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NewsLetters

Expo/Industry events for the next few months

Shale Insight
September 21-22, 2016
David L. Lawrence Convention Center
Pittsburgh, PA

http://shaleinsight.com/ 

West Virginia Oil and Gas Expo
Oct. 5, 2016
Mylan Park's Expo Center
Morgantown, WV

http://wvoilandgasexpo.com/ 

Utica Summit
October 11, 2016
Embassy Suites
Canton, OH

http://www.uticasummit.com/ 

Midstream PA 2016
October 13, 2016
Penn Stater Conference Center
State College, PA 

http://midstreampa.com/   

Get Your Business Noticed on Mobile Devices
Webinar – September 14, 2016
Details to Follow

Latest Facts and a Rumor from the Marcellus, Utica, Permian, Eagle Ford, Bakken and Niobrara Shale Plays 

  • Inflection Energy Bringing in a Rig.  We have heard from a couple of sources that Inflection Energy is bringing a rig into PA.  I think most of Inflection’s permits are in Lycoming County, PA area.  (RUMOR)   
     
  • Wow!  Good News from the U.S. Government for the O&G industry.  U.S. officials announced plans last week to speed up permitting for oil and gas drilling on federal and Indian lands to reduce delays, even as applications were projected to be down 40% from their historical average amid an ongoing price slump.

    Low energy prices already have quashed domestic energy exploration, driving down revenue, and seriously hurt budgets for the major energy producing states, including Wyoming, New Mexico, Colorado, Alaska, North Dakota and Montana, which receive a substantial revenue share from oil and gas activity on U.S. lands.

    In an attempt to streamline drilling approvals and reduce costs for companies, U.S. Bureau of Land Management Director Neil Kornze last week said all drilling applications must be filed online under the new proposal.

    Online-only permitting would allow 90% of drilling applications to be completed within 115 days, bureau spokeswoman Beverly Winston said – a 105-day improvement from 2015’s 220-day completion rate.

    “The new system is a big improvement over the current, hard copy-based application system,” Kornze said.

    But Kathleen Sgamma of the Western Energy Alliance voiced concern about the potential time savings. She said the long time to process permits is driven in part by environmental studies and other requirements not counted in the administration’s 220-day processing average.

    “We’re a bit skeptical that the [automated] system will result in significant time savings,” Sgamma told The Associated Press. “Generally companies avoid public lands if they can, because they know there’s no certainty on getting through all the leasing.”
     
  • Williams to Begin Work on Pipelines in NYC and VA.  Construction is scheduled to begin in the fourth quarter on pipeline expansion projects in New York City and Virginia, Kallanish Energy has learned.

    Williams Partners’ New York Bay Expansion and the Virginia Southside II Expansion projects are both scheduled to begin moving natural gas in the fourth quarter of 2017.

    Both projects were approved last week by the Federal Energy Regulatory Commission.

    The expansions are part of Williams’ Transco pipeline system that extends more than 10,200 miles from Texas to the eastern U.S., including New York City.

    Both projects are fully subscribed, the Oklahoma-based company said, in a statement.

    The New York project is designed to transport 115 million cubic feet per day (MMcf/d) and serve increasing local demand. It will connect to the Rockaway Delivery Lateral and the Narrows meter station.

    The Virginia project is designed to provide 250 MMcf/d to provide additional natural gas to a new gas-fired power plant in Greensville County, Virginia.

    That 1,580-megawatt plant is being built by Dominion Virginia Power.

    “Our Transco pipeline infrastructure continues to connect prolific natural gas supplies with some of the fastest-growing gas markets in the U.S.,” said Rory Miller, senior vice president of Williams Partners’ Atlantic-Gulf operating area.
     
  • Dakota Aces Pipeline Gets Approval.  The US Army Corps of Engineers gave a set of approvals to a section of the $3.8 billion Dakota Aces oil pipeline last week and officials are expecting construction to speed up in the coming weeks.

    According to a report by The State Journal-Register, officials granted approvals including permission to cross the Missouri and Mississippi River. The pipeline will be approximately 1,172 miles long that will connect the Bakken and Three Forks production areas in North Dakota to Patoka, IL, according to the project’s website.

    However, the report notes that legal challenges remain for the project, including one recent suit filed by The Standing Rock Sioux Tribe in North Dakota which claims the project could threaten water supplies and sacred ground in the tribe’s reservation.

