The Bakken by now has become well known as a major crude oil play. The unconventional shale formation—located in the Williston basin at the center of North America beneath North Dakota, Montana, Saskatchewan and a sliver of Manitoba— has achieved a well-earned place on the shortlist of major shale plays.

The big action’s in North Dakota, which passed such crudeproducing mainstays as Alaska last year to become the thirdlargest oil producer in the U.S., behind Texas and California. The Bakken now accounts for 90% of North Dakota’s crude output, according to the Energy Information Administration (EIA). The EIA pegged the state’s crude production at nearly 750,000 barrels (bbl.) per day in late 2012—more than a 50% increase from the year-earlier month, and climbing.

Overall U.S. oil production continued its recent climb last year, and the Federal Reserve Bank of Minneapolis points out some 40% of the 2012 increase in domestic oil production came from Bakken wells.

Montana—where the first Bakken horizontal well went down in 2000—to the west and Canada to the north also have seen upticks in activity. Montana’s October 2012 oil production was nearly 10% above the 2011 month but still below records set in 2006-2008 when historically high crude prices stimulated drilling targeted at conventional plays. Some 25 rigs were drilling in the Big Sky state that month, compared with eight in October 2011. Further production increases appear likely.

Put it all together, and the Bakken appears to be climbing toward the million-barrel-per-day mark—a number reached by just a handful of oil fields in history. A Wells Fargo Securities report released in late 2012 projected 1.3 million bbl. per day by 2017, compared to around 400,000 bbl. per day in 2011.

That’s a lot of oil coming out of a region with a small population and light industrial base. There isn’t a lot of local demand for crude, natural gas or natural gas liquids (NGLs). North Dakota has one refinery at Mandan, operated by Tesoro Corp. The refiner and marketer expanded its Mandan plant last year to 68,000 bbl. per day, supplied by its Tesoro High Plains Pipeline linking the plant to North Dakota producers.

Bakken defined

Most shale plays in North America are gas prone but the Bakken has proved an oily version of the unconventional plays that currently create major changes in the energy industry, although Bakken wells do produce a fair amount of associated gas and NGLs, which creates other challenges.

The play also challenges producers with some comparatively complex geology. Generic references to “the Bakken” typically refer to the stacked, multi-play Bakken formation, which has upper, middle and lower producing zones and the geologically similar Three Forks formation farther down. Late Devonian to early Mississippian in geologic age, the source rocks are tight, low-porosity shales and dolomites that resisted conventional drilling and completion techniques. Prior to horizontal drilling and hydraulic fracturing, Bakken wells proved so-so for producers.

But technological advancement turned this sow’s ear into a silk purse. Bakken wells typically produce a light, sweet crude very similar to the West Texas Intermediate that serves as a refining- industry standard—and highly desired by refiners.

Perhaps the abundant Bakken represents too much of a good thing, says Bernard Colson, director of energy infrastructure equity research for Global Hunter Securities. Focused on covering the midstream, Colson tells Midstream Business that pipeline capacity in the Williston basin is now at a premium, and when there is space available the existing pipelines can only take the crude where producers don’t want to go. The pipeline network routes most of that crude into other bottlenecks with their own current challenges: the hubs at Cushing, Oklahoma, and Clearbrook, Minnesota.

“We’ve had a big shortage of pipeline transportation capacity there,” Colson says. “Think of the U.S. as a funnel with Cushing as kind of the neck of the funnel.” The growing Bakken crude output competes at those hubs with growing production from other North American shale plays and Canada’s oil sands.

Shades of OPEC

Tad True, vice president of Bridger Pipeline LLC, put the pipeline problem Colson describes in perspective at the recent Hart Energy Rockies Midstream Conference in Denver, when he pointed out “there’s a 900,000 bbl.-a-day difference between total takeaway capacity and total peak production” in the Bakken, adding “some Organization of Petroleum Exporting Countries (OPEC) don’t produce that much.”

Given that production greatly exceeds pipeline capacity, Bakken producers have turned to a midstream medium that has seen only a minor, niche-player role since before World War II: railroads. That has created a spike in railrelated traffic and infrastructure additions in the region. Lengthy unit trains of 100-plus tanks cars have become a regular sight in the region.

Rail has an outsized—and growing—importance in the play, Justin Kringstad, director of the North Dakota Pipeline Authority, tells Midstream Business. He estimates 52% of the state’s Bakken crude production now goes to market via train. Industry estimates peg rail a year earlier at less than 20% of Bakken shipments.

