Post Tagged with: "Exports"

Source: Cameron LNG Media Kit

LNG Takes up 7 Percent U.S. Gas Production in July

From The Houston Chronicle


U.S. LNG exports have expanded to the point they made up 7 percent of total U.S. natural gas production in July, the Energy Information Administration reported Monday.

Last month gas deliveries to LNG export facilities reached 6 billion cubic feet a day, as new export facilities come online along the Gulf Coast.

“In the first half of 2019, two new liquefaction trains came online: Cameron LNG Train 1 in Louisiana in May and Corpus Christi LNG Train 2 in Texas in June,” the report read. “Two new LNG export facilities—Elba Island LNG in Georgia and Freeport LNG in Texas—plan to place their first trains in service in the next two months.”

 

 

Since 2017 the United States has exported more gas than it consumes, both delivering liquefied gas via tanker overseas and through pipelines to Mexico and Canada.

Over the first seven months of this year, gas exports through LNG and to Mexico averaged 10 billion cubic feet a day, a 30 percent increase from last year.

August 19, 2019 - 6:03 am Closing Bell Story, Energy News, LNG, Natural Gas News, Trade
OPEC keeps curbs - Saudi Arabia Minister of Energy Khalid Al-Falih - Oil & Gas 360

Saudis to Limit Oil Exports in September to Stabilize Market

From The Houston Chronicle


Saudi Arabia plans to keep oil exports below 7 million barrels a day next month as OPEC’s biggest producer allocates less crude than customers demand in a bid to stabilize the market, according to the kingdom’s officials.

State-run Saudi Arabian Oil Co., known as Aramco, will cut customer allocations across all regions by a total of 700,000 barrels a day next month, the officials said, asking not to be identified because the information isn’t public. The country’s production will be lower in September than in this month, they said.

For North American customers, the kingdom will send about 300,000 barrels a day less than they nominated for oil scheduled to load in September, according to a person familiar with the matter. Reductions to European buyers will be larger, said the person, who is familiar with Saudi policy. There will also be modest cuts to Asian buyers.

Saudi Arabia is reducing allocations despite strong consumption in all regions, the officials said. While the kingdom could have produced about 10.3 million barrels a day because demand is much higher, it decided to keep output and exports suppressed, they said. The producer and its partners in the OPEC+ coalition are determined to do what they can for market stability, they said.

Global benchmark Brent crude rose as much as 3.2% to $58.01 on Thursday. Prices are still down about 12% over the past week.

 

 

 

Market meltdown

Saudi Arabia, the world’s largest oil exporter, has already cut production more than required under an agreement between the Organization of Petroleum Exporting Countries and allies outside of the group to help drain inventories and reach market stability. Oil has been swept up in a global market meltdown as the U.S.-China trade dispute worsened, spurring fears it would morph into a currency war.

Prices recovered some of their losses after a Saudi official said the kingdom won’t tolerate a further sell-off and has phoned other producers to discuss a response. Still, a cooling global economy and the U.S-China trade dispute are putting a brake on fuel demand, so even if global producers decide to cut output further, they may struggle to revive prices.

China Continued Iran Oil Imports in July in Teeth of U.S. Sanctions: Analysts

China Continued Iran Oil Imports in July in Teeth of U.S. Sanctions: Analysts

From Reuters


China imported Iranian crude oil in July for the second month since a U.S. sanctions waiver ended, according to research from three data firms, with one estimate showing some oil entered tanks holding the country’s strategic reserves.

According to the firms, which track tanker movements, between 4.4 million and 11 million barrels of Iranian crude were discharged into China last month, or 142,000 to 360,000 barrels per day (bpd). The upper end of that range would mean July imports still added up to close to half of their year-earlier level despite sanctions.

The imports are continuing at a precarious moment in U.S.-China relations: The flow is hampering U.S. President Donald Trump’s efforts to choke off oil exports vital to Iran through sanctions, just as tensions rise in the festering U.S.-China trade dispute that has cast a pall over the global economy.

Senior Trump administration officials estimate that 50-70% of Iran’s oil exports are flowing to China, while roughly 30% go to Syria.

China is typically Iran’s largest oil customer and contests Washington’s sanctions. But June imports of around 210,000 bpd were the lowest in nearly a decade and 60% below their year-ago level, according to customs data, as some Chinese refiners, concerned about the sanctions, refrained from dealing with Iran.

The General Administration of Chinese Customs is scheduled to release details of July imports by origin in the last week of August.

Neither the National Development & Reform Commission, the state planner that oversees the country’s state oil reserves, nor the national customs bureau responded to Reuters’ requests for comment.

 

Jinzhou reserves doubled

Similar to June imports, it’s unclear how much of the July shipments has been sold to buyers or stored in bonded storage tanks and yet to clear customs. Some 20 million barrels of Iranian oil appeared stranded at the northeastern port of Dalian after moved into bonded tanks since late last year.

While the customs department does not disclose details of port entries, oil analytics firms track where tankers arrive.

According to research by data provider Refinitiv, July saw five vessels operated by the National Iranian Tanker Company (NITC) discharge 958,000 tonnes of Iranian crude into Chinese port Jinzhou in the northeast, Huizhou in the south and Tianjin in the north.

NITC didn’t immediately respond to a request for comment.

Jinzhou, Tianjin and Huizhou are locations for refineries and commercial storage owned by Chinese state oil firms China Petrochemical Corp (Sinopec Group) and China National Petroleum Company (CNPC). Some of the country’s tanks holding Strategic Petroleum Reserves (SPR) – kept by many countries as stockpiles for emergency situations – are also located in these cities.

Asked if it was among buyers of Iranian oil, Sinopec declined comment. CNPC did not respond to a request for comment.

In a report dated July 29, London-based energy data firm Kpler said inventories at the Jinzhou underground SPR rose to 6 million barrels from 3.2 million in mid-June “as a result of Iranian crude flows…The increase is fully the result of Iranian barrels discharged into the facility.”

The firm estimated 360,000 bpd of Iranian crude had been delivered to China last month.

Vortexa, another London-based energy market intelligence firm, pegged the July deliveries into China at 4.4 million barrels and identified similar port destinations.

 

 

 

‘Destabilizing activities’

Asked if U.S. sanctions apply in the case of Beijing storing Iranian oil in SPR facilities, a State Department official told Reuters Washington does not preview sanctions activities as it seeks to force Tehran to accept stricter limits on its nuclear activity and policy in the Gulf.

“But we will continue to look for ways to impose costs on Iran in an effort to convince the Iranian regime that its campaign of destabilizing activities will entail significant costs,” said the spokesman.

In July, Washington sanctioned state-run Chinese oil trader Zhuhai Zhenrong Co for allegedly violating restrictions imposed on Iran’s oil sector.

Elizabeth Rosenberg, an expert on sanctions with Center for a New American Security, a Washington-based think-tank, said if oil changes hands and even if it is then put in storage, the buyer would then be violating sanctions.

China has repeatedly criticized the unilateral U.S. sanctions on Iran and opposed Washington’s “long-arm” jurisdictions.

“Strictly speaking, from the perspective of international law, China or other countries don’t have an obligation to obey unilateral sanctions from the U.S.,” said Zha Daojiong, Peking University professor of International Political Economy.

Oil Falls 3% as Trade War Concerns Hit Demand Outlook

Oil Falls 3% as Trade War Concerns Hit Demand Outlook

From Reuters


Global oil benchmark Brent futures fell more than 3% on Monday on global growth concerns after U.S. President Donald Trump last week threatened China with more tariffs, which could limit crude demand from the world’s two biggest buyers.

Brent crude LCOc1 fell $2.08, or 3.36%, to settle at $59.81 a barrel.

U.S. West Texas Intermediate (WTI) crude CLc1 futures fell 97 cents, or 1.74%, to settle at $54.69 a barrel, finding some support from a draw in inventories at the Cushing, Oklahoma, storage hub and delivery hub for WTI.

Stocks at Cushing fell nearly 2.4 million barrels in the week to Aug. 2, traders said, citing data from market intelligence firm Genscape. WTI’s discount to Brent WTCLc1-LCOc1 narrowed to $5.15 a barrel, its narrowest since July 2018.

Both crude benchmarks plummeted by more than 7% last Thursday to their lowest level in about seven weeks after Trump’s announcement, before recovering somewhat to leave Brent down 2.5% on the week and U.S. crude 1% lower.

Trade war worries hit global equities again on Monday, while stoking a rally in safe-haven assets including the Japanese yen, core government bonds and gold.

“While latest trade headlines will be forcing downward adjustment in global oil demand expectations for this year and possibly next, it is looking quite likely that Asia will bear the brunt of the expected slowing in oil demand growth,” Jim Ritterbusch of Ritterbusch and Associates said in a note.

Trump last week said he would impose a 10% tariff on $300 billion of Chinese imports starting on Sept. 1 and said he could raise duties further if China’s President Xi Jinping failed to move more quickly toward a trade deal.

The announcement extends U.S. tariffs to nearly all imported Chinese products. China on Friday vowed to fight back against Trump’s decision, a move that ended a month-long trade truce.

 

 

On Monday, China let the yuan tumble beyond the 7-per-dollar level for the first time in more than a decade.

A lower yuan raises the cost of dollar-denominated oil imports in China, the world’s biggest crude oil importer.

Signs of rising oil exports from the United States also pressured prices on Monday. U.S. shipments surged by 260,000 barrels per day (bpd) in June to a monthly record of 3.16 million bpd, U.S. Census Bureau data showed on Friday.

Lending some support to prices, Iran’s seizure of an Iraqi oil tanker raised concerns about potential Middle East supply disruptions in the Gulf.

Iran will no longer tolerate “maritime offences” in the Strait of Hormuz, its foreign minister said on Monday.

Oil Prices Could Crash by $30 if China Buys Iranian Crude: BofA

Oil Prices Could Crash by $30 if China Buys Iranian Crude: BofA

From CNBC


Crude oil prices could sink by as much as $30 a barrel if China decides to buy Iranian crude oil in retaliation to the latest U.S. tariff measures, according to Bank of America Merrill Lynch.

“While we retain our $60 a barrel Brent forecast for next year, we admit that a Chinese decision to reinitiate Iran crude purchases could send oil prices into a tailspin,” a BofA Merrill Lynch Global Research report said Friday, warning that prices could sink by as much as $20-30 a barrel in that scenario.

The Chinese Ministry of Commerce has threatened countermeasures after President Donald Trump threatened to slap a 10% tariff on $300 billion dollars of Chinese goods. The decision Thursday floored oil markets and sent crude plunging 8% — the most in four years.

Analysts warn that “oil volatility is set to rise again” as markets wait for a Chinese response to the latest US tariff threat, which could include purchasing Iranian oil.

“This decision would both undermine US foreign policy and cushion the negative terms-of-trade effects on the Chinese economy of rising US tariffs,” the report added.

 

Iranian oil exports slide

Shipments of Iranian oil fell below 550,000 b/d (barrels per day) in June from about 875,000 b/d in May and about 2.5 million b/d in June 2018, according to data from S&P Global Platts. Roughly half of Iran’s exports were shipped to China in June and July, according to the firm.

But a Chinese decision to purchase Iranian oil in a further defiance of U.S. sanctions could act as a double edged sword, according to other analysts.

