Wonders of US Shale: US Shale Benefits: The U.S. leads global petroleum and natural gas production with record growth in 2018

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Big Oil Investors Bracing for Bad News



(Bloomberg) -- Slumping energy prices, sluggish global demand and shrinking chemical margins are weighing on the oil industry as its biggest names prepare to announce quarterly results to investors demanding ever-higher payouts.

The so-called supermajors -- Exxon Mobil Corp., Royal Dutch Shell Plc, Chevron Corp., Total SA and BP Plc -- are expected to disclose a 42% plunge in third-quarter earnings, on average, when they post results this week. That drop-off is too steep to blame on the 18% decline in crude oil prices, which means executives will have some explaining to do.

Exxon, Shell, and BP already have already taken steps to manage shareholder expectations by releasing limited data points on things like refinery repairs, asset sales and hurricane impacts on offshore oil production. Nonetheless, investors will be watching for additional color on what to expect for the remainder of 2019.

To make sense of all the moving parts in Big Oil’s earnings reports that start Oct. 29 with BP, look for these five things:

1. Surprises

Most of the bad news already should be priced in. Exxon fell 2.6% on Oct. 2 after disclosing a half-billion dollar hit from lower oil prices, a deficit that wasn’t plugged by improved refining profits.

Meanwhile, Shell warned that oil and gas output inched lower, and its refineries and chemical plants operated at about 90% of full capacity. BP warned that its tax bill rose, production declined, and it incurred an impairment on some assets it sold, factors that dampened hopes of an imminent dividend increase.

2. Petrochemicals

Long touted as Big Oil’s next high-growth opportunity, petrochemicals are languishing. The U.S.-China trade war has weakened demand for plastics amid concerns that $40 billion in planned U.S. Gulf Coast chemical plants will create a glut.

“Current trends continue to suggest a prolonged downturn” in chemicals, RBC Capital Markets analyst Biraj Borkhataria said in an Oct. 17 note. Exxon, with its giant chemical division, is the most heavily affected by this trend among peers.

What Bloomberg Intelligence Says

Chemicals may not recover materially from recent margin contraction, and overhang from oversupply amid economic slowdown is concerning.

--Fernando Valle, analyst

3. Growth

In a world awash in crude and confronted with climate change, growth is a major conundrum for Big Oil. Should these companies be expanding or winding down? Investors don’t seem to have a clear answer right now. Exxon’s stock has been punished after the company spent too much on future projects while Chevron is regularly challenged on whether it has enough in the tank for growth after 2023.

Meanwhile there’s uncertainty whether Shell can match historic returns with investments in renewables and power, though earlier this month Total CEO Patrick Pouyanne declared the company has already achieved double-digit returns by selling electricity.

Don’t expect major pronouncements on such existential issues, but executives may offer clues to their thinking during earnings conference calls when they’re quizzed about 2020 spending and progress toward asset-disposal targets. BP’s call may get more scrutiny than most after it said earlier this month that longtime CEO Bob Dudley is handing the reins to upstream director Bernard Looney in February.

4. Shale

Exxon and Chevron each plan to more than triple production in the U.S. Permian Basin to 1 million barrels a day by the early 2020s. As for the European giants’ attitude toward shale, BP’s $10.5 billion acquisition of BHP Group Ltd.’s assets last year was a statement of intent.


Analysts will be keeping a close eye on how those companies avoid the pitfalls of smaller rivals stung by overambitious drilling programs, and how their performance stacks up against lofty targets. Despite the production boom, investors have soured on shale because of poor performance by independent producers that burned through nearly $200 billion of cash in the past decade.

5. Dividends

The supermajors have long been among the stock market’s most generous dividend payers but in the new world of plentiful crude and anti-fossil fuel campaigns, increasing payouts and share buybacks are seen as key to retaining investors. Just as critical is whether the companies can afford them: the supermajors’ dividend yields this year surged to more than double the return on 10-year Treasury notes.

While none of the five companies’ dividend programs are in jeopardy, investors are keen to see how sustainable they are when balanced against costly drilling and construction projects, such as Exxon’s $30 billion-a-year spending program, and Shell’s investments in lower-profit renewable power.

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Battered Oil Majors Give Guidance On Permian Production, IMO 2020 Impacts


American oil production is expected to grow 7.2% next year to 13.2 million barrels per day; pipeline takeaway capacity from the Permian Basin will grow 2.4 million barrels/day, threatening crude by rail; and oil majors are already enjoying widening refining margins in anticipation of IMO 2020.

ExxonMobil (NYSE: XOM), Chevron (NYSE: CVX) and Royal Dutch Shell (NYSE: RDS-A) reported their financial results for the third quarter of 2019 on Oct. 31 and Nov. 1.

All three companies experienced deeply negative year-over-year earnings growth, mostly due to price action in global petroleum markets, which affected realized prices from oil and gas sales. West Texas Intermediate crude oil prices are down 12.6% since Nov. 1, 2018, to just over $55/barrel today.

ExxonMobil's fully diluted earnings per share (EPS) fell to $0.75 for the quarter, up 2.74% sequentially but down 48.6% year-over-year. Chevron's EPS plummeted to $1.36, down 40% sequentially and 35.5% year-over-year. Shells' earnings fell to $0.59 per share, up 37.2% sequentially but down 13.2% year-over-year.

Oil company investment and performance are relevant to transportation and logistics for three reasons. 

First, investments by oil majors in exploration and production in North America are a significant driver of freight demand. Second, midstream investments in pipeline construction, especially pipelines that add to the takeaway capacity of the Permian Basin, will have a permanent impact on demand for crude by rail and crude by truck. Third, the oil majors' guidance for downstream earnings — which includes refineries producing diesel fuel — holds clues to the impact that IMO 2020 will have on distillate demand and the spread between crude and diesel prices.

