Investment in Oil and Gas Sector Continues to Drop

Ministry of Energy and Mineral Resources (ESDM) noted that the realization of investment in the oil and gas sector in the first half of 2017 only amounted to US $ 34.8 billion. This achievement decreased compared to investment in the same period of the year 2016, which reached US $ 5.65 billion.

If we look back, the realization of oil and gas investment in 2009 is low. But start up in 2014 and then straight down. At that time oil prices below US $ 50 per barrel.

Deputy Minister of Energy and Mineral Resources Arcandra Tahar said, globally energy sector investment has decreased up to 12%. Specifically in the oil and gas sector, the global figure fell by 26%.

In addition to the effects of oil prices, Arcandra said, oil and gas companies operating in Indonesia are also doing the efficiency. Nevertheless, oil production in Indonesia is still around 802,000 barrels per day or barrels per day (bopd), from the 2017 target of 815,000 barrels per day. Arcandra said the decline was not due to the implementation of the gross split sharing pattern.

"The gross split regulation is at the beginning of this year, just look at the oil and gas auction last year, the demand is only one," he said.

In order to accelerate the realization of oil and gas projects, Arcandra ordered his staff to facilitate all sorts of permits. He asks if any documents are piling up immediately.

"If you can clean at our table, investors do not want their project delay, especially if the delay is up to a year," added Arcandra.

Director General of Oil and Gas of ESDM Ministry Ego Syahrial said the government had hoped that the Indonesian Deepwater Development project of Chevron, Masela and Train III Tangguh could lift oil and gas investment in semester 1-2017. But it is impossible to do

Well, in the Il-2017 semester, Syahrial believes the project Deepwater Development Chevron and Cricket Field can contribute investment this year. He calculated, Indonesia Deepwater Development consists of three parts.

The first has occupied aka onstream to 100,000 barrels per day. So just work on Gendalo and Gehem projects.

"It's our intention to help speed up the process.Okay can not get it now, but next year can Revision plan of development (POD), "Ego said.

Deputy Head of SKK Migas Sukandar added that in addition to the two projects, there is also a Tangguh Train III project that will contribute this year's investment.

"Now in the land preparation, the structure is being done in Batam," he said.

Sukandar expects Pertamina's investment in the Mahakam block to increase oil and gas sector investment in the second half. Meanwhile, downstream oil and gas investment from refinery and gas pipeline project. Ego estimates, oil and gas investment this year is not up to US $ 22 billion, but can only US $ 12 billion.

"It used to be a very optimistic target," he said.

IN INDONESIA

Investasi Sektor Migas Terus Melorot

Kementerian Energi dan Sumber Daya Mineral (ESDM) mencatat, realisasi investasi pada sektor minyak dan gas pada semester I-2017 hanya sebesar US$ 34,8 miliar. Pencapaian ini menurun dibandingkan investasi pada periode yang sama tahun 2016 lalu, yang mencapai US$ 5,65 miliar. 

Kalau kita menengok ke belakang, realisasi investasi migas pada tahun 2009 memang rendah. Tapi mulai naik pada tahun 2014 dan kemudian langsung turun. Saat itu harga minyak di bawah US$ 50 per barel.

Wakil Menteri ESDM Arcandra Tahar menyebutkan, secara global investasi sektor energi memang mengalami penurunan hingga 12%. Sementara khusus di sektor migas, secara global turun hingga 26%.

Selain efek harga minyak, Arcandra bilang, perusahaan migas yang beroperasi di lndonesia juga melakukan efisiensi. Kendati begitu, produksi minyak di Indonesia masih tetap di sekitar angka 802.000 barel per hari atau barel oil per day (bopd), dari target pada tahun 2017 yang sebesar 815.000 barel per hari. Arcandra mengatakan, penurunan itu bukan karena penerapan pola bagi hasil gross split. 

"Aturan gross split ada awal tahun ini. Coba lihat lelang migas tahun lalu, peminatnya hanya satu," tegas dia

Demi mempercepat realisasi proyek migas, Arcandra memerintahkan jajarannya agar bisa mempermudah segala macam perizinan. la meminta jika ada dokumen menumpuk segera dikerjakan.

"Kalau bisa clean di meja kita. Para investor itu tidak mau proyek mereka delay. Apalagi jika delay sampai setahun," imbuh Arcandra.

Direktur Jenderal Minyak dan Gas Bumi Kementerian ESDM Ego Syahrial mengungkapkan, tadinya pemerintah berharap pada proyek The Indonesian Deepwater Development Chevron, Masela, dan Train III Tangguh bisa mengangkat investasi migas di semester l-2017. Tapi hal itu mustahil dilakukan

Nah, di semester Il-2017, Syahrial yakin proyek Indonesia Deepwater Development Chevron dan Lapangan Jangkrik bisa menyumbang investasi tahun ini. Ia menghitung, Indonesia Deepwater Development terdiri dari tiga bagian.

Yang pertama sudah berpruduksi alias onstream hingga 100.000 barel per hari. Jadi hanya kurang menggarap proyek Gendalo dan Gehem. 

"Itu maksud kami membantu mempercepat proses. Oke tidak bisa mendapatkan sekarang, tapi tahun depan bisa revisi plan of development (POD)," kata Ego. 

Wakil Kepala SKK Migas Sukandar menambahkan, selain kedua proyek itu, ada juga proyek Train III Tangguh yang akan menyumbang investasi tahun ini. 

"Sekarang sedang dalam land preparation, struktur sedang dikerjakan di Batam," katanya.

Sukandar berharap, investasi Pertamina di Blok Mahakam bisa menambah investasi sektor minyak dan gas pada semester II, Sementara itu, investasi sektor hilir minyak dan gas dari proyek kilang dan pipa gas. Ego menaksir, investasi minyak dan gas tahun ini tidak sampai US$ 22 miliar, tapi hanya bisa US$ 12 miliar. 

"Dulu target sangat optimitis," kata dia.  

Kontan, Page-18, Wednesday, August 9, 2017

Saudi Arabia Raises Rising Oil Prices

Although price movements began to slow, oil prices still tend to strengthen. Analysts even forecast the price could return to penetrate the level of US $ 50 per barrel. Tuesday (8/8), at 18.30 Western Indonesia Time, Western Texas Intermediate (WTI) oil price contract for September 2017 delivery on the New York Mercantile Exchange rose 028% to US $ 49.53 per barrel.

Within a week, oil prices have shot 0.75%. The cause of this increase is Saudi Arabia's decision to cut oil sales to Asia for September. Reportedly, Saudi Arabian Oil Co. Reducing oil production restrictions by OPEC is considered a failure.

