Facts & Rumors # 315

Save these 2019 for Shale Directories Seminars

 

Utica Midstream March 21, 2019 Walsh University North Canton, OH www.uticasummit.com

Upstream PA 2019 April 17, 2019 Penn Stater Conference Center State College, PA

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

New DOE Study Supports Ethane Appalachian Storage Hub.   An ethane storage/distribution hub in the Appalachian Basin offers the U.S. petrochemical and plastics industries supply and geographic diversity, mitigates feedstock price spikes, and lessens the possibility of weather-related production disruption, a new Department of Energy report states. The 91-page report, mandated by, and delivered to, the U.S. Congress, entitled “Ethane Storage and Distribution Hub in the United States,” highlights the potential in Appalachia for a hub due to the huge availability and low-cost of natural gas liquids available via the Marcellus and Utica Shale plays. And the Trump administration is prepared to support such a project, Kallanish Energy reports.

'Incredible opportunity'

“There is an incredible opportunity to establish an ethane storage and distribution hub in the Appalachian region and build a robust petrochemical industry in Appalachia,” said U.S. Secretary of Energy Rick Perry, speaking Tuesday at the annual National Petroleum Council Meeting in Washington D.C. “As our report shows, there is sufficient global need and enough regional resources to help the U.S. gain a significant share of the global petrochemical market. “The Trump Administration would also support an Appalachia hub to strengthen our energy and manufacturing security by increasing our geographic production diversity.” The report to Congress examines the potential for a hub by comparing it to existing ones that already service the Gulf Coast and Permian Basin, which account for most of the U.S. growth in natural gas liquids outside Appalachia.

Supporting economic security

In addition, market analysis from the report emphasizes development of an Appalachian hub may offer a competitive advantage for the U.S. to gain global petrochemical market share while not being in conflict with ongoing Gulf Coast expansion. The report explains a new Appalachian hub would enhance the geographic diversity of the U.S. petrochemical industrial sector, supporting U.S. economic security. The regional group currently working on securing both public and private funding for an Appalachian Basin hub, said it’s not surprised with the DOE report’s conclusion.

Pleased, not surprised

Appalachia Development Group LLC (ADG) told Kallanish Energy it’s pleased -- though not surprised -- with the results of the DOE report. “This report further validates the strategic importance of the Appalachia Storage and Trading Hub and the positive impacts it will have on our country and our allies around the world,” said Steve Hedrick, chairman & CEO of ADG.  “Ensuring the opportunity for geographic diversification of the nation’s chemical manufacturing assets, while leveraging the regional resources in Appalachia in the safest, most efficient manner possible, provides a truly unique opportunity that requires public-private collaboration to see it forward.”

Industrial catalyst

The proposed, roughly $3.5 billion hub is considered to be a catalyst for industrial development within the Appalachian region. The American Chemistry Council estimates $36 billion in new petrochemical investments, more than 100,000 new long-term jobs that includes more than $6 billion in annual payroll and $2.9 billion in annual tax revenue for the Appalachian region, should the hub be built in West Virginia, Ohio or Pennsylvania. Currently, the U.S. has ethane hubs at Mont Belvieu, Texas, and Conway, Kansas. There also is a hub in Sarnia, Ontario Canada. “… both Mont Belvieu and Conway are in relatively close proximity to the growing NGL production projected from the Permian Basin in the Southwest,” according to the DOE report (reviewed by Kallanish Energy). “The East region of the U.S. currently is without a NGL storage hub similar to Mont Belvieu, Conway, or Sarnia. The extent to which East region NGLs will be converted and consumed locally will depend on regional infrastructure additions and, more specifically, the interplay between storage and transportation.”

Ethane production keeps growing

Ethane production in the Appalachian Basin is projected to continue to grow through 2025, to a total of 640,000 barrels per day (Bpd) -- more than 20 times greater than just five years ago. According to the U.S. Energy Information Administration, natural gas production in Ohio, Pennsylvania, and West Virginia has increased so rapidly their combined share of total U.S. natural gas production has jumped from 2% in 2008, to 27% in 2017. In addition, natural gas liquids processing and fractionating capacity in Appalachia has grown quickly to match this increase in natural gas production. However, the Appalachian region currently lacks other physical infrastructure for a “hub” that connects supply and demand sources, including storage for NGLs. Williams Introduces New Pipeline Project.  A major operator of energy infrastructure in Pennsylvania is planning a $500 million project to increase the amount of Marcellus Shale natural gas that can be transported from wells in the northern and western parts of the state. The increased capacity will supply enough natural gas to meet the daily needs of approximately 2.5 million homes, The Williams Cos. says. Commitments from producers Seneca Resources Co., Cabot Oil & Gas and UGI Utilities will enable it to expand its Transco pipeline daily capacity by 582,400 dekatherms (a dekatherm is equivalent to about 1,000 cubic feet), it says. The company cites a growing demand for natural gas along the Atlantic seaboard. The Leidy South Project is in the pre-filing stage with the Federal Energy Regulatory Commission during which public comment is sought. Williams has scheduled open houses from 6 to 8 p.m. Tuesday at the Hughesville Volunteer Fire Co. in Hughesville, and from 6 to 8 p.m. the following day at the Chapman Twp. Volunteer Fire Co. in North Bend. Dates and locations for open houses in Schuylkill and Luzerne counties have not been set, the company says. The timetable calls for Williams next summer to submit to FERC an application to begin construction in early 2021. The project limits environmental impacts by maximizing the use of existing infrastructure, Williams says. The Leidy South Project includes: Replacement of 6.09 miles of Transco's existing 24-inch pipe with a 36-inch line and install a 2.46-mile, 32-inch loop, both in northwestern Clinton County. Installation of a 42-inch, 3.55-mile loop in Lycoming County near the Columbia County line. Updates to a compressor station in Columbia County and one in western Schuylkill County, both on the Central Penn South line. Updates to a compressor station in Wyoming and one in Luzerne County on the Central Penn North line. A loop is new pipe connected to and placed adjacent to an existing pipeline in the same easement. Pennsylvania is the second largest gas-producing state behind Texas, averaging 15 billion cubic feet a day, Williams noted. While record volumes of natural gas are being produced, consumer access to it is limited by insufficient pipeline infrastructure, it says. Williams operates more than 3,600 miles of transmission and gathering pipelines in Pennsylvania. Latest News on LyondellBasell – Braskem. (Thanks, Tom Gellrich, TopLine Analytics)    Brazilian court blocks Boeing-Embraer deal = politics getting into business following the election in Brazil. The judge argued that since the Brazilian Federal Government is changing, the decision is aimed at preserving the possibility of reversing the deal, in the case the new government is against it. The new Brazilian government is pro-business, so this is only a delay. The Braskem - LyondellBasell deal may be in the same boat. Previously it looked like that deal would be completed the first half of 2019. Shale Revolution Reduces Trade Deficit by $250B.  What if the shale revolution had never happened? We’d be another $250 billion in the hole with our trade deficit. That’s the finding of a new report released by IHS Markit titled “Trading Places: How the Shale Revolution Has Helped Keep the U.S. Trade Deficit in Check.” The report finds the total U.S. merchandise trade deficit in 2017 was $250 billion lower than it otherwise would have been if the petroleum (crude oil, refined products and natural gas liquids – petroleum liquids separated out from natural gas and also known as NGLs) trade deficit had remained at its 2007 level. Thank God for shale! The report also examines the impact of rising U.S. oil, natural gas and chemicals production on the domestic trade merchandise balance and how the U.S. position in energy and chemicals may evolve in coming years. Interesting stuff. The boom in U.S. oil and gas production over the past decade has exerted a moderating force on what is a large domestic merchandise trade deficit by helping reduce the country’s net petroleum imports, a new report by business information provider IHS Markit (Nasdaq: INFO) says. Continued U.S. production growth is now on track to make the country a net-exporter of petroleum for the first time since at least 1949. The total U.S. merchandise trade deficit in 2017 was nearly $250 billion lower than it otherwise would have been if the petroleum (crude oil, refined products and natural gas liquids – petroleum liquids separated out from natural gas and also known as NGLs) trade deficit had remained at its 2007 level, the report finds. IHS Markit projects that the U.S. petroleum trade balance will further improve by roughly $50 billion between 2017 and 2022. The findings are part of a new report entitled Trading Places: How the Shale Revolution Has Helped Keep the U.S. Trade Deficit in Check. The report examines the impact of rising U.S. oil, natural gas and chemicals production on the domestic trade merchandise balance and how the U.S. position in energy and chemicals may evolve in coming years. “The improved U.S. trade position in petroleum has been a counterbalancing force helping to keep the U.S. trade deficit in check over the past decade,” said Daniel Yergin, vice chairman, IHS Markit. “The resurgence of domestic oil and gas production has flipped the trade position of several products along the energy value chain on their heads, while that of other products, such as crude oil, have been significantly reduced.” U.S. production of liquids (crude oil and natural gas liquids) nearly doubled from about 7 million barrels a day (mbd) in 2007 to 13 mbd in 2017 and 14.8 mbd in the first nine months of 2018. Crude oil alone rose from 5 mbd in 2007 to 9.4 mbd in 2017 and averaging 10.6 mbd in the first 9 months of 2018 — and hitting 11.2 mbd in October 2018. This rise, combined with a slight decline in domestic demand, contributed to a sharp fall in U.S. petroleum net imports as a share of total consumption – from a high of 60 percent in 2005 to 19 percent in 2017 and 14 percent in nine months of 2018. IHS Markit estimates that the U.S. petroleum trade deficit in dollars fell from about $320 billion in 2007 to about $75 billion in 2017 as net imports declined. During this same time, when the petroleum trade deficit was shrinking dramatically, the trade deficit for non-petroleum merchandise grew by about $230 billion. The continued growth of U.S. crude oil and NGL production—along with relatively flat liquids demand—are expected to make the U.S. a net-petroleum exporter by early next decade, the report says. This would be the first time since at least 1949 that the U.S. was not a net petroleum importer. “The United States moving from net imports to being a net petroleum exporter would be an historic shift, something not achieved since at least the Truman administration,” said David Witte, senior vice president and division head for energy and chemicals at IHS Markit. “It speaks to the profound and continued impact that the U.S. shale boom has had in terms of investment, job creation, manufacturing, GDP and now trade.” The resurgence of U.S. oil and gas production has already altered the domestic net trade position of a number of energy products over the same 2007-2017 period, the report says. IHS Markit expects exports of these products to continue to rise. They include:

• Refined products: from about 1 mbd of net imports in 2007 to about 2 mbd net exports in 2017 – a positive change of about 3 mbd
• Natural Gas Liquids: from 0.2 mbd net imports in 2007 to 1.1 mbd of net exports in 2017 – a positive change of more than 1 mbd.
• Natural Gas: from 10.4 bcf/d of net imports in 2007 to 0.4 bcf/d of net exports in 2017 – a positive change of nearly 11 bcf/d
• Gas-and NGL-based chemicals: from about 6 MMt/y of net imports in 2007 to about 4 MMt/y of net exports—a positive change of more than 9 MMt/y
• Crude oil: from about 10 mbd of net imports in 2007 to about 7 mbd of imports in 2017 – a positive change of about 3 mbd

