Shale Directories Seminars
March 21, 2019
North Canton, OH
Upstream PA 2019
April 17, 2019
Penn Stater Conference Center
State College, PA
Latest facts and a rumor from the Marcellus, Utica, Permian, Eagle Ford, and Bakken Shale Plays
Rice Brothers Interview with S&P Global Platts. Dissident EQT shareholders Toby and Derek Rice on Tuesday said they plan to nominate a slate of candidates to challenge the current EQT board if the company’s leadership does not readily adopt their plan for restructuring the producer’s entire operational strategy.
In a conference call to outline their plans the brothers called on the EQT board to hire Toby Rice to head the revamped company, replacing current CEO Rob McNally, and to hire as many as 15 former Rice executives to rapidly implement changes to the producer’s operations in the Appalachian Basin.
“We are ready to nominate highly qualified director candidates for election at the EQT 2019 annual meeting, in the event that EQT continues to not engage with us in a meaningful and constructive manner,” Toby Rice said on the conference call.
The brothers, founders of Rice Energy, which EQT acquired in November 2017, together own about 3% of the company’s outstanding shares. They are expected to announce their slate of board candidates soon after EQT sets a date for its annual shareholder meeting, which is typically held in April, but which was postponed until June last year to give shareholders time to adjust to a series of corporate changes that the company was undergoing.
In an interview with S&P Global Platts, Toby Rice outlined the plan, which called for the use of existing proprietary technology, improved well spacing, and company-wide operational planning, to bring the average drilling cost down to $735/foot, compared with EQT’s projected all-in drilling expense goal of $1,095/foot.
“Those things combined allow us to effectively plan and that is the key to executing at scale in a large manufacturing mode,” he said.
Rice said EQT has failed to use technology that Rice developed in its last several years as an independent company. The cloud-based, mobile technology, which was accessible by all employees, created “a digital work environment,” and “contained all of the work flows that the entire business needed to execute, to lease land, drill wells, produce wells and markets the gas.”
EQT’s decision to not use the technology was driven by the company’s legacy culture, which is resistant to change, Rice said. “They confuse being the biggest with being the best,” he said.
1,000-FOOT WELL SPACING
The Rice brothers’ plan also calls for wells drilled in the Marcellus Shale play to be placed 1,000 feet apart, which they claim would result in an increase of about 10% of per-well estimated ultimate recovery compared with EQT’s 880-foot spacing plan.
Both the current EQT leadership and the Rice brothers’ team seem to agree that 12,000 feet is the optimal average lateral lengths for wells drilled in the Appalachian Basin. However, Toby Rice said EQT continues to experiment with ultra-long laterals of beyond 15,000 feet, a move he called “a little bit of a head-scratcher.”
In its Q3 2018 earnings report, EQT pinned part of the blame for a $300 million increase in its 2018 capital expenditures budget on “the learning curve on ultra-long laterals.”
In 2018, the company drilled 25 wells with ultra-long laterals and this year it plans to drill 20 more, Rice said.
“Your operational risk increases as you go longer than 15,000 feet. When we’re executing in a manufacturing mode, we want to make sure we’re doing it with the highest confidence at the lowest risk,” he said.
EQT’s leadership has challenged the Rice Brother operational plans, saying they failed to account for the challenges faced by EQT, which has much a larger asset base and geographic footprint than Rice Energy had at the time of the merger.
However, Rice pushed back against that argument, saying 90% of EQT’s 2019 planned drilling activities lie within the territory formerly owned by Rice Energy. In a statement Tuesday, EQT spokeswoman Linda Robertson said the company’s leadership continues to stands behind its own long-term development plan.
“We disagree with the analysis put forward by the Rices and look forward to continuing our discussions directly with shareholders,” Robertson said. “EQT remains focused on reducing costs and generating substantial free cash flow to create further value for EQT shareholders.”
Rice Brothers Plan. In late 2017, the big fish, EQT Corp., acquired its sibling smaller fish, Rice Energy, to become the biggest U.S. fish in terms of natural gas production.
Taking it to the shareholders
This week, Rice brothers Toby and Derek, continued their push to take command of EQT, appealing directly to shareholders to make big-time changes at EQT, including making Toby Rice EQT’s chief executive. Another 10-15 former Rice Energy executives are on standby, ready to step in at EQT to make the brothers’ plans work.