“Iran would welcome any opportunity to increase its production whether or not it breaches the terms of the U.S. sanctions, but the strategy there would introduce China to a partner over which it doesn’t have an enormous amount of control,” Edward Bell, Director of Commodities Research at Emirates NBD told CNBC’s “Capital Connection.”

“Don’t forget there are other producers that would also be targeting that trade with China, so for instance you could see Iraq or Saudi Arabia step in and try and discount the volumes that they would be exporting to China as a way to circumvent Iran getting that extra market share,” he added.

 

 

 

Traders fret on crude demand

Crude oil prices slumped further on Monday, as traders focused on a deteriorating demand outlook.

Analysts at BofA Merrill Lynch said the latest round of US tariffs could reduce global oil demand by 250,000-500,000 barrels per day, adding to worries about a demand slowdown that is challenging the fundamentals for crude.

“The kind of deterioration in global trade volumes that we’ve seen this year does mathematically lead into lower demand for crude oil,” Bell added.

“If that carries on through the end of 2019 or perhaps even 2020 as we enter the firm end of the US election cycle when Trump is likely to want to maintain that hard stance on China, then it could be a very difficult barrier for crude to try and break through some of those demand concerns.”

Brent crude was trading at $60.94 early Monday, down around 1.5%, while WTI traded at $54.81, again slipping around 1.5% for the session.

Oil prices turned firmly lower during midday trading on Tuesday. Crude futures were little changed earlier in the session, depressed by a report of record Saudi production but supported by expectations that oil exporters would agree to cut output at an OPEC meeting next week. Oil & Gas 360

EIA: Saudi Arabia Has Been Exporting More Crude Oil to China, Less to the United States

From the EIA


EIA: Saudi Arabia Has Been Exporting More Crude Oil to China, Less to the United States - Oil & Gas 360

Source: EIA

Saudi Arabia’s crude oil production approached a four-year low in May 2019, averaging an estimated 9.9 million barrels per day (b/d), more than 1 million b/d lower than its all-time high in November 2018. Production in Saudi Arabia dropped following a December 2018 agreement by members of the Organization of the Petroleum Exporting Countries (OPEC) to cut crude oil production. Saudi Arabia’s crude oil exports, especially to the United States, have also fallen. However, some countries—in particular, China—have increased their imports of crude oil from Saudi Arabia.

Four Asia-Pacific countries that publish crude oil imports by country of origin—China, Japan, South Korea, and Taiwan—collectively imported an average of 3.5 million b/d of crude oil from Saudi Arabia in 2018. China’s, Japan’s, and Taiwan’s 2019 year-to-date crude oil imports from Saudi Arabia are larger than their 2018 annual averages, but South Korea’s have declined slightly, based on data through May 2019.

In contrast, U.S. crude oil imports from Saudi Arabia have declined year-to-date through April 2019 compared with the 2018 average by more than 0.2 million b/d, averaging 0.6 million b/d for the first four months of 2019. Weekly estimates through July 12 show continued declines, indicating that U.S. crude oil imports from Saudi Arabia averaged about 0.5 million b/d in May and in June.

EIA: Saudi Arabia Has Been Exporting More Crude Oil to China, Less to the United States - Oil & Gas 360

Source: EIA

These recent changes in crude oil trade patterns are partially a result of long-term structural trends within China and the United States and partially a result of recent oil market dynamics. From 2010 through 2018, EIA estimates that total Chinese petroleum consumption increased from 9.3 million b/d to 13.9 million b/d and that Chinese domestic production increased from 4.6 million b/d to 4.8 million b/d. As a result, China’s need to meet incremental oil consumption has been met primarily by imports.

China’s crude oil imports from Saudi Arabia have gradually increased in recent years, and in March 2019, reached 1.7 million b/d, the highest level for any month since at least 2004. Other countries, including Russia and Brazil, have been exporting more crude oil to China, however, and Russia surpassed Saudi Arabia as China’s largest source of crude oil on an annual average basis in 2016.

U.S. crude oil imports, on the other hand, have steadily decreased as domestic crude oil production has increased. In addition, U.S. crude oil imports from OPEC members have declined following increases from other countries, especially Canada. Canadian crude oil can be a substitute for certain OPEC grades and can have lower transportation costs when shipped by available pipeline capacity.

 

 

Saudi Arabian crude oil exports to China increased recently, in part, because of the start-up of a new 0.4 million b/d refinery in Dalian, Liaoning Province, which has a supply agreement with Saudi Aramco, Saudi Arabia’s national oil company. Saudi Aramco also has a supply agreement with a 0.4 million b/d refining and petrochemical complex in Zhejiang Province, which started trial operations this year.

Recent global oil supply issues could keep Saudi Arabian crude oil exports to China, Japan, South Korea, and Taiwan relatively high in the coming months. These four jurisdictions were all initially granted significant reduction exceptions (SREs) for Iranian crude oil imports through May 2019. However, because SREs were not renewed, each country will likely need an alternative to Iranian crude oil.

As a partial substitute for Iranian barrels, crude oil imports to these countries from Saudi Arabia could stay near first-quarter 2019 levels for the coming months. Saudi Arabia’s support of maintaining current OPEC production cuts through March 2020, however, will likely reduce the Saudi Arabian crude oil available for export.

In addition, Saudi Arabia’s seasonal increase in domestic crude oil consumption for power generation could reduce available crude oil export volumes this summer. The increase is dependent on the weather, but higher domestic consumption could be a more significant factor in determining the level of Saudi Arabian crude oil exports in the coming months.

Principal contributor: Jeff Barron

U.S. Sanctions China’s State-Run Oil Company for Buying from Iran

U.S. Sanctions China’s State-Run Oil Company for Buying from Iran

By Tyler Losier, Energy Reporter, Oil & Gas 360

Secretary of State Mike Pompeo announces sanctions for Zhuhai Zhenrong and its chief executive
The United States government will be imposing sanctions on Zhuhai Zhenrong Company Limited, a state-run oil company in China, and its chief executive for purchasing crude oil from Iran.

On Monday, Secretary of State Mike Pompeo announced in a speech at the Veterans of Foreign Wars convention that Zhuhai Zhenrong and its top executive, Youmin Li, will be blocked from banking or completing property transactions in the U.S. for knowingly making “significant” purchases of Iranian crude on May 2. Li will also be barred from entering the U.S.

“They violated U.S. law,” Pompeo told the crow...

Millions of Barrels of Iranian Oil Are Piled Up in China’s Ports

Millions of Barrels of Iranian Oil Are Piled Up in China’s Ports

From Bloomberg


Iran-owned tankers continue to haul shipments to bonded tanks, oil held by Iran’s state-owned producer and Chinese companies

Tankers are offloading millions of barrels of Iranian oil into storage tanks at Chinese ports, creating a hoard of crude sitting on the doorstep of the world’s biggest buyer.

Two and a half months after the White House banned the purchase of Iran’s oil, the nation’s crude is continuing to be sent to China where it’s being put into what’s known as “bonded storage,” say people familiar with operations at several Chinese ports. This supply doesn’t cross local customs or show up in the nation’s import data, and isn’t necessarily in breach of sanctions. While it remains out of circulation for now, its presence is looming over the market.

The store of oil has the potential to push down global prices if Chinese refiners decide to draw on it, even as the Organization of Petroleum Exporting Countries and allies curb production as growth slows in major economies. It also allows Iran to keep pumping and move oil nearer to potential buyers.

“Iranian oil shipments have been flowing into Chinese bonded storage for some months now, and continue to do so despite increased scrutiny,” said Rachel Yew, an analyst at industry consultant FGE in Singapore. “We can see why the producer would want to do so, as a build-up of supplies near key buyers is clearly beneficial for a seller, especially if sanctions are eased at some point.”

There could be more of the Persian Gulf state’s oil headed for China’s bonded storage tanks, Bloomberg tanker-tracking data show. At least ten very large crude carriers and two smaller vessels owned by the state-run National Iranian Oil Co. and its shipping arm are currently sailing toward the Asian nation or idling off its coast. They have a combined carrying capacity of over 20 million barrels.

The bulk of Iranian oil in China’s bonded tanks is still owned by Tehran and therefore not in breach of sanctions, according to the people. The oil hasn’t crossed Chinese customs so it’s theoretically in transit.

Some of the crude, though, is owned by Chinese entities that may have received it as part of oil-for-investment schemes. For example, one of the Asian nation’s companies could have helped fund a production project in Iran under an agreement to be repaid in kind. Whether this sort of transaction is in breach of sanctions isn’t clear, and so the firms are keeping it in bonded storage to avoid the official scrutiny it would if it’s registered with customs, according to the people.

Nobody replied to a faxed inquiry to China’s General Administration of Customs.

 

Lack of Clarity

The build-up of Iranian oil in Chinese bonded storage has yet to be clearly addressed by Washington. The White House ended waivers allowing some countries to keep importing Iranian oil on May 2.

There are currently no exemptions issued to any country for the import of Iranian oil, and any nation seen importing cargoes from the Persian Gulf producer will be in breach of sanctions, according to a senior Trump administration official, who asked not to be identified because he wasn’t authorized to speak publicly about the matter.

“The U.S. will now need to define how it quantifies the infringement of sanctions,” said Michal Meidan, director of the China Energy Programme at the Oxford Institute for Energy Studies. There’s a lack of clarity on whether it would look at “financial transactions or the loading and discharge of cargoes by company or entity,” she said.

China received about 12 million tons of Iranian crude from January through May, according to ship-tracking data, versus about 10 million that cleared customs over the period. The discrepancy could be due to the flow of oil into bonded storage. China will release June trade data that will include a country-by-country breakdown of oil imports in the coming days.

 

 

One of the Iranian tankers that appears to have loaded oil after the U.S. waivers ended is VLCC Horse. It discharged at Tianjin in early-July after sailing from the Middle East, where shipping data showed it signaling its destination as Iran’s Kharg Island on May 4.

Several other Iran-owned tankers offloaded in China or were heading there, according to ship tracking data. VLCC Stream discharged at Tianjin on June 19, while Amber, Salina and C. Infinity offloaded crude at the ports of Huangdao, Jinzhou and Ningbo. Snow, Sevin and Maria III were last seen sailing in the direction of China.

Putting crude into bonded tanks in China also means Iran can avoid having to tie up part of its tanker fleet by storing the oil at sea for months at a time. The Islamic Republic used floating storage in 2012 to 2016 and again in 2018 as buyers shunned its crude due to U.S.-imposed trade restrictions.

Should the Iranian crude leave bonded storage and end up in the market, it could pressure oil prices, according to Bank of America Merrill Lynch. West Texas Intermediate plunged more than 20% from late April to mid-June as the U.S.-China trade war intensified. It’s since recovered some of those losses, partly as a result of the rising tension between Washington and Tehran, and is trading near $57 a barrel.

“A further escalation in U.S. tariffs on Chinese goods could jointly drive global economic growth a lot lower and encourage Iran-China cooperation,” Bank of America Merrill Lynch said in a June note. “If Chinese refiners start to purchase Iran oil in large volumes on a sustained basis as U.S. tariffs rise again, WTI could drop to $40 a barrel.”

EcoStim Energy Solutions provides completion and stimulation services in Argentina's Vaca Muerta shale play.

