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Expo/Industry events for the next few months

Marcellus-Utica Midstream
January 30 – February 1, 2018
David L. Lawrence Convention Center
Pittsburgh, PA 
Emerging Opportunities Ohio River Valley Conference
February 22, 2018
Oglebay Resort
Wheeling, WV 
Utica Midstream
April 4, 2018
Walsh University
North Canton, OH 
For other events visit

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

WV Secretary of Commerce Gives China Energy Update.  State Commerce Secretary Woody Thrasher says dirt could be flying this year in connection with an $83.7 billion deal with the Chinese to help develop West Virginia’s petrochemical industry.
“Like anything of that magnitude, you have to do everything one step at a time,” Thrasher told members of the Senate and House of Delegates’ Joint Committees on Natural Gas Development and Energy.
Thrasher gave an update on the China deal during legislative interim meetings Tuesday in Charleston.
“In the three visits we’ve had (to China), there’s been a great sense of urgency (on the part of the Chinese),” Thrasher told Del. Jill Upson, R-Jefferson, after Upson asked what activity the state might see in the next 12 to 24 months.
Thrasher said he was making another trip to China on Saturday “to try to get an early project moving forward.”
In November, Thrasher signed an $83.7 billion memorandum of understanding with a Chinese energy company that wants to take advantage of West Virginia’s vast supplies of Marcellus and Utica shale gas. Under the 20-year development deal, the Chinese would invest in infrastructure and plants to convert the byproducts of natural gas production for the production of petrochemicals.
Tied with a recent announcement by the federal Department of Energy to sign off on a $1.9 billion loan to the South Charleston-based Appalcahia Development Group to further development of an Appalachian storage hub for gas liquids, “there is a significant opportunity before us,” Thrasher said.
Thrasher told Del. Mark Zatezalo, R-Hancock, that the Legislature might have a role in improving the Mountain State’s regulatory and business climate to make the state more attractive to the Chinese and others who might want to invest in petrochemicals and spinoff industries.
“We’re not the only ones who have (natural gas),” Thrasher said. “That raw material could come from Pennsylvania. It could come from Ohio.”
Thrasher said the development deal is also good for the Chinese.
“It makes sense from a business model,” he said. “Gases are not available in China.”
Sen. Randy Smith, R-Tucker, asked if the Chinese had any plans to build any more coal-fired power plants in West Virginia, citing the recent construction of new coal-fired power plants in Japan as an example.
Thrasher said coal liquefication projects and other coal-to-chemical projects have been discussed as part of the China deal, but he did not say whether any power plants were contemplated.
The memorandum of understanding signed with West Virginia is part of a $250 million trade deal with the Chinese negotiated by the Trump administration in a move many have seen as an attempt to help balance trade relations between the two countries.
But, unlike the exploitation of West Virginia’s coal reserves over the past 150 years, the projects proposed under the China deal are intended to provide local infrastructure and create a local petrochemical industry.
“It is not a transfer of the resource,” Thrasher said, but “bricks and mortar” facilities to turn gas liquids into chemicals and other products.
He said projects that come out of the China memorandum of understanding will employ West Virginians, help the state’s economy and pay state taxes.
Del. John Shott, R-Mercer, asked if other parts of the state might see jobs or development come out of the China deal. Thrasher said most of the jobs and development would be in and around the areas of the state that produce gas, but hoped there would be some business opportunities all over the state.
“A rising tide raises all ships,” he said.
EIA Projects Bullish Outlook for Oil Projects.  Brent crude oil averaged $54/barrel in 2017, an increase of $10/Bbl from 2016 levels, the Energy Information Administration’s Short-Term Energy Outlook (STEO) reveals.
Prices increased “fairly steadily” through the second half of the year, with year-end prices higher than the annual average, according to STEO.
Daily Brent spot market prices ended 2017 near $67/Bbl -- the highest level since December 2014, Kallanish Energy reports. The monthly average spot price of Brent crude oil increased by $2/Bbl in December, to $64/Bbl, marking only the fourth time in the past three years monthly Brent crude oil prices averaged more than $60/Bbl.