The brothers are prepared to bring their own slate of directors for a shareholder vote if big changes don’t soon begin to occur.
Appalachian Basin-focused EQT acquired Rice Energy for $6.7 billion. But since the deal closed, EQT’s share price has fallen more than 30%, which the Rice boys blame on operational and managerial mismanagement at EQT.
The Rice brothers originally had approached EQT’s board and management with their reorganization plan.
Getting nowhere in their eyes, Tuesday the brothers took the fight directly to shareholders, showing off their plans for running EQT the right way, making money, lowering costs, increasing production – everything the brothers claimed Rice Energy did which made it such a prize for EQT in 2017.
Boosting free cash flow
The brothers, who own roughly 2.8% of EQT, said in their presentation this week and have said for two months they could improve EQT’s free cash flow by $500 million annually.
Among their recommendations: streamlining portions of EQT; digitizing workflows; and improving planning to reduce well costs, Kallanish Energy reports.
An EQT spokeswoman reiterated previous responses that EQT disagreed with the Rice’s analysis, and looks forward to continued discussions with shareholders.
EQT’s average Marcellus Shale well cost for a 12,000-foot lateral was $1,250 per foot in 2018, while Rice Energy, before its merger with EQT, averaged $790 per foot for wells with laterals reaching 8,800 feet in the same region, according to the Rice presentation. The brothers also said EQT has “erroneously adjusted downwards” its well costs.
More, more, more
In the presentation, the brothers said operations could be improved by altering well designs to include more sand, water and stages per lateral-foot.
The presentation also said they had initiated dialogue with EQT to improve its business, but claimed those suggestions have been ignored, prompting it to bring their concerns directly to shareholders.
EQT presented its plans for 2019 in late January, which prompted more back-and-forth between the company and the brothers, each accusing the other of (paraphrasing) false and misleading statements.
Southwestern 2019 Drilling Plans. Southwestern Energy said it plans to drill 95 to 115 wells in 2019 in the Appalachian Basin, to complete 100 to 120 wells, and to turn to sales 90 to 110 wells, Kallanish Energy reports.
It will end 2019 with 35 to 45 DUCs, drilled but uncompleted wells. Those wells will be drilled in northeast and southwest Pennsylvania and the West Virginia Panhandle.
The company is projecting capital spending in 2019 at between $1.08 billion and $1.18 billion. That’s a drop of roughly $120 million from 2018 spending and a $200 million reduction from what had been projected earlier for 2019 spending, said the Texas-based company.
Southwestern is projecting total 2019 production at between 750 and 785 billion cubic feet-equivalent (Bcfe). That will include natural gas production between 588 and 616 Bcfe and natural gas liquids and condensate of between 26.95 million barrels (Mmbbls) and 28.25 Mmbbls.
Its Appalachian production in 2018 was 702 Bcfe, 20% of which was liquid production, according to Southwestern. It’s projecting liquids in what it designates as Southwest Appalachia will increase by 20%, to 75,600 Bpd.
Production in northeast Pennsylvania will remain flat in 2019, but it will produce free cash flow, the company said.
The company is also projecting a 25% reduction in average well costs and a 35% increase in average lateral length, to more than 10,000 feet.
Southwestern said 70% of its gas production is hedged. Drilling and completion activity will be primarily in the first half of 2019.
“Our operational execution and capital efficiency improvements are clearly evident in our lower well costs and our successful ultra-long lateral results. The company expects to generate free cash flow by the end of 2020, and remains committed to a sustainable net debt/EBITDA ratio of 2X. We continue to demonstrate returns-focused capital discipline while leveraging our flexibility and adjusting our capital allocation decisions with market conditions,” said Bill Way, president and CEO, in a statement.
20,000 Wells in 2019. A new report estimates that amid strong production growth, the US shale sector is on a trajectory to drill and complete more than 20,000 wells this year. Released this month by Energent, Westwood Global Energy Group’s unconventional-focused research unit, the figure represents an 8% increase over 2018.
“If you look at it closer, by the end of 2019, you see that completions will start to outpace the drilling on a basin-by-basin level,” said James Jang, a data analyst and consultant with Energent, who added that the trend will also include a collective drive to whittle down the sector’s large inventory of drilled-but-uncompleted wells (DUCs).
