Latest facts and a rumor from the Marcellus, Utica, Permian, Eagle Ford, and Bakken Shale Plays
EQT Response to Rice Brothers Challenge. Jan 22 (Reuters) – EQT Corp’s production guidance for 2019 and a plan for increased focus on generating cash flow drew a rebuke from founders of the company it merged with 15 months ago, who said they would challenge the energy firm’s board in an upcoming shareholder ballot.
Pittsburgh-based EQT became one of the largest gas-focused U.S. producers when it completed its tie-up with Rice Energy in November 2017.
Despite its new scale, EQT’s share price has lagged since the merger – a situation which spurred in December two of Rice Energy’s founders, Toby and Derek Rice, to call for changes.
In response, EQT said it would focus on generating free cash flow that could be returned to shareholders, with EQT Chief Executive Robert McNally telling Reuters it was “highly likely” it would seek to buy back shares in the “near term.”
Shareholder reaction to the plan was broadly negative, with EQT shares ending 5.5 percent lower.
The sentiment was matched by the two Rice brothers, who said in a statement that EQT’s plan “does not address the fundamental concerns being raised”, and they will ask shareholders to replace board members and install Toby Rice as CEO.
A spokeswoman for EQT did not respond to a request for comment on the Rice statement.
However, according to a letter sent to the brothers, seen by Reuters, the EQT board said while it was “open-minded” to new ideas and adding management expertise, it questioned the “experience and suitability” of the brothers to be appointed CEO and to the board.
DIFFERENCE
The core schism is over how the company develops its assets: the Rice brothers insist EQT’s poor stock performance since the merger has been because the current management has not fulfilled the firm’s potential, while EQT insist the siblings’ projections are inflated and based on outdated market conditions.
Under its plan, EQT expects to generate around $2.7 billion of accumulated adjusted free cash flow over the next five years. Adjusted free cash flow in 2019 was expected to be $350 million.
Aiding cash flow generation would be $100 million of cost savings, an initiative to trim a further 10 percent of costs across its development program, as well as an up-to-21 percent decline in forecasted capital expenditure this year versus 2018.
The company also plans to sell its 19.9 percent stake in Equitrans Midstream Corp, the pipelines business that EQT spun out in November.
The Rice brothers have insisted they can generate an additional $400 million to $600 million pre-tax free cash flow per year under their plan – which has attracted the support of top-ten shareholder D. E. Shaw Group.
A spokesman for D. E. Shaw did not immediately respond to a request for comment.
Trump Looking to Take Steps to Limit States’ Power to Block Pipelines. The Trump administration is considering taking steps to limit the ability of states to block interstate gas pipelines and other energy projects, according to three people familiar with the deliberations. The effort, possibly through an executive order, is aimed chiefly at states in the Northeast U.S., where opposition to pipeline projects has helped prevent abundant shale gas in Pennsylvania and Ohio from reaching consumers in New York and other cities. New York used a Clean Water Act provision to effectively block the construction of a natural gas pipeline being developed by Williams Partners LP to carry Marcellus shale gas 124 miles to New England. The project got the green light from the Federal Energy Regulatory Commission but then ran into obstacles in New York, where regulators denied a water quality permit. The effort dovetails with expectations that President Donald Trump would use his State of the Union address to tout efforts to accelerate permitting and construction of oil and gas pipelines, though he has postponed the speech and the exact timing of any announcement remains unclear.
US Supreme Court Rejects Landowners Challenge to Mountain Valley. The US Supreme Court on Tuesday refused to hear a constitutional challenge by landowners affected by the construction of the Mountain Valley Pipeline to the Federal Energy Regulatory Commission’s procedures for reviewing the Appalachian Basin natural gas takeaway project.
The approximately 300-mile pipeline is being designed to deliver 2 Bcf/d of gas to markets in Virginia and North Carolina, and it is seen as a key conduit for allowing more Marcellus shale supplies to be used for power generation and LNG exports.
Even with the high court’s decision to deny certiorari — an order granting review of a decision by a lower court — the EQM Midstream Partners-operated project still faces significant opposition from environmental and public advocacy groups, including battles over water crossings and water permits.
A federal appeals court previously vacated the project’s US Army Corps of Engineers permit, and Virginia’s State Water Control Board has voted to hold a hearing to consider revoking the Clean Water Act Section 401 permit for the project.
Spokeswoman Natalie Cox said in an email responding to questions that the operator continues to target full in-service in fourth-quarter 2019. She declined to comment on the high court’s decision, which was made without comment.
