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

The Availability of Goods Became Obstacles

The availability of local goods and services is still an obstacle for upstream oil and gas business actors in applying Domestic Component Level or TKDN 

Marjolijn Wajong, Executive Director of Indonesian Petroleum Association (IPA), said that the cooperation contract contractor (KKKS) will strive to fulfill the obligation to use local components. However, the implementation of TKDN can not be done optimally because constrained aspects of availability.

Goods or services that meet the needs of operations, quality, delivery times and prices derived from local vendors are sometimes limited in availability.

"The current challenge is the availability of domestically produced goods and services in accordance with the quality of upstream oil and gas operations and domestic goods provider's capacity," her said.

According to him, for the components that can not be met local vendors, the government is still open the discussion room so that operations are not hampered. There is a concept change from prioritizing to being required in relation to the use of local products that are governed by the Work Order Manual (TOD) 007 Revision 04.

Based on data from the Ministry of Energy and Mineral Resources up to the end of the first semester of 2017, and total upstream oil and gas procurement reached US $ 5.28 billion or around Rp 44.25 trillion, TKDN commitment reached 58.94% or around Rp 22.95 trillion.

Although the achievement of TKDN touches 50%, some goods and services still require supply and outside. For this type of goods, TKDN low grade drilling pipes estimated to reach only 25%. In addition, underwater pumps and machinery and equipment with a target performance of 30% to 2020.

Local content of seismic survey services and marine geologic studies is targeted to reach only 25% by 2020. In the meantime, marine drilling services and front end engineering design (FEED) in the sea are targeted to reach only 45% until 2020.

"However, discussions with the government are still open to some commodities that according to the standard needs of oil and gas operations can not be met by domestic production, so import channels are still possible," he said.

In revision of PTK Procurement also stipulated that for transactions below Rp 10 billion must be followed by originating vendors and related operating areas to provide multiple effects to the region.

IN INDONESIA

Ketersediaan Barang Jadi Hambatan

Ketersediaan barang dan jasa lokal masih menjadi hambatan pelaku usaha hulu minyak dan gas bumi dalam menerapkan kewajiban tingkat komponen dalam negeri atau TKDN. 

Direktur Eksekutif Indonesian Petroleum Association (IPA) Marjolijn Wajong mengatakan, kontraktor kontrak kerja sama (KKKS) akan berupaya untuk memenuhi kewajiban penggunaan komponen lokal. Namun, penerapan TKDN belum bisa dilakukan secara optimum karena terkendala aspek ketersediaan.

Barang atau jasa yang sesuai dengan kebutuhan operasi, kualitas, waktu penyerahan dan harga yang berasal dari vendor lokal terkadang masih terbatas ketersediaannya. 

“Tantangan saat ini adalah ketersediaan barang dan jasa produksi dalam negeri yang sesuai dengan kualitas standar operasi hulu migas dan kapasitas produksi penyedia barang dalam negeri," ujarnya 

Menurutnya, untuk komponen yang belum bisa dipenuhi vendor lokal, pemerintah masih membuka ruang diskusi agar kegiatan operasi tidak terhambat. Ada perubahan konsep dari mengutamakan menjadi diwajibkan terkait dengan penggunaan produk lokal yang diatur dalam Pedoman Tata Kerja (PTK) 007 Revisi 04.

Berdasarkan data Kementerian ESDM sampai dengan akhir semester I/2017, dan total pengadaan hulu migas yang mencapai US$5,28 miliar atau sekitar Rp44,25 trliun, komitmen TKDN mencapai 58,94% atau sekitar Rp 22,95 triliun.

Meskipun capaian TKDN menyentuh 50%, beberapa barang dan jasa masih memerlukan pasokan dan luar. Untuk jenis barang, TKDN pipa pengeboran low grade yang diestimasi hanya tercapai 25%. Selain itu, pompa bawah laut dan mesin dan peralatan dengan target capaian 30% hingga 2020.

Kandungan lokal jasa survei seismik dan studi geologi laut targetnya hanya bisa tercapai 25% hingga 2020. Sementara itu, jasa pengeboran di laut dan jasa pendefinisian proyek (front end engineering design/FEED) di Iaut ditarget hanya bisa tercapai 45% sampai 2020.

“Namun diskusi dengan pemerintah masih terbuka untuk beberapa komoditas yang menurut standar kebutuhan operasi migas belum dapat dipenuhi oleh produksi dalam negeri maka jalur impor masih dimungkinkan," katanya.

