Assisting the Asset Manager to Obtain the Most Favorable Possible Allocation of Funds - Coursework Example

Scenario The year is now and you are a team member in the asset that is the of Assessment Existing wells and infrastructure are as shown in figure 1, which also includes the deep gas development well G-3, scheduled to be drilled in 2015, budgets and economics permitting, and the next planned deep gas well, G-4. Associated and non-associated gas that is surplus to asset power generation requirements is sold to a power station to the northeast of the site. Oil and gas pipelines run from the Southern Gathering Station (SGS) and the Northern Gathering Station (NGS) to the Terminal, from which there is a single gas line to the external power station and a single oil line to the Single Buoy Mooring (SBM). The general strategy for the asset remains to maintain a positive cash flow at least until the end of 2023, but not to guarantee this situation much beyond that point. This is because under the Production Sharing Agreement with the host government your company is obliged to hand back an economic asset on 1.1.2024, and it wishes to extract maximum benefit before that date. There is also currently no provision for any form of tax relief against asset decommissioning costs incurred by your company, so not only running at a loss but also early abandonment is to be avoided. You are, however, given no information on forecast total asset revenues and costs in the Appendix, so your best personal strategy is to obtain maximum funding for an optimum project portfolio, in 2015 and in future years. Corporate Planning advises that the Project Screening Value for local quality crude oil to be applied in economic evaluation is $97.6/bbl RT 1.7.2014 in the remainder of 2014 and in all future years. The contract governing gas sales to the local power station means that the corresponding gas price is $2.44/mmscf RT 1.7.2014, again for the balance of 2014 and in all future years. They have decided to maintain the policy of applying a real terms discount rate of 15% pa to exploration, appraisal and Greenfield development projects in this (East African) region. Your parent company’s weighted average cost of capital is forecast to be 6% pa after tax for the foreseeable future, and the purchasing power of the US dollar is predicted to decline steadily at the rate of 2% pa. For all the candidate projects considered here, incremental tax and tax relief can be modeled as an 84% government take, with no delay in payment or repayment versus the timing of the associated revenues or costs. Bearing in mind the asset production decline rate of 22% pa for oil wells and 8% pa for gas wells, and the year-on-year reduction in the time remaining before handback of the asset to the government, barring any hydrocarbon price shocks the nonessential activities budget is likely to decline by around 30% pa, which is in line with recent history. No drilling, well maintenance (except in emergency) or infrastructure development can be carried out during the monsoon season, April to June inclusive. Potential Projects Data Development Drilling (Project A): The first well, G-1, in the recently developed deep non-associated gas reservoir was drilled in 2013. Well G-2 will be drilled immediately after the end of the 2014 monsoon season, ie around 1 July. The deep gas reservoir is believed to be able to support a total of 8 similar wells. Given that the period 2015-2023, running up to asset hand-back, is only 9 years and that production from G-1 suggests an 8% pa decline rate, the Asset Manager is willing to consider proposing to Corporate Planning that both G-3 and G-4 be drilled in 2015. Drilling each deep gas well takes 8 weeks. Important: if you propose drilling well G-4, you must modify the economic results of Project A (Well G-3) in recognition of the fact that its flowline will cost $3.76m RT 1.7.2014 whereas the G-3 flowline cost is $6.92m RT 1.7.2014. Ideally you will also reflect the economic impact of the spud date you propose to the Asset Manager for any development well. Well G-4 may not be drilled before G-3 under any circumstances, as the well sequence and locations are determined by reservoir management considerations. Given the generally low level of drilling and workover activity forecast for your asset, there is no justification for owning or leasing more than one land rig. In its generalised form, it is important to establish that the optimisation of the CAPEX and OPEX are both directed at the generation of capital fund revenue for the company: only that they are to be done in two different fashions. For the 100m CAPEX, any spending decisions made on it must be one that can potentially increase the wealth or value of assets that are already in place and that will become useful beyond the given tax year (quote). On the part of the 20m OPEX, it would also be expected to be used in a more value for money fashion even though they have to be used to cater for expenses that will be incurred whiles the project is underway (quote). Given the prevailing background, it is strongly recommended that for the development drilling, both G-3 and G-4 be drilled in 2015. This is because of the collective wealth creation that will accrue from the two wells when drilled concurrently. For example, it is said that the value of G-1 will decline by a percentage rate of 8% per annum. What this means is that if the company would opt for periodic drilling