A refining boom in North Dakota? That seems to be the case.
There’s a clear opportunity for new downstream capacity in North Dakota, one of the main centers of the U.S. shale renaissance, but refiners there face a lot of hurdles. A new major plant hadn’t been built in the U.S. since the 1970s, and with good reason: Refining projects are expensive and capital-intensive and the industry is cyclical. Intensely high capital costs, oil price volatility, complex regulatory hurdles, and the uncertain outlook for shale could derail new refining projects in the state. Last year, the first new refinery in the U.S. in roughly four decades, a “teapot” with just 20,000 barrels per day (bd) of capacity, started operation in Dickinson, North Dakota, while a 55,000 bd plant is looking to start construction this year. Before Dakota Prairie Refining opened its facility last year, there was only one refinery in the state. These two would essentially double refining capacity in North Dakota to 150,000 bd.
There’s a clear opportunity for new downstream capacity in North Dakota, one of the main centers of the U.S. shale renaissance, but it faces a lot of hurdles.
The owners of the facilities, Dakota Prairie Refining and Meridian Energy Group, are essentially making big bets on the durability of the U.S. shale industry. The thinking behind the new capacity is as follows: The refiners will run discounted feedstock from local production and then sell refined products directly back to the local economy. “North Dakota has a severe shortage of diesel fuel that will only worsen as oil production continues to grow,” said Meridian Energy Group, the owner of the Davis Refinery that hopes to come on line in 2018, on its website.
North Dakota’s output is falling
While ample oil production and the need for fuel in North Dakota create a clear opportunity, there are a number of cracks in the refiners’ outlook. When Dakota Prairie began building its plant in early 2013, the outlook for shale and the local economies were completely different. Now, crude output is tapering off amid the weak price environment. Production in North Dakota has fallen by 120,000 bd since December 2014.
Against this backdrop, rigs have been idled and unemployment has surged, undermining demand for products like diesel, which is used to produce oil and move the crude where it’s refined. Two years ago at this time, 178 rigs were running in the state, down now to 26. Dakota Prairie Refining’s plant is producing one-third diesel. In the Midwest last year, diesel demand fell along with the rig count, and for the first month of 2016, it totaled 73,000 bd lower than the same time in 2015, according to the Energy Information Administration (EIA). While crude output will likely rebound when and if prices reach higher levels, the efficiency gains the industry has developed could translate into lower fuel demand—or at least cap growth—in the future. A weaker economy in the state could also translate into less local fuel consumption.
Rigs have been idled and unemployment has surged, undermining demand for products like diesel, which is used to produce oil and move the crude where it’s refined.
Meridian isn’t too concerned with the drop in production, and in fact says it could benefit as feedstock costs come down. “The Davis Refinery will generally benefit from lower cost crude, and falling production is a symptom of reduced market value for crude,” William Prentice, the Chairman and CEO of Meridian, told The Fuse in an email. “However, Davis will also increase competitive choices for producers, helping stabilize production.” Meridian noted that production in the state is still above 1 mbd, and the plant will need only 5 percent of that to run at full capacity.
But in a stroke of bad luck for the region, Bakken crude is selling only slightly under West Texas Intermediate (WTI) at the moment, versus more than minus $20 at some points in 2012. If the spread between the two widens again, they will be able to capture discounts for their feedstock, helping support margins.
Shale’s long-term outlook is uncertain
On top of the current plunge in rig activity, it’s unclear what the longer-term trend is for shale. The EIA, for instance, said last year that U.S. shale would begin declining during the first part of next decade, even in its high-price projection. To be sure, however, the amount of reserves in North Dakota is one of the highest in the country, but price and decline rates are key wild cards in the outlook.
There are a couple of other downsides, both of which deal with refinery logistics. North Dakota is not a key demand center like the East and West Coasts, and the infrastructure near the plants isn’t built to move refined products to major areas. At the same time, the North Dakota refineries can’t ship excess supply outside the country, a big advantage for Gulf Coast plants that are able to capture strong margins by feeding Latin America and Europe.
First new refinery since the 1970s
There are two main reasons why a new refinery hadn’t been built in the U.S. in 40 years. For one, it’s an expensive and capital-intensive investment in a cyclical industry. It’s more economic to expand existing capacity than to build new plants. Last year, operating refining capacity totaled 17.8 mbd, up from the low of 14.5 mbd in 1985, reflecting how much growth there’s been even without building new facilities. The biggest additions include Motiva upgrading its refinery in Port Arthur, Texas by about .275 mbd and Marathon more than doubling its Garyville, Louisiana plant to above .5 mbd.
Secondly, there has been significant local and environmental opposition nationwide, with the “not-in-my-backyard” argument derailing multiple projects. For instance, Arizona Clean Fuels, which tried to build a new refinery in Yuma, had to deal with rising costs, a long permitting time, and stricter environmental regulations. The company’s website’s last post was a link to a Yuma Sun 2009 article with the title “Refinery Still Moving Forward.” Clearly it’s not. Hyperion Refining in South Dakota ran into similar obstacles in 2013 and never went forward with construction of its massive $10 billion, 400,000 bd project.
The facility at Dickinson, which is owned by WBI Energy and Calumet Specialty Products Partners, cost $400 million to build. While that number is relatively modest in capital expenditure terms, the facility is itself small, hence the term “teapot” when used to describe it. Meridian Energy Group, meanwhile, wouldn’t give a cost figure, but says it has been able to keep outlays under control. “Our capex is well under what one would expect of a complex facility this size, and we will be solidly profitable very early,” the company told The Fuse by email.
Putting economics aside, the proposed plant’s biggest pressure may come from permitting and local opposition, given that it will be located near the historic Theodore Roosevelt National Park. “If you visualize a typical refinery located there, I can understand why [locals] are nervous,” Meridian’s Prentice told The Fuse. “However, this will be… a game-changing facility in this industry, and we will meet or exceed even the stringent regulations imposed on us due to our location. If we tried to resist the need to take the high-road on compliance, it would cause setbacks, but we won’t.”
The future of refining in North Dakota will depend on a growth profile in crude production.
Meridian is currently completing the engineering and modeling necessary to file for an air quality permit, a big step in moving forward toward the construction phase. “This is going to be the cleanest refinery in the world, but we have to prove it,” Prentice said.
It’s clear that both plants and their owners have a long slog ahead of them in turning their investments into profitable ventures giving the shifting dynamics of the downstream industry—and the U.S. shale outlook. The future of refining in North Dakota will depend on a growth profile in crude production. In order for that to occur, oil prices need to rise to boost activity and support demand. It’s ironic that refiners will cheer higher prices for crude, but that’s the case in North Dakota.