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Edited Transcript of PTTEP.BK earnings conference call or presentation 1-Aug-19 10:59am GMT

Q2 2019 PTT Exploration and Production PCL Earnings Presentation

Bangkok Aug 23, 2019 (Thomson StreetEvents) -- Edited Transcript of PTT Exploration and Production PCL earnings conference call or presentation Thursday, August 1, 2019 at 10:59:00am GMT

TEXT version of Transcript

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Corporate Participants

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* Kanok Intharawijitr

PTT Exploration and Production Public Company Limited - EVP of Geosciences & Exploration Group

* Montri Rawanchaikul

PTT Exploration and Production Public Company Limited - Executive VP of Strategy & Business Development Group and Acting SVP of New Business Unit

* Phongsthorn Thavisin

PTT Exploration and Production Public Company Limited - CEO, President & Director

* Sumrid Sumneing

PTT Exploration and Production Public Company Limited - EVP of Finance & Accounting Group

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Presentation

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Operator [1]

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Welcome to PTTEP's analyst meeting in the second quarter of 2019, featuring the announcement of the company's operating performance in the second quarter of 2019. Before we begin, please allow me to invite our Chief Executive Officer, Khun Phongsthorn Thavisin, to share PTTEP's strategic directions; followed by Khun Montri Rawanchaikul, Executive Vice President, Strategy and Business Development Group, who will be providing an industry update and key highlights of the recent period; Khun Kanok Intharawijitr, Executive Vice President, Geosciences, Subsurface and Exploration Group, who will be sharing PTTEP's success in executing the exploration well of SK410B project; and Khun Sumrid Sumneing, Executive Vice President, Finance and Accounting Group, to summarize PTTEP's quarterly financial performance.

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Montri Rawanchaikul, PTT Exploration and Production Public Company Limited - Executive VP of Strategy & Business Development Group and Acting SVP of New Business Unit [2]

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The range of oil price volatility has been narrower than the former threshold of USD 60 to USD 70 per barrel. Now it has been clear that the key mechanism that drives the oil price trend is the demand rather than supply, taking into account such factors as Iran's response to the sanction, the OPEC's production cut scheme, the overall global economic condition and the U.S. pipeline debottlenecking. Another determining factor is the U.K.'s new Prime Minister and the outcome of Brexit on October 31, 2019, which can potentially lead to the recession if the U.K. is to leave the EU. With this being said, demand is the key driver of the oil price. If demand growth is slow, the oil price is hardly going to increase. If OPEC does not extend the production cut period, the oversupply condition is going to pursue.

Now that OPEC has incorporated Russia, who has been in close contact with Saudi Arabia, the production cut scheme has been extended for another 9 months. Also countries outside the OPEC are willing to cooperate on this cause. In the meantime, we can expect another wave of the U.S. shale oil production during 2020 to 2025. After that, it depends on the amount of available reserve and whether or not the technology can accommodate the production procedures as they require an abundant amount of water in the crude extraction process and the issue concerning water disposal still remains in question.

In the short-term period, the oil price shall be in the range of USD 60 to USD 70 per barrel, as shown here. The third quarter consensus has reported the Brent price reaching USD 70 per barrel. Then we have to wait and see how this scenario is going to turn out in the fourth quarter as the winter season arrives.

For those who have been following the LNG situation, this is quite an excitement as the LNG prices changes rather rapidly given that LNG spot price in Asia has hit record low of below USD 4 per MMBtu. The LNG market has been quite volatile recently. During 2024 to 2025, there are 2 major possibilities, one of which believes that the oversupply will materialize, and the other one advocates that demand will increase to the point where LNG price will increase. In this regard, FGE has taken the point concerning new projects into consideration when making a forecast: the participation of Russia, Arctic LNG 2 and Qatar expansion. In response to this, this situation is unlikely to impact PTTEP as we have secured long-term sales, and we will need to think very carefully prior to investing in any LNG projects as there are many facets of uncertainty.

