Perhaps none of the unconventional shale plays fell harder as oil prices went over the cliff at the end of 2014 than the Bakken. The sprawling Williston Basin unconventional play, along with the associated Three Forks Formation, faced a double whammy as lower prices exacerbated an ongoing shortage of midstream infrastructure.

You couldn’t get there from here. Oil prices just didn’t work for many producers’ acreage and drilling dropped right along with commodity prices. From a weekly peak of 224 rigs making hole in early June 2012, the Williston’s rig count dropped 90% by second-quarter 2016. It has since recovered—somewhat—to 52 as the second quarter ended.

But the Bakken was—and is—a big and promising play. The U.S. Energy Information Administration (EIA) estimated in a recent report that Bakken wells would produce an average of nearly 1.14 million barrels per day (MMbbl/d) in June.

One of 10

Remember that production number: Only 10 oil fields in the world produced more than 1 MMbbl/d last year—and the Bakken was one of them, said Jack Stark, COO and president of Continental Resources Inc., who spoke at Hart Energy’s DUG Bakken and Niobrara conference in Denver earlier this year. The Bakken still averaged 1.1 MMbbl/d of production in 2016 between North Dakota and Montana, which Stark attributed to technology strides and greater understanding of the geology, he said. He added there is more to come. Bakken production peaked at 1.2 MMbbl/d in late 2014.

If the Bakken were a separate coun-try, it would rank 19th in worldwide oil production, Stark noted. “It has produced 2 billion barrels to date.”

Stark said in his presentation that, by his estimate, Bakken production could stand at nearly 1.1 MMbbl/d by year-end 2017 if the industry com-pletes all the drilled but uncompleted wells (DUCs) and enough rigs join the basin’s fleet on new projects. However, he warned, “without a rig increase, you won’t keep production flat.”

Continental Resources alone had 187 DUCs to complete in the first quarter of 017. A North Dakota state estimate in mid-June was that, among all operators within its borders, there were 830 DUCs at the end of April.

The gas side

There’s good news on the natural gas side, too. The Bakken’s significant associated gas production has created another midstream-related issue, given the region’s comparative lack of gas gathering and processing capacity. That resulted in significant flaring at one point, creating environmental concerns, regulatory issues, and lawsuits from mineral rights holders, who complained that flared gas cut into their royalty payments.

Seaport Global Securities LLC, commenting on a recent EIA report, noted Bakken gas production was up to 1.71 billion cubic feet per day (Bcf/d) as the second quarter began, a nearly 10% rise from 1.56 Bcf/d in January, “and is now showing year-over-year growth of 3.55%.” The North Dakota Department of Mineral Resources reported in mid-June that April gas production was a new all-time high: 1.84 Bcf/d.

Dakota Access arrives

A bigger development for the Williston than the oil-price pickup was that the Bakken midstream seems to finally be offering producers adequate pipeline capacity out of the basin to prime markets to the east and south.

And the best could be yet to come as the new Dakota Access Pipeline

(DAPL) gets up to speed. The 1,172-mile, 30-inch, $3.8 billion project finally entered service late in the second quarter after long delays caused by bitter protests by environmentalists and the Standing Rock Sioux Tribe—although the pipeline does not cross the tribe’s reservation.

The opposition isn’t over, however, and a federal judge ruled in June that the Army Corps of Engineers did not ade-quately consider the pipeline’s environ-mental impact when it issued the permit in February that allowed construction to resume. At most, that ruling could lead to a suspension of pipeline service, although the parties were scheduled to meet with the judge as the third quarter began, to consider further proceedings.

Operator Energy Transfer Partners LP (ETP) set initial capacity at 470 Mbbl/d—a little more than 40% of the play’s current production.

Greg Haas, director of integrated oil and gas for Stratas Advisors, told Midstream Business that “the Dakota Access Pipeline and the other interconnections that will bring Bakken crude all the way to Louisiana and Texas refineries [are] by far the best development, probably, in the Bakken over the last three years.

“That’s because [they] will proba-

bly close more of the discount to West Texas Intermediate (WTI) and to the

[imported] waterborne crude and give the operators some welcome uplift in

a relatively high-cost area with great resources but fairly remote markets.”

Elephant Analytics said in a recent report that Bakken producers face a

price differential of between $8/bbl

and $9/bbl against WTI at the Cushing, Okla., crude trading hub.

Pipe to Patoka

DAPL’s capacity can be increased to 570 Mbbl/d, or half of current basin output. It connects the Williston with the Midwest’s Patoka, Ill., oil hub. And as Haas noted, that’s not all. From there, ETP repurposed a 680-mile section of its Trunkline gas system to create the Energy Transfer Crude Oil Pipeline (ETCOP) headed south to the Gulf Coast. With a capacity of up to 570 Mbbl/d, ETCOP provides a direct pipeline connection for Bakken crude to

Texas and, potentially, all the way to the St. James, La., crude trading hub, according to Haas.

