Abdul Mahdi al-Ameedi, director general of Iraq’s oil ministry’s Petroleum Contracts & Licensing Dept. (PCLD), sheds light on the ministry’s fourth bid round scheduled for May30-31, and the service contract on offer, its advantages and shortcomings, in an interview with IOF editor Ruba Husari in Baghdad. (للنص العربي اضغط هنا)
Q: Offering a service contract type with a fixed fee for oil and gas exploration work is unusual and almost unseen in the industry. How can you justify it?
A: Our justification is that the state considers that production-sharing contracts (PSC) are illegal and unconstitutional since the Iraqi constitution stipulates that oil and gas in Iraq is the property of the Iraqi people. Since a PSC gives foreign companies the right to a portion of the production under the form of profit oil, they are considered in contravention with the current constitution. The other justification is that we have already awarded service contracts in three previous bid rounds and this has become the norm for the ministry of oil. It is true that service contracts entail a higher risk for both sides because we have to agree in advance on remuneration fees that we cannot guarantee 100% that they are adequate and the companies cannot be sure either despite factoring in the risk element in their calculations. I agree it is difficult to predict the profit or loss in this case.
Q: Are PSCs problematic because they are politically unacceptable to Iraq?
A: Of course, politically speaking it is not acceptable but it emanates from the fact that it contravenes with the constitution. There is a political dimension to it too in the fact that all the contracts signed by the Kurdistan region of Iraq are the PSC type, and the ministry has objected to these contracts on the basis that they are not acceptable from a constitutional or legal point of view. So, naturally, the ministry of oil would not back this type of contract.
Q: The fact that the ministry objects to the Kurdistan region signing contracts does not necessarily mean that a PSC is not the right type of contract for this kind of work in Iraq.
A: We do not object to PSCs because they are not right but rather on the contrary, this type of contract is considered best for exploration because the risk is reduced whether for the oil ministry or for the companies. The commercial and economic terms of the PSCs can be drafted in a way to protect the interests of the state and the state does not lose. But since the constitution states that there is no sharing in the country’s oil, then this type of contract is not applicable in Iraq.
Q: Why would international oil companies accept to play a role as your banker since under a service contract they advance the funds and recoup them later and at the same time that of a service company that builds facilities and infrastructure?
A: We did initially consider the idea of using service and engineering companies instead of organizing bid rounds. However, these companies would require immediate payment putting added financial pressure on the oil ministry to pay the cost of exploration as it arises. For that reason, we opted for a bid round where international oil companies invest money and get repaid at a later date.
Q: Borrowing from banks to pay for exploration and development instead of oil companies could be cheaper for Iraq.
A: I’m not sure whether international banks would agree to lend Iraq in the current circumstances and for the purpose of conducting oil and gas exploration which by nature entails a certain risk. There is another advantage in using oil companies since those companies would be more vigilant while doing the exploration work than engineering companies because eventually they will develop the fields themselves. So for both technical and moral reasons those companies will be responsible for whatever is achieved during the exploration phase.
Q: How do you deal with the fact that a service contract does not impose a ceiling on costs that are entirely repaid by the ministry and could result in higher cost per barrel than other type of contracts?
A: We have tried in the service contract for the fourth bid round to address this issue in a different manner than the previous bid rounds. According to the new arrangement, part of the oil or gas production will go towards repaying petroleum costs but the contractor or the operator will be paid remuneration fee only on the remaining production after deduction of costs. This should entice the contractor to reduce costs in order to increase the amounts which will enter into the calculation of the remuneration fees and ensure higher profitability. This clause is similar to the calculation of profit oil under a PSC where spending is controlled because it’s deducted from a share of production before the allocation of profit oil.
Q: Still, a service contract encourages spending to keep the R-factor at its highest because the higher the cost, the higher the R factor and the higher the remuneration fee.
A: This is true. It’s possible to exaggerate the cost but this is also valid under the PSC. The R-factor is a mechanism that exists in this contract and is related to the expenditures and production. Naturally the contractor tries to maximize his take from that and the exaggeration of costs can be in the benefit of the contractor even if it affects production, regardless of whether he is paid a remuneration fee or profit oil. Auditing the expenditures is one thing that the (Iraqi) upstream company can use in order to control expenditures. I can say that within our companies, people are gaining experience and building their capabilities so the control on expenditures should be better now than what it was at the start of the implementation of the previous contracts.
Q: What are the incentives and benefits that are included in the final draft of the model contract for the fourth bid round?
