U.S. oil fields create big business for railroads, specialized truckers and project 3PLs.
By Eric Kulisch
The giant oil-shale and gas field in North Dakota and Montana is proving to be a bonanza for energy companies and the U.S. economy in terms of lower fuel costs for users, but it’s also creating sizable opportunities for project logistics and transportation companies to move drilling equipment and supplies inbound, and oil to refineries.
A big reason for the rapid acceleration in demand for bulk transport is that development has outpaced installation of pipelines to deliver recovered fuel.
There are 3 to 4.3 billion barrels of oil, 1.85 trillion cubic feet of natural gas and 148 million gallons of natural gas liquids recoverable from the Bakken Formation that runs from southern Canada through the upper Plains states, according to a 2008 estimate by the U.S. Geological Survey. Oil extraction currently is the primary activity there. The USGS is gathering new scientific information and plans to issue an update of its 2008 estimate in the fourth quarter of next year.
About 86 million barrels of oil were pumped out of North Dakota alone in 2010, with production there topping about 670,000 barrels per day last July. The North Dakota Department of Mineral Resources says the Bakken and adjacent Three Forks formations contain 7 billion barrels of proven reserves. It estimates the reserves probably have 10 billion barrels and that up to 14 billion barrels possibly exist there.
Extracting oil and gas in this region is made possible by new technology and drilling techniques, as well as high crude oil prices that make it economically viable to undertake more difficult production projects. The fossil fuels are embedded within shale rock formations at depths where there is not enough pressure to flow to a well. They are released through a process known as hydraulic fracturing, or “fracking,” under which water, sand and special chemicals are injected under high pressure into the rock to create fissures and prop them open so oil and gas can escape to the wellbore. Horizontal drilling enables energy companies to access the oil and gas at greater depths and distances.
There are hundreds of active oil wells in the Bakken region.
The Bakken shale is not the only area of the country where shale oil and gas production has taken off. Development is also robust in the Marcellus Shale of Pennsylvania and at the Barnett and Eagle Ford shale sites in Texas. A promising oil field is still being explored in New York. The new domestic supply is helping keep a lid on global oil and gas prices, reducing U.S. dependence on vulnerable foreign imports and making U.S. manufacturers more competitive by lowering the price of petroleum-based chemical feedstocks for their products.
The International Energy Agency recently projected that the United States will surpass Saudi Arabia as the world’s largest oil producer by the end of the decade.
Delivering drilling pipe, pumping units, chemicals, water, sand, clays, rigs, cranes and crane pads, and a host of other construction materials using multiple modes is a complex process that requires project logistics companies to have a significant amount of engineering skill. It takes, for example, about 200 tanker trucks to deliver water to each well for the fracturing process.
Each well requires the equivalent of 47 railcars of materials, including water, which translates into 1,200 truckloads from the railhead to the final destination. And 500 trucks are needed to haul away wastewater. A year ago, each well required 30 railcars. The increase is because energy companies have learned how to drill further than in the past and demonstrates how rapidly logistics needs are changing in this sector, Graham Brisben, chief executive officer of Professional Logistics Group (PLG), a boutique consulting firm specializing in logistics strategy, said during an October conference call with clients of financial services firm Stifel Nicolaus.
Freight companies are also hauling in lumber and other materials to build houses, schools, stores, and hospitals as towns in North Dakota and Montana swell with people arriving to work in the oil fields.
In an interview, Brisben said the biggest areas of opportunity for 3PLs involve managing long-haul flatbed loads and imported ceramic material for propping open fissures. The engineered ceramic “proppants” are typically shipped from Asia in one-metric ton bulk bags that are palletized, loaded on containers and either shipped by intermodal rail to the shale development site or transloaded into boxcars and then shipped.
“We now estimate that imported ceramic proppants are 15 percent of the market,” he said.
Trucking giant J.B. Hunt is seeing more need for specialized fleets to support the Williston Basin exploration and is responding through its dedicated contract carriage segment, CEO John Roberts said Oct. 1 during a panel discussion at the Council of Supply Chain Management Professionals’ annual conference in Atlanta.
Tom Sanderson, CEO of non-asset-based logistics provider Transplace, said his company is doing some consulting to help customers design their supply chains to serve the Bakken oil and gas belt. C.H. Robinson, a $10 billion 3PL and the largest truck broker in the United States, sees the Bakken as a potential area of opportunity in which to expand services with existing customers, officials said during a separate interview there.
