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NewsLetters

  Expo/Industry events for the next few months

Marcellus-Utica Midstream
January 30 – February 1, 2018
David L. Lawrence Convention Center
Pittsburgh, PA
https://www.hartenergyconferences.com/marcellus-utica-midstream

Emerging Opportunities Ohio River Valley Conference
February 22, 2018
Oglebay Resort
Wheeling, WV
http://emergingopportunitiesorv.com/

Utica Midstream
April 4, 2018
Walsh University
North Canton, OH
www.uticasummit.com

For other events visit http://www.shaledirectories.com/site/oil-and-gas-expo-information.html

Latest facts and a rumor from the Marcellus, Utica, Permian, Eagle Ford, Bakken and Niobrara Shale Plays

 

Antero 2018: $1.45 Billion to Drill 125 Marcellus & 25 Utica.   Antero Resources Corporation  announced its 2018 capital budget and guidance, extended long-term targets through 2022 and provided an update to 2017. Antero will host its analyst day Thursday, January 18, 2018 in New York City. The event webcast was live beginning at 9:00 am ET. Interested parties may access the live audio webcast and related presentation materials on Antero's investor relations website at http://investors.anteroresources.com.

2018 Guidance and Long-Term Target Highlights Include:

  • Net daily production is expected to average approximately 2.7 Bcfe/d in 2018, a 20% increase over 2017 levels
  • Net daily liquids production is projected to grow 23% over 2017 volumes to 130,000 Bbl/d
  • Stand-alone E&P Adjusted EBITDAX is expected to be $1,700-$1,800 million with consolidated Adjusted EBITDAX of $2,050-$2,150 million in 2018
  • Expect to fully fund 2018 stand-alone E&P drilling and completion capital with Stand-alone E&P Adjusted Operating Cash Flow
  • 2018 natural gas realizations before hedges expected to be a $0.00-$0.05/Mcf premium to Henry Hub, with C3+ NGL realized price averaging 62.5% to 67.5% of Nymex WTI
  • Increasing 5-year planned average lateral lengths by 2,500 feet, or 28%, to 11,400 feet per well
  • Maintaining a compound annual growth rate target in net production of 20% from 2017 through 2020 and introducing a 15% target in each of 2021 and 2022
  • Targeting a debt-adjusted compound annual growth rate in net production of 24% through 2020 and 20% to 24% in each of 2021 and 2022
  • Targeting flat consolidated drilling and completion capital budget of $1.3 billion annually through 2020
  • Targeting reduced 5-year drilling and completion capital by a cumulative $2.9 billion compared to prior year targets, driven by a combination of longer laterals, improved cycle times, capital re-allocation and enhanced recoveries
  • Targeting cumulative Free Cash Flow of $1.6 billion through the five-year period ending 2022 based on strip pricing and $2.8 billion based on flat $60 WTI oil and $2.85 natural gas
  • Targeting stand-alone net debt to Adjusted EBITDAX of low 2x in 2018 and under 2x leverage in 2019 and beyond

Preliminary Fourth Quarter 2017 Highlights Include:

  • Average net daily gas equivalent production was 2,347 MMcfe/d, an 18% increase over the prior year quarter
  • Realized natural gas price before settled commodity derivatives averaged $2.80 per Mcf, a $0.13 negative differential to Nymex, and tighter than fourth quarter guidance of a negative differential of $0.15-$0.20
  • Realized C3+ NGL price before settled commodity derivatives averaged $39.16 per barrel (71% of WTI), a 55% increase as compared to the fourth quarter of 2016 and a 35% increase sequentially
  • Fourth quarter stand-alone E&P net income expected to be in the range of $490 to $510 million, with consolidated net income or loss, including noncontrolling interest, of $525 to $560 million
  • Fourth quarter Stand-alone E&P Adjusted EBITDAX expected to be in the range of $370-$385 million with consolidated Adjusted EBITDAX of $430-$445 million, above the midpoint of previous fourth quarter guidance

