AuthorTopic: Hills Group Oil Depletion Economic and Thermodynamic Report  (Read 59445 times)

Offline BuddyJ

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Re: Hills Group Oil Depletion Economic and Thermodynamic Report
« Reply #240 on: September 25, 2019, 04:06:19 AM »
A fine detailing of just another one of the mechanisms that is likely to be involved in peak demand. It isn't as though the big think tanks have been calling for a peak demand scenario for the fun of it.

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🛢️ Europe’s Gas Demand Soars As Dutch Giant Folds
« Reply #241 on: October 03, 2019, 04:43:31 AM »
https://oilprice.com/Energy/Natural-Gas/Europes-Gas-Demand-Soars-As-Dutch-Giant-Folds.html

Europe’s Gas Demand Soars As Dutch Giant Folds


Europe’s energy landscape will be completely changed once the Dutch shut down the largest gas field on the continent years ahead of schedule, according to Rystad Energy.

The Netherlands recently announced that production at Groningen – Europe’s largest gas field – will be halted in 2022, eight years earlier than initially planned. However, despite the ambitious target of decommissioning the field by 2022, Rystad Energy expects that there could be some residual production from Groningen up to 2030 as it is technically challenging to completely shut down production in such a short timeframe.

The drastic drop in output from Groningen will redefine the European energy landscape. The field, which had a rebound in production at the start of this century, reaching 57 billion cubic meters (Bcm) in 2013, was for decades the central cog in northwest Europe’s gas system.

“The phase-out of this giant field will force Europe to expand its gas imports at an even quicker pace. We can already see this drastic shift taking place in the Netherlands, which is in the midst of the transition from being a net gas exporter to a net importer,” says Carlos Torres-Diaz, head of gas markets research at Rystad Energy.


In Europe, more supply from alternative sources will be needed as domestic production declines and demand continues to increase. The continent has ambitious plans to decommission coal and nuclear power generation, and this could lead to higher gas demand, especially in the medium term. Renewable energy sources should replace some of the lost power capacity, but due to the low capacity factors of these technologies and their intermittency, the power system will rely strongly on gas power to provide security of supply. Consequently, Rystad Energy forecasts that gas-for-power demand in Europe will continue to increase until 2025 and then gradually decrease as renewables gain momentum.

The Netherlands has formally set an ambitious goal that 83% of total power generation is to be sourced from solar and wind by 2040. Such a transition to renewables means that the need for gas-power could reach a peak in 2020 and start a gradual decline earlier than in the rest of Europe. This will lead to a 32% drop in total gas demand in the country over the next two decades, from around 37 Bcm in 2019 to 25 Bcm by 2040.
Related: OPEC Chief Invites All 97 Oil Producers To Join OPEC+ Coalition

“More pipeline and LNG imports will be needed in the Netherlands to replace declining production from Groningen. Dutch exports to neighboring countries are also expected to drop making the whole region more dependent on LNG imports to meet its demand,” Torres-Diaz added.


Rystad Energy expects the global market for LNG to remain oversupplied over the next two years and then tighten after 2023.

“We remain optimistic about the potential for global growth in demand driven by Asia in the long term and forecast total LNG demand to reach 604 million tonnes per annum (tpa) by 2030. That means 175 million tpa of new supply is needed to meet demand by 2030,” Torres-Diaz remarked.

Turning to the global market for natural gas, Rystad Energy forecasts global supply will reach 4660 Bcm by 2030. The additions are driven by North America, the Middle East and Russia.


“Since our last forecast in June 2019, we have increased our base supply outlook by around 50 Bcm for 2030, driven by increased supply potential from the US and Russia” Torres-Diaz said.

Traditional gas suppliers, such as Indonesia, Norway and the Netherlands, are facing production declines due to maturing fields and the production cap at Groningen in the Netherlands.

By Rystad Energy
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https://oilprice.com/Energy/Energy-General/Replacement-Rate-Hits-20-Year-Low-Oil-Industry-Only-Replace-1-In-6-Barrels.html

Replacement Rate Hits 20-Year Low: Oil Industry Only Replace 1 In 6 Barrels


Oil and gas companies have discovered 7.7 billion barrels of oil equivalent (boe) year-to-date, according to Rystad Energy’s latest global discoveries report.

