Big oil getting bigger: US majors focus on shale:

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Big oil has gotten bigger. A lot bigger.

That’s what Simon Flowers, chairman and chief analyst at Wood Mackenzie, stated in his latest version of The Edge, a regular column published on the company’s website.

“The majors have increased commercial reserves by 62 billion barrels of oil equivalent (proven and probable) through the downturn, equivalent to another BP and Chevron combined,” Flowers said in the column.

“Our forecast for 2030 production for the seven companies is over six million boepd, or 40 percent higher today than it was in our 2014 view,” he added.

In the column, Flowers asked Tom Ellacott, Wood Mackenzie’s senior vice president, if the majors are chasing volume rather than value.

“No, far from it,” was Ellacott’s response.

“Cash generation is paramount – cost-cutting and productivity gains have driven cash flow breakevens down from $63 per barrel in 2015 to an average of just $40 per barrel today,” Ellacott stated in the column. 

“We’ve also seen a profound strategic shift with companies building resilience into portfolios … We’d say the majors aren’t just bigger but are also in far better shape” Ellacott added.

Flowers also asked Ellacott if bigger means “less focused”.

“No, the opposite,” Ellacott stated in the column. “We’re starting to see increasing portfolio concentration,” he added.

Ellacott highlighted that the majors are focusing on asset types or geographies “where they have competitive strengths and competencies”.

“The U.S. majors, for example, have significantly strengthened tight oil exposure. European Majors have used DROs, M&A and exploration to beef up advantaged positions in conventional plays,” Ellacott stated.

The seven big oil companies comprise Equinor, Chevron, ExxonMobil, Eni, Shell, BP and Total, according to Wood Mackenzie.

Flowers first joined Wood Mackenzie in 1983. He has more than 20 years of experience across a breadth of commodities and sectors including oil and gas, utilities and mining, Wood Mackenzie’s website states.

Ellacott has worked at Wood Mackenzie for more than 20 years. He recently led the analysis of over 40 companies in the corporate service, including all the majors, leading independents and the main Asian national oil companies. 

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cost-cutting and productivity gains have driven cash flow breakevens down from $63 per barrel in 2015 to an average of just $40 per barrel today

Total BS


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2 minutes ago, Bob D said:

cost-cutting and productivity gains have driven cash flow breakevens down from $63 per barrel in 2015 to an average of just $40 per barrel today

Total BS


You can wallow in your BS !!! LOL

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OK  So it's half cycle breakevens.  Recent acquisitions still have an extremely high hurdle.  Chevron bought 1mm acres (minerals and royalties) in the Permian from before the beginning of time.  That dog will hunt.

I'm a wallower from way back!


Edited by Bob D

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“The majors have increased commercial reserves by 62 billion barrels of oil equivalent (proven and probable) through the downturn,”
An interesting statement keeping in mind that exploration is at a 70 year low.
If the majors have ‘gained’ 62 billion barrels through the acquisition of other companies, that means that the smaller companies ‘lost’ 62 billion barrels - a zero sum game.
Global reserves did not change in the least.

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4 minutes ago, Douglas Buckland said:
“The majors have increased commercial reserves by 62 billion barrels of oil equivalent (proven and probable) through the downturn,”
An interesting statement keeping in mind that exploration is at a 70 year low.
If the majors have ‘gained’ 62 billion barrels through the acquisition of other companies, that means that the smaller companies ‘lost’ 62 billion barrels - a zero sum game.
Global reserves did not change in the least.

The majors, collectively gaining 62b bbls of reserves doesnt means (in my interpretation is)  that they acquired it through third party buyouts, to me it seems that they explored for those over the years before and during and through the downturn, and were able to add those to their reserves. I doubt that smaller companies collectively were able to explore and add 62bil bbls over 10 years? 12 years? to their reserves.

So, thus, the majors and therefore, the world, gained 62bil bbls of reserves, it was always there, has been there, they just made the efforts to "find" it.

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If the majors actually have added 62 billion barrels of proven reserves through exploration in the downturn, it should be fairly easy to identify the discoveries that make up these reserves. Do you happen to have that info available? I am on my handphone at the moment and looking it up would be a chore with my fat fingers.

