Shale to be profitable in 2019!!!

Shale industry to be profitable in 2019: IEA: The shale industry worldwide is expected to achieve positive free cash flow this year, according to a report released by the International Energy Agency.

It would be the first year since 2010 cash flow is predicted to be positive, anticipating a 50% increase in cash flow. There also is expected to be a 20% decrease in investment between 2017 and 2018 in the U.S. sector, which is the global leader in terms of spending on energy supply.

According to the World Energy Investment 2019 report, positive free cash flow should be reached because of three factors, implying the current WTI price of $60 per barrel doesn’t decline significantly.

First, the numerous drilled but uncompleted wells (DUCs) can be brought online with a limited amount of spending. According to the IEA, the number of completed DUCs has been increasing since February.

Second, new pipelines in the Permian Basin are starting to flow product, allowing for more export capacity to go alongside production growth.

Finally, independent companies are likely to stick to cash flow neutrality with crude priced between $50 and $55/Bbl, as investors put more pressure on their clients.

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US policy cranks up the risks to oil supply – and price

Geopolitics is never far from the fray. The oil market was chronically oversupplied a few months ago. Now Brent is back over US$70/bbl as tension builds around some of OPEC’s bigger producers. Could prices go higher? For the answer, I turned to Ann-Louise Hittle, VP Oils Research.

What worries you most in the short term?
Rising geopolitical tension around Iran. The end of sanctions waivers will reduce exports from around 1.2 million b/d today to 0.7 million b/d this summer. That’s less than a third of what they were selling in 2017, and takes another 0.4-0.5 million b/d out of global supply, with only China and India still prepared to buy Iranian crude. Should the US succeed in its goal to reduce Iran’s exports to zero, it would worsen supply tightness materially. The other big concern is that as economic pressure bubbles up, Iran responds to US pressure with a knock-on effect for regional stability.

What about Venezuela and Libya?
The stalemate in Venezuela looks set to be protracted and the recovery of supply slower. We’ve cut our 2020 forecast to 0.83 million b/d, flat on 2019. So, through next year, Venezuelan production is a third of what it was in 2014. As for Libya, we just reduced our 2019 forecasts by 50 kb/d to 0.9 million b/d. The escalating civil war there shouldn’t be underestimated as a risk to global supply.

Meantime, the US keeps pumping
Yes, and dominating non-OPEC production growth. We forecast 1.9 million b/d of US liquids growth in 2019, only marginally down on last year’s phenomenal 2.2 million b/d. The Permian is the driving force, contributing two-thirds of this year’s increase. The bidding war for Anadarko underlines the attraction of Permian tight oil growth to Big Oil, and we’ll see more consolidation. The bigger companies have access to capital and have only just begun to industrialise the play. Permian volumes will grow year-on-year for the foreseeable future.

Is the rest of non-OPEC growing, too?
Overall, yes. Production outside the US stagnated in the immediate aftermath of the price crash. The industry adapted and cut costs, and supply is growing again. We forecast non-OPEC production outside the US to increase from 2018 by 1.2 million b/d by 2020, almost half what the US will deliver. The bulk is from new projects in Brazil, Canada, Australia and Norway.

Will demand growth absorb all the new supply?
No, but oil demand is ticking along quite nicely. We expect growth of 1.1 million b/d in 2019, accelerating to 1.5 million b/d in 2020 – assuming a gentle easing of global economic growth rather than a major slowdown. Asia and US petrochemicals provide much of the growth, with a recovery in the Middle East and Latin America, and the IMO in 2020, helping things along.

And OPEC+ is still managing the market?
It has to – to balance the market. Saudi Arabia and the UAE, the two biggest OPEC producers, have reduced production by about 1 million b/d from October 2018 levels. That’s more than twice the cuts they agreed to, and despite the loss from the market of 0.8 million b/d from Libya, Venezuela and Iran. The reductions in OPEC supply have brought the market into balance in 2019 – 1.0 million b/d of global supply growth versus 1.1 million b/d of demand growth. Without the fall in OPEC production, the market would be awash in crude and prices much lower.