Dalam revisi PTK Pengadaan pun diatur bahwa untuk transaksi di bawah Rp 10 miliar harus diikuti vendor yang berasal dan daerah operasi terkait untuk memberikan efek berganda kepada daerah.

Bisnis Indonesia, Page-32, Tuesday, August 8, 2017

Changing Gas Prices

Gas prices are one of the most crucial points when oil prices fall, but domestic gas prices are unaffected. Gas prices remain high and complained by consumers. In fact, it is a consequence that must be borne because in the few years back when the high oil prices gas prices in the country it remains low.

Especially for the price of gas power plants, the government wants the cost of electricity production is low, but can absorb the gas with the optimum. The government issued a regulation on gas price limits of power plants in January 2017.

Not long ago with the liquefied natural gas (LNG) fomlula at the departure jetty of 11.5% of the Indonesian crude price (ICP), the government issued a new formula recently.

Through Regulation of Minister of Energy and Mineral Resources No.45 / 2017 which replaces the Regulation of Minister of Energy and Mineral Resources No. 11/2017 on Utilization of Natural Gas for Government Plant to re-tune the gas pricing formula. From the original 11.5% of ICP to LNG at the departure dock, the government now regulates the price of piped gas at the maximum power plant that PT State Electricity Company can purchase and private power developers at 14.5% of ICP.

The reason for the change, the 11.5% formula is considered too high for PLN and independent power producer (IPP). The reason is, this price does not include the cost of LNG transportation, regasification, and the cost of channeling gas through the pipeline. PLN and IPP can also use LNG if they have access or have plans to build their own LNG receiving terminal.

LNG price in the hands of konsmnen that can be purchased that is under gas pipe supply. In addition, if the import LNG price is equal to the domestic LNG price, the developer must purchase domestic LNG. LNG that requires a longer process to be used in a power plant actually gets the same formula as a pipe gas that only needs a process of delivery through the pipeline.

Simple logic, if the gas price at the mouth of the well is only 8% of ICP, and the gas pipe at the plant gate of 14.5% should be the LNG formula is higher because the process is longer than the other two options.

Director of Fuel Oil and Gas PLN Chairman Rachmatullah said, for the provision of gas generating the next, after the existence of this rule, the use of LNG will be more difficult. Because the four existing LNG receiving terminals are not yet operating efficiently, so the cost of regasification is high.

Thus, it is difficult to use LNG with a 14.5% formula from ICP which has included regasification cost factor as well as distribution to plant gate. Four regasification facilities currently in operation are in Benoa, Bali (PT

(Java Gas Company) with capacity of 240 MMscfd, Arun, Aceh (PT Pertamina Gas) and in West Java (owned by Nusantara Regas) with capacity of 400 MMscfd .

"If the LNG is heavy, because the four terminals currently operating are still inefficient, expensive because it is built when the market in the ship industry again as high as possible" he said.

He considered that the use of piped gas would be more easily realized because it does not require a process along the LNG to be used in the plant. In addition, he said, there is a space of negotiations that can make the selling price of gas to the plant lower than the formula set by the government.

"If gas pipes, hopefully under it. There's a negotiating room. "

HARD TO APPLY

Chairman of the Association of Indonesian Private Electric Manufacturers (APISI) Ali Herman Ibrahim said, seen and availability, the domestic does have the ability to supply gas needs generator. However, the price of gas pipelines and LNG already high so that will complicate the producers and traders of gas because the power sector does not have the ability to absorb the gas following the formula set by the government.

"So the rules are troublesome to follow the manufacturers or gas traders. Gas exists, but the price is high. "

Senior Expert of Gas & Power Wood Mackenzie Edi Saputra said gas pipes can not be the mainstay to supply the plant. The reason, new large-capacity gas projects have shifted to a place further away from the market. Therefore, the role of domestic LNG will be very crucial to meet the needs of the plant.

From Wood Mackenzie's data, in 2030 more than 60% of the electricity sector gas demand is expected to be met and LNG. According to him, the government has learned from the previous rule that the formula set is too low. In terms of the LNG price index on oil prices, he said the government has raised its index from 11.5% to 14.5% from ICP.

However, the price setting scheme is not without flaws. According to Edi, there will be upstream projects that can not be included in the established criteria. For example, he said, projects such as the Indonesian Deepwater Development (IDD) and the Masela Block would not be able to produce LNG at prices that follow government limits.

