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Expo/Industry events for the next few months

OOGA Winter Meeting
March 8-10, 2017
Hilton Columbus at Easton, OH
http://oogawintermeeting.com/ 

Upstream PA 2017
March 21, 2017
Penn Stater Conference Center
State College, PA
http://upstreampa.com/  

Utica Upstream 
April 5, 2017
Walsh University
Canton, OH
http://www.uticacapital.com  

Ohio Valley Oil & Gas Regional Expo
April 25-26, 2017
Belmont County Carnes Center
St. Clairsville, OH
http://www.ohiovalleyoilgasexpo.com/ 

Appalachian Storage Hub Conference
June 15, 2017
Hilton Garden Inn
Southpointe, PA
http://www.appastorage.com/ 

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

Mariner East 2 Is Really Two Pipelines.

The Philadelphia-area company said during its quarterly financial call with analysts the Pennsylvania Department of Environmental Protection’s permit approval for two lines has convinced more producers to commit to the project. More commitments signaled greater interest in building an additional line adjoining the one now under construction.

The project’s cost is more than $2.5 billion, Kallanish Energy calculates.

“ME 2 (Mariner Express 2), as a project, has always been about two pipes,” Michael J. Hennigan, CEO of Sunoco Logistics’ general partner said during the call. “We wanted to do that from the beginning. We permitted for two pipes so that's always been the project's goal … .”

Hennigan said because his company didn't know when it was going to get the state Department of Environmental Protection (DEP) permits, SXL has continued an open season to allow more shippers of natural-gas liquids such as propane and butane to commit to buying capacity on the new pipeline.

The Mariner East pipelines together connect the Marcellus and Utica Shale regions in Ohio, West Virginia, and Pennsylvania to Sunoco’s terminal in Marcus Hook, outside Philadelphia.

The Mariner East project is actually three adjoining pipelines that will flow propane, ethane and butane to Marcus Hook. Though some of the propane is destined for domestic markets, most of the committed shippers are exporting the materials to European petrochemical plants.

Mariner East 1 is a 300-mile, 70,000 barrels per day (BPD) capacity pipeline running from Houston, south of Pittsburgh, to Marcus Hook that SXL began operating roughly two years ago. Mariner East 2, or ME2, would extend that pipeline an additional 50 miles west, to Scio, Ohio, which, with the assistance of a short, third-party line, will connect ME2 to four fractionation facilities.

Construction has already begun on the new 20-inch ME2 pipeline, which originally will be able to flow 275,000 BPD, expandable to 450,000 BPD. SXL plans to complete the project by Oct. 1.

The second Mariner East 2 pipeline, which Sunoco Logistics calls ME2X, would be a 16-inch, 250,000 BPD line built next to the 20-inch pipeline. The two pipes would be built sequentially, not simultaneously, Hennigan said, with MEX2 to be completed in 2018.

New Name, Old Player.  Mountaineer Keystone has a new name: Arsenal Resources, Kallanish Energy understands.

The company, a driller in the Marcellus and Utica shales in the Appalachian Basin, announced the change Friday. The company also unveiled a new logo to go with the new name. Its new tag line is “People Powered. Asset Strong.”

“It is our people and our assets that together are our greatest competitive strength, and our rebranding underscores this,” said CEO Dave Wood, in a statement.

The transition to Arsenal Resources will take several weeks, the company said. Its primary URL has changed to www.arsenalresources.com.

The company says it is the fourth largest contiguous pure play natural gas acreage holder in the West Virginia Marcellus Shale core area. Arsenal has operations in West Virginia, Pennsylvania and Ohio.

New EPA Administrator Moving Quickly.  Scott Pruitt said the Clean Power Plan, the signature climate regulation of the Obama administration, will soon go away.

Pruitt told the Wall Street Journal he expects to quickly withdraw both the Clean Power Plan and the Waters of the United States Rule, the Obama administration’s attempt at clarifying the EPA’s regulatory authority under the Clean Water Act.

“There’s a very simple reason why this needs to happen: Because the courts have seriously called into question the legality of those rules,” Pruitt told the Journal.

As Oklahoma Attorney General, Pruitt was party to lawsuits against the EPA for both regulations. Challenges to both rules are currently working their way through the court system, but Pruitt made clear he’s not waiting for the courts to decide before initiating the rule-making process necessary to withdraw both rules.

Pruitt sued EPA 14 times before becoming its leader, Kallanish Energy learns.

Pruitt refused to say whether he thought the EPA should have a role in regulating carbon and other greenhouse gases, something that had been a priority for the agency under Obama.

He has consistently challenged climate change, arguing there is significant debate as to whether it’s happening and whether humans are the primary cause.