whereby it would consider drilling G-3 alone in 2015 and drilling the G-4 in subsequent years, the quantitative value of well will be reduced. What is more, there are rooms for uncertainties, which may mean that the 8% decline per annum would even worsen. Having made all these points, it is perfectly agreed that the drilling of the two wells at a go will come with a large tone of outright expenditure but considering the fact that the percentage of capital expense in that expenditure will be higher than the operational expense, the company cannot be said to be on a losing way if this action is taken. Sidetracks (Project B) The long reach coastal wells N-7, N-8, S-7, S-8 and S-9 have very high water cuts and economic pre-screening has shown that it is now too late in the asset life to convert them economically to water injection service. If they are sidetracked to the northwest, reservoir connectivity is such that they will act predominantly as acceleration projects rather than tapping otherwise inaccessible oil. Each sidetrack will take 6 weeks. Important: if you decide to sidetrack any of these wells, you do not have to include all 5 in your plan for 2015. The economics of each will be as for one fifth of the Project B economically evaluated in the Appendix. Ideally, however, as for all activities, you will reflect the economic impact of the precise timing you propose. Clearly, to sidetrack the coastal wells will yield very little economic value to the project as the sidetracks do not guarantee any reasonable tapping of inaccessible oil. Worse of all, it is presently not prudent to convert them to water injection service as the economic pre-screening suggests. In the light of all of this, the best recommendation that is given on the long reach coastal wells is for the project seekers to undertake selective sidetracks. This is recommendation is made against the background that a decision to totally ignore the long reach coastal wells N-7, N-8, S-7, S-8 and S-9 will be a major hindrance to the reservoir connectivity and projected sequence of the workflow. In this regard, the medial coastal wells namely S-7, S-8 and N-7 are recommended to be sidetracked. If for nothing at all, for the year 2015, only a part of the available long reach coastal wells can be sidetracked. Given the fact that the economics of each will be as for one fifth of the major project also, not much of the available expenditure in the form of capital expenditure and operational expenditure will be expected to be invested in this area. Particularly so for there to be a cut out on the cost of these sidetracks is the fact that the sidetrack yields no direct economic benefit for the project owners in terms of oil extraction (quote) and would therefore come under the revenue expenditure. Meanwhile, this is expenditure with a total worth of 20m only and so should not be channelled towards sectors with no proven economic yielding. Corrosion Workovers (Project C) The southwestern sector of the oilfield is subject to relatively severe corrosion problems as a result of higher levels of both H2S and CO2 in the associated gas. Vertical wells S-5 and 6 are currently closed in, with tubing and liner leaks. It is believed that use of special steel in completions will reduce the annual failure rate from 25% to 10%, and the economic evaluation spreadsheet for Project C is based on this strategy. Each workover takes 3 weeks. You may opt for standard completions, but the economics for a corrosion workover will then be as for a sand screen change-out (Project D). Each workover takes 3 weeks. Important: if you decide to repair either of these wells, you do not have to include both in your plan for 2015. The economics of each will be as for one half of Project C or Project D, depending on the technical option you select. Ideally, however, as for all activities, you will reflect the economic impact of the precise timing you propose. Spending on the corrosion workovers out of the stipulated 100m CAPEX and 20m OPEX would be based mainly on the timing within which these operations could be completed. The implication here is that already, the need to have a combined development drilling for project one is being advocated and so not much extra-drilling costs can be incurred. However, each of the vertical wells S-5 and S-6 could have their own economic benefits if invested into and added to the volume of oil that can be drilled. Ideally therefore, selective workover needs to be done. If for nothing at all, when investment is made with special steel in completion, there will be a reduction in the annual failure rates by 15%, which could be calculated in economic wise to mean some substantial wealth of money. In relation to the selection of which of the wells to be repaired, premium will be placed on proximity in the sense that a technique of using special steel, which could have a high rising economic impact will be used. In light of this, it would be necessary to limit all possible untracked expenses. Using proximity to select the closes well among the two would also ensure that the time to be carried out in undertaking this project is beaten down so that intensive work can begin on the combined development drilling. Finally, the movement of equipment to the site for the repair works will be favoured and this will in turn cut down on cost if proximity measures are used to select the closest among the two well for repairs to take place. Sand Screen Change-out