Portion Contractor added

The Government expands the additional portion of revenues for oil and gas contractors using the gross split share scheme regulated in the Minister of Energy and Mineral Resources Regulation. No. 52/2017 as revision of Regulation of Minister of Energy and Mineral Resources No. 8/2017 on the Gross Split Revenue Contract.

The government has implemented a gross profit sharing scheme since the beginning of this year for new contracts to replace production cost sharing contract (PSC) for cost recovery.

In the revision of the beleid, there are several important points. First, the split through the ministerial discretion is not restricted as in the preceding 5% maximum rule.

Second, the government adds a new component to the profit-sharing variable in the 2% plan of development (PoD) phase. If there is no PoD II, the 0% revenue-sharing variable is different from the previous rule which actually becomes 0.5% reduction for the contractor.

Thirdly, on the availability of supporting infrastructure components, the new frontier variable is increased by two, the new frontier offshore with 2% weight and the new frontier onshore 4%.

Fourth, the component of Hydrogen Sulfide Content Level (H2S), the highest weight that can be obtained at 5% from 1%. Fifth, on the component of the Domestic Content Level (TKDN), new incentives are given 2% additional split to achieve 30% to 50%.

Sixth, the components of the production stage, the weight plus and the beginning, 3% secondary and 5% tertiary, to 6% and 10% respectively.

OIL PRICE

Seventh, progressive components, incentives from oil prices using the fomula (85-ICP) x 0.25. Assuming ICP is US $ 50, the contractor may get an additional profit sharing of 8.75% or higher than the addition in the previous rule which uses a 5% level for oil prices of US $ 40 to US $ 55 per barrel.

Eighth, there is a new component in progressive profit sharing, ie gas price using formula for gas price of US $ 7 per MMBtu weight gain (7-gas price) x2,5. For the gas price of US $ 7 to US $ 10, the weight is 0%. Then, for a price of more than US $ 10 per MMBtu the formula (10-gas price) x 2.5. That is, the government set a normal limit of upstream gas prices of US $ 70-US $ 10 per MMBtu.

Ninth, for the cumulative component of production which previously started with 1 million barrels of oil equivalent (MMboe) with a weight of 5%. now converted to start from 30 MMboe with 10% weight. However, the government did not change the gross profit-sharing share between the government and contractors for oil development by 57:43 and 52:48 for gas. Meanwhile, the final profit sharing does not include the existing tax from upstream oil and gas activities.

Although the revenue-sharing space is expanded, Deputy Minister of Energy and Mineral Resources (ESDM) Arcandra Tahar said that in the most difficult field development scenario, the government still gets a profit share.

In the gross split regulated in the old rules only, Non-Tax State Revenue (PNBP), ie from the share of the government's share in ONWJ Block is only 19% for gas and 265% for oil. However, he did not mention how many of the smallest revenue-sharing opportunities the government has.

"There is no worst case scenario. just try, do not split this merged with this combined with this so that 100% contractor for example, probably not? I do not think so, "he said.

Previously, Executive Director of Indonesia Petroleum Association (IPA) Marjolijn Wajong said that to attract government investment need to pay attention to the economic characteristics of each field. According to Marjolijn each field has a character so it has different challenges to be developed. With that in mind, Marjolijn said the government could not set one point that should be applied in other fields.

"Regarding the adequacy to be able to withdraw investment, according to IPA, the revision of the regulation should pay attention to the economic characteristics of each field resulting from the difficulty of the field." There can be no fixed number for all fields, "her said.

Energy Observer from Reforminer Institute Komaidi Notonegoro said the new gross split still can not minimize the risks that must be borne by the contractor. He mentioned that small-capital contractors will not be able to manage the work area because now all development risks are borne entirely by the contractor because no longer apply the operating cost refund scheme as implemented since the 1970s.

IN INDONESIA

Jatah Kontraktor Ditambah

Pemerintah memperluas tambahan porsi pendapatan bagi kontraktor minyak dan gas bumi yang menggunakan skema bagi hasil kotor atau gross split yang diatur dalam Peraturan Menteri ESDM. No. 52/2017 sebagai revisi Peraturan Menteri ESDM No. 8/2017 tentang Kontrak Bagi Hasil Gross Split.

Pemerintah menerapkan skema bagi hasil kotor sejak awal tahun ini untuk kontrak baru menggantikan kontrak bagi hasil (production sharing contract/PSC) pengembalian biaya operasi atau cost recovery.

Dalam revisi beleid itu, terdapat beberapa poin penting. Pertama, ruang penambahan bagi hasil (split) melalui diskresi menteri tidak dibatasi seperti pada aturan sebelumnya yang maksimum 5%.

Kedua, pemerintah menambah komponen baru pada variable bagi hasil dalam fase rencana pengembangan lapangan (plan of development/PoD) II sebesar 3%. Jika tidak ada PoD II, variabel bagi hasil tetap 0% berbeda dengan aturan sebelumnya yang justru menjadi pengurang 0,5% bagi kontraktor.

Ketiga, pada komponen ketersediaan infrastruktur pendukung, variabel new frontier bertambah dua, yakni new frontier offshore dengan bobot 2% dan new frontier onshore 4%.

Keempat, komponen Tingkat Kandungan Hidrogen Sulfida (H2S), bobot tertinggi yang bisa didapat sebesar 5% dari semula 1%. Kelima, pada komponen Tingkat Kandungan Dalam Negeri (TKDN), insentif baru diberikan 2% tambahan split untuk capaian 30% hingga 50%.

Keenam, komponen tahapan produksi, bobot ditambah dan semula, 3% sekunder dan 5% tersier, menjadi 6% dan 10% secara berturut-turut.

HARGA MINYAK

Ketujuh, komponen progresif, pemberian insentif dari harga minyak menggunakan fomula (85-ICP) x 0,25. Dengan asumsi ICP US$ 50, kontraktor bisa mendapat tambahan bagi hasil 8,75% atau lebih tinggi dari tambahan dalam aturan sebelumnya yang menggunakan jenjang yaitu 5% untuk jenjang harga minyak US$ 40 sampai US$ 55 per barel.

Kedelapan, terdapat komponen baru pada bagi hasil progresif, yaitu harga gas menggunakan formula untuk harga gas US$ 7 per MMBtu bobot yang didapat (7-harga gas) x2,5. Untuk harga gas US$ 7 hingga US$ 10, bobotnya 0%. Kemudian, untuk harga lebih dari US$ 10 per MMBtu formulanya (10-harga gas) x 2,5. Artinya, pemerintah menetapkan batas normal harga gas hulu sebesar US$ 70-US$ 10 per MMBtu. 

