Category Archives: PSC Terms

Gas Impor Bukan Solusi Untuk Persoalan Harga Gas Bumi

Sebagai tindak lanjut atas upaya pemerintah untuk menurunkan harga gas bagi pelaku industri dalam negeri, pemerintah khabarnya kini mewacanakan upaya untuk mengimpor gas dari Malaysia, Brunei, Timur Tengah atau negara-negara produsen gas lainnya. Pilihan untuk membuka keran gas impor yang ditengarai harga belinya lebih rendah diharapkan dapat memenuhi target yang dicanangkan oleh Presiden agar harga beli gas di titik industri dalam negeri dapat berada di kisaran $5 hingga $6 per mmbtu, atau bahkan lebih rendah lagi apabila memungkinkan. Saat ini, harga gas industri dalam negeri berada di kisaran rata-rata lebih dari $9 per mmbtu, bahkan di beberapa wilayah industri seperti Sumatera Utara mencapai hingga $13 per mmbtu. Tingginya harga gas industri membuat pelaku industri dalam negeri sulit bersaing dan beberapa di antaranya bahkan mengalami masalah kelangsungan usaha.

Rantai pasok gas dalam negeri memang terbilang panjang dan berbelit. Kompleksitas struktur pasokan dan kerumitan tata laksana membuat upaya pembenahan menjadi tidak mudah dan membutuhkan waktu. Produksi gas di sisi hulu migas mulai dari mulut sumur lapangan beserta fasilitas produksi berlanjut pada jalur transportasi atau transmisi utama berupa pipa primer, sebelum kemudian didistribusikan melalui jalur pipa sekunder kepada berbagai pembeli industri yang menggunakan gas sebagai bahan baku manufaktur ataupun sebagai energi pembangkit. Pelaku di sisi hulu migas umumnya hanya terdiri dari satu pihak yang mengoperasikan wilayah kerja hulu migas di bawah Kontrak Kerja Sama bagi hasil (KKS atau Production Sharing Contract), namun pelaku usaha transportasi dan distribusi gas jumlahnya dapat sangat banyak di mana gas dipindahtangankan berkali-kali sebelum akhirnya mencapai pembeli akhir. Harga gas secara keseluruhan tentunya bergantung pada tingkat keekonomian seluruh pelaku yang terlibat dalam rantai pasok mulai dari hulu hingga hilir.

Sebelum pemerintah mengeluarkan kebijakan untuk memperbolehkan masuknya gas impor, tentunya terlebih dahulu harus dilakukan kajian yang mendalam dengan penuh kehati-hatian agar keputusan yang diambil akhirnya memang akan mengatasi permasalahan tanpa menimbulkan permasalahan lain yang bahkan justru dapat memperburuk kondisi saat ini.

Impor gas pada kenyataannya harus dilakukan dalam bentuk Liquefied Natural Gas (LNG), tidak dalam bentuk gas bumi yang dikirimkan melalui pipa. Secara proses, LNG merupakan gas alam yang terlebih dahulu harus dicairkan (likuifaksi) untuk kemudian dikapalkan menggunakan tanker khusus LNG kepada terminal tujuan yang lalu melakukan regasifikasi untuk mengubah LNG kembali menjadi gas alam yang kemudian dapat didistribusikan melalui pipa kepada pengguna gas. Proses yang lebih panjang untuk likuifaksi, pengapalan, dan regasifikasi tentunya membuat produksi LNG menjadi relatif lebih membutuhkan biaya dibandingkan gas bumi biasa.

Harga pasar Spot LNG internasional di kawasan Asia Pasifik saat ini berkisar $6.10/mmbtu, sehingga alhasil setelah proses regasifikasi (sekitar $2/mmbtu), transmisi primer (asumsi $1/mmbtu) dan distribusi (kurang lebih $1/mmbtu) akan menghasilkan harga pada titik pembeli akhir tetap tinggi atau bahkan mungkin justru lebih tinggi dibandingkan harga gas domestik saat ini. Patut pula dicatat bahwa harga LNG di kawasan Asia Pasifik selalu dikaitkan dengan formula yang mengacu pada harga pasar minyak mentah, sehingga apabila harga minyak mentah naik maka dengan sendirinya harga LNG juga turut meningkat.

Produsen gas domestik di sektor hulu migas di bawah peraturan dan perundangan yang ada diharuskan memberikan prioritas untuk memenuhi kebutuhan gas dalam negeri terlebih dahulu sebelum diperbolehkan untuk melakukan ekspor gas. Dengan demikian, sudah sepatutnya bila pihak pembeli gas domestik juga sebaliknya memprioritaskan untuk membeli dari produsen gas dalam negeri. Gas impor justru mengurangi potensi pasar gas domestik Indonesia sendiri dan dikhawatirkan akan berdampak jangka panjang yang dapat melemahkan sektor hulu migas domestik akibat tidak adanya konsistensi regulasi, ketiadaan pasar, dan hilangnya minat investor untuk melakukan kegiatan eksplorasi hulu atau mengembangkan cadangan yang telah ditemukan.

Kebijakan pemerintah untuk memperbolehkan masuknya gas impor secara perekonomian makro akan sedikit banyak menguras cadangan devisa nasional yang pada dasarnya dapat turut memperlemah nilai tukar rupiah, sementara kebijakan yang lebih mendahulukan gas domestik tidak akan menggerus cadangan devisa negara dan dengan demikian tidak akan memperlemah nilai tukar rupiah.

