The following Shale Directories Members are OPEN for BUSINESS during COVID-19 related shutdown.*
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1st Choice Energy Services
Allison Crane & Rigging
Frontier Group of Companies
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Green Valley Seed
Inland Tarp and Liner
MJ Painting Contractor Corp.
Mansfield Crane Service
Marshall County Co-Op – Southern States
NAI Ohio River Corridor
Oglebay Resort and Conference Center
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Shale Directories Conferences
4th Annual Appalachian Storage Hub Conference
New Date Coming
Hilton Garden Inn
Southpointe, Canonsburg, PA
8th Annual Upstream PA 2020
New Date Coming
State College, PA
8th Annual Utica Midstream
New Date – September 24, 2020
North Canton, OH
8th Annual Midstream PA 2020
November 12, 2020
State College, PA
8th Annual Utica Downstream
New Date Coming
North Canton, OH
2nd Annual Appalachian Basin Real Estate Conference
December 10, 2020
Latest facts and a rumor from the Marcellus, Utica, and Permian, Eagle Ford Plays
Coronavirus FLASH REPORTS: No Reports This Week
Facts & Rumors Newsletter #381
U.S. Army Corps of Engineers Appealing Montana Ruling. The Army Corps of Engineers alerted a federal court yesterday that it was appealing an order blocking use of its nationwide permit program for certain pipeline projects. In a notice to the U.S. District Court for the District of Montana, the Army Corps said it was appealing both Chief Judge Brian Morris’ initial order barring a wide range of projects from using Nationwide Permit 12 and his subsequent amended order blocking use of the permit for new oil and gas pipelines.
Permitting Picking up in May. (Thank you, NGI) The collapse in drilling activity deepened in April, with permitting for oil and natural gas wells at a record low, but there are glimmers of gains so far this month, according to an analysis by Evercore ISI.
The analysis led by James West compiles data from state and federal officials for a deep dive of where permitting is underway and where it has fallen. April permitting was less a bump in the road and more like a train wreck.
However, April showers may be bringing May flowers, the data indicated. Using week/week (w/w) data, Evercore said oil permits climbed 19% from the final week of April to 166 in the first week of May. The Permian Basin accounted for the most permits early this month, rebounding to 100, up by 35 from the week before. The gain was partly offset by the Eagle Ford Shale, with six fewer permits, and the Mississippian Lime, down by seven.
Still, natural gas permits “strengthened to 39,” a 64% gain w/w, “as a result of resilience in the Haynesville Shale,” which added 15 permits. Permitting in other onshore plays dropped to 65, down by 37 from late March.
For natural gas, permitting has been hit and miss since the start of the year, according to Evercore.
Marcellus Shale permitting plunged by 44% through April year/year and was down by 20% from March to 169. The Utica Shale, a mix of gas and liquids, saw a month/month (m/m) decline of 14 permits.
However, the Haynesville, second to the Marcellus in dry gas production, posted a slight recovery from March, with permits up by 13.
Year-to-date through April, gas permitting across the country decreased by 39% to 884, “resulting from lower applications in the Marcellus to 409,” off 44% year/year, “and the Haynesville to 383,” down 31%.
In Texas, where the bulk of the country’s oil and gas is produced, permitting moved to its lowest count in more than 10 years during April and fell 28% year to date, Evercore said.
Permits by the oil and gas majors, which dominate in the Permian, were off in the first four months by 25% from the same period in 2019.
U.S. onshore permits in April overall fell by 2% from March to 2,013, “primarily as a result of declines in the Gulf Coast (minus 26%) and Midwest (minus 59%),” West said. “Excluding ‘other’ shale plays, drilling permits marked the lowest total in our dataset going back to 2006 at 1,001.”
For individual plays, the m/m declines were led by the Permian, off 159 from March, and in the Eagle Ford Shale, down by 74. Lower permit counts also were reported in the Granite Wash formation, down by 16, and in the Barnett Shale, off 13.
Wells permitted during April in the West Texas portion of the Permian “declined to 504 (minus 24% m/m) due to curtailments in Howard, Reeves, Loving and Midland counties, where aggregate permit applications declined to 144 (minus 128 m/m).”
Contributing to the decline in permits during April was the pullback by some of the biggest operators in Texas, including EOG Resources Inc., which requested 26 fewer permits than in May. ExxonMobil’s requests were down 26 m/m, while Permian pure-play Diamondback Energy Inc. had 18 fewer requests. BP plc requested seven fewer permits than in March.
In the Eagle Ford, the second largest play in Texas, permitting contracted in April to 94, off 44% m/m.