Kesembilan, untuk komponen kumulatif produksi yang sebelumnya dimulai dengan 1 juta barel setara minyak (MMboe) dengan bobot 5%. kini diubah menjadi mulai dari 30 MMboe dengan bobot 10%. Namun, pemerintah tidak mengubah porsi bagi hasil secara kotor antara pemerintah dan kontraktor untuk pengembangan minyak sebesar 57:43 dan 52:48 untuk gas. Adapun, bagi hasil akhir yang didapatkan belum termasuk pajak yang ada dari kegiatan hulu migas.

Meskipun ruang penambahan bagi hasil diperluas, Wakil Menteri Energi dan Sumber Daya Mineral (ESDM) Arcandra Tahar mengatakan bahwa pada skenario pengembangan lapangan tersulit, pemerintah tetap mendapat bagi hasil.

Pada gross split yang diatur dalam aturan lama saja, Penerimaan Negara Bukan Pajak (PNBP) yakni dari porsi bagi hasil pemerintah di Blok ONWJ hanya sebesar 19% untuk gas dan 265% untuk minyak. Namun, dia tidak menyebut berapa peluang bagi hasil paling kecil yang dimiliki pemerintah.

“Tidak ada worst case scenario. coba saja, jangan split ini digabung dengan ini digabung dengan ini sehingga kontraktor 100% misalnya, mungkin tidak? Rasanya tidak," katanya.

Sebelumnya, Direktur Eksekutif Indonesia Petroleum Association (IPA) Marjolijn Wajong mengatakan bahwa untuk bisa menarik investasi pemerintah perlu memperhatikan karakteristik keekonomian masing-masing lapangan. Menurut Marjolijn setiap lapangan memiliki karakter sehingga memiliki tantangan berbeda untuk bisa dikembangkan. Dengan pertimbangan itu, Marjolijn menyebut pemerintah tidak bisa menetapkan satu angka yang harus diterapkan di lapangan lainnya.

"Mengenai kecukupan untuk dapat menarik kembali investasi, menurut IPA, revisi peraturan tersebut harus memperhatikan karakteristik keekonomian masing-masing lapangan yang diakibatkan dari tingkat kesulitan lapangan tersebut. Tidak bisa ditetapkan suatu angka tenentu untuk semua lapangan," ujarnya.

Pengamat Energi dari Reforminer Institut Komaidi Notonegoro mengatakan, gross split baru masih belum bisa meminimalisir resiko yang harus ditanggung kontraktor. Dia menyebut kontraktor bermodal kecil tetap tidak akan bisa mengelola wilayah kerja karena kini seluruh risiko pengembangan ditanggung sepenuhnya oleh kontraktor karena tidak lagi berlaku skema pengembalian biaya operasi seperti yang diterapkan sejak periode 1970-an.

Bisnis Indonesia, Page-32, Monday, Sept 4, 2017

US Refinery Operations Start Recovering

Major oil refineries in Texas, United States, returned to normal operation after the storm Harvey crashed on Saturday (26/8). This recovery increases the demand outlook so that it lifts the price of oil. At the close of trade

Friday (1/8), the price of WTI oil in October 2017 contract rose 0.06 points or 0.13% to US $ 47.29 per barrel.

Prices edged up in the past two trades, but are still down 11.97% throughout 2017. Some refineries in the US have closed or slowed operations since Harvey's storm took place on Friday (25/8). These factors suppress the demand for crude oil so that prices fall further.

The peak occurred on Wednesday (30/8), when the price of WTI reached the level of US $ 45.96 per barrel. This is the lowest position since the close of trading on July 21, 2017 at the level of US $ 45.77 per barrel.

Based on Reuters data, a number of major refineries in Texas began normal operations on Saturday (2/9), a week after Harvey storm hit several areas in the US. Exxon, for example, began reopening a crude oil refinery facility with a capacity of 560,500 barrels per day (bpd).

Phillips 66 also continues the operation of Sweeny refinery with a capacity of 247,000 bph. Valero Energy also increased production and evaluated the performance of the refinery at Porth Arthur of 335,000 bph.

However, the largest US oil refinery belonging to Motiva Enterprises LLC in Port Arthur that processes 605,000 barrels per day (bpd) still states shutdown. Total Company still cuts 50% of its processing capacity by 225,000 bpd. According to the Goldman Sachs Group, refined crude oil processing capacity of the US fell 23% or about 4.1 million bpd since Harvey stormed.

The production volume of crude oil decreased by about 1.4 million bpd or equivalent to 15% of total daily mining. Partner Again Capital LLC John Kilduff said, Uncle Sam's crude oil demand increased after Harvey storm subsided. In addition, the US Department of Energy agreed to release 4.5 million barrels of stock to meet raw material demand.

"The government is reacting positively to fix the situation There are signs the refinery is alive again, so it helps easing the jitters of market participants against Harvey storms, "he said as quoted by Bloomberg, Saturday (2/9).

Portfolio manager Manulifem Asset Management LLC Joseph Bozoyan estimates Harvey's storm factor will still affect the oil market in the next few weeks. This sentiment is thought to greatly disrupt the outlook for demand, despite the gradual recovery in progress.

In addition to Harvey's sentiment, supply reductions from a number of major producers raised the fundamentals of the oil market, contributing to heating up prices.

Petro-Logistics estimates the average production of 14 member countries to decline 419,000 bpd compared to the previous month. In June and July of 2017, OPEC production surged to a record high of 32.66 million bpd and 32.87 million bpd. The volume exceeded the target of cutting production tariffs to 32.50 million bpd per month.

Monex Investindo Futures analyst Faisyal said oil prices still tend to be bearish in the short term. The US $ 47.30 area will be the nearest resistance level before it heats to US $ 47.80 per barrel. Should it slip below US $ 4 7, the price will go to the support level of US $ 46.50 per barrel.

IN INDONESIA

Operasi Kilang AS Mulai Pulih

Sejumlah kilang minyak utama di Texas, Amerika Serikat, kembali beroperasi normal setelah bencana badai Harvey menerjang pada Sabtu (26/8). Pemulihan ini meningkatkan prospek permintaan sehingga mengangkat harga minyak. Pada penutupan perdagangan

Jumat (1/8), harga minyak WTI kontrak Oktober 2017 naik 0,06 poin atau 0,13% menuju US$47,29 per barel. 

Harga naik tipis dalam dua perdagangan terakhir, tetapi masih turun 11,97% sepanjang 2017. Sebagian perusahaan kilang di AS menutup atau memperlambat pengoperasiannya sejak badai Harvey berlangsung pada Jumat (25/8). Faktor tersebut menekan permintaan minyak mentah sehingga harga semakin tersungkur.

Puncaknya terjadi pada Rabu (30/8), ketika harga WTI mencapai level US$45,96 per barel. lni merupakan posisi terendah sejak penutupan perdagangan 21 Juli 2017 di level US$45,77 per barel.

