SHALE Magazine Jan/Feb 2019

SHALE JAN/FEB 2019

THE OILFIELD HOUSING DILEMMA AND AN IDEAL SOLUTION 5 ENERGY ISSUES TO WATCH DURING THE 86TH TEXAS LEGISLATIVE SESSION

APACHE AND THE ALPINE HIGH:

MAGAZINE

UT AUSTIN STUDY

SUGGESTS NEW SHALE GAS DRILLING METHODS BOOST PRODUCTION POTENTIAL RAPIDLY ADVANCING TECHNOLOGIES ARE TRANSFORMING THE OIL INDUSTRY CONOCOPHILLIPS’ EAGLE FORD RELAY FOR LIFE COMMITTEE HOSTS 4TH ANNUAL REDFISH ROUND-UP

CHANGING THE WAY THE OIL FIELD WORKS

JANUARY/FEBRUARY 2019  SHALE MAGAZINE

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JANUARY/FEBRUARY 2019

CONTENTS SHALE UPDATE

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Shale Play Short Takes

FEATURE

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UT Austin Study Suggests New Shale Gas Drilling Methods Boost Production Potential

COVER STORY

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It took a team without preconceived notions to discover the potential of the Alpine High play. Using research, testing and a few drilled wells, Steve Keenan, Apache Corporation’s Senior Vice President for Worldwide Exploration, and his Apache team were able to conclude that this area would produce rich wet gas and oil. Now that production has begun in the area, Apache is seeing incredible results while enjoying a very low lease operating expense and taking the right steps to recycle natural resources and minimize their environmental impact.

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INDUSTRY

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Were You There at the Shale Revolution?

COVER AND TABLE OF CONTENTS PHOTOS COURTESY OF APACHE

INDUSTRY

BUSINESS

40 South Texas Energy & Economic Roundtable

58 Crude Oil Export Terminal on Harbor Island,

Honors Recipients of the 6th Annual Eagle Ford Excellence Awards

42 King Permian 44 Rapidly Advancing Technologies Are Transforming the Oil Industry

Texas Hits New Milestones

60 The Oil Field Housing Dilemma and an Ideal Solution

LIFESTYLE

POLICY

64 Running on Empty?

48 Why Shale Companies Shouldn’t Sit Out the

SOCIAL

50 Effects of the Midterms on the Oil & Gas Industry 52 5 Energy Issues to Watch During the 86th

66 SAPA Hosts 7th Annual Midstream Classic 67 STEER Eagle Ford Excellence Awards

54 How the Movies Drive Public Policy

68 ConocoPhillips’ Eagle Ford Relay for Life

War on Coal

Texas Legislative Session

Reception

Committee Hosts 4th Annual Redfish Round-Up

POLICY

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The Carbon Tax — and Reasons to Oppose It

BUSINESS

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Commodity Hedging: Lessons Learned by Early Adopters of New Hedge Accounting Rules

LIFESTYLE

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Keeping Your New Year’s Resolution JANUARY/FEBRUARY 2019  SHALE MAGAZINE

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VOLUME 6 ISSUE 1 • JANUARY/FEBRUARY 2019

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PUBLISHER / CEO CHIEF FINANCIAL OFFICER Deana Andrews CHIEF OPERATING OFFICER & EDITOR-IN-CHIEF Lauren Guerra

Providing energy for the world while staying committed to our values.

Finding and producing the oil and natural gas the world needs is what we do. And our commitment to our SPIRIT Values—Safety, People, Integrity, Responsibility, Innovation and Teamwork— is how we do it. That includes caring about the environment and the communities where we live and work – now and into the future. © ConocoPhillips Company. 2017. All rights reserved.

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PUBLISHER’S NOTE

HAPPY 2019!

As we start this new year we look forward to new opportunities for growth and success. The U.S. oil and gas industry has seen a resurgence in recent months and 2019 has the promise of more growth for the industry. Recent EIA natural gas projections have steadily risen from month to month and crude production in 2018 far exceeded projections; however, volatility in the market seems to always be on the horizon. We will continue to watch and share the critical topics affecting our domestic energy industry, such as proposed legislation, infrastructure necessities and improvements, global demand and supply, to name a few.

Looking forward into 2019, SHALE Magazine and In the Oil Patch look forward to bringing you the latest energy news and topics for discussion. If you haven’t done so, listen to In the Oil Patch airing throughout most

of Texas and areas of New Mexico and Louisiana, streaming on the iHeart Radio app and housed online on Soundcloud, iTunes and Stitcher. We welcome knowledgeable oil and gas energy professionals to cover trends, complications, services, opportunities, legislation and more!

We have also added new events and programs to our calendar this year with strategic and exciting partners! Keep an eye on our email newsletter (sign up on shalemag. com) and our social media accounts on Facebook, Twitter and LinkedIn to stay informed on our upcoming schedule.

Thank you for starting another year learning about oil and gas, business, lifestyle and policy topics with SHALE Magazine. We look forward to continuing to serve you and sharing the economic growth and benefits of the energy industry.

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JANUARY/FEBRUARY 2019  SHALE MAGAZINE

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SHALE UPDATE

SHALE PLAY SHORT TAKES By: David Blackmon

Bakken Shale – North Dakota/Montana

Citing strong success in their 2018 drilling and production efforts, both Marathon and Hess announced in December that they plan to expand their positions and activities in the region during 2019. Hess said it would expand its Bakken drilling program from four to six active rigs and drill as many as 170 new Bakken wells in the coming year. Marathon CEO Lee Tillman cited strong results from a four-well test in the company’s Ajax area of Dunn County, and said the company plans to expand on those results in its core acreage during 2019.

Meanwhile, ConocoPhillips announced that it plans to dedicate over half of its planned $6.1 billion capital drilling budget for 2019 to projects in the Bakken, Eagle Ford and Permian Basin.

The company said it plans to allocate an 11-rig drilling program between the three basins.

Overall, the Bakken continued to set record daily production records for both crude oil and natural gas, even as the region’s rig count remained essentially static throughout the fourth quarter.

Denver/Julesberg (DJ) Basin - Colorado

The Colorado oil and gas industry successfully beat back Prop. 112, a ballot proposition that would have implemented a vaguely-defined 2,500’ statewide setback rule. After a long and expensive campaign, voter in the state strongly rejected the proposition by a 56-44 margin.

However, longtime industry critic and opponent Jared Polis was elected to become the state’s next governor in the same election, making it likely that efforts to diminish the industry’s license to operate in the state will continue.

Despite all the political noise, the overall rig count for the basin moved slightly higher and production of both oil and natural gas continued to set records throughout the fourth quarter of 2018.

Permian Basin – Texas/New Mexico

· · ·

46.3 billion barrels of crude oil; 20 billion barrels of natural gas liquids; and 281 trillion cubic feet of natural gas.

The U.S. Department of Transportation awarded a $50 million grant in early December to the Texas Department of Transportation (TxDOT) to help pay for improvements to the highway system in the Permian region. The grant would go toward projects designed to improve highway safety and connectivity in the booming region.

“Our rural communities depend on roads like SH 158 and SH 137 to keep us connected,” Congressman Mike Conaway said. “Critical infrastructure improvements are especially necessary as the Permian Basin’s energy sector continues to boom, making these roads busier than before.”

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Eagle Ford Shale – Texas

Despite the crude oil price collapse, the Eagle Ford rig count remained steady in the ~80 range, and production of both oil and natural gas continued to trend upward throughout the fourth quarter of 2018. Overall oil production reached its highest point since late 2015, while natural gas production in the play approached record levels as the year came to an end.

Oct. 30, Chesapeake announced it would acquire Wildhorse Resource Development Corp. in an all-stock deal worth almost $4 billion. The acquisition includes roughly 420,000 net acreage position along with significant existing production from both the Eagle Ford and Austin Chalk formations.

In good news for Eagle Ford gas producers, Cheniere Energy opened the first train in its Corpus Christi LNG export facility in December, shipping out its first load Dec. 11.

ARUNAS/BIGSTOCK.COM

The USGS, in an updated assessment released in early December, declared the Wolfcamp Shale/Bone Spring formation to be the largest continuous oil and gas resource it has ever estimated. The new assessment estimates the Wolfcamp Shale contains the following amazing volumes of technically recoverable resource:

Marcellus Shale – Pennsylvania/West Virginia/Ohio

A study compiled and released by Energy In Depth in November shows that natural gas production from the Marcellus/Utica Shale plays has enabled the construction of over 26,000 megawatts of electric generation capacity in the Ohio/Pennsylvania/West Virginia region. This represents more than $25 billion in capital investment and the creation of almost 18,000 jobs during that time.

In December, the U.S. Department of Transportation awarded the city of Hannibal, Ohio $20 million to invest in improvements to the Long Ridge Energy Terminal. The funds will go toward improvements and expansion of the Terminal’s rail and pipeline energy loading facility. The Long Ridge Terminal has three primary lines of business that are operational or in development, including power generation, natural gas liquids storage, and transloading and frac sand transloading.

Additionally, the terminal has two barge docks on the Ohio River with a docking capacity of up to 48 barges.

The Appalachia region’s rig count and natural gas production levels moved upward in the fourth quarter of 2018, as the NYMEX price moved well above $4 per Mmbtu due to lower-than-normal storage levels and cold early winter weather.

Haynesville/Bossier Play – Louisiana/East Texas

QEP Resources announced in late November that it would sell its acreage and production in the Haynesville/Bossier region to Aetheon III, a private equity firm based in Dallas, for $735 million.

This sale advances QEP’s strategy to become a pure Permian Basin producer, and follows a series of other divestitures of non-Permian assets by the company during 2018.

Continuing to build commitments on its planned Driftwood LNG Facility in Calcasieu Parrish, Telurian, Inc. reached a memorandum of understanding with Vitol to supply 1.5 million metric tons per year (mmty) of liquefied natural gas for at least 15 years.

The Driftwood Facility, planned for opening in 2023, would source the bulk of its natural gas supply from the Haynesville/Bossier play area.

Despite the run-up in natural gas prices, the rig country for this region remained basically static throughout the fourth quarter of 2018.

SCOOP/STACK Play – Oklahoma

Thanks largely to a rebounding oil and gas industry — which provides about 25 percent of the annual revenue taken by the state government — the Oklahoma state Legislature will enjoy a small revenue surplus when it convenes in January, the first time that has been the case since 2013.

However, ongoing pressures from the public to restore some of the major spending cuts to education and healthcare that have taken place over the past decade will still have policymakers looking for ways to raise revenues in 2019.

The industry is planning to mount an effort to tie the state’s oil and gas production taxes to the state’s rainy day fund, similar to what is done in Texas. Such a change would provide a certain and steady stream of funding to the fund, and also serve to make members of the Legislature more aware of the industry’s contributions to the state’s economy.

About the author: David Blackmon is the Editor of SHALE Oil & Gas Business Magazine. He previously spent 37 years in the oil and natural gas industry in a variety of roles — the last 22 years engaging in public policy issues at the state and national levels. Contact David Blackmon at david.blackmon@shalemag.com.

JANUARY/FEBRUARY 2019  SHALE MAGAZINE

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 FEATURE

UT Austin Study Suggests New Shale Gas Drilling Methods Boost Production Potential Special to SHALE

A

new analysis of the nation’s major shale gas plays has revealed that the amount of natural gas that can be technically recovered from future well locations has increased by 20 percent compared with an estimate made about five years ago, even while active drilling has depleted the resource. Researchers attributed the increase largely to new drilling practices.

The analysis, conducted by the University of Texas at Austin’s Bureau of Economic Geology, looked at the production capabilities and the total gas in place of four of the country’s top natural gas fields: the Barnett, Fayetteville, Haynesville and Marcellus plays. It is an update of a similar study the bureau conducted from 2011 to 2013 that was the most comprehensive report on unconventional resources publicly available at the time.

Svetlana Ikonnikova, the principal investigator of the study and a research scientist at the bureau, said that developments in drilling technologies, market conditions, cost structures and improvement in geological characterization prompted the research team to update the assessment.

“Five years ago, we hardly thought of multilayer or stacked well drilling, or of quadrupling lateral well length,” she said, referring to drilling innovations that have expanded production.

The team used 3D modeling and advanced data analytics to enhance the understanding of: • Geologic reservoir characterization; • Individual well decline and recovery analysis; • Individual well geology and engineering improvements that increase productivity; and • Economically recoverable resource assessment.

The researchers found that future wells in the four shale gas plays can technically recover about 780 trillion cubic feet (Tcf) of natural gas, in addition to about 110 Tcf of gas already recovered by wells drilled by the end 2017. (“Technically recoverable” gas can be produced using currently available technology and indus-

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try practices.) That estimate was about 650 Tcf in the previous study. The United States consumed about 27 Tcf of natural gas in 2017, so the new estimate suggests the addition of about five years of domestic consumption.

