In the middle of 2008, the average price for over-the-road diesel came close to the lofty price of $5 per gallon. The week of July 14, the average price across the country was $4.77 per gallon. That week, in California and in a few New England states the price peaked above $5. From 2011 through the end of 2013, the average national price was more often over the $4 per gallon mark than it was under.
In January 2012, a New York based client asked me if I thought that prices would again reach the $5 per gallon mark. My immediate response was “it could, but several things have to go wrong for that to happen.” We talked about the challenges behind predicting what fuel prices would do, and how his fleet budget did not account for the sharp increase that started in the middle of 2011. This transportation manager of over 200 trucks had a serious challenge. He needed to make accurate predictions of the expected price in an environment where the price of crude oil was boiling around $100 per barrel. Boiling is an accurate description, as the price of crude bounced daily between $100 and $125 per bbl. Diesel prices boiled right along with crude. However, in the Northeast, spot shortages and price spikes appeared, which made the manager more nervous.
What came from that request was the following article that I wrote for him to share with his management team. We advised the manager to plan for NE diesel prices to be between $4.00 and $4.50 per gallon – taxes included – for the year, but to watch for regional events that could drive the costs higher, such as a shutdown of one of the refineries that operated in the region.
To help the client’s management team understand the conditions in the market, we wrote a series of reports over January and February 2012. This is the first of the reports we wrote, released in late January 2012.
Gasoline and diesel prices are on the rise in the Northeast US. The typical thought is to place blame on rising crude oil prices. That is the average, knee-jerk response by those who don’t understand how oil turns into gasoline or diesel.
The real answer to the increase in prices is more complex. Price increases are almost always the product of complex combinations of events, many not visible unless you know what you are looking for.
Crude oil prices are a key driver. That is the main feedstock cost on the way to making diesel. However, there are other factors that can amplify or modulate refined products costs, factors that form the complex refined petroleum products market.
This report is a short tour through the factors that could affect diesel prices in the Northeast US in the next year. We provide these illustrations to give the reader visibility to the factors and the potential impacts if something goes wrong in the market.
The short answer is “yes.” Our first exhibit is The Sun Oil Company. At the end of fiscal 2011, the company reported a loss of $1.684 Billion. Refining proved to be a millstone around the neck of the company, with refining margins dragging it deep into the red ink. Refining losses brought about drastic changes at the company, including the shutdown the Marcus Hook refinery, and warnings that it could shut down the massive Sunoco operations in South Philadelphia.
The company commented in the fourth quarter earnings announcement, “The decrease in earnings was primarily the result of lower realized margins and production volumes. These negative factors were partially offset by lower expenses. Margins deteriorated throughout the fourth quarter during which market margins for gasoline were frequently negative. Margins were also impacted by high premiums for crude oil versus the Dated Brent crude oil benchmark. Production volumes were impacted by the idling of the Marcus Hook facility during the fourth quarter. The overall crude utilization rate was 81 percent for the quarter, down from 90 percent in the third quarter of 2011.”
Unpacking that announcement, Sun Oil made poor margins on gasoline, and for much of the fourth quarter, sold gasoline for less than it cost to produce. The company shuttered a refinery to help cut off the flow of money-losing gasoline. Overall, the company only used 81% of the capacity of the refinery system – even after closing Marcus Hook.
In September 2011, Sunoco hired Credit Suisse to help find buyers for the Marcus Hook and Philadelphia refineries. Sunoco and Credit Suisse approached more than 150 potential purchasers from around the world to consider a range of options, including operating the refineries (or only one refinery), operating specific units within the refineries, or using the facilities for their storage and logistical capabilities.
There is some interest in the Philadelphia refinery, and Sunoco continues to hunt for a deal to sell that facility as an operating refinery. If they fail to make a deal Sunoco will idle the main processing units at Philadelphia by July 2012. Sunoco did not receive a single proposal for Marcus Hook as an operating refinery. Sunoco has no hope that Marcus Hook will sell as an operating refinery, but is continuing to pursue alternatives for the facility, perhaps as a terminal operation.
Sunoco is not the only refiner shutting down East Coast operations. ConocoPhilips shut down the Trainer, PA refinery in fall 2011. ConocoPhillips Senior Vice President of Refining Willie Chiang said at the time, “US East Coast refining has been under severe market pressure for several years.” Chiang attributed the market pressure to an interesting mix of causes; product imports, weakness in motor fuel demand, and “costly regulatory requirements.”
Let’s take that mix of causes apart.
Gasoline demand is down in the EU, and refineries there are busy exporting gasoline to the US. In fact, the US imports refined petroleum products such as gasoline – about 3 million barrels per day of refined petroleum products, according to the EIA. US based refiners also import from crude refineries outside the United States unfinished products used as refinery inputs and blending components. US based refiners and terminals mix these blending components with domestic components to produce finished gasoline.