Berdasarkan data Reuters, sejumlah kilang utama di Texas mulai beroperasi normal pada Sabtu (2/9), seminggu setelah badai Harvey menerjang beberapa wilayah di AS. Exxon, misalnya, mulai membuka kembali fasilitas penyulingan minyak mentah dengan kapasitas sebesar 560.500 barel per hari (bph).

Phillips 66 juga melanjutkan pengoperasian kilang Sweeny berkapasitas 247.000 bph. Adapun Valero Energy turut meningkatkan produksi dan mengevaluasi kinerja kilang di Porth Arthur sejumlah 335,000 bph.

Namun demikian, kilang minyak terbesar di AS milik Motiva Enterprises LLC di Port Arthur yang memproses 605.000 barel perhari (bph) masih menyatakan shutdown. Perusahaan Total pun tetap memangkas 50% operasi dari kapasitas pengolahan sebesar 225 .000 bph. Menurut catatan Goldman Sachs Group, kapasitas penyulingan minyak olahan AS turun 23% atau sekitar 4,1 juta bph sejak badai Harvey menerjang. 

Adapun volume produksi minyak mentah berkurang sekitar 1,4 juta bph atau setara dengan 15% total penambangan harian. Partner Again Capital LLC John Kilduff menuturkan, permintaan minyak mentah Paman Sam meningkat setelah badai Harvey mereda. Selain itu, Departemen Energi AS setuju untuk melepas stok sebanyak 4,5 juta barel untuk memenuhi permintaan bahan baku.

"Pemerintah bereaksi positif untuk membenahi keadaan. Ada tanda-tanda kilang sudah hidup kembali, sehingga membantu

meredakan kegelisahan pelaku pasar terhadap badai Harvey," tuturnya seperti dikutip dari Bloomberg, Sabtu (2/9).

Portofolio manager Manulifem Asset Management LLC Joseph Bozoyan memperkirakan faktor badai Harvey masih akan mempengaruhi pasar minyak dalam beberapa minggu ke depan. Sentimen ini dinilai sangat mengganggu prospek permintaan, kendati pemulihan bertahap sedang berjalan.

Di samping sentimen Harvey, pengurangan pasokan dari sejumlah produsen utama mengangkat fundamental pasar minyak sehingga turut memanaskan harga.

Petro-Logistics memerkirakan rerata produksi 14 negara anggota merosot 419.000 bph dibandingkan dengan bulan sebelumnya. Pada Juni dan Juli 2017, produksi OPEC tercatat melonjak ke level tertinggi sebesar 32,66 juta bph dan 32,87 juta bph. Volume tersebut melampaui target kesepakatan pemangkasan produksi menjadi 32,50 juta bph per bulan.

Analis Monex Investindo Futures Faisyal menuturkan, harga minyak masih cenderung bearish dalam jangka pendek. Area US$47,30 akan menjadi level resistan terdekat sebelum memanas menuju US$ 47,80 per barel. Apabila tergelincir ke bawah US$ 4 7, harga akan menuju level support US$ 46,50 per barel.

Bisnis Indonesia, Page-16, Monday, Sept 4, 2017

Kepodang Gas Stoped

The gas distribution contract from Kepodang Field, Muriah Block will be suspended due to the declaration of Petronas Carigali Muriah Limited as the oil and gas block operator located on the north coast of Java.

Director of Procurement State Electricity Company Supangkat lwan Santoso said that it will end the contract of gas distribution Kepodang with the grandeur of the declaration. Kahar conditions are occurrences beyond the control of contractors that affect operations in the field.

Gas supply from Kepodang Field decreased so that the realization of the distribution was below the volume specified in the contract. This force majeure condition causes the buyer and seller to be exempted from their responsibility. Kahar allows buyers to terminate the gas distribution contract.

"If force majeure is likely to be direterminate [the contract is terminated]," he said.

According to him, the completion of the contract was chosen because of the price side, Kepodang gas is quite expensive. Kepodang gas sold for US $ 4.61 per MMBtu with an escalation of 8.6% per year will be channeled to the 1,000 megawatt (MW) Tambak Lorok-Semarang Steam Power Plant (PLTGU) owned by PT Perusahaan Listrik Negara. Gas that generates 600 MW of electricity is channeled through gas pipelines Kepodang-Tambak Lorok Semarang

He estimates that in the next 5 years the price of gas from the field starting production in 2015 could reach US $ 10 per MMBtu. Thus, Kepodang Field majeure condition becomes the company's moment to seek other more affordable supply sources.

"Kepodang is relatively expensive with an 8% escalation. If LNG [liquid natural gas] is not necessarily more expensive, "said Iwan.

LNG SUPPLY

Other sources of supply, said Iwan, could come from liquefied natural gas / LNG through the construction of new storage and regasification facilities around PLTGU Tambak Lorok. The use of LNG will support the supply from the Gundih Field of 50 MMscfd as it will increase the installed capacity in Tambak Lorok with the development plan of Block 3 as well as the supply that can meet the needs as electricity consumption goes up and requires more gas supply.

PLN's subsidiary PT Indonesia Power will build Block 3 of Tambak Lorok-Semarang with a power capacity of 780 MW worth Rp 4.8 trillion. The gas generator project is scheduled to start operation in April 2020 assuming PLTGU Block 3 Tambak Lorok production reaches 3.7 GWh per year. The engineering, procurement, and contraction (EPC) engineering work will be conducted by GE Power, Marubeni Corporation and PT Hutama Karya consortiums.

Senior Manager of Corporate Affairs & Administration Petronas Carigali Indonesia Andiono Setiawan said that until now it is still doing coordination and discussion of induced declaration of Kepodang Field Majority.

With the majestic condition that Petronas Carigali Muriah Limited has announced as an operator, the supply will be distributed until 2018. In the gas sale and purchase agreement (PJBG), Kepodang field will supply 116 million cubic feet per day (MMscfd) gas for 12 years. However, daily production is currently around 70 MMscfd.

The initial production of Kepodang field gas starts in September 2015. On the block. Petronas Carigali Muriah Limited controls 80% participation and Saka Energi Muriah Limited by 20%.

With power status in the field, Petronas is still discussing with SKK Migas, Ministry of ESDM. PLN as the gas buyer and PT Kalimantan Jawa Gas as the owner of the gas pipeline network. Currently, the government through the Institute of Oil and Gas (Lemigas) as a center for research and development of oil and gas technology, conducts a study of the subsurface conditions.

"Currently we are still coordinating and discussing with related parties regarding Kepodang especially with SKK Migas, ESDM, PLN and also KJG [Kalimantan Jawa Gas]," he said.

IN INDONESIA

Gas Kepodang Disetop

Kontrak penyaluran gas dari Lapangan Kepodang, Blok Muriah akan dihentikan karena deklarasi kahar dari Petronas Carigcali Muriah Limited sebagai operator blok minyak dan gas bumi yang berloksi di pantai utara Jawa tersebut.

