Implications of Residual Fuel Oil Phase Out

Transcription

1 Implications of Residual Fuel Oil Phase Out By David Ramberg, Center for Energy and Environmental Policy Research and the Joint Program on the Science and Policy of Global Change, Massachusetts Institute of Technology, 77 Massachusetts Ave., Cambridge, MA 02139, E19-411, Phone: /Fax: , and Sam Van Vactor, Economic Insight, Inc., , Abstract By 2020, the International Convention for Prevention of Pollution from Ships (MARPOL), adopted by the International Maritime Organization (IMO), will mandate that no marine vessel will be allowed to consume fuel with a sulfur content greater than 0.1%. Since current bunker fuels generally contain more than 3% sulfur, residual fuel oil may very well be phased out of the markets. Whether (and to what extent) this occurs depends on the interaction between the decisions of refiners, the demand for boiler fuels in general, and the supply/demand balance of boiler fuel alternatives. This paper examines refiners decisionmaking processes with regard to the destruction of residuum, which can be either further refined into light products or blended into residual fuel oil. A simple residuum upgrading model is developed and its logic is briefly tested with empirical data. Current trends in the usage of residual fuel oils and bunker fuels, as well as the relative supply of heavy vs. light crude oils, are examined in the context of the refiner model to determine the likely fate of residual fuel oils. The focus is on background and a characterization of market forces and influences rather than a rigorous test of alternative hypotheses. 1. Introduction This paper briefly examines the trends in residual fuel oil demand as well as the most common methods of disposal for refinery residuum and characterizes a plausible scenario for the future of residual fuel oil demand. The focus is on background and a characterization of market forces and influences rather than a rigorous test of alternative hypotheses. Residual fuel oil demand has been declining and is set to decline even more dramatically in the coming decade if current trends prevail. At the same time, refiners are finding ever-heavier crude oils on their slates, with an increasing amount of residuum content. Other than asphalt production, the two principal methods for residuum disposal are blending into residual fuel oil and coking. Thus, further decline in the residual fuel oil market suggests a strong incentive for refiners to add additional coking capacity. 2. Status of the heavy fuel oil market 2.1 Types of refineries and the refining process Petroleum refineries are complex operations. In general, they are classified as simple or sophisticated, but within the sophisticated category there are a wide variety of options. All simple refineries have distillation towers in which crude oil is heated until various cuts boil off. When condensed, many of these cuts are similar to refined products and can be marketed 37 th IAEE International Conference, New York, NY, June 15-18,

2 with a minimum of further processing. Simple refineries have limited upgrading facilities and they sometimes sell their output to other refineries for further processing. Declining petroleum consumption since 2008 has caused many simple refineries to shut down. Sophisticated refineries start processing like the simple ones, with a distillation tower. However, they add additional steps and process the resulting cuts into marketable products with a variety of upgrading facilities. The most common of these processes are thermal and catalytic cracking. Complex refineries often have sulfur removal units and a variety of other facilities required to meet strict product standards for gasoline and low-sulfur diesel. Some sophisticated refineries go a step further and add a coking unit. Coking allows refiners to take the heaviest cut of oil, referred to as residuum, from the distillation tower and break it into lighter products such as diesel and gasoline by applying heat and catalysts. The process also produces coke, a solid carbon product not unlike coal. Cracking can also upgrade some of the residuum, but at higher marginal cost, mostly because the cracking of residuum fouls up the sensitive catalysts in the cracking units. Academically there have been few studies characterizing refinery economics. Part of the reason for this is that each refinery is uniquely designed to use specific crude oils as feedstocks and to produce a slate of products in demand in its targeted markets. That makes generic characterizations of refinery economics difficult, if not impossible. Some investigators have nonetheless produced some useful methodological contributions. Dixon produced a model-based approach for a modern coking refinery (Dixon, 2009). 1 Others have developed a model using graph theory based on the characterization of a refinery as a complex interconnected system (Sadhukhan, et al., 2003). 2 Some forward-looking researchers have also investigated the possibility of upgrading refineries to both reduce emissions and eliminate the residuum entirely (McKenna and Sheikh, 2010). Interestingly, this paper advocated the addition of a coking unit as well as a gasifier to dispose of both residuum and petroleum coke. 3 The gasified coke would be used to provide the refinery s electricity needs. In general, the literature on refinery economics is rather sparse, and is largely confined to a couple of chapters in textbooks with a broader focus on refinery processes (e.g., Gary, Handwerk, and Kaiser, 2007 and Fahim, et al., 2010). 2.2 Types of products A modern sophisticated refinery produces several dozen products. Output varies by season and in response to market prices. Refiners maintain sophisticated linear programming models that compute daily profitability based on marginal processing costs, product market prices, and crude oil costs. Every refinery begins crude processing with an atmospheric distillation tower that heats the crude feedstock to boiling. Gasified petroleum products rise through the tower, and different 1 Dixon is employed at a ConocoPhillips refinery. 2 Graph theory uses mathematical modeling to characterize relationships between elements. It is made up of hubs, called nodes or vertices, which are connected by linkages called edges. Each edge contains the information about how each node is connected to adjacent nodes. In the Sadhukhan et al. model, nodes represent refinery units, and edges track the physical flow of product between units, as well as the energy needs and other relevant information for each. 3 Increasing production of Canadian tar sands has produced a coke surplus in the Midwest. 37 th IAEE International Conference, New York, NY, June 15-18,