Seasonal Demand Patterns Give Argentinian LNG a Unique Opportunity

By Tyler Losier, Energy Reporter, Oil & Gas 360

Vaca Muerta production growth leads to LNG exports
In the past few years, Argentina’s natural gas production has been steadily rising, mainly due to an increased focus on the Vaca Mueta shale and tight gas play, located in the Neuquén Basin.

Currently, production from the Vaca Muerta accounts for 23% of Argentina’s total gas yield, and according to EIA estimates, the play has technically recoverable resources consisting of 308 Tcf of natural gas. In comparison with North American formations, the Vaca Muerta is about on par with the Eagle Ford Basin, located in southern Texas.

Source: EIA

Despite only 4% of the Vaca Muerta entering into the development phase so far, Argenti...

What Energy Security Looks Like: 90% of Natural Gas Used in U.S. Is Produced Domestically

What Energy Security Looks Like: 90% of Natural Gas Used in U.S. Is Produced Domestically

By Tyler Losier, Energy Reporter, Oil & Gas 360


The United States has been a net exporter of natural gas since 2017

In the United States, natural gas is one of the most prevalent sources of energy, and according to the EIA, in 2018, 90% of the natural gas consumed by Americans was produced domestically.

In general, thanks to the shale boom, both production and consumption of dry, consumer-grade natural gas in the U.S. have increased significantly since the mid-2000s, reaching a peak of 30 Tcf in 2018.

Furthermore, for the first time since 1966, in both 2017 and 2018 American production of natural gas exceeded consumption.

What Energy Security Looks Like: 90% of Natural Gas Used in U.S. Is Produced Domestically - Oil & Gas 360

Source: EIA

The advent of horizontal drilling and hydraulic fracturing has allowed producers of natural gas to extract the commodity more economically than ever before, which is likely why in 2018, natural gas from shale wells accounted for more than half of all gross withdrawals, according to EIA data. It total, gross withdrawals of natural gas in 2018 reached 37 Tcf.

As production of American natural gas increased, so too did exports, leading to the U.S. becoming a net exporter of natural gas in 2017. In 2018, that trend continued, with the U.S. exporting a record of approximately 4 Tcf, while only importing 3Tcf, the lowest figure since 2015.

 

 

As far as which industries use the most natural gas, in 2018, more than two-thirds of American natural gas consumption could be attributed to the electric power (35%) and industrial (34%) sectors. This is by no means out of the ordinary, as the U.S. electric power industry has been the largest consumer of natural gas in three of the last four years.

Formerly, the industrial sector was the largest end user, before electric power gained the lead in 2012. Other smaller consumers include the residential, commercial and transportation sectors, who mainly use natural gas for the purposes of heating.

Source: Islamic Republic News Agency

Oil Spikes After ‘Suspicious’ Tanker Attacks in Middle East

By Tyler Losier, Energy Reporter, Oil & Gas 360

Two vessels seriously damaged after seemingly intentional strike
Two tankers were attacked Thursday near the Strait of Hormuz in the Gulf of Oman, leading to a spike in oil prices as markets opened today.

U.S. officials are blaming Iran for the incidents; however the country has vehemently denied any involvement.

Source: Islamic Republic News Agency

The attacks on the two ships, which occurred approximately 14 nautical miles off the coast of Iran, are respectively the fifth and sixth such incidents to occur in the past couple months. A multinational investigation into the previous attacks pointed to a “state actor” as the culprit, however the United Nations has stopped shy...

Source: EIA

U.S. Gulf Coast Crude Oil Imports at Lowest Level Since 1986

Domestic production has reduced imports approximately 83% since peak
As of March of this year, the EIA estimates that the United States Gulf Coast imports approximately 1.8 million barrels of crude oil per day (BOPD), the lowest recorded rate since 1986.

The highest recorded rate of imports occurred in Mach of 2007 when the average was approximately 6.6 million BOPD. Since then, the Gulf Coast has repositioned itself as a net exporter, rather than an importer, capitalizing on a number of different trends in order to drive its numbers up.

Source: EIA

Consequently, the Gulf Coast has achieved an approximately 83% reduction in imports since its 2007 peak.

Stateside, one of the biggest influences on falling importation numbers is t...

Building Boom Shows Biggest U.S. Oil Hub Hasn’t Lost Its Allure

Building Boom Shows Biggest U.S. Oil Hub Hasn’t Lost Its Allure

From Bloomberg


Over two million barrels a day of new pipe capacity planned, Storage capacity at Cushing could reach 100 million barrels

America’s largest oil hub in Cushing, Oklahoma, is growing even as producers and traders look to move surging West Texas production to the coast for export.

The U.S. petroleum industry is planning to build about 4.8 million barrels of storage capacity and as many as seven new pipelines to move oil to and from the hub. The growth is a reminder of Cushing’s significance as a key trading hub for U.S. and Canadian crudes despite booming exports, according to speakers at last week’s Crude Oil Quality Association meeting in Oklahoma City.

Companies are building up Cushing, the delivery point for West Texas Intermediate futures, even as pricing in Houston is growing in importance for overseas markets. U.S crude exports reached 3.6 million barrels of crude per day during the week ended February 15, the highest since Washington ended restrictions in late 2015.

Six pipeline projects have been planned to move about 2 million barrels a day of crude away from Cushing by the end of 2021, but it’s unlikely they’ll all get built, according to Hillary Stevenson, Genscape Inc’s director of oil market business development. A more conservative estimate would be close to 750,000 barrels a day of new outgoing capacity, she said.

The majority of the new storage is from Keyera Energy Corp’s proposed 4.5 million-barrel Wildhorse terminal that is set to be complete by the middle of next year. Magellan Midstream Partners LP and Plains All American Pipeline LP will also add new storage, Stevenson added.

The U.S. government currently estimates working storage capacity at Cushing at nearly 77 million barrels.

Tallgrass Energy LP could build up to 5.5 million barrels of storage at a new Cushing terminal but it may depend on its Seahorse crude pipeline project, Genscape’s Stevenson said in an email. TC Energy Corp and Magellan both have additional tanks permitted in Cushing, but it’s unclear if and when these tanks, which amount to about 2 million barrels in total, would be added. Plains All American also has the ability to add tanks, she added.

Trading volume in Cushing has increased 10% year-on-year with so much happening in the market as well as new output, flooding and outages, said Dan Brusstar, CME Group director of energy research. “We may see storage growing to 100 million barrels soon.”

Energy Consultant Doubts Jordan Cove Economics

Energy Consultant Doubts Jordan Cove Economics

From the Grand Junction Sentinel

Oregon energy researcher and consultant Robert McCullough has done work in the liquefied natural gas realm while keeping an eye on the controversial Jordan Cove LNG proposal in his home state.

“We were watching the hubbub around Jordan Cove and I said, ‘you know, nobody really believes this is going anywhere. Why don’t we write down why?,'” he said.

Portland-based McCullough Research recently did just that, with McCullough and his colleagues penning a 10-page report to its clients questioning the economics of the project and giving it just a one-third chance of reaching the operational stage.

“Our analysis indicates that Jordan Cove will have a significant cost disadvantage compared to its competitors — approximately 25 (percent),” the report says.

He said he doesn’t think Jordan Cove, being pursued by Pembina Pipeline Corp., can beat out the LNG Canada project under way in British Columbia and the Cheniere Energy existing and planned projects on the Gulf Coast.

“In the end, it’s all going to be who can offer the lowest tolling fee, and these guys (Jordan Cove) clearly are not going to win that contest,” McCullough said.

Tolling fees are what buyers of the natural gas would pay based on costs such as liquefying it and getting it to them.

Jordan Cove is of interest to supporters of western Colorado natural gas development due to hopes that it could provide a long-term outlet for locally produced gas. While it also has some support in Oregon, others there oppose it because of concerns including impacts to the environment and to landowners along a proposed pipeline route in the state to serve it.

McCullough agrees that Jordan Cove has a big advantage over Cheniere because Gulf Coast LNG has a longer trip to Asia that requires a trip though the Panama Canal. But the Cheniere and LNG Canada projects are larger ones that benefit from economies of scale, he said. LNG Canada also has direct access to cheap gas from western Canada gas fields, whereas the price Jordan Cove pays for gas will be determined by the going price at the natural gas trading hub at Malin, Ore., where its pipeline would begin. That hub’s price is influenced by the fact that it serves California markets.

Jordan Cove also faces the cost of having to build a pipeline to serve it, a cost Cheniere isn’t saddled with, McCullough said. And Cheniere is close to electricity and experienced labor, he said.

Jordan Cove plans to use natural gas as the power source for producing LNG, whereas competitors are using cheaper and more reliable electricity, he said.

Jordan Cove spokeswoman Tasha Cadotte says the market feels different than McCullough about the project’s economic viability, as evidenced by the fact that Jordan Cove has nonbinding commitments from buyers for 11 million metric tons per year of LNG. That’s more than the project’s planned annual production capacity.

“The combined benefits of cheaper gas supply, shorter shipping distances, and the lack of reliance on the Panama Canal have made (Jordan Cove) competitive with LNG projects around the world, including the U.S. Gulf Coast,” she said.

Oregon energy researcher and consultant is keeping an eye on the controversial Jordan Cove LNG proposal - Oil & Gas 360

Jordan Cove LNG proposed Asia shipping route avoids Panama Canal – Source: Pembina

Eric Carlson, executive director of the West Slope Colorado Oil and Gas Association, said he doesn’t know the LNG business well enough to say whether Jordan Cove is a good investment or not.

But he said it makes sense that it offers cheaper shipping costs than for LNG coming from farther east and going through the Panama Canal. He also said what he hears is that there is a huge market for LNG in Asia and Europe.

“It may be that there’s enough space available and market availability for sort of all of the above — all these LNGs (facilities) that are being proposed, there might be potential” for all of them to be built, he said.

Pembina recently said in a news release that it continues to consider Jordan Cove to be viable but is limiting capital investment on non-permitting-related activities until it makes a final decision on whether to go forward with it.

It said it has approved “incremental funding” of about $50 million this year in support of regulatory and permitting work.

Cadotte clarified in a recent email that the $50 million is in addition to $100 million it had previously said it planned to spend this year on the project, rather than being a $50 million reduction in that spending. She said the $100 million already has been spent.

Notably, Michael Hinrichs, who has made multiple trips to western Colorado as spokesman for Jordan Cove, is no longer involved with the project. Cadotte said his departure from Pembina was voluntary. Reached by phone, Hinrichs also said it was voluntary but declined to further discuss the reasons behind it.

He said he is still doing public affairs consulting in the western United States.

 

June 3, 2019 - 8:35 am Closing Bell Story, Energy News, LNG
EOG Earns $635 Million, Plans International Crude Exports

EOG Earns $635 Million, Plans International Crude Exports

Guidance: production above, CapEx below
By Richard Rostad, analyst, Oil & Gas 360

EOG Resources (ticker: EOG) announced first quarter results today, showing net income of $635 million, or $1.10 per share.

EOG reported much smaller derivative losses than many E&P companies this quarter, with derivative losses of only $20.5 million. After adjusting for derivatives and other charges, EOG earned $689 million in Q1 2019, dead even with the company’s adjusted earnings in Q1 2018. After paying $128 million in dividends, EOG generated $55 million in free cash flow in Q1.

EOG produced 773.6 MBOEPD in the quarter, up 17% year-over-year and 1% sequentially. The company achieved the ideal quarter when compared to guidance, as EOG’s cr...

