bongot, operated by BG Thailand, and the JDA, which is being developed in conjunction with Malaysia. The Bongot field remains the star performer in the country, with 975m scfd produced in 2014 after becoming the first play in Thailand’s history to top the 1000m-scfd mark the previous year with 1008m scfd. Output from the field, which is owned by a consortium of PTTEP (44.4%), Total (33.3%) and BG Thailand (22.2%), rebounded in the first half of 2015 to 1004m scfd.
Natural gas output from the JDA rose to a high of 761m scfd in 2014, making it the second-largest contributor after gas began flowing from the project in 2008. Other major contributors included Arthit with 246m scfd, Pailin (314m scfd), Erawan (219m scfd), Funan and Jakrawan (176m scfd), Satun (138m scfd) and Phu Horm (106m scfd).
Yet while the majority of these areas have established themselves as key contributors to the energy sector for decades, production growth in the now mature fields has slowed, with continued extraction requiring constant investment cycles in order to maintain output. Ongoing investment has been less of an issue in the past for operators of legacy fields such as Chevron and BG Thailand, but with the concession contract termination dates for some of these crucial fields just over the horizon and no clear framework for extensions set, future production levels are far from guaranteed.
The weak point in the regulatory framework governing oil and gas concessions which was not anticipated in the original Petroleum Act (PA) is that there is no legal construct for how to proceed once the contract and subsequent extension expires. This problem is looming large as the concessions for Thailand’s most productive blocks near their termination dates. The three contracts governing the Bongot block are set to expire in 2022 (one block) and 2023 (two blocks) while Chevron’s Erawan blocks will also expire in 2022.
Taking into account this five-year development window, the operators of these blocks will thus need a concrete framework on which to base investment decisions by 2017 at the latest in order to avoid declining production. For its part, the government, including the DMF, announced in 2015 it would clarify details on the new contracts and have the new policy in place by the end of 2016 (see analysis).
Although concerted exploration and production efforts have continued to increase Thailand’s oil and gas output over the years, slowing domestic output along with an increasing appetite for primary energy has resulted in a growing reliance in foreign imports to make up the difference. More than half of Thailand’s hydrocarbons needs were met by imports in 2014, with indigenous supply accounting for 893m boepd, equal to 44% of the total annual supply. The imports were 16% crude oil (142,840 bpd), 9.5% condensate (85,006 boepd), and 74.5% natural gas (3650m scfd). Even with the current climate of low energy prices, energy imports cost the country BT1.4trn ($42.1bn) in 2014 and averaged BT1.2trn ($36.1bn) annually from 2007-14.
Domestic demand for crude oil and refined petroleum products has increased from 1.3m bpd in 2010 to 1.87m bpd in 2014. While some of this domestic demand is eased by refining condensates recovered from natural gas fields, Thailand remained heavily reliant on crude imports totalling 804,912 bpd in 2014 and 892,985 bpd through the first half of 2015. The majority of the imports were shipped from the Middle East, which accounted for 66% of all imports in 2014, with another 10% sourced from the Far East, while a number of other countries supplied the remaining 24%. Crude oil imports were valued at B979.9bn ($29.5bn) in 2014, which were easily the largest single energy expense, accounting for 70% of all imported energy costs for the year.
Unlike oil, domestic output of natural gas continues to rise for the time being. Unfortunately for the country’s energy balance, these modest gains in production are being outpaced by increases in demand, leaving the country to turn to imports again to make up the shortfall. This has led to a dramatic increase in foreign gas in the energy mix – mostly from neighbouring Myanmar – which grew from just 2m scf in 1998 to a high of 1025m scf by 2014. Transported via cross-border pipelines, the majority of the gas comes from the Yadana, Yetakun and Zawtika gas fields in Myanmar, which contributed 413m scfd, 339m scfd and 91m scfd, respectively, to the total supply for the year. These imports have been supplemented by global shipments since the country’s first regasification terminal began operations in 2011, and LNG imports totalled 182m scfd in 2014. At least three more LNG-receiving terminals are planned to accommodate increased shipments in the coming years, with the second terminal expected to come on-line in 2016. Payouts for imported natural gas totalled BT117bn ($3.5bn) in 2014, or 8% of the total energy importation bill.
The 2015-16 global economic and energy climate, along with a growing number of LNG export terminals in the region, has made it easier for buyers to acquire natural gas on global markets at more attractive prices than were available a few years ago. Yet pursuing a strategy of increased energy imports could be detrimental to the country in the long run. Even paying the lower spot market prices currently available for natural gas on the international market, the economic value of buying domestic gas from the Gulf of Thailand at a slightly elevated price is likely to be greater due to increased domestic investment, spillover benefits to secondary support industries and taxation revenue from domestic operations. The natural gas situation is further complicated by the status of PTT, which has a monopoly as Thailand’s sole natural gas buyer and distributor in the face of ongoing deregulation discussions.