Commenting on Antero's long-term targets, Paul Rady, Chairman and CEO, said, "2018 will be a transformational year for the company as we move toward free cash flow generation, while maintaining our peer leading high margin growth profile. Through continued efficiency gains, we reduced our five-year capital spend target by a cumulative $2.9 billion as compared to last year's internal long term targets, while maintaining our annual production growth targets through 2022. Due to the significant capital efficiencies that we have achieved over the past several years including from longer lateral drilling, we expect to deliver this high growth profile with flat annual drilling and completion spending through 2020 followed by modest spending increases in 2021 and 2022.  Antero's ability to target top-tier production growth, while generating free cash flow and a declining leverage profile, speaks to our extensive high quality liquids rich drilling inventory. As the largest NGL producer in the U.S., we have substantial exposure to the improving liquids commodity price environment, which supports our ability to deliver peer leading Adjusted EBITDAX margins and achieve the long term targets outlined here today."

2018 Capital Budget

Antero's consolidated capital budget for 2018 is $1.45 billion, including $1.3 billion for drilling and completion, $25 million for leasehold maintenance and $125 million for discretionary leasehold expenditures. Antero's drilling and completion budget has remained essentially flat for three consecutive years. Net production is expected to average approximately 2.7 Bcfe/d in 2018, representing year-over-year growth of 20% as compared to 2017, including 23% liquids growth to 130,000 Bbl/d. Approximately 80% of the drilling and completion budget for 2018 is allocated to the Marcellus Shale and the remaining 20% is allocated to the Ohio Utica Shale.

The Company's 2018 capital budget excludes Antero Midstream Partners LP's ("Antero Midstream") (NYSE: AM) $650 million capital budget for the construction of low and high pressure gathering pipelines, compressor stations, processing and fractionation facilities, fresh water delivery and advanced wastewater treatment infrastructure.  Antero Midstream announced its 2018 capital budget and guidance today in a separate news release, which can be found at www.anteromidstream.com.

In 2018, Antero plans to operate an average of five drilling rigs and four completion crews in the Marcellus Shale and expects to complete 120 to 125 wells with an average lateral length of 9,300 feet. The drilling plan in the Marcellus averages nine wells per pad. As average lateral lengths continue to increase, total well costs are expected to decline further in 2018 to $0.80 million per 1,000' of lateral, a 45% decline from 2014 and a 9% reduction from 2017 well costs. 

The Company plans to operate one drilling rig and one completion crew in the Ohio Utica Shale in 2018 and expects to complete 20 to 25 wells with an average lateral length of approximately 11,600 feet. Antero is currently drilling and completing its Utica wells at an average budgeted cost of $0.89 million per 1,000' of lateral, a 43% well cost improvement over 2014 and a 9% improvement from 2017 well costs.

Antero is budgeting to continue to consolidate acreage for development plan purposes in the core of its Marcellus and Ohio Utica leasehold positions in 2018 along with extending leases on acreage that is planned to be developed over the next several years. Antero has budgeted $125 million for discretionary leasehold expenditures and approximately $25 million is budgeted for leasehold maintenance spending required to support the five-year development plan. Consistent with historical practices, the Company does not budget for asset or corporate acquisitions.

Mountain Valley Pipeline Tries to Keep Moving Forward.  Attorneys for holdout landowners along the path of Mountain Valley Pipeline (MVP) are using MVP’s willingness to tweak the route of the pipeline to avoid certain areas, against it. Yes, try to work WITH folks–and they turn around and use it against you. MVP is a $3.5 billion, 303-mile pipeline that will run from Wetzel County, WV to the Transco Pipeline in Pittsylvania County, VA. In October, the Federal Energy Regulatory Commission (FERC) gave final approval for the project.

