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Permian Bankruptcies Could Fuel A Buying Spree For Big Oil

Permian Bankruptcies Could Fuel A Buying Spree For Big Oil

The United States shale revolution is over. Production in the Permian Basin, which spreads across West Texas and Southeast New Mexico, has been slowing for months, but the novel coronavirus took things from bad to much, much worse for U.S. shale. The oil price shock that followed the spread of the COVID-19 pandemic, combined with a massive global oil glut spurred by a spat between with learning OPEC+ member countries of Russia and Saudi Arabia, drove West Texas Intermediate oil prices down to a previously unthinkable -$37.63 a barrel earlier this month.  While shale prices have since moderately rebounded, the Permian Basin is still in bad shape. The oil fields that made the United States the biggest crude oil producer in the world is now seeing tens of thousands of fired and furloughed employees as the region is rocked by a sweep of bankruptcies across the shale sector. Last week CNBC reported that “the oil industry shakeout is just beginning with more production cuts and bankruptcies ahead,” detailing that “U.S. oil companies are already paring back spending and closing wells, but wild trading in the futures market was a warning to curb production now because the world at some point will not be able to store any more supply.”

Just because the U.S. oil industry has hit a rough patch, however, doesn’t necessarily mean that the West Texas shale play is all played out. In fact, it stands to reason that, as competition dries up and blows away like so many tumbleweeds, Big Oil may step in and buy up faltering shale independents. 

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New Satellite Data Reveals Dangerous Methane Emissions in Permian Region

New Satellite Data Reveals Dangerous Methane Emissions in Permian Region

New research based on satellite data confirms that the oil and gas industry in the Permian region of Texas and New Mexico is leaking record amounts of methane. The new research published in the journal Science Advances found that methane emissions in the Permian Basin were equivalent to 3.7 percent of the total methane produced by the oil and gas industry there.

In December DeSmog reported on the work of Robert Howarth, a biogeochemist at Cornell University, who has been studying the methane emissions of the oil and gas industry. Howarth’s latest research estimated that 3.4 percent of all natural gas produced from shale in the U.S. is leaked throughout the production cycle, which appears to be confirmed by this new research.

Methane is a powerful greenhouse gas and makes up approximately 90 percent of what is known as natural gas. It’s a major contributor to global warming.

The oil and gas industry has long tried to sell the idea of natural gas, which is, again, primarily methane, as a clean energyclimate solution. However, with a leakage rate of 3.7 percent, natural gas is actually worse for the climate than coal.

Advertisements for natural gas from the industry trade group the American Petroleum Institute have claimed, “Thanks to natural gas, the U.S. is leading the way in reducing emissions.”

This new satellite data confirms that simply isn’t the case. When the methane leaks from oil and gas production are taken into account, natural gas is unquestionably a dirty fossil fuel.

This new research also helps explain why methane emissions rose at such a high rate in 2019.

…click on the above link to read the rest of the article…

Exxon Cuts 2020 Capex By 30% On Expectations For 25-30% Demand Drop

Exxon Cuts 2020 Capex By 30% On Expectations For 25-30% Demand Drop

With oil trading at prices that are uneconomical even for the world’s biggest majors, on Tuesday morning Exxonmobil announced it cut its 2020 Capex by 30% and cash Opex by 15% as the CEO said he expects a record 25-30% demand drop this year.

The company said that the largest share of Capex reductions, or roughly 30% of total, would be in the Permian Basin. As a result of the spending cuts, the company will a production hit of 100,000 to 150,000 barrels/day from the Permian Basin in 2021 due to its spending reductions, CEO Darren Woods says on call with reporters, adding that in 2020 the production cut would be a modest reduction of only 15,000 barrels, which will hardly be enough an OPEC+ demanding US shale producers join the global production cuts now not in one year.