The report does caution that trade tensions between the U.S. and its trading partners could introduce new risks and therefore alter the trajectory of global energy trade and energy demand. In particular, the report notes recent frictions with China, which is a growth market for U.S. exports of LNG, crude oil, NGLs and gas- and NGL-based chemicals. “Overall turmoil in world trade patterns could not only dampen trade along the energy value chain but also affect global economic growth and thus impact demand for the many hydrocarbon and chemical products that depend on economic growth,” said Jeff Meyer, director, oil markets at IHS Markit.* Permit Info – Antero, Ascent, and SWN.   Antero Resources Corp. has been issued permits for three Shiloh-Wick Field-Marcellus Shale ventures in Tyler County, W.Va. The permitted wells will be drilled from a drill pad on a 317-acre lease in Centerville District, Middlebourne 7.5 Quad. The Heintzman Unit 1H well has a planned depth of 17,800 ft and will be drilled to the south. The Heintzman Unit 2H well has a planned depth of 17,500 ft and will be drilled to the southeast. The Heintzman Unit 3H well has a planned depth of 17,400 ft and will be drilled to the east-southeast. Nearby production in the Shiloh-Wick Field is at an Antero Utica producer, Rymer Unit 4HD. It was completed in 2016 flowing 20 MMcf/d of gas. Ascent Resources LLC has received permits for four Utica Shale-Colerain Field wells in Jefferson County, Ohio. The wells will be drilled from a drill pad in Section 34, Mount Pleasant Township. The Ruth E MTP 2H well has a planned depth of 22,000 ft, and the Ruth E MTP 4H well has a planned depth of 22,000 ft. The Ruth E MTP 6H well has a planned depth of 22,500 ft, and the Ruth E MTP 8H well has a planned depth of 23,000 ft. Ascent Resources LLC is underway at two Jewett Consolidated Field wells in Jefferson County, Ohio. The Utica Shell wells are on a 378-acre lease in Section 18-8n 3w. The Geno E SMF JF 5H well has a planned depth of 24,300 ft and will be drilled to the northwest. The offsetting Geno W SMF JF 1H well has a planned depth of 26,000 ft, and it will be drilled to the north. Nearby production is at an American Energy Partners completion in Section 27 in the Dillonvale 7.5 Quad at the Smithfield  A 1H-27 well. The Smithfield pad discovery was drilled to 18,525 ft (9,631 ft true vertical depth), and it was tested flowing 18.1 MMcf/d of gas. Southwestern Energy Co. has received permits to drill two Marcellus Shale tests from a drill pad in Ohio County, W.Va. The Roy Riggle OHI 6H well has a projected depth of 12,429 ft and a projected true vertical depth of 6,542 ft. It will be drilled to the northeast. The offsetting Roy Riggle OHI 206H well has a planned depth of 15,325 ft and a planned true vertical depth of 6,519 ft. It will be drilled to the southeast. The company also has received permits to drill Marcellus ventures in nearby Brooke County, W.Va., at the Worthley Brk 1H, Worthley 201H, Worthley Brk 210H and Worthley Brk 5H wells. Largest Oil and NatGas Potential Ever in TX and NM.  The US Geological Survey assessed that the Bone Spring Formation in Texas and Wolfcamp Shale in New Mexico contain the largest oil and natural gas potential ever found, the Department of the Interior said in a press release on Thursday. "he Wolfcamp Shale and overlying Bone Spring Formation in the Delaware Basin portion of Texas and New Mexico’s Permian Basin province contain an estimated mean of 46.3 billion barrels of oil, 281 trillion cubic feet of natural gas, and 20 billion barrels of natural gas liquids," the release said. Interior Secretary Ryan Zinke celebrated the assessment by saying that the United States has a lot of energy and the country's dominance in the energy sector is now proven. The Wolfcamp shale in the Midland Basin portion of the Texas Permian Basin province has been examined by the US Geological Survey in 2016. The organization concluded then that the formation contained an estimated mean of 20 billion barrels of oil, 16 trillion cubic feet of associated natural gas and 1.6 billion barrels of natural gas liquids. ETP Launches Open Season.  Energy Transfer LP (ET), via its Sunoco Pipeline L.P. unit, has launched a binding open season to solicit shipper commitments of C3+ (natural gas liquids, excluding ethane) from the Marcellus/Utica Shale play in Pennsylvania to facilities in Claymont, Delaware and Marcus Hook, Pennsylvania, through the Mariner East pipeline system. The open season will allow Sunoco Pipeline to add additional product commitments to the pipeline, which is nearing completion, according to Energy Transfer. The Mariner East 2 line is designed to move NGLs across Pennsylvania to the Marcus Hook Industrial Complex near Philadelphia, with 275,000 barrels per day of capacity when completed by Jan. 1, 2019, Kallanish Energy learns. The Mariner East 2X project will Increase NGL takeaway from the Marcellus to the East Coast w/ storage at Marcus Hook Industrial Complex, when completed in the third quarter of 2019. Mariner East 1 originally went into service four years ago flowing propane. In the first quarter of 2016, ethane was added to the flow, via the series of pipelines from the Marcellus/Utica in Ohio, West Virginia and Pennsylvania. Energy Transfer LP is the new name for the now-merged Energy Transfer Equity and Energy Transfer Partners. Jupiter Connecting the Permian to the World.  Jupiter CEO Tom Ramsey believes the Texas crude transport, storage and pipeline operator can soon connect the Permian wellhead to the world. Jupiter MLP is now collecting shipper interest in a Permian crude pipeline that could connect producers to three export terminals along the Texas Gulf Coast. After earning funding in October for a 600-mile-plus pipeline with several origination points across the West Texas and New Mexico, Jupiter is now less than a year-and-a-half away from commencing operation. The pipeline has already received the necessary rights-of-way. Once complete, the pipeline will provide deep water port access at Houston, Corpus Christi and Brownsville, Texas. Charon System Advisors is providing the funding for the build-out of the pipeline. In Brownsville, Jupiter has already secured the ability to store. Repsol To Increase Drilling in the Marcellus.  Spain’s Repsol SA expects to raise production in the Marcellus natural gas shale field by about 50% by year-end 2020 due to efficiency gains, an executive said at an industry conference in New York on Dec. 6. “With just the addition of one rig and investment of about $400 million a year, we're going to be able to raise production by 50 percent and be cumulative cash flow positive by the end of 2020,” Paul Ferneyhough, executive director of North America for Repsol said at the S&P Global Platts Global Energy Outlook Forum. Repsol holds an interest in 168,400 net acres in the Marcellus Shale, one of the largest natural gas fields in the world, extending throughout the Appalachian Basin and stretching across Pennsylvania, according to its website. PA NatGas Production. Up! Up! Up!  Pennsylvania’s natural gas production, producing wells, and average per-well production all via horizontal drilling in 2018 continues in the direction the category trio has followed since 2011: Data distributed by the state’s Independent Fiscal Office reveals from 2011 through 2017, and full-year 2018 results based on nine months of data, show substantial increases in all three categories – triple-digit percentages from 2011-2018, Kallanish Energy calculates. Production volume is projected to hit 6 trillion cubic feet (Tcf) this year, up 646 billion cubic feet from 2017’s 5.35 Tcf production, and a whopping 4.95 Tcf – 472% -- from 2011’s horizontal well production of 1.05 Tcf. The number of producing wells for 2018 is projected at 8,600, up 710 wells, or 9%, from 2017’s 7,890 producing wells, and up 6,832 wells, 386.4%, from 2011’s 1,768 producing horizontal wells. Also, the all-important average production per well continues to climb, the Independent Fiscal Office reports. The Office is projected to reach 1.58 billion cubic feet (Bcf) this year, up 301 million cubic feet (Mmcf), or 23.6%, from 2017’s 1.28 Bcf. The 2018 projection would be 904 Mmcf, or 134.5%, higher than 2011’s 672 Mmcf average production per well. Comparing individual Pennsylvania counties, Susquehanna County, in the northeast portion of the state, led in both production and share of total state production, according to the state Independent Fiscal Office. Susquehanna in 2018 is projected to produce 1.07 Tcf, up 10.7% from 2017’s 966.1 Bcf of production. The county’s share of total production is 213.9%. Second place is Washington County, in Pennsylvania’s southwest quadrant, expected to produce 862.4 Bcf this year, up 27.2% from 2017’s 677.9 Bcf, with the county grabbing a 19.3% share of statewide production. SWN Totally Focused on Appalachian Basin.  Southwestern Energy said Tuesday the independent producer has completed the sale of its Fayetteville Shale assets in Arkansas to privately-held Flywheel Energy for $1.65 billion net to the seller. The Spring, Texas-based Southwestern now has all its operations concentrated in West Virginia and northeast Pennsylvania, Kallanish Energy calculates. “This strategic transaction represents a further significant step in the transformation of the company,” says Bill Way, president and CEO of Southwestern. “We’re now better positioned to leverage our leading technical and operating capabilities to drive greater value from our highly attractive and significant asset base in Appalachia, pay down debt and create even greater financial flexibility.” The assets sold include 716 million cubic feet per day (mmcf/d) of net production from 4,033 producing wells across over 900,000 net acres, and an integrated midstream gathering system with over 2,000 miles of gathering pipelines and more than 50 compressor stations, all located in central Arkansas. As a result of this deal, the company said it's further strengthening its balance sheet and is positioned to capture greater returns from its 500,000 acres in the Appalachian Basin. The proceeds will be used to retire senior notes of $900 million, retire the outstanding balance under the company’s revolving credit facility, repurchase stock up to the remainder of the company’s $200 million stock buyback program and invest in Appalachia assets over the next two years. Southwestern’s fourth-quarter production guidance will be impacted by a reduction of roughly 19 billion cubic feet resulting from the Fayetteville sale. Flywheel was backed in the deal by a $700 million equity commitment from alternative investor Kayne Private Energy Income Funds. PA and OH Permitting in October and November 2018.  The Pennsylvania Department of Environmental Protection issued 269 permits across the state for drilling and operating an unconventional well in October and November 2018. In western Pennsylvania, there were 58 permits issued in Washington County; 31 permits issued in Greene County; 21 permits in Westmoreland County; 15 permits issued in Allegheny and Butler counties; and two permits issued in Beaver County. In the first 11 months of this year, there have been a total of 1,687 permits issued across the commonwealth. Of those, there were 301 permits issued in Greene County. Other top counties for drilling/operating permits in western Pennsylvania were: Washington, 282; Westmoreland County, 132; Butler, 88; Allegheny, 73; Beaver, 60; Fayette, 41; and Armstrong, 32. Drilling also remains active in the northcentral region of Pennsylvania, where there are 5,421 active horizontal wells drilled since the beginning of 2008. Statewide, there are 10,817 active horizontal wells.