The litigation targeted the way eminent domain use has evolved in a deregulated gas market to take private property for pipeline development. Specifically, the case related to FERC’s certificate order for Mountain Valley Pipeline and whether landowners subject to property condemnation had adequate opportunity for judicial review.
Record PA Impact Fees. Pennsylvania’s impact fee on shale gas wells is expected to raise a record $247 million this year, driven in part by the anticipated receipt of millions of dollars in past fees that the state plans to collect after winning a state Supreme Court case last month. The state’s Independent Fiscal Office released a report Thursday projecting that this year’s payments, due in April, will be $37.4 million more than last year’s collection. More than $22 million of the revenue bump is expected to come from outstanding payments — including from companies that contended they owned so-called “stripper wells” that produced too little gas in some months to have to pay the fee in 2017. The state Supreme Court ruled in late December that wells that produce more than 90,000 cubic feet of natural gas in just one month of a year must pay the impact fee, reversing a lower court order from 2017 that said wells only had to pay the fee if they produced that volume every month of a year.
Encino Energy Is Hiring. Encino is growing! It’s committed to hiring the best and brightest individuals, to working in a safe manner and respecting our environment, and to delivering superior results while serving in the communities where we live and work. There are a number of job openings in Ohio and Texas.
To get information on these job opening click:
http://www.encinoenergy.com/careers
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Los Alamos National Labs Helps Fracking Become More Profitable. (Thank you, MDN). Can math help us be better frackers? Researchers at the Los Alamos National Laboratory certainly think so. Researchers have developed a new mathematical model that better predicts previously hidden fractures that can potentially boost efficiencies and profits in natural gas production.
Knowing more about those tiny fractures and the patterns they make helps drillers optimize pumping, fracturing-fluid viscosity, and other parameters. A new research paper titled, “Branching of hydraulic cracks enabling permeability of gas or oil shale with closed natural fractures,” was recently published in the in the Proceedings of the National Academy of Sciences. Sorry, we don’t have a full copy of the paper (which is mostly math and science stuff most of us don’t understand anyway).
We do, however, have a good summary of the research from LANL, and a copy of the paper’s abstract.
LANL released the following announcement touting the new study:
A new computational model could potentially boost efficiencies and profits in natural gas production by better predicting previously hidden fracture mechanics. It also accurately accounts for the known amounts of gas released during the process.
“Our model is far more realistic than current models and software used in the industry,” said Zden Bažant, McCormick Institute Professor and Walter P. Murphy Professor of Civil and Environmental Engineering, Mechanical Engineering, and Materials Science and Engineering at Northwestern’s McCormick School of Engineering. “This model could help the industry increase efficiency, decrease cost, and become more profitable.”
Despite the industry’s growth, much of the fracking process remains mysterious. Because fracking happens deep underground, researchers cannot observe the fracture mechanism of how the gas is released from the shale.
“This work offers improved predictive capability that enables better control of production while reducing the environmental footprint by using less fracturing fluid,” said Hari Viswanathan, computational geoscientist at Los Alamos National Laboratory. “It should make it possible to optimize various parameters such as pumping rates and cycles, changes of fracturing fluid properties such as viscosity, etc. This could lead to a greater percentage of gas extraction from the deep shale strata, which currently stands at about 5 percent and rarely exceeds 15 percent.”
By considering the closure of preexisting fractures caused by tectonic events in the distant past and taking into account water seepage forces not previously considered, researchers from Northwestern Engineering and Los Alamos have developed a new mathematical and computational model that shows how branches form off vertical cracks during the fracking process, allowing more natural gas to be released. The model is the first to predict this branching while being consistent with the known amount of gas released from the shale during this process. The new model could potentially increase the industry’s efficiency.
The results were published in the Proceedings of the National Academy of Sciences on Jan. 11, in a paper titled “Branching of Hydraulic Cracks in Gas or Oil Shale with Closed Natural Fractures: How to Master Permeability.”
Understanding just how the shale fractures form could also improve management of sequestration, where wastewater from the process is pumped back underground.
To extract natural gas through fracking, a hole is drilled down to the shale layer—often several kilometers beneath the surface—then the drill is extended horizontally, for miles. When water with additives is pumped down into the layer under high pressure, it creates cracks in the shale, releasing natural gas from its pores of nanometer dimensions.
Classic fracture mechanics research predicts that those cracks, which run vertically from the horizontal bore, should have no branches. But these cracks alone cannot account for the quantity of gas released during the process. In fact, the gas production rate is about 10,000 times higher than calculated from the permeability measured on extracted shale cores in the laboratory.
Other researchers previously hypothesized the hydraulic cracks connected with pre-existing cracks in the shale, making it more permeable.