The projected increase comes largely from new drilling practices that increase recovery, reduce per-unit cost and allow companies to continue drilling even during periods of low oil or natural gas prices. These new methods include stacked drilling, which accesses gas by expanding the vertical reach of fracturing. Drilling wells closer together and installing wells that can

run horizontally for about two miles has further improved recovery.

Researchers also calculated the total gas held in the four shale plays to be 3,100 Tcf. Katie Smye, co-principal investigator of the study and bureau geologist, said it’s important to understand the amount of gas-in-place to verify what proportion has been recovered, compare results across plays and determine where additional wells can be drilled and efficiency can be improved.

For instance, in the Haynesville and Marcellus plays, only 2 to 3 percent of the total gas-in-place is expected to

be recovered by wells drilled to date, Smye said. This percentage is influenced by a number of factors including technology, economics and the amount of the play available for drilling.

“The Marcellus contributes the majority of the gas-in-place due to its size and resource density,” Smye said. “However, resource density in the Haynesville is comparable to the best areas in the Marcellus.”

In the study, for the base case scenario, researchers assumed a natural gas price of $3.25 per million British thermal units (MMBtu) and an oil price of $65 a barrel. Despite being lower than price assumptions from the past analysis, these prices yielded a 20 percent increase in natural gas supply compared with the base case scenario in the original study. Researchers also ran scenarios at lower prices, using a natural gas price of $2.75 per MMBtu and an oil price of $50 a barrel, and at higher prices, using $4.50 per MMBtu and $80 a barrel. These scenarios are in line with the range of projections by the Energy Information Administration until about 2030.

Production outlook projections for major shale gas plays from the 2012 and 2017 analyses with varying assumptions on energy prices.

Even with the boost in production, the analysis shows production will plateau around 2030, barring a more dramatic price increase or boost in technology.

Researchers said this analysis emphasized the need to better understand cross-play dynamics in terms of capital allocation and investment decision making. Sharp declines in drilling and production from the Barnett and Fayetteville Shales imply that these plays have matured, although they may simply be less attractive in terms of return on investment relative to other plays, especially those with more liquids production. The bureau’s Tight Oil Resource Assessment consortium has been focusing on the Permian Basin, which has been attracting the most investment in recent years.

The bureau is part of the UT Jackson School of Geosciences and is the State Geological Survey of Texas. Its 15-member interdisciplinary Shale Production and Reserves Study team integrates engineering, geology and economics. Peer-reviewed studies of the report’s technical analyses will be published in the coming months. The study was funded by the U.S. Department of Energy National Energy Technology Laboratory.

The University of Texas at Austin is committed to transparency and disclosure of all potential conflicts of interest of its researchers. All of the shale gas play research team members have filed required disclosures. Co-Principal Investigator Scott Tinker sits on the Shell Science Council and serves on government boards and commissions dealing in energy issues. Team members Robin Dommisse and Bill Fisher hold stock in oil and gas companies.

Dommisse, Scott Hamlin and Ken Medlock occasionally consult for oil and gas companies and/or for government entities on energy topics. Michael Marder is currently receiving funding from Shell through the Shell-UT Unconventional Research program.

The university is not aware of potential conflicts of interest for any of the other team members. The Jackson School itself receives annual income from royalties on shale gas reserves donated to the university.

For more information: Contact Mark Blount, Bureau of Economic Geology at 512-471-1509.

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cover story

Apache and the

Alpine High: CHANGING THE WAY THE OIL FIELD WORKS

PHOTOS COURTESY OF SHALE

By: David Blackmon

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“My story starts in 1956 when I was one year old, and M. King Hubbard made a prediction about ‘peak oil.’ He said somewhere around 1970 U.S. production would peak at about 10 million barrels per day and then it would fall off over the next 25-30 years to about 4 million bpd, and the U.S. would be completely dependent on foreign oil.”

Steve Keenan is, to put it mildly, a high-energy individual. Apache Corporation’s Senior Vice President for Worldwide Exploration, he is a 40-year veteran of the oil and gas industry, a geoscientist who has seen it all and done most of it. As we start our interview last November, he is seated at his desk at the company’s offices on the western edge of San Antonio, trying to describe to this writer the series of events that led to the discovery of the massive Alpine High resource in the Delaware Basin of far West Texas. As we will soon see, it was a discovery that required a “cradle to grave” kind of approach, and true to form, Keenan was starting his explanation at the cradle.

“That’s important because people really believed what Hubbard was saying,” he continues. “And the amazing thing to me is that he was practically correct — oil did peak at 10 million bpd around 1970, and it did fall and we were disproportionally dependent on imports for a long time.

But it didn’t fall in the logistic distribution curve that he predicted.” To emphasize this point, Keenan pulls up a line graph of the last 45 years of U.S. oil production onto his computer display. “If you’ll notice, there are changes in the slope of the curve, and it is those changes in slope that are the story of my career.

“Up until about 2005 the industry was involved in what we used to just

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SHALE MAGAZINE  JANUARY/FEBRUARY 2019

call ‘exploration’ but which we now refer to as ‘conventional exploration,’ since we now have exploration in ‘unconventional’ or ‘resource’ plays,” he says, describing the different terms used to differentiate the sand and limestone formations from which almost all oil and gas was extracted during the industry’s first 150 years and the tight sands, coal and shale formations that have produced most of it in the U.S. during the course of the 21st century.

“All these changes in slope are important because what they represent are the introduction of new ideas, really creative and adaptive thinking, so that we could slow or arrest that decline. Or some kind of new engineering capability or new technology that didn’t exist previously. But mainly it was creative thinking.”

He points to a specific spot on the graph (see chart on page 26). “This is where I come in. I actually first got hired in 1978, after the Arab oil embargo and the discovery at Prudhoe Bay. Like a lot of people my age with my credentials (he has an MS degree, undergrad in geology with a master’s thesis topic pertaining to spectral analysis of seismic signals – most of his contemporary MS colleagues studying Geophysics were writing about the evaluation of gravity or magnetic data) I began my career working in frontier areas where all the big hopes were. The main suspects at that time were in Alaska and California.”

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Indeed, the progression of Keenan’s career, which, before coming to Apache Corp. in June 2014 included stops at Cities Service Oil Company, SOHIO Petroleum, BP, Marathon and EOG Resources, reads basically as compendium of some of the largest major oil discoveries of the last 40 years.

As Keenan notes, the early years of his career, spent at Cities Service, were spent exploring for oil on the North Slope of Alaska and in California, where he worked on the huge Milne Point field 35 miles west of Prudhoe Bay, and also on the Point Arguello field in the Pacific Ocean waters offshore California, just north of Santa Barbara.

While working as Regional Project Manager and as Chief Geophysicist at a domestic independent oil company from 1985 through 1997, Keenan gained a wealth of international experience, exploring for oil faraway places like Norway, Oman, Spain, Argentina and Egypt. Keenan moved over to Marathon Oil in 1997, and spent the next five years working on assets in the deep waters of the Gulf of Mexico and Angola.

Keenan next moved to become Division Exploration Manager of the South Texas operations for EOG Resources. There, he led the company’s highly-successful development of the Middle Wilcox tight sands assets in South Texas. Then, in 2008, his team made a major new discovery when it drilled, hydraulically fractured and completed the first successful horizontal well in the giant Eagle Ford Shale formation.

Wait, you’re thinking, didn’t Petrohawk drill that first successful Eagle Ford well?

That is the common story, and, to be fair, Petrohawk was the first company to publicly announce a successful Eagle Ford completion, in October of 2008.

In 2008, EOG made a strategic decision to add more liquids to its portfolio of assets as the natural gas market in the U.S. began to become over-supplied. Keenan and his team were directed by then-EOG CEO Mark Papa at that time to go find more oil, even though it had been highly successful in drilling for the natural gas in the Wilcox formation for many years by then.

In the summer of that year, Keenan’s team which included current Apache employees Chester Pieprzica, Roberto Alaniz and Navneet Behl, drilled the Tully C. Gardner #94H, a 4,200’ lateral well in Webb County, Texas, which is in the wet gas window of the Eagle Ford Shale, and brought it online in August. So, why does the Petrohawk well continue to get the credit? Because EOG made the strategic decision to not make an announcement of its new discovery.

“At EOG, we decided that there was no value to us in telling people that,” Keenan says with a chuckle. “We convinced our management to move over to Karnes County (to the east) [to start up an expanded leasing program]. We then moved our rig over into Karnes County and drilled what was the first crude oil well in the Eagle Ford Shale.

“If you think about it, what business advantage would we [EOG] have to tell anybody about that first well?” Keenan says, noting that doing so would only serve to bring new competitors into the play area. “When we drilled that first well, we had about 15,000 acres under lease in the Eagle Ford,” he notes. In the coming months, EOG’s acreage position ultimately grew to more than 575,000 acres, and the company became one of the handful of biggest players in the Eagle Ford drilling boom that lasted through 2014, and is now seeing something of a revival today.

Shortly after Papa retired from EOG, Keenan made the decision to move along

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as well, this time coming into Apache Corporation, initially as its Managing Director of North American Unconventional Resources. From there he has quickly advanced to his current position as Senior Vice President for Worldwide Exploration.

The discovery of the Alpine High resource was no doubt a big factor in his rapid advancement within the organization.

A Resource with a Bad Reputation The Alpine High has always been there — well, it’s been there for several hundred million years, anyway — just waiting for the right team of scientists to come along and find it. As things turned out, it took a team staffed by people with little or no prior experience in the Permian/Delaware Basin to make the discovery.

I first interviewed Keenan in August, 2016, shortly after Apache had made the initial announcement of the major new discovery, for a piece published on Forbes.com. During that interview, Keenan pointed to his team’s lack of previous experience in the region as a major factor in Apache’s ability to discover the Alpine High, meanwhile many companies that had come before had passed it by. As Keenan put it, his team’s lack of preconceived notions about the nature of the rock beneath the ground allowed it to “contravene the pre-existing dogma” about the play, and evaluate it through non-biased eyes.

Companies have explored for oil and gas in the general area for decades.

Most previous exploration took place on the Northern and Eastern flanks of Apache’s current acreage position, although some early wells were drilled within it in the early 2000’s. At that time, companies were testing the Barnett/Woodford extension to see if it might be as productive as the Northeastern extent of the formation in the Dallas/Fort Worth area had been.

Those efforts turned out to be only modestly successful, and preconceived notions about the reservoir quality and structural history of the area that now constitute the core of Apache’s acreage precluded any further serious testing in that portion of the play from taking place.

The drilling of hundreds of previous wells in the general area since the 1970s without much success had led producers in the area to develop a set of assumptions about the resource. The Alpine High had developed a reputation, it seems, that caused explorers with long experience in the region to shy away from it in favor of other prospective areas they believed were more likely to yield significant resource.

When Keenan and his crew put fresh eyes on the available seismic and other information, and gained management approval to begin drilling test wells, they soon developed an entirely different set of beliefs where the Alpine High was concerned. “In our case, having no preconceived notions, we were very interested in the source interval of the Woodford Barnett and the Pennsylvanian,” he told me in 2016. “That is not the play currently being made in the Delaware and Permian basins. We spent a lot of time and money looking at our own proprietary 3D seismic, drilled a couple of wells and systematically tested our concepts, including thermal maturity, minerology and history of movement. We concluded Alpine High was a play in which these major factors are favorable.”

Where the industry dogma dictated that the reservoir quality had very high clay content and would thus be difficult to effectively fracture, the Apache team concluded that the clay content in the key underground formations was actually quite low. Where the industry believed the structural history of the area was uplifted and highly complex, Keenan’s team concluded it was actually relatively stable. Where the dogma presumed that

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the underlying thermal maturity dictated that this would be, if anything, a dry gas play, the Apache team concluded it would in fact produce very rich wet gas and oil.

“There is a big difference between conventional and unconventional reservoirs, and that’s what keeps some companies from making discoveries,” Keenan continued in our November interview, “Because they don’t actually recognize the difference even though they know the language.

“The main thing to understand is that unconventional reservoirs are dynamic systems, as opposed to conventional reservoir systems, which are static. These extremely complex reservoirs require the right systems and understanding to accurately map them. That’s how we understood that the Alpine High was a major, major play.

“This is all about system permeability, because it has a macro, micro and nano scale. It’s not that hard — almost anyone can do it as long as they look at it the right way.” People had been looking at the Alpine High the wrong way for more than 40 years. Keenan’s team was the first to come along and change that.

Moving from Delineation to Development When I ask Keenan to talk about the thickness — the vertical extent — of the Alpine High play, he responds with a gleam in his eye: “Well, I’m about to show you — it’s one of my favorite subjects.”

“What makes the Alpine High difficult is the dimensional complexity.

We have to do not only geographic delineation, but also stratigraphic delineation,” he says, meaning that Apache must drill test wells in order to determine not just the boundaries of the surface extent of the play area, but also to measure the overall vertical extent and number of formations with commercial production potential. “Then comes development.”