Ohio numbers

As of Nov. 17, there were 2,081 deep horizontal wells producing in the Utica or Point Pleasant shale plays in Ohio. Another 376 have been drilled, but are not producing at this time, according to the Ohio Department of Natural Resources. Of the 36 horizontal wells drilled in the Marcellus Shale in Ohio, 23 are producing wells. Eighteen of those 23 are in Monroe County, primarily in Ohio Township. Another three are in Belmont County, and there are single wells producing in Carroll and Jefferson counties in the Marcellus play. The ODNR issued 22 permits in the Utica/Point Pleasant shale plays in October, and 11 permits in November, as of Nov. 17. Guernsey County. There were seven permits issued in October and 0 in November in Guernsey County. Of the October permits, six are being drilled, four on the Fineran site in Wills Township and two on the Posey site in Oxford Township. The remaining permit was also issued for a well on the Posey site. All were issued to Eclipse Resources. Jefferson County. Ascent Resources Utica received eight new permits in Jefferson County in October, four for the Faldowski site and four on the Lori sites, all in Smithfield Township. Ascent is drilling on six of the sites. Another permit was issued on the Lori site in Smithfield Township in November. Monroe County. Equinor USA Onshore Properties (formerly Statoil) received two permits in October for horizontal wells in Green Township, and in November, Eclipse Resources received four permits in Switzerland Township. Three were for the Craig Miller wells, and the fourth on the Pittman site. Harrison County. Four permits were issued in October in Harrison County’s Archer Township to Chesapeake Exploration. One of the four, all issued for the Davis Trust wells, is being drilled. Chesapeake received another three permits in November 2018, all for the Wunnenberg wells in Cadiz Township. Also in November, Ascent Resources Utica received three permits for the Ellen well in Moorefield Township. Noble County. Triad Hunter LLC received a permit for drilling in Noble County’s Jefferson Township for a site dubbed “Woodchopper.”

Shale oil and gas at a glance

The companies with the most Ohio Utica shale permits, as of Nov. 17, are:

• Chesapeake Exploration, with 886 (719 producing)
• Ascent Resources Utica, 485 (367 producing)
• Gulfport Energy Corporation, 406 (299 producing)
• Antero Resources Corporation, 260 (215 producing)

Drilling interest is shifting south: Belmont County has the most total drilling permits issued since 2011, at 585, passing Carroll County, which was the state’s first boom area and has 525 drilling permits. There were 54 drilling permits issued in Belmont County in 2018, compared to only five in Carroll County. Monroe County, which has 418 total permits, received 45 permits in 2018. Harrison County remains active, with 33 of its total 433 permits issued in 2018. Guernsey County has 242 total permits, with 32 issued to date in 2018. Utica Shale natural gas production in Ohio was more than 21 times greater in 2017 than in 2012. Pennsylvania’s gross natural gas production, primarily from the Marcellus Shale, reached nearly 5.5 trillion cubic feet in 2017, and the state was the nation’s second-largest natural gas producer after Texas. Marcellus shale map Pennsylvania now has 10,817 active horizontal wells drilled across the state. Washington County has the most active wells, at 1,884, followed by Susquehanna, in the northcentral region, with 1,551 active wells. In the U.S., estimated production of natural gas from shale plays increased 9% in 2017. The Marcellus shale play is the largest natural gas shale play in the United States by volume of reserves. Joe Barone jbarone@shaledirectories.com 610.764.1232