Among the other Exxon announcements:

  • Expects to meet projected investments of USD 20bln on US Gulf Coast manufacturing facilities
  • Expects to reach proposed US investments of USD 50bln over 5yrs announced in 2018
  • Mozambique project, expected later this year, has been postponed
  • Current operations onboard Liza Destiny production vessel are undisturbed
  • Capital allocation priorities remain unchanged
  • Long-term fundamentals that underpin Co’s business plans are unchanged
  • Globally, the company sees industry refinery output declining in-line with demand and storage available

We’re in a “capital-intensive commodity business that’s used to ups and downs in price cycles. However, I have to say we haven’t seen anything like what we’re experiencing today” the CEO said, concluding ominously that “these are definitely challenging times for all of us.”

Exxon’s stock price rose by 7% on the news, although it remains about 40% below levels it traded at at the start of the year. The company’s dividend yield remains a above 8% – a staggering number for what was not that long ago one of the world’s largest companies.

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Peak Permian Oil Production May Arrive Much Sooner Than Expected

Peak Permian Oil Production May Arrive Much Sooner Than Expected

Ad in Houston Airport mentioning declining Permian oilfields

In mid-January, Adam Waterous, who operates the private equity firm Waterous Energy Fund, made a prediction about the crown jewel of the U.S. shale oil industry, the Permian shale play that straddles Texas and New Mexico.

“We think we are at or near peak Permian,” Waterous told Bloomberg. “The North American oil market has been grossly overcapitalized, which is not sustainable.”

Bloomberg reporter Simon Casey goes on to qualify that “[p]redicting peak Permian output for 2020 isn’t a mainstream view.” However, evidence is piling up that the U.S. shale industry may indeed be close to peaking as it runs out of the two things required to continue increasing oil production: money and what’s known as “tier one acreage.”

Tier one acreage is the term for the areas that produce the most oil per well. It’s also known as “sweet spots,” “core acreage,” or “good rock.”

The idea of the U.S. shale revolution peaking long before either the broader oil and gas industry or the Energy Information Administration expects isn’t a popular one. And the idea was even less popular when DeSmog started detailing why it was likely all the way back in October 2018, and even when the Wall Street Journal made the case a year later.

Today, as more and more Permian oil companies go bankrupt and wells in the nation’s most prolific oil patch turn out less and less, one early warning nows seems especially prescient. In 2018, Paal Kibsgaard, the CEO of Schlumberger — one of the largest oil services providers — cautioned about declining well productivity in the Permian Basin, pointing to increasing “child wells” and to the boom-gone-bust Texas oilfield, the Eagle Ford Shale. 

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To Many’s Dismay, Permian Produces More Gas and Condensate Instead of Oil and Profits

To Many’s Dismay, Permian Produces More Gas and Condensate Instead of Oil and Profits

aerial view of West Texas oil fields

As oil prices plummet, oil bankruptcies mount, and investors shun the shale industry, America’s top oil field — the Permian shale that straddles Texas and New Mexico — faces many new challenges that make profits appear more elusive than ever for the financially failing shale oil industry.

Many of those problems can be traced to two issues for the Permian Basin: The quality of its oil and the sheer volume of natural gas coming from its oil wells.

The latter issue comes as natural gas fetches record low prices in both U.S. and global markets. Prices for natural gas in Texas are often negative — meaning oil producers have to pay someone to take their natural gas, or, without any infrastructure to capture and process it, they burn (flare) or vent (directly release) the gas.

As DeSmog has detailed, much of the best oil-producing shale in the Permian already has been drilled and fracked over the past decade. And so operators have moved on to drill in less productive areas, one of which is the Delaware sub-basin of the Permian. Taking a close look at the Delaware Basin highlights many of the current challenges facing Permian oil producers.

Delaware Basin Producing More Gas Along With the Oil

The Delaware Basin is where most of the new oil production is coming out of the Permian. As a Bloomberg Wire story reported in December, “in recent years investments have shifted to the Delaware, where output is much gassier than in the historic Midland portion of the Permian.”

The last thing a Permian oil producer wants is to have natural gas coming out of the ground with the oil because, as Bloomberg notes, this persistent “nuisance” is “undercutting profits for explorers.” That’s a generous assessment because many explorers have no profits to undercut, only losses to grow.