    The project remains on schedule to be in-service by the end of the year, according to the report.



    The Dakota Access pipeline is anticipated to be operational by the end of 2016.
     
  • EnLink News.  EnLink is partnering with Natural Gas Partners, an energy-focused private equity firm with deep producer relationships, to expand its midstream services and accelerate growth in the prolific Delaware Basin.

    Lobo II, a new expansion of EnLink’s existing Lobo System in the Delaware Basin, is anchored by long-term commitments from major producers and is expected to be operational by year-end 2016.   
     
  • Williams Moving Forward after Failed ETE Deal.  Putting its failed $33 billion merger with Energy Transfer Equity behind it, pipeline giant Williams is taking a “back to the future” tact for moving the company forward.

    On Monday, CEO Alan Armstrong responded with a plan that looks much like the Williams’ strategy five years ago, Kallanish Energy finds.

    While remaining extremely bullish on the natural gas market, the Tulsa, Oklahoma-based company slashed its dividend 68.8% (to 20 cents from 64 cents) and will used the funds to invest roughly $1.7 billion in its Williams Partners unit to pay for what the company called “growth prospects.”

    “We currently have projects in negotiation or execution to add 7.6 billion cubic feet per day (Bcf/d) of capacity to markets served by [interstate pipeline] Transco through 2020, which amounts to 65% of [analytics/consulting firm] Wood Mackenzie’s five-year projected demand growth for natural gas along Transco’s corridor,” Armstrong said.

    Williams’ future -- and Armstrong’s place in leading it -- has been under the microscope since Dallas, Texas-based Energy Transfer terminated its deal in June to buy Williams after months of rhetoric, lawsuits and spilled bad blood.

    Within 48 hours of the deal falling completely apart, six Williams board members had resigned after failing to toss Armstrong.

    One of those directors, activist investor Eric Mandelblatt of Soroban Capital Partners, said in a letter Armstrong was “incapable of maximizing shareholder value” and described his track record as “abysmal.”

    Williams was the latest pipeline company to cut its quarterly dividend in the face of low energy prices. The company expects to finalize the sale of its Canadian operations by Oct. 1, for more than $1 billion.

    While Williams isn’t currently looking to revisit a previous plan that would’ve rolled its Williams Partners master-limited partnership back into the company, Armstrong didn’t rule out such a move in the future.

    Williams on Monday reported it lost $405 million during the second quarter, primarily due to a $745 million non-cash, pre-tax impairment charge. One year ago, the company’s profit totaled 114 million.

    Revenue dropped 5.4%, to $1.74 billion from $1.84 billion in the year-ago quarter.
     
  • PA Sets NatGas Production Record in 2015.  Natural gas production in Pennsylvania grew to a record high in 2015, according to a new report from the state’s Department of Environmental Protection.

    More than 4.6 trillion cubic feet (Tcf) of natural gas were produced from the Marcellus Shale and other formations in 2015, Kallanish Energy has learned — enough natural gas to heat 62 million American homes. That’s up 13.5% from the 4 Tcf of natural gas produced in the state in 2014, the agency said in a 33-page report.

    By comparison, Pennsylvania produced just over 1 Tcf of natural gas in 2011.

    Pennsylvania is the second largest supplier of natural gas in the U.S., behind only Texas.

    “As our report shows, despite the reduction in the number of natural gas wells that were drilled in Pennsylvania during 2015, the overall volume of natural gas produced continued to increase to a record level,” said acting DEP secretary Patrick McDonnell, in a statement.

    In 2015, Pennsylvania saw 785 unconventional wells and 285 vertical-only wells drilled. That 785 total is a decline of 42.8% from the 1,372 horizontal wells drilled in 2014.

    The top five counties for unconventional drilling in 2015 were Washington, 160 wells; Susquehanna, 152; Greene, 103; Butler, 85; and Bradford, 43.

    Pennsylvania said only 55 Utica/Point Pleasant wells were drilled in 2015. Mercer County was No. 1 with 23 wells and Tioga was second with nine wells.

    In 2015, Pennsylvania approved 2,081 permits for horizontal wells. That was down from 3,182 wells permitted in 2014, a 34.6% drop.

    The top five counties for unconventional permits in 2015 were Washington, 361; Greene, 325; Susquehanna, 288; Bradford, 224; and Butler, 143.

    The top county for vertical-only wells was Warren, with 130 permits.