“The industry is well on track to repeat the feat achieved in 2018 when around 10 billion boe of recoverable resources were discovered,” says Palzor Shenga, senior analyst on Rystad Energy’s upstream team.

(Click to enlarge)

Russia has seen the most discovered resources thus far in 2019, with the Dinkov and Nyarmeyskoye discovery announced earlier this year holding around 1.5 billion boe of recoverable resources. Guyana and Cyprus nab the other places on the podium.

(Click to enlarge)

The so-called resource replacement ratio for conventional resources now stands around 16%, which is the lowest seen in recent history.

“This means that only one barrel out of every six consumed is being replaced by new sources. This is the lowest replacement ratio we have witnessed in the last two decades,” Shenga added.

(Click to enlarge)

However, the industry has high hopes after the prolific success of ExxonMobil’s Stabroek block off the coast of Guyana and more recent discoveries by other operators in the region, which have led to a surge in offshore exploration in the Caribbean. More acreage is being made available for bidding, with some countries conducting their first-ever licensing rounds in 2019 and 2020.
Related: Banks See Oil Prices Staying Low Despite Attacks On Saudi Oil

Offshore drilling activity has been on a steady rise in recent years, with 23 new exploration wells expected in 2019. By comparison, only seven offshore wells were drilled in 2013.

“We estimate the annual number of wells drilled could increase slightly to 25 wells in 2020, as more operators join the Caribbean exploration circuit,” says Santosh Kumar, an exploration analyst on the upstream team.

Rystad Energy expects the Guyana-Suriname basin will continue to occupy headlines with a few planned wells in both Guyana and Suriname. The basin is pinned as one of the most prospective, underexplored basins in the world and will definitely get a facelift from its current assigned volumes if hydrocarbons are established towards the east.

“Explorers have set their sights on establishing a working petroleum system and unlocking the underlying commercial prospectively of the basin. The latest update suggests that the basin could have a potential of around 13 billion boe,” Shenga said.

A wildcat exploration campaign led by Apache is currently underway in Guyana’s eastern neighbor, Suriname. Prior to this only 14 wells have been drilled in the Guyana-Suriname basin beyond water depths greater than 20 meters.

By Rystad Energy
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🛢️ A Draconian Crackdown Looms Over Natural Gas
« Reply #243 on: October 17, 2019, 12:00:22 AM »
When the Big Banks stop issuing debt on this investment, it's dead.

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https://oilprice.com/Energy/Energy-General/A-Draconian-Crackdown-Looms-Over-Natural-Gas.html

A Draconian Crackdown Looms Over Natural Gas
By Nick Cunningham - Oct 16, 2019, 3:30 PM CDT


The natural gas industry is reeling as the political climate begins to shift against the industry faster and earlier than many expected.

“If large institutional financial banks stop funding fossil fuel companies, that's going to be a real challenge,” Charlie Riedl, executive director of industry trade group Center for Liquefied Natural Gas, said this week at the Gulf Coast Energy Forum in New Orleans, according to S&P Global Platts. “That's a conversation we have to have. If natural gas becomes the next coal, that's going to be a real challenge.”

The coal industry has been battered by all sides over the past decade, crushed by the surge of shale gas itself and by renewable energy, but also squeezed by a shrinking pool of capital as banks and insurers cut off finance. For instance, on Wednesday, insurer Axis Capital announced that it would restrict insurance to both coal and tar sands oil.

To date, the gas industry, although having been under fire from environmental groups for years, has been spared the draconian crackdown by both capital markets and regulatory action. In fact, Big Oil has made a massive bet on natural gas as the future, which oil executives view as a hedge against peak oil demand.

But the political winds are shifting quickly. Earlier this year, Berkeley, California became the first U.S. city to ban new natural gas hookups in new buildings. Menlo Park and Windsor soon followed, and dozens of other cities are exploring similar prohibitions.

Some Democratic presidential candidates have vowed to ban fracking if elected.
Related: Oil Prices Jump On A Lone Piece Of Bullish News

The industry risks losing its social license to operate. Record levels of gas flaring in Texas is surely not helping matters.

Charlie Riedl of the Center of Liquefied Natural Gas told S&P Global Platts that the industry has to do more to slash emissions.