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Burn, Pay, Or Shut It Down: Three Evils For Permian Drillers

Burn, Pay, Or Shut It Down: Three Evils For Permian Drillers

Evil Permian Drillers

There was a time when natural gas was a welcomed byproduct of crude oil drilling, and drillers in the prolific Permian basin enjoyed this consolation prize–at least when natural gas prices were on the rise. All good things come to an end, though, and the amount of natural gas now exceeds the capacity to get rid of it.

With pipeline capacity fully exploited and natural gas prices squarely in the red, Permian drillers today are faced with three lousy choices: burn off the natural gas, pay to have the gas removed, or slow oil drilling activities to staunch the flow of natural gas.

Crude oil and natural gas are like two peas in a pod: when you find oil, you often find gas. 

Crude oil is pumped out of the well, and a small amount of natural gas comes almost inevitably comes with it. 

But over time, this ratio changes: less oil, more natural gas. 

Now, there is simply too much natural gas, and drillers in the American shale patch must face the not-so-pleasant music, with only one question remaining: which shale drillers can hold on until more pipeline capacity comes online?

Burn, Baby, Burn

The first option for drillers trying to weather the natural gas storm is to burn it off. 

This is flaring–and it’s a rather unpopular method, publicly speaking, due to the negative impact on the environment. For drillers, though, it’s a cost-effective way of dealing with the glut, and since they all must answer to shareholders and lenders, flaring is the first choice when it comes to watching the bottom line. 

Flaring has increased exponentially in recent years as the discrepancy between natural gas and pipeline capacity increased, creating unfavorable market conditions and leaving drillers holding a bag of unwanted natural gas. 

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The Drilling Frenzy Is Over For U.S. Shale

The Drilling Frenzy Is Over For U.S. Shale

Shale Boom

A few high-profile shale executives say the glory days of shale drilling are over.

In a round of earnings calls, the financial results were mixed. A few companies beat earnings estimates, while others fell dramatically short.

But aside from the individual performances, there were some more newsworthy comments from executives on the state of the industry. A common theme emerged from several notable shale executives: the growth frenzy is coming to an end.

The chief executive of Pioneer Natural Resources, Scott Sheffield, said that the Permian basin is “going to slow down significantly over the next several years,” and he noted on the company’s latest earnings call that the company is also acting with more restraint because of pressure from shareholders not to pursue unprofitable growth. “I’ve lowered my targets and my annual targets, a lot of it has to do with…to start with the free cash flow model that public independents are adopting,” Sheffield said.

But there are also operational problems that have become impossible to ignore for the industry. He listed several factors that explain the Permian slowdown: “the strained balance sheets lot of the companies have, the parent-child relationships that companies are having, people drilling a lot of Tier 2 acreage,” Sheffield said. “So I’m probably getting much more optimistic about 2021 to 2025 now in regard to oil price.” In other words, U.S. shale is slamming on the brakes, which may yet engineer a rebound in global oil prices.

He said that this would be good news for OPEC. “I don’t think OPEC has to worry that much more about U.S. shale growth long-term,” Sheffield said. “And all that is very beneficial. So we are probably going to be more careful in the years 2021 to 2025 because there’s not much coming on after the three big countries that are bringing on discoveries over the next 12 months Norway, Brazil and Guyana.”

 …click on the above link to read the rest of the article…

EXXONMOBIL U.S. OIL & GAS FINANCIAL TRAIN-WRECK: Producing Shale Is Destroying Its Bottom Line

EXXONMOBIL U.S. OIL & GAS FINANCIAL TRAIN-WRECK: Producing Shale Is Destroying Its Bottom Line

The United States largest oil company, ExxonMobil, is facing a financial train-wreck in its domestic oil and gas sector.  And, the majority of the blame can be attributed to Exxon’s move into shale.  After Exxon acquired XTO Energy in 2009, a U.S. shale oil and gas producer, it has seriously begun to ramp up shale oil production in the Permian.