EIA forecasts the Brent crude oil spot price will average $60/Bbl in 2018, and $61/Bbl in 2019.
After falling in 2017, EIA expects global oil inventories to rise by 0.2 million b/d (MMBPD) in 2018, and 0.3 MMBPD in 2019.
EIA/STEO forecasts inventory builds in 2018 and 2019 will contribute to crude oil prices declining from current levels to an average $60/Bbl during the first quarter of 2018. Prices are then expected to remain relatively flat through 2019.
Daily and monthly average crude oil prices could vary significantly from annual average forecasts, because global economic developments and geopolitical events in coming months have the potential to push oil prices higher or lower than the current STEO price forecast.
“Also, the U.S. tight oil sector continues to be dynamic, and quickly evolving trends in this sector could affect both current crude oil prices and expectations for future prices,” according to STEO.
Average West Texas Intermediate (WTI) crude oil prices are forecast to be $4/Bbl lower than Brent prices in 2018 and in 2019, falling from the $6/Bbl average price difference seen in the fourth quarter of 2017.
The falling price discount of WTI to Brent in the forecast is based on the assumption current constraints on the capacity to transport crude oil from the Cushing, Okla., storage hub to the U.S. Gulf Coast will gradually lessen.
EIA/STEO estimates the price difference between Brent and WTI reflects the competition of the two crude oils in global export markets.
Thus, there are two components of the price difference: the cost of delivering WTI crude oil from its pricing point at Cushing to the U.S. Gulf Coast for export; and the additional transportation costs U.S. crude oil exports incur on their way to Asia compared with costs to deliver Brent from the North Sea to Asia.
EIA estimates without pipeline constraints, moving crude oil from Cushing to the U.S. Gulf Coast typically costs roughly $3.50/Bbl.
“EIA estimates it costs roughly $0.50/Bbl more to transport WTI from the U.S. to Asia than it costs to ship Brent from the North Sea to Asia,” EIA/STEO reported.
The current values of futures and options contracts suggest uncertainty in the oil price outlook. WTI futures contracts for April 2018 delivery that were traded during the five-day period ending Jan. 4, averaged $61/Bbl, and implied volatility averaged 19%.
These levels established the lower and upper limits of the 95% confidence interval for the market's expectations of monthly average WTI prices in April 2018, at $52/Bbl and $71/Bbl, respectively.
U.S Crude Production to Exceed 10 MMBPD.  The Energy Information Administration’s Short-Term Energy Outlook (STEO) projects total U.S. crude oil production to average 10.3 million barrels per day (MMBPD) in 2018, up 1.0 MMBPD from 2017.
If achieved, forecast 2018 production would be the highest annual average on Energy reports.
In 2019, crude oil production is forecast to rise to an average of 10.8 MMBPD. Increased production from tight rock formations in the Permian Basin in West Texas/southeast New Mexico accounts for 0.8 MMBPD of the expected 1.2 MMBPD of crude oil production growth from December 2017 to December 2019.
EIA/STEO expects most of the remaining 0.3 MMBPD growth to come from the Federal Gulf of Mexico, as seven new projects are expected to come online by the end of 2019.
The Permian is expected to produce 3.6 MMBPD of crude oil by the end of 2019, roughly a 0.9 MMBPD increase from estimated December 2017 levels, and representing about 32% of total U.S. crude oil production in 2019.
Production from the Eagle Ford Shale play is projected to be between 1.2 MMBPD and 1.3 MMBPD in 2018 and 2019, respectively, slightly higher than the 2017 level.
The Bakken is expected to produce an average 1.2 MMBPD in 2018, and 1.3 MMBPD in 2019, up from 1.1 MMBPD in 2017. The Bakken region predominately spans the Williston Basin that contains the Bakken and Three Forks formations.
Growth in crude oil production, especially in the Permian, is expected to result in increased associated natural gas production and natural gas processing.