Keeping The Lights On
Despite sporadic deregulation efforts by the government, and attempts to move away from an inefficient and centralised power market structure, state-owned power companies continue to play a major role in the generation, transmission and distribution segments. Under government regulations, the Electricity Generation Authority of Thailand (EGAT) retains the sole right to buy power from other private producers, including neighbouring countries, and is also the only firm permitted to supply electricity to distributors and retailers. As a result of this framework, there is no competition in the wholesale electricity market in Thailand. For the distribution and retail sectors, the markets are also allocated solely to the Provincial Electricity Authority of Thailand, which provides distribution, sales and electric energy services to rural regions across the majority of the country, while the Metropolitan Electricity Authority of Thailand provides power to the urban areas of Bangkok, as well as the Nonthaburi and Samut Prakran provinces.
Despite the emergence of privately owned and operated independent power producers (IPPs), small power producers (SPPs) and very small power producers, EGAT retains a strong position in the power generation segment as well, with the vertically integrated company controlling 47% of installed power capacity nationwide at the end of 2014. The next-largest contributors were IPPs, which operated a cumulative total of 38% of capacity, with SPPs chipping in another 10%, leaving imported power to account for the remainder. All in all, the power generation sector boasted a total installed capacity of 34.67 GW nationwide at the end of 2014, down slightly from 33.68 GW the previous year. In addition to responsibility for electricity generation, acquisition and distribution, EGAT is also responsible for the country’s transmission system, along with various national and regional control centres.
While the reliance on fossil fuels has increased over the decades as Thailand has prioritised abundant and relatively inexpensive fuel to provide sufficient power for the country’s growing economy and industrial base, this pendulum is set to swing back towards a more diverse energy basket in the coming decades. The exploitation of domestic natural gas reservoirs in the early part of the millennium has led to an increased reliance on natural gas as feedstock for natural gas-fired power plants, and power consumers derived 66% of their electricity from natural gas plants in 2014. Coal and lignite producers were the next-most prolific, producing 21% of the country’s annual consumption of 180,945 GWh. Other minor contributors included foreign imports of electricity at 7% of the total, followed by hydro power plants at 3%, oil-fired plants providing 1% and other power plants supplying the remaining 2%. Standard power contracts awarded by EGAT, which employ tariffs derived from a pricing formula based on fuel benchmark costs, traditionally run for a 25-year lifespan for conventional power plants, after which the units are generally scrapped in favour of newer, more technologically advanced plants rather than extending contracts for older, less-efficient units with higher variable costs. By contrast, the contracts for hydro power plants, which have the benefit of no fuel costs and no harmful emissions, often run on extensions long after their original agreements come to fruition.
After languishing as little more than an afterthought in the sector, energy efficiency and alternative energy should take on a much more prominent role in Thailand’s energy basket, with the government exhibiting a pronounced shift towards these more environmentally friendly options in recent years. These new strategic priorities have been signalled by a number of recent policy papers and the Power Development Plan 2015 (see analysis). As a result, opportunities are opening up for alternative energy producers in the country, specifically, for non-hydropower renewable energy producers.
Oil and gas production in Thailand has largely plateaued as the majority of active fields have reached maturation, which will result in a continuation of a slow but steady decrease in domestic crude output and flat-to-minimal growth in the natural gas segment. A lack of investment in new exploration as a result of ongoing uncertainty regarding amendments to the PA, along with the protracted delay of the 21st bidding round, will likely result in lower reserve replacement in the short term and a greater reliance on imported fuel. The commercialisation of smaller and marginal reserves as well as the optimisation of maturing wells could stave off any dramatic declines in production over the next decade, but hopes of discovering new large, game-changing reserves still hinge largely on finding a political resolution regarding the disputed Cambodia-Thailand boundary and the subsequent development of a joint development zone.
In the electricity segment, the concerted strategic shift away from imported fossil fuels towards energy diversification and independence should lead to ample growth in non-hydropower renewable energy and clean coal-fired generation, along with a more limited ongoing expansion in gas-fired power plants. Overall, the energy sector’s long-term growth outlook remains comparatively subdued as the country continues to experience challenges in procuring gas supplies and is noticeably moving towards an increasing reliance on electricity imports.
The energy efficiency measures included in the most recent policy blueprints, and the resulting projected high power reserve margins, will also likely lead to a dampening effect on demand for new generation capacity. Projections aside, these relatively high predicted reserve margins are unlikely to be fully realised due to a number of mitigating factors, including a failure to achieve generation targets. Renewable power will become increasingly important but short-term grid connection challenges remain, and conservation and efficiency goals could also prove difficult and costly to fully implement.
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