In early November, the West Virginia Dept. of Environmental Protection gave the project its approval. And in December, the Virginia Water Control Board voted to approve the project. So it should be clear sailing for MVP–except for some 15% of holdout landowners along the pipeline’s route who refuse to sign easements. MVP has taken them to court, asking a federal judge for permission to use eminent domain to gain access to those properties. But the holdouts’ lawyers are saying continued tweaks to the pipeline route are evidence MVP doesn’t know what the heck it wants and who to “condemn” with eminent domain–and that’s enough reason for the judge to refuse granting blanket condemnation for eminent domain…

Fighting FERC.  The builder of the proposed Constitution Pipeline from Pennsylvania to New York said it will ask the Federal Energy Regulatory Commission to take another look at its recent ruling that upholds New York State’s denial of a water-quality permit for the troubled project.

Constitution Pipeline said it will seek a rehearing or appeal FERC’s decision on Jan. 11, in which the commission declined to overturn the permit decision by New York State’s Department of Environmental Conservation (DEC). That decision has stopped the company from beginning to build the 124-mile natural gas line.

The company, a unit of the Williams Companies, argues that DEC waived its right to issue a water quality permit under Section 401 of the federal Clean Water Act because it did not act within a “reasonable time,” which FERC interprets as one year.

Constitution says FERC got it wrong by failing to recognize that the waiver applied to the company’s application.

FERC’s action is the latest setback for the project, which has also failed to persuade an appeals court to overturn the DEC’s permit denial.

The DEC denied the water permit in April 2016, three years after Constitution first applied, and after the company twice withdrew and then resubmitted its application. In its denial, the department said Constitution had not provided enough information to allow the DEC to determine whether the pipeline project would meet water-quality standards.

Super-sized Well Pads.  Dave Elkin remembers in the earlier days of the Marcellus when EQT drilled three wells from a single well pad and it was considered a technological marvel.

“The greatest thing since sliced bread,” Mr. Elkin, a senior vice president of asset optimization at EQT Corp., thought at the time.

It was a quaint memory that contrasts sharply with the company’s and industry’s new normal: superpads — concrete platforms that can house 30 wells, maybe even 40, with long horizontal tentacles stretching underground for up to 4 miles in each direction.

A superpad means a quarter of a billion dollars pumped into a single hillside in a place like rural Washington County, PA. It means fewer well pads in total but much more activity on those that exist. It means that from a 10-acre spot, a company like EQT can theoretically slurp natural gas from underneath an area nearly the size of the City of Pittsburgh.

“I call them mini-industrial complexes,” said David Schlosser, president of exploration and production at EQT.

Downtown-based EQT — now the largest producer of natural gas in the U.S. — is leading the Marcellus pack in supersizing its well pads, with about a dozen sites permitted to hold 20 or more wells.

There’s the Big Sky pad in Nottingham, Washington County, with 26 permitted wells. The Strope pad in Franklin Township, Greene County, with 28. The Prentice pad in Forward Township has 37 wells permitted on it.

They may not all materialize, Mr. Schlosser cautioned; the company often gets permits for more wells than it will eventually drill to keep its options open.

The Cogar pad in Amwell Township is a case in point. It was permitted to hold 30 wells, but to date only 22 have been drilled, and EQT says it is stopping there. The pad itself is on a hill and it’s difficult to see all the machinery on the concrete slab from the winding country roads that encircle it.

Yet everything around it hints at the operation. Pipeline ditches, trucks, lights, road signs intended to guide the trucks away from vulnerable roads — all are preludes to the industry on the hill.

Cogar is one of the EQT’s largest pads to date. The company averages about 17 or 18 wells on a well pad.

Supersizing the wells — drilling more wells per pad and extending those wells farther underground — was a key motivator for EQT’s $6.7 billion acquisition of Canonsburg-based Rice Energy Inc. last year. The consolidation is a sign that the shale game is maturing.

Oil and gas companies across the country’s shale regions are negotiating the optimum size of a pad — one that marries the efficiencies of having one site of operations with the careful choreography of spacing the production from each well so it doesn’t overwhelm the gathering and compression infrastructure.

Denver-based Antero Resources, which drills in the Marcellus and Utica in West Virginia and Ohio, said it is averaging about 10 wells pads in the Marcellus. “That’s way up from three wells or four wells per pad just a few years ago for most operators,” Glen Warren, the company’s president, said during an earnings call in September.