“So, this is our timeline,” he says, pointing to another graph on the screen. “It took about two years (starting in 2014) to do geographic delineation, and more or less the same amount of time to do the stratigraphic delineation. Right now, we are transitioning from delineation to the development phase.” Through its delineation process, Apache has determined that, in some parts of the play, the vertical extent of commercial formations stacked atop one another reaches a thickness of up to 5,500 feet.

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Alpine High Development Timeline In more than one of the test wells, Keenan says, the company was able to identify as many as 13 separate producing intervals. Pulling up another illustration, he points out, “Three producing zones in the Woodford, three in the Barnett, one in the Pennsylvanian, four in the Wolfcamp and two in the Bone Springs. That’s 13,” he notes with a grin.

Keenan points out that there had been some impatience from Wall Street to see the project move to the point of development, “but there’s a dimensional complexity here that can’t be overstated. Everybody says ‘so what’s taking so long?’ and I have to remind them that the Eagle Ford, which took three years to delineate, was just 90 to 220 feet thick, and it’s just one interval. Here we have 5,500 feet and 13 intervals.”

With so many producing intervals, the question of what order do you produce them in inevitably comes up. “You start deep and work your way up,” Keenan says. “You produce your deeper, source interval first, paying for all your necessary infrastructure as you’re doing that, and then you move up to the more shallow intervals. If you try to produce the shallow first, you lose the deep.” Makes sense.

It may have taken four years for Apache to get to the point of fully moving into the development phase, but the production numbers coming out of the Alpine High are already quite impressive. Alpine High production in the third quarter averaged 49,000 barrel of oil equivalent (BOE) per day, a 52 percent increase over the second quarter of 2018.

This obviously represents a tremendous rate of growth over a relatively short period of time. The company’s ability to control costs at the same time is equally impressive: “At the same time our lease operating expense has gone from $6.55 [a] barrel down to $3.00,” Keenan says.

“A lot of people say that if they have an oil play and you have a wet gas play, they have the superior asset. But we look at value optimization and capital efficiency quotient. What matters to us is the recycle ratio — what are our margins, and what was our finding cost? The main metric that justifies everything we do here is the quotient of margins and finding costs, and we have some of the lowest finding costs in the entire basin.”

As of our November interview, Apache had drilled right at 180 total wells in the Alpine High, and had eight active rigs in its drilling program. Thanks to its careful and systematic process of geographic and stratigraphic delineation and targeted initial drilling, Apache now believes it has a firm handle on the full extent of hydrocarbons in place within the Alpine High play.

Keenan points out that getting to this point was crucial for the next phase of the project, which is

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It may have taken four years for Apache to get to the point of fully moving into the development phase, but the production numbers coming out of the Alpine High are already quite impressive

the design and building-out of the processing and transportation infrastructure that will be needed to break the raw gas stream down into its components and get the production to market. “The reason we had to have to have that high degree of confidence is the processing and transportation infrastructure for an area in which you start from zero is extremely capital intensive. In order for us to know how to size everything, and how to develop it, we have to first know what’s in place.”

He sits back in his chair and smiles. “So, what have I been doing on my summer vacation since the last time we talked?” he points to the screen, “I’ve been trying to figure all of this out.”

From the looks of things, he seems to have been pretty successful.

A Proactive Approach to Water and the Environment “The biggest problem and operating expense for all the operators east of us is water – handling, transporting and disposing of it.”

Keenan is pointing to another graph he has pulled up on his computer, this one comparing the water cut in an Alpine High well to several wells outside of the Alpine High delineated field.

I had just asked him to talk about the ways

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in which Apache is handling its water issues in this desert region of Texas, and he was quick to point out that while the Alpine High production is rich in liquids content, those liquids are mainly liquid hydrocarbons — the water content is actually very low compared to other plays in the basin. As Keenan puts it, “We have a hydrocarbon-wet system, not a water-wet system, and our initial water load just drops right off [after the well comes on-line].

“We have our own water transfer system within our 336,000 acres, so we are recycling almost all of the produced water anyway.” He points out that this lack of produced water is a key factor in the company’s ability to get its per-barrel lease operating expense to such a low level.

Still, water-related issues are always going to be a concern to the local public in any freshwater-poor region of the country, and activists immediately began ringing alarm bells in the area after Apache went public with the Alpine High discovery in the summer of 2016. Among other things, allegations were raised that Apache’s operations would deplete and/or contaminate the region’s underground freshwater aquifers, and that they would damage the huge swimming pool at nearby Balmorhea State Park, a local tourist attraction that is fed by naturally-occurring springs.

To mitigate these concerns and to ensure the safety of its own operations, Apache has from the outset of its operation worked closely with local officials, academics and regulators to ensure that any impacts from its operations to the region’s environment are minimized.

Within a few weeks of announcing the discovery in 2016, Apache had entered into a partnership with The University of Texas at Arlington (UTA) to conduct a baseline groundwater study.

In addition to that, Castlen Kennedy, the company’s Vice President of Public Affairs, reminded me of other measures Apache has taken to avoid impacts to fresh groundwater aquifers in the area: “To meet our water needs, we are recycling our own produced water and are supplementing it with brackish water resources instead of freshwater. We have already built five water recycling systems in the Alpine High region and have developed brackish water sources from the non-potable Rustler Aquifer.

In Alpine High, our goal is to source 100 percent of the water needed to supplement our recycled produced water program from nonpotable water sources.”

She also pointed out that the company’s efforts to ensure minimal environmental impacts is not focused only on water, noting that Apache has also engaged with experts to conduct “extensive baseline research including air, water and soil studies and cultural, historical and surface impact assessments of the region.” She noted that Apache committed very early on not to drill wells “under Balmorhea State Park, the San Solomon Springs nor the town of Balmorhea,” although the company owns lease holdings in those areas.

Not only have the company’s operations done no damage to the Balmorhea Springs pool, when the pool suffered major structural damage due to ageing concrete and erosion in May 2018, Apache stepped up to the plate in a big way to help fund the repairs. The pool was built in the mid-1930s by the Civilian Conservation Corps, and some of the concrete wall that supports the main diving board collapsed during annual cleaning operations that take place each May, prior to opening the pool for the summer. Working in partnership with the Texas Parks and Wildlife Foundation, the company committed the first $1 million in a joint effort to raise the $2 million needed fix the damage.

Actions like this, and many others the company has taken over the past two years, have helped calm the initial fears from some in the area, and denied local activists a major audience. The reality that the company’s operations have had no detrimental impact to the region’s water resources presents a case study for safe and responsible operations in watersensitive areas of the country.

Meeting the Midstream Challenge As most are now aware, getting new oil and gas production out of the Permian Basin has become a challenge in recent months as the existing system of pipelines has become fully subscribed. It should come as no surprise that

this lack of pre-existing infrastructure was something Keenan and his team were fully aware of. As they went through the field delineation process, the team carefully evaluated and developed a detailed plan of action for how to address this issue.

“We have 150 miles of 30-inch and 24-inch trunkline built out, we have five refrigeration gas-processing plants, and we are in the process of building three cryogenic plants,” Keenan begins, “and we have firm commitments in place to move our oil, gas and NGLs out of the basin.”

As if to emphasize the point about planning and preparedness, just a few days prior to our November interview, Apache closed on a partnership deal with Kayne Anderson Acquisition Corp. to create Altus Midstream. Altus will own essentially all of Apache’s existent midstream infrastructure in the play, and will manage the build-out of the processing and gathering systems needed to ultimately eliminate the need for trucking and carry all the Alpine High production to mainline delivery points.

In this deal, Apache retains ownership of 79 percent of Altus, which will also manage options to purchase equity interests in five top-tier, Permian Basin mainline pipeline projects, which will ultimately facilitate the movement the company’s production to ultimate markets.

With that, Keenan says it’s time to meet Navneet Behl, Apache’s dynamic Vice President of Unconventional Operations for North America.

Behl and Keenan are on the same floor, but in offices in diametricallyopposite corners, so our walk transits the full length and breadth of the floor.

On this journey across the building, no visitor to the Apache offices could help but be struck by what can only be described as the phenomenal level of teamwork taking place among the staff. Everywhere you look you find people huddled up in conference rooms, break rooms and individual offices. It quickly becomes obvious that these are not people

To mitigate concerns and to ensure the safety of its own operations, Apache has from the outset of its operation worked closely with local officials, academics and regulators to ensure that any impacts from its operations to the region’s environment are minimized

engaged in idle chat about their kids or last night’s TV shows — it is groups of co-workers from all disciplines collaborating in their efforts to find ways to solve problems and lower costs.

In talking with Keenan and Behl, the motivations behind all of this collaboration become readily apparent. Describing Behl as dynamic is, in fact, an understatement. This is a man who, in addition to working overtime each week in his job at Apache, flies out to MIT and back on weekends to participate in that university’s executive MBA program. It takes about 30 seconds of listening to him talk about his work and his team to realize that, just like Keenan, this is a guy who loves what he does, and that love for and dedication to the work is obviously contagious throughout the Apache offices.

Behl starts our discussion by demonstrating how he and others are able to monitor operations at Alpine High — well over 300 miles to the West — from the office in real time through the use of drone technology.

The first footage he pulls up is an overview of the location where the three cryogenic processing plants are being constructed.

“This is one of the cryo plants here,” he says, pointing to the screen, where the drone is giving us a full shot of the construction area for the three plants, “and this is where all the fluid comes in, this is the stabilizer rack. So, you have one, two, three plants under construction, and we have room for three more.”

I asked next if the company had been impacted by the Trump administration’s tariffs on imports of steel and aluminum. “Not on the plant, but on some of the pipelines. After the tariffs came in, some of pipe costs went up 20 percent.” Just a part of doing business in the oil patch that most operators and midstream companies have had to endure in recent months.

He then went back to the drones. “Some of the drones are outfitted with the LDAR infrared camera equipment, so we can fly them over every JANUARY/FEBRUARY 2019  SHALE MAGAZINE

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one of our central tank batteries to check for leaks and we fix them proactively. In the past, many companies didn’t even know what was going on, but with this new technology we can do all of this remotely.”

Behl points to a partnership Apache recently entered into with a service provider that even allows the drones to automatically conduct the inspections on a predetermined schedule without human intervention.

The data collected is then downloaded into the service provider’s software for analysis, which then notifies Apache personnel of any problems detected.

Behl next takes us over to another building that houses what Apache calls its “Fusion Center,” a facility from which teams of technicians monitor the volumes flowing from each well through the company’s gathering system and manages other elements of the Alpine High operation. On the way over he points out that he and Keenan opened the San Antonio office with just a handful of employees working out of two apartment units located in a housing/retail multi-use complex across the street from the current office tower, on which Apache now occupies two full floors. In the intervening two years the staff has expanded to more than 290, and will continue to grow in the coming years as the play develops.

In the Fusion Room facility, which actually consists of several different rooms, we watch as technicians monitor gas flows, well pressures, tank levels and many other elements of the oil field that in years past required human interaction in the field. At one point, we watch on a screen as a vacuum truck pulls up to a secured wellsite gate, and the technician has a short phone conversation with the driver 300 miles away to verify his credentials before clicking an onscreen button to open the gate and let him through.

After that, Behl notes one of his managers huddled in one of the corners with three other men, diagramming something on a whiteboard. He

takes us over to the group and asks his man what they’re working on. As it turns out, the three other men are with one of Apache’s trucking contractors, and they are working on ways to improve safety and minimize downtime hours while working on Apache’s projects. This will not only cut costs for Apache, it will also benefit the trucking contractor by freeing up hours it can then dedicate to other customers.

In this office, the drive to control costs never stops.

Changing the Way the Oil Field Works As our tour of the Fusion Center concludes, Behl summarizes all the uses of technology being employed by the Alpine High team in its continuous quest to streamline processes and lower costs, and concludes by saying, “We want to change the way the oil field works.”

They appear to be succeeding.

Back in Keenan’s office, he takes out a quote from a paper authored

by Warren Buffett and Jamie Dimon: “The nation’s greatest achievements have always derived from long-term investments. In both national policy and business, effective long-term strategy drives economic growth and job creation.”

“What we have right now in our industry,” Keenan says, “is a predilection towards quarterly results and short-term profit, and a de-emphasis on effective long-term strategy. So, the industry has subordinated long-

DON’T EV ER WASTE A CHAN CE TO

WANDER.

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term strategy, as well as sustainability, in favor of short-term profits.”

He points to another quote, this one from former British Prime Minister Margaret Thatcher. It says, “Don’t follow the crowd, let the crowd follow you.”

“That’s our view of exploration,” Keenan continues. “We don’t sit around like the Maytag repairman and wait for someone to call us and tell us what to do. We come up with our own ideas. Exploration is a search for the purpose of discovery, and discovery is defined as ‘the first detection of something new.’

“We have the vision as a company to be the premier exploration and production company, and our strategy for differentiation is to find high-impact, large-scale plays and — very importantly — deliver them at a low-entry cost.

Our average lease bonus cost for the Alpine High is about $1,200 per acre,” far below what many competitors have been willing to pay in recent years in order to get their own piece of the Permian Basin.