ExxonMobil plans on expanding Permian shale oil production to 600,000 barrels a day (bd) by 2025, up from the 115,000 bd as of October (thanks to the data from Shaleprofile.com).  If you look at the chart below, Exxon’s Permian shale oil production shot up from less than 50,000 bd at the beginning of 2018, to over 115,000 bd in October:

Exxon is now the largest player in the Permian, according to the article, Exxon Becomes Top Permian Driller to Combat Falling Oil Output:

Exxon Mobil Corp. has overtaken rivals to become the most active driller in the Permian Basin, showing the urgency with which the world’s biggest oil company by market value is pursuing U.S. shale.

Exxon’s escalation in the Permian is essentially a bet that it can drill wells so cheaply that they’ll be profitable despite crude’s tumble since early October. The company says its shale wells can make double-digit returns with oil at just $35 a barrel.

Exxon moved into the Permian to stem a decade of falling domestic U.S. oil production.  However, its statement that it will enjoy double-digit gains at a $35 oil price in the Permian may be more “delusional thinking” rather than company pragmatic optimism.  I spent some time looking over Exxon’s financial statements, and I have to say I was quite shocked by their utterly dismal 2018 U.S. oil and gas financials.

 …click on the above link to read the rest of the article…

Evidence Mounts For Shale Slowdown

Evidence Mounts For Shale Slowdown

frack crew

There is a growing pile of evidence pointing to a slowdown in the U.S. shale industry, as low prices take their toll.

The rate of hydraulic fracturing began to decline in the last four months of 2018, a sign that U.S. shale activity began to slow even before the plunge in oil prices. According to Rystad Energy, the average number of fracking jobs declined to 44 per day in November 2018, down from an average of between 48 and 50 for the five-month period between April and August 2018.

“After reaching a peak in May/June, fracking activity in the Permian Basin has gradually decelerated throughout the second half of 2018,” Rystad Energy senior analyst Lai Lou said in a statement.

“Looking at preliminary data for November, we see evidence that seasonal activity deceleration has likely started in all major plays except Eagle Ford,” Lou added. “There has been a considerable slowdown in Bakken and Niobrara in November, our analysis shows.” Rystad said that much of the slowdown can be attributed to smaller companies.

The drilling data echoes that of the Dallas Fed, which reported last week that drilling activity began to slow in the Permian in the fourth quarter. Whether measuring by production, employment, business activity, equipment usage rates – a wide variety of data from the shale industry points to an unfolding slowdown.

Moreover, independent data also suggests that a lot of shale drillers are not profitable with oil prices below $50 per barrel. Breakeven prices on the very best wells can run in the $30s or $40s per barrel, but industry-wide all-in costs translate into much higher breakeven thresholds. The rig count has also already plateaued after growing sharply in the first half of 2018.

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The Real Implications Of The New Permian Estimates

The Real Implications Of The New Permian Estimates

oil rig

This week the United States Geological Survey (USGS) announced a groundbreaking oil and gas discovery in West Texas’ Permian Basin. According to the organization’s recent press release, a whopping 46.3 billion barrels of oil, 281 trillion cubic feet of natural gas, and 20 billion barrels of natural gas liquids are now believed to lie untapped in the Wolfcamp Shale and overlying Bone Spring Formation area of Texas and New Mexico’s Permian Basin.

Major players in the energy industry already have a significant presence in Wolfcamp and Bone Spring, including Occidental Petroleum Corp. and Pioneer Natural Resources Co. It was already well known and well documented that these fields were remarkably fertile grounds for oil extraction, but the jaw-dropping extent of the new figures released this week by the USGS has made the massive crude and shale reserves of the Permian Basin freshly headline-worthy. The figures in this week’s press release are in fact, in the case of Wolfcamp Shale, more than double the previous resource assessment.

(Click to enlarge)

Source: USGS

The USGS assessed the area more than two years ago in 2016, and has officially determined that it contained the largest estimated quantity of continuous oil in the entire United States. “Christmas came a few weeks early this year,” said U.S. Secretary of the Interior Ryan Zinke in response to these momentous figures. “American strength flows from American energy, and as it turns out, we have a lot of American energy. Before this assessment came down, I was bullish on oil and gas production in the United States. Now, I know for a fact that American energy dominance is within our grasp as a nation.”