State regulators granted authorization to drill 480 oil and gas wells in the Permian, with the New Mexico portion accounting for 46% of the activity, West said. New Mexico activity was driven lower by public operators, whose permit applications fell to 142 in April, down by 19 m/m.
Through April, overall drilling permits across the country fell by 61% year/year to 8,751.
“The majors have reduced permit applications by 24% year/year in the Permian, while wells approved for large-caps have declined to 547,” off by 5%, said West.
Private operators in the Permian had cut their permit count through April by 6% to 1,424.
Meanwhile, Evercore’s analysis said more wells are being plugged and abandoned. In the Bakken Shale, permits to plug were up by 14 in April over a three-month period, and they were two higher than in March. Operators also plugged 1,532 wells in Texas, moving up by 776 from March.
For water disposal wells used in oil and gas development, the Railroad Commission of Texas approved 15 in April, a gain of 25 m/m, with no permits granted by New Mexico regulators. The Marcellus and the Green River Basin each received a permit for disposal wells, while the Denver-Julesburg/Niobrara permits rose to six from zero.
Permian Pipeline Being Sued. The Permian Basin Pipeline, intended to transport natural gas across over 400 miles, could potentially be blocked in court after an environmentalist group filed a lawsuit against it. The group alleges a federal agency ignored a court order that could have vacated permitting, allowing the line to be built over bodies of water as it stretches from West Texas to the Gulf Coast.
Permian Drilling Restarting. Pipeline operator sees Permian wells restarting production. Some drillers in the biggest North American oil field are reopening wells shut in response to the pandemic-driven price collapse, according to pipeline giant Energy Transfer LP. In the Permian Basin’s Midland region, about 8% of oil volumes that feed Energy Transfer’s pipe network had been shut at the start of the month, Mackie McCrea, the company’s chief commercial officer, said during a conference call on Monday. “As of today, we’ve seen about 25% of that turned back on,” McCrea said.
China’s Oil Demand Is Returning. For a sneak peek at the return of Chinese oil demand, look no further than the rebound in price of the nation’s favorite grades.
In the last few days a Chinese state-owned refiner bought Brazil’s Lula crude for August arrival at a premium of about 50 cents a barrel to Brent on a delivered basis, according to four traders in Asia. That’s a sharp recovery from the middle of April when the same grade traded at a discount of around $6.
The price jump comes as factories across Asia’s largest economy restart and people return to work, with some favoring their cars over taking public transport. Crude processing at China’s independent refineries is now higher than pre-virus levels, while fuel demand is also starting to rebound in India.
Output curbs by the OPEC+ alliance have led to steep increases in official selling prices by producers including Saudi Arabia and Kuwait. Supplies of Basrah oil from Iraq were also cut to at least three Asian buyers for June this week, tightening regional balances. That, in turn, is prompting marketers of crude from the Americas to Africa to hike offer levels in Asia, despite ample inventories in onshore and floating storage.
Diversified Picking Up EQT Wells. Diversified Gas & Oil, a company that claims to succeed where other oil and gas producers fail by aggregating an enormous portfolio of Appalachian wells, has announced two more deals on the horizon.
To fund them, the Alabama-based firm is issuing shares of its stock, which is traded in London, at a time when demand for fossil fuels, commodity prices and energy company stocks are hurting.
The move is in line with the company’s self-described “contrarian business strategy” of buying up older, shallow wells. But, as with several other recent deals, the two proposed transactions also include dozens of horizontal shale wells from Downtown-based natural gas producer EQT Corp.
EQT, which has been shopping around some of its non-core assets to pay off debt, would receive $125 million in exchange for 900 wells, most of them shallow assets in West Virginia and 67 horizontal shale wells in Pennsylvania. The shale wells are between 5 and 10 years old, according to Diversified’s announcement of the potential deals.
Using old oil and gas wells as collateral, Diversified gets $200M from hungry investors
By count, horizontal shale wells make up a minuscule proportion of Diversified’s portfolio — the company had just over 500 of them as of the end of last year, according to a reserve report released this week, out of nearly 60,000 total wells.
But shale now accounts for more than a quarter of Diversified’s oil and gas production.
The shale wells are also more expensive to decommission, a responsibility that is growing for Diversified even though much of its obligations to plug and abandon thousands of wells are pushed out decades into the future, as per agreements with the states where the company operates.
The other proposed deal that Diversified recently disclosed involves about 6,100 conventional wells in Tennessee, Kentucky and West Virginia, along with pipelines and two natural gas storage fields. The assets are currently owned by Carbon Energy Corp. and would be worth $100 million at closing.
Both the EQT and the Carbon deals have provisions for extra payments if commodity prices rise.
