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NewsLetters

Expo/Industry events for the next few months

Utica Midstream
June 8, 2016
Pro Football Hall of Fame
Canton, OH

http://www.uticasummit.com/

DUG East
June 21 – 23, 2016
David L. Lawrence Convention Center
Pittsburgh, PA

http://www.dugeast.com/

Latest facts and a rumor from the Marcellus and Utica Shale

  • PA DEP Quigley Maybe Is on His Way Out.  John Quigley may be on his way out as PA Secretary of DEP.  When the story comes out about his behavior regarding his actions as the result of the PA state legislative committees voting down DEP’s new regulations, you will be appalled.  It’s hard to believe that a government official can so biased, but in this day and age, it may be the norm.

    Governor Wolf has to remove Quigley from office.  (RUMOR)
     
  • Gulfport 1st Qtr. Update.  Gulfport Energy’s Utica Shale production was strong in the first quarter but the company lost $242.3 million.

    Gulfport has drilled 244 Utica wells in Ohio. It has the second most wells after Chesapeake Energy.

    The Oklahoma City-based company had revenue of $157 million during the quarter, but losses dragged its balance sheet into the red. Gulfport’s largest loss, $219.0 million, was from a drop in the future value of production from its oil and natural gas properties.

    Gulfport’s first quarter production averaged 692.2 million cubic feet equivalent per day, 1 percent above the company’s highest estimate. However, oil and natural gas prices were about half what they were a year ago.

    The company spent $74.5 million drilling and fracking wells and another $19.7 million on leases.

    Most of Gulfport’s production was in the Utica, where the company drilled 10 wells and began production from 15 wells during the quarter.

    The company has three rigs in the Utica and plans to drill up to 24 Utica wells and begin production from as many as 39 wells this year.

    Gulfport estimated second quarter production would be between from 664 million and 692 million cubic feet equivalent per day.
     
  • Fractured Wells Account for 66% of U.S. Production.  Natural gas production from hydraulically fractured wells now comprises roughly 66% of total U.S. marketed gas production, according to the Energy Information Administration.

    This share of production is even greater than the share of crude oil produced using so-called fracking, which accounts for about half of current U.S. crude oil production.
     
  • Eclipse 1st Qtr. Update.  Eclipse Resources Corporation (NYSE:ECR) (the “Company” or “Eclipse Resources”) today announced its first quarter 2016 financial and operational results, second quarter and full year 2016 guidance, and provided an update on its extended reach lateral well.

    First Quarter 2016 Highlights:
     
    • Revenues were $49.6 million. Adjusted Revenue1, which includes the impact of cash settled derivatives, grew to $58.9 million, representing a 12% increase relative to the first quarter of 2015
    • Adjusted EBITDAX1 was $25.3 million, representing a 22% increase relative to the first quarter of 2015
    • During the quarter, the Company drilled its “Purple Hayes” well with a lateral extension of over 18,500 feet in under 18 days. Subsequent to quarter end, the Company completed the well with 124 frac stages, averaging 5.3 stages per day, finishing with a total estimated D&C cost of approximately $854 per lateral foot. The Company believes this is the longest, horizontal, onshore lateral ever drilled in the United States.
    • The Company maintained its voluntary production curtailment program during the quarter, averaging 201.1 MMcfe per day, which was in line with the Company’s targeted rate for the quarter, representing a 26% increase relative to the first quarter of 2015. The production mix was approximately 75% natural gas, 17% NGL’s and 8% oil
       
  • ETE Can’t Close the Williams Deal.  Energy Transfer Equity CEO Kelcy Warren’s deal to acquire rival Williams Cos is not looking good.

    Speaking on the company’s earnings call, Warren said tax issues would sink the $21 billion deal. It has been in doubt for months, with Williams alleging Energy Transfer (ETE) has been trying to break the deal as ETE has unveiled numerous issues with the merger.

    “We can’t close this deal,” Warren said last week on his company’s earnings call. “Absent a substantial restructuring of this transaction, which Energy Transfer has been very willing and actually desiring to do, absent that, we don’t have a deal.”

    Warren said Energy Transfer would be open to a deal that would remove the $6 billion cash portion of its cash-and-stock offer for Williams, Kallanish Energy understands.