An additional injection for oil price increases after US crude oil reserves (US) are also expected to fall. Asia Tradepoint Futures analyst Deddy Yusuf Siregar said the US oil reserves for the week ending August 4, 2017 are predicted to fall by about 2.6 million barrels.

"This condition gives a signal to market players that maybe the US began to reduce production," he said on Tuesday (8/8).

    Therefore, Deddy is optimistic that by the end of the third quarter WTI oil price can move again in the range of US $ 48-US $ 50 per barrel. Pressed negative catalyst but negative catalyst also still lurking oil prices. One of them is the re-production of the largest oil refinery in Libya, the Sharara block. This makes Libyan oil production above 1 million barrels per day.

Despite OPEC members, Libya and Nigeria have been given no leeway not to participate in a production-limited deal of 1.8 million barrels per day until March 2018. Pressure for oil prices increased after demand for oil imports in China in July fell 6.9% From the previous month. This figure is the biggest slowdown since January 2017. Moreover, China is the world's largest crude consumer. This can depress oil prices.

"China's import data also fell below market expectations and made the market pessimistic," said Faisyal, Research & Analyst Monex Investindo Futures.

Therefore, Faisyal predicts, WTI oil price today will move in the range of US $ 48.50-US $ -49, 65 per barrel. Meanwhile, according to Deddy's analysis, WTI oil prices will move in the range of US $ 48.50-US $ 50.39 per barrel in the next week.

Technically, the current oil price is rolling above the line of MA 50 and MA 100, but it is still stuck at the 200 MA. This indicates in the long term the strengthening has not been confirmed. The MACD indicator is in the positive area. Then the RSI is at 60 and stochastic at the 58 level. Most indicators indicate a bullish opportunity.

IN INDONESIA

Arab Saudi Menyulut Naik Harga Minyak

Meski pergerakan harganya mulai melambat, harga minyak masih cenderung menguat. Para analis bahkan memperkirakan harganya bisa kembali menembus level US$ 50 per barel. Selasa (8/8), per pukul 18.30 WIB, harga minyak west Texas Intermediate (WTI) kontrak pengiriman September 2017 di New York Mercantile Exchange naik 028% ke level US$ 49,53 per barel. 

Dalam sepekan, harga minyak sudah melesat 0,75%. Penyebab kenaikan ini adalah keputusan Arab Saudi memangkas penjualan minyak ke Asia untuk September. Kabarnya, Saudi Arabian Oil Co. melakukan pengurangan pembatasan produksi minyak oleh OPEC dinilai gagal. 

Suntikan tambahan bagi harga minyak bertambah setelah cadangan produksi minyak mentah Amerika Serikat (AS) juga diperkirakan turun. Analis Asia Tradepoint Futures Deddy Yusuf Siregar mengatakan, cadangan minyak AS untuk pekan yang berakhir 4 Agustus 2017 diprediksi turun sekitar 2,6 juta barel. 

“Kondisi ini memberikan sinyal pada pelaku pasar bahwa mungkin AS mulai mengurangi produksinya,” ungkap dia, Selasa (8/8). 

     Karena itu, Deddy optimistis hingga akhir kuartal tiga nanti harga minyak WTI bisa kembali bergerak di rentang US$ 48-US$ 50 per barel. Terdesak katalis negatif namun katalis negatif juga masih mengintai harga minyak. Salah satunya adalah kembali berproduksinya kilang minyak terbesar di Libia, yakni blok Sharara. Hal ini membuat produksi minyak Libia berada di atas 1 juta barel per hari. 

Walau termasuk anggota OPEC, namun Libia dan Nigeria memang mendapat kelonggaran untuk tidak ikut serta dalam kesepakatan pembatasan produksi sebesar 1,8 juta barel per hari hingga Maret 2018. Tekanan bagi harga minyak bertambah setelah permintaan impor minyak di China di Juli turun 6,9% daripda bulan sebelumnya. Angka ini merupakan perlambatan terbesar sejak Januari 2017. Terlebih lagi, China merupakan konsumen minyak mentah terbesar di dunia. Hal ini dapat menekan harga minyak. 

"Data impor China juga turun di bawah ekspektasi pasar dan membuat pasar pesimis," jelas Faisyal, Research & Analyst Monex Investindo Futures.

Karena itu, Faisyal memprediksi, harga minyak WTI hari ini akan bergerak di kisaran US$ 48,50-US$-49;65 per barel. Sementara menurut analisa Deddy, harga minyak WTI akan bergerak di rentang US$ 48,50-US$ 50,39 per barel dalam sepekan ke depan.

Secara teknikal, harga minyak saat ini bergulir di atas garis MA 50 dan MA 100, tetapi masih tertahan di MA 200. Ini mengindikasikan dalam jangka panjang penguatan belum terkonfirmasi. Indikator MACD berada di area positif. Kemudian RSI berada level 60 dan stochastic di level 58. Sebagian besar indikator mengindikasikan peluang penguatan harga.

Kontan, Page-11, Wednesday, August 9, 2017

Gas Price Blue Tiung is Down

The long journey of gas field development Jambaran Tiung Biru (JTB) has met the agreement. Deputy Minister of Energy and Mineral Resources (ESDM) Arcandra Tahar said, one result is related to the selling price to PLN Gresik Region USD 7.6 per mmbtu flat during the contract.

Related to the price of gas, Arcandra explained, initially gas selling price in JTB field to PT PLN about USD 9 per mmbtu. However, the selling price is too expensive for PLN. The government also asked for lowered investment. JTB is operated by Pertamina's subsidiary Pertamina EP Cepu, with its partner PT ExxonMobil Indonesia.

Pertamina relented and lowered its operational expenditure (capital expenditure / capex) around USD 250 million. As a result, JTB gas sales price to PLN to about USD 7.6 per mmbtu flat for 30 years.

PT. ExxonMobil Indonesia decided to release shares in JTB gas field. Therefore, the gas sale price is decided not to enter with the economy Exxon. Arcandra asserted, Exxon's pullback is entirely due to business-to-business decision with Pertamina.

Previously, ExxonMobil and Pertamina EP Cepu (PEPC) gained the right to manage 41.4 percent at the Tiung Biru Jambaran Field. The rest is owned by regional owned enterprises (BUMD) 9.2 percent and Pertamina EP 8 percent.

