Opportunity Flares Up In The Bakken

Through the darkness of crumbling prices and shrinking margins, hope alights over the Bakken Shale’s landscape like … well, like gas flares above a pipelinedeficient oil and gas field.

Price-induced gloom has not hindered the midstream’s great Bakken buildout. That’s because production continues in the Williston Basin, state regulations in North Dakota demand a response to flaring and oil and gas prices are universally expected to return to former glory, even if it takes a while.

“Production will continue, and there is still a huge infrastructure buildout taking place,” Tessa Sandstrom, director of communications for the North Dakota Petroleum Council, told Midstream Business. “We believe strategic investments will continue as the Bakken is a long-term asset. Certainly, there may be some projects that operators or others hold off on, but key infrastructure is going forward.”

It has to, because the economics of supply and demand insist on it.

“They’re continuing to produce in the Bakken and that capacity needs to get to those refining markets,” Katie Haarsager, Enbridge Energy Partners LP’s North Dakota community relations adviser, told Midstream Business. “Even if the production side of things slows to a nice, steady pace, we’ll know that we’ll have that [Sandpiper Pipeline] project in place for when the capacity coming out of the Bakken is in need of a pipeline.”

Flaring reduced

Flaring of natural gas has been a major issue in the Williston Basin. The percentage of North Dakota’s gas production that is flared has actually declined since its peak in 2011, according to SNL Energy, citing the U.S. Energy Information Administration (EIA) and the North Dakota Industrial Commission. But while the percentage has dipped, rapidly expanding production—soaring more than 900% since 2010—has vaulted flared gas production from 5.3 billion cubic feet (Bcf) in third-quarter 2010 to 30.3 Bcf in thirdquarter 2014.

That creates a two-part challenge for the industry. The environmental threat has triggered legislative action requiring a reduction in flaring, and burning gas in the field is akin to burning money.

“The industry is responding,” Andy Steinhubl, principal, energy strategy for KPMG LLP, told Midstream Business. “The economics of that response vary depending on the basin. The economics can actually be attractive. You’ll earn a rate of return if you’re in markets like the Permian that are close to established infrastructure and markets where the molecules are high value.”

Tulsa-based ONEOK Inc. is among those leading the Bakken charge, but the company admits that its projects won’t be enough.

“We have in the works enough plants to get us up to 1.2 Bcf/d, and the analysts are indicating gas production could be easily 2 Bcf/d or more,” company President and CEO Terry Spencer told analysts last November in response to a question about regulators’ pressure to hit flaring targets. “What that tells me is we need more processing plants.

“We’ve got about a 50%—as we sit today about a 50% market share up there—so I would expect a lot of those plants to come right underneath and right well within our footprint,” he said. “And we have some of that in our unannounced. So yes, we see a lot of runway there and visibility into a lot more growth.”

ONEOK’s Bakken NGL pipeline almost doubled its gathering to around 60,000 bbl/d from second-quarter to third-quarter 2014. Its expansion, completed last September, provides additional capacity to transport up to 135,000 bbl/d. The company’s new Garden Creek III plant has raised expectations of higher-margin, fee-based volumes.

Targa’s target

“My existing customers would probably say that they wish that the [McKenzie County Badlands] plant that’s coming on by the end of this year was on faster,” Joe Bob Perkins, Targa Resources Partners LP’s CEO told analysts last November. “The plant we’re going to try to have on by the end of next year is highly needed. We’re trying to do everything we can to work on the flaring. The fact is the oil wells are better and there’s more gas from those oil wells than people originally anticipated. So, I think of it as an opportunity and a task to get our arms around the flaring issue.”

In fact, operators met the initial benchmark of 26% in October by flaring only 22% of gas produced, according to the North Dakota Industrial Commission. That was achieved by allowing the backlog of wells awaiting completion to grow. The benchmark for January was 23%. Within two years, flaring is required to be reduced to 15%, then 10% within six years.

So why not just build the gathering infrastructure during the initial process and avoid having to wrestle with legislative deadlines and taking heat from environmentalists?

The answer comes down to economics, the science of making choices and determining priorities. The midstream players in the Bakken could only do so much.