    Williams declined to answer questions about the merger on its own earnings conference call last week, but said its board is still unanimously committed to enforcing its rights under the merger agreement.

    The stand-off, preceded by a lawsuit and a countersuit both alleging breaches of the agreement, underscore how bad relations have gotten between the two sides.

    Energy Transfer originally raised the tax issues last month. ETE’s lawyers at Latham & Watkins have told the company it may not be able to deliver a needed tax opinion declaring the deal would be a tax-free exchange. It has already rejected two possible solutions to the tax issue proposed by Williams.

    ETE has made clear the deal is no longer attractive. It has slashed its estimates for expected cost savings and said it would likely have to cut its distributions to shareholders entirely in 2017 if it has to complete the deal. It has also said it will have to cut jobs in Williams’ home state of Oklahoma.

    Williams is determined to push ahead, attracted by the same $6 billion cash component Energy Transfer argues is weighing down the deal.

    “I’ve never heard of an example like this — of this degree of buyer’s remorse,” Sydney Finkelstein, a professor at the Tuck School of Business at Dartmouth College, told Reuters.

    “It was a bad deal from the beginning and they’ve realized it afterward, and now they’re going about the process of trying to get out of the deal in a way that destroys the credibility of their own management,” he said.

    We saw this one coming.
     
  • Atlantic Sunrise Gets FERC Approval.  Pipeline giant Williams last week won preliminary approval from the Federal Energy Regulatory Commission (FERC) for its $3 billion Atlantic Sunrise Pipeline project.

    At almost the same time, environmentalists went to Federal Court objecting to the project, Kallanish Energy understands.

    “The FERC staff concludes approval of the project would result in some adverse environmental impacts; however, most of these impacts would be reduced to less-than-significant levels with the implementation of [Williams’ unit] Transco’s proposed mitigation and the additional measures recommended in the draft EIS [Environmental Impact Statement], FERC said.

    The Atlantic Sunrise is an add-on to the Transco system, which includes more than 10,000 miles of pipe moving 10% of the nation’s natural gas.

    The Atlantic Sunrise project includes construction of 198 miles of new pipeline, most of which would be in Pennsylvania, designed to move Marcellus Shale gas from Northeast Pennsylvania as far south as Alabama. Design capacity is 1.7 billion cubic feet per day.

    “Since this proposal was first introduced in 2014, we have changed more than half of the original project route as direct result of feedback from landowners and other stakeholders,” Williams said. “Even at this stage of the project, we continue to work to identify opportunities to even further reduce environmental impacts.”

    Environmental group Delaware Riverkeeper Network has challenged the project’s mandated state water quality permits in federal court, filing a lawsuit last week in the Third Circuit Court of Appeals, calling the Pennsylvania Department of Environmental Protection’s issuance of water quality certificates for Atlantic Sunrise a violation of the federal Clean Water Act.

    Delaware Riverkeeper’s Maya van Rossum said the project will impact more than 4,100 acres of land, and the proposed pipeline would cross 333 waterbodies and 250 wetlands.

    “The Pennsylvania Department of Environmental Protection [PADEP] is failing to fulfill its obligations to determine whether pipelines like the Atlantic Sunrise pipeline will harm our environment prior to deciding whether to give them the certification – this is not only a violation of the clear meaning and intent of the Clean Water Act and the Pennsylvania Code, but it is a fundamental violation of PADEP’s obligation to protect our environment and communities,” van Rossum said.

    The National Environmental Policy Act (NEPA) mandates FERC complete the EIS. The 60-day public comment period closes on June 27, and FERC says it will issue the final EIS in October.
     
  • Rex to Keep Active in OH.  Bolstered by a joint-venture agreement, Rex Energy continues to drill Utica Shale wells in Carroll County.

    Officials with the Pennsylvania-based company discussed its first-quarter earnings during a conference call with investors Wednesday.

    Rex Energy lost $62.2 million or $1.11 per share during the quarter. Revenue from operations was down 44 percent, and commodity revenue dropped by a third from the same quarter a year ago.

    Production from Rex wells was equal to 200 million cubic feet of natural gas a day, up 7 percent from the fourth quarter. Oil, condensate and natural-gas liquids, including ethane, accounted for 38 percent of production. The company plans to choke back some wells this summer while commodity prices are low, but still projects production growth of 5 to 10 percent this year.