What will OPEC+ do as Iran’s exports fall?
The market is on course to tighten in the third quarter, so Saudi Arabia is starting to lift its production to compensate. Presently, OPEC has around 1.8 million b/d of spare capacity that can be brought on stream within a month. The tricky bit will be timing – balancing the Saudi and others’ increases with the fall in Iran’s exports. That could mean price volatility through the transition period this summer.

Could prices go higher?
We expect Brent to hold a little over US$70/bbl in the coming months. But the US policy decision to throttle supply with simultaneous sanctions on Iran and Venezuela is fraught with risk. Yes, OPEC can meet the immediate shortfall, but that leaves precious little spare capacity if there’s more supply disruption. Mounting geopolitical tension is a real threat to oil market stability.
Source: Wood Mackenzie

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Another first for US LNG exporters as six facilities receive gas same day

Gas deliveries were observable Wednesday at all six US LNG export facilities in the Lower 48 states, the first time that has happened as America is poised to increase its share of the global supply market, S&P Global Platts Analytics data showed.

Four of those facilities are currently operating, following Cameron LNG’s startup Tuesday in Louisiana, and two more are preparing to begin production – Kinder Morgan’s Elba Liquefaction in Georgia and Freeport LNG in Texas.

Combined, total LNG feedgas demand from all six fully operational LNG terminals could be upwards of 11.3 Bcf/d, Platts Analytics data showed. Total deliveries set a new record of 5.9 Bcf/d on May 12 and were near that level on Wednesday, with all six facilities reporting incoming gas deliveries, albeit tiny in Elba’s case.

US LNG market growth will depend on the utilization of those facilities, as well as the success of a dozen other second-wave projects that are actively being developed for service in the early- to mid-2020s.

The increased activity will provide new outlets for gas supplies from US shale drillers in key Gulf Coast, Midcontinent and Northeast basins. A proposed West Coast facility, if built, would be able to tap Rockies gas production. US midstream operators will also benefit as pipeline volumes are expected to get a lift.

With the startup of LNG production at Cameron LNG, feedgas deliveries to the facility are expected to ramp up there in the days ahead. Majority owner Sempra Energy said the first commissioning cargo would be loaded in the coming weeks. Project officials said during a tour of the facility in February that the number of commissioning cargoes that are shipped before commercial service begins could range from one to seven, depending on customer needs.

Netbacks from the Platts JKM, the benchmark price for spot-traded LNG in Northeast Asia, to the Cameron LNG export facility were estimated at just over $1.10/MMBtu on Tuesday, down roughly 30 cents/MMBtu since the beginning of the month, largely due to weakening bids in Asia and rising Atlantic Basin day rates. Despite this drop, the JKM has maintained a roughly 60 cent/MMBtu premium over the UK’s National Balancing Point, suggesting that initial exports from Cameron will be incentivized to deliver into the Asian markets.

This trend is also demonstrated by the forward markets, which indicate that the JKM netback will continue to outpace the NBP netback through late-summer, Platts Analytics data showed.

Besides Cameron LNG and the two export facilities preparing to start up, Cheniere Energy operates Sabine Pass in Louisiana and a terminal near Corpus Christi, Texas. Dominion Energy operates Cove Point in Maryland.

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Hess Produces Record-Breaking Test Well In Williston Basin

Oil Patch Hotline
Thu, 05/02/2019 - 10:09

Hess Corp. has produced a record-breaking 24-hour test well this month in McKenzie County, N.D., surpassing all records for U.S. land wells, according to an article in the website of the Oil Patch Hotline, an oil and gas trade publication for the Williston Basin.

“This was a barn burner,” said Hotline Publisher Dennis Blank. “The highest IP tests recorded before this on new horizontal Bakken wells were in the range of 3,000 to 4,000 barrels of oil equivalent per day.”

Hess said the An-Bohmbach-153-94-2734H set a new record 24-hour IP at 14,662 boe/d. The well produced 10,169 barrels of crude oil and 26,960 Mcf of natural gas and is located in Sec. 22, T153N-R94W. This new record breaker followed an earlier April 5 record of 10,626 boe/d on a companion horizontal well in the same pad.

“It was a great well and a great result,” said Hess President Greg Hill. “We achieved a very high rate IP, and it confirmed that our acreage performed very strongly in comparison to other operators.”