Direktur Pengadaan PT Perusahaan Listrik Negara Supangkat lwan Santoso mengatakan bahwa pihaknya akan mengakhiri kontrak penyaluran gas Kepodang dengan adanya deklarasi kahar. Kondisi kahar merupakan kejadian di luar kendali kontraktor yang memengaruhi operasi di lapangan. 

Pasokan gas dari Lapangan Kepodang turun sehingga realisasinya penyaluran di bawah volume yang ditetapkan dalam kontrak. Kondisi kahar atau force majeur ini mengakibatkan pihak pembeli dan penjual dibebaskan dari tanggung jawabnya. Kahar memungkinkan pembeli untuk mengakhiri kontrak penyaluran gas.

"Kalau force majeure kemungkinannya direterminate [kontrak disetop]," ujarnya.

Menurutnya, penyelesaian kontrak dipilih karena dari sisi harga, gas Kepodang tergolong mahal. Gas Kepodang dijual seharga US$ 4,61 per MMBtu dengan eskalasi 8.6% per tahun akan dialirkan ke Pembangkit Listrik Tenaga Gas Uap (PLTGU) Tambak Lorok-Semarang berkapasitas 1.000 megawatt (MW) milik PT Perusahaan Listrik Negara. Gas yang menghasilkan listrik 600 MW itu disalurkan melalui ruas pipa gas Kepodang-Tambak lorok.

Dia memperkirakan bahwa pada 5 tahun mendatang harga gas dari lapangan yang memulai produksi di 2015 itu bisa mencapai US$ 10 per MMBtu. Dengan demikian, kondisi force majeure Lapangan Kepodang menjadi momen perseroan mencari sumber pasokan lain yang lebih terjangkau.

“Kepodang relatif mahal harganya dengan eskalasi 8%. Kalau LNG [gas alam cair] belum tentu lebih mahal," kata Iwan.

PASOKAN LNG

Sumber pasokan lain, kata lwan, bisa berasal dari gas alam cair/LNG melalui pembangunan fasilitas penyimpanan dan regasifikasi baru di sekitar PLTGU Tambak Lorok. Penggunaan LNG akan mendukung pasokan dari Lapangan Gundih sebesar 50 MMscfd karena akan bertambahnya kapasitas terpasang di Tambak Lorok dengan rencana pengembangan Blok 3 juga sebagai pasokan yang bisa memenuhi kebutuhan sewaktu konsumsi listrik naik dan membutuhkan pasokan gas lebih.

Anak usaha PLN, PT Indonesia Power akan membangun Blok 3 Tambak Lorok-Semarang berkapasitas daya 780 MW senilai Rp 4,8 triliun. Proyek pembangkit gas tersebut dijadwalkan mulai beroperasi pada April 2020 dengan asumsi produksi PLTGU Blok 3 Tambak Lorok mencapai 3,7 GWh per tahun. Pekerjaan rekayasa, pengadaan dan konstruksi (engineering, procurement, and contraction/EPC) pembangkit akan dilakukan konsorsium GE Power, Marubeni Corporation, dan PT Hutama Karya.

Senior Manager Corporate Affairs & Administration Petronas Carigali Indonesia Andiono Setiawan mengatakan bahwa hingga saat ini pihaknya masih melakukan koordinasi dan diskusi dari imbas deklarasi kahar Lapangan Kepodang.

Dengan kondisi kahar yang telah disampaikan Petronas Carigali Muriah Limited sebagai operator, pasokan akan disalurkan hingga 2018. Dalam perjanjian jual beli gas (PJBG), lapangan Kepodang akan menyuplai gas sebesar 116 juta kaki kubik per hari (MMscfd) selama 12 tahun. Namun, produksi harian saat ini sekitar 70 MMscfd. 

Produksi perdana gas Lapangan Kepodang dimulai pada September 2015. Pada blok tersebut. Petronas Carigali Muriah Limited menguasai saham partisipasi sebesar 80% dan Saka Energi Muriah Limited sebesar 20%.

Dengan status kahar pada lapangan tersebut, Petronas masih melakukan diskusi dengan SKK Migas, Kementerian ESDM. PLN sebagai pembeli gas dan PT Kalimantan Jawa Gas sebagai pemilik jaringan pipa gas. Saat ini, pemerintah melalui Lembaga Minyak dan Gas Bumi (Lemigas) sebagai pusat penelitian dan pengembangan teknologi minyak dan gas bumi, melakukan kajian kondisi bawah permukaan lapangan tersebut.

"Saat ini kami, Petronas masih melakukan koordinasi dan diskusi dengan pihak-pihak terkait mengenai Kepodang terutama dengan SKK Migas, ESDM, PLN dan juga KJG [Kalimantan Jawa Gas],” ujarnya.

Bisnis Indonesia, Page-32, Thursday, August 31, 2017

Toll Fee Gas Arun-Belawan falls

Downstream Regulatory Agency (BPH) of Oil and Gas lowered the tariff for transportation aka toll fee transmission for the Arun-Belawan gas pipeline which operated by PT Pertamina Gas (Pertagas). 

     In its decision, BPH Migas set a toll fee of the transmission line from Arun-Belawan to US $ 1.54 per MSCF. Jugi Prajogio, a member of the BPH Migas Committee, said that with the stipulation, the toll fee for the transmission of the Arun-Belawan segment is down around US $ 1 per MSCF.

"Domain BPH sets the toll fee transmission, formerly US $ 2.53 MSCF, now US $ 1.54 MSCF. It down about US $ 1 MSCF," he said Wednesday (30/8).

The determination of tariff for natural gas transportation through pipeline shall be determined based on Regulation of BPH Migas No 03/2017 concerning Tariff of Gas Transportation through Transmission Pipe of Arun (Aceh) to Belawan (North Sumatra) to PT Pertamina Gas at 22 August 2017. This determination was signed by the Head of BPH Migas M. Fanshurullah Asa.

This Regulation of BPH Migas revokes and declares the Minister of Oil and Gas Regulation No. 15 / TARIF / BPH MIGAS / KOM / 2014 regarding the Initial Determination of the Gas Transportation Tariff through the Transmission Line of Arun Belawan to PT Pertamina Gas.

Through the determination of the tariff of natural gas transportation of the Arun-Belawan transmission line is a real form of work BPH Migas supports the policy of the President of Indonesia, Joko Widodo who requested that the price of natural gas in Indonesia more rational and enjoyed by the people.

"Our step is to help the industry and PLN get a rational gas price," said Hari Pratoyo, BPH Migas Committee.

Hari Pratoyo said, BPH Migas can only mengefisiensikan gas prices to the end user through the determination of toll fee rates according to their authority. However, for the gas price of a Business Entity whose process must be regasified or using LNG, of course BPH Migas can not regulate the regasification rate.