A Flood of U.S. Oil Exports Is Coming

A Flood of U.S. Oil Exports Is Coming

From Bloomberg

Oil trader Paul Vega is at the vanguard of shale’s next revolution.

Driving his pick-up truck through the heartland of the Permian basin — the vast tract of west Texas scrub where one of history’s greatest oil booms means miles-long traffic jams — Vega says there’s more crude being pumped than America’s refineries can absorb. Today, the primary task of trading houses like his is getting the stuff overseas.

“We buy it, we truck it, we put it on a pipeline, and there it goes to the port — and from there to the world,” said Vega, who heads the office of global commodities trader Trafigura Group in Midland, the region’s oil industry hub.

What started as an American phenomenon is now being felt around the world as U.S. oil exports surge to levels unthinkable only a few years ago. The flow of crude will keep growing over the next few years with huge consequences for the oil industry, global politics and even whole economies. OPEC, for example, will face challenges keeping oil prices high, while Washington has a new, and potent, diplomatic weapon.

American oil exports stepped up a gear last year, jumping more than 70 percent to just over 2 million barrels a day, according to government data. “That could double again over the next few years as people continue to invest in shale,” said Russell Hardy, the head of top oil trader Vitol Group. Over the past four weeks, U.S. oil exports have averaged more than 3 million barrels a day — more than what Middle East petro-state Kuwait sells.

“This is the new American energy era,” U.S. Energy Secretary Rick Perry told an industry conference in Houston earlier this month.

Oil traders and shale executives believe U.S. crude exports are set reach 5 million barrels a day by late 2020, up another 70 percent from current levels. If the U.S. hits that target, America will be exporting, on a gross basis, more crude than every country in OPEC except Saudi Arabia. (On a net basis, the U.S. remains, just, a net importer, but that’s likely to change in the next few months.)

“The second wave of the U.S. shale revolution is coming,” said Fatih Birol, the head of the International Energy Agency. “This will shake up international oil and gas trade flows, with profound implications for geopolitics.”

The political impact is already being felt. The Trump administration has been able to impose aggressive sanctions on oil exports from Iran and Venezuela knowing the flow of crude from Texas will keep on rising. The economic impact on the U.S. is also evident: in dollar terms, the country’s petroleum trade deficit fell to its lowest in 20 years in 2018.

The U.S. is already a big exporter of refined products such as gasoline and diesel. When combined with rising crude exports, the IEA forecasts American petroleum exports will reach roughly 9 million barrels a day within five years, up from just 1 million in 2012. In the process, the U.S. will become the world’s second-largest exporter of crude and refined products by 2024, overtaking Russia and nearly topping Saudi Arabia.

Until now, the surge in U.S. oil production from the Permian and other shale basins like the Bakken in North Dakota was absorbed at home, feeding refineries in the U.S. Gulf of Mexico coast. Now, U.S. refiners are finding it increasingly hard to process more of the kind of light crude pumped in the Permian as their plants were built to process denser heavy crude — the type pumped in Venezuela and the Middle East.

“The United States is probably darn close to being able to process as much light crude as it can,” Thomas J. Nimbley, the head of U.S. oil refiner PBF Energy Inc., told investors.

As a result, shale executives are traveling the world to seek new customers. Gary Heminger, the head of Marathon Petroleum Corp., for example, was recently in Singapore and South Korea looking for buyers for shale crude.

“All the incremental Permian production needs to be exported,” said Raoul LeBlanc at consultant IHS Markit Ltd. and a former head of strategy at Anadarko Petroleum Corp. “The Permian needs to find refineries willing to take U.S. light sweet crude as a base-load, most likely in Asia.”

Despite a tight oil market due to American sanctions on Venezuela and Iran mixed with OPEC production cuts, finding new buyers isn’t as easy as it sounds. The crude from the Permian is light, yielding lots of naphtha — used in the petrochemical industry — and gasoline, but comparatively little diesel. And most refineries want to produce diesel.

Until now, U.S. shale producers and oil traders had been selling most of their crude on spot transactions — one at a time. As a result, American oil exports saw wildly different destinations from month to month, from Spain to Thailand to Brazil.

A few stable markets are starting to emerge. Oil refineries in Canada, Italy, the U.K., and South Korea are becoming regular buyers. And little by little, oil traders are securing long-term deals with overseas refineries, known as term contracts.

Yet, the rapid rise in oil exports is challenging. Not even Saudi Arabia in the 1960s and 1970s saw exports grow so quickly.

“The U.S. export market needs to transition from infancy to adulthood far more rapidly than any major exporter ever has,” said Roger Diwan, another oil analyst at IHS Markit.

Key for U.S. oil exports is China, mired in a trade war with Washington. Until this year, Chinese refiners were buying large chunks of American shale exports. But the flows all but dried up in August. If U.S. oil exports are going to increase at the pace that executives and traders anticipate, the shale industry needs the White House to strike a trade deal with the Chinese.

“If the China demand pull fails to materialize, for political reasons, quality mismatch or otherwise, U.S. exports will likely have to muscle their way into the global refining system, likely via price discounts,” Diwan said.

U.S. shale crude is already selling at a big discount to Brent, the international oil benchmark. West Texas Intermediate sells nearly $10 under Brent. And some of the lighter grades from the Permian, including a new stream called West Texas Light, are seeing even wider discounts.

Finding buyers for the light Permian crude isn’t the only obstacle. Pipelines and ports have become the biggest bottleneck in U.S. oil exports, with traders engineering logistically complex chains combining railways, trucks, pipelines, barges, and ship-to-ship transfers to get crude out of the country. Several ventures are aiming to build new facilities to allow exports via supertankers, which need deepwater ports.

The export surge started in late 2015 when Washington lifted a 40-year ban on most oil sales overseas, imposed in the aftermath the 1973-74 oil embargo by the Arab members of the Organization of Petroleum Exporting Countries.

Although the Permian isn’t growing as fast as last year, oil traders and executives still anticipate that America will add another million barrels a day this year to its production, with the bulk coming in the second half. The current slowdown, which some executives jokingly call a “fracking holiday,” is the direct result of shareholder demands for higher returns and less growth, and lower oil prices in late 2018 and early 2019. But the Permian is likely to re-accelerate in the second half of this year when new pipelines open.

If the forecast proves correct, U.S. crude production will surpass 13 million barrels a day by December, up from 11.8 million barrels a day at the end of last year and well above the previous all-time high set in 1970.

“It’s going to be less than if people were able to spend unconstrained, but there’s going to be growth, lots of it,” said Osmar Abib, chairman of global energy at Credit Suisse Group AG.

March 26, 2019 - 4:30 pm Closing Bell Story, Crude Oil News, Energy News
U.S. Energy Dominance Is Good for The World: U.S. Secretary of State Pompeo

U.S. Energy Dominance Is Good for The World: U.S. Secretary of State Pompeo

From the Houston Public Media

U.S. Secretary of State Mike Pompeo said the United States’ growing energy dominance helps its geopolitical goals.

Speaking at the CERAWeek energy conference in Houston last week, Pompeo said the United States is not just exporting energy, but also its commercial values.

“Our model matters now, frankly, more than ever in an era of great power rivalry and competition where some nations are using their energy for malign ends and not to promote prosperity in the way we do here in the West,” Pompeo said.

He singled out several countries, including China, Russia and Iran, which he called “bad actors.”

Pompeo called on both American and foreign companies to work with the U.S. government to help more countries get their oil and gas from the United States.

In a report released Monday, the International Energy Agency forecasts the United States will become a net oil exporter in the next few years and even challenge Saudi Arabia for the top exporting spot.

 

March 18, 2019 - 6:54 am Closing Bell Story, Energy News, People
U.S. Petroleum Trade at All-Time High: Tops 17.5 MMBPD in 2018

U.S. Petroleum Trade at All-Time High: Tops 17.5 MMBPD in 2018

Soaring imports drive new record in crude and products shipments
By Richard Rostad, analyst, Oil & Gas 360

The U.S. has become a major presence in the global petroleum trade, with gross imports and exports reaching an all-time high in 2018.

The EIA reports the total U.S. imports and exports of crude and refined products reached 17.5 MMBPD in 2018, well above the previous highs seen in the mid-2000s. This record has been achieved at a time when net imports are at a multi-decade low, as the U.S. imported a net 2.3 MMBOPD in 2018. This is the lowest net import of petroleum since 1967.

Imports of crude oil have been falling since 2005 and averaged 7.7 MMBOPD in 2018. Light oil from the Bakken, Eagle Ford and Permian have drive...

Cove Point Fall Colors, Nov. 2017

U.S. To Become Net Energy Exporter in 2020, Years Ahead of Schedule

LNG Exports, falling oil imports break 66-year pattern
The EIA has released its Annual Energy Outlook, examining major trends in energy in America through 2050.
Perhaps the most significant projection made by the EIA in this year’s AEO regards the country’s trade in oil and gas. The U.S. is expected to become a net energy exporter by 2020, a major milestone as the country has been a net importer of energy for the last 66 years. This milestone is also ahead of schedule, as last year the EIA forecasted net exports in 2022, and in 2017 net exports were not expected until 2026.
This milestone is driven primarily by shipments of LNG and refined products, as natural gas will surpass coal to become the country’s largest net energy export in 2020, ...

Oil & Gas 360 - France’s Total and Sempra Energy Sign North America LNG Deal

Why the U.S. Imports LNG from Russia and Nigeria Despite Its Gas-Export Boom

From Bloomberg

More than a decade in and the U.S. shale boom keeps breaking output records, with fields from Pennsylvania to Texas producing more natural gas than the country needs. That has triggered billions of dollars of investments to ship liquefied natural gas overseas. Yet the U.S. is still importing LNG from places such as Russia and Nigeria. There are two reasons for that: pipeline bottlenecks and the requirements of a 1920 law meant to support a robust U.S. shipping industry.

  1. Does the U.S. consume more gas than it produces?

No. Gas production jumped 12 percent in 2018 to a record 89.6 billion cubic feet a day while consumption was 81.7 billion cubic feet per day, according to the U.S. Energy Information Administration. The problem is getting it to the right places at the right time because of insufficient pipeline capacity near big metropolitan centers. Pipelines historically have been designed to operate at a reduced rate for most of the year so that when a cold snap hits, there’s space for a surge in demand. But with the shale boom, many households, power plants and factories have switched from fuels such as heating oil and coal to take advantage of cheap gas. This added consumption means that some lines are close to full year-round and are thus unable to cope when demand peaks.

  1. Where are shortages occurring?

Mostly in the Northeast. The region was the destination of most of the 200 million cubic feet a day of LNG the U.S. imported in the first 10 months of 2018. In January 2018, frigid weather sent New York City spot gas to a whopping $175 per million British thermal units, compared with less than $3 elsewhere in the country, as gas distributors engaged in bidding wars for pipeline space.

  1. Why can’t the U.S. buy its own LNG?

There’s certainly lots of it. Surplus U.S. gas supply allowed America’s booming LNG industry to ship 2.8 billion cubic feet a day to overseas markets during the first 10 months of 2018, according to the EIA. But while the U.S. is poised to become the world’s third largest LNG supplier by 2020, with six export facilities, the Jones Act of 1920 mandates that vessels moving between U.S. ports be built and registered in the country, and crewed by Americans. There are currently no U.S.-flagged LNG carriers.