Guidance on North American Exploration and Production

The hydraulic fracturing ("fracking") of shale oil formations in North America is a significant driver of truckload demand to move equipment, people, sand, water and chemicals. Hundreds of truckloads are associated with the drilling and completion of each frack well, and because they tend to experience rapid losses in production after the first year, wellhead equipment is moved and more wells are drilled than in conventional oil deposits.

Of the three companies, ExxonMobil has the most aggressive projections for production growth in the Permian and Bakken shale basins, with plans to essentially triple its production to nearly 1.4 million barrels per day. Permian production increased 7% sequentially in the third quarter and was up 72% year-over-year.






Chevron produced 455,000 barrels/day in the Permian Basin in the third quarter, up 35% year-over-year, and said its projected oil and gas production growth of 4-7% next year would be driven largely by growth in the Permian Basin and by other shale and tight rock plays.

Royal Dutch Shell does not have a large North American portfolio but has Shell-operated shale projects coming online in the Permian Basin and Fox Creek, Alberta, in 2019-20 which will produce, at peak, 250,000 barrels/day.

The oil majors' expansion of Permian production has to be read against a backdrop of struggling independent producers, many of whom have been cash flow negative and are finding themselves capital-constrained as commodity prices fall. In other words, shale production in North America is consolidating rather than expanding dramatically, although it is still expected to grow year-over-year in 2020.


Recent forecasts from the Energy Information Administration (EIA) project slowing overall production growth in the Permian Basin for 2020.

"EIA expects growth to pick up in the fourth quarter as production returns in the Gulf of Mexico and pipelines in the Permian Basin come online to link production areas in West Texas and New Mexico to refining and export centers on the Gulf Coast," the EIA wrote in its October Short-Term Energy Outlook. "However, EIA forecasts growth to level off in 2020 because of falling crude oil prices in the first half of the year and continuing declines in well-level productivity. EIA forecasts U.S. crude oil production will average 12.3 million b/d in 2019, up 1.3 million from the 2018 level, and will rise by 0.9 million b/d in 2020 to an annual average of 13.2 million b/d."

For 2020, the EIA expects American crude oil production to rise 7.4% to 13.2 million barrels/day.

Guidance on Permian Basin Pipeline Construction

This year, nearly every Class 1 railroad experienced strong growth in the Petroleum Products commodity class, which includes crude by rail. CSX's petroleum carloadings are up 4.9% year-over-year, Norfolk Southern are down 3.3%, Union Pacific are up 22.4%, BNSF is up 19%, Canadian National is up 20.4%, Canadian Pacific is up 13.1%, and Kansas City Southern is up 25.6%.

Except for the Canadian rails, which will be able to continue shipping crude due to provincial Alberta policy, those volumes may be under threat from new pipelines that can move crude oil even more cheaply than the railroads.

Of the three oil companies, ExxonMobil is the only one with significant midstream assets in the United States. ExxonMobil is participating in a joint venture with several other midstream players to build the Wink to Webster crude oil pipeline, which will add 1 million barrels/day of takeaway capacity from the Permian Basin to refinery facilities on the Gulf Coast. That pipeline is projected to come online in early 2021.

Simply put, there are a number of pipeline projects funded and underway in the Permian Basin. On its earnings call this week, Enterprise Products (NYSE: EPD) CEO Jim Teague said the company's Midland-to-ECHO 3 and 4 Permian crude pipeline system expansions will add about 900,000 barrels/day of capacity in total. Phillips 66 has a new 900,000-bpd pipeline, the Gray Oak, which is still undergoing testing. It's the last of three major pipelines connecting the Permian to the Gulf Coast to come online this year. The other two, the Plains All American Cactus II and Kinder Morgan's Gulf Coast Express, will move 670,000 barrels of oil and 2 billion cubic feet of natural gas per day, respectively.

That's a total of 2.4 million barrels/day of additional takeaway capacity. For reference, the newer tanker railcars, which are being phased in due to safety concerns, carry about 675 barrels each. The new pipelines will therefore replace roughly 3,555 railcars worth of crude-by-rail demand each day.

Guidance on Downstream Earnings and IMO 2020 Impacts

It's impossible to predict the price of petroleum commodities, but oil majors are reporting widening spreads between crude and diesel and sour/sweet distillates (i.e., high-sulfur and low-sulfur distilled products like gasoline, diesel and marine fuel oil).

Royal Dutch Shell said its downstream earnings were positively impacted by "stronger contributions from oil products trading and optimisation, as we realised opportunities from our well-positioned and integrated portfolio in the lead up to the International Maritime Organisations' stricter environmental rules for shipping fuel, which will start on the 1st of January 2020."

ExxonMobil said clean/dirty spreads were widening, which favors more complex refineries



Chevron was reticent on the effects of IMO 2020 in its earnings presentation, but we note that the company enjoyed $255 million of margin expansion in its downstream business in the third quarter on a sequential basis, which followed a $260 million sequential downstream margin expansion in the second quarter. The vast majority of that was driven by better margins in Chevron's Asian refineries, the company said. Seven of the global top ten container ports by throughput are located in Asia.

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Who really knows where energy is going? After all, it's a crazy, mixed-up world out there. 

It's hard to imagine that the Sabatier Reaction is over a hundred years old. The electrolysis of water for purposes of methanation seems almost comical in the world of excess natural gas, especially methane, yet there is still a power utility in North Dakota that uses that principle with coal as its feedstock. There is a similar one in Europe: either France or Germany. 

In the midst of a Green Movement that takes no prisoners, the world still moves on hydrocarbon energy. It's like hanging onto an old girlfriend while you are secretly sending flowers to a new prospect. 

It makes you want to have been born in an earlier time. But me? I would have died without penicillin. 