By some accounts, the “black gold” rush to the upper plains could limit truckload capacity in other parts of the country as truck drivers migrate to the region for better pay, but analysts say the ripple effect will be minimal.
The availability of trucks and drivers is roughly at equilibrium around the nation, with a few exceptions, but if the economy begins to grow logistics experts warn there quickly could be a shortage of manpower and equipment to move goods on time.
Some commercial drivers are leaving their regular jobs for the oil and gas industry because they can make much more money, Matt Ehrlinger, director of corporate transportation for NCH Corp. and the new chairman of the National Industrial Transportation League, told reporters in conjunction with the association’s annual meeting in Anaheim, Calif., Nov. 12-13.
“We’ve seen a little bit of exodus,” Ehrlinger said of seasoned drivers in his company’s private fleet.
Noël Perry, an economist who studies freight transport and logistics markets as a partner at FTR Associates and through his own Transport Fundamentals, downplayed the overall impact of shale oil development in the Bakken Field on truckload and tank truck capacity.
During the past five years about 100,000 truck drivers have relocated to areas with new oil/gas production, about 20,000 of them to the Williston Basin. The amount of drivers that shifted from other regions to the upper plains represents less than 1 percent of the available pool of 2.1 million drivers, or less than 0.2 percent per year, Perry said in an interview. Tank-truck carriers that haul liquid bulk commodities are most likely to be effected by driver defections, but many of the drivers making the switch are probably nomadic, long-haul drivers without stable, short-distance routes back home, he said.
And those types of individuals, according to Brisben, may have difficulty securing jobs. Carriers have to be more selective when hiring tank-truck drivers, who are required by law to have a tank-truck endorsement on their commercial driver’s license and a hazardous materials endorsement if they haul hazmat loads.
Any relocation of drivers in a tight labor market will have some effect, but it will be hardly noticed compared to tighter safety regulations scheduled to kick in 2013 that are expected to weed out a significant number of drivers, Perry explained.
The migration of drivers to energy fields could slightly exacerbate the macro driver shortage, Brisben agreed, but the lack of qualified drivers will mostly be felt by the regional and local truckers that are most attracted to the new energy business, Brisben told American Shipper.
Labor supply is a problem for these trucking companies, “because the same kind of individuals needed for a trucking job are the same kind you need for roughneck work in the oil fields” and states like North Dakota have very low unemployment rates, he said.
3PL Play. One of the earliest third-party logistics providers to aggressively offer supply chain services for the oil and gas industry in the Williston Basin region of North Dakota and Montana was BNSF Logistics, the non-asset-based sister company of BNSF Railway.
BNSF Logistics opened an operations center in Williston, N.D., in October 2011 that specializes in coordinating rig moves and urgent deliveries of supplies by any mode, including truckload, flatbed, less-than-truckload, and air. It also transports drill cuttings, sand and ceramic sand for fracking, pipe casing and flexitanks.
The company, with headquarters in Grapevine, Texas, and Springdale, Ark., manages about 10 to 15 oil rig moves per month using specialized flatbed trucks for companies, such as Continental Resources and Brigham Oil & Gas LP, according to a recent case study on BNSF Logistics published by consulting firm Armstrong & Associates. Moving a rig from one location to another takes about 30 days and each rig requires 20 to 30 truckloads of components and materials. Larger components have to be unloaded by crane.
Much of the sand is being shipped from mines in Illinois and Wisconsin and BNSF Logistics imports some ceramic sand in containers from China and Brazil. Sand shipments typically involve transloading the sand from hopper cars at rail yards to dump trucks that deliver to the drilling sites. BNSF Railway, for example, delivered more than 25,000 railcars of fracking sand to oil and gas producers in the Bakken region and BNSF Logistics transloaded 528 rail hopper cars in 2011.
There are 85 mines operating or under construction in Wisconsin, with 20 more proposed, to meet demand for white fracking sand. The mining boom has led to a buildup of railroad infrastructure as well as a large increase of trucks carrying sand from non-rail served quarries to transload facilities. In western Illinois, overuse of roads has led some communities to impose road-use fees on trucks and a temporary moratorium on sand deliveries in an effort to deal with truck traffic, noise and silica dust, Brisben, the PLG consultant, said.
In August, the Canadian National Railway said it reached a multi-year agreement with Superior Silica Sands to move fracking sand from a new processing center at its quarry in northern Wisconsin to shale production sites in the United States and western Canada.
