U.S. refiners turn to heavy oil amid pipeline crunch
Fat margins could be crimped by takeaway capacity, pollution rules
Amid the rolling landscape of east-central alberta, where Highway 13 dips into a valley that cradles the Battle River roughly 160 kilometers southeast of downtown Edmonton, the staging ground for a half-century of petroleum exports rises abruptly on the horizon. “These are all the new tanks that were built in 2008-09, these ones right along the road here,” says Alan Parkin, chief administrative officer with the Town of Hardisty. He eases his minivan off the highway and gestures to a cluster of jumbo storage terminals. “This is all Enbridge.”
The side road is lined with the towering vats, painted white and gleaming in the morning sun. Calgary-based Enbridge Inc. is by far the biggest terminal operator on the Prairie outcrop. The firm’s Hardisty Contract Terminal – which competes for space with tanks owned by Kinder Morgan Canada, Gibson Petroleum Co., Flint Hills Resources and Husky Energy Inc. – can store 7.5 million barrels of oil, enough to fill 48,000 Olympic-sized swimming pools to the brim, although eyeballing precisely how much oil is sloshing around in the giant steel reservoirs at any given time is no exact science. “There’s really no way of knowing if they’re full or not,” Parkin says.
There are signs, though, that activity in the region is poised to accelerate. Steering his car onto a gravel stretch of road, Parkin stops and points north to a rise, bereft of much save a few trees. Heavy machinery works below, in the shadow of three oil tanks bearing the TransCanada Corp. insignia. “They’re getting things ready to start construction next year,” the administrator says. “Keystone XL is behind this hill.”
Plans for the multibillion-dollar pipeline call for construction of three additional storage tanks – big enough to each hold 350,000 barrels of oil – to facilitate added deliveries of crude oil to the Texas Gulf Coast. The site was leveled last year, Parkin says, in anticipation of a speedy approval for the project by the United States Department of State that never quite materialized. “They’re not going to do anything over the winter,” Parkin guesses.
Nor, it seems, will much happen come spring. After years of regulatory reviews, approval of the controversial Keystone expansion could be delayed by anywhere from 12 to 18 months, until after the 2012 presidential election. The State Department signaled in November that it would ask TransCanada to study alternative routes for the artery that skirt the Sand Hills region in Nebraska. TransCanada has said it will re-route the pipeline to avoid the area. Steven Paget, an analyst with FirstEnergy Capital, calculates the delay could cost the Calgary firm at least $29 million per quarter over 18 months, assuming a six per cent annual cost to the $1.9 billion the pipeline giant has so far invested in materials and site preparation. That could push the overall capital cost of the project north of $8 billion, a $1-billion jump from original estimates that could ultimately be passed to shippers in the form of higher tolls if and when the line gets built.
Even that prospect has not been enough to send comitted customers into the arms of transportation rival Enbridge Inc., which has plans of its own to connect oil sands producers to the Gulf Coast. “We still have an agreement with TransCanada over Keystone,” says Valero spokesman Bill Day, declining to discuss specific commitments. “For now we’re still in support of the Keystone project. We’re hopeful that the Obama administration will come to its senses.”
Valero has invested heavily to boost its heavy oil refining capacity. The company is midway through a $1.6-billion upgrade to its century-old Port Arthur refinery. Construction has begun on a 60,000-barrels-daily hydrocracker unit plus facilities designed specifically to process an additional 150,000 barrels of high-acid, heavy sour Canadian oil sands crude every day. The project was shelved by the financial contraction of 2008-09 but has since been revived amid growing global demand for middle distillates like diesel and jet fuel.
The company hopes to complete the expansion by the third quarter of 2012, slightly ahead of the initial proposed 2013 startup of TransCanada’s Gulf Coast bullet line. The pipeline delay has not changed those plans. Nor has it obviated the demand for Canadian bitumen. “It makes more sense to bring that oil from Canada to the U.S. Gulf Coast where we have processing capability than to try to build processing capability up where the oil is in Canada,” Day says, echoing a widely held and – for Canadian labor groups – controversial view that diluted bitumen will help replace dwindling production of Maya crude from Mexico and uncertain output from Venezuela. “We’re hopeful that heavy oil from Canada will supplant some of those supplies at Port Arthur.”