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On 8/23/2019 at 2:28 PM, ceo_energemsier said:

Flaring limits, bottlenecks to constrain Bakken shale growth

There is considerable potential to increase oil production from the Bakken shale to at least 2 million b/d from its current 1.44 million b/d, but flaring regulations and infrastructure bottlenecks are limiting production growth, according to GlobalData.



There is considerable potential to increase crude oil production from the Bakken shale to at least 2 million b/d from its current 1.44 million b/d, but flaring regulations and infrastructure bottlenecks in North Dakota are limiting production growth, according to London research and consulting firm GlobalData.

Bakken oil production is facing constraints associated with prescribed limits set by North Dakota on natural gas flaring. The state is currently flaring about 19% of the gas it produces—well above the 12% permitted by state regulations.

In a recent report, GlobalData states that in 2018, the major counties for crude oil and gas production in the Bakken shale were McKenzie, Williams, Mountrail, and Dunn—all in North Dakota. Continental Resources Inc., Hess Corp., Whiting Petroleum Corp., ExxonMobil Corp., and ConocoPhillips were the leading producers in the play in 2018.

“Bakken oil wells show competitive performances when compared to recently completed wells in the Permian basin and Eagle Ford,” said GlobalData oil and gas analyst Andrew Folse, but “to some extent, the actual potential of the Bakken play is not getting realized due to restrictions on the flaring of natural gas in North Dakota, as most of this flared gas is associated with oil-producing wells in the Bakken formation.” Folse said, “As long as gas infrastructure in the region does not expand, the pace of drilling new wells will be constrained and oil production from the Bakken will remain flat or grow at a low rate.”

The Permian basin, Bakken, and Eagle Ford are currently producing more than 83% of the country’s oil production. During this year’s first half, these three formations averaged 4.05 million b/d, 1.44 million b/d, and 1.43 million b/d, respectively. Permian production has increased by 9%, the Bakken about 1%, and the Eagle Ford has stayed constant throughout the year.

“Bakken wells exhibit the lowest breakeven price among the three shale plays at $30.50/bbl, mainly due to the exceptionally high 30-day initial production rates of over 1,250 boe/d observed in this play. Also, the Bakken total production stream is over 75% oil where the other plays are around 58%,” Folse said.


“Moreover, many Bakken operators are picking up the trend of drilling longer laterals and experimenting with completion designs. Companies are drilling laterals up to 12,000 ft. The general objective remains to increase the productivity of the new producing wells in a higher proportion with respect to the cost increase associated with these more complex wells,” he said.

The Bakken should have built their pipeline years ago instead of getting involved with the Canadians. It was a geopolitical, strategic mistake. 

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14 hours ago, Boat said:

The Bakken should have built their pipeline years ago instead of getting involved with the Canadians. It was a geopolitical, strategic mistake. 

everyone should have built every where else!! US west coast , the most viable, the nut bags blocked it, then the canadians

just send it south to TX


or let that other pipeline happen!!!!


Edited by ceo_energemsier

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ConocoPhillips Counting On US Shale To Bring In More Cash

The U.S. independent has set its sights on bringing in $50 billion in free cash flow over the next decade, including $19 billion from its Lower 48 assets.


U.S. independent ConocoPhillips Co. aims to generate about $19 billion in free cash flow between 2020 and 2029 from its Lower 48 assets with the Permian Basin, Bakken and Eagle Ford Shale—the so-called Big 3—leading the way.

“We now have 6.5 billion barrels at less than $40 cost of supply in the Lower 48. Six billion barrels of that is in the Big 3 and that’s grown by about 1 billion barrels since our last Analysts Day in 2017,” Dominic Macklon, president of the company’s Lower 48 region, told analysts Nov. 19. “No greater than 97% of those increases have been organic, driven primarily by successful results in additional benches in the Delaware and improved well performance in the southwest area of Eagle Ford.”

The goal is part of the company’s 10-year plan that targets about $50 billion in free cash flow, limiting spending to less than $7 billion over the next decade as it grows annual production by more than 3% on average.

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Natural Gas Emerging as the World's Go-To Fuel


Natural gas is the cleanest, most versatile, and most flexible fossil fuel. Gas emits 50 percent less CO2 than coal and 30 percent less than oil, not to mention having near zero local pollutants that cause smog. In addition, in contrast to coal (65 percent for power) and oil (60 percent for transport), gas has a variety of uses. Gas gets utilized in the power, industry, commercial, residential, and the transportation sectors. And increasingly important as nations seek to decarbonize, gas is the backup generation source for intermittent renewables. It is gas that fills in for those frequent times when the “the wind isn’t blowing” and “the sun isn’t shining.” 

This all explains why gas today provides a rising 30 percent of the energy used in the rich OECD economies. Now, the still developing countries – which constitute 85 percent of the global population – hope to follow the Western model in making a global “dash to gas.” China and India especially have national strategies to lower their overdependence on coal and lift gas’ 8 percent share of energy supply to around 20 percent.    

Since 2000, global gas reserves have expanded over 50 percent to 7,000 Tcf. In turn, total demand since 2010 alone has risen 25 percent to 380 Bcf/d. The rapidly growing LNG trade is encouraging more gas usage, evolving this longtime regional product into a global and fungible commodity like oil. LNG continues to extend its ~15 percent share of the world’s gas consumption by connecting distant suppliers and buyers. LNG investments hit $50 billion in 2019 alone, with hundreds of billions of dollars more on the horizon.

The U.S. shale revolution itself is at the heart of the global “dash to gas.” Over the past decade, U.S. gas production has risen over 60 percent to 93 Bcf/d. Excess supply has helped the U.S. become the third largest LNG supplier in just a few years, now shipping out over 7 Bcf/d. The growth of destination-flexible, hub-priced LNG exports from the U.S. is establishing a more liquid and flexible gas market. Along with advancing systems like FLNG, this is deepening the pool of importing nations, now at 45 versus 25 five years ago.