https://www.shaledirectories.com/blog/facts-rumors-315/

Facts & Rumors # 314

Save these 2019 for Shale Directories Seminars

Utica Midstream March 21, 2019 Walsh University North Canton, OH

Upstream PA 2019 April 17, 2019 Penn Stater Conference Center State College, PA

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

Appalachian Storage Hub Location.  I have heard from different sources that the Appalachian Storage Hub will be located in West Virginia.  The Parsons Corporation was selected by the Appalachian Development Group to evaluate the five locations identified by the Benedum Study.  The two West Virginia locations in the study are located in these counties: one site covers Tyler, Doddridge and Wetzel counties; the other site covers Roane, Jackson, Putnam and Kanawha counties. I’m betting my money on the Roane, Jackson, Putnam and Kanawha counties.  (RUMOR) More Permian Consolidation.   Multi-billion-dollar acquisitions have made headlines this year, as Concho Resources acquired RSP Permian, and Diamondback Energy is about to complete its purchase of Energen Resources. As the Permian’s unconventional shale play matures and shifts into manufacturing mode, experts said companies will need to scale up to continue their success. That’s an assessment agreed upon by panelists at the recent Executive Oil Conference presented by Hart Energy “Consolidation will continue for the next year, year and a half,” said Mike Marziani, executive vice president and chief financial officer, Tall City Exploration III. He said 10 or 15 names could disappear, “not just in the Permian Basin but across the E&P industry.” While he said that could sound like a negative, “those same dynamics offer opportunities for small companies like us” that can take advantage of the non-core assets shed by the larger companies. James Walter, co-chief executive officer of Colgate Energy LLC, said “the Permian Basin has always had an independent mind set. We’ll see the independents regroup and come back.” Chris Atherton, president, EnergyNet, said activist investors appear to be driving at least some activity in the mergers and acquisitions market. “Activist investors are sable rattling with the public companies, particularly Delaware Basin companies, to divest their lesser acreage,” he said. Added Walter, “Companies are starting to recognize the value of high-grading their portfolios.” Marziani said that some acreage doesn’t meet thresholds where they’re worth selling. His company recently launched its third iteration, backed by up to $500 million in equity financing from the private equity firm Warburg Pincus. “Our team is focused on the Permian Basin, east of the Midland Basin to west of the Delaware Basin and everywhere in between,” he said. “We’re dedicated to new play concepts. The first Tall City leased in Howard County, 60 miles from the Wolfcamp play. We say there are still places to explore.” He said with the Permian offering five to seven benches of drilling inventory, there will be opportunities in the churn of acreage as leases turn over because wells weren’t drilled in a timely manner. He said Tall City’s team also “doesn’t shy away from step outs. We’ll take the fairways; we’ll go places that aren’t leased. We also explore three-dimensionally. This basin has scale, and the fact it still has surprises, offers opportunities.” Walter said Colgate got its start in 2015 putting together a three-section block in Reeves County. As companies consolidate, said Atherton, “You have this behemoth of a company with inventory they won’t get to for 30 years. They can spin that off to other companies.” ETP Going to PA Government to Defend Mariner East 2 Service Date. Energy Transfer LP representatives are heading to Pennsylvania’s capital on Thursday for a hearing before utility regulators to defend the company’s plan to put the Sunoco Mariner East 2 natural gas liquids pipe into service by year end. Energy Transfer wants to temporarily connect an existing 1930s-era 12-inch (30.5 centimeter) pipe to the parts of its long-delayed 20-inch Mariner East 2 pipeline that it has already completed so it can start transporting liquids for customers. Those customers have been waiting for more than a year to ship liquids on Mariner East 2. When Energy Transfer first started working on the $2.5 billion project in February 2017, it had planned to put the 350-mile (563-kilometer) pipe into service in the third quarter of 2017. Mariner East 2 and another Energy Transfer project, the Rover natural gas pipe from Ohio to Michigan, were delayed over the past year in part because the projects together racked up more than 800 state and federal permit violations while the company raced to build them. Those opposed to Energy Transfer’s plans for Mariner East 2 asked the Pennsylvania Public Utility Commission (PUC) to stop construction on Mariner East 2 and also stop the company from transporting liquids on the existing Mariner East 1 pipeline. The administrative law judge at the PUC scheduled to hear the case on Thursday is Elizabeth Barnes, the same judge who heard a case earlier this year that sought to stop the Mariner East project. In that case, Judge Barnes ordered Energy Transfer to stop transporting gas on Mariner East 1 and stop work on Mariner East 2 in West Whiteland Township after sinkholes were discovered near the pipeline. In the latest case, seven residents of Delaware and Chester Counties in southeast Pennsylvania argued Energy Transfer did “not provide adequate notice of procedures sufficient to ensure the safety of the public in the event of a leak or rupture.” In response, Energy Transfer spokeswoman Lisa Dillinger said in an email “We do not believe the claim is valid...The integrity of our Mariner East 1 and 2 pipelines has been verified in the last few months” by state and federal regulators. Mariner East transports liquids from the Marcellus and Utica shale fields in western Pennsylvania to customers in the state and elsewhere, including international exports from Energy Transfer’s Marcus Hook complex near Philadelphia. Cyber Security Importance. A hot topic of discussion in companies today is cyber security -- and the energy industry is not immune to all the issues that revolve around cyber security, according to Jim McGlone, chief marketing officer of Virginia-based Kenexis Consulting. Cyber security is a global issue that affects everyone, he said, addressing the audience at the all-day program entitled "Kallanish New Horizons: Appalachian Basin," presented Thursday at the Southpointe Business Park, south of Pittsburgh, presented by Kallanish Energy. “It’s complicated, changing, global and uncertain. Everyone has the problem. It’s a challenge,” McGlone said. “It’s ever-changing and there really isn’t an answer.” There are, he said, lots of "nasty" people in the world who are willing to "mess with you and your company for reasons that often cannot be explained," he said. McGlone, a certified industrial cybersecurity professional, suggested basic steps conference attendees could take to boost their own cyber security, and alternatives they might consider. That includes microprocessor-based switches and other non-hackable safeguards. And changing the password for their in-home router. He also questioned whether it is really necessary to connect everything via computer systems that could be hacked. Winter Gas Markets Rig Higher (Thank you, BTU Analytics) At the end of August 2018, the level of concern about the upcoming winter seemed muted as the December 2018 Henry Hub futures contract traded around $3 despite the fact that US gas storage levels were about 600 Bcf behind the 5-year average at the time. The consensus view could be summarized as new pipeline capacity was coming online in fall 2018 which would allow producers to grow supply to meet winter demand. Fast forward to November 14, 2018 and new pipelines are online (Nexus and Atlantic Sunrise, for example) and production has grown (Appalachia pipeline production receipt flow samples have consistently sustained over 30 plus Bcf/d this week).  But, like the flick of a switch as the winter gas market rips higher, we are in a demand driven winter gas market where the Henry Hub prompt futures is up over $1.30 this week to $4.80 per MMBtu today. Gone is the summer 2018 gas market where pipeline constraints limited supply area growth, while supply area basis was weak and summer demand was met with futures not budging above $3 per MMBtu. In the current market, demand has grown faster than producers can respond with production gains. What has changed in the market going into winter 2018-2019? Supply, demand, and pipe capacity have all grown. As shown below, monthly modeled supply has grown across many supply basins year-over-year, with Appalachia leading the way at 4.0 Bcf/d thanks in part due to new pipe capacity. The challenge is demand has also structurally moved higher. Looking at a demand sample (deliveries off of interstate pipelines) of regional demand by facility type, comparing November 2017 vs 2018, the 4.0 Bcf/d of Appalachian production growth is being soaked up by 3.4 Bcf/d of either Appalachian demand or adjacent regional demand to Appalachia, as shown in green below. The Southeast power, LDC and Atlantic Seaboard LNG (Cove Point) components represent the three largest year-over-year gains. With Transco connecting Appalachia, the Atlantic Seaboard, and the Southeast, we can see below the impact on pipeline flows as winter demand has ramped up. Atlantic Sunrise started service October 6, 2018 and the increased volumes can be seen as flows south at the Virginia-North Carolina border approached 2 Bcf/d. As the recent ramp in demand has started (and note we are only talking about ‘November cold’ here) flows south on Transco have dropped by about 700 Mcf/d. It seems the market finally cares about the 600 plus Bcf storage deficit to the five-year average and how much producers can ramp supply going into winter as the winter 2018-2019 strip is now priced over $4.50 per MMBtu, while the summer strip 2019 is below $2.80 per MMBtu. What does this mean as we roll into the peak winter months of January and February? How much inventory are producers carrying into winter? To access BTU Analytics’ view on Henry Hub and basis pricing, subscribe to the Northeast Gas Outlook service. Important PA Supreme Court Ruling.  Justices to decide whether rule of capture applies to fracking. The Pennsylvania Supreme Court is set to determine whether the rule of capture, which precludes trespass liability for drillers where oil and gas drains from surrounding lands in the course of conventional extraction from an underground pool, applies where shale gas is extracted through hydraulic fracturing. In an apparent case of first impression, the Pennsylvania Superior Court ruled earlier this year that it does not. On Nov. 20, the high court issued a one-page order agreeing to consider a single question on appeal: “Does the rule of capture apply to oil and gas produced from wells that were completed using hydraulic fracturing and preclude trespass liability for allegedly draining oil or gas from under nearby property, where the well is drilled solely on and beneath the driller’s own property and the hydraulic fracturing fluids are injected solely on or beneath the driller’s own property? “The case has drawn heavy amicus interest from industry organizations including the Marcellus Shale Coalition, the American Exploration & Production Council, the Pennsylvania Chamber of Business and Industry, the Pennsylvania Independent Oil & Gas Association, the Independent Petroleum Association of America and the American Petroleum Institute. Real Trouble for Atlantic Coast Pipeline.  The U.S. Army Corps of Engineers has suspended a national permit for the Atlantic Coast Pipeline to cross more than 1,500 streams in three states, raising a potential new barrier for construction of the project through Virginia. About half of the 600-mile pipeline would be built in Virginia from West Virginia to North Carolina, but Dominion Energy and its partners are still waiting for federal regulators to allow them to proceed with construction here. The Army Corps’ offices in Norfolk, Wilmington, N.C., and Pittsburgh issued orders late Tuesday to suspend the Nationwide 12 permit’s use for the project’s stream crossings. Dominion spokeswoman Jen Kostyniuk said the company had voluntarily offered to suspend the permit for all three states while attempting to resolve issues from a decision by the 4th U.S. Circuit Court of Appeals earlier this month. In that decision, the court issued a temporary stay of the permit for stream and river crossings in West Virginia. ExxonMobil Using Renewables for Electricity in the Permian.  Exxon has inked a 12-year deal with Danish renewable energy company Orsted to buy 500 MW of electricity produced by solar and wind farms to power its oil production in the Permian, Bloomberg reports. Although the terms of the contract remained undisclosed, it is the largest such contract featuring an oil company as a party, Bloomberg new Energy Finance commented. “We frequently evaluate opportunities to diversify our power supply and ensure competitive costs,” Exxon spokeswoman Julie King told Bloomberg in a statement. The company has been the target of a lot of criticism—and lawsuits—regarding its attitude to climate change and renewable energy use. Yet now that solar and wind power is becoming cheaper and demand for the commodity in the Permian is soaring, the time is apparently right for Exxon to start changing. The electricity Exxon will be buying from Orsted will be produced at two farms, one solar and one wind—both which are still under construction. The Sage Draw wind farm will be completed in 2020 and the Permian Solar farm will be launched in 2021. The Permian is the shale play where production is growing the fastest and with it demand for electricity is growing, too. Bloomberg reports that just one part of the Permian, the Delaware Basin, consumed 350 MW of electricity this summer, which was triple the consumption three years ago. This amount is enough to power almost 300,000 households and it is set for another triple increase, according to utilities, in the next four years. New FERC Commissioner.   A Senate committee has voted to confirm fossil fuel advocate and Department of Energy staffer Bernard McNamee to a vacancy on the Federal Energy Regulatory Commission, Kallanish Energy reports. On Tuesday, the Energy and Natural Resources Committee voted 13-10 to approve McNamee’s nomination by President Trump. McNamee’s nomination was approved by the committee’s 12 Republicans plus U.S. Sen. Joe Manchin, Democrat-West Virginia. The nomination now goes to the full U.S. Senate and a vote is possible before Dec. 31. McNamee is a former anti-renewables activist who did pro-fossil fuel work at the Texas Public Policy Foundation, a conservative think tank that has opposed wind power projects. He also worked on the Department of Energy’s controversial coal and nuclear bailout plan that was rejected by Ferc last January. That plan has strong support within the Trump administration. OH EPA Seeking Input on PTTGC Permit.  The Ohio Environmental Protection Agency is seeking public input on a second permit for the proposed ethane cracker plant at Shadyside in Eastern Ohio’s Belmont County. The agency will hold a public information session Dec. 12 on draft modifications to the wastewater discharge permit for the $6 billion petrochemical complex proposed by PTT Global Chemical America. A public hearing will immediately follow the first session that night. The Epa said the modifications to the wastewater permit would decrease the levels of pollutants released into the Ohio River, change the locations from which storm water will be discharged and modifies the limits at an internal monitoring station that does not directly discharge to the surface water. The Ohio draft permit is available for public review at the agency’s district office in Logan, Ohio. The Epa will accept comment on the draft wastewater permit through Dec. 19. They may be submitted at epa.dswcomments@epa.ohio.gov. Thailand-based PTT has not yet made a final investment decision on the Ohio ethane cracker. It is also seeking an air permit from the Ohio Epa. A public hearing was held last night (Nov. 27) in Shadyside. The plant, if approved and if built, annually would produce 1.5 million tons of ethylene and other materials. The plant would use six ethane cracking furnaces and manufacture ethylene, high-quality polyethylene and linear low-density polyethylene. The EPA will accept public comment on the draft air permit through Dec. 11. Comments may be sent to Kimbra.reinbold@epa.ohio.gov. Earlier this year, PTT approved an agreement with a subsidiary of Daelim Industrial Co. Ltd., a leading Korean construction and chemical company, to conduct a feasibility study and to secure funding for the Ohio petrochemical complex. PTT Global Chemical America is a subsidiary of PTT Global Chemical, Thailand’s largest integrated petrochemical company. Royal Dutch Shell is building a similar ethane cracker in Beaver County, Pennsylvania, northwest of Pittsburgh. The plants would take ethane from drilling in the Utica and Marcellus shales and turn it into ethylene and polyethylene for making plastics. Permian NatGas at $0.  Permian natural gas markets felt a cold shiver this week, but not a meteorologically induced one of the type running through other regional markets. Gas marketers braced as prices for Permian natural gas skidded toward a new threshold: zero! That's not basis, but absolute price, a long-anticipated possibility that became a reality on Monday. The cause is very likely driven, in our view, by continued associated gas production growth poured into a region that won't see new greenfield pipeline capacity for at least 10 months. What happens next isn't clear, but expect Permian gas market participants to be a little excitable or jittery the next few months. In today's blog, "Keep Breathin' - Sky Falls For Permian Gas Prices on Cyber Monday," Jason Ferguson reviews this latest complication for Permian natural gas markets. Mountain Valley Completion Still 4^th Qtr. 2019.  EQM Midstream Partners LP said on Wednesday it still expected to complete the $4.6 billion Mountain Valley natural gas pipeline from West Virginia to Virginia in the fourth quarter of 2019 despite a legal opinion explaining why an appeals court vacated a water permit for the project. The U.S. Court of Appeals for the Fourth Circuit issued the opinion late Tuesday explaining why it sided with environmental groups in October and decided to vacate the so-called Nationwide Permit 12 that allows the pipeline to cross rivers in West Virginia. In the opinion, the court said the project’s proposed construction methods violated a special condition put forward by West Virginia, requiring stream crossings to be completed within 72 hours. The court also pointed to another special condition requiring projects to obtain state water quality certification for pipelines bigger than 36 inches (91.4 centimeters) in diameter. Mountain Valley has a 42-inch pipeline. West Virginia is in the process of modifying the special conditions to allow Mountain Valley and another gas pipe, Dominion Energy Inc.’s Atlantic Coast, to move forward. Analysts at Height Capital Markets in Washington said they expect West Virginia’s Department of Environmental Protection to issue the modified special conditions by the end of year, allowing Mountain Valley to seek a new permit from the Army Corps. Joe Barone jbarone@shaledirectories.com 610.764.1232

