US crude oil stocks posted an increase of 5.5 MMBbl from last week. Gasoline and distillate inventories decreased 2.1 MMBbl and 0.7 MMBbl, respectively. Yesterday afternoon, API reported a crude oil build of 6.9 MMBbl while reporting a gasoline build of 2.2 MMBbl and a distillate draw of 0.87 MMBbl. Analysts, to the contrary, were expecting a crude oil draw of 0.5 MMBbl. The most important number to keep an eye on, total petroleum inventories, posted a large increase of 8.8 MMBbl. For a summary of the crude oil and petroleum product stock movements, see the table below.
US crude oil production increased 100 MBbl/d last week, per the EIA. Crude oil imports were up 1.16 MMBbl/d last week, to an average of 7.1 MMBbl/d. Refinery inputs averaged 16.6 MMBbl/d (505 MBbl/d more than last week), leading to a utilization rate of 90.1%. The crude oil and total petroleum stocks build stopped the price rally and pushed prices down below $66/Bbl. Prices are still getting support from the US government’s decision to cancel Iranian sanction waivers and the unrest in Libya potentially threatening the country’s supply levels. Prompt-month WTI was trading down $0.38/Bbl, at $65.92/Bbl, at the time of writing.
Prices have been rising and rallied to their six-month highs at the beginning of the week, breaking through the $66/Bbl mark on Tuesday. The sharp increase in prices was due to the US government’s decision to drive Iran’s crude exports to zero. The tightening global supply levels and situation in Libya also supported prices.
Prices pierced $66/Bbl after the Trump administration announced that it will not extend sanction waivers to certain countries that import Iranian oil, as well as announcing that all Iranian oil buyers will have to end imports from Iran in about a week or be subject to US sanctions. The Trump administration’s announcement certainly increased the bullish sentiment, as cancellation of waivers can erase as much as 1 MMBbl/d of additional supply in a market that has already been tightening due to OPEC-led supply cuts and declining production in Venezuela. Escalating tensions in Libya continue to threaten supply levels in the near term.
The US government’s goal of reducing Iran’s exports to zero and its latest announcements certainly have increased the possibility of a supply deficit and triggered the price rally. However, this rally may be temporary, as there were already discussions between OPEC and Russia about possibly not extending the supply cuts into the second half of the year, with a potential scenario of increasing the supply levels. After the Iranian sanctions announcement, the OPEC meeting in June becomes even more important, as OPEC (led by Saudi Arabia) and Russia may decide to fill the gap created by the reduction in Iranian and Venezuelan supply levels and try to grab market share from the United States, as the US is showing no signs of slowing down, instead continuously ramping up production. Another risk to prices will be the execution of Iranian sanctions, as Iran already retaliated by threatening to close the Strait of Hormuz, a crucial shipping lane in the global oil trade, which could cause disruptions and be detrimental to global supply levels.
The US government’s announcement on canceling waivers and bringing Iranian exports to zero took prices between $65/Bbl and $68/Bbl range (an area of consolidation from last fall during the price collapse) as previously mentioned here. The market will need further bullish headlines to break through this range whether from further news on sanctions or any supply disruptions from Libya. In the meantime, the possibility of OPEC and Russia ending the supply cuts and potentially increasing supply levels to replace the Iranian and Venezuelan crude, increasing US production and a gloomy global economic and demand growth outlook will keep the pressure on prices. If Iranian sanctions are not fully executed, get lash back or are denounced by countries with waivers at the same time if OPEC decides to end the supply cuts and increase output, prices could trace back to the $60/Bbl range, especially given the weak demand growth projections.
Petroleum Stocks Chart
US crude oil stocks posted a decrease of 1.4 MMBbl from last week. Gasoline and distillate inventories decreased 1.2 MMBbl and 0.4 MMBbl, respectively. Yesterday afternoon, API reported a crude oil draw of 3.1 MMBbl alongside a gasoline draw of 3.6 MMBbl and a distillate build of 2.3 MMBbl. Analysts, to the contrary were expecting a crude oil build of 1.7 MMBbl. The most important number to keep an eye on, total petroleum inventories, posted an increase of 2.5 MMBbl. For a summary of the crude oil and petroleum product stock movements, see the table below.