Production from the proposed acquisitions would amount to 20% of Diversified’s 2019 output, another significant boost to its Appalachian status.
The company cautioned that it is still doing diligence on the deals and made no guarantees that they will close.
Fracking E-Fleets Gaining Rapid Acceptance. US service companies are sending hydraulic fracturing units into overflowing equipment yards at the fastest clip ever seen. But one thing not likely to be found at these sites are the recently emerged electrically powered fracturing units, or “e-fleets.”
At the start of the year, there were about 290 active fleets of all flavors spread across the country, according to figures from Primary Vision. The firm, which publishes the US frac count weekly, estimates the active number was down to 47 at the end of last week—15 of which are believed to be e-fleets.
“It’s amazing that [e-fleets] accounted for roughly 3% of the market about 2 months ago and now they’re potentially about 30%,” said Matt Johnson, the president and chief executive of Primary Vision.
Three companies own this entire space which has been driven by the shale sector’s growing concerns over noise levels, fuel costs, and carbon footprints. Evolution Well Services and US Well Services, both based in the Houston area, each are estimated to be operating six electric pumping spreads. Midland-based ProPetro operates the remaining three e-fleets.
E-fleets are called so because they use gas-powered turbines to generate electricity that is then used to run the pumps. The approach means only eight to 10 pressure pumping units are needed on location whereas the typical diesel-powered spread requires around 20 units to treat a well. Using gas also generates meaningful fuel savings and a reduction in the emissions intensity of each well completion.
The biggest reason that e-fleets have not seen greater adoption in recent years is their cost, which is widely understood to be at least twice that of a traditional diesel-powered fleet.
In an ironic twist, those big price tags are now the most likely reason why the e-fleets are proving to be more resilient amid what is otherwise a total market collapse. To take on the risk and cost of building out a new e-fleet, service companies typically require multiyear contracts from their operator clients.
US Well Services said in its most recent earnings call this week it signed a 3-year contract for electric fracturing services with gas shale producer EQT Resources which operates three of its electric fleets plus one conventional spread. This deal was struck after the pressure pumper brought on its sixth e-fleet to work for Shell in January. The e-fleets, which run about $13 million each, now represent two-thirds of the company’s entire working asset base.
ProPetro launched its first electrically powered pumping units in January. Last year, the company reported the first two of these fleets were contracted by ExxonMobil (XTO Energy) and Diamondback Energy.
“They believe in the technology,” said Phillip Gobe, the executive chairman of ProPetro during the firm’s most recent earnings call. “I think they believe that going forward, we are going to be in a lower-priced world. They need new technology that’s more efficient, less people, less cost to run, and they are willing to let us bring it out and continue.”
Johnson noted that Evolution—which operates e-fleets exclusively—may hold a competitive edge amongst its peers since it has four dedicated fleets operating with EOG Resources. “As of this past week, EOG might be the only operator in the Eagle Ford still fracking and it’s with an electric spread,” he said, adding that all of the 15-active e-fleets are expected to remain fully utilized for the foreseeable future.
Evolution highlighted that in addition to long-term contracts, chief to its strategy of weathering the cyclical pumping business is to diversify where it operates. Carrie Murtland, the chief operating officer of Evolution, said a third of the firm’s fleets are working in the Marcellus and Utica basins.
“The bifurcation between oil and natural gas economics is glaringly evident today,” she said. “A portion of our clients are evaluating what their production plans look like with WTI tumbling to negative values, meanwhile customers in the natural gas business have growing excitement around $3.00-plus gas futures.”
One big question around this development is whether it is a trend or an anomaly exposed by extraordinary events. Murtland cautiously pointed out that the answer depends entirely on the shale sector’s ability to spend cash—and whether those new dollars go to the higher-cost e-fleets.
“Currently, nearly all electric fleet capacity is being utilized, meaning that if overall completions activity utilization does rise in the future, electric providers would be required to deploy new fleets in order to maintain the sudden market share gains that we have seen recently,” she said. “From Evolution’s perspective, we continue to have a watchful eye on the market and will defer any decision to invest further into horsepower growth until we have a clearer picture of how activity and service pricing will unfold.”
Pipeline Accidents Down 17%. The pipeline industry says data shows lines carrying crude oil and other liquids are getting safer amid a construction boom adding thousands of miles of new pipe. The number of incidents on liquids pipelines was down 17% from five years ago, with 77 fewer spills and other mishaps in 2019 compared with 2015, according to an annual report issued yesterday by the American Petroleum Institute and the Association of Oil Pipe Lines (AOPL).