Valero is far from the only refiner preparing for a flood of Alberta bitumen. As more oil sands output flows through Hardisty – the town bills itself as “Alberta’s Oil Hub” – en route to markets in the U.S., refiners from the Gulf Coast through the Midwest and up to Detroit are spending billions of dollars to refit old plants with additional or brand new coking capacity to handle and process the stuff. The last 25 years in particular have been marked by a seismic shift in the consistency of U.S. oil imports, the Congressional Research Service reports. Imports have grown steadily “heavier” while the average sulfur content of those barrels has increased. The change has forced refiners already facing higher crude prices – and thus, higher input costs – to invest in expensive technology to treat low grade volumes of crude or else exit the business entirely. At the same time, environmental legislation, improving vehicle efficiency standards and excess plant capacity are conspiring with soft demand for refined petroleum products at home to dim the sector’s long-term prospects.
Philadelphia-based Sunoco Inc. announced in September that it plans to close two refineries on the U.S. East Coast and exit the business completely. Only a few weeks later, ConocoPhillips Corp. announced that it had suspended production at its 185,000-barrels-daily Trainer refinery in Pennsylvania. The company cited the large investment required to meet new state regulations for the sulfur content in heating oil and gasoline as one reason for its decision, and made clear that it would mothball the facility if a buyer couldn’t be found within six months. All told, the announcements fit a pattern of global consolidation that removed roughly one million barrels of primary distillation capacity from the market in September alone, according to the International Energy Agency’s October monthly oil report. Industry observers expect the trend will likely continue. “We foresee more closures,” says Jackie Forrest, Calgary director, global oil, for consultancy IHS CERA. “We’d expect as much as 500,000 barrels per day of refining capacity to be taken out of North America in the next five or 10 years, and that’s just because we’re not going to need all those refineries, because demand for refined products is slowly declining.”
Appearances, though, can be deceiving. Amid the shutdowns and sales announcements, some American refiners have persevered, thanks in no small part to the glut of crude oil stuck at Cushing, Oklahoma, and the ongoing regionalization of West Texas intermediate (WTI) as a benchmark price compared to its international counterpart, North Sea Brent. Refiners that process heavier crudes in particular, including Calgary-based Cenovus Energy Inc. through its partnership with the newly formed downstream division of ConocoPhillips, saw cash flows bolstered by higher-than-expected refining margins through the first half of 2011. Cenovus and ConocoPhillips share ownership of the Wood River plant in Roxana, Illinois, which can process some 356,000 barrels of crude oil every day. A $3.7-billion expansion of coking capacity at the facility completed this fall – mirroring ongoing expansion at the pair’s Foster Creek and Christina Lake joint ventures – promises to bring heavy crude oil refining capacity to roughly 240,000 barrels per day and boost product yields by five to 10 per cent by converting asphalt into gasoline, jet fuel and diesel.
Not to be outdone, Marathon Petroleum Corp., the refining arm recently spun off from Marathon Oil Corp., has likewise spent big to boost coking capacity. The Findlay, Ohio-based firm completed a $3.8-billion upgrade to its Garyville, Louisiana, refinery, which handles mostly heavy sour crudes, in 2009, boosting capacity by 208,000 barrels per day. And work continues on a $2.2-billion heavy oil upgrade project at the company’s Detroit refinery, where plans call for the addition of a 28,000-barrel-per-day delayed coking unit to process heavier slates of crude oil, as well as construction of a pipeline spur to tap growing supplies of Canadian oil sands by fall 2012.
In all, the project will allow Marathon to process an incremental 80,000 barrels per day of heavy Canadian crude, boosting local refining capacity by 15 per cent. As his company announced second-quarter net income had jumped roughly 50 per cent to $802 million from $405 million a year earlier, company president and chief executive officer Gary Heminger highlighted the not-so-secret ingredient in the sector’s financial success. Marathon’s refining and marketing gross margin had surged nearly 50 per cent in the second quarter, to 25.66 cents per gallon from 13.06 cents a year earlier. To explain the spike, Heminger turned his attention to the Mid-continent, home to 50 per cent of his firm’s refining capacity. The company will continue benefiting from cheaper crude acquisition costs, he informed investors, so long as “growth in domestic and Canadian crude supply exceeds the logistical systems needed to move the new production to consuming markets.”
