Refining Heavy Crude

Global refiners expand as U.S. refiners anticipate greater access to secure supplies through new pipelines.

The United States is the world’s largest current and likely market for refined products and heavy oil refining in the near term. Going forward, FUEL examines the potential impacts resulting from the still-rising trend and plans for refining heavy oil in the U.S. refining markets.

U.S. and global refiners are investing in equipment to convert rising flows of low-cost heavy crude into higher value light petroleum products. Canadian oil sands operators in Alberta are expanding production of synthetic crude oil and diluted bitumen while pipelines seek to expand on each side and across the U.S. northern border.

Such stable and growing supplies can calm or even swamp U.S. energy markets, which in recent months have seen delays in pipeline projects as uncertainties or declines have unfolded across key U.S. crude supply points.

These include the Macondo disaster in the Gulf of Mexico, the Enbridge and Alyeska pipeline leaks and uncertainties over Middle Eastern crude availability through Egypt or from Libya in just the last three quarters alone.

The role of heavy Canadian crude oil amid rising geopolitical uncertainty was the topic of a February 23 interview on CNBC with Dr. Mohamed El-Erian, CEO and co-chief investment officer of PIMCO, which manages US$1 trillion dollars of assets. El-Erian noted both “new sets of risks” and “new sets of opportunities,” saying, “there are many oil exporters out there that don’t have geopolitical issues who are benefiting from higher oil prices – like Canada.”

U.S. advantaged to refine Canadian heavy crude

Q&A with John Hofmeister on North American Energy Supply

FUEL conducted an extensive interview with John Hofmeister, noted energy expert and former president of Shell Oil Co., who now runs Citizens for Affordable Energy, to find out more about the present and future state of North America’s energy supply.

FUEL: In your recent media appearances, you relayed expectations for high crude and retail gasoline prices. What is your outlook for energy affordability?
Hofmeister: It’s my view that global demand including U.S. demand is going to push oil prices to triple digits this year, probably in the first half [of the year]. Is it accurate to expect US$5/gal gasoline in 2012, and $100 per barrel crude in 2011?

I think OPEC [Organization of Petroleum Exporting Countries] will be reluctant to increase production for a variety of reasons, not the least of which [is] some of its members are really strapped with declining production. They need all the money they can get.

FUEL: How important is the resumption of deepwater drilling to U.S. energy markets?
Hofmeister: With the [U.S] Interior Department managing the richest oil basin in the U.S. to full stop in terms of future drilling, production only declines in the Gulf of Mexico.

The absence of drilling will lead to production decline at a time when the world needs more oil, not less. I am projecting unscientifically up to 1 million b/d short by the end of 2012.

The natural decline of production with the absence of new drilling yields roughly 1 million b/d of oil equivalent out of the Gulf of Mexico by the end of 2012 into 2013. It will take years to recover that.

FUEL: Will an increase in onshore unconventional oil production offset the decline in offshore production?
Hofmeister: The Interior Department will quote figures of [onshore] drilling increases for 2010 versus 2009 [to] make it sound like drilling is increasing, not decreasing. But that’s different than [declining] production numbers from the huge reservoirs of the Gulf. Those will not be offset by the small incremental amounts of unconventional oil coming out of the gas shale plays.

In other words, you can drill night and day, which they do, but the amount of production is so modest relative to the big reservoirs in the Gulf. You are not discovering nor producing at the enormous quantities of the Gulf of Mexico reservoirs.

FUEL: Unconventional initial production flow rates of 1,000 or 2,000 b/d at best do not compare well with the flow rates from deepwater wells such as at Macondo, do they?
Hofmeister: If you compare Macondo at 65,000 b/d spewing into the Gulf, versus just as you say, 1,000 b/d initial production, there is no comparison.
We have in the Piceance Basin in the Rockies – in Wyoming, Utah, and Colorado – about 1 trillion bbl.

But development has been blocked particularly by Denver-elected officials, most notably then Sen. Ken Salazar, who now happens to be Secretary of the U.S. Department of Interior.

When you have the Interior Department run by an attorney general, which he was before he was a senator, and a prosecutor from the Justice Department, Michael Bromwich [now director of the Bureau of Ocean Energy Management, Regulation and Enforcement], you get what you get.

That’s largely a mindset that says ‘stop’ so that no risk is taken, or ‘stop or we’ll prosecute.’ So we have been in a stoppage.