U.S. LNG is adding the transparency and predictably that the market has been lacking since its inception decades ago. The U.S. is also improving pricing dynamics by increasing gas-on-gas competition and spot market sales, while lowering the riskier buyer reliance on oil-indexation, overly high volume purchases, and long-term contracts. So not just lowering pricing domestically, the U.S. shale boom and its LNG are helping to keep gas prices lower globally, boosting more interest in the commodity itself.

Looking forward, the International Energy Agency (IEA) expects that the U.S. will add 30 percent of the world’s new gas production through 2030, and the country could become the largest LNG exporter within five years. To be sure, however, ongoing liquefaction capacity gains from Qatar, Australia, Russia, Canada, and some African nations are expected to keep global gas prices low and add more opportunities for buyers.

Low prices themselves are being understated in terms of locking-in more gas infrastructure and usage. They are especially required for the still developing nations because citizens simply cannot afford more expensive energy. This justifies previous World Bank President Jim Yong Kim’s view that a Western insistence on “only wind, only solar” for the world’s poor was not just impractical but utterly unfair. To illustrate, rich Germany is spending literally hundreds of billions of dollars forcing wind and solar into the system yet is now looking at building three LNG import terminals.

Indeed, many other nations understandably want to follow the same “dash to gas” that the U.S. has. The IEA has credited the shale gas boom as the key factor in why the U.S. has been reducing CO2 emissions faster than any other nation. In the not too distant future, perhaps in less than a decade, natural gas will surpass oil to become the world’s primary fuel. Farther out, the U.S. Department of Energy’s International Energy Outlook 2019 models that global gas demand will soar 40-45 percent by 2050.

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In just a few months, the U.S. will be fully energy independent and by 2030, the country’s total primary energy production will outpace primary energy demand by 30 percent, according to a forecast by Norwegian energy research firm Rystad Energy.

“This milestone follows a strong period of growth in both hydrocarbon and renewable resources, and we forecast that the U.S. will have primary energy surplus – and not a deficit – by February or March 2020, depending on the intensity of the winter season,” said Sindre Knutsson, vice president on Rystad Energy’s gas markets team.

Rystad Energy expects the Energy Information Agency’s (EIA) next monthly release to show that the U.S. has been self-sufficient in primary energy for a full 12-month period, from October 2018 through September 2019.

Knutsson said this will be the first time this has occurred since May 1982.

Broader Implications

The U.S.’ move to energy independence will affect the industry in several ways.

The U.S. had a petroleum deficit of $62 billion in 2018 – equivalent to 10 percent of the country’s overall trade deficit of $621 billion, including goods and services.

“These changes in the U.S. energy balance could turn [that deficit] to a surplus of $340 billion by 2030,” said Knutsson. “That adds up to a $400 billion shift, in the space of only a dozen years, thanks primarily to the gargantuan rise of output from the US shale sector.”

Rystad Energy believes total primary energy production will grow from 95 quadrillion Btu in 2018 to 138 quadrillion Btu in 2030, with crude oil and natural gas production driving that growth at 75 percent and 38 percent, respectively.

Production in the Permian, Bakken and Eagle Ford shale plays will drive crude output growth while supply increases in the Marcellus, Haynesville and Utica basins will drive natural gas production growth.

As for demand, Rystad Energy forecasts cumulative average growth of about 0.4 percent from 2018 to 2030, to about 106 quadrillion Btu in 2030.

“The emerging energy surplus will make the U.S. less vulnerable to foreign energy-related politics and facilitate growing exports,” said Knutsson. “While renewable energy output will be consumed domestically, the future for oil and gas exports is bright.” 




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US to Become Net Oil Exporter in 2020: Shale Drillers to Gain


Advanced techniques like hydraulic fracturing and horizontal drilling have made U.S. shale operations extremely efficient. Explorers are now capable of producing more oil with the deployment of lesser rigs. Thus, despite the recent signs of moderation in American oil production growth, the country is poised to become energy-independent by next year.

Shale Drillers to Back US’ Energy Independence

Conservative capital spending by U.S. oil explorers have slowed down drilling activities across the country’s major shale plays. With a drop in rig count, shale resources have been witnessing a decline in crude production growth. In fact, the growth in production will continue to decelerate since most of the analysts are predicting a curtailment in future drilling programs.

Despite the slowdown, the overall production volumes of crude in America will be growing in the coming years. According to the U.S. Energy Information Administration (EIA), from a record annual average volume of 11 million barrel per day (Bbl/D) in 2018, the United States will increase average crude production to 12.3 million Bbl/D in 2019. Also, the annual average U.S. production volumes of the commodity in 2020 will rise to 13.2 million Bbl/D, as estimated by EIA.

Precisely, the prolific shale plays in the United States, especially the Permian Basin, will continue to contribute to the country’s crude production and hence has paved the way for America’s energy independence. EIA added that from an average net import volume of 520,000 Bbl/D of crude oil and petroleum in 2019, the United States will report net export volumes of the commodities at an annual average of 750,000 Bbl/D in 2020.

Oil Industry’s Future Lies With America

Analysts not only expect America to become a net exporter of oil in the years to come but also anticipate the United States to be among the few exporting countries to primarily contribute additional crude volumes to the global energy market. Meanwhile, OPEC projects production decline in its volumes for oil and other liquidsover the next five years. OPEC estimates production of liquids at 32.8 million Bbl/D in 2024, suggesting a decline from the current level of 35 million Bbl/D.

Thus, in the production race for crude oil, the United States will be surpassing OPEC despite the slowdown in America’s shale drilling activities. Precisely, when OPEC is planning to curb its annual average crude production to stabilize oil prices amid the global supply glut, the United States has decided to increase its production share in the global energy market.

Shale Drillers in Focus  

America’s intention to continue to contribute additional oil worldwide despite low crude prices reflects the shale drillers’ operational efficiencies. Thus, it is worthwhile to track prospective oil explorers with footprint in prolific shale plays in the United States that include Permian basin, Eagle Ford and Bakken.