But Bažant and his fellow researchers found that these tectonically produced cracks, which are about 100 million years old, must have been closed by the viscous flow of shale under stress.
Instead, Bažant and his colleagues hypothesized that the shale layer had weak layers of microcracks along the now-closed cracks, and it must have been these layers that caused branches to form off the main crack. Unlike previous studies, they also took into account the seepage forces during diffusion of water into porous shale.
When they developed a simulation of the process using this new idea of weak layers, along with the calculation of all the seepage forces, they found the results matched those found in reality.
“We show, for the first time, that cracks can branch out laterally, which would not be possible if the shale were not porous,” Bažant said.
After establishing these basic principles, researchers hope to model this process on a larger scale.
This research was funded by the Laboratory Directed Research and Development program at Los Alamos National Laboratory, and the collaborating team at Los Alamos was funded by the U. S. Department of Energy’s Office of Science. Other authors of the paper include Saeed Rahimi-Aghdam, Hyunjin Lee, Weixin Li, and Hoang Nguyen of Northwestern, and Viet-Tuan Chau, Satish Karra, Esteban Rougier, Hari Viswanathan, and Gowri Srinivasan of Los Alamos National Laboratory. (1)
The paper’s statement of significance and abstract:
Significance
Development of a realistic model of fracking would allow better control. It should make it possible to optimize various parameters such as the history of pumping, its rate or cycles, changes of viscosity, etc. This could lead to an increase of the percentage of gas extraction from the deep shale strata, which currently stands at about 5% and rarely exceeds 15%.
Abstract
While hydraulic fracturing technology, aka fracking (or fracing, frac), has become highly developed and astonishingly successful, a consistent formulation of the associated fracture mechanics that would not conflict with some observations is still unavailable. It is attempted here. Classical fracture mechanics, as well as current commercial software, predict vertical cracks to propagate without branching from the perforations of the horizontal well casing, which are typically spaced at 10 m or more. However, to explain the gas production rate at the wellhead, the crack spacing would have to be only about 0.1 m, which would increase the overall gas permeability of shale mass about 10,000×. This permeability increase has generally been attributed to a preexisting system of orthogonal natural cracks, whose spacing is about 0.1 m. However, their average age is about 100 million years, and a recent analysis indicated that these cracks must have been completely closed by secondary creep of shale in less than a million years. Here it is considered that the tectonic events that produced the natural cracks in shale must have also created weak layers with nanocracking or microcracking damage. It is numerically demonstrated that seepage forces and a greatly enhanced permeability along the weak layers, with a greatly increased transverse Biot coefficient, must cause the fracking to engender lateral branching and the opening of hydraulic cracks along the weak layers, even if these cracks are initially almost closed. A finite element crack band model, based on a recently developed anisotropic spherocylindrical microplane constitutive law, demonstrates these findings.
Could Trump Kill WV $84 Billion Investment from China Energy? West Virginia may personify the trade war with China — a state with $84 billion on the line and money that would transform the area. State officials and economic developers are working hard behind the scenes. But they are hampered by something completely out of their hands — the actions taken by Donald Trump to start levying tariffs on certain goods coming out of China.
In November 2017, China Energy Investment Corp. signed a non-binding trade agreement with the state of West Virginia that would pump billions into its economy. In return, China would get access to the plethora of shale gas that rest below the state’s land, all to feed its own chemical and manufacturing base.
Without knowing what’s actually inside the “contract” between the two entities, it is potentially a win-win deal. The “wet gas” that is separated from the “dry gas” is used as a feedstock for industry: methane, butane, ethane and propane — components of everything we touch. In fact, the abundance of shale gas has prompted industry from all over the world to locate to the United States.
“The Chinese are right at our doorsteps,” West Virginia Governor Jim Justice said at a press event. “As are the people from Qatar. As are other foreign investments coupled with U.S. investment. They are truly friends. But they are working through this tariff stuff and trade imbalance. They can’t pull the trigger until this done. It will be settled. We will not get in an all-out trade war with China.”
Some context: West Virginia’s gross economic output is about $75 billion a year and its coal business has lost ground to more competitive and cleaner electric generation fuels. Consider that the coal industry there had employed 70,000 miners in the 1970s and 13,000 miners are employed today. Right now, blue chip oil and gas companies are doing business in the state and include Chesapeake Energy, Equitable Resources, Marathon Oil, Range Resources and Williams Co. China Energy’s investment, though, would top them all.