IN INDONESIA

Harga Gas Tiung Biru Turun

Perjalanan panjang pengembangan lapangan gas Jambaran Tiung Biru (JTB) telah menemui kesepakatan. Wakil Menteri Energi dan Sumber Daya Mineral (ESDM) Arcandra Tahar menuturkan, salah satu hasilnya adalah terkait harga jual ke PLN Wilayah Gresik USD 7,6 per mmbtu flat selama kontrak.

Terkait dengan harga gas tersebut, Arcandra menjelaskan, awalnya harga jual gas di lapangan JTB kepada PT PLN sekitar USD 9 per mmbtu. Namun, harga jual tersebut dirasakan terlalu mahal bagi PLN. Pemerintah pun meminta investasinya diturunkan. JTB dioperasikan anak usaha Pertamina, yakni Pertamina EP Cepu, dengan partnernya, PT ExxonMobil Indonesia. 

Pertamina mengalah dan menurunkan belanja operasional (capital expenditure/capex) sekitar USD 250 juta. Hasilnya, harga jual gas JTB kepada PLN menjadi sekitar USD 7,6 per mmbtu flat selama 30 tahun.

PT. ExxonMobil Indonesia pun memutuskan untuk melepas saham di lapangan gas JTB. Sebab, harga jual gas yang diputuskan tidak masuk dengan keekonomian Exxon. Arcandra menegaskan, mundurnya Exxon sepenuhnya karena keputusan business-to business dengan Pertamina.

Sebelumnya, ExxonMobil dan Pertamina EP Cepu (PEPC) mendapatkan hak kelola 41,4 persen di Lapangan Jambaran Tiung Biru. Sisanya dimiliki badan usaha milik daerah (BUMD) 9,2 persen dan Pertamina EP 8 persen.

Jawa Pos, Page-5, Wednesday, August 9, 2017

Pertamina Garap Tunu

The new well block mahakam

PT Pertamina Hulu Mahakam (PHM) has obtained positive results and well drilling activities at Tunu Field, Mahakam Working Area, since 16 July. The well is named TN-N74 and TN-N75 which has a depth of about 1,078 meters, with a Shallow Arcthitecture Tubingless (SAT) wellow composting system type.

Upstream Director of PT Pertamina Syamsu Alam said the drilling in this transitional period aims to keep the production wells well ahead of the management shift. Currently, the annual gas production volume in the Mahakam Working Area is 1.635 million standard cubic feet per day, while oil production reaches 63,000 barrels per day.

The drilling is financed by the company, and is executed by Total E & P Indonesie as an existing operator. Pertamina has allocated US $ 160 million for drilling investment for this year.

"We and Total E & P Indonesie agree there is a transition period, so this drilling aims to reduce the rate of production so as not to decrease drastically and constantly when changing operators later," he said

In accordance with the production sharing contract signed by PT Pertamina Hulu Mahakam (PHM) and SKK Migas at the end of December 2015, PT Pertamina Hulu Mahakam (PHM) reserves the right to fund the necessary oil and gas operations activities since the contract is signed until the transition of effective management proceeds.

The company plans to drill 14 wells during 2017. With these activities, it is expected that oil and gas wells can be produced immediately when Pertamina takes over the management which came into effect on January 1, 2018.

Syamsu said the drilling results at Lapangan Tunu showed satisfactory results. Even the activity is beyond the initial expectations, because the geological condition of the well is quite risky. In addition, the company also received no obstacles or obstacles reports during drilling.

"When talking drilling in the Mahakam, geologically very challenging. The layers are numerous and thin, so it is definitely risky. But so far the results in the three wells are actually very good, because it found several layers previously hidden, "he continued

He revealed the possibility of a reduced cost incurred from initial estimates when drilling was fully realized.

"There are several innovations that are applied during drilling, so the activities are more efficient and the cost is cheaper, so the efficiency is not because it is deliberately sparing, but as a result of that successful breakthrough".

Furthermore, drilling will be done in Handil field. In addition, other aspects prepared by the company are human resources. Syamsu expressed the aspect of human resources is an important factor in the transition of management.

"We hope as many of our Total E & P Indonesie employees continue their work to maintain the operation. The report indicates that 90% of the bids have been returned and declared willingness to join Pertamina.

IN INDONESIA

Pertamina Garap Tunu

PT Pertamina Hulu Mahakam (PHM) telah memperoleh hasil yang positif dan kegiatan pengeboran sumur di Lapangan Tunu, Wilayah Kerja Mahakam, sejak 16 Juli. Sumur tersebut bernama TN-N74 dan TN-N75 yang memiliki kedalaman sekitar 1.078 meter, dengan tipe arsitektur komplesi sumur shallow arcthitecture tubingless (SAT). 

Direktur Hulu PT Pertamina Syamsu Alam mengatakan pengeboran dalam masa transisi ini bertujuan untuk menjaga tingkat produksi sumur-sumur menjelang peralihan pengelolaan. Saat ini, volume produksi tahunan gas bumi di wilayah Kerja Mahakam mencapai 1.635 juta kaki kubik per hari (million standard cubic feet per day), sedangkan produksi minyak mencapai 63.000 barel per hari.

Kegiatan pengeboran ini dibiayai oleh perseroan, dan dieksekusi oleh Total E&P Indonesie selaku operator existing. Pertamina mengalokasikan US$160 juta untuk investasi pengeboran selama setahun ini.

"Kami dan Total E&P Indonesie sepakat ada masa transisi, jadi pengeboran ini bertujuan untuk menekan laju produksi agar tidak menurun drastis dan terus-menerus saat berganti operator nanti," tuturnya

Sesuai dengan kontrak bagi hasil yang diteken oleh PHM dan SKK Migas pada akhir Desember 2015, PHM berhak membiayai kegiatan operasi migas yang diperlukan sejak kontrak diteken hingga peralihan pengelolaan efektif berjalan.

Perseroan berencana mengebor 14 sumur selama 2017 . Dengan kegiatan tersebut, diharapkan sumur-sumur migas dapat segera diproduksi saat Pertamina mengambil alih pengelolaan yang mulai berlaku pada 1 Januari 2018.

Syamsu mengatakan hasil pengeboran di Lapangan Tunu menunjukkan hasil yang memuaskan. Bahkan aktivitas itu terbilang melampaui ekspektasi awal, sebab kondisi geologis sumur yang cukup berisiko. Selain itu, perseroan juga tidak menerima laporan hambatan ataupun kendala selama pengeboran berlangsung.