A: There are several benefits. Some companies, especially the small and medium-sized ones did not have an opportunity to work in Iraq and they are keen on projects. The other benefit – even though it’s too early to judge – is a financial benefit in the case where the remuneration fees that the companies will bid were in line with those fixed by the ministry of oil. If the remuneration fee a company bid is too high compared to that of the ministry of oil, then it will not win a contract but at the same time it has nothing to lose. Among the incentives is the term of the contract, especially for gas where the development period is much longer than that for oil. Another incentive is the possibility to export the excess natural gas where the contractor can enter into a separate agreement with the ministry of oil on terms to be negotiated in time. We added another incentive in the final draft which covers the minimum expenditure which was fixed at $150 million for each block but has been modified in the final draft to take into consideration the size of the block so the range of this minimum is now between $90 million and $130 million. Also previously the contractor had to pay the unspent amounts of the minimum expenditure when he does not make a commercial discovery but this has been considered unfair and was removed.
Q: What are the parameters used by the ministry of oil to determine the maximum remuneration fee for each block?
A: There are two factors that are taken into consideration when looking at the economics of any project: one is the investment profile and the other is the production profile. In this round, as it was in the second and third rounds, our calculations – and those of the companies – are based on assumptions related to the costs of development and the production rates that can be achieved. This remains valid for the fourth bid round with the exception that there will be other expenditures related to exploration and appraisal. These are the two factors that our previous experience showed they are valid and we can rely on them, and which the companies also referred to positively in their comments on the first drafts of the model contract. Based on this, we have fixed one remuneration fee for each block on offer.
Q: Would the remuneration fees in this upcoming round be of a different order than what we have witnessed in the previous rounds?
A: It is certain that the range of remuneration fees will be different this time than in the previous rounds. They will be much higher because the ministry of oil takes into consideration that these are exploration blocks and as a result involve higher cost and also higher risk since the contractor could spend millions of dollars and find dry holes and lose everything he spent. So in order to give the contractor the motivation to conduct exploration, the remuneration fees fixed by the ministry will be higher than in previous rounds. The fees will also be different for oil blocks than for gas blocks but in both cases they will be higher.
Q: How can a bidder determine from now the remuneration fee he will be paid in several years time based on unknown reserves of oil and gas that are yet to be found and taking into consideration that oil discoveries will be subject to a further up to seven years holding period?
A: Well, the holding period does not have to be seven years, it could be much shorter if the ministry decides to develop a commercial find earlier. But aside from the fact that the contractor will develop and produce and be paid his costs back, there is a reference in the contract to the possibility for the contractor to get his costs back as soon as the discovery is made and confirmed if the ministry asks for a holding period on development. He can get paid back his specific costs with interests and potential costs without interests if he chooses to. In the case where the contractor decides to wait until the field is developed before he gets his costs back, he will be paid interest on both types of costs. It’s up to the contractor to decide whether the interest is worth it or not.
Q: Still, a company is bidding now a certain fee that might not be relevant in 12 years – assuming 5 years exploration and 7 years holding period – where market conditions could change as far as the oil price or the value of the dollar are concerned.
A: There is a risk for both sides, the ministry of oil and the companies, in this exercise. Any company who chooses to participate in a bid will make its calculations and determine what is an appropriate fee. If this fee is in line with what the ministry of oil has set, then he will be welcome to start work. If it is not, then he will not get involved and will not take any risks. It is a difficult formula for both sides and we are aware that some companies might chose not to participate for this reason. But we have no choice but to draw up a service contract with those terms for the reasons I explained earlier.
Q: The price could be that no big oil companies will participate in the fourth round and you end up with only small and medium sized companies who are desperate for a foot in Iraq at any price.
A: It goes without saying that we prefer to see big and solid companies with proper technical and financial capabilities awarded contracts. This is our wish and it’s something we encourage. But if these companies opt not to compete or if their bids came too high in terms of the remuneration fee they bid, we will have no choice but to award the contracts to those who offer acceptable bids. We had a previous experience in the last bid round when Total bid $19/ bbl for Akkas gas field while Kogas bid $5.5/bbl and won the contract. So far we have no issues with Kogas’ implementation of its contract and its respect of the contractual timelines. Though it’s too early to judge, I still believe that companies such as Kogas and others are keen to prove themselves and to uphold their reputation.
Q: What is the incentive for a company to take the option to export gas based on a separate agreement to be negotiated in time as stated in the contract, when it does not own the gas in the first place?