Gas impor sama sekali tidak memberikan bagian negara dari Penerimaan Negara Bukan Pajak (PNBP) maupun penerimaan pajak di sisi hulu migas, melainkan justru memberikan penerimaan kepada negara lain. Sementara itu, gas domestik memberikan bagian negara berupa PNBP dan pajak berdasarkan Kontrak Kerja Sama hulu migas yang besarnya hingga 70% dari keuntungan di wilayah kerja hulu migas (30% sisanya merupakan bagian keuntungan untuk investor hulu migas). Bahkan kalaupun harga gas impor sedikit lebih murah sekalipun, secara agregat makro maka penerimaan negara justru dapat tetap akan berkurang dibandingkan apabila mengutamakan gas domestik.

Masuknya gas impor yang mengurangi pasar gas domestik tidak akan memberikan dampak berganda kepada sektor perekonomian hulu di dalam negeri yang diperoleh dari investasi hulu migas, dihasilkannya Dana Bagi Hasil (DBH) bagi Pemda di mana lapangan produksi gas berada yang sangat berperan bagi pembangunan daerah, terbukanya lapangan kerja, dan berbagai manfaat perekonomian lainnya. Seluruh dampak berganda tersebut pada akhirnya juga memberikan penerimaan negara dalam bentuk pajak dari sektor penunjang industri hulu migas, pajak pribadi individu karyawan hulu migas, dan sebagainya.

Jumlah kapasitas produksi gas alam dan LNG domestik yang saat ini belum terkontrak cukup besar, sehingga sepatutnya dapat diserap terlebih dahulu oleh pasar pembeli domestik. Sebagian dari kapasitas tersebut memang telah dialokasikan oleh Pemerintah untuk memenuhi kebutuhan gas dalam negeri dan dengan demikian tidak diperbolehkan untuk diekspor secara jangka panjang. Produsen hulu gas dan LNG dengan demikian telah sekian lama menunggu diserapnya kapasitas yang ada tersebut, sehingga penantian mereka akan sia-sia apabila kemudian justru gas impor yang digunakan untuk memenuhi kebutuhan gas dalam negeri. Kapasitas produksi gas domestik yang ada ini telah atau sedang dikembangkan dan pengembalian biaya (cost recovery) di hulu migas juga telah dikeluarkan untuk berbagai fasilitas produksi, infrastruktur dan pengolahan hulu, sehingga akan sangat mubazir dan sia-sia apabila kemudian menjadi tidak diserap dan Pemerintah justru memilih untuk melakukan impor gas.

Cadangan gas domestik yang telah ditemukan dan belum dikembangkan jumlahnya juga sangat besar, antara lain di lapangan Masela, lapangan IDD, Natuna, dan banyak lagi lapangan gas lainnya. Tidak sepenuhnya benar apabila dikatakan bahwa cadangan gas tersebut dapat dibiarkan menunggu di bawah tanah untuk generasi anak cucu kita mendatang, sekalipun apabila secara geologis hal tersebut bisa saja dilakukan. Cadangan gas tersebut ditemukan oleh investor hulu migas melalui kegiatan eksplorasi yg membutuhkan biaya investasi yang sangat besar dengan tingkat resiko yg tinggi. Apabila kemudian cadangan yg telah ditemukan tersebut ditunda pengembangannya menunggu sekian lama karena justru mendahulukan gas impor, maka masa kontrak wilayah kerja hulu migas akan terus berkurang tanpa adanya kepastian perpanjangan masa kontrak. Keekonomian investor hulu dengan demikian akan terus tergerus dan akhirnya mereka akan dirugikan. Akibatnya, investor tidak akan lagi berminat masuk ke Indonesia untuk melakukan kegiatan eksplorasi menemukan cadangan baru. Industri hulu migas secara jangka panjang akibatnya akan terus melemah.

Tidak tepat juga apabila dikatakan bahwa gas dan LNG domestik dapat diekspor saja ke negara lain sementara kebutuhan domestik justru dapat menggunakan gas impor. Harga LNG impor dan ekspor secara praktis adalah sama karena berdasarkan harga pasar komoditas yang mengikuti mekanisme pasar saat ini, sehingga tidak dapat dipastikan akan diperoleh transaksi agregat yang secara netto bersifat positif. Ekspor gas juga tidak sejalan dengan konsep paradigma baru bahwa sumber energi nasional tidak lagi digunakan sebagai motor utama penghasil devisa ekspor namun kini justru lebih diutamakan sebagai penggerak pertumbuhan ekonomi nasional di dalam negeri. Ekspor gas sebaiknya memang hanya dilakukan apabila pasar domestik sudah tidak dapat menyerap baik dari sisi volume produksi atau dari sisi tata waktu. Terkadang, ekspor gas memang tidak terhindarkan untuk menjaga keekonomian proyek hulu migas saat harga gas ekspor lebih tinggi daripada harga pasar gas dalam negeri.

Patut juga dicermati bahwa apabila harga gas impor dari negara lain memang ternyata lebih murah daripada harga gas domestik, belum tentu hal tersebut disebabkan oleh faktor biaya produksi dan karakteristik lapangan gas yang lebih baik. Bisa jadi hal tersebut dikarenakan adanya perbedaan ketentuan kontrak dan kondisi fiskal sesuai dengan peraturan dan perundangan. Di Indonesia di bawah rezim kontrak kerja sama bagi hasil, investor hulu untuk lapangan gas harus menanggung investasi seluruh biaya kapital dan non kapital, namun hanya mendapat bagi hasil setelah PNBP dan pajak sebesar 30% hingga 40% dari total keuntungan yang dihasilkan oleh wilayah kerja hulu migas tersebut, sehingga secara keekonomian (NPV, IRR) menjadi lebih terbenani dibandingkan dengan negara lain yang menganut sistem kontrak royalti dimana bagian negara jauh lebih kecil. Mekanisme di bawah Peraturan Presiden No 40/2016 (mengenai harga gas untuk industri tertentu) sebenarnya sudah sangat baik, dimana untuk menurunkan harga gas di sisi hulu maka bagian pemerintah di sektor hulu dapat dikurangi tanpa mengurangi keekonomian investor. Pemerintah juga dapat membantu memperbaiki keekonomian proyek hulu migas dengan memberikan berbagai insentif fiskal dan non fiskal.