“Kalau bicara pengeboran di Mahakam, secara geologis sangat menantang. Lapisannya banyak dan tipis, jadi sudah pasti beresiko. Tapi sejauh ini hasil di tiga sumur itu justru sangat baik, karena ditemukan beberapa lapisan yang sebelumnya tersembunyi," sambungnya

Dia mengungkapkan adanya kemungkinan berkurangnya biaya yang dikeluarkan dari perkiraan awal saat pengeboran terealisasi sepenuhnya. 

"Ada beberapa inovasi yang diterapkan saat pengeboran, sehingga kegiatan lebih efisien dan biayanya lebih murah. Jadi efisiensinya bukan karena sengaja di hemat, tapi sebagai hasil dari terobosan yang berhasil itu".

Selanjutnya, pengeboran akan dilakukan di lapangan Handil. Selain itu, aspek lain yang dipersiapkan oleh perseroan adalah sumber daya manusia. Syamsu mengutarakan aspek SDM merupakan faktor penting dalam peralihan pengelolaan.

“Kami berharap sebanyak mungkin karyawan Total E&P Indonesie melanjutkan pekerjaannya untuk menjaga operasi. Hasil laporan menunjukkan ada 90 % tawaran yang sudah kembali dan menyatakan kesediaan untuk bergabung dengan Pertamina.

Bisnis Indonesia, Page-34, Wednesday, August 9, 2017

Funding Jambaran-Tiung Biru in cut

The government cut capital expenditure in the Jambaran-Tiung Biru field project, Cepu Block of US $ 550 million to US $ 1.55 billion compared to the initial plan of US $ 2.1 billion.

The cutting of gas field investment located in Bojonegoro, East Java, makes the gas price generated more competitive. Deputy Minister of Energy and Mineral Resources (EMR) Archandra Tahar said the government is conducting the efficiency of the Jambaran-Tiung Biru project so that state and contractor revenues increase. Besides ilu, the efficiency has an impact on the decrease of gas price generated from the oil and gas field.

The Ministry of Energy and Mineral Resources conducted capex / capital expenditure or investment cost from US $ 2.1 billion to US $ 1.55 billion. It's a great achievement. The project can be executed immediately, "he said, Tuesday (8/8).

Archandra acknowledged that the efficiency caused oil and gas investment cap in this year also corrected. The realization of upstream oil and gas investment in the first half of 2017 reached US $ 4.8 billion or 21.62 percent of this year's target of US $ 22.2 billion

"However, this is an efficiency step, not to be seen from the declining investment," he said.

Jambaran-Tiung Biru will produce 330 MMscfd of gas with sales of 172 MMscfd for 16 years. In addition, PT PLN will absorb gas from Tiung Biru by 100 MMscfd, while 72 MMscfd is purchased by industry in Central Java. Gas from Jambaran-Tiung Biru will also be connected with gas transmission line of Gresik-Semarang segment along 267 km with diameter 28 inch.

Jambaran-Tiung Biru is an amalgamation of two fields, namely Jambaran Field and Tiung Biru. The Jambaran field is part of the Cepu Working Area, while the Tiung Biru Field is part and Territory The work of PT Pertamina EP.

In the Jambaran-Tiung Biru project, Pertamina EP Cepu is the operator and together with EMCL each have 41/1% management rights, while BUMD has 9.2% and 8% is owned by Pertamina EP.

IN INDONESIA

Pendanaan Jambaran-Tiung Biru Dipangkas

Pemerintah memangkas belanja modal dalam proyek lapangan Jambaran-Tiung Biru, Blok Cepu sebesar US$ 550 juta menjadi US$1,55 miliar dibandingkan dengan rencana awal US$2,1 miliar.

Pemangkasan investasi lapangan gas yang berlokasi di Bojonegoro, Jawa Timur itu membuat harga gas yang dihasilkan lebih kompetitif.  Wakil Menteri Energi dan Sumber Daya Mineral (ESDM) Archandra Tahar mengatakan, pemerintah melakukan efisiensi proyek Jambaran-Tiung Biru sehingga penerimaan negara dan kontraktor meningkat. Selain ilu, efisiensi itu berdampak terhadap penurunan harga gas yang dihasilkan dari lapangan migas itu.

Kementerian ESDM melakukan efisiensi capex/belanja modal atau biaya investasi dari US$2,1 miliar menjadi US$1,55 miliar. Ini capaian besar. Proyek tersebut dapat segera dieksekusi,” katanya, Selasa (8/8).

Archandra mengakui bahwa efisiensi itu menyebabkan capian investasi migas pada tahun ini turut terkoreksi. Realisasi investasi hulu migas pada semester I/2017 baru tercapai US$ 4,8 miliar atau 21,62% dari target tahun ini US$ 22,2 miliar 

“Namun, ini merupakan sebuah langkah efisiensi, jangan dilihat dari turunnya investasi,” katanya.

Jambaran-Tiung Biru akan memproduksikan gas 330 MMscfd dengan penjualan sebesar 172 MMscfd selama 16 tahun. Selain itu, PT PLN akan menyerap gas dari Tiung Biru sebanyak 100 MMscfd, sedangkan 72 MMscfd dibeli industri di Jawa Tengah. Gas dari Jambaran-Tiung Biru juga akan tersambung dengan pipa gas transmisi ruas Gresik-Semarang sepanjang 267 km dengan diameter 28 inci.

Jambaran-Tiung Biru merupakan penggabungan dari dua lapangan, yaitu Lapangan Jambaran dan Tiung Biru. Lapangan Jambaran merupakan bagian dari Wilayah kerja Cepu, sedangkan Lapangan Tiung Biru menjadi bagian dan Wilayah kerja PT Pertamina EP.

Dalam proyek Jambaran-Tiung Biru, Pertamina EP Cepu menjadi operator dan bersama EMCL masing-masing memiliki 41/1% hak kelola, sedangkan BUMD memiliki 9,2%, dan 8% dikuasai Pertamina EP.

Bisnis Indonesia, Page-34, Wednesday, August 9, 2017

Natural Gas Demand for GAS and China Increases

Natural gas prices are heating up in the short term along with the prospect of growing US and Chinese consumption. On Tuesday's trading at 8:15 pm, the price of natural gas for September contracts rose 0.24 points or 0.86 percent to US $ 2.825 per million British thermal unit (MMBtu).

However, during the year, prices fell 24.19%. Senior vice president of energy trading at FC Stone Latin America LLC Tom Saal says the natural gas market is sensitive to climate change in the United States. In fact, changes in weather projection could potentially trigger a price rally.