We have shortlisted five U.S. shale drillers, each carrying Zacks Rank #3 (Hold), that investors should keep an eye on. You can see the complete list of today’s Zacks #1 Rank (Strong Buy) stocks here.

With the divestment of its Eagle Ford resources, Pioneer Natural Resources Company PXD has become a pure-play Permian stock. The company has estimated more than 20,000 drilling sites in the nation’s most prolific basin which is likely to provide the company with decades of oil production.

Diamondback Energy, Inc. FANG is a pure-play Permian player with presence across more than 394,000 net acres in the Permian. With more than 7,000 drilling locations in the basin, the company is expected to continue to ramp up its oil equivalent production.

Callon Petroleum Co. CPE — is solely focused on the Permian Basin. The company boasts an impressive footprint (86,000 net acres) throughout the region. The company entered the basin in 2009 with around 8,800 net acres and has been strengthening its hold in the region since then.  

In the Delaware Basin — part of the larger Permian basin — and Eagle Ford, EOG Resources, Inc. EOG has identified a total of 8,400 undrilled premium locations that are likely to contribute the company with incremental oil production volumes.

ConocoPhillips Company COP derives significant volumes of oil from the Eagle Ford, Bakken, and Permian areas.


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1-U.S. crude output rises 66,000 bpd to record 12.5 mln bpd in Sept- EIA



NEW YORK, Nov 29 (Reuters) - U.S. crude oil production in September rose to a new record of 12.46 million barrels per day (bpd) from 12.397 million bpd in August, the U.S. government said in a monthly report on Friday.

The United States has become the world's largest oil producer as technological advances have increased production from shale formations.

Oil output in Texas rose 72,000 bpd in September, while production in North Dakota and the Gulf of Mexico fell during the month. Production also climbed in Oklahoma and Alaska.

U.S. gasoline demand fell 652,000 bpd in the month to 9.2 million bpd. U.S. demand for distillate fuels, including diesel, fell 87,000 bpd to 3.9 million bpd, according to the report.

Meanwhile, monthly gross natural gas production in the lower 48 U.S. states rose to an all-time high of 104.8 billion cubic feet per day (bcfd) in September from the prior record of 104.2 bcfd in August, according to the EIA's 914 report.

In Texas, the biggest gas producing state, output increased 1% to a fresh record high of 29 bcfd in September.

In Pennsylvania, the second-biggest gas-producing state, output rose 0.1% to a record 19.24 bcfd in September from the prior all-time high of 19.22 bcfd in August

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U.S. Posts First Month in 70 Years as a Net Petroleum Exporter



(Bloomberg) -- The U.S. solidified its status as an energy producer by posting the first full month as a net exporter of crude and petroleum products since government records began in 1949.

The nation exported 89,000 barrels a day more than it imported in September, according to data from the Energy Information Administration Friday. While the U.S. has previously reported net exports on a weekly basis, today’s figures mark a key milestone that few would have predicted just a decade ago, before the onset of the shale boom.

President Donald Trump has touted American energy independence, saying that the nation is moving away from relying on foreign oil. While the net exports show decreasing reliance on imports, the U.S. still continues to buy heavy crude oil from other nations to meet the needs of its refineries. It also buys refined products when they are available for a lower cost from foreign suppliers.

“The U.S. return to being a net exporter serves to remind how the oil industry can deliver surprises -- in this case, the shale oil revolution - that upend global oil prices, production, and trade flows,” said Bob McNally, a former energy adviser to President George W. Bush and president of the consulting firm Rapidan Energy Group.

Soaring output from shale deposits led by the Permian Basin of West Texas and New Mexico has been in main driver of the transition -- but America’s status as a net exporter may be fragile. Many Texas wildcatters are predicting a rapid decline in production growth next year, while some Democratic contenders for the White House have called for a ban on fracking -- the controversial drilling technique that unleashed the boom.

“In the days of Jimmy Carter and even Ronald Reagan, we would have longed for this day,” said Jim Lucier, managing director of Washington, D.C.-based Capital Alpha Partners LLC. “Now we scarcely notice it at all.”

In its Short-Term Energy Outlook earlier this month, the EIA flagged the turnaround and forecast total net exports of crude and products of 750,000 barrels a day in 2020, compared with average net imports of 520,000 barrels a day this year.

Analysts at Rystad Energy said this week the U.S. is only months away from achieving energy independence, citing surging oil and gas output as well as the growth of renewables.

“Going forward, the United States will be energy independent on a monthly basis, and by 2030 total primary energy production will outpace primary energy demand by about 30%,” said Sindre Knutsson, vice president of Rystad Energy’s gas markets team.

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Study Forecasts More Increases in US Oil Production


Even though there appears to be signs of weakening in the crude oil and natural gas production boom in the U.S., a new report from the Energy Information Administration (EIA) predicts continued production increases through 2020.

EIA revised its Short-Term Energy Outlook this week forecasting a 119,000 barrels per day (b/d) increase in oil production in 2020 over 2019. EIA says oil production will increase to 12.3 million b/d this year, which is up from 11 million b/d in 2018.

EIA increased its U.S. benchmark West Texas Intermediate (WTI) crude oil price forecast by $2 per barrel in November to $56 and by $1 in both December and January to $55 and $54, respectively. The slight increase in crude oil prices also contributed to EIA’s increased production forecast for the first half of 2020 because of EIA’s assumption of a six-month lag between a crude oil price change and a production response.

The Permian Basin of West Texas and East New Mexico continue to lead the way. EIA forecasts Permian production will grow by 915,000 b/d in 2019 and by 809,000 b/d in 2020. EIA based production increases in the Permian Basin on the expansion of pipelines in the area allowing for more crude oil and natural gas to be shipped to consumers and relieving the price reduction because of oversupply.