3 components of the crude oil condense in stacked trays positioned within the tower at decreasing temperature levels. The heavy components with higher boiling points condense in the lower trays of the tower. The components with the lowest boiling points rise to the top as gases. The top of the distillation tower produces propane, isobutene and other gases. The next set of cuts includes naphtha, which is the primary building block for gasoline. Following these light products are the middle distillates mainly kerosene and diesel. As the name implies, they are the middle part of the barrel and in many respects are the most flexible of all the cuts. That is because middle distillates can be refined into a variety of products gasoline, motor diesel, jet fuel, and heating oil. The flexibility of middle distillates makes them the most valuable part of a crude oil barrel. Once the useful cuts have boiled off, the refiner is left with the residuum, a tar-like sludge. Moreover, impurities, like sulfur, tend to collect in this last cut. In the past residuum has been a waste product. Refiners burned it or paid someone to cart it away. Except in a few jurisdictions, environmental regulations prevent such activity today. Residuum is not directly marketable. There are three main options for its disposal: 1) further processing into asphalt, 2) blending with middle distillates to market as FO-380 (the fuel is also known as residual, bunker or heavy fuel oil), and 3) upgrading residuum into coke and light petroleum products mainly middle distillates and gasoline. This paper takes the asphalt market as more or less given and focuses on the tradeoff between blending residuum for the FO-380 market or, alternatively, upgrading residuum into light petroleum products. We do not attempt to model the operations of an entire refinery, which is much more complex than the distillation tower and coker we have described. In fact, after atmospheric distillation, the residuum is passed through a vacuum distillation tower where more cuts can be extracted. The residuum of the vacuum distillation tower (eventually) becomes the feedstock for the coker. For the purposes of analysis here, it is sufficient to consider only that the refiner will always have some amount of residuum it needs to destroy, and that aside from asphalt production, the only options are coking to gases, middle distillates, and petroleum coke or blending into residual fuel oil. Before proceeding with that analysis, however, it is worth describing the FO-380 product and its associated costs of processing. Most, if not all, developed economies prohibit burning high-sulfur fuel oil, with one major exception bunker fuel for ships operating on the high seas. A small amount of lowsulfur (less than 1%) FO-380 is burned for power generation, but even this is being phased out. 4 The reason is simple economics. Diesel or light fuel oils are more efficient for use as motor oils or power generation. If refiners have to process heavy fuel to remove sulfur it is not that much more expensive to upgrade the material through coking to a middle distillate, where sulfur removal is part of the built-in process. High sulfur FO-380 is the cheapest fuel oil a refiner can make. Generally, it is about two-thirds residuum and one-third diesel. Product specifications are met by blending the two fuels. Blending is often cheaper than upgrading, but it is not costless. The blender must maintain adequate storage, including heated tanks. Moreover the market is small and sporadic, with high transaction costs. 4 A good example is Hawaii s power generation company, Hawaii Electric Co. It has announced its intention to stop using residual fuel oil in the near future and replace it with diesel (HECO, 2013). 37 th IAEE International Conference, New York, NY, June 15-18,

4 2.3 Who uses heavy fuel oil Figure 1 illustrates the trend in heavy fuel oil consumption as collected by the Energy Information Administration (EIA, 2014). Overall consumption declined 31% from 1986 through The vast share of the Figure!1:!!Residual!Oil!ConsumpIon! drop, however, was!14,000!! experienced by North America, Europe and Japan: a 54% decline. In the remainder of the world!12,000!!!10,000!! the decline was only 11.4%; consumption rose!8,000!! and then fell in China during the period, muting!6,000!! the decrease. Residual fuel oil use has declined even as world petroleum consumption has increased. In 1986 heavy fuel oil accounted for nearly 21% of total Thousand!barrels!per!day!(MB/D)!!4,000!!!2,000!!!"!!!! 1986! 1989! 1992! 1995! 1998! 2001! 2004! 2007! 2010! North!America! Europe! Japan! China! Other! Source:(EIA( petroleum consumption. By 2010 the share had fallen to around 10% (EIA, 2014). The IEA calculates similar figures 20% in 1986 and 9.5% in 2010 (IEA, 2013). 5 There have been two principal causes of the decline: first, cheaper fuels - coal and natural gas - easily substitute for heavy fuel oil in the boiler Thousand!barrels!per!day!(MB/D)!!14,000!!!12,000!!!10,000!!!8,000!!!6,000!!!4,000!!!2,000!! Figure!2:!!Bunkering!and!Non"Bunkering!Residual!Oil! ConsumpKon!!"!!!! 1986! 1989! 1992! 1995! 1998! 2001! 2004! 2007! 2010! North!America! Europe! Japan! China! Other! World!Bunker! Source:(EIA( fuel market. Second are the environmental constraints placed on the use of the fuel in most developed countries. This constraint on use is due to sulfur emissions arising from burning the fuel. Heavy fuel oil has a slightly higher carbon emission compared to other oils and its footprint is significantly higher than natural gas, but the impact of CO 2 emission regulations is not yet an important consideration. 5 The IEA and the EIA use different methodologies to calculate residual fuel oil and bunker fuel usage. Rather than arbitrarily decide which data set is more accurate, we have chosen to present the data of each organization to provide the reader with a range of reasonable estimates. 37 th IAEE International Conference, New York, NY, June 15-18,