When asked how many wells he believes the company will ultimately be able to drill on its 336,000 Alpine High acres through the full development of the field, Keenan, as is his habit, offers an unconventional answer: “We don’t know.” Oh.

But he goes on. “Our metric isn’t how many wells, it’s how do we maximize the net present value (NPV) on some kind of scaled basis.” He goes on to point out that the scale and metrics used to determine how many wells to drill per surface acre can vary from unit to unit and from section to section within the play. “What we’re trying to do is maximize recovery at the lowest cost. We want to figure out how to drill the fewest wells with the highest NPV. So, we can’t answer the question yet, because we’re in the transition from delineation to full development.

“Now, the question is recovery: How do we recover it to maximize value? We’ve got dimensional complexity that almost no other play has, that nobody could understand unless they came to this office.”

In the end, it was well worth the 275-mile drive from my home in Mansfield, just south of Fort Worth, to San Antonio, to sit down with Keenan and his team for this interview. Because he’s right: There was no way to really comprehend all the moving parts involved in making the Alpine High work without seeing it all in person.

It all brings to mind what Texas A&M graduates like to tell other people about their school’s unique culture: “From the outside

looking in, you can’t understand it. And from the inside looking out, you can’t explain it.” To truly understand the complexity of the Alpine High and how Keenan and his team at Apache are changing how the oil field works in their management of it, you really do have to be there and see it firsthand.

About the author: David Blackmon is the Editor of SHALE Oil & Gas Business Magazine. He previously spent 37 years in the oil and natural gas industry in a variety of roles — the last 22 years engaging in public policy issues at the state and national levels. Contact David Blackmon at david.blackmon@shalemag.com.

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INDUSTRY

Were You There at the Shale Revolution?

By: David Porter

M

ost of the time it is difficult, if not impossible, to recognize that a major sea change is taking place — especially when it is just getting started. The Barnett Shale seemed to burst on the scene around the 2004-2005 timeframe as an instant success. Like most every overnight success, the story began 20 some years earlier when George Mitchell started drilling vertical wells and hydraulically fracturing those wells. After 20 plus years of experimentation and hard work, as well as adding horizontal drilling to the mix, drilling in the Barnett became successful.

For the next five or six years, most shale plays were natural gas dominated. Then from 2010 to 2012, producers started figuring out how to extract oil from shale formations. The Bakken, the Eagle Ford and a little later the Permian, became major fields that produced oil from shale formations. Taking two technologies (hydraulic fracturing and horizontal drilling) that had been around for a while, and using them together, is what turned shale formations into a major recoverable hydrocarbon asset.

Remember a decade or so ago, when everyone thought we were running out of natural gas and oil? There was all this doom and gloom about the natural resources picture. The production increase has been incredible. In fact, the lower prices caused by the increase in American supply of hydrocarbons is one of two major threats to the long-term survival of the industry. The other major threat being mandates and subsidies for renewables.

Let’s examine what the shale revolution has meant to U.S. oil production.

Oil production Mbpd December 2000 5,903 December 2005 4,864 December 2010 5,598 December 2015 9,202 December 2018 (estimated) 11,600

Those of us who have lived in Texas or other parts of the oil patch the last 10 to 12 years have had a front row seat to watch the revolution take place

Mbpd = Million barrels per day Approximately two-thirds of U.S. natural gas production comes from shale formations. In September 2008, U.S. oil production averaged less than 4 Mbpd. In November 2018, U.S. average oil production was 11.7 Mbpd. U.S. oil production has roughly tripled in the last 10 years.

It would be hard to overstate the impact this increase in production has had to the economy of the country and the state of Texas. I would argue that most of the good economic news we have had in the last 10 years has been due to the increase in U.S. energy production and the resultant economic activity. The improvement in our balance of trade deficit resulting from the reduction of oil imports has been tremendous.

Those of us who have lived in Texas or other parts of the oil patch the last 10 to 12 years have had a front row seat to watch the revolution take place. Many of the readers of this magazine have not only watched this revolution but were, and remain, key participants in this shale revolution, having helped bring the benefits to not only us locally, but to the entire world. We are right in the middle of this revolution happening. We don’t have the proper perspective to know how long the revolution is going to last, but if we don’t mess it up by adopting the wrong regulatory and other policy, the shale revolution should continue to benefit the country for many more years. The shale revolution was truly a new beginning for the energy industry in the United States.

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About the author: David Porter has served as a Railroad Commissioner (2011–17) and Chairman (2015–16), as well as Vice Chairman of the Interstate Oil and Gas Compact Commission (2016).

Prior to service on the Commission, Porter spent 30 years in Midland, Texas, as a CPA working with oil and gas producers, service companies and royalty owners. Since leaving the Commission, Porter works as a consultant for oil and gas companies. He also serves as Chairman of the 98th Meridian Foundation, a nonprofit concerned with water, energy and land issues.

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INDUSTRY

South Texas Energy & Economic Roundtable Honors Recipients of the 6th Annual Eagle Ford Excellence Awards STEER RECOGNIZES THOSE GOING ABOVE AND BEYOND IN THE EAGLE FORD SHALE Special to SHALE

T

he South Texas Energy and Economic Roundtable (STEER) honored Energy Waste, Cheniere Energy, Resirkulere, CPS Energy, EcoVapor Recovery Systems, OmniTRAX, CASA of Bee, Live Oak and McMullen Counties and the George West Education Foundation as the recipients of the 2018 Eagle Ford Excellence Awards. The awards recognize leading companies and organizations working in or with the oil and gas industry for their diligent efforts in protecting the environment, making safety a top priority and giving back to the communities in which they live and work.

“Though the Eagle Ford Shale operations have been active for 10 years, the commitment to a focus on safety, environmental protection and community involvement continues to surpass expectations,” said Chris Ashcraft, Interim CEO of STEER. He continued, “It is important to the oil and gas industry, our board of directors in particular, to honor these companies and organization today, winners and nominees, who encompass these values as much as STEER.” The awards ceremony provides both oil and gas companies and their contractors an opportunity to be acknowledged for their efforts in the areas of Environmental Stewardship, Safety Performance, and Community and Social Investment.

Winners of the Eagle Ford Excellence Awards demonstrate innovation within the industry, make safety their largest priority and benefit the greater South Texas region through workforce development and education.

The keynote address at the awards ceremony was provided by Texas State Senator Pete Flores, District 19. Senator Flores spent most of his career as a Texas Game Warden, serving the State for 27 years and achieving the rank of Colonel.

Senator Flores was elected in a special election in September 2018, becoming the first Hispanic Republican in the Texas Senate and the first Republican to represent Senate District 19 in over 139 years.

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Recipients of the 2018 Eagle Ford Excellence Awards are: Safety Performance For companies or organizations with less than 250 employees: EcoVapor Recovery Systems For companies or organizations with more than 250 employees: OmniTRAX Community and Social Investment For companies or organizations with less than 250 employees: Energy Waste

The awards recognize leading companies and organizations working in or with the oil and gas industry for their diligent efforts in protecting the environment, making safety a top priority and giving back to the communities in which they live and work

For companies or organizations with more than 250 employees: Cheniere Energy Environmental Stewardship For companies or organizations with less than 250 employees: Resirkulere For companies or organizations with more than 250 employees: CPS Energy Impact Award CASA of Bee, Live Oak and McMullen counties George West Education Foundation

For more information: The South Texas Energy and Economic Roundtable (STEER) is the leading Eagle Ford Shale resource in the region and is the primary coordinator for communication and public advocacy surrounding the oil and natural gas industry in South Texas. STEER serves as the bridge connecting the industry and communities throughout South Texas to ensure positive collaboration and communication surrounding the activities associated with energy production in the Eagle Ford Shale.

For more information about STEER, visit STEER.com.

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INDUSTRY

King Permian H

appy 2019! The shale revolution, marked by the harmonic convergence of horizontal drilling, hydraulic fracturing and an endless supply of oil and natural gas naturally present in the United States, has not only demonstrated incredible staying power, but it has also ushered in nothing short of a geopolitical realignment — all to our nation’s great advantage.

Proving that even a seeming negative in this story would be turned into a positive, the crude oil price-bust only five years ago that was prompted by a supply glut became an opportunity for the industry to further refine efficiencies in drilling and operations. The result has been an impressive reduction in the break-even price. Let’s just say neither Saudi Arabia nor any other oil-producing country has made anything remotely resembling that kind of progress.

This past year saw the U.S. set a new crude oil daily production record of 11.7 million barrels. Let that sink in for a moment — after 160 years of continuous growth, the U.S. actually set a new daily-production record. The countless prognosticators of “peak oil” since the Drake well first produced oil near Titusville, Pennsylvania back in 1859 surely are either turning in their graves or throwing up their collective hands in surrender. How can we have produced billions of barrels of oil and trillions of cubic feet of natural gas and still have more confirmed reserves than at any time in the past? The answer, of course, is that the oil and natural gas have always been there; the difference-maker is human ingenuity combined with private mineral ownership and capitalism. Technology continues to improve, but the incentive to pursue that improvement is the opportunity to make money.

This past year also saw the U.S. become the leading crude-oil producer in the world. We were already the world’s leading natural gas producer. Yes, there are many significant contributors to both of these accomplishments — the Marcellus Shale in Pennsylvania and West Virginia, the Bakken Shale in North Dakota, the Utica Shale in Ohio, the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend, Anadarko, Canadian and Kingfisher) in Oklahoma, and even the offshore production in the Gulf of Mexico. In Texas, we have the prolific Eagle Ford Shale, the Barnett Shale and the Haynesville Shale.

But the undisputed king of them all — a king with multiple lives, no less — continues to be the Permian Basin in West Texas and southeast New

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Mexico. It accounts for at least 63 percent of total Texas crude oil production and 95 percent of total New Mexico crude oil production.

Texas set its own crude oil daily production record last year with 4.6 million barrels. Last September, the Permian Basin produced 3.5 million barrels of crude oil and 11.6 trillion cubic feet of natural gas.

The discovery well started producing in 1920 in Mitchell County, one of fifty-two Texas and New Mexico counties covered by the Permian Basin, which adds up to more than 75,000 square miles. Over the past near-century, the Permian Basin has produced over 33 billion barrels of crude oil and 118 trillion cubic feet of natural gas. Despite that prolific history, not only did the Permian Basin set a new crude oil daily production record last year, but experts are estimating that last year’s record 3.5 million barrels will grow to 5.4 million barrels by 2023. That would mean that the Permian Basin would be producing more than any member of OPEC other than Saudi Arabia.

There are multiple producing formations in the Permian Basin, but one particular formation is really driving the current record production — the Wolfcamp Shale. Last year, that one formation produced one million barrels of crude oil and four billion cubic feet of natural gas daily, which represented one-third of Permian Basin production of both. Oil wells producing from the Wolfcamp have tripled from 2,200 to 7,750 since 2005.

The U.S. Geologic Survey estimates that the Wolfcamp Shale alone still contains 19 billion barrels of crude oil, 16 trillion cubic feet of natural gas and 1.6 billion barrels of natural gas liquids in reserves.

But aren’t we just setting ourselves up for yet one more boom-bust cycle that will see companies make another mass exit from Midland/ Odessa at the first hint of a bust? This expansion seems to be much different in kind from past booms; in fact, the last bust also seemed much different. Companies that had committed to expansions during the last boom didn’t slow down when the 2015 bust hit. Concho continued building their new campus in Midland, Anadarko continued with their plan to open a new campus in Midland, Pioneer continued with its strategy to sell off all of its assets and focus exclusively on the Permian Basin, Oxy proceeded with their plan to spin off a separate company to focus on the Permian Basin, Apache went forward with their massive “Alpine High” development in Reeves County, and Chevron and Exxon continued with their plans to reassert themselves as major players in the Permian Basin. In fact, during the last bust, Chevron reportedly

J. G. DOMKE/BIGSTOCK.COM

By: Bill Keffer

reduced their headcount in every location but Midland.

Last November, one more major announcement provided additional confirmation that the oil and gas industry has invested, and continues to invest, in the Permian Basin for the long term. Seventeen companies have formed the Permian Strategic Partnership and committed more than $100 million over the next several years to help Permian Basin communities with roads, schools, health care, housing and workforce. On one hand, it’s understandable because these companies need to be able to attract quality personnel to live and work in Midland, Odessa and other Permian Basin communities. On the other hand, that kind of financial commitment has never been made before. It obviously proves that the industry plans to drill wells and produce oil and gas in the Permian Basin for years, if not decades, to come.

Of course, that’s not to say that there won’t still be drama in the global and domestic markets. After all, people are involved. Whether it’s the final collapse of Venezuelan oil production, continuing sanctions against Iran’s oil production, the increasing exports of oil and natural gas from the U.S. to China, India, Germany and other countries, more record-setting production rates in the U.S., reductions in production by OPEC to prop up crude-oil prices, or the advent of Democrat control of the U.S. House with their aggressive efforts to shut down the oil and gas industry over the next two years; there will surely be no dull moments. Drill, baby, drill!