  1. Where is imported LNG coming from?

Everett terminal in Massachusetts, by far the most active of the dozen import terminals in the U.S., received about two dozen cargoes in 2018, with all but one apparently coming from Trinidad and Tobago, according to Energy Department and ship-tracking data compiled by Bloomberg. Russian LNG made its debut in the U.S. in January of last year as prices climbed during freezing temperatures. Dominion Energy Inc.’s Cove Point terminal in Maryland imported a cargo from Nigeria in late December.

 

January 3, 2019 - 12:27 pm Closing Bell Story, Energy News, LNG
U.S. Shale Gas Export Projects Face Much Longer FERC Permitting Delays

U.S. Shale Gas Export Projects Face Much Longer FERC Permitting Delays

From Bloomberg

FERC backlog after a surge in plant applications: unexpected wait could affect commercial viability of projects

The approval of U.S. shale-gas export projects could be delayed by as many as 18 months as the top energy regulator struggles with a backlog of permit requests, according to people familiar with the matter.

The Federal Energy Regulatory Commission is preparing to notify some developers of liquefied natural gas plants of 12- to 18-month delays in reviews, the people said, asking not to be named because the information isn’t public. That could affect the commercial viability of several ventures vying for a spot in the rapidly growing global gas market.

FERC, an independent agency under the U.S. Department of Energy, is already tapping outside help, with Chairman Kevin McIntyre saying last month that FERC is hiring private contractors for the first time to help work through LNG reviews.

Tamara Young-Allen, a FERC spokeswoman, confirmed the agency had asked the companies to pay for the external contractors, but would neither confirm nor deny the delay notifications coming in the future.

The surge in applications for new export projects is testament to the American shale gas boom that turned old plans to import the fuel on their head. The U.S. has two major LNG export facilities in operation today, with four more set to enter service by the end of 2019. Another four have received all major regulatory permits and are awaiting the final go-ahead from their developers. And more than a dozen are seeking approval from FERC.

‘Center of the World’

On Wednesday, Commissioner Neil Chatterjee took to Twitter to offer possible solutions to the problem, including increasing pay for agency staffers in a bid to retain them or opening a regional office in Houston, which he called “the center of the world” for natural gas legal and technical expertise.

Paul Varello, president and CEO of Commonwealth LNG, said he’s heard that it will take 18 months to two years to prepare an environmental review for his proposed project — compared to the six to eight months traditionally spent on those assessments.

“Right now, it is a startling revelation to me that it will take me twice as long to permit the plant as to build it,” he said in an interview in Washington. “Five years to permit it, and two and a half years to build it.”


From Oil & Gas 360 –  Expert’s Testimony to Congress: Permitting Delays May Take U.S. Out of First Place in LNG Race

July 13, 2018 - 9:09 am Closing Bell Story, LNG, Regulatory
Canadian Oil Prices Set to Climb

Canadian Oil Prices Set to Climb

From Bloomberg

Canadian oil prices are poised to continue their slow, steady march upward next year as shipping bottlenecks ease and U.S. refiners look north to fill the gap created by decreasing output from Venezuela, according to Deloitte.

Western Canada Select at the Hardisty hub will average C$53.35 this year and climb to C$54.55 a barrel next year, according to a forecast from Andrew Botterill, a partner at Deloitte in Calgary. He estimates prices will reach C$69.15 in 2023, a 30 percent advance from this year’s average.

Driving the gains will be an increase in rail capacity that will help alleviate some of the transportation woes that have weighed on prices and higher demand from U.S. Gulf Coast refiners seeking to make up for lost production out of Venezuela, Botterill said. The prospects for increased pipeline space have also brightened recently with last week’s approval of Enbridge Inc.’s Line 3 expansion in Minnesota. Still, the threat of increased production from the U.S. may continue to hang over prices, he said.

“There’s some optimism, but it’s a little bit muted at this point in time,” Botterill said in an interview. “We’re excited that growth looks like it can actually occur and have some legs to it, but we’re still a little bit cautious.”

Alberta’s AECO natural gas benchmark is estimated to average about C$1.70 per thousand cubic feet this year and climb 18 percent to C$2 next year, according to Deloitte. The price is seen advancing to C$3.20 in 2023, an 88 percent gain from this year.

July 5, 2018 - 1:32 pm Canada, Closing Bell Story, Energy News, International
Africa’s Largest non-OPEC Producer is on a Roll

Africa’s Largest non-OPEC Producer is on a Roll

Egypt is the largest non-OPEC oil producer in Africa and the third-largest dry natural gas producer on the continent, according to the EIA’s newest report on Egypt. In recent years, the country has seen political instability accompanied by growing power demand and a recovering energy industry.

Natural gas supply shortages often cause frequent blackouts in Egypt – and 2011’s political turmoil certainly didn’t help deliver any security for its energy picture. But the country has placed a priority on developing its energy resources, eliminating energy subsidies, strengthening its fiscal policy and growing its economy. And with gas supplies from the Zohr, Leviathan and Tamar fields, Egypt is securing the energy it will need for industrial and petrochemical plants, and expanding consumer electricity supply, for the next few decades.

Africa’s Largest non-OPEC Producer is on a Roll

Consumer demand shuts down one of two LNG export facilities

Egypt has two LNG export facilities with a combined capacity of 586 Bcf per year. The Spanish-Egyptian Gas Company (SEGAS) LNG facility in Damietta is a single LNG train with a capacity of 240 Bcf per year and is owned by Union Fenosa Gas (80%) and by EGPC and EGAS (10% each).

The SEGAS LNG facility began production in December 2004, but operated below its nameplate capacity until the plant closed in December 2012 as a result of growing domestic energy demands.

Egypt’s other LNG facility, the Egyptian LNG project (ELNG), is located at Idku and is a joint venture that includes Shell, Petronas, EGAS, EGPC and ENGIE. The facility has two LNG trains, each having a capacity of 172.8 Bcf per year.

ELNG began production in May 2005, but the facility was idle from late 2014 to April 2016 and exports have been sporadic.

In 2016, Egypt exported approximately 26 Bcf of LNG. Most of the exports went to the Asia-Pacific (61%) and the Middle East (24%), according to the 2017 BP Statistical Review of World Energy.

Consumption

Egypt is the largest oil and natural gas consumer in Africa, and it accounted for about 22% of petroleum and other liquids consumption in 2016. The country also consumed 37% of Africa’s natural gas in 2016. Energy consumption is expected to continue growing.

The rapid growth of oil and natural gas consumption has been driven by increased industrial output, economic growth, energy-intensive natural gas and oil extraction projects, population growth, an increase in private and commercial vehicle sales and energy subsidies.

Egypt’s total primary energy consumption was approximately 3.61 quadrillion BTUs in 2016, according to the 2017 BP Statistical Review of World Energy.

Africa’s Largest non-OPEC Producer is on a Roll

According to the EIA, natural gas supply shortages cause frequent blackouts in Egypt – and 2011’s political turmoil certainly didn’t help. The International Monetary Fund (IMF) said political instability caused a drop in foreign investment. However, within the general region, financial support from the United Arab Emirates, Saudi Arabia and Kuwait has improved Africa’s economic conditions.

Investors contribute to energy production by providing capital, which in turn allows foreign and domestic companies to drill new wells, build infrastructure and acquire modern technology offered by international majors.

Eliminating subsidies

The Egyptian government is implementing a reform program that will eliminate energy subsidies, thereby reducing spending and strengthening its fiscal position – these cuts are part of an IMF economic reform package. Energy subsidies are expected to decline to 2.4% of Egypt’s GDP in fiscal year 2017 – 2018 (ending June 30, 2018), from a peak of 5.9% of GDP in 2013 – 2014.

According to the EIA report, energy subsidies have contributed to Egypt’s large budget deficit and created financial challenges for its national oil company, the Egyptian General Petroleum Corporation (EGPC). Subsidies have also deterred foreign operators from investing in the sector. However, quicker-than-expected progress on implementing reforms and recent natural gas discoveries have led to renewed interest among foreign investors in Egypt’s energy sector.

New Zhor gas field

Eni S.p.A. (ticker: E) reported first gas from the Zohr field in late December 2017, marking one of the fastest development processes of an offshore field in recent years.

Africa’s Largest non-OPEC Producer is on a Roll

Discovered in August 2015, Zohr is a large gas field located in offshore Egypt, about 120 miles north of Port Said. Eni estimates the field has resource potential of more than 30 Tcf of gas, or 5.5 billion BOE. Eni announced FID on the field in February 2016, only six months after discovery.

Facilities began test production in late December at a rate of 350 MMcf/d. Bloomberg said that volumes from the field will reach 2.7 Bcf/d by the end of 2019. The project cost $12 billion, with a break-even cost equivalent to $30/bbl.

Noble Energy sells Egypt $14 billion of natgas

Noble Energy, Inc. (ticker: NBL) signed agreements in February 2018 to sell significant quantities of natural gas from the Leviathan and Tamar fields to Dolphinus Holdings Limited.

Africa’s Largest non-OPEC Producer is on a Roll

Leviathan and Tamar Fields, May 2018

These agreements, one for natural gas from Leviathan and one for Tamar, each provide for total contract quantities of 1.15 trillion cubic feet of natural gas. The natural gas is anticipated to supply industrial and petrochemical customers as well as future power generation in Egypt, Noble said.

Sales volumes under the agreement associated with the Leviathan field are anticipated to begin at a firm rate of approximately 350 MMcf/d at the startup of the Leviathan project at the end of 2019.

For the Tamar agreement, sales volumes are anticipated to begin at an interruptible rate of up to 350 MMcf/d, dependent upon gas availability beyond existing customer obligations in Israel and Jordan.  Noble Energy said it will have an option to convert the Tamar interruptible quantity to a firm-basis with a significant take or pay commitment. Both contracts are for a 10-year term.

Trans-Alaska oil pipeline

A Minimum of 5.7 Billion Barrels Await Drillers at ANWR

The Arctic National Wildlife Refuge (ANWR) is located on the northern coast of Alaska, due east of both Prudhoe Bay and the National Petroleum Reserve-Alaska (NPRA). The coastal plain (the 1002 Area) covers 1.5 million acres and is about 8% of the total area of ANWR.

A Minimum of 5.7 Billion Barrels Await Drillers at ANWR

USGS 1002 Area Map

In its latest (1998) resource assessment, the United States Geological Survey (USGS) estimated that the total technically recoverable crude oil resource for federal lands, state waters and native lands in the coastal plain has a 95% chance of being more than 5.7 billion barrels and a 5% chance of being as high as 16.0 billion barrels, with a mean estimate of 10.4 billion barrels.

Slow start, but reliable

The middle resource case projected by the EIA (Mean ANWR) shows an increase of 3.4 billion barrels in cumulative U.S. crude oil production from 2031 to 2050, compared with the AEO2018 Reference case.

According to the EIA, production from ANWR does not start until 2031 because of the time needed to acquire leases, explore and develop the required production infrastructure. Crude oil production from the coastal plain of ANWR peaks at about 880,000 BOPD in 2041 in the Mean ANWR case.

A Minimum of 5.7 Billion Barrels Await Drillers at ANWR

Domestic production reduces imports, saves money

Between 2031 and 2050, cumulative crude oil production in the United States is 3.4 billion barrels higher in the Mean ANWR case than in the AEO2018 Reference case. Every additional barrel of crude oil produced from ANWR is projected to reduce U.S. net imports of liquid fuels by about one barrel, the EIA said.