The weather forecasting agency MDA Weather Services reports temperatures in the central and eastern parts of the US tend to warm on August 17-21, 2017. Louis is predicted to be the hottest region because temperatures can reach 93 degrees Fahrenheit (34 degrees Celsius).

"Warming weather also adds to the prospect of demand for natural gas," he said as quoted by Bloomberg, Tuesday (8/8).

Meanwhile, based on U.S. data Energy Information Administration (EIA), in the week ended Friday (28/7) natural gas stocks rose 959 billion cubic feet to 3.01 trillion cubic feet. However, that figure is down 8.5% of the volume

Inventory in early 2017.

The EIA report also shows the current supply surplus is likely to be normal to 3% level compared to March 2017 at 21%. That is, Uncle Sam experienced significant demand growth. Chief executive officer and portfolio manager of Geosol Capital LLC Alex Elsik conveyed, the growth of natural gas demand in the US not only occur in hot weather, but will also peak before winter.

"As the supply narrows, there will be an increase in exports and the need for power generation. Stronger gas consumption could bring the price to US $ 4 per MMBtu," he said.

The last time the natural gas reached the level of US $ 4 per MMBtu is in 2014. Although difficult, the opportunity is still there as long as there is a boost from weather factors that spur demand.

The current low price of natural gas is also fueling purchases ahead of winter. The United States is quite reliant on the commodity because it contributes about 30% of the total fuel for power generation.

"Winter risks can trigger bullish on natural gas. The lower the price, the more demand in the market, "he said.

President of Schork Group Inc., Stephen Schork said natural gas prices could heat up significantly if there is support from the weather, especially in winter. It is estimated that the winter will begin in the third week of November 2017. Meanwhile, the World Bank predicts that the average price of natural gas 2017 will increase by 15% year on year (yoy) to US $ 3 per MMBtu from US $ 2.49 MMBtu. Influential sentiments are capacity building in the US and Australia, and heating up oil prices.

IN INDONESIA

Permintaan Gas Alam GAS dan China Menanjak

Harga gas alam memanas dalam jangka pendek seiring dengan prospek bertumbuhnya konsumsi Amerika Serikat dan China. Pada perdagangan Selasa (8/8) pukul 16.15 WIB, harga gas alam untuk kontrak September 2017 meningkat 0,24 poin atau 0,86% menuju US$2,825 per million british thermal unit (MMBtu).

Namun, sepanjang tahun berjalan, harga turun 24,19%. Senior vice president of energy trading at FC Stone Latin America LLC Tom Saal menuturkan pasar gas alam sensitif terhadap pergantian cuaca di Amerika Serikat. Bahkan, perubahan proyeksi cuaca berpotensi memicu reli harga.

Lembaga perkiraan cuaca MDA Weather Services melaporkan suhu di wilayah tengah dan timur AS cenderung menghangat pada 17-21 Agustus 2017. Kota St. Louis diprediksi menjadi wilayah paling panas karena suhu bisa mencapai 93 derajat fahrenheit (34 derajat celcius).

“Menghangatnya cuaca turut menambah prospek permintaan terhadap gas alam,” tuturnya seperti dikutip dari Bloomberg,

Selasa (8/8).

Sementara itu, berdasarkan data U.S. Energy Information Administration (EIA), dalam sepekan yang berakhir Jumat (28/7) stok gas alam naik 959 miliar kaki kubik menjadi 3,01 triliun kaki kubik. Namun, angka tersebut turun 8,5% dari volume persediaan pada awal 2017. 

Laporan EIA juga menunjukkan surplus pasokan saat ini cenderung normal ke level 3% dibandingkan dengan Maret 2017 di posisi 21%. Artinya, Paman Sam mengalami pertumbuhan permintaan yang signifikan. Chief executive officer and portfolio manager Geosol Capital LLC Alex Elsik menyampaikan, petumbuhan permintaan gas alam di AS tidak hanya terjadi saat cuaca panas, tetapi juga akan memuncak menjelang musim dingin.

"Ketika pasokan mengecil, akan terjadi kenaikan ekspor dan kebutuhan untuk pembangkit listrik Konsumsi gas alam yang menguat bisa membawa harga menuju US$ 4 per MMBtu,” tuturnya.

Terakhir kali gas alam mencapai level US$ 4 per MMBtu ialah pada 2014. Meskipun sulit, peluang tersebut masih ada asalkan ada dorongan dari faktor cuaca yang memacu permintaan.

Rendahnya harga gas alam saat ini juga memicu pembelian menjelang musim dingin. Amerika Serikat cukup mengandalkan komoditas tersebut karena berkontribusi sekitar 30% terhadap total bahan bakar untuk pembangkit listrik.

“Risiko musim dingin dapat memicu bullish terhadap gas alam. Semakin rendah harga, akan semakin banyak permintaan di pasar,” ujarnya.

President of Schork Group Inc., Stephen Schork mengatakan harga gas alam bisa memanas signifikan jika ada dukungan dari cuaca, terutama pada musim dingin. Diperkirakan musim dingin akan berlangsung mulai pekan ketiga November 2017. Sementara itu, Bank Dunia memprediksi rerata harga gas alam 2017 meningkat 15% year on year (yoy) menjadi US$3 per MMBtu dari sebelumnya US$2,49 MMBtu. Sentimen yang memengaruhi ialah peningkatan kapasitas di AS dan Australia, serta memanasnya harga minyak.

Bisnis Indonesia, Page-9, Wednesday, August 9, 2017

Electricity Gas Price Limit Maximally 14,% ICP

The government limits gas prices to power plants, both liquefied natural gas (LNG), not to exceed 14.5% of the Indonesian Crude Price (ICP). Through this beleid, the government wants LNG prices that can compete with gas pipelines.

The gas price for the power plant is stipulated in Regulation of the Minister of Energy and Mineral Resources (ESDM) No. 45 of 2017. This regulation revised the Regulation of the Minister of Energy and Mineral Resources 11/2017 which set the price of gas for electricity by 8% of ICP for power plant near the mouth of the gas well and 1 1.5% ICP for both domestic and export LNG and power plants away from gas field.

Deputy Minister of Energy and Mineral Resources Arcandra Tahar said, the revision is done because the price limit specified in Ministerial Regulation 11/2017 is useless. Because the Ministerial Regulation compares the price of piped gas without including the components of transportation costs and regasification.

"The workable gas price of 14.5% of ICP is calculated at the plant gate. If this price is not reached, then the Minister determines, "he said

He said that with the old beleid, when PLN obtained a gas 11.5% gas pipe price of 11.5% ICP and 11.4% ICP, PLN had to take the supply of LNG. In fact, not necessarily the price of gas to the power plant is only 1 1.4% ICB considering the cost of transportation and regasification has not been calculated, so the LNG price must be able to compete with gas pipelines.