That’s in addition to existing links eastward from the Illinois pipeline terminal. At the same time mid-stream infrastructure has expanded, producers’ drilling and production costs have dropped.

Whiting Petroleum Corp., a major Williston producer, said in its first-quarter 2017 earnings report that estimated breakevens on its core Bakken acreage are now in the $40s/bbl.

The number is “well below consen-sus views for the basin’s economics,” analysts with R.W. Baird & Co. Inc. reported. If Whiting is right, then the Bakken may start to percolate sooner than expected—if oil prices stay where they are.

Baird said in a May report that Tallgrass Energy Partners’ “Pony Express [Pipeline] remains the key risk. An oversupplied crude oil transport market from the Bakken, particularly in the wake of … completion of Dakota Access, likely means some combination of rate and volume attrition for the pipeline long-term.”

Baird noted Pony Express volumes in the second quarter “fell 9%, likely due to line-fill purchases on Dakota Access. With superior rates and a path to Cushing, Pony should remain a favored export option, though management will need to continue its connectivity efforts, such as the 100 Mbbl/d Holly refining connector,” which is due to enter service in the fourth quarter.

That line will directly serve HollyFrontier Corp.’s El Dorado, Kan., refinery. The 760-mile Pony Express line begins at Guernsey, Wyo., and also serves Niobrara producers in Wyoming and Colorado. It has a direct link to the Phillips 66 Co. refinery at Ponca City, Okla., before terminating at Cushing. Capacity is 420 Mbbl/d.

West Coast markets

Pipelines east and south are good news, but there’s still a demand for Bakken crude on the West Coast, too. However, a westbound pipeline to Pacific refiners remains highly unlikely given distance, a comparatively thin market, and serious environmental opposition. Stop and think how the public would feel about laying a pipeline through Glacier National Park.

The result is a significant portion of Bakken oil continues to trundle west by rail—and will for the foreseeable future. Crude by rail was an outsized player in the Bakken’s early years, given its limited pipeline connections, but volumes headed south and east have dropped significantly.

Tesoro Logistics Partners LP moves a sizeable amount of Bakken crude west via BNSF Railway to parent Tesoro Corp.’s refinery at Anacortes, Wash., north of Seattle. Tesoro Logistics is a sizeable midstream operator in the Williston, in part because its parent’s refinery at Mandan, N.D., is the state’s only major refinery. (Following the third-quarter closure of the merger between Tesoro and Western Refining Inc., Tesoro and the MLP’s names changed to Andeavor Corp. and Andeavor Logistics LP, respectively.)

Haas said, “I think some firms probably have some barrels still going east as a result of long-term, take-or-pay-type contracts.” But DAPL can deliver into terminal facilities in the Midwest that can transload the crude onto rail tankers halfway, thereby potentially lowering the cost of the journey to eastern refineries, he added.

DAPL is reshuffling the pieces of the nation’s midstream puzzle and that may mark the end of eastbound crude by rail as those contacts end. Reuters reported recently that two major East Coast refiners—Phillips 66 and Delta Air Lines Inc.’s Monroe Energy LLC unit—plan to start taking more water-borne crude from the Gulf Coast via Jones Act tankers.

Gulf Coast terminals can mix or match crude from the Eagle Ford, Permian and Bakken to East Coast refiners’ specifications. The alternative is imported crude, primarily Nigerian Bonny Light, which will continue to be the dominant feedstock, according to analysts quoted by Reuters.

Midstream growth

The DAPL line may be the biggest cur-rent midstream capex project in the Bakken, but it is not the only one.

In its first-quarter earnings announcement, Crestwood Equity Partners LP outlined an active expansion program in North Dakota. Crestwood started construction early this year of its $115 million, 30 million cubic feet per day (MMcf/d) Bear Den gas processing plant and its associated Bear Den West Pipeline to handle increasing production volumes on its Arrow gathering system, serving acreage surrounding the Fort Berthold Indian Reservation in North Dakota.

Bear Den West is scheduled to start up in the fourth quarter of 2017.

“Additionally, as gas and oil volumes on the Arrow system are expected to continue to increase throughout 2017 and 2018,” the company reported,

“Crestwood is currently finalizing plans to add an additional train of processing capacity at the Bear Den plant by the end of fourth-quarter 2018.”

Crestwood has been a major oper-ator in the play and plans to expand its presence there, Robert G. Phillips, chairman, president and CEO, told Midstream Business.

“The Bakken is the most import-ant basin that we are in right now,” Phillips said. “It’s where we’re spending the majority of our capital this year. It’s where we see the greatest volume growth and that’s where we see the greatest opportunity to provide services to our producer customers. It’s really an exciting time for us.”

