PUMPING The DUMBBELL

The North American energy industry right now has a lot to celebrate about crude oil. U.S. crude production clicked above 7 million barrels (bbl.) as 2013 began, achieving a level last seen in December 1992, according to the Energy Information Administration (EIA).

Expect that number to continue its climb in the foreseeable future, John Auers, senior vice president for Turner, Mason & Co., a consulting engineering firm, tells Midstream Business.

“We see a low forecast of 9 million bbl. per day of domestic production by 2020 and a high of 11 million. That’s not final, but that’s the range where we see production. Whereas a year ago, we were looking at about 9 million bbl. top, but now we’re saying it could range a lot higher than that. And, it might change upward a little bit more.”

Across the border, Canada’s crude output also continues to rise, surpassing 3 million bbl. per day in 2012, says the Canadian Association of Petroleum Producers (CAPP). Auers agrees, projecting Canada’s production will continue to rise in the foreseeable future.

“We’re updating our Canadian forecast now,” he says. “Our 4.5 million bbl. per day at 2020 is sort of a working number. But I’m suspecting it’s going to be a bit higher than that, somewhere between 4.5 million bbl. per day and 5 million.”

“It’s tremendously exciting, and it’s a quite different position than where we [the U.S.] saw ourselves not long ago,” Terry Higgins, executive director of refining and special studies for Hart Energy, tells Midstream Business.

The U.S. trend comes through what is now a well-known story: application of new technology—in particular horizontal drilling and hydraulic fracturing to shale resource plays. Canada has seen some shale-play development, but the bulk of its increase comes from the Athabasca and other oil sands plays in northern Alberta.

Growing supply and sluggish demand has had a predictable impact on prices. One of the world’s major benchmark, or “marker,” crudes—West Texas Intermediate (WTI) traded at the Cushing, Oklahoma, hub—has fallen comparatively in price to other marker crudes, such as North Sea Brent.

Midstream operators have responded with multiple projects to build new infrastructure or retool existing systems to handle a compound annual growth rate in production that approaches 10%. Pipeline construction, with its associated gathering systems and tank farms, continues at a furious pace, and the industry will need a massive amount of capital to complete all that work.

Al Monaco, president and chief executive of Enbridge Energy Partners, recently gave a perspective of how much work there is to be done. “Over the past two years, we have committed $15 billion of new investments that will open new markets and help to address the significant price disparities facing western Canadian and Bakken producers, and to meet the demand of North American refiners,” he said in a statement.

Alongside that work has come new rail infrastructure, a transportation medium that had been virtually forgotten as a large-scale crude hauler since World War II. Railroads now represent a major midstream competitor to pipelines in the Bakken and an important player elsewhere. Unit trains now haul a big chunk of Bakken production to East Coast refineries, which had been dependent on higherpriced Brent, with lesser volumes headed to the West Coast or Gulf Coast refiners.

Pipelines and railroads are not mutually exclusive players. For example, major pipeline operator Kinder Morgan Energy Partners and shortline rail specialist Watco Cos. recently announced their KW Express partnership with Mercuria Energy Trading Co., which plans to build a 210,000 bbl. per day rail and barge loading operation at Greens Port Industrial Park on the Houston Ship Channel. It will be able to handle three unit trains a day that will bring in crudes from Cushing, West Texas, the Bakken and Canada.

Pipeline projections

Global Hunter Securities published a report early this year that projected takeaway capacity in the major shale plays through 2017. For the Bakken, it estimated year-end 2012 takeaway capacity at 1.17 million bbl. per day, including more than 700,000 bbl. per day of rail capacity—or nearly 60% of midstream’s total capacity.

The report projected a 69% increase in Bakken capacity by 2017 to nearly 2 million bbl. per day. Global Hunter found “there seems to be a shortage of pipeline capacity through 2013. However, with all the projects currently in development, 2014 and beyond are looking more than adequately covered with pipeline alone. Given that in 2012 rail has been absolutely vital and has grown tremendously over the past several years, we estimate a large overcapacity of rail transport in the out years of our forecast.”

