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Expo/Industry events for the next few months

DUG Eagle Ford
August 29-31, 2017
San Antonio, TX 
Shale Insight
September 27-28, 2017
David Lawrence Center
Pittsburgh, PA 
West Virginia Energy Expo
October 4, 2017
Morgantown, WV  
Utica Summit
October 11, 2017
Walsh University
North Canton, OH  
Midstream PA 2017
October 19, 2017
Penn Stater Conference Center
State College, PA 
For other events visit

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

EQT 2nd Qtr. Update.  EQT announced second-quarter 2017 net income of $41.1 million, compared to a net loss of $258.6 million in the year-ago quarter, Kallanish Energy reports.
Net cash provided by operating activities was $294.2 million, $85.7 million higher than 2Q 2016, the company said.
The company also announced in the second quarter that it is merging with Rice Energy, in a deal worth $8.2 billion.
“Rice is an outstanding strategic and operational fit for us, and we anticipate the combined entities will capture significant operating efficiencies, improved overall well economics and deliver stronger returns to our shareholders. With our asset position in one of the most prolific natural gas basins in the world, we remain confident in our ability to drive both near- and long-term value creation,” said president and CEO Steve Schlotterbeck, in a statement.
Earnings and cash flow were higher primarily as a result of increases in commodity prices and produced volumes, EQT said.
“Significant sales volume growth and an increase in the average realized price contributed to our strong second quarter,” Schlotterbeck added.
The company reported 2Q 2017 production was up 7% over 2Q 2016 and the average realized price was 36% higher. Production was 198.1 billion cubic feet-equivalent in the quarter.
The company drilled 66 gross wells in the second quarter, including 43 Marcellus Shale wells and 23 Upper Devonian wells. It began production from 17 wells: 15 in the Marcellus and two in the Upper Devonian.
In anticipation of its merger with Rice, EQT suspended its Utica Shale test program. That is because improved returns on Marcellus Shale wells from longer laterals made possible by the Rice acquisition are higher than the return expected on the average Utica well today.
The company reduced its 2017 sales volume guidance by 10 to 15 Bcfe as a result of the suspension of the Utica program.
Rice Acquires LOLA.  (This acquisition was not mentioned in the releases we saw about EQT’s 2nd quarter financial report.)  NGI’s Shale Daily has done it again. Ace reporter Jamison Cocklin has unearthed news that (so far) no one else has: Rice Energy has quietly, confidentially, hush-hush purchased all of the assets of LOLA Energy. 
The sale raises a lot of questions. But first, who is LOLA? No, not the show girl in Barry Manilow’s 1978 hit song Copacabana. LOLA Energy was birthed near the end of 2015, by former EQT executives using $250 million of private equity money from Denham Capital.
The name LOLA comes from the phrase Locally Owned, Locally Accountable. LOLA didn’t waste any time. They leased land in Greene County, PA–a prime location highly prized by both Rice Energy and EQT–and also in West Virginia, land in Monongalia, Wetzel and Marion counties. Shale Daily reports that rumors have been swirling for weeks, but NGI now has the goods–copies of transfer records going from LOLA to Rice. For some reason, perhaps related to EQT’s impending purchase of Rice Energy, Rice and LOLA have kept the deal hush-hush. But the lid is off now! 
Shell to Focus More on Shale.  Shell plans to have a portfolio more balanced between shale and deepwater assets, CEO Ben van Beurden said Thursday, noting the company’s portfolio today seemed more heavily weighted toward offshore assets, Kallanish Energy learns.
“A shale portfolio isn’t a bad portfolio, but it needs to be high-graded here and there. So we will be buying and selling bits and pieces here and there,” the executive revealed, without disclosing further details.
With shale operations in the U.S. and in Argentina, Shell is now looking to have shale and deepwater with “sort of an equal weight, so that we can enjoy the resilience of the deepwater business, but also enjoy the CAPEX flexibility of the shale business,” he said.
The Anglo-Dutch supermajor plans capital expenditures of $25 billion, in projects that offer most competitive break-even and resilient options. Shell's chief financial officer, Jessica Uhl, said during an analyst conference call Shell is looking at new projects that make economic sense at $40 a barrel or below, and at liquefied natural gas (LNG) projects economically with LNG prices in the $5 range.