The company in December was scheduled to complete an 85-acre sand processing plant and rail storage facility along CN’s Barron spoke near Poskin, Wis., capable of producing up to 2.4 million tons per year of high-quality sand. CN last year began a $35 million upgrade of almost 40 miles of track between the main line in Ladysmith and Barron to enable it to restore service to Barron. Other plants are expected to eventually open along the connector line.
CN said its fracking sand volume has grown almost 70 percent during the past three years to 35,000 carloads and $100 million worth of business in 2011. The railroad has set a goal of reaching C$300 million in fracking sand revenue within three to five years. CN’s revenues totaled C$9 billion ($8.8 billion) last year.
Since the third quarter of 2011, rail rates for hopper cars of sand have risen 10 to 14 percent for shippers with individual loads that are part of a larger manifest, according to Brisben’s presentation. The cost of transportation as a percentage of product price is much higher for fracking sand (58 percent) than it is for ethanol (8 percent) and wind turbines (12 percent). Fracking sand prices currently are on the downswing as more sand is mined while rail rates are increasing.
During the early rush to develop the Bakken oil field, the logistics market was chaotic, with exploration companies, energy services providers and sand producers all leasing railcars and taking responsibility for sand delivery. The operational inefficiency and duplication of effort has recently led some sand producers such as U.S. Silica to increase the amount of freight they control by acting as distribution middlemen, essentially setting up retail outlets in the shale development areas, aggregating volume to negotiate better unit-train rates with railroads, and arranging rail-transload deliveries to a single location rather than to each energy company site, Brisben said.
Those that are prepared to utilize unit trains and make volume commitments are able to secure less expensive long-term contracts, while differentiating themselves from competitors.
“The frac sand producer that can push transportation costs down the most, through effective logistics management, will be best situated in this market,” he said, noting that this is one of PLG’s strengths.
Getting Oil To Market. Railroads are getting a lot of business for their tank-car divisions hauling crude oil from the northern plains to refineries because producers have not had time to build much pipeline infrastructure there following the development rush.
Oil is delivered to loading terminals by truck or a local network of gathering pipelines leading from the wells.
Nonetheless, oil loadings are relatively small compared to other commodities and will not make up for the recent decline in coal volume from utilities switching to cheaper, cleaner natural gas, Brisben cautioned.
“The sheer number of carloads in the rail industry for coal is so much larger than sand and crude. The increase in sand and oil carloads is merely a blip on the map from a pure carload count perspective. The combined sand and crude carloads are unlikely to equate to even 25 percent of the coal carloads. Despite the decrease in coal carloads, railroad companies have maintained very good pricing discipline and pricing power. Consequently, their ability to weather the decline in coal carloading has come mainly from an ability to price other commodities more aggressively,” he said.
But oil, combined with volume growth in automotive and intermodal, strong pricing and cost management can help the rail industry make up for some of the lost coal business, Stifel analysts John Larkin and Michael Baudendistel said in a client note.
BNSF has a much larger network footprint in the Bakken Shale than any other rail company, maps of the four major U.S. and Canadian carriers with western operations confirm.
BNSF Railway announced in September that it now has enough capacity to haul 1 million barrels of oil per day from the Williston Basin. The company has 1,000 miles of rail line in the region and now serves 10 originating terminals. Its trains run to 40 tank farms or refineries in 14 states and can reach the remaining 70 percent of the market through interline agreements. In the past five years, BNSF’s annual volume has increased from 1.3 to 90 million barrels. The railroad said it transports 25 percent of the oil extracted from the Bakken Shale.
Brisben said BNSF has an 80 percent share of the oil rail market. He predicted the Canadian Pacific Railway, which has three terminals in North Dakota, will price its oil business aggressively to attract customers because it doesn’t have the reach into prime areas of the Williston Basin.
BNSF invested $197 million in 2012 on projects in North Dakota and Montana, including track surfacing, construction of two inspection tracks, raising a section of track, replacing 121 miles of rail and 332,000 rail ties, as well as signal upgrades and purchases of new equipment. It also hired more than 560 new employees to fill existing and newly created positions in the Williston Basin and set up a dedicated Unit Energy Desk that works as a single point of contact with customers to coordinate and plan unit train movements to and from the region.