If the projection holds, then it would mark the highest number of wells drilled since 2014 when US operators drilled almost 32,500 wells. It would also be the first time since the first half of 2016 that shale producers completed more wells than they drilled.
Energent expects the US rig count to drop in late 2019 as operators begin to aggressively target the DUCs, which should peak at about 10,300 wells in mid-year before being reduced to 4,600 in 2022. “The reason why you have seen the DUC count increasing over the past 3 years is because of the oil price factor,” said Jang. He explained that operators have been using the DUCs as “a kind of call option” as they waited for improved prices to maximize the economics of their developments.
Despite the turbulent period between October and December, prices have been relatively stable since then and may continue their modest rebound. Energent’s scenario for 20,000 new wells relies on a base WTI oil price of $60/bbl this year. If prices slip to $52/bbl, drilling activity will likely be disrupted and could stall, the report says.
The projected growth in drilling activity is already taking shape in the Eagle Ford Shale, the Williston Basin, and the Mid-Continent shale plays (i.e. the SCOOP/STACK). Drilling in the Eagle Ford increased by 43% year-over-year in 2018, while the Williston and Mid-Continent saw upticks of 36% and 23% respectively.
Activity levels in the Permian Basin have been more balanced ever since production overtook takeaway capacity last year. “That issue will be mostly solved by late 2019,” said Jang, as new oil and gas pipelines come on stream with combined capacities of 1.4 million B/D and 4 bcf/D.
The analysis has also found that US shale producers may be approaching limits on horizontal well lengths and proppant loading. Average lateral lengths in the US only increased by 300 ft in 2018, or 4%, compared to the 8% increase of 560 ft. seen in 2017. Energent says the trend suggests that after years of increasing these key well design parameters operators are starting to come up against technical, acreage, and economic limits.
Well lengths in the DJ and Niobrara Basin saw the most notable change. In 2017, year-over-year growth was 21%, or 1,400 ft, compared to last year’s increase of only 3%, or 240 ft.
Proppant volumes are increasing, but the acceleration in tonnage per well is slowing too. The US total increased by 9%, or 530 tons per well in 2018 while in 2017 the same year-over-year figure was 27%, or 1,260 additional tons of proppant and sand.
The Permian lines up closely to the national average, showing a 2018 increase of 8% compared to a 26% increase in 2017. The sharpest drop off in proppant growth was seen in the Appalachia region, which includes the gas-rich Marcellus Shale. There, average proppant increases fell from an average of 41% in 2017 to only a 5% increase last year.
Source: Energent, Westwood Global Energy Group.
DEP Cutting Red Tape in SW PA. The state Department of Environmental Protection says it is cutting red tape often associated with its review of projects that could impact air, water and soil quality in southwestern Pennsylvania. In the past year, the DEP’s Southwest Regional Office reduced its backlog of permits by more than 75 percent – from 1,464 to 359 – and shortened its review timeline for erosion and sediment control general permits by more than 220 days, the office said. Not only has the office reduced the backlog of pending permit applications in the region, which covers eight counties, “it has stayed current on new permits and has not added to the backlog,” said DEP spokeswoman Lauren Fraley. Helping with the streamlining was DEP’s decision to open a Regional Permit Coordination Office, or RPCO, and to shift two counties – Indiana and Armstrong – from the Southwest Regional Office to the Northwest Regional Office, Fraley said. “DEP’s goal with this initiative is to reduce the backlog of pending applications, improve permit review times, manage workloads and expand the use of electronic permit application tools to help simplify the process where possible,” Fraley said.
ExxonMobil and Chevron Focusing on Permian. ExxonMobil and Chevron are accelerating the pace of their production growth in the Permian Basin, the heart of the US shale oil boom, indicating that the country’s output is likely to keep increasing strongly despite the fall in crude prices since October. Reporting earnings for the fourth quarter of last year, both companies, which are the largest US oil groups, talked about stepping up activity and output in the Permian region of Texas and New Mexico. Exxon and Chevron have been in the forefront of moves by large international oil groups to invest in the US shale industry, which was first opened up by smaller exploration and production companies. Exxon has stepped up the number of rigs it is running in the Permian Basin above its previous plan and increased its production there by 93 per cent from the fourth quarter of 2017. Darren Woods, the company’s chief executive, said the company was planning to accelerate its investment further. Chevron said it had paused its program of adding more rigs but said its production growth was also running well ahead of its earlier expectations, rising by 70 per cent compared with 2017.