It’s notable that the reference to gas becoming the new coal has been uttered by several industry executives in the past few weeks. “The industry really is at a critical juncture,” Woodside Petroleum CEO Peter Coleman said at a recent conference in Houston. “We run the risk of being demonized like that other fossil fuel out there called coal.”

For the oil industry, this is very much an existential problem. Many large oil companies are massive gas producers as well, and their portfolios are trending in a more gas-heavy direction.

Judging by BP’s recent PR blitz, they appear worried about the direction that the conversation on gas is taking.

BP’s CEO Bob Dudley said that Michael Bloomberg’s $500 million campaign to kill off natural gas-fired power plants is “irresponsible.”

“Every scenario I look at, we cannot carpet the world with renewables fast enough,” Dudley told CNBC.

Dudley’s counterpart at Shell also doubled down this week, calling the “demonization” of oil and gas “unjustified.” Shell has gone to great lengths to cast its business as one in transition, and last year the company announced that it would tie executive pay to reductions in greenhouse gas emissions.

By some measures, Shell is ahead of its peers. But that is a low bar to clear. The amount of money spent on clean energy by the oil majors is a pittance. ExxonMobil, for instance, spent a tiny fraction of 1 percent of its overall spending on low-carbon technologies between 2010 and 2018.

Shell’s CEO Ben van Beurden has struck a more conciliatory tone than his American competitors. “Things that we did 10 years ago, and everybody thought was entirely appropriate, correct, and ethical, maybe in today’s value sets [people will] say, ‘How could you do that’?” van Beurden told the FT in an interview last month.

But his patience seemed a little more worn out in an interview with Reuters this week. “Despite what a lot of activists say, it is entirely legitimate to invest in oil and gas because the world demands it,” van Beurden said. “We have no choice” but to continue to spend on long-term oil and gas projects, he added. Reuters noted that the Anglo-Dutch oil giant has plans to give final investment decisions on more than 35 new oil and gas projects by 2025.
Related: What’s Behind The Bearish Bias In Oil Markets?

A September report from Carbon Tracker found that the oil majors funneled $50 billion into projects that are not aligned with the Paris Climate Agreement. Those investments were made since just last year. In other words, the industry is betting on, and very much invested in, the world blowing past climate targets.

In the Reuters interview, Shell’s Ben van Beurden dismissed the notion that the company’s projects would not be viable. “One of the bigger risks is not so much that we will become dinosaurs because we are still investing in oil and gas when there is no need for it anymore. A bigger risk is prematurely turning your back on oil and gas,” he said.

But he did admit that he was nervous that the company was losing investor interest amid growing pressure to act on climate change. He said that Shell’s shares were trading at a discount in part because of “societal risk.”

“I am afraid of that, to be honest,” he added. “It is not at a scale that the alarm bells are ringing, but it is an unhealthy trend.”

By Nick Cunningham of Oilprice.com
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🛢️ Brazil's $50 Billion Oil Boom Is Falling Apart
« Reply #244 on: November 01, 2019, 05:49:28 AM »
https://oilprice.com/Latest-Energy-News/World-News/Brazils-50-Billion-Oil-Boom-Is-Falling-Apart.html

Brazil's $50 Billion Oil Boom Is Falling Apart
By Julianne Geiger - Oct 31, 2019, 6:30 PM CDT Brazil Oil Auction


Exxon may not be interested in stepping up to the bidding plate at Brazil’s massive $50 billion transfer of rights auction next week, because the oilfields up for grabs come with a hefty price tag, Exxon’s president of exploration, Stephen Greenlee said in an interview with Bloomberg.

Exxon, Greenlee explained, already holds licenses offshore Brazil, but when it bought those rights, the assets were far less expensive than what the Buzios oilfield is expected to go for this time around.

“Whether or not we participate, it would be wrapped up in how we would see that opportunity versus all the other investment options, because there are a lot of investment options out there right now,” Greenlee said, adding that Exxon wasn’t the only oil company with reservations about the high price tag.

Already Total SA, Repsol, and BP Plc have said they are not interested.

No doubt, Brazil’s auction is offering as close to a sure thing as you can get—but oil companies are worried that the high price tag of the rights would eat into any profits, shrinking it to less attractive levels.