“These expansions, which helped alleviate transportation bottlenecks and led to increased prices for WTI in Midland, Texas, (the price that producers may expect to receive in the Permian region) relative to prices for WTI-Cushing. The higher relative prices in the Permian region should continue to encourage crude oil production growth in the region,” EIA stated in the report.


EIA forecasts that the Bakken region in North Dakota will have the next largest crude oil production growth in 2019. EIA expects Bakken crude oil production will grow by 152,000 b/d in 2019 and 96,000 b/d in 2020. EIA forecasts that production in the Federal Offshore Gulf of Mexico will increase by 138,000 b/d in 2019 and 116,000 b/d in 2020.

Although EIA forecasts that overall U.S. crude oil production will continue to increase, EIA expects the growth rate will slow largely because of a decline in oil-directed rigs. According to Baker Hughes, active rig counts fell from 877 oil-directed rigs in the beginning of January 2019 to 674 rigs in mid-November, a 23 percent decline. Rig counts in the Permian region fell 15 percent during this period, from 487 to 408 rigs.

Because EIA expects WTI-Cushing crude oil prices to stay lower than $55 until August 2020, EIA anticipates that drilling rigs will continue to decline as producers cut back on their capital spending, resulting in notable slowing in the growth of domestic crude oil production over the next 14 months.

EIA noted that although U.S. rig counts are declining, improvements in rig efficiency, which allows fewer rigs to drill the same number of wells, partially offsets declining rig counts. In addition, higher initial production from wells (although not necessarily the total estimated ultimate recovery) is offsetting some of the slowdown in rig counts.

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Two oilfield services companies have conducted layoffs in Texas, according to notices received by the Texas Workforce Commission (TWC) on Nov. 22.

Houston-based National Oilwell Varco (NOV) said it is suspending operations at its facility in Galena Park, Texas, citing “unforeseeable business circumstances.”

The temporary closure will result in 85 layoffs, according to NOV, and affected employees were notified Nov. 22. The layoffs are permanent and will be finalized through Jan. 21, 2020.

Pumpco Energy Services, Inc., a subsidiary of Superior Energy Services, Inc., also conducted a workforce reduction at its Odessa, Texas location, resulting in the termination of 112 employees.

Pumpco, which has its headquarters in Houston and delivers fracking services for well completions, said all layoffs will be permanent and that affected employees are not represented by a union and have no bumping rights. 

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Halliburton Co. (NYSE: HAL) plans to cut more than 800 jobs after the closure of an office in El Reno, Oklahoma, according to the Houston Chronicle.

The company filed a letter with the Oklahoma Office of Workforce Development Monday disclosing the reductions. Michael Queener, vice president of the MidCon area at Halliburton, announced in the letter that the El Reno field camp, located about 30 miles west of Oklahoma City, would shutter operations, which includes a dispatch command center and several hydraulic fracturing crews. In total, 808 jobs are expected to be cut, according to the Chronicle.

This is not the first headcount reduction for Halliburton in 2019. The oil field services giant shed about 8 percent of its North American Workforce in the second quarter. Then, in the third quarter, it reduced the headcount of its Rocky Mountain arm by about 650 people in Colorado, Wyoming, New Mexico and North Dakota.

Although he did not explicitly indicate a trend of job cuts would continue, Halliburton CFO Lance Loeffler said at a Houston Business Journal energy panel in November that headcount reductions come as the company aims to reduce costs. 

“We don’t want to stack crews today that aren’t earning their cost of capital. That’s not what we’re in business to do,” he said at the time. “We’re doing that today because that is the stark reality of what pricing has done. That is what it has forced us to do.”

The oil and gas industry has faced contractions in recent months, with 23 percent of Texas companies in that sector reporting third-quarter layoffs, according to a survey by the Dallas Federal Reserve. 

Oil and gas companies are generally experiencing another wave of bankruptcies. There have been 50 bankruptcies across oil and gas upstream, services and midstream businesses through the first nine months of 2019, according to data from Haynes and Boone LLP’s latest bankruptcy report.

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Non-OPEC production is growing at record speed

Oil production from non-OPEC countries is expected to grow at record speed in 2020, creating a headache for OPEC, which is scheduled to meet this week in Vienna to discuss extending oil production cuts.




Oil production from non-OPEC countries is expected to grow at record speed in 2020, creating a headache for the Organization of the Petroleum Exporting Countries (OPEC), which is scheduled to meet this week in Vienna to discuss extending oil production cuts.


Rystad Energy predicts that total non-OPEC production (crude oil and condensate) will grow by around 2.26 million b/d in 2020, creating a challenge for OPEC and Russia as they attempt to balance the global oil market next year.

“The record high production growth from non-OPEC tight oil and offshore puts significant pressure on OPEC’s ability to balance the oil market in 2020. Rystad Energy believes that OPEC will need to extend and deepen production cuts if they have any hope of supporting the oil price in the near-term,” said Espen Erlingsen, head of upstream research at Rystad Energy.

Looking at the year-over-year change in total non-OPEC oil production from 1960 – the year OPEC was born – towards 2020, we see that production from non-OPEC countries grew the most in 1978, growing 1.96 million b/d thanks to increases from Russia, US, UK and Mexico.

Next year, this 40-year old production growth record may be beaten. Tight oil is expected to be a key contributor to the non-OPEC oil production expansion, contributing around 1.35 million b/d of the 2.26 million b/d increase according to Rystad Energy analysts. Offshore will balloon by an impressive 1.25 million b/d, almost 0.9 million b/d of which will come from deepwater.

“In a unique turn of events, it is the offshore segment which will drive much of 2020’s non-OPEC supply growth. The record-high production growth next year comes almost exclusively from tight oil and offshore,” Erlingsen said.



