Making A Case For Heavy Crude, Part 1 - Crude Upgraders
By M. Simchi, PRMIA Calgary
Introduction
With the recent surge in global demand for crude oil and the consequential rise of its price, Heavy Crude Upgrader (HCU) projects have had a come back to the spot light. Global consumption of crude oil is about 84 MM Bbls a day and it seems that this demand is not decreasing any time soon. Moreover, the majority of this demand in the industrial world is due to the demand for gasoline and diesel fuel for transportation. To convert the crude oil to transportation fuel refineries need to separate the distillates and convert the bottom of the barrel material to the required products through cracking and cocking processes. The efficiency of this process is crucially related to the quality of the input crude. As a rule, the sweeter and the lighter the input crude, the easier the processes. Such a relationship has put an upward pressure on the price of sweet and light crudes such as WTI, whereas the heavy and sour blends are sold at discounts.
Experience has demonstrated that the reserves of the sweet and light crude are becoming more scarce. It seems that the majority of WTI-like crude reserves in North America have already been found and are being depleted. Moreover, the API of crude blends from the Middle East, the largest producer of this commodity by far, ranges around 32 or lower. As a result, there has been a relative glut of heavy/sour crude in the market and the heavy crude differentials have widened to historical highs. Considering the fact that there are only a limited number of refineries in North America, the downward pressure on heavy crude has been ever increasing. This phenomenon is a major cause of concern for the producers and their corresponding states. As a result, major state owned producers such as Saudi Aramco and Venezuela's PDVSA have made considerable investments in refineries in North America.
However, in free market environments such as Canada the governments rarely invest in such projects. Moreover, refinery projects are extremely complicated and need substantial amount of capital to install heavy crude processing capacity. Also obviously, it is much easier to add a cocker to an existing facility than to build a brand new one. As a result, building extra refining capacity exceeds the ability of the small and medium size producers. Considering that refinery is not the core business of most of the major producers in Canada, it is hard to justify such a project at all.
State owned and private producers of heavy crude are among the major stake holders in this regard and need to seek other solutions to materialize the optimal use of their crude oil. These solutions not only have to be beneficial in a short run, but also have to ensure business continuity and economic growth for on a long term basis. They should provide sustainable employment, improve the technical and intellectual capital and keep the potential upside value of the commodity with the producers. Two of projects that have the potential to deliver such a variety of effects are:
1. Building Crude Oil Pipelines to diversify the delivery of crude to alternative markets.
2. Building Heavy Crude Upgraders to convert heavy.
For example, Canada has had a long standing experience in operating and regulating pipelines such as Transcanada and Alliance pipelines. The tariff system in Canada is well established and the governance and control mechanisms are sound. Moreover, there exist a few upgrading units in Alberta and Saskatchewan with extensive amounts of experience and skill. Noting that all the tar sand projects in Alberta include upgrading units, a heavy crude upgrading unit will be well positioned to be inline with Alberta's long term plans. One should also notice that the above projects are rather complimentary than being exclusive. An HCU along with a pipeline will ensure high quality crude oil with a diversified portfolio of delivery locations and potential customers.
The current article analyzes a typical heavy crude upgrader from the quantitative and financial point of view. A complete analysis of such a project is an extensive task on itself and is beyond the scope of this article. In this article however, we present main steps in such an evaluation and point out to some of the potentially risky spots. We will limit our analysis to a producer's point of view and try to hedge the crude differential such that the cost of production is reflected in the price of input heavy crude. We will study the monetary value of such a project and will take into account functionality and constraints of it. We will also point out some of the imbedded assumptions in such a project and demonstrate their consequences. We will study two hedging schemes and will study the implications of cost over-runs.
Budgeting an Upgrading Unit
Heavy crude upgrading units possess unique characteristics that make their valuations complicated. On the negative side these units:
- Are long term projects.
- Require substantial capital costs.
- Have long development phase.
- Include variable costs that are market dependent.
- Contain up-keep and non-recoverable costs.
- Impose potential environmental costs.
However, on the positive side they:
- Are value added units.
- Are strategically in line with producing heavy crude oil.
- Reduce market exposures to crude differentials.
- Take advantage of dynamic input and output markets.
The operational functionality offered by an upgrading unit is the main source of the value added that otherwise will not exist. To elaborate on this point, we consider two phases of such a project.