Related: Protect The Oil: Trump’s Top Priority In The Middle East

For Exxon, who has gone gangbusters into Guyana, Brazil is not the last frontier. But it is not definitively bowing out of Brazil. Exxon will consider the opportunity, weighing it against available opportunities in US shale and LNG projects.

Brazil’s transfer of rights auction is scheduled to take place on November 6. Petroleo Brasileiro SA is intending to “bid to win” Buzios, which has been hailed by Exxon as the “largest and most prolific” deepwater discovery ever.

Next door to Brazil, ExxonMobil is currently pushing ahead with Hess on its Guyana Liza Phase 1 discovery, with hopes of achieving first producing there by December. The US oil major is also looking to increase its oil production in the Permian to 1 million bpd by 2024.

By Julianne Geiger for Oilprice.com
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🛢️ Why 2020 Could Be A Crisis Year For Refiners
« Reply #245 on: November 10, 2019, 04:27:06 AM »
https://oilprice.com/Energy/Energy-General/Why-2020-Could-Be-A-Crisis-Year-For-Refiners.html

Why 2020 Could Be A Crisis Year For Refiners
By Tsvetana Paraskova - Nov 09, 2019, 6:00 PM CST


“The single largest oil market disruptor”—as some experts and media have dubbed the new shipping fuel rules set to kick in in less than two months—has had refiners on edge this year as they prepare for the dramatic switch in marine fuel specifications.   

The refining industry around the world has carefully planned to boost compliant fuel production in the back end of the year, expecting windfall from the IMO-effect in the months immediately preceding the shipping rules change. 

But as January 1, 2020, is fast approaching, the previously expected refining margins bonanza could turn to bust as the disruption is now expected to be much less dramatic than previously thought.

According to the new rules by the International Maritime Organization (IMO), only 0.5-percent or lower sulfur fuel oil should be used on ships beginning January 1, 2020, unless said ships have installed the so-called scrubbers—systems that remove sulfur from exhaust gas emitted by bunkers—so they can continue to use high-sulfur fuel oil (HSFO).

To be sure, the new fuel specifications are set to send shockwaves through the entire supply chain in the shipping industry—from crude oil producers, to refiners, to traders, to shippers, to end-consumers of everything traded on ships.

However, supply of compliant low-sulfur fuel could be just as sufficient, while demand may be subdued, due to the global economic and trade growth slowdown and at least some non-compliance from shippers, which analysts at Wood Mackenzie put at around 10 percent for 2020.

Russia is one of the countries set to delay the IMO rules implementation, but only in its territorial waters including rivers, Energy Minister Alexander Novak said, responding to questions sent by Bloomberg. Russia will still comply with the rules in international waters. Due to its predominantly high-sulfur oil, Russia is set to be one of the biggest losers in the new marine fuel rules.
Related: Canadian Oil Prices Crash After Keystone Spill

The new regulation will lead to low-sulfur fuel oil (LSFO) displacing HSFO demand, but the change looks less dramatic now than it did several months ago.

The shipping industry consumes 3.5 million bpd of HSFO, while refiners around the world are set to provide 1.5 million bpd of IMO-compliant very-low sulfur fuel oil (VLSFO), according to WoodMac’s Head of Oils Analysis Alan Gelder. There will still be demand for HSFO—from the ships with scrubbers installed, and from some non-compliance, including shippers prepared to cheat in markets with limited controls, and non-compatibility of VLSFO. Around 1 million bpd of marine fuel demand would be for marine gasoil (MGO), a middle distillate similar to diesel, WoodMac reckons.

VLSFO is cheaper than marine gasoil, but some conservative customers could still prefer MGO, Sharon Weintraub, Chief Executive Officer for Supply and Trading, Eastern Hemisphere, at BP, told Reuters in September.

Supply of VLSFO looks to be greater than initially thought, Matt Stanley, an oil broker with StarFuels in Dubai, told Reuters.

With relatively adequate supply of compliant fuel, refiners may not see the refining margins boom they were expecting earlier this year.

As 2020 is drawing nearer, LSFO storage around the world’s key bunkering port, Singapore, is piling up. As at end-October, 7.3-7.5 million tons of LSFO and blendstocks were sitting in floating storage on board 29 supertankers offshore Singapore, up from 7 million tons at the start of October, according to Refinitiv analysts quoted by Reuters.