5 Overall, the decline in residual fuel oil usage is masked by an increase in its use as a fuel for maritime bunkering. The decline in residual fuel oil usage excluding its use as a bunker fuel is over 50% globally. Among OECD countries, the decline is nearly 70% from 1986 through 2010; among the non-oecd nations, the decline is over 37% (EIA, 2014). Only the use of residual fuel oil as a bunker fuel has increased over this period. Bunkering increased from just 9.3% of global residual fuel oil consumption in 1986 to over 35% in 2010 (EIA, 2014). Data from the International Energy Agency show the bunkering percentage of total residual fuel oil consumption increasing from about 12.4% in 1971 to nearly 39% by 2011 (IEA, 2013). Figure 2 uses the EIA data to depict the decline in residual fuel oil usage for non-bunkering purposes, and to superimpose the rising global bunker fuel consumption trend over the period. This suggests that non-bunker fuel usage of residual fuel oils is declining even in developing nations. According to the IEA, usage of heavy fuel oil used for shipping bunker fuel increased from about 1.6 million barrels per day (mmb/d) in 1986 to over 3.2 mmb/d by 2010 (IEA, 2013). The EIA calculates a similar increase, from nearly 1.2 mmb/d to over 3.1 mmb/d in the same period (EIA, 2014). Generally, the breakdown of heavy fuel oil consumption in 2010 is as follows: Table&1:&Breakdown&of&Residual&Fuel&Oil&Usage&in&2010,&million&b/d Use EIA IEA EIA&%&Total IEA&%&Total Bunkers % 38.8% OECD % 19.6% Non8OECD % 41.6% Total % 100.0% Sources:?IEA?World,Energy,Statistics,and,Balances,?EIA,International,Energy,Statistics 2.4 Heavy fuel oil pricing Figure$3:$Comparison$of$Crude$Oil$and$FO-380$Prices$ $140.00$ $120.00$ $100.00$ $80.00$ $60.00$ $40.00$ $20.00$ $0.00$ Jan-1987$ Jan-1991$ Jan-1995$ Jan-1999$ Jan-2003$ Jan-2007$ Jan-2011$ Heavy$Fuel$Oil$ Brent$Crude$Oil$ Price$Difference$ Source: EIA Since heavy fuel oil is an inferior petroleum product (containing many impurities and higher handling costs), its expected price ought to be below crude oil prices. That is normally the case, but there has not been a consistent relationship between the two price series. At times FO-380 prices come close to parity with crude oil. At other times they are deeply discounted. Figure 3 illustrates 37 th IAEE International Conference, New York, NY, June 15-18,

6 the relationship between average wholesale high-sulfur fuel oil prices in the U.S. as compared to the European price for Brent North Sea crude oil in US dollars per barrel (EIA, 2014b, c). The chart illustrates that heavy fuel oil prices were deeply discounted in two periods: during first Gulf War and in the oil price runup. In both cases there was a rapid increase in petroleum product and crude oil prices, with heavy fuel oil prices lagging. 3. Simplified model of refinery upgrading A simplified model can be used to explain how the dynamics of petroleum product and crude oil prices work in the refinery system. The price differential between light and heavy petroleum products generally correlates with differentials between light and heavy crude oils. That is, the wider the differential between heavy and light refinery feedstock, the greater the incentive to upgrade. There are many different technological options for upgrading heavier oil into lighter products and petroleum product demand growth is not a prerequisite for additional upgrading capacity. The need actually depends on the relative mix of petroleum products in demand. There are a number of ways to model the economics of a refinery that processes feedstocks from a specific slate of crude oils and produces a specific slate of products based on the process units that it contains. Sadukhan, Zhang and Zhu presented a model of a complex refinery based on graph theory that does not require optimization for identification of the lowest-cost method of producing the highest-value slate of products (Sadukhan, et al., 2003). Their model is adaptable to a variety of refinery types, but its complexity rivals that of the optimization-based linear programs employed by the refiners themselves. Dixon produced a much more tractable model for refinery production of anode-grade petroleum coke using a simplified coking refinery model (Dixon, 2009). Dixon s coking refinery contains an atmospheric crude distillation unit, a vacuum distillation unit, a delayed coker, a gas oil hydrotreater, a fluidized catalytic cracker, a distillate hydrotreater, a reformer/isomerizer, and an alkylation unit. Its purpose was to model the changing product slate when shifting toward a heavier, more sulfur-laden crude slate. Both papers relied on economic and operating data for refinery process units included in alternative editions of Petroleum Refining Technology and Economics (Gary, Handwerk, and Kaiser, 2007). For the model presented in this paper, we have a much narrower focus: given that refiners will always have some amount of residuum produced by their refining activities, what are the incentives to upgrade to higher-valued products? The model we use to explore this question is much simpler than those described above. The decision on whether to coke residuum into highervalued products is based on the difference in value between the feedstock and the slate of higher valued products that coking produces. The wider the difference, the greater the value to the refiner of coking. Heavy vs. light crude oil price differences can serve as a proxy where product prices are not available. Figure 4 illustrates the classical Marshallian relationship between feedstocks and products, but with a key modification. Ordinarily the vertical axis measures price. In Figure 4, however, the vertical axis measures the price or value difference between heavy and light crude 37 th IAEE International Conference, New York, NY, June 15-18,