Certainly the biggest beneficiary of that swelling rail traffic has been BNSF Railway Co. The Fort Worth-based firm shipped its first unit train of crude-carrying tank cars in 2009, John Miller, vice president of industrial product sales, tells Midstream Business. By late 2012, BNSF had increased its crude-handling capacity to 1 million bbl. per day of crude oil and NGLs out of North Dakota and Montana. Unit trains of as many as 118 cars are now the rule on BNSF rails headed in every direction, Miller adds.

For the record, the typical railroad tank car holds around 650 to 700 bbl. of crude so the average unit train hauls somewhere around 65,000 to 75,000 bbl. of oil.

The Bakken will receive a “significant” share of BNSF’s capital budget this year as “we’re looking to invest and reinvest, because this is a growing area for us, and our customers are spending significantly to upgrade loading capacity in the Bakken,” Miller says. The Williston basin’s midstream situation “leads to the great advantages of rail,” noting they include the flexibility to offer multiple destinations, the ability to respond quickly and rail’s capacity to develop loading terminals much faster than pipelines can, Miller adds.

Salt Lake City-based Savage Cos. opened its Trenton, North Dakota, rail terminal last year, located in the heart of the Bakken’s most productive area near the North Dakota/Montana border. The terminal has 300,000 bbl. of storage capacity, five truck bays and a double-loop track that can handle trains of 118 cars. Savage has been heavily involved in oilfield trucking and materials handling so the new rail terminal was a natural—and large—addition to existing operations there, Nathan Savage, senior vice president and group leader for the oil and gas solutions group, tells Midstream Business. The Bakken’s a big play, he adds, so players there must be big. “It seems kind of like the nature of this business: Go big or go home,” Savage says. “And so we started with a relatively large facility. But if the market dictates that we expand that facility, we certainly will. We stick very close with our customers because this is largely a customerdriven business; by what they see as their requirements, and what we need to do to meet those requirements.”

Why rail?

Why the emergence of a midstream transportation medium that has been lightly used to move crude in the modern era? Global Hunter’s Colson credits two things. First, Bakken production grew so fast producers had to resort to rail just to move the production.

“Obviously, rail has a shorter lead time, it’s less capital intensive, and it gives you more flexibility,” he says. “So while it is more expensive on a per-barrel basis, you have a lot more flexibility.”

Second, credit the current price differential refiners must pay between Cushing and other inland hubs versus coastal ports that price according North Sea Brent and other crudes. A basic rule of economics has emerged at inland hubs: Abundant supply and limited customers result in lower prices.

“There are just enormous opportunities for producing companies right now. It doesn’t matter if you pay the $10 or $15 it takes to rail the crude to market, it’s worth it,” Colson says. The differential between West Texas Intermediate at Cushing and Brent on the East Coast, for example, has hovered around $20 bbl. in recent months, so producers come out ahead despite the higher rail tariff—and refiners come out ahead with lower feedstock prices.

To keep this unusual situation in perspective, True reminded the Rockies Midstream conference “it wasn’t that long ago when the absolute price of crude oil was between $22 and $26, and now we’re looking at differentials of about the same amount.”

BNSF’s Miller also mentions pipeline customers must lock themselves into years-long contracts that limit the ability to respond if and when prices change. Rail customers, however, can take advantage of changing market dynamics by shifting destinations, capturing the best rate of return and ultimately maximizing profits.

He cites the railroad’s handling of East Coast shipments when Hurricane Sandy came ashore in October 2012. BNSF and other railroads re-routed eastbound unit trains on the fly to other customers temporarily. The oil kept moving, the important thing for Bakken producers he points out.

“It’s easier and faster to get rail facilities built and rail offers more flexibility once facilities are built,” Miller adds. “I think that’s why you see more customers who thought of rail as temporary are becoming more convinced that rail is a permanent solution.”

Savage describes how his diversified firm gains a firsthand view of the other end of the supply chain that begins in the Bakken. It operates the new rail unloading terminal for Tesoro Logistics LP that serves Tesoro’s 120,000 bbl. per-day refinery in Anacortes, Washington, north of Seattle. The terminal, which opened in late 2012, isn’t in the Bakken but is there because of the Bakken, he points out. It gives the company a unique perspective on both ends of the business.