Energy Department Says Record Production of NatGas to Continue Through 2020. The U.S. natural gas market will continue full speed ahead through 2020, delivering low prices and booming exports, the Energy Department predicts in its Short-Term Energy Outlook. Planned capacity additions for natural gas will continue to replace coal-fired plants coming offline in 2019. Natural gas will continue as the primary source of U.S. electricity, the report states, increasing from 35 percent of domestic electricity generation in 2018 to 37 percent by 2020. Coal-fired electricity is expected to fall to 24 percent of generation by 2020. The U.S. is expected to continue to be a net exporter of natural gas as production outpaces domestic consumption. The increase in exports will be driven by additional liquefied natural gas capacity additions at the Cameron LNG and Freeport LNG facilities along the Gulf Coast, the report states.
Saudi’s Looking for NatGas Investments in the US. Saudi Arabia is looking to invest in U.S. natural gas. The Kingdom is considering Tellurian’s proposed Driftwood LNG export terminal in Louisiana and Sempra Energy’s Port Arthur LNG facility in Texas. For example, Tellurian seeks equity partners who would buy stakes in Driftwood and receive LNG that they could use themselves or resell at a markup. And why wouldn’t oil titan Saudi Arabia be interested in U.S. LNG? Really just starting exports in February 2016, the U.S. will become the third largest LNG exporter this year, after Qatar and Australia. We have recently set records with over 5 Bcf/d of LNG feedgas demand, and we could become the number one exporter within five years. The potential for U.S. LNG exports is simply staggering. As of December, FERC has 70 outstanding LNG export terminal applications awaiting review, potentially having a mind blowing 55 Bcf/d of export capacity (note: the global LNG market is only 40-43 Bcf/d, so obviously not all of this will come online). Further, the Saudis are looking to acquire U.S. natural gas assets, ready to spend “billions of dollars” here. NOTE: CNBC also report.
Boost in CAPEX Spending in 2019. The majority of senior energy industry executives expect to maintain or increase spending this year to meet demand for oil and gas after years of austerity, a survey by DNV GL shows. DNV, a technical adviser to the energy industry, surveyed 791 senior professionals from firms with annual revenue ranging from $500 million or less to those earning $5 billion and more, Reuters reported. BP, Shell and many other companies cut capital spending and costs in 2016 after the price of benchmark Brent crude fell to a 12-year low of below $30 a barrel. Helped by output cuts by the Organization of the Petroleum Exporting Countries and its allies, Brent climbed to an average price of $70 last year compared to $50 for the period 2015 to 2017. It was trading above $62 a barrel on Monday. DNV’s annual outlook of the global oil and gas industry showed 70 % of respondents planned to maintain or increase capital spending in 2019, compared to 39% in 2017. Those expecting to sustain or increase operating expenditure also grew to 65% in 2019 from 41% in 2017. In addition, 67% believed more large, capital-intensive oil and gas projects would be approved this year. “Despite greater oil price volatility in recent months, our research shows that the sector appears confident in its ability to better cope with market instability and long-term lower oil and gas prices,” said Liv Hovem, who heads DNV’s oil and gas division.
Chevron CEO Bullish on Global Economy. The global economy may be losing momentum, but energy and industrial products sales don’t show growth will stop, according to Chevron chairman and CEO Michael Wirth.
Financial markets are under pressure this week following new signs of a slowing economy, Kallanish Energy reports. Tuesday, the IMF lowered its forecast for global economic growth. A day earlier, China reported its weakest annual economic expansion in 28 years.
Wirth told CNBC the slowdown concerns him because small changes to demand can shove the oil market into oversupply or deficit, resulting in volatile prices.
However, he doesn’t see major problems yet. “We’re not seeing signs that we’re hitting any kind of a wall. Things may have slowed down a little bit in certain parts of the world,” he said in an interview at the World Economic Forum in Davos, Switzerland Wednesday.
A day earlier, BP CEO Bob Dudley told CNBC he expects growth in oil demand this year, despite concerns about the global economy.
Oil prices are currently recovering from a drop to 18-month lows in the final quarter of 2018. The plunge came after a rapid rise to nearly four-year in early October.
Asked where he’d like crude prices to be, Wirth said what he really wants is oil market stability. “Commodity markets, when they’re volatile, make it hard for investors to invest. It’s hard on consumers, and so you really need a price that encourages investment and draws in enough new investment, but is not so high that it weighs on the economy,” he told CNBC. “We’re probably not far from that kind of a price right now.”
International benchmark Brent crude oil futures fell 35 cents, or roughly 0.5%, to $61.15 per barrel around 2:30 p.m. ET Wednesday. U.S. West Texas Intermediate crude futures ended Wednesday’s session down 39 cents, or about 0.75%, to $52.62/Bbl.
Halliburton’s 4th Qtr. Financial Update. Halliburton has announced fourth-quarter income from continuing operations of $664 million, up from $435 million in 2018’s third quarter, Kallanish Energy reports.