    The Marcellus Shale produced 4.4 Tcf of the state’s total gas production. The Utica Shale/Point Pleasant produced 79 billion cubic feet (Bcf).

    The top five producers, by volume, were Chesapeake Appalachia, Cabot Oil & Gas, Range Resources, EQT Production and Chief Oil & Gas.

    Pennsylvania said the number of unconventional violations dropped from 425 in 2014, to 404 in 2015, and penalties against drillers also declined, from $7.1 million, to $3.4 million.

    The report can be found at http://www.dep.pa.gov/Business/Energy/OilandGasPrograms/OilandGasMgmt/Pages/Annual-Report.aspx
     
  • Enbride and Marathon Buying into Bakken Pipeline.  A unit of Canadian pipeline giant Enbridge and Marathon Petroleum are paying $2 billion in cash for a stake in the Bakken pipeline system from an affiliate of Energy Transfer Partners and Sunoco Logistics Partners.

    Energy Transfer (ETP) and Sunoco Logistics (SXL) are selling 36.75% of the Bakken project, which includes the Dakota Access pipeline and the Energy Transfer Crude Oil (ETCO) pipeline, Kallanish Energy learns.

    ETP and SXL will receive $1.2 billion and $800 million in cash at closing, respectively. As previously announced, the Bakken Pipeline entities have arranged a $2.5 billion project financing facility that is expected to provide substantially all of the remaining capital necessary to complete the project.

    The Enbridge unit is paying $1.5 billion for its share in the deal, while Marathon will ante up $500 million.

    The deal gives Enbridge the ability to move shale oil from the Bakken to refineries along the U.S. Gulf Coast, through connections to its mainline pipeline.

    The project will consist of roughly 1,172 miles of new 30-inch crude pipeline from North Dakota to Patoka, Illinois, and more than 700 miles of pipeline converted to crude service from Patoka to Nederland, Texas.

    Bakken Holdings is selling 49% of its 75% interest (36.75%) in Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66.

    The Dakota Access pipeline is currently expected to deliver in excess of 470,000 barrels per day (BPD) of crude oil from the Bakken/Three Forks production area in North Dakota to market centers in the Midwest.

    Dakota Access will provide shippers with access to Midwestern refineries, potential unit-train rail loading facilities to facilitate deliveries to East Coast refineries, and the Gulf Coast market.

    The Energy Transfer Crude Oil pipeline, through an interconnection in Patoka, Illinois with Dakota Access, will provide crude oil transportation service from the Midwest to the Sunoco Logistics Partners and Phillips 66 storage terminals located in Nederland.

    Upon closing, a subsidiary of MPC has committed to participate in a forthcoming Dakota Access/Energy Transfer Crude Oil Pipeline open season and, subject to the terms and conditions of the open season, make a long-term volume commitment on the Bakken Pipeline Project.

    A new open season is expected to be launched before Oct. 1.

    Upon closing of the transaction, the Enbridge unit and Marathon plan to terminate their transportation services and joint venture agreements for the Sandpiper Pipeline Project.

    The companies would continue to evaluate the scope and timing of Sandpiper, a proposed 616-mile crude line from North Dakota to Wisconsin.
     
  • Hurray for WV.  An affiliation of 13 states, led by West Virginia, sued the Environmental Protection Agency on Tuesday over its regulations for oil and gas, calling the rules a "job-killing attack" on the nation's oil and natural gas workers.

    The lawsuit, filed in the D.C. Circuit Court of Appeals (reviewed by Kallanish Energy), asks the court to examine EPA's rule regulating methane emissions from new, reconstructed and modified oil and gas wells that use hydraulic fracturing (fracking).

    “Petitioners will show that the final rule is in excess of the agency's statutory authority and otherwise is arbitrary, capricious, an abuse of discretion and not in accordance with law,” according to the filing. “Accordingly, petitioners ask the court to hold unlawful and set aside the rule …”

    The states argue the regulations impose an "unnecessary and burdensome" standard on the oil and natural gas industry, "while setting the stage for further limits on existing oil and gas operations before President Obama leaves office."

    “These rules will cause West Virginia coal miners to lose their jobs and West Virginians’ electricity bills to skyrocket,” according to West Virginia Attorney General Patrick Morrisey. “EPA’s actions will upset the careful balance of ensuring reliable, affordable electricity while encouraging job growth and responsible protection of the environment.”