A Minimum of 5.7 Billion Barrels Await Drillers at ANWR

The reduction in U.S. imports of crude oil and petroleum products improves the U.S. balance of trade by reducing the levels of expenditures on crude oil and petroleum products imports.

In the AEO2018 Reference case, cumulative U.S. expenditures on imported crude oil and petroleum products are about $4.9 trillion (2017 dollars) between 2031 and 2050.

A Minimum of 5.7 Billion Barrels Await Drillers at ANWR

In the Mean ANWR case, comparatively higher domestic crude oil production from 2031 through 2050 reduces cumulative expenditures on imported crude oil and liquid fuels by about $409 billion (8%).

Jones Act of 1920

The EIA said that nearly 80% of oil produced in Alaska in 2017 was sent to Washington and California on Jones Act vessels at a shipping cost of about $5.50 per barrel.

The Jones Act requires that all goods transported by water between U.S. ports be carried on ships constructed in the United States, owned by U.S. citizens and crewed by U.S. citizens and permanent residents.

Availability of vessels compliant with the Jones Act and constraints through high-traffic waterways on the West Coast could also limit the amount of Alaskan crude oil that gets processed in domestic refineries, the EIA said.

Given these factors, it is likely that some volumes of Alaskan oil including new production from ANWR would be exported to Asia.

About 15% of Alaskan crude oil production was processed in Alaska. A small amount of Alaskan crude oil was shipped to Hawaii or exported to international destinations in 2017.

Trans-Alaska Pipeline needs more oil

Alaska also relies on the 40-year-old Trans-Alaska Pipeline System (TAPS) to transport crude oil from the frozen North Slope to the warm-water port at Valdez on the state’s southern coast. The 800-mile pipeline was built from 1974 to 1977, and achieved peak flow in late 1980s at 2 MMBPD. According to the EIA, the current flow is only about 500,000 BPD.

A Minimum of 5.7 Billion Barrels Await Drillers at ANWR

Trans-Alaska Oil Pipeline

Less oil production leads to slower flow, meaning that crude oil spends more time in the pipe with less movement. The slower flow may cause more wax to accumulate in the pipe, driving up maintenance costs. Additionally, the more time oil spends in the pipe, the more heat it loses – causing a higher risk of ice problems. Adding oil production from ANWR into the pipeline would directly address the lack of oil flow.

Background on ANWR – 1002 Area

In 1960, the Secretary of the Interior signed an order protecting the northernmost parts of Alaska at the federal level. The order protected 8.9 million acres and named it the Arctic National Wildlife Range. In 1980, President Carter signed the Alaska National Interest Lands Conservation Act (ANILCA) into law, renaming and enlarging the Arctic National Wildlife Refuge (ANWR) to over 19 million acres, with eight million of the 19 million ANWR acres designated as Federal Wilderness.

A Minimum of 5.7 Billion Barrels Await Drillers at ANWR

USGS 1002 Area Map

The non-wilderness area is called the 1002 Area and could be developed with Congressional approval. The 1002 Area is approximately 1.5 million acres and is a target of E&P development. Alaskan Senator Lisa Murkowski had proposed limited development of up to 2,000 acres.

After 4 decades of debate, ANWR development law makes it through committee and is passed by Congress

On November 15, 2017 the Senate Committee on Energy and Natural Resources approved Senator Murkowski’s ANWR energy development plan. The budget reconciliation legislation came favorably out of committee on a bipartisan vote of 13-10. Senator Murkowski voted in support of the legislation, which passed the Budget Committee and was put up for a vote, with both houses passing the act just a week before Christmas 2017.

“After decades and decades in this chamber, we are opening up a small non-wilderness area of the Alaska National Wildlife Refuge for responsible development. That is the most ambitious step we have taken in years to secure our own energy future,” House Speaker Paul Ryan said at the time.

The Congressional Budget Office estimates the legislation will raise nearly $1.1 billion over the 10-year budget window. Between rents, royalties, and federal taxes, it will raise substantially greater revenues once production from the 1002 Area begins.

Sen. Murkowski said on her website that opening the 1002 Area will generate $124.6 billion in royalties alone, based on current estimates.

Now the work begins before drilling can start—creating an environmental impact statement for the 1002 Area before it can be drilled and produced. After that the Federal Government would schedule lease sales. In March, the White House called for swift leasing action for ANWR, but experts say it may take two or more years before an EIS is ready.

Inventories Back at Five-Year Averages—for Now

Inventories Back at Five-Year Averages—for Now

The production cuts may have erased the surplus, but for how long?

Stored petroleum around the world fell through 2017 and the first quarter of 2018, ending a period of oversupply in the global market that began before OPEC began production cuts in November 2016, according to data from the EIA.

The production cuts took effect in January 2017, reducing supply by 1.2 MMBOPD (compared to October 2016 levels) and limiting total OPEC production to 32.5 MMBOPD. Russia joined in by agreeing to reduce its crude oil production, and OPEC eventually extended the agreement a year later, in November 2017. Extension of production cuts has resulted in steadier oil prices gliding upward on a smooth increase.

The decrease in production eventually caused the global market to balance. Crude oil and other liquids inventories declined after a long stretch of steady increases from mid-2014 through most of 2016.

Inventories Back at Five-Year Averages—for Now

According to the EIA, from January 2017 to April 2018, OECD inventories decreased by 234 million barrels. The U.S. accounted for more than half of that decline, as U.S. crude oil and other liquids inventories decreased by 162 million barrels over that period. By the end of April 2018, both OECD and U.S. inventory levels were lower than the five-year averages, for April 2013–April 2017.

Inventories Back at Five-Year Averages—for Now

OPEC to reconvene on June 22

On May 25, 2018, Saudi Arabia’s energy minister said OPEC and Russia could together increase production by approximately a million barrels. Reacting to comments from the Saudi oil minister, crude oil prices fell by about $5 per barrel in total over a few days, but the positive price trajectory returned on May 30.

EIA sees a return to surpluses on the horizon

The EIA forecasts that the tightening trend in global petroleum markets will soon reverse, with both U.S. and OECD inventories returning to surpluses, compared with their five-year averages (although on a smaller scale compared with 2015–2016).

As to the weekly reports of U.S. inventory levels by which you could almost set your watch every Wednesday, the EIA said it will release both the crude oil and the natural gas reports on Thursday instead, a result of the Memorial Day holiday this week.

Pioneer Selling Oil at Premium Pricing, Looks to Add 250-275 Wells to Production in 2018

Pioneer Selling Oil at Premium Pricing, Looks to Add 250-275 Wells to Production in 2018

Forecasts cashflow of approximately $3.2 billion at current strip prices for the remainder of 2018 – $66 per barrel for oil and $2.80 per Mcf for natural gas

Running 20 Permian Hz rigs

Pioneer Natural Resources Company (ticker: PXD) reported Q1 2018 net income of $178 million, or $1.04 per diluted share.

Companywide production was 312 MBOEPD in the quarter, but freezing temperatures in early January caused production losses of ~6MBOEPD and a compressor station fire in the West Panhandle field also decreased production by ~2 MBOEPD. WPX said that West Panhandle production resumed in early April at ~8 MBOEPD.

Pioneer Selling Oil at Premium Pricing, Looks to Add 250-275 Wells to Production in 2018

PXD Permian Production, May 2018

President and CEO Timothy L. Dove said, “Our transition to a Permian Basin ‘pure play’ is progressing according to plan… When the divestiture of these non-Permian assets is complete, the company will report stronger cash operating margins and corporate returns due to an increase in revenue per BOE and a decrease in operating cost per BOE.”

Permian well completion upgrades slated

Pioneer said it placed 47 Version 3.0 wells on production during the first quarter of 2018.

The company also said it placed 16 wells on production during the first quarter of 2018 that utilized higher intensity completions (compared to Version 3.0 wells) – these are referred to as “Version 3.0+” completions.

Pioneer Selling Oil at Premium Pricing, Looks to Add 250-275 Wells to Production in 2018

PXD Completions, May 2018

Results from the 20 Version 3.0+ wells completed in 2017 and early production results from the 16 Version 3.0+ wells that were placed on production in the first quarter of 2018 significantly outperformed production from nearby offset wells with less intense completions.

The company originally planned to test approximately 45 Version 3.0+ completions during the first half of 2018, with the remaining wells for 2018 expected to be predominantly Version 3.0 completions. However, based on the success of the higher intensity completions to date, the company is evaluating adding more Version 3.0+ completions in the second half of 2018.

Rigs, capital

Pioneer Selling Oil at Premium Pricing, Looks to Add 250-275 Wells to Production in 2018

Courtesy of Pioneer

Pioneer is operating 20 horizontal rigs in the Permian and the company expects to place 250 to 275 wells on production during 2018. Pioneer said it is currently evaluating the timing of rig additions later in 2018 to support the 2019 plan.

The company is funding 2018 capital spending from a forecasted cashflow of approximately $3.2 billion at current strip prices for the remainder of 2018 ($66 per barrel for oil and $2.80 per Mcf for gas).

The 2018 capital budget of $2.9 billion is expected to increase due to additional Version 3.0+ completions, late-year rig additions and inflation.

Getting premium pricing: pipeline commitments insulate Pioneer from widening Midland-Cushing differentials

Firm pipeline commitments will allow Pioneer to deliver ~160 MBOPD, or 95% of current Permian Basin net oil production, to Gulf Coast refineries and export markets. In Q1, the company delivered 160 MBOPD to the Gulf Coast, of which 87 MBOPD was exported.

The firm pipeline contracts insulate Pioneer from the recent widening of the Midland-Cushing oil price basis differential by providing exposure to Brent-related pricing.

Pioneer Selling Oil at Premium Pricing, Looks to Add 250-275 Wells to Production in 2018

Midland Differential, May 2018

According to Pioneer, as a result of this premium pricing, Gulf Coast refinery and export sales added $16 million of incremental cash flow in the first quarter of 2018.

Gas takeaway secured

Approximately 75% of Pioneer’s Midland Basin gas production is transported under firm pipeline transportation agreements to southern California. The remainder is primarily sold under term contracts at Waha.

Additional firm pipeline transportation has been secured on Kinder Morgan’s Gulf Coast Express pipeline, which is anticipated to be on line late in the third quarter of 2019. Firm transportation on the Gulf Coast Express pipeline will provide access to LNG exports, refineries, petrochemical facilities and Mexican markets.

Q2 2018

Total production is forecasted to average between 312 MBOEPD to 322 MBOEPD and Permian Basin production is forecasted to average between 268 MBOEPD to 276 MBOEPD.

Pioneer Selling Oil at Premium Pricing, Looks to Add 250-275 Wells to Production in 2018

PXD Q2 2018 Guidance, May 2018

Production costs are expected to average $10.00/BOE to $12.00/BOE.

Conference call Q&A excerpts

Q: The company is tracking towards the upper end of the 19% to 24% Permian Basin growth range. Does that just contemplate the 45 Version 3.0+?

President and CEO Timothy L. Dove: I think first of all, the production numbers we’re seeing so far have been outstanding, and we continue to operate at a strong rate of growth.

So I think the numbers we’re reflecting today really don’t yet contemplate adding additional 3.0+ because we haven’t determined that number yet.

