I keep running across comments on numerous websites where several claim that the price of gasoline is high because we cannot build new refineries. The fact is that is flat wrong. In terms of overall capacity the U.S. has too much with 600,000 BPD of refining capacity sitting idle and shutdown PERMANENTLY. In addition to this, there is at least 200,000 BPD of capacity which has been shutdown for a number of years and no longer considered in refining capacity utilization reports.
Now that that is stated, let me address "refining capacity" which is not exactly a true measure. Refineries are built for certain slates of crude oil sources. Two of the main points to consider are API Gravity and Sulfur Content. Inside of these a refiner must consider a detailed assay of a crude oil, with consideration given to naphtha, paraffin and asphaltene content, just to name a few.
Now that we have considered feedstock, we need to consider what markets the refinery is going to serve. Will the market be just to produce gasoline, diesel, kerosene (jet fuel) and fuel oil? What about asphalt, petrochemicals feedstocks (naphthas, benzene, toluene, xylene, propylene, butanes, etc...) and lube oil/greases? What about reformulated gasoline? How about ultra low sulfur diesel? Is there a petroleum coke market? All of these things are crucial into deciding the configuration of a refinery, but it all comes down to two things, feedstock and market for products as to how a refinery is built, or complexity of a refinery.
Now we talk about refining capacity of an individual refinery. I won't bore you with engineering details, but instead give an example of one that I tried to sell a few years ago.
This was a nice little refinery, a few decades old but recently modernized less than a decade ago for using 35 API low sulfur crude oil. It was a simple "hydroskimming" refinery with a crude unit, and a reformer. A reformer is required to produce usable gasoline with high enough octane rating. There was a local metro area where all of the gasoline, kerosene and diesel could be sold & delivered via tank trucks able to load and deliver more than one truckload per day. The crude unit residual bottoms could be delivered, also via truck, to another couple of refineries within easy driving distance where they could be further processed and broken down into refined products.
There was one problem and that was that the pipeline which delivered feedstock was changed to a Canadian heavy crude blend averaging about 20 API Gravity, and of high sulfur content. There were sources of local crude oil but while being very low in sulfur, were very light. So, the refinery went from being rated at 12,000 BPD to never being able to refine more than 10,000 BPD due top loading of the crude column with light ends (gases) from the 60 API Gravity available crude oil. My client desired to relocate this refinery and use it for a low sulfur 40 API crude high in naphtha content which would have resulted in close to 15,000 BPD capacity.
See I've made three critical points here being...
1. Refining capacity always depends on crude source, change in crude sources will change actual capacity.
2. Crude source and market needs dictate design of a refinery
3. Logistics of getting the proper crude oil or blend of crude oils to a refinery are CRUCIAL
All of this being said, let me point out that we have expanded an reconfigured substantial refining capacity over the last decade.
Midwest - After Billions of dollars in capital investment into reconfiguration and expansion of 10 (more or less) major refineries, they can now use Canadian heavy crude blends, which are a blend of produced (pumped out of the ground) and syncrude (upgraded to around 40 API gravity with sulfur having been substantially removed) with an API gravity of around 20 or so. They no longer need to have supertankers offloading at LOOP (Louisiana Offshore Oil Port) and shipping 1.2 million BPD via the Capline Pipeline to IL to be shipped, via pipeline, refineries in MI, IL, IN & OH.
East Coast - Several old inefficient refineries have been torn down which were wholly reliant on light sweet crude. Cost to transport "Bakken" type tight shale crude via tank car is cost prohibitive. Refined products pipelines from the Gulf Coast deliver goods cheaper than these refineries and make them.
Gulf Coast - A dozen very major refineries which began to be reconfigured for very heavy crude with high sulfur content from Venezuela and Mexico (Mayan) in the early 1980's to capitalize on low cost of those crude oils and exponential increase in worldwide demand for petroleum coke. These refineries NEED heavy crude to be efficient, tight shale production does not supply that, but Keystone XL would. Deer Park Manufacturing Complex (Shell operated in Houston area) is no longer under contract for processing heavy crude for PEMEX. Several huge expansions occurred in the last 10 years.
West Coast - California refineries have been processing heavy crude from the Los Angeles & Kern River basins for decades, able to handle Canadian heavy blends without much alteration.
Rocky Mountain - Capitalizing on Bakken price delta and have expanded dramatically mostly by relocating idle process units from refineries in other areas compatible with light sweet crude. BTW, that proposed Hyperion refinery of ND appears to nothing but hype. They never applied for all the permits and never obtained the land.
Carribean - Refineries in St. Croix & Puerto Rico are all permanently shutdown. This is purely due negative cash flow reasons, EPA regs and fines didn't help but not the real reason. The cost of crude from overseas, shipment of production via sea and cost to operate are all too high to be viable.