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Expo/Industry events for the next few months

Midstream PA 2018
September 25, 2018
Penn Stater Conference Center
State College, PA

WV Energy Expo 2018
October 3, 2018
Hazel and J.W. Ruby Community Center
Morgantown, West Virginia

Utica Summit
October 10, 2018
Walsh University
North Canton, OH

Shale Insight
October 23-25, 2018
David Lawrence Conference Center
Pittsburgh, PA

For other events visit

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

FERC Halts Mountain Valley Pipeline.  A $3.7 billion pipeline in America’s biggest shale gas play could be rerouted after a federal agency ordered all work on the project to stop.

In a rare move, regulators on Friday ordered EQT Midstream Partners LP to halt construction on its 303-mi Mountain Valley conduit, which would carry natural gas from the Marcellus basin to southern markets. The decision follows a U.S. appeals court’s order a few weeks ago vacating two key permits for the project.

The ruling, which requires agencies including the U.S. Forest Service to take a closer look at the project’s environmental impact, could lead to a “material re-route” for the pipeline, Height Securities LLC analysts Katie Bays and Josh Price said Monday in a note to clients.

EQT Midstream is confident that the permits in question will be restored, and that the Bureau of Land Management will stand by its decision that the route favored by the company is better than alternatives, spokeswoman Natalie Cox said in an email.

The company’s parent, EQT Corp., last month pushed the expected in-service date for the project to the first quarter of 2019 from late 2018. But late 2019 or early 2020 is more likely, Charles Robertson, an analyst at Cowen & Co., said in a note to clients.

And while the setbacks probably won’t cost EQT the $600 million it estimated earlier this year, “those construction stops do start to pile on material costs when the delays are reaching months instead of weeks,” Bloomberg Intelligence analyst Brandon Barnes said in an email.

Federal Court Vacates Two Atlantic Coast Pipeline Permits.  A federal appeals court has vacated two permits for the $6.5 billion Atlantic Coast natural gas pipeline, effectively halting pipeline construction, Kallanish Energy reports.

The order came Monday from the Richmond-based Fourth U.S. Circuit of Appeals.

The order comes just days after the Federal Energy Regulatory Commission halted work on the Mountain Valley natural gas pipeline after the same appeals court had ruled a U.S. Forest Service permit was invalid.

Eco-groups want FERC to issue a similar stop-work order on the Atlantic Coast Pipeline. Construction has started in West Virginia and North Carolina on the line, but has not yet started in Virginia.

The court, in a 62-page document, ruled two permits for the Atlantic Coast Pipeline were invalid: a permit from the National Park Service to run the pipeline under the Blue Ridge Parkway in Virginia between Augusta and Nelson counties, and a second permit allowing the U.S. Fish and Wildlife Service to allow the “incidental taking” or killing of five endangered species when no other options exist along the pipeline route.

The court called the incidental taking rule to be “arbitrary and capricious.”

Dominion Energy, one of the companies behind the pipeline, said it is working to get the two permits reinstated as quickly as possible and does not expect major delays on the project. It told Virginia media the wildlife permit impacts roughly 100 miles of pipeline: 80 miles in Virginia and 20 in West Virginia.

Construction can proceed on other sections of the pipeline.

Pipeline opponents in West Virginia and Virginia have been in court fighting the project.

Work is under way in West Virginia and North Carolina, but an erosion permit is still needed in Virginia before construction can begin.

The appeals court has scheduled a Sept. 28 hearing on the Virginia erosion issue in a separate lawsuit.

The 600-mile pipeline is designed to move 1.5 billion cubic feet per day of natural gas from the Marcellus and Utica shales through West Virginia and Virginia to the Carolinas.

It is being developed by Dominion, Duke Energy, Piedmont Natural Gas and Southern Company Gas. The project is expected to be completed in late 2019.