Jangka waktu yang dibutuhkan sejak masa eksplorasi, pembuktian besaran cadangan (appraisal), pra-pengembangan, dan konstruksi pengembangan lapangan migas di Indonesia juga sangat panjang, antara lain karena banyaknya masalah perizinan, persetujuan, pembebasan lahan, dan sebagainya. Lapangan gas Tangguh adalah contoh nyata dimana kontrak wilayah kerjanya mulai ditandatangani tahun 1987, penemuan cadangan pertama sekitar tahun 1993, pembuktian cadangan diselesaikan pada tahun 1997, keputusan investasi final (Final Investment Decisions, FID) tahun 2004, dan produksi pertama baru tahun 2009, yaitu 22 tahun sejak penandatanganan kontrak. Lapangan gas Masela tampaknya juga bernasib sama atau bahkan lebih lama, ditandatangani tahun 1998 dan diperkirakan baru akan berproduksi tahun 2025/2026, 28 tahun sejak penandatanganan kontrak. Proses yang berkepanjangan ini semua juga pada akhirnya menggerus keekonomian investor secara keseluruhan (full-cycle) yang berujung pada dibutuhkannya harga jual gas lebih tinggi untuk membuat proyek pengembangan dapat dilakukan secara komersial. Pemerintah dapat terus membantu mengatasi masalah ini dengan penyederhanaan proses perizinan, proses persetujuan dan peraturan perundangan yang lebih kondusif selain dengan cara memberikan insentif fiskal dan non fiskal.

Tidak sepenuhnya tepat apabila dikatakan bahwa biaya transportasi LNG menggunakan pengapalan dari Papua ke Aceh membutuhkan biaya besar. Biaya transportasi dari Papua hingga ke Aceh hanya berkisar $0.50-$0.70 per mmbtu, justru jauh lebih rendah daripada biaya transmisi dan distribusi pipa yang berjarak jauh lebih dekat di mana panjang pipa hanya beberapa kilometer saja. Transportasi LNG menggunakan pengapalan setelah gas dicairkan terbilang efisien, namun memang proses likuifaksi dan regasifikasi membutuhkan biaya tambahan ekstra. LNG dari lapangan gas Tangguh di Papua saat ini tidak digunakan untuk memenuhi kebutuhan gas industri di Sumatera Utara melainkan dikirimkan ke Aceh untuk proses regasifikasi dan kemudian dipipakan dari Lhokseumawe, Aceh, ke Belawan, Sumatera Utara untuk pembangkit listrik tenaga gas milik PLN di Belawan. Pertimbangan impor LNG dari Timur Tengah tidak akan mempersingkat jarak tempuh, mengingat Papua – Aceh tidak lebih jauh daripada Timur Tengah – Aceh.

Kiranya dapat disimpulkan bahwa rencana Pemerintah untuk membuka keran impor gas/LNG sebaiknya terlebih dahulu dikaji secara hati-hati, dikonsultasikan dengan pelaku industri hulu migas, dan tidak dilakukan secara terburu-buru sepanjang masih tersedia kapasitas gas/LNG domestik yang belum terserap dan sepanjang masih ada cadangan lapangan gas domestik yang belum dikembangkan.

Untuk mencoba menurunkan harga gas bumi bagi industri dalam negeri, langkah-langkah yang sejauh ini sudah mulai diambil oleh Pemerintah sesungguhnya telah baik dan tepat, sekalipun membutuhkan upaya yang besar dan waktu yang tidak singkat. Diterbitkannya Peraturan Presiden nomor 40/2016 beserta Peraturan Menteri untuk implementasinya, pembenahan sektor transportasi, transmisi dan distribusi gas dengan mengurangi transaksi berantai dan meniadakan margin laba yang tidak wajar, penghapusan perantara gas bumi yang tidak memiliki infrastruktur, dan perbaikan keekonomian hulu migas melalui pemberian fasilitas insentif fiskal maupun non fiskal seluruhnya diharapkan dapat menyeimbangkan rantai pasok gas bumi tanpa menimbulkan masalah jangka panjang bagi industri gas nasional dari titik paling hulu hingga titik paling hilir dan dari titik paling barat di Aceh hingga titik paling timur di Papua.

Shall I Revive This Site ?

All, I’ve been away from this site for a couple of years now. At one point in the past, this site was quite popular in the Indonesian oil & gas industry. So many things have changed since then within the industry. Would be great if we can start networking through this site again. Let me know if you think it’s worth reviving the site by indicating your support. Thanks a bunch !

Investment Credit – An Incentive Which Can Backfire As a Disincentive

Bit by bit, one by one, I would like to discuss in this Forum some of the basics of the Indonesian PSCs. By no way I have the intent to preach and teach the visitors of this site, I just want to give you different perspectives to the foundations of the terms and concepts in the Indonesian PSCs. Discussing recent issues and developments surrounding the industry is definitely important and “fun”, but discussing the basics should also be useful as from time to time we have to go to the basics to help iluminate or even resolve the current issues.
Without Incentives, It's Just A Phantom Platform in The Mist

Without Incentives, It's Just a phantom platform in the mist

 

In the past, I have given my in-depth perspectives on cost recovery and Domestic Market Obligation (DMO). In this article, I would like to discuss one of the most common incentives given in the Indonesian PSCs, the Investment Credit (IC).