US crude oil production decreased 100 MBbl/d last week, per the EIA. Crude oil imports were down 0.60 MMBbl/d last week, to an average of 6.0 MMBbl/d. Refinery inputs averaged 16.1 MMBbl/d (22 MBbl/d less than last week), leading to a utilization rate of 87.7%. The crude oil inventory draw and China’s first quarter GDP showing a growth gave support to prices. Also supporting prices is the unrest in Libya potentially threatening the country’s supply levels. Russia’s statements on abandoning supply cuts and potentially increasing output for second half of the year is pressuring prices. Prompt-month WTI was trading up $0.11/Bbl, at $64.16/Bbl, at the time of writing.
Prices retracted back from their five-month highs, but still traded in the $63/Bbl-$64/Bbl range last week as tightening supply market and the bearish news on supply cuts for the second half of the year pulled prices in both directions. The move up to near the $65/Bbl mark last week was mainly due to news about Libya and the possible impact of fighting on the country’s crude production levels, bringing supply further down in an already tightening market due to declines in Venezuela and Iran.
The price increase due to news from Libya last week were offset by the fears of a slowdown in global economic growth and Russia’s remarks on supply cuts. The US government announcing tariffs on European goods and the IMF lowering its economic growth forecast both increased the fears about global economic outlook while Russian Energy Minister Alexander Novak’s remarks on the extension of supply cuts into second half of the year being unnecessary put uncertainty what OPEC+ may decide in their upcoming meeting in June.
Bearish sentiment and pressure on prices increased at the start of the week due to concerns about OPEC-led supply cuts potentially not being renewed for the second half of the year. The concerns began after Alexander Novak’s comments last week and reached a new level on Monday after Russian Finance Minister Anton Silunav was quoted by Russian TASS agency as saying that OPEC and Russia could decide to abandon the deal and boost production to fight for market share with the United States. Although tightening supply levels, due to declining Venezuelan and Iranian production, as well as the renewed fighting in Libya support the bullish sentiment, the recent news from Russia certainly put some question marks on supply/demand levels for the second half of the year. Increasing US production and gloomy global economic and demand growth will continue to pressure prices, and this pressure can intensify given any other bearish news on supply cuts from Russia and OPEC.
Last week, WTI prices gave their first indication that the price run may follow a more traditional bullish extension. While trading higher early in the week, prices respected the bearish inventory numbers from the EIA and the headline news and promptly started to retrace some of the week’s gains. The $0.50 decline in WTI during the last 45 minutes of trade on Friday is an indication that some of the bullish elements are taking profits on short-term gains. This profit activity is part of a bull market behavior pattern. Participants need to collect profits before adding to additional commitments, and this usually leads the market to periods of consolidation that have been discussed before. The key this week is how far the declines will go before bullish participants add to existing positions. Further extensions taking prices between $65/Bbl and $68/Bbl (an area of consolidation from last fall during the price collapse) will require more bullish headlines and will likely run into selling. The market will closely watch any news surrounding Iranian sanctions, Libyan supply levels, OPEC-led supply cut news, and US-China trade talks. Any slight shift in sentiment due to fundamentals or bearish news could cause a consolidation phase, with a potential retracement back to the $60/Bbl range.
Petroleum Stocks Chart
On January 1st, 2020, the global shipping industry will undergo a radical change, with all ships having to reduce the sulfur content within marine fuels from 3.5% to 0.5%, as mandated by the International Maritime Organization (IMO). As with all radical changes, winners and losers await, meaning there is significant opportunity everywhere.
In this paper, DrillingInfo uses a refinery optimization model to look at the potential effects of this regulation for a single complex refinery with a delayed coking unit.
What does the change mean for refineries?
Bunker fuel provides a valuable outlet for refineries as it has the highest sulfur content specification out of the major refinery products. The heavy bottom of the barrel fractions that have too much sulfur content to become diesel (0.0015% maximum sulfur content), No.2 oil (0.05%), or light sulfur fuel oil (1%) can still generate revenue as long as they meet the 3.5% specification for marine fuel in non-emission control areas (ECAs). Furthermore, the markets for light sulfur fuel oil and other relatively high-sulfur products are small compared to that of 3.5% bunker fuel (Figure 1) so as the new specification takes effect there will not be another “release valve” for high-sulfur fractions above the 0.5% threshold.
With the new IMO specification, the residual fractions that used to go into marine fuels will largely become waste unless they can be further processed and desulfurized. Refineries with delayed coking units stand to benefit from this change as they have the capability to process these fractions into other products, which most refiners lack.