FUEL: From south of the U.S. border, Juan-José Suárez-Coppel, CEO of Pemex, disclosed plans on CNBC to ramp crude production for internal consumption and export. Will rising Mexican production alleviate shortfalls in U.S. waters?
Hofmeister: The predicted rate out of Mexico that we heard was to recover production to 3 million b/d by 2015. But that did not sound unequivocal – he did not sound sure – it was not a hard number.

If you tell the whole story of Mexico, they have mortgaged oil production in prior years for future production. They are mortgaged nine years into the future.
They were paid already for production for 2013, 2014, 2015, etc. So what they have to do is to keep mortgaging future production.

And that [forward arrangement] was mortgaged at then-current crude oil prices. Mexico faces a severe revenue problem, which causes them to mortgage even more production. So the people who are buying those future contracts, they’re buying a lot of air.

The CNBC reporter after the [Pemex] report noted that when politicians run the industry, you get what you get. The same principal applies in this country when the politicians run the industry.

Right now what we are seeing is the Interior Department running the Gulf of Mexico right into the ground.

FUEL: Across the northern border, Canada is already the largest source of imported crude oil. The TransCanada Keystone XL pipeline expansion seeks to extend that supply, yet the administration is delaying necessary permissions. Your thoughts?
Hofmeister: It is an absolutely necessary part of our future infrastructure if we are going to continue to supply the American consumer with the fuels that they need to live their lives and to keep our economy strong. That’s point one.

Point two is that the ecological issues raised by either oil sands or by pipelines of such great length crossing rivers, valleys and lakes, are fundamentally manageable.

If the American consumer is not going to be able to access the Canadian oil sands product, you can be absolutely 100% sure that Chinese consumers will.

FUEL: Canada’s other major oil pipeline operator, Enbridge, recently announced investment from China’s Sinopec to study feasibility of a westward pipeline from Alberta to Canadian West Coast export facilities. Any insight on that?
Hofmeister: The reality is the oil sands oil is going to be produced. It can either go south or it will go west to China. It will be consumed.

If the [Obama] administration is so short-sighted and so insensitive to the affordability of fuels by the citizens of the U.S. as to deny the pipeline’s construction, it is only a matter of time that the populace changes who is in government through an election cycle.

The president is at risk at losing a re-election contest based upon the real pocketbook issue of gasoline prices. His own Interior Department is directly contributing to the risk … by refusing to produce oil.

FUEL: What’s ahead for the exploration and production industry in the U.S.?
Hofmeister: Two other [indicators] show the Interior Department is intent on stopping things rather than making things happen.

The Interior Secretary, of his own authority without any congressional interactivity, has created a new concept called the “Wilderness Zone,” which the secretary himself can determine is sufficiently sensitive as to disallow mining, drilling or any other industrial use.

Even worse, in my opinion [is that] early in December, the secretary announced that he would postpone the next five-year plan, due in 2012, to 2017.

That is a message to the industry that, whether the president gets re-elected in 2012 or not, the Interior Department of the United States of America is punting on any offshore leases for the duration of how long they might be in office.

That says to the world that the U.S. is not going to produce its own oil and is going to rely on more imports. This creates the psychology of high-priced crude.

The U.S. economy benefits from access to stable imports of crude from neighboring Canada that amounted to 1.8 million b/d in 2009. This one nation provided about half of the heavy crude run in U.S. refineries that year.

Unlike the rest of the world that also seeks heavy oil to refine, the U.S. economy also benefits from proximity to Canada’s reserves, which represent more than half of the commercially available heavy oil reserves not controlled by national oil companies of foreign governments.

The U.S. also is advantaged with an installed capital base of 137 complex operating refineries, which in 2009 processed 14.7 million b/d of total crude oil (5.4 million b/d of domestically produced, the rest imported).

The country also benefits from a large base of refineries capable of processing heavy crude, which processed 3.7 million b/d of heavy crude, half of which came from Canada.

Therein lies the potential opportunity for additional imports from Canada to replace the other heavy crude sourced from global markets. As part of a proposed $13 billion investment, TransCanada Corp. seeks to implement the Keystone XL pipeline expansion to boost heavy crude imports by at least 700,000 b/d beginning in 2013, if the Department of State grants approval in 2011.