Range Resources’ president and CEO, Jeff Ventura, explained in an analyst call in September 2016 that the company has been building well pads big enough to accommodate 20 wells for years. But in order to “spread a fixed amount of capital out” and make sure that the leases for those sites are secured through some level of natural gas production, Range has ended up with a bunch of pads with five or fewer wells on them.

“Looking forward, it becomes a wind in our sails,” he said. Not only can Range save on road and infrastructure construction by returning to those pads to drill more wells, Mr. Ventura said, but it can react to market trends quicker by having pads at the ready.

For example, if natural gas liquids prices tick up, Range can return crews to well pads in liquids-rich areas. If they fall, it can shift to well pads in dry gas areas.

Last year, about a third of Range’s new drilling activity came from pads that had already been drilled in prior years, a company spokesman said.

In the Permian Basin in Texas, Encana has built a “mega pad” that is slated to hold 64 wells.

It has been described as spanning the length of eight football fields and the width of two and is, by the company’s account, a very busy site with multiple rigs operating in tandem.

More than half of the wells on the “mega pad” have already been drilled, and the Canadian company is targeting rock formations at several different depths.

The same is happening in the Marcellus and Utica shales.

EQT’s largest pads — “upwards of 40 wells” — Mr. Schlosser said, will be the ones with both Marcellus and Upper Devonian wells on them. The company believes the two layers of gas-rich shale should be developed together to prevent cracks between the two from draining valuable gas.

In Greene County and further south, where EQT is likely to target only one shale layer, the company will probably average close to 20 wells per pad, he said.

Squeezing even that many on a single site requires some creative geometry in the subsurface.

Instead of drilling all of the wells straight down to what is called a kickoff point and then curving the pipe horizontally at the end, EQT is starting the kickoff process for some wells at shallower depths and taking its time with that curve before reaching the final destination. This ensures that the wells don’t crowd each other underground.

In a cross section of the earth, this kind of well would look less like an upright chair and more like a recliner.

For neighbors of such sites, the superpad trend means the oil and gas company will be visiting more often and staying longer.

If it takes a company about a year to drill and complete a well pad with a handful of wells, developing one with 15 or 20 is at least a three-year commitment, Mr. Schlosser explained, because EQT drills the wells in batches.

“We split them out in runs of five or six at a time,” he said.

Otherwise, the pipelines that collect the gas would need to be huge and would quickly become obsolete since shale gas volumes drop off significantly in the first year. The same goes for water hauling infrastructure.

So drillers will finish the first batch, let the gas flow, wait for it to taper and then start on the next half a dozen to fill the pipes back up.

As for the length of the horizontal wells, Ms. Elkin said the current “economic and technological limit” is 21,000 feet, or 4 miles. In the Utica Shale, which is deeper than the Marcellus, horizontal wells may stretch some 25,000 feet.

But that’s just for today.

Big February Coming for Shale Oil Drillers.  American shale oil drillers will deliver another month of strong growth in February, the U.S. Department of Energy forecast on Tuesday. Oil output from the nation's major shale oil regions is poised to grow by 111,000 barrels a day next month, according to the latest drilling productivity report from the department's U.S. Energy Information Administration. EIA expects total production from the seven regions to hit 6.55 million barrels a day in February. The administration also raised its estimate for January production to 6.44 million barrels a day.

Considering that in 2009, a Chesapeake Energy brochure proudly announced an eight-well “superpad” in the Haynesville Shale, all limits are subject to rapid change.

More Rigs Coming to the Bakken.  Williams County, ND, is one of three counties where more rigs are likely to land in the latter half of 2018, according to analysis by the state’s Oil and Gas Division. The other two counties are Divide and Burke. But the deployers of those new rigs are likely to be new names in the Bakken. North Dakota Pipeline Authority Justin Kringstad has developed new numbers showing break-evens in the state for every county. It shows that Divide, Williams and Burke counties are now on par with the Permian for break-evens. Kringstad is estimating five to 10 more rigs will show up in the latter half of 2018, and the three counties are the likeliest hosts. “We’ll see how that plays out,” Helms said. “I think on the optimistic side of that, the companies who used to own those properties and would normally be deploying those rigs have sold those rigs to smaller companies like Kraken and Liberty Resources. So the Oasis and Continental Resources folks that used to own those assets in Burke, and Divide and northern Williams County, where there’d be direct competition with Anadarko and the Permian, they don’t own them anymore.”