7 oil or between heavy and light petroleum products. The horizontal axis measures the quantity of residual oil left over from the simple distillation process that is upgraded into lighter, highervalued products. Price&Difference& Light&Products& &&Residual&Oil&& Or&Heavy&&& Light&Crude&& Oils& ΔP 2& ΔP 1& other options. Figure'4:''Refinery'Upgrading'Economics' Coker& Capacity& Other&Upgrading& Processes& D 1& Quan<ty&of&Light&Products&Refined&from&Residuum& All& Upgrading&& Capacity& SRMC & LongIRun&& Coker&& Cost& D 2& Variable& Coker&& Cost& As a general rule, refiners have rising short-run marginal cost curves associated with upgrading using thermal or catalytic cracking. Coking, on the other hand, is far more capital intensive but has a relatively flat marginal cost curve until the coker is at full capacity. As a general rule, the variable cost of coking, and therefore its marginal cost, is proportionally lower than that of the other processes until fully used. Under this logic, as long as a coking refiner has access to residuum feedstock, cokers will be utilized to full capacity before turning to the The model can be expressed mathematically as follows: The supply curve is segmented between coking units and other upgrading processes: SRMC = MC! when Q (0, Q! ], SRMC = f P, Q when Q Q!!, Q!, and SRMC = when Q > Q!. SRMC denotes short-run marginal cost, MC! is the marginal (variable) cost of operating a coking unit, Q represents the quantity of light products produced specifically from residuum upgrading, Q!! is the coking capacity in the market, Q! is the total residuum upgrading capacity from all processes, and P is the price difference between the slate of lighter products produced and residual fuel oil, for which the difference between heavy and light crude oils can serve as a rough proxy. f P, Q is a steeply increasing function. One might ask why the price difference is between light products and residual fuel oil, rather than residuum. The reason is because if the price difference between the light products and 37 th IAEE International Conference, New York, NY, June 15-18,

8 residual fuel oil is less than the short-run marginal cost of upgrading residuum to lighter products, then the least-cost option would be to blend residuum into residual fuel oil rather than upgrade it to lighter products through coking. (Note, however, if a refiner chooses not to run its coker it must also account for the opportunity costs associated with possible underutilization of other refinery processes. Thus, the calculation of short run marginal cost of upgrading is highly complex. In some cases it may actually be negative.) The demand curve is a decreasing function of the price differential between light products and residual fuel oil: Q = f( P) If P is very large, then consumers will not demand light products beyond what is produced from less intensive refinery operations. The logic is that if residual fuel oils are heavily discounted, they will be preferred to the lighter products even though they are dirtier, more toxic and cause more damage to equipment on combustion. As the price differential narrows, the difference in fuel quality becomes more important, and consumers will increasingly prefer the light product to the heavy one. In this model, the equilibrium quantity is fully determined by the demand curve s intersection with P (Q = f( P)). By definition, the differential between heavy and light products determines the equilibrium quantity at which consumers are satisfied with the relative production of various types of petroleum products. A number of elements of the equation are difficult to estimate from outside of the industry due to a lack of data. For example, the SRMC curve for non-coking processes is not known because the markets rarely provide the incentive for refiners to re-tool their cracking and other upgrading units to process residuum into higher-valued products. Certainly, the refiners do not announce which process units are upgrading residuum during the course of their operations. But we serendipitously do have an insight into the variable and long-run costs of coker operations thanks to open testimony on the setting of the Trans Alaska Pipeline System (TAPS) quality bank tariff. On the TAPS system, drillers feed crude oil of varying qualities to the pipeline at the North Slope, where they are commingled so that a crude of average quality is received at the southern terminus where it is loaded onto tankers. In order to compensate the producers who supplied higher-than-average quality crude oil into the pipeline, the producers who supplied lower-than-average quality crude pay into the Quality Bank (QB). The high-quality producers receive payments from the QB to reflect the actual value of the crude they supplied. Since 1995, the Federal Energy Regulatory Commission (FERC) has mandated that the crude streams be valued using a distillation method. The distillation method values crude streams by using assay data to construct what each crude stream would produce in petroleum products after simple atmospheric distillation a process unit present in all refineries. The yield-weighted value of these distillation cuts comprises the crude stream value. In 2005, the FERC decided that the residuum cut, lacking any market price by which to assess its value, should be priced at 37 th IAEE International Conference, New York, NY, June 15-18,