With a new pipeline running from Canada to Cushing, Okla., and another segment running from Cushing to the U.S. Gulf Coast, the proposed Keystone XL project would supply additional heavy crude into U.S. markets while de-bottlenecking the oversupplied oil trading hub and offering new crude supplies to the 8.6 million b/d refining network along the U.S. Gulf Coast. The pipeline also has plans to pick up hundreds of thousands of barrels each day of unconventional oil from the Bakken producers as it runs past the region on its way to Cushing.

U.S. refiners are investing to refine heavy crude
FUEL spoke with Khary Cauthen, Washington representative of the American Petroleum Institute (API), who noted that refiners are making “major investments and modifications to their facilities to take in this important resource from our neighbor to the north.”

According to the API, “Canada’s oil reserves are second only to Saudi Arabia, and America imports more oil from Canada than from all Persian Gulf countries.”

Heavy oil typically trades at a discount to lighter crude oils because it is harder to process into light valuable products. That’s why refiners invest in conversion units, special metallurgies and other assets that allow heavy oil refining.

The wide variation in heavy oil crude quality affects how and where it can be refined. Such considerations include whether it was diluted or pre-processed into “syncrude” (synthetic crude) in Alberta, as well as the inherent properties of the oil such as metal content, including nickel and vanadium, acid level, nitrogen and carbon content, and the sweet/sour sulfur and acid characteristics of the oil.

Even with all the fundamental crude quality variations, refiners employ three predominant types of processing units – cokers, hydrocrackers and catalytic crackers – to convert heavy crude into usable products and commonly referred to as “conversion capacity.”

As of January 1, 2010, the U.S. Department of Energy’s annual census of refinery capacity listed substantial heavy crude conversion capacity, including 2.4 million b/d from cokers, 1.7 million b/d from hydrocrackers and 5.7 million b/d from catalytic cracking units. Nearly half of U.S. refineries operate coking units.

Additionally, Terry Higgins, executive director of Hart Energy’s World Refining & Fuels Service (WRFS), said that U.S. refiners will likely complete less than 500,000 b/d of underway expansions before 2015. After that, Higgins sees nothing else on the horizon. That limited investment in U.S. conversion capacity expansions contrasts with more aggressive plans by the other nations that he tracks.

China angling to be the heaviest of heavy oil refiners
Hart Energy’s Refinery Tracker counts 20 million b/d of announced crude refining capacity expansions by 2015 concentrated in Asia, the Middle East and Latin America. Higgins said WRFS analysis of the most-likely projects found that global conversion capacity expansions should exceed 10 million b/d by 2030 similarly concentrated in these regions. Is it a wonder that China is lining up access to Canada’s heavy oil sands?

The recent Energy Predictions 2011 report by Deloitte LLP noted a “China effect” as tanker runs from Canada’s West Coast to Asia began with one heavy crude tanker in 2005, expanded to four by 2008 and “in 2010, one vessel a month made the trip, each carrying 600,000 bbl of oil.” The report also cited China’s interest in “new pipelines” heading west. Sinopec recently disclosed an early investment in Enbridge’s proposed $5.5 billion Northern Gateway pipeline from Alberta to Western Canada’s deepwater ports.

Laura Atkins, Hart Energy’s director of Petroleum Research and the principal author of the report Heavy Crude Oil: A Global Analysis & Outlook to 2030, told FUEL that “Canada has a tremendous amount of heavy oil reserves and production is increasing every year. The Chinese have been buying into partnerships for oil sands and upgrader projects. It makes sense that if they can get Canadian heavy crude to Canada’s West Coast and then on to China, then they will do it.”

Deloitte’s report noted recent oil sands deals by PetroChina and Chinese National Offshore Oil Co. (CNOOC). According to Roger Ihne, principle and portfolio leader with Deloitte’s energy practice, unlike prior investment in U.S. refineries by Saudi Aramco, PDVSA (Petróleos de Venezuela) and others, today’s foreign energy investors aren’t aiming to place rising crude production in U.S., but rather to source fuel for home markets.

“It’s about fuel-hungry nations,” Ihne told FUEL. He also noted a potential for upstream/downstream cross-border “backward/forward integration.”

These transactions are exemplified by Canada’s Suncor Energy, which since 1967 has produced Alberta oil sands and now refines that production in Denver and at refineries across Canada. Another example is Canada’s Cenovus Energy, which operates refineries in partnership with ConocoPhillips in Texas and Illinois, which are expanding conversion capacity and doubling heavy crude runs.