https://www.shaledirectories.com/blog/facts-rumors-314/

Facts & Rumors # 313

Save these 2019 for Shale Directories Seminars

Utica Midstream March 21, 2019 Walsh University North Canton, OH

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

Are NatGas Prices for Real?  Natural gas prices have hit $4/Mcf for the first time since, well a few days in January, but they have been at or near $3/Mcf for most of the past five years, so the possibility of a “recovery” in prices is gladdening hearts in the producing industry. The fact that inventories have been below normal for the past year without moving prices has caused much gnashing of teeth and confounded the price bulls. North American natural gas may be the purest free market for commodities in the world, where supply and demand face a number of restrictions and/or regulations, but ultimately the market balance is set by economics. This is not the same as saying they are certain or that prices are predictable. As is so often the case, the causal factors are crucial. For some time, it has been argued that prices were below breakeven costs and must rise, that shale gas decline rates were so high production couldn’t be maintained, that Wall Street would force drillers to be more conservative in their investments, and/or that LNG exports would drive prices up. Only one of these appears relevant. Interestingly, the tighter inventory situation can be explained primarily by the sudden surge in LNG exports. Although they constitute only one-third of total exports they have increased sharply in the past two years as new export terminals have come on-line and oil prices have made them attractive. NatGas Almost $5. Cold weather blanketing much of the U.S. this week boosted spot natural gas prices for Nov. 15 to their highest since January in several regions, while natural gas futures slid 10% as investors took profits after a rally that had lifted them to their highest levels in nearly four years. Front-month gas futures rose as high as $4.929 per million British thermal units (mmBtu) on Nov. 14, their highest since February 2014. Traders said the cold this week would force utilities to start withdrawing gas from storage caverns that are already around 16 percent below normal for this time of year, prompting concerns of possible gas shortages in some parts of the country later this winter. NatGas Storage at 13 year low.  Working natural gas in underground storage in the Lower 48 U.S. states at Oct. 31, totaled 3.21 trillion cubic feet (Tcf), according to data from the Energy Information Administration released last week. Inventory levels for the Lower 48 and in each of the five U.S. natural gas regions ended the refill season at their lowest levels since October 2005 -- and these levels were considerably lower than their previous five-year averages, Kallanish Energy learns. While the natural gas storage injection season is traditionally defined as April 1 through Oct. 31, additional injections do occur in November. The South Central region saw the largest margin between the five-year range and working natural gas storage levels at Oct. 31, reaching 932 Bcf, 159 Bcf (15%) lower than the previous five-year range. The Pacific region saw the largest percentage difference between the end-of-season levels and the five-year range, at 264 Bcf, or 54 Bcf (17%) lower. The three other regions EIA divides the Lower 48 into to track stored working gas were 3% to 7% lower than the previous five-year range. A low starting inventory level and below-average net injections of natural gas into storage contributed to working natural gas stocks ending the refill season at this relatively low level, according to EIA. Lower-than-average temperatures in April 2018 resulted in uncharacteristic, continued withdrawals from storage during the month. Working natural gas stocks ended the withdrawal season on March 31 at 1.36 Tcf — the fourth-lowest level reported since 2005. Although net injections recovered in the following months, the net increases in working natural gas for the injection season were lower than the five-year average. From April 1 through Oct. 31, EIA estimates net injections totaled 1.85 Tcf. Injections were 269 Bcf (13%) lower than the five-year average, despite being 97 Bcf (6%) higher than injections in 2017. This level was the fourth-lowest net injected volume for the refill season in 13 years. The South Central and Pacific regions posted the largest differences from the five-year average. In the Pacific region, net injections into storage fell 33 Bcf (26%) lower than the five-year average. In the South Central region, reported net injections totaled 201 Bcf (39%) lower than the five-year average. In the East and Midwest regions, net injections were each 18 Bcf lower than the five-year average (3%). The only region that matched its five-year average net injections was the Mountain region. Despite increased natural gas production, increased demand for natural gas reduced net injections into working gas storage. Natural gas production averaged 83.6 Bcf/day during the refill season in 2018, compared with 74.7 Bcf/day in 2017 during the same period. However, greater-than-average power sector consumption of natural gas during the late spring and summer, combined with increased natural gas demand from U.S. export markets, resulted in lower-than-average weekly net injections of natural gas into storage. PTT Seeking OH Air Permits.  While it remains unclear if PTT Global Chemical America will build an ethane cracker in eastern Ohio, the company is seeking an air permit for the project from the Ohio Environmental Protection Agency, Kallanish Energy reports The state agency has scheduled a public information session on a draft air permit on Nov. 27, at Shadyside, Ohio, in Belmont County. A public hearing will immediately follow, during which the public can submit comments on the record concerning the draft permit for the $6 billion plant. The meeting was announced Tuesday by the state regulators. If approved, the permit would allow construction of an ethane cracker plant with an annual production capacity of 1.5 million tons. The plant would use six ethane cracking furnaces and manufacture ethylene, high-quality polyethylene and linear low-density polyethylene. Carbon monoxide, nitrogen oxide, volatile organic compounds, particulate matter and greenhouse gas pollutants are expected to be emitted, along with minor quantities of other pollutants, the state regulator said. Computer modeling was conducted to ensure local air quality will be protected, it said. If the permit is approved, the total maximum air emissions would be limited to protect public health and the environment, the EPA said. Encino in the Utica.  Chesapeake Energy has quietly left the gas-rich Utica Shale in eastern Ohio, but its drilling plan is still being implemented by Encino Energy, at least temporarily. The $2 billion purchase of 933,000 acres and 920 horizontal Utica wells from Chesapeake by Encino Acquisition Partners (Eap) officially closed on Oct. 29, as Chesapeake moved to reduce its corporate debt. The deal could result in more Utica production from a better-financed company that can invest in the shale region, according to observers. At the time of the deal in July, Chesapeake CEO Doug Lawler said, “We can’t grow the investment as we like and that makes it a strong candidate for divestiture.” He said the Utica was the best asset to sell and that leaves Chesapeake with five strong assets for future growth. The company last month spent $3.98 billion to acquire additional Eagle Ford and Austin Chalk assets in southeast Texas from WildHorse Resource Development Corp. “Chesapeake divesting its Utica Shale assets in Ohio is a positive move for Chesapeake and creates a new opportunity for someone else to come in and continue to develop this resources and acreage,” Matthew Hammond, executive vice president of the Ohio Oil and Gas Association told the Columbus Dispatch newspaper. The deal comes as Encino and Ascent Resources emerge as two of the biggest players in the Utica Shale as a result of recent deals, Kallanish Energy reports. Chesapeake, the third largest gas producer in the U.S., was one of the early Utica developers and its biggest producer. The Oklahoma-based energy giant had stormed into Ohio in 2010 and snapped up prime acreage in the Utica, a true first mover. Its colorful CEO, the late Aubrey McClendon, a strong Utica advocate, had quipped the Utica would be the biggest thing to hit Ohio since the plow. Now those Utica assets have been acquired by Encino and its partner, the Canadian Pension Plan Investment Board. They had teamed in 2017, with the goal of acquiring large, high-margin oil and natural gas production and development assets in the Lower 48 U.S. states. Their goal is to develop a major E&P company to further drill its Utica assets and to increase production and free cash flow. “The Utica is our most important asset,” Encino Energy president and CEO Hardy Murchison told the Canton Repository newspaper in early November. “It’s by far our largest and it’s our focus for the foreseeable future. We see decades of drilling ahead of us there, and we see it as being profitable across a wide range of oil and gas price outlooks. This is our focus,” he said. Little-known Encino Energy, a privately held company with headquarters in Houston, plans to work two rigs in the Utica Shale; Chesapeake recently had no rigs in the play. A third Utica drilling rig will be added next year and maybe a fourth rig in 2020, it said. Initially, Encino said it will drill wells that had been planned by Chesapeake. It intends to stick to the overall Utica drilling plan laid out by Chesapeake for where and how much it will drill for the next year or so. By 2020, Encino intends to implement its own drilling plan in Ohio. The company will keep its regional headquarters in Louisville, Ohio, outside of Canton, Ohio, for roughly 100 employees that transferred from Chesapeake. Encino plans to buy additional Utica acreage and to hire more workers as more rigs are added, said Murchison, who previously worked at First Reserve Corp. as well as Simmons and Co. International and Range Resources. The company has hired Ray Walker, Range’s recently retired chief operating officer, to direct its drilling efforts in the Utica. “We’ve got a lot of room to grow and what we’re really focused on is making good, steady cash flow year after year after year,” Walker told the Canton Repository. Murchison said his partnership looked at oil and natural gas basins across the country, but was drawn to the Utica. Chesapeake had assembled high-quality acreage in the Utica and the acreage that Chesapeake held included Utica dry gas and wet gas windows that produce condensate and natural gas liquids that can be lucrative, in addition to natural gas. The Utica and the Marcellus Shale also have pipelines and processing plants and an under-construction ethane cracker in Beaver County, Pennsylvania, near Pittsburgh. Chesapeake said roughly 322,000 acres it sold lie within the prime Utica commercial window for drilling. Its Ohio wells produced an average of 107,000 barrels of oil-equivalent per day (Boe/d), including 67% natural gas, 24% natural gas liquids and 9% oil. They produce about 600 million cubic feet of gas-equivalent per day (Mmcfe/d). It said the proved oil and gas reserves in the Utica Shale, as of Dec. 31, 2017, were roughly 480 million Boe (72% natural gas, 23% NGLs and 5% oil). Encino was created in 2011 and partnered with the Canadian pension fund in 2017 to create Encino Acquisition Partners. Encino put up $25 million, while the pension fund invested $1 billion. The Canada Pension Plan Investment Board is a management organization that invests funds not needed by the Canada Pension plan to pay benefits to 20 million contributors and beneficiaries. CPPIB, headquartered in Toronto, is governed and managed independently of the Canada Pension Fund and has no connection to government. As of March 31, the CPP Fund had C$356.1 billion ($268.97 billion) in assets. Its Energy & Resources portfolio consists of 10 direct investments valued at C$6.1 billion ($4.61 billion). Encino’s operations prior to the Chesapeake deal were based largely in the Anadarko Basin in Oklahoma. GE Taking Steps to Sell Baker Hughes.  General Electric is speeding up a plan to divorce itself from oil-and-gas giant Baker Hughes. GE (GE), which has been racing to repair a bloated balance sheet, announced a complex agreement on Tuesday to unload up to 166 million shares in oilfield services firm Baker Hughes (BHGE). The transactions would raise about $4 billion at current prices. The timing of the deal shows how bad the debt-riddled conglomerate needs the cash. GE only completed its takeover of Baker Hughes in July 2017. Yet by June 2018, GE said it would eventually get rid of its 62.5% stake. GE had to reach an agreement to escape a lock-up period that prevented the company from exiting the Baker Hughes investment until July 2019. New GE CEO Larry Culp, who took over on October 1, is under immense pressure to bolster the company's balance sheet by rapidly selling off businesses. Panicked investors have sent GE stock plunging 50% this year, on track for its worst year since 2008. GE shares closed 8% higher on Tuesday, Culp vowed on Monday to move with a "sense of urgency" to get GE's debt problem under control. "We do have a lot of leverage," Culp told CNBC. "We have a number of options to bring that leverage down over time." In a statement on Tuesday, Culp said the Baker Hughes agreements "accelerate" the company's plan to pursue an orderly separation from Baker Hughes. GE has said the process could take several years to complete. Anderson to Lead NETL.   A West Virginia University professor, who is one of the Appalachian Basin’s top experts on, and most vocal proponents for, natural gas liquids storage and petrochemical plants, is moving to a larger, national stage. Brian Anderson, who also is director and founder of the WVU Energy Institute, has been selected the new director of NETL, the National Energy Technology Laboratory, Kallanish Energy reports. NETL has facilities in Morgantown, West Virginia, just south of Pittsburgh, and on the U.S. West Coast. “Dr. Anderson’s extensive experience and knowledge in engineering and science is extraordinary," U.S. Secretary of Energy Rick Perry said, in a statement. "As the only national laboratory that is fully owned and operated by the Department of Energy, I am confident the National Energy Technology Laboratory will continue to make strides in advancing coal, natural gas, oil, and other energy technologies under his leadership." Anderson assumed his new position Sunday. PA Using More NatGas.  More and more people are recognizing the potential Marcellus and Utica Shale natural gas could have if the gas and associated natural gas liquids were used in Pennsylvania, rather than being exported to other areas of the U.S. — and internationally. PIOGA hosted "Marcellus to Manufacturing," a day-long program in Pittsburgh which brought current and potential natural gas-related companies together to hear how firms are and can capitalize on gas, and how Pennsylvania’s state government can help make investment a reality. Mike Storms, a member of a panel discussing downstream opportunities and managing risk in the energy market, expressed the attitude of the day-long program in just seven words: “We love that the gas is here,” said the director of Operations, Engineered Products, at the Elliott Group, a 100-plus-year-old company that designs, manufactures and services turbomachinery. Elliott certainly is a beneficiary of abundant Marcellus Shale gas. Among the oil and gas-related projects it’s involved with is Shell’s now-under-construction ethane cracker in Beaver County, Pennsylvania. The Jeannette, Pennsylvania-based Company sold millions of dollars of equipment for the cracker, including monstrous compressors and steam turbines, Kallanish Energy finds. One of the primary reasons Shell selected the western Pennsylvania site for the first cracker built in the Appalachian Basin in decades was abundant, inexpensive gas. “We’re seeing facilities being built now, that if they had been built 10 years ago, would never have been built here,” according to Andy Huenefeld, price risk manager, for Kinect Energy Group. “They would have built elsewhere for low labor costs. Now, they are building here for low energy prices.” ETP Expanding Pipeline Capacity in the Bakken.  Energy Transfer Partners (ETP) said last week it's considering expanding capacity on the Dakota Access pipeline system by 45,000 barrels per day (Bpd), to as much as 570,000 Bpd, Kallanish Energy learns. CEO Thomas Long said in the company’s earnings call “recent differentials and continued basin growth highlights the need for additional takeaway capacity out of the basin.” Crude oil production in the Bakken play has reached a record and is expected to increase by nearly 13,000 Bpd in November. This would put daily production capacity at a peak of 1.35 million barrels per day (Mmbpd). The Dakota Access pipeline system can currently handle 525,000 Bpd of western Canada crude. TX October Permits.   The Railroad Commission of Texas in October issued a total of 1,149 original drilling permits, compared to 997 permits in October 2017, a 15.2% increase, Kallanish Energy reports. The October 2018 total included 1,051 permits to drill new oil or gas wells, 11 to re-enter plugged well bores and 87 for re-completions of existing well bores. The breakdown of well types for those permits is 271 oil, 64 gas, 729 oil or gas, 77 injection, two service and six "other" permits, the commission reported. In October 2018, the commission processed 987 oil, 170 gas, 49 injection and seven other completions. That compares to 257 oil, 91 gas, 39 injection and four other completions in October 2017. Total well completions processed for 2018 year-to-date are 9,254, up from 5,799 recorded in the same period of 2017, a nearly 60% increase. According to well services company Baker Hughes, the Texas rig count as of Nov. 9 was 530, representing about 50% of all rigs in the United States. The Texas state permit system is seen by many as a good indication of the way the industry is moving on a monthly basis. The Midland area was No. 1 in October for permits to drill oil/gas holes with 545 permits. It was followed by the San Antonio area, the Refugio area, the San Angelo area and North Texas. For oil completions, the Midland area again was No. 1, with 464 permits, followed by the San Antonio, Refugio, San Angelo and Lubbock areas. For gas completions, the Midland area was tops with 71 permits, followed by the San Antonio, Refugio, East Texas and, in a tie, the Panhandle and Deep South Texas areas. Oil Shortfall by 2020.  The International Energy Agency (IEA) said Tuesday there’s a mismatch between robust oil demand in the near term and a shortfall in projects, causing a “sharp tightening” of oil markets in the 2020s, Kallanish Energy reports. Launching the World Energy Outlook (WEO) 2018 report, in London, the IEA said oil consumption will continue to grow in coming decades due to rising petrochemicals, trucking and aviation demand. But meeting this growth could prove to be a challenge. Approvals of conventional oil projects need to double from their current low levels, the IEA warned. “Without such a pick-up in investment, U.S. shale production, which has already been expanding at a record pace, would have to add more than 10 million barrels a day from today to 2025 -- the equivalent of adding another Russia to global supply in seven years – which would be a historically unprecedented feat,” it said. Analyzing the diverse range of energy fuels, the Paris-based agency said the geography of energy consumption continues its historic shift to Asia, but finds mixed signals on the pace and direction of change. The WEO found oil markets are entering a period of “renewed uncertainty and volatility,” heading to a potential supply gap in the early 2020s. Meanwhile, demand for gas is on the rise, erasing talk of a glut as China emerges as a giant consumer. Solar PV is charging ahead, but other low-carbon technologies and especially efficiency policies still require a big push. IEA executive director Fatih Birol said investments of roughly $2 trillion per year will be needed to meet future energy demand. “Our analysis shows that over 70% of global energy investments will be government-driven and, as such, the message is clear: the world’s energy destiny lies with government decisions,” he added. “Crafting the right policies and proper incentives will be critical to meeting our common goals of securing energy supplies, reducing carbon emissions, improving air quality in urban centers, and expanding basic access to energy in Africa and elsewhere.” Also on Tuesday, OPEC said it has revised downwards its estimate for global oil demand growth in 2019 by 70,000 barrels per day (Bpd), compared to its previous month estimate. Crude consumption is now forecast to reach 100.08 million barrels per day (Mmbpd) next year. The producers’ cartel warned the oil markets were heading towards a new supply glut in 2019, as lower demand would meet higher non-OPEC supply. EQT Spins Off Midstream.  Equitrans Midstream Corp. has completed its previously announced spinoff from the EQT Corp., Kallanish Energy reports. Equitrans is one of the largest natural gas gatherers and transmission pipeline operators in the U.S., with a major footprint in the Marcellus and Utica Shale plays in the Appalachian Basin, the companies said. Pittsburgh-based Equitrans on Tuesday began trading on the New York Stock Exchange under the symbol "ETRN." The separation from EQT officially took pace Monday at 11:59 p.m. through a pro rata distribution of 80.1% of the outstanding common stock of ETRN. EQT shareholders retained their EQT shares and received 0.80 shares of ETRN common stock for every share of EQT common stock outstanding as of the close of business on Nov. 1. EQT retained 19.9% of the outstanding common stock of ETRN. “Today, we launch Equitrans Midstream as a powerful independent company with a very bright future,” said president and CEO Thomas Karam, in a Tuesday statement. “ETRN now emerges with strong fundamentals and, as we work to deliver solutions for our customers and create additional value for our shareholders, our goal is to achieve the scale and scope of a premier, top-tier midstream company,” he said. Equitrans’ strategy will be to focus on leveraging existing pipeline and storage infrastructure systems by developing organic growth projects that will expand its footprint across the Appalachian Basin with delivery to major demand markets, the company said. Those organic projects will primarily involve gathering and transporting natural gas to markets and providing water and other midstream services to producers across the Appalachian Basin, according to the company. “We are laser-focused on the execution of our inflight projects including the Mountain Valley Pipeline, which are expected to drive more than 50% growth in EBITDA over the next three years,” said chief operating officer Diana Charletta, in a statement. Permian Energizes Dallas-Fort Worth.  The Austin Chalk. The Barnett Shale. The Eagle Ford. These mighty Texas formations are forever cemented into local lore for the fortunes they’ve created. They’re geological playgrounds, where high-stakes games of hide-and-seek regularly occur between eager risk-takers and a precious commodity silently waiting to seep up from below. But no oil play possesses the unbridled potential of the Permian. Since it was first tapped in 1923, the shale basin has seen extraction of about 30 billion barrels. That pales in comparison to what still lies beneath. According to London-based consulting and research firm IHS Markit, between 60 billion and 70 billion barrels of recoverable oil remain underground. The value, based on current oil prices, tops $4.3 trillion. “How can we have been drilling in the Permian Basin for 100 years and then find out it has twice as much as we thought?” energy maverick T. Boone Pickens often asks. It’s a question that remains to be answered, but one thing is for certain: The effects of the Permian are being felt far beyond West Texas, where new technologies and drilling efficiencies have made it easier and cheaper to tap into the basin’s rich reserves. The boom is already having a profound impact in Dallas-Fort Worth, as energy players, logistics companies, private equity firms, investment bankers, M&A and tax attorneys, tech and service companies, oil-and-gas consultants, and others position themselves to get a piece of the action. The Latest on DUC’s.  The number of drilled, but uncompleted (DUC) wells in the Lower 48 U.S. states seven most productive basins/plays rose by 3.3% from September to October. The increase occurred despite three of the seven areas reporting a drop in DUCs, according to the November issue of the Energy Information Administration’s Drilling Productivity Report (DPR). The DPR reveals 269 DUCs were added to the September total of 8,276. The new total is 8,545, as of Oct. 31, Kallanish Energy reports. The biggest increase by far from September to October was in the Permian Basin, up 249 drilled, but uncompleted wells, 6.9%, to 3,866, from 3,617. The Anadarko was the closest basin/play to the Permian, up 41 DUCs, or 3.9%, from September to October, to 1,084, the DPR reveals. The three drilling areas which recorded a month-to-month drop in DUCs were Appalachia (the Marcellus and Utica Shale plays), Bakken and Niobrara, down 19, 20 and 14 DUCs, respectively, to 623, 797 and 401, respectively. The Eagle Ford play saw a 25-DUC increase, to 1,571, while the Haynesville Shale recorded a seven-DUC increase, to 203.