The PSC has fixed terms on profit split for oil and for gas, well defined accounting terms, and likewise with the applicable corporate tax rates which is based on the prevailing tax regulation at the signing date of the PSC. Other variables to project economics such as petroleum reserves and prices are mostly given or environmental. The headroom left for improving project economics for the contractor is hence by granting special incentives. Without the incentives, some project may not be economic for the contractors to proceed with development which would only lead to stranded reserves generating no value to both parties. Special incentives shall be negotiated, agreed, and approved in advance along with POD approvals and project sanctioning.

Incentives are granted after careful consideration and evaluation. The discussions and negotiations can sometime be very tough as some of the variables are based on future assumptions of recoverable reserves, rates and timing of production volumes, costs, and prices which definitely most of the time are subjective. Disagreements happen all the time. It is true that once the project is complete and the field has been producing for a number of years, then when you’d look back you would probably realize that a previously agreed and applied incentive was probably insufficient to help project economics or on the other hand probably had not even been required at all given the other variables have all changed favorably.

There are several types of incentives usually granted for a development project. Investment credit is one of them, typically included in the PSC contract itself:

CONTRACTOR may recover an investment credit amounting to twenty seven point zero zero zero zero percent (27.0000%) of the capital investment cost directly required for developing Natural Gas production facilities of any field out of deduction from gross production before recovering Operating Costs, commencing in the earliest production Year or Years before tax deduction (to be paid in advance in such production Year when taken).

The applicability of investment credit for development of fields other than those fields which are referred in to the first plan of development shall be proposed by CONTRACTOR for approval by BPMIGAS based on the economics of such development. BPMIGAS shall not unreasonably withhold its approval to such investment credit.

The first clause is clear that IC is given at a certain rate (can vary from PSC to PSC, within the range of 17% to 27%) applicable to the development capital expenditures related to oil or gas production facilities (including the tangible portion of well costs). This means that IC is in reality an uplift to capital investments, on which you can essentially recover more than what you actually spend for development. This is similar to uplift on development cost recovery in PSAs in other countries such as Angola (50%), with a big difference on the tax implications (we will see that later below).

The other term related to IC is the fact that it should be claimed in the first year of production (or the first years of production, in the case that gross revenue after FTP in the first year is not sufficient to recover the whole amount of IC) before recovering operating costs, hence it should be applicable after FTP but before recovery of other cost recoveries (current year non capital costs, current year depreciation, and deferred unrecovered costs).

The unique (but very detrimental to contractor’s project economics) characteristics of IC is the fact that it’s recoverable but taxable at the same time when claimed/taken. This in truth significantly reduces the bottom-line uplift factor. For example, in a PSC where the profit split is 15% after tax and the tax rate is 48%, then the bottom line additional cashflow for the contractor is merely 37% of the amount of IC taken (52% from the gross IC after 48% tax, less the unfavorable impact on contractor’s profit share after tax of 15%). In a PSC where the profit split after tax is 40% (typical for gas in a frontier area), the bottom line additional cashflow for the contractor is so small at only 12% of the gross IC claim (52% from the gross IC after 48% tax, less the unfavorable impact on contractor’s profit share after tax of 40%).

Let’s see an example below where in one case there’s no IC granted as compared to another where $1,000 of IC is claimed under exactly the same variables of volume, price, and cost recovery. The profit split for the contractor before tax is 76.9% or 40% after tax rate of 48%.

As we can see, the bottom line impact on contractor’s cashflow is merely $120, which is 12% of the $1,000 gross IC claimed. Again, this is caused by the fact that IC has two implications: (1) it increases contractor’s recovery by $1,000, but taxable at 48% leaving us with only $520; (2) it reduces the gross profit to be split by $1,000 of which the contractor’s unfavorable share is negative 40% or negative $400 after tax.

The first example above is of course applicable only in the case when the first year production volume, price, IC, and cost recovery are all such that there’s enough left for profit share. In reality, a new and first project in a PSC always accumulates significant amount of deferred unrecovered costs being carried forward, causing the early years of production to have no equity to be split at all as the whole revenue left after FTP is consumed for cost recovery. In this situation, claiming IC in the first year (or years) of production will actually put the contractor in an unfavorable cashflow position for the year as total contractor’s entitlement volume would still be the same (the recovery of IC simply would only shift the recovery of deferred unrecovered costs to the following year) but the contractor then has to pay the taxes on IC immediately.

Let’s see the second example where typically the first years of production are solely used to recover deferred unrecovered costs.

The total favorable impact on the contractor’s cashflow is also $120, but the time lag between the two cashflow events is now 4 years apart. In the first year, cashflow with IC is lower by $480 which is caused by the 48% tax payments on the $1,000 IC claimed. Meanwhile, cashflow in the fourth year is higher by $600, caused by the delayed deferred unrecovered cost of $1,000 (which in turn adds contractor’s share from cost recovery of $1,000 partially offset by the negative impact on profit share after tax of $400). The $480 downside on cashflow for the first year is indeed lower than the $600 upside on cashflow in the fourth year, but the $120 delta is so small that when it’s discounted the incremental impact on contractor’s NPV is actually negative by $27 !

This is exactly what I mean by the title of this article that investment credit could become a disincentive rather than an incentive if the project is such that: the time lag between first production until the project starts generating equity profit to be split takes several years (due to high unrecovered costs, low volume, and or low price), the tax rate is high, and the profit split for the contractor is also high (causing the negative offsetting impact on profit share being high as well). If the impact on project NPV is negative, then what’s the point of claiming the incentive ? It completely escapes the concept of incentive in the first place. The weird thing about this strange phenomena of IC is that the bigger your profit share, then the less favorable the impact of IC on cashflow and NPV (as I said above, for a 15% after tax profit split the cashflow impact is 37% while for a 40% split the cashflow impact is merely 12%). Even worse, the bigger the investment credit, then the worse your project NPV will be: for example if in the last example the IC is for $2,000 then the negative cashflow in the first year will be $960 while the positive impact on cashflow in the fourth year will be $1,200 for a net positive cashflow of $240 (which is double than when IC is only for $1,000), but the incremental impact on project NPV will be negative by $53 (which is about double the negative incremental NPV of $27 when IC is only $1,000).