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8 hours ago, ceo_energemsier said:

Shale industry to be profitable in 2019: IEA: The shale industry worldwide is expected to achieve positive free cash flow this year, according to a report released by the International Energy Agency.

It would be the first year since 2010 cash flow is predicted to be positive, anticipating a 50% increase in cash flow. There also is expected to be a 20% decrease in investment between 2017 and 2018 in the U.S. sector, which is the global leader in terms of spending on energy supply.

According to the World Energy Investment 2019 report, positive free cash flow should be reached because of three factors, implying the current WTI price of $60 per barrel doesn’t decline significantly.

First, the numerous drilled but uncompleted wells (DUCs) can be brought online with a limited amount of spending. According to the IEA, the number of completed DUCs has been increasing since February.

Second, new pipelines in the Permian Basin are starting to flow product, allowing for more export capacity to go alongside production growth.

Finally, independent companies are likely to stick to cash flow neutrality with crude priced between $50 and $55/Bbl, as investors put more pressure on their clients.

"There is also expected to be a 20% decrease in investment between 2017 and 2018 in the U.S. sector,..."

The last time I checked it was 2019, so this expectation is irrelevant. 

This error tends to 'poison' the entire article and makes any other statement suspect.

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Quote

I believe it when I see debt reduction and return of value to the shareholders. @Mike Shellman seems to think it'll happen then the fat lady sings https://www.oilystuffblog.com/single-post/2019/05/16/International-Erroneous-Agency

So true.  Put the pen to the paper on some of these completed fracked wells in Oklahoma.  Despite high initial production, the well's production falls way off in the long term.  The costs involved, including mineral rights and legal, don't make them very viable for positive cash flow.

 

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Additional Capital Discipline Critical for Future Shale Sucess

 

 

The shale industry continues to surprise and confound both the market and investors: the market by producing more than expected, but investors by producing lower returns than they would like. The result has been a cry from some investors to exhibit more capital discipline in order to reduce costs and improve returns. 

It seems as if the smaller shale companies are genetically driven to race ahead, in spite of the torpedoes, as they were born from an aggressive outlook towards an evolving new geological province. George Mitchell succeeded in unlocking the shale gas resource by not listening to financial advisors who thought he was throwing away his money. Also, when the shale resource was poorly understood (and oil and gas prices were astronomically high), it seemed prudent to lock up leases as quickly as possible. Unfortunately, this led to high debt levels which proved difficult to service when prices retreated, causing a number of bankruptcies and restructurings. 

Debt reduction became the watchword, and did so again after last fall’s surprise oil price collapse. Rystad survey suggested a five percent reduction in capital expenditures by shale producers. Now, however, some companies appear to be ramping up activity, causing one investment firm (Tudor Pickering Holt) to say, “Please for the love of God, don’t do it!” 

But I would argue that the current situation is not as risky as the two previous groups of failures, in two particulars. First, companies are not engaging in a mad land-rush where they acquired large amounts of non-producing assets; they are more focused on drilling, which generates immediate revenue. Second, the last two rounds of bankruptcies and restructurings were set off by the collapse in first, natural gas prices, and then world oil prices (See figure).  Gas had been around $8/Mcf and dropped to $4/Mcf while oil had gone from $100/barrel to roughly $50.

 

INSERT TITLE HERE
U.S. Oil and Gas Prices

The odds of oil or gas prices dropping by 50 percent from current levels for an extended period appears vanishingly small.  Natural gas, in particular, is a relatively stable market where booms and busts are less common, since political supply disruptions are few and OPEC irrelevant. It is hard to imagine natural gas dropping from $2.50 to $1.25/Mcf (ignoring the Permian situation), and while oil could conceivably fall to $30 for WTI, that is clearly unsustainable. The worst threat would be if some event in the Mideast sent oil prices soaring, and shale producers assumed they would persist at elevated levels—and borrowed and spent on that assumption.

And oil and gas are different. Natural gas producers in the Marcellus cannot expect a price boom to give them a big payday and should stick to the “shale as manufacturing” approach with steady investment and moderate debt. For oil producers, even a year and a half of high prices can yield significant returns from fast-declining wells, so that having an inventory of prospects (undrilled or unfracked) which can be brought online rapidly when prices are high can be a valuable strategy—as long as the company can pull back when prices drop. 