The firm has earmarked $300 million in potential capital projects to expand in the Williston from fourth-quarter 2016 into 2019.

Also in the first quarter, it completed a direct link between its Arrow system and DAPL at Energy Transfer’s Johnson Corner, N.D., station, and it also completed the Phase 1A increase to the Arrow system’s capacity to handle crude oil, gas and produced water.

Crestwood has the good fortune, Phillips added, to serve producers active on and around the Fort Berthold Indian Reservation—one of the hottest areas of the Bakken—that enjoys “great ock, great producers and breakevens below $40/bbl. It’s probably considered the best rock in the Bakken and Three Forks plays.

“We didn’t see as sharp a drop in drilling through the crude oil downturn from the fourth quarter of 2014 through 2016 as much of the Williston did, which is a testament to the quality of the rock,” he said.

Crestwood serves WPX Energy Inc., Halcon Resources Corp., QEP Resources Inc., Exxon Mobil Corp.’s XTO Energy Inc., Whiting Petroleum Corp. and Enerplus Corp. Targa Resources Corp. is the other big midstream service provider in the area.

Good and getting better

Good Bakken wells are getting better as producers improve drilling and completion techniques, and that means higher initial production (IP) rates.

“We have seen a huge increase in volumes on the Arrow system,” Phillips added. “We just hit 80 Mbbl/d of oil gathered, and we’re bursting at the seams with natural gas right now.”

The system has an oil capacity of 125 Mbbl/d. Gas gathering capacity is 100 MMcf/d with current throughput around 55 MMcf/d—but growing rap-idly. “We have been challenged with all of the new well connects that we have made this year.”

Crestwood’s initial forecast for 2017 projected that 70 new wells would be added to Arrow. “We will have connected 70 wells already through the first six months of this year, so we’ve already surpassed our 2017 budget. It looks like, based on current drilling plans, we could connect 100 to around 120 wells for the year.

“That’s great for cash flow, but it presents some problems for down-stream processing, which led us to announce that we’re going to build our own processing plant,” Phillips said.

ONEOK Inc. has handled processing off the Arrow system under a 2011 agreement, “the only option at the time,” he said. That agreement expires in 2019.

“We made the operational and processing decision to build our own processing plant and self-perform processing. That’s important in two respects. One is that we think we can give our producers higher netbacks on their gas and gas liquids because of our NGL marketing team, potentially at a higher price, and, most importantly, flow assurance.”

Phase I of the new Bear Den pro-cessing plant and pipeline is scheduled to go onstream in the third quarter—a $115-million, 30 MMcf/d project.

“Then we will make a decision to expand that processing plant in 2018, probably another $110 million to

$120 million [and] 90 MMcf/d to 100 MMcf/d if volumes continue to rise,” Phillips said.

“We estimate there are 1,400 to 1,500 locations left on our system, so we expect to have active drilling and development for the next several years, and we’re building toward that. It’s an exciting time for us,” Phillips said.

Changes at COLT

Crestwood’s other big Williston asset, the COLT Hub at Epping, N.D., has been a major crude-by-rail terminal but has had a changing role as rail traffic declines and DAPL enters service. COLT has seen “a significant reduction in rail loading, but, at the same time, we have done a much better job of using the COLT hub as a supply aggregation point,” Phillips said.

“It’s connected into DAPL, so

we have new contracts there with Sunoco [Logistics Partners LP] and Energy Transfer, and it is one of the staging areas used to aggregate and stage barrels into that part of the DAPL system.

“Our view is DAPL is a good thing for the Bakken,” Phillips continued. “It will bring higher netbacks because it will allow producers to market their oil production in higher-price markets, largely the Gulf Coast, which those producers have not had a lot of access to in the past.”

With the new crude line entering service, the Williston Basin is “overbuilt on the oil side. But we’re underbuilt on the gas side right now and underbuilt on the gas-liquids side. We think that is where the long-term opportunities are and why Crestwood is expanding its gas gathering and processing assets,” Phillips added.

Going gassy

“We think oil production will generally increase 8% to 10% per year over the next four or five years,” he said. “But gas production could increase at 2x to 3x that level because the field is getting gassier.

“We’ve got more gas and gas liquids to handle. Therefore, I suspect that there is a potential for a new NGL-takeaway pipeline [in] the basin to compete with ONEOK. If you presume a big increase in gas and gas liquids, you have to presume there is going to be the need for more takeaway infrastructure to deal with it,” Phillips added.

ONEOK has a large midstream presence in the Williston—something the Tulsa, Okla.-based firm wants to enlarge. It told analysts in a recent presentation that about 30 rigs are active on 3 million ONEOK-dedicated acres. The firm opened a new field office in Sidney, Mont., last year to support its sprawling operations.