Tariffs Not Affecting LNG Exports.  U.S. LNG exports are soaring to record highs . EIA data notes that six LNG vessels with a combined capacity of 21.6 Bcf left the U.S, five from Sabine Pass and one from Dominion Energy's Cove Point in Maryland. For July, 30 LNG cargoes left the country, and we saw the highest exports in our history. Yet, the future still shines even brighter. By the end of next year, the number of major operating U.S. LNG export terminals will at least triple to six . Importers seek the flexible contracts, transparent hub-based pricing, and spot sales that our industry deploys, not to mention craving access to the massive and ever-growing U.S. gas production complex that is 30% larger than 2nd place Russia. (Forbes)

Appalachian NatGas Narrows Spreads with Henry Hub.  Natural gas production in the last decade in the Appalachian region has grown faster than capacity to move the gas into U.S. markets, pushing down local prices substantially.

More recently, pipeline infrastructure from Appalachia has increased capacity to deliver Appalachian natural gas to regional markets, increasing relative spot prices at Appalachian hubs, and narrowing their price spreads relative to the U.S. natural gas price benchmark Henry Hub in Louisiana.

Natural gas production in the Appalachian Basin averaged 22 billion cubic feet per day (Bcf/d) in 2017, a 25% increase from 2015 average levels, according to the Energy Information Administration.

EIA’s latest data indicate production has continued to increase, and production in Appalachia reached 26 Bcf/d in April 2018. Kallanish Energy reports.

“Based on 2017 estimates, production in the Appalachian region accounted for almost half of total U.S. dry natural gas production,” according to EIA.

As infrastructure in the Appalachian has increased, however, the summer price spread to Henry Hub has decreased. For example, in the summer of 2015, the Dominion South price was $1.48 per million British thermal units (MMBtu) lower than Henry Hub, but by summer 2017, the Dominion South Hub was $1.07/MMBtu lower than Henry Hub.

Winter spreads at the Dominion South Hub, on the other hand, have remained relatively flat in recent years, averaging $0.90/MMBtu lower than Henry Hub.

Other hubs in Appalachia have followed a similar seasonal pattern. Most of the recent pipeline buildout in Appalachia, including the Rover and Rockies Express pipelines, have been concentrated near the southwest border of Pennsylvania where the Dominion South hub is located. As a result, the price spread between Dominion South and Henry Hub has narrowed more than other hubs in north-central Pennsylvania, such as Leidy and Marcellus.

On June 1, Rover Pipeline’s interconnect to the Vector pipeline and Dawn Hub, near Detroit, Michigan, was completed, which increased takeaway capacity from southwest Pennsylvania and further narrowed the price spread between Dominion South and Henry Hub.

In June, the Dominion South price was $0.71/MMBtu lower than Henry Hub; however, the Marcellus and Leidy hubs were $1.01/MMbtu and $1.04/MMbtu lower than Henry Hub, respectively.

Encino Buys Chesapeake’s Utica Assets.  Encino Acquisition Partners announced recently it signed a definitive agreement to acquire all of Chesapeake Energy’s Utica Shale oil and gas assets in Ohio for $2 billion. EAP is acquiring 933,000 net acres of leasehold spanning the condensate, liquids-rich and dry gas windows of the Utica play in Ohio. On that property are 920 wells producing and non-producing wells, and EAP plans to operate multiple drilling rigs on the properties to increase production and cash flow.

Chesapeake was the largest leaseholder in Columbiana County and at the forefront of the leasing boom in the Utica shale that began in 2010. Canada Pension Plan Investment Board and Encino Energy formed EAP in 2017 to acquire large, high-margin oil and gas production and development assets in the U.S. lower 48 states. In support of this acquisition, CPPIB will invest approximately $1 billion in EAP and will own approximately 98 percent of the partnership. Houston-based Encino will invest in EAP alongside CPPIB and will operate the acquired assets on behalf of EAP.