Adjusted income from continuing operations for Q4 2018, excluding a tax benefit related to a strategic change in corporate structure, was $358 million. Halliburton’s total revenue in Q4 was $5.9 billion, a 4% drop from revenue of $6.2 billion in Q3.
Operating income was $608 million in the 4Q, a 15% drop compared to operating income of $716 million in the previous quarter.
Total revenue for full-year 2018 was $24 billion, an increase of $3.4 billion, or 16%, from 2017, the Houston-based company reported. Reported operating income for 2018 was $2.5 billion, compared to $1.4 billion for 2017.
“I am pleased with our overall financial results for the year and for the fourth quarter. Our team optimized our performance in North America as the market softened and the recovery of our international business continued,” said chairman, president and CEO Jeff Miller, in a statement.
“The trajectory of this cycle has been far from smooth. As expected, in North America, the demand for completion services decreased during the fourth quarter, leading to lower pricing for hydraulic fracturing services.
“Our international business continues to show signs of a steady recovery, with revenue increasing 7% sequentially, underscoring the versatility and global reach of our business portfolio,” he said.
Halliburton intends to “dynamically respond to the changing market environment, reduce capital spending, develop differentiating technologies and generate strong cash flow,” Miller said.
The company said North American revenue in Q4 was $3.3 billion, an 11% decrease from Q3. The decrease was primarily driven by lower activity and pricing in stimulation services, partially offset by higher fluids activity in the Gulf of Mexico, it said.
Completion and production revenue in Q4 was $3.8 billion, a drop of $338 million, or 8%, from Q3, and operating income was $96 million, a sequential drop of $117 million, or 19%, Halliburton said. That was due largely to lower activity and pricing from stimulation services in North America.
LNG Challenges in 2019. (Thank you, BTU Analytics) With Train 2 of Cheniere’s Corpus Christi LNG facility in the midst of commissioning and deliveries to the facility expected to ramp shortly, LNG exports are further cemented as a core of the US’ natural gas demand mix. Going forward, this trend will only continue. For example, if facilities under construction hit their current in-service dates, then the US will get to about 9 Bcf/d of LNG export capacity and feed gas for those new facilities will make up more than 65% of the US’ structural natural gas demand growth in 2019. With so much demand concentrated mostly on the Louisiana and Texas Gulf Coast, an influx of feed gas and supporting infrastructure will change historic pricing dynamics along the Gulf Coast.
With the growth of LNG feed gas targeting the Gulf Coast, as shown in the graphic below, and more on the way, combined with the impact of new infrastructure out of the Northeast and Permian, BTU has expanded our coverage of natural gas basis analysis and forecasts with the Gas Basis Outlook to more fully capture the changing pricing dynamics in North America.
To further highlight these emerging challenges for the gas market we will be hosting a complementary webinar on February 5th.
Beyond Gulf Coast LNG demand pulling incremental molecules down to the Gulf, other markets have been inundated with low cost supply that have put, and continue to put, downward pressure on pricing. While the US added 10 Bcf/d of production year-over-year, the biggest culprit for providing downward pricing pressure has been the Permian, which, in 2018, added almost 2.5 Bcf/d associated gas supply that is driven by liquids economics rather than gas pricing.
To date, western basis has most noticeably felt the brunt of expanding Permian pressure with CIG basis averaging $0.60/MMBtu back in 2018 compared to about $0.30/MMBtu in 2017. However, an outlet for this gas is expected to arrive in 2019 in the form of Kinder Morgan’s 2 Bcf/d Gulf Coast Express, which will provide some (short-lived) relief to Rockies’ and Permian pricing, while transferring pressure towards Agua Dulce and the Texas Gulf Coast.
Not to be outdone, the Northeast has also gone through its own infrastructure transformation in 2018, with major greenfield projects, Rover, NEXUS, and Atlantic Sunrise either ramping up or commencing service as shown in the graphic below.
Atlantic Sunrise capacity moves molecules down the Atlantic Seaboard into the Southeast, while Rover and NEXUS capacity mostly target Upper Midwest markets. With most of the ramp-up in flows taking place in the fourth quarter, the full effects of this new capacity have been masked by winter heating demand. However, when winter ebbs, expect molecules to do their best to make their way down to the Gulf towards growing LNG demand contributing to further congestion along the Gulf Coast, Perryville, and Carthage.
This confluence of molecules, either directly or indirectly, making their way down to the Gulf Coast, combined with the pull of new LNG demand coming online, set the scene for an interesting 2019. Sign up for our free webinar to see what we are watching for in 2019.
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