    Rex spent $30.6 million during the quarter, nearly all of it on projects in the Utica and Marcellus shales. That spending was offset by $31.8 million in reimbursements through a joint venture with Benefit Street Partners, an affiliate of Providence Equity Partners.

    Benefit Street Partners has participated in six Carroll County wells and has agreed to join in two more, Rex President and CEO Thomas Stabley said.

    Rex drilled two wells, fracked a well and placed four wells in production in Carroll County during the quarter. The company had five wells drilled and waiting to be fracked at the end of March.

    The three-well Kiko pad in Washington Township went into production during the first quarter. The wells averaged five-day sales rates equal to 1,300 barrels of oil per day. The production included 2.3 million cubic feet of natural gas per day, 502 barrels of natural-gas liquids per day and 369 barrels of condensate per day, assuming full ethane recovery.

    The Kiko wells averaged 4,900 in lateral length and were fracked in 33 stages.

    Rex is finishing its three-well Goebeler pad in Harrison Township and expects to begin production this quarter. The Goebeler wells have average lateral lengths of 7,360 feet. The company said it would begin fracking its two-well Perry pad, also in Harrison Township, when the Goebeler project is finished. After the Perry pad is completed in June, Rex will have to drill one more pad to hold most of its Carroll County acreage, Stabley said.

    Rex has drilled 37 Utica wells in Ohio since 2012. The company is headquartered in State College, Pa.
     
  • Training for Roustabouts.   Penn College of Technology will be offering programs for previous roustabouts.  

    This 15 day course is for individuals who are looking to upgrade their skills and earn portable certifications.  Classes included in the training are:  PEC SafeLand USA, Natural Gas 101, Well Pad Construction, Part Identification & Tool Usage, Basic Rigging, Rig Simulator Training, Pressures & Forces, Natural Gas & Liquids Production, Spill Prevention & Reporting, Confined Space Awareness, Pipe Threading & Cutting, HDPE Pipe Fusing, Fall Protection, Medic First Aid/CPR & AED, NSC DDC-4 Defensive Driving.   Prepare for a career in Energy, Manufacturing, Construction, or Warehouse/Logistics.  
     
  • Shell Current Projects Leading to the Cracker.  Shell Chemical LP continues with preliminary work that could lead to a massive petrochemicals complex in the Pittsburgh area — but the firm still has not fully committed to the project.

    A Shell spokeswoman recently confirmed that the company has built a heavy-haul bridge across State Route 18 in Monaca, Pa., that would allow trucks to reach the proposed site. She also confirmed that Shell will spend up to $69 million to move a water intake site from the Monaca location and build a new water treatment site for Center Township.

    The agreement between Shell and the Center Township Water Authority was “mutually beneficial,” the spokeswoman said.

    “A decision is still yet to be made regarding the future of the proposed project; however Shell’s preliminary site work continues,” she wrote in an email. “The next step involves pre-construction activities to build a roll-on, roll-off dock facility near where the CTWA water supply source is currently located.”

    The spokeswoman added that pre-construction activities related to the dock “are critical to the potential construction phase if Shell decides to build the facility, since it will be used to deliver major pieces of equipment.”

    The plan calls for relocating CTWA’s facilities, including a new surface water intake and new surface water treatment plant. Shell will pay up to $69 million of the projected $72 million cost of the move.

    Houston-based Shell first proposed the petrochemicals project in early 2012, citing access to natural gas feedstock in the surrounding Marcellus Shale region and proximity to a large segment of the U.S. population. Products made by the proposed complex would include ethylene feedstock and polyethylene resin.

    Shell officials previously have said the project could create several hundred full-time jobs, along with as many as 10,000 temporary construction jobs and numerous related jobs throughout the area.

    Most shale-based PE/ethylene projects have been aimed at the U.S. Gulf Coast, where three major expansions will open next year. Several projects proposed for the Appalachian region — including Pennsylvania — appear to have stalled.

    Pennsylvania state officials already have approved Shell’s Act 2 Plan, which allows the firm to improve the environmental footprint of the site.

    “In recent months, much of our visible ongoing work — including the movement of large volumes of dirt from one side of Route 18 to the other — directly relates to major elements of our Act 2 Plan,” the spokeswoman said.