Energy analyst Matthew Jurecky with Wood Mackenzie said in a February 9 CTV News report that this round of oil-directed investments by foreign multinationals could be “the tip of the iceberg.” That report also noted that CNOOC paid $3.5 billion to acquire a 33% interest in Chesapeake’s Eagle Ford (Texas) and Niobrara (Colorado) acreage to access unconventional oil production.

U.S. conversion expansion plans nearing completion
Global heavy oil production growth is spurring the strongest conversion capacity growth outside the United States. The paucity of U.S. conversion capacity expansion may in part be explained by strong existing capacity and ongoing logistical constraints. Another point is that alternative fuels and advancing efficiency standards are expected to lower U.S. gasoline demand.

High-dollar refinery capital investments in the U.S. are hard to justify given the overhang of excess refining capacity that awaits closure or sale.

If excess refineries are sold, competing operators may benefit by picking up refining capacity at below-replacement costs. To the detriment of the seller and other operators, that could enable the new owners to accept lower refinery margins on bargain-basement investments.

Furthermore, the current administration’s push for greenhouse gas permits and other restrictions are causing refiners to expect “additional tranches” of “incredibly expensive” environmental costs, as Sunoco Inc. CEO Lynn Elsenhans stated at the 2011 Deloitte Oil and Gas Outlook Conference in Houston.

Yet, some refiners like Cenovus and ConocoPhillips at their Wood River, Ill., joint venture refinery are proceeding with U.S. conversion capacity expansion projects.

Marathon Oil Corp. in recent years has committed more than $6 billion to expand U.S. refineries to run heavy oil. The $4 billion Garyville Major Expansion project that added 200,000 b/d of heavy oil capacity might not have happened if it were to come up today, FUEL learned from Marathon’s Jim Shoriak, director of refining group major projects.

Shoriak told FUEL at the 2010 World Refining Summit in Houston, “we were very glad to have gotten this project permitted when we did. I doubt that we would make this type of investment, starting from scratch right now, with the environment that we see ourselves in.”

Janet Clark, Marathon Oil Corp’s chief financial officer, spoke of the project at the Deloitte 2011 Oil and Gas Outlook Conference, saying it will run “the cheapest source of crude available. And we think that positions Garyville to succeed in a more challenging environment.” Clark noted U.S. refining market uncertainty, but said Marathon invests “with the flexibility to adjust.”

U.S. imports of heavy oil from Canada have doubled in the last 15 years, offering refiners and petroleum consumers secure and nearby access to plentiful resources. Source: FUEL Estimates, National Energy Board of Canada

Clark added that the firm’s $2.2 billion Detroit Heavy Oil Project is being made “to take the heavy oil from Canada and convert it into light, high value transportation fuels.” An analysis by FUEL suggests an incremental 80,000 b/d capacity to run heavy Canadian crude will result there.

FUEL also contacted company officials for details on the $5 billion Port Arthur Refinery expansion by Motiva Enterprises in Texas. There, a 95,000 b/d coker expansion unit will nearly triple the plant’s current coking capacity to support crude run expansion to 600,000 b/d from 275,000 b/d today.

Robert W. Pease, CEO of Motiva Enterprises told FUEL at a recent refinery conference that his refineries “are geared for heavy crude. There’s a lot of it out there.”

FUEL asked about the back-up plan if that doesn’t come from Canada. Pease replied that it would potentially “alter economics, and we would sure like it to be as efficient as possible, but we will adapt to whatever we have to. It’s going to come from somewhere. The world rebalances.”

Tesoro Corp. also detailed benefits of refining diverse heavy oils during the company’s February 3 conference call to release fourth-quarter 2010 results. Everett Lewis, executive vice president and chief operating officer, Tesoro, said, “we continue to be very creative around what we are doing with our crude sourcing. We ran almost 35 different sources of crudes in the fourth quarter.”

Tesoro spokesperson Mike Marcy told FUEL that Tesoro’s West Coast refineries “run a basket” of Pacific Rim crudes from overseas and onshore including San Joaquin valley heavy crude. “Depending on the metallurgy and how each refinery is configured … most refiners will blend the various crudes … that they have determined over the years … [are] most advantageous to the refinery, also depending on what is the product mix of the refinery. … It’s part of the romance of the industry.”

Valero Energy Corp., which operates 14 refineries in North America with 2.6 million b/d crude processing capacity, disclosed during its fourth-quarter conference call an ongoing $1.5 billion hydrocracker project at the Port Arthur Refinery in Texas. It will start in late 2012 and enable 150,000 b/d runs of heavy Canadian crude. The company also disclosed it will complete a similar 50,000 b/d hydrocracker by year-end 2012 at the St. Charles Refinery in Louisiana.