“There will be a rule-making process to withdraw those rules, and that will kick off a process,” Pruitt told the Journal. “And part of that process is a very careful review of a fundamental question: Does EPA even possess the tools, under the Clean Air Act, to address this? It’s a fair question to ask if we do, or whether there in fact needs to be a congressional response to the climate issue.”

Pruitt told the Journal as EPA administrator, he is most focused on issues like cleaning up Superfund sites and bringing states into compliance with federal air quality standards.

Range 4th Qtr. Update.  2016 financial results and 2017 capital spending plan.

Highlights –

  • Record average daily production of 1.854 Bcfe during the fourth quarter
  • 2017 capital budget set at $1.15 billion, projected to provide 33-35% year-over-year growth in 2017 and approximately 20% organic growth in 2018
  • North Louisiana well costs reduced to $7.7 million per well from $8.7 million previously
    • Fourth quarter 2016 unhedged cash margins improved by over four times to $0.97 per mcfe, compared to $0.22 per mcfe in fourth quarter 2015
  • Reserve replacement of 292% at $0.34 per mcfe drill-bit development cost for 2016

Commenting, Jeff Ventura, the Company’s CEO said, “2016 was a significant year for Range, as we completed the acquisition of Memorial Resource Development in September, providing Range operational and geographic diversity with wells that rival our prolific Marcellus wells.  In addition, we are beginning to see the advantages of a diversified marketing portfolio, as prices are expected to improve for all products in 2017, driving higher margins and a peer-leading recycle ratio.  Higher expected margins and cash flow provide us the opportunity to increase our capital budget to $1.15 billion in 2017, after two consecutive years of declining capital spending.  This increased activity in 2017 results in solid growth this year, but also positions us well for 2018 and beyond.  With thousands of future locations in our core inventory and talented operational, technical and marketing teams, Range is well-positioned to drive shareholder value for years to come.”

Capital Spending Plans

Range has set its 2017 capital spending budget at $1.15 billion. Approximately two-thirds of the capital budget will be allocated to the Marcellus and one-third to North Louisiana.  The budget includes projected service cost increases in 2017, which are expected to be minimal in the Company’s areas of operation.  In the Marcellus, approximately 80% of activity will be directed towards liquids-rich drilling, which has a number of advantages.  Range’s liquids-rich acreage has an extensive inventory of existing pads that reduce capital costs and gathering expense.  The acreage is also in close proximity to capacity for both existing and expected NGL and natural gas takeaway projects, improving netback pricing.  Lastly, recent improvements in NGL pricing has bolstered expected drilling returns.   Despite shifting capital towards the liquids-rich area, the Company still expects production of approximately 2.07 Bcfe per day in 2017, which equates to absolute growth of 33% to 35% year-over-year.  Capital spending in 2017 will also contribute towards production growth of approximately 20% in 2018, expected to be at or near cash flow, assuming a natural gas price of $3.25 per mcf and an oil price of $60.00 per barrel.

The 2017 capital budget includes approximately $1.07 billion for drilling and recompletions (93% of the total), $44 million for leasehold, $22 million for seismic, and $18 million for pipelines, facilities and other.  The budget includes 118 wells expected to be brought on line during the year in the Marcellus and 56 wells in North Louisiana.  In the Marcellus, approximately one third of the wells are planned to be drilled from existing pads in 2017.

Fourth quarter 2016 drilling expenditures of $195 million funded the drilling of 22 (18.9 net) wells.  Drilling expenditures for the year totaled $535 million, and Range drilled 108 (101.9 net) wells during the year.  A 100% success rate was achieved.  In addition, during 2016, $33 million was spent on acreage purchases, $4 million on gas gathering systems and $30 million on exploration expense.   The capital expenditure amounts include North Louisiana expenditures incurred since closing of the merger on September 16, 2016.  Drill-bit only finding cost averaged $0.34 per mcfe, including pricing and performance revisions with a reserve replacement ratio of 292%.

SWN 4th Qtr. Update.  Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the fourth quarter and the year ended December 31, 2016. Calendar year 2016 highlights include:

  • Net cash provided by operating activities of $498 million and net cash flow of $645 million;
  • Net loss attributable to common stock of $2.8 billion, or $6.32 per diluted share, and adjusted net loss attributable to common stock of $7 million, or $0.01 per diluted share;
  • Total net production of 875 Bcfe, including 498 Bcfe from the Appalachia Basin and 375 Bcf from the Fayetteville Shale;
  • Encouraging results associated with Northeast Appalachia completion testing and production flow optimization, including an aggregate initial production rate of approximately 92 million cubic feet per day from five wells on the Cramer pad that were placed to sales in the fourth quarter;
  • First sales successfully commenced in Tioga County, Pennsylvania;
  • Positive early results from the Company's first drilled and completed Utica well in Marshall County, West Virginia;
  • Upward proved reserves performance revisions of 683 Bcfe, reflecting the continued improvement in ultimate well recoveries and lower costs; and
  • Proved Developed Producing (PDP) Finding and Development costs for the total company of $0.75 per Mcfe, a 15% improvement from prior year.

