For decades, the ongoing development of Thailand’s major oil and gas fields provided the country with a steadily increasing flow of energy. Strong demand, favourable geology and an attractive concession contracting system combined to create an environment that attracted considerable interest from major international oil companies, which in turn poured hundreds of millions of dollars into exploration and development projects to keep the oil flowing.
As large existing fields mature and production wanes, however, the country’s energy landscape looks decidedly different. While this growth and decline cycle is a natural development for hydrocarbons fields the world over, the effects on Thailand’s energy sector are particularly strong as losses are occurring in every major oil and gas field simultaneously. Even more concerning is the fact that there are few exploration efforts under way, meaning there are no new discoveries of reserves with which to offset declines.
The lack of new exploration and development is attributable to a number of factors, including ongoing international territorial disputes, soft commodity prices, a lack of easily accessible “elephant” reservoirs, ongoing domestic political wrangling regarding oil and gas regulation and, perhaps most importantly, years of delays in launching the next round of oil and gas concessions. While oil firms are capable and well-versed in navigating technical and economic factors in the market, uncertainty related to the regulatory system governing the sector and the dearth of new concession opportunities are taking a toll on upstream development.
Exploration investment in the country has tailed off significantly in recent years. As of December 2016, there was just one lone exploratory well under way in the country, being drilled by state-owned PTT Exploration and Production (PTTEP) in the onshore S1 block. This was a sharp decline from the previous year when a total of 49 exploratory wells – 20 onshore and 29 offshore – were drilled, averaging just more than four per month.
In terms of financial commitments, concessionaires altogether invested BT208.82bn ($5.9bn) in their onshore and offshore operations. Of this total, exploration expenses accounted for BT8.86bn ($249.6m), or just 4% of overall expenditure in 2015. This is considerably less than the amount spent on other areas of the value chain, with field development expenses reaching BT142.1bn ($4bn), or 68%; production and sales at BT53.81bn ($1.5bn), or 26%; and administration expenses, BT4.05bn ($114m), or 2%.
The investment figure for exploration activity in 2015 is significantly less than in previous years, when companies spent BT15.89bn ($447.6m) on exploratory services as late as 2013, and averaged BT13.62bn ($383.7m) annually in the 2011-14 period.
This decline in exploration investment may be having a relatively small impact on output presently, but the longer-term ramifications are likely to be substantial. This trend is already becoming apparent in domestic energy reserve estimations, which have slipped over the past five years. In 2012 the country’s proven, probable and possible (known collectively as 3P) reserves were calculated to contain 930m barrels of crude oil, 600m barrels of condensate and 18.6trn cu feet of natural gas. When new exploration was curtailed in the ensuing years these reserve projections likewise fell off, decreasing in each successive year until 3P reserves totalled 531m barrels of crude, 357m barrels of condensate and 15.9trn cu feet of gas by the end of 2015.
Waiting In The Wings
This slowing of exploratory activity is set for an even more precipitous decline in the coming years, however, due to the expiration of current exploration licences. As laid out in existing oil and gas law, exploratory permits are valid for a period of three years, with two- and three-year extensions possible for operators working these concessions. With the last blocks issued during the 20th round of contracts in 2008, the terminus of this nine-year exploration window comes to a close in 2017, meaning the only permitted exploratory activity will be by existing operations probing the periphery of their current reservoirs.
This trend stands in marked contrast to the steady stream of successful exploration and development projects carried out in the previous decades. After a series of 20 successful oil and gas concession bidding rounds spanning more than four decades since the original oil and gas law was enacted in 1971, implementation of the 21st bidding round has dragged on for nearly a decade as the government wrestles with developing an entirely new system for hydrocarbons exploration and production.
This status quo was shaken up starting in 2012 after anti-drilling sentiment led the Department of Mineral Fuels to delay the concession, and then again in 2014 when segments within the government proposed a new paradigm in which to develop domestic energy reserves prior to the planned launching of the 21st concession round. At a vote carried out in January 2014, the National Reform Council disagreed with a proposal to move forward with the 21st licensing round by a vote of 130 to 79. The primary argument made by those opposed to the new licensing round was desire to move to a production-sharing system.
The government of Thailand’s effective take of oil and gas profits under the existing system comes in at 67% – well above global averages of 58%, but just less than the 74% averaged by South-east Asian nations, according to data from the consultancy Wood Mackenzie. But because Thailand yields consistently smaller discoveries compared to its neighbours – its average discovery size is the smallest in the region at only 7m barrels of oil equivalent (boe), compared to ASEAN average discovery size of 58m boe from 2004-13 – the government may not be well positioned to demand a higher effective take. The net result of this impasse has had such a cooling effect on the sector that new exploration has virtually ground to a halt in the country as oil and gas companies bide their time until new concessions are issued.
“We feel good about using Thailand as a centre for our Asia operations and we would like to do more in the country, but the next round of concessions continues to be delayed,” John Bell, Asia director for exploration and production company Ophir Energy, told OBG.
In the current situation, it remains unlikely that the 21st bidding round will receive the go-ahead until the various government factions come to a consensus on amendments to the oil and gas law, which would either implement a new system of production-sharing contracts (PSC) or keep the existing concession arrangement, or perhaps some combination of the two. The new proposal would do away with traditional concession contacts between operators and the government and replace them with PSCs like those utilised by other regional neighbours, such as Malaysia and Indonesia.
Under the PSC system, the government is allocated a certain percentage of the offtake from each contract with operators in charge of the exploration and development of their respective contract area. Now saddled with nearly all of the financial risks associated with the development of these areas, operators are in return granted other financial incentives designed to more equally distribute risk via cost-recovery components included in the PSCs. Although the wholesale switch to the PSC system is not inherently detrimental or unfair to private oil companies, a myriad of unanswered questions related to the implementation of any new policy has muddied the regulatory waters considerably.
This uncertainty also comes at a crucial point in time for the country’s largest legacy oil and gas fields, which Thailand relies upon to provide for the bulk of its domestic energy supply. Many of the existing concession contracts held by international oil companies operating the productive fields in the Gulf of Thailand are set to expire in 2022 and 2023.
With the future of these concessions unclear, these companies remain averse to further investments without a guarantee that any capital expenditures will be recovered. The immediate result of this dilemma will accelerate the decline of these maturing blocks in the absence of new investment in enhanced oil recovery technology designed to stem or even reverse production declines. An additional dilemma also arises from the lack of continuity in the form of the decommissioning process required to safely shut down production and remove the existing infrastructure after a hydrocarbons field is closed out. Without any deal in place to extend operations of these blocks, existing operators have little incentive to embark on the costly decommissioning procedures, leaving it as the responsibility of the government or new future concession holder to incur these costs after a marginal production run instead of the more common scenario in which these costs are offset from decades of operational profits.
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