"Regasification rates and LNG prices for end users in North Sumatra are set business to business (B to B)," he said.

IN INDONESIA

Tarif Toll Fee Gas Arun-Belawan

Badan Pengatur Hilir (BPH) Migas menurunkan tarif pengangkutan alias toll fee transmisi untuk ruas pipa gas Arun-Belawan yang dioperasikan oleh PT Pertamina Gas (Pertagas). 

    Dalam keputusannya, BPH Migas menetapkan toll fee ruas transmisi dari Arun-Belawan menjadi US$ 1,54 per MSCF. Jugi Prajogio, Anggota Komite BPH Migas mengatakan dengan penetapan tersebut, toll fee transmisi ruas Arun-Belawan turun sekitar US$ 1 per MSCF. 

"Domain BPH menetapkan toll fee transmisi, dulu US$ 2,53 MSCF, sekarang US$ 1,54 MSCF. Ini turun sekitar US$ 1 MSCF,"katanya Rabu (30/8).

Penetapan tarif pengangkutan gas bumi melalui pipa ditetapkan berdasarkan Peraturan Badan Pengatur Hilir Minyak dan Gas Bumi (BPH Migas) No 03/2017 tentang Tarif Pengangkutan Gas Bumi Melalui Pipa Ruas Transmisi Arun (Aceh) ke Belawan (Sumatera Utara) untuk PT Pertamina Gas pada 22 Agustus 2017. Penetapan ini ditandatangani oleh Kepala BPH Migas M. Fanshurullah Asa.

Peraturan BPH Migas ini sekaligus mencabut dan menyatakan tidak berlakunya Keputusan Kepala BPH Migas Nomor 15/TARIF/BPH MIGAS/ KOM/2014 tentang Penetapan Initial Tarif Pengangkutan Gas Bumi Melalui Pipa Ruas Transmisi Arun Belawan kepada PT Pertamina Gas.

Melalui penetapan tarif pengangkutan gas bumi ruas transmisi Arun-Belawan ini merupakan bentuk kerja nyata BPH Migas mendukung kebijakan Presiden RI , Joko Widodo yang meminta agar harga gas bumi di Indonesia lebih rasional dan dinikmati rakyat banyak.

“Langkah kami ini untuk membantu industri dan PLN mendapatkan harga gas yang rasional," kata Hari Pratoyo, Komite BPH Migas.

Hari Pratoyo bilang, BPH Migas hanya bisa mengefisiensikan harga gas kepada end user lewat penetapan tarif toll fee sesuai kewenangannya. Namun, untuk harga gas dari Badan Usaha yang prosesnya harus diregasifikasi atau memakai LNG, tentu saja BPH Migas tidak bisa mengatur tarif regasifikasi.

“Tarif regasifikasi dan harga LNG untuk end user di Sumatera Utara ditetapkan secara business to business (B to B)," katanya.

Kontan, Page-18, Thursday, August 31, 2017

PLN Not Interested to Buy Kepodang Substitute Gas

Gas Sale and Purchase Contract (PJBG) Petronas Carigali and PT Perusahaan Listrik Negara stop post Kepodang Field declared kahar. In fact, during this Kepondang to supply gas PLTGU Tambak Lorok, PLN will instead build floating storage regasification units (FSRU) in cooperation with Pertamina and PGN.

Director of Strategic Procurement H. Supangkat Iwan Santoso explained after Field of Kepodang force majeure, there is clause to stop contract according to Gas Sales and Purchase Agreement (PJBG). Approval of Kepodang Field Majeure statement by SKK Migas and Minister of EMR one month ago, PLN has no contract with Petronas.

"It's out of our control, so each of our responsibilities goes out, it's not there, we have no responsibility to buy from suppliers, no responsibility for entry," Iwan said on Tuesday (29/8).

Iwan asserted, PLN also did not enter into new contracts with Petronas if later the Malaysian oil company offered to replace the supply of gas Kepodang from other gas sources. Moreover, the price offered is expensive.

"The escalation is too high, until the plant gate is US $ 7 per mmbtu more, the escalation is 8%, very high, so five years is more than US $ 10 per mmbtu," said Iwan.

Therefore, PLN chose to seek alternative gas for PLTGU-Tambak Lorok. One way to find gas supply pipe.

IN INDONESIA

PLN Tidak Berminat Beli Gas Pengganti Kepodang

Kontrak Jual Beli Gas (PJBG) Petronas Carigali dan PT Perusahaan Listrik Negara berhenti pasca Lapangan Kepodang dinyatakan kahar. Padahal, selama ini Kepondang memasok gas PLTGU Tambak Lorok, Sebagai gantinya PLN akan membangun penampung gas terapung atau floating storage regasification unit (FSRU) bekerjasama dengan Pertamina dan PGN.

Direktur Pengadaan Strategis H. Supangkat Iwan Santoso menjelaskan setelah Lapangan Kepodang force majeure, ada klausul menghentikan kontrak sesuai Perjanjian Jual Beli Gas (PJBG). Persetujuan pernyataan force majeure Lapangan Kepodang oleh SKK Migas dan Menteri ESDM satu bulan lalu, PLN tidak ada kontrak dengan Petronas.

"Itu di luar kendali kami. Jadi masing-masing tanggung jawabnya jadi lepas, sudah tidak ada. Kami tidak ada tanggung jawab beli dari pemasok tidak ada tanggung jawab masuk," kata Iwan pada Selasa (29/8).

Iwan menegaskan, PLN juga tidak melakukan kontrak baru dengan Petronas bila nantinya perusahaan minyak Malaysia itu menawarkan mengganti pasokan gas Kepodang dari sumber gas lain. Apalagi harga yang ditawarkan mahal. 

"Eskalasinya terlalu tinggi. Sampai plant gate US$ 7 per mmbtu lebih, eskalasi 8%, tinggi sekali. Jadi lima tahun lagi sudah lebih dari US$ 10 per mmbtu,“ jelas Iwan. 

Oleh karena itu, PLN memilih untuk mencari alternatif gas lain untuk PLTGU-Tambak Lorok. Salah satu caranya dengan mencari pasokan gas pipa. 

"Sekarang masih ada dari Gundih ya 50 mmscd. Nanti kekurangannya dari LNG," tuturnya.

Kontan, Page-18, Thursday, August 31, 2017

Cost of Rental of Gas Pipe Downgraded

The Downstream Regulatory Agency for Petroleum and Natural Gas lowered the rental cost of natural gas transportation in the Arun-Belawan pipeline to US $ 1.55 per thousand cubic feet (Mscf) compared to US $ 2.53 per Mscf. The cutting of gas transportation cost in the toll road is contained in Regulation of Oil and Gas Regulatory Agency No. 3/2017 on Tariff of Gas Transportation Through Arun Transmission Pipe (Aceh) to Belawan (North Sumatra) to PT Pertamina Gas dated 22 August 2017.