Japanese refiners are ready to supply LFSO but they will keep up HSFO production and supply because Japan hasn’t banned discharging of water from open-loop scrubbers at ports, according to S&P Global Platts.   
Related: Why The U.S. Won't Back Down From Syrian Oil Fields

Regardless of the marine fuel that the shipping industry will use, demand for each of those could be much lower than expected in view of the global economic slowdown and seaborne trade growth slowdown.

In its September Oil Market Report, the International Energy Agency (IEA) said that the trade slowdown weighs on fuel oil demand and allows for a less disruptive switch to IMO-compliant fuel. In March, the IEA expected gasoil shortage of 200,000-300,000 bpd in 2020.

“With fewer than four months left before the rule kicks in, we believe that the oil market is likely to be better supplied than we thought,” the IEA said in September.

Refining capacity has increased globally, while bunker demand is now lower due to the ongoing contraction in global trade, the agency noted. In addition, U.S. light oil supply has increased, and U.S. grades are in demand with refiners who process them into VLSFO fuels. These recent developments “now point at the likelihood of an even smoother start to the implementation,” the IEA said.

By Tsvetana Paraskova for Oilprice.com
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🛢️ Another Oil Major Bails On Marcellus Shale
« Reply #246 on: December 24, 2019, 01:46:36 AM »
https://oilprice.com/Energy/Energy-General/Another-Oil-Major-Bails-On-Marcellus-Shale.html

Another Oil Major Bails On Marcellus Shale
By David Messler - Dec 23, 2019, 2:00 PM CST


There have been some signs the shale boom that re-energized America’s domestic energy industry a few years back, might be entering a maturing phase of its development. A phase where weaker players would hit a debt wall or be bought out at discounted value. A phase where, companies with cash who might have felt shale plays were too frothy at present levels, and had stayed on the sidelines waiting for the “froth” to dissipate. Biding their time. Now you can now almost hear the knives on the whetstone.

Beginning in 2019 these signs began to take shape in the massive retrenchment of the service industry that powered shale growth. Companies like Halliburton, (HAL) and Schlumberger, (SLB) threw in the towel and began to take charges against earnings, and layoff hundreds of staff.

This trend took on a real and tangible face when in a recent filing Chevron (CVX) said it would write down and put on the auction block its Marcellus shale assets. Assets it acquired from Atlas Energy in 2011 for $3.2 bn.

In the third quarter, 2019 conference call where this news was released to analysts, Michael Wirth, Chairman and CEO of Chevron commented-

“Mr. Wirth said Chevron must be selective about its investments moving forward, focusing on oil-rich regions like the Permian Basin in West Texas and New Mexico.” - WSJ

According to CVX, not all shale is created equal. Let’s make a note of that! My job as an oil industry expert is to dig a little deeper and see if we can determine just what drove this decision.

The Marcellus vs. The Permian

Why is Chevron abandoning the Marcellus for the Permian? Let's take a look at the isopach maps for both. In the graphic for the Marcellus, noted as Figure 2, you can see it is a relatively thin structure over most of its extent. And thins progressively the farther west it goes. The EIA comments thusly about production in the Marcellus:

"Most of the current production is located in areas where the formation thickness is greater than 50 feet." - EIA
Related: Expect More Writedowns From Oil Majors

Well, that just makes sense! But, as you look at the map of the Marcellus, one thing that strikes you is... those areas are concentrated in just a few areas on the eastern edge of the play, that some call the "Sweet Spots.” As you will see in the acreage map obtained from Chevron, they are generally quite a bit west of these sweet spots in about 50 percent of the acreage shown.

EIA

By comparison, the Permian play that is drawing Chevron's attention as it exits the Marcellus is thousands of feet in thickness across a broad swath of the Permian, as the EIA map below reveals.

EIA

Superficially, it seems to make sense. Cash out of a play that's gas-prone if you prefer oil. One that at best is a few hundreds of feet in vertical pay and go to one with thousands of vertical feet of pay across multiple horizons.

Too bad for CVX's shareholders they didn't figure that out before plunking down a few billion for acreage in the Marcellus.

Take some Maalox Chevron....you've got gas!

If you take a look at the acreage map below, you can see Chevron's current Marcellus footprint. As noted above they are well out of position to the eastern sweet spots in about half the play.