Tesoro’s numbers

The numbers Tesoro has provided in recent investor presentations gives one example of the economics behind what makes rail work as a midstream alternative. For the Anacortes plant, the firm estimated a $22.60 per bbl. savings compared to Alaska North Slope (ANS), which has been the refinery’s chief feedstock in recent years. Take out an average of $9.75 per bbl. in rail costs.

The difference in those numbers creates some compelling numbers for the refiner. Tesoro estimates Anacortes’ runs to still this year will be 40%-50% Bakken and 10%-20% ANS, with the balance in feedstock coming from Canadian and foreign producers. In 2011, Anacortes ran 57% ANS, plus Canadian and foreign and zero Bakken. The company projects its $60 million capital investment to handle Bakken unit trains and their crude will create annual EBITDA of $160- to 180-million with a 220% internal rate of return.

But the Williston basin’s pipeline operators are moving ahead with expansion plans to handle the rising crude volumes. Enbridge Inc. has been a major player in the region for years and has construction under way on a Bakken-area expansion. The firm has a 240-mile crude oil pipeline gathering system in North Dakota, connected to its interstate transmission pipeline system, which delivers most of the oil to the Clearbrook hub and customers in the Midwest.

The two-phase work includes the Beaver Lodge project, looping a portion of Enbridge’s existing North Dakota system—plus a new line, pumping and line replacements in the Bakken Pipeline project. Construction schedules call for completion of the Bakken work early this year, which will add 120,000 bbl. per day of new takeaway capacity. Future work could raise capacity to 325,000 bbl. per day.

Changing direction

But the current glut at existing hubs has caused producers and pipelines to move cautiously on conventional, hub-directed projects.

ONEOK Partners LP failed to receive sufficient interest in its proposed, 200,000 bbl. per-day Bakken Crude Express project during an open season in late 2012. Perhaps the concept of yet-another link to Cushing and its sluggish crude prices gave Bakken producers pause. ONEOK announced the project’s cancellation late in the year, although some industry observers speculate it may be reborn later, perhaps with capacity or destination changes.

Bakken Crude Express had a price tag of more than $4 billion and would have linked Williston basin producers with the Cushing hub. Separately, Cushing has some good news about its own bottleneck. It gains additional takeaway capacity to Gulf Coast customers this year with the reversal of the Seaway Pipeline and completion of the Gulf Coast project by TransCanada Pipelines Ltd.—the southern leg of the contested Keystone XL Pipeline. Those two projects are expected to ease the Cushing backlog. Keystone XL could serve Bakken producers more directly if it eventually enters service from Alberta to Texas after overcoming substantial environmental and regulatory challenges.

To the east, Enbridge has refused a connection at the Clearbrook hub with the proposed 450-mile, 16-inch High Prairie Pipeline project. High Prairie Pipeline LLC has proposed a 120,000 bbl. per day link between Alexander, North Dakota, and the Minnesota hub. But Enterprise replied there is no available capacity at Clearbook to handle the additional crude. That triggered regulatory proceedings with the Federal Energy Regulatory Commission last year.

Creating some balance

So has that midstream infrastructure investment broken the bottleneck? Things may be getting better.

“I do think it’s easing,” replies Savage. “There are a number of facilities that have come online. In fact, some projections would indicate that there’s going to be an overcapacity of rail as we move forward. When you combine that with the pipe that is already in place, and some of the pipe that has been announced, clearly I think if you look at, say, the Lower 48, there’s certainly a lot of pipeline capacity going south to the Gulf Coast.

“But if you look at the East Coast and West Coast destinations, and you look at rail facilities that are being built to handle that, our sense is there’s going to be some balance. It isn’t all rail. It isn’t all pipe. Certainly rail is new, when you consider how little—what a small percentage— of crude in this country even moved by rail a handful of years ago,” he adds.

Pipelines and rail are not mutually exclusive as a means to the midstream end. For example, Enbridge has a major interest in the Berthold Station rail terminal expansion, located just west of Berthold, North Dakota. Phase one, with a capacity of 10,000 bbl. per day, entered service in late 2012. Phase two, adding another 80,000 bbl. per day, is scheduled to enter service early this year.