With the issuance of the decision, the old regulation stipulates the cost of leasing pipe US $ 2.53 Mscf through the Decree of the Head of BPH Migas. 15 / Tariff / BPH Migas / Kon / 2014 shall be declared null and void.

BPH Migas commissioner Jugi Prajogio said that the move aims to help the industry and PT Perusahaan Listrik Negara get a more rational gas price for the supply of Steam and Gas Power Plant (PLTGU) Belawan.

"Through the determination of the tariff for the transport of natural gas for the Arun transmission line (Aceh) -Belawan (Medan), this is our effort to efficient gas price," he said during a press conference on Wednesday (30/8).

According to him, there are several things that are guarded by BPH Migas to reduce gas prices in consumers. He pointed out, business talks between operators who build gas pipelines and pipeline supply companies as well as others.

Previously, due to the high cost of this distribution, PLTGU Belawan can not operate efficiently until the cost of electricity tariffs become expensive. There are a number of cost components that are charged to PLN.

Gas delivered to PLTGU Belawan through transmission pipeline Arun-Belawan belongs to PT Pertamina Gas, a subsidiary of PT Pertamina which charges a toll fee of US $ 2.53 per Mscf. The total cost of regasification and toll fee of transmission pipeline alone is US $ 4.09 per MMBtu. Therefore the gas price to be more than US $ 10 per MMBtu so arrived at PLTGU Belawan.

PLN is still negotiating with Pertagas that Pertamina's subsidiary is willing to cut regasification fee at Arun LNG Terminal and Arun-Belawan toll fee pipeline. Forward. PLN will also need gas supply for PLTGU North Sumatra (Sumbagut) 800 megawatt (MW), Arun 184 MW and Arun Power Plant Expansion 250 MW, PLTGU Sumbagut 800 MW requiring additional gas supply adds a flow of about 80 MMscfd,

Jugi added that BPH Migas will also oversee the pipe rental fee set by the business entity in other gas pipeline projects.

IN INDONESIA

Biaya Sewa Pipa Gas Diturunkan

Badan Pengatur Hilir Minyak Bumi dan Gas Bumi menurunkan biaya sewa pengangkutan gas bumi di pipa ruas Arun-Belawan menjadi US$ 1,55 per ribu kaki kubik (Mscf) dibandingkan dengan sebelumnya US$ 2,53 per Mscf. Pemangkasan biaya pengangkutan gas di ruas tersebut tertuang dalam Peraturan BPH Migas No. 3/2017 tentang Tarif Pengangkutan Gas Bumi Melalui Pipa Ruas Transmisi Arun (Aceh) ke Belawan (Sumatra Utara) untuk PT Pertamina Gas tertanggal 22 Agustus 2017.

Dengan dikeluarkannya keputusan tersebut, regulasi yang lama yang menetapkan biaya sewa pipa US$ 2,53 Mscf melalui Keputusan Kepala BPH Migas No. 15/Tarif/BPH Migas/Kon/2014 dinyatakan tidak berlaku.

Komisioner BPH Migas Jugi Prajogio mengatakan bahwa langkah tersebut bertujuan untuk membantu industri dan PT Perusahaan Listrik Negara mendapatkan harga gas yang lebih rasional untuk pasokan Pembangkit Listrik Tenaga Gas dan Uap (PLTGU) Belawan.

“Melalui penetapan tarif pengangkutan gas bumi ruas transmisi Arun (Aceh)-Belawan (Medan) ini merupakan upaya kita untuk mengefisiensi harga gas,” katanya saat menggelar konferensi pers, Rabu (30/8).

Menurutnya, ada beberapa hal yang dikawal oleh BPH Migas untuk menekan harga gas di konsumen. Dia mencontohkan, pembicaraan secara bisnis antara operator yang membangun pipa gas dan perusahaan penyedia bahan pipa serta pihak lainnya.

Sebelumnya, akibat mahalnya biaya distribusi ini, PLTGU Belawan tidak bisa beroperasi dengan efisien hingga biaya tarif listrik menjadi mahal. Ada sejumlah komponen biaya yang dibebankan ke PLN.

Gas yang dialirkan ke PLTGU Belawan melalui pipa transmisi Arun-Belawan milik PT Pertamina Gas, anak usaha PT Pertamina yang mengenakan biaya sewa pipa (toll fee) sebesar US$ 2,53 per Mscf. Total biaya regasifikasi dan toll fee pipa transmisi saja sudah US$ 4,09 per MMBtu. Oleh karena itu harga gas menjadi lebih dari US$ 10 per MMBtu begitu sampai di PLTGU Belawan.

PLN masih bernegosiasi dengan Pertagas agar anak usaha Pertamina itu bersedia memangkas ongkos regasifikasi di Terminal LNG Arun dan toll fee pipa Arun-Belawan. Ke depan. PLN juga akan membutuhkan pasokan gas untuk PLTGU Sumatra bagian utara (Sumbagut) 800 megawatt (MW), PLTG Arun 184 MW, dan PLTG Arun Ekspansi 250 MW, PLTGU Sumbagut 800 MW yang memerlukan tambahan pasokan gas menambah aliran sekitar 80 MMscfd,

Jugi menambahkan, BPH Migas juga akan mengawal biaya sewa pipa yang ditetapkan oleh badan usaha di proyek pipa gas lainnya.

Bisnis Indonesia, Page-32, Thursday, August 31, 2017

ExxonMobil Stock Release Will Not Seamlessly

The transfer of 41.4% shareholding shares owned by PT ExxonMobil Cepu Limited in Jambaran-Tiung Biru Field will not go smoothly along with the adjustment of contracts that have been signed by the oil company from the United States.

President Director of PT Pertamina EP Cepu, a subsidiary of PT Pertamina, Adriansyah, said that ExxonMobil has indeed been cleared out of the gas field project located in Bojonegoro, East Java. However, the takeover of shares of ExxonMobil's participation by Pertamina will not be easy.

In addition to the issue of stock price calculation, Pertamina EP Cepu (PEPC) needs to make adjustments to gas drilling plans. In addition, many contracts and tenders signed by Exxon need to be re-adjusted. According to him, not necessarily the tender value agreed by ExxonMobil is also suitable for PEPC. Therefore, there needs to be a recalculation of project tenders.

"The plan of six wells, three Exxon, our three [PEPC]. At the beginning it should be Exxon who drilled a gas well, so the preparation is on Exxon all. When it is taken over, it must be transferred to all of us. This needs to be a [replacement] contract renovation, "he said Monday (28/8).

Adriansyah added that the gas sale and purchase agreement (PJBG) from Jambaran-Tiung Biru, Cepu Block could not be done before the share transfer of the participation was completed.