In the Eagle Ford, the report projected a similar rise in capacity serving South Texas producers, rising from 1.3 million bbl. per day in 2012 by 29% to 1.7 million bbl. per day by 2017. Rail, in contrast to the Bakken, will remain a small but constant Eagle Ford player at around 75,000 bbl. per day, or roughly 4% of capacity this year.

The infrastructure riddle differs in the Permian basin, sprawling across West Texas and New Mexico. The basin’s conventional production dates back 90 years, and a walk across almost any pasture in the area finds pipes, tank batteries and other infrastructure—some in use, some not. Portions of that existing crude-handling capacity can be modified to handle growing unconventional production, but much of it doesn’t fit the needs of growing shale plays.

Global Hunter’s report estimated the Permian’s takeaway capacity at 1.3 million bbl. per day for 2012, rising 62% by 2017 to 2.2 million bbl. per day. Rail, in similar fashion to the Eagle Ford play, should remain a small but stable player. New capacity, however, heads off in new directions.

“The traditional route to market for Permian producers has been Cushing, Oklahoma, for further transport to the Midwest refiners. This is clearly sub-optimal today,” the report added, as the Cushing trading hub now brims with Canadian and Bakken crudes headed south to Gulf Coast refiners.

“It is this dynamic that has driven recent pipeline development directly from the Permian to the Gulf Coast,” it added. Major Permian crude transportation projects include expansion of Sunoco Logistics’ existing West Texas Gulf Pipeline; Sunoco’s Permian Express system, to come on in 2014; and the new BridgeTex Pipeline, a joint venture of Magellan Midstream Partners and Occidental Petroleum. It is scheduled to start up in mid-2014.

Not all of the new midstream pipelines will head to the Gulf Coast. Refiner Holly Energy Partners earlier this year announced plans to expand its common-carrier pipeline system in New Mexico to move Permian crude to its Navajo refinery at Artesia, New Mexico. Holly plans to convert an existing products line to crude service, reverse its flow, then add new pipeline segments and a truck rack. The $35- to $40-million project will have a 100,000-bbl.- per-day capacity and is scheduled to go on stream by early 2014.

Canadian conundrum

Canada has its own midstream scramble under way. Northern Alberta’s sprawling oil sands represent one of the largest single oil reserves in the world but getting production from a remote corner of North America to market will take some work. CAPP forecasts oil sands production to grow from 1.6 million bbl. per day in 2011 to 5 million bbl. per day by 2030. Several projects to expand Alberta’s regional- gathering systems linking producing regions to the Hardisty, Alberta, hub are under way.

There have been proposals to create pipeline links eastward to Canada’s refining and petrochemical centers in Ontario and Quebec, such as Enbridge’s Line 9 reversal that will move crude eastward. The first phase of the 240,000- bbl.-per-day project will be completed the middle of this year with a second phase set for completion in mid-2014.

In the opposite direction, Kinder Morgan has announced plans for a C$5.8 billion project to expand its TransMountain pipeline to 890,000 bbl. per day from 300,000 bbl. per day. The 713-mile line runs from Edmonton, Alberta, to Burnaby, British Columbia, outside Vancouver. Start-up could come in 2017, pending environmental and regulatory approvals.

“Pipeline space is getting tight, and even if all the proposed expansions are built, it will remain tight,” Ian Anderson, president of Kinder Morgan Canada, said at Hart Energy’s DUG Canada conference in Calgary.

Rail has a foothold, mostly to handle shipments of diluent from big condensate plays, such as the Marcellus and Utica, into Alberta. Its role could grow if pipeline projects are delayed or shelved.

The Keystone key

But the fundamental link that can daylight oil sands production is the Keystone XL Pipeline project between Alberta and Gulf Coast refiners. The proposal has been the topic of a bitter political and environmental debate in the U.S.

The $5.3 billion, 1,179-mile, 36-inch project would link the Hardisty hub with Steele City, Nebraska, and existing lines of operator TransCanada Corp. It could enter service in 2015, pending approval by President Obama, who rejected the project in January 2012 based on environmental concerns about its route through Nebraska.

TransCanada relocated its proposed right-of-way and received approval from Nebraska Gov. Dave Heineman early this year.

What many opponents overlook is much of Trans- Canada’s sprawling Keystone system is already in service, Mike Lorusso, group head of CIT Energy, pointed out in a recent investor report.