Northeast Appalachia

In the fourth quarter of 2016, the Company placed 12 wells to sales that had an average lateral length of 6,075 feet and an average cost of $4.7 million per well.  The average rate for the first 30 days for wells online was 17,178 Mcf per day in the fourth quarter of 2016 compared to 4,796 Mcf per day in the fourth quarter of 2015.  The stronger early rates are a result of increased completion intensity and optimized flow techniques implemented during the second half of the year.  During the fourth quarter, Northeast Appalachia placed 11 wells to sales that were completed using increased completion intensity and optimized flow techniques, with all wells exhibiting encouraging early results.  One example is the Cramer pad in Susquehanna County, where the Company brought five wells to sales in the fourth quarter with a cumulative rate of approximately 92 million cubic feet per day.  Additionally, the Racine pad that was placed online in the third quarter of 2016 has continued to outperform offset wells, producing 75% more volumes in the first 125 days. While the Company continues to assess what portion of these increased volumes relate to incremental expected recovery and what portion relates to acceleration, these results clearly indicate additional value is being created with these new methods.

Additionally, the Company continued its delineation efforts in Tioga County, where initial infrastructure was installed, and it placed its first two well to sales in January 2017. The well results observed to date confirm the productivity of the acreage and the Company intends to further develop this area throughout 2017.

In 2016, Southwestern's operated horizontal wells had an average completed well cost of $5.3 million per well and an average horizontal lateral length of 6,142 feet. This compares to an average completed operated well cost of $5.4 million per well and an average horizontal lateral length of 5,403 feet in 2015. 

As of December 31, 2016, Southwestern had spud or acquired 568 operated wells, of which 447 were horizontal and on production and 73 were in progress. Of the 447 operated horizontal wells on production, 281 were located in Susquehanna County, 140 were located in Bradford County, 25 were located in Lycoming County, and one was located in Wyoming County. Of the 73 wells in progress, 46 were either waiting on completion or waiting to be placed to sales, including 36 in Susquehanna County, six in Bradford County and four wells in Sullivan, Tioga and Wyoming Counties, combined.

Southwest Appalachia

In the fourth quarter of 2016, Southwestern brought online seven wells in Southwest Appalachia, including the Company's first drilled and completed Utica well, the O.E. Burge 501H.  It was completed with a lateral length of 8,061 feet and is exhibiting the vast potential of this reservoir in the Company's Southwest Appalachia acreage.  With the encouraging results, the Company accelerated the timeline for drilling its next Utica test well, which began drilling earlier this month.

Additionally, completion intensity testing continued during the quarter with increased amounts of proppant being used in some wells.  In one group of wells, the Company tested one well using approximately 5,000 pounds per lateral foot of proppant and four wells using approximately 3,500 pounds per lateral foot, compared to the recent standard of 2,000 pounds per lateral foot.  These wells, along with other test wells, have recently been placed online and early results are expected to be available at the end of the first quarter.

In 2016, of the 18 wells brought to sales, 15 were drilled and completed by Southwestern, of which 14 targeted the Marcellus Shale.  The Marcellus wells had an average completed well cost of $5.4 million per well and an average horizontal lateral length of 5,316 feet. This compares to an average completed operated well cost of $6.9 million per well and an average horizontal lateral length of 6,985 feet in 2015.

The Company had a total of 299 horizontal and four vertical wells that the Company operated and that were on production as of December 31, 2016.  Additionally, there were 42 horizontal wells in progress at the end of 2016, of which 20 were waiting on pipeline or production facilities.  

Rice Increases CAPEX Budget 153%.  Pennsylvania-based Rice Energy and its affiliates plan to spend $1.04 billion on drilling and completions in 2017 in the Marcellus and Utica Shale plays, plus an additional $225 million on land acquisition, Kallanish Energy reports.

The company plans to spud 75 wells and to complete another 55 wells in the Marcellus Shale in southwest Pennsylvania. It has plans to drill 20 wells and begin production on an additional 20 wells in the Utica Shale in eastern Ohio.