    The states argue the regulations "would raise production and distribution costs and, in turn, force an increase in consumer utility bills" by making fuel costs higher for power plants increasingly dependent on low-priced natural gas."

    The EPA itself predicts its regulations will cost $530 million in 2025, while other studies project the annual price tag may reach $800 million.

    In addition to West Virginia, the lawsuit includes attorneys general from Alabama, Arizona, Kansas, Kentucky, Louisiana, Michigan, Montana, Ohio, Oklahoma, South Carolina and Wisconsin, along with the Kentucky Energy and Environment Cabinet and North Carolina Department of Environmental Quality.
     
  • EagleClaw Makes Permian Purchase.  EagleClaw Midstream Ventures, a midstreamer backed by private equity firm EnCap Flatrock Midstream, is acquiring PennTex Permian, a subsidiary of PennTex Midstream Partners, for an undisclosed price.

    Primarily located in Reeves County in West Texas, PennTex Permian’s assets include a 60 million cubic feet per day (MMcf/d) capacity cryogenic processing plant, roughly 90 miles of gathering pipeline and approximately 35 miles of condensate pipeline.

    “Given the Delaware Basin’s stacked pay potential, we believe Reeves County may contain the largest inventory of profitable wells in the U.S.,” said Bob Milam, EagleClaw CEO. “This acquisition and our new state-of-the-art plant bring top-tier assets into our portfolio.”

    PennTex Permian’s assets are supported by long-term dedications of more than 75,000 acres from regional producers, Kallanish Energy learns.

    EagleClaw will connect the PennTex system to its East Toyah System, bringing EagleClaw’s current processing capacity to 120 MMcf/d and total gathering pipeline to more than 200 miles served by nine field compressor stations with a total of 20,000 horsepower of low- and high-pressure compression.

    The combined systems serve producers in the Permian’s Delaware Basin in West Texas targeting stacked pay zones.

    Due to the performance of recent wells drilled in the area, EagleClaw also announced last week it’s broken ground on an additional cryogenic processing plant at its East Toyah processing complex in Reeves County.

    The Toyah II plant will have the capacity to process 200 MMcf/d. EagleClaw expects to bring the Toyah II plant online later this year, bringing EagleClaw’s total processing capacity to 320 MMcf/d.

    An 18-mile natural gas liquids (NGL) pipeline connects the East Toyah complex to Lone Star’s West Texas Gateway Pipeline, which transports NGLs to Mont Belvieu, Texas.

    The East Toyah complex also is connected to Kinder Morgan’s El Paso 1600 Pipeline and, by October, will have an additional connect into ONEOK’s WestTex Transmission System, an intrastate natural gas pipeline system that connects into the Roadrunner Gas Transmission Pipeline.

    EagleClaw expects to complete the acquisition of PennTex Permian by Oct.1.
     
  • Noble 2nd Qtr. Update.  Noble Energy, Inc. announced results for the second quarter of 2016, including a reported net loss of $315 million, or $0.73 per diluted share. The adjusted net loss(1) for the quarter was $103 million, or $0.24 per diluted share, which excludes the impact of certain items typically not considered by analysts in formulating estimates. EBITDAX (1) (earnings before interest expense, income taxes, depreciation, depletion, and amortization, and exploration expenses) and Adjusted EBITDAX (1) were $291 million and $597 million, respectively. Capital expenditures for the quarter were $262 million, down approximately 70 percent from the second quarter of last year pro-forma for the Rosetta Resources Inc. merger. For the second quarter of 2016, approximately 65 percent of the capital was allocated to U.S. onshore and approximately 35 percent to global offshore (including Gulf of Mexico and International).

    Operations Update

    Eagle Ford

    Record quarterly sales volumes of 74 MBoe/d were achieved in the second quarter of 2016, an increase of 17 percent from the second quarter of 2015 on a pro-forma basis and up 23 percent from the first quarter of 2016. Liquids represented 62 percent of the total (25 percent crude oil and condensate and 37 percent NGLs), while natural gas accounted for the remaining 38 percent. Eagle Ford production made up 90 percent of the volumes with the Permian delivering the remaining 10 percent.