    “Contractors are creating a flat, homogenous site for potential construction,” she added. “This and other preliminary site development work is necessary and will position Shell well if we decide to move forward with the project.”

    Shell also has posted a job opening on the LinkedIn web site for a position described as technical service team lead polyethylene for Pittsburgh.

    “Posting positions prior to making a final decision to proceed with a proposed project is routine,” the spokeswoman said. “It's no guarantee of future employment; however we aim to redeploy individuals within Shell to the extent we are able.”
     
  • Could We See a Rigless Recovery? (Thank you, OILPRO’s Bill Allen)  EOG Resources is turning something old into something new again.

    The shale company, which is also known as the "Apple of E&P" for its innovation, has made a bit of history by applying Enhanced Oil Recovery (EOR) to a US horizontal shale reservoir. Last week, EOG spoke extensively for the first time about a gas injection pilot program it has been quietly running in the Eagle Ford for three years.

    During the shale boom, EOR has been pushed to the backburner, generally thought of as a conventional method for old fields. During the boom, EOR was not as sexy as growing lateral lengths, stage counts, and frac intensity. In tight oil plays, EOR has only been applied sparingly and experimentally.

    But EOR is less capital intensive than primary drilling and application makes sense at this point in the cycle as tight oil portfolios start to mature. EOG is the first US independent to talk about large scale EOR for US unconventional oil development. After reviewing their early results, they certainly won't be the last to talk about it.

    With four pilot projects spanning 15 wells under its belt, EOG believes it can lift type curves in the Eagle Ford 30-70% beginning 2 to 5 years into the well lifecycle.

    EOG has one more pilot project planned for 2016 - a field scale pilot with 32 wells - and the company is evaluating capital allocation to the strategy, which carries attractive economics.

    Does EOG's EOR Innovation Portend A Rigless Recovery?

    EOG's detractors will be quick to ask whether EOG still deserves its "Apple of E&P" nickname if its best idea at this point in the cycle is applying a 50-year-old technique to shale production. But we believe the results are compelling to the point where they could be game changing. Maybe it was just a matter of time until EOR was applied to shale wells, but the same could be said for fracing, which has been around for over 60 years. Only recently has fracing's true power been unleashed, and now we'll see if EOR goes the same way as fracing. If anyone can prove the methodology and scale it up in the Eagle Ford, it will be EOG.

    In the US shale plays, an extensive inventory of DUCs and refrac opportunities already suggest a drilling could be late when oil prices recover. Now EOG's "old, new" concept of EOR for shale could add more barrels without rigs. The combination of these factors leaves us wondering if we could see a rigless recovery in US tight oil plays over the next few years. In other words, could a scenario emerge where oil prices return to $60-$65 and US oil production rises yet very few drilling rigs go back to work?

    Further, EOG's new EOR approach gives us reason to believe the base decline of US tight oil production could disappoint. If EOG is able to scale this up, the steep decline of its Eagle Ford wells will start to level out.

    EOG CEO Bill Thomas seems to think the sum of EOG's innovations and efficiency gains will equal a rigless recovery. Last week, he said something that should give drillers pause: "We do not need 50 rigs drilling thousands of wells per year. It will take far less capital to grow production at strong double-digit rates."

    Admittedly, EOG touts its unique attributes and Eagle Ford reservoir characteristics as enablers of the EOR approach and as reasons that the company's EOR success in shale should not be extrapolated industrywide. But one thing is certain: other operators pay attention to EOG. And other operators will try to repeat EOG's success, with some pulling it off.

    The more EOR spreads in horizontal oil basins, the less E&Ps will need drillers and service contractors to increase oil production. EOR is far less contractor intensive than new well construction. The process makes use of produced gas readily available to the field, and there are few other incremental operating costs.

    It's early days, but we view this as a critical initiative that everyone who cares about oil prices and oilfield activity should be monitoring over the next few years.

    EOG Has Completed The 1st Economic Enhanced Oil Recovery Test In US Horizontal Shale Reservoir

    Here are a few key takeaways on the Eagle Ford EOR project (from EOG's conference call on May 6):

    The EOR technique is not capital intensive. There is no incremental drilling required, so capital costs average approximately $1 million per well (the process makes use of produced gas readily available in the field).

    Unlike typical secondary recovery projects, the production response occurs quickly, within the first two to three months, and holds steady for longer.