The graph on the right stems from the question arising from the previous analyst meeting regarding the high sulfur fuel oil that is associated with gas price. Over the next few years, lower portion of our gas sales will be linked to high sulfur fuel oil. The portion highlighted in pink is the gas from Murphy, which is not linked to high sulfur fuel oil. Likewise, the products from Partex, whereby we shall be able to close a deal in the fourth quarter is also not linked to high-sulfur fuel oil. The volume with no linkage to high-sulfur fuel oil is likely to increase as we are going to have Sabah H, whose production will commence in 2020. On the other hand, the portion highlighted in red represents our gas portion in Thailand and Myanmar that is linked to high-sulfur fuel oil. With the incorporation of the new PSC, the linkage to high-sulfur fuel oil is going to become less likely.

Going forward in the next 5 years, PTTEP's operating performance will be both linked to oil price and high-sulfur fuel oil. However, the trend suggested that the high-sulfur fuel oil spread will become narrower, so analysts and investors are not so worried as the demand for high-sulfur fuel oil over the next few years is still going to be prevalent.

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Phongsthorn Thavisin, PTT Exploration and Production Public Company Limited - CEO, President & Director [3]

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With regard to our strategies, the new mission statement, Energy Partner of Choice, has been made considerably tangible after our 20-year experience in this business. Despite our collaboration with Total, Chevron, Shell and others, we cannot really regard them as our strategic partners, from the point that we have refocused our mission statement from being the leader in this business to being the partner who is willing to work with every party to deliver value. We have seen a lot of things materialize as a result of such change, enabling us to truly form alliances with strategic partners. Speaking of which, one of the key partners is PETRONAS with whom we have never realized such a close relationship despite 20 years of working together. As a proof of such claim, the number of our projects in Malaysia has increased from 1 to 11 over the recent years. Thus, we can say that we have successfully formed a strategic partnership with PETRONAS.

Another company is Mubadala, a subsidiary of Abu Dhabi National Oil Company, who has been working with us in the Erawan project. Meanwhile, we also have 2 exploration blocks in collaboration with ENI. If you have been following the news over the past 3 to 4 years, ENI has been highly successful with its exploration endeavors. Another key success area is that the time to market of ENI's products is very short and effective, which is the objective that we share. After having been studying each other for some time, we believe that ENI has been more confident in working with us. For Total, even though we will not be working together upon their concession expiry of Bongkot project, we're still partners in the MD-7 project in Myanmar, which is a deepwater field that we have planned for the exploration drilling in the fourth quarter. Furthermore, we have a chance to mutually develop some projects in the Middle East together with Total and Oxy on the Partex project in Oman and other countries.

This slide is a summary of our strategic direction from this point forward. As mentioned before, we will be executing the Coming-Home Strategy, focusing on Thailand, Myanmar and Malaysia and expanding further to the UAE and Oman. Previously, countries in the Middle East were quite reluctant to open for business opportunities from other countries, but now they share a common direction as we do, as seen from higher acceptance of foreign partners. With the strategies featuring expand and execute, recently, you may have seen PTTEP's tangible expansion and movements. Going forward, we will need to ensure that we are able to execute businesses that we acquired in order to achieve the desired outcomes.

Even though the expansion by acquisition can potentially earn us the reserves and production capacity, they somehow have to be inevitably paid for, and we need to make sure that they generate a certain amount of return at some point. After having embarked on the acquisition journey for a while, we need to actively ensure that execution is carried out effectively and to seriously strengthen our exploration activities. From this point forward, the expansion activities may be lower, and we will shift our focus to exploration and execution activities to ensure success.