Uhl revealed there are two deepwater projects on the radar for sanctioning in the next two years: one off Nigeria and one in the Gulf of Mexico. She added the decisions will be based on value, while decisions on LNG projects will also take into consideration “the right timing.”
In terms of shale acquisitions, van Beurden said if there’s an opportunity to deepen the company’s position in shale exploration and production, he will take it, without participating in a gold rush.
Shell is investing around $2-$3 billion in shale operations, with over $1 billion exclusively in the Permian.
Nexus Delayed until 2018.  The stalled Nexus natural gas pipeline across northern Ohio will be delayed into 2018, Kallanish Energy reports
That news came from DTE Energy in a Wednesday earnings call with analysts and the media.
When next year the $2 billion pipeline might be in service depends on when the project might win approval from the Federal Energy Regulatory Commission, which still lacks a quorum to conduct business, said DTE chairman and CEO Gerard Anderson.
“As you know, the FERC quorum has not yet been restored. And, as I said on the first-quarter call, we expected a year-end 2017 in-service date if we received a FERC certificate by the end of the second quarter or sometime within reach of mid-year.
“We also said on the first-quarter call that if the FERC certificate wasn’t received within that time frame, then the project might push into 2018. Well, that’s where we are now — with an in-service date in 2018,” Anderson said.
“We continue to make progress on the pipeline in the interim. So we have all the materials and equipment, nearly all the right-of-way easements, we’re in the final stages of obtaining the necessary permits and our construction contracts are in place,” he added.
Anderson said once the FERC certificate is received, work will begin and, at that time, a more precise projected in-service date will be provided. Construction will take seven to 10 months, the company said.
The 256-mile pipeline being developed by Nexus Gas Transmission would transport natural gas from the Utica and Marcellus Shale plays in Ohio, West Virginia and Pennsylvania to the Midwest, Ontario and the Gulf Coast.
The 36-inch line could transport up to 1.5 billion cubic feet per day. About two thirds of the capacity has been contracted, officials said. It's being developed by Texas-based Spectra Energy and Michigan-based DTE Energy.
Nexus opponents had offered an alternate route away from the Akron-Canton area of Ohio, but the company has opposed that option.
FERC Approves Atlantic Coast Pipeline.  The Federal Energy Regulatory Commission staff has approved a final environmental impact statement for the $5 billion Atlantic Coast Pipeline, Kallanish Energy reports.
The 600-mile pipeline will have “numerous impacts” but those can be mitigated, the federal agency said in its 866-page main report. The report was prepared by four federal agencies and two West Virginia state agencies.
The pipeline must still be approved by the FERC commissioners after a quorum has been confirmed by the U.S. Senate.
The pipeline is being developed to move 1.5 billion cubic feet per day of natural gas from the Marcellus and Utica Shale plays from West Virginia to the Carolinas.
The pipeline is being developed by four U.S. energy companies: Dominion, Duke Energy, Piedmont Natural Gas and Southern Company Gas.
FERC last December released its draft environmental impact statement for the project. The application was filed with FERC in September 2015.
Halliburton 2nd Qtr. Update.  The Houston energy services company Halliburton said Monday that its revenues jumped in the second quarter as its North American fracking business boomed, but the company expects the pace of growth to slow as oil prices remain low in the coming months.
The slowdown should help Halliburton customers - the oil producers - from pumping too much oil too fast and further undermining prices and the industry's recovery, said Dave Lesar, the executive chairman Dave Lesar.
"The rig count growth is showing signs of plateauing and customers are tapping the brakes," said Lesar, who will remain executive chairman until he retires at the end of 2018.
Lesar's successor, CEO Jeff Miller downplayed the slowdown, saying the growth in North American shale drilling is "going from 80 miles an hour to 70 miles an hour." James West, an analyst at investment bank Evercore ISI in New York, agreed with Miller, arguing that "tapping" is not the same as "slamming" the brakes.
Halliburton reported nearly $5 billion in revenues in the second quarter, up nearly 30 percent from the same time last year and 16 percent from the first quarter of 2017, as exploration and production companies flocked to U.S. shale plays, particularly the Permian Basin in West Texas. Halliburton is the North American leader in oilfield services, especially hydraulic fracturing, or fracking.