"Price ceiling is not ideal, there will be no chance of upstream projects with government limits such as the Abadi Field Project and IDD, it is difficult to meet the price ceiling, let alone the reference at the plant gate in the hands of consumers]."

The government needs to test other schemes with gas procurement auctions in a transparent and competitive manner. Thus, the gas producers will compete for the gas supply to be purchased by the power plant.

"The government needs to evaluate a more transparent and competitive mechanism compared to the price set.In terms of this year's target, domestic LNG production touched 278 cargoes, consisting of 163 cargoes coming from Bontang LNG Plant and 115 cargoes from the Tangguh Refinery If the LNG price formula is too low , Many gas sales contracts were canceled, gas field projects were not developed or abandoned by investors.

IN INDONESIA

Utak-Atik Harga Gas

Harga gas menjadi salah satu poin yang Krusial terutama pada saat harga minyak turun, tetapi harga gas di dalam negeri tidak terpengaruh. Harga gas tetap tinggi dan dikeluhkan oleh konsumen. Padahal, hal itu merupakan konsekuensi yang harus ditanggung karena dalam beberapa tahun ke belakang ketika harga minyak tinggi harga gas di dalam negeri justru tetap rendah.

Khusus untuk harga gas pembangkit listrik, pemerintah menginginkan agar biaya pokok produksi listrik rendah, tetapi bisa menyerap gas dengan optimum. Pemerintah mengeluarkan aturan tentang batas harga gas pembangkit pada Januari 2017.

    Belum lama bertahan dengan fomlula harga gas alam cair (liquefied natural gas/LNG) di dermaga keberangkatan 11,5% dari harga minyak mentah Indonesia (Indonesian crude price/ICP), pemerintah menerbitkan formula baru belum lama ini.

Melalui Peraturan Menteri ESDM No.45/2017 yang menggantikan Peraturan Menteri ESDM No. 11/2017 tentang Pemanfaatan Gas Bumi untuk Pembangkit pemerintah mengutak-atik ulang formula harga gas pembangkit. Dari semula 11,5% dari ICP untuk LNG di dermaga keberangkatan, kini pemerintah mengatur harga gas pipa di pembangkit maksimum yang bisa dibeli PT Perusahaan Listrik Negara dan pengembang listrik swasta sebesar 14,5% dari ICP.

Alasan perubahan itu, formula 11,5% dianggap masih terlalu tinggi bagi PLN dan pengembang listrik swasta (independent power producer/IPP). Pasalnya, harga ini belum mencakup biaya transportasi LNG, regasifikasi, dan biaya penyaluran gas melalui pipa. PLN dan IPP pun bisa menggunakan LNG bila memiliki akses atau memiliki rencana untuk membangun terminal penerimaan LNG sendiri. 

Harga LNG di tangan konsmnen yang bisa dibeli yakni di bawah penawaran gas pipa. Selain itu, bila harga LNG impor sama dengan harga LNG domestik, pengembang wajib membeli LNG domestik. LNG yang memerlukan proses lebih panjang untuk bisa digunakan di pembangkit listrik justru mendapat formula yang sama dengan gas pipa yang hanya membutuhkan proses penghantaran melalui pipa. 

Logika sederhananya, bila harga gas di mulut sumur hanya 8% dari ICP, dan gas pipa di plant gate 14,5% seharusnya formula LNG lebih tinggi karena proses yang dilalui lebih panjang dari dua opsi lainnya.

Direktur Bahan Bakar Minyak dan Gas PLN Chairani Rachmatullah mengatakan, untuk penyediaan gas pembangkit berikutnya, setelah adanya aturan ini, penggunaan LNG akan semakin sulit. Pasalnya, empat terminal penerimaan LNG yang sekarang ada saat ini belum beroperasi secara efisien sehingga biaya regasifikasi tinggi.

Dengan demikian, sulit untuk menggunakan LNG dengan formula 14,5% dari ICP yang sudah memasukkan faktor biaya regasifikasi juga distribusi ke plant gate. Empat fasilitas regasifikasi yang saat ini beroperasi yakni di Benoa, Bali (PT Pembangkitan Jawa Bali) berkapasitas 50 juta kaki kubik per hari (MMscfd), di Lampung (PT Perusahaan Gas Negara Tbk.) berkapasitas 240 MMscfd, Arun, Aceh (PT Pertamina Gas) serta di Jawa Barat (milik Nusantara Regas) dengan kapasitas 400 MMscfd. 