Dating back to December 2018, we have secured G1, G2 and the winning of Bongkot and Erawan. Then in January 2019, we have signed operatorship of 2 offshore exploration blocks in the UAE together with ENI, followed by Sinphuhorm project in February and the acquisition of Murphy Oil and the final investment decision of Algeria Hassi Bir Rekaiz in March. In June, there was an acquisition of Partex, the final investment decision of Mozambique, which had been on process for quite some time, and the gas discovery in SK410B. This coincides with what has been said that as the acquisition activities have been going on for some time, we need to shift our focus to exploration activities and the SK410B project has resonated with this notion.

At this point, there are 3 major pillars of transition: Erawan, Bongkot and the complete acquisition of Murphy Oil potentially increasing our production capacity by around 50,000 barrels of oil equivalent per day. And if the Sabah H project is executed as planned, we can expect another 20,000 barrels of oil equivalent added to our capacity. In this regard, this entity will no longer be regarded as Murphy, but rather PTTEP Malaysia Assets, whereby we are going to speed up our exploration processes, which will be elaborated further by Khun Kanok.

In terms of new businesses, we are quite confident that ARV has a lot of growth potential as our offerings are more unique than the general AI technology. This is because ARV has been specifically developed to support the oil and gas business. The main premise of this venture is located in Wangchan, adjacent to Vidyasirimedhi Institute of Science and Technology or VISTEC, where our test grounds are located, with a large pool, simulation platforms and a vast runway for drones. We believe we can be the catalyst for growth in the EECi, and we can also capture the knowledge base from VISTEC. Furthermore, the National Science and Technology Development Agency or NSTDA will also be working alongside VISTEC, so we are certain that there will be some extent of complementing benefits arising from this cause.

For M&A, if opportunities present themselves and if the business has a positive outlook, we will then pursue M&A opportunities given our sufficient capacity. Upon the exploration success of the SK410B project, it has earned us confidence to identify reserves for future production based on our own capacity without having to invest a large sum of money to acquire. So this is the strategic direction and the way forward for PTTEP. And with our unified dedication, I believe we can successfully deliver success.

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Kanok Intharawijitr, PTT Exploration and Production Public Company Limited - EVP of Geosciences & Exploration Group [4]

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This history of SK410B project can be dated back to about 30 years ago in 1987. At the time, JX Nippon acquired the concession to operate the project, and during 1987 to 1997, several gas fields were discovered here and there in the area. Back in 1994, JX Nippon drilled 2 wells in the area. The image shown is the cross-section illustration of an underground limestone mountain about 3 kilometers below the surface. At the first drilling attempt, it was such high pressure that called for a vigorous control. At the end of the very same year, the second drilling attempt was exercised next to the first one, but none of the gas was detected. With that, a conclusion was drawn that this field did not have anything much to offer, only about 60 Bcf worth of gas. Hence, the concession was relinquished. PTTEP, together with KUFPEC, was willing to pursue this opportunity given our experience in Rattana well in Northeastern part of Thailand. The exploration activities were executed quickly as driven by the CEO. The production sharing contract was acquired since 2016, but the actual drilling did not take place until March 2019 after availability of rig. The exploration period was 3 years, and during that time, we conducted the 3D seismic evaluation and interpretation, though the data derived must be retained there.

When we commenced the drilling in March 2019, we were affronted that we could hardly reap any fruits from this well as the previous 2 attempts were unsuccessful. Thus, we interpreted that the lack of success was because the limestone was so dense. So we decided to give it another try, and the outcome was positive and surprising. At about the depth of 3,800 meters, the drilling column got stuck, which I sought an approval from the CEO to side track the drilling in order to test the flow of the petroleum. Because we assumed that the area was not large, the equipment prepared was rather small, enabling us to extract only 42 million cubic feet per day only. At the current point, none of the liquid was detected, only gas regarded as gas down to. However, we need to drill further and there is another field about 4,000 to 5,000 meters down below. For a comparison purpose, Zawtika field, at the beginning, the area of the field was approximately 400 to 500 square meters with 3 operating platforms and 1 central processing platform and the capacity of 200 million cubic feet per day, starting from 1.2 Tcf. Whereas the gas down to threshold of SK410B mentioned just now is 2.2 Tcf. For the peak down to at that point, the height is about equivalent to the twin towers in Kuala Lumpur.