What does a single refinery model look like?
The most standard refinery processing unit is an atmospheric distillation unit (ADU), which separates crude oil into different fractions depending on their volatility. This is the process which splits crude oil into the gases, naphthas, kerosene, gas oils, and residues that it consists of. The yields of these fractions, expressed as a percentage of the crude oil input, and their physical properties, including sulfur content among others, can vary greatly between different crude oil assays. In this case we are particularly interested in a heavy assay that produces a lot of residue, the type that is often refined in the US Gulf Coast, because the ability to process this type of crude gives complex coking refineries their advantage in the market. The yields of a standard Western Canadian Select (WCS) assay are illustrated in Figure 2.
After the fractions exit the ADU, their path through various refinery units is anything but standard. The flows of these fractions through the refinery depend not only on the available processing units and their capacities, but also on product specifications and prices as the refiner will decide how much of each fraction to send into each unit in order to maximize profit. This type of problem – maximizing a profit objective subject to operational constraints – is the perfect application for linear and nonlinear programming.
In this paper we utilize the OptiFlo-Crude model to look at a complex refinery based on a Gulf Coast facility with some modifications made for illustrative purposes. Our refinery has an ADU capacity of 335 MBbl/d, and it has the following units: vacuum distillation unit (VDU), hydrotreaters for naphtha (NHT), kerosene (KHT), and gas oils (GOHT), light naphtha isomerization (LNIS), hydrocracking unit (HCU), fluidized catalytic converter (FCC), reformer (RFO), alkylation unit (ALK), and delayed coking unit (DCU).
A typical refinery blends different assays together to maximize profit while considering the physical properties of the assays together with the state of the transportation network (bottlenecks, cost of transport, crude availability, etc.). While this blending is very important on a macro scale and is being modelled at DrillingInfo, for this single refinery case we consider only the WCS assay.
How does the refinery operate with current specifications and prices?
In the base case scenario, the selected refinery’s operations are optimized given today’s 3.5% maximum sulfur specification for bunker fuel. The past 12-month average prices for end products are used as inputs. Figure 3 illustrates the basic flow diagram for this refinery, from the ADU into the other units.
The optimal product outputs for this refinery are displayed in Table 1. On a volume basis, the outputs are 42% diesel, 35% gasoline, 8% jet fuel, and a combined 15% for all other products. Some demand constraints were imposed on the model to avoid overproduction that would flood a low-demand market with supply. For example, the 3.5 MBbl/d of light sulfur fuel oil produced at this refinery already makes up more than 6% of US production of this product (Figure 1) so the light sulfur fuel oil output was limited to 1% of the refinery’s production.
What happens when IMO regulations are implemented and the price of bunker fuel rises?
In scenario 2, the IMO 2020 regulations are implemented and the price of the new bunker fuel is set accordingly. Since the maximum sulfur specification of the new bunker fuel (0.5%) lies between that of No.2 oil (0.05%) and light sulfur fuel oil (1%), its price is set using an average of these two prices weighted by the strictness of the specification. The resulting price is $74.07/Bbl compared to $85.32 for diesel, $81.98 for No.2 oil, $65.29 for light sulfur fuel oil, and $62.11 for the current 3.5% sulfur bunker fuel.
The optimal product outputs for this refinery are displayed in Table 2. Interestingly, this refinery increases bunker fuel production from 7.2 MBbl/d in the base case to 23.2 MBbl/d with the new specification and price as it reduces the production of diesel by 17.4 MBbl/d.
The spec change and price increase in bunker fuel caused the refinery to shift hydrotreated lower sulfur fractions away from the diesel pool and into bunker fuel. The composition of bunker fuel (Figure 4) changed from mostly ADU/VDU fractions in the base case to mostly DCU/GOHT fractions in scenario 2. The light gas oil (1.4% wt. sulfur), heavy gas oil (2.3%), light vacuum gas oil (3%), heavy vacuum gas oil (3.7%), and heavy cycle gas oil (2%) could be blended together to meet the old 3.5% specification, but the new specification required hydrotreated heavy vacuum gas oil (close to 0%) blended with light cycle (1.1%) and heavy cycle (2%) gas oils coming out of the DCU.