A: It is not a condition that the company owns the gas in order for the export scheme to be profitable. Basrah Gas Co (BGC), which is a joint venture between South Gas Co, Shell and Mitsubishi, will export gas from southern Iraq even though it does not own the gas. It is possible to build an export scheme on similar basis as the BGC around any gas field. In this case the contractor would build the facilities and infrastructure for exporting gas and an agreement with the ministry of oil would determine the terms to achieve his interests without owning the gas. For example, an agreement to establish a joint venture could include a certain percentage of the gas export price. The contractor can also invest in the export facilities and receive a fee for processing the gas for export. These are all issues that can be agreed in time.
Q: Why did you dismiss the initial idea you had of announcing the maximum remuneration fee before the bidding starts?
A: It is true we did have a discussion about doing that when we were preparing to launch the fourth bid round. However, because we can never be certain about the figure since it is all built on assumptions related to production and costs, the risk would be too high for us. We ran the risk of announcing a higher figure for the remuneration fee than that calculated by the companies, then the companies would bid a fee close to the ministry’s while it could have been much lower had we not announced ours. This would result in big losses for the ministry.
Q: Why not agree the remuneration fee after the discovery is made and confirmed?
A: This would require entering into negotiations with the contractor after the discovery is made and after it is approved. However, the approval itself depends on the economics of the project which require that the fee is known by then. This means that we would be entering into negotiations before we can confirm the commerciality of a discovery which would lead to nowhere because at that stage the companies’ interest would be to exaggerate the costs and disagreements would follow. Reaching an agreement could take a long time and we do not have the luxury of time. We need to find the gas and produce it as soon as possible. Add to this that the figure would never be accurate even then because we would be relying on results from just one or two wells to build an economic model.
Q: However, it is customary in the industry to negotiate the development terms after a discovery is made and confirmed.
A: In our view, and based on our limited capabilities, it would be difficult to reach agreement at a later stage. Disagreements over small issues could drag on for a long time and as I said we do not have time. We do need to find gas and develop it and produce it as soon as we can to satisfy the local needs.
Q: Is there a mechanism that guarantees that the remuneration fees agreed in advance are not too high or too low?
A: Well, this is the risk that we are taking and we accept it. To start with, the remuneration fees we will fix will be acceptable to us. At the end of the day, what determines whether the remuneration fee is too high or too low is the oil or gas in place and the reserves. This is what will determine in due time whether the remuneration fee we chose is to our benefit or to that of the contractor or to both.
Q: What IRR (internal rate of return) do you expect the companies to achieve in the exploration round?
A: It will be a reasonable IRR. When we look at the possible return on the investment, we look not just at the IRR but also the NPV (net present value) on big and medium projects as well as on small projects of say $100 million. We also take into consideration the discounted profitability ratio and whether it’s reasonable or not. We look at all three factors at the same time and if the result is positive, we tend to choose the remuneration fee that achieves this. I will not reveal any figures at this stage because it is not possible to announce the IRR we used in our calculations ahead of the bidding. But in any case, we would not base our calculation on a rate that does not achieve the companies’ interest. Our objective is not to infringe a loss on companies. For that reason the IRR that we considered cannot be 8% or 9% for example, because in such a case we will not be able to award any contracts since the companies will not bid anything close to what we find acceptable. Our objective is to award contracts because as I said our interest is to discover gas reserves and develop them and so our interest is that the companies achieve a reasonable rate of return. Any company that bids something that is based on a loss just to get a contract will not be able to implement such a contract, and either the performance will be unacceptable to us or the company itself will withdraw eventually. This is not in our interest.
Q: How do you evaluate the bidding in the previous rounds and what lessons do you draw from the low fees that were bid?
A: The previous rounds were very critical and the fees that were bid for certain fields by some companies in order to win contracts were critical too. In other words, the profitability was at its minimum. The problem with such critical fees is that any obstacles or delays would have a negative impact on the implementation of the contract based on the production levels that were bid and contracted. We hope that companies will not repeat that experience and would not bid very critical fees in the upcoming round. We know that competition pushes companies to reduce the fees they bid and as a result there will be a very thin line between the profit and loss calculations. The ministry of oil does not bear any responsibility for this. It is the companies’ choice. So if they make a loss they should not blame it on us. I acknowledge that in certain cases there were delays in the commitments undertaken by the ministry or by South Oil Co which resulted in delays on the part of the contractors but these will be taken into consideration in time.
Q: Would there be a rescheduling of the commitments undertaken in the contracts to account for these delays in commitments?