The Fort Worth, Texas-based company has also increased capacity on oil routes from 100 to 104 tank cars per train, and in some cases up to 118 tank cars, plus added signals and sidings along key routes, according to a news release.
Newer loading facilities have large loop tracks and some double-loop ones can handle two more unit trains. In those locations, railroads aim to load the oil within 24 hours and have another train ready to load when the previous train leaves, but few facilities in North Dakota are operating at anything close to their stated capacity, according to a blog by Rusty Braziel, a 30-year energy trader, planner analyst and software developer who runs a social networking site for energy industry professionals called RBN Energy.
The Union Pacific moved 25,000 carloads of crude oil from the Bakken and Eagle Ford shale formations to St. James, La., in 2011, up 37 percent from commencement of operations in 2010, and the oil business was expected to increase more than 400 percent in 2012, according to the railroad’s 2011 annual 10-K filing and fact book.
UP serves two captive oil terminals in St. James, which has strong pipeline connections to refineries in the Gulf. The addition of these relatively new high-capacity facilities along with their connectivity are a major reason UP has experienced an increase in bulk oil shipments, Brisben said.
Norfolk Southern has benefitted from the Marcellus Shale development in Pennsylvania, while eastern rival CSX Transportation has routes that mostly lie outside the main drilling areas, Brisben said.
In addition to St. James, common destinations for loaded unit trains include a terminal in Stroud, Okla., (located a short distance from the oil trading hub in Cushing where massive tank farms exist) and one operated by fuel wholesaler Global Partners in Albany, N.Y. In Albany, the crude is pumped into storage tanks and then loaded on barges to move down the Hudson River for delivery to Northeast refineries. Other individual tank cars make it to East and West coast refineries as part of less-than-trainload batches that are sorted with cars of autos, containers and other types of cargo and switched to various destinations along the way, industry experts say.
BNSF has responded to the near-capacity situation in Cushing by serving a new rail-to-barge transload facility owned by Marquis Energy in Hayti, Mo., to compete with the UP in St. James, Brisben said. The new facility is able to transload unit train quantities, store several hundred thousand barrels of oil, and then distribute by barge to Gulf Coast refineries.
UP is able to attract significant oil volumes even though it doesn’t have any loading facilities in the Bakken, because it has the largest rail receiving terminal in the Gulf. It interchanges to its network in Kansas City and elsewhere oil that originates on the BNSF and CP.
In early 2012, U.S. Energy Development Corp. said it was doubling the size of its St. James facility to handle two-unit trains with 130,000 barrels of oil a day. The facility has a fully automated 52-spot high-speed railcar offloading rack. Global recently expanded its terminal to be able to receive two 120-unit trains each day, Braziel reported.
It makes sense for East and West coast refineries to buy crude from the Bakken because it is about the same price as West Texas Intermediate (after trading at a discount until the new rail infrastructure reduced logistics constraints) and cheaper than imported crude. The difference between Bakken and imported Brent crude is about $20 per barrel, but the spread constantly changes.
Transporting oil to the Gulf Coast, for example, costs about $10 to $15 per barrel, according to PLG’s analysis.
“It’s a definite advantage to buy mid-continent crude and refine it on the coasts,” Brisben said in the interview.
Many East and West coast refineries that traditionally have received crude from ocean tankers for the first time are making capital investments in unit-train receiving infrastructure, he added.
Tesoro Corp., an independent refiner and marketer of petroleum products, is building a $50 million rail offloading station adjacent to its refinery in Anacortes, Wash., with four tracks and capacity for 50,000 barrels per day. The energy company said in a news release that the Bakken crude deliveries will decrease its dependence on foreign oil and declining production from Alaska’s North Slope field.
In late November, Canadian energy distribution company Enbridge Inc. announced that its U.S. subsidiary, Enbridge Rail, and a joint venture partner would create the Eddystone Rail Co. to develop a $68 million unit-train facility and related local pipeline infrastructure near Philadelphia for delivering Bakken and other light sweet crude oil to area refineries. The project is expected to handle 80,000 barrels per day in the third quarter of 2013 and capacity could be doubled as early as mid-2014. The joint venture will lease land from a power generation plant and reconfigure existing track to bring in 120-car trains, install crude offloading equipment, refurbish an existing 200,000 barrel tank and upgrade an existing barge-loading facility.
A Sunoco refinery in Philadelphia is converting its infrastructure to receive oil trains from the Bakken and Marcellus shale regions.