Permits Approved for Pipelines to Corpus Christi. A pair of pipelines to move crude oil and natural gas liquids from the Permian Basin to Corpus Christi has received their final federal permits. San Antonio pipeline operator EPIC Midstream Holdings LP announced on Wednesday that the company had obtained the final permits needs for the company’s crude oil and natural gas liquids pipelines. The U.S. Army Corps of Engineers issued a Nationwide Permit 12 for the projects, giving the company approval for final construction activities and placing the pipelines into service. The issuance of the Corps permit further demonstrates our ability to safely and responsibly build these two pipelines and I would like to thank all stakeholders involved in the approval process,” EPIC Midstream Holdings CEO Phil Mezey said in a statement. Already largely complete, the EPIC Y-Grade Pipeline is a 700-mile project to move natural gas liquids, or NGLs, from the Permian Basin of New Mexico and West Texas to a facility in Robstown. The 650-mile project will move crude oil and from seven terminals in the Permian Basin and Eagle Ford Shale of South Texas to a facility in Robstown.
Frac Sand Glut in TX. Just a year after rushing into America’s busiest oil field with new mines, frac-sand producers may have overdone it. West Texas sand used in the hydraulic fracturing process will drop 19% this year to about $30 a ton compared to 2018, according to industry consultant Rystad Energy AS. Sand pricing is a key financial input for oil explorers because fracing is the most expensive phase in drilling an oil well. A slew of new West Texas mines close to Permian Basin drilling sites are elbowing Midwest mines that formerly dominated the frac-sand trade. Miners in and around Wisconsin that controlled 75% of the market in 2014 will see that diminish to 34% in 2020, Ryan Carbrey, Rystad’s senior V.P. of shale research, told Petroleum Connection’s Frac Sand Industry Update conference in Houston on Wednesday. The sand oversupply has developed just as demand for fracing is taking a hit from the late-2018 slump in crude prices and more modest exploration programs by oil producers, Mulvehill said. Fracing demand is set to drop 3% in 2019, he said.
LNG to the Middle East. Exxon Mobil and Qatar Petroleum on Tuesday announced a final decision to finance a $10 billion-plus project to export liquefied natural gas from the Texas Gulf Coast. The decision moves forward the latest export terminal fueling growing shipments of U.S. LNG, or natural gas cooled to liquid form, for overseas travel. The Department of Energy last month forecast that LNG will play a major role in the U.S. exporting more energy than it imports by 2020, a feat the nation has not achieved in nearly 70 years. The plan to export LNG from Exxon’s Golden Pass terminal speaks to the renaissance in U.S. energy production. The facility was originally built to import LNG, but the surge in U.S. natural gas production over the last decade means American drillers are now looking overseas for buyers.
Trump Selects Oil Lobbyist for Interior Secretary. President Trump on Monday announced he would nominate David Bernhardt, a former oil lobbyist and current deputy chief of the Interior Department, to succeed Interior Secretary Ryan Zinke, who resigned amid allegations of ethical missteps. In a message on Twitter, Mr. Trump wrote, “David has done a fantastic job from the day he arrived, and we look forward to having his nomination officially confirmed!” While Mr. Zinke had been the public face of some of the largest rollbacks of public-land protections in the nation’s history, Mr. Bernhardt was the one quietly pulling the levers to carry them out, opening millions of acres of land and water to oil, gas and coal companies. He is described by allies and opponents alike as having played a crucial role in advancing what Mr. Trump has described as“energy dominance” agenda for the country. President Trump on Monday announced he would nominate David Bernhardt, a former oil lobbyist and current deputy chief of the Interior Department, to succeed Interior Secretary Ryan Zinke, who resigned amid allegations of ethical missteps. In a message on Twitter, Mr. Trump wrote, “David has done a fantastic job from the day he arrived, and we look forward to having his nomination officially confirmed!” While Mr. Zinke had been the public face of some of the largest rollbacks of public-land protections in the nation’s history, Mr. Bernhardt was the one quietly pulling the levers to carry them out, opening millions of acres of land and water to oil, gas and coal companies. He is described by allies and opponents alike as having played a crucial role in advancing what Mr. Trump has described as“energy dominance” agenda for the country.