Bottom Line: the cost to import finished or almost finished gasoline costs less than the cost to refine crude into gasoline in these East Coast refineries.
No surprise is the drop in demand for gasoline. With the increase in fuel costs, people are driving less. The Highway Trust Fund is feeling that drop too, as consumers switched to more fuel-efficient cars and stopped driving cars as much. The Highway Trust Fund is fueled by a 17 cent per gallon Federal Fuel Tax. Fewer miles and more miles per gallon mean fewer gallons, and less money for fixing roads. But that is another story for another report.
Before we start to bang a drum about the evil polluters and how the oil companies brought the regulation upon themselves, let’s think a little bit about the cost to make capital changes to a process plant, like a refinery.
A refinery is a chemical processing plant. The refinery takes crude oil feedstock and runs it through a process where it is distilled, cooked, cracked and blended into different products, like gasoline and diesel. The process is complex, and most refineries can’t make massive changes in their process. They can make minor adjustments, but the plants are engineered to take in a specific range of crude and make a specific mix of finished products.
Most of the East Coast refining is performed in refineries along the Delaware river. The Delaware from Philadelphia south is open and deep for large tankers. In fact, if you look along the Delaware, there is a total of six refineries, making the Philadelphia and the lower Delaware area the third largest oil refining area in the country.
Why the concentration along the river? Easy access to tankers filled with Brent Crude, the light and sweet crude feedstock the refineries are designed for. Brent crude is very expensive now. In fact, it has been for a while.
In the past few years, several of these refineries have shuttered because they were no longer economically feasible to operate under the changing market conditions. One of the changing conditions is the cost of imported RBOB and CBOB sold on the NYMEX. Over the past few years the cost of imported RBOB was under the cost to make domestic RBOB. Refiners have to make up some of that cost, and so they have been increasing diesel and fuel oil prices to help compensate. They could do this for a while, but only to a point.
Oil chemistry impacts the price. Oil chemistry affects the refining process, and the cost of refining. Not all crude oil is the same. Crude oil from the North Sea, from North Africa and from the Middle East is light and sweet, meaning that it had a lower sulfur content and a lower concentration of heavy oil compounds. Light and sweet crude is easier to refine, there is not as much sulfur to remove, and it takes fewer steps to make yield.
The many of the refineries in the Philadelphia area are designed and built to take in light and sweet. They can’t take the sour, heavy oils that come out of the Midwest, the tar sands of Canada or the heavy and sour from Venezuela. They can’t get the light and sweet from Texas because there are no crude pipelines or US flag tankers to carry the oil from under the ground in Texas. The light and sweet in the Bakken of North Dakota is trapped from a lack of transport.
To switch these refineries to use the heavy and sour crudes requires substantial capital improvements, replacement of much of the refining process crackers, cookers and towers. Those replacements take deep pocket capital and time.
Time and capital these refineries do not have. I suspect that by the end of the year, Sunoco will shutter all of its refining capacity and become a logistics and marketing company, if is has the money to live. ConocoPhillips already closed Trainer. Costal Refining is in the process of closing.
There is another refinery farther south in Delaware City, DE that Valero once owned. Valero shut down that refinery in November 2009 because management thought there was too much capacity in the region, and they did not want to operate a money-losing refinery. Delaware Governor Jack Markell worked tirelessly to find a company to buy the shuttered plant from Valero and open it back up. With 550 jobs that were the highest blue-collar wages in the state of Delaware, and average salary of over $100,000 per year, the Governor was sure to work his butt off.
The refinery did sell, even if Valero really did not want it sold. The new owners, Delaware City Refining Co. LLC and PBF Holding, not only bought the Delaware City operation, they picked up the Paulsboro, NJ operation that Valero also had up for sale. PBF restarted the operations and is running the Delaware City operation at 50%. Why 50%? It is the part of the operation set up for heavier and more sour crude. In fact, PBF announced plans to invest over $1 billion in a new hydrocracker that would cut sulfur content in about 65,000 barrels per day of distillate to less than 15 ppm and allow processing of a heavier crude. The new hydrocracker would handle production form the Delaware City operations and from the 170,000 barrels per day refinery at Paulsboro, NJ. The plan is contingent on “the issuance of timely and appropriate federal and state environmental and other permits that will not increase the cost to build or operate the project, as well as acceptable labor agreements that will ensure that the project can be built in an efficient and cost-effective manner,” according to the company.
Hence the “costly regulatory requirements” the ConocoPhillips VP of Refining Willie Chiang brought up when announcing the closure of the Trainer facility.
This is just one part of the story. There is more, much more, to tell. As I shared in the beginning of this report, this is a complex story with many moving parts. In the next report we will cover the moving parts, like pipelines and trains.
Until then, let me leave you with two thoughts:
Can you say rising demand in the face of falling supply?