EIA/STEO forecasts hydrocarbon gas liquids (HGL) production at natural gas processing plants will increase by 0.5 MMBPD in 2018, and 0.4 MMBPD in 2019.
EIA expects higher ethane recovery rates in 2018 and 2019, following planned increases in demand for petrochemical plant feedstock in the U.S. and abroad.
FERC Denies Constitution Request.  The US Federal Energy Regulatory Commission has denied Williams' request that it revive the Constitution Pipeline project by finding the New York water quality review waived through delay.
Constitution had argued that the New York State Department of Environmental Conservation gamed the process by pushing it to withdraw voluntarily its application and resubmit it, and the resulting delay in the permitting process was unreasonable, even if the agency acted within a year of the latest submission.
But FERC affirmed its interpretation that a waiver of a Clean Water Act Section 401 water-quality review occurs following one year after an agency receives an application, saying a case-by-case approach would create uncertainty and conflict with precedent.
The 121-mile, 650 MMcf/d Constitution Pipeline project has been stalled since April 2016, when New York environmental regulators rejected a water-quality certification. The application was first submitted to NYSDEC in August 2013
Project ties to Northeast PA production
Constitution, backed by subsidiaries of Williams, Cabot, WGL Holdings and Duke Energy's Piedmont Natural Gas, would link production in northeastern Pennsylvania to downstream interconnects with Tennessee Gas Pipeline and Iroquois Gas Transmission in upstate New York. It would further move volumes north for redelivery into high-demand markets in New England and New York City by way of the Tennessee and Iroquois systems.
Marcellus & Utica Lead NatGas Growth.  U.S. dry natural gas production averaged 73.6 billion cubic feet per day (Bcf/d) in 2017, up 1.0% from 2016, and reversing the 2016 production decline, the Energy Information Administration reports in its just-released Short-Term Energy Outlook (STEO).
“The strongest growth in dry natural gas production occurred late in the year, as improved economics related to expanded pipeline capacity contributed to a 3.8% increase in production between the third and fourth quarters of 2017,” STEO states.
The rate of production growth is expected to moderate in 2018.
Spot NatGas Prices Expected to Fall in 2018.  Henry Hub natural gas spot prices averaged $2.99 per million British thermal units (MMBtu) in 2017, up 47 cents/MMBtu from a 17-year low in 2016.
Spot natural gas prices are projected to average $2.88/MMBtu in 2018, and $2.92/MMBtu in 2019, the Energy Information Administration\ in its just-released Short-Term Energy Outlook (STEO).
Prices are expected to decline slightly from 2017 levels based on strong expected production growth, which EIA forecasts will meet growing domestic consumption and exports, Kallanish Energy finds.
Natural gas futures contracts for April 2018 delivery traded during the five-day period ending Jan. 4, averaged $2.75/MMBtu, STEO reports.
“Current options and futures prices indicate market participants place the lower and upper bounds for the 95% confidence level for April 2018 contracts at $2.01/MMBtu and $3.75/MMBtu, respectively,” STEO said.
Last year at this time, the natural gas futures contracts for April 2017 delivery averaged $3.38/MMBtu, and the corresponding lower and upper limits of the 95% confidence level were $2.39/MMBtu and $4.77/MMBtu, respectively.
NatGas Storage Biggest Pull Ever.  Frigid temperatures over most of the eastern U.S. for the week ended Jan. 5, resulted in the biggest pull from storage of working natural gas since the Energy Information Administration began keeping records eight years ago, Kallanish Energy reports.
In its Weekly Natural Gas Storage Report, EIA said a whopping 359 billion cubic feet (Bcf), or 11.5% of all working gas in storage, was pulled from underground, with the total volume of working gas stored dropping to 2.77 trillion cubic feet (Tcf), from 3.13 Tcf one week earlier.
The latest storage total was down 415 Bcf, or 13.0%, from the year-ago total of 3.18 Tcf, and was down 382 Bcf, or 12.1%, from the five-year average of 3.15 Tcf.