Workovers (Project D) Vertical wells N-4 and N-6 are currently closed in awaiting replacement of their sand screens. Each workover will take 3 weeks. Discounting the 5 long reach coastal wells, whose only usefulness relies on future sidetracking, there are 8 other vertical wells, which are likely to generate 2 workovers per year unless special steel completions are installed in sour gas locations. Important: if you decide to repair either N-4 or N-6, you do not have to include both in your plan for 2015. The economics of each will be as for one half of Project D. Ideally, however, as for all activities, you will reflect the economic impact of the precise timing you propose. Onshore ESPs (Project E) The general strategy for the asset described in the Scenario section requires that in addition to the planned total of 8 deep gas wells action be taken to reduce the production decline rate in the oilfield. Pre-screening economics indicate that there is too little oil remaining onshore for retrofitting of water injection facilities to be commercially justified and that gas lift economics are severely impacted by the initial gas inventory required in each well. Installation of electrical submersible pumps is therefore the preferred technical option. The impact of each ESP is approximately to restore a well to its production rate of 2 years earlier. Project E represents installation of ESPs in all of the 4 candidate workover wells. If you install an ESP while the corresponding well is being repaired, the incremental rig time required is 0.5 days per well. That well will not be able to produce, however, until electrical power is hooked up on 10 November 2015, so you must take account of the corresponding production deferment costs set out in Table 1. If you install an ESP independently of the repair of the corresponding well, the incremental rig time required is 3 days per well, and again the well will not be able to produce until 10 November 2015. If installation takes place after 10 November 2015 you must reflect the corresponding production deferment costs, set out in Table 1. The Project E economics in the Appendix are invalid if you install an ESP in a damaged well which is not worked over by 10 November 2015. Important: you may proceed with Project E without installing ESPs in all of the 4 candidate workover wells. Indeed, you have been advised not to install an ESP in a well still awaiting repair at 10 November 2015. If you install pumps in fewer than 4 wells, however, you must reflect the reduced production benefits by modifying the Project E economics accordingly. These benefits are proportional to the number of ESPs. Project E must in any case, however, carry the full $24m cost of power generation facilities at the terminal and the $12m cost of infrastructure for transmission into the field, plus future maintenance of these. These facilities are sized for 12 ESP installations and their construction will take 12 weeks. Offshore ESPs (Project F) The same comments with regard to water injection and gas lift apply as onshore. Project F represents installation of ESPs in wells A-1 and B-1 using a drilling barge. The power generation and infrastructure CAPEX modeled is incremental to Project E. Each offshore workover takes 4 weeks, including ESP installation, cabling and electrical hook-up. Important: you may proceed with Project F without installing ESPs in both of the offshore wells. If you install a pump in only one well, however, you must reflect a halving of the production benefits by modifying the Project F economics accordingly. You may also proceed with Project F without investing in Project E, but in this case you must add the $36m of power generation and infrastructure CAPEX from Project E, since Project F was modeled as incremental to project E, and recalculate the economics accordingly. Deferment Costs The production deferment costs referred to above, calculated after tax, are as follows: Question You are charged with assisting the Asset Manager to obtain the most favourable possible allocation of funds, to be spent in 2015, during your company’s annual corporate budgeting process in September 2014. Discretionary activities in your asset have to compete, on an individual project basis, with individual activities in other assets worldwide. Indications from Corporate Planning are that in the “first cut” of the annual budget exercise, $100m will be available to your asset for capital expenditure (CAPEX) on non-essential activities in 2015 and $20m for revenue expenditure (OPEX) on these activities. Essential in this context, applying to all other activities, means required by law or in order to maintain the Certificate of Fitness to operate the asset, or already committed. Committed expenditure relates to projects whose budgets were approved in earlier years, including ongoing operating costs but not well workovers. Task 1: The Discount Rate (Approx 200 words) - Discuss, in no more than 100 words, various considerations that apply to the selection of a discount rate for use in the economic evaluation of projects in general. In the selection of a discount rate for use, two major considerations are made as ways of ensuring that a comprehensive investment analysis method is selected. These considerations are the internal rate of return (IRR) and net present value (NPV). The internal rate of return is made on discount rate as it represents the effective interest rate that the company enjoys