And Norway’s Statoil said in September it would use rail, not pipelines, to deliver oil from its new operations in North Dakota.
“So the economics of rail are going to get even more attractive because taking unit trains directly instead of single car shipments gains you a 10 to 20 percent price reduction with the railroads” and avoids transloading to barges, Brisben said.
He estimated that 40 percent of the Bakken output is moved by rail today following the infrastructure development of the past year. The rail market share will stay steady, Brisben predicted, but won’t go up much further because of competition from future pipelines. Railroads will experience downward pressure on rates as additional pipeline capacity comes on line during the next three years and the gap narrows between Brent and West Texas Intermediate crude.
The pipeline capacity coming on line, he noted, is mostly north-south, so the volume and margin losses for the rail industry will mostly be to the Gulf Coast and the trading hub in Cushing. Rail pricing should stay firm to both coasts because there is no major pipeline infrastructure planned to get there from the Bakken.
It costs more to ship by rail than pipeline, but BNSF and energy industry experts say the flexibility of rail service gives energy customers access to new markets because they can follow spot market trends and ship all over the country to locations where oil commands a higher price rather than being captive to a single pipeline tariff. Another advantage of rail, Brisben said, is speed to market. Rail transit takes five to seven days versus 30 days for pipeline.
“Rail is the fastest way to provide increased export capacity out of the Bakken, creating a near-term solution to transportation bottlenecks and the resulting crude oil pricing differentials,” Stephen Wuori, president of liquids pipelines for Enberidge, said in a statement. “Eddystone is an important step in our longer-term strategy to accommodate the anticipated growth of light crude oil supply and to provide Bakken producers and refiners cost-effective capacity to premium markets on the eastern side of North America.”
Perry speculated that oil volume for railroads will eventually recede beyond five years as more pipelines get built, but BNSF spokeswoman Krista York-Woolley said the railroad views the oil business as a long-term play. Customers such as EOG Resources and Hess Corp. have spent almost $1 billion to build the 10 crude-loading facilities served by BNSF and wouldn’t be spending that kind of money for only a short-term fix, she said.
Permitting and construction for new pipeline takes a long time, as demonstrated by the controversial proposal for the Keystone Pipeline, and installing rail infrastructure is cheaper and faster.
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“The oil is being developed and it needs to get to market right now and not wait for two to four years for more pipeline capacity to come online,” Brisben said.
“There are a lot of places where we’re shipping crude where pipeline doesn’t go. So there will always be a need for both,” York-Woolley added.
On Nov. 27, natural gas company Oneok Partners of Tulsa, Okla., announced it has dropped plans for a 1,300-mile crude oil-pipeline with capacity to transport 200,000 barrels per day from the Bakken region to the crude oil market in Cushing by mid-2015 because there were not enough long-term commitments from producers.
The rail-to-barge terminal in Hayti and couple of other facilities planned for the Illinois River will open the door for more oil transport on inland waterways, Brisben said.
The most significant short-term barrier for energy companies seeking to grow in, or enter, the oil/shale market is the tight supply of rail tank cars, Brisben said. The current backlog of orders for tank cars runs into the second quarter of 2014 and has sent lease rates soaring.
But with increased use of unit trains, and refineries building new track and unloading capacity, turn times will be faster and railroads will gain more use from the existing fleet, he said.
What’s the next opportunity for railroads? Transporting natural gas liquids as refiners gear up to process and store this natural gas byproduct.
Shortline railroad operator Genesee & Wyoming announced Dec. 3 that its subsidiary, The Columbus & Ohio River Rail Road Co., has signed a long-term agreement to serve the $900 million natural gas liquids fractionation plant being constructed in Scio, Ohio, by Utica East Ohio Midstream.
The processing and storage facility is located in eastern Ohio, near the Utica Shale development. The Columbus & Ohio will construct a one-mile rail siding and rehabilitate a three-mile storage track to serve the facility, which when fully operational is expected to ship 10,000 carloads of natural gas liquids per year.
The plant is scheduled to open in May.
Other project sites related to Utica Shale-development are located on or plan to locate on the railroad, Genesee & Wyoming said.
The Columbus & Ohio recently completed a $2 million expansion of its main yard in Newark, funded in part by the state of Ohio. The yard can sort 100,000 railcars per year.
G&W’s Ohio, Pennsylvania and New York railroads directly overlay the core development areas of the Utica and western Macellus Shale formations.