Last week’s draw was the largest weekly withdrawal ever, according to EIA data dating back to early January 2010, and since 1994, based on Reuters estimates of government energy data.
The previous record working gas withdrawal was 288 Bcf in January 2014, when an Arctic cold air mass surged south into the central and eastern U.S.
Texas Permits Drop 12% in December.  The Railroad Commission of Texas issued 885 original drilling permits in December 2017, Kallanish Energy reports.
That compares to 1,009 issued in December 2016,a 12.3% decline, the state agency said.
The new permits include 792 to drill new oil or gas wells, eight to re-enter plugged well bores and 85 for re-completions of existing well bores, it said.
The wells include 175 for oil, 67 for gas, 586 for oil or gas, 548 for injection and nine other permits, the commission reported.
In December, the commission processed 514 oil, 80 gas, 26 injection and three other completions. That compares to 430 oil, 93 gas, 20 injection and two other completions in December 2016.
Well completions for full-year 2017 were 6,914, down 34% from 10,468 in 2016, the commission said.
The Texas working-rig count as of Dec. 5 was 454, according to well services company Baker Hughes, a GE company. That represents roughly 49% of all active rigs in the U.S.
The most permits to drill new oil wells were issued in the Midland region, with 407 permits. Second was the San Antonio area, with 127 oil permits.
The Midland area was No. 1 for oil well completions in December, with 286. Second was the San Angelo area, with 66.
For gas permits, the Midland area was first, with 19 permits. Second was the San Antonio area, with 16 permits.
Energy Transfer Partners Projects.  Let’s look at ETP’s organic projects placed into service in 2017.
Energy Transfer Partners brought online some of its largest organic projects in 2017, including the following:
  • It placed two major natural gas pipeline projects into service in Mexico, namely the Trans-Pecos Pipeline and the Comanche Trail Pipeline.
  • The controversial Bakken Pipeline project was placed into service in June 2017. However, the project is still facing some legal hurdles.
  • It completed Phase 1A of the Rover Pipeline project. It recently received FERC (Federal Energy Regulatory Commission) approval for Phase 1B of the project. That could increase total transportation capacity of the Rover Pipeline to 1.7 bcfd (billion cubic feet per day).
The company also placed two processing plants into service in 2017, including the Panther Plant and the Arrowhead Plant.
Upcoming projects
ETP expects to place the complete Rover Pipeline project into service by the end of the first quarter of 2018. Once complete, the 713-mile pipeline is expected to move 3.3 bcfd of natural gas from the Marcellus and Utica Shale plays to US markets and to the Union Gas Dawn Storage Hub in Ontario, Canada, according to the company’s press release.
In addition to the Rover Pipeline, ETP expects to bring online some major projects in 2018, including the Mariner East 2 pipeline project, the Revolution System project, Phase 2 of the Bayou Bridge project, and Lone Star Fractionation V. The Mariner East 2 pipeline project has faced major delays due to environmental and regulatory hurdles.
CNX CAPEX Budget 2018.  CNX Resources Corporation announced an updated 2018 capital expenditure forecast of $790-$880 million, excluding the recent acquisition of the general partner interest of CNX Midstream Partners LP . The 2018 budget includes $515-$580 million of drilling and completion ("D&C") capital and approximately $275-$300 million of capital associated with land, midstream, and water infrastructure. The 2018 D&C capital budget is allocated approximately 65% to the Marcellus Shale and 35% to the Utica Shale.  
"CNX's updated 2018 capital plan reflects an industry leading balance sheet and the company's commitment to invest in high rate of return projects, which will result in substantial value creation in 2018 and beyond," commented Nicholas J. DeIuliis, president and CEO. "Our development program in 2018 is largely supported by our robust hedge book, which, as of December 31, 2017, has fully-covered volumes with both NYMEX and basis hedges of approximately 375 Bcfe, and 70% of 2018 production volumes, based on the midpoint of guidance. This de-risking of our revenue allows us to lock in attractive rates of return and confidently execute our development plans."