The US tops the list of non-OPEC countries who will see the quickest production growth in 2020, driven by tight oil production. Norway and Brazil, the world’s two dominant offshore players, follow close behind.


Norwegian production growth will in large part be driven by Johan Sverdrup, as well as smaller projects such as Oda, Valhall West Flank, and Trestakk.

“Although a rather mature producer, Norwegian production growth may reach an all-time high next year, boosted by a bevy of young finds,” Erlingsen observed.

The same can be said of Brazil, where record high production growth is expected next year thanks to the Buzios, Lula, and Lara projects. Rystad Energy forecasted recently that Brazil’s state oil company Petrobras is set to become the world’s largest oil producer among publicly listed companies by 2030. 


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Marcellus/Utica poised for growth as another big shale play slows down



An expected drop over the next couple of years in the country's hot crude oil and natural gas play, the Permian Basin in Texas and New Mexico, will end up benefitting the Marcellus and Utica in the future, according to a natural gas executive.

What has happened in the Permian has so far had a big impact here in Pennsylvania and the rest of Appalachia, which is the largest gas field in the country but doesn't have the same output in crude oil. The mostly oil play has been booming over the last few years, and it has been throwing off natural gas and natural gas liquids in such quantities that it's almost giving away natural gas and liquids. For natural gas producers in the Marcellus and Utica Shale, who are trying to make money off the gas produced here, the Permian associated gas has been dropping prices as well as competing for capital.

But some projections show the Permian's rapid growth may be declining — and the Energy Information Administration reported earlier in 2019 that year-over-year production growth has slowed from a peak in 2018. The Marcellus and Utica, for instance, continue to grow production. John Powell, SVP of marketing, supply and logistics for Crestwood Equity Partners LP, told the Marcellus Utica Midstream Conference on Thursday morning in downtown Pittsburgh, said that poses an opportunity after 2024 in Appalachia to provide for the natural gas liquids like ethane, propane and butane.

"That gas is going to come from the Marcellus and Utica area," said Powell. Crestwood Equity (NYSE: CEQP), a master limited partnership for midstream operations that has assets in the region, believes there's pretty much enough pipeline capacity, with small exceptions, in the Marcellus and the Utica to handle the liquids that would need to be transported. But, Powell said, there might need to be more fractionation capacity – processing plants like MarkWest and Blue Racer Midstream — that processes natural gas into liquids.

Despite a somewhat downbeat tone to the first day of the conference due to the immediate and near future term for natural gas producers and the midstream companies that take the gas from the field to market, Thursday's sessions were more positive about the outlook. Presenters talked about challenges, including regulatory and activist. But they also said that the Marcellus and Utica midstream industry is likely to see growth with the use of ethane, a natural gas byproduct, as the raw feedstock for the Shell petrochemical plant in Beaver County as well as one proposed in Belmont County, Ohio, and potential other petrochemical plants that will spring up. And there's also a potential to export more natural gas liquids to the rest of the world for future development. But the fast production growth has meant that there's a lot of product that doesn't have anywhere to go yet, said Jeff Pinter, EVP of NGL Liquids, a division of midstream provider NGL Energy Partners LP (NYSE: NGL).





"The future is very bright. There's a lot of demand coming ... but we're a little early on supply," Pinter said.

The main market for export in the future will be Asia, Pinter said. But those plants haven't been built yet.

And, said Wally Kandel, SVP of Solvay Specialty Polymers USA as well as a founding member of Shale Crescent USA, there are lots of opportunities to use the natural gas liquids here, either as polyethylene and polypropylene plants or in downstream manufacturing facilities.

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N. American Shale Primed for Growth Despite Possible Oil Price Declines



If OPEC and Russia don’t decide on deeper cuts in oil production for 2020, it could cause oil prices to drop. But the production outlook for North American shale will remain robust in coming years, according to Norwegian energy research firm Rystad Energy.

“In spite of the decline in spending and activity levels, the North American shale supply is not following the downward trend,” said Sonia Mladá Passos, a product manager of Rystad Energy’s Shale Upstream Analysis team.

Using a base case price scenario which assumes a WTI price of $55/barrel in 2019; $54/barrel in2020; $54/barrel in 2021 and $57/barrel in 2022, Rystad expects North American light tight oil (NA LTO) supply to reach 11.6 million barrels per day by 2022. This indicates an annual growth rate of 10 percent from 2019-2022.

In a price scenario with WTI remaining flat at $45 per barrel, NA LTO supply would level at 10.1 million barrels per day toward 2022.

“The flat development of U.S. LTO production is also possible in lower price scenarios, but we would likely see an initial period of multi-quarter production decline, with output stabilizing at a lower level,” Mladá Passos said.

This year, LTO supply from North America is set to reach 8.6 million barrels per day, with 93 percent driven by the U.S., according to Rystad.

Additionally, the industry is primed to spud 17,000 horizontal wells targeting shale formations in the U.S. and Canada this year. Rystad anticipates drilling activity to remain flat, according to the base case price scenario.

However, a low-price scenario with WTI staying flat at $45 per barrel, North American shale activity may experience a sharp decrease, falling by 26 percent in 2020, year-on-year.

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The relationship between crude oil (WTI) and natural gas (Henry Hub) prices has long been an essential one. These two sources of energy are intrinsically linked, and together supply over 60 percent of U.S. and global energy. Especially over the past decade, oil and gas are being produced by the same companies. Even the oil majors like Shell and ExxonMobil are increasingly positioning themselves as gas giants. They realize, of course, that gas is the centerpiece strategy around the world to cut greenhouse gas emissions, backup wind and solar, and provide reliable and affordable energy.

As for the fundamentals, where oil is found natural gas is also found, and vice versa. “Associated gas” comes along as basically a “free” byproduct of crude extraction, with “associated oil” coming along with gas. For consumption, while oil no longer competes in the main demand sector for gas, power generation, lower cost natural gas liquids such as ethane are coming to displace naphtha from crude utilized in industrial and manufacturing processes.