What I’m pointing you to is the fact that we are going to increase the number of 3.0+. And as a result, we’ll come out with production guidance at that time. But needless to say, one of the reasons we’re hitting the top end of our range is because of 3.0+.

The more we drill, the better we’re going to do.

Q: What is the cadence of infrastructure spending, and do you still anticipate the breakeven trending down to $50 and then ultimately $40 level?

President and CEO Timothy L. Dove: First of all, on your question regarding the cadence of incremental spending above just D&C, we have some significant projects this year that you’re familiar with.

One of them is our Midland wastewater plant investment, so as to them being able to take 240,000 barrels a day of effluent water from the system. That’s easily $100 million-plus this year we think that’s going to be spent later as we get into the year, in addition to which we have regular capital needs for our pumping services fleet as well as other items corporately.

The other thing to note is we do continue to spend money on a relatively even cadence on tank batteries and saltwater disposal systems. Our estimate continues to be that by the end of this year, we’ll be about 65% completed on the whole field-wide implementation of that, so we do have a few more years of spending at that level.

Our longer-term modeling is to add roughly $300 million per year. When we put out our ten year plan, that was the number we included. And it could be a combination of things. It could be gas processing. We have two gas processing plants coming in this year, two coming in next year. So this is an important part of our capital in the sense that it prepares us for the long term.

Q: As you all are now contemplating these additional rig adds, you all previously talked about considering revamping and renovating a couple of your frac fleets. And I’m just wondering if there’s been any decision made on that front.

President and CEO Timothy L. Dove: Yes, first of all, the fleets – we have one or two fleets that probably need some refurbing. One in particular is really on ice today, and that was something we have to evaluate really for as a late 2018-2019 decision, realizing today of course we’re using, depending upon the day, six or seven of our own fleets and one outside fleet. The calculus is such that we need about one fleet for every three rigs.

So let’s say, for example, we were at 24 rigs at any particular time, we would need eight fleets. So we’re within the bandwidth. We might just refurb one of ours or bring in a third party. We’re evaluating it. It’s sort of a lease versus buy decision. Going further, though, we would have to make that decision in a bigger sense. That really becomes a 2020 issue, so we’d have to make the decision really in 2019.

Canada’s Energy Sector Faces Rough Waters

Canada’s Energy Sector Faces Rough Waters

Stiff U.S. competition, an inter-province pipeline row prolongs limited export opportunity, and U.S. is its only big export customer

 

With U.S. shale on a tear, imports are dropping

Total U.S. crude production reached 10 MMBOPD in November 2017 and the Canadian Industrial Outlook report from The Conference Board of Canada estimates that U.S. production will pass 11 MMBOPD in 2019, putting Russia and Saudi Arabia in the rearview mirror.

This means that Canadian E&Ps will have to compete with the U.S. for investors and pipeline takeaway as production from the Permian, STACK/SCOOP, Eagle Ford and other big U.S. shale plays continue its growth spurt.

The U.S. is the number one buyer of Canada’s energy products. Largely from oil sands heavy oil production sent to Gulf coast refineries.

U.S. is prime customer for Canada’s heavy oil: IHS

A new report out this week from HIS Markit said that one third of the U.S. Gulf coast heavy oil market could be supplied by Canada by 2020.

As supplies from Mexico, Venezuela and other competitors wane, Canadian supply is increasing its share of refining runs in the world’s largest heavy oil market.

Supplies of Canadian oil sands heavy crude being refined on the U.S. Gulf coast could top 1.2 million barrels per day (MMBOPD)—a full one-third of the region’s heavy oil refining market—by 2020, according to the report by IHS Markit.

Current runs of Canadian crude in the USGC market are estimated to already be in excess of 800,000 barrels per day, the report says.

Imports from Canada in the U.S. Midwest have joined renewed U.S. domestic light oil to collectively displace nearly all other imports, the report said.

The U.S. Gulf Coast is home to the world’s highest concentration of heavy oil refineries, with in excess of 90 percent of the heavy oil supplied to them from imports.

But supplies from some traditional sources of these imports are waning. Over the past five years, production from Mexico and Venezuela—two key oil sands competitors—has declined by nearly 1 MMBOPD.

IHS Markit believes that Canadian heavy oil imports may be simply “stopping off” at Cushing, Oklahoma, in the U.S. Midwest—where they have already exceeded demand in that market—before being rerouted to the Gulf coast. Due to the way imports are often tracked, these imports would be counted as having been delivered into Cushing rather than to their final destination.

“The U.S. Gulf Coast is the most logistically approximate and technically suited to receive increasing volumes of heavy oil from Canada,” said Kevin Birn, executive director – IHS Markit, who heads the Oil Sands Dialogue. While the United States provides security of demand for Canada, there are risks to overreliance, the report points out.

The IHS Markit forecast assumes the completion of all the country’s remaining long-distance export pipelines. If those projects were delayed or Canadian or other heavy oil supply is more prolific than anticipated, Canada may have to compete more aggressively for market share in the United States—something it has not yet had to do.

“Although Canadian imports are of similar quality as Latin American crudes, they are not identical. There is a point when more extensive modifications will be required to better tailor facilities to accommodate greater volumes of the Canadian heavy crude,” said Birn. “In a situation where the level of competition is high, Canadian crude may have to adjust price to incentivize refiners to make additional modifications and/or displace greater quantities of offshore imports.”

Alternative diversification strategies—such as customizing oil sands blends or developing upstream partial processing technologies that would result in the marketing of a greater range of crude oil qualities—can help mitigate the risks.

“These solutions would not remove the risk and would still take considerable investment and time,” the report said.

“The reality is that Canada—the 5th largest oil producer in the world—maintains an almost singular reliance on one market,” Birn said. “Such a situation is unique in the world and will always carry associated concerns.”

“New pipelines that provide access to tidewater will be crucial for Canada to develop new export markets given that Canada’s biggest export market for oil, the United States, is ramping up its own production,” said Michael Burt, director of industrial economic trends at The Conference Board of Canada.

Canada’s Energy Sector Faces Rough Waters: Stiff U.S. Competition, an Inter-Province Pipeline Row, Limited Export Opportunity with U.S. as its Primary International Customer

Pipeline capacity in Western Canada simply can’t keep up with production. According to Bloomberg, Western Canadian crude production will exceed the pipeline capacity to carry it away by 338 MBOPD by the end of 2018.

Canada’s Energy Sector Faces Rough Waters: Stiff U.S. Competition, an Inter-Province Pipeline Row, Limited Export Opportunity with U.S. as its Primary International Customer

The EIA estimated that Canada produced 4.9 MMBOPD in 2017. But due to the backed-up railways, export-by-rail has resulted in higher costs and reduced profits for Canadian E&Ps. At the time of this article, Western Canadian Select (WCS) was around $50/bbl, while WTI was around $65/bbl.

Differential is costing Canadian producers $10 billion a year: Scotiabank

Scotiabank estimates that the forgone profits due to the price differential between Canadian and U.S. oil will cost Canada more than $10 billion this year, or 0.5% of GDP.

The B.C.-Alberta pipeline dispute

More U.S. domestic production and less dependence on imports will amplify the economic effects of Canada’s B.C.-Alberta dispute. Yesterday, The Globe and Mail reported that Alberta Premier Rachel Notley went so far as to offer up buying the Trans Mountain pipeline from Kinder Morgan, using taxpayer money to ensure that Canadian energy products reach oversea markets in Asia.

But British Columbia, which has strongly opposed to fossil fuel projects, didn’t flinch. “Certainly the Premier of Alberta is entitled to do whatever she wants within her borders. If she wants to invest in a pipeline, that’s her business,” B.C. Premier Horgan told the media.

Don’t count Canada out just yet

The Canadian Industrial Outlook forecasts that Canada’s oil industry will return to profitability in 2018. The report said companies have become more efficient – output per worker has increased by 15.4% over the last five-years. Canada’s oil industry will have to increase productivity even more to remain competitive. For example, current U.S. rigs are nearly 3.1 times more productive than January 2014 rigs.

According to the Canadian Industrial Outlook, total crude production in Canada is forecasted to rise by an average annual rate of 3.4% between 2018 and 2022 and the vast majority of that increase will come from oil sands, while offshore production and diluent production will make up the remainder.

Canada’s Energy Sector Faces Rough Waters: Stiff U.S. Competition, an Inter-Province Pipeline Row, Limited Export Opportunity with U.S. as its Primary International Customer

With prices and production both on the rise, industry revenues are forecasted to increase by about 8% in 2018, the Outlook said. However, employment gains will be modest due to efficiency gains and cost-containment – the Canadian oil industry is expected to create 2,150 new jobs over the next five-years.

Industry pre-tax profits are expected to reach $1.4 billion this year, the Outlook reported.

Canada’s Energy Sector Faces Rough Waters: Stiff U.S. Competition, an Inter-Province Pipeline Row, Limited Export Opportunity with U.S. as its Primary International Customer

What about Canada’s existing pipelines, expansions and newbuilds?

Enbridge’s Line 3 Replacement Project will come online in 2019 – currently it is conditionally approved by Canada’s federal government, and it should add about 0.37 MMBOPD takeaway capacity. According to Enbridge, the Line 3 Replacement is a multi-billion dollar private investment consisting of 1,031 miles of 36-inch diameter pipeline beginning in Hardisty, Alberta and ending in Superior, Wisconsin.

The disputed Trans Mountain Expansion (TME), also conditionally approved by Canada’s federal government, will need Prime Minister Justin Trudeau’s constitutional powers to snap British Columbia’s political opposition to the project. If approved, the TME will add another 0.59 MMBOPD starting in 2021, along with the Keystone XL’s 0.83 MMBOPD. Assuming the Keystone XL receives final approvals of its amended route in Nebraska.

Canada’s Energy Sector Faces Rough Waters: Stiff U.S. Competition, an Inter-Province Pipeline Row, Limited Export Opportunity with U.S. as its Primary International Customer


One Third of the U.S. Gulf Coast Heavy Oil Market Could be Supplied by Canada by 2020, IHS Markit Report Says

As supplies from Mexico, Venezuela and other competitors wane, Canadian supply is increasing its share of refining runs in the world’s largest heavy oil market

Supplies of Canadian oil sands heavy crude are increasingly being refined on the U.S. Gulf Coast (USGC) and could top 1.2 million barrels per day (mbd)—a full one-third of the region’s heavy oil refining market—by 2020, says a new report by business information provider IHS Markit (ticker: INFO).

Current runs of Canadian crude in the USGC market are estimated to already be in excess of 800,000 barrels per day (bpd), the report says.

Entitled Looking South: A Canadian Perspective on the U.S. Gulf Coast Heavy Oil Market, the Oil Sands Dialogue report says that the increasing volumes into the USGC refining market is coming at an opportune time for both nations. Imports from Canada  have exceeded demand in their traditional import market—the U.S. Midwest—where they have joined renewed U.S. domestic light oil to collectively displace nearly all other imports.

The U.S. Gulf Coast is home to the world’s highest concentration of heavy oil refineries and more than 90 percent of the heavy oil supplied to them comes from imports. But supplies from some traditional sources of these imports are waning. Over the past five years, production from Mexico and Venezuela—two key oil sands competitors—has declined by nearly 1 mbd. This is increasing the need for Canadian heavy crude oil of similar quality, the report says.