About the author: Bill Keffer is a contributing columnist to SHALE Oil & Gas Business Magazine.

He teaches at the Texas Tech University School of Law and continues to consult. He also served in the Texas Legislature from 2003 to 2007.

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45

INDUSTRY

Rapidly Advancing Technologies Are Transforming the Oil Industry By: David Blackmon

A

series of very remarkable factoids about the U.S. oil and gas industry have come to light in the past few months. Among those are:

• U.S. reserves for both oil and natural gas reached all-time record highs in November; • The U.S. actually became a net exporter of petroleum liquids for one week that same month; • America is the largest global producer for both oil and natural gas; • The new USGS estimate of the resource contained in the Wolfcamp Shale in the Permian basin makes it the largest continuous resource ever measured in North America.

There’s much more, but that sampling gives you a good flavor for the magnitude of the economic opportunity the industry represents for our country these days. The volumes of available resource ultimately grow so large that they become almost impossible to adequately comprehend.

Perhaps the most impressive number of all, though, is the fact that, in the 12 months from November 2017 through October 2018, America’s oil and gas producers were able to increase the nation’s production of crude oil by over 2 million barrels per day, a rise of about 22 percent. It is a number that almost defies belief.

In October 2017, analysts optimistic about the potential of the domestic industry were projecting an overall increase in crude volumes of 500,000 to 800,000 bpd. But the upstream segment of the industry managed to more than double those optimistic predictions.

How did they do it?

Simply put, it’s a combination of a bunch of really smart people in the industry deploying an array of constantly advancing technologies.

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Indeed, the development and deployment of new technologies in the oil patch these days is happening at such a rapid pace that it is becoming impossible for those of us who chronicle the industry to keep up with it all More powerful and fuel-efficient drilling rigs and other oilfield equipment; more accurate downhole sensors that allow drillers to better target the sweet spots of the formation rock as they move through it horizontally; more effective frac fluids and better completion technologies that maximize initial flow rates and expected resource recoveries. All these examples and many others have played key roles in the massive supply surge by American producers. It’s a true revolution with a pace that accelerates on a daily basis.

Equally important during this time of rising commodity price uncertainty is the fact that, at the same time they were ramping up production so rapidly, most producing companies were also trimming down their costs significantly. In this issue’s cover story, you will read about the ability of Apache Corporation to pare its lease operating expense down at its Alpine High operations in West Texas by over 50 percent in just 18 months.

One key to the company’s ability to achieve that cost saving has been through the deployment of advancing technologies. A few exam-

ples of this include: The use of remote-controlled drones to conduct site inspections; the deployment of infra-red cameras to identify and capture fugitive emissions at production and pipeline facilities; the use of digital communications that allow technicians in San Antonio to monitor oil and gas production flows, control production equipment and conduct other operations that in the past required onsite human intervention.

Indeed, the development and deployment of new technologies in the oil patch these days is happening at such a rapid pace that it is becoming impossible for those of us who chronicle the industry to keep up with it all. As an example, during the span of just a couple of weeks recently, I interviewed senior representatives at three different companies who have developed technologies that can help companies control costs and improve efficiencies in wildly varying ways.

PRT, a recent acquisition of DrillingInfo – PRT has developed an advanced machinelearning tool that has proven able to accurately predict weather and wind patterns up to two weeks in advance. Why is that important? Because electricity has long been the single biggest piece of lease operating expense at most upstream and midstream facilities. Many companies purchase power supply in advance at spot prices, and a better ability to accurately forecast the weather for a longer advance time will enable these companies to save more in their power costs. Cool, right?

AspenTech – AspenTech is also in the machine-learning business, in addition to a range of other endeavors. One of its new technologies uses machine-learning to not only monitor machine degradation, but also actually predict when pieces of equipment are about to break down. The ability to know when a piece of major equipment must be repaired or replaced enables companies to avoid major breakdowns that at times can result in major

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delays and cost thousands or even millions of dollars. This tool also has a flow assurance application that enables companies to anticipate and avoid interruptions in their ability to get their production to market.

MuscleWall – MuscleWall is different from the first two in that it is not a computerbased digital tool, but a physical technology that enhances the ability of companies to control surface water. MuscleWall manufactures a variety of modular barriers that can be easily set in place in a matter of hours by two-man crews for use in flood control, stormwater management, water containment, and for companies operating along coastlines, coastal erosion control. These barriers can be used in place of earthen berms at well sites, drilling sites, surface water storage tanks and even major facilities like gas processing plants and refineries.

Now, I’m an old guy who has a hard time setting up a standard cable box, and I learned about all of these technological marvels over the span of a couple of weeks. Think about what the staff in the production, drilling, operations, engineering and geological departments within the average upstream or midstream company are faced with evaluating and deploying each and every day in terms of technological tools that can help control and reduce and avoid costs.

Though it has seldom received the credit it deserves for it, the oil and gas industry has always been a “high-tech” business; a business in which technology constantly advances. So, that has not changed at all.

What has changed, though, and will continue to change is the pace at which the advances are coming. This is not your father’s oil and gas industry.

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@shalemagazinetexas Shale Oil & Gas Business Magazine @shalemag About the author: David Blackmon is the Editor of SHALE Oil & Gas Business Magazine. He previously spent 37 years in the oil and natural gas industry in a variety of roles — the last 22 years engaging in public policy issues at the state and national levels. Contact David Blackmon at david.blackmon@ shalemag.com.

OTHER SERVICES OFFERED BY SHALE MAGAZINE Branding / Web Production / Search Engine Optimization / Ad Design / Social Media Video Production / Public Relations / Email Marketing / Campaign Strategy / Direct Mail SHALE Magazine is a statewide industry publication that showcases the significance of the South Texas petroleum and energy market. SHALE’s mission is to promote economic growth and business opportunities that connect regional businesses with oil and gas companies. The publication supports market growth through promoting industry education and policy, and its content includes particular insight into the development of the Eagle Ford Shale and Permian Basin plays and the businesses affected.

JANUARY/FEBRUARY 2019  SHALE MAGAZINE

47

POLICY

By: Jordan McGillis Policy Analyst, Institute for Energy Research

T

he National Climate Assessment is the latest in a series of reports that has thrust climate change into the public spotlight — and added to the intensity of calls for a carbon tax. This brief article will illustrate first the arguments put forth by advocates for the carbon tax and then explain a couple of reasons among the many for which my organization, the Institute for Energy Research (IER), steadfastly opposes such calls.

The Case for a Carbon Tax The argument for a carbon tax is fairly straightforward if one understands

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SHALE MAGAZINE  JANUARY/FEBRUARY 2019

1. Emissions of carbon dioxide cause global warming; 2. Global warming will impose costs on human society writ large; and 3. A government can discourage carbon dioxide emissions, and thus avoid the costs of global warming, by placing a tax on carbon-based fuels while reducing taxes elsewhere to improve economic efficiency.

The first foundation, that emissions cause global warming, is the predominant position within climate science and — while all scientific findings should be subject to independent scrutiny — need not be challenged here. The second and third foundations, that global warming imposes costs and that government action can deliver us from those costs, are where IER’s strongest opposition lies.

Social Cost of Carbon The claim that global warming will impose costs on human society is more tenuous than it at first appears. Some aspects of this claim are certainly true. For example, a warming planet causes sea levels to rise, threatening coastal real estate. This aspect of the claim is rather uncontroversial. The tenuous element of the claim is that the costs of, say, building a sea wall can be quantified and credibly attributed to a unit of carbon dioxide emissions. The attempt at quantifying this cost is a cottage industry unto itself and it has generated a construct known as the “social cost of carbon.” IER has spilled much ink over the past decade in dissecting the so-called SCC. The social cost of carbon is an attempt at measuring the harm from emitting 1 ton of carbon dioxide warming impacts in dollar value terms. And it is this value that then anchors carbon tax proposals.

Simple though it may sound, the SCC is an interdisciplinary Frankenstein’s monster — one with no redemption in sight.

The tools with which we analyze the potential effects — positive and negative — of increased carbon dioxide emissions to generate an SCC are called Integrated Assessment Models (IAMs). IAMs link climate projections with economic projections. But what is often overlooked is that even taking climate projections as given and accepting the selection of economic variables intended to present a picture of economic costs and benefits decades in the future, the SCC estimate relies largely upon an arbitrary discount rate.

The discount rate is a concept that seeks to translate future costs and benefits into present dollar terms. As described by economist William Nordhaus, “Discounting is a factor in climate-change policy — indeed in all investment decisions — that involves the relative weight of future and present payoffs.”

While the costs of global warming’s most adverse effects will accrue well into the future, the costs of taxing energy hurt each of us here and now. The discount rate quantifies how much benefit we require in the future to prompt us to take on a cost today. This choice has a profound impact on the social cost of carbon, as shown in the chart below.

As you can see, these calculations from Nordhaus’s DICE model supply an SCC for the year 2020 as high as $56.92 at the 2.5 percent rate, but as low as $5.87 at the 7 percent rate.

The importance of this arbitrary number to the ultimate value that is generated for the SCC undermines the credibility of the metric

FAUX TOE/BIGSTOCK.COM

THE CARBON TAX — AND REASONS TO OPPOSE IT

the framework most commonly employed by advocates. The framework operates from these basic foundations:

and should call into question the validity of the carbon taxes that rest upon it.

Tax Interaction Effect Another strike against the carbon tax case is that it would plague us with what is known as the tax interaction effect.

As first illustrated by A. Lans Bovenberg and Lawrence H. Goulder in the late 1990s carbon taxes are a relatively inefficient way to raise revenue. Their research indicates that the economic cost of raising revenue through carbon taxes will tend to be higher than through taxes with a broader base, like income taxes. Broad tax bases allow tax rates to be low while maximizing revenue. A carbon tax, however, zeros in on a narrow range of commodities and activities. As a result, carbon taxes will tend to exacerbate distortions in markets for intermediate inputs, consumer goods, labor and capital.

Therefore, goes the argument of Bovenberg and Goulder, it is likely that a revenue-neutral carbon tax will impose more deadweight loss on the economy than the tax status quo.

So even if we ignore the arbitrary nature of the SCC, the tax interaction effect casts doubt on the wisdom of carbon taxes.

Climate Action Comes at a Cost The growing drumbeat in favor of a carbon tax harps on the costs of inaction, but all too often tax proponents fail to consider fully the costs of action.

Take, for instance, the admonitions of the United Nations that governments around the world must strive to limit global warming to 1.5°C. This call for aggressive action, with its implied carbon tax of at least $135 by 2030, would entail economic upheaval in the near term. And it is not obvious — again, even if we accept SCC calculations — that pursuing aggressive government action to mitigate climate change would produce benefits in excess of costs.

As IER economist Robert P. Murphy wrote upon the announcement of William Nordhaus’s Nobel nod in October, Nordhaus’s work shows that the recent mitigation goals announced by the United Nations are likely to cause far more damage to economic growth than they would alleviate in terms of warming damages.

Final Word Instead of handcuffing our capacity for productive growth, our best path forward may simply be enriching ourselves as much as possible to prepare for any vagaries of climate we may face. Our species is the most adaptable the world has ever seen. Through free markets and wealth maximization, we will put ourselves into the best position to manage threats of all kinds. The case for a carbon tax is not of the open-and-shut variety. Global warming may be a problem as we move further into the 21st century, but that alone does not provide terra firma to tax the energy sources that power our prosperity.

connect. share ideas. discuss.

SHALE Oil & Gas Business Magazine is an industry publication that showcases the significance of the South Texas petroleum and energy markets.

SHALE’s mission is to promote economic growth and business opportunity that connect regional businesses with oil and gas companies. It supports market growth through promoting industry education and policy, and it’s content includes particular insight into the Eagle Ford Shale development and the businesses involved. Shale’s distribution includes industry leaders and businesses, services workers and entrepreneurs.

About the author: Jordan McGillis is a policy analyst at the Institute for Energy Research. He focuses on the carbon tax debate and federal lands.

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49

POLICY

Why Shale Companies Shouldn’t Sit Out the War on Coal By: Bette Grande

First, they came for the coal industry, and I did not speak out — Because I was not in the coal industry.

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SHALE MAGAZINE  JANUARY/FEBRUARY 2019

by the support some members of the natural gas industry are giving to the carbon tax proposals.

These actions, quietly and not-so-quietly, echo the words of Niemöller, and while the natural gas industry can see some short-term benefit by supporting carbon tax efforts, in the long term they are simply fashioning their own noose.

Large multi-national energy companies have touted themselves as “green” for years, investing in renewables and causes unrelated to their core business. Their reward? Lawsuits and bad publicity. Independent energy companies should avoid this game; the rules are not in their favor and the deck is stacked against them.

