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 !
Posted in PSC Terms
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.
Posted in PSC Terms
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.
Posted in PSC Terms
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.
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:
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 !
Posted in PSC Terms
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.
Posted in PSC Terms
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 !
Posted in PSC Terms
The parliament inquiry (Hak Angket DPR) on government’s decision to increase fuel price back in late April this year is currently going on. So many parties have been and will be summoned to testify at the parliamentary hearing sessions. Pertamina, Ministry of Energy and Mineral Resources, BPH MIGAS, BPMIGAS, oil industry experts, and top executives from oil companies are targeted for the inquiry. This particular issue has been the favorite subject of countless debates in the public media, the internet, and almost everybody in the country is anxious about learning the “true story” behind the government’s decision.
There is one particularly popular expert on the subject and he was widely involved in almost all discussion forums on TV, radio, and the internet. His famous claim throughout the debacle was the fact that the government should not increase the fuel price simply due to the increase of world oil price as in reality the government’s share from the producing PSCs actually costs nothing to the government. Details of his arguments and calculations are easily available in so many other sources, hence I don’t want to repeat or quote them here. However, simply put, his view is based on the following simple (and my further simplified and rounded) logics:
The “true story”, of course is not that simple. There are webs of regulations, contracts, and cross departmental complexities. Note that the PSCs have DMO oil compensated by the government at very low prices. Refining process in Pertamina’s refineries and the distribution channels are equally mysterious. We also import finished fuel product directly. Reconciling and investigating everything will be nightmarish (meanwhile members of the parlieamentary task force claim that they will “turn every single stone”).
The oil & gas industry in this country, on a stand alone basis, indeed is capable of providing low fuel price for the people. Not as low as what Chavez has been spoiling his people in Venezuela, but we can definitely do less than Rp. 6,000/litre. Again, only if the whole economy of the country is all about the oil & gas industry. In reality, of course that is not the case. Even if we achieve world class efficiency with no corruptive leaks along the whole value chain from the very top in exploration and production all the way down to the gasoline stations across the archipelago, we would never achieve a situation where the petroleum industry can support the whole state budget. That would only be possible if production increases in multiplications and domestic fuel consumption somehow shrinks to a mere fraction, basically those things will never happen.
What’s wrong with the four-bullet logics above is the fact that the government actually use the proceeds from the oil industry to finance other expenditures in the state budget: to pay the government employees, to build schools, to maintain and repair roads and infrastructures, to pay Pertamina for “fuel subsidy”, etc. Hence the whole issue is not limited just to the industry. As I said time and time again, it’s more of a state budget issue rather than an oil industry issue. We have to admit that there are rooms for improvement and enhanced efficiencies in the industry, but the state budget issue is a much bigger problem.
Using the very same example above, what actually happens is what I simplified below:
I tend to see that the parliamentary inquiry then is a bit out of place when it comes to focusing solely on the oil & gas industry. You could clearly see that this is way beyond the industry. The upstream part of the industry is well controlled and very structured, their findings will be limited to a little inefficiency on cost recovery, declining production, minimum exploration activities and hence disappointing reserves replacement. Meanwhile, I should not comment on the downstream side as I have very limited knowledge about it but definitely they will find inefficiencies as well. They should also question what the government is doing to control and manage domestic demand for (especially subsidized) fuel, such as encouraging large scale conversion programs to alternative energy for both transporation and power generation. Last but certainly not least, they should scrutinize the state budget itself as rooms for expenditure efficiency and enhancement of non-oil state revenues could be much bigger there. The logic is simple: the more efficient the state budget then the more fund is available for fuel subsidy (I myself strongly oppose the idea of adding the fuel subsidy as it is consumptive rather than productive, with no value adds to the national economy), or, alternatively, the higher state revenues from other sectors are, then the more could be allocated for fuel subsidy (other sectors subsidizing the oil industry rather than the other way around). Looking at the issue at its right proportion, the parliamentary inquiry could go uncontrollably without boundaries, which is highly unlikely and will get you nowhere.