Halliburton swung to a small profit $28 million the second quarter, after a $32 million loss in the first quarter and a $3.2 billion loss in the second quarter of 2016 after it paid the $3.5 billion termination penalty from its failed takeover of Houston rival Baker Hughes. Halliburton's stock fell by $1.87 a share, or 4.2 percent, to close at $42.51 Monday.
Halliburton's rival, the world's leading energy services firm, Schlumberger, also reported big revenue gains and last week, but its stock slipped, too on Friday over investor fears the worldwide oil glut will persist and ultimately undercut drilling activity. Schlumberger's stock dipped 11 cents Monday to $66.42 a share. The nation's active drilling rig count is now at 950 rigs, up from an all-time low of 404 rigs in May 2016, according to Baker Hughes, a GE company, which tracks the data. This past week saw the total rig count dip by two, only the second time since early January the number of active oil rigs has declined.
"It's not rocket science that - with oil prices in the mid-$40s - the rig count will start to slow," said Byron Pope, an energy analyst with Tudor, Pickering, Holt & Co. in Houston. That slowdown doesn't mean the nation's oil field activity will plummet, he said. It should to grow at a more measured, and maybe even healthier pace, Pope added.
Halliburton has recently focused on gaining market share as the oil and gas industry recovers. Halliburton's North American revenues jumped 24 percent over the first quarter of 2017.
In March, Halliburton said it was adding 2,000 jobs to North American oil fields, especially in the Permian Basin. Halliburton now counts more than 50,000 employees after cutting 35,000 positions over the two-year oil bust.
BTU Analytics Challenges EIA Drilling Productivity Report.  There’s no Slowdown.  Recent headlines from journalists and industry veterans alike have pointed to the latest EIA Drilling Productivity Report (DPR) as a sign that US oil production growth rates are slowing and that the growth in Permian productivity has stalled out. (See chart below).  BTU Analytics would contend that those hoping that Permian productivity has hit a peak and thus US oil production forecasts are overblown are deceiving themselves.
 Each month, the EIA estimates the productivity of the US shale rig fleet for seven major shale producing areas including the Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian, and Utica. Let’s begin by briefly reviewing the EIA Drilling Productivity Report model methodology using a numerical example in parenthesis.
First, the EIA estimates legacy gas production changes by comparing production between two consecutive months. In the first month, EIA sums the production from all producing wells in that period (100 B/d) and then in the second month sums the production from the same group of wells as the first month (75 B/d). The difference in production between month 1 (100 B/d) and month 2 for the same wells (75 B/d) is the legacy production change (-25 B/d). In a perfect world, the difference between month 1 and month 2 for the same wells would nearly always highlight a decline in the base production because reservoir pressures should decline between month 1 and month 2 reducing the total output from the wells.
The next step toward calculating rig productivity is to subtract the legacy production (75 B/d) from total production in month 2 (200 B/d). The resulting output should be the new production (125 B/d) added by producers in month 2. The EIA Drilling Productivity Report model then divides the new production (125 B/d) by the total number of rigs operating two months ago in the basin (25 active rigs) to calculate productivity per rig (125 / 25 ) = 5 B/d per active rig.
Month 1 Total Production = 100 B/d
Production from Legacy Wells in Month 2 = 75 B/d
Month 2 Total Production = 200 B/d
New Production Added = 200 – 75 = 125 B/d
Total Active Rigs 2 Months Prior = 25
Productivity per Rig = New Production Added / Total Active Rigs =
125 / 25 = 5 Barrels of oil per rig
There are several potential flaws with modeling rig productivity utilizing this approach. The first flaw is that it assumes all new production in period 2 originated from rigs active just two months prior.  It’s no secret at this point that the industry has a tremendous ability to add rigs quickly to a region, but completion crews often fail to keep pace with producers in the basin.  From 2009-2015, operators in the Marcellus and Utica outstripped the ability of infrastructure and completion crews to keep pace with drilling activity, leading to a peak of nearly 1,600 wells in excess backlog, and oil plays have been no different. The price crash in 2015 led operators to defer completions across all of the major oil producing areas, leading to an excess backlog that peaked in 2016 at over 2,000 wells in the Eagle Ford, Permian, Bakken, and Niobrara.