This doesn’t mean that companies should disregard their debt levels. The threat to cash flow is naturally greatest for the smaller producers who don’t have the deep pockets of an Exxon or a Chevron and they should avoid treating their investment as a gamble: big payout with high prices, risking bankruptcy with a significant price drop. 

 

 

For U.S. shale companies, 2019 will see a boost in production and a decrease in capital spending, according to analysis by Rystad Energy.

After analyzing fourth quarter 2018 earnings reports from 45 U.S. shale operators, Rystad found that, on average, companies planned on 15 percent growth in oil production while cutting capital spending by five percent.

However, oil supermajors   ExxonMobil and Chevron plan to increase investments on the heels of strong 4Q 2018 earnings propelled by Permian production.

“Earnings and guidance confirm that most U.S. shale operators aim to moderate drilling and completion activity this year, prioritizing cost discipline over aggressive growth,” Rystad Energy partner Artem Abramov said in a statement emailed to Rigzone.

Abramov added that an average of five percent growth is based upon just a handful of shale operators anticipating double-digit oil production additions compared to 4Q 2018.

“In fact, a number of shale players estimate a decrease in oil output versus 4Q 2018,” he said.

However, five percent growth for all of 2019 compared to 4Q 2018 would still equal 10 percent growth between 4Q 2018 and 4Q 2019.

“If this growth rate is representative for the entire 9.5 million barrels per day oil output currently achieved in the Lower 48 states excluding Gulf of Mexico, we are then talking about nearly 1 million barrels per day of oil production growth from the U.S.,” said Abramov.

 

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(edited)

On 5/20/2019 at 4:20 AM, DanilKa said:

seems to think it'll happen then the fat lady sings

Hey, thanks for this, mate. Hope springs eternal for the US shale oil phenomena. Profit, deleveraging, dividends, no flaring, no groundwater use, growth...its all going to come together some day very soon. We should give it all another ten years, and another three or four hundred billion of long term debt before we start to panic, right? 

Remember, if hard hats can grow on trees, so can shale oil ! 

 

Hard Hat 7.jpg

Edited by Mike Shellman

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Typical Worker’s Pay Nears $200,000 at Oil Refiner

 

Workers at oil and gas companies ranked near the top in median pay, as shale boom squeezed already tight labor market.

It was a fruitful year for the rank and file at oil-and-gas companies, from Exxon Mobil Corp. to Phillips 66.

Oil and gas drillers and refiners had some of the highest-paid median workers in the energy and utility sectors in 2018, according to The Wall Street Journal analysis of annual pay disclosures by hundreds of big U.S. companies.

Houston-based Phillips 66 paid its median worker $196,407, the highest of any company in the sector. Phillips was followed by Anadarko Petroleum Corp. at $183,445. Oil giant Exxon Mobil, which has roughly 72,600 employees, according to its latest proxy, had the third-highest median worker pay with $171,375.

Phillips 66 and Anadarko both boosted their 2018 median pay by about 15% in 2018 compared with 2017. Exxon raised its median pay about 6%. Oil-and-gas companies typically pay their workers better than many other sectors because they have fewer low-paid retail jobs and must compete in a tight labor market driven in part by the shale-oil boom.

Phillips 66 and Exxon declined to comment beyond their proxy statements. Anadarko Petroleum didn’t respond to requests for comment.

Utility companies, such as Xcel Energy Inc. and American Electric Power Co., were closer to the energy and utility sector’s median of about $117,000, the highest median of any sector in the S&P 500. An American Electric Power spokeswoman said its compensation plan takes into account employee performance and that the company compares its pay levels to its peers. Xcel Energy didn’t respond to requests for comment.

The lowest-paid median employee in the energy sector worked at Marathon Petroleum Corp., earning $27,703. Unlike other oil and gas producers, Marathon operates roughly 3,900 Speedway convenience stores with about 40,000 employees, most of whom are part-time and work lower-wage jobs, according to Marathon’s latest proxy filing.

Without Speedway, Marathon’s median worker pay is $167,607, according to its proxy filing. The company claims in its filing that it is the only domestic downstream refining company with a substantial retail presence.

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