    The combination of lower operating costs and steady production delivers a return profile that complements EOG's primary drilling program. Primary drilling delivers high returns and short paybacks. The EOR pilots have a much different profile, characterized by modest upfront capital investment that delivers a long annuity of incremental oil production and strong cash flow. The rate of return is still on par with primary drilling. But for each dollar invested, EOR delivers at least twice the net present value created as primary drilling.

    EOG's models suggest the process will increase recovery by 30% to 70%. These are incremental potential reserves, not accelerated production, delivered at potential finding costs of $6.00 per barrel or below or less.

    Rolling out the effort will take EOG some time and is dependent on the pace of primary development drilling and field development. The results of a 5th pilot (which is essentially a field scale model) to be conducted this year will be key to determining how much capital is allocated to EOR in 2017. So far, all 32 of the wells tested in their 4 pilots to date have been successful.

    The project started with some laboratory experiments to understand what the fluid behaviors would be, and the lab work was encouraging. Then EOG rolled it out to a single-well pilot and had positive results from that. And then they started applying it to more multi-well pilots. The next step is the field scale model mentioned above, which is the fifth pilot encompassing 32 wells.

    At this point, EOG is not giving away many details around the process itself or how they are implementing it. They did say that it is a miscible process. EOG is using gas readily available in the field and using its large footprint to move gas around and get it to the leases to conduct the EOR process.

    CEO Bill Thomas warned in no uncertain terms against extrapolating the pilot's success across all shale basins and operators, saying it will not be a blanket application across shale or even the Eagle Ford for that matter. "Geology matters. The Eagle Ford is unique. The same geologic characteristics that make the Eagle Ford prolific in primary development also make it unique for enhanced oil recovery. The EOR process we are using to produce incremental oil out of the Eagle Ford is not necessarily applicable to other horizontal basins. Number two, how you initially drill the field matters. Secondary recovery works best on leased units that were developed using the best completions with optimal spacing. Finally, returns matter. We figured out how to execute EOR economically." EOR economics are enhanced by scale of EOG's footprint in the play, and its leading infrastructure key to execution.

    EOG's Experiment Has Been Running Quietly For Some Time Now

    The current EOR experiment EOG is running in the Eagle Ford began about three years ago. Several times in the past, EOG has rather quietly mentioned the concept of applying Enhanced EOR in horizontal shale wells.

    Morgan Stanley analyst Evan Calio observed in a recent note to clients that the company has been looking at this idea since as early as 2012. Calio wrote:

    Previously, management (Papa) referenced gas injection during a May 30, 2012 presentation at a conference: "And so in the Eagle Ford, we're looking at something that has also been used for 50 years but at a much lower frequency of use. And that's a simply dry gas injection, where you put dry gas in a reservoir and then you push it through the reservoir. And it picks up heavy ends. And then on that – one way to look at it is, you inject it, it costs $2.50 an Mcf because it's dry gas. And by the time it passes through the reservoir, it picks up a whole lot of heavy ends. And you pull it out of reservoir, and it's worth about $15 an Mcf by the time you get all the liquids out of it. So it'll be interesting to see whether that technology works or not."

    Enhanced Oil Recovery (EOR) is a time-tested method of optimizing production in conventional plays, but it's new to the Eagle Ford, and light tight oil plays in general for that matter.

    In the late-1970s and early-1980s, the easy oil in the US was being depleted. With massive conventional oil fields in West Texas producing less, operators began experimenting with EOR, also referred to as secondary or tertiary production. Courtesy of Schlumberger, here are the three levels of oil recovery (EOR is generally thought of as secondary and tertiary recovery).

    Primary production: The first stage of hydrocarbon production, in which natural reservoir energy, such as gasdrive, waterdrive or gravity drainage, displaces hydrocarbons from the reservoir, into the wellbore and up to surface. Initially, the reservoir pressure is considerably higher than the bottomhole pressure inside the wellbore. This high natural differential pressure drives hydrocarbons toward the well and up to surface. However, as the reservoir pressure declines because of production, so does the differential pressure. To reduce the bottomhole pressure or increase the differential pressure to increase hydrocarbon production, it is necessary to implement an artificial lift system, such as a rod pump, an electrical submersible pump or a gas-lift installation. Production using artificial lift is considered primary recovery. The primary recovery stage reaches its limit either when the reservoir pressure is so low that the production rates are not economical, or when the proportions of gas or water in the production stream are too high. During primary recovery, only a small percentage of the initial hydrocarbons in place are produced, typically around 10% for oil reservoirs. Primary recovery is also called primary production.