“If I’m going to build a pipeline to take molecules to market, the first priority is going to be oil,” Steinhubl said. “The whole industry was geared toward getting the oil, drilling the oil, putting the oil online, getting the oil to market—because that’s the highest-value product. Gas in those cases was a byproduct, so what they were doing in the pursuit of getting oil to market was taking the path of least resistance in dealing with the byproduct, which was flaring.”

It was that delay, however, that prompted environmental regulations to mitigate the extent of flaring. North Dakota House Bill 1134 provides deadlines for compliance with flaring reform as well as tax incentives. The law permits flaring for one year following first production from a well. After that point, the state mandates that flaring cease and the well be either:

• Capped;
• Connected to a gas gathering line;
• Equipped with an electrical generator that consumes 75% of its gas;
• Equipped with a system to use at least 75% of the gas in a variety of alternative methods; or
• Equipped to reduce the volume or intensity of the flare by more than 60%.

“It’s very punitive and there’s a hard, fixed time line, which is why producers are trying to do whatever possible to get good midstream provider services,” Ryan Lewellyn, president and CEO of Tall Oak Midstream, told Midstream Business. Tall Oak is not engaged in the Bakken—but has attracted interest from producers and is weighing options. “The other thing there that they have to deal with is the lack of pipelines—long-haul pipelines—so they’re railing and trucking all their product. When you’re spending that much money—when you’re getting $50 for your product and you’re spending 10% to 20% of it on transportation that makes it harder to be economic.”

Steinhubl agreed. The relatively youthful Bakken simply hasn’t had the time to develop an advanced pipeline grid, unlike the Permian Basin or Eagle Ford Shale.

“It wasn’t that those investments weren’t necessarily economic,” he said of the industry’s approach to the gas facet of the plays. “In many cases they’re economic, they’re just less economic than the oil-focused investments. Really, it’s not until you get to the more remote basins, like the Bakken, that don’t have the benefits of all the existing gas infrastructure and proximity to markets; yet they’re still being forced to deal with new regulations.”

‘Tax’ on oil

The skyward trek of natural gas production in the Bakken is tied to crude production’s dramatic ascent and the associated gas produced along with it. That has bred some resentment among producers, who feel targeted by the U.S. Environmental Protection Agency and state regulators over a byproduct of their primary business.

North Dakota hopes to see more pads like this one: Whirring pumpjacks with no associated gas flare nearby. Source: Pioneer Energy Services Corp./John Boykin

“You might look at that as a tax on the economics of the primary product, or oil,” Steinhubl said. “The onerousness of that tax varies. It gets a bit more challenging when you get into the Bakken, which doesn’t have the pre-existing pipeline transportation or gas-liquid separation infrastructure and is not as close to as broad and as high a value end-use market, and that tax becomes a bit higher.”

So producers in the Bakken have sought other ways to comply with regulations until the midstream catches up on gas infrastructure, Steinhubl said. Among them are converting drilling rigs and fracking equipment to be fueled by natural gas instead of industry-standard diesel, which must be brought in.

The North Dakota Oil and Gas Research Council is providing grant money to test projects designed to reduce flaring. One flare-capturing system, developed by Bakken Frontier LLC for Whiting Petroleum Corp., is an NGL recovery system that removes liquids from the raw gas, leaving less to flare. Bakken Frontier estimates that its system, which has been shown to work in Texas plays but is an unknown in North Dakota, will capture 80% of the gas. Assuming 1.5 million cubic feet per day of gas flared and a market Y-grade (mixed gas liquids) price of 70 cents per gallon, the return on investment could reach almost $2.2 million per year.

Another technological innovation to speed pipeline construction and cut costs is the Top Liner, developed by Charleston, W.Va.-based Walhonde Tools Inc. The device aligns pipe segments for welding, cutting the process from eight hours to 45 minutes and allowing a pipefitter with a lower certification level to perform the work. It has been deployed by customers in numerous conventional and unconventional plays.

Metaphors be with us

In its collective quest for a metaphorical resolution to the quandary of swooning oil and gas prices, the industry’s minds have hoped for an external silver bullet, such as action by the Organization of the Petroleum Exporting Countries, particularly Saudi Arabia, to cut production; or a sudden resurgence in China’s economic long march. Then there is speculation about an internal magic number, the market oil price at which all is well.

“If I had to pick a price, I think $75 [per barrel] is a price where almost all [producers] would show you—even with oil at $100, $115—they would show you what their returns would look like at $75 oil,” Tall Oak’s Lewellyn said. “They kind of all felt that $100, $115 probably wasn’t sustainable.