"So essentially LNG prices in plant gate should be lower than 14.5% ICR" said Arcandra.

This provision applies to both domestic LNG and imported from other countries. According to Arcandra, the pricing of 14,% ICP is already considering the economy of oil and gas field. Assuming crude oil prices in the range of US $ 50 per barrel, the gas price for PLN should be about US $ 7 per million british thermal unit / mmbtu at the power plant.

In addition, pricing also takes into consideration domestic and international gas prices, consumer purchasing power, and added value from gas utilization. Meanwhile, gas price for mouth well power plant is still set at 8% of ICP According to Article 13 Ministerial Regulation 45/2017, if gas price is 8% ICP, PLN can appoint directly for the purchase of electricity.

But when gas prices exceed that limit, the purchase of electricity must go through a public auction. Another regulated clause is that if domestic and imported LNG prices have the same price, PLN and IPP must prioritize domestic LNG supply. However, if the price agreement is not reached, the Minister may determine the policy of natural gas provision.

As for the duration of gas supply, in this new rules the government no longer limits to 20 years such as the age of the power plant. Ministerial Regulation 45/2017 states the period of supply based on the assumption of conditions and performance of gas field reservoirs. If there is potential for longer gas supply, the contractor may extend the contract with PLN.

IN INDONESIA

Harga Gas Kelistrikan Dibatasi Maksimal 14, % ICP

Pemerintah membatasi harga gas untuk pembangkit listrik, baik gas pipa maupun gas alam cair (liquefied natural gas/LNG), tidak boleh melebihi 14,5% dari harga minyak mentah Indonesia (Indonesian Crude Price/ ICP). Melalui beleid ini, pemerintah menginginkan harga LNG yang dapat bersaing dengan gas pipa.

Harga gas untuk pembangkit listrik ini ditetapkan dalam Peraturan Menteri Energi dan Sumber Daya Mineral (ESDM) Nomor 45 Tahun 2017. Beleid ini merevisi Peraturan Menteri ESDM 11/2017 yang mematok harga gas untuk kelistrikan sebesar 8% dari ICP untuk pembangkit dekat mulut sumur gas serta 1 1,5% ICP untuk LNG domestik maupun ekspor dan pembangkit yang jauh dari lapangan gas.

Wakil Menteri ESDM Arcandra Tahar menuturkan, revisi dilakukan lantaran batas harga yang ditetapkan dalam Peraturan Menteri 11/2017 tidak ada gunanya. Pasalnya, Peraturan Menteri tersebut membandingkan harga gas pipa tanpa memasukkan komponen biaya transportasi dan regasifikasi. 

“Yang workable itu harga gas 14,5% dari ICP dihitung di plant gate. Kalau harga ini tidak tercapai, maka Menteri yang menentukan,” kata dia

Dikatakannya, dengan beleid lama, ketika PLN memperoleh tawaran harga gas pipa 11,5% ICP dan LNG 11,4% ICP maka PLN harus mengambil pasokan LNG tersebut. Padahal, belum tentu harga gas sampai di pembangkit listrik hanya 1 1,4% ICB mengingat biaya transportasi dan regasifikasi belum dihitung, sehingga harga LNG harus dapat bersaing dengan gas pipa. 

“Jadi intinya harga LNG di plant gate harus lebih rendah dari 14,5% ICR” tegas Arcandra.

Ketetapan ini berlaku baik untuk LNG domestik maupun yang didatangkan dari negara lain. Menurut Arcandra, penetapan harga 14,% ICP ini sudah mempertimbangkan keekonomian lapangan migas. Dengan asumsi harga minyak mentah di kisaran US$ 50 per barel, maka harga gas untuk PLN harus, sekitar US$ 7 per million british thermal unit/mmbtu di pembangkit listrik. 

Selain itu, penetapan harga juga mernpertimbangkan harga gas domestik dan internasional, kemampuan beli konsumen, dan nilai tambah dari pemanfaatan gas ini. Sementara itu harga gas untuk pembangkit listrik mulut sumur, tetap ditetapkan 8% dari ICP Sesuai Pasal 13 Peraturan Menteri 45/ 2017, jika harga gas 8% ICP, maka PLN bisa menunjuk langsung untuk pembelian listriknya. 

Namun ketika harga gas melebihi batas tersebut, pembelian listrik harus melalui pelelangan umum. Klausul lain yang diatur yakni bila harga LNG domestik dan impor memiliki harga yang sama, PLN dan IPP wajib mengutamakan pasokan LNG dalam negeri. Namun, bila tidak tercapai kesepakatan harga, Menteri dapat menetapkan kebijakan penyediaan gas bumi.

Sementara soal jangka waktu pasokan gas, dalam beleid baru ini pemerintah tidak lagi membatasi sampai 20 tahun seperti usia pembangkit listrik. Peraturan Menteri 45/2017 menyatakan jangka waktu pasokan berdasarkan asumsi kondisi dan kinerja reservoir lapangan gas. Jika memang ada potensi pasokan gas lebih panjang, kontraktor dapat memperpanjang kontrak dengan PLN.

Investor Daily, Page-10, Tuesday, August 8, 2017

Govt loosens reins on oil, mining firms

In response to the President’s concerns about lndonesia’s business climate, the Energy and Mineral Resources Ministry has relaxed requirements for firms to seek ministerial approval when changing their top management or when transferring shares or project interests.

President Joko “Jokowi” Widodo recently criticized a number of ministerial decrees, including of the Energy and Mineral Resources Ministry, which he considers burdensome for businesses and detrimental to his attempts to increase the country’s appeal for investors.

The new decree, Ministerial Decree No. 48/2017, replaces just two-week-old Decree No. 42, which obliged firms in the energy and mining industry to secure approval from the minister for high level management shake-ups as well as a partial or full transfer of shares or participating interests in a project.

Signed by Energy and Mineral Resources Minister Ignasius Jonan on Thursday the new rules only demand firms in the upstream oil and gas sector to obtain the minister’s agreement for transfers of participating interests or shares that change controlling share ownership.

“The new decree aims to realize values of good governance and increase the surveillance of companies in order to garner the maximum benefit for the people, while also maintaining a good investment climate,” Ghufron Asrofi, who leads the legal department at the ministry’s oil and gas directorate general, said on Monday

According to the new rules, ministerial consent is also necessary for mining firms for both a transfer of shares or change in top management. A similar approval also applies for firms in the geothermal sector that list their shares at the local bourse. 