Going back to the example above with 25 rigs running, what happens to rig productivity if producers are only completing 80% of the wells they are drilling in that period? From the EIA Drilling Productivity Report model methodology, the rig productivity would still be 5 barrels per rig, but effectively only 20 rigs contributed production in period 2 since 20% of the wells were deferred to a future period. If we account for the fact that producers deferred 20% of the wells drilled and divide the new production (125) by 20 rigs (25 x 80%), then the rig productivity increases to 6.25 barrels per rig, or 25% higher than the estimate EIA would have of 5 barrels per rig. This also means that the 5 rigs that did not contribute production in period 2 have built a backlog of wells capable of adding an additional 31.25 barrels of production per day in a future period.  The above example assumes that operators deferred completions to a future period, but the inverse can also be true.
Rig productivity in period 2 could be  overstated if operators deferred completions from an earlier period into period 2 giving the rigs active today an artificial uplift from work done in an earlier period.
Now that we have worked through EIA Drilling Productivity Report methodology with a simplified example, let’s return to the fact that the EIA Drilling Productivity report shows that Permian rig productivity peaked in August 2016 at 707 barrels per rig and has declined to an estimated 597 barrels per rig.
The above chart adds BTU Analytics’ estimates of wells drilled and wells completed for the Permian basin as well as the EIA’s estimate for rig productivity and active rigs. The peak in rig productivity in August coincides with the bottom in the total number of rigs active in the basin. However, completion activity did not follow active rigs to new lows in the summer of 2016 but actually began to increase as producers responded to higher oil prices that had risen from a low of $30.44 per barrel in February 2016 to as high as $48.59 in June 2016, which was just prior to the “peak” in rig productivity.
Since August of 2016, producers have added nearly 200 rigs to the Permian basin, of which 95% are drilling horizontal wells. While producers have continuously added rigs, completion crews have failed to keep up. As of July 2017, BTU Analytics estimates the fleet drilled 375 horizontal wells but only turned to sales approximately 250 wells, reducing the effectiveness of the rig count by 33%. Adjusting the rig productivity for July by the effective rig count (607 / 67%) indicates that rigs are contributing more than 900 barrels per rig, nearly 30% above the EIA peak in productivity in August 2016.
Rig productivity in 2017 likely only gets better if the initial trends in 2017 continue. Operators are pushing towards longer laterals across the board. So far, only Delaware Texas has yet to see a bump in overall lateral lengths (Note: Chart only includes wells with reported production data as of July 2017).
Not only are lateral lengths getting longer for producers in the Permian Basin, but new completion designs utilizing more proppant per lateral foot are contributing to higher initial production rates. The graphic below shows the 30-day average initial production rate normalized for 1,000 feet of lateral.  Despite wells being completed in 2017 in Delaware Texas not being longer than the wells in 2016, the average initial production per 1,000 feet of lateral has increased 54%, and wells in Central Midland have seen IP rates per 1,000 feet of lateral double.
As completion crews race to keep up with drilling rigs throughout 2017, be wary of analysis showing declining productivity.  To follow these developments in coming months, subscribe to the BTU Analytics’ Oil Market Outlook  or follow our Permian production forecast in our Upstream Outlook.
Rover Pipeline Has Problems in WV.  The West Virginia Department of Environmental Protection (WVDEP) has ordered Energy Transfer Partners LP's (ETP) Rover Pipeline LLC to cease and desist development activities because of violations under the project's state-issued water pollution control permit.
In an order issued last week and filed with FERC Monday, WVDEP said Rover must suspend "land development activity until such time when compliance with the terms and conditions of its permit and all pertinent laws and rules is achieved."
WVDEP conducted site inspections of Rover construction in progress on April 26 and July 12 and said it observed several violations related to improper sediment and erosion controls. The alleged violations occurred as Rover constructed its Sherwood Lateral and Sherwood Compressor Station in West Virginia’s Doddridge and Tyler counties.
Rover has been ordered to "immediately install and maintain necessary storm water and sediment/erosion control devices to prevent the release of sediment-laden water into the waters of the state" and to submit a detailed plan of corrective action.
Asked about the order, ETP spokeswoman Alexis Daniel said the operator would "continue to work with" WVDEP "to resolve these issues in a manner that is satisfactory to all parties.” Construction continues, she said, in West Virginia’s Hancock and Marshall Counties.
Hess 2nd Qtr. Update.  Hess Corp. reported Wednesday a bigger loss in the second quarter compared to a year ago, as the company produced fewer barrels of oil due to a drilling cutback.