Chinese Cyber Attack on Pipelines. Four words in the Senate testimony of Director of National Intelligence Dan Coats heightened the threat of a state-backed cyberattack on U.S. energy infrastructure. “China has the ability to launch cyberattacks that cause localized, temporary disruptive effects on critical infrastructure — such as disruption of a natural gas pipeline for days to weeks,” Coats told the Senate Intelligence Committee last Tuesday. The end of that sentence — “for days to weeks” — was an unusual warning by U.S. intelligence leadership that an adversary could cause an extended energy outage. Security experts and industry officials are pondering the implications of Coats’ message. Security alerts from the Department of Homeland Security have disclosed Chinese, Russian and other state-backed attempts to crack into energy systems, including warnings in 2014 about a Chinese campaign against U.S. gas pipelines and a 2017 Russian intrusion aimed at U.S. nuclear plants and other industry targets. U.S. officials gave conflicting reports last summer about how deeply the 2017 campaign penetrated U.S. power plants. Investigators ultimately reported that hackers had not taken enough control to cause widespread damage or put the electric grid at risk. Coats’ statement appears to change the threat picture, if taken literally, and that’s how it must be taken, one expert told E&E News.
Utica Midstream has Kenexis, a cybersecurity company, as its presenting sponsor. Jim McGlone, a certified cybersecurity professional, will identify the 5 major cybersecurity problems. I strongly urge to attend. www.uticasummit.com
SW PA Leads PA Shale Drilling. Southwestern Pennsylvania continued to grow its share of shale gas drilling in 2018, gaining 401 wells since Jan. 1, 2018. The 11-county region — Allegheny, Armstrong, Beaver, Butler, Clarion, Fayette, Greene, Indiana, Lawrence, Washington and Westmoreland — accounted for half of the 795 new wells added in Pennsylvania last year. Statewide, Susquehanna County added 180 wells last year, tops in the state. Greene county was next, with 116 and Washington County added 105 wells. Washington and Greene counties made up three-quarters of the new wells drilled in southwestern Pennsylvania. The most active operator for new wells in the ground in 2018 was Cabot Oil & Gas Corp., which operated entirely in Susquehanna County last year, adding 122 wells in the northeastern county. EQT Corp., the region’s most-active driller, has more than 1,300 wells in the region, and added 98 last year. Range Resources Corp. added 80 wells, to push its local well total to almost 1,250. Chevron Corp. and CNX Resources Corp. also added more than 50 wells in southwestern Pennsylvania last year.
FERC Gives National Fuel 3-Year extension on Northern Access Pipeline. National Fuel was granted a three-year deadline extension from the Federal Energy Regulatory Commission to complete a pipeline that would flow natural gas from the Marcellus Shale of northern Pennsylvania into Canada.
Ferc gave National Fuel until Feb. 3, 2022, to finish the Northern Access Pipeline, Kallanish Energy reports. The project has been on the drawing board for five years.
“A three-year extension of time is necessary because applicants do not anticipate commencement of project construction until early 2021, due to New York’s continued legal actions and to time lines required for procurement of necessary pipe and compressor facility materials,” according to last week’s letter from Richard W. Foley, a branch chief in Ferc’s Division of Pipeline Certificates.
National Fuel spokeswoman Karen L. Merkel told The Buffalo News newspaper the letter is “yet another step in the right direction.”
Connecting under the Niagara River
The 97-mile route would run through Allegany, Cattaraugus and Erie counties and also includes two miles of extensions of existing pipelines in Niagara County, New York.
Merkel told the News the goal is to connect to a Canadian pipeline under the Niagara River, to feed the gas into the North American Pipeline Grid serving Canada and the northeast U.S.
Ferc approved the project in February 2017, despite opposition from environmentalists and some residents in towns along the route, and the agency gave the company two years to finish the work. That deadline would have expired Feb. 3.
DEC denies water permit
The New York State Department of Environmental Conservation (DEC) has blocked the project by denying National Fuel a water quality certificate needed to build the pipeline across Western New York streams.
But last August, Ferc ruled the DEC missed a deadline to act on the water quality certificate, making the denial invalid as far as Ferc is concerned.