I know that Guyana is a big play at the moment, but 62 billion barrels is alot of oil.

From my perspective, exploration has been pathetic since at least 2015.

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13 minutes ago, Douglas Buckland said:


If the majors actually have added 62 billion barrels of proven reserves through exploration in the downturn, it should be fairly easy to identify the discoveries that make up these reserves. Do you happen to have that info available? I am on my handphone at the moment and looking it up would be a chore with my fat fingers.

I know that Guyana is a big play at the moment, but 62 billion barrels is alot of oil.

From my perspective, exploration has been pathetic since at least 2015.

My inference from the article brief is that , it is referring to all the discoveries through the downturn and that would depend on when you consider the start of the downturn, you refer 2015, so we will go by that. You know how long discoveries take and how much longer it takes them to be booked as reserves, so my guess that these companies have been at it since atleast 2006-2008 to make those discoveries and then add them to the reserves right before the downturn and during and through and post the downturn.

The large discoveries have been made offshore and onshore across the globe.

Here is some info. I will post some historical data for the last 15 years when I get access to it




Based on the locations of past giants, Mann et al. predicted new discoveries of giant oil and gas fields would mainly be made in passive margin and rift environments, especially in deepwater basins. They also predicted that existing areas that have produced giant fields would be likely targets for new discoveries of "elephants", as the fields are sometimes known in the oil and gas industry.

Data from 2000–07 reflect the accuracy of their predictions. The 79 new giant oil and gas fields discovered from 2000–07 tended to be located in similar tectonic settings as the previously documented giants from 1868–2000, with 36 percent along passive margins, 30 percent in rift zones or overlying sags (structures associated with rifts), and 20 percent in collisional zones.[8]

Despite a recent uptick in the number of giant oil and gas fields, discovery of giants appears to have peaked in the 1960s and 1970s. Looking to the future, geoscientists foresee a continuation of the recent trend of discovering more giant gas fields than oil fields. Two major continental regions—Antarctica and the Arctic—remain largely unexplored. Beyond them, however, trends suggest that remaining giant fields will be discovered in "in-fill" areas where past giants have been clustered and in frontier, or new, areas that correspond to the predominant tectonic settings of past giants.[9]



Wednesday, February 27, 2019

Exxon Mobil Corporation added 4.5 billion oil-equivalent barrels of proved oil and gas reserves in 2018, replacing 313 percent of the year’s production.

The company’s proved reserves totaled 24.3 billion oil-equivalent barrels at year-end 2018, with liquids representing 64 percent of the reserves, up from 57 percent in 2017.

ExxonMobil’s reserves life at current production rates is 17 years. Over the past 10 years, ExxonMobil has added proved oil and gas reserves totaling approximately 17 billion oil-equivalent barrels, replacing 108 percent of produced volumes, including the impact of asset sales.

“We continue to add high-value, attractive assets to our portfolio that have positioned the company for long-term growth,” Darren W. Woods, ExxonMobil chairman and chief executive officer, said in a company statement.

“Multiple new discoveries offshore Guyana, continued growth in the Permian Basin and a strategic acquisition in Brazil greatly enhanced our already strong portfolio of high-quality, low-cost-of-supply opportunities,” he added.

ExxonMobil is the largest publicly traded international energy company, according to its website. Earlier this month, the company announced estimated 2018 earnings of $20.8 billion, up from $19.7 billion a year earlier.



ExxonMobil Says Gulf Oil Discoveries Are Largest In a Decade

ExxonMobil Says Gulf Oil Discoveries Are Largest In a Decade


ExxonMobil Corporation announced two major oil discoveries and a gas discovery in the deepwater Gulf of Mexico after drilling the company”s first post-moratorium deepwater exploration well. ExxonMobil estimates the wells



Global discoveries of conventional oil and gas continue to show promising growth, with new finds totaling 6.7 billion barrels of oil equivalent (boe) in the first half of 2019, according to the mid-year assessment of upstream data by Rystad Energy.