A: Not at this stage. There are reasons behind the delays which in part are due to the fact that it’s a whole new experience for the ministry of oil as well as to the companies. The ministry did have impressive capabilities before the occupation but not anymore. For the current workforce, it’s a new experience and the expertise and capabilities we have do not rise up to the scope of work and the requirements of the contracts, so delays were expected and they have happened. But I do believe that all these delays we have witnessed over the first two years of the implementation of the contracts will end this year and next and if any delays take place in the future they will be very limited. I also expect the performance of the upstream companies in the south, the north, and the midlands to improve considerably so that no delays would impact the commitments of the contractor undertaken in the contract, or the cost recovery and fees payments. The lessons of the previous rounds have been learnt.
Q: Why does the draft contract of the fourth bid round then include a clause on possible delays in carrying out petroleum operations that the ministry could request if it’s not ready for the gas offtake, which is by itself a source of concern for the bidders?
A: The is a contractual matter that deals with the possibility that the Iraqi upstream company require no more than a few months delay, but this has no impact on the economics of the project because it is a short delay. For that reason we did not consider there is a need for the ministry to commit to anything in this case or pay compensation. This is a different case from constraints on oil production in previous contracts where the contractor is compensated by getting his fees even if output is constrained. Here we are not talking about huge delays, and it does not mean we will not carry out our commitments regarding infrastructure and others, but only about operational delays that are not considerable.
Q: Who will build the infrastructure for the delivery of gas after it’s produced?
A: The contract lays this responsibility with the contractor in coordination and in full agreement with the ministry. The contractor is responsible for constructing the infrastructure up to the delivery point and also any infrastructure beyond that for which he gets cost repayment. This is actually an incentive to invest because the contractor will guarantee that this infrastructure is ready since it is his responsibility to make sure it is. For example, if the delivery point happens to be at a median point between the field and a power plant, we would ask the contractor to build the delivery line up to the plant and it is his interest to do so.
Q: How do you deal with an oil discovery in a gas field and a gas discovery in an oil field in the contract?
A: To start with, the fees paid for an oil field are different from those applied to gas fields. It is not possible to pay fees that are fixed for a gas field development for the development of oil. In any case, any oil discovery will not be developed without the approval of the oil ministry, be it an independent commercial discovery or limited amounts of oil. As the contract stipulates, the development of such a discovery would require first the approval of the upstream company and then would require new negotiations to agree the fees to be paid for such development. The same principle applies when gas volumes are discovered in an oil field. But these are exceptional cases.
Q: Why did you set a 40-year term for the gas contract and a 30-year term for the oil contract?
A: Aside from the fact that gas requires longer time to market, some companies have suggested longer period for gas development for reasons of economics. Our own calculations have shown that it is also in our interest to have a longer development period because repayment of costs will be over a much longer time. So these long terms do not cause any loss to us, on the contrary, it is in our economic interest to pay over a longer term.
Q: How many of the 47 prequalified companies have paid participation fees and how many are classified as operators?
A: About 38 companies have paid participation fees in order to be able to place a bid. Of these, there are about 20 operators and 18 non-operators.
Q: Is the modification of the termination clause in the final draft of the fourth bid round contract to include signing contracts with other authorities than the central government and the widening of the definition “law” to include regulations and policies of the ministry of oil a result of the experience you had with ExxonMobil?
A: The previous contract did contain such clause but it was indirectly stated and did not impose legal and contractual obligations on the contractor. It did state that oil and gas in all of Iraq is the property of all the Iraqi people and that the Iraqi government as representative of the entire population has the exclusive right to exploit, explore and produce the oil and gas. What happened is that the issue with ExxonMobil and its signing of contracts with the Kurdistan region of Iraq came up before we finalized the draft contract so we decided to include an obligation on the side of the companies who prequalify by the ministry or sign contracts with it not to work in any area of Iraq – not just the Kurdistan region – without the approval of the federal government as represented by the ministry of oil. So a paragraph was added to the termination clause that states that any company that violates the law or that enter into agreements and contracts without the approval of the government will have its contract terminated and will lose all rights stipulated in the contract. All these issues are now clearly stated in the current contract. Yes, this is one of the lessons drawn from the ExxonMobil case.
Q: Were you surprised to see ExxonMobil sign contracts with the Kurdistan region? Did you consider it unthinkable when you drafted the previous contracts?
A: We never imagined that any company, especially one with the stature of ExxonMobil and with the weight it carries worldwide and a reputation to uphold, would commit an act that contravenes with the laws and policies and that infringe on the authorities of the ministry of oil and the federal government. The breach is clear here. We never expected it from any of the companies and we still don’t expect such an act from any company. We are still in dispute with ExxonMobil. The issue is not close yet even though it’s taking a long time to settle.