1 - Development Phase:
During this phase the capital is spend in developing the project. At any instance of the time the owner of the project may estimate the value of the future cash flows and determine if the project will be in the money or not. At the end of this phase, the owner can decide whether to go ahead with operating the plant or not. At this stage, if the present value of the future cash flows is greater than the development costs, then the project will be in the money. Otherwise the project will be out of the money. Hence, during the development phase, the owner of the plant has an out of the money Call Option.
2 - Utilization Phase:
At this phase, the owner has two choices. If the differential is wider than the operational costs, the owner will run the plant and materialize the spread net of the operation costs. If the spread narrows bellow the operation costs, then the owner has the option to shut down the plant and wait for favourable market conditions to return. Therefore, during the utilization phase, the owner owns a possible stream of cash flows as well as a Put Option.
The Financial Analysis
For our analysis we consider the following simplified upgrading unit:
1. Capital: $1 Billion
2. Operational Costs: $6.50 /Bbl
3. Fixed Costs: $2.50 /Bbl
4. Total capacity: 60,000 Bbl/Day
5. Input Mix: Heavy Crude
6. Output Mix: Light Sweet Crude
We also assume the forecast market of:
1. Heavy crude: $25 /Bbl
2. Long term Sweet crude: $35 /Bbl
3. Tax rate: 25% 4. Interest rate: 5%
The first part of our analysis is to determine the present value of the optionality offered by the plant construction and operation. The following graph shows the final result of such computations.
This graph demonstrates a few points. First, our proposed plant is slightly out of the money. That is, even with the optionalities provided by the plant, the value added of the plant does not justify the capital expenditure of the project. Second, the break-even capital expenditure is about $980 MM. In order to make the plant profitable, steps have to be taken to reduce the capital needed. The net impact of such measures can be derived from the above graph. Third, the relatively steep slope of the Break Even Curve (the blue curve) shows that the project is very sensitive to cost over-runs.
However, the above graph does not identify the price regimes in which the plant will actually be functional. That is there will be a minimum price of sweet crude bellow which the plant's operation will not begin. We refer to this threshold price as the hurdle price. The hurdle price is the equivalent WTI price where the transition of the plant from the development phase to the operational phase will occur. The hurdle price is an extremely important concept because, if the WTI price stays bellow such a level the capital invested in developing the plant will not be recovered. Projects with high hurdle prices are more risky to run and are very sensitive to cost over-runs. On the other hand, low hurdle prices allow the plant to stay profitable in weaker economic environments and will reduce the probability of plant shut downs and their economic impacts. The following graph shows the hurdle prices implied by the capital structure of the plant.
This graph demonstrates that for the project to be valuable, the price of WTI has to cross the $53/ Bbl. Moreover, even a reduction of $100 MM in project expenses will still require $52 /Bbl of WTI price. It's also important to notice that in case of cost over-runs, the validity of such a project is in serious doubt. A 20% cost over-run will demand WTI prices close to $56 /Bbl, raising the specter of the project failing to generate enough cash flows to compensate for the capital expenditures . Obviously, the project and its hedging scheme need a substantial change. Note that since heavy crude is the input for the plant, the price of heavy behaves as an operational cost for the unit. To compensate for our uneconomic project, we change our hedge to $22 /Bbl for the heavy crude. As the result we would expect the project to be more valuable and the required effective prices to be also lower. Moreover, we would expect that the project's sensitivity to cost over-runs be milder.
As the above graph shows, our plant is well in the money and is suited to handle moderate cost over-runs. It also provides us with a way to estimate the net effects of such over-runs. To assess the implied WTI prices we use the following graph.
As the above graphs exhibits, our implied WTI equivalent price is now $46 /Bbl. Moreover, even with 20% cost over-runs the plant is still valuable and there is a better chance of recovering the costs and the return on capital. The following graph presents the return on the capital based on the cost structure of the plant.
Conclusion
Heavy Crude Upgrading projects have significant long term economical values. They are strategically in line with the producers' position and are complimentary to its existing and proposed projects. However, before building these plants a detailed analysis of their financial structure and return on capital must be performed. Because of their imbedded optionality, these plants can generate significant value added. On the other hand, to use their optionalities effectively, one has to implement effective hedging policies and ensure that their implied price regimes are met. Cost over-runs need to be given proper attentions and steps must be taken such that the fixed and operational costs will not materially deviate from their designed values.
Acknowledgement
The author would like to express his gratitude to Steven Reilly, the VP. Risk at Nexen Inc., for his constructive comments and insight.