What makes more economic sense is the option to defer IC claim to the year when the project starts having equity profit to be split, hence the time lag between tax payment on IC and the aditional cashflow will no longer exist. The IC deferral will not change the total net additional cashflow, but the incremental project NPV definitely will be better with IC as compared to without IC. This option as I understand used to be available with special approval from Pertamina (BPPKA/MPS), but in reality there’s no legal contractual ground to that practice as the PSC clearly stipulates that IC has to be taken in the first year of production.

Conclusion: IC is probably the strangest incentive ever given in any PSC system in the world. This incentive could be good for project economics, but could be bad in certain situations. First of all, the fact that it’s taxable in itself significantly reduces the uplift factor. Then the stipulation that the claim and the tax payment should be done in the first year of production makes it worse to the extent it could become a disincentive. Nowadays, high oil price in itself is somekind of an incentive already for project development, but certain gas projects with contracted fixed price to domestic market may still need special incentives to be economic for proceeding with development. Interest Cost Recovery (ICR) is a far superior incentive relative to Investment Credit, but it’s rarely (if not never) granted within the last few years. ICR is applicable to the unrecovered balance of the gas investment, yielding a much bigger effective uplift factor, and is cost recoverable but not taxable in itself. If ICR is out of reach while IC is a disincentive, then the contractor has limited or no room to mitigate investment risks with regards to (argueably unknown future) volume, costs, and price.

Site Update – Another Milestone

A Place We Should Call Home

A Place We Should Call Home

Today, the PSC Discussion Forum reaches another milestone. We surpassed 3,000 hits. Not bad at all for a period of less than 3 months since the launch on July 25, 2008, and that includes the one month vacancy during Ramadhan. Words of mouth and your continuous support to pass on the link to this site are the keys in socializing it to an ever wider audience.

It’s now time to take the Forum into a new dimension. I’ve been thinking about inviting you to also be the contributors to this site, not just by putting forward more comments on the articles I write and post, but also as writers on any subject relevant to Indonesian PSCs. The way to do this is by letting me know in a comment, and then you can send me the article by e-mail. Note that when you post a comment, you should put in your e-mail address, even if it’s not visible to others it’s actually visible to me as the site host/owner, so I can contact you off-line. As the host and moderator of the site, I reserve the right to sort and edit your articles as required.

Again, thanks a lot for being a regular visitor to the site and for all the support !

B.A.D.

Domestic Market Obligations – A Closer Look

 

Domestic or Export or both ?
Domestic or Export or both ?

UPDATE: I added a new paragraph (in violet) in this posting to re-emphasize the unique (and strange) limitation on DMO for oil.

In this article, I would like to address one basic aspect of the Indonesian PSCs, Domestic Market Obligation (DMO), which is unique and specific. Historically, it is an important part of the PSC concept itself. When the PSC founding fathers initially formulated the concept back in the mid 60’s, they were well aware of the strong link to the constitution whereby it is clearly stipulated that all natural resources belong to the state and shall be utilized for the welfare of the people. Hence, this new concept of PSC should not give the impression that oil resources were given away to foreign parties without considering the implication on domestic need. Taking government share only was not justifiable, even if it was sufficient for domestic requirements. In order to ensure that the foreign contractors were also held responsible to fulfilling domestic needs of the people, DMO was introduced as an inseparable part of the PSC. In the beginning, of course the focus was solely on crude oil as domestic gas use was very limited or even non-existent.

 Oil DMO

DMO for oil has been in place since the very first PSC ever awarded. Let’s quote the DMO clause in the PSC:

(o) Contractor shall, after commercial production commences, fulfill its obligation towards the supply of the domestic market in Indonesia. CONTRACTOR agrees to sell and deliver to a domestic buyer a portion of the share of the Petroleum to which CONTRACTOR is entitled pursuant to Section VI subsections 1.3 and 3.1 calculated for each Year as follows:

(i) multiply the total quantity of Crude Oil produced from the Contract Area by a fraction the numerator of which is the total quantity of Crude Oil to be supplied, and the denominator is the entire Indonesian production of Crude Oil of all petroleum companies;

(ii) compute twenty-five percent (25%) of total quantity of Crude Oil produced from the Contract Area;

(iii) multiply the lower quantity computed, either under (i) or (ii) by the resultant percentage of CONTRACTOR’s entitlement provided as applicable under subsection 1.3 of Section VI hereof, from the Crude Oil remaining after deducting Operating Costs.

The quantity of Crude Oil computed under (iii) shall be the maximum quantity to be supplied by CONTRACTOR in any Year, pursuant to this Paragraph (o), and deficiencies, if any, shall not be carried forward to any subsequent year; provided that if for any Year the recoverable Operating Cost exceeds the difference of total sales proceeds from Crude Oil produced and saved hereunder minus the First Tranche Petroleum as provided under Section VI hereof, CONTRACTOR shall be relieved from the supply obligation for such year.

The price at which such Crude Oil shall be delivered and sold under this paragraph (o) shall be twenty five percent (25%) of the price (depending on the time the PSC was signed, some PSCs are compensated at 10%, 15%, or 20% of Indonesian Crude Price which is a reflection of market, while older PSCs are compensated for DMO barrels at merely 20 US cents), as determined under subsection 1.2 of Section VI. CONTRACTOR shall not be obligated to transport such Crude Oil beyond the point of export; but, upon request, CONTRACTOR shall assist in arranging transportation, and such assistance shall be without cost or risk to CONTRACTOR.