In this regard, there are several small fields surrounding the area now owned by JX Nippon, and we are now in the process of negotiating with them to join and form a large hub. If we are to declare the reserves of 2 to 4 Tcf, we are potentially going to be the largest operator in this area. And supposing the consensus confirms the reserve of 2 Tcf, we are potentially going to be the seventh largest in the world for gas find in 2019. Nevertheless, we need to drill another well in order to determine the exact amount of reserves. With this, we expect to produce the first batch of gas during 2022 to 2024 as the Malaysian market is rather tight at the moment. Now with the acquisition of Murphy Oil. We have assumed another shallow water well, SK438. With these being said, PTTEP's growth outlook has become clearer with Northern Sarawak, Southern Sarawak, Peninsular Malaysia with block PM415 and PM407, which shares resemblance with Bongkot. They are the 3 major hubs that we are going to monitor over the next 10 years. Moreover, we anticipate to initiate further developments of the deepwater projects, Sabah H and Sabah K in 2020. In short, PTTEP has the highest number of exploration blocks in Malaysia, which presents quite a promising future given the potential of each block.

You can see from the clip that the gas pressure is very high, so it fumes out pretty vigorously. And at night, it blazes a bright blue color, signifying that it is high-quality gas.

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Sumrid Sumneing, PTT Exploration and Production Public Company Limited - EVP of Finance & Accounting Group [5]

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The half year sales volume has increased to 327,000 barrels of oil equivalent per day from 298,000 barrels of oil equivalent per day in the same period last year. This was mainly due to higher volume from Bongkot, as a result of the acquisition of additional 22.2% interest offset with the impact of higher shutdown days in the first half of this year. Meanwhile, the weighted average selling price has increased from USD 45.51 per barrel to USD 47.26 per barrel. All in all, leading to the net profit of USD 827 million in the first 6 months of 2019, increasing by 54% compared to the same period last year.

Turning to the cost side. The unit cost for the first half of this year was pretty unchanged from the previous year despite the higher exploration expense of around USD 23 million due to well write-off and higher general and administration expenses from the recognition of additional compensation from the new Labor Protection Act.

For cash flow, the amount of money disposed of was higher than what has been earned by about USD 500 million. However, the EBITDA margin has been maintained at 74%. The performance for the first 6 months of 2019 has a rather positive outlook. This was not yet including incremental upside from Murphy and Partex.

Our assets have slightly decreased from USD 19,484 million to USD 18,775 million. The liabilities also have decreased due to the absence of current liabilities; tax payment, coupled with debt repayment of USD 418 million with an additional bond issuance of USD 480 million.

The decrease in equity was due to the repayment of hybrid bond of around USD 500 million, and the dividend payment for the second half of 2018 performance during the first half of the year of approximately USD 409 million, offsetting with the net profit of about USD 827 million.

Looking back to the dividend payment history, the dividend paid in the first half of 2019 is considered the highest in the past 5 years at THB 2.25 but with the payout ratio of 36% and dividend yield of 4%. The record date has been scheduled on August 9, 2019, and the payment date is on August 23, 2019.

With regards to the debt profile, the weighted average cost of debt has dropped to 5.04%, and the average loan life is 8.62 years.

Compounding annual growth rate of sales volume for 5-year period until 2023 is expected to grow by 7% to 437,000 barrels of oil equivalent per day. This scenario has already taken to account Murphy, G1/61 Erawan field and G2/61 Bongkot field, whose production will start in 2022 to 2023. However, the Murphy will start the contribution to the sales volume in the second half of 2019 and the full contribution of around 60,000 to 70,000 barrels of oil equivalent per day can be expected in 2021 to 2022.