Even the success of the shale revolution sends mixed messages. While it is true that the shale

A carbon tax will directly impact the Bakken and other tightoil plays

FORMATORIGINAL/BIGSTOCK.COM

T

he battle over carbon will play a significant role in the long-term development of the tight oil plays in the United States. There is yet another push for a carbon tax underway in Washington, D.C. and in some states. Congressman Ted Deutch (D-Fla.) is leading the way in the House of Representatives with Reps. Francis Rooney (RFla.), Brian Fitzpatrick (R-Pa.), John Delaney (DMd.), and Charlie Crist (D-Fla.) as co-sponsors.

The Deutch proposal, officially “The Energy Innovation and Carbon Dividend Act,” would establish a carbon tax of $15 per ton of carbon dioxide equivalent in 2019, set to increase by $10 every year thereafter. The tax would be imposed mostly at the midstream level on the use, sale or transfer for use of “Covered Fuels,” such as crude oil, natural gas, coal and derived products.

Shale operators are focused on continuing advancements in drilling, recovery and the infrastructure constraints that directly affect the bottom line. But they would be wise to keep an eye on the anti-carbon movement. The current administration has cut regulations that hampered energy development and, early in December, the Environmental Protection Agency (EPA) announced that it will revise an Obama-era rule on carbon capture and sequestration. While this rule is aimed at the coal industry, oil and gas producers should support the move. The reduction of regulations is welcomed by the energy industry, but the continuing push for a carbon tax should remind the industry to be engaged, vigilant and united.

Pro-energy policymakers in Washington, and around the country, are increasingly frustrated

revolution has drastically reduced CO2 emissions, since 2005 CO2 emissions in the U.S. have dropped by 14 percent, yet global emissions increased by 17 percent. But touting that fact only gives credibility to the idea that carbon is bad. If environmental groups actually cared about a reduction in CO2 emissions, they would embrace the shale revolution, but they do not.

A carbon tax will directly impact the Bakken and other tight-oil plays. Fewer than 14,000 unconventional wells have been drilled to date in the Bakken. That is less than 25 percent of the total number of wells that will be drilled to fully develop the shale play in North Dakota. Depending on demand and the price of oil, the North Dakota Department of Minerals Resources expects that it will take another 40 or 50 years to complete the drilling activity in the Bakken. But, if implemented, an escalating carbon tax will dramatically increase costs and reduce demand negatively impacting the economics of the tight-oil plays. Make no mistake, that is the goal.

The Moral Road Energy producers have nothing to be ashamed of — carbon-based energy has improved the lives of billions of people across the planet. Abundant food and inexpensive and reliable energy continue to improve quality of life. It is time for the entire energy industry to take the moral high ground.

The U.S. National Society of Engineering states that societal electrification (by coal) was the greatest engineering achievement of the 20th century, providing security and improved quality of life wherever it stretched.

Today six out of seven people on this planet live in underdeveloped nations. A carbon tax will not help these people, it will shackle them.

In the U.S., environmental activists wage the war on carbon against “big coal” and “big oil” but it is the consumer — the citizens

— who pay the cost. Hardest hit are the elderly, the poor and the children who benefit greatly from abundant, secure and inexpensive heat, electricity and transportation.

On these faces is the true cost of the war on carbon.

Access to energy has increased life spans, improved health and living conditions and improved the economy, providing jobs.

Our farmers, who feed the world, are heavily dependent on the oil and gas industry for the production and security of our nation’s food supply. Increased levels of CO2 are greening the planet, increasing the quality and quantity of food produced.

Some see the vital role that carbon-based energy must continue to play for future generations. Kirk Johnson from the National Rural Electric Cooperative Association (NRECA) represents 900 consumer-owned utility cooperatives, supplying electricity to one out of eight Americans. EPA rules should reflect the technology that exists today. The previous regulation didn’t do that, so we opposed it. We are researching new technologies including Carbon Capture and Storage (CCS), and the Dry Fork Station in Wyoming which is a test center for CCS research. We provide electricity to 42 milliom Americans, and 93 percent of persistent poverty areas.

The War on Carbon — Pick a Side Shale producers should care about the war on carbon — it is vital to the long-term survival of the industry, and, more importantly, it is the right and moral thing to do.

The current administration in Washington supports the energy industry, but there is no guarantee that it will stay that way. Elections have consequences and those in power in the future could change things back and do more damage to the oil industry than before.

All fossil fuels are targets — and if all in the industry do not stand together, then all will surely fall.

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About the author: Bette Grande is a Research Fellow for energy and environment issues at The Heartland Institute. She served as a North Dakota state Representative from 1996– 2014. Grande was a member of the House Appropriations Committee, Education and Environment Division. She was born and raised in Williston, North Dakota.

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51

POLICY

Effects of the Midterms on the Oil & Gas Industry By: Tim Tarpley, VP Government Affairs, PESA

A

s the dust settled on election night 2018, we now begin to evaluate the consequences that the election’s results may carry with them. Specifically, how could the election and the changes it brings impact the oil and gas industry?

First, the good news: In Colorado, Proposition 112 was handedly defeated, failing 57 percent to 43 percent. Proposition 112 had been the subject of much debate since it was added to the state’s ballot earlier this year. The proposition stated that new wells could not be constructed within 2,500 feet of any structure intended for human occupancy, such as a home, school, hospital or office building. Currently, oil and gas wells may not lie within 500 feet of most structures and in some cases, 1,000 feet.

The proposition caused much concern within the state’s oil and gas industry and in the state’s political sphere.

The current governor, as well as both the Republican and Democratic nominees for governor, all opposed the proposition. The Democratic nominee for Governor, Rep. Jared Polis, went on to win the nomination.

While Polis was a vocal opponent of Proposition 112, he has supported limitations on oil and gas drilling in the past, so it

52

is possible that the fight in Colorado is not entirely over.

One state over in New Mexico, voters saw Democrat Rep. Michelle Lujan Grisham win the governorship over fellow Congressman Steve Pearce. Although Lujan Grisham has said she wants to work with industry, she promised during the campaign that she will undertake a methane mitigation policy as governor. She has also been critical of President Trump’s suspension of rules enacted by the EPA and BLM during the Obama administration to curb methane emissions. A staunch supporter of renewables, Lujan Grisham believes that by recovering methane that is flared or lost to infrastructure leaks, the Land of Enchantment could recoup tax dollars that could be better spent on education.

In other statewide ballot measure news, Florida voters passed Amendment 9 comfortably, which prohibits offshore oil and gas drilling in state waters. It does not, however, interrupt the transportation of oil or gas products within this area. Florida’s state water boundary extends out three nautical miles from its shore in the Atlantic and nine nautical miles from its shore in the Gulf.

Meanwhile, Republicans were able to keep their majority in the Senate, meaning that certain pro-business legislative

SHALE MAGAZINE  JANUARY/FEBRUARY 2019

priorities — such as tax reform and cutting back on costly regulations via the REINS Act — will likely remain in place.

On the other hand, the most significant challenges to our industry could come from the Democrat controlled House of Representatives. The Democrats secured a big win in the House, flipping several Republican-held seats by the end of the night and regaining the majority in the House for the first time since 2010. The House will likely not be successful in passing much legislation due to the senate and presidential veto acting as a check. However, during the Obama administration, House Republicans passed a rule change in the House to allow for most committees to obtain legally enforceable subpoenas. This tool will surely be used by the new House majority to launch widespread investigations of the administration and policies important to the oil and gas industry.

Committee investigations into climate change, fracking, crude oil exports, and LNG permitting should be expected. On the bright side, the House may serve as a check on the administration’s tariff policy which will be welcome news to many in our industry.

Elections always have consequences, and the ramifications of the 2018 elections will be felt for years to come.

Elections always have consequences, and the ramifications of the 2018 elections will be felt for years to come

For more information: Visit pesa.org About the author: Tim Tarpley, Vice President Government Affairs, oversees PESA’s Public Policy committees and programs. Tarpley most recently served as Chief of Staff to Congressman Ted Poe (R-TX) and began his legislative career as an aide to Congressman Thornberry (R-TX).

Tarpley holds a juris doctor from Creighton University School of Law and a master of laws from American University Washington College of Law.

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53

POLICY

5 Energy Issues to Watch During the 86th Texas Legislative Session

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his January, as many Texans recover from the holidays and gaze into what some folks call winter here, members of the Texas Legislature will gather in Austin to be sworn in for the 86th legislative session. The Texas Legislature is charged with meeting for only 140 days every two years. A common saying is it would be better if they met for two days every 140 years. Nevertheless, the 2019 legislative session is upon us. Here is what we can expect to see and which issues could impact your business in the energy world.

On the political side, Texas has a much different looking House of Representatives and Senate this coming session. The Senate will see six new members in the 31-member body. The Republicans control 19 seats, with the Democrats having 12 senators. The House saw a dozen Republicans lose their seats. A new Speaker of the House will also be selected in January. Speaker Pro Tempore Dennis Bonnen announced in November that he secured enough votes to become the new Speaker.

in the state, will need to understand each of these proposals and determine as to how it may impact their business.

Road Funding: Another key issue will be road infrastructure. As the industry continues to grow, we are putting pressure on local highway systems. Last session, the oil and gas industry supported several plans to focus more dollars on this critical infrastructure, with some limited success.

Look for road funding to again be a public policy topic that will be debated.

For the Texas energy industry, we will see several past issues resurface, including these five that could have a big effect:

Eminent Domain: The use of eminent domain will be one of the most important issues for the energy industry this session. Before the 2017 session, a group of large landowners formed “Texans for Property Rights” to address several issues they saw as wrong with the current process of utilizing eminent domain. Working with some legislators, they had filed a bill that included a long list of grievances. Some of these issues included forcing the industry to pay for their attorney’s fees, venue location, aggressive sales tactics by right of way agents, “low-ball” offers, and the lack of oversight to file a complaint against perceived abuse of the system.

School Financing: Property taxes and school finance will play a major role this legislative session. Governor Greg Abbott, Lt. Governor Dan Patrick and Bonnen have discussed the need to reform the current system. Senators and Representatives alike have heard from constituents, educators and policy experts on this issue. We should anticipate seeing plans circulate the capitol. The oil and gas industry, a significant taxpayer

The energy industry responded by worked individually and as part of the “Coalition for Critical Infrastructure,” which is an organization composed of ports, railroad, municipalities, water companies, counties and other entities that use eminent domain.

The eminent domain bill died last session and the issue was referred to study through the past year.

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For the Texas energy industry, we will see several past issues resurface

BESTDESIGN36/BIGSTOCK.COM

By: Chris Hosek, Partner, Texas Star Alliance

A House committee studying the various eminent domain issues has held several interim hearings these past few months. Industry opposition is bringing forth examples of the threat and abuse of Eminent Domain. The committee is also looking at the issue of “market value” or “throughput” value in their scope of fair compensation. They will also continue to argue “transparency.”

Water: Water is always a major policy debate in Texas. In this legislative session, it will be no different.

We must watch this carefully since water impacts our business in several different ways and is vitally important to continue our production and growth.

On the produced water side of the policy debate, efforts to look at water recycling will continue. These may include trying to identify and streamline any regulatory or legislative issues. We may also see an effort to offer some type of incentive to recycle the water. This effort may have new support as induced seismicity continues to be debated and monitored. The industry worked several sessions ago to create and fund the TexNet program, to help understand and better monitor any issues.

Railroad Commission: One of the major obstacles to federal overreach in Texas energy production is a properly funded, fully staffed Railroad Commission. Their budget is an important factor to watch this session.

Having worked there, the Legislative Appropriations Request (LAR) is one of the most important documents produced to set the

budget. This session the Railroad Commission is requesting 22 new pipeline inspectors and $10 million to advance their IT systems operations.

They are not requesting any new fees or taxes.

Building off the success of the last session, Texas Energy Day will be Feb. 20 at the Texas Capitol. This is a time for energy employees to meet their legislators and talk about what oil and gas production means to them, their families and their communities. I would encourage all to attend. Communicating effectively with the legislators is key to keeping our industry successful.

As winter gives way to spring, the legislative session days will grow longer into the night. The oil and gas industry has given so much to this state: a strong economy, massive tax revenues and royalty payments, and an Economic Stabilization Fund (rainy day fund) that is the envy of most states. It is important for all Texans to advocate to keep the oil and gas industry strong.

WHAT’S YOUR NEXT MOVE?

Communicating effectively with the legislators is key to keeping our industry successful • space planning • office furnishings • moving solutions

About the author: Chris Hosek is a principal of Texas Star Alliance, specializing in direct lobbying and state agency relations. He has experience with a broad range of legislative issues and policy initiatives including a specific expertise in the energy sector. Chris served as the Chief of Staff for five years to the Chair of the Railroad Commission of Texas.

courtierconsulting.com/reality

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POLICY

How the Movies Drive Public Policy

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ilm is a powerful medium. From a policy perspective, few other forms of communication can so rapidly change public sentiment.

This is particularly true of feature films. Although documentaries are certainly important — and this year they have seen a resurgence that includes “Won’t You Be My Neighbor” and “RBG” — it is with feature films that messages resonate in an accessible fashion to a large audience. They not only inform and persuade — they also entertain and emote. As Mary Poppins might say, “A spoon full of sugar helps the medicine go down.”