My suggestion: please do not expect to get anything special as a result of this inquiry, not to mention that there must be a political agenda behind the initiative in anticipation of the upcoming election year.
Posted in PSC Terms
Fact or Fiction: The Tale of Indonesian PSCs
The oil & gas industry in this beloved country of ours is definitely full of surprises. Surprises with regards to regulations, procedures, processes, and even things which are supposed to be contractually fixed such as cost recovery, corporate taxes, sales contracts, and profit splits. In an industry which deals a lot with more than enough uncertainty in exploring and finding reserves, more uncertainties (surprises are uncertainties in nature, regardless they are favorable or unfavorable) is not desirable at all. In the end this may all lead to deteriorating investment climate.
In this country, ”strange” things in the oil & gas industry happened in the past, are happening at present time, and no doubt will always happen in the future. If the media and a lot of people currently are making a big fuss about the Tangguh LNG selling price to Fujian as being the lowest ever, then they should step back and see if the case is unique. In reality, there are some other “strange” deals around us. Let’s revisit one of them.
A few years ago, a tsunami of attention all of a sudden was flooding around the Chevron (formerly CPI, Caltex Pacific Indonesia) – Conocophillips crude oil and gas swap. Until 1998, CPI burned some 61,000 b/d of Duri crude to generate steam for the Duri EOR project. In order to reduce the quantity of heavy Duri crude burned, gas delivery commenced in 1998 from the Corridor PSC in southern Sumatra. The Corridor Block Gas Project is operated by ConocoPhillips. Processed gas is piped 544 kilometres, via a 28-inch diameter line, to Duri. Compression facilities were brought into operation in mid 2003 and increased capacity to 460 mmcfd.
First gas sales started in October 1998 and reached 300 mmcfd in 1999. The gas has replaced about two thirds of the Duri crude that was previously burned. Initially electricity and steam were produced separately but, in 1998, construction of a US$190 million, 300 MW, cogeneration plant began to allow the simultaneous production of electricity and steam using supplied gas. The three-train plant is 95% owned by Chevron, is operated by Chevron Energy Indonesia Ltd (replacing Amoseas) and became fully operational at the close of 2000. The increased efficiency of the cogeneration plant resulted in a saving of Duri crude used in power and steam production.
Additional gas sales from Corridor commenced in 2002 and has displaced Duri crude completely, although a few oil-fuelled steam generators remain as backup should the gas supply be interrupted. CPI also produces some gas for its own use as fuel for the Power Generation and Transmission system. Around 120 mmcfd is used to generate close to 400 MW, required to power CPI’s operations.
What was later considered to be the strange parts were the sales and purchase contracts for the gas supplied by Conocophillips.
In Q1 1996, terms were finalised for a Gas Supply and Exchange Agreement between Gulf Resources and Caltex (Contract CPI-1). Under the terms of the agreement with CPI, gas from the Corridor PSC is exchanged for Duri crude on an energy equivalent basis, adjusted for oil transportation, storage and terminaling, and thermal efficiency. A conversion factor of 6.2 mmbtu/bbl is used. Initially the sales gas had a calorific value of around 1,040 btu/scf, although from 2001 this increased to 1,060 btu/scf. The contract carries a take-or-pay provision varying between 72% and 98%. The Gas Sales Agreement is for 15 years with a DCQ of 312.5 bbtu/d until 30 June 2003, dropping to 250 bbtu/d for an additional 5.5 years and declining thereafter until the end of the contract in November 2013. The total contracted quantity is 1.05 tcf of sales gas. Most of the CPI-1 gas is used for the Duri steamflood project and at the 300 MW co-generation plant.
On 21 December 2000, a further Gas Supply and Exchange Agreement was signed between CPI and Gulf Indonesia for additional gas deliveries to the Duri Area for steam and power generation (Contract CPI-2). Under the terms of the agreement, CPI-2 gas is exchanged for Duri crude using an energy conversion factor of approximately 7.75 mmbtu/bbl, representing a discount to CPI 1 of some 25%. The contract carries a take-or-pay provision of 70%. The total contracted quantity is 1.1 tcf of sales gas over 19 years. The CPI-2 contract compensates for CPI-1 depletion in the medium term. Initially CPI-2 gas will supply the Duri steamflood operations with some 45 mmcfd, destined for the 300 MW co-generation plant.