    Highlights include:
     
  • The Company brought one well online in the Wolfcamp A interval in the Permian's Delaware Basin. The Calamity Jane 2101H well, with a lateral length of 4,859 feet, was completed using slickwater and 3,000 pounds of proppant per lateral foot. To date, the well has achieved a maximum IP-30 rate of 2,541 Boe/d (or 523 Boe/d per thousand lateral feet) with 57 percent oil. On a normalized basis (5,000 foot lateral well), the well is outperforming the 700 MBoe type curve by more than 75 percent.
  • In the second quarter, Noble Energy commenced production on seven Lower Eagle Ford wells in the Gates Ranch area. Six of the wells were located in South Gates Ranch and had a lateral spacing of approximately 500 feet, an average lateral length of 7,240 feet, and an average IP-30 of 3,954 Boe/d (or 547 Boe/d per thousand lateral feet). The wells had proppant concentrations of approximately 2,000 pounds per lateral foot and cluster spacing of 40 feet. On average and normalized for lateral length, the IP-30 rates have outperformed a 3 MMBoe type curve (for a 5,000 foot lateral) over their first 30 days of production.
  • In late March, the Company brought on production six additional Lower Eagle Ford wells in the Gates Ranch area. Five of the wells were located in South Gates Ranch and tested lateral spacing of 1,000 feet or more, had an average lateral length of 4,570 feet, and resulted in an average IP-30 rate of 3,993 Boe/d (or 878 Boe/d per thousand lateral feet). On average, the wells had proppant concentrations of over 2,000 pounds per lateral foot and cluster spacing of 20 feet. Normalized for lateral length, these wells have outperformed a 3 MMBoe type curve (for a 5,000 foot lateral) by approximately 60 percent over the first 90 days.
  • There were 46 wells drilled but uncompleted (including 31 in the Eagle Ford and 15 in the Delaware) at the end of the quarter.

    ​​DJ Basin

    Sales volumes averaged 113 MBoe/d in the second quarter of 2016, an increase of nearly 5 percent from the second quarter of 2015. Liquids represented 66 percent of DJ Basin volumes (46 percent crude oil and condensate and 20 percent NGLs) and 34 percent was natural gas. Combined volumes for Wells Ranch and East Pony averaged 57 MBoe/d during the quarter, up 23 percent compared to the second quarter of 2015. Volumes in the second quarter were impacted by a planned turn-around at the Wells Ranch central processing facility as well as unplanned third-party processing facility downtime.

    Highlights include:
     
  • ​Average well costs for normalized long laterals with enhanced completions were reduced to $2.6 million in Wells Ranch.
  • Drilled 26 wells at an average lateral length of over 8,100 feet, with all of the wells drilled in the second quarter located in Wells Ranch (88 percent) and East Pony (12 percent). Nearly all of the wells drilled used the monobore technique. Delivered average spud to rig release drilling days of five, seven and eight for standard (4,500 feet), medium (6,000 feet) and long (9,000 feet) length lateral wells, respectively.
  • Commenced production on 25 wells, with an average lateral length of 8,270 feet. Approximately half of the wells that commenced production in the quarter were brought on line in May, with the remainder in June. More than two-thirds of the wells put into production in the quarter utilized slickwater fluid with proppant concentrations of 1,000 pounds or more per lateral foot.
  • Ten wells brought online in the quarter within the Company's Mustang IDP, seven of which utilized enhanced completions, have significantly outperformed expectations. These are the Company's first enhanced completions within the DJ Basin outside of the Wells Ranch and East Pony areas.
  • Added approximately 11,700 net acres in Wells Ranch, a 20 percent increase, in exchange for approximately 13,500 net acres primarily out of the Company's Bronco area. The improved contiguous acreage position in Wells Ranch enhances the IDP's value by increasing long lateral locations and optimizing the use of existing infrastructure.
  • Completed the initial close for the Greeley Crescent acreage sale, receiving $486 million proceeds within the second quarter. The Company expects to receive the remaining $19 million in a final closing around the end of the year.
  • The Company exited the quarter with 36 wells drilled but uncompleted.

    Marcellus Shale

    Sales volumes in the Marcellus Shale averaged 546 million cubic feet of natural gas equivalent per day (MMcfe/d) in the second quarter of 2016, an increase of 28 percent over the same quarter of last year and down approximately 5 percent versus the first quarter of 2016. Natural gas represented 91 percent of the volumes sold, with the majority of the remainder composed of NGLs.