Cabot Opens Office in OH. (Thank you, MDN)  Cabot Oil & Gas is drilling test wells in north central Ohio looking for “what’s next” after the Marcellus. Cabot began to push dirt around on its first OH wellpad (in Ashland) in April, and began to drill a hole on that pad in June. Cabot has also begun drilling at a second site, and has filed for a permit to drill at a third site, in Vermillion Township in Ashland County. We’ve read comments by Cabot that the type of exploration they’re doing in OH just as often doesn’t pan out as it does–no doubt trying to manage and tamp down expectations. However, actions speak louder than words. On Monday Cabot held a ribbon-cutting ceremony for a new (albeit small) branch office located in Jeromesville (Ashland County). Sure looks to us like things are getting serious!

In the past Cabot has been cagey about which rock layer they’re targeting in Ohio. We know it’s not the Utica. Devon Energy previously tried drilling the Utica in Ashland–it didn’t work. While both the Knox and the Rome layers have been mentioned in Cabot’s permits, it appears it is the Knox layer that is Cabot’s targeting. Although Cabot doesn’t admit what they’ll find (oil, gas, NGLs), it’s clear they’re hoping to find oil.

FERC Approves Northern Access Pipeline. (Thank you, MDN)  On Feb. 3, 2017, the Federal Energy Regulatory Commission (FERC) approved a long-delayed project–National Fuel Gas Company’s (NFG) Northern Access 2016 pipeline project. The $500 million project includes building 97 miles of new pipeline along a power line corridor from northwestern Pennsylvania up to Erie County, NY. The project also calls for 3 miles of new pipeline further up, in Niagara County, along with a new compressor station in the Town of Pendleton. Although FERC granted permission to build it, the State of New York, specifically the state’s Dept. of Environmental Conservation (DEC), arbitrarily and capriciously tried to block it.  NFG, in no mood to screw around filed a motion asking FERC for a “reconsideration and clarification” on the role of the DEC in reviewing the project. On Monday, FERC ruled on that request, ruling in NFG’s favor and against NY DEC. FERC said the DEC took longer than the one year they have under law to issue their rejection, therefore, FERC itself is issuing the water permits.

Summit Opens Binding for Permian’s Delaware Basin.  Summit Midstream Partners is holding a binding open season for its Double E natural gas pipeline in the Permian Basin in West Texas and New Mexico, Kallanish Energy reports.

The open season on 500 million cubic feet of available capacity will close on Sept. 14. Total capacity is in excess of 1 billion cubic feet per day.

Last week, Summit Midstream announced a deal with XTO Energy, an ExxonMobil subsidiary, to become a foundation shipper on the pipeline project.

The pipeline will connect the northern Delaware Basin in West Texas and New Mexico to the Waha Hub in West Texas. The pipeline is expected to begin service in 2021.

The project will stretch 134 miles with 30- to 42-inch pipe.

It will originate in Eddy County, New Mexico, and serves Lera County in New Mexico and Loving, Reeves, Ward and Pecos counties in Texas.

Summit Midstream will handle the development, permitting and construction of the pipeline and will operate the pipeline upon commissioning.

Summit Midstream and ExxonMobil have also executed an equity option agreement that provides ExxonMobil or an affiliate the right to become an equity partner in Double E.

Crude Outlook Positive through 2019. (Thanks, Rick Stouffer, Kallanish Reports)   These are relatively heady times in North America’s oil and gas industry. Gone are the dark days roughly three years ago when it was hard scanning bankruptcy court dockets and not finding an oil and gas-related company that had overextended when West Texas Intermediate crude was pushing $100/Bbl, but during 2015 fluctuated between more than $60/Bbl, to under $40/Bbl at the end of the year.

Forced to become super-efficient or die, the industry responded, cut expenses, upped efficiency to levels no one had previously thought about, and pulled the industry out of the red and into the black.

Short-term outlook positive

The good news when looking forward from mid-2018 is that a number of industry watchers see continuing through the remainder of 2018 and well into 2019, Kallanish Energy reports.

“Investor confidence in upstream continues to recover due to rising oil prices and sustained oil demand growth,” according to Conglin Xu, senior editor-Economics for Oil & Gas Journal. She was the primary speaker during a recent webinar presented by O&GJ.

Xu laid out her company’s midyear forecast for 2018 and 2019, and the overall message was positive – although there remains a handful of what O&GJ Editor Bob Tippee labeled “uncertainties” that will impact crude prices should any or all come into play.