This shown investment plan has already been taken into account of the G1/61, G2/61 and Murphy while the Partex and SK410B have not yet been included. The total amount of capital expenditure for 5-year time frame is about USD 12.6 billion, which is not included the acquisition amounting of USD 2,086 million. So the total amount of capital expenditure is USD 14 billion. Meanwhile, the operational expenditure is USD 8,695 million. At this point, people may wonder if the fund is sufficient to cover the capital expenditure. In response to that, if cash flow from operations amount to USD 17 billion, and with the capital expenditure of USD 14 billion, plus some other financing expenses of about USD 6 billion, totaling USD 20 billion, meaning that additional USD 3 billion is required. However, with the beginning cash of USD 4 billion, we will be left with USD 1 billion, and we can operate with an additional funding of USD 1 billion, allowing us to follow through with this investment plan.

With the loan drawdown of USD 1 billion, the maximum and minimum debt-to-equity ratio has been maintained at 0.23x and 0.17x, respectively. In conclusion, with this debt-to-equity ratio, we still have debt headroom for additional funding of around USD 3 billion to USD 4 billion.

The average sales volume in the third quarter of 2019 has been projected to be 356,000 barrels of oil equivalent per day, increasing from the second quarter of 2019 due to the Murphy acquisition while the full year is forecasted around 345,000 barrels of oil equivalent per day. Meanwhile, the average gas price is likely to be about the same at USD 6.80 per MMBtu. On the other hand, the unit cost may appear to be higher in the second half of the year because the operational expenditure spending are typically lower in the first half, coupled with the fact that some exploration write-off expenses will be incurred later in the year, leading to slightly higher unit cost. Last but not least, the EBITDA margin still maintained between 70% to 75%.

We will now open the floor for questions.

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Questions and Answers

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Unidentified Analyst, [1]

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When do you expect to drill additional appraisal well in SK410B?

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Unidentified Company Representative, [2]

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We expect to drill in 2020 to affirm the petroleum potential of this field. However, based on the result of the first well, we expect it to be at least 2 Tcf.

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Unidentified Analyst, [3]

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What is the potential of gas market for SK410B to Bintulu?

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Unidentified Company Representative, [4]

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The capacity of LNG complex in Bintulu is sufficient for the current and upcoming gas contracts.

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Unidentified Analyst, [5]

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Could you compare discovery of SK410B and with that of M3?

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Unidentified Company Representative, [6]

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SK410B's discovery is quite significant with the size of multi Tcf and market readiness. For M3, the resources are in a smaller size, and we have plans to monetize it through Gas to Power project as Myanmar's market is in need of electricity.

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Unidentified Analyst, [7]

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What is PTTEP's view on profitability as the company projected on higher production and reserves?

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Unidentified Company Representative, [8]

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We expect our profitability to be in line with higher volume. For the acquisition of Murphy, we expect the cost profile to be roughly at the same level as PTTEP's current unit cost. For G1 and G2, despite the lower selling price, the unit cost should be lower as well from the low depreciation, depletion and amortization, no heavy upfront capital expenditure.

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Unidentified Analyst, [9]

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When is the new bidding round in Thailand?

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Unidentified Company Representative, [10]

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The time line depends on the government's decision. However, we are ready to participate if the bidding is announced.

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Unidentified Analyst, [11]

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Why does PTTEP record APICO's interest, 72.8%, as an investment in joint venture, one line and received dividend, instead of consolidating line by line?

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Unidentified Company Representative, [12]

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According to accounting standards, it is considered as an investment in joint venture because, in the details of the shareholder agreement, we do not share assets and liabilities in the acquired company.

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Unidentified Analyst, [13]

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What is your view on major E&P companies that withdraw investment from deepwater in North Sea, while PTTEP has been acquiring more E&P assets?

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Unidentified Company Representative, [14]

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Most E&P companies are adjusting their portfolio by selling some assets and investing in focused areas, which they have expertise, including PTTEP that we now focus in our Coming-Home Strategy.

[Statements in English on this transcript were spoken by an interpreter present on the live call]