According to Valero spokesman Bill Day, Valero’s refineries in 2010 ran nearly 80 different crudes including about 450,000 b/d of heavy crude and domestic onshore conventional and unconventional oil to diversify risk from declines in Mexican crude output, declining Gulf of Mexico crudes post-Macondo and interruptions from foreign waterborne sources.

Day noted how unconventional oil into Cushing’s already long oil storage flush with Canadian and Mid-continent crude has depressed prices for the West Texas Intermediate (WTI) grade of crude relative to international waterborne crudes such as Brent.

“With the availability now of Eagle Ford oil and its price relative to WTI versus the waterborne crudes that come into Corpus Christi that are priced more along the lines of Brent crude, the Eagle Ford is more affordable. We are maximizing its use,” Day said.

Historic time for a North American choice
At press time, the U.S. oil hub at Cushing, holds nearly 38 million bbl of deeply discounted conventional, unconventional and heavy oil in storage since takeaway capacity has not kept pace with a changing onshore production landscape and rising oil supply inputs at the hub.

As Mexico and Venezuela exports declined in last decade, the U.S. imported more heavy oil from Canada and from ever more far-flung regions.
Source: U.S. EIA, FUEL Analyses

Without enhanced takeaway to the nearly 8 million b/d of refining capacity along the U.S. Gulf Coast, which represents about half of U.S. refining capacity, the land-bound stored crude trades at what some are calling a permanent discount to more fungible waterborne crudes like the Brent or Louisiana grades. Though that may be good news for the mid-continent refineries with 2 to 3 million b/d of capacity with access and equipment to run such crudes, it helps neither North American crude producers nor nearly half of U.S. producers and fuel consumers.

Incremental fixes may include a reversal of crude pipes running from the Gulf Coast to Cushing, such as the ConocoPhillips Seaway pipeline, although that company’s management recently said such a reversal was not in the company’s interests.

Another short-term option includes moving crude by truck and rail tankerage (at only a couple hundred barrels at a time) from Cushing to the Gulf Coast. A more long-lasting solution is that proposed by TransCanada’s Keystone XL pipeline expansion.

Commenting on the importance of the Keystone XL pipeline expansion for the U.S., John Hofmeister, noted energy expert and former Shell Oil president, who now runs Citizens for Affordable Energy, told FUEL the pipeline expansion is “an absolutely necessary part of our future infrastructure” needed “to supply the American consumer with the fuel so that they need to live their lives and to keep our economy strong. If the American consumer is not going to be able to access the Canadian oil sands product, you can be absolutely 100% sure that Chinese consumers will. The oil sands will be produced, period. It can either go south or it will go west to China. It will be consumed.”

On February 4, Canada’s Prime Minister Stephen Harper met U.S. President Barack Obama and discussed multiple topics including the Keystone XL expansion.

“The choice that the United States faces,” Harper said, “is whether to increase its capacity to accept such energy from the most secure, most stable and friendliest location it can possibly get that energy, which is Canada, or from other places that are not as secure, stable or friendly to the interests and values of the United States.”

"Pipeline expansion is an absolutely necessary part of our future infrastructure." –John Hofmeister

Obama did not address or respond to the issue, noted a February 4 Journal Star report from Nebraska, where residents are watching closely since the proposed 1,600 mile pipeline may traverse the state. History will further unfold in 2011 as Nebraskans and the world await the administration’s announcements on the Keystone XL Pipeline expansion.

But until such time that we are able to commercialize our way to clean energy or create fuel out of nothing, the world and the United States will need rising amounts of oil, whether or not we subsidize hydrogen fuel cells, biogas, algae biofuels or any other number of “green” schemes.

Nonetheless, refiners who provide society with usable fuel will refine heavy oil. That holds especially true for operators in the world’s largest refining economy – the United States – next to the world’s largest commercially available heavy oil reserves – Canada.

As Earth Day again approaches in April 2011, perhaps by then the industry will have more clarity on the regulatory announcements to either enable U.S. refiners to access and refine more imported Canadian heavy oil via the Keystone XL pipeline, or drive that strategic resource westward to ready Asian markets while inducing greater U.S. reliance on waterborne imports of fungible heavy oil from farther afield.

Greg Haas can be reached at ghaas@hartenergy.com or +1 (713) 260-5201.