The new decree may alleviate anxiety among investors, who had complained about the issuance of numerous controversial decrees by the ministry since early this year. Among them are Decree No. 8/2017 on a gross-split scheme for new upstream oil and gas contracts and Decree No. 12/2017 on prices of electricity generated from renewable energy.

Top officials of the ministry, particularly Deputy Minister Arcandra Tahar, promised to revise the decrees and have them signed as soon as the President took issue with them, but no revision had been revealed until Monday. Burdensome decrees may hinder the government’s objective to jack up the investment in the energy and mining sector to US$43 billion this year from $27 billion last year. 

Business players in the extractive industries applauded the ministry’s move, calling it a step toward improving policies for investors. Indonesian Petroleum Association (IPA) executive director Marjolijn Wajong said the new decree incorporated many of the group’s suggestions.

“This is a good move by the ministry It has listened well to what we requested [for the revision],” said Marjolijn during the announcement of the new decree. “Had the decree not been revised, it would have been really tough for us to implement it in our business.”

Indonesian Renewable Energy Society (METI) chairman Suryadharma also welcomed the revision, pointing out the improbability of implementing the previous one. 

All the things the ministry requires in the previous decree are what investors have always done themselves in general shareholders’ meetings. It is simply impossible to comply with both the government and the stakeholders of a company, as their decisions cannot be synchronized,” Surya told 

“This revision is a positive sign that the government has accommodated the needs of stakeholders in the renewable energy business.”

Jakarta Post, Page-13, Tuesday, August 8, 2017

Cost Benefit of Gross Split Policy

Post-issued in January 2017, the gross split policy (Minister of Energy and Mineral Resources Regulation No. 8/2017) seems relatively unresponsive to the upstream oil and gas industry. Although not the main cause, gross split policy allegedly contributed to the absence of enthusiasts working area of ​​oil and gas offered this year.

The implementation of the gross split policy actually departs from the goodwill of the government, which is to solve the problem of cost recovery and bureaucracy which is considered more complex on regular production sharing contract (PSC) model.

Gross split is believed to benefit both parties, government and industry players (contractors). The government will benefit because there is no longer cost recovery that has been a polemic. While the contractor will benefit from the absence of a necessity to develop a plant of development (POD).

In relation to gross split, since the discourse I recommend that the implementation of this policy is optional. Without prejudice to its advantages, I see this contract model can not be forced to apply to certain field conditions.

In this case, the optional nature is essentially also relevant to the provisions of the Oil and Gas Law no. 22/2001 and its implementation rules. If you look at the substance of Minister of Energy and Mineral Resources Regulation no. 8/2017, it appears that all oil and gas contracts in Indonesia will be directed to use the gross split contract.

Taking into account existing developments, the implementation of these regulations may not be easy and will face constraints at the operational level. Economic problems are likely to become an issue and a clerical constraint. In terms of economic issues, my review found that in some cases the gross split PSC is not quite feasible compared to the cost recovery PSC contract.

Compared to PSC cost recovery model, the application of gross split PSC from the side of economic calculation tends to hurt both parties. Among the potential losses that can be generated is to reduce revenue, both for government and contractors.

Simulations with the same assumptions and parameters, found that the Net Present Value (NPV), the Internal Rate of Return (IRR), the Pay Out Time (POT), the age of the field, and the government revenue on the gross split PSC model were no better than the PSC cost Recovery.

The NPV and IRR on the gross split PSC are potentially lower because the contractor has to bear all the risks and costs. The economic age of the field is potentially shorter because the contractor's portion can be allocated as less operating cost.

While the loss of cost recovery will reduce the ability of contractors to cover investment costs for each year. This condition puts POT on longer. The ultimate impact is the government revenue from the entire project life will be reduced.

One weakness of PSC gross split relative to PSC cost recovery is that this contract model indirectly limits contractors to cover operating costs. The impact of these restrictions is not simple, as it will shorten the economic life of the field and decrease production over the overall life of the project.

As a result, gross revenue to be shared for both sides will also be reduced. Another weakness found is the gross split PSC model was more sensitive to oil price fluctuations. Thus the contractor will relatively bear a higher risk if there is an oil price fluctuation.

Without additional incentives or fundamental changes to the scheme of this model, it is almost certain that the gross split PSC economy is no more attractive than the cost recovery PSC model. In addition to economic issues, the implementation of PSC gross split policy is also relatively problematic in the construction of its legal umbrella.

Viewed from several aspects, Minister of Energy and Mineral Resources Regulation no. 8/2017 is not solid enough to be a cornerstone in the implementation of upstream oil and gas management and operation.

Regulation at the level of Ministerial Regulation can not be used as a basis for resolving cross-cutting issues. While the slice of oil and gas sector problems with other sectors is quite large.

One of them is taxation problem whose authority is in the Ministry of Finance. Although for this issue the government has submitted to prepare a special Government Regulation (PP) to regulate the taxation of PSC gross split, but from the aspect of regulatory hierarchy, this is not unusual.

Strange if a PP issued by Ministerial Regulation which is the level of regulations below it. From the aspect of certainty, the regulation at the level of Ministerial Regulation is also vulnerable. A Ministerial Regulation is relatively easy to undo by either the same minister or a different minister in the event of a cabinet reshuffle / ministerial change.

While the oil and gas business contract is a long-term contract that requires regulatory certainty. Substance Regulation of Minister of Energy and Mineral Resources No. 8/2017 is also not automatically in line with the revision of the Oil and Gas Act which is currently being rolled in the House.

Thus it is possible the enactment of the Oil and Gas revisions later it will annul this regulation. Observing a number of potential problems that may arise, the government would need to review the implementation of the PSC policy gross split.

Related to the potential costs and benefits that will be brought about, it would be better if the application of gross PSC split is optional, assigned to the contractor to choose which is more suitable. The simple thing that we sometimes forget is that the gross split PSC contract model is not really a new thing. But why for decades did Indonesia use PSC cost recovery?

It could be because the PSC gross split does not match the conditions and characteristics of upstream oil and gas business in Indonesia.

IN INDONESIA

Biaya Manfaat Kebijakan Gross Split

Pasca diterbitkan pada Januari 2017, kebijakan gross split (Peraturan Menteri ESDM No. 8/2017) tampaknya relatif tidak memperoleh respon positif pelaku industri hulu migas. Meski bukan penyebab utama, kebijakan gross split disinyalir memberikan kontribusi atas belum adanya peminat wilayah kerja migas yang ditawarkan pada tahun ini.