National Fuel CEO Ronald J. Tanski told Wall Street analysts during a quarterly earnings call last Friday he was encouraged by a recent ruling by the federal Court of Appeals in the District of Columbia (in an unrelated case) that state agencies aren’t allowed to take more than a year to process a water quality certificate.
“We’re hoping that this recent federal court decision will allow Ferc to quickly dismiss New York’s rehearing request on Ferc’s most recent authorization for our project,” Tanski said, the News reported.
Atlantic Coast Pipeline Serviced Delayed Until 2011. Dominion Energy reported last week the Atlantic Coast natural gas pipeline (Acp) will be delayed going into service due to continuing environmental lawsuits and permitting problems and that the price tag for the project has increased, Kallanish Energy reports.
The company said the completion date for the pipeline is early 2021, although partial service could begin in late 2020. The cost will be between $7.0 billion and $7.5 billion, excluding financing. It had previously estimated the pipeline’s cost at between $6.5 billion and $7.0 billion, excluding financing.
Dominion said it currently expects the now-halted construction could begin again on the pipeline’s full route in the third quarter of 2019. The 600-mile pipeline had originally been slated to begin service in late 2019. Construction started in the spring of 2018.
“We remain highly confident in the successful and timely resolution of all outstanding permit issues, as well as the ultimate completion of the entire project,” said Dominion Energy chairman, president and CEO Thomas F. Farrell II, in a statement.
“We are actively pursuing multiple paths to resolve all outstanding issues, including judicial, legislative and administrative avenues. We … expect ACP to contribute to our operating earnings in 2019, 2020 and for decades to come,” he said.
The pipeline would run from West Virginia into southern Virginia. There are new plans to expand it south into North Carolina.
The Virginia-based 4th U.S. Circuit Court of Appeals has vacated required permits for the pipeline project and legal hearings are continuing.
The pipeline is designed to move 1.5 billion cubic feet per day (Bcf/d) of natural gas from the Marcellus and Utica shales through West Virginia and Virginia to the Carolinas.
In related news, Dominion Energy said the 38-mile Supply Header project in West Virginia and western Pennsylvania, designed to feed gas to the Acp, will begin service in late 2020 at a cost between $650 million and $700 million.
Earlier, the company had said that the Supply Header would cost around $500 million and begin service in late 2019.
More Hope for Northern Access Pipeline. Another glimmer of hope emerged on Tuesday for the long-stalled Northern Access natural gas pipeline expansion as the U.S. Court of Appeals for the Second Circuit vacated New York’s denial of a key permit that completely halted work on the Appalachian project two years ago. The appeals court chose not to weigh in on a variety of factors in the case, but said the decision by the New York State Department of Environmental Conservation (DEC) to deny a water quality certification (WQC) for the National Fuel Gas Co. (NFG) project was baseless. The court remanded the case to the DEC to further explain why the WQC was denied. “Although this is a close case, the denial letter here insufficiently explains any rational connection between facts found and choices made,” the court said. “Specifically, there are no record citations in the denial letter, and there are no citations to specific projects or studies the department may have considered.” After nearly three years of regulatory review, DEC emailed NFG a 13-page letter before midnight on April 7, 2017, noting that the plan to construct 71 miles of pipeline in the state failed to meet water quality standards and would negatively impact the environment. NFG has been fighting the decision ever since. The decision has made it difficult for exploration and production subsidiary Seneca Resources Corp. to develop and move gas from northwestern Pennsylvania.
PA Permits January 31, to February 7, 2019
County Township E&P Companies
- Bradford Wilmot Chesapeake
- Greene Jefferson Chevron
- Greene Jefferson Chevron
- Greene Richhill CNX
- Greene Richhill CNX
- Greene Richhill CNX
- Indiana North Mahoning CNX
- Susquehanna Lenox Cabot
- Susquehanna Lenox Cabot
- Susquehanna Lenox Cabot
- Susquehanna Lenox Cabot
- Susquehanna Lenox Cabot
- Susquehanna Lenox Cabot
OH Permits for weeks of February 2, 2019
County Township E&P Companies
- Guernsey Londonderry Ascent
Joe Barone moc.s1566672591eirot1566672591cerid1566672591elahs1566672591@enor1566672591abj1566672591 610.764.1232