Crude production growing

One thing Xu emphasized is that crude production worldwide will increase over the next two years and, in some locations, production should grow for the next decade.

Russia, which currently is producing roughly 11.1 million barrels per day (Mmbpd), will expand its output by more than 200,000 bpd, Xu told her webinar audience, quoting consulting firm ESAI Energy. Russia currently has 500,000 Bpd of spare capacity.

“Brazil production will grow annually to 2030 by an average of 130,000 Bpd,” Xu said. “Canada’s output will grow 750,000 Bpd over the next decade, while Mexico’s production will continue to decline, to 2 Mmbpd.”

The Permian

But it’s the U.S. – specifically the Permian Basin – where the real crude oil production action is white-hot. Permian production is roughly 3.3 Mmbpd, while pipeline capacity out of the Permian is 3.5 Mmbpd – or lower – which is the only hindrance to hold down the basin’s crude production.

“New rig additions in the Permian stalled as the infrastructure bottleneck weighed on the price of Permian crude grades,” according to Xu.

Producers actually have moved some rigs from the Permian to other basins, Xu said, with the biggest benefactor a cross state move to the Eagle Ford Shale.

Spending grows

Spending in the U.S. shale plays expands in 2018, according to Xu, with global investment in upstream operations in oil and gas will increase by 5% this year, to $475 billion.

Looking at crude demand, Xu said U.S. demand this year will reach 20.38 Mmbpd, up 2.4% from 2017, while worldwide demand will jump 6.7% in 2018 from 2017, to just under 28 Mmbpd.

But all is not perfect in the O&G world. As previously mentioned, O&GJ editor Tippee offered five uncertainties which could impact the forecast.

Among the potential roadblocks to continuing good news in O&G, Tippee’s list included how long the OPEC+ supply management pact will last, along with what geopolitical upsets somewhere in the world might occur.

“How will trade tensions affect (production), and by how much might a trade war curb supply?” Tippee said. Finally, where is the balance between (industry) deregulation and reregulation?”

“Man Camps” Are Back.  There’s not much to look at except dirt, mesquite, and sagebrush around the 10 acres of flat, almost treeless land near Goldsmith, Texas, where Aries Residence Suites runs a housing complex used by itinerant oil workers. Three years ago, all 188 rooms were as empty as the landscape—a testament to crude’s tumbles from more than $100 a barrel to $30. Today, prices are up around $70 and almost every Aries bed is occupied, just as at many other “man camps” throughout West Texas. The Permian Basin, a more than 75,000-square-mile expanse of sedimentary rock that’s one of the world’s biggest oil plays, is drawing billions of dollars in new investment. Companies are scrambling to find people to do everything from operating drilling rigs to driving trucks. Wages have reached such lofty levels that even unskilled laborers can earn $100,000 a year. Many of the jobs are in remote areas with no houses, schools, or supermarkets, so free room and board are essential perks for workers, most of whom elect to leave their families at home.

Price Disconnect in NatGas Storage in the East.  (Thank you, BTU Analytics)  Just past the halfway point of injection season, US natural gas storage levels are at 2.27 Tcf, which are nearly 560 Bcf below the 5-year average storage level and only 29 Bcf above the lowest storage level at this point over the last five years (2014). The East and Midwest regions are trending particularly low as both fell below their 2014 regional low storage levels in June and have remained low in the weeks since. While storage levels have been trending low, pricing has remained relatively constant. In the past, prices have typically increased when storage levels have fallen below the 5-year average. However, so far this year, we have not seen an increase in pricing like we saw when storage levels dropped in 2013 and 2014. Today, we will take a closer look at injection rates in the East and how those might affect end of season storage levels and pricing as we head into winter.

EOG 2ND Qtr. Update.  EOG Resources reported second-quarter net income of $697 million, buoyed by a 15% increase in total crude production in the U.S., Kallanish Energy reports.

That compares to net income of $23.1 million in Q2 2017.