If we look at films over the past few decades, it’s interesting to see how many of them have caught the public’s imagination and influenced governmental policy. “Midnight Express,” the 1978 movie about Billy Hayes, who tried to smuggle hash out of Istanbul but was caught, tried and sentenced to four years in prison chronicles his extreme privation and abuse. After the picture’s release, Turkish tourism was devastated and relations between the U.S. and Turkey soured.

Of course, we tend to think of the most sensational examples first. “Jaws” caused beach tourism to drop. The Exorcist tapped into people’s fears of the demonic and triggered a spate of theological thrillers. More recently along the same lines, Hollywood has found that superhero films and endless sequels keep

the box office crackling. Such tent poles serve as vicarious theme park rides, though they are light on socially relevant content.

As far back as 1942, “Bambi” resulted in a sizable drop in deer hunting in the U.S. Even today, hunting and vegan discussions often invoke references to “Bambi.”

Other types of films can have even more direct impact upon public policy. “The China Syndrome” was eerily prescient regarding the prospect of nuclear power plant accidents — Three Mile Island occurred just 12 days after the movie’s release in 1979. Since then, the U.S. curtailed the use of nuclear power for electricity generation due to fear of meltdowns — further reinforced by Chernobyl and Fukushima.

Movies can inspire career choices. “All The President’s Men” caused a spike in journalism school enrollments. Navy recruiters set up shop outside of screenings of “Top Gun” as military enlistments spiked. (Fans take note: The sequel, “Top Gun: Maverick” is slated to come out in 2020.)

The silver screen can elaborate great social issues. “Philadelphia” with Tom Hanks in an Academy Award winning performance highlighted workplace bias against AIDS victims.

“Guess Who’s Coming to Dinner” took the topic of interracial marriage into the mainstream.

“Hotel Rwanda” increased global awareness of the genocide by Tutsi and Hutu factions.

Environmental themes frequently enter the fray. “The Day After Tomorrow” resulted in greater consciousness of climate change.

Overtones of ecosystem collapse appear in “Avatar” — the top grossing film of all time.

Earlier this year, “First Reformed” arrived in theaters, in which Ethan Hawke grapples with the mounting implications of human-manufactured waste by-products.

An article by Michelle Pautz at the University of Dayton demonstrated how “Argo” and “Zero Dark Thirty” shaped opinions about government. Approximately 25 percent of viewers changed their opinion about government after watching one of the movies.

A newly-released feature may serve to raise public consciousness as well. “The Hate U Give,” based on a best-selling young adult novel by Angie Thomas, presents an absorbing look at race, inequality and justice in the U.S. In a vehicle potentially ripe for heavyhanded narrative, the filmmakers expertly address important social issues in a thoughtful and insightful manner.

Without question, feature films hold the potential to sway public opinion capture our imagination. Although often viewed as purely entertainment, motion pictures represent more than that. They can influence vocations, address pressing social issues and cause us to rethink our lifestyles — no mean feat in today’s complicated world.

About the author: Thomas Tunstall, Ph.D., is the Senior Research Director at the University of Texas at San Antonio’s Institute for Economic Development, and was a principal investigator for numerous economic and community development studies.

He has published peer-reviewed articles on shale oil and gas, and has written op-ed articles on the topic for the Wall Street Journal. Dr. Tunstall holds a doctorate degree in political economy, a master’s in business administration from The University of Texas at Dallas, and a bachelor of business administration from The University of Texas at Austin.

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By: Thomas Tunstall, Ph.D.

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BUSINESS

Commodity Hedging: Lessons Learned by Early Adopters of New Hedge Accounting Rules

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or public companies with a Dec. 31, 2018, fiscal year-end, new hedge accounting rules will become effective Jan. 1, 2019. The FASB issued the new hedge accounting guidance Aug. 28, 2017, through Accounting Standards Update (ASU) No. 2017-12. The ASU provided the election to early adopt the new guidance and some companies made the early election to take advantage of favorable provisions. The following is a discussion of lessons learned by commodity hedgers that early adopted the new guidance.

It has been interesting to note that relatively few companies early adopted the new hedge accounting guidance. Entities maintaining derivatives can be divided into two groups: those applying hedge accounting and those that do not apply hedge accounting. For companies that do not apply hedge accounting, the new guidance has not prompted companies to start electing hedge accounting. Those companies have become comfortable addressing the earnings volatility associated with derivative instruments utilizing non-GAAP measures.

For companies applying hedge accounting, early adopters mostly included companies that were starting new hedging programs or companies that desired to remove ineffectiveness from their financial statements. While companies viewed the new hedge accounting

rules favorably, many companies shied away from early adoption. This was largely because accounting resources have been strained adopting other new accounting standards for revenue recognition and leases.

For commodity hedgers, the largest changes to the hedge accounting rules under the new guidance include the following three items: • Ability to perform qualitative effectiveness assessment testing following designation inception • Ability to designate a contractually specified component • Elimination of the requirement to separately measure and report hedge ineffectiveness One of the greatest struggles for commodity hedgers to achieve hedge accounting under the existing guidance was the effort associated with ongoing effectiveness assessment tests. Under the current accounting guidance, a commodity hedger typically performed effectiveness assessment testing by performing regression analysis. The challenge was largely the lack of available market data representing the hedged item required to perform the ongoing regression analysis. This analysis was required at inception and at least quarterly

thereafter. Under the new hedge accounting guidance, a company may perform an inception quantitative effectiveness assessment test utilizing regression and then perform ongoing effectiveness testing qualitatively. When an entity performs qualitative assessments of hedge effectiveness, it must verify and document that the facts and circumstances related to the hedging relationship have not changed such that it can assert qualitatively that the hedging relationship was and continues to be highly effective. Early adopters hedging commodity price risk have noted limited benefits with qualitative testing as they execute hedges on a continuous basis requiring inception regression testing on an ongoing basis. In addition, even though the accounting standard provides for qualitative updates, many auditors are continuing to request ongoing quantitative support unless the hedging relationship is highly correlated, such as instances where the hedging instrument mirrors a designated contractually-specified component.

Under the current hedge accounting guidance, a commodity hedger is required to hedge the cashflow risk associated with the entire contractual cash flow. This was counter to how many companies utilized derivative instruments to manage their price risk. The new guidance gives companies the ability to designate a contractually-specified component,

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By: Shane Randolph, Managing Director, Opportune LLP

which is a significant benefit to many commodity hedgers. However, there have been some challenges for some companies to meet the criteria of a contractually-specified component.

Early adopters have noted three areas of concern when electing to designate a contractually-specified component: • Finding documents to support the contractually-specified component; • Ability to designate spot purchases; and • The interplay with the normal purchases and normal sales scope exemption.

Finding documents to support the existence of a contractually-specified component can be challenging for companies in some industries.

Some industries have industry standards that incorporate contractuallyspecified pricing component language into the boilerplate purchase and sale agreements. Agricultural, livestock and many metals are purchased and sold under market mechanisms that already include the contractually-specified language required to meet the contractually-specified component designation.

Common Commodity Industry Groups • Power • Oil, Natural Gas, NGLs • Refined Products (Diesel, Gasoline, Chemicals, etc.)

• Precious Metals • Industrial Metals • Agricultural (Dairy, Grains, Fiber, etc.) and Livestock Companies that operate in power, crude oil, natural gas, NGLs and refined products have mixed results when seeking to designate a contractually-specified component. The ability to designate a contractuallyspecified component is relatively limited for manufacturing or refining companies where the input into a finished good can have a contractually-specified component; however, once processed or combined with other items, the ultimate product sold does not contain a contractuallyspecified component. For example, crude oil might be a significant input for jet fuel, but a sales contract for the ultimate sale of jet fuel often will not reference a crude oil index.

Many companies purchase and sell product in a spot market. This can be particularly true for larger oil and natural gas producers that market their own production and for trading organizations. These companies have found significant limitations in designating a contractually-specified component under the new hedge accounting guidance. When a company knows that they will be buying or selling product at a future date, they often execute a derivative to hedge future price variability. However, a contract does not exist specifying the pricing at delivery of the physical product. The company will buy or sell the product at a negotiated price

a few weeks prior to delivery or at delivery. The market convention to negotiate the ultimate spot price will reference industry benchmarks, but nothing will be included in the contract noting the pricing components.

For example, a trucking company operating in New York and Pennsylvania knows that they will be purchasing diesel in 12 months and executes New York Harbor ultralow sulfur diesel (ULSD) futures contracts to hedge the purchases. The fleet will be purchasing the diesel at the pump under spot pricing, but this spot price will not meet the contractually-specified component requirements.

In order for a company to qualify for a contractually-specified component designation, the new accounting guidance requires the company to designate the hedged item under the normal purchase and normal sale exemption. This election often does not create issues for most companies. However, for companies that are engaged in trading activities where physical fixed price positions are recorded at fair value to offset financial positions, this can be problematic. A company may enter into a physical agreement that has an index price and the fixed price will be determined at a later date. The normal purchase and normal sale exemption is an irrevocable election, so once the election is made for the physical agreement before the fixed price is determined, the company cannot record the fixed price agreement at fair value later.

In addition, the normal purchase and normal sale exemption contains a prohibition against net settlement. This can be problematic for companies that have physical purchase and sales with the same counterparty.

Rather than physically deliver all the purchases and separately deliver all the sales, they will only deliver the net position, which is not allowed under the normal purchase and normal sales exemption. Companies engaged in these activities are limited in their ability to receive the benefits of a contractually-specified component designation.

While there have been challenges encountered by early adopters, the Financial Accounting Standards Board’s (FASB) changes to the hedge accounting rules have been favorably received by users for the most part. Companies should carefully consider the changes under the new hedge accounting guidance and take steps to properly implement any changes.

About the author: As a Managing Director at Opportune, Shane assists companies and financial institutions throughout North America, South America, Europe and Asia-Pacific in their understanding of what is possible as they deal with the challenges of implementing risk management programs and highly technical accounting pronouncements. Shane oversees the risk management, derivatives, stock-based compensation and complex securities service offerings of Opportune. He assists clients with the entire risk management lifecycle, including strategy, execution, compliance, valuation and hedge accounting.

He has undergraduate and graduate degrees in accounting from Oklahoma State University. He is also a member of the American Institute of Certified Public Accountants.

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BUSINESS

Crude Oil Export Terminal on Harbor Island, Texas Hits New Milestones By: Port Corpus Christi

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he Port of Corpus Christi Authority reached several milestones in the development of the crude oil export terminal on currently planned for Harbor Island, Texas.

Corpus Christi-based Lone Star Ports, LLC (Lone Star Ports) will lead the development of the Terminal, the first U.S. onshore export terminal servicing fully-laden Very Large Crude Carriers (VLCCs), furthering the Port’s position as a global crude oil export hub. Lone Star Ports is a joint venture between The Carlyle Group and The Berry Group (Berry). Berry is the largest private employer in the Corpus Christi area through its numerous investments and operations in the oil and gas industry and its subsidiary Bay Ltd., a Corpus Christi-headquartered infrastructure, construction and fabrication contractor for the oil and gas sector. The Berry Group is led by directors Marvin Berry, Dennis Berry and Lawrence Berry.

Lone Star Ports is led by CEO Jeremiah “Jerry” Ashcroft III. Ashcroft has led the development of several large marine terminals, including the development and operations of BORCO and Hovensa/Limetree Bay. Most recently, Ashcroft served as President and CEO of EQT Midstream, which included three separate publicly-traded midstream platforms with a combined market capitalization of $11 billion. Ashcroft also served as CEO of Gulf Oil LP and President of three business units for Buckeye Partners, LP He began his energy career with Colonial Pipeline Company.

Ashcroft is a graduate of the United States Naval Academy and served in the U.S. Marine Corps for 10 years.

Lone Star Ports has signed indicative agree-

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ments with Harvest Midstream and EPIC Crude Pipeline, which is backed by funds affiliated with Ares Management. These two pipelines will provide connectivity to more than 1 million barrels per day (mmbbls/d) of crude oil from the Permian and Eagle Ford basins in Texas. Lone Star Ports also entered into an indicative agreement with Martin Midstream Partners LP (Martin) for Martin to work with Lone Star Ports to provide a single, integrated VLCC solution on Harbor Island.

These agreements and arrangements remain subject to definitive documentation among the relevant parties, coordination with the Port, satisfactory completion of due diligence and final approval by each relevant party.

“Our partnership with the Carlyle Group is designed to assure global energy markets that requisite infrastructure will be in place and ready to support the growing exports of American crude oil. We are pleased with the progress The Carlyle Group has achieved thus far in reaching full project commercialization,” said Sean Strawbridge, CEO of the Port of Corpus Christi.