"Kalau LNG berat, karena empat terminal-terminal yang saat ini operasi masih belum efisien, mahal karena dibangun saat market di industri kapal lagi setinggi-tingginya" ujarnya.

Dia menilai bahwa penggunaan gas pipa akan lebih mudah direalisasikan karena tidak memerlukan proses sepanjang LNG untuk bisa digunakan di pembangkit. Selain itu, dia menyebut, terdapat ruang negosiasi yang bisa membuat harga jual gas ke pembangkit lebih rendah dari formula yang ditetapkan pemerintah. 

“Kalau gas pipa, semoga bisa di bawahnya. Ada ruang negosiasi."

SULIT DITERAPKAN 

Ketua Asosiasi Produsen Listrik Swasta Indonesia (APISI) Ali Herman Ibrahim mengatakan, dilihat dan ketersediaannya, domestik memang memiliki kemampuan untuk menyuplai kebutuhan gas pembangkit. Namun, harga gas pipa dan LNG sudah terlanjur tinggi sehingga akan menyulitkan produsen dan pedagang gas karena sektor ketenagalistrikan tidak memiliki kemampuan untuk menyerap gas mengikuti formula yang ditetapkan pemerintah.

“Jadi aturan tersebut repot untuk di ikuti produsen atau trader gas. Gas ada, tetapi harga terlanjur tinggi." 

Senior Expert Gas & Power Wood Mackenzie Edi Saputra mengatakan, gas pipa tidak bisa dijadikan andalan utama untuk menyuplai pembangkit. Pasalnya, proyek-proyek gas baru yang berkapasitas besar telah bergeser ke tempat yang semakin jauh dari pasar. Oleh karena itu, peran LNG domestik akan sangat krusial untuk memenuhi kebutuhan pembangkit.

Dari data Wood Mackenzie, pada 2030 lebih dari 60% kebutuhan gas sektor ketenagalistrikan diperkirakan akan dipenuhi dan LNG. Menurutnya, pemerintah telah belajar dari aturan sebelumnya bahwa formula yang ditetapkan terlalu rendah. Dari segi indeks harga LNG terhadap harga minyak, dia menyebut pemerintah telah menaikkan indeksnya dari 11,5% menjadi 14,5% dari ICP

Namun, skema penetapan batas harga bukanlah tanpa kekurangan. Menurut Edi, akan tetap ada proyek-proyek di hulu yang tidak bisa masuk dalam kriteria yang ditetapkan. Sebagai contoh, dia menuturkan, proyek-proyek seperti Indonesian Deepwater Development (IDD) dan Blok Masela tidak akan bisa menghasilkan LNG dengan harga yang mengikuti batasan pemerintah.

"Price ceiling [harga atas] itu tidak ideal. Masih akan ada peluang proyek-proyek di hulu tidak masuk dengan batas yang ditetapkan pemerintah seperti Proyek Lapangan Abadi dan IDD. Sulit memenuhi price ceiling tersebut apalagi acuannya di plant gate ditangan konsumen]."

Pemerintah perlu menguji skema lainnya dengan lelang pengadaan gas dengan cara yang transparan dan kompetitif. Dengan demikian pada produsen gas akan berkompetisi agar pasokan gasnya bisa dibeli pembangkit listrik.

"Pemerintah perlu mengevaluasi mekanisme yang lebih transparan dan kompetitif dibandingkan dengan menetapkan price. Dari sisi target tahun ini, produksi LNG domestik menyentuh 278 kargo, terdiri dari 163 kargo berasal dari Kilang LNG Bontang dan 115 kargo dari Kilang Tangguh. Bila formula harga LNG terlalu rendah, banyak kontrak jual beli gas batal ditandatangani, proyek-proyek lapangan gas tidak dikembangkan atau ditinggalkan para investor.

Bisnis Indonesia, Page-34, Monday, August 7, 2017

PGN Sales Stagnant Regulation

The fate of gas business of PT Perusahaan Gas Negara (PGN) will slow down. It is predicted that the margin of issuers coded in PGAS stock in Indonesia Stock Exchange (IDX) will continue to shrink because of stumbling blocking rules.