“Now that’s a very broad, general statement,” he continued. “Some of them would be really happy at $65 and drill a lot of wells. I don’t think $65 gets everybody back to the previous capital plans. I think at $75, everybody’s pretty much back to their previous capital deployment and rig plan.”

Stratas Advisors, a Hart Energy company, projects a higher price point of $90 per barrel (bbl).

“This price level provides enough of an upside that operators can sustain the high levels of capital expenditure necessary to drill so many wells,” Stratas’ research team projects. “Our current reference case price forecast indicates that this will occur in 2018.”

RBN Energy LLC offers three scenarios: a “high growth” projection in which crude returns to $80 per bbl by 2017; a “cutback” forecast that sees oil not reaching $70 per bbl until 2020; and a “contraction” estimate assuming lower production levels that does not expect a return to $60 per bbl until 2020.

In the Bakken formation specifically, the director of North Dakota’s Department of Mineral Resources, Lynn Helms, told legislators in January that the state needs a $55 per bbl average breakeven price and fleet of 140 rigs to maintain production of 1.2 million bbl/d. Like all shale plays, the Upper Devonian and Lower Mississippian Bakken is anything but monolithic. The breakeven prices range from $29 per bbl in Dunn County, in the western part of the state, to $77 per bbl in neighboring McLean County.

Clockin’ the Bakken

How quickly will prices rise and restore the Bakken’s production to its former glory? KPMG’s experts were reluctant to specify a magic number, but expressed doubt that midstream players need to worry about one.

“I don’t feel like you’re going to see significant reductions to investments in midstream like you are seeing in E&P because production is still going to rise, so the demand is still going to be there,” Brandon Beard, KPMG partner, told Midstream Business. “I think that are a number of investors out there—whether they are private equity or groups like Kinder [Morgan Inc.]—that understand the energy cycles. They understand that prices are low, but in general the market seems to be viewing oil prices back into the high $50s by the end of the year and into the $60s the following year, so within another 12 to 24 months, the economics are going to continue to improve.”

Tulsa, Okla.-based ONEOK Inc. operates three natural gas processing plants in the Williston Basin—Garden Creek I, II and III—that are able to process 300 million cubic feet per day (cf/d) combined. The company’s projects in the works will be able to handle a total of 1.2 billion cf/d, but that will still be far short of forecasted Bakken production. Source: ONEOK Inc.

That improvement in economics is forecast not just because of an anticipated price recovery, but because of efficiencies that are continually lowering the breakeven price at the well.

“The prices have dropped and they’ve dropped quite a bit,” Steinhubl acknowledged. “But with the Bakken, you’ve seen productivity per well triple in the last three years. It’s doubled over the last two years so the learning curves, and hence the economics, to drill a well have improved accordingly. Costs—drilling costs, fracking costs—already respond to the price downturn so we’re already hearing estimates of almost immediate reductions of 10% in costs and heading more toward 30%.”

Estimates like the one presented to North Dakota lawmakers are predicated on assumptions of where costs are and the cost structure is at a particular point in time, Steinhubl said. The true economics of a shale play just don’t work that way.

“My point is this is a very dynamic environment, both in terms of where oil-field service and equipment costs are going—which is lower, and that lowers the breakeven point—as well as the technical learnings and learning curves of drilling and fracking and producing Bakken and other shale oils, which is inherently improving the economics of the well and developing that resource,” he said. “So the breakevens are dropping very quickly.”

And while lower prices would logically shut in production of a well in which costs are below breakeven, that’s not necessarily how a particular company will react.

“In some cases, your E&P businesses are going to have latitude to shut a well in if the economics are not in their favor, but that’s not going to work for every well for a number of reasons,” Beard said. “Even though the economics may not be the best, they can’t just shut in every well they want to shut in. They’re going to have to continue producing in certain situations.”

Still on track

The EIA expects U.S. crude oil production to rise 7.4% in 2015 to 9.31 million bbl/d. In the Bakken alone, the agency expected daily crude oil output to surpass 1.3 million bbl/d in February and natural gas output to reach nearly 1.54 Bcf/d.

That level of production has got to get to market somehow and rail is a popular alternative transportation mode, accounting for nearly 60% of all crude moved out of the Williston Basin as of last November, according to the North Dakota Pipeline Authority.