Jesse Jackson Supports Illinois Pipeline. A recent Axios article noted that Jesse Jackson, in a break from others on the left, is advocating for a proposed natural gas pipeline that would service Pembroke Township, Illinois. This should come as no surprise: Rev. Jackson has been advocating for a link to service Pembroke since December, a predominantly poor community where many residents rely on relatively expensive propane or less efficient wood-burning fireplaces for warmth in the winter. Natural gas heat would be an affordable, potentially life-saving option for this community.
In fact, Rev. Jackson has been joined by other civil rights leaders in their support for the use of natural gas, despite arguments that the world should eliminate the use of fossil fuels as quickly as possible. Specifically, Jackson, Rev. Al Sharpton and National Urban League President Marc Morial have in separate interviews indicated that natural gas is needed as an affordable “bridge fuel” to be used until the country can fully transition to renewables. The clear argument is that energy costs make up a larger percentage of poorer households’ budgets than wealthier households. Therefore, hikes in energy costs disproportionately impact the poor. Economists would say, increases in energy costs act much like a regressive tax.
FERC Rejects Pause in Permitting. Federal Energy Regulatory Commission Chairman Neil Chatterjee has refused requests to pause energy infrastructure permits for the duration of the coronavirus pandemic. In a Tuesday letter addressed to Virginia Attorney General Mark Herring (D), Chatterjee said the public’s need for strong energy infrastructure is not lessened by the pandemic.
LNG Demand Falling. Tanking LNG demand takes center stage in natural gas futures decline; Hefty storage build expected. Natural gas futures continued to pull back Wednesday as liquefied natural gas demand (LNG) took another hit. With government storage data expected to produce a second consecutive triple-digit injection, the June Nymex gas futures contract settled 10.4 cents lower at $1.616. July fell 10.9 cents to $1.856. Spot gas prices also retreated further amid the lack of significant heating or cooling demand across the Lower 48.
O&G Jobs Could Be Back Soon. America’s oil and gas jobs could soon come roaring back. Forbes. Opinion. Bill Gilmer knows an economic bust when he sees one. In the 1980s, when oil prices tumbled amid a supply glut, Gilmer watched as Houston’s office space cleared out and stayed out. But when Gilmer surveys Houston’s oil and gas-driven economy these days, he doesn’t see a bust. He sees an industry that’s poised to roar back to life as soon as demand returns and inventories clear. “This is not a hard industry to reopen,” he said.
Sharp Price Pull Back in Oil Unlikely. The risk of a sharp pull-back in oil prices has decreased as the rebalancing of the crude market gathers pace, Goldman Sachs said, aided by a gradual lifting of coronavirus lockdowns and a faster-than-expected fall in output.
The Wall-Street bank raised its May global demand estimate by 1.4 million barrels per day (bpd), but still sees a decline of 16 million bpd from pre-COVID levels.
However, recovering demand and lower output would push the global oil market into deficit in June, it said in a note dated May 13.
The bank said the biggest improvement in demand continues to be in gasoline road transportation, and in China, the United States and Germany, but re-iterated its view that a return to normal demand levels will take time.
Goldman expects oil prices to have limited upside in coming months, citing a big inventory overhang and the ability for shut-in production in North America to restart if prices rally further.
The bank maintained its summer price forecasts of $30 per barrel for Brent and $28 per barrel for WTI as demand uncertainty in coming months remains high.
“We believe that the next stage of the oil market rebalancing will be one of range-bound spot prices with the most notable shifts being a decline in implied volatility as well as a continued flattening of the forward curve without long-dated prices rising yet,” it said.
Oil prices rose on Thursday after an unexpected drop in U.S. crude stocks. Brent crude futures were trading at $29.37 per barrel and U.S. West Texas Intermediate (WTI) at $25.56 a barrel.
Brent crude prices are still down more than 50% for the year after the coronavirus pandemic slashed fuel demand, forcing oil producers, including OPEC and other producers including Russia, a grouping known as OPEC+, to scale back production.
“Outside of OPEC+, production appears to have fallen slightly faster than our expectations,” Goldman said, adding it expects core-OPEC production increases to occur in the final quarter of this year rather than the 0.3 million bpd previously pegged for the third quarter.
Current binding inventory constraints will keep prices capped through 2020, setting the stage for a big deficit in 2021 that will lead prices well above the forward curve, the bank added.
PA Permits May 7, to May 14, 2020
County Township E&P Companies
- Greene Center EQT
OH Permits May 9, 2020
County Township E&P Companies
- Belmont York Gulfport
- Belmont York Gulfport
- Belmont York Gulfport
WV Permits May 4, to May 8, 2020
- Brooke SWN
- Brooke SWN