Friday, November 29, 2019

From rust to robust: Appalachia's shale region is reshaping American energy

From rust to robust: Appalachia's shale region is reshaping American energy


The U.S. has surpassed Russia and Saudi Arabia as the world’s top oil and natural gas producer — an accomplishment important not only to America’s foreign policy but also to the father and mother in Steubenville, Ohio, working to provide for their family.

America’s energy abundance has positively transformed our country’s energy outlook by delivering shared economic, environmental and security benefits for all. Consumers, from families to manufacturers, continue to be the clear winners.

Over the span of 2008 to 2018, natural gas end-users, which include American households, businesses, manufacturers and electric power generators, have realized an incredible $1.1 trillion in savings, according to a recently released economic analysis. The savings on natural gas directly impacts nearly all goods and services. When allocating the entire $1.1 trillion savings over the past 10 years from every sector to each household in America, the yield is approximately $9,000 of savings per household.

For the family in Steubenville, those savings might mean extra room in the family budget to go on a vacation, save for their children’s education, or put a little away for a rainy day.

Just as the savings tied to domestic natural gas can give families added spending power, shale development is a shot in the arm for manufacturing and for good-paying, family-sustaining jobs critical for a thriving middle class.

These savings, enjoyed by consumers coast-to-coast, are made possible in large part by the natural resources found in the heart of Appalachia. Since the 1970s, this region has witnessed a mass exodus of manufacturing jobs. Once known as the nation’s manufacturing hub, the region was tagged with the “rust belt” moniker.
Natural gas is the fuel of manufacturing and America’s historic decline in manufacturing was significantly impacted by the nation’s decline in natural gas fuel supply. Today, America has an abundance of natural gas largely because of the development of the Marcellus and Utica Shale formations in Ohio, West Virginia and Pennsylvania. From 2008 to 2018, 85 percent of all natural gas growth in the U.S. has come from the above three states.

The three states combined now produce more natural gas than Texas. If Ohio, West Virginia and Pennsylvania were a country they would be the world’s third-largest natural gas producer, behind only the U.S. and Russia. That is why we’ve given this region a new moniker: “Shale Crescent USA.”

This strength of natural gas production and opportunity for long-term growth gives manufacturers in Shale Crescent USA a competitive edge not seen in decades. Its future as a second petrochemical hub is beginning to take shape with Shell’s $6-billion cracker plant under construction in western Pennsylvania, the highly anticipated potential for the PTT Global Plant facility in eastern Ohio, and similar projects currently in various stages of discussions across the region.

Drawn by the vast amounts of ethane and other natural gas liquids used to create consumer products, companies are investing in the local economy and creating jobs. This “second phase” of the energy renaissance — the expansion of American manufacturing — is the next step in capitalizing on our geological gifts, which will create more well-paying jobs and keep the U.S. competitive globally.

America’s strengthened energy outlook provides a host of economic, environmental and national security gains. But for the people of Shale Crescent USA, the family in Steubenville, the home energy savings and the opportunity to once again make things in America is one of the most important and promising benefits our domestic energy revolution presents.

Jerry James is president of Artex Oil and co-founder of ShaleCrescent USA, an economic development initiative that aims to drive growth and investment in Ohio, Pennsylvania and West Virginia. Follow on Twitter @ShaleCresUSA.

Falling oil prices may be misreading a tenuous situation in Iraq

RT: Iraq protests 191126
Boys run past burning tires set up by Iraqi protesters during ongoing anti-government protests in Najaf, Iraq, November 26.
Alaa al-Marjani | Reuters
  • Oil drops on Friday, triggered in part by the resignation of Iraq’s prime minister, a move that some traders believe could calm protests in the country.
  • But analysts say the situation is not resolved, since protesters are aiming their ire at Iran and Iran is unlikely to want to reduce its influence in the country.
  • Oil is also moving on technical factors and is reacting to uncertainty in both U.S.-China trade talks and around the outcome of OPEC’s meeting with Russia next week.
The resignation of Iraq’s prime minister helped trigger a drop in oil prices, but analysts say that may not be the right response by investors, as Iraq’s future may have just become even more uncertain.

Iraq is the second-largest oil producer in OPEC, with output nearing 5 million barrels a day, and analysts had said that anti-government protests in the country could ultimately impact oil exports if they continued.

Prime Minister Adel Abdul-Mahdi announced his resignation Friday after the country’s top cleric criticized the government following a deadly day of protests. Ayatollah Ali al-Sistani urged Iraq’s Parliament to stop the country from “sliding into chaos, violence and destruction,” according to news reports.

Oil fell in U.S. trading after the development but was also impacted by negative sentiment around trade talks and OPEC.

West Texas Intermediate futures were down 4.3% at $55.61 per barrel in midday trading. Brent futures were off 2.2% at $62.49 per barrel.

“It’s falling because the protesters got what they wanted,” said John Kilduff, partner with Again Capital. He said investors may now think the potential for disruption of Iraq oil exports has abated.

“Let’s see how the market reacts to this development. Scores were killed over the weekend,” he said.

Helima Croft, head of global commodities strategy at RBC, said the situation in Iraq now risks getting worse. “I think this is maybe far from over,” she said. “They are trading on a headline because they believe the Middle East is becoming more tranquil, not realizing that the battle for the future of Iraq is entering a more dangerous phase potentially.”

Protesters have focused on Iran’s influence in the country, which has water shortages, power outages and a high level of unemployment.

“There’s a sense the oil dividend is not being used to produce any economic dividend,” Croft said.

Croft said Abdul-Mahdi was expendable because he was not tied to any party, and the question now is when will elections take place.

“He was a consensus pick. What has to be a concern to Iran is that these Shiite protesters in Iraq have turned their rage on Iran,” said Croft.

Kilduff said the protests are another challenge to Iran in the region, at a time when its regime is also being challenged by violent protests in its own country. “That’s a key development, that the ire of the protesters is directed toward Iran,” he said.

As oil was being hit hard Friday, the outlook for the trade dispute between the U.S. and China looked more uncertain. The talks are expected to continue, but the potential for a deal became murkier after President Donald Trump signed a bill supporting protesters Wednesday, and Beijing responded negatively in return.

There are also doubts surfacing about OPEC’s meeting next week, with Russia potentially seeking to have its condensates exempted from the production quotas. News reports quoted unnamed sources saying Saudi Arabia does not want to shoulder a bigger percentage of the cuts.

“The OPEC meeting is looking more bearish by the day,” Kilduff said, noting that oil was also moving on technical factors. “The meeting looks like it might be going off the rails.” West Texas Intermediate futures slid just under the 50-day moving average at $55.62 per barrel.

Iraq is now the fourth government to fall, following Lebanon, Algeria and Sudan.

“Oil’s a totally broken barometer. The fact we’ve had multiple governments falling in the region does not mean the region is becoming more placid,” Croft said.

Wednesday, November 27, 2019

OPEC and Russia likely to extend oil production cuts at upcoming meeting

RT: Vladimir Putin, 191114
Russia’s President Vladimir Putin waves to the media prior to a meeting of leaders of the BRICS emerging economies at the Itamaraty palace in Brasilia, Brazil, Thursday, November 14, 2019.
Pavel Golovkin | Pool via Reuters

  • OPEC and Russia, or OPEC Plus, meet in Vienna next week, and it is widely expected oil ministers will extend their production cut agreement to June or even the end of next year.
  • There are rumblings that Russia has not been happy with the structure of the deal, and may want to find a way to limit participation.
  • The meeting coincides with the initial public offering of Saudi Aramco, and there is also speculation Saudi Arabia may want to find a way to boost oil prices.
OPEC and Russia are likely to extend their oil production deal at least through midyear, but if they were to cut more output, as some speculate, it would blindside what has become a complacent market, analysts said.

The ministers head into the Dec. 5 and 6 meeting with oil prices near their highest levels in two months. OPEC and Russia and other allies have an ongoing agreement to reduce output by 1.2 million barrels a day, with the biggest cuts coming from Saudi Arabia.

“At this stage, it’s not perfect for a number of producers, but it’s not catastrophic either,” said Helima Croft, global head of commodities strategy at RBC. “We’re kind of treading water.”

The current agreement expires in March, but many analysts expect the OPEC plus group to extend it until its next meeting in June or even to its meeting a year from now.

“It’s a very unsettled time for OPEC. The gulf between the haves and have nots has widened. Price relief has not been enough to stave off social unrest in a number of key producer states. ... There’s no better option at this point,” Croft said. ”...We’ve had almost like a second Arab spring.”

Croft expects the deal to be extended until June, and then ministers will again review it. Many other analysts expect the cuts will be extended as well, but some believe OPEC and Russia could cut even more.

“A Hollywood shock ending would be if they actually went deeper,” Croft said.

An IPO in waiting

The meeting comes at a key time for Saudi Arabia, which will be issuing stock in its state-run Saudi Aramco for the first time ever, just as OPEC’s meeting gets underway.

“It wouldn’t surprise me if the Saudis would go for more [production cuts], to tighten the market even more than they have already,” said John Kilduff of Again Capital. Kilduff said Saudi Arabia may want to make sure oil prices continue to improve, especially in light of the Aramco offering.

Russian energy minister Alexander Novak has said he doesn’t favor increasing the size of the cuts, and the Russian position is that members should be forced to comply with the current level of production.

Russia has also been angling to have condensates removed from the deal, meaning it would only to have its actual crude oil production counted, not other petroleum byproducts. If that were to happen, Russia’s share of the cuts would fall since its overall production total would drop.

“The Russian intentions will be a critical aspect of it for the future, especially with them wanting some wiggle room on the condensate and potentially produce more. They’ll be in the deal in name only,” said Kilduff.

There has been speculation that Russia may be unhappy with the production agreement, in part because its energy companies oppose it.

“It’s not so much that Russia is going to storm out of the meeting. As to what may end up happening, may be more wait and see,” said Citigroup energy analyst Eric Lee. He said it’s possible the OPEC plus group could maintain the status quo, hold off on extending the agreement, and call a meeting for right before the March expiration. That would unsettle the market, he said.

″“Unless they deliver something quite strong and stick to it, then it’s more likely to have some downside risk,” he said.

The ‘Sultan of Oil’

Lee said it’s even possible Russia and Saudi Arabia could ultimately break off their agreement, and it may have been ended already were it not for Russia’s problems with contaminated oil earlier this year. The incident forced it to reduce exports, and it came into compliance with the accord.

But most analysts say the agreement has support from President Vladimir Putin and that’s what matters most.

“He’s the new sultan of oil,” said Kilduff. Even Putin mentioned the Aramco IPO when discussing OPEC recently in Brazil.

“We have really constructive dialogue with OPEC,” Putin was quoted as saying. “We understand that the tough stance, including from our friends from Saudi Arabia, is linked to the Saudi Aramco IPO. Everybody understands this. It’s an open secret.”

Russian energy companies are set to meet with Novak later in the week. “It helps Russia’s bargaining position if Novak goes into the meeting and says he has a coalition of producers who don’t like the cuts,” she said.

Croft said the Russian relationship with OPEC, or Saudi Arabia, is important, and Putin supports the arrangement so Russia will be behind maintaining an agreement.

“I think the financial benefits and the soft power strategic gains far outweigh the cost of shutting down several hundred thousand barrels,” said Croft. “The broader Russia Inc has gained enormously in terms of new deals that have been signed with Saudi Arabia and the UAE...The ultimate decision maker is Vladimir Putin and the deal provided significant dividends.”

Kilduff said oil prices could go higher because currently the market is ignoring turmoil in the Middle East and is mostly focused on the trade talks between the U.S. and China.

Croft noted that protests in Iraq, near energy operations in Basra, could impact oil output if energy workers got involved. There has been unrest across the Middle East, including in Iran, where protests against the government are increasing as the economy worsens and Tehran cut gasoline subsidies.

“The futures market is signalling that the market is tightly supplied at the moment,” said Kilduff. Brent futures were at $64.28 per share late Tuesday, near its highest level in two months.

Tuesday, November 26, 2019

Oil gains, holds near 2-month high as looming OPEC meeting expected to yield deeper cuts

 Employees of Aramco oil company work at Saudi Arabia's Abqaiq oil processing plant.

Oil prices recovered late Monday after a mostly down day, having gained in three of the past four sessions.

Prices remained near the two-month closing highs scored last Thursday as “the trifecta of positivity: U.S.-Sino trade talk optimism, OPEC+ compliance and a sturdy U.S. macro data scrim, should continue to resonate” with oil bulls, said Stephen Innes, chief Asia market strategist with AXI Trader.

West Texas Intermediate crude futures for January delivery CLF20, -0.03%  closed up 24 cents, or 0.4%, to $58.01 a barrel on the New York Mercantile Exchange. January Brent crude BRNF20, +0.19%, the global benchmark, gained 26 cents, or 0.4%, at $63.65 a barrel on ICE Futures Europe.

Contributing to the positive tone on the trade front, the Chinese government on Sunday released a document calling for more protection of intellectual property rights. Oil futures hit a two-month high on Thursday before choppy trading action took over at week’s end when China’s President Xi Jinping said Beijing wants to work with the U.S. for a trade deal, but was not afraid to “fight back” to protect its own interests, according to the Associated Press.

“Traders will be looking for any positive signs that the much-discussed face to face between the U.S. and China will take place before Dec. 15 when the U.S. is scheduled to impose more tariffs,” said Innes.

The front-month U.S. benchmark WTI contract ended 0.1% lower last week, while Brent, the global benchmark, logged a weekly gain of roughly 0.1%. 

“Given WTI moved to multiweek highs on Thursday, the bulls are broadly in control,” said Richard Perry, analyst with Hantec, in a note. Perry pegs near-term resistance at $58.65 and then $59.40 for WTI. He’s advising clients that as a “run of higher lows and higher highs continues, we see buying into weakness as the strategy.”

Oil prices have climbed of late as global supplies have fallen so far this year thanks to efforts by the Organization of the Petroleum Exporting Countries and its allies, but growth in U.S. shale output and a slowdown in crude demand threaten to ruin that progress.

Those are among the big issues that the group will deal with when it holds meetings to discuss the oil market on Dec. 5-6 in Vienna. As officials ready to meet, global benchmark Brent trades around 19% higher year to date, after posting a yearly loss of almost 20% in 2018, according to Dow Jones Market Data.

A combination of improved OPEC compliance, expectations for an extension of cuts from the group beyond March 2020 and slowing U.S. production growth have all added up to a bullish picture for crude oil. In support of that last factor, Baker Hughes BKR, +0.13%  on Friday reported a fifth consecutive weekly decline in the U.S. oil-rig count. The number of active U.S. rigs drilling for oil fell by 3 to 671.

“Expectations are building for action to be taken by OPEC+,” ING strategists said in a note. The cartel will need to deepen cuts and extend them through June 2020, the strategist group said, as “failing to do so would mean the risk of weaker prices, given the scale of the surplus forecast over the first half of 2020.” 

But, they added, notable price rises this week “could send the wrong message to OPEC+ members, possibly signaling that deeper cuts are not needed.”

In other energy trading, December gasoline RBZ19, +1.09%  recovered to gain less than 0.1% at $1.6748 a gallon, settling 2.4% higher for last week, while December heating oil HOZ19, -0.03%  rose 0.7% to $1.9443 a gallon; it fell 1% last week.

December natural-gas futures NGZ19, -3.56%  fell 5% to $2.5310 per million British thermal units, after they fell around 0.9% last week.

The product market was in retreat amid a forecast for milder weather for the period post-Thanksgiving.

Monday, November 25, 2019

China’s International Offshore Oil Footprint

 Oil be damned ... China is now the largest crude oil operator in the North Sea 

Willing to take risks in places others often won’t, China is a keen financer of global offshore oil and gas projects. Most recently, the one-party state’s national oil companies have signed mega deals with Nigeria and the Philippines. Where else can China’s money be found and what are the benefits and drawbacks of its foreign investment? We investigate.

China is the world’s biggest foreign buyer of oil, importing two-thirds of what it consumes. Between the early 1990s and 2010, China’s oil consumption increased five-fold.

To secure supply, the country’s three major Chinese national oil company’s (NOCs)– China National Petroleum Corporation (CNPC), China Petroleum & Chemical Corporation (Sinopec) and China National Offshore Oil Corporation (CNOOC) – are known for making rapid investments in offshore oil and gas projects across the globe.

With the backing of the Chinese one-party state, unlike their Western counterparts, China’s NOCs are unhampered by risk adverse investors and often willing to go where others won’t. This has seen the country invest in geopolitically sensitive regions with the seemingly dual purpose of securing oil supply and cementing China’s global influence.


Nigeria is Africa’s biggest oil producer. One of China’s first investments in the country was in the Egina field, which commenced production in 2018 and is expected to reach peak production of approximately 200,000 barrels of crude oil per day in 2019. The project gave CNOOC, China’s third largest NOC, vital experience in the region.

In 2016, the Nigerian government signed $80bn worth of oil and gas infrastructure agreements with Chinese companies to be spent on pipelines, refineries, power, facility refurbishments and upstream, according to the Nigerian National Petroleum Corporation (NNPC).

By August 2019, NNPC is reported to have said that Chinese investment in Nigerian oil and gas had reached $16bn. The state owned company view the investment as a validation of the sectors continued potential, as well as a way to reach its target to grow production to three million barrels per day by 2023.

However, while the Nigerian government has generally welcomed Chinese financers, others have raised concerns over the country’s over-reliance on Chinese money – a common theme for the poorer countries it invests in.


In recent years, the Philippines and China’s relationship has been marred over territorial disputes in the South China Sea. Despite this, in 2018, Beijing and Manila agreed to a joint oil and gas exploration deal after a two-day visit by Chinese President Xi Jinping to the Philippines.

Philippines opposition Senator Antonio Trillanes is reported as saying that co-operation with China for oil and gas exploration would not affect the two nations’ positions on sovereignty and maritime rights. Nevertheless, the deal angered some who thought it would compromise the country’s territorial claims in the South China Sea.

In August 2019, Jinping doubled down. He said China and the Philippines could take a “bigger step” in the joint development of oil and gas resources in the South China Sea if they properly handle their dispute over sovereignty.

However, the secretive passage of China’s warships within Manila’s 12-mile territorial sea has put President Duerte under pressure to assert its dominance over China in the region, and it remains to be seen if the two countries can continue to work together.


As tensions continue to rise between the US and Iran, and indeed China and the US, Beijing has strengthened its strategic partnership with Tehran.

Recently, China promised to invest $280bn in the country’s beset oil and gas industry. This forms part of an update to a $400bn, 25-year investment program in the Iranian economy signed in 2016. The investments will focus on Iran’s oil and gas sector, but also touching other industries such as manufacturing.

In exchange for the money, Chinese firms will maintain the right of the first refusal to participate in any and all petrochemical projects in Iran, including the provision of technology, systems, process ingredients and personnel required to complete such projects.

China joins Russia as a major lender- and economic lifeline – to the country which is currently stymied by new US sanctions.

But China will have to work hard to get around the sanctions or see its oil and gas companies that have interests in both the US and Iran suffer for falling foul of them.

The sanctions are thought to be responsible for news in October that CNPC has withdrawn from Iran’s phase 11 of South Pars gas field.


In exchange for oil, China has provided loans – reportedly around $60bn worth since the 80s – that have helped rebuild Angola after its brutal civil war. Angola is one of the major petroleum exporters to China, with more than half of the petroleum exported by Angola in 2016 being bought by China.

Chinese companies also hold interests in licences offshore Angola. China’s Sinopec developed a 50/50 partnership with Angolan state-owned Sonangol, called Sonangol Sinopec International. The group holds 50% participating interest in offshore Block 18 in Angola, which is operated by BP and covers an area of more than 5000km2 and lies in water depths of 500 – 1600m. The joint venture has interests in eight other oil blocks in Angola and one onshore oil block in Indonesia.

The Angolan government is said to be keen for China to provide further investment to revive the country’s ailing oil industry, which has seen falling production.

However, like in other nations, some believe the high-level of Chinese investment has left Angola too reliant on the state and unable to take advantage of other deals. For example, The Financial Times reports that, as of February 2019, Angola’s foreign-exchange reserves are just over a third of what they were in 2013.


Growing environmental concerns over the development of Canada’s oil sands have put US and European companies off entering the market. But not resource hungry China.

The country’s big three national oil companies — CNOOC, PetroChina and Sinopec – have invested big in Canada’s expensive to extract oil sands. This is unlike the Western majors who have reduced their interests in the region.

In 2012, PetroChina became the first Chinese national company to wholly own a Canadian oil sands development after it bought out its partner Athabasca Oil Sands Corp’s stake in the MacKay River project in northern Alberta.

Similarly, CNOOC has an interest in more than 300,000 acres in the Athabasca region. This includes the Long Lake facility, located in northern Alberta, which began producing in 2008, with production capacity at around 72,000 boe/d. In 2018, an expansion project started which will add 26,000 boe/d from three well pads that will be tied-in to the existing Long Lake facility.

Reaffirming its commitment to the area, Sinopec has joined a group planning to build an $8.5bn oil refinery in Alberta that will process 167,000 barrels per day of crude into gasoline and other products.


Libya’s proven oil reserves are around 50 billion barrels, according to OPEC. Before the Libyan war, around 75 Chinese companies operated in the country, involving around 50 projects. At one point, China was

reportedly shipping roughly 150,000 barrels per day of crude oil from Libya.

Investment from China, which makes a point of always remaining politically neutral in other countries’ affairs, is said to be favourable to the Libyan government in order to help bail out the country’s oil industry which has been degraded through years of civil unrest. In fact, the chairman of the country’s National Oil Corporation has emphasized the importance of energy sector cooperation with Beijing.

China, on the other hand, likely views a presence in Libya conducive to its two aims of securing oil supply and cementing its global influence.

The partnership has already produced results and Libya’s oil exports to China are already growing. In 2017, they reported a total of $1.7bn, double the year previously.

Thursday, November 21, 2019

Gas Prices Languish As Storage Falls To Near-Record Lows

Natural Gas

The natural gas market appears to have lost a sense of scale for storage volumes. Prices languish while last week’s EIA figure for gas in storage at the end of injection season, normalized to supply, represents the second lowest on record even as gas demand is poised for a last major surge.

From 1975 until 2008, annual dry natural gas production varied oscillated flatly from 44 to 55 Bcf/d for over thirty years before beginning a quiet explosion. By contrast, 2019 will average in the low 90s after growing at a break-neck 11% in 2018 and continuing to grow through this year. This new reality of supply and demand changes the significance of the nearly unchanged gas storage capacity.

Storage, of course, buffers seasonal temperatures, and seasonal use has grown only marginally in the last ten years. Storage, however, also buffers the much larger industrial and export demand. That buffer, for both the impending winter and for the near-term growth in exports, now stands at the second lowest on record for the season.

The chart below shows the complete 25 years of weekly storage data available from the EIA normalized to production. Until the last few years, injection season commonly concluded with about 60 days of supply in reserves as shown in gray. The normalized buffer sagged from 2014 to 2017 (orange), but last year (red) marked the low point of a nearly three-year shortage. After those years of chronic depletion of storage, prices responded over $4, and rig count ascended briefly to peak in January of this year at 202. Prices ebbed, and rig count followed closely with the best plays laying down rigs from early March. Given the four to six months of delay common for horizontal wells, the last of the resulting bonus supply has already arrived. Related: The Race To Develop A 50 Billion Barrel Oilfield

Figure 1: Storage normalized to supply. (, EIA data)

Moreover, the so-called “first wave” of LNG exports should have more than doubled U.S. exports during 2019, mostly during the injection season. But four of the five projects—Cameron, Corpus, Freeport, and Elba Island--started late. Unmaterialized demand sent available natural gas production into storage fields instead of cargo holds, topping off one of the largest storage injections recorded.

These new export volumes did not disappear, though; they only delayed. In the latest data available, exports had not yet reached 5 Bcf/d in June, though the full build-out will reach over 9 Bcf/d. Together with a few Bcf/d of planned industrial expansions, these exports will wrap up a decade of rapid growth with one final multi-BCF push beginning during this withdrawal season and ending by about the middle of next year. Related: Is Big Oil Wasting Its Time in The US Shale Patch?

Notwithstanding the excess injection over the summer due to unrealized demand and a burst of drilling, the storage season ended last week with only about 39 days of supply. In fact, normalized storage stands now at the beginning of withdrawal season lower than three previous years (2016, 2012, 2006) at the end of storage season.

Gas rig count has now fallen 35% from last January to stand at 129, and the laying-down has accelerated in the last two months. Meanwhile, the steep initial declines of shale wells mean that each month the industry must bring on about 2.8 Bcf/d of new (wet) gas supply just to maintain current production. By comparison, the Barnett Shale peaked at 5.2 Bcf/d, and Range Resources produces 2.2 Bcf/d.

Major export and industrial projects guarantee demand growth. Six months of declining drilling have locked in supply contraction, and the storage buffer lies near its all time low. Since neither Permian flaring nor drilled-uncompleted wells wait below the stage as deus ex machina, supply and demand are left to play out the drama on their own.

By Dwayne Purvis for

Wednesday, November 20, 2019

As Oil Prices Drop And Money Dries Up, Is The U.S. Shale Boom Going Bust?

Oil prices are down amid weak demand, and investors no longer seem willing to write the industry a blank check.
Spencer Platt/Getty Images

The shale oil boom that catapulted the U.S. into being the world's largest oil producer may be going bust. Oil prices are dropping amid weakening demand, bankruptcies and layoffs are up, and drilling is down — signs of a crisis that's quietly roiling the industry.

Some of the most successful companies in the oil business are household names — think Exxon Mobil or Chevron. But the boom in shale drilling has been driven by smaller, independent operators. These companies have pushed the limits of drilling technology and taken big risks on unproven oil fields.

Today, shale accounts for about two-thirds of U.S. oil production and nearly all of the industry's growth, but many of the companies that made that growth possible are now struggling to stay afloat.

That has a lot to do with the business model of U.S. shale, says David Deckelbaum, an analyst at investment bank Cowen. "This is an industry that for every dollar that they brought in, they would spend two," he says.

For years operators focused on drilling lots of new wells very fast, prioritizing explosive growth over profitability. Until now they've been able to rely on deep-pocketed investors who were willing to pour fresh capital into the industry, despite years of lackluster returns.

It's a story that may be familiar to anyone who's been following the tech industry in recent years. Deckelbaum compares it to a kind of a prospector mentality.

"There's always this idea of this brand new play that's going to have billions of barrels of upside and if you can just get in early, then it'll pay off in the long run," he says.

Oil has always been a boom-and-bust industry. In 2014, for instance, a catastrophic price crash left the industry reeling. But even then, billions in new investment flowed into U.S. shale.
Today, shrinking global demand for oil is driving the price down once again. What's different this time around? Investors no longer seem willing to write the industry a blank check.
"I think now you've seen a lot of pressure of, 'We want you to be a real business. Your cost structure's too high, you have too much debt, I'm not funding your drilling anymore with external capital. You have to live within your own means,' " Deckelbaum says.
Without access to new cash, many producers are pulling back on exploration. The number of rigs drilling for new oil is at its lowest point in two years.
That's bad news for people like Ron Fountain, who works on a drilling rig in the Bakken shale of North Dakota. He thinks back to a few years ago, when the price of oil was more than $100 a barrel and companies were drilling with abandon.
"That's when we were still booming," Fountain says. "There was rigs coming out every month. We couldn't keep up, there was so much work going on."

Today though, with more and more rigs sitting idle, life has become uncertain for Fountain and his fellow drillers.

"We went from having three-year contracts to well-to-well contracts, which means you drill one hole and if you did a good job, then they'll give you another. Or they drop you and you gotta figure it out from there," Fountain says.

He's not the only one feeling the pinch. Halliburton, one of the biggest players in U.S. shale drilling, has laid off nearly 3,000 workers. In the Permian Basin, the country's most prolific oil field, employment has almost completely stalled out — after growing more than 11% last year.

Meanwhile, many of the smaller producers who piled up debt are struggling to pay it back. That has led to a wave of bankruptcies — nearly three dozen so far this year.

All of this is adding up to slower oil output. Production was flat in the first half of 2019, after growing more than 20% last year, according to Department of Energy data. In theory, as production slows and supply shrinks, the price of oil should go back up, which could provide a much-needed boost. The question, Fountain says, is how many companies will be able to survive until then.

"I think as an industry we're going to be OK," he says. "But I think there's a lot of people that are kinda holding their breath."

Tuesday, November 19, 2019

OPEC's share of Indian oil imports in October hits lowest since 2011

A boy walks past an oil tanker train stationed at a railway station in Ghaziabad

OPEC's share of India's oil imports fell to 73% in October, its lowest monthly share since at least 2011, tanker data from sources showed, as refiners shipped in fuel from the United States and other suppliers.

India, which usually imports about 80% of its needs from members of the Organization of the Petroleum Exporting Countries (OPEC), has been diversifying its sources of oil as local refiners have upgraded plants to process cheaper crude grades.

India, the world's third-biggest oil importer, shipped in 4.56 million barrels per day (bpd) of oil in October, about 3.3% less compared with a year ago, data showed. Of that, it bought 3.43 million bpd from OPEC.

OPEC's share of India's imports in September was about 81% although total volumes were lower, as the South Asian nation cut imports to a three-year low due to maintenance at some refineries.

OPEC oil output dipped to an eight-year low in September after attacks on Saudi oil plants led to production cuts, a Reuters survey showed. The kingdom's output has since recovered.

In October, Iraq replaced Saudi Arabia as India's top oil supplier, tanker arrival data showed, with refiners cutting purchases of the more expensive Saudi oil.

Sources who supplied the data asked not to be named.

"Saudi had raised its official selling price (OSP). That led to some buyers migrating to Iraqi and other producers," said Ehsan Ul Haq, an analyst with Refinitiv.

Saudi Arabia raised its October OSP for its Arab Light grade for Asia by $0.60/barrel compared to a $0.35/barrel increase in Iraq's Basra Light.

To make up for lower Saudi purchases, India also boosted purchases from Nigeria, its third-biggest supplier in October, as well as from Kuwait and Mexico.

India shipped in a record 336,000 bpd of U.S. oil in October, about 7.5% of total imports, as private refiner Reliance Industries bought three tanker cargoes, data showed. The United States was Indian's fourth-biggest supplier in October.

"Indian demand for gasoil has been falling but overall Asian demand has been relatively strong because of new marine fuel rules from January. And good diesel cracks is prompting refiners to buy distillate rich crudes like that of Nigeria," Haq said.

Refining margins or cracks for 10 ppm gasoil traded at $15.46 per barrel over Dubai crude during Asian trade on Monday. Cash premiums for the fuel climbed to 34 cents per barrel to Singapore quotes, compared with 31 cents per barrel on Friday.

India's fuel demand in October declined by 1.4% from a year earlier, and its diesel consumption fell by the steepest in about three years, government data showed on Thursday.

(Reporting by Nidhi Verma; Editing by Edmund Blair and Tom Hogue)

Monday, November 18, 2019

Saudi Aramco gives nine banks top roles on world's biggest IPO: sources

GP: Jamie Dimon, chairman, president and chief executive officer of JPMorgan Chase & Co WEF
Jamie Dimon, chief executive officer of JPMorgan Chase & Co.
Jason Alden | Bloomberg | Getty Images

DUBAI (Reuters) - Saudi Aramco has hired nine banks as joint global coordinators to lead its planned initial public offering (IPO), slated to be the world’s largest, two sources familiar with the matter told Reuters on Wednesday. 

The mandates have been heavily sought by the world’s biggest investment banks for a transaction which, according to Saudi Crown Prince Mohammed bin Salman’s initial plans, could generate around $100 billion for Saudi Arabia’s state coffers. 

The kingdom plans to list 1% of the state oil giant - the world’s largest oil company - on the Riyadh stock exchange before the end of this year and another 1% in 2020, sources told Reuters this week, as initial steps ahead of a public sale of around 5% of Aramco. 

Aramco has selected JPMorgan Chase & Co (JPM.N), Morgan Stanley (MS.N) and Saudi Arabia’s National Commercial Bank (1180.SE), which were previously working on the share sale before it was paused last year, the sources said, declining to be identified due to commercial sensitivities. 

It has also chosen Bank of America Merrill Lynch (BAC.N), Goldman Sachs Group Inc (GS.N), Credit Suisse Group AG (CSGN.S), Citigroup Inc (C.N), HSBC Holdings PLC (HSBA.L) and Saudi Arabia’s Samba Financial Group (1090.SE), they added. 

To secure the lead role on the IPO, JPMorgan’s efforts were led by senior bankers in New York, London and Saudi Arabia who had long-standing relationships in Saudi Arabia, rather than Chief Executive Jamie Dimon, according to a person familiar with the matter. 

Aramco, JPMorgan, Bank of America, Citi, Credit Suisse, Goldman Sachs and HSBC declined to comment. The remaining banks did not immediately respond to requests for comment. 

The IPO plan has rapidly gained momentum in recent days with the appointment of the head of the kingdom’s PIF sovereign wealth fund, Yasser al-Rumayyan, as Aramco’s new chairman. 

Rumayyan, a close ally of Prince Mohammed, took over from former energy minister Khalid al-Falih in a move to separate Aramco from the ministry, a step Saudi officials have said was important to pave the way for the IPO. 

Bankers have been courting Saudi Arabia to secure roles in the transaction, which has faced repeated delays, but which officials have said will happen by 2020-2021. 

Aramco’s chief executive, Amin Nasser, said this week that the domestic IPO would be the “primary” listing but that the company was also ready for an international share sale. He said the final decision on venue and timing rested with the government. 

The flotation is crucial for Prince Mohammed’s plans to diversify the Saudi economy in an era of low oil prices. 

Based on the indicated $2 trillion valuation that Saudi Aramco had hoped to achieve, a 1% float would be worth $20 billion, a huge milestone for the local stock market. 

FILE PHOTO: Logo of Saudi Aramco is seen at the 20th Middle East Oil & Gas Show and Conference (MOES 2017) in Manama, Bahrain, March 7, 2017. REUTERS/Hamad I Mohammed/File Photo
Analysts and bankers, however, have said $1.5 trillion is a more achievable valuation for Aramco.
Aramco raised $12 billion this year in its first international bond, gaining more than $100 billion in demand, in a deal that many saw as a pre-IPO relationship-building exercise with international investors. 

Reporting by Hadeel Al Sayegh and Davide Barbuscia; Additional reporting by Joshua Franklin in New York; Editing by Ghaida Ghantous and Marguerita Choy

Morgan Stanley Values Saudi Aramco at $1trn

Saudi Aramco has been given a $1trn valuation by Morgan Stanley, as Wall Street is still divided on how much the world’s biggest oil company is actually worth.

Aramco has been given a valuation range spanning hundreds of billions of dollars, according to research from two Wall Street banks that underlines the dilemma facing lenders working on what is expected to be the world’s largest initial public offering.

In a presentation for investors, Morgan Stanley bankers ran through several valuation models that gave a spread of about $1trn between the most bearish and bullish scenarios. For example, based on a dividend discount model the spread ran from $1.06trn up to $2trn.

The base case was $1.52trn, according to the presentation seen by Aramco faces a delicate balance as it seeks to push its IPO valuation as close as possible to Crown Prince Mohammed Bin Salman’s $2trn — a figure that’s been met with skepticism from many professional investors — while making sure it’s attractive to potential Saudi buyers.

Among 16 banks that offered a valuation, the range in estimates ran from $1.1trn at the bottom right up to $2.5trn, a nuber that even the crown prince might find optimistic. The midpoint was $1.75trn, according to people who’ve reviewed all the research.

Friday, November 15, 2019

Safety in Polar waters addressed

Arctic Aframax Tanker is a joint development by Deltamarin and Aker Arctic Technology. Image courtesy of Aker Arctic.

New joint guidelines for Polar waters operation have been released by the ICS and OCIMF. 
Maritime trade between Arctic destinations and the rest of the world is expected to expand and an increasing number of ships are now undertaking voyages in Polar waters.
Technical developments in ship design and equipment continue to facilitate more and more ship operations in remote Polar areas, despite challenging and unpredictable sea and weather conditions.
The Polar Code, adopted by the IMO, requires shipping companies intending to operate in Polar waters to develop a Polar Water Operational Manual (PWOM) in order for their ships to be issued with a Polar Ship Certificate.
New joint guidelines from the International Chamber of Shipping (ICS) and the Oil Companies International Marine Forum (OCIMF) were aimed at supporting shipping companies by providing advice on how to develop a PWOM that best suits their needs.
Appendix II of the IMO Polar Code already provides a model PWOM. However, the ICS and OCIMF recognised that additional guidance is necessary to help shipping companies to develop a quality PWOM that is truly fit for purpose.
The new Guidelines purpose is to provide the means for shipping companies and Masters to develop a comprehensive PWOM tailored to the needs of their individual ships, taking into account the environmental hazards and the nature of their operations.
’Guidelines for the Development of a Polar Water Operational Manual’ has been prepared by expert contributors with in-depth experience of operating ships in Polar waters, as well as knowledge of the challenges faced by seafarers on board.
Topics addressed include: identifying hazards; understanding operational limitations; updating procedures; upgrading equipment and systems; understanding relevant legislation and ensuring that the results of assessments are fully addressed in the PWOM.

Wednesday, November 13, 2019

Aramco’s Breakeven Costs Are The Lowest In The World


Aramco has the lowest production costs for oil projects in the world, the company said in its newly released IPO prospectus, adding that partner producers such as Russia, Venezuela, and Nigeria had much higher production costs.

The Saudi state company said its after-tax breakeven costs for producing fields were below $10 per barrel, compared with just over $20 per barrel for the UAE, more than $40 per barrel for Russia, and almost $50 per barrel for Nigeria.
Low production costs are one of the main reasons Aramco is considered an attractive investment opportunity for energy investors, along with its massive reserves.

However, there have been several factors that may discourage international investors from betting on the Saudi giant, including the intensifying climate change fight that many worry will affect oil demand negatively as well as the risk of outages after the September attacks on Saudi oil infrastructure that took off the market some 5.7 million bpd in production capacity.

Aramco released its IPO prospectus earlier this week but the 658-page document did not address some important questions such as the exact day of the float, the number of stock to be offered—though it said it will constitute 0.5 percent of Aramco’s total shares—and the price per share. 

There is also the issue with supervolatile oil prices that have some wondering how close Riyadh could get to its desired $2-trillion valuation for the company. Now, some analysts are also warning investors to consider the overwhelming influence of the Saudi royal family over the business of Aramco.
“The biggest issue with Aramco is that everything about this company is controlled by the Saudi royal family — shareholder opinions, your board votes, none of that makes any difference,” Pavel Molchanov from Raymond James told CNBC.

“There’s a lot to think about when buying Aramco,” State Street senior global multi-asset strategist Daniel Gerard said, adding the focus should be on “how much political influence would there be over the investment decisions.”

By Irina Slav for

Tuesday, November 12, 2019

Oxy to Sell Permian Campus After Anadarko Acquisition

(Bloomberg) -- Occidental Petroleum Corp. plans to sell a four-story office building in the heart of the Permian Basin and move employees into a nearby one owned by Anadarko Petroleum Corp., the oil producer it bought for $37 billion three months ago.

The 213,000 square-foot complex will be vacated by April 2020 and is a “compelling” investment opportunity, according to a marketing document from CBRE Group Inc., the real-estate broker handling the sale alongside Midland-based Moriah Real Estate Co.

The property was built in 2014 and is located in Westridge Park on the west side of Midland, near the airport. It’s also close to Anadarko’s campus and directly opposite Chevron, which Occidental outbid to acquire Anadarko. EOG Resources Inc. also has an office nearby.

“We have told our employees in Midland that they will be moving into the state-of-the-art building that Anadarko began constructing prior to the acquisition,” Melissa Schoeb, a spokeswoman for Occidental, said by email. “The building is large enough to house our combined workforce and we will begin the move when it’s ready for occupancy.”

Occidental is under pressure to sell assets and pay down debt after the acquisition, which has been criticized by investors including billionaire activist Carl Icahn. The stock plunged this week after Chief Executive Officer Vicki Hollub slashed 2020 capital spending by 40%, raising concern that the company won’t pump enough oil to cover dividend payouts and debt service.

To contact the reporter on this story:
Kevin Crowley in Houston at
To contact the editors responsible for this story:
Simon Casey at
Mike Jeffers

Repsol Looks to Alberta to Replace Mexican and Venezuelan Oil

(Bloomberg) -- Repsol SA is looking as far away as Western Canada for oil for its European refineries amid dwindling supplies from Mexico and Venezuela.

The Spanish oil company is considering using rail to transport as much as half-a-million barrels of heavy crude a month 1,911 miles (3,075 kilometers) from Alberta to Montreal before loading it onto tankers bound for Europe, according to people familiar with the situation. The company has also considered shipping the crude to New Jersey for shipment to Europe.

The European company has typically sourced heavy crude supplies from Latin America, particularly Mexico and Venezuela. But U.S. sanctions, as well as civil strife, have crippled Venezuela’s oil production, which has fallen to less than 700,000 barrels a day from more than 2 million four years ago. Mexico’s oil production has fallen for 14 straight years to 1.83 million barrels a day in 2018. That’s left Repsol looking for alternatives.

Repsol declined to comment in an email.

Repsol’s European refineries hold about 25% of the continent’s coking capacity, according to the company. Coking units allow refineries to process heavier crude, which is typically cheaper than lighter oil, into high-value fuels such as gasoline and diesel.

Alberta’s landlocked status means it ships nearly all of its crude oil to the U.S. by pipeline or rail. The Trans Mountain pipeline to the Pacific Coast allows a tiny fraction to be shipped to Asia. The long distance to market has kept Canadian heavy crude selling for less than West Texas Intermediate futures. The discount was more than $20 a barrel on Monday.

Shipments of oil sands crude to Europe are rare. Repsol occasionally gets heavy Canadian crude via U.S. Gulf ports, where Canadian oil competes with U.S. crude for sea berths and space on pipelines.

About 400,000 barrels of Alberta crude were sent to the U.K. last year, the first significant shipment to Europe since 2014, when a tanker of Alberta crude left a terminal near Montreal for shipment to Italy, according to the Canadian International Merchandise Trade database.

Repsol produces conventional heavy crude in west-central Alberta at its Chauvin field.

To contact the reporters on this story: Robert Tuttle in Calgary at;Lucia Kassai in Houston at;Rodrigo Orihuela in Madrid at

To contact the editors responsible for this story: David Marino at, Mike Jeffers, Kevin Orland

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