Penerapan kebijakan gross split sesungguhnya berangkat dari niat baik pemerintah, yaitu menyelesaikan masalah cost recovery dan birokrasi yang dinilai lebih kompleks pada model production sharing contract (PSC) reguler.

Gross split diyakini akan menguntungkan kedua belah pihak, pemerintah dan pelaku industri (kontraktor). Pemerintah akan diuntungkan karena tidak ada lagi cost recovery yang selama ini sering menjadi polemik. Sementara kontraktor akan diuntungkan dengan tidak adanya keharusan untuk menyusun plant of development (POD).

Terkait dengan gross split, sejak diwacanakan saya merekomendasikan agar penerapannya kebijakan ini bersifat opsional. Tanpa mengesampingkan kelebihannya, saya melihat model kontrak ini tidak dapat dipaksakan untuk diterapkan pada kondisi lapangan tertentu.

Dalam hal ini, sifat opsional pada dasarnya juga relevan dengan ketentuan Undang-Undang Migas No. 22/2001 dan aturan pelaksanaannya. Jika mencermati substansi Peraturan Menteri ESDM No. 8/2017, tampak bahwa seluruh kontrak migas di Indonesia akan diarahkan untuk menggunakan kontrak gross split. 

Mencermati perkembangan yang ada, penerapan regulasi ini kemungkinan tidak mudah dan akan menghadapi kendala pada tingkat operasional. Masalah keekonomian kemungkinan akan menjadi isu dan kendala ulama. Terkait dengan masalah keekonomian, review yang saya lakukan menemukan bahwa pada kasus tertentu PSC gross split tidak cukup layak dibandingkan kontrak PSC cost recovery. 

Dibandingkan model PSC cost recovery, penerapan PSC gross split dari sisi hitungan keekonomian cenderung merugikan kedua belah pihak. Di antara potensi kerugian yang dapat ditimbulkan adalah akan menurunkan penerimaan, baik untuk pemerintah maupun kontraktor.

Simulasi dengan asumsi dan parameter yang sama, menemukan bahwa Net Present Value (NPV), Internal Rate of Return (IRR), Pay Out Time (POT), umur lapangan, dan pendapatan pemerintah pada model PSC gross split tidak lebih baik dibandingkan dengan PSC cost recovery.

NPV dan IRR pada PSC gross split berpotensi lebih rendah karena kontraktor harus menanggung seluruh resiko dan biaya. Umur ekonomis lapangan berpotensi lebih pendek karena bagian kontraktor yang dapat dialokasikan sebagai operating cost lebih sedikit.

Sementara hilangnya cost recovery akan mengurangi kemampuan kontraktor menutup biaya investasi untuk setiap tahunnya. Kondisi ini menyebahkan POT semakin lama. Dampak akhirnya adalah pendapatan pemerintah dari keseluruhan umur proyek akan berkurang.

Salah satu kelemahan PSC gross split secara relatif dibanding PSC cost recovery adalah model kontrak ini secara tidak langsung membatasi kontraktor dalam menutup biaya operasi. Dampak dari pembatasan ini tidak sederhana, karena akan memperpendek umur ekonomis lapangan dan menurunkan produksi pada keseluruhan umur proyek. 

Akibatnya, gross revenue yang akan dibagi untuk kedua belah pihak juga akan berkurang. Kelemahan lain yang ditemukan adalah model PSC gross split ternyata lebih sensitif terhadap gejolak harga minyak. Dengan demikian kontraktor secara relatif akan menanggung risiko yang lebih tinggi jika terdapat gejolak harga minyak.

Tanpa adanya insentif tambahan atau perubahan mendasar dari skema model ini, hampir dapat dipastikan keekonomian PSC gross split tidak lebih menarik dibandingkan model PSC cost recovery. Selain masalah keekonomian, penerapan kebijakan PSC gross split juga relatif bermasalah dalam konstruksi payung hukumnya.

Ditinjau dari beberapa aspek, Peraturan Menteri ESDM No. 8/2017 tidak cukup solid untuk dapat dijadikan landasan dalam pelaksanaan pengelolaan dan pengusahaan hulu migas.

Regulasi setingkat Peraturan Menteri tidak dapat digunakan sebagai landasan untuk menyelesaikan permasalahan lintas sektor. Sementara irisan permasalahan sektor migas dengan sektor yang lainnya cukup besar.

Salah satunya masalah perpajakan yang kewenangannya berada di Kementerian Keuangan. Meskipun untuk masalah ini pemerintah menyampaikan akan menyiapkan Peraturan Pemerintah (PP) khusus untuk mengatur perpajakan PSC gross split, tetapi dari aspek hierarki regulasi, hal ini sesungguhnya tidak lazim.

Aneh jika sebuah PP terbit berdasarkan Peraturan Menteri yang merupakan level peraturan di bawahnya. Dari aspek kepastian, regulasi setingkat Peraturan Menteri juga rentan. Sebuah Peraturan Menteri secara relatif akan sangat mudah dibatalkan pemberlakuannya baik oleh menteri yang sama atau menteri yang berbeda ketika terjadi reshuffle kabinet/pergantian menteri.

Sementara kontrak pengusahaan migas merupakan kontrak jangka panjang yang memerlukan kepastian regulasi. Substansi Peraturan Menteri ESDM No. 8/2017 tersebut juga tidak secara otomatis sejalan dengan proses revisi Undang-Undang Migas yang saat ini sedang bergulir di DPR.

Dengan demikian tidak menutup kemungkinan pemberlakuan Undang-Undang Migas revisi nantinya justru akan menganulir Peraturan Menteri ini. Mencermati sejumlah potensi permasalahan yang dapat ditimbulkan, pemerintah kiranya perlu meninjau kembali penerapan kebijakan PSC gross split. 

Terkait dengan potensi biaya dan manfaat yang akan ditimbulkan, akan lebih baik jika penerapan PSC gross split bersifat opsional, diserahkan kepada kontraktor untuk memilih mana yang lebih cocok. Hal sederhana yang terkadang kita lupakan adalah bahwa model kontrak PSC gross split sesungguhnya bukan hal baru. Tetapi mengapa selama puluhan tahun Indonesia menggunakan PSC cost recovery?

Bisa jadi karena memang PSC gross split tidak cocok dengan kondisi dan karakteristik pengusahaan hulu migas di Indonesia.

Bisnis Indonesia, Page-2, Tuesday, August 8, 2017