About half of the money for land acquisition will be spent in Greene County, Pa., with the rest spent in Pennsylvania’s Washington and Ohio’s Belmont counties, the company said. The company spent $686 million on capital projects in 2016.

It said Marcellus wells would each cost $7.4 million, while Utica wells would each cost $13 million.

The company is forecasting 2017 production will grow by 59%, to 1.29-1.36 billion cubic feet-equivalent per day (Bcfe/d).

In addition, Rice Midstream is allocating $315 million on 2017 capital spending. That money will be spent on its Olympus Midstream gathering system and to fund its Strike Force joint venture with Gulfport Energy.

Rice Energy has benefitted from its acquisition of Vantage Energy in 2016, CEO Daniel J. Rice IV said, in a statement.

Fourth-quarter 2016 net production averaged 1.15 Bcfe/d, an 83% increase from Q4 2015, the company said, or a 49% jump excluding Vantage Energy production.

Total net production in 2016 averaged 831 million cubic feet equivalent per day, a 51% increase from 2015, the company said.

In 4Q 2016, the company reported a net loss of $178.4 million or 88 cents a share. It reported a loss of $280 million or $2.06 per share in 4Q 2015.

For full-year 2016, Rice Energy reported a net loss of $298.2 million, compared to a loss of $291 million in 2015.

PA Judge Keeps Mariner East 2 Moving.  A Pennsylvania Environmental Hearing Board judge last Friday denied a request for a temporary stay filed by three environmental groups opposing state permits that clear the way for Sunoco Logistics to build the Mariner East 2 pipeline.

The hearing was held after the Clean Air Council, Delaware Riverkeeper Network and Mountain Watershed Association filed earlier last week seeking the stay, hours after 20 permits were approved by the state Department of Environmental Protection.

The Environmental Hearing Board is a court established to hear appeals on Department of Environmental Protection actions.

Judge Bernard A. Labuskes Jr. slated a second hearing on the eco-groups’ request for March 1-3, with additional days in March if necessary.

The 350-mile, 20-inch Mariner East 2 pipeline would run parallel to the company's 12-inch Mariner East line, both carrying propane, ethane and butane to the Marcus Hook plant near Philadelphia.

Before Sunoco Logistics can begin construction, it must secure U.S. Army Corps of Engineers approval, Kallanish Energy understands.

Joseph Minott, chief council for the Clean Air Council, said he was disappointed by the ruling, but looks forward to proving the groups' case.

“We look forward to making our case to the court as quickly as possible. The inadequacy of the DEP's permits should be troubling to all Pennsylvanians,” Minott said, in a statement.

Later in the day Friday, the groups filed a request for an expedited hearing and a reconsideration of the request for a temporary stay.

DEP spokeswoman Lauren Fraley told the Tribune-Review newspaper the department does not comment on matters under litigation.

No LNG Glut. This is good news for Appalachian Basin E&P Companies.  As the pipelines get built, there is a market for their gas.  With a very warm winter, the global opportunities for LNG will offset the warm winter.  The global market and cracker plants will drive the production of NatGas in the Appalachian Basin.

There is no evidence of a liquefied natural gas (LNG) glut and LNG markets are expected to keep growing, Royal Dutch Shell states in a new report.

Global demand for LNG reached 265 million tons in 2016, enough to power about 500 million homes. That represented an increase in net LNG imports of 17 million tons, or 6.4%.

Many had expected a strong increase in new LNG supplies in 2016 would outpace demand growth, but that didn’t happen, Kallanish Energy has learned.

Instead demand growth kept pace with supply as greater-than-expected demand in Asia and the Middle East absorbed the increase in supply from Australia, according to Shell’s first LNG Outlook.

“Global LNG trade demonstrated its flexibility time and again in 2016, responding to shortfalls and regional gas supply and to new emerging demand,” said Maarten Wetselaar, Shell’s integrated gas and new energies director, in a statement.

“The outlook for LNG demand is set to grow at twice the rate of gas demand, at 4% to 5% a year between 2015 and 2030,” he added.

China and India were two of the fastest-growing buyers and the two countries are poised to continue driving a rise in demand. Together, China and India increased their LNG imports by 11.9 million tons in 2016. That boosted China’s LNG imports in 2016 to 27 million tons and India’s to 20 million tons, said Shell, an LNG player.

Total global LNG demand grew with the addition of six new importing countries since 2015, it said, including Columbia, Egypt, Jamaica, Jordan, Pakistan and Poland. They bring the number of LNG importing countries to 35, up from roughly10 in 2000.

Egypt, Jordan and Pakistan were among the fastest-growing LNG importers in 2016. Due to local shortages in gas supplies, they together imported 13.9 million tons of LNG.