    Highlights include:

     
  • Commenced production on 16 non-operated wells within the Joint Venture.
  • Solid well performance continues at the operated Rich Hill 23 pad in Greene County, Pennsylvania. The combined production of the eight wells was approximately 95 MMcf/d, essentially flat after six months of production.
  • The non-operated Green Hill 53 pad, also located in Greene County, Pennsylvania, has averaged 80 MMcf/d over the first 60 days of production from nine wells.
  • Exited the quarter with 79 wells drilled but uncompleted in the Joint Venture.
  • CONE Midstream Partners gathered gross volumes averaging approximately 1.2 billion cubic feet per day during the quarter, an increase of nearly 32 percent from the same quarter in the previous year.
     
  • Rice Increases E&P Budget.  Canonsburg-based Rice Energy Inc. (NYSE: RICE) said Wednesday that it will be adding to the pace of its drilling the Utica Shale in Ohio.

    Joining other natural gas companies that have increased plans for drilling as the market has improved, Rice said it would boost its capital budget from the previously forecast $640 million to $660 million. That includes a $65 million increase in its drilling plans for its Utica Shale holdings.

    Rice said it has been able to wring out more efficiencies from its Marcellus drilling program, which has led to a reduction of $55 million to $230 million for 2016. That's even with increasing the number of Marcellus Shale wells, Rice said in a statement Wednesday.

    It also plans to spend $100 million on land acquisition, up $20 million from previously planned.

    Rice expects 62 wells started in 2016 and 60 online, including 34 in the Marcellus and 26 in the Utica in a split between operated and nonoperated wells.

    CEO Daniel J. Rice IV said in a statement that it had record low development and high production.

    "These accomplishments are a testament to our team's ability to capitalize on assets that generate strong returns in this challenging commodity environment," Rice said. "With our steady development of highly economic and productive core Marcellus and Utica wells, we are uniquely positioned with a strong balance sheet and differentiated midstream asset portfolio to continue generating best-in-class growth and returns for our shareholders."

    This goes from Rice to Eclipse???

     
  • Eclipse 2nd Qtr. Update.  After reviving its idled drilling program, increasing this year's capital expenditures and starting work again on its drilled but uncompleted (DUC) wells during the second quarter, Ohio pure-play Eclipse Resources Corp. said its recovery could gain significant speed by mid-year 2017.

    The company is currently running one rig on its dry gas Utica Shale acreage and working down its 20-well DUC inventory in the condensate window. After increasing its full-year guidance in June to 205-210 MMcfe/d, Eclipse again raised its exit rate on Wednesday to 225-230 MMcfe/d (see Shale Daily, June 29). Even with a one-rig program, the company is targeting year/year 2017 production growth of 30%. But if gas prices continue to move higher, and the company has adequate liquidity, management said it could add another rig by mid-2017.

    "We would very much like to be going to two rigs next year, however, I think there's two triggers for that to happen," said CEO Benjamin Hulburt. "One is the financing of that rig so that we don't have to draw our revolver or the balance sheet. It would require either a noncore acreage sale or some other type of joint venture. At this point, we aren't looking at the traditional joint venture-type capital. We're really more focused on the noncore acreage sale."

    Adding a second rig next year, Hulburt said, would also depend on stronger forward gas prices in 2017 and 2018, as well as the company's ability to hedge.

    While Hulburt said the company is open to a farm-in across some of its acreage, Eclipse is currently working to divest 8,000-10,000 noncore acres to boost its liquidity. It has 102,000 net acres in the Utica and another 13,000 net acres prospective for the Marcellus Shale. An equity offering during the second quarter raised $123 million. Those funds, combined with increased revenue from more production at higher prices, are expected to fully fund next year's drilling program.

    "Moving forward, we are continuing to design our drilling program to extend our lateral reach across all our units on our acreage position," Hulburt said. "As a result, our current expectation is that our average lateral in 2017 will be approximately 14,000 feet, which will focus predominantly in the dry gas portion of our Utica Shale acreage."

    Management has said it drilled the Purple Hayes to test the limits of its acreage, reduce drilling and completion costs per foot and improve well economics. The company expects to ultimately drill longer wells and has said the techniques employed on the Purple Hayes could translate to other wells.

    The company has plans for two similar "super laterals" next year in the condensate window if oil prices permit them. It also plans to test more Marcellus wells in the dry gas window this year. COO Thomas Liberatore said the company is testing some of what it learned from the Purple Hayes as it works down its DUCs, using higher proppant loads and tighter stage spacing.