9 the yield-weighted values of the cuts after processing residuum in a coker, less the coker s costs. A return on capital was included, as was an 87% utilization rate and a 20-year lifespan (FERC, 2005). During public hearings, an estimated cost breakdown for coking residuum was revealed in publicly-available testimony. It emerged that as of the year 2000, for a West Coast refiner processing Alaska North Slope (ANS) crude oil, the per-barrel cost of residuum processing through a coking unit was $8.24. $5.54 was the per-barrel capital cost for a West Coast-based coking unit including a 4- drum coker and associated equipment as well as two sulfur plants (to remove 100% of the sulfur from the stream) and a downstream hydrotreater. The fixed cost per barrel was $1.83, and the variable operating cost per barrel was $0.87 (FERC, 2006, pp ). 6 The total cost has been periodically updated on the order of one or two times per year, but the cost breakdown has not been reported since Proportionally, based on the 2006 filing, we can use the following breakdowns to provide proxy values for variable, fixed and capital costs: in 2000, variable costs were approximately 11% of total costs, fixed costs were approximately 22% of the total costs, and capital costs were approximately 67% of total costs. The latest TAPS Quality Bank tariff filing pegs total West Coast coker costs at $13.46 per barrel (ConocoPhillips, 2014, pp. 28). Under the ratios calculated above, the cost breakdown is $1.48 per barrel for variable costs, $2.96 per barrel for fixed costs, and $9.02 per barrel for capital costs in Market dynamics are evident from Figure 4. Assume there is a demand shift away from heavy oils to light oils in the product market: the schedule shifts from D 1 to D 2. Average petroleum product prices might not change, but light product prices should rise relative to heavy products. The price difference, ΔP 1, rises to ΔP 2. This incentive causes refiners to recycle heavy oils through cracking equipment, etc. at increasing cost. If the differential goes above long-run coker costs, refiners will have an incentive to increase coker capacity, i.e., to invest in new facilities. They will do so in order to displace less efficient upgrading equipment. Such investments allow refiners to reduce costs and increase profits, but they will not necessarily add new overall refining capacity. 3.1 Empirical Evidence If the coker model holds in practice, we can expect to see two phenomena: we should see coker utilization increase whenever the price differential between heavy fuel oil and light crudes is greater than the variable cost of coking; second, we could expect to see coking capacity additions whenever the price differential is greater than the long-run coker cost for an extended period of time. However, we should consider that the FERC coker costs are broadly generic and will not necessarily reflect coker costs across the entire globe or across the entire industry. Keeping this shortcoming in mind, we use the following data: 6 The definition of fixed costs, used by the FERC for regulatory purposes includes some costs that could be avoided and, thus, ought to be categorized as marginal costs. For this analysis, however, we utilized the FERC categories. 37 th IAEE International Conference, New York, NY, June 15-18,

10 A heavy-light spread price series, for which we can use either the Brentresidual fuel oil price spread data reported in Figure 3 (provided by the EIA), or we can compare Los Angeles Ultra Low-Sulfur Diesel prices with Los Angeles 380CST High-Sulfur Fuel Oil prices. Both of the latter are provided by Bloomberg. 7 We can also use another light-heavy spread proxy: the difference between the Brent crude oil price and the Mexican Maya crude oil price (the latter is a benchmark heavy crude oil (Dixon, 2010, pp. 944)). A figure for coker utilization. The EIA provides data on both coker capacity and processing of fresh feed input for the US and PADD 5 (the West Coast) (EIA, 2014d and 2014e). Feed Input divided by capacity is capacity utilization. We should see this figure increase whenever the heavy-light price differential is greater than the variable cost of coking. We also use the raw coker feed input data in thousand barrels per day. A figure for coker capacity. In addition to the U.S. data provided by the EIA (EIA, 2014d), the Oil & Gas Journal has compiled global coker capacity by year since 1997 (OGJ, ). Figures for the variable and total cost of coking as calculated by the FERC for the TAPS quality bank. These are provided on the website of ConocoPhillips Transportation Alaska, Inc. (CPTAI, ) and in the FERC filing of 2006 which retroactively calculated costs back to 2000 (FERC, 2006, pp. 26). The monthly data extend from February 2000 through April of There are a number of potentially confounding factors that will make it difficult to decisively determine the impact of an increasing light-heavy price spread on coker utilization. First, each refinery and each coking unit are unique; the FERC s calculation was for a typical coking unit at a West Coast refinery that processes ANS crude oil. That fact alone will make the FERC s coker costs unlikely to be representative of the global market. Second, refiners may make their processing decisions well in advance of the actual month of production. The refinery system is so complex that making ad-hoc changes in one process might affect others adversely, and so negatively impact profitability over the entire refinery despite an improvement in the economics of the coking unit. One might expect there to be some kind of lag in the price signal, or a period of sustained price spreads, before the refinery responds. Another issue is that a refinery may choose to coke its residuum into middle distillates regardless of short-term price signals because of the need to maintain a minimum level of crude throughput in the refinery to meet marketing obligations, and/or to keep other processing components of the refinery fully utilized. A related issue is that, to ensure access to crude oils, an independent refinery may have contracted a set quantity of crude oil for delivery in advance through forward contracts. If the negative margin from coking excess residuum is less than the cost to breach the crude delivery contract, the refinery will continue to operate its coker regardless of the price signal. Additionally, a refiner may take a coker down for needed maintenance independently of price signals. This would show up as a decrease in coker utilization even though the price signal had nothing to do with the curtailment. Furthermore, capacity utilization may appear to decrease in 7 Bloomberg prices retrieved from Bloomberg Terminal on March 23, Price series are monthly. LA ULSD Ticker code is DIEILAAM Index, Ticker code for LA 380 CST Fuel Oil is N6LA380 Index. All prices converted to dollars per barrel using 42 gallons per barrel for diesel prices and 6.66 barrels per metric ton for FO 380CST (conversion factor URL: accessed April 4, 2014). 37 th IAEE International Conference, New York, NY, June 15-18,