The 800,000 bpd estimate for current runs of Canadian crude in the USGC is already significantly higher than many other estimates. IHS Markit believes that Canadian heavy oil imports may be simply “stopping off” at Cushing, OK in the U.S. Midwest—where they have already exceeded demand in that market—before being rerouted to the Gulf coast. Due to the way imports are often tracked, these imports would be counted as having been delivered into Cushing rather than to their final destination.

“The U.S. Gulf Coast is the most logistically approximate and technically suited to receive increasing volumes of heavy oil from Canada,” said Kevin Birn, executive director – IHS Markit, who heads the Oil Sands Dialogue. “With supply overtaking demand in the U.S. Midwest and traditional sources of offshore heavy supply to the Gulf Coast in decline, Canadian supply has become an obvious and attractive alternative.”

Increased volume in the USGC market would raise Canada’s already sizeable reliance on the U.S. oil market, however. And while the United States provides security of demand for Canada, there are risks to overreliance, the report says.

The IHS Markit forecast assumes the completion of all the country’s remaining long-distance export pipelines. If those projects were delayed or Canadian or other heavy oil supply is more prolific than anticipated, Canada may have to compete more aggressively for market share in the United States—something it has not yet had to do.

“Although Canadian imports are of similar quality as Latin American crudes, they are not identical. There is a point when more extensive modifications will be required to better tailor facilities to accommodate greater volumes of the Canadian heavy crude,” said Birn. “In a situation where the level of competition is high, Canadian crude may have to adjust price to incentivize refiners to make additional modifications and/or displace greater quantities of offshore imports.”

Alternative diversification strategies—such as customizing oil sands blends or developing upstream partial processing technologies that would result in the marketing of a greater range of crude oil qualities—can help mitigate the risks. However, given the scale of Canadian heavy oil supply today and anticipated growth, these solutions would not remove the risk and would still take considerable investment and time, the report concludes.

“The reality is that Canada—the 5th largest oil producer in the world—maintains an almost singular reliance on one market,” Birn said. “Such a situation is unique in the world and will always carry associated concerns.”

Halliburton Nisku, Alberta Canada
Victor Gribansiciy
November 2006

American Energy Imports Lowest Since 1982

U.S. continues to import less while exporting more

Total net energy imports to the United States fell to 7.3 quadrillion BTUs (quads) in 2017, a 35% decrease from 2016 and the lowest level since 1982, when both gross imports and gross exports were much lower, the EIA said today in a new report.

Gross energy imports have been generally decreasing from a high of 34.7 quads in 2007; however, the larger factor leading to the reduction in the net energy trade balance has been increasing energy exports.

Gross energy exports rose to 18 quadrillion BTUs in 2017, a 27% increase from 2016 and the highest annual U.S. energy exports on record.

American Imports Lowest Since 1982

U.S. Gross Net Energy Trade (1950-2017), Mar. 2018

Increasing U.S. energy exports have been driven largely by increases in exports of petroleum products and natural gas. In recent years, exports of crude oil have also contributed to the overall rise in energy exports after crude oil export restrictions were lifted at the end of 2015. In energy content terms, the United States now exports nearly as much energy in the form of crude oil (2.3 quads) as coal (2.5 quads).

In 2017, the United States saw substantial increases in exports of all fossil fuels, with exports of crude oil (89% higher than in 2016), petroleum products (11% higher), natural gas (36% higher) and coal (61% higher) all increasing over the prior year.

Exports of crude oil and petroleum products both reached record levels, the EIA said. Petroleum products such as gasoline, distillate fuel, propane and other fuels currently make up the largest share (54%) of U.S. energy exports.

American Imports Lowest Since 1982

U.S. Gross Exports (1950-2017), Mar. 2018

The United States became a net exporter of petroleum products in 2011 and natural gas in 2017. In 2017, the United States was a net exporter of coal, coal coke, petroleum products, natural gas, and biomass, but a net importer of crude oil. Net electricity trade with Mexico and Canada was relatively minimal.

An increase in total U.S. energy production contributed to the decline in net imports in 2017, led by production increases in renewable energy (8%), especially hydropower and wind, as well as production increases in coal (6%), natural gas plant liquids (6%), crude oil (5%) and natural gas (1%).

Total U.S. energy consumption was virtually unchanged from the previous year’s level.

American Imports Lowest Since 1982

Energy Production, Energy Trade, Mar. 2018

Tellurian Keeps Sailing

Tellurian Keeps Sailing

Tellurian Inc. (ticker: TELL) wrapped up its first year as a public company, ending 2017 with $128.3 million of cash and cash equivalents. The company remains debt free, but reported a net loss of $231.5 million, or $(1.23) per share as it ramps up permitting and preconstruction phases for its Driftwood LNG plant on the Louisiana Gulf coast. Driftwood is targeting a 2019 groundbreaking.

The company bought natural gas resources in 2017 and has approximately 327 Bcfe of proved natural gas reserves. Tellurian President and CEO Meg Gentle said, “Tellurian is developing asset opportunities representing $29 billion of near-term investments…”

Bechtel invests $50 million in Tellurian

Bechtel Oil, Gas and Chemicals, Inc. recently made a $50 million, zero-coupon preferred equity investment in Tellurian, which has an implied Tellurian common share price of $8.16 per share.

Brendan Bechtel, chairman and CEO of Bechtel Group, Inc. said, “Tellurian management and Bechtel have worked together for many years and we look forward to continuing our success as equity partners.”

Gentle said, “Bechtel and Tellurian management have constructed 55 Mtpa of liquefaction capacity together on various projects and have formed a respected and productive relationship. We are fortunate to have such strong strategic partners including Bechtel, GE and Total and look forward to breaking ground at Driftwood LNG in 2019.”

Permian pipeline open season

Tellurian’s subsidiary, Permian Global Access Pipeline LLC (PGAP) is looking to secure shippers for its proposed 625-mile long, 42-inch in diameter interstate natural gas pipeline. The pipeline will connect the Permian to southwest Louisiana.

PGAP is estimated to cost approximately $3.7 billion to construct and will have the capacity to transport 2 Bcf/d. Construction is projected to begin as early as 2021 and the proposed pipeline is aiming to be in service as early as 2022.

The open season began at noon central time on Wednesday, March 21, 2018 and runs through Friday, May 25, 2018.

Liquefied Natural Gas Plant, Australia

U.S. Crude Oil, NatGas Exports Both Hit New Highs

U.S. crude oil exports grew to an average of 1.1 MMBOPD in 2017, the EIA said, which is the second full year since restrictions on crude oil exports were removed. Crude oil exports in 2017 were nearly double the level of exports in 2016. Increased U.S. crude oil exports were supported by increasing U.S. crude oil production and expanded infrastructure, the EIA said.

U.S. Crude Oil Exports 1920-2017, Mar. 2018

U.S. Crude Oil Exports 1920-2017, Mar. 2018

According to the EIA, U.S. crude oil exports went to 37 destinations in 2017 – this compares to 27 destinations in 2016. As usual, Canada was the largest destination for U.S. crude oil exports. However, Canada’s share has gone down from 61% in 2016, to 29% in 2017.

U.S. crude oil exports to China accounted for 202,000 BPD (20%) of the 527,000 BPD total increase. China passed the United Kingdom and the Netherlands to become the second-largest destination for U.S. crude oil exports in 2017.

Plenty of European nations are receiving U.S. crude oil exports.  The United Kingdom, Netherlands, Italy, France and Spain are some of the nations that have been pumping in crude imports. India, which did not receive U.S. crude oil exports in 2016, received 22,000 BPD in 2017. India tied with Spain as the 10th largest destination.

U.S. Crude Oil, NatGas Exports Both Hit New Highs

U.S. Crude Oil Export Destinations 2017, Mar. 2018

Crude oil now makes up 18% of total U.S. petroleum exports, the EIA said, making it the third-largest petroleum export after hydrocarbon gas liquids (HGL) and distillate fuel. Before the restrictions on domestic crude oil exports were lifted in December 2015, most of the growth in U.S. petroleum exports was petroleum products—mainly HGLs (such as propane), distillate fuel and motor gasoline.

Previously, crude oil’s largest share of total U.S. petroleum exports was 13% in 1999, when total volumes of U.S. petroleum exports were less than 1 MMBOPD, which was much lower than the 6.3 MMBOPD total in 2017.

U.S. Crude Oil, NatGas Exports Both Hit New Highs

Total U.S. Crude Oil and Petroleum Exports, Mar. 2018

Increasing U.S. crude oil production and expansions of U.S. pipeline capacity and export infrastructure facilitated increased crude oil exports. U.S. crude oil production reached 9.3 MMBOPD in 2017, a 0.5 MMBOPD increase from 2016. The EIA’s March STEO forecasts U.S. crude oil production to increase by 1.4 MMBOPD in 2018.

60 years later, American natural gas returns to the spotlight

The United States exported more natural gas than it imported in 2017, making it the first time since 1957 that the U.S. has been a net natural gas exporter. The transition to net exporter occurred as natural gas production in the United States continued to grow, reducing pipeline imports from Canada and increasing exports, both by pipeline and as LNG.

U.S. Crude Oil, NatGas Exports Both Hit New Highs

U.S. Annual Natural Gas Trade 1975-2017, Mar. 2018

U.S. Crude Oil, NatGas Exports Both Hit New Highs

U.S. Dry NatGas Production 1975-2017, Mar. 2018

The United States surpassed Russia in 2009 as the world’s largest natural gas producer as shale gas production drove overall increases in natural gas production. Production reached an average of 73.6 Bcf/d in 2017, a 1% increase from the 2016 level and just slightly lower than the 2015 record level.

U.S. Crude Oil, NatGas Exports Both Hit New Highs

U.S. NatGas Exports, Mar. 2018

As the United States produced more natural gas, pipeline imports from Canada have decreased. With new pipeline capacity coming on line, more natural gas can be delivered to regions in the Midwest and Northeast, displacing Canadian imports and increasing U.S. pipeline exports to Canada.

U.S. natural gas pipeline capacity into Mexico has also increased over the past few years, driven by growth in demand for natural gas from Mexico’s power sector and favorable prices compared with natural gas supplied by LNG shipments, the EIA said.

U.S.-Mexico natural gas pipeline capacity is currently 11.2 Bcf/d, with another 3.2 Bcf/d of capacity scheduled to be added later in 2018. Pipeline exports to Mexico have grown along with pipeline capacity, more than doubling since 2014 and averaging 4.2 Bcf/d in 2017.

U.S. Crude Oil, NatGas Exports Both Hit New Highs

Annual U.S. LNG Exports by Destination 1975-2017, Mar. 2018

U.S. LNG exports increased dramatically over the past two years as new liquefaction capacity has come online. The only liquefaction terminal previously operating in the United States — the Kenai LNG terminal in Alaska — ceased operations in 2015.

In 2016, as the Sabine Pass LNG terminal in Louisiana began to ramp up operations, increasing U.S. LNG exports. Sabine Pass now has four operating liquefaction units, with a fifth currently under construction.

The Cove Point LNG facility in Maryland exported its first LNG cargo on March 1, 2018. Cove Point is the second currently operating LNG export facility in the United States, after Sabine Pass. Four other LNG projects are under construction and are expected to increase U.S. liquefaction capacity from 3.6 Bcf/d to 9.6 Bcf/d by the end of 2019.

EIA’s STEO projects that the United States will be a net exