Monday, September 24, 2018

U.S. Likely World’s Largest Crude Oil Producer, DOE Authorises Short-Term Natural Gas Exports

http://legacy.lib.utexas.edu/maps/united_states/us_gas_production_in_conventional_fields-2009.jpg

The Energy Information Administration (EIA) estimated in its latest Short-Term Energy Outlook that the U.S. is now the largest global crude oil producer, likely surpassing Russia and Saudi Arabia.

In February, U.S. crude oil production exceeded that of Saudi Arabia for the first time in more than two decades. In June and August, the United States surpassed Russia in crude oil production for the first time since February 1999.

EIA estimates that U.S. crude oil production averaged 10.9 million barrels per day (bpd) in August, up by 120,000 bpd from June. EIA forecasts that U.S. crude oil production will average 10.7 million bpd in 2018, up from 9.4 million bpd in 2017, and will average 11.5 million bpd in 2019.

Meanwhile, EIA estimates that U.S. crude oil production averaged 10.9 million bpd in August, up by 120,000 bpd from June. EIA forecasts that U.S. crude oil production will average 10.7 million bpd in 2018, up from 9.4 million bpd in 2017, and will average 11.5 million bpd in 2019.

The U.S. Department of Energy (DOE) also announced that on September 6, 2018, a short-term order was issued to the Freeport LNG project to export up to 2.14 billion cubic feet per day (Bcf/d) of LNG over a two-year period to both free-trade and non-free trade agreement countries. This order authorises Freeport’s initial commissioning volumes and other exports pursuant to short-term contracts. Freeport LNG will be exporting the LNG from the Freeport LNG Liquefaction Project, which is currently under construction on Quintana Island, Texas.

During this two year authorisation period, Freeport LNG will be authorised to export LNG to any country not prohibited by U.S. law or policy. The two year export term will become effective on the date of the commencement of the facility’s first export of LNG, currently projected to be in the third quarter of 2019.

Since exports of U.S. LNG began in 2016, over 1.3 trillion cubic feet of U.S. natural gas has been exported. EIA estimates dry natural gas production in the U.S was 82.2 Bcf/d in August, up 0.7 Bcf/d from July. Dry natural gas production is forecast to average 81.0 Bcf/d in 2018, up by 7.4 Bcf/d from 2017 and establishing a new record high. EIA expects natural gas production will continue to rise in 2019 to an average of 84.7 Bcf/d.

Friday, September 21, 2018

VLCC upturn - wait a little while longer

gms_market_commentary_on_shipbreaking_in_week-_19-_vlcc-focus_75807.jpg


The Crude and residual fuel oil transportation market will remain over-supplied in 2019, according to the latest outlook from McQuilling Services taken from the consultancies Mid-Year Update publication.
 
There will be commensurate weakness in VLCC and other DPP segments, freight and earnings before re-balancing thereafter.
 
Vessel supply pressure increased last year at a time when demand fell, due to rising crude pricing, lower OPEC production and de-stocking of inventories.
 
The inevitable decline in utilisation was the direct influence towards weakening earnings, which remains the story today.
 
As for 2019, McQuilling said that the projection requires an examination of forward looking fundamentals and the impact on VLCC utilisation.
 
There is an expected rise in VLCC supply over the next 15 months, as from an original projection of 50 VLCC deliveries, 24 have been confirmed through the end of August, indicating 26 are delivering in the near term. In addition, McQuilling’s adjusted orderbook shows 61 VLCC deliveries scheduled for 2019.
 
Balancing the equation is an increase in deletions, which year-to-date numbered 30, with full-year estimates adding an additional 10%. Its forecast for 2019 deletions remained unchanged at 29 VLCCs.
 
This shows that tonne/day supply is projected to exceed 240 mill by the end of next year, a 7.5% increase over current levels. Therefore, in order for utilisation to remain at current levels (60.3%), demand would need to match this rise.
 
McQuilling’s models suggested that tonne/day demand will trend closer to 2018 levels, pointing to a weaker market in 2019 in the context of vessel supply pressures. It was acknowledged that upside demand shocks and higher than expected deletions may be mitigating factors for an improvement in utilisation.
 
In conclusion, while the fundamentals and technicals point to a weak market in 2019, McQuilling’s long-term forecasts reveal a more-balanced market in 2020 and a significantly tighter market in 2021/22.

Thursday, September 20, 2018

Trump blasts OPEC on oil prices, says ‘must get prices down now!’


https://www.marketwatch.com/story/trump-blasts-opec-on-oil-prices-says-monopoly-must-get-prices-down-now-2018-09-20

President Donald Trump took another swipe at global oil producers Thursday as the price of benchmark crude inched toward the $80-a-barrel threshold, tweeting at the Organization of the Petroleum Exporting Countries:
The remarks come ahead of a closely watched meeting in Algiers of a committee made up of representatives of OPEC countries and its outside allies. The producers had agreed in June to boost production in an effort to get output nearer a previously agreed ceiling. The June agreement was seen, in part, as a response to U.S. pressure.

Oil prices have been on the rise, boosted in part by Trump’s decision to pull out of the Tehran nuclear accord and renew sanctions on Iran aimed at sharply curtailing the major producer’s exports.

Trump’s latest tweet also come after a news report earlier this week said officials from Saudi Arabia, OPEC’s de facto leader and the crucial swing producer, were growing comfortable with the possibility of crude prices above $80 a barrel.

November futures on Brent crude LCOX8, -0.89% , the global benchmark, turned lower and were 41 cents, or 0.5%, at $79.03 a barrel in recent action. Futures on West Texas Intermediate for November delivery CLX8, -0.51% on the New York Mercantile Exchange were also dragged lower and traded off 9 cents, or 0.1%, at $70.69 a barrel. Brent is up 2% so far in September and more than 18% since the end of 2017, while WTI is up nearly 17% for the year to date.

The decision by OPEC and its allies, particularly Russia, to boost output in June was seen as an effort to help blunt the impact of the expected drop in Iranian output.

It’s no surprise to see politicians sensitive to rising oil prices, which translate to higher gasoline prices at the pump, particularly ahead of midterm congressional elections in November. Trump, who has embraced and reaffirmed Saudi Arabia as a key U.S. ally, has taken aim at the cartel previously, in a pattern observers said appears to show a sensitivity to pushes toward the $80 threshold for Brent.

Wednesday, September 19, 2018

Trump Hit Iran With Oil Sanctions. So Far, They’re Working.

An Iranian-flagged support boat near an oil tanker. A big drop in Iran’s oil exports two months before United States sanctions go into effect has had little impact on the global oil market.CreditCreditAli Mohammadi/Bloomberg


https://www.nytimes.com/2018/09/19/business/energy-environment/iran-oil-sanctions.html

HOUSTON — When President Trump announced in May that he was going to withdraw the United States from the nuclear agreement that the Obama administration and five other countries negotiated with Iran in 2015 and reimpose sanctions on the country, the decision was fraught with potential disaster.

If Mr. Trump’s approach worked too well, oil prices would spike and hurt the American economy. If it failed, international companies would continue trading with Iran, leaving the Islamic Republic unscathed, defiant and free to restart its nuclear program.

But the policy has been effective without either of those nasty consequences, at least so far.
Nearly two months before American oil sanctions go into effect, Iran’s crude exports are plummeting. International oil companies, including those from countries that are still committed to the nuclear agreement, are bailing out of deals with Tehran.

And remarkably, the price of oil in the United States has risen only modestly while gasoline prices have essentially remained flat. The current global oil price hovers around $80 a barrel, $60 below the highs of a decade ago.

“The president is doing the opposite of what the experts said, and it seems to be working out,” said Michael Lynch, president of Strategic Energy and Economic Research, a research and consulting firm.

Initial signs of a foreign-policy success could benefit Mr. Trump politically as Republicans try to hold on to control of Congress. The president and lawmakers allied with him could point to the administration’s aggressive stand toward Iran as evidence that his unconventional approach to diplomacy has been much more fruitful and far less costly than Democrats have been willing to acknowledge.

The administration’s tactical advantage could be fleeting, of course, if Iran retaliates with cyberattacks or militarily, incites more militia violence in Iraq, or revives its nuclear program.

The most important reason that predictions of higher oil prices have been wrong is that there is plenty of oil sloshing around the world. The United States has become a huge exporter of oil in the last several years and is now shipping roughly the same amount — more than two million barrels a day — that Iran did earlier this year.

Trade tensions and economic problems in developing countries like Turkey and Argentina might also be slowing the growth of energy demand.

Another thing in Mr. Trump’s favor is that while governments in Europe and Asia have publicly opposed his decision to withdraw from the nuclear agreement, many businesses in those places have made a different calculation. They have concluded that it makes little financial sense to risk investments in and trade with the United States by doing business with Iran.

Until Mr. Trump’s May announcement, Western allies considered the nuclear deal with Iran a success. In exchange for agreeing to strict limits on its nuclear program and international monitoring, Iran was allowed to re-enter the global oil market. The deal lifted restrictions on foreign companies doing business in Iran and gave the country access to frozen assets overseas.

After Nov. 4, companies that buy, ship or insure shipments of Iranian oil can be excluded from the American market and banking system unless they obtain waivers from the administration.

Trump administration officials say its sanctions are designed to punish Iran for its interventions in Syria, Yemen and other countries.

For Iran, the timing could not be worse. The country has lost influence over oil prices as other producers have eclipsed its energy industry, which has not kept up with technological advances.

At the beginning of the century, Iranian officials could shake the oil markets by staging military maneuvers or merely hinting that they would reduce supplies. Back then, American oil production was falling and global demand for crude was surging.

But those days are long gone. Like the United States, countries including Canada and Brazil are also exporting more oil. Russia, Saudi Arabia and Iraq have also increased production, helping to keep oil prices in check. Saudi Arabia and its Persian Gulf allies are only too happy to support the sanctions against their chief rival, Iran, by expanding exports.

That has provided a buffer for the global oil market as Iranian exports dropped by more than 25 percent, or around 600,000 barrels a day, between June and the start of September. Exports are expected to drop by an additional half-million barrels when American sanctions go into effect. All told, exports could drop from a high of 2.7 million barrels this year to fewer than a million in 2019 — lowering the country’s exports to less than 1 percent of the global market, from about 3 percent earlier this year.

That would further squeeze the Iranian government, which had $50 billion in oil revenue last year; oil and petroleum products make up about 70 percent of the country’s exports by value.

“For Iran, it shows the leverage that they have had through oil has not only diminished but may never return,” said Amy Myers Jaffe, a senior fellow specializing in energy at the Council on Foreign Relations. “People just don’t care if they are going to lose business in Iran. People don’t feel desperate for supply.’’

The sanctions are so onerous that even companies from countries opposed to Mr. Trump’s approach are withdrawing from Iran.

South Korea, Iran’s third-biggest oil market last year, halted purchases in August after buying 194,000 barrels a day in July. Shipments to France and Japan, two other major markets, are also dropping.

OMV, the Austrian oil company, recently backed out of an agreement with the National Iranian Oil Company to evaluate oil fields. Hellenic Petroleum of Greece, Spain’s Repsol and Italy’s Eni are winding down oil purchases.

The Foundation for Defense of Democracies, a conservative Washington think tank, found that 71 foreign companies planned to withdraw from Iran, 19 intended to stay and 142 were undecided or hadn’t said as of early September.

“Big international companies have to ask themselves what risks are they willing to take on,” said David Adesnik, the foundation’s director of research. “Even if you don’t have a business in the U.S. you can be cut off from our financial system, and that’s not something a truly global firm can afford.”
The next big shoe to drop appears to be India, Iran’s second-biggest oil market after China. Reliance Industries, the nation’s leading refiner, has said it will stop buying Iranian crude when American sanctions kick in. And the State Bank of India, the country’s largest lender, has told refiners that it will block payments for Iranian crude.

American officials are waging a public and private campaign to persuade foreign leaders to cut economic ties with Iran — and to buy more American oil.

During a visit to India this month, Secretary of State Mike Pompeo said the administration was seeking a total halt to Iranian oil exports, although countries will be given time to switch suppliers.

“Purchases of Iranian crude will go to zero from every country or sanctions will be imposed,” Mr. Pompeo said.

The sanctions could allow Russian and Chinese companies to replace Western businesses in Iran. After Washington denied it a waiver, the French oil giant Total pulled out of a contract to develop the South Pars gas field, leaving a potential opening to China’s CNPC to increase its investment in the field.

China, which imports a half-million barrels of Iranian crude a day, can more easily resist American policy than other countries. That’s because its smallest refiners and domestic banks have little or no exposure to the United States.

Russia is another obstacle.

Gazprom and Rosneft, two state-controlled Russian oil and gas giants, are negotiating oil development deals worth roughly $10 billion with the Iranian oil ministry.

For its part, Iran is not sitting still. The state-run Iranian tanker company is storing oil on its fleet of supertankers rather than shut down production, which can damage wells. Iran could smuggle oil over land through Pakistan and Afghanistan, and barter with trading companies to get around sanctions.

International transactions are largely denominated in dollars, which strengthens American sanctions. Over time, Iran’s oil trade could shift to other currencies, particularly the Chinese renminbi.

“We will continue by all means to both produce and export,” President Hassan Rouhani of Iran said recently on state TV. “Oil is in the front line of confrontation and resistance.”

Monday, September 17, 2018

Meet the Shalennials: CEOs under 40 making millions in Texas oil

Image result for John Sellers and Cody Campbell
John Sellers and Cody Campbell


Dozens of young entrepreneurs, mostly in their 30s, are running private-equity-backed companies in the frenzied boom in West Texas and New Mexico.

John Sellers and Cody Campbell are holding court one hot August evening in the corner of an oil-themed dive bar in Midland, Texas. After flying in on their private jet, they’re shaking hands, cracking jokes and talking deals with aspiring oilmen, contractors and land traders, almost all in their early 30s. A life-size, stuffed grizzly bear stands by a wall wearing a baseball cap embossed with: “Make Oil & Gas Great Again.”

It’s not hard to see why Sellers and Campbell are in such high demand in this hardscrabble city that has become the global centre of the shale revolution. Over the past decade, they’ve bought and sold tens of thousands of oil leases in the Permian Basin, making deals blessed with a handshake in diners, on the hoods of trucks and in bars such as this.

The co-CEOs of Double Eagle Energy III may be the most prolific, and richest, Texas dealmakers you’ve never heard of. At just 36 years old, they’ve personally made at least $500 million combined, according to an analysis by the Bloomberg Billionaires Index, based on typical deals in the sector. They declined comment on their wealth.

The oil industry has produced many billion-dollar fortunes, from H.L. Hunt, who rose to fame in the 1930s, to Harold Hamm, who led the innovations in shale that began in the 2000s. But while most were made from striking oil, the new game in town is land. Sellers and Campbell began as land men, specialists in buying and quickly selling drilling rights, which, in Texas, are all privately owned.

“You can have the best drilling engineer, the best geologist, the best of everything, but if you don’t own an oil and gas lease you can’t drill a well,” Campbell said, wearing a polo shirt, jeans and cowboy boots and sipping whiskey on the rocks. “The land man was always looked down upon because he wasn’t a scientist. Not anymore.”

They’re not alone. Dozens of young entrepreneurs, mostly in their 30s, are running private-equity-backed companies in the frenzied boom in West Texas and New Mexico that may each be worth billions of dollars.

Whether they realise that kind of cash will depend, of course, on the vagaries of the shale industry, where consistent profits remain elusive. Rising costs and pipeline shortages have put the breaks on growth this year. And like any property boom, an early entry can make a career while being late can break one. Many of the young men admire the late Aubrey McClendon, the founder of Chesapeake Energy, who became a billionaire leasing land for natural gas drilling in the 2000s. But he’s a cautionary tale: He was ousted after he had borrowed heavily betting on rising gas prices that never came.

The young upstarts are unperturbed by all that. With larger rivals continuing to bulk up — $30 billion in deals have been announced in just the past six months — they see themselves as prime takeover targets, and they’re angling for that big payday.

Sellers and Campbell have been friends since their days in junior high school just south of Amarillo. They played football together, first in high school and then at Texas Tech University. Sellers was a defensive lineman and Campbell an offensive lineman who’d go on to have a brief NFL career before a pectoral injury drove him out of the game.

They had gotten into real estate while in college, but business stalled in 2008 due to the financial crisis. So, on the advice of friends, they put whatever they had left into a lease in the Haynesville shale play in East Texas. They were able to quickly sell it to an operator who was looking to drill and made a profit.

For the next four years they perfected the play, expanding to the Eagle Ford in South Texas and the Permian to the west. “It was all in, all in, all in, every time,” Sellers said.

Their model at first was to simply flip leases quickly and then to participate as a non-operating partner in drilling. But they soon saw that the fast-growing world of fracking opened up a massive opportunity, one that fit perfectly with their backgrounds in real estate.

Historically, Permian wells were all vertical, meaning there was no incentive to find adjoining land. But since the late 1990s, when fracking began, shale production has meant drilling sideways, pumping water, sand and chemicals at high pressure to create cracks in rock deep in the ground to release oil or natural gas.

As operators became more sophisticated, they drilled wells longer, running horizontally for two, sometimes three miles. That meant they needed to line up multiple, connected land leases. The shale game became less about finding oil and more about patching together the land needed to drill long wells. That’s what Sellers and Campbell do — put the jigsaw puzzle together. And, of course, several contiguous leases that enable two miles of horizontal drilling are worth exponentially more than by themselves.

“In certain areas we’re in now, it’s thousands of people who could own units you think can be drilled,” Campbell said.

In 2013, private equity came knocking. With the shale revolution well underway, Apollo Global Management backed Sellers and Campbell in an Oklahoma deal in which they more than quadrupled the original investment in a year, they said.

Their biggest payout to date came last year, when they sold about 70 000 acres to Parsley Energy for $2.8 billion. Since then they’ve raised more money from Apollo, assembled an even larger position of 80 000 acres and started a drilling company. Based on recent sales prices, their current holdings could be worth as much as $6 billion. They declined comment on that estimate.

The two have a reputation for being aggressive buyers, freely paying broker commissions, a practice that often held up deals in the past.

“If someone brings us a deal, they’re going to be well-compensated,” Sellers said, as he finished a chicken salad, washed down with Tito’s, a Texas-made vodka, mixed with soda. “Our philosophy is we don’t care what other people make as long as we’re OK with the price.”
Here are profiles of other young Permian executives.

The operators

Sitting by a frack pond in West Texas next to a dirt road one hot August afternoon, Will Hickey, 31, swipes through an app on his phone. It shows the results from a recently drilled well: 2 400 barrels of oil a day. “We’re making a lot of oil, baby!” he says, bumping fists with his business partner James Walter, 30.

Hickey and Walter were working at Pioneer Natural Resources and Denham Capital, respectively, when, in 2015, they decided to go into the oil business together. They moved to Midland and soon spotted an opportunity around the city of Pecos in the Delaware Basin. They raised $75 million from private equity firms Pearl Energy Investment and NGP to start their company, Colgate Energy.

They bought small leases in this less-developed part of the Permian and bet they could buy others nearby or swap with larger companies, Hickey said.

Three years on, they have won $450 million of investment from private equity backers, own rights to 30 000 acres of land and moved into drilling, operating two rigs.

Of their 30 employees, all but one are under 35 years old.

“It’s so fast-paced out here, the land deals, the data, the technology — it’s become more and more a young man’s game,” said Walter. “Our office feels more like Google than Exxon Mobil.”

The investment banker

Mark Hiduke, 31, had always aimed to be an investment banker, but the 2008 financial crisis limited his opportunities as a new graduate of Southern Methodist University. He soon joined Pioneer as part of a seven-member team in charge of buying and selling assets.

He noticed that many deals crossed his desk that were too small for large companies to consider. “Leases were selling for $5 000 an acre,” he said. “I thought, ‘This is crazy, the valuation should be five or six times this.’ ”

With funding obtained from NGP, he started PCORE and bought small, overlooked leases and sold them just 18 months later. The deal made his investors three times their money despite a 68% drop in oil prices, he said.

He began a second company, called PCORE II, in 2016, leasing land in the southern part of the Delaware Basin, which was cheaper at the time than the Midland Basin.

The land man

While running land and mineral ownership searches for Devon Energy Corp. after graduating from Tarleton State University, Tyler Glover, 33, kept coming across an odd name: Texas Pacific Land Trust.

Created to pay back creditors of the bankrupt Texas Pacific railway in the 1880s, the trust owns large swaths of land and mineral royalties in West Texas. After more than 100 years of selling off land, the trust was left with areas in Loving, Reeves and Culberson counties that no one wanted to buy.

It just so happened that this was the core of the Delaware Basin, the western part of the Permian and one of the centres of the shale revolution.

Glover joined Texas Pacific as a land man in 2011, the youngest person at the company by at least 15 years, he said. Texas Pacific had a market value then of just over $1 billion.

As the market woke up to the size of the company’s land holdings (a 1 million acre mix of surface and royalty rights), its value has surged to $6.4 billion to make it the best-performing major US oil stock never to have pumped a barrel of crude. Glover is the chief executive officer, historically an administrative role.

“There is no way anyone could re-create an asset base like this today,” he said. “Because of the value of the land and resources we sit on now, more active management of Texas Pacific is a necessity.”

The sand man

After observing his family’s coal business as a child, Kentucky-born Rhett Bennett, 37, didn’t want to get into mining after graduating from the University of Georgia in 2004. So he jumped into the energy industry and, after a few twists and turns, wound up right back in the mining business.

Not mining for coal, though. Mining for sand, the grit that makes fracking possible.

Bennett first moved to Texas back in 2004. He learned about oil leases from friends and started flipping them. In 2015, he bought a big position in southeast New Mexico and sold it 16 months later to Marathon Oil for $700 million, making five times the original investment for himself and his investors, he said.

Bennett then got into supplying sand for frackers after he noticed that most of the sand used for wells was being transported by train hundreds of miles, from Wisconsin. He opened Black Mountain Sand in West Texas, joining scores of other entrepreneurs trying to muscle out the Wisconsin crowd. He believes his company would be worth about $2 billion on public markets.

“If you’ve been around the last 10 years, you’re as experienced as anybody else,” he said.

© 2018 Bloomberg L.P

Thursday, September 13, 2018

IEA report: Global oil supply hit a record high in August despite Iran, Venezuela fallout

Welders work on the Strategic Petroleum Reserve pipeline on June 1, 1980, in West Hackberry, Louisianna. Begun under President Ford to reduce the threat of oil embargoes, the SPR crude oil is stored in huge underground salt caverns along the Gulf of Mexico, a natural choice due to the proximity of many refineries and distribution points.
Welders work on the Strategic Petroleum Reserve pipeline on June 1, 1980, in West Hackberry, Louisianna. Begun under President Ford to reduce the threat of oil embargoes, the SPR crude oil is stored in huge underground salt caverns along the Gulf of Mexico, a natural choice due to the proximity of many refineries and distribution points.

https://www.cnbc.com/2018/09/13/iea-global-oil-supply-hits-record-despite-iran-venezuela-fallout.html
  • Global oil supply hit a record high in August at 100 million barrels per day (bpd).
  • Higher output from OPEC managed to more than offset seasonal declines from non-OPEC members, which nonetheless increased year-on-year, led by the U.S.
  • August saw OPEC’s crude supply hit a nine-month high of 32.63 million bpd, despite falls in production from major players Venezuela and Iran.
Global oil supply was firing on all cylinders in August, reaching a record 100 million barrels per day (bpd), the International Energy Agency revealed in its monthly Oil Market Report Thursday.

Higher output from Organization of the Petroleum Exporting Countries (OPEC) managed to more than offset seasonal declines from non-OPEC members, although non-OPEC supply was also up 2.6 million bpd in August of the previous year, led by the U.S. The IEA forecasts non-OPEC production to grow by 2 million bpd in 2018 and 1.8 million bpd in in 2019, characterized by "relentless growth led by record output from the U.S."

Meanwhile, August saw OPEC's crude supply hit a nine-month high of 32.63 million bpd, despite concerns over falling production and slashed access in major producers Venezuela and Iran. Higher volumes from Nigeria and Saudi Arabia as well as increased production in Libya and Iraq served to outweigh these drops.

The 15-nation cartel's members agreed to start raising output beginning in July this year to stabilize markets and offset losses in major suppliers Iran and Venezuela, OPEC's third and sixth-largest producers, respectively.

Tehran is facing the loss of most of its energy export markets as the Trump administration prepares to sanction its oil sales on November 4 after pulling out of the Iran nuclear deal in May. August saw Iran's production drop dramatically by 150,000 bpd to 3.63 million bpd, its lowest level since July 2016, as buyers cut orders in the face of impending U.S. penalties.

The Iran deal, known officially as the Joint Comprehensive Plan of Action and signed with five other world powers, offered sanctions relief to the Islamic Republic in exchange for limits to its nuclear program. Renewed sanctions imposed by Washington on other parts of its economy in August have already sent its currency, the rial, into a tailspin.

Meanwhile, Venezuela's protracted economic crisis has led to a production collapse that's seen 1 million bpd wiped off the market in the past two years, and supply there is expected to continue to deteriorate rapidly.

Oil demand less bullish

The demand outlook is less bullish. Global oil demand growth for 2018 and 2019 are unchanged, the IAE reported, remaining at 1.4 million bpd and 1.5 million bpd, respectively.

Weaker demand in Organization for Economic Cooperation and Development (OECD) members in Europe and Asia, as well as higher gas prices in the U.S., put some downward pressure on the pace of demand growth, while shakiness in emerging markets over trade disputes and weakened currencies pose a risk to demand outlook for 2019.

Meanwhile, OECD Americas oil demand is set to post strong growth for 2018. Brent crude prices fell in August but more recently rose to two-month highs around $80 a barrel.

Despite robust production and supply, oil markets are tightening, meaning that a disruption in any major producer could lead to a material impact on prices. "We are entering a very crucial period for the oil market," the IAE report stressed.

"The market is expected to tighten during the later part of this year, because if Iran's exports do fall by a considerable volume, we'll be relying on other producers to increase their output to make up for that," Neil Atkinson, head of the oil industry and markets division at the IEA, told CNBC on Thursday. He described Iraq, Libya, Nigeria and Saudi Arabia as some of the producers having the spare capacity to see more output increases in the coming months.

But this in itself is not certain: instability in Iraq and Libya in particular could disrupt supply levels.

Iraq, OPEC's second-largest producer which saw near-record production in August at 4.65 million bpd, is currently witnessing violent protests in and around Basra, which hosts the majority of its oil production facilities and its only deepwater port. Demonstrators have blocked roads and threatened to shut down oil facilities in protest against failed state services, unemployment and political corruption.
Meanwhile Libya, posting a major output rebound in the same month of 280,000 bpd to reach 950,000 bpd, remains vulnerable to disruptions due to continued unrest and security problems. The U.S. Treasury department in conjunction with the United Nations on Wednesday imposed sanctions on a leading Libyan militia leader for his attacks on vital oil facilities in June.

In terms of the drop in output from Iran and subsequent impact on oil prices, there is "no way of knowing" how much its exports will fall, Atkinson said. While some analysts have suggested oil could hit $100 a barrel in the aftermath of the sanctions, Atkinson refrained from making any calls, saying "it's pure speculation to try and put a figure on it."

"It's a question of waiting to see in these next few weeks how the period in the run-up to November 4th plays out," he said, alluding to planned talks between the U.S. government and other countries like India, China and South Korea. "And then we'll have a clearer idea of where things might go."

Wednesday, September 12, 2018

Oil, gasoline prices rise as storms approach US

Katrina in the Gulf
  • Oil rallied on worries U.S. sanctions on Iran will hurt global oil supplies, and gasoline rose as a series of hurricanes and storms headed toward the U.S. or Gulf of Mexico.
  • Hurricane Florence was a Category 4 hurricane barreling toward the Carolinas, but it is not as likely to impact oil and gas directly.
  • An as-yet-unnamed storm, likely to develop into a tropical depression, and Tropical Storm Isaac could both potentially head into the Gulf of Mexico, where oil production and refinery facilities are located.
  • Strategists say it appears more likely the administration will succeed in taking large supplies of Iranian oil from the market, as South Korea and Japan indicated they would no longer buy it.
https://www.cnbc.com/2018/09/11/oil-jumps-gasoline-rises-as-storms-approach-us.html

Oil rallied on concerns U.S. sanctions on Iran could hurt global supply, while gasoline rose as traders watched multiple storms approaching U.S. shores and the Gulf of Mexico.

Hurricane Florence, a Category 4 hurricane, barreled toward the Carolinas Tuesday. But other smaller storms, such as Tropical Storm Isaac, are potentially more worrisome for the oil and gas industry, because they have the chance of moving into the Gulf of Mexico, where there are energy production and refining operations. Gasoline prices also rose on concerns about issues at the Phillips 66 Bayway refinery, affected by a power outage and flooding in New Jersey.

Crude, however, was more affected by signs President Donald Trump's sanctions on Iranian oil may succeed in removing a large amount of Iran's exports from the market once they take effect in November.

"It looks like South Korea and Japan are going to zero purchases. That's in line with the administration's demands," said John Kilduff, partner with Again Capital. "Both those countries stepped up to buy more U.S. crude oil."

West Texas Intermediate crude oil futures for October jumped 2.5 percent to $69.25 per barrel, while Brent crude surged 2.2 percent to $79.10. RBOB gasoline futures for October delivery jumped 2.2 percent to $2.00 per barrel.

"The market is getting concerned that those sanctions will be very effective in taking Iranian oil off the market, at the same time wondering if there are going to be other outages in Venezuela, Libya and can other producers make up supplies," said Andrew Lipow, president of Lipow Oil Associates.

As for gasoline prices, Lipow said there should not be much impact from Florence on gasoline unless it creates flooding or power outages that impact pumping stations for the Colonial Pipeline, which runs through the Carolinas and carries gasoline to the Northeast.

Platt's said that when Hurricane Irene came close in 2011, Colonial Pipeline made tentative plans to shut down but didn't have to — but that this storm looks worse. Platt's said Colonial issued a statement to shippers Monday, saying it was preparing for potential impacts later this week.

"Gasoline is getting helped by a couple of things. You get a sugar rush of demand when you get massive evacuations. The problem is you borrow from demand today from next Thursday when you have no demand. Hurricanes are demand destroyers," said Tom Kloza, global head of energy analysis at Oil Price Information Service. "I think people are worried there are so many areas at risk of flooding that are contiguous to the Colonial pipeline."

Tuesday, September 11, 2018

Iran to move oil export terminal out of Gulf


http://www.tankeroperator.com/ViewNews.aspx?NewsID=10045

Iran is to move its main oil export terminal from the Arabian Gulf to the Oman Sea, President Hassan Rouhani announced on Tuesday, according to local newswires.
 
Rouhani said exports were already being moved from Khark Island to Bandar-e-Jask in the Oman Sea. and This move will be completed by the end of his term in 2021, he confirmed.

"This is very important for me, it is a very strategic issue for me. A major part of our oil sales must move from Khark to Jask," Rouhani said in a televised speech as he inaugurated three new petrochemical plants in the southern energy hub of Asaluyeh.

To reach the oil terminal on Khark Island, tankers must pass through the narrow Strait of Hormuz choke point.

Iran has repeatedly threatened to block the Strait of Hormuz -- which is used by most of the GCC states, including Saudi Arabia -- when faced with sanctions on its oil exports and possible military action by the US.

The strait is the world's most important oil choke point with roughly 35% of all oil shipments passing through it, according to the US Energy Information Administration (EIA).

Bloomberg reported that Iran exported 2.1 mill barrels per day of oil in August and analysts calculate that US sanctions could reduce this figure to around 1 mill barrels per day.

Monday, September 10, 2018

Delta Belatedly Is Facing Up To Its One Big Mistake: Investing In An Oil Refinery

This Thursday, April 19, 2012 file photo shows the ConocoPhillips refinery in Trainer, Pa., near Philadelphia.  Delta Air Lines Inc. bought the refinery as part of an unprecedented deal that it hopes will cut its jet fuel bill. A Delta subsidiary paid $150 million, including $30 million in job-creation assistance it is getting from the state of Pennsylvania. (AP Photo/Alex Brandon)
This Thursday, April 19, 2012 file photo shows the ConocoPhillips refinery in Trainer, Pa., near Philadelphia. Delta Air Lines Inc. bought the refinery as part of an unprecedented deal that it hopes will cut its jet fuel bill. A Delta subsidiary paid $150 million, including $30 million in job-creation assistance it is getting from the state of Pennsylvania. (AP Photo/Alex Brandon)

https://fuelfix.com/blog/2015/07/06/as-delta-refinery-snaps-up-nigerian-crude-u-s-producers-ask-congress-for-freedom-to-export/


Delta Airlines has done a lot of things right since its 2008 acquisition of, and merger with Northwest Airlines, but buying a mothballed, dilapidated, small-ish and costly-to-operate oil refinery outside Philadelphia in 2012 most definitely is not one of them.

Plenty of experts in both the airline and the oil industries said at the time that Delta’s purchase from ConocoPhillips of what is now known as the Monroe Energy refinery in Trainer, PA, was a bad idea, and have continued to say so ever since. But only now are Delta’s own executives, who steadfastly have kept on defending the six-year-old mistake, beginning to admit it. And they’re only doing it now in a grudging, indirect way. But that can’t obscure the fact that Delta, the nation’s most profitable airline thanks mostly to its leaders over the last decade, likely would be even more profitable had they just stuck to their airline knitting instead of wading into the murky swamp of the oil business.

Last week Delta officials said publicly that they’ve hired Barclays Investment Bank and Jefferies Financial Group to look for a joint venture partner to buy a presumably large share of the airline’s Monroe Energy subsidiary. That – also presumably – is because Delta’s leaders know full well that they’ve got no realistic hope of finding a sucker crazy enough to take the whole thing off their hands.

In fact, University of Houston energy economics professor Ed Hirs, a long-time critic of Delta’s foray into the oil business, last week told Reuters that Delta’ quest to sell some of Monroe Energy could come up empty. That would put the Atlanta-based carrier - the world’s second-largest in passengers, capacity and revenue behind the less-profitable American Airlines - in a difficult position. It would have to decide between continuing to sustain large (but far from fatal) losses on its refinery or shutting it down entirely, much to their great embarrassment.

“It was a boneheaded decision” six years ago to buy it, Hirs said. “And they are still paying for it. It is going to be tough to sell a refinery that has faced closure several times due to bad economics.”

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Delta, then led by now-retired CEO Richard Anderson, bought the Trainer refinery for just $150 million. But the plant, which had been dormant for a while before the purchase, needed about $120 million in immediate investment at the time to bring it back online in a way that would meet new, tougher environmental rules. But Anderson, with the strong backing of his top lieutenants, including his eventual successor Ed Bastian, broadly proclaimed that the refinery soon would be producing $300 million annually in pre-tax profits.

But just as both airline and oil industry experts said at the time would be the case, Delta’s refinery, which initially produced mostly jet fuel – essentially kerosene – only came close to achieving such results one time.

Monroe Energy lost $63 million in the less than one quarter of 2012 in which it was owned by Delta. It then lost another $115 in 2013 as Delta struggled through the oil industry learning curve.
The refinery operation turned modestly profitable in 2014, earning $96 million before taxes, then reached its high water mark of $291 in profits in 2015. But as the price of oil and – more importantly refined fuels – fell sharply in 2016 so did Monroe Energy’s performance. The refinery had to quit producing about 40% of its product as jet fuel, on which profits were non-existent, and to increase its production of gasoline and diesel fuel, better-selling products that allowed it to lose less money per barrel of production and to collect on government incentives paid to refineries that mix corn-based ethanol into auto fuels. Thanks to a yawning imbalance between the supply – and the price - of crude reaching the plant and the price for its finished products Monroe Energy lost about $125 million that year.

In 2016 Delta called in consultants to help it sort out its oil refinery’s economic issues. They’re the ones who convinced Delta management to have the refinery shift production toward more gasoline and diesel and away from jet fuel. That helped slow the losses, but only a bit. The refinery’s financial results from 2017 and thus far in 2018 (which Delta has not made public) certainly have not been good enough to stop management from seeking a partner – preferably one with real oil industry investing and operational savvy – who might be able to solve the refinery’s problems (or at least provide Delta with some cushion against the refinery’s losses).

Luckily for Delta, their up-front investment in the refinery was relatively low. And compared with the airline’s $40.5 billion in 2017 revenues and $6.1 billion in profits, its Monroe Energy predicament remains something of a bothersome sideshow.

Still, Delta’s foray into the oil industry serves as another sobering lesson to airlines, which historically have done quite poorly whenever they’ve tried various types of vertical integration strategies.

Pan Am, TWA, Northwest, United and American are big U.S. airlines that did not do so well as owners and operators of big hotel chains. American in the 1980s, apparently thinking its base in Texas somehow gave it special insight into the oil business, also wasted time, and a little money, on an oil trading subsidiary. Most carriers also used to own at least a portion of the computerized reservations systems used to sell their tickets via travel agencies in the days before online selling. Those drew lots of attention from regulators but never created the kind of profits that they likely would have made had they been independent companies instead of captives providing their services to their owner-airlines at deeply discounted prices.

The biggest, ugliest example of failed airline efforts at vertical integration was the attempt in 1969 and 1970s of former United Chairman Richard Ferris to create a one-stop shop travel company called Allegis. It included not only United but also the Hilton and Westin hotel chains, Hertz rental cars and other, smaller travel companies. Ferris’ plan was so unpopular with employees and investors alike that it got him booted out of the company less than six months after he unveiled the Allegis mega-brand. All the Allegis subsidiaries except United then were sold off within a year. And United escaped being forced into bankruptcy only by agreeing to be acquired in an union-sponsored Employee Stock Ownership Plan deal that hamstrung the company for years thereafter.

In Delta’s case, despite Anderson’s hyped prediction of $300 million in annual pre-tax profits from the refinery business, the real reason Delta wanted to own a refinery was to use it as a physical hedge against fluctuating and potentially devastatingly high oil prices. The airline’s thinking was that by producing itself a sizeable percentage of the jet fuel the airline would be buying on the market, it could shield itself from the violent up and down swings in the per gallon price and from the periodic kerosene supply shortages that tended to drive big price spikes.

But, as many academics have argued over the years, when a commoditized business like the airline business buys other commoditized businesses like hotels and oil companies – companies whose products are highly sensitive to swings in demand and low price competition – the discounts at which one of those companies is forced to sell its products or services to its sister company typically fails to increase total corporate profits. Instead, researchers have argued effectively it usually has just the opposite of the intend impact by retarding total corporate profit growth.

In Delta’s case not only was that true,  its ownership of Monroe Energy actually helped bring down the price of jet fuel for ALL airlines even though only Delta committed corporate capital and management time to producing those savings.

As a result, Delta never has been able to close the gap between its unit cost for fuel and the price its primary competitors, American, United and Delta, pay per unit of capacity. In 2011 Delta paid, on average $3.10 per gallon of fuel vs. American’s price of $2.93, and United’s $2.87. Even Southwest managed to pay slightly less than Delta, $3.09 a gallon, that year even as its fabled fuel hedging position collapsed amidst an unpredicted big drop in the market price of fuel.
More to the point, it cost Delta 4.8 cents for the fuel it required to fly one seat one mile in 2011. American paid 4.6 cents while United and Southwest paid 4.5 cents each.  The purchase of Monroe Energy was supposed to push Delta from the bottom to the top of that list, but last year it still ranked fourth among that quartet of carriers in price paid for the fuel required to fly one seat one mile: 2.5 cents vs. 2.4 for all three of its big rivals. That tiny, one-tenth of a penny difference actually means a lot given that Delta flew 228.4 billion available seat miles in 2017. Had it simply paid the same price for fuel per available seat mile as its competitors paid last year Delta would have saved about $228.4 million in total fuel expense.

In short, Delta’s purchase of, and continued investment of capital in the Trainer refinery has produced none of the desired results for the airline.  Thus last year’s switch from heavy production of jet fuel to producing more gasoline and diesel was a quiet but clear – and painfully delayed - recognition of reality. So is this year’s decision to find another company on which Delta potentially can lay off some of the risk and responsibility for that refinery.

Thus Delta, which has done many, many things rights over the last 10 years, is facing up, however reluctantly and belatedly, to its one big mistake. And in the big picture, even that mistake isn’t all that big. Still, it is a black mark on Delta managements’ reputation, and one that investors don’t like. Right now they’ll put up with it, given the other, overwhelmingly positive results coming from Delta. But will they be so indulgent if Delta can’t find a partner with which it can share ownership of that old, struggling refinery in Pennsylvania?

Contributor

Dan Reed

I write about airlines, the travel biz, and related industries
 
I wrote my first airline-related news story in May 1982 – about the first bankruptcy filing of Braniff International Airways. That led to 26 years covering airlines and related subjects at the Fort Worth Star-Telegram and USA TODAY. I followed the industry through the entire arch of deregulation: expansion, disruption, and consolidation. I’ve also written two books on the subject: American Eagle: The Ascent of Bob Crandall and American Airlines, published in 1993, and (with co-author Ted Reed) American Airlines, US Airways and the Creation of the World’s Largest Airline, published in 2014. Today, I operate my own consulting firm and work as a freelance journalist covering aviation, faith, travel, business, IT, education, and sports. I’m a graduate of the University of Arkansas (Woo Pig Sooie!) and Southwestern Baptist Theological Seminary.

Friday, September 7, 2018

Tanker backlog builds up again in Venezuela after dock closure: data



(Reuters) - Crude exports by Venezuela’s PDVSA have slowed after a tanker collision at its main port last month disrupted operations, adding to a backlog of vessels waiting to load, according to shipping sources and Reuters data.
 
Oil is the financial lifeline for the embattled socialist government of President Nicolas Maduro, but his cash-strapped administration has failed to invest enough in the industry to prevent its decline. Venezuela has sought to increase exports after asset seizures and declining output earlier this year raised the prospect of temporary suspension of contracts. 

PDVSA has not said how long it will take to repair damage from the collision and resume normal loading and discharging operations. The company did not immediately reply to a request for comment. 

Last week, PDVSA offered loadings at an alternative port to crude customers whose shipments were affected by the collision, but only a few have accepted so far, the sources said. That alternative, the Puerto la Cruz terminal, is limited to loading 500,000 barrels of crude per tanker, far less than the 2 million barrels PDVSA’s main port of Jose can handle. 

Large tankers including three Suezmaxes and seven Very Large Crude Carriers (VLCCs) are lined up off Jose waiting to load at the available docks and monobuoys systems. 

The vessel backlog around PDVSA’s ports has been increasing since late August, following the collision. As of Sept. 6, more than 20 tankers were waiting to load 26 million barrels of Venezuelan crude, according to Reuters Trade Flows and vessel tracking data. 

PDVSA’s crude exports rose in July to 1.39 million barrels per day (bpd), the most since November, but last month they slipped almost 8 percent to 1.29 million bpd on Jose port’s partial operations, falling oil output and Caribbean terminal seizure attempts by creditors including U.S. producer ConocoPhillips, according to the Reuters data. 

One of PDVSA’s main customers, Russia’s state-run Rosneft, loaded a 925,000-barrel cargo of diluted crude oil (DCO) during the weekend at one of Jose’s monobuoys after being diverted from the South dock, still closed because of the collision. 

Rosneft-chartered Nordic Moon set sail to Malta on Sunday after waiting to load in Venezuela since early August. But the Russian company still has other four vessels waiting to load up to 6 million barrels of heavy crude at Jose, according to the data. 

Jose’s South dock, which suffered damage from the collision last month, is mainly used for shipping Orinoco Belt crude and discharging imported naphtha used to dilute the country’s extra heavy oil and make it exportable. 

Reporting by Marianna Parraga; Editing by Steve Orlofsky

Thursday, September 6, 2018

Mexico President Plans Massive New Oil Refinery In Blow To U.S. Refiners

Amlo


Mexico’s President Andres Manuel Lopez Obrador has plans to build the country’s largest refinery with a capacity to produce 400,000 barrels of gasoline daily, Reuters reports, citing comments by Obrador during a meeting with businessmen in Monterrey.

The refinery would cost US$8 billion to build and construction could start soon, which would see it complete within three years. Though Reuters quoted Obrador as saying, “400,000 bpd of gasoline,” it added in its report that the comments did not made it clear whether he was referring to the crude oil processing capacity of the future facility or its gasoline production capacity.

Currently, Mexico’s refineries have a combined processing capacity of a maximum 1.6 million bpd of crude but, Reuters notes, it has been working at just 40 percent capacity since the start of the year because of accident-caused outages and operational issues. Pemex, which operates the six refineries, also exported more crude as prices improved internationally. In July, the state oil company produced 213,000 bpd of gasoline.

Earlier this year, Rocio Nahle, an adviser to Obrador and the most likely candidate for the Energy Minister job, said “In a three-year period, at the latest, we need to try to consume our own fuels and not depend on foreign gasoline.” This would be bad for U.S. refiners, who export the biggest portion of their production to Mexico. In the last few years, Mexican imports of gasoline and diesel have risen to more than 800,000 bpd, representing over 66 percent of domestic demand.
Mexico’s current oil production stands at about 1.84 million bpd, of which 60 percent is exported. At the same time, according to Reuters, the country imports around 1 million bpd of refined products.

“The commitment is to produce gasoline in Mexico,” Obrador said at the Monterrey meeting. “We want to produce gasoline because we have the raw material, we have crude oil.”

Regarding production, last month Obrador said all oil auctions would be suspended until contracts awarded by the previous government over the last three years are reviewed.

By Irina Slav for Oilprice.com

Wednesday, September 5, 2018

Oil demand to hit 100 mln bpd sooner than projected: OPEC's Barkindo

 
 Mohammad Sanusi Barkindo, Secretary General, Organisation of Petroleum Exporting Countries, OPEC


CAPE TOWN (Reuters) - World oil consumption will reach 100 million barrels per day (bpd) later this year, hitting that level much sooner than previously forecast, OPEC’s secretary-general said on Wednesday.

Mohammad Barkindo also told an energy conference in South Africa’s Cape Town that a stable environment was needed to encourage oil industry investment to meet the rising demand.
“The world will attain the 100 million barrels a day mark of consumption later this year, much sooner than we all earlier projected. Therefore stabilizing forces which create conditions conducive to attracting investments are essential,” he said. 

“The priority ... is on ensuring stability is sustainable, spreading confidence in the industry and encouraging an environment conducive to the return of investments,” he added. 

The Organization of the Petroleum Exporting Countries with Russia and other producers have implemented a deal since January 2017 on cutting 1.8 million bpd from output to prop up prices that fell below $30 a barrel in 2016 from over $100 in 2014. 

On Wednesday, benchmark Brent LCOc1 was trading at just below $78. 

Barkindo said oil industry confidence was returning and OPEC was exploring ways of institutionalizing cooperation between OPEC and its non-OPEC allies on their production levels.
Barkindo also told reporters at the conference that global trade disputes could hurt energy demand in future, although he said he was hopeful the uncertainty would lift soon. 

U.S. President Donald Trump’s tariff threats against China, the world’s second-biggest economic power, have caused jitters in markets across the world. 

“The trade disputes that are emerging among some of the leading partners in the world will eventually hurt (global economic) growth and, by extension, demand for energy,” he said. 

“But we are confident ... these parties will be able to overcome some of these challenges,” Barkindo said. “We are hopeful we will be able to overcome this cloud of uncertainty regarding trade as quickly as we can in order to mitigate the contagion.” 

Writing by Alexander Winning and James Macharia; Editing by Edmund Blair

Tuesday, September 4, 2018

What is Saudi Aramco? | CNBC Explains

With pipelines full, oil and gas companies turning to trucks, rail

http://2.bp.blogspot.com/-mlwg8jcDUyM/VGZeRq9cmAI/AAAAAAAACDE/AAsQg_vXDj8/s1600/ethanol%2Btransloading.png


Oil producers in the Permian Basin, dealing with a shortage of pipelines, are increasingly turning to trucks and rail to ship the flood of crude from the West Texas oil field to refineries and export terminals on the Gulf Coast.

These transportation shifts are driven by two simple math problems. First, crude oil production in the Permian has reached 3.6 million barrels a day, while pipeline capacity out of the region is just 3.5 million barrels a day, according to the energy research firm Wood Mackenzie. Next, crude is selling for as much as $10 more a barrel in South Texas, the Gulf Coast and other markets outside of West Texas, where inventories are building in part because of the lack of pipeline capacity

The latest effort to move oil to more lucrative markets was launched earlier this week, when the Houston oil transport company JupiterMLP signed a deal with Vista Proppants and Logistics of Fort Worth to ship West Texas crude by rail from Vista’s loading terminal in Pecos. Vista plans to ship about 400,000 barrels a month from its Pecos terminal through 2019 and potentially into 2020, depending on when pipeline projects are completed.

It’s unclear how much of crude Vista will handle for JupiterMLP, which has completed permitting to build a processing and export terminal at the Port of Brownsville and plans a 670-mile pipeline from West Texas to the export terminal. Neither company responded to requests for comment.

Pipeline capacity has become a particular problem in the Permian, as booming production of both crude and natural gas has exceeded capacity and created bottlenecks. Several companies, including Kinder Morgan and Phillips 66 Partners, both of Houston, are racing to complete pipeline projects, but most are not expected to begin operations until at least next year.

The bottlenecks, meanwhile, are not only having an impact on prices in West Texas prices, but also production. The Railroad Commission of Texas, which oversees the oil and gas industry, recently reported that oil production in the state — most of it concentrated in the Permian — declined about 2 percent in June, compared to the same month a year earlier, the first year-over-year decline since early 2017. Analysts attributed the decrease to the pipeline shortage.
A recent analysis by the London consultancy Westwood Global Energy Group estimated that pipeline constraints could delay as much as $1.4 billion of investment in the Permian and keep 345 wells from getting completed in the second half of this year. That means the wells have been drilled, but not hydraulically fractured, or fracked, to begin producing oil and gas.

The number of these drilled but uncompleted wells, known as DUCs, have increased significantly in the Permian. The Department of Energy estimated 3,470 DUC wells in the Permian in July, up 80 percent from just over 1,900 a year earlier.

Production companies big and small are contracting for pipeline capacity on yet-to-be completed and cutting deals with trucking companies and rail carriers to get their crude out of West Texas to other markets in the meantime. Union Pacific Railroad, one of the largest rail operators in the country, has seen a recent uptick in crude oil coming out of the Permian, said company spokesman Jeff DeGraff, though he wouldn’t cite specific figures.

Oil companies have also turned to the trucking industry to transport their crude, potentially adding more stress on an industry that is already under pressure from driver shortages and the demands of hauling record amounts of sand and water for fracking and moving drilling rigs and equipment from one site to another.

Matt Nevarez, the director of operations for the Midland trucking company TexStar Crude Transport in Midland, said demand for shipping crude is so strong that his company is hiring trucks out of San Antonio to carry oil from West Texas to South Texas markets in Three Rivers, Cotulla, and Victoria. When asked which companies were moving oil by truck, Nevarez said, “All of them.”

“The market spread for what they can sell a barrel for in South Texas versus Midland, it’s huge, so everybody’s wanting to get their oil down there,” Nevarez said.

But environmentalists worry that all of these extra trucks on the road carrying crude oil and trains going through populated areas could pose a public health risk. Luke Metzger, the director of the advocacy group Environment Texas, pointed to the oil train accident and explosions in the Canadian town of Lac-M├ęgantic that killed more than 40 people when a train full of North Dakota crude oil derailed in the middle of town and exploded.

Metzger said he doesn’t believe that many people in the state are aware of dangers posed by increased shipments of crude by truck and rail.

“That’s unfortunate because these could be very dangerous and people need to know that this could be going to a neighborhood near them soon,” Metzger said.

Relief may be coming in the form of what John Coleman, a senior research analyst at Wood Mackenzie calls three mega pipeline projects. Totaling 2.1 million barrels of capacity, they are the EPIC Crude Oil Pipeline, the Gray Oak Pipeline, and the Cactus 2 Pipeline. All aim to be completed by the end of 2019.

rdruzin@express-news.net | Twitter: @druz_journo

Sunday, September 2, 2018

Saudi Arabia hints at plan to turn Qatar into an island

 
The Saudi plan, which would physically separate the Qatari peninsula from the Saudi mainland, is the latest stress point in a highly fractious 14-month long dispute between the two states (AFP Photo/KARIM JAAFAR) 


Riyadh (AFP) - A Saudi official hinted Friday the kingdom was moving forward with a plan to dig a canal that would turn the neighbouring Qatari peninsula into an island, amid a diplomatic feud between the Gulf nations.

"I am impatiently waiting for details on the implementation of the Salwa island project, a great, historic project that will change the geography of the region," Saud al-Qahtani, a senior adviser to Crown Prince Mohammed bin Salman, said on Twitter.

The plan, which would physically separate the Qatari peninsula from the Saudi mainland, is the latest stress point in a highly fractious 14-month long dispute between the two states.

Saudi Arabia, the United Arab Emirates, Bahrain and Egypt cut diplomatic and trade ties with Qatar in June 2017, accusing it of supporting terrorism and being too close to Riyadh's archrival, Iran -- charges Doha denies.

In April, the pro-government Sabq news website reported government plans to build a channel -– 60 kilometres (38 miles) long and 200 metres wide –- stretching across the kingdom's border with Qatar.
Part of the canal, which would cost up to 2.8 billion riyals ($750 million), would be reserved for a planned nuclear waste facility, it said.

Five unnamed companies that specialise in digging canals had been invited to bid for the project and the winner will be announced in September, Makkah newspaper reported in June.

Saudi authorities did not respond to requests for comment and there was no immediate reaction on the plan from Qatar.

After the dispute erupted last year, Qatar -- a small peninsula nation -- found its only land border closed, its state-owned airline barred from using its neighbours' airspace, and Qatari residents expelled from the boycotting countries.

Mediation efforts led by Kuwait and the US, which has its largest Middle East air base in Qatar, have so far failed to resolve the dispute.