Judging from the conditions and situation back in the years of 1996 and 2000, those two exchange contracts were deemed to be “normal” and nobody picked up anything wrong with them. Both were approved and fully acknowledged by Pertamina and the government. It was considered appropriate as well that essentialy Conocophillips was to be paid for their gas supply in the form of the crude oil which used to be burned by CPI, as the gas in reality is supplied to replace the burned crude to produce steam recovery. If the best domestic gas contract back then was around $3/mmbtu, then the first contract (CPI-1) was at about the same price anyway (at conversion factor of 6 mmbtu/bbl, base crude price of $18/bbl would give you $3/mmbtu). The deal must be good for all parties based on the conditions then, and CPI actually gave away less crude oil (relative to what they used to burn) to pay for the gas they received from Conocophillips.
A few years ago, the exchange contracts were cursed as costing the government zillions of rupiah as the oil price started hiking up to the roof. The Corridor block gas was probably the most expensive piped gas in the world due to the “unfair” exchange. People were screaming that the gas should have been bought (at say $3/mmbtu) rather than exchanged for crude oil. They said that at $60/bbl oil, the Corridor block gas price was ca. $10/mmbtu, higher than any other gas contracts in the world (not to be compared with LNG which is liquified processed gas which indeed usually sells at higher prices). They said that the exchanged crude oil should have been exported and sold, generating gigantic additional revenue for the state and the people. To make things even worse, they accused that on the Conocophillips side, the sales proceeds of the crude oil they received were treated as gas revenue, on which the contractor’s profit split is double compared to that for crude oil. The “facts” were laid bare open to the public: had the oil been sold on the Chevron side, the government would have got a 87.5% to 90% share based on oil split, rather than being shared based on a 70% government share on the Conocophillips side based on gas split. Some people argued that despite the fact that in this case Conocophillips produced gas from the PSC rather than oil, the revenue should be somehow treated as oil revenue considering it was an exchange.
And then, something strange happened again: the fury died down just like that. Minimum or no media coverage at all. I myself am not aware the latest on this issue, other than some news claiming that Chevron somehow stopping the exchange and (will ?) export the previously-exchanged oil. Not sure either how Conocophillips is handling this on their side.
We should wait and see where’s the ongoing debate on Fujian LNG sales price will take us.
Posted in PSC Terms
A new day in Iraq, a sunset in Indonesia
This site might be the place for some people to worship and (for some others to) condemn Production Sharing Contract as the main type of petroleum contract in Indonesia, but there are so many different types of petroleum contract in the global oil & gas industry. PSC is certainly not the best type of contract for all situations and locations, just like any other types of contracts. There is no single type of petroleum contract that fits all conditions, situations, and locations.
A good example would be the current push (by the Americans and the Brits) for the Iraqi government to adopt the PSA (Production Sharing Agreement) concept for its giant oil & gas industry, departing from their traditional concept of state ownership and operations. While the Iraqi people struggle to define their future amid political chaos and violence, the fate of their most valuable economic asset, oil, is being decided behind closed doors.
Note that conceptually PSA is almost identical to PSC, with key differences in the fact that PSC is mostly onesidedly outlined and stipulated based on a contract template with terms generally applicable uniformly for all blocks. PSA, meanwhile, is typically based on negotiable terms and conditions (profit split, incentives, accounting rules, etc) agreed by the investor and the host government, to the extent that each PSA could be unique even within the same country.
Iraqi public opinion is strongly opposed to handing control over oil development to foreign companies. But with the active involvement of the US and British governments a group of powerful Iraqi politicians and technocrats is pushing for a system of long term contracts with foreign oil companies which will be beyond the reach of Iraqi courts, public scrutiny or democratic control.
Economic projections show that the model of oil development that is being proposed will cost Iraq hundreds of billions of dollars in lost revenue, while providing foreign companies with enormous profits.