An example is the Presidential Regulation (PP) No 44/2017 on the Determination of Natural Gas Prices. The beleid called on the industry to lower gas prices by a benchmark of US $ 6 per million metric british thermal unit (mmbtu). However, the decline in gas prices was not accompanied by the increase in the tariff for gas transportation or toll fee.

Economics and Energy Observer from Gajah Mada University (UGM) Fahmi Radhi said PGN's business is gas trading and pipeline leasing for downstream gas distribution and final consumers. If PGN's toll fee is still above the cost of production (HPP), PGN still obtains margin from pipeline leasing. However, if the price is set below the HPP, PGN will incur a loss from the Pipeline leasing business sector.

"HPP pipe leasing is calculated from the average operational cost plus the depreciation of investment costs.The setting of the toll fee by the government smaller than the HPP will harm and eliminate the margin of PGN," explained Fahmi

Just so you know, in the financial statements, earnings PGN first quarter of 2017 is decreased compared to the same period last year. In the first quarter of 2016, PGN's profit was still at US $ 100.65 million, while the first quarter-2017 was US $ 96.8 million. During the period of January-March 2017, PGAS distributed 1,542 million standard cubic feet per day (mmscfd) of natural gas. This realization decreased compared to the same period last year, amounting to 1,643 mmscfd.

Fahmi said in the business, the government's decision is not fair. Because the price upstream is raised. On the other hand, PGN should not raise gas prices.

"The unfair market distortion is very real disadvantage for PGN's business," said Fahmi.

PGN Corporate Secretary Rachmat Hutama said it will always follow government policies or decisions, including changes in the selling price of natural gas and Conoco-Phillips to PGN in Batam Region under the Batam I contract.

IN INDONESIA

Penjualan PGN Tersendat Regulasi

Nasib bisnis gas PT Perusahaan Gas Negara (PGN) akan melambat. Diprediksi ke depan margin emiten berkode saham PGAS di Bursa Efek Indonesia (BEI) ini akan terus menyusut lantaran tersandung aturan yang menghambat.

Contohnya adalah Peraturan Presiden (PP) No 44/2017 tentang Penetapan Harga Gas Bumi. Beleid tersebut meminta industri agar menurunkan harga gas dengan patokan US$ 6 per million metric british thermal unit (mmbtu). Namun, penurunan harga gas itu tidak dibarengi kenaikan tarif pengangkutan gas bumi atau toll fee.

Pengamat Ekonomi dan Energi dari Universitas Gajah Mada (UGM) Fahmi Radhi mengatakan, bisnis PGN adalah perdagangan gas dan penyewaan pipa untuk penyaluran gas ke hilir dan konsumen akhir. Bila toll fee PGN masih diatas harga pokok produksi (HPP), PGN masih memperoleh margin dari penyewaan pipa. Namun, apabila harga ditetapkan di bawah HPP, maka PGN akan mengalami kerugian dari Sektor usaha penyewaan pipa. 

"HPP penyewaan pipa diperhitungkan dari rata-rata biaya operasional ditambah depresiasi biaya investasi.  Penetapan toll fee oleh pemerintah yang lebih kecil dari HPP akan merugikan dan menghilangkan margin PGN," jelas Fahmi 

Asal tahu saja, dalam laporan keuangan, laba PGN kuartal I tahun 2017 ini menurun dibandingkan periode yang sama tahun lalu. Kuartal I 2016 laba PGN masih sebesar US$ 100,65 juta, sementara kuartal I-2017 US$ 96,8 juta. Selama periode Januari-Maret 2017, PGAS menyalurkan gas bumi sebanyak 1.542 million standard cubic feet per day (mmscfd). Realisasi ini menurun dibandingkan periode yang sama tahun lalu, sebesar 1,643 mmscfd.

Fahmi menilai dalam berbisnis, keputusan pemerintah itu tidak fair. Pasalnya, harga di hulu dinaikkan. Di sisi lain, PGN tidak boleh menaikkan harga gas. 

"Distorsi pasar yang tidak fair itu sangat nyata merugikan bagi usaha PGN," tegas Fahmi.

Sekretaris Perusahaan PGN, Rachmat Hutama mengatakan, pihaknya akan selalu mengikuti kebijakan atau keputusan pemerintah, termasuk mengenai perubahan harga jual gas bumi dan Conoco-Phillips kepada PGN di Wilayah Batam berdasarkan

kontrak Batam I.

Kontan, Page-18, Monday, August 7, 2017