“The rail economics themselves are robust,” Steinhubl said. “CSX [Corp.] and Norfolk Southern [Corp.] are big operators but neither of them have much percentage of their overall business devoted to oil. And the oil companies are learning, improving in their use of rail and its economics.

“They’ve extended the number of cars involved in unit trains,” he said. “Many of them have invested in cars. Those cars have been amortized so that their cost basis is lower. They have invested in yards to more quickly offload unit trains. So there has been a lot of investment made, and they are continuing to improve the underlying economics of rail shipping. So really it becomes a matter of: Are the barrels available to ship by rail? The rail economics are fine.”

So fine, in fact, that it hasn’t always been the availability of barrels to ship by rail, but the availability of rail cars to haul the oil.

“I looked at a couple of companies in 2013, and they couldn’t get any more rail—it was tapped for oil,” Beard said. “It was because Brent had achieved such a large premium over [West Texas Intermediate (WTI)] that producers in the Bakken were buying at the wellhead and moving it to market in the GOM [Gulf of Mexico]. They were getting every barrel they could to sell at Brent pricing because it had exceeded a $20 premium to WTI and rail markets were tapped out for whatever the rail companies had allocated as available in the Bakken area.”

That’s no longer the case. In mid-January, the spread inverted and WTI became more expensive than Brent for a time. Pipelines going into service affect pricing differentials, Beard said, but producers still like rail because of the flexibility that it offers.

“They can either sell into WTI markets like the Gulf Coast if that’s the advantaged crude to compete against—as it has been lately, or they can move it to the East Coast if Brent is the advantaged crude to compete against, so rail has some advantages over pipeline,” Steinhubl added. “You see some players like Tesoro even say, ‘look, even if we could build pipelines, we’d probably still stay on rail because we’ve invested in the economics of that mode and it creates the optionality.’ You can basically take it to either coast. Well, three coasts: You can take it east, west or the Gulf and just play against where it is most advantaged to take the crude based on what other crude markets are doing at a particular point in time.”

Lack of lines

The current low prices may inspire yearning for the surety of pipeline completions, but crazy markets can inspire an “anything goes” mentality.

“Trucking is even more expensive than rail,” Beard said. “So you think about shipping, trucks the most expensive, then you go to rail, then you go to pipeline. When Brent was at its peak a few years ago, I was actually seeing producers truck oil out of the Eagle Ford to a point on the Gulf Coast where they could get Brent pricing. They were hauling it to the coast on trucks because they could still get more value out of their barrel despite the higher transportation cost. The difference between Brent and WTI can really drive that.”

Simply put, Steinhubl said, North America is pipeline-infrastructure short.

“We are so short that rail is required at this point to balance the market and even trucks are required at the margin,” he said. “As long as those modes of transportation are required—which they will be as we’re $800 billion deficit of available pipeline infrastructure—they’re going to be in the market. If they’re in the market, then certain players will find it to their advantage to leverage that model as opposed to pipelines.”

The higher cost of moving product by truck or rail will cut into profit margins, of course, even more when prices sink. Until the pipes are built, they do what they have to do.

“If they had access to a pipeline, would they do it?” Steinhubl asked. “Yes, probably, but there’s not enough capacity to go around. So as long as one barrel has to move by railroad, that’s going to set the marginal economics. Some players, because they can play the optionality, they’re going to find using railroad to their advantage. Over time, all that will be backed out in favor of pipelines.”

The near-term outlook, however, shows producer margins tightly squeezed, a point of concern raised by RBN Energy’s Sandy Fielden, director of energy analytics.

“With North Dakota located in the middle of nowhere, much of the crude has to travel long distance to coastal markets where most refineries are located,” he wrote in a recent report.

“In the absence of adequate pipeline capacity, producers have used more expensive rail transport to get Bakken crude to refineries on the East and West Coast. That made sense back in 2012 when pipelines were highly congested and crude prices at coastal locations were at a premium. Today, cheaper pipelines should be the preferred option but rail is still the dominant method of transport to market,” he added.

“If production stays at current levels or increases, there isn’t enough capacity available anyway to ship all North Dakota production by pipeline. As a result, some barrels will still be shipped using more expensive rail options—further pressuring producer returns. Relief—in the shape of new pipelines—is still two years away—if those pipelines ever get built,” according to the analyst.