Quarterly revenue increased from $2.6 billion to $4.2 billion, a 60% increase.

The company credited higher oil prices, larger production volumes and reduced costs for much of the profit gain in the quarter.

“EOG delivered a strong quarter, meeting or exceeding expectations for production volumes, price realizations and operating expenses,” said chairman and CEO William R. Thomas, in a statement.

“The EOG machine is firing on all cylinders. We grew crude oil production in five operating areas while reducing costs. Our disciplined investments across a diverse array of premium plays are generating record rates of return,” he said.

Second quarter oil production was a company record of 384,000 barrels per day, with the biggest increases in the Delaware Basin in West Texas and New Mexico, the Eagle Ford in South Texas and the Powder River Basin (PRB) in Wyoming, the company said.

It also operates in the Bakken Shale in North Dakota and Montana and the DJ Basin in Colorado.

The company said it intends to expand oil drilling in the Powder River Basin, where it has leased 400,000 acres. It has two rigs at work and intends to complete 45 net wells in 2018. It intends to expand drilling and infrastructure in 2019.

It is eying the Mowry and Niobrara shales along with the Turner formation in Wyoming.

That effort will add 1,600 premium drilling sites and more than 30 years of oil or more than 2.1 billion potential barrels of oil-equivalent, it said. The company drilled seven Turner wells in Q2 2018.

The company’s emphasis is to only drill and complete wells in premium locations. In Q2, the company drilled 216 net wells with 67 in the Eagle Ford and 70 in the Delaware Basin.

It's increasing its production in the Austin Chalk in South Texas with five new wells.

SWN 2nd Qtr. Update.  Southwestern Energy on Friday reported a 19% increase in the Appalachian Basin production in the second quarter, Kallanish Energy reports.

Its net Appalachian production was 167 billion cubic feet-equivalent, or 1.8 billion cubic feet-equivalent per day, including 20% liquids production, the Texas-based company said.

The company’s overall quarterly production was 234 Bcfe from two Marcellus Shale areas and from the Fayetteville Shale in Arkansas. That is up 5% from Q2 2017.

In Northeast Appalachia, total net production was 112 Bcf, or 1.2 Bcf/d, a 15% increase from Q2 2017, the company said.

It placed 17 wells in northeast Pennsylvania to sales in the quarter, 11 of which were online for 30 days and had an average 30-day rate of 17.2 million cubic feet per day.

Southwestern said it has expanded its core position in Pennsylvania’s Tioga County to 37,500 net acres. Last month, the company signed a joint venture with a private company, adding 23 future drilling locations in Tioga County.

In Southwest Appalachia, total net production in southwest Pennsylvania and West Virginia was 55 Bcfe, or 604 Mmcfe/d, including 60% liquids.

It said natural gas liquids averaged 53,500 barrels per day and oil production averaged 7,800 Bpd in the quarter. Those are increases of 47% and 31%, respectively, compared to Q2 2017, it said.

The company is largely focused on the gas-rich area in West Virginia that provides some of the highest margins in the company’s portfolio.

It turned 26 wells to sales and reported the margin in Southwest Appalachia was 76% higher than a year ago. The margin improvement was driven by higher liquids production and prices, Southwestern said.

It said two wells on a recently developed pad are still producing 1,500 Bpd of condensate after 90 days of production and are among the highest condensate producers reported in the Appalachian Basin.

It said its gas-rich wells account for 75% of the company’s drilling efforts in Southwest Appalachia in 2018. The company in Q2 2018 drilled 37 wells, completed 56 wells and placed 46 wells into service.

Southwestern reported second-quarter net profit of $51 million, compared to a net gain of $284 million one year ago. Operating revenue was $816 million, up from $811 million.

Continental Resources 2nd Qtr. Update.  Continental Resources on Wednesday reported second-quarter net income of nearly $243 million, as oil and natural gas production grew by 26% from a year ago, Kallanish Energy reports.

In Q2 2017, the company reported a net loss of $63.6 million.

Continental reported its second quarter revenue grew by 72%, to $1.14 billion, due to increased production and a major jump in its oil sale prices to an average of $63.35 per barrel.