Utica Shale Well Activity as of Nov. 10. 2019

DRILLED: 252 (254 as of last week) DRILLING: 121 (120) PERMITTED: 469 (467) PRODUCING: 2,075 (2,072) TOTAL: 2,917 (2,913)

TOP 10 COUNTIES BY NUMBER OF PERMITS

1. BELMONT: 585 (585 as of last week)
2. CARROLL: 525 (525)
3. HARRISON: 430 (427)
4. MONROE: 414 (414)
5. GUERNSEY: 242 (242)
6. NOBLE: 223 (223)
7. JEFFERSON: 203 (202)
8. COLUMBIANA: 159 (159)
9. MAHONING: 30 (30)
10. WASHINGTON: 22 (22)

TOP 10 COMPANIES BY NUMBER OF PERMITS

1. CHESAPEAKE: 888 (888 as of last week)
2. ASCENT RESOURCES UTICA: 485 (481)
3. GULFPORT: 406 (406)
4. ANTERO: 260 (260)
5. ECLIPSE: 193 (193)
6. RICE: 128 (128)
7. XTO: 75 (75)
8. HILCORP: 59 (59)
9. CNX GAS: 52 (52)
10. PENNENERGY RESOURCES: 40 (40)

SOURCE: OHIO DEPARTMENT OF NATURAL RESOURCES     Joe Barone jbarone@shaledirectories.com 610.764.1232 Vera Anderson vera@shaledirectories.com 570.337.7149