Notwithstanding the foregoing, for a period of five (5) consecutive years (meaning sixty (60) months) starting the month of the first delivery of Crude Oil produced and saved from each new field in the Contract Area, the fee per Barrel for the pro rata quantity of Crude Oil supplied to the domestic market from each such new field shall be equal to the price determined in accordance with Section VI hereof for Crude Oil from such field taken for the recovery of Operating Costs. The proceeds in excess of the aforesaid twenty five percent (25%) shall preferably be used to assist financing of continued exploration efforts by CONTRACTOR in the Contract Area or in other areas of the Republic of Indonesia, if such opportunity exists. In case no such opportunity can be demonstrated to exist, in accordance with good oil field practice, CONTRACTOR shall be free to use such proceeds at its own discretion.

The interpretation of the above clauses is that the DMO volume shall be applicable to contractor’s entitlement of both the FTP and the profit barrels, being the lesser of (i) and (ii), times the contractor’s entitlement percentage share. If the gross production of the particular PSC is 100,000 bopd, the domestic national consumption is 1,000,000 bopd, while the total national production is also 1,000,000 bopd, then (i) should be 100,000 bopd X 1,000,000 bopd / 1,000,000 bopd = 100,000 bopd. Meanwhile (ii) should simply be 25% of 100,000 bopd produced by the PSC, which gives you 25,000 bopd. In this case then the lesser of the two is (ii), which means that the DMO volume should then be 25,000 bopd X 28.9% (assuming contractor’s entitlement share of profit barrels of 28.9% before tax or 15% after tax) = 7,212 bopd. The basic calculation hence is 25% X 28.9% X 100,000 bopd of gross PSC production.

Things will be completely different if domestic consumption is much lower or gross national production is much higher. If domestic consumption is 1,000,000 bopd while gross national production is 4,000,000 bopd, then (i) essentially will give you the same factor as (ii): 25%. We know that the same factor is true if domestic consumption is 250,000 bopd. Too bad we all know that cutting domestic consumption down to 250,000 bopd is just equally impossible as increasing production to 4,000,000 bopd. Hence, clause (i) definitely will never ever be used in reality (not in our lifetime folks !, unless we have multiple elephant discoveries sometime in the very near future).

Yet, clause (i) is still in place even if it’s practically useless for probably the last 30 years ever since the domestic fuel consumption has exceeded 25% of the domestic oil production level due to increasing domestic consumption as well as declining production. Theoretically, that clause is still important to be fair to the foreign contractors to ensure an extreme situation will not happen where the DMO volumes supplied by all contractors in the country are in excess of the domestic requirement/consumption itself which will lead the government to end up exporting some of the DMO volumes supplied by contractors, hence not consistent with the spirit and idea of DMO itself in the first place.

Note that the essential concept of DMO is such that basically each PSC contractor in the country shall proportionally carry the obligation to supply domestic needs at their profit entitlement share, knowing that the remaining share goes to the government anyway which in theory should then fill the gap. To better illustrate this, let’s take the first example where DMO should be  = 7,212 bopd. This means that the difference of the PSC’s gross share of DMO as calculated under (i) 100,000 – 7,212 = 92,788 bopd will have to be closed by the government from their share of FTP and profit barrels which of course is not sufficient given that some portion of the gross production is actually taken by the contractors for cost recovery and their own profit barrels.

Also note that the PSC also regulates that what’s calculated above under point (iii) is the maximum DMO for the contractor, meaning that if contractor’s profit share after FTP and cost recovery is nil due to high cost recovery (in the case of a new field start-up with deferred unrecovered costs), then there’s no DMO obligation at all. Using the same example, if gross production in the PSC is 100,000 bbls and FTP is say 20,000 bbls (20%), then the available barrels for cost recovery is 80,000 bbls. If total cost recovery (including recovery of prior years’ costs) is worth more than 80,000 bbls, then there should be no DMO applicable to the contractor. If cost recovery is equivalent to 79,000 bbls, then DMO is limited to the contractor’s share of FTP and profit barrels rather than 7,212 bbls as calculated under (ii) and (iii), leaving the contractor with no exportable barrels other than those for cost recovery. In the example, DMO then should be limited to (28.8% X FTP 20,000) + (28.8% X profit barrels 1,000) = 6,058 bbls, rather than the maximum of 7,212 bbls.

What’s odd about this is the fact that the contractor has the obligation to supply DMO when they have just a single drop of barrels to be split with the government after cost recovery (equity to be split) which basically means they have to give up their share on FTP, while if you have no barrels left after cost recovery then you are not subject to DMO at all. I suspect that this clause is somehow defective, as in the PSC versions prior to the implementation of FTP (in the 80’s), the limitation on DMO reads exactly the same but hence only applicable to contractor’s profit share (as there was no FTP and hence no FTP share). When the government introduced FTP, they tend to consider that contractor’s share on FTP is similar to its profit share and hence added as being subject to DMO, without changing the limitation. In reality, of course contractor’s share on FTP is not the same as profit share, since FTP share will always be there while the non-existence of profit share is a reflection that there still is deferred unrecovered cost. Deferred unrecovered cost in its turn is somekind of carry-forward losses, so how could a party which still carry cumulative losses be subject to supply DMO ? I guess the true spirit of DMO limitation as originally intended in the earlier PSC versions is probably to have no DMO obligation before there’s profit to be split, but then again a contract is a contract and all parties will have to honor and live with it. This strange limitation in reality can easily be “legally manipulated” by the contractor. Going back to the example in the previous paragraph, the contractor can easily spend legitimate additional cost recovery worth 1,000 bbls to completely avoid supplying DMO of 6,058 bbls.