The Jambaran-Tiung Biru field is planned to produce 330 million cubic feet per day (MMscfd) gas with a gas that can be channeled at 172 MMscfd with 100 MMscfd to be absorbed by PLN and 72 MMscfd absorbed by the industry.

The project, which is projected to begin operation in 2020, is a merger of two fields from two different working areas (oil and gas blocks). The Jambaran field is part of the Cepu Block, while the Tiung Biru Field is part of Pertamina EP's working area. 

 With the reason the project is not economically sound, ExxonMobil decided to resign as a partner. Even so, he mentioned that the other partner, namely Regional Owned Enterprises (BUMD) is still committed to continue the partnership in the project.

In Cepu Block, ExxonMobil Cepu Limited (EMCL) becomes operator and controls 20.5% participation share, Ampolex 24.5%, Pertamina EP Cepu 45% and some 10% BUMD.

Meanwhile, in the project, PEPC is an operator and with EMCL each has 41.4% of the management rights. BUMD has 9.2% and the remaining 8% is controlled by Pertamina EP.

The government commissioned PT Pertamina through PEPC with the issuance of Letter of the Minister of Energy and Mineral Resources No. 9/13 / MEMM / 2017 in January 2017 to develop the Jambaran-Tiung Biru Field and complete the discussion with ExxonMobil through a business scheme.

IN INDONESIA

Pelepasan Saham ExxonMobil Tidak Akan Mulus

Pengalihan saham partisipasi 41,4% milik PT ExxonMobil Cepu Limited di Lapangan Jambaran-Tiung Biru tidak akan berjalan mulus seiring dengan penyesuaian kontrak-kontrak yang telah diteken oleh perusahaan minyak asal Amerika Serikat tersebut.

Direktur Utama PT Pertamina EP Cepu, anak perusahaan PT Pertamina, Adriansyah mengatakan bahwa ExxonMobil memang sudah dipastikan akan keluar dari proyek lapangan gas yang berlokasi di Bojonegoro, Jawa Timur, tersebut. Namun, pengambil-alihan saham partisipasi ExxonMobil oleh Pertamina tidak akan mudah.

Selain masalah penghitungan harga saham, Pertamina EP Cepu (PEPC) perlu melakukan penyesuaian rencana pengeboran sumur gas. Selain itu, banyak kontrak dan tender yang diteken oleh Exxon yang perlu disesuaikan kembali. Menurutnya, belum tentu nilai tender yang disepakati oleh ExxonMobil juga cocok untuk PEPC. Oleh karena itu, perlu ada penghitungan ulang terhadap tender-tender proyek.

“Rencananya enam sumur, tiga Exxon, tiga kita [PEPC]. Di awal mestinya Exxon yang mengebor sumur gas, jadi persiapannya ada pada Exxon semua. Ketika diambil alih, ini mesti dialihkan kepada kita semua. lni perlu novasi [penggantian] kontrak," ujarnya Senin (28/8).

Adriansyah menambahkan bahwa perjanjian jual beli gas (PJBG) dari Jambaran-Tiung Biru, Blok Cepu pun belum bisa dilakukan sebelum pengalihan saham panisipasi tersebut selesai.

Lapangan Jambaran-Tiung Biru rencananya memproduksikan gas sebesar 330 juta kaki kubik per hari (MMscfd) dengan gas yang bisa disalurkan sebesar 172 MMscfd dengan 100 MMscfd akan diserap PLN dan 72 MMscfd diserap industri.

Proyek yang diproyeksikan mulai beroperasi pada 2020 itu merupakan penggabungan dua lapangan dari dua Wilayah kerja (blok migas) berbeda. Lapangan Jambaran merupakan bagian dari Blok Cepu, sedangkan Lapangan Tiung Biru yang menjadi bagian dari wilayah kerja Pertamina EP. 

   Dengan alasan proyeknya tidak sesuai keekonomian, ExxonMobil memutuskan untuk mengundurkan diri sebagai mitra. Meski begitu, dia menyebut bahwa mitra lainnya, yakni Badan Usaha Milik Daerah (BUMD) masih berkomitmen melanjutkan kemitraan dalam proyek.

Pada Blok Cepu, ExxonMobil Cepu Limited (EMCL) menjadi operator dan menguasai saham partisipasi sebesar 20,5 %, Ampolex 24,5%, Pertamina EP Cepu 45% dan beberapa BUMD 10%.

Sementara itu, dalam proyek itu, PEPC menjadi operator dan bersama EMCL masing-masing memiliki 41,4% hak kelola. BUMD memiliki 9,2% dan sisanya sebanyak 8% dikuasai Pertamina EP.

Pemerintah menugaskan PT Pertamina melalui PEPC dengan terbitnya Surat Menteri ESDM No 9/ 13/MEMM/2017 pada Januari

2017 untuk mengembangkan Lapangan Jambaran-Tiung Biru dan menyelesaikan pembahasan dengan ExxonMobil melalui skema bisnis.

Bisnis Indonesia, Page-32, Wednesday, August 30, 2017

Pertamina Want to Sign Tiung Biru

PT Pertamina and PT Perusahaan Listrik Negara (PLN) have signed a head of agreement (HOA) gas supply Jambaran Tiung Biru, August 8, 2017 and then at the Office of the Ministry of Energy and Mineral Resources (ESDM). However, until now the agreement gas sale and purchase has not been signed.

Pertamina EP President Director Cepu Adriansyah disclosed that the gas sale and purchase agreement for Tiung Biru Field can be signed as long as the process of releasing the participating interest right of participating interest of Exxon is completed. Understandably, only Pertamina EP Cepu approved the sale price of Tiung Biru gas to PLN.

According to Adriansyah, if to sign the agreement, it means for all gas. Whereas in Tiung Biru there is still Exxon.

"If I sign but Exxon has not finished B to B (business to business), we must supply, for example until 2020 must supply 172 mmscfd, new commitment from Cepu, while Exxon is only part, we can not" Adriansyah.

Even so he is optimistic, in the next two months signed a gas sale and purchase agreement with PLN. Currently Pertamina is still conducting business to business (B to B) talks with Exxon for all rights to participation of Tiung Biru bia owned by Pertamina.

Discussion is still related to Exxon's participation price valuation of 41.4% in Tiung Biru and the takeover of drilling plans.

 "We have six wells, three Exxons and three of us." In the beginning, Exxon should be drilled, so its preparation adds to Exxon all, and when it's taken over, it should be shifted to all of us, it needs a contract renovation, it needs to be discussed first.

In addition, with the current investment value of Tiung Biru changing, Pertamina EP Cepu needs to evaluate Exxon's contracts. If there is an overpriced contract, Pertamina will renegotiate the contract and even re-tender.