11 the months immediately after a capacity expansion as the refiner gets the coking unit running up to speed. These fluctuations likewise have nothing to do with responding to price signals. Furthermore, the coking capacity data are annual as of January 1 st each year, regardless of when in the year the capacity was actually added; this makes identifying when an increase in coker feed inputs is due to an increase in overall capacity vs. when it is due to price signals impossible. All of these factors together make it highly unlikely that such a simple model will be able to account for a very high proportion of the changes in coker throughput as a function of the lightheavy product (or crude) price spread The monthly model on coker variable costs Though the above caveats should dampen expectations, we ran a number of formulations of the model using monthly data on the light-heavy crude (or product) price spread, the FERC s proxy for coker variable costs, and the change in coker throughput. We modeled from zero to three-month lags on the following formulation as a trigger : ( P MC! ). The idea was that trigger values above zero should produce positive changes in coker throughput, and values below zero should produce negative changes. Using the trigger in levels did not result in very good fits perhaps because the trigger value was nearly always positive given the small variable cost for cokers. Using the change in the trigger value ( P MC! ) was more promising, although almost none of the monthly formulations were good fits. The highest R 2 figure was less than 0.05, meaning that the price spread alone accounted for less than 5% of the total variation in coker inputs. Our best result, which was statistically significant at the 2% level on 131 monthly observations, was the 3-month lag of the ( P MC! ) trigger on the monthly change in coker throughputs in PADD 5 (the US West Coast). The key model outputs are as follows: Table 2: 3-Mo. Lagged Change in ΔP less Coker Variable Costs on Coker Throughputs Coefficients Standard Error LCL UCL t Stat p-level H0 (2%) rejected? Intercept No ΔP-MCc, t Yes R Square Adjusted R Square # observations 131 In short, a $1 increase in the trigger (the spread between Brent crude oil and the EIA s generic residual fuel oil prices, less the FERC s variable cost proxy value) will increase the coker throughput in PADD 5 by 1.7 thousand barrels per stream day 3 months later, on average. The 95% confidence interval of this effect is from 30 barrels per stream day to nearly 3.5 thousand barrels per stream day. The coefficient has a p-value of Most importantly, we see that the results are directionally consistent with the theory. That we only found significant results in PADD 5 makes sense, since we were using PADD 5 coker costs as a proxy for all coker variable costs. Costs outside of PADD 5 are not likely to reflect the FERC proxy values The annual models on coker costs For annual data, we were left with only observations if we included the coker cost proxies, which begin in Even without them, we would have a maximum of observations (depending on the price series used to construct the light-heavy spread). In these cases, we were never left with enough observations to reject the null hypothesis that the 37 th IAEE International Conference, New York, NY, June 15-18,

12 outcomes recorded could have come from random processes. While we did find a relatively strong fit in the case of the Brent-Maya spread on the change in worldwide coker capacity (an R 2 of 0.2), the results were not statistically significant due to a lack of observations. More data, encompassing a wider range of years, would be required to test this model rigorously using annual data. 3.2 Model conclusions Although the results drawn from the model testing are tenuous, the data are at least weakly directionally consistent with our logic. The logic in the model supports two principal conclusions: 1) Typically refiners will always use their cokers, if available. If product demand shifts towards heavy fuel oil, refiners will back down other less efficient processes, but still use the coker. This is because processing residuum through a cracking unit, while technically possible, will destroy the catalysts much more quickly. The result is a greater need for maintenance and an increase in the time a cracker needs to be taken offline; 2) The demand for coker investment depends on the balance of light and heavy crude oil production as well as regulatory constraints on the use of heavy fuel oil. 4. Impact of new environmental regulations High sulfur heavy fuel oil has been effectively phased out in developed countries. As noted earlier, in 2010 developing countries consumed about 3.5 mmb/d and the bunker market consumed 3.2 mmb/d of residual fuel oils (IEA, 2013). The bunker market is poised for big changes by 2020 in a series of steps. The International Maritime Organization (IMO) amended the International Convention for the Prevention of Pollution from Ships (MARPOL) in The MARPOL agreement designated specific portions of U.S., Canadian and French waters as Emission Control Areas (ECAs) (EPA, 2010, pp. 1). The new regions join areas of the Baltic Sea and North Sea already included in similar ECAs. Current regulations allow oil containing 1% sulfur or less to be burned in ECAs. However, requirements get much stricter in According to the IEA: More importantly, in 2015 ECA wide sulphur limits are due to be further reduced to 0.1%. This new, tighter ECA sulphur limit is expected to result in a sharp upturn in OECD marine gasoil demand, at the expense of marine fuel oil. (IEA, 2014, pp. 13). Although this diminishes demand for high sulfur heavy fuel oil along European and North American coasts it does not impact the bulk of the market. The primary vessels that use high sulfur oil are large ships typically involved in international trade. High sulfur FO-380 of less than 3.5% sulfur is sold to these ships in U.S. and European ports. Although it cannot be burned in the ECAs, once outside an ECA ships are free to burn it. However, by 2020 the MARPOL agreement will reduce sulfur content in all global bunker fuels to 0.5% (EPA 2010, pp. 4). If these regulations come about, the demand for high sulfur fuel oil for bunkering will disappear in favor of diesel grades, and total residual fuel oil demand will drop by nearly half if current trends for non-bunkering uses persist. The other large sector of use is in developing countries. As their economies improve many are likely to adopt environmental regulations similar to those in the OECD. This is more 37 th IAEE International Conference, New York, NY, June 15-18,