It comes as no surprise that refiners are making significant headway in their ability to process heavy oil. The U.S. refining industry has evolved in tandem with growing production of the stuff in Mexico, Venezuela, Colombia and Alberta. As much as 20 per cent of global oil reserves are considered heavy. Of that, fully 1.1 trillion barrels is considered technically recoverable with today’s technology. Beyond the financial benefits – and increasingly, the pure necessity – of buying heavier oil, the advantage of building infrastructure to process lower grade barrels shows up in product yields. “You can make more refined products out of them,” Forrest at IHS CERA says. “If you go to the Middle East, if you look at what’s being built in India, in China – these are complex refineries, and complex refineries tend to be able to make more products if they’re running heavier crudes, because they can take that heavy bottom and create refined products out of it.”
Higher margins enjoyed through much of 2011 will likely persist at least until additional takeaway capacity materializes from the U.S. Midwest. TransCanada’s Keystone expansion was billed as an equalizer of sorts that would solve a historic discount leveled against Canadian heavy crude relative to its Mexican and Arab counterparts in the Gulf Coast market. The spread has averaged between US$10 and US$12 per barrel over the last three years, according to analyses by Calgary-based Peters & Co. That gap could tighten “significantly,” the investment brokerage says, as Mexican imports to the U.S. dwindle, and are ultimately replaced by Canadian barrels. More immediately, robust demand for heavier barrels in the Midwest could see Western Canada Select – the primary heavy oil marker for Canada – priced at a narrower discount to WTI, in the US$10 per barrel range, over the next 12 to 18 months or until new pipes are built, FirstEnergy Capital predicts. For oil sands operators, though, even that upside will be short-lived. Even if the WTI-Brent spread narrows, “There isn’t an unlimited set of refineries [in the Midwest] that we can sell to,” Forrest says.
The capacity constraint is exacerbated by surging production of light oil from North Dakota’s Bakken formation. The renaissance in light oil production has led to steeper discounts for Canadian crude and thrust pipeline builders into a race to crack the Midwest storage glut. Enbridge is eyeing mid-2012 to reverse the Seaway pipeline it paid $1.15-billion for a one-half stake in, and TransCanada has mused publicly about de-coupling the southern leg of its Keystone expansion. Both projects will squeeze refiners, who have grown accustomed to fat margins and markets flush with cheap oil. Prices could rise further as upgrades to refineries in Wood River and Detroit, led by Cenovus and Marathon, respectively, boost demand for heavy oil by 210,000 barrels per day by the second half of 2012, RBC Capital Markets predicts.
The risk for refiners looking to sync facility upgrades with growth projections in Alberta’s oil sands remains carbon. A suite of proposals put forward by the U.S. Environmental Protection Agency currently making its way through Congress could make processing heavier slates of crude oil more expensive. As of January, new rules that target so-called “stationary sources” of air pollutants under the U.S. Clean Air Act mandate that any refinery undergoing major upgrades must deploy the best available technology to reduce greenhouse gas emissions. The concept remains highly subjective, but it could evolve to include high-cost technologies like carbon capture and storage, Forrest warns. Performance standards that might, for example, target GHGs per unit of output at refineries and power plants are also on the environmental watchdog’s drawing board.
Add in the effects of low-carbon fuel standards – currently being considered in roughly 50 per cent of the U.S. gasoline market, according to CERA – and refiners could be forced to rethink their growing reliance on heavier blends that boast higher-than-average GHG life-cycle emissions. “Most of them are targeting a 10 per cent reduction in all of those emissions over 10 years,” Forrest notes, describing the carbon policies. “If you’re trying to sell Canadian oil sands into that market, it’s pretty tough to see how you’re going to comply with that mandate if you’re going to bring in higher-carbon crudes.”