It connected 75 new wells in the first quarter of 2017 and counted 300 DUCs awaiting connection to pipe. Plans are to expand its Bakken NGL line to 160 Mbbl/d in 2018 through additional pumping. ONEOK feeds that line through an extensive gas gathering system and four processing plants with a combined capacity of nearly 1 Bcf/d.

ONEOK’s 60 Mbbl/d Bakken NGL Pipeline provides the major gas-liquids capacity out of the Williston, connecting to its Overland Pass Pipeline. TC PipeLines LP’s Northern Border line provides a major outlet for gas.

Earlier this year, Targa Resources reported that it will double its Bakken-focused capex to $150 million in 2017 for its Badlands system in advance of expected growth in oil and gas production. Targa’s network crosses core Bakken acreage in North Dakota’s McKenzie, Dunn and Mountrail counties. It currently has 410 miles of crude gathering lines, 200 miles of gas gathering lines and 90 MMcf/d of processing capacity at three plants: Little Missouri I, II and III.

Savage Services Corp. placed its 60 Mbbl/d Savage Bakken Connector Pipeline in service in June. The nine-mile short segment connects Savage’s existing Bakken Petroleum Services hub at Trenton, N.D., with DAPL.

High Plains expansion

Tesoro Logistics is expanding its High Plains line and recently completed an expansion of its storage terminal to 1 MMbbl.

It also recently acquired the Robinson Lake and Belfield gas gathering and processing systems. Combined, they have 170 MMcf/d of processing capacity with 18,700 bbl/d of fractionation capacity.

The play’s improving economics have intrigued securities analysts. Simmons & Co. International analyst Kashy Harrison wrote recently that Newfield Exploration Co.’s enhanced completions have resulted in IP rates of 2,445 barrels of oil equivalent per day (boe/d) composed of 75% oil and 25% gas, for $6.1 million per well. He rated the results as well as the company’s results in the Stack play in Oklahoma and its fiscal performance “a strong showing … that should be well received by investors, especially given the future implications for the company’s multi-year production guidance.”

Hess Corp., one of the biggest Bakken producers, reported this spring that it is adding a fourth rig in the Bakken this year. Hess has been a dominant player in the Williston and reported average production of 105 Mboe/d in 2016.

Midstream spinoffs

The Hess name has taken on an additional Williston role in the region. It spun off its midstream assets in the basin as Hess Midstream Partners LP in April—the stock market’s first MLP IPO of the year. The offering priced above expectations. It is majority owned by Hess and private-equity firm Global Infrastructure Partners.

Hess Midstream has interests in nearly 1,600 miles of oil and gas gathering lines; the Tioga, N.D., gas processing plant and fractionator; the Tioga, Mentor and Ramberg terminals; and the new Johnson Corner header system, which is to start up this year with a capacity of 100 Mbbl/d.

Another big Williston producer, Oasis Petroleum Inc., launched its IPO plan in May to spin off a portion of its midstream assets as Oasis Midstream Partners LP. It reported, “The MLP is intended to support [Oasis’] strategy to grow its midstream business.” Oasis’ assets—both upstream and mid-stream—are entirely in the Williston Basin. The offering is expected to include some of the producer’s oil gathering and transportation lines, gas gathering and processing system, and water handling systems.

Better, not best

So are the good times back for the industry across the Northern Plains?

Not quite, but things are certainly better than they were. In a recent report, Wells Fargo Securities LLC analysts have “a positive outlook on the midstream/MLP sector for 2017,” they reported “while the relative volatility in crude oil prices has resulted in a lack E&P continue to suggest a ramp-up in drilling activity and volumes in low-cost basins” such as the Permian and the Midcontinent’s Scoop and Stack plays. As for the Williston Basin, they speculated that times have improved for the “next tier” of shale plays—that includes the Bakken—but a true turnaround must wait if commodity prices don’t show at least modest improvement from the $50/bbl range.

One indicator that the Bakken has a ways to go came in the second quarter of 2017, when SM Energy Co. withdrew an offer to sell its 123,570 net acres in Divide County, N.D., stating that “valuations in the sales process did not reach [its] thresh-old to meaningfully reduce its leverage.”

Wells Fargo senior analyst David Tameron had estimated the package’s worth at $574 million in January when WTI was about $50. The assets were producing 10,700 boe/d at year-end. SM had dropped its rigs in the play and reported 17 DUCs on the property.

Stratas’ Haas emphasized it will take a few months—maybe a year—to gauge the full impact of having DAPL in service.

“This will certainly increase takeaway and likely lead to higher netbacks in the region,” he said. “Now, producers have lower-cost transportation and I think a lot of them are learning how to produce more with less capital. It seems like DUC counts should begin to be worn down, but we’ll have to wait and see. It’s still kind of early.”

The Bakken may not be where the industry wants it to be, but positive changes are certainly welcome after two dismal years.

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