    Secondary Recovery: The second stage of hydrocarbon production during which an external fluid such as water or gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding. Normally, gas is injected into the gas cap and water is injected into the production zone to sweep oil from the reservoir. A pressure-maintenance program can begin during the primary recovery stage, but it is a form or enhanced recovery. The secondary recovery stage reaches its limit when the injected fluid (water or gas) is produced in considerable amounts from the production wells and the production is no longer economical. The successive use of primary recovery and secondary recovery in an oil reservoir produces about 15% to 40% of the original oil in place.

    Tertiary Recovery: Traditionally, the third stage of hydrocarbon production, comprising recovery methods that follow waterflooding or pressure maintenance. The principal tertiary recovery techniques used are thermal methods, gas injection and chemical flooding. The term is sometimes used as a synonym for enhanced oil recovery (EOR), but because EOR methods today may be applied at any stage of reservoir development, the term tertiary recovery is less commonly used than in the past.

    Tertiary oil recovery has enabled operators to extract 30%+ more oil from depleted reservoirs, but the process has some side effects. The associated natural gas recovered with oil requires enhanced separation capabilities when other gases like CO2 or nitrogen are used in the EOR flooding process. Separating the gases is key to commercialization and re-use in the reservoirs.
     
  • World Wide Consumption of NatGas Bullish Going Forward.  Worldwide natural gas consumption is projected to increase from 120 trillion cubic feet (Tcf) in 2012, to 203 Tcf in 2040 in the “International Energy Outlook 2016” reference case.

    Natural gas accounts for the largest increase in world primary energy consumption, Kallanish Energy understands.

    “Natural gas remains a key fuel in the electric power sector and in the industrial sector,” according to the outlook, released Wednesday by the Energy Information Administration.

    “In the power sector, natural gas is an attractive choice for new generating plants given its moderate capital cost and attractive pricing in many regions, as well as the relatively high fuel efficiency and moderate capital cost of gas-fired plants.”

    The outlook adds that as more governments begin implementing national or regional plans to reduce carbon dioxide (CO2) emissions, natural gas may displace consumption of the more carbon-intensive coal and liquid fuels.

    To meet the rising natural gas demand projected in the outlook’s reference case, the world’s natural gas producers increase supplies by nearly 69% from 2012 to 2040.

    The largest increases in natural gas production from 2012 to 2040 occur in non-OECD Asia (18.7 Tcf), the Middle East (16.6 Tcf), and the OECD Americas (15.5 Tcf).

    In China, production increases by 15 Tcf as the country expands development of its shale resources. The U.S. and Russia increase natural gas production by 11.3 Tcf and 10 Tcf, respectively.

    China, the U.S. and Russia account for nearly 44% of the overall increase in world production of natural gas between 2012 and 2040, according to the outlook.

    World liquefied natural gas (LNG) trade between 2012 and 2040 more than doubles, from 12 Tcf to 29 Tcf, according to the international outlook.

    Most of the increase in liquefaction capacity occurs in Australia and North America, where a number of new liquefaction projects are planned or under construction, many of which are expected to become operational within the next decade.
     
  • Obama Takes Final Shot at O&G Industry with Methane Regs.  The Obama administration issued a final rule Thursday to reduce methane emissions from U.S. oil and gas production by nearly 50% over the next decade, part of Obama’s efforts to curb climate change.

    Issued by the Environmental Protection Agency, the rule would slash methane emissions from drilling by 40-45% by 2025, compared to 2012 levels.

    It would require energy producers to find and repair leaks at oil and gas wells and capture gas that escapes from hydraulically fractured wells, Kallanish Energy reports.

    Methane, the key component of natural gas, comprises a small percentage of greenhouse gas emissions in the U.S., but is considered more powerful than carbon dioxide at trapping heat in the atmosphere, making it a target for environmentalists.

    Government officials estimate the rule would cost the industry about $530 million in 2025. Those costs would be outweighed by reduced health care costs and other benefits totaling about $690 million, officials project.