The 1,123 million boe average monthly discovered volumes year-to-date reflect an approximate 35% uplift compared to the 827 million boe seen in 2018. So far, 2019 has been a year of gas discoveries, which hold a majority (63%) share compared to liquids, a phenomenon not seen since 2016.

“Offshore discoveries in Russia, Guyana, Cyprus, South Africa and Malaysia are propelling what is already a very successful year for international E&P companies. With deepwater finds contributing half of the discovered volumes, it can be inferred that high-risk frontier plays in the deepwater are back on the map for explorers,” says Rohit Patel, Senior Analyst at Rystad Energy.

Majors and integrated national oil companies, with their high-risk appetite and successes in frontier regions, have been exceptional in dominating conventional exploration performance, accounting for more than an 80% share of 2019 discovered volumes. Rystad Energy analysis has identified 56 global conventional discoveries so far this year, 30 of which are located offshore.

In the first half of 2019, Russia was the leader of the pack in terms of total discovered resources, followed by Guyana, Cyprus, South Africa and Malaysia.

Gazprom announced two big gas discoveries in the Kara Sea off the northwestern part of West Siberia's Yamal Peninsula – Dinkov and Nyarmeyskoye. Together, these discoveries hold nearly 1.5 billion boe of recoverable gas resources. Dinkov, the larger of the two fields, holds 1.1 billion boe of resources, making it the largest discovery so far this year.

In Guyana, ExxonMobil’s spate of oil discoveries continue in the Stabroek block, with three major discoveries reported in 2019 – Tilapia, Yellowtail (oil) and Haimara (gas-condensate). These three fields could collectively hold almost 800 million boe of recoverable reserves. ExxonMobil’s success rate in the 15 wells drilled so far on the Stabroek block stands at an impressive 86%. First oil from the block is expected in mid-2020.

ExxonMobil also made headlines in the Mediterranean Sea, notching up its maiden success with the giant Glaucus gas discovery off Cyprus. The discovery is estimated to hold 700 million boe in recoverable resources and is the second major find in Cypriot waters after Eni’s Calypso gas discovery, which has a similar resource size. ExxonMobil is lining up an appraisal campaign on this discovery in 2020. Eni and partner Total are also planning to begin a five-well drilling program off Cyprus later this year.

South Africa
Total’s Brulpadda wildcat completed in February in Block 11B/12B made a large gas-condensate discovery in the Lower Cretaceous Post-rift Paddavissie Fairway in South African deep water. Total and partners in the block have reported that the discovery could hold a billion barrels or more. Results from PVT analysis and technical validation are still being assessed in an effort to confirm the resource size. Rystad Energy currently estimates the discovery resource size at between 500 million and 600 million boe. Four additional prospects – Luiperd, Platanna, Woudboom and Blassop – have been de-risked within the fairway and a multi-well drilling campaign targeting oil in the eastern side of the fairway is expected to commence on the block in early 2020. The campaign might be carried out in stages as the operational window in the area is limited to December to March. The Luiperd prospect, with a pre-drill resource estimate of more than 500 million boe, might be spud next.

Thailand’s national energy company PTTEP unveiled a major offshore gas discovery with the Lang Lebah-1RDR2 exploration well in SK410B license in Malaysian waters. Rystad Energy estimates the discovery could hold between 2 trillion and 2.5 trillion cubic feet (Tcf) of gas. The discovery is believed to be the largest discovery ever made by PTTEP as operator and is in alignment with the company’s strategy to expand its footprint in the region.





Conventional oil and gas discovered resources in 2019 are on pace to rise 30% from last year and reach their highest level since the beginning of the industry downturn.

Global discoveries yielded 3.2 billion BOE during the first quarter, with 2.2 billion BOE alone coming in February, the most since August 2015, according to data from research consultancy Rystad Energy.

A successful exploration push by the majors—namely ExxonMobil—is driving the rebound as companies refocus on expanding their resource base after lower activity in recent years. The US major alone accounted for 38% of the total volumes following its Glaucus-1 natural gas discovery off Cyprus and Tilapia and Haimara oil and gas discoveries off Guyana, ranking Nos. 1, 3, and 7, respectively, of this year’s biggest finds.