The company said losses in its exploration and production unit, its biggest, rose to $354 million in the second quarter, from $328 million a year earlier, Kallanish Energy reports.
"Our loss before income taxes was $425 million in the second quarter of 2017, compared with a loss before income taxes of $678 million in the prior-year quarter," the company explained. "The improved second quarter 2017 pre-tax results reflect higher realized crude oil selling prices and lower operating costs and exploration expenses that were partially offset by lower sales volumes."
Net production, excluding Libya, fell to 294,000 barrels of oil-equivalent per day (BOE/d) from 313,000 BOE/d.
Hess, like its fellow independent producer Anadarko Petroleum did earlier this week, cut its 2017 E&P capital budget, in New York-based Hess’ case, to $2.15 billion from its previous guidance of $2.25 billion.
Like many of its peers, Hess is struggling to adapt to the fall in oil prices this year.
Appalachian Lawmakers Ask Trump for $10 Billion for Underground Storage.  Having lost tens of thousands of coal mining jobs to the rise in natural gas, several states have decided if you can’t beat them, join them.
A bipartisan group of lawmakers hopes to persuade President Donald Trump to spare a loan program he wants to kill and use it to help a $10 billion gas-storage project in the hard-hit Appalachian region of the eastern U.S. where coal had once dominated. Proponents say it would help spur new chemical, refining and other manufacturing industries -- and give out-of-work miners a new career path.
"We need a more diverse portfolio," said Brian Anderson, director of West Virginia University’s Energy Institute, and a member of the project’s coordinating committee. "If you have one industry that dominates your economy and that industry sees a decline then it really runs huge ripples through your entire economy."
Coal and natural gas compete in the electricity markets and the proliferation of fracking in recent years led to cheaper gas that has displaced coal. Coal had once accounted for more than half of all U.S. electricity generation, but last year natural gas topped coal to become the largest source of power generation. The impact has been felt especially hard in the Appalachian region -- which was once largely dependent on coal mining and steel production.
The Appalachian Storage Hub, estimated to cost as much as $10 billion, could encompass underground caverns in Pennsylvania, Ohio or West Virginia, although the final site has yet to be selected. It would have the capacity to hold as much as 100 million barrels of ethane, methane and other products produced in conjunction with natural gas. It would also include a 3,000-mile pipeline network to link up the storage sites with petrochemical plants.
Millennium Seeks FERC Approval.  Millennium Pipeline is asking the Federal Energy Regulatory Commission for permission to begin construction on its stalled Valley Lateral Project, even though New York State has not approved the $275 million project, Kallanish Energy reports.
Millennium Pipeline is seeking FERC approval by Aug. 31, to proceed on the new lateral in southern New York. The project is a 7.8-mile line in Orange County to serve the natural gas-fired CPV Valley Energy Center in Wawayanda, N.Y. That $1 billion plant is 80% complete and testing will likely begin in August.
The plant is being developed by Maryland-based Competitive Power Ventures Holdings. It requires 130 million cubic feet per day (MMcf/d) of natural gas to generate electricity at the 640-megawatt plant.
The pipeline project also calls for adding and improving compressor and metering stations in Sullivan, Rockland, Orange and Delaware counties, and improving connections with other pipelines.
The project will boost natural gas flow by 223 MMcf/d the company said.
The New York Department of Environmental Conservation has failed to approve the new lateral for 19 months, in what many observers see as an effort by New York State to block drilling and pipeline projects.
The state agency must approve a water-quality certification to build the pipeline and is supposed to take action within 12 months.
The company filed its 1,200-page application with New York DEC in November 2015.
Millennium Pipeline later took New York State to court. Last June, the U.S. Court of Appeals for the District of Columbia dismissed the suit, but said FERC could step in and approves the project because the state had failed to act.
That led the company to file last week a detailed 15-page letter to FERC outlining its efforts.
The Millennium Pipeline, completed in 2008, runs 244 miles from Steuben County to Rockland County in New York State.
Interior Department to Repeal Fracking Regs.  The U.S. Department of the Interior announced plans to erase the Obama administration’s regulations over hydraulic fracturing on federal land, Kallanish Energy learns.
The proposed repeal, published Tuesday in the Federal Register, said the 2015 final rule was “unnecessarily duplicative of state and some tribal regulations” and imposed “burdensome reporting requirements and other unjustified costs on the oil and gas industry.”