13 likely in countries that have access to shale gas that is potentially cheaper and much cleaner. As a boiler fuel, natural gas is preferable to residual fuel oils not only because of its favorable emissions profile, but also because burning natural gas causes less damage to equipment than burning residual fuel oil. However, it is possible that a glut of residual fuel oil will decrease the prices sufficiently that low-income nations will increase their use of it as a boiler fuel. 5. Balance of heavy and light crude oil There has been a general expectation that global crude oil production will shift towards a greater proportion of heavy relative to light crude oils. The expectation is based on simple economics: light crude oils are somewhat cheaper to produce and transport and, of course, they require less sophisticated refining. This is reflected in higher prices for high-gravity low-sulfur (light sweet) crude oils. Thus, when given a choice, producers will develop light before heavy crude oil fields. The deposits of light crude oils should therefore be depleted more quickly than the deposits of heavy crudes. Moreover, there are known abundant deposits of heavy oils notably Canadian tar sands and Venezuela s Orinoco belt. This expectation has been somewhat offset recently with the development of light shale oil in the U.S. s Bakken and Eagle Ford deposits. While shale oil is viable in the U.S. it remains unclear as to whether the technology can be exported to other countries. Even if it is possible to develop oil shale elsewhere it is likely to be in existing oil provinces, dominated by OPEC s members. They will certainly choose to develop lower cost conventional oil first. In any case, the expectation of increased light crude oil in the U.S. is more than offset by existing plans for Canadian oil sands and other heavy oils. Thus, it is unlikely that average refinery feedstocks will become lighter, either in North America or the rest of the world. 6. Need for Refinery Investment According to the Oil and Gas Journal s annual refining survey, global coking capacity increased by 1.0 mmb/d from 1997 through 2010 and now totals 4.7 mmb/d (OGJ, ). EIA and IEA data indicate that heavy fuel oil consumption declined by mmb/d over the same period (EIA, 2014 and IEA, 2013). There were, of course, other investments made in cracking capacity that allow further bottoms upgrading. Nonetheless, these data underscore the likely impact of further reductions in high-sulfur heavy fuel oil. If MARPOL regulations are implemented as planned in 2020, approximately 1.5 mmb/d of coking capacity ought to be added to accommodate the surplus of residuum. Adding a coker to an existing refinery typically costs around $1 billion, for a capacity of 40 thousand b/d. This suggests a required investment of around $35 billion between now and 2020, although some of the capacity will likely be built in tandem with new refineries. 7. Conclusion It is highly likely that the trend depicted in Figure 1 will continue with the resulting impact on refiner configuration being an increase in coking capacity. The trends in various key factors residual fuel oil demand, environmental protection, and the heaviness of the crude slate all suggest that the most effective and least expensive way to dispose of residuum in the 37 th IAEE International Conference, New York, NY, June 15-18,