Q: How did you settle the case of making more than one discovery in one contract area which was raised in discussions with the companies over the earlier drafts of the contract?
A: The issue that was raised concerns the minimum threshold of 200 million barrel of oil equivalent (boe) over the contract term that the ministry of oil has fixed for declaring a discovery as commercial. The companies’ concern was related to discoveries that might not make the threshold but that are within the contract area where other commercial discoveries exist and whether in this case they can be developed as commercial discoveries or not. In the final draft, we dealt with such a discovery by stating that the upstream company would be willing to classify it as commercial even if it does not make the threshold as long as it’s developed and produced as part of an existing development area. This applies even in a case where it’s not an oil discovery within an oil field area or a gas discovery within a gas field area. Such a find could still be developed even if it produces less than 200 million boe over the contract term.
Q: What was the basis for choosing 200 million boe to declare a find commercial?
A: The choice of this minimum was based on comparisons with the Siba gas field. In our view, Siba gas field, which was the smallest of all fields offered in the previous three rounds, can produce about 200 million boe of gas. So we decided to use it as the parameter to determine the commerciality of any discovery. We also conducted a feasibility study based on a discovery of 200 million boe in order to determine whether it’s economically feasible to produce such a discovery and to use this in case we need to prove that it is feasible to develop even a small discovery. So despite the companies’ arguments for a lower threshold, we decided this will be the base for declaring the commerciality of any discovery and anything below that would not be commercially or economically feasible enough to allow the ministry to develop it and carry costs that are too high for very little gas.
Q: Why did you choose to make payment in kind to the companies’ in the fourth bid round contract and not in cash as in previous contracts?
A: The reason is that Iraq will be producing a lot of oil in a few years and production will be increasing just as the potential new fields in this round are estimated to come on stream. If we assume that the volumes contracted based on the first two rounds – more than 10 million b/d – will be produced, it is going to be a challenge to market those volumes as well as catering for them in terms of transportation and storage. It also means that we would have to find buyers in order to sell our oil and then pay the contractors. So we opted to pay the contractors in kind instead of looking for additional markets and buyers.
Q: Why did you cancel the state partner in the fourth round contract?
A: The idea behind including a state partner share in the previous contracts was not for economic or commercial purposes. There is no such economic or commercial advantage since the part of the fee that goes to the state partner – which is 25% – is in fact paid by the government and is not deducted from the contractor’s fee, as it is wrongly assumed. The other reason for including it in previous rounds was to build the capabilities of our staff through their participation, in the state partner role, in the discussions of the plans and the budgets and calculations of costs and gaining a certain experience in those matters. Removing the state partner from the fourth bid round contract will reduce the remuneration fees to an acceptable level. Since the highest remuneration fee we set in previous rounds was $7.5/bbl, had we included the state partner’s share in our calculations this time the fees we set would appear as if multiplied by 3 or 4 to become acceptable. Instead, we chose to cancel the state partner and bring down the maximum remuneration fees.
Q: Why does the fourth bid round contract include a signature bonus but not a discovery bonus as it is customary in exploration contracts?
A: Any money paid by the contractor will be reflected in higher fees. When we did our calculations based on a discovery bonus and again without it, it was reflected in higher figures in the first case. We chose the remuneration fees carefully and in a way that does not reflect exaggerated figures. We also put signature bonuses at a level that does not impact the remuneration fee calculation. It is wrongly assumed that the contractor pays those bonuses from his own pocket when in fact it is repaid as part of the remuneration fee.
Q: Why include a signature bonus in this case?
A: Because it is a tradition to include a signature bonus and because it is additional funds that enter the state treasury and is repaid over a long period of time that starts with the development seven years after the effective date, and can take 20 or 30 years to repay. It is also small amounts of money the biggest of which is $25 million. It is worth noting here that in the previous rounds, and despite their expertise and financial awareness, the companies entered into contracts as if completely devoid of financial experience because the figures and the remuneration fees they bid were too low. At the time, we did not include the signature bonus in our calculations of the remuneration fee or the cash flows. We assumed that the signature bonus is not repaid. I admit with retrospect that it was maybe an overzealous nationalistic thinking. But even though we did not include the bonus, the companies bid lower fees than those fixed by the ministry. In the fourth round, we want it to be fair to the companies and want the contract to be more attractive especially because it’s exploration.