Despite higher pricing, the estimated revenue of this refinery decreases from $27.44 million in the base case to $27.23 million in scenario 2. If we impose a maximum limit of 7.2 MBbl/d on bunker fuel production based on the base case, this refinery still reduces diesel production and increases the production of waste from zero to 0.5 Mkg/d, further reducing revenue to $27.18 million. This happens because the refinery does not have enough capacity to desulfurize the residual gas oils enough to blend them into a product.
What happens when distillate prices respond?
If refiners do start to shift production away from diesel, its price is expected to rise providing incentive to meet market demand. Given the opportunity cost of producing the new bunker fuel, the price of diesel must rise by $13/Bbl for this particular refinery to return diesel production to roughly equal to the base case. To avoid other readjustments of fraction flows, the prices of jet fuel and gasoline must also rise slightly, by less than $1/Bbl. The optimal outputs of this scenario are displayed in Table 3.
Although most products are back to roughly the same level of production as the base case, the output of new bunker fuel is significantly reduced as waste production is increased. It’s interesting to note that while volume of jet fuel increases, the mass of jet fuel is the same as the base case and the volume swell is entirely due to a change in specific gravity caused by changes in its fraction composition. The expected revenue for this refinery rises from $27.44 million in the base case to $29.13 million in scenario 3.
These results illustrate why the price of diesel must rise in response to the IMO 2020 sulfur regulations and why the change is expected to benefit complex coking refineries. The $13.00 (or 15%) rise in diesel price is specific to this refinery with this crude oil assay and will vary with other refinery and assay configurations.
Refinery modelling on a macro scale
DrillingInfo OptiFlo-Crude is a nonlinear programming model that considers the entire US refining network on a macro scale, linking production (upstream) to refining demand and exports (downstream) via all the transportation paths (midstream) across the country. By understanding the demand for specific barrels by specific refineries based on the crude oil composition and refinery operations, we can predict how crude will flow, what price a certain barrel will command in the market, what pipelines and routes will be under/over utilized, where additional infrastructure is needed, where bottlenecks will emerge, and what slate of refined products will be produced in the US.
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Natural gas storage inventories increased 25 Bcf, with an implied flow of 29 Bcf, for the week ending April 5, according to the EIA’s weekly report. This injection is well below the market expectation, which was an inventory increase of 38 Bcf. This week also came with reclassifications in the Pacific and South Central regions. In the Pacific, gas stocks showed a reclassification of a 1 Bcf decrease, and South Central stocks showed a 2 Bcf drop.
Working gas storage inventories now sit at 1.155 Tcf, which is 183 Bcf below inventories at the same time last year and 485 Bcf below the five-year average.
At the time of this writing, the May 2019 contract was trading at $2.689/MMBtu, $0.011 below yesterday’s close of $2.670/MMBtu. The little reaction to the bullish report shows that the market is content with injections at this point in the season. Prices are likely to show more volatility later in the season if inventory levels are low and injections are below expectations.
This injection season started much earlier than last year. Looking at the past two weeks for the same time last year, we had draws totaling 48 Bcf. This year, we have injections totaling 48 Bcf, nearly a 100 Bcf difference in inventories. The difference in inventories can mainly be attributed to the longer winter last year, which ran through most of April. With more injections expected throughout April 2019, prices will likely stay below $3/MMBtu as inventory levels close the gap on the five-year average.
See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.
This Week in Fundamentals
The summary below is based on Bloomberg’s flow data and DI analysis for the week ending April 11, 2019.
- Dry gas production decreased 1.07 Bcf/d on the week. The decrease stems mainly from declines in the South Central/Gulf region, which fell 1.06 Bcf/d. The big drop in the region was Louisiana, which fell 0.51 Bcf/d.
- Canadian net imports decreased 0.34 Bcf/d on the week.
- Domestic natural gas demand decreased 8.72 Bcf/d week over week. Res/Com demand continued its decline into the summer season, falling 7.66 Bcf/d week over week, while Industrial demand fell 1.23 Bcf/d and Power demand gained 0.17 Bcf/d.
- LNG exports fell 0.67 Bcf/d week over week due to maintenance at the port of Sabine on trains 1 and 2. Mexican exports increased 0.05 Bcf/d.
Total supply is down 1.41 Bcf/d, while total demand decreased 9.64 Bcf/d week over week. With the decrease in demand greater than the decrease in supply, expect the EIA to report a stronger injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 94 Bcf. Last year, the same week saw a draw of 36 Bcf; the five-year average is an injection of 27 Bcf.