DUC’s Are Up in December.  The number of drilled, but uncompleted wells (DUCs) located in the Lower 48 U.S. states’ seven major producing plays rose by 2.1% from November to December, the Energy Information Administration’s January Drilling Productivity Report (DPR) found.

Four of the seven plays reported a month-to-month increase in DUCs, led by the Permian Basin, up 137, to 2,777, from 2,640 DUCs in November, Kallanish Energy learns.

The Eagle Ford Shale play recorded a 36-DUC increase from November to December, to 1,468, from 1,432. The Anadarko and Haynesville Shale plays reported a combined 13-DUC increase from November to December, the DPR reports.

The Niobrara, Bakken and Appalachia (the Marcellus and Utica Shale plays) plays all reported a drop in DUCs, totaling 23 (to 577 total), four (to 715), and three (to 748), respectively.

EXCO Resources Files for Bankruptcy The number of drilled, but uncompleted wells (DUCs) located in the Lower 48 U.S. states’ seven major producing plays rose by 2.1% from November to December, the Energy Information Administration’s January Drilling Productivity Report (DPR) found.

Four of the seven plays reported a month-to-month increase in DUCs, led by the Permian Basin, up 137, to 2,777, from 2,640 DUCs in November, Kallanish Energy learns.

The Eagle Ford Shale play recorded a 36-DUC increase from November to December, to 1,468, from 1,432. The Anadarko and Haynesville Shale plays reported a combined 13-DUC increase from November to December, the DPR reports.

The Niobrara, Bakken and Appalachia (the Marcellus and Utica Shale plays) plays all reported a drop in DUCs, totaling 23 (to 577 total), four (to 715), and three (to 748), respectively.

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PA Permits January 11, to January 18, 2018

           County                                   Township                                          E&P Companies

  1. Beaver                                         Marion                                                PennEnergy
  2. Beaver                                         Marion                                                PennEnergy
  3. Beaver                                         Marion                                                PennEnergy
  4. Beaver                                         Marion                                                PennEnergy
  5. Beaver                                         Marion                                                PennEnergy
  6. Beaver                                         Marion                                                PennEnergy
  7. Beaver                                         Marion                                                PennEnergy
  8. Greene                                         Franklin                                             Rice
  9. Greene                                         Franklin                                             Rice
  10. Greene                                         Franklin                                             Rice
  11. Greene                                         Franklin                                             Rice
  12. Greene                                         Franklin                                             Rice
  13. Greene                                         Franklin                                             Rice
  14. Greene                                         Franklin                                             Rice
  15. Greene                                         Franklin                                             Rice
  16. Greene                                         Wayne                                               Rice
  17. Greene                                         Wayne                                               Rice
  18. Washington                                Carroll                                                  EQT
  19. Washington                                Carroll                                                  EQT
  20. Westmoreland                            Hempfield                                          APEX
  21. Westmoreland                            Hempfield                                          APEX
  22. Westmoreland                            Hempfield                                          APEX
  23. Westmoreland                            Washington                                      CNX
  24. Wyoming                                     Forkston                                            SWN

OH Permits for week ending January 13, 2018

           County                                   Township                                          E&P Companies

  1. Belmont                                       Colerain                                             Ascent
  2. Belmont                                       Colerain                                             Ascent
  3. Belmont                                       Mead                                                  XTO
  4. Belmont                                       Mead                                                  XTO
  5. Belmont                                       Mead                                                  XTO
  6. Belmont                                       Mead                                                  XTO

Joe Barone jbarone@shaledirectories.com 610.764.1232

Vera Anderson vera@shaledirectories.com 570.337.7149

 

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