“The Keystone pipeline serves two purposes,” Lorusso said. “The first is to bring Canadian oil into storage facilities in Cushing, where it will join U.S.-produced oil. The second is to move the oil from there to refineries and terminals in the Gulf Coast. However, what is interesting and overlooked is that two phases of Keystone are already completed and bringing Canadian oil into the U.S., and an existing pipeline (Seaway) between Oklahoma and the Gulf Coast recently reversed its flow to move this oil to the Gulf Coast. So all Keystone XL will do is increase existing capacity to bring oil into the U.S. and transport it to the Gulf.”

There appears to be plenty of additional demand for southbound capacity. Enbridge Inc. and Energy Transfer Partners LP announced plans recently to jointly develop a crude pipeline linking eastern Gulf Coast refineries and the St. James, Louisiana, hub with Patoka, Illinois.

The project calls for conversion of an existing 700- mile, 30-inch natural gas pipeline to crude service. Capacity will be 420,000 bbl. to 660,000 bbl. per day, depending on the type of crudes shipped. The partners plan to have the system in service by 2015. Crude oil can reach the Patoka hub from both western Canada and the Bakken through a variety of existing pipelines, as well as through Enbridge’s Southern Access Extension pipeline, now in development.

Another system rejiggering plan is Shell Pipeline’s Ho- Ho Reversal project to reverse the flow of an existing crude line, turning it eastbound from Houston to Houma, Louisiana. Shell is working in stages along the 300,000-bbl.-per-day system. Ho-Ho will enable shippers to move Eagle Ford and Permian crudes eastward from Houston’s pipeline hub, which has growing southbound flows from Cushing, thanks to the Seaway Crude Pipeline and the prospect of additional volumes as TransCanada’s Gulf Coast leg of Keystone goes on stream.

Seaway start-up

Seaway is a 50/50 joint venture of Enterprise Products Partners LP and Enbridge Inc. The partners purchased the 500-mile, 30-inch pipeline from ConocoPhillips in 2011, reversed its flow and placed it in service between Cushing and Freeport, Texas, in the first half of 2012. They increased capacity to 400,000 bbl. per day early this year. Looping will increase capacity to 850,000 bbl. per day in early 2014.

A question some analysts mull now is whether midstream will overbuild as it answers the capacity question that emerged in the past couple of years.

All of the new infrastructure should begin to bring the price of WTI back to something approaching its normal place in the world crude market by 2015, Francisco Blanch, head of global commodities and derivatives research at Bank of America Merrill Lynch, told attendees at Platts’ North American Crude Marketing conference, held recently in Houston.

He added “shale is transforming the U.S. energy balance” with other world powers, particularly China, which he said is now becoming the world’s leading oil importer as U.S. imports decline.

So what about the customers, the refiners who buy all that oil? They face big problems of their own. Most of that new North American crude is light and sweet (low sulfur) or the opposite, heavy and sour (high sulfur). Lots of crude is headed to refineries, but much of it doesn’t fit well with plants’ processing structure.

The industry’s script for the past 40 years has been North American oil output will slowly dwindle and imports will make up the difference. Concurrent with that trend, the worldwide crude slate will continue to get heavier with higher sulfur content. Those projections led refiners to invest billions in the past 30 years to retool plants to handle heavy/sour crudes—fluid catalytic cracking, coking and hydrodesulfurization units that enable them to convert those oils into high-demand light products, primarily gasoline.

The dumbbell

Hart Energy’s Higgins refers to the new trend with a term that comes up in refiners’ conversations nowadays: “It’s the dumbbell. The available crudes are going to the light end from the shales and the heavy end from Canada.”

The crudes coming to North American refinery gates tend to be one extreme or the other. Tight oil shale plays typically produce very light oils. Bakken crude averages 41º API gravity and 0.2% sulfur while Eagle Ford crude is even lighter, 45º API gravity and 0.6% sulfur. Western Canadian Select, the marker crude for oil sands production, on the other hand, rates 20.3º API gravity with 3.4% sulfur, according to Turner, Mason. Meanwhile, worldwide supplies of conventionally produced, middle-weight crudes continue to decline.

“Everything’s changed,” Turner, Mason’s Auers says. “It’s a new paradigm. Everything everybody thought three years ago has shifted.”