The NGL challenge

While most midstream operators focus on moving the Bakken’s abundant crude production, the play also has a sizeable output of associated gas and NGLs—although those products represent only around 3% of a typical well’s revenues, by some estimates. The play’s similar to other unconventional shale plays in that it produces wet gas with an abundant NGL cut, including a higher-thanusual ethane component. The Wells Fargo report estimated current Bakken NGL production at 250,000 bbl. per day, increasing to 310,000 bbl. per day in 2017.

Bakken gas and NGL volumes—as with its crude— must shoehorn into markets already filled with production from elsewhere, in this case primarily Canadian output from Alberta and British Columbia that moves to the Midwest through Northern Border Pipeline Co. and the Alliance Pipeline LP system. The 2,300-mile Alliance system is unusual because it can move 1.6 billion cubic feet per day of dense-phase gas that includes NGLs, headed for the Aux Sable processing plant southwest of Chicago. The partnership’s proposing new services and tolls that would take effect in late 2015 when existing contracts expire, which could re-arrange gas and NGL service in the region. It plans an open season early this year to solicit capacity bids from producers.

Gas and NGL production require separate midstream investments in new infrastructure dedicated to processing, fractionation and transportation.

“While the overall magnitude of gas production in the Bakken shale is likely to be relatively small compared to projected growth in oil production, the resulting growth in NGL supply is fairly substantial,” the investment firm said.

One variable in gas and NGL production estimates is producers can legally flare light-hydrocarbon production in North Dakota in certain situations—and many do. Wells Fargo estimated as much as 34% of the gas produced in the state in the latter half of 2012 went to flare stacks.

But that may have to change. Political and environmental pressures should increase as overall production grows. That will cause producers to seek end markets for their gas and NGL production.

“Processing capacity does not appear to be the limiting factor for natural gas sales in the region; rather, the constraint appears to be on the gathering side. Unlike crude oil, which can be gathered from the wellhead via trucks, natural gas must be produced into gathering lines,” Wells Fargo said. “Similarly, for midstream companies, gathering economics are currently not that compelling on a stand-alone basis as the absolute volume of gas produced in the play is still relatively small.”

Despite these disadvantages, the midstream seems well prepared to handle an increase in ethane volumes during the next five years based on both announced and indevelopment projects, but propane might be more of a challenge, it said.

Currently, Bakken-produced propane goes by rail to the Bumstead, Arizona, hub near Phoenix and rail capacity will continue to play a major role in keeping the market balanced.

According to the report, midstream NGL capacity will be adequate for the next three years, though it will be very tight until ONEOK places an expansion of its Bakken NGL Pipeline in service in mid-2014. In that case, if 100% of the gas produced in the play were processed and not flared, then as much as 30,000 bbl. per day of takeaway capacity would be needed to keep the propane market in balance.

By 2016, Wells Fargo anticipates propane could again become bottlenecked out of the play. This would require an additional 10,000 bbl. per day of capacity to be added, which implies construction of an additional 80,000 bbl. per day of Y-grade (mixed NGLs) takeaway capacity or 200 million cubic feet (MMcf) per day of wet gas takeaway. rocess Bakken ethane until prices improve. A combination of rising gas prices, comparatively high pipeline tariffs and depressed prices at the Conway, Kansas, NGL hub probably means ethane rejection and continued flaring.

According to Wells Fargo, processors may be better off flaring ethane instead of processing it while prices remain at current low levels. On a long-term basis, the investment firm anticipates ethane demand will increase to 112,000 bbl. per day by 2017 from 9,000 bbl. per day in 2010.

ONEOK remains a major midstream operator in the region and has announced multiple, Bakken-related projects valued in the billions of dollars. It has announced construction of the Garden Creek II gas processing plant and related infrastructure, which could cost as much as $345 million by the time it enters service in the second half of 2014. It’s going in adjacent to ONEOK’s existing Garden Creek plant that entered service at year-end 2011.

Related to that work, ONEOK has announced it will add additional pumping horsepower to its under-construction Bakken NGL Pipeline, raising capacity to 135,000 bbl. per day from 60,000 bbl. per day. The line is scheduled to enter service in the first half of this year, with the expansion work expected to be completed in the second half of 2014. The 600-mile line will move unfractionated NGLs to the Overland Pass Pipeline, which links Colorado gas liquids producers with the Conway hub.

Combined, ONEOK’s Bakken NGL system will have a capacity of 490 MMcf per day in the Bakken with more than 5,000 miles of gathering lines at completion in late 2014.

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