Net cash provided by operating activities in the quarter was $753.8 million. EBITDAX for the quarter was $896.7 million.

The Oklahoma-based company reported Q2 production of 25.8 million barrels of oil-equivalent, or 284,059 Boe/d. Total Q2 production included 157,116 Bpd of oil and 761.7 million cubic feet per day of natural gas.

The company’s Bakken Shale production in North Dakota and Montana averaged 158,119 Boe/d, up 32% from a year ago.

In Q2, the company completed 35 gross (19 net) operated wells flowing at an average initial 24-hour rate of 2,282 Boe/d.

In the Bakken, it intends to operate five completion crews and six rigs in the second half of 2018. The rig count will grow to seven by the end of the year.

The company reported its STACK production in Oklahoma increased by 61.9% from a year earlier, while production in Oklahoma’s SCOOP play increased by 6%.

The company said it completed 26 gross (13 net) operated STACK wells with first production in Q2 2018. It completed 16 gross (13 net) operated SCOOP wells with first production in Q2.

The company expects to average four completion crews in Oklahoma and 18 rigs in the second half of 2018.

Eleven of those rigs are in the company’s Project Springboard in the SCOOP play where the company plans to drill 350 wells in a 70-square-mile area. That area will have 13 rigs working by the end of 2018.

That project could increase the company’s oil production by as much as 10% over the next year, officials said.

Permian Pipelines Ahead of Schedule.  Plains All American Pipeline LP said two West Texas crude pipeline projects would begin partial operations slightly ahead of their original schedules as bottlenecks in the region depress prices to the weakest level in four years. “We expect continued growth across our gathering and intrabasin pipeline systems (in the Permian) and to operate at or near capacity on our takeaway pipelines throughout the second half of the year,” said Greg Armstrong, Plains chief executive. The Permian basin in West Texas and western Canada has been grappling with takeaway constraints as oil production in the region has outpaced pipeline capacity.

NatGas Saving Money for Ohioans. Thanks to increased production and new technologies, which have decreased the price of natural gas, Ohio energy consumers saved more than $40.2 billion between 2006 and 2016, according to a new report released today by Consumer Energy Alliance (CEA).

Thanks to increased production and new technologies, Ohio energy consumers saved more than $40.2 billion between 2006 and 2016, according to a new report released today by @CEAorg

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PA Permits August 2, to August 9, 2018

County                                   Township                                          E&P Companies

  1. Greene                                         Morris                                                 CNX
  2. Greene                                         Morris                                                 CNX
  3. Greene                                         Morris                                                 CNX
  4. Greene                                         Morris                                                 CNX
  5. Susquehanna                            Brooklyn                                            Cabot
  6. Susquehanna                            Brooklyn                                            Cabot
  7. Susquehanna                            Brooklyn                                            Cabot
  8. Susquehanna                            Brooklyn                                            Cabot
  9. Susquehanna                            Brooklyn                                            Cabot
  10. Susquehanna                            Brooklyn                                            Cabot
  11. Susquehanna                            Brooklyn                                            Cabot
  12. Washington                                Nottingham                                       Range
  13. Washington                                Nottingham                                       Range
  14. Washington                                Nottingham                                       Range
  15. Washington                                Nottingham                                       Range
  16. Washington                                Nottingham                                       Range
  17. Washington                                Nottingham                                       Range

OH Permits for weeks ending August 4, 2018

County                                   Township                                          E&P Companies

  1. Belmont                                       Pultney                                              XTO
  2. Belmont                                       Pultney                                              XTO
  3. Belmont                                       Richland                                            Ascent
  4. Guernsey                                    Washington                                      Ascent
  5. Guernsey                                    Washington                                      Ascent
  6. Jefferson                                     Smithfield                                          Ascent
  7. Jefferson                                     Smithfield                                          Ascent
  8. Monroe                                        Green                                                 Eclipse

Joe Barone 610.764.1232
Vera Anderson 570.337.7149

Northeast Supply Enhancement