According to Shell, the bulk of LNG export growth in 2016 came from Australia, where exports grew by 15 million tons, to 44.3 million tons. In the U.S., the Sabine Pass terminal in Louisiana exported 2.9 million tons last year.

Shell said additional investments will be needed after 2020 to meet growing LNG demand from Asia.

In China, a government target has been set for gas to make up 15% of the country’s energy mix by 2030, up from 5% in 2015. Southeast Asia, including Malaysia and Indonesia, will also become a major LNG importer by 2035, Shell said.

The DUCs Are Gone. (Thank you, BTU Analytics)  Over the past two years BTU Analytics has written extensively about DUCs or drilled but uncompleted wells, with our first energy market commentary on the topic posted all the way back in January of 2015. But over the past several months, we’ve been telling our clients that the market impact of DUCs is essentially done, and the correlation between rig activity and production will again improve as that hangover from the shale boom is lifted. DUCs may be done, but is the market being set up for a new hangover? One caused by the collective excitement and potential of the Permian Basin?  Make way for PUCs.

The term “DUC” well gained traction in the months following the oil price crash in 2014.  Prior to the price collapse, wells were drilled and typically completed within a predictable time frame, generally one to six months, depending on the region and whether pad drilling was being employed.  But when oil prices crashed, many producers slowed any activity that they could, hoping to reserve cash and future production until higher prices were on the horizon.  Some producers were so bold as to publicly highlight a time frame in which they expected the market to recover, and communicated to the market that they would wait to complete wells until that time.

The halted momentum from 2014 left US producers with over 1,000 wells across the major US oil plays in excess backlog in the first quarter of 2015, as illustrated in the chart below.



Note that BTU Analytics attempts to differentiate between all DUCs and a level of DUCs outside of what we consider to be normal working inventory by only focusing on the number of wells beyond normal working inventory, which we define as excess backlog. This number grew to over 2,000 by Q1 2016 as oil prices fell to new lows and producers cut both drilling and completion activity further.  However, completion activity exceeded new drilling for 2016, and the current number of DUCs falls within BTU Analytics’ estimate of working inventory in all major plays other than the Williston and DJ.

With the DUC backlog being exhausted across many of the major US oil plays, rig activity returns to the forefront.  The ramp in rigs in the Permian has the industry regaining some of its former swagger.  But production associated with current rig activity in the Permian will begin testing takeaway infrastructure later this year. As producers in the basin push ahead with their development plans without fully considering the impact of herd mentality, BTU Analytics expects excess backlog in the basin to grow once again (Permian Uncompleted Wells?  PUCS!).

Visit our Blog for daily updates on what’s happening in the oil & gas industry.

http://www.shaledirectories.com/blog/

Rig Count 

  • Baker Hughes Rig Count the week of February 24, 2017
     
  • PA     
    • Marcellus 34 unchanged
  • Ohio
    • Utica 19 unchanged
  • WV 
    • Marcellus 10 unchanged
  • TX
    • Eagle Ford 64 up 3
  • TX & NM
    • Permian Basin – 306 up 3
  • ND
    • Williston – 35 down 1
  • CO
    • Niobrara – 21 unchanged
       
  • TOTAL U.S. Land Rig Count 733 up 3

PA Permits February 16, to February 23, 2017

       County               Township           E&P Companies

1.    Greene                Center                EQT
2.    Greene                Center                EQT
3.    Greene                Center                EQT
4.    Greene                Center                EQT
5.    Greene                Center                EQT
6.    Lawrence            North Beaver       Hilcorp
7.    Lawrence            North Beaver       Hilcorp
8.    Lawrence            North Beaver       Hilcorp
9.    Lawrence            North Beaver       Hilcorp
10.   Susquehanna    New Milford          SWN
11.   Tioga                Duncan                EQT
12.   Tioga                Duncan                EQT
13.   Tioga                Duncan                EQT
14.   Washington       Donegal               SWN
15.   Washington       Hanover               Range

OH Permits for week February 18, 2017

        County             Township     E&P Companies

1.    Belmont             South             Rice
2.    Belmont             South             Rice
3.    Belmont             South             Rice
4.    Belmont             South             Rice
5.    Belmont             South             Rice
6.    Jefferson           Island Creek   Chesapeake
7.    Jefferson           Island Creek   Chesapeake
8.    Monroe              Lee                Eclipse Resources
9.    Noble                Beaver            Antero
10.   Noble              Beaver            Antero
11.   Noble              Beaver            Antero

Joe Barone jbarone@shaledirectories.com 610.764.1232
Vera Anderson vera@shaledirectories.com 570.337.7149

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