Source: Chevron's Post Atlas Energy Marcellus shale footprint. Note that Chevron's acreage is about half and half. Half in the sweet spot where formation thickness is in the 150-300' range, and half in the 25-50' thickness range.

EIA

The next thing we learn from the map showing oil to gas ratios is, it's really gassy. Well that’s no surprise really as the Marcellus is the reigning champ for gas as the table from the EIA’s Drilling Productivity Report reveals.

EIA

The problem and of course the root cause of Chevron’s dissatisfaction is that gas prices are in the tank due to over production domestically. There is no immediate cure on the horizon for that problem.

Thermal maturity

Thermal maturity refers to the alteration of the rock from burial depth. The heat generated from deeper burial causes the kerogen (the precursor to oil and gas) to transform into the useful forms we drill to obtain. The EIA report again has pertinent information as to what drove Chevron's decision to walk away from the Marcellus.
Related: The Complete Guide To Cementing

Thermal maturity values (based on vitrinite reflectance, Ro measurements of core samples) in the Marcellus Shale generally increase in a southeastern direction, as shown in Figure 6, ranging from 0.5 percent Ro to more than 3.5 percent across the Appalachian basin. Recent Marcellus Shale drilling activity and results suggest that the most substantial hydrocarbon production takes place roughly southeastward of the 0.6 percent Ro maturity contour in the western parts of West Virginia, eastern Ohio, Pennsylvania, and southern New York. At thermal maturity values of greater than 3.5 percent Ro, the hydrocarbon production potential from the Marcellus Shale may become problematic based on the limited drilling results released to date. - EIA

Another problem CVX may have found is that a bunch of its southwestern acreage appears to be in the "thermally over-mature" area. What this will all boil down to is that the acreage will not be productive.

How about pressure?

Pressure is generally regarded as a good thing in oilfield operations, particularly when it comes to producing oil. Naturally pressured or over-pressured formations produce more oil and gas than those that are under-pressured. Pressure helps the well to overcome the effects of gravity and forces hydrocarbons up the well bore to the surface. Much cheaper than alternatives.

The EIA report, from which I drew much of the information I present here, comments about the Marcellus pressure regime.

The Marcellus exhibits several different pressure regimes across the Appalachian basin. Generally, the Marcellus is under-pressured to the southwest and normal-pressured to potentially over-pressured to the northeast, with a transitional area in between. Likely, the highest ultimate recoveries will be from the normal to over-pressured areas. The presence of these distinct pressure regimes and variations in lithology requires different approaches to well stimulation and completion (Zagorski et al., 2012). - EIA

Nearly all of Chevron's acreage is in the western section of Pennsylvania, with about half in the southwest section. The least pressured acreage in the Marcellus.

What has been happening with gas prices since CVX did this deal?

Source

You could pretty much ski down this slope, absent the big "mogul" in early 2018, when it got cold for a week.

Source

What the chart above tells is that operators are laying down rigs in the Marcellus in droves. Why? Because gas prices are so low, they can't make any money.

Or, they may be like poor old CVX and just have some bad rock they need to unload to the next "greater fool."

Summary

CVX got "city-slickered," in its deal with Atlas. Its position in the Marcellus consists of:

    Gas-prone reservoirs at a time when gas prices are very low.
    Low pressure regimes that add to the costs of production.
    Poor thickness of reservoir rock.
    Thermal maturities that yield mostly gas vis a vis oil, or is not productive at all.

The Atlas folks have to be chuckling a bit as they head out to the Country Club. They pulled the ultimate "lipstick on a pig," play with CVX, who fat with $100 bbl oil money opened up its checkbook to catch a wave only to find it fell flat.

It's time to high grade its drilling portfolio and shift resources to where the return will be better. And that's just what CVX is telling us it is going to do, focusing on the Permian.

Your takeaway

CVX's write-down of its Marcellus assets surely won't be the last in this play. There is just too much gas right now.

One of the problems with lower tiers of rock is that there are just less oil and gas contained in the volume of rock as opposed to Tier I acreage. This in part accounts for the sharp drop-off in production a few months after they are brought on line.

What’s next for CVX? It missed out on the Anadarko opportunity earlier this year. When the CEO says “we going to focus on the Permian,” is he talking up the possibility spending some of ~$10 bn in cash CVX has in its coffers? We wouldn’t be surprised.