The key findings of a study I found in the internet concluded that:
The debate over oil “privatisation” in Iraq has often been misleading due to the technical nature of the term, which refers to legal ownership of oil reserves. This has allowed governments and companies to deny that “privatisation” is taking place. Meanwhile, important practical questions, of public versus private control over oil development and revenues, have not been addressed.
The development model being promoted in Iraq, and supported by key figures in the Oil Ministry, is based on contracts known as Production Sharing Agreements (PSAs), which have existed in the oil industry since the late 1960s. Oil experts agree that their purpose is largely political: technically they keep legal ownership of oil reserves in state hands, while practically delivering oil companies the same results as the concession agreements they replaced.
Running to hundreds of pages of complex legal and financial language and generally subject to commercial confidentiality provisions, PSAs are effectively immune from public scrutiny and lock governments into economic terms that cannot be altered for decades.
In Iraq’s case, these contracts could be signed while the government is new and weak, the security situation dire, and the country still under military occupation. As such the terms are likely to be highly unfavourable, but could persist for up to 40 years.
Furthermore, PSAs generally exempt foreign oil companies from any new laws that might affect their profits (just like the Indonesian PSCs where tax regulations are fixed based on the ones enacted at the signing of the contract). And the contracts often stipulate that disputes are heard not in the country’s own courts but in international investment tribunals, which make their decisions on commercial grounds and do not consider the national interest or other national laws. Iraq could be surrendering its democracy as soon as it achieves it.
POLICY DELIVERED FROM AMERICA TO IRAQ
Production sharing agreements have been heavily promoted by oil companies and by the US Administration.
The use of PSAs in Iraq was proposed by the Future of Iraq project, the US State Department’s planning mechanism, prior to the 2003 invasion. These proposals were subsequently developed by the Coalition Provisional Authority, by the Iraq Interim Government and by the current Transitional Government. The Iraqi Constitution also opens the door to foreign companies, albeit in legally vague terms.
Of course, what ultimately happens will depend on the outcome of the political struggle, on the broader political and security situation and on negotiations with oil companies. However, the pressure for Iraq to adopt PSAs is substantial. The current government is fast-tracking the process and is already negotiating contracts with oil companies in parallel with the constitutional process, elections and passage of a Petroleum Law.
The Constitution also suggests a decentralisation of authority over oil contracts, from the national level to Iraq’s regions. If implemented, the regions would have weaker bargaining power than a national government, leading to poorer terms for Iraq in any deal with oil companies.
A RADICAL DEPARTURE
In order to make their case, oil companies and their supporters argue that PSAs are standard practice in the oil industry and that Iraq has no other option to finance oil development. Neither of these assertions is true.
According to International Energy Agency figures, PSAs are only used in respect of about 12% of world oil reserves, in countries where oilfields are small (and often offshore), production costs are high, and exploration prospects are uncertain. None of these conditions applies to Iraq. The oil fields there are mostly big with high production level, low operating costs per barrel, and technically it’s more difficult to find fresh water reservoir than to find oil in the Iraqi desert.
None of the top oil producers in the Middle East uses PSAs. Some governments that have signed them regret doing so. In Russia, where political upheaval was followed by rapid opening up to the private sector in the 1990s, PSAs have cost the state billions of dollars, making it unlikely that any more will be signed. The parallel with Iraq’s current transition is obvious.
The advocates of PSAs also claim that obtaining investment from foreign companies through these types of contracts would save the government up to $2.5 billion a year, freeing up funds for other public spending. Although this is true, the investment by oil companies now would be massively offset by the loss of state revenues later. At this cost, the advantages referred to are simply not worth it.
Iraq has a range of less damaging and expensive options for generating investment in its oil sector. These include: financing oil development through government budgetary expenditure (as is currently the case), using future oil flows as collateral to borrow money, or using international oil companies through shorter-term, less restrictive and less lucrative contracts than PSAs such as risk service contracts, buyback contracts, and development and production contracts.
PSAs represent a radical redesign of Iraq’s oil industry, wrenching it from public into private hands. The strategic drivers for this are the US/UK push for “energy security” in a constrained market and the multinational oil companies’ need to “book” new reserves to secure future growth.