ExxonMobil announced in February that its Glaucus-1 well intersected a 133-m gas-bearing reservoir on Block 10 southwest of Cyprus in the Eastern Mediterranean Sea. Based on preliminary interpretation of the well data, the discovery could represent an in-place gas resource of 142–227 billion cu m, the company said.

Tilapia-1 and Haimara-1 brought ExxonMobil’s total discoveries on the Stabroek Block off Guyana to 12. Tilapia-1 encountered 93 m of high-quality oil-bearing sandstone. Haimara-1 intersected 63 m of high-quality, gas condensate-bearing sandstone. 

The second largest discovery, also announced in February, was Total’s Brulpadda well on Block 11B/12B off South Africa. It encountered 57 m of net gas condensate pay in Lower Cretaceous reservoirs. The company said it plans to acquire 3D seismic this year and drill up to four exploration wells on the license. Total is also a partner in the CNOOC-operated Glengorm discovery in the UK North Sea—that area’s biggest discovery in a decade. Meanwhile, Eni reported finds off Angola and Egypt.

Repsol boasted the largest onshore find with its Kali Berau Dalam gas discovery in Indonesia, which comes with a preliminary estimate of at least 2 Tcf of recoverable resources. The company said in its February announcement that it plans a subsequent appraisal well.

Rystad notes that another 35 “high-impact” exploration wells are expected to be drilled this year—both onshore and offshore. Three are under way:

  • Shell’s Peroba well off Brazil, with estimated prospective resources of 5.3 billion boe.
  • Total’s Etzil well off Mexico, with estimated prospective resources of 2.7 billion boe.
  • Eni’s Kekra well off Pakistan, with estimated prospective resources of 1.5 billion boe.

"If these wells prove successful, 2019’s interim discovered resources will be the largest since the downturn in 2014,” said Zain Shariff, Rystad upstream analyst.



The oil & gas exploration winners of 2018




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Hess Corp. and Chevron teamed up to announce a new Gulf of Mexico discovery at their Esox-1 test well near the existing Tubular Bells field in the deepwater Gulf.

The discovery will lead to what essentially is an expansion project. New York-based Hess and Chevron will develop the area as a lower-cost tieback project, connecting the new wells via pipelines and subsea umbilicals to the Tubular Bells facilities that are about six miles west of the Esox-1 well.

The first Esox well is expected to come online in early 2020.

“We are delighted with the success of the Esox well, which demonstrates the value of our infrastructure-led exploration program in the deepwater Gulf of Mexico,” said Chief Executive John Hess.

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Years of Offshore Investments Could be Valueless



Years of offshore investments could be valueless, according to Rystad Energy.


Years of offshore investments could be valueless.

That’s according to Rystad Energy, which stated that international exploration and production (E&P) companies are struggling to make money from offshore investments made during the latest investment upturn.

In a new study, Rystad evaluated all offshore oil fields sanctioned since 2010 and ranked them by estimated value per barrel of oil under various oil price scenarios. According to the company, entire vestiges of offshore field development projects will fail to offer a return on investment in today’s oil price environment.

For example, Rystad noted that offshore projects sanctioned between 2010 and 2012 have “barely been able to generate any value” for E&P companies and highlighted that projects sanctioned between 2013 and 2014 are “expected to have no value creation”.

In addition, Rystad revealed that for upstream companies to come out of the 2013-2014 investment years without “massive losses”, the oil price will need to increase to around $70 per barrel.

Looking further ahead, Rystad said value creation is positive for sanctioning between 2015 and 2018, even when applying a future oil price of only $40 per barrel.

“Looking back at the offshore projects sanctioned between 2010 and 2014 with the knowledge we have today, we see that the last offshore investment cycle is struggling to create value,” Espen Erlingsen, head of upstream research at Rystad Energy, said in a company statement.

“High development costs combined with low oil prices have severely undermined the profitability of these assets,” Erlingsen added.

“With the pivot in development costs from 2015 onwards, the projects sanctioned over the last four years are in a much better position,” the Rystad representative continued.

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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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