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Will The ‘Next Permian’ Ever Be Developed?

Will The ‘Next Permian’ Ever Be Developed?

Vaca Muerta

The Vaca Muerta Shale Basin in Argentina is the only unconventional play outside of North America where activity has already made the transition from exploration to full-scale development. The potential prize is huge – geographically, the Vaca Muerta Shale is three times the size of the highly prolific Permian Basin in the US, and it could turn out to be the “next Permian” if the right conditions are established. But much remains to be done before that happens.

Rystad Energy’s Shale Intel group, in collaboration with Luxmath Consulting, has released a comprehensive new report covering all aspects of the Vaca Muerta Shale – including development status, production forecasts, drilling and completion projections, and the outlook for the various service segments in the industry. The report integrates Rystad Energy’s well-level research for Argentina, public disclosures from oil & gas companies and service contractors active in the region, and our conversations with on-the-ground field experts.

(Click to enlarge)

“There are several major bottlenecks that are currently affecting Vaca Muerta – proppant, infrastructure, labor, pressure pumping and the macro economic situation in Argentina. In addition, investments need to be made in water transportation infrastructure as drilling and completions increase within the region,” says Ryan Carbrey, Senior Vice President of Shale Research at Rystad Energy.

Vaca Muerta should see the tally of fracked wells reach between 140 and 150 this year. Only three of those wells are vertical, while all other wells are high-density horizontal completions. It is expected that fracking activity will grow at a rate of 20% per year from 2019 through 2021, reaching about 250 wells in 2021. According to Rystad Energy research, this heightened activity will generate a significant boost in Vaca Muerta oil production – from about 60,000 bpd in the third quarter of 2018 to between 160,000 and 200,000 bpd in the fourth quarter of 2021. Most of this growth will come from the liquids-rich Loma Campana portion of the play, operated by YPF.

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Bakken Prices Crumble On Pipeline Woes

Bakken Prices Crumble On Pipeline Woes

Pipeline

Oil production is growing so quickly in the Bakken that the region is starting to suffer from painful pipeline constraints.

U.S. shale is not new to pipeline bottlenecks. The Permian basin has suffered from steep discounts this year, with WTI in Midland trading as much as $20 per barrel below WTI in Houston at times. Meanwhile, the midstream bottleneck is especially acute in Canada, where the inability to build a major pipeline out of Alberta has led to price discounts that have reached as high as $50 per barrel. Western Canada Select fell as low as $15 per barrel in recent daysafter a U.S. federal judge blocked construction on the Keystone XL pipeline, dealing yet another blow to Canada’s oil industry.

Now, the pipeline woes could be spreading to the Bakken. Production in the Bakken has jumped this year, rising from 1.188 million barrels per day (mb/d) in January to 1.354 mb/d in November, according to the EIA’s forecast in its Drilling Productivity Report. It is a dramatic turnaround for the Bakken after it had hit a temporary peak in late 2014 at 1.26 mb/d, before falling to 0.956 mb/d two years later. Since bottoming out at the end of 2016, however, production has slowly rebounded, with a record output level expected this month.

Rising output has been good news for Bakken shale drillers, but now they face an uncertain near-term future as pipeline capacity fills up. While the Bakken is producing over 1.3 mb/d in output, the region’s pipeline systems can only handle 1.25 mb/d, according to Reuters and Genscape. With pipelines essentially tapped out, oil producers are starting to turn to rail, just as they did years ago when the Bakken first burst onto the scene.

To make matters worse, cold weather could disrupt rail loadings, an unfortunate bit of timing as takeaway capacity dwindles.

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Permian Drillers Prepare To Go Into Overdrive In 2019

Permian Drillers Prepare To Go Into Overdrive In 2019

Permian

In recent months, pipeline capacity shortage in the Permian has been the center of shale drillers and oil analysts’ attention as much as the surging production from this fastest-growing U.S. oil region that has helped total American crude oil production to exceed 11 million bpd for the first time ever.

Many of the big U.S. companies—including supermajors Exxon and Chevron—boosted their Permian oil production in the third quarter as they have firm capacity commitments and integrate Permian production with downstream operations.