In theory, this strange limitation should not make a big monetary difference for the contractor as DMO for the first 60 months is fully compensated at ICP market price anyway and the situation where cost recovery is so high hence leaving small fraction of profit barrels should mostly be true only for new project start-ups with lots of deferred unrecovered costs which in most cases should be fully recovered within less than 60 months anyway (unless production level is low, investment cost is excessive, or price is rock-bottom). In the new contracts post 2006, DMO is not limited to contractor’s share of FTP and profit barrels, but also includes its cost recovery barrels.

As for the compensation fee beyond the “full” compensation period of 60 months, I always believe that initially it was a reflection of the production costs per barrel. In the mid sixties, 20 cents was probably the average cost to produce when oil price was less than $2/bbl. When oil price increased to a new level after the first oil crisis in the early 70’s and later in the early 80’s, DMO fee was revised to 10% of weighted average ICP (market) of all crude produced in the PSC within the calendar year. And so on and so forth until the recent PSCs have 25% of ICP as the rate for DMO fee. The idea was that the contractors shall not be penalised for supplying DMO, but they shall not make profits either as it is part of their obligation to supply oil to the “rightful owners” of the resources: the people of the Republic. Today, 25% of a market price of $100/bbl is $25/bbl, not exactly bad for compensating the production costs of the DMO barrels.

What about the 25% factor for (ii) ? My wild guess is that back then probably the domestic consumption was about 25% of the gross national oil production level. Nowadays we consume more than what we produce, but that doesn’t mean that we should revisit the terms and change it to a bigger factor without carefully looking into the consequences on investment climate and the economic implications to the contractors. Again, as I say time and time again, the best way to get a bigger share is not by taking more from the contractors but rather by increasing the production level thru finding more discoveries and developing more reserves.

The investors tend to see DMO as additional government take, especially considering the relatively low compensation fees after 5 years of production. When they calculate economics for investment evaluation, especially for marginal fields, sometimes DMO becomes the hurdle for commercial decision. On the other hand, the fact that the PSC allows contractors to be fully compensated for DMO at weighted average ICP market price for the first 5 years (60 months to be exact) also gives rise to issues of accelerating production well in advance even with the risk of damaging the reservoirs and reducing ultimate recoverable reserves. This is where BPMIGAS plays an important role of monitoring prudent operations while at the same time also makes sure that DMO does not become a disincentive to new field developments.

I did say above that DMO is unique and specific to Indonesian PSCs, but some other countries have similar clauses with completely different terms. For example, in Vietnam they have a clause whereby the government reserves the right to purchase all production in the PSC from the contractor at market price, which probably is important in emergency situation where importing is difficult or for military reason in a state of war (when access to petroleum becomes very strategic). In the Indonesian PSCs, there is also a clause which gives the government the option to “purchase” contractor’s entitlement at ICP “market” price in the case when government’s entitlement share of profit barrels (hence not taking into account its share of FTP and DMO volume) is less than 50% of the gross PSC production to the extent that the “purchase” plus the government’s entitlement share of profit barrels adds to 50% of gross PSC production:

BPMIGAS shall have the option, in any Year in which the quantity of Petroleum to which it is entitled pursuant to subsection 1.3 of Section VI hereof is less than 50% of the total Production by 90 days written notice in advance of that Year, to market for the account of CONTRACTOR, at the price provided for in Section VII hereof for the recovery of Operating Costs, a quantity of Petroleum which together with BPMIGAS’s entitlement under subsection 1.3 of Section VI equals fifty percent of the total Petroleum produced and saved from the Contract Area.

Obligation to Supply the Heaviliy Subsidized Domestic Consumption

Gas DMO

DMO for natural gas is something relatively new, introduced after 2002 post the new oil & gas law. This concept is similar to oil DMO, but not exactly the same and has lots of complications in its implementation.

First of all, gas DMO is applicable to a specific percentage portion of the proved reserves (some parties say that it could be 15%, 25%, or even up to 50%) as negotiated and agreed by both parties (the government and PSC contractor). The DMO volume then is calculated as the agreed percentage of proved reserves multiplied by contractor’s entitlement percentage on volume after cost recovery (profit gas). Applicable price and terms on gas DMO volume should be based on an arms length transaction between the contractor and the domestic gas buyer.

There are some unique complexities around gas DMO relative to that for oil:

  • First of all it’s applicable to reserves rather than to production volume considering gas sales contract is always done on a mid to long term basis.
  • Then, the percentage of proved reserves subject to DMO is not definitively stipulated in the PSC as what it is for oil (25%) but rather is subject to be negotiated and agreed by both parties, mostly due to the fact that it depends on so many things such as size of the proved reserves, location relative to closest domestic market, gas prices (both for domestic as well as for international sales), and costs to develop and produce the gas. The last thing we want is having a fixed percentage which is detrimental to the economics of the whole project, making it not commercially viable for the contractor.
  • There is no dictated price such that for oil DMO, price should be negotiated with the domestic buyer on an arms length basis. The intent of gas DMO is more about supplying some of the gas to domestic buyers when the contractor has the option to export it internationally (by converting into LNG or piping it to a neighbouring country as those are the only ways to export gas at the moment). The fact that domestic gas prices tend to always be lower than international prices is unfavorable enough for the contractor anyway.
  • Gas has no liquid market, especially for domestic supply. Even if the contractor is obligated and willing to supply to a domestic buyer, it may take an extended time to find one. The time for the buyer to build its infrastructure and plant to take gas for power generation, for example, can also take years. Usually the PSC stipulates that a 2 year limit to reach an agreement with a local buyer is in place, beyond which the contractor then has the option to market the gas internationally instead. 