The company expects 2018 non-D&C capital for midstream, water, and land to drive future stacked pay development and further differentiate CNX's unique asset base. With CNX recently closing the acquisition to now control 100% of CNXM, stacked pay development has begun to directly impact the capital budgeting process and 2018 represents the initial investment required. This non-D&C capital is primarily driving production over the course of 2019, 2020 and beyond. The new stacked pay development lifecycle allows CNX to develop a single formation first and then come back on a pad to take advantage of existing, first formation, infrastructure. This development sequencing is essentially doubling the life and value of a field. As a result, rates of return on future development should benefit meaningfully from this infrastructure build-out as CNX capitalizes on the sequencing of dual formation development.
With the company's recent purchase of Noble Energy's general partner interest in CNXM, CNX has absorbed Noble Energy's 50% of capital contributions that they previously made to CNXM. As a result, CNX expects midstream capital in 2018 to be approximately $100 million. Much of the 2018 midstream capital will go towards building out development companies (DevCo's) outside of DevCo I, which will create future dropdown opportunities.
The company is increasing water capital in 2018 to approximately $75-$100 million, which includes building water infrastructure for two major stacked pay project areas that the company expects to be ready in the fourth quarter of 2019. This additional infrastructure will increase completion efficiencies by improving cycle times, resulting in additional production, lower costs per barrel, and lower future capital costs. Overall, the company estimates material cost savings by building out water infrastructure, compared to the alternative of trucking water. This water capital investment will benefit the company through future dropdowns of ownership interest into CNXM. 
The company's 2018 land capital is approximately $100 million, which includes title, land acquisition, and permitting, in order to maximize future development. Land capital in 2018 will help CNX build out its core Marcellus and extensional stacked pay Utica areas that are part of the company's 5-year development plan. A negligible amount of land capital is associated with 2018 development, but instead, the capital that the company is spending in the current year is driving net asset value per share growth by securing future development beyond 2018.
CNX is maintaining its 2018 expected production volumes of 520-550 Bcfe, which equates to an approximately 30% annual increase, compared to 2017 expected volumes, based on the midpoint of guidance. CNX plans to run three rigs through the first half of 2018 and will add a fourth rig starting in July.
Sand Mines Coming to West Texas.  A surge in demand for frac sand brought announcements in 2017 of plans to build sand mines in West Texas, with three currently open and another six scheduled to open in the next two months, the Odessa (Texas) American newspaper reported.
But oil industry research firm Infill Thinking is tracking 16 companies that have announced 23 mining sites. “It’s been the year of announcements and the beginning of construction,” Joseph Triepke, founder of Infill Thinking, told the American. “We really haven’t seen a whole lot of trucks coming out of the gate yet, but that’s coming.”
West Texas sand is a finer grade than traditional Midwestern sand and, even though questions remain about how the finer sand will affect wells in the long term, findings by oil companies show the more fine-grade sand is pumped down a well, the more oil it produces.
Hi-Crush and Alpine Silica opened mines north of Kermit, Texas, in 2017, each having production capacity of roughly 3 million tons of sand annually, Kallanish Energy learns. Aequor opened a third mine in Culberson County, Texas, with a production capacity of approximately 2.5 million tons per year, Aggregates Manager reports. 
Black Mountain Sand plans to open a sand mine capable of producing 4 million tons per year in January, and another one in February, both in Winkler County. Preferred Sands plans to open a mine capable of producing 3.3 million tons per year in Ector County.
U.S. Silica plans to open a plant capable of producing 4 million tons per year in Crane County, while High Roller Sand will open another plant of roughly the same size near Kermit. And Vista Sand will open a sand mine capable of producing roughly 3 million tons per year in Winkler County.
Halliburton’s area vice president for the Permian Basin, Chris Catjanis, told local media the local sand mines could slash transportation costs by roughly 40%, lowering the breakeven cost of an oil well.