14 future will be through a substantial increase in global coking capacity. According to the logic of the residuum upgrading model presented in section 3, the lowest-cost method of disposal of residuum is likely to be the coker in the absence of a market for bunker fuel blending and assuming current trends in asphalt demand. However, it is still possible that developing countries that have not yet adopted strict policies of environmental protection could increase their usage of residual fuel oils once the bunker fuels market dries up. If refiners do not prepare for the 2020 phase-out of high-sulfur residual fuel oils in advance, there could be a glut of the fuel, which would provoke a price collapse. At low enough prices (and a high enough price differential), consumers may opt to use residual fuel oil instead of cleaner alternatives such as diesels or natural gas. The environmental benefits expected with the enforcement of the MARPOL 2020 limits may not materialize unless similar constraints on land-based use of residual fuel oils are enacted worldwide. 8. References ConocoPhillips Transportation Alaska, Inc. (CPTAI). ( ). Pipeline Tariffs, TAPS. URL: accessed April 3, ConocoPhillips Transportation Alaska, Inc. (ConocoPhillips). (2014). Oil Pipeline Filing FERC No (cancels FERC No ). January 27, URL: tybank%20tariff%20filing%20at%20ferc%20% pdf, accessed April 3, Dixon, Todd W. (2009). US Refining Economics A Model Based Approach. Light Metals The Minerals, Metals, & Materials Society, 2009, pp Fahim, Mohamed A., T.A. Alsahhaf, and A. Elkilani (2010). Fundamentals of Petroleum Refining. First Edition. Elsevier, Gary, James H., G.E. Handwerk, and M.J. Kaiser (2007). Petroleum Refining: Technology and Economics, Fifth Edition. Taylor and Francis Group. Boca Raton, FL, USA. Hawaiian Electric Companies, June 28, 2013, (HECO, 2013) Integrated Resource Planning Report. Appendix I, Hawaii Electric Companies Fuels Master Plan, to Retrieved from Hawaii Electric Co. website December 2013: Oil & Gas Journal (OGJ) ( ). OGJ Survey Downloads. Worldwide Refineries - Capacities as of January 1, Coking. Pennwell. URL: accessed 4/3/14. Organization for Economic Cooperation and Development, International Energy Agency, IEA (2013), "Oil demand by product for non-oecd countries", IEA World Energy Statistics and Balances (database). doi: /data en, URL: accessed April 2, th IAEE International Conference, New York, NY, June 15-18,

15 Organization for Economic Cooperation and Development, International Energy Agency (IEA) (2014). Oil Market Report. February 13, URL: accessed March 18, Sadhukhan, J., N. Zhang, and X.X. Zhu (2003). Value Analysis of Complex Systems and Industrial Application to Refineries. Industrial and Engineering Chemistry Research, 2003, 42: U.S. Department of Energy, Energy Information Administation (EIA). (2014). International Energy Statistics, (Thousand Barrels Per Day), URL for Residual Fuel Oil Consumption: =1980&eyid=2012&unit=TBPD, accessed 3/28/14. URL for Residual Fuel Oil Consumption for Bunkering: d=1984&eyid=2010&unit=tbpd, accessed 3/28/14. URL for Total Petroleum Consumption: CG5,CH,JA,&syid=1980&eyid=2012&unit=TBPD, accessed 3/31/14. U.S. Department of Energy, Energy Information Administation (EIA). (2014b). Spot Prices for Crude Oil and Petroleum Products, Europe Brent Spot Price FOB (Dollars Per Barrel), file pet_pri_spt_s1_m.xls, URL: accessed 4/1/14. U.S. Department of Energy, Energy Information Administation (EIA). (2014c). U.S. Residual Fuel Oil Prices by Sales Type, U.S. Residual Fuel Oil Sulfur Greater Than 1% Wholesale/Resale Price by All Sellers (Dollars Per Gallon), file pet_pri_resid_dcu_nus_m.xls, URL: accessed 4/1/14. U.S. Department of Energy, Energy Information Administation (EIA). (2014d). U.S. Number and Capacity of Petroleum Refineries, U.S. Refinery Thermal Cracking, Coking Downstream Charge Capacity as of January 1 (Barrels per Stream Day), file pet_pnp_cap1_dcu_nus_a.xls, URL: accessed 4/4/14, and PAD District 5 Number and Capacity of Petroleum Refineries, West Coast (PADD 5) Refinery Thermal Cracking, Coking Downstream Charge Capacity as of January 1 (Barrels per Stream Day), file pet_pnp_cap1_dcu_r50_a.xls, URL: accessed 4/4/14. U.S. Department of Energy, Energy Information Administation (EIA). (2014e). U.S. Downstream Processing of Fresh Feed Input, U.S. Downstream Processing of Fresh Feed Input by Delayed and Fluid Coking Units (Thousand Barrels per Day), file pet_pnp_dwns_dc_nus_mbblpd_m.xls, URL: accessed 4/4/14, and PADD 5 Downstream Processing of Fresh Feed Input, West Coast (PADD 5) Downstream Processing of Fresh Feed Input by Delayed and Fluid Coking Units (Thousand Barrels per Day), 37 th IAEE International Conference, New York, NY, June 15-18,

16 file pet_pnp_dwns_dc_r50_mbblpd_m.xls, URL: accessed 4/4/14. U.S. Environmental Protection Agency (EPA). (2010). Designation of Emission Control Area to Reduce Emissions from Ships in the U.S. Caribbean. March, URL: from page accessed April 8, U.S. Federal Energy Regulatory Commission (FERC) Commission affirms initial decision on TAPS quality bank, but limits scope of retroactive refunds for resid. News Release, October 20, Docket Number OR89-2, et al. URL: accessed April 3, U.S. Federal Energy Regulatory Commission (FERC) BP Pipelines (Alaska), Inc. et al submits FERC Oil Tariff 33 et al under IS Docket No. IS Accession No , filed July 3, URL: accessed April 1, th IAEE International Conference, New York, NY, June 15-18,