Refiners’ plant modifications to handler heavier and heavier crudes won’t be for naught, he adds. “We’re actually in a situation where we’re going to be long on heavy crude.” What will happen is that Canadian crude is backing out heavy crudes from Mexico and Venezuela. Plants “that can run heavy crude right now, that have cokers in place, are still going to run those cokers. That’s our belief,” Auers says.

No place like home

At the other end of the scale, North American shale oil is backing out light, sweet crudes that have been tankered to Gulf Coast refineries for years, Edward Morse, managing director and global head of commodity research for Citi Group, told the Platts conference.

“The change has been unbelievably rapid,” Morse said. “Already, we see Nigerian crude cargoes with no home.” A recent Bloomberg report said 13% of Nigeria’s projected March cargoes went unsold.

But there will be mixing and matching of refinery crude runs because abundant supplies have created very attractive prices, Larry Schwartz, a Houston-based refining and petrochemicals consultant, tells Midstream Business, adding that question of finding a home for a given crude is important.

“When I say a good home, I mean where people can take advantage of pricing,” Schwartz says. “Because if you’re a refiner, it’s all about price. I’m going to use a number, maybe $15 to $20 below what a refiner is normally paying. Then, that refiner can be persuaded to compromise on runs” and run lighter crudes through refineries geared for heavy oils—if the price is right and the numbers work—even if the refinery operates at less than peak efficiency.

A typical light shale crude “produces a lot of light ends. It produces a lot of gasoline and light naphtha. And some of that light naphtha goes into the jet (fuel) pool,” Schwartz says.

Rail has helped change things, Schwartz adds, since it can put sizeable volumes of a given crude into markets that might not otherwise have it available via pipeline. “What you see is that people are doing crude by rail. They are trying to get crude down to the Gulf Coast because if they can hit the Gulf Coast, specifically if they can get it to St. James, Louisiana, (a crude trading hub) or if they can get to the Houston area, then they are basically looking at a Louisiana Light Sweet crude equivalent [above WTI but below Brent]. So you’ve got all this crude going on rail cars, you’ve got a growth of rail infrastructure up to the Bakken region.”

But adding rail can’t always provide a quick-fix alternative because of incomplete infrastructure. “I think you can do the math and sit down and say, ‘Okay, I can load some unit trains up in North Dakota.’ But how many areas can actually accept those unit trains? My sense is they’re not equivalent just yet, so you get a disconnect here” because unit-train unloading capacity at the destination may not be equal to unit-train loading capacity.

Changing demand

Schwartz mentions an important modifier on his description of light product output—if there is sufficient gasoline demand. Another current trend is that at the very time refiners have more light, sweet crude available, gasoline demand has continued to drop since a 2007 peak. This demand also was negatively impacted by the blending of ethanol in the gasoline pool, further reducing petroleum demand. Meanwhile, demand for the heavier distillates, such as jet and diesel fuel, continues to climb, and that creates more attractive prices for these products.

Refiners have had to tweak their plants and runs accordingly. For example, Valero Energy recently placed a 57,000- bbl.-per-day hydrocracker on stream to make more distillate at its Port Arthur, Texas, refinery and expects to start up a 60,000-bbl.-per-day hydrocracker at its St. Charles, Louisiana, plant during this quarter. Both may be expanded to 75,000 bbl. per day in 2015 if demand warrants.

Richard Grissom, vice president of strategic planning and market analysis at Valero, told the Platts conference distillate’s “demand rise is not only happening in the U.S. but the world. The industry has changed in the U.S.; we need to be an exporter of products.”

Hart Energy’s Higgins agrees, adding “With all this crude available, we need to go to the export market, we can’t handle it all.” He expects North American energy independence by 2020 but adds some crude imports will continue, particularly shipments to East and West Coast refineries that are isolated from the existing pipeline network.

While crude exports may be practical and necessary for the industry, they are virtually outlawed by U.S. regulations. The alternative: Product exports are climbing rapidly. EIA statistics show the U.S. became a net product refined product exporter in mid 2011, and the volume of refined product shipments continues to grow rapidly. As March began, EIA said product exports totaled 1.5 million bbl. per day with distillates making up the largest portion of shipments.