Despite their disadvantages to the Iraqi economy and democracy, they are being introduced in Iraq without public debate.
It is up to the Iraqi people to decide the terms for the development of their oil resources, but they should be well aware of the likely consequences of decisions being made in secret (by others) on their behalf.
WHAT ABOUT INDONESIA ?
I would say that the Indonesian government should also be really careful in deciding to adopt the type of petroleum contract suitable for a block. In reality, we should probably have more than just a single model. The PSC model might be best for certain blocks with uncertain prospects, high development and operating expenses, and small potential reservoirs (I would say hence that the PSC is best fit for all wildcat exploration blocks in the country, with probably some variations in terms).
Meanwhile, we could only have certainty of low costs and large reservoirs in the case of existing PSCs which are seeking for an extention. This is the only condition where the government have the option to adopt a different type of contract (or tighter PSC terms), or even to nationalize the operation (with lots of precautions as I wrote in another article in this site). Remember, it is true that no single size fits all, but the PSC actually comes in different sizes.
Posted in PSC Terms
Technically, you don’t make profits out of cost recovery. Cost recovery barrels are the ”bad barrels”, as opposed to profit barrels which are the “good barrels”. Bad in the sense that it always gives you a negative impact on bottom line value. This is true of course if the nature of the cost itself is non-value generating. Everytime you spend $1.00 of non-value generating cost recovery, then the PSC contractor will have to absorb a negative financial impact of $0.15 after cost recovery and tax in a typical oil PSC where the pre-tax profit split is 71% : 29% with a 48% total tax rate. Value-wise it’s always bad as you tend to spend the money first before you recover it through production, hence time-value wise it’s always a negative as well, even if you’re allowed to cost recover all costs immediately. The value of these bad barrels is even worse if cost recovery is charged over several years of PSC depreciation (for capital expenditures), widening the time gap between cash outflow from the pay-out and inflow from cost recovery barrels and tax deductibility. This alone is a strong enough reason why a PSC operator should always strive to be as efficient as possible.
Strangely enough, there are accusations and speculations raised by so many parties that the PSC contractors are not efficient, tend to spend as much as they want uncontrollably, and even make profits out of cost recovery. Those accusations are probably mostly caused by a common misunderstanding that all the expenditures in the PSC are cost recoverable and that cost recovery is a cost reimbursement mechanism for the contractor paid by the government by giving away the cost recovery barrels. I’ve written another article in this site proving that the misunderstanding is of course wrong. True reimbursement would keep the contractors value-neutral, something which the cost recovery and tax mechanism in the PSC does not achieve as the contractors’ financials are still adversely impacted by cost recovery.
But let’s see closer and evaluate whether indeed there’s a possibility, however remote, that a PSC contractor can actually make a profit out of cost recovery barrels in addition to profit barrels, the “technically-correct” source of value. One possibility of extracting value from cost recovery is by playing a “game” with the entitlement nomination as the basis for sharing crude oil liftings. A simple way to do this is by proposing a budget (and its subsequent revisions and monthly estimates) in which cost recovery is assumed to be higher than the real known expectation at that point of time. Overstating the cost recovery budget or estimates will of course end up with higher contractor’s entitlement nomination, justifying more share of crude liftings. At the end of the period, actual entitlement based on actual volumes, actual prices, and actual cost recovery will be calculated and the contractor will then be found to be in an overlift position. Even if the overlift has to be settled anyway, at least the contractor has gained with regards to getting the cash earlier (time value of money). This is essentially getting an interest-free loan from the government, even if it’s only for a brief period of one year or less. The contractor can also combine this scheme with good lifting strategy, ensuring more liftings (including the intentional overlift disguised by higher cost recovery nomination) when price is higher. The overlift will then be settled in cash on a weighted average basis, hence adding even more profit if the contractor manages to lift at prices higher than the weighted average price. It is true that a positive lifting price variance, which is a reflection of additional contarctor’s revenue, is taxable, but the net after tax is still additional value for the contractor. Some PSCs calculate actual entitlement and overlift on a quarterly basis, but some others calculate them on an annual basis. On the annual ones, based on the budget, the contractors logically could start lifting (a proportional portion of) cost recovery barrels in January for expenditures budgeted to be spent 11 months later in December, so that the “interest-free loan” is bigger and over a longer period, especially if later on that drilling program in December slips into the following year or even canceled and never be actually spent. Again, the nature of this “game” is limited to intentional overlift and delaying the disclosure of cost recovery reduction until the period-end actuals come out, and this is always settled in time by the contractor. However, the government also carries further complications to this unethical “lifting strategy”, such as having to fill the volume gap caused by the contractor’s overlift by importing crude oil from the middle east to secure domestic feedstock to Pertamina’s refineries, sometimes at a higher price than the eventual overlift settlement of their rightful entitlement share from the PSC being “temporarily stolen” by the contractor.