Lucid Energy Group Sold.  Lucid Energy Group, which bills itself as the Permian Basin’s largest privately-held natural gas processor, and its financial sponsor, EnCap Flatrock Midstream, said Monday they’re selling Lucid Energy Group II for roughly $1.6 billion in cash.
The buyer is a joint venture controlled by investment fund Riverstone Global Energy and Power Fund VI, managed by Riverstone Holdings, and investment funds managed by Goldman Sachs’ Merchant Banking Division (MBD).
The Lucid II assets included in the transaction are located in the core of the northern Delaware Basin and are known as the South Carlsbad Natural Gas Gathering and Processing System, and the Artesia Natural Gas Gathering and Processing System.
Assets include roughly 1,700 miles of natural gas gathering pipelines and 585 million cubic feet per day (MMcf/d) of processing capacity, with an additional 200 MMcf/d under construction and scheduled to be in service by mid-2018.
The Coming Northeast Petrochemical Industry.  An abundance of gas from the Marcellus and Utica shale formations in the northeastern U.S. offers great potential for jobs and economic development, but infrastructure, community support and a well-trained workforce are necessary to capitalize on the opportunity.
That’s the conclusion of the U.S. Northeast Petrochemical Industry Market Outlook 2018, a new white paper from Petrochemical Update. The publication provides a near-term market overview for petrochemical industry in the northeast U.S. It also includes an update of current and proposed projects, a perspective on regional challenges to petrochemical sector expansion, an update on the Appalachian natural gas liquids storage hub and a construction cost analysis.
“While the region with its ample and reliable supply of ethane is primed for the emergence as a second major petrochemical manufacturing hub in the United States, it faces the challenges of rapidly developing a workforce, as well as storage and pipeline infrastructure to fuel such development,” the report says.
The paper notes that discoveries of natural gas in the Marcellus and Utica shale extending from New York through Pennsylvania, Ohio and West Virginia prompted announcements of three new ethane cracking plats in the area. However, the Shell Appalachia LLC petrochemical complex in Beaver County, Pennsylvania, is the only one on track to be constructed. It will be the first major U.S. project of its type to be built outside the Gulf Coast in 20 years.
The paper cites Energy Information Administration (EIA) data showing that the demand for natural gas is growing along the U.S. Gulf Coast by about 20 percent year because of the commissioning of LNG export facilities, stronger industrial demand and the increases in pipeline exports to Mexico.
According to the paper, “This demand is also being met by recent shale gas activity in the West Texas Permian Basin, Woodford Basin and Eagle Ford Basin, all of which have good connectivity to the Gulf Coast ethylene cracker market.”
EIA data shows that in the northeast region, natural gas production of 20 billion cubic feet (bcf) per day in 2017 should double in the next 35 years, accounting for 40 percent of total U.S. natural gas production. Dry natural gas production in the eastern region of the forecast to grow by a third between 2015 and 2025.
The U.S. produces 25 percent of all the world’s NGL and more than 25 percent comes from the northeast, according to the American Chemical Council (ACC). From 2026 to 2030, NGL production for U.S. demand alone is expected to reach nearly 6.3 million barrels per day (bpd). More than 1 million bpd of NGL will be sourced from the Marcellus and Utica Shale plays.
Unique to the region is that up to 40 percent of the natural gas produced from the Marcellus and Utica shale play is rich in NGL. More than 70 percent of it is ethane and propane.
However, the paper notes that while the northeast region is exporting its ethane to Canada, the Gulf Coast and Europe, “lack of pipelines restricts what is sold, and the balance of at least 150,000 b/d is downgraded in value as it is mixed with the natural gas that supplies homes and businesses for heating and cooking.”
The Petrochemical Update white paper says that a second petrochemical hub in the U.S.—in addition to the one on the Gulf Coast—could “provide supply-chain redundancy for the nation which now relies primarily on production from a region susceptible to hurricanes and tornados.”