     
  • Antero 2nd Qtr.  Colorado-based Antero Resources reported a second-quarter loss of $596 million, despite record production, Kallanish Energy finds.

    That compares to a quarterly loss of $145 million one year ago.

    The company, a major producer in the Marcellus and Utica Shale plays, set a production record of 1.762 billion cubic feet-equivalent per day (Bcfe/d). That is a 19% increase over 2015.

    That included record net daily liquids production of 75,041 barrels per day (BPD), a 63% increase over a year ago.

    Antero completed and placed online 31 Marcellus and Utica wells in the second quarter. The company has seven rigs and five completion crews working in the Marcellus and Utica.

    The company remains extremely interested in developing the liquids-rich areas in the Appalachian Basin, despite slightly higher costs than dry-gas areas, said Chief Financial Officer Glen Warren Jr. in a Wednesday earnings call with analysts and the media.

    The company is heavily hedged heading into late 2016 and early 2017, said CEO Paul Rady.

    Antero has been working on reducing costs and improving efficiencies during the 18-month industry downturn, including low commodity prices, he said.

    Costs have been reduced by 34% in the Marcellus and 33% in the Utica, Rady said. Wells are being drilled in 15 days in the Marcellus and 16 days in the Utica, he added.

    Antero intends to begin adding more sand, as much as 1,750 to 2,000 pounds per foot, and more water, as much as 40 to 45 barrels per foot, to the fracking process in a pilot project to boost production, Rady said.

     
  • Chesapeake 2nd Qtr. Update.  ”Lower” was the operative word for independent producer Chesapeake Energy during the second quarter.

    As in lower year-over-year crude oil and natural gas production, lower rig count, lower expenses, lower commodity prices and, consequently, lower revenue but, on the positive side, a lower quarterly net loss.

    For the three months ended June 30, the Oklahoma City, Oklahoma-based company reported oil-equivalent production of 60 million barrels of oil-equivalent (MMBOE), down from 64 MMBOE in the year-ago quarter.

    Oil production fell to 8 million barrels (MMBbls), from 11 MMBbls for the quarter ended June 30. The average realized oil price plunged to $44.31 a barrel (Bbl), from $71.39/Bbl.

    Natural gas production dropped to 269 billion cubic feet (Bcf), from 275 Bcf, at a realized price of $1.97 per thousand cubic feet (Mcf) this second quarter, from $2.35/Mcf one year ago.

    Natural gas liquids production was flat, at 7 MMBbls, Kallanish Energy learns. The average realized price was $12.88/Bbl in the recently concluded quarter, vs. $13.02/Bbl one year ago.

    “As a result of our portfolio’s strong performance to date in 2016, we have increased our total production guidance for the remainder of the year,” said Doug Lawler, Chesapeake’s CEO. “As for an initial look into 2017, we believe our oil production will be relatively flat in 2017 as compared to 2016, while total production volumes are projected to be down approximately 5% compared to 2016 levels.”

    The number of rigs operated by Chesapeake year-over-year plunged by almost two-thirds, to nine from 26, while gross wells spud dropped to 49 from 109, and gross wells connected fell to 141 from 173 one year ago. Well completions actually rose, to 131 from 121.

    Totally quarterly capital expenditures dropped to $456 million, from $957 million.

    Chesapeake from second-quarter 2015, to second-quarter 1016, reduced debt by a whopping $3 billion, to $8.7 billion.

    The company reported a quarterly net loss of $2.76 billion, a huge improvement from the $7.93 billion loss one year ago.

    The primary cause of the most recent loss was a $1.05 billion noncash drop in the carrying value of Chesapeake’s oil and gas assets due to the low prices for oil and natural gas. The company also reported an unrealized hedging loss of $544 million.

    Revenue dipped to $3.58 billion from $6.74 billion in the year-ago quarter.

     
  • Sunoco 2nd Qtr. Update.  Pipeline/Terminaling company Sunoco Logistics (SXL) reported second-quarter across-the-board increases in throughput of crude oil, natural gas liquids and refined products, Kallanish Energy reports.

    Throughput wasn’t able to put revenue and profit higher than the year-earlier quarter’s results, as both dipped at the Newtown Square, Pennsylvania-based company.

    Crude oil pipeline throughout totaled 2.33 million barrels per day (MMBPD), from 2.17 MMBPD in the year-earlier quarter, while crude throughput at SXL’s terminals rose to 1.50 MMBPD, from 1.32 MMBPD one year ago.