This first possibility, however, is very remote as the whole processes of budgeting, entitlement nomination and lifting scheduling, are all very tightly controlled by BPMIGAS. The process to get the annual budget (WP&B) approved is very well structured involving multiple stages of meetings, challenges, discussions, and follow-ups. Rules for monthly entitlement nomination are clearly defined, including the requirement to use last actual monthly ICP as the price forecast for the rest of the period in calculating entitlement. Lifting scheduling is managed by all parties and collectively agreed in regular meetings. The monitoring process of crude oil lifting status also involves a twice-a year COMLE meeting where all producing PSCs get together with BPMIGAS and the overlift PSCs get “humiliated” and “disgraced” publicly in front of the whole forum (especially if the overlift volume and value is gigantic). PSC contractors with high ethical standards and those which really concern about reputation would never do this cheap trick intentionally.
The second possibility to make a profit out of cost recovery is of course by charging bogus costs illegally. This is undeniably stealing from the government. I would say none would do this and even if some try, they will get caught easily in the monitoring process and financial audit. This one is definitely criminal and intentional, and the consequences should be harsh punishments or even criminal court litigation.
The third “option” to cheat the cost recovery mechanism in a PSC is by passing value to associate companies. In a typical oil producing PSC, if the operating company has to suffer a 15% negative bottom-line cashflow for every dollar spent, then as long as the associate companies or other related parties make more than a 15% profit, then the overall group of companies will still gain collectively. An example would be a producing PSC contractor which contracts out a $10 million exploratory well drilling program to its associate company. If the well turns out to be a dry hole, the PSC contractor will suffer a loss of $1.5 million (15%) after cost recovery and tax, but its associate company could still be making a profit way in excess of $1.5 million. If the well is a success, then it’s even better as both sides of the group will be making profits. This could allegedly be done for all types of contracts: transportation, office building, facilities, seismic, you name it. The unofficial code for this scheme is “keeping it in the family“.
This last trick, however, is also very unlikely to happen, at least not on a big scale. In reality, the process for procuring goods and services is heavily controlled, monitored, and audited by BPMIGAS and other government agencies (BPKP, BPK). Everything has to be approved and signed off by BPMIGAS. The contracts will definitely have to be on an arms-length basis and competitive with other bidders. The fact that an associate company can bid more competitively due to the corporate or ownership special relationship is a different issue not exactly relevant to be concerned with (as it would be indifferent or even more costly if the contract is with a completely unrelated party). The last item on the now world-famous 17-item negative list in the ministerial decree is specifically addressed to prevent this potential loophole. The last item says that all related party contracts with associate companies or other parties with special relationship which are financially unfavorable or detrimental to the government shall not be cost recoverable.
The legal and rightful way to make a profit for a PSC contractor is no doubt thru its share of the equity to be split, that’s exactly why you call it profit barrel in the first place. Meanwhile, cost recovery, just like in any other industries, is simply cost, defined as an offset to sales revenue and hence an erosion to profit.
BTW, I apologize for being inactive for more than a week. Not trying to find an excuse here, but last week we had an extended week-end with the Indonesian independence day, and then I also celebrated my birthday. A year older, a year wiser, hopefully ……
Posted in Cost Recovery