Before the government insists on enforcing gas DMO, I believe there should be a careful evaluation on the overall macroeconomic and social implications, to make sure that the gas DMO implementation gives the utmost benefit to the country. A classic example would be the case when the market price of international gas (LNG) is say $18/mmbtu, while supply to a local fertilizer plant is $3/mmbtu, hence it should be carefully evaluated whether enforcing DMO is better than exporting all the gas on which the government share is much bigger than the $3/mmbtu anyway to the extent that it makes more economic sense to subsidize the fertilizer plant or even importing the final fertilizer products. I’m not saying that we should ignore the social implications, I just mean to say that the overall balance should be closely evaluated.

Gas DMO is in its infancy, there are some unknowns to its enforcement. It is a new concept not to be compared to oil DMO which is as old as the PSC itself (40 years). Considering the fact that it’s only relevant to PSCs producing LNG and piping gas to neighbouring countries, the application is somewhat limited. Nevertheless, the government should be wise with regards to its implications on the overall economics.

In conclusion, DMO is a reflection of foreign contractor’s participation to prioritize on domestic security of supply which is an underlying concept of the PSC itself with regard to honoring the fact that all petroleum minerals belong to the people.

Have a pleasant weekend, folks !

Eid Mubarak ! I Wish You a Joyous Eid Celebration …..

Greetings !

Greetings !

Eid ul Fitr is a special celebration, a time when we share best wishes, forgive each other for any wrongdoings and mistakes, and reach purity of honesty and honor the spirit of togetherness. Again, may you have all the best on this important religious and individual milestone.

I took a month long break from posting on this site during the holy month of Ramadhan, not just to honor the religious festivity, but also to accommodate some indirect and direct concerns regarding some of my postings. Certain parties complained about specific articles being too direct on certain issues in certain PSCs while at the same time they also raised concerns about me not commenting on other prominent issues. I had the opinion that I should not defend my position, but I decided to retrospect on myself and promised to be more objective in the future (even if in all the previous postings I had tried to always put myself in all different shoes and angles). The purpose of this discussion forum is not to stir up controversies and be aggressive on certain issues. It is a forum where we can share and discuss openly with no strings attached. If you do not agree with any of the opinions put forward by me or anyone else in this forum, then please chip in with your own observations and point of view.

The PSC Discussion Forum is back in action and you should expect to have new postings coming out soon …..

Best regards to you all,

B.A.D.

Much Ado About Nothing – A Comedy or A Tragedy ?

Happily ever after ?

Happily ever after ?

A light reading for the weekend.

Much Ado About Nothing, the title of this article refers to the famous play by William Shakespeare about a group of people having a complex misundertsanding about a very simple event (alleged infidelity that in reality never takes place) which then is blown completely out of proportion and almost leads to a tragedy and a disaster. It’s a comedy, actually, hence it’s really funny and has a very happy ending. It’s my favorite Shakespeare’s play. You should either read the book or watch the movie if you haven’t.

Sadly to say, the same “drama” is currently playing in the Indonesian oil & gas industry. This one is not a comedy, and hence not funny at all. But the plot is identical: complete misunderstanding, mistrust, much ado about nothing (people raising concerns and making things up about trivial or even non-existing issues), and “infidelity” (one party being “unfaithful” or accused of being “unfaithful” to the other). The key players in the “play” are Migas, Ministry of Energy and Mineral Resources, BPMIGAS, Honorable Members of the Parliament, the media, and the Oil Companies. The investors on one hand and the government on the other hand already signed wedding vows, using the PSC contracts as the certificate of marriage, including all the pre-nuptial agreements. They lived happily for the last 40 years, sharing happiness throughout time, facing difficulties shoulder to shoulder, and even gave birth to wonderful projects.

Then suddenly, one side of the “partnership” started complaining that there is a financial crisis. What the couple generate for a living keeps declining in quantity, even if it sells at a much higher price now. The problem is more on the domestic needs: the children are not mature and need to be heavily subsidized by the parents. The family budget is at risk and it is difficult to keep it balanced. Meanwhile, the children are not ready to be full grown ups and live on their own without parental support. The problem gets worse with the fact that other family expenditures can not be reduced to create room for allowing more child support allocation. In reality, the other expenditures are also increasing due to inflation and in some cases inefficiencies for paying too much on useless stuffs. Bottom line: it’s a family budget issue.

Rather than tweaking the expenditures or educating the children to be more mature and self sufficient, the focus is twisted more on the family income. The party generating the quantities of this specific product is accused of not being efficient, spending way too much money to produce the widgets, leaving less quantity available for the family (the children in particular). The pre-nuptial agreement on how the products should be shared is also challenged and there are attemps to dishonor it, even if they are not done straight to the face. Some production costs which used to be parts of the sharing calculation are now disallowed. Meanwhile, one party accuses the other as being unfaithful to the pre-nuptial agreement. Things get really bad.

However, divorce is not an option, they still need each other. No one party is willing to sacrifice the future of the family over this fiasco. They probably need a session with a marriage counselor, especially after all the spectators and the neighbours make things worse by taking sides and by adding fuel to the blazing flame. Too bad, there’s no available marriage counselor. Looks like they have to settle the issues by themselves. There are differences in perspectives, things have changed a lot over the last 40 years, but the mutual feelings for co-existence is still very much there. They still love each other, even if now they see each other in a different way.

The Shakespeare’s play at least comes to a happy ending, leaving all characters happy, even after some long twists and turns. We hope the same conclusion will close our “play” in this critical industry of ours: a very happy ending with all mistrust and misunderstanding gone, disagreements resolved, and start running full steam ahead generating more and more profits for all parties, especially for a better wellfare of the people in this greatest archipelago.

Have a nice weekend folks !