on its investments (quote). The net present value on the other hand gives a measure of the difference between present value of cash inflows and existing value of cash outflows (quote). These two are considered viable considerations because they aid in analysing the profitability of the given investment. - Explain in no more than 100 words the discount rate you would prefer to use when evaluating the 6 projects included in the Appendix, taking into account the above consideration and the policy statements stated in the above Scenario section. Given the 6 projects that have been earmarked by the company, the best form of discount rate that will be preferred would be the Weighted Average Cost of Capital. This is selected against the backdrop that it helps in identifying the cost of working capital available to the company (quote). This is done by way of calculating the individual rates at which the company is expected to execute payment on average to its securities so as to clear or finance its capital assets. The weighted average cost of capital (WACC) is preferred over others as it holds the potential of ensuring that payment of security holders are not done offhand but on an average basis to ensure that the net present value can be measured. Task 2: Optimisation (Approx 1500 words): Summarize how you recommend that up to $100m RT 1.7.2014 of CAPEX and up to $20m RT 1.7.2014 of OPEX should be spent in 2015 on activities selected from the Appendix, bearing in mind the comments made throughout this assessment, and explain how you have arrived at your recommendations, including project screening and ranking and strategic considerations. Your summary should be in the form of a drilling sequence for the asset land rig, showing any concurrent activities offshore. A simple table listing the activities and their start and end dates will suffice. For the sake of brevity you may use the letter codes for the various projects, but be sure to distinguish between well G-3 and G-4 (if applicable) and to specify the number of wells selected from each of the other letter codes. Important: do not write about the technical background to the projects, as project sponsors among your colleagues have will have briefed the Asset Manager. Neither should you make comments about the general role of project economic evaluation, as this will be well understood by him and by the Corporate Planning representatives who will collect data from you for the September Budget Exercise. You will only receive credit for showing how you apply the principles you have learned in this module to the specific practical task of optimizing the 2015 discretionary activities within the constraints imposed on you. Remember that your asset is competing on a global scale with the rest of your company for funds. Task 3: Handling Data Uncertainties (Approx 300 words): In doing task 2, all your evaluations have been based on point estimates for various project variables. Discuss how your solution approach should be tailored to handle each of the following scenarios. You do not have to implement your tailored approach (es). However, you are required to reflect on any disadvantages a tailored approach may have and explain how to work around them. - The Project Screening Value for local quality crude oil to be applied in economic evaluation has a significant range of possible values of $90 to $110/bbl RT 1.7.2014. The solution approach will be tailed in relation to the internal rate of return (IRR) when the predicted economic performance of the present oil drilling project is placed at a value of $90 to $110/bbl from 1st July 2014. With this, once the internal rate of return (IRR) exceeds the predicted hurdle, the asset management team and for that matter the asset manager can easily get the indication of the need to proceed with the project. But if the internal rate of return (IRR) does not reach the threshold or hurdle, then the best action to take would be to reject the present state of the value (quote). - The gas price is represented by a triangular probability distribution (minimum $4, mode $4.88 and maximum of $5.40)/mmscf RT 1.7.2014. With the given values, the input value can easily be found to undertake an input into the prevailing PERT. Subsequently, the critical path method (CPM) will be computed in coming out with a model that best yields commercial monetary value for the current range. In practice therefore, the gas price will be approached such that all major dependencies that would ensure that the maximum price is reached will be advocated while shedding less focus for dependencies that shifts the price towards the minimum. In its worse form scenario, the least bargain that should be permitted should be that of the mode or average cost price. - All cost estimates have significant range of possible values of their best estimates +/- 10%. Cost estimate range of +/-10% is rather on the higher sides and would need rapid intervention that is aimed at reducing the range. Even though the range could generally accepted to an average of the actual cost inflows and outflows, it is always alarming to leave the estimates at such higher ranges when the calculations of the accounting team can be trusted. What is even more disturbing is the fact that the company will be dealing with a situation whereby very huge market cost will be dealt with. Consequently, the range of 10% from such values when quantified would give a turnover of huge prices. Read More