Fielden lists a number of projects that fill in only part of the gap. Capacity additions have taken the form of the Plains Bakken North (40,000 bbl/d), Butte Loop expansion (100,000 bbl/d) and Hiland Double H (50,000 bbl/d, recently acquired by Kinder Morgan).

Then there is Sandpiper, a $2.7 billion, 616-mile, 24-inch pipeline that will deliver 225,000 bbl/d from the Bakken to a terminal in Clearbrook, Minn. Beset by permitting delays, the project’s in-service date has been moved back to 2017.

ONEOK's Lonesome Creek natural gas processing facility in North Dakota’s Williston Basin will add 200 million cubic feet per day of natural gas processing when completed, likely by fourth-quarter 2015. Source: ONEOK Inc.

“We’re definitely moving forward with Sandpiper,” Enbridge’s Haarsager said. “It’s a commercially sanctioned project, we do have an anchor shipper with Marathon [Petroleum Corp.], with those committed volumes there, so we’ll continue to move forward with Sandpiper and make sure this infrastructure is in place.”

The delays can be attributed to working through the regulatory processes in multiple states, and that processes are typically lengthier now as a result of pressure from environmental advocates than in the past.

“We’ve worked through the North Dakota Public Service Commission to regulate the North Dakota section of the Sandpiper project, and now we’re working through Wisconsin and also Minnesota,” Haarsager said. “We have seen a longer process in Minnesota than as per usual, and a lot of that has directly affected the delay and in-service date.”

Sandpiper will enable producers to access Midwest refinery markets via the Flanagan, Ill., and Patoka, Ill., terminals as well as Gulf Coast markets via the Cushing, Okla., trading hub and the Enbridge/Enterprise Seaway pipeline, which brings product to the Freeport, Texas, area.

“In terms of market access, however,” Fielden wrote, “Sandpiper does not offer Bakken producers access to any new destinations that they cannot get to on existing pipelines—just more capacity.” East Coast and West Coast refineries welcome Bakken oil but new pipelines to those distant markets are unlikely to ever be built.

Waiting on demand

In a strange way, the price plunge may be just what the industry needed, and a plus for the midstream. Pullbacks in drilling have allowed producers to keep flaring within North Dakota’s new limits and pipeline builders have a chance to narrow the infrastructure deficit.

“We would see this being a bit of a welcome relief in the intensity of the buildout required,” Steinhubl said. “In many cases, you have so much trucking and railroading going on, there hasn’t been an opportunity to build all the pipelines that would be economical and desirable to handle this influx of supply and the need to get that supply from new places to new places.”

The anticipated future demand for oil and gas translates into the current demand to create infrastructure, leading investors to aim their cash and enthusiasm toward midstream companies.

“We’ve seen a fairly large increase in interest in midstream over the last 12 to 18 months,” Beard said. “From 2009 to 2014, we saw lots of growth in E&P investments. Now we are seeing midstream investments really grow.

Heavily dependent on rail, the Bakken Shale is shifting toward pipelines as the midstream buildout continues.

“What’s a little more unique to me is that we’re seeing more and more private equity groups through portfolio companies make greenfield investments in midstream. We’re seeing a little more than we have in the past, which tells me that the appetite for taking on risk in the midstream space is growing. I’ve been involved in a couple of transactions where clients were comfortable taking on merchant risk, meaning they were buying an asset that was not fully contracted, they were comfortable taking on capacity risk.”

The economic fundamentals—the interplay among supply, demand and cost—hasn’t changed, Steinhubl said.

“You have an interplay between supply, demand and cost,” he said. “A lot of folks, when they talk about the recent price drop, would say at least 30% of the blame is weak demand; 50% of the blame is oversupply. The reason you have oversupply is not just because we’ve had this ramp-up in light oils in the United States, it’s also because of the return of production in places like Iraq and Syria, more rapid than expected. And it’s due to the fact that a few key countries in OPEC made the decision that they would not withdraw production from the market. All of these other sources, including light, tight oils are coming on the market. We’re oversupplied and, hence, price has to drop to balance supply and demand.”

The market is working the way it is supposed to work. The massive buildout continues, and while oil and gas prices have fallen, the lows never bothered the midstream anyway.

Joseph Markman can be reached at jmarkman@hartenergy.com or 713-260-5208.