    Refined products flowed through SXL’s lines during the recent second quarter totaled 524,000 BPD, up from 465,000 BPD, while terminal throughput of refined products rose to 559,000 BPD, from 508,000 BPD.

    NGL pipeline throughput rose to 245,000 BPD, from 217,000 BPD, while NGL terminal throughput climbed to 214,000 BPD, from 193,000 BPD.

    SXL’s second-quarter profit totaled $202 million, down 26.8% from $276 million one year ago. Revenue dropped 29.1%, to $2.27 billion, from $3.20 billion.

     
  • Gulfport Increases E&P.  Oklahoma-based Gulfport Energy intends to boost its drilling in Ohio’s Utica Shale, Kallanish Energy learns.

    With the natural gas price strip above $3, the company feels confident it can support a six-rig drilling program in 2017, CEO Michael Moore told analysts and the media during a Thursday earnings call.

    That would require capital spending of $675 million to $725 million on drilling and completions and could boost production by 20 to 25%, Moore said.

    If natural gas prices continue to increase, Gulfport could be looking at an eight-rig drilling operation in the Utica Shale, he added.

    Gulfport currently has three rigs operating in that region; a fourth rig is scheduled to begin operations in September.

    The company also intends to boost Utica completion activities in late 2016 and has updated its budget to drill 17 to 18 net wells and to begin production at an additional 10 to 11 net wells, Moore said.

    The company reported a second quarter loss of $339.8 million, compared to a second quarter 2015 loss of $31.3 million.

    Net production in the quarter averaged 664.7 million cubic feet-equivalent per day (MMcfe/d), up 40% from a year ago.

    In late 2015 and early 2016, Gulfport had voluntarily curtailed its Utica Shale drilling by about 15% because of low commodity prices. It drilled 12 Utica wells in the second quarter and began production on seven Utica wells.

     
  • Carrizo 2nd Qtr. Update. Carrizo Oil & Gas reported second-quarter production grew by 15% from a year earlier due to strong production in the Eagle Ford Shale in Texas.

    That production reached 41,533 barrels of oil-equivalent per day (BOE/d), Kallanish Energy reports.

    Oil production in the quarter rose 7%, the Houston, Texas-based company said, to 23,942 barrels per day (BPD).

    The company also said it intends to drill more by eliminating planned drilling and completion holidays in the fourth quarter. That will not significantly impact production totals but will better position the firm for 2017 growth, officials said.

    The company drilled 19 gross-operated wells in the second quarter and completed 19 gross wells in the Eagle Ford Shale. It has an additional 33 wells awaiting completion.

    For 2016, the company intends to drill 67 gross wells and complete 73 gross-operated wells in the Eagle Ford.

    The company had also voluntarily curtailed its Marcellus Shale drilling in Pennsylvania and Utica Shale drilling in Ohio. No wells were drilled in the second quarter.

    The company is keeping a close eye on prices, especially in the Marcellus, officials said. If prices rise, Marcellus activity is likely.

    The company did no drilling in the Niobrara Shale in Colorado and nearby states and is continuing to test its Delaware Basin holdings in West Texas.

    Carrizo reported a second quarter loss from continuing operations of $262.1 million, compared to a $47 million loss in the second quarter of 2015.

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Rig Count 

  • Baker Hughes Rig Count the week of August 5, 2016
     
  • PA     
    • Marcellus 15 unchanged
  • Ohio 
    • Utica 13 unchanged
  • WV 
    • Marcellus 7 down 1
  • TX
    • Eagle Ford 37 up 4
  • TX & NM
    • Permian Basin – 177 up 5
  • ND
    • Williston – 28 up 1
  • CO
    • Niobrara – 18 down 1
       
  • TOTAL U.S. Land Rig Count 443 up 3

PA Permits for July 28, to August 4, 2016

       County            Township                E&P Companies

1.    Clinton              Gallagher                Range
2.    Sullivan            Shrewsbury             Exco
3.    Tioga                Richmond               Shell

OH Permits for weeks ending July 30, 2016

        County              Township            E&P Companies

1.    Jefferson             Smithfield            Ascent Resources
2.    Jefferson             Warren                Gulfport
3.    Jefferson             Warren                Gulfport
4.    Jefferson             Warren                Gulfport
5.    Monroe                Salem                 Eclipse Resources

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

Northeast Supply Enhancement