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Facts & Rumors # 312

Expo/Industry events for the next few months

Downstream Petrochemical Value Chain November 15, 2018 Eagle Sticks Golf Club 2655 Maysville Pike Zanesville, OH

https://bit.ly/2CWeXjs

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

Shell E&P Pulling out of PA.  Shell is looking to sell its acreage in Tioga County, PA.  Shell has been assigning well site workers to other Shell operations in other parts of the world.  (RUMOR) ExxonMobil’s CEO Comments on the Permian.  The world's biggest public energy company doesn't worry about size when it comes to potential deal-making. The driver of any acquisition for Irving-based Exxon Mobil Corp. isn't the scope of the target; it's whether the company finds more value in it than the market does, said chief executive officer Darren Woods at the New Economy Forum in Singapore. The explorer is looking for opportunities to purchase assets even as it plans to expand output at existing fields from West Texas to Mozambique. "We have the capacity to do any size opportunity that can come about, so it's really a function of looking at the value that Exxon Mobil can extract, and how we would integrate that into our portfolio," Woods said in a Bloomberg TV interview, while declining to comment on any specific targets. Exxon spent $6 billion buying drilling rights from the Bass family in the Permian Basin last year and has been cited by analysts a potential purchaser of Endeavor Energy Resources LP, the basin's largest privately-held oil producer -- an acquisition that could total more than $10 billion. The oil major certainly has the capability to do big deals, with more than $3 billion of cash on its balance sheet and low debt, according to Bloomberg data. Woods sees a bright future for the oil industry, with 2.5 billion people set to enter the middle class in the next 20 years. That means more liquefied natural gas for electricity, more petrochemicals for plastics, and more oil to fuel the heavy-duty transportation required to move consumer goods. The company is seeking to grow production with a focus on Guyana, Brazil, Papua New Guinea, Mozambique and the Permian Basin in West Texas and New Mexico. Exxon has already surpassed its plan to mobilize about 30 rigs in the U.S. shale region by year's end: the company had 38 machines drilling Permian wells as of last week, a 40 percent increase in just six months. Still, Woods said the company remains committed to not rushing development in the region. West Texas Intermediate crude prices had risen 26 percent this year through early October before giving back nearly all of the gains in the past month. "The price in the oil markets are going to go up and come down again, and our view is the business we build in the Permian, we're building for the long term," he said. "It needs to be efficient, low-cost and effective, so we're making sure the pace we go at allows that to happen." Chevron’s Shale Focus.  With each passing quarter, Chevron continues to benefit from, and become more dependent upon, its booming shale-drilling business in the Permian Basin. The company is getting much better results than expected from its drilling program there and is generating lots of excess cash flow to reward investors with share repurchases and dividends. What's even more fascinating about Chevron's strategic plan is that it's also selling assets and keeping capital spending at incredibly low levels. Is the company banking its entire future on shale, or are there other plans in the works? Let's take a look at Chevron's most recent earnings results and see what management was up to this past quarter. 9 Lives of the Constitution Pipeline.  (Thank you, MDN) Miracle of miracles, two Democrat FERC commissioners (Cheryl LaFleur and Dick Glick), along with one Republican commissioner (Chairman Neil Chatterjee), voted unanimously to extend the time frame by another two years for Williams to build the Constitution Pipeline. As you may recall, the Constitution was stopped cold by NY Gov. Andrew Cuomo and the state Dept. of Environmental Conservation (DEC). Constitution is planned to run from Susquehanna County, PA up into, and mostly situated in, New York State. Encino to Stay in Canton, OH Area.  Encino Acquisition Partners plans to drill Utica Shale wells for decades to come, with Stark County home to the company’s Ohio operations. The Houston, Texas-based partnership closed Monday on a $2 billion deal to buy Chesapeake Energy’s Utica assets in Ohio. Encino Acquisition Partners acquired 920 operated and non-operated wells and the drilling rights to more than 900,000 acres, along with Chesapeake’s field office in Louisville and the 109 employees who work there.

Who is Encino?

