Page 1

ISSUE 1 2018

Can Midstream Keep Up? With Production Rising, Takeaway Capacity Tightens Page 22

Plus Operators, Analysts Explain New OilďŹ eld Mantra Page 16

And Oil Sands Vs Shale Oil Page 11 Printed in USA




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Speak at a Premier Shale Oil Event Presentation abstracts will be accepted for the 2018 Bakken Conference & Expo through March 23, 2018. Presentation ideas may be submitted on one of the following topics: exploration and production; logistics; infrastructure and construction; products and technology; investment strategies; policy.

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July 16-18, 2018 Roughrider Center \\ Watford City, ND 4


Presentations In addition to being presented on stage, presentations are available during and after the conference. Available for 12 months after. Registered attendees only.


A PREMIER NORTH DAKOTA SHALE OIL EVENT Focused on Bakken Play Technologies and Efficiencies

The Bakken Conference & Expo is the nation’s premier event featuring innovations that are driving new efficiencies and the profitability of oil recovered from shale formations.

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ISSUE 1 2018








Shale Investors Take New Direction

Shale’s Need For Midstream

BY LUKE GEIVER The need for gathering, takeaway and long-haul infrastructure in most shale plays is immediate. How long will the industry continue its frenzied push to build-out midstream?

BY PATRICK C. MILLER After pushing E&Ps to ramp-up production and acquire acreage, investors are asking producers to rethink IP rates and spending habits.




4 & 27

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Report explains oil sands vs shale oil DOE injects $30 million into shale, oil research



In 2018, Shale is Undersupplied BY LUKE GEIVER



ON THE COVER: A drilling rig operates while midstream gathering equipment works in the foreground. Like most North American shale plays, the Bakken is in need of more midstream infrastructure. PHOTO: CALIBER MIDSTREAM



In 2018, Shale Is Undersupplied A familiar thread is once again weaving through the stories, conversations and descriptions of the current shale space. We’ve experienced it before, back when oil prices were above $90/b and reaching total depth on a horizontal well took a month or more. As you’ll

VOLUME 2 ISSUE 1 EDITORIAL Editor Luke Geiver Staff Writer Patrick C. Miller Copy Editor Jan Tellmann


find this issue there is a thread of excitement in the uncon-

President Tom Bryan

Luke Geiver

ventional world right now, an understanding that much of

Vice President of Operations Matthew Spoor

EDITOR North American Shale magazine

infrastructure, workers and depending on which source you

what drives activity levels is undersupplied: sand, midstream subscribe to, global oil inventories. Midway through 2017, it became clear that gathering,

takeaway and long-haul shipping capacity in every major shale play was becoming a concern. The supply of infrastructure and services was falling behind demands from the production side. In the fourth quarter

Marketing & Sales Director John Nelson Business Development Manager Bob Brown Circulation Manager Jessica Tiller Marketing & Advertising Manager Marla DeFoe

of 2017, we ran numerous stories detailing a new midstream project, joint-venture, gathering plan or


pipeline open season calls. When it became time to quantify and explain the issues with midstream ca-

Art Director Jaci Satterlund

pacity in places like the Permian, Bakken or DJ Basin for this issue, we had a long list of headlines to add into the greater story as examples of how producers and shale midstream entities view the supply and demand needs of the industry. In the feature, “Shale’s Need For Midstream” on page 22, we included more than 10 examples of new midstream-related projects. And, since we finished that piece, the list could have expanded. Sentiment from some of the midstream groups in the feature explain why, or how long, the trend will continue. It’s possible that one of the most important trends to spread throughout shale this year is a new investor and operator mantra towards initial production rates. For months, we’ve heard and written about rumblings from the investor (and E&P) side that the goal in the future should be centered on long-term development. Such an approach could make initial production rates less important, and, in some cases, allow E&Ps to focus more on investor share buybacks and payouts. Patrick C. Miller spoke with every side of that story, including an operator, analysts and others, for his feature this month. From the news and trends section of this issue, it is also clear to see that 2018 will harbor growth. From frack sand suppliers continuing their ramp-up, to more rigs headed to the Bakken, the North American shale scene is moving beyond active and, instead, closer to a word we all know is the exact opposite of a bust. As part of the industry, our team is ready for the new year and heightened activity levels. We are

Subscriptions Subscriptions to North American Shale magazine are free of charge to everyone with the exception of a shipping and handling charge for any country outside the United States. To subscribe, visit www. or you can send your mailing address and payment (checks made out to BBI International) to: North American Shale magazine/ Subscriptions, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. You can also fax a subscription form to 701-7465367. Reprints and Back Issues Select back issues are available for $3.95 each, plus shipping. Article reprints are also available for a fee. For more information, contact us at 866-746-8385 or Advertising North American Shale magazine provides a specific topic delivered to a highly targeted audience. We are committed to editorial excellence and high-quality print production. To find out more about North American Shale magazine advertising opportunities, please contact us at 866-746-8385 or Letters to the Editor We welcome letters to the editor. If you write us, please include your name, address and phone number. Letters may be edited for clarity and/or space. Send to North American Shale magazine/Letters, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203 or email to lgeiver@

excited to announce that in 2018, we’ll be publishing more issues and we will soon be announcing more content offerings for you to learn from or utilize as a powerful messaging and advertising platform. COPYRIGHT © 2018 by BBI International


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Niobrara A major DJ Basin producer formed after Bill Barrett Corp. and Fifth Creek Energy combined. Once approved, BBC will have increased its DJ Basin position by 112 percent and the number of undeveloped locations by 70 percent. Most of the acreage is already held by production and is adjacent to shale super producer EOG Resources. Some of the acreage is located next to the Jake well, the first horizontal test well drilled in 2009 that led to the activity in the DJ Basin. RS Energy Group and Anadarko Petroleum Corp, have formed a collaborative partnership to integrate proprietary RSEG intelligence and analytics with Anadarko’s internal data. Anadarko will use the new data intelligence on its acreage in the DJ and the Delaware.

New Mexico


became the third largest oil producing state in the U.S. due to production increases in the state’s portion of the Delaware Basin.

The Permian is a Phoenix, rising from the ashes to new heights. While some believed the region was dead, according to researchers from IHS Markit, the world’s hottest shale play is now on pace to shatter production records previously recorded in 1973. Calling it a global disrupter, IHS said the Permian will play a major role in helping the U.S. exceed 10.5 million barrels of oil produced by the end of 2018. This year, oil major Chevron will invest $3.3 billion into the Permian. The goal is to spend capital on projects that will yield returns in roughly two years. The total 2018 budget for Chevron is $18.3 billion. At oil prices comparable to 2017, Chevron expects to deliver production growth and reach free cash flow. With its $483 million acquisition of Forge Energy’s Delaware Basin position, Oasis Petroleum is no longer a Bakken pure-play producer. Oasis executives have a long history in the Texas play and also said they had a good relationship with the Forge team, which to date, has only drilled nine horizontal wells in an acreage block that could support over 600. The purchase will not change the view Oasis has on the Williston Basin, but it will give the company a position in the core of each shale play. 8


Eagle Ford Vitol, a global energy and commodity trading company that trades more than 7 million barrels of crude oil per day, has begun talks with Harvest Pipeline Co. on a new crude oil terminal located near Corpus Christi, Texas. As the first energy trader to export U.S.-based shale oil following the removal of the export ban on U.S. crude, Vitol believes U.S. shale oil will only grow in demand throughout the world. Harvest believes its Midway junction line located in the Eagle Ford would be able to send barrels from the Eagle Ford to Corpus Christi. Permian barrels would also benefit from the new terminal, according to Harvest.

Bakken With two existing NGL pipelines operating at capacity and more NGL supply in production, ONEOK Inc. is planning a new 900-mile pipeline to move NGL’s from the Williston Basin to facilities in Cushing, Oklahoma. Set for a planned capacity of 240,000 barrels of unfractionated NGLs per day, the infrastructure could be completed by the end of 2019 at a cost of roughly $1.4 billion. The Elk Creek Pipeline will help producers in North Dakota that are required to capture a set percentage minimum of associated gas extracted during oil recovery.

Marcellus/Utica For $93.7 million, Pennsylvania-based Eclipse Resources Corp., will add roughly 87 drilling locations spread throughout 44,500 acres of prime Utica dry gas areas. The Flat Castle acreage will be purchased from Travis Peak Resources and will allow Eclipse to drill 16,000 foot laterals targeting Utica dry gas formations. With its midstream subsidiary, Eclipse also acquired Cardinal NE Holdings LLC for $18.3 million in a move that will net Eclipse the midstream gathering assets that were already being used on the Flat Castle acreage.

SCOOP/STACK Morgan Stanley Energy Partners has chosen Durango Midstream as its partner for exposure to the SCOOP and STACK plays of the Midcontinent. Through equity provided by MSEP, Durango will build upon its infrastructure assets in the Oklahoma county of Grady. Richard Cargile, formerly president of Midstream Operations at Energy Transfer Partners L.P., is leading Durango Midstream’s efforts in a region that Robert Lee, managing director for MSEP said offers “exceptional” opportunities.

Production By Play: Anadarko: 487,000 bpd - 6.0 million cf/d

Oil and gas production each up month over month

Appalachia: 114,000 bpd – 26.3 million cf/d

Oil and gas production each up month over month

Bakken: 1.1 million bpd – 2.1 million cf/d

Oil and gas production each up month over month

Eagle Ford: 1.2 million bpd – 6.3 million cf/d

Oil and gas production each up month over month

Haynesville: 44,000 bpd – 7.6 million cf/d Oil down and gas up month over month

Niobrara: 549,000 bpd – 4.8 million cf/d

Oil and gas production each up month over month

Haynesville Goodrich Petroleum will spend up to $75 million this year to increase production across its Haynesville acreage by nearly 150 percent. Goodrich has hedged 40 to 42 percent of its expected natural gas volumes for the year at a blended average price of $3.02 and 50 to 55 percent of expected crude oil volumes for the year at $51.08.

Permian: 2.7 million bpd – 9.5 million cf/d

Oil and gas production each up month over month

Drilled Uncompleted Wells: Anadarko: 977 Appalachia: 785 Bakken: 713 Eagle Ford: 1,441 Haynesville: 195 Niobrara: 630 Permian: 2,613



CONNECTED TO THE WORLD: The U.S. already provides one-quarter of all natural gas liquids to the global economy. With greater investment in Appalachia, the region has the resources and know-how to increase production and make the Northeast a petrochemical hub. PHOTO: EQT

Appalachian shale gas could create new US petrochemical hub The Northeastern U.S. rich in shale gas could become the country’s second great petrochemical hub. In its 2018 market outlook, Petrochemical Update said the Marcellus and Utica offer huge potential for jobs and economic development, but other factors including infrastructure, community support and a well-trained workforce are necessary to make it happen. In the next 35 years, natural gas production could double from the 20 billion cubic feet per day numbers the Appalachia region boasts currently. Of the world’s total, the U.S. produces a quarter of all NGL, according to the American Chemical Council. The Marcellus and Utica plays

Potential Economic Impacts of an Appalacian Chemical Industry (Permanent, By 2025) Employment

Payroll ($2016)

Federal, State, and Local Tax Revnue

$32.4 billion in $23 billion in petrochemicals, chemical + resins and plastic resins derivatives $5.4 billion $3.4 billion in in plastic plastic compounding + products plastic products

25,664 direct jobs (chemical and plastic products manufacturing)

$1.7 billion direct

$1.7 billion in federal tax revenue annually

TOTAL: $35.8 billion

TOTAL: 100,818 jobs

Capital Investment ($2016)

Direct Output ($2016)

TOTAL: $28.4 billion


are rich in NGLs, producing roughly 70 percent of its gas streams in the form of ethane or propane.


43,042 indirect (supply chain) jobs

$3.0 billion indirect (supply chain)

32,112 “payroll-induced” jobs $1.5 billion in local communities where payroll-induced workers spend their wages TOTAL: $6.2 billion

$1.2 billion in state and local tax revenue annually TOTAL: $2.9 billion


DIGGING FOR VALUE: A new report shows the abundance of U.S. shale oil is giving heavy oil processors looking to expand oil sand operations and processing possibilities a difficult dilemma.

Report explains Oil Sands vs Shale Oil A new oil sands reports highlights the difficulty bitumen producers have in competing with U.S.-based light, tight oil production. Due to the processing requirements linked to oil sands utilization, investors and endusers are still in favor of shale oil. According to the report entitled, “A New Look: Extracting Value from the Canadian Oil Sands,” produced by research firm IHS Markit, there are three viable options for oil sands to compete with U.S. shale. Option 1: Utilize upgrade facilities that can convert oils sands bitumen into light, synthetic crude oil that competes for refinery space with light sweet crude. Option 2: Convert existing refineries to handle and process bitumen from start to finished product.


Option 3: Build new refineries that can handle and process bitumen from start to be finished product. IHS believes the best option is to convert existing refineries. The least viable option for expanded bitumen processing is to build upgrading facilities. “The abundance of so much light, tight oil will also weigh on any new significant investment in heavy oil processing in North American, the study said. “The most attractive option for growing oil sands production continues to look like the export of heavy sour bitumen blends to U.S. Gulf Coast regions, which imported over 1.8 million barrels per day of crude oil of similar quality to the oil sands from offshore places like Venezuela, Mexico and others,” said Patrick Smith, co-author of the study.

Oil Sands Processing Refresher DIG: Scooped out of a large mine field, oil sand material is deposited onto massive trucks. CRUSH & TRANSFER: Bitumen-rich sand is ground at an ore plant before going to an extraction plant. EXTRACT: In the primary phase, oil sand in a giant tank is separated from sand and water. DILUTE: Mixed with naptha, the bitumen is removed of any remaining minerals or water. UPGRADE: Creating synthetic crude oil requires 900 degrees, giant furnaces and a process to remove excess carbon. Hydrogen is added to make the solution suitable for industrial use.



Proppant Logistics are Complex and Prone to Bottlenecks Illustrative 20 Million lb. Completion Requirements



~10,000 tons of sand

 Proppant mined and stored in

mine storage (silos or domes)

 Proppant loaded into unit train

~100 railcars

and delivered to basin  High capacity transloads with ability


~10,000 tons of throughput

to unload unit train in 24 hours  Proppant transloaded into storage

facility (large silos) or directly to truck  Highest variability in supply chain


~400 truck loads  Subject to congestion and bottlenecks  2.5 million lbs of storage capacity


~2.5 million lbs / 6 silos

 Assuming 4 day completion, System

turned 2x every 24 hours  Storage at demand center reduces


Frack sand suppliers adding scale, new tracking capabilities Frack sand suppliers are not sticking to the status quo. As operators continue to push the known limits of sand placed perlateral-foot and suppliers reimagine ways to offer more economical and efficient proppant supply networks, source mine locations are morphing and technology used to track shipments is increasing. The merger of Unimin Corp. and Fairmount Santrol has created the largest proppant and sand supplier in the U.S. The recently merged entity now has more than 45 million tons of annual production capacity with a presence in every major U.S. shale basin. Mat12

thew LeBaron, chairman of the Fairmount Santrol board, said the merger has come at an opportune time in the industry. Unimin’s team felt the new joint effort matched its plan to blanket the Permian with sand mines and proppant locations. At the end of the year, there could be up to four operating mines in Texas run by the merged group. Jenniffer Deckard, president and CEO of the new entity, said frack sand customers are asking for more from suppliers in both scale and efficiencies at a time when demand is rapidly growing. Alfonso Olvera knows how


great the demand on frack sand supplies has been and continues to be. In 2010, Olvera was featured in Inc. Magazine’s Coolest College Startups of the Year story. In late 2017, proppant supplier and transload facility operator Solaris Oilfield Infrastructure purchased Olvera’s company Railtronix. The company designed and created by Olvera helps to provide operators and others with sophisticated information of the inventory levels and tracking of proppant. The information set provided from Railtronix gives updates on railcars, warehouse inventory, railcar originations, railcar maintenance

schedules, status of shipments and other data. Solaris, which is less than five years old as a company and went public in 2017, will combine the new data with its own software. Olvera has become the Senior Vice President of Technology with a goal of lowering the cost of delivered proppant to operators in the Eagle Ford, Permian and SCOOP/STACK plays by minimizing downtime and inefficiency along the route from the mine to the wellsite storage center.


SIGNED ON: Through its funding, the U.S. Department of Energy will advance its understanding of shale energy capture in multiple basins, including plays that are not currently drawing major activity. PHOTOS: U.S. DEPARTMENT OF ENERGY

DOE injects $30M into shale, oil research The Department of Energy’s Office of Fossil Energy will invest roughly $30 million into six shalerelated projects spread throughout the U.S. Through the Advanced Technology Solutions for Unconventional Oil and Gas Development funding opportunity offered by the DOE, the $30 million will be used to “address critical gaps in our understanding of reservoir behavior and optimal well-completion strategies, next-generation subsurface diagnostic technologies and advanced offshore technologies.” Project Breakdown:

The Next Generation of Well Cement

Hydraulic Fracture Test Site

Total Value: $1.8 million Scope: A proof-of-concept hexagonal boron-nitride cement composite will be made and tested offshore to prevent spills and leakages at extreme conditions. Participants: C-Crete Technologies Location: Stafford, Texas

Total Value: $20 million Scope: To evaluate well completion, design optimization and impacts of using gas-based technology in hydraulic fracturing at a test well in the Delaware Basin. Participants: The Institute of Gas Technology, Anadarko Production Co., Shell Exploration and Production Co. Location: Delaware Basin, Texas; Des Plaines, Illinois

Understanding The Tuscaloosa Marine Shale

Mitigating Gas Hydrate Deposition

Total Value: $9.6 million Scope: To perform better assessments of the reservoir and find new approaches for developing the play’s unique geology. Participants: University of Louisiana at Lafayette Location: Lafayette, Louisiana

Total Value: $1.8 million Scope: Validating robust pipeline coatings used to prevent deposits of hydrates in undersea oil pipelines. Participants: Colorado School of Mines Location: Golden, Colorado

Finding The Potential of New Stacked Plays Value: $11 million Scope: To investigate and characterize the resource potential of emerging unconventional reservoirs in the Nora gas field of southwest Virginia, part of the Lower Huron shale. Participants: Virginia Polytechnic Institute and State University Location: Blacksburg, Virginia

Eagle Ford Shale Lab Total Value: $10 million Scope: Develop new monitoring technology for initial stimulation and production periods for an unconventional reservoir well. Participants: Texas A&M Engineering Experiment Station Location: College Station, Texas



Some energy service firms are investing in growth

DEAL STRIKERS: With interest in oilfield services high in 2018, firms like Nine Energy have issued and completed the initial public offering process. PHOTO: NINE ENERGY


With oil prices stable heading into a new year and E&P budget forecasts similar or better to last year, some energy service firms are making their move. Keane Group, emboldened by supply and demand fundamentals in the well completions industry that it said are highly constructive, has put in an order for 150,000 new horsepower to add to its existing frack fleet. To end 2017, James Stewart, CEO of Keane, said “favorable conditions have continued to improve throughout the year (2017), and robust 2018 capital budgets announced by producers in recent weeks have amplified and validated the growing demand for our services,” which he added, “remain in excess of supply.” For $115 million, Keane is paying roughly $770 per horsepower for its new fleet. In addition, the company also purchased some wireline trucks. The new equipment will be deployed to the Delaware Basin and give the company more than 26 frack fleets

with roughly 800,000 hp concentrated on the Delaware. Liberty Energy Services and Nine Energy Services are also positive on the view others have of their entities. Each company has made a move to list on the New York Stock Exchange through an initial public offering. Four years after it united four different energy service firms in separate shale plays, Nine Energy intends to list under the ticker symbol “NINE” at a price of $20 to $23 per share. Roughly 7 million shares will be issued. The company currently consists of 8 former energy service firms and is active in every major U.S. shale play. Liberty Energy Services, the Denver-based completion expert that previously announced—and then retracted—plans to go public, will do so again with the ticker symbol “LBRT” at an IPO price of $14 to $16 per share. The company will issue nearly 11 million shares.


FRACK IMAGE: Fracture maps help to validate completion designs on every well with minimal operational risk and cost. PHOTO: REVEAL ENERGY SERVICES

DiverterSCAN tech effective at reconstructing results in real-time Fracture maps deployed on more than 2,000 stages in horizontal wells located in the U.S. or Canada have helped operators understand the effectiveness of diverters. The technology, known as DiverterSCAN, was developed by a Houston-based team of engineers and industry vets and reduces the knowledge acquisition time for producers from 90 days to near real-time. By attaching a simple pressure gauge to a wellhead, Reveal Energy’s team can use the pressure data to help model what is happening in a fracture cluster two-miles below the surface

and provide an accurate recreation through a unique model. More timely fracture initiation and effectiveness data can help operators continue or alter a pre-determined fracture plan and diverter distribution set-up. Diverter material, made from fibers, plastics or gels, is activated with pressure or temperature downhole and can help divert frack sand and fluids from overfilling a certain fracture point or cluster along a well bore. Operators are now using the diversion technique to help more evenly place fractures and enhance overall well stimulation.

Gauge of Success From the pressure gauge, Reveal can do more: FracSCAN technology accurately quantifies 3D fracture maps of half-length, height and asymmetry DepletionSCAN technology identifies the depletion boundary surrounding a parent well PerfSCAN technology enables an understanding of pumping rate effects on fluid distribution ProppantSCAN technology offers insight into the fluid system and pumping schedule






GO YOUR OWN WAY: Shale oil and gas producers are seeing investors move away from operations that emphasize production at all costs and toward more a more sound economic model that's sustainable over the long term. PHOTO: ABRAXAS




Are the days of achieving the highest possible IP rates over? Are investors now more interested in long-term well productivity than short-term payback? If so, can producers respond to what investors want?

By Patrick C. Miller

Not long ago, word of ever-increasing initial production rates from new wells drilled by operators in U.S. shale plays was music to investors’ ears. The higher the flow rate of crude, the faster the rate of return on their investment. But that standard of success began to lose much of its appeal in the latter half of 2017 and into early 2018 when investors began to push back against the business models of shale operators. They charged that profits from increased production were plowed back into new capital expenditures as a means of continuing to raise production, leading to negative cash flows and higher debt. It was, some claimed, an unsustainable model that wasn’t attractive to investors. This triggered a spate of stories in the business media about investors openly expressing dissatisfaction with the shale oil and gas industry for employing risky financial strategies and structures that rewarded growth rather than profit and investment returns, which is what investors now say they really want. “The winds, they do change,” proclaims Robert

Watson, CEO of San Antoniobased Abraxas Petroleum Corp., which has operations in the Bakken, Permian and Eagle Ford shale plays. “It’s certainly a new way of looking at the industry.” As Watson explains, “It went from the land grab issues in the early part of this decade where people were spending inordinate amounts of money on acreage and then not having the capital to develop it,” he says. “Investors really want companies to generate good economics which, for the most part, means living within your means, spending cash flow or below cash flow and using any free cash flow to do something good for the shareholders, whether it’s pay off debt, buy back shares or even pay a dividend.”

Still Pulling Hard Not all shale operators have abandoned the idea of achieving the highest IP rates possible on new wells, however. “It certainly depends on the company’s strategy,” says Jonathan Garret, research director for Lower 48 upstream with Wood Mackenzie in Houston. “Some companies—EOG for example—are interested in hav-



ing the well pay back as quickly as possible. Essentially everything, once it’s paid back, it’s just upside,” Garrett says. There’s less of a concern with actual estimated ultimate recoveries as opposed to payback—shortening that payback period as much as possible. That’s why oftentimes you’ll see EOG wells being pulled really hard like an open choke whereas, if you look at Hess in the Bakken, they’re more interested in maximizing value per drilled spacing unit.” Garrett notes that there are technical reasons why producers might want to avoid achieving the highest IP rates possible from a newly drilled well. “We can flow it as hard as we want and we’ll have a really strong, flashy initial production rate, but from a reservoir management standpoint, we could be pulling on that well so hard that we actually prematurely close up some of those fractures that we created. Or we start to pull proppant into our perforations and then that well would decline far faster than if we had a more optimized approach for managing that flow. “There’s a lot of levers that you can pull,” he continues. “You don’t necessarily want to pull that well so hard and so fast that you close up fracks, you get screen-outs or, in some cases we’ve seen, you start producing large amounts of water prematurely because you didn’t do a good job of managing production.” Still, Garrett believes that investors are less impressed with high IP rates than they once were. “I do think that there’s a shift taking place to a more sustainable, more fundamentally


FORMULA FOR SUCCESS: Abraxas Petroleum's rate of return from its Bakken operations has enabled the company to fund activities in the Delaware Basin of West Texas. PHOTO: ABRAXAS

sound model that’s not necessarily centered on mega-gains in production and growth at any cost,” he says.

The New View of Upstream E&Ps As Watson observes, “It’s just a new world view that the investors have toward the upstream E&P business. The way we’ve run Abraxas is that we’ve always been more concerned with rate of return than we have for growth for the sake of growth. That’s now playing out as the way investors really want to see E&P companies work.” Rystad Energy, an independent oil and gas consulting and business data firm head-


quartered in Oslo, Norway, with offices in America, has closely monitored changes in the U.S. shale oil and gas industry as it emerged from the low-oil-price environment. Artem Abramov, the company’s vice president for analysis, says that in 2017, oil and gas activity began to expand dramatically, which caused the demand for services to increase and service costs to rise. “Service costs started growing and well costs increased, but production didn’t increase that quickly because there’s a natural lag,” he explains. “Normally it takes between four to eight months from when you start drilling a new shale well to the moment when it starts contrib-

uting to production. In this kind of transition phase, it’s natural that cash flow balances degrade quite significantly.” As a result, Abramov says many producers posted negative cash balances during the first two quarters of 2017, which triggered an adverse reaction from investors, many of whom had also invested in shale prior to the oil price downturn “These investors never saw their money back because of the price collapse,” he continues. “That’s why investor sentiment shifted toward the direction of preferring the shale producers to work more on the cash flow balances. They’re no longer willing to see this kind of behavior

U.S. shale oil: average lateral length and proppant intesity by completion month Pounds per foot

Feet 9,000

Stimulated interval per well (LHS) Proppant per foot (RHS)









0 Jun-12












U.S. shale oil: average stage count and spacing by completion month Foot per stage

Number of stages 40







250 200


Frac stages per well (LHS) Stimulated interval per stage (RHS)


150 100

10 Jun-12













barred,” but that sentiment has changed. “When they sat back and saw what they were asking companies to do, they realized that they were just slitting their own throat,” he says. “What they were asking people to do, in a lot of cases, was forcing them to destroy capital— growth for the sake of growth and nothing else. Some were drilling uneconomic wells and buying PRODUCER'S PERSPECTIVE: uneconomic acreage.” Robert Watson, CEO of Abraxas Garrett says many shale Petroleum Corp., says investor expectations have changed. E&Ps are responding to investor PHOTO: ABRAXAS expectations. In the past, he says the focus was on drilling, deleverwhen shale producers just boost Growth at Any Cost? aging and then distribution. production fairly rapidly at the “In this new paradigm, it’s Watson says there was a cost of negative cash flow.” time when investors wanted the reverse,” he explains. “It’s disHowever, Abramov notes, producers “to grow no holds tribution, deleveraging and then “You have to expect negative cash flow when industry is in a growth mode because you invest more than you receive with an ambition to get high cash flows in the future.” As he further explains, this caused problems because the shale industry experienced a second wave of growth in 2017, and many shale investors didn’t receive returns during the first wave. Their preference now is for the industry to grow organically, funding its spending by altering cash flow, Abramov says.

drilling. There’s still a fear in the marketplace that the E&Ps will essentially get back to their old tricks again. They’ll start spending more than they’re taking in and keep a lid on prices.” Instead, Garrett believes producers should follow the cliché of value over volume. If a company needs more dollars to drill, he says it should sell something to raise the cash rather than borrowing it. “Investors want to see that companies are operating within their cash flow,” he says. “First and foremost—E&Ps borrowing money—I would say those days are over for now. That’s why you’re seeing some of these noncore asset sales. You saw Whiting



Permian Basin: decision breakeven oil prices for horizontal wells by completion quarter USD per barrel 120

Development phase of activity 100

Optimized well design

In-basin proppant penetration


Higher degree of vertical integration (E&Ps)



Median Tier 1 Tier 4


New activity in non-core Expiration of cheap service contracts Supply chain bottlenecks

Moderate cost escalation for new contracts 0

*Decision breakeven oil price accounts for well drilling and completion costs, LOEs, production taxes, royalties, transportation costs and price differentials in the calculation. A 10% discount rate is applied. Gas and NGL revenues are includes with 2 USD/mmbtu and 15 USD/bbl flat prices, respectively. SOURCE: NASWELLCUBE, RYSTAD ENERGY RESEARCH AND ANALYSIS

sell $500 million worth of their Fort Berthold acreage in the Bakken. You saw Halcon completely exit the Bakken. You saw SM Energy sell mostly out of the Powder River Basin. “People will either take that cash and pay down debt or use it to grow their development program organically as opposed to going out to the capital markets for that cash,” Garrett notes.

Pros and Cons of High-Grading Both Abramov and Garrett say investors are also watching declining production in certain areas of some shale plays. Rystad Energy, for example, conducted research on the accelerated decline rate in Eagle Ford production, a mature crude play. “From one side, it’s a normal

thing,” Abramov explains. “As a play matures, you need to move outside of the core acreage or the Tier I acreage. Normally you should expect some depletion or the reservoir. On some of these results, they were underperforming. Even with expectations of low performance, they were below expectations. “That’s why many investors pulled back from Eagle Ford and shifted over to younger, less-mature plays in the Permian Basin,” he adds. “In the Permian Basin, we had some issues with the skyrocketing gas-to-oil ratio. All these negative new trends generated some inputs. Investors were reacting very actively last year on any kind of negative news when it came to shale.” Garrett says Wood Mackenzie is closely monitoring how


long producers can continue to tap their core assets to maintain production. “Since the downturn, everyone has talked about highgrading,” he says. “Reporters and investment bankers will ask, ‘How are you guys getting through the downturn?’ And everyone says, ‘Well, we’re high grading.’ “At what point are you out of high-graded locations?” Garrett asks. “At what point do you have to step out from areas that aren’t so great, despite the fact that technology is still quite good? That’s why we’re starting to see some degradation in well performance in some of those top producing wells in 2017 as compared to 2016.” As Garrett sees it, one of the most important questions investors can ask is how many highgraded locations producers have left that can provide a good rate of

return? “You can only drill what you have,” he notes.

What Investors Really Want Watson says the model Abraxas employs relies on the company’s top-tier acreage in the Bakken to generate cash flow for its newer operations in the Delaware Basin. “Our Bakken operation is really generating great returns for us,” he explains. “That allows us to accelerate what we’re doing in west Texas. We’re just very lucky to be in a position that we can continue to drill within cash flow. To put it bluntly, the Dakota Access Pipeline gave us a great shot in the arm. The returns we’re seeing in the Bakken are as good or better than what we’re seeing in West Texas because of the pipeline.” Abramov expects changes in


Perspectives On The Future Operator: “We should want these businesses to be in a position where they can weather the downturns.” Robert Watson, Abraxas Petroleum Corp.

Analyst: “I do think that there’s a shift taking place to a more sustainable, more fundamentally sound model that’s not necessarily centered on mega-gains in production and growth at any cost.” Jonathan Garrett, Wood Mackenzie

Trend Tracker: “The operators were sort of promising to investors that they would try to encourage organic growth, that they would try to achieve cash flow neutrality and would not take any new debts.” Artem Abramov, Rystad Energy

2018 from last year when conference calls on second quarter results were mostly concerned with discussions about cash flow balances.

“The operators were sort of promising to investors that they would try to encourage organic growth, that they would try to achieve cash flow neutrality and

would not take any new debts,” he says. “We think some of the largest and most efficient operators will be able to achieve this in 2018—companies like Continental Resources, EOG or Pioneer. They all have an opportunity this year to adjust their activity to such a level that they will be able to fund their operations with operational cash flow and still accelerate production. They have already passed through the early expansion phase when they need a lot of financing.” Watson says a positive aspect of the oil price downturn was that it caused investors to look at how shale E&Ps were being forced to operate and conclude that it wasn’t a relevant way to run a business. “We should want these businesses to be in a position where

they can weather the downturns,” he says. “The only way to do that is to be a little more prudent with your balance sheet and make sure you’re generating the maximum rate of return on shareholders’ equity.” As Watson concludes, “Investors are looking with a tainted eye at people saying their wells are making a 100 percent rate of return—and then look at companywide rate of return on equity, which is sometimes negative. They want to know what’s happening. Why is there such a gap? They want to see that gap closed considerably.” Author: Patrick C. Miller Staff Writer, North American Shale magazine 701-738-4923

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MIDSTREAM THE LONG-VIEW: Producers in the SCOOP/STACK are in need of more midstream infrastructure, just like others in every major U.S. shale play.



Jeff Dorrow remembers office visits with oil producers to talk about the merits of a 700-mile pipeline starting in the Permian and terminating along the Texas Gulf Coast when West Texas Intermediate was priced at $26 and a minimum volume commitment to be on the pipeline was a dirty phrase. Dorrow, vice president of commercial operations for EPIC, a crude oil and natural gas liquids midstream operator, knew that when rising prices collided with new technology across the greater Permian Basin, contractual talks for long-haul pipeline commitments would turnout much differently. By the end of 2017, Dorrow and his team announced plans to build that 700-mile crude line—along with another NGL pipeline spanning more than 650-miles—after receiving ample shipper commitment from multiple E&Ps. “We knew just how good the rock was in the Permian,” Dorrow says, “and that it was just a matter of time.” Although Dorrow believes certain elements of the EPIC story are unique, he also knows that his team is only one part of a significant moment in the near-term time line of shale. As oil prices have gradually risen the past two years, activity levels across North America have either stabilized or risen. Production levels in most shale plays are now rising and in nearly every region, areas that were once adequately supplied with crude or gas or NGL gathering and takeaway capacity at a time of lower oil prices are now teetering toward—or are at—the point of gathering and takeaway undersupply. In May, Morningstar Commodity Research predicted what was to come for shale as oil prices, rig counts, laterals, completion stages and production numbers all continued to tick upwards. “If output continues to sure at current rates,” the company said in a research report to investors, “then even more takeaway capacity expansion will be needed as early as next year.” In mid-2017, headlines of new midstream projects located in the Permian, the DJ Basin and the Marcellus began, and have remained consistent. While Dorrow says the midstream gathering, takeaway and long-haul businesses are certainly competitive right now, he shares the same view offered by most of the headline makers of the past six months: Despite all of the newly announced projects, shale needs more infrastructure.

Bringing an EPIC Permian Project To Life

Increased oil and gas production across every major U.S. shale play has created strong demand for new or expanded infrastructure. How long will the trend continue?

By Luke Geiver

The EPIC team knew their pipeline projects would become successful when oil prices began to turn positive. With several other shale plays yet to regain economic viability when oil was in the $40 range, the Permian was holding steady. With production volumes stable in the Permian even under the run of skeleton crews, Dorrow and his team knew that once prices rose further or new technology capable of lowering breakeven costs was deployed on a greater



Midstream Opportunities Outside The Permian East Daley Capital, a Colorado-based energy asset research group, has quantified where and why midstream entities will succeed this year. The biggest reason midstream firms will thrive this year is not related to new technology, unique infrastructure designs or complex contracts. The main reason for optimism amongst midstream services is due to increased oil and gas production across the U.S. The Bakken will benefit from increased production, rising rig counts and the presence of more frack crews this year as opposed to last. Midstream entities will have ample opportunity for increasing services and man-hours. Companies like ONEOK, Kinder Morgan, Targa, Enbridge and Tallgrass will all see a better year this year due to an increase in production. Firms linked to shale gas—especially those in the Marcellus and Utica regions—will also benefit because of higher production volumes, according to East Daley. “The Marcellus will continue to be the best location for midstream companies exposed to natural gas,” said Justin Carlson, vice president and managing director of research. Other key findings from EDC’s 2018 Guidance Outlook indicate that: •Impending 2018 midstream financial guidance announcements could deviate significantly from market expectations. •Overall adjusted-EBITDA forecasts skew positive vs. current market consensus, indicating midstream sentiment may be too pessimistic. •Pessimistic midstream sentiment, higher production growth and natural gas contract risk are three major themes that will drive the midstreamsector in 2018.

scale, everyone would realize that the Permian was going to run out of crude takeaway capacity. Because the pipeline projects EPIC was proposing required more than a year of lead time, it still wasn’t easy to get producers to see the future at first. To help producers become part of the EPIC pipeline, the team created a unique offering. According to Dorrow, EPIC has created a co-op structure for the initial shippers signed up for the pipeline. Typically, shippers committed to a pipeline must pay deficiency payments when they fail to provide their committed volumes to the pipeline. However, because the EPIC line is set-up like a co-op, the initial folks who sign-up to ship crude will not be subject to deficiency payments, Dorrows says. “Our group believes in the Permian. We believe that at no point will our pipeline ever be less than a third full.” Those same initial shippers will also hold an equity stake in the pipeline. In addition to

Headlines Reveal The Need For Midstream Infrastructure Houston midstream companies form DJ Basin JV Noble Midstream Partners and Greenfield Midstream partnered on an acquisition of existing midstream assets in the DJ Basin. Their plan is to expand operations after completing the deal. Jeremy Ham, CEO of Greenfield noted that “the DJ Basin is one of the fastest growing plays in the country.”

ONEOK, Martin Midstream partner on $200M Delaware Basin pipeline Partnering on the 120-mile, 16-inch pipeline capable of moving 110,000 barrels of natural gas liquids per day puts the duo in a position “for significant future NGL volume growth,” according to Terry Spencer, president of ONEOK.

Permian producer Callon finds midstream asset management group Brazos Midstream will own and manage the midstream infrastructure assets of Callon Petroleum Co., a Permian pure-play E&P. Stephen Luskey, chief commercial officer of Brazos called the Permian “one of the most promising regions in the entire midstream services industry.”

New Stakeholder gathering system to serve Permian, San Andres Stakeholder Midstream is planning to build a crude and NGL gathering system for Permian producers working in the San Andres. Gaylon Gray, co-CEO at Stakeholder said, “operators are accelerating their drilling schedules.”

NuStar Energy to expand capacity of Permian crude system With oil throughput volumes approaching capacity on its existing Permian Basin crude system, NuStar has proposed adding another 70,000 barrels per day to its existing infrastructure.

ONEOK to build $1.4 billion Elk Creek pipeline to aid Bakken The Dakota Access Pipeline has solved all of the Bakken’s takeaway issues. With NGL and oil volumes once again pushing the capacities of existing infrastructure, ONEOK is planning to build a new $1.4 billion pipeline to move NGLs out of the region to an interconnect in Kansas.

Global energy trader eyes crude terminal project to move Texas shale

Vitol, the global energy and commodity trader that was the first to export U.S.-based shale oil to Europe, wants to do more. With Harvest Pipeline Co., Vitol intends to build a crude oil terminal at the Port of Corpus Christi to enhances its export abilities. 24 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2018

Phillips 66, Enbridge plan West Texas crude pipeline The combined effort could create the Gray Oak pipeline. The new infrastructure would be capable of moving 385,000 barrels of crude per day to terminals along the Texas Gulf Coast.

Magellan’s new proposal: connect Permian, Eagle Ford to Texas coast Based on shipper demand, Magellan Midstream believes it can build a gathering system to move Eagle Ford and Permian crude—up to 600,000 bpd—to the Port of Corpus Christi. The pipeline could be completed by the end of 2019.

Morgan Stanley, former ETP president partner on Midcontinent project Durando Midstream, now led by the former president of Energy Transfer Partners, has partnered with Morgan Stanley Energy Partners to build out more midstream infrastructure in the SCOOP/STACK where the team said there are “exceptional opportunities presented by nearby oil and gas producers.”

EVX Midstream announces Eagle Ford crude oil project In McMullen County, Texas, EVX will build a crude gathering line in conjunction with a large operator in the area. The company has already said it is looking for more projects in 2018.


the co-op structure, the EPIC team is not forcing shippers to use specific connection points at the pipeline’s terminal location near Corpus Christi. “The flexibility of the structure had a lot to do with getting people to sign up,” Dorrow says. In addition to the crude project, the company has also made plans to build a NGL line. As the Delaware play expands, the lighter the barrels are going to get, based on the volumes of NGLs present in the production streams there, Dorrow adds. “NGLs are really starting to become a constraint on production. No matter where it is, there is less than ideal amounts of infrastructure for production,” he says. “Continued expansion of these assets is necessary.” Author: Luke Geiver Editor, North American Shale magazine 701-738-4944 TRACKING TECH: In addition to new LACT units. cryogenic processing equipment is getting installed at a rapid pace in the Permian.


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Issue 1 2018 - North American Shale magazine  

MANAGING THE MOLECULE The North American Shale magazine is the #1 Source of news and information about shale energy business and communitie...

Issue 1 2018 - North American Shale magazine  

MANAGING THE MOLECULE The North American Shale magazine is the #1 Source of news and information about shale energy business and communitie...