Even when pipeline shipments of ethane out of the northeast region are factored in, up to 350,000 to 400,000 bpd of ethane is available for petrochemical feedstock within New York, Pennsylvania, Ohio and West Virginia—enough for five or six ethane crackers, the paper says.
Ormet Site in SE OH Getting NatGas Electric Plant.  Back in 2014 MDN told you that the former Ormet aluminum plant in Hannibal (Monroe County), OH had been purchased out of bankruptcy by Niagara Worldwide and turned into the Center Port Transload Facility, with an emphasis on providing services for the Marcellus/Utica industry. 
In April 2017, we brought you news about plans to build a 485-megawatt Utica gas-fired electric plant at the Center Port location. A lot has happened since that time. Most of the facility (not all) changed hands again, selling to Fortress Transportation and Infrastructure for $30 million last June. Since that time, what was called Center Port Terminal has been renamed–to Long Ridge Energy Terminal. The new owners are moving forward, quickly, with plans to build the gas-fired power plant, which is now called the Hannibal Port Power Project. According to the Long Ridge website, the Hannibal Port Power gas plant will be operational by 2020–meaning construction will begin this year…
Russian NatGas Is Going to Boston.  This is so wrong on so many levels. Our blood pressure went through the roof when we spotted a story that a shipload of Russian-produced LNG (liquefied natural gas) is almost certainly coming to Boston and will be delivered on Jan. 22nd. 
We suspect it may be an illegal shipment. Here’s what happened. The LNG tanker Christophe de Margerie loaded a shipment of LNG at Russia’s Yamal LNG plant–in the Russian Arctic–delivering it to the UK at the Isle of Grain terminal in Kent. The LNG was offloaded and stored, but not pumped into the UK grid. Instead, officials said the LNG would be resold to a higher paying customer. A few days later the tanker Gaselys loaded LNG from the same terminal in Kent. While those who own the shipment won’t say, it’s almost certain the LNG they loaded was the very same LNG unloaded a few days prior–from Russia. Gaselys is coming to America–to unload the Russian LNG in Boston, because New England is natural gas starved at the moment due to the ongoing cold snap. 
Why not just bypass the unloading/reloading process and ship direct to the U.S.? Because the U.S. slapped the Yamal LNG plant with sanctions following Russia’s moves against the Ukraine. It’s illegal to receive gas produced from that plant. So the people involved “whitewashed” the gas by unloading in Kent, and then pretending they’ve reloaded different gas molecules from the same facility. It’s a farce. Fake. Fraud. The gas coming to Boston is Russian gas. The reason New England needs gas so bad is because of their elected leaders, like Massachusetts Attorney General Maura Healey and Massachusetts Sen. Elizabeth Warren–both of whom adamantly oppose new natural gas pipeline projects in their state that would deliver cheap Marcellus/Utica gas to the region. Massachusetts residents should rise up against Healey and Warren for their actions which now mean New England is paying our ENEMIES for natural gas. 
In New Jersey, the consumer is paying a 3000% more for NatGas than in PA.  Yes, it’s 3000%!!!
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PA Permits January 4, to January 11, 2018

    County             Township E&P Companies
1. Butler               Allegheny EM Energy
2. Butler Allegheny        EM Energy
3. Butler Allegheny EM Energy
4. Butler Allegheny EM Energy
5. Butler Allegheny EM Energy 
6. Butler Allegheny EM Energy
7. Butler Allegheny EM Energy
8. Butler Allegheny EM Energy
9. Butler Allegheny EM Energy
10. Butler Allegheny EM Energy
11. Butler Allegheny EM Energy
12. Tioga Liberty SWN
13. Tioga Liberty SWN
14. Tioga Liberty SWN
15. Tioga      Liberty SWN
16. Washington Somerset Rice
17. Washington Somerset Rice
18. Washington Somerset Rice

OH Permits for week ending January 6, 2018

      County Township E&P Companies
1. Jefferson Ross Chesapeake
2. Jefferson Ross Chesapeake 
Joe Barone 610.764.1232
Vera Anderson 570.337.7149
DUG Technology