Encino Energy and the Canada Pension Plan Investment Board formed Encino Acquisition Partners in 2017. The pension board owns 98 percent of the partnership and Encino Energy, a privately held company in Houston, operates the assets. The Chesapeake deal gives Encino Acquisition Partners more Utica wells than any other company in the state. “The Utica is our most important asset,” said Encino Energy President and Chief Executive Hardy Murchison. “It’s by far our largest and it’s our focus for the foreseeable future. We see decades of drilling ahead of us there and we see it as being profitable across a wide range of oil and gas price outlooks. This is our focus.” The new partnership looked at oil and natural gas basins around the country. Chesapeake held a lot of high-quality acreage in the Utica Shale, and had built a great team of workers in Ohio, all of whom joined Encino, Murchison said. Chesapeake also was looking to sell assets to pay off debts. Chesapeake’s acreage spanned the Utica Shale region, which has areas that produce everything from oil to natural gas to hydrocarbons like ethane that are used in making plastics and other chemicals. Being able to drill for different products gives Encino Acquisition Partners flexibility to deal with swings in the prices of natural gas and oil. The Utica region also has infrastructure — including new pipelines and processing plants — and end users of oil and natural gas, such as the Shell Appalachia “cracker plant” under construction near Pittsburgh. And the Winner Is??  NatGas!! (Thank you, MDN). We spotted an intriguing editorial in the Williamsport Sun-Gazette. It quotes a study by “an independent, market-based think tank” with some phenomenal findings. If you invest $1 million in solar, over a 30-year period you’ll get around 25 million kilowatt hours of electricity. If you invest that same $1 million in wind, you’ll get 50 million kilowatt hours over a 30-year period. But if you invest the same $1 million in natural gas-fired electric generation (cost to extract the gas, etc.), you’ll get 400 million kilowatt hours of electricity over 30 years! NatGas yields 8 times as much electricity per dollar as wind, and 16 times as much as solar. Finally, NatGas Power Plant Coming to WV.  A natural gas power plant in Brooke County is one step closer to becoming a reality. Plans have been in motion since 2010. Friday, the site was issued a permit by the state. "The opportunity is here, the shale gas reserves are here, we're just ready to get to work to build this plant and we've been waiting a few years for this announcement,” said Business Development Corporation Executive Director Pat Ford. An announcement was publicly made Friday afternoon by the West Virginia Supreme Court of Appeals. "What we want the public to know is that this is going to be over $880 million in investment to construct this plant and approximately 1,100 jobs, both direct and indirect, associated with this plant,” Ford said. Rover Gets 2 FERC Approvals.  The Federal Energy Regulatory Commission has granted Rover Pipeline permission to begin additional service moving natural gas across northern Ohio, Kallanish Energy reports. The federal agency last week told the company it could begin service on the Sherwood Lateral, Sherwood Compressor Station, Sherwood Delivery Meter Station, CGT Lateral and CGT Delivery Meter Station in the Appalachian Basin. They were the last parts of the Rover pipeline project that needed FERC approval. Approval was granted, FERC said, “on the basis of ongoing inspections, reports by the commission’s third-party compliance monitors, my staff’s determination that rehabilitation and restoration of the affected areas are generally proceeding satisfactorily and Rover’s commitment to promptly finalize restoration of the approved facilities,” said FERC spokesman Rich McGuire, in a two-page letter. Rover Pipeline, a subsidiary of Texas-based Energy Transfer Partners, has pledged restoration and rehabilitation on the remaining slips or land movements on the CGT Lateral will be completed by Dec. 18 and on the Sherwood Lateral by Jan. 2, McGuire said. He said the company had identified 44 slips or ground movement areas that needed work. Last week, the company and another federal agency indicated that Rover Pipeline was likely guilty of what were called three “probable violations.” The problems between the pipeline company and the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration have largely been resolved. The violations are for improper testing of pipeline welds, failing to comply with specifications or standards on repairing dents to the steel pipe and failure to build the pipeline to avoid stresses on the pipeline. Those two laterals are mechanically complete and the final grading and seeding have been completed, Rover Pipeline wrote. The company said it has also filed plans for additional ground-movement areas outside the construction right of way along the Sherwood and CGT laterals. The Sherwood Lateral runs about 54 miles from eastern Ohio into West Virginia. The CGT line runs about six miles from the Sherwood line to an interconnection with a Columbia Gas Transmission line. The $4.2 billion twin pipelines had encountered trouble with leaks and spills from horizontal directional drilling in Ohio where drilling had been halted for a time because of concern by state agencies. Construction was also halted for a time in West Virginia because of erosion and sediment control problems along pipeline laterals. The 713-mile pipeline will move up to 3.25 billion cubic feet per day of Utica and Marcellus natural gas to the Gulf Coast, the Midwest and Ontario. Initial service on the pipeline began Aug. 31, 2017. Clouds on the Drilling Horizon.  (Thank you, BTU Analytics) Earnings season is here, and with it comes company specific insights as well as occasional perspective on the macro environment.  Halliburton and Schlumberger commentary is often a bell weather of industry activity, so today BTU Analytics dives in to see what signals two of the largest oil service companies are sending to the market. While overall the rebound in the North American market has benefited service companies over the last two years, there is significant concern around both the short-term and long-term viability of the prominent US plays in the most recent earning announcements. Additionally, the strong run of improving operating margins over the last couple of years has begun to slow.  The chart below shows operating margins for HAL and SLB through 3Q 2018. Operating margins have been trending mostly flat since 4Q 2017. Slowing North American activity during the third quarter caused some service pricing weakness for HAL and SLB, and some of the challenges being faced over the next 12 months could mean that operating margins may not see improvement back to the 16% – 22% range seen in 2014. In the short term, both companies are feeling the effects of infrastructure impacting their clients. SLB stated that the takeaway constraints out of the Permian Basin have led to lower activity in their hydraulic fracturing business which placed pressure on their 3Q performance. Halliburton also saw some customers defer completions due to takeaway issues, however, companies with firm capacity have continued to complete wells and maintain activity in the Permian. Slower activity is expected to persist through 4Q, with operators pulling back through the end of the year due to both takeaway issues and budget exhaustion.  Both companies see the current slowdown to be temporary and predict that WTI prices remaining in the $70/Bbl range will allow for larger budgets and encourage strong operator activity in 2019. The pullback in activity across the US is consistent with BTU’s current well forecast, shown below. Increases in total US Wells to Sale activity has begun to slow, with BTU calling for 3Q 2018 to be the peak of completion activity until later in 2019 when many of the pipeline takeaway issues are resolved. Drilling activity is forecasted to remain higher than completions throughout this time frame, and for basins such as the Permian it could result in a significant build-up of DUCs (drilled uncompleted wells) over the next few months. While service companies are hoping that activity will pick up in early 2019, BTU sees challenges which could push higher completions out until later in the year. What are those challenges and what risks does BTU Analytics see to future activity levels?  For more insight into BTU’s views, request a sample of the US Upstream Outlook report. Encana – Newfield Merger.   Encana has become the second largest unconventional oil producer in North America with its all-stock merger with Newfield Exploration. The Calgary-based exploration and production company will now hold core-of-the-core assets in three major North American shale basins, including the Permian, SCOOP/STACK and the Montney. The value of the merger is roughly $5.5 billion, according to Encana. “When combined with our cube development model, expected synergies and relentless focus on efficiency, we are positioned to deliver highly efficient growth and quality returns,” said Doug Suttles, president and CEO of Encana who will assume the same role of the combined companies. Encana’s cube development program combines above-surface strategies with below ground operations. The strategy involves multiple drilling rigs working on massive multiwell pads. The system utilizes crew and infrastructure to create more efficient above ground operations. Below ground, Encana is able to use more horsepower and complete more wells while on the pad. According to the company, there is a major benefit to drilling and completing an entire cube pattern of wells positioned in multiple zones at once. “Historically, our industry was slow to identify the optimal well spacing for unconventional plays,” said Mike McAllister, Encana’s COO. “This has led to large infill drilling programs years later to try and boost recovery factors.” Following the completion of the deal—expected in early 2019—Encana intends to raise its dividends to shareholders by 25 percent and complete a $1.5 billion share buyback program. The combination of the two E&P’s creates a new version of Encana that will produced more than 577,000 barrels of oil equivalent per day Lee Boothby, president and CEO of Newfield, said Encana will now be able to develop Newfield’s assets at a faster rate. Suttles told investors that the new assets will allow Encana to transfer learnings from one basin to another and that with more assets, the company can now remain fluid with its capital, deploying in the basin’s that offer the best returns. Encana will now own roughly 63 percent of the new company, with Newfield owning the remainder. Mountain Valley Pipeline Seeks FERC Approval.  Mountain Valley Pipeline LLC petitioned the Federal Energy Regulatory Commission for authorization to build the MVP Southgate project, an interstate natural gas pipeline designed to move natural gas to central North Carolina. The pipeline company will construct and own the proposed MVP Southgate, which is a joint venture between EQM Midstream Partners, affiliates of NextEra Energy, Consolidated Edison; RGC Resources; WGL Midstream; and PSNC Energy, Kallanish Energy reports. EQM Midstream Partners will operate the pipeline and own the largest interest in the joint venture. Mountain Valley Pipeline LLC and PSNC have entered into binding long-term agreements that make PSNC Energy an anchor shipper for the project. MVP Southgate will tie into the Mountain Valley Pipeline near Chatham, Virginia, and transport Marcellus and Utica Shale natural gas to delivery points in North Carolina’s Rockingham and Alamance counties for distribution to PSNC Energy’s residential and commercial customers. As currently proposed, the MVP Southgate project is roughly 73 miles long. Construction is anticipated to begin in the first quarter of 2020, with a full in-service date targeted for the fourth quarter of 2020. Pioneer 3^rd Qtr. Update.  Pioneer Natural Resources reported third-quarter net income of $411 million, compared to a net loss of 23 million in Q3 2017, the Irving, Texas-based company reported. It reported quarterly revenue of $2.48 billion, Kallanish Energy reports. Pioneer said it is producing 288,000 barrels of oil-equivalent per day (Boe/d) in the Permian Basin of West Texas/southeast New Mexico. That's an increase of 14,000 Boe/d, or 5%, from Q2 2018, it said. Pioneer said Permian oil production grew to 186,000 barrels of oil per day (Bpd), an increase of 11,000 Bpd, or 7%, from Q2. Overall, company production in Q3 was 321,000 Boe/d. Oil sales averaged 195,000 Bpd, while natural gas liquids averaged 63,000 Bpd and natural gas sales averaged 378 million cubic feet per day (Mmcf/d). It is projecting Permian production growth of 19% to 24% in 2018, compared to 2017. “The third quarter was another very strong quarter for Pioneer and resulted in production being above guidance, healthy earnings and solid execution,” said president and CEO Timothy Dove, in a statement. He added, “The Permian Basin continues to be the best place to be in the shale oil business, providing unmatched resource potential and opportunity and delivers highly productive wells, strong cash margins and robust returns.” In the quarter Pioneer placed 69 horizontal wells into service in the Permian Basin. It is operating 22 rigs in the basin and plans to add two additional rigs in December. Pioneer expects to place 250 to 275 Permian wells into service in 2018. Pioneer said it placed its first multi-zone Spraberry appraisal pad with six wells in western Martin County. The initial results are about 35% better than previous Spraberry wells, the company said. Two additional multi-zone Spraberry pads will begin service in Q4. The company spent $835 million in Q3 on drilling and well completions. In the quarter, Pioneer delivered 165,000 Bpd of oil to the Gulf Coast, of which roughly 130,000 Bpd are being exported, it said. The company has leased about 750,000 acres in the Permian Basin. It's divesting Eagle Ford Shale and other assets to become a Permian pure-play company. That should be completed by Dec. 31, Dove said. Bakken Deal.  A SPAC has entered the Williston Basin. Vantage Acquisition Operating Company LLC, a special purpose acquisition company formed by former exploration and production executives, has acquired the Williston Basin assets of QEP Resources. The deal, expected to close in early 2019, is valued at $1.725 billion and includes QEP’s South Antelope and Fort Berthold leasehold positions. After raising $552 million in 2017 for the purpose of acquiring a leasehold position in a major shale play, the Vantage team will now be focused on further developing the assets developing by QEP, including wells targeting multiple pay zones of the Middle Bakken and one bench of the multi-layer Three Forks formation. Plains All American Expands Capacity in the Permian. Pipeline operator Plains All American said it had expanded the capacity of its network in Texas, launching its Sunrise pipeline from the Permian to Cushing, Oklahoma, which boosted overall daily volumes to between 300,000 and 350,000 barrels, Reuters reports, citing the company’s third-quarter earnings call. Earlier estimates for the capacity of the expanded network had suggested daily volumes of 200,000-250,000 bpd of crude. The news should be very welcome for Permian producers who have been grappling with pipeline capacity shortages amid fast-growing production. The Sunrise pipeline’s total capacity is as much as half a million barrels daily. Its launch has already affected prices positively, lifting them from four-year lows. As of July, the pipeline capacity in the Permian was 3.1 million bpd, according to S&P Global Platts calculations, with production at 3.5 million bpd. However, there is a total 2.6 million bpd in new capacity coming online soon: the additional barrels should begin to flow in full by the third quarter of 2019, S&P Global Platts reported. There is even more capacity coming online in later years, but this has sparked concern—vague for now—that if prices take a dive again, which is always a possibility, Permian field and pipeline operators could end up with stranded capacity as production growth slows down. However, this possibility is still only hypothetical, so the news about additional pipelines should immediately help producer get a better price for their crude; they’ve had to sell at a substantial discount to WTI because of the pipeline bottlenecks in recent months. Others are upbeat about the Permian’s production growth prospects. “In the past 24 months, production from just this one region—the Permian—has grown far more than any other entire country in the world,” Daniel Yergin, vice chairman of IHS Markit said in August, commenting on the future of the star shale play in the United States. “Add an additional 3 mbd by 2023—more than the total present-day production of Kuwait—and you have a level of production that exceeds the current production of every OPEC nation except for Saudi Arabia.” Permian “frac holiday” Will Be Ending.   Take Carrizo Oil & Gas Inc.’s operations, for instance. Just three months after moving drill rigs out of the Permian basin because of pipeline shortages, the Houston-based explorer is already talking about bringing them back in the middle of next year. That’s one of several signs the end may be near for a self-imposed slowdown executives call a “frac holiday.” The result: Carrizo will reach an “inflection point” in 2019 where both production and cash flow begin to rise together, CEO Chip Johnson said on a conference call Tuesday. In other words, things will soon be booming again. Carrizo is among many smaller operators forced to slow activity in the U.S.’s biggest oil field towards the end of this year after the Permian’s rapid production growth overwhelmed pipelines. The lack of conduits left oil almost trapped, lowering in-basin prices to almost $18/bbl, or 26%, below the U.S. benchmark in September. But with at least three major pipeline projects scheduled to come online next year, producers are now seeing the problem as a mere footnote in the basin’s ongoing story of surging production growth. “It will be a series of events throughout 2019 that occur” to ease the bottleneck, Halliburton Co. CEO Jeff Miller told Bloomberg TV this week. “It’d be easy to see, as we finish the year, things being perfectly normal.” This year, the number of wells drilled but waiting to be fracked has increased 50% to 3,722, indicating a new wave of production is set to be unleashed once the pipes are ready, spending budgets are approved and frack crews are available. This matters to world oil markets. West Texas Intermediate has tumbled almost 20% since the beginning of October as fears over U.S. sanctions against Iranian ease. Added production from the Permian would further this trend. Indeed, it bolsters the view that American oil production is in an exponential growth phase. The U.S. surpassed Russia in August to claim the title of the world’s top oil producer after posting the largest year-on-year output increase in its history. The Permian accounts for about a third of the country’s output and is the world’s fastest-growing major oil field. Consultant Rystad AS sees U.S. production climbing another 45% to as much as 16.5 MMbpd by 2030. Permian legend Mark Papa, who was a pioneer of U.S. shale as CEO of EOG Resources Inc. from 1999 to 2013, agrees that pipeline shortages “should go away by year end 2019” and may even turn into a surplus. However it’s not all plain sailing thereafter, Papa, who’s now CEO of Centennial Resource Development Inc, said in an interview last month. “Some of the other issues like personnel and water handling issues are some of the more long term issues,” he said. There are “insufficient people to get the work done.” Range Resources Receives Philanthropy Award.  The Washington County Community Foundation held their annual Philanthropy awards and recognition banquet. And in a room full of local people dedicated to community service and charitable giving, Range Resources CEO and President Jeff Ventura humbly accepted the Foundation’s Charles C. Keller for Corporate Philanthropy. As he spoke to the assembled guests, Ventura talked about why southwestern Pennsylvania is special to him and to the employees of Range Resources. “I was born and raised here in western Pennsylvania. I know how close-knit the communities are and how much the people in this region and in this county support one another. Organizations like the Community Foundation are part of what make this area such a great place to live and work. Washington County is a very special place for Range and our employees, and we are so proud to be a part of this community. We pioneered the Marcellus Shale not far from here, and it is where Range has grown as a company for nearly 15 years.” Anadarko Sells Midstream Assets.  Independent producer Anadarko Petroleum (APC) on Thursday announced it’s selling most of its midstream assets for $4.025 billion to Western Gas Partners. At the same time, Western Gas Partners (WES) announced it’s merging with Western Gas Equity Partners (WGP), following a number of master limited partnerships looking to simplify their organizational structure – and hopefully, save money. LNG Plant Coming to NEPA.  (Thank you, MDN)  We have some exciting news to share. A company called New Fortress Energy is planning to build an LNG (liquefied natural gas) liquefaction plant in Wyalusing (Bradford County), PA. The $800 million plant will supercool and liquefy locally extracted Marcellus Shale gas and ship it first by truck, eventually by rail, to “customers in the U.S. as well as abroad.” Meaning exports. How cool is that? It seems that LNG liquefaction plants no longer have to be located along a shoreline to engage in exports. Joe Barone jbarone@shaledirectories.com 610.764.1232 Vera Anderson vera@shaledirectories.com 570.337.7149

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