Chevron will open Monday, the 23rd trading near recent highs. Knowing this charge will hit Q-4 earnings, the stock price will likely fall back toward the $110’s. It has been remarkably resilient in that area bouncing off it twice this year. CVX pays a sweet dividend of $4.76 per share, yielding just under 4 percent currently. By comparison peers Shell and BP are paying in the 6.5 percent range, so pure yield seekers might want to look at them.

Bottom-line. CVX made a misstep in the Marcellus and now must pay for it. None-the-less, it is an extraordinarily well managed company and we think at the sub-$110 level it belongs in every energy portfolio.

By David Messler for Oilprice.com
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🛢️ Is This The Beginning Of A Shale Crisis?
« Reply #247 on: December 27, 2019, 12:13:45 AM »
Yes.

RE

https://oilprice.com/Energy/Crude-Oil/Is-This-The-Beginning-Of-A-Shale-Crisis.html

Is This The Beginning Of A Shale Crisis?
By Nick Cunningham - Dec 23, 2019, 6:00 PM CST


Banks are cutting their lending to struggling U.S. shale drillers, another blow to an industry that has long been dealing with a questionable business model.

Banks are restricting lending and revising their estimates on the value of some shale reserves, according to the Wall Street Journal. Even the largest banks, such as JPMorgan Chase and Capitol One Financial Corp., are expected to cut their exposure to the shale industry. Sources told the WSJ that the banks are growing more concerned that if drillers go bankrupt, their assets – the value of which could be declining – may not cover the outstanding loans.

The scrambling among big financial institutions comes as the industry is being hit by a wave of write downs. Chevron said earlier this month that it expects to take a $10 to $11 billion write down, largely the result of weak assets in Appalachia and a big LNG project in Canada. Last week, Royal Dutch Shell said that it would write down $1.7 to $2.3 billion in assets in the fourth quarter, although the company declined to offer more details.

In recent months, other big oil companies also reported write downs, including Repsol BP, Equinor and Halliburton.
Related: The Complete Guide To Cementing

But the oil majors aren’t in any danger of going bankrupt. Weaker shale drillers pose a bigger risk to banks because some may be unable to pay back debt. Roughly 200 oil and gas companies have gone bankrupt in North America since 2015, according to Haynes & Boone. More than 30 bankruptcies have occurred in 2019, the highest number in three years. Energy companies accounted for more than 90 percent of defaults on corporate debt in the third quarter, the WSJ noted, using Moody’s data.

Haynes & Boone estimates that banks could cut their credit lines to the sector by as much as 10 percent. But, that is an industry-wide average. For individual companies that are in a weak position, the reductions will be much more significant. Meanwhile, according to Credit Benchmark, roughly 22 oil and gas companies saw their credit ratings upgraded by a variety of financial institutions in November, while 33 saw their ratings downgraded.

If the spigot of capital flowing from Wall Street into West Texas is tightened, drilling and production could continue to slow.

The Dallas Fed recently revealed that broader lending growth in West Texas has slowed dramatically. The value of loans in West Texas grew by 4.8 percent in the third quarter, compared to 7.5 percent in the rest of the state. Loan value for apartments and other housing fell by 15 percent, compared to an increase of 12 percent in the rest of Texas. Home inventories are now on the rise.

On the ground, the effects are becoming increasingly visible. The Permian is shedding jobs and vacancies in corporate office space have increased.

The problem plaguing the shale sector is more damning than just overly optimistic profit forecasts from oil executives. The issue is also one of disappointing operational results, which cuts to the heart of the problem with shale. Put bluntly, shale wells are not producing as much oil as advertised, and in the aggregate, they are declining at faster rates than the industry promised, as the WSJ has reported over the past year.
Related: Expect More Writedowns From Oil Majors

If shale wells ultimately produce less over their lifetimes than companies advertised to their investors, then the companies themselves are likely worth a lot less than previously thought. They will produce less oil and gas, less cash flow and even the unproduced reserves they are sitting on could suddenly be worth much less than previously thought.

That has massive implications for the entire sector. The problem is crystallized in a quote from Michelle Foss, an energy fellow at Rice University’s Baker Institute for Public Policy. “There is a struggle now for investors to determine what things are actually worth,” Foss told the WSJ.

By Nick Cunningham of Oilprice.com
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