House Natural Resources Committee chairman Rob Bishop, a Utah Republican and a critic of the regulations, praised Interior Secretary Ryan Zinke for the move.
“I applaud Secretary Zinke and his team for their work in returning the Department, its sub-agencies and bureaus to their core statutory functions,” said 
Another Pipeline for the Bakken.  The North Dakota Public Service Commission is holding public hearings on the largest pipeline proposed in the state since the Dakota Access Pipeline (DAPL) protests.
Commissioner Julie Fedorchak said she hasn’t heard of opposition to the project proposed by Cenex Pipeline, but the commission has notified local law enforcement about the hearings.
“We want to make sure we’re prepared for any type of protest,” Fedorchak told the Bismarck Tribune newspaper.
Cenex, a subsidiary of Minnesota farmer cooperative CHS, proposes to build a 10-inch, 180-mile pipeline from Sidney, Mont., to Minot, N.D., to transport refined fuels such as gasoline and diesel fuel. The project would replace a portion of an existing 8-inch pipeline and add additional capacity.
The $160 million project would transport about 38,000 barrels per day (BPD), Kallanish Energy learns.
Public hearings were scheduled for Monday and today at Tioga City Hall.
Commissioner Brian Kroshus said the Dakota Access protests “really changed the game.” “We’re prepared that there might be some voices of opposition,” said Kroshus, who joined the commission in the aftermath of the protests, which involved thousands.
Guess What NYC Needs?  Pipelines.  New York City needs more natural gas pipelines–and it needs them BAD. That’s the upshot of a newly released report from the New York Building Congress, a trade group representing some 450 other building-related trade groups with 250,000+ members. 
The report, titled “Electricity Outlook: Powering New York City’s Future”  says NYC needs more pipelines built before the Indian Point Nuclear plant closes in 2021–both for electric generation (to replace Indian Point’s electricity) and because of the prohibition coming on heavier fuel oil used for wintertime heating. Interesting (and mind-blowing) fact: 81.5% of the electricity flowing in the five boroughs of NYC comes from natural gas-fired electric plants. 
The report calls for the Federal Energy Regulatory Commission to promptly approve Transco’s Northeast Supply Enhancement Project, when FERC has a quorum, which will flow more PA Marcellus gas to NYC and New Jersey. The report also calls on officials to approve Millennium Pipeline’s expansion request in Upstate. Of course the irony is not lost on those of us who live in Upstate New York–the irony being that we could be the ones providing at least some of that natural gas to our cousins in the City, if sleaze ball Gov. Andrew Cuomo hadn’t banned fracking. So yes, New York needs more natural gas and needs it ASAP, but New York has banned the production of it–so we’ll have to get it from places like Pennsylvania, Ohio and West Virginia instead. Bad for us, but good for them…
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Rig Count 

  • Baker Hughes Rig Count the week of July 28, 2017
  • PA
    • Marcellus 34 unchanged
  • Ohio 
    • Utica 28 up 1
  • WV 
    • Marcellus 14 up 1
  • TX
    • Eagle Ford 76 down 2
  • TX
    • Permian Basin – 379 up 5
  • ND
    • Williston – 54 unchanged
  • CO
    • Niobrara – 29 down 1
  • TOTAL U.S. Land Rig Count 931 up 7

PA Permits July 20, to July 27, 2017


County                                   Township                                          E&P Companies


  1. Butler                                           Jefferson                                           PennEnergy
  2. Butler                                           Jefferson                                           PennEnergy
  3. Susquehanna                            Lathrop                                              Cabot
  4. Susquehanna                            Lathrop                                              Cabot
  5. Susquehanna                            Lathrop                                              Cabot
  6. Susquehanna                            Lathrop                                              Cabot
  7. Susquehanna                            Lathrop                                              Cabot
  8. Susquehanna                            Lathrop                                              Cabot
  9. Washington                                Amwell                                               Range
  10. Washington                                South Strabene                                Range
  11. Washington                                South Strabene                                Range
  12. Washington                                South Strabene                                Range
  13. Washington                                South Strabene                                Range
  14. Washington                                South Strabene                                Range


OH Permits for week July 22, 2017



County                                   Township                                          E&P Companies


  1. No new permits this week.
Joe Barone 610.764.1232
Vera Anderson 570.337.7149
Utica Summit 2019