    EPA administrator Gina McCarthy said the new rule would “protect public health and reduce pollution linked to cancer and other serious health effects while allowing industry to continue to grow and provide a vital source of energy for Americans across the country.”

    The American Petroleum Institute, the largest lobbying group for the oil and gas industry, said the new rule could harm America’s “shale energy revolution” that has lowered U.S. carbon emissions and reduced costs for American consumers.

    “Even as oil and natural gas production has risen dramatically” in recent years, “methane emissions have fallen, thanks to industry leadership and investment in new technologies,” said Kyle Isakower, API vice president of Regulatory and Economic Policy.

    “It doesn’t make sense that the administration would add unreasonable and overly burdensome regulations when the industry is already leading the way in reducing emissions,” Isakower added.
     
  • Magnum Hunter Exits Bankruptcy.  Magnum Hunter Resources and certain of its subsidiaries said this week it’s exited Chapter 11 bankruptcy, fewer than five months after voluntarily filing for bankruptcy protection from creditors.

    In December, Magnum Hunter filed for Chapter 11, agreeing to a debt-to-equity swap, after receiving support from 75% of its creditors, Kallanish Energy reports.
    According to the terms of the deal, the ownership of the company was transferred to the lenders against more than $1.1 billion in listed debt in the bankruptcy filing.

    According to the Chapter 11 filing, the company listed assets of roughly $1.5 billion, coupled with $1.1 billion in debt.

    To emerge from bankruptcy, the company restructured its balance sheet, de-leveraging pre-bankruptcy debt of $1 billion. Magnum Hunter also converted its 100% post-filing debtor-in-possession (DIP) financing into equity, through the debt-to-equity swap.

    The company’s new board is now looking for a new chief executive to replace the departed Gary Evans (see story elsewhere in this issue).

    In the interim, Joseph C. Daches, current chief financial officer, and Rick S. Farrell, current senior vice president Business Development/Land, will serve as co-CEOs.
     
  • New Player Emerges in the Permian and Eagle Ford.  Gary Evans, who left his job Monday as CEO of independent producer Magnum Hunter Resources just as it emerged from bankruptcy, already has formed a new company, Kallanish Energy understands.

    Evans formed Energy Hunter Resources, and is close to buying two pieces of land in the oil-rich Permian Basin and Eagle Ford Shale play, Evans told Reuters.

    “All the veterans in the business know that this is a phenomenal time to get something new going, when everybody else is running for the hills,” Evans told Reuters.

    “I’m a big believer that oil prices this time next year will be $10 to $20 higher per barrel. So I’d like to drill some now and capture some of that upside,” he said.

    Evans said he was keying on the Eagle Ford and the Permian because he has worked there and their sweet spots still offer profit with oil around $44 a barrel.

    The former wildcatter is restricted for one year from buying working interests in the Marcellus and Utica Shale plays where Magnum Hunter operates.

    Evans told Reuters the first round of financing for Energy Hunter Resources will be a private placement with friends and family. He added he later may tap public capital markets, where he has raised roughly $6 billion during his career.
     
  • Bankruptcies This Week.  There were two bankruptcies this week – Linn Energy and Penn Virginia.

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

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

Rig Count

  • Baker Hughes Rig Count the week of May 13, 2016
     
  • PA
    • Marcellus 16 unchanged
  • Ohio
    • Utica 10 unchanged
  • WV
    • Marcellus 10 unchanged
  • TX
    • Eagle Ford – 33 down 1
  • TX & NM
    • Permian Basin – 134 down 5
  • ND
    • Williston – 24 down 1
  • CO
    • Niobrara – 15 unchanged
       
  • TOTAL U.S. Land Rig Count 382 down 6

PA Permits for May 5, to May 12, 2016

       County              Township     E&P Companies

1.    Potter                Sweden        JKLM
2.    Potter                Sweden        JKLM
3.    Potter                Sweden        JKLM
4.    Potter                Sweden        JKLM
5.    Westmoreland    Salem          Apex

OH Permits for weeks ending May 7, 2016

       County        Township       E&P Companies

1.    Monroe        Salem            Statoil
2.    Monroe        Salem            Statoil
3.    Monroe        Switzerland     XTO

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

DUG Technology