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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. 

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

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.

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

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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Spending Boost Fails To Raise Production In The Permian

Spending Boost Fails To Raise Production In The Permian

Midland

The U.S. shale industry is gearing up to spend more this year, despite assurances to maintain capital discipline.

In the second quarter, shale companies signaled their intention to lift capex. Part of the reason is that costs are on the rise, so some drillers have to spend more to produce the same amount of oil and gas. That was an unexpected development, and one that shareholders are not happy about.

A survey of 33 shale companies by Rystad Energy found that while the group revised up spending by about 8 percent, they only increased their expected production levels for this year by 1.4 percent. “This disconnect might suggest that the shale industry requires more capital than before to achieve healthy production growth,” Rystad said in a new report.

There are some signs that the Permian, for instance, is running into some productivity problems, raising the possibility that the highly touted “efficiency gains” over the past few years are reaching their limit.

On the other hand, the industry is also spending more because they have plans to increase drilling activity, which could lead to higher output next year. “[W]hile a part of increased spending is due to service cost inflation, a significant part of the incremental budget is also planned to be used for additional drilling throughout 2H 2018 to support more intensive completion activity and production growth in 2019,” Rystad Energy said in its report.

The largest spending increase came from companies focused on the Permian basin, which is not surprising given both the frenzied pace of drilling in West Texas as well as the reports that the basin is suffering from bouts of cost inflation. Occidental Petroleum stood out from the bunch, with an announced increase in spending by $900 million.

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The Productivity Problem In The Permian

The Productivity Problem In The Permian

Permian oil well

The multi-year campaign to boost efficiency and productivity in the U.S. shale patch could be nearing its limits.

Output in the Permian basin is already starting to slowdown, largely due to pipeline constraints. However, there is also a series of other data points that suggests that shale drillers are bumping up against a ceiling in terms of productivity and efficiency.

New data from the EIA shows a rather startling slowdown in the amount of oil that the average rig can produce from a new well in the Permian. In September, the EIA expects new-well production per rig to fall by 10,000 barrels per day (bpd) in the Permian, compared to August levels. That means that when a company deploys a rig to drill a new well, that rig will produce a little less oil than it did compared to the average rig did a month earlier.

(Click to enlarge)

New-well productivity has seesawed a bit over the years, spiking in 2016 when the industry scrapped inefficient rigs during the market downturn. Indeed, some of the recent decline in new-well productivity can be chalked up to the industry rushing to drill more. In this sense, it isn’t that the rigs are necessarily less productive, just that there are so many of them out there in the Permian, that the productivity figures fall because the denominator is larger.

But it’s also a reflection of the fact that drillers are being forced into less desirable locations with the field so crowded.

“We believe that the short-cycle nature of shale exploitation and the intensity of activity in the Permian means that production from Tier 1 geological locations (e.g., those with the best pay, the optimum pressure) is starting to move to Tier 2, which is unable to achieve the same rates of productivity,” Standard Chartered wrote in a note.

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Trump Tariffs Could Delay Permian Relief

Trump Tariffs Could Delay Permian Relief

Transmountain Pipeline

The oil and gas industry hoped they would be spared from Donald Trump’s trade war, but the Permian basin was just hit with some bad news.

The Permian basin has run up against a bottleneck for pipeline capacity. Gushing oil from West Texas will surpass the available space on the region’s pipelines this year, which could force output growth to suddenly plateau after expanding at a blistering pace over the past few years. New pipelines are still a year away.

One of the crucial pipeline projects slated to come online at some point next year is the Plains All American Pipeline LP’s Cactus II project, which will ferry 585,000 bpd crude oil from the Permian basin to the Gulf Coast at Corpus Christi.

Plains All American sent a request to the Trump administration, seeking an exemption from the 25 percent tariffs on imported steel. An industry estimate finds that about three-quarters of all the steel used in oil and gas pipelines comes from abroad, often because projects use a special type of steel that is hard to find domestically.

The Trump administration just shot down the request from Plains All American, the first rejection for a major oil and gas project. The denial could significantly raise the cost of the $1.1 billion Cactus II pipeline. The Commerce Department justified its rejection by arguing that there was sufficient supply of steel found within the United States.

A long line of other companies are also seeking exemptions, and the Commerce Department has to go through one by one. The agency has granted 267 exemptions and denied another 452, according to Reuters. There have been over 25,000 requests. Royal Dutch Shell and Chevron recently received an exemption on steel used in specific types of equipment for their offshore drilling projects in the Gulf of Mexico.

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Flip This Well: How Fracking Company CEOs Get Rich While Losing Billions

Flip This Well: How Fracking Company CEOs Get Rich While Losing Billions

Last year the fracking company Halcón Resources announced a new strategy that was sold as the path to profits for the previously troubled shale oil and gas firm. The company had sold its stake in the Bakken oil fields in order to double down on the Permian shale in Texas. At the time, Reuters touted the deal as a “stunning turnaround” for CEO Floyd Wilson, and the good news immediately drove up the Halcón stock price by 35 percent.

“The sale of our Williston Basin operated assets transforms Halcón into a single-basin company focused on the Delaware Basin where we have more than 41,000 net acres,” Wilson said in a statement. He was making his pitch and investors responded.

However, the move was part of a familiar formula for those in the shale industry, which uses horizontal drilling and hydraulic fracturing (fracking) to release oil and gas from shale formations: Borrow lots of money, drill lots of fossil fuels at a loss, flip the company for a profit.

As the Reuters article points out, Wilson’s ultimate goal is to create excitement about the potential of its Permian basin wells and then flip Halcón, just as he’s flipped other shale firms: “Focusing on the Permian could help Wilson achieve his long-held dream of selling Halcón to the highest bidder.”

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Permian Growth Is Reaching Its Limits

Permian Growth Is Reaching Its Limits

Oil rig

The Permian isn’t just suffering from a bottleneck for oil, but also for natural gas.

In 2016, for instance, gas flows leaving the Permian typically clocked in at about 3.6 billion cubic feet per day (Bcf/d), according to S&P Global Platts. That number has ballooned to 6.3 Bcf/d as of May 2018.

Obviously, the surge in gas flows from the Permian is the result of a massive increase in gas production. Gas output has surged more than 135 percent since 2013 and is expected to rise to just shy of 10.5 Bcf/d (including natural gas liquids) in June 2018. The problem is that the region’s ceiling on takeaway capacity stands at about 7.3 Bcf/d.

Skyrocketing natural gas production has unsurprisingly weighed on regional prices. According to S&P Global Platts, natural gas prices at the Waha Hub in West Texas traded at an 8-cent per MMBtu discount to Henry Hub two years ago, but that discount widened to about $1/MMBtu this month.

With so much gas on their hands, Permian drillers have resorted to higher rates of flaring. The Environmental Defense Fund estimates that top Permian producers are flaring as much as 10 percent of their gas. “This flaring is so extreme, it can be seen from space,” EDF says. “In 2015 alone, enough Texas Permian natural gas was flared to serve all of the Texas household needs in the Permian counties for two and a half years.”

S&P Global Platts reported that gas flows to Mexico have increased over the past few weeks, relieving some pressure. But infrastructure within Mexico hasn’t been able to keep up with the supply of gas north of the border, so some of the pipelines are under-utilized. In any event, the gas volumes moving to Mexico will be swamped by new supply coming online in the Permian. At some point, the glut of gas could force curtailments in drilling.

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