According to him, it needs to be seen again all. "There is a match, some are not, some are too expensive, if we think we renegotiate or we re-tender, if the re-tender we count the time because next year start drilling should be," explained Adriansyah. Pertamina EP Cepu is scheduling the drilling of two wells by the middle of next year and September 2018.

IN INDONESIA

Pertamina Ingin Meneken Tiung Biru

PT Pertamina dan PT Perusahaan Listrik Negara (PLN) telah melakukan penandatangan head of agreement (HOA) pasokan gas Jambaran Tiung Biru, 8 Agustus 2017 lalu di Kantor Kementerian Energi dan Sumber Daya Mineral (ESDM). Namun, hingga kini perjanjian jual beli gas belum diteken. 

Direktur Utama Pertamina EP Cepu Adriansyah mengungkapkan, perjanjian jual beli gas untuk Lapangan Tiung Biru bisa diteken asalkan proses melepas hak partisipasi alias participating interest Exxon selesai. Maklum, hanya Pertamina EP Cepu yang menyetujui harga jual gas Tiung Biru ke PLN.

Menurut Adriansyah, jika sampai menandatangani perjanjian, artinya untuk semua gas. Padahal di Tiung Biru ini masih ada Exxon. 

"Kalau saya tanda-tangan tapi Exxon belum kelar B to B (business to business)-nya, kami wajib pasok. Misalnya sampai tahun 2020 wajib supplai 172 mmscfd. Komitmen baru dari Cepu, sementara Exxon baru sebagian, kami belum bisa," jelas Adriansyah.

Biarpun begitu ia optimistis, dalam dua bulan ke depan menandatangani perjanjian jual beli gas dengan PLN. Saat ini Pertamina masih melakukan pembicaraan business to business (B to B) dengan Exxon agar seluruh hak partisipasi Tiung Biru bia dimiliki Pertamina.

Pembicaraan masih terkait valuasi harga hak partisipasi Exxon sebesar 41,4% di Tiung Biru dan pengambilalihan rencana pengeboran.

 "Rencananya enam sumur, tiga Exxon dan tiga kami. Di awal mestinya Exxon yang mengebor, jadi persiapannya add pada Exxon semua. Ketika diambil-alih, ini mesti dialihkan ke kami semua, ini perlu novasi kontrak, ini perlu dibicarakan dulu," katanya.

Selain itu, dengan nilai investasi Tiung Biru saat ini berubah, Pertamina EP Cepu perlu mengevaluasi kontrak-kontrak Exxon. Jika ada kontrak terlalu mahal, Pertamina akan melakukan renegosiasi kontrak bahkan melakukan tender ulang.

Menurutnya, hal itu perlu dilihat lagi semua. "Ada yang cocok, ada yang tidak, ada yang terlalu mahal, kalau menurut kami renegosiasi lagi atau kami tender ulang. Kalau tender ulang kami hitung waktunya karena tahun depan mulai pengeboran seharusnya," jelas Adriansyah. Pertamina EP Cepu menjadwalkan pemboran dua sumur pada pertengahan tahun depan dan September 2018.

Kontan, Page-18, Wednesday, August 30, 2017

Pertamina’s refinery projects on track

Despite it mounting financial burdens, state-owned energy firm Pertamina is going a.head with its refinery projects in line with its goal to increase its refined oil production capacity in the long term.

The firm has suffered financially from selling gasoline and diesel fuel at economically infeasible prices since last April, in line with the governments instructions to maintain affordability nationwide.

In the first half of this year, the firm’s total liabilities rose slightly by 1.07 percent year-on-year (yoy) to US$26.3 billion, while its net profits fell steeply by 23.65 percent to nearly $1.4 billion.

In spite of these woes, Pertamina is set to soon formulate the engineering package for the upgrade of the Cilacap refinery in Central Java and the development of a new refinery in Tuban, East Java, after all parties have agreed on joint marketing efforts.

It will join hands with Saudi Arabian oil giant Saudi Aramco in a $5.8 billion project to boost the production capacity at Cilacap by 14.94 percent to 400,000 barrels of oil per day (bopd) by 2023. Separately it will also team up with Russia’s Rosneft Oil Company in a $15 billion project to construct the Tuban refinery with a capacity of 300,000 bopd once it begins operations in 2024.

Pertamina petrochemical and processing megaprojects director Ardhy N. Mokobombang said on Monday that it had completed the bankability and feasibility studies for both projects. Nonetheless, the firm still had to discuss with Aramco about the transfer of Pertamina’s assets to the future joint venture (JV) established by both parties, locally known as irzbreng.

“We hope that Pertamina and Aramco can reach an agreement on this inbreng process in conjunction with the completion ofthe engineering package,” Ardhy said, referring to the basic engineering design (BED), front-end engineering design (FEED) and detailed engineering design (DED). Both firms will conduct engineering designs prior to the JV foundation.

Pertamina, meanwhile, will first establish a JV with Rosneft for the Tuban refinery project, followed by preparation and implementation of the engineering project. When this is complete, the two firms will settle the final investment decision (FID) and start the construction process.

“We are still in the process of establishing the JV company. We will initially set up PT Kilang Pertamina Internasional [KPl], which will become the holding company for the JV between Pertamina and Rosneft,” Ardhy said. 

Pertamina, the majority share holder with 55 percent stake in both Cilacap and Tuban projects, was previously the sole off-taker for products of those refineries. However, this position will make all debts from these projects consolidated to Pertamina alone, resulting in an increase in its debt covenant. Therefore, it has proposed readjustments for them, through which the off-take agreement will be in line with the share portion of each party involved.

On Aug. 16, Pertamina finance director Arief Budiman said the renegotiation processes regarding the off-take deal was 95 percent ready and would soon be legally complete.

Pertamina plans to upgrade four existing refineries and build two new facilities, as it aims to raise its refined oil production output to 2.6 million bopd by 2030. At present, Indonesia’s refineries are only capable of producing around 830,000 bopd, a little over half of the current refined-fuel demand. 

In another development, the company is also seeking to upgrade its jetty and crude tanks in Sorong, West Papua, in order to optimize the production capacity of its Kasim refinery in the region. The Kasim facility has a fully installed capacity of 10,000 bopd, but only produces around 6,000 bopd because of a lackof crude supply from surrounding oil fields.

The output falls short ofthe overall demand in Papua and neighboring provinces West Papua and Maluku that totals 24,000 bopd.

“Hence, to optimize the production capacity of the Kasim refinery to 10,000 bopd, we will upgrade our jetty and crude tanks in Sorong so that they will be able to store 400,000 barrels of oil compared to only 17,000 barrels of oil at this moment,” Pertamina processing director Toharso said.

A crude tanker with a capacity of 200,000 barrels of oil, sourced from Cepu, Central Java, would call at Sorong once every week or two and the fuel, he added.

Jakarta Post, Page-17, Tuesday, August 29, 2017