Many smaller drillers, however, are going on a ‘frac holiday’—as Carrizo Oil & Gas said in its Q3 earnings release this week—in some of their Permian acreage by the end of this year, to sit out the worst of the pipeline constraints, and to be ready to return to completions next year.

The majority of company executives and industry analysts expect that the Permian bottlenecks and the wide WTI Midland to Cushing price differential are transitory issues that will go away by the end of 2019, when many of the new pipelines out of the Permian will have started operations.

Until then, some smaller drillers like Carrizo are on a ‘frac holiday’ this month and next. Commenting on the Q3 performance, Carrizo’s President and CEO S.P. “Chip” Johnson said that the company had been drilling more in the Eagle Ford than in the Permian in order to capture higher pricing from the Eagle Ford oil.

“We expect our activity to remain weighted to the Eagle Ford Shale until the second half of 2019, when we plan to begin moving rigs back to the Delaware Basin,” Johnson said. In the earnings call, he noted that the shift to the Eagle Ford “shielded us from the dramatic widening of differentials in the Permian Basin during the quarter.”

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U.S. Shale’s Glory Days Are Numbered

U.S. Shale’s Glory Days Are Numbered

Fracking

There are some early signs that the U.S. shale industry is starting to show its age, with depletion rates on the rise.

A study from Wood Mackenzie found that some wells in the Permian Wolfcamp were suffering from decline rates at or above 15 percent after five years, much higher than the 5 to 10 percent originally anticipated. “If you were expecting a well to hit the normal 6 or 8 percent after five years, and you start seeing a 12 percent decline, this becomes more of a reserves issue than an economics issue,” said R.T. Dukes, a director at industry consultant Wood Mackenzie Ltd., according to Bloomberg. As a result, “you have to grow activity year over year, or it gets harder and harder to offset declines.”

Moreover, shale wells fizzle out much faster than major offshore oil fields, which is significant because the boom in shale drilling over the past few years means that there is more depletion in absolute terms than ever before. A slowdown in drilling will mean that depletion starts to become a serious problem.

A separate study from Goldman Sachs takes a deep look at whether or not the shale industry is starting to see the effects of age. The investment bank says the average life span for “the most transformative areas of global oil supply” is between 7 and 15 years.

Examples of these rapid growth periods include the USSR in the 1960s-1970s, Mexico and the North Sea in the late 1970s-1980s, Venezuela’s heavy oil production in the 1990s, Brazil in the early 2000s, and U.S. shale and Canada’s oil sands in the 2010s. Each had their period in the limelight, but ultimately many of them plateaued and entered an extended period of decline, though some suffering steeper declines than others. Supply Soars

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Is The Bakken Close To Breaking?

Is The Bakken Close To Breaking?

Bakken

While the Permian has experienced a drilling boom and has received tons of media attention, a lesser-known but still remarkable revival has been underway in the Bakken this year. At the same time, the increased rates of drilling in North Dakota are starting to reveal signs of strain on the basin, as drillers are increasingly forced into less desirable locations.

The Bakken was hit harder than the Permian during the oil market downturn that began in 2014, with rigs and capital diverted away from North Dakota and rerouted to West Texas. Oil production hit a temporary peak in late 2014 at 1.26 million barrels per day (mb/d), declining for much of the next two years.

However, production began to rise again in early 2017 before accelerating this year. In October, the EIA expects Bakken production to hit 1.33 mb/d, a new record high.

In some ways, the Bakken is enjoying a bit of a revival because the Permian has become overcrowded. The pipeline bottleneck, the strain on rigs and equipment, completion services, labor, water and even on road traffic has caused a lot of headaches for shale drillers in West Texas. Some shale executives have decided to shift resources elsewhere, and the Bakken has received a boost as a result.

The Bakken took over as the most profitable place for shale drillers on average this summer, at least temporarily surpassing the Permian. That may not last as the steep discounts for WTI in Midland drags down the profitability of the Permian, a situation that will resolve itself over the next few years as pipelines come online. But the improved outlook for the Bakken is notable nonetheless.

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