Seen in the graphic below, the diversion between oil and gas prices came in 2008-2009. This is right when the U.S. shale oil and gas revolution took off, when the deployment of hydraulic fracturing and horizontal drilling technologies became widespread. So just looking over this century, there have really been two distinct periods for oil and gas: the “pre-shale era” (2000-2008) and the “shale era” (2009-present).  




We can measure the oil and gas price disconnect over the past 20 years. Before 2009, for instance, the price of oil was nine times higher than natural gas. This is about normal because there is almost six times more energy in a barrel of oil than an MMBtu of gas. In the shale era since, however, oil has been nearly 25 times more expensive than gas. While not exactly a cause-and-effect indicator, the correlation coefficient (R) calculates the strength of the relationship between the movements of two variables (measured from -1 to +1). In the shale era since 2009, the R between oil and gas prices has been +0.45, well below the +0.75 R seen pre-shale. Thus, although it has stayed a positive one, the relationship between oil and gas pricing has weakened over the past decade.

This is all noteworthy because both U.S. oil and gas production have boomed since 2009. Domestic crude output has risen 150 percent, with gas up 60 percent. The vital difference between these two commodities, however, is that oil is easily transportable and therefore sold on an immense international market with linked prices. For oil consuming nations, outside forces and decisions reverberate around the world. The U.S. shale oil boom is simply not able to shelter the domestic market like shale gas has. Gas remains a regional product with distinct markets: over 70 percent of the world’s oil usage is internationally traded, versus just 30 percent for gas.

Looking forward, higher oil prices will generally mean lower U.S. gas prices. That is because of the Permian basin in West Texas, the largest oil field in the world. Higher prices will lead to more oil drilling and more associated gas supply. To illustrate, despite not having a single gas-directed rig in 16 months, the Permian now accounts for almost 20 percent of U.S. gas output. In the reverse, lower oil prices can lift gas prices by lowering gas production. The reality is that gas remains a secondary resource to oil, and its market is just too small to have a material impact on oil prices.

More U.S. LNG, however, will continue to gradually change oil and gas price dynamics. Although it now accounts for just 15 percent of global gas use, the expanding LNG trade is evolving gas into a global commodity like oil. Now in third place, the U.S. is expected to become the largest LNG seller within five years. Especially since our spot sales are highly attractive, this will give outside events greater influence on domestic gas prices. With isolation for the U.S. natural gas market slowly fading, there is good news in keeping prices low for consumers. The U.S. Department of Energy expects another 20-25 Bcf/d of domestic shale gas production through 2040 and even more beyond.

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Despite Challenges, Recruiters Optimistic for 2020



The U.S. oil and gas industry has seen its fair share of ups and downs and 2019 was no exception.

Recruiters felt it, too.

“It’s really been kind of a rollercoaster,” Jeff Bush, president of CSI Recruiting, told Rigzone.

Bush explained his firm, which focuses exclusively on recruiting and placement for the upstream sector, was busy in the first quarter and “extremely slow” during the summer.

“The few things we were working on definitely took a long time to come to fruition,” he said. “I think there was a real hesitancy to make a decision. There’s an idea of, ‘if I don’t make a decision, I can’t be blamed for spending too much money in my division. So, I’ll just ask my current staff to do more.’ We saw that really start to change pretty significantly in the early part of September.”

The third quarter saw decisions being made and people getting hired. This continued through November.

“Where we’re seeing the highest demand is accounting and finance, reservoir engineering and land administration – not much in geoscience or land,” he said. “These are full-time, good-paying jobs, but the number of openings is still pretty slim.”

Bush says all of his crew is busy now, though there continues to be a general level of hesitancy among energy companies.

“Most of the folks that are in a position to hire aren’t quite sure that they want to pull the trigger, and if they are, they want to make sure they’ve seen a slew of candidates across the experience spectrum to be sure they’re making the absolute right hire.”

Summer Chancey, president of global business operations for Viking Recruiting Resources, also saw increased hiring activity in the latter part of 2019.

“In third quarter, the hiring activity increased significantly and has remained constant to date,” Chancey told Rigzone. “This year we hit a tipping point with more open jobs than individuals readily available to fill them.”

She said companies have created competitive compensation packages to attract and retain talent, as well as offer increased personal/vacation time, increased salaries and flexible hours/remote work options.

“Throughout 2019, we experienced a high demand for field technicians and operators as significant infrastructure projects were completed,” she said. “About 25 percent of our available positions were filled by contractors who transitioned into permanent, direct-hire opportunities.”






2020 Outlook

As we approach 2020, many E&P companies are tightening their budgets and looking to drum up investor confidence.

Chancey said she predicts hiring needs to increase within the technology space, with individuals who are trained to operate sophisticated software or equipment increasing in demand.

Bush said he believes 2020 will mirror a lot of what was seen so far in 2019.

“There’s going to be a lot of companies we know really well that are not going to do anything or may go out of business,” said Bush. “That said, I think there is going to be activity and there are going to be companies who are actively pursuing development programs…who those will be – that’s the big question.”

He does feel confident his firm will be busy – if not busier – next year.

“It seems there’s no consistent pattern on who’s able to execute on programs,” Bush said. “Sometimes it’s the small company, sometimes it’s the conventional company, sometimes it’s the company in the Permian, sometimes it’s the company in the Mid-Continent, sometimes it’s a company with a private-equity backing and sometimes it’s a family-owned company.”

As for which companies will be hiring in 2020 – it’s anybody’s guess.

“It’s a volatile market lately,” he said. “I think a reduction in the number of companies is inevitable. I think a lot of the smaller players will go away. I think private-equity money will continue to exit the industry. But we’re still going to see activity. There’s still going to be people drilling for oil and gas.”


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