Key insights: Lone Star Ports, a Corpus Christiheadquartered company, to lead project development and operations Lone Star Ports is a joint venture between The Carlyle Group and The Berry Group, the largest private employer in Corpus Christi EPIC Crude Pipeline, backed by funds affiliated with Ares Management, and Harvest Midstream to interconnect with the facility, enabling connectivity to more than 1 million barrels per day of crude oil Lone Star Ports and Martin Midstream Partners LP to establish an exclusive Very Large Crude Carriers solution on Harbor Island

For more information: As the leading U.S. crude oil export port and a major economic engine of Texas and the nation, Port Corpus Christi is the fourth largest port in the United States in total tonnage. Strategically located on the western Gulf of Mexico with a 36-mile, 47-foot (MLLW) deep channel, Port Corpus Christi is a major gateway to international and domestic maritime commerce. The Port has excellent railroad and highway network connectivity via three North American Class-1 railroads and two major interstate highways.

With an outstanding staff overseen by its seven member commission, Port Corpus Christi is “Moving America’s Energy.” www.portcorpuschristi.com.

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BUSINESS

The Oilfield Housing Dilemma and an Ideal Solution By: Lauren Guerra

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A situation that has only your company's employees, at close proximity, with known vacancy and occupancy limits, while staying affordable, seems to be the most ideal housing option for short-term housing hiring practices of the various other companies can pose threats if they are not doing thorough screenings of their employees. Again, these man-camps can be distant from the work site, again adding to the safety concerns of commuting. Lastly, these man-camps can also be cost prohibitive for some employers.

An ideal solution to housing seems to have some commonalities. A situation that has only your company's employees, at close proximity, with known vacancy and occupancy limits, while staying affordable, seems to be the most ideal housing option for short-term housing. It is possible through some planning and foresight from company decision-makers.

Corporate Mobile Housing, Inc. has an option that encompasses many of these ideal factors and quite a few added benefits. Corporate Mobile Housing offers fully-furnished, maintained, private housing options to fit the needs of employers. With a like-home feel, the shortterm housing properties are fully customizable

to accommodate the needs of the employees and provide a safe, affordable housing option for employers.

The properties built by Corporate Mobile Housing are more residential than man-camps and come with a network of highly-capable maintenance and vendor sources to ensure the community is taken care of and repaired as needed. Additionally, the cost can be at times close to half the cost of man-camps and hotels.

From the early stages of planning a property, Corporate Mobile Housing helps their client to achieve the goal of providing safe and convenient housing for employees. The properties can be provided on the company’s own properties, in many areas common to the energy and construction industries, or the properties can be built directly (and conveniently) on the worksite to allow for little to no commute time.

Corporate Mobile Housing helps their clients to plan the property site to their needs, assists in the process of obtaining permits, contractors,

PHOTO COURTESY OF CORPORATE MOBILE HOUSING

et’s face it — housing, especially in areas like the Permian Basin, is hard to come by. Companies in energy, construction and similar industries with the need for short-term housing can find it difficult to locate housing options that are both convenient and affordable.

Options for these companies include mass hotel room bookings or such a thing called man-camps. Both of these options, however, can be quite expensive for employers. Additionally, they could be distant from the worksite, decreasing efficiency and increasing the chances of commute-related traffic accidents for their employees.

Hotels can be a real issue for employers for a number of reasons. Not only are they expensive and inconvenient due to travel time from the work site, but hotels are also unpredictable. In busy areas, like the Permian, it can be difficult to find vacancies to accommodate the number of workers that are expected to be housed for the duration of their time at a work site. By the time you’ve located a hotel with enough rooms for the number of days you need them, you’re already dealing with an unneeded hassle. With safety and privacy concerns that are innate when dealing with hotels and the cost of the rooms coupled together, this solution to the housing problem can become stressful and expensive very quickly.

Man-camps really are exactly as they sound.

These “camps” are not the most homely of places and can be filled with workers from various companies. The concerns that come to mind here is the privacy factor, not only because they are close quarters, but also because you don’t know who’s in them. Not knowing the

preliminary setup, and necessary hookups to make the property fully-functioning. From planning to site development to building and maintaining, Corporate Mobile Housing provides expert assistance to make the transition to private housing as seamless and hasslefree as possible.

Corporate Mobile Housing has many services to provide in the planning, building and maintaining of corporate short-term housing needs, including: • Housing Units • Food Service • Laundry Services • DIRECTV • Power Generation • Fencing • Water and Wastewater • Security • Light Towers • Mobilization/Demobilization • Labor/Management/Maintenance • Site Selection & Engineering • Evaluate City, County and State Coding • Satellite Communications In addition to housing, the company can provide options for field offices and trailer house rentals if this is also in the needs of prospective clients. Working with field management closely, Corporate Mobile Housing can provide excellent service to fit the timelines designated by upper-management.

Corporate Mobile Housing is proudly on the ISNetworld network, displaying their commitment to an impeccable reputation, excellent safety record and all the reporting/insurance information to assure the company is in compliance and is fully prepared to manage projects for prospective clients.

The company is seeing many new areas of growth in Texas including West Odessa, Monahans, Kermit, Pecos, Cotulla and Midland, and some areas of New Mexico, including Jal and Carlsbad. However, the company can expand to areas that are dictated by their clients’ needs, either on their property or land that Corporate Mobile Housing acquires and develops.

If short-term housing has been a headache in the past, contact Corporate Mobile Housing to learn more about the full array of options and services this company can provide to alleviate those hassles.

Introducing the SHALE Mobile App Free to Download on iPhone and Android GPS-Enabled Directory Oil and Gas Survival Kit and More!

For more information: Contact John Lauve at jlauve@ corporatemobilehousing.com or call 432-232-0822.

About the author: Lauren Guerra is the Chief Operating Officer and Editor-in-Chief of SHALE Magazine. For editorial inquiries, please email lauren@shalemag.com.

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LIFESTYLE

Keeping Your New Year’s Resolution Special to SHALE

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nyone can make a New Year’s resolution. How many of us can actually keep one though?

Food for thought — maybe we should resolve ourselves to make minor changes over time instead of a couple drastic maneuvers on Jan. 1. Maybe if we resolve to make a few small changes over the course of the year, we will have a better chance of looking back and thinking, “Job well done!”

How will you resolve to change in 2019? What realistic promises will you make yourself, your loved ones or business associates?

According to Fox News, every year about 40 to 45 percent of adults in America make a New Year’s resolution, with the top three goals being weight loss, to stop smoking and to save money. According to a study published in the Journal of Clinical Psychology, only eight percent of the people who set New Year’s goals actually achieve them — about 80 percent will give up in the first two weeks.

Let’s think this through and work out a full-proof way to make sure the goals we set come to fruition.

How will you resolve to change in 2019?

1. Decide what you really want to achieve. What is meaningful to you and how can you realistically go about bringing it to life? This will be the hardest part of the equation, so make it your number one priority and the planning will be downhill from here. Think big-picture and don’t allow your inner editor to limit your ideas.

2. If you have more than one goal, prioritize. Which goals means the most to you personally? If you have a professional goal, as most of us do, don’t let it outshine your inner wants. Obviously, life has costs and sometimes we have to compromise our personal desires in lieu of professional ones; Still, make time for yourself and your own needs. If you are stagnant then it will show in every aspect of your life.

3. Be specific. Once you have narrowed down the priorities, then make a plan. Kind of like putting together a budget — get honest with yourself regarding the specifics of what you want and how badly you want it.

Whether you are working with a budget of $30,000 or $300,000, the same

rules apply. Put pen to paper and sketch out what you want for the year.

Perhaps you want to travel — Start thinking about where you’d like to go and how badly you want to get there. What steps need to be taken to make this dream a reality? Maybe you need a new car — Do you have equity in your current car? Do you need to save for a down payment? How can you alter your lifestyle and budget to allow you to save?

4. Hold yourself accountable. Tell a friend, spouse, family member — how will you set yourself up for success? Sometimes setting goals is not enough; you have to state your intentions daily, tell someone else what your goal is and remind yourself what it is you intend to accomplish. Put a post-it note on the bathroom mirror. Set a daily reminder in your phone calendar. Tell yourself, out loud, daily what you are going to make happen. Who knows? Maybe the universe is listening.

For more great ideas and information: Visit www.forbes.com/sites/moneywisewomen/2011/05/11/the-power-of-stating-your-intentions-out-loud/#5f83c3105acf

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A few simple steps to turn your fleeting resolution into reality:

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LIFESTYLE

Running on Empty?

AURA MD BODY PROVIDES 360-DEGREE APPROACH TO BOOST HEALTH AND WELLNESS By: Dr. Ashley Toutounchi, Founder and Head Physician at Aura MD Body

sustainable lifestyle accompanied by desired weight-loss and anti-aging results.

At Aura MD Body, we offer evidence-based and scientific-driven treatments that are customized to individual goals, considering factors such as biology, genetics and lifestyle. From vitamin injections and rapid weight loss to medication-assisted weight loss or genetic weight loss testing or micronutrient testing, we pride ourselves on the use of all pharmaceutical-grade products to ensure the highest-quality service, consistency and transparency is provided to our patients.

To overcome feeling like your energy and appearance is heading “downstream,” Peptide Therapy is a sciencebased biological growth hor-

mone optimization treatment that can make you look and feel younger without going under the knife. It is evident that growth hormone levels decline with age; in comparison to levels measured in your twenties, there is a drop of around 60 percent by age 40 and by the time you are age 60, your levels are depleted by 80 percent!

By optimizing growth hormone levels, both men and women can experience:

• Anti-Aging Effects of Increased Collagen Production • Decreased Body Fat Composition • Increase in Lean Muscle • Increased Energy • Improved Libido • Increase in Restful Sleep Stages • Heightened Immunity • Improved Cardiovascular Function Aura MD Body offers the most exclusive, safest and highest-quality peptide formulation on the market, generating an increase in growth hormone secretion without increased appetite or high cortisol levels, meaning your body’s growth hormone levels increase in a natural physiological range.

If you’re looking for an easy pick-me-up, our Boost Bar is a popular service where patients can opt for custom blended va-

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rieties of vitamins, antioxidants or amino acid injections to maximize metabolism, boost energy and immunity, build lean muscle mass and reduce free radicals to boost your beauty regimen for glowing skin and hair. Depending on your desired outcome, we can put together custom packages to include injections such as Amino Blast to help you burn those extra calories during a workout.

The first step to making a change is recognizing the need for one. If you’re tired of being tired and want to shed those extra pounds, I recommend you explore your options at Aura MD Body to decide what the best approach is for you as an individual. We understand the obstacles you are facing as a business professional, and we are passionate about helping you make a seamless transition to incorporate positive and healthy changes into your day to day health and fitness routine.

For more information: Visit www.

AuraMDBody.com or call 832-804-7948. Follow us on Instagram and Facebook.

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he oil and gas industry is demanding and professionals are working in a fast-paced setting far beyond the hours of nine to five. With this type of work environment, along with the networking and business meetings that take place outside of the office, it’s highly common for men and women to compromise their health. From business meetings over lunch to client dinners throughout the workweek, fatigue and weight gain are two common side effects business professionals experience as a result of this lifestyle.

As a health professional, it is my job to educate my patients on the importance of a 360-degree approach to health and wellness in order to achieve a

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SOCIAL

SAPA Hosts 7th Annual Midstream Classic

PHOTOS COURTESY OF SHALE

The San Antonio Pipeliners Association (SAPA) hosted the seventh annual Midstream Classic, a scholarship fundraising event Nov. 16 at the Hyatt Hill Country Golf Club. The event had a great turnout, including over 30 event sponsors.

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STEER Eagle Ford Excellence Awards Reception

PHOTOS COURTESY OF SHALE

The South Texas Energy and Economic Roundtable (STEER) hosted the sixth annual Eagle Ford Excellence Awards. Energy Waste, Cheniere Energy, Resirkulere, CPS Energy, EcoVapor Recovery Systems, OmniTRAX, CASA of Bee, Live Oak and McMullen Counties, and the George West Education Foundation were the recipients of the 2018 Eagle Ford Excellence Awards.

The awards recognize leading companies and organizations working in or with the oil and gas industry for their diligent efforts in protecting the environment, making safety a top priority and giving back to the communities in which they live and work.

JANUARY/FEBRUARY 2019 ď “ SHALE MAGAZINE

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ConocoPhillips’ Eagle Ford Relay for Life Committee Hosts 4th Annual Redfish Round-Up

PHOTOS COURTESY OF CONOCOPHILLIPS

On Oct. 27, 2018, ConocoPhillips hosted the Eagle Ford Relay for Life Committee’s Fourth Annual Redfish Round-Up to raise funds for the American Cancer Society and cancer patients in our surrounding area. The 2018 event featured 42 teams, 21 event sponsors and a raffle prize. This year’s event raised $57,175. Over the past four years, a total of $101,217 has been raised to help the American Cancer Society fund groundbreaking cancer research, critical patient care services, education and prevention initiatives and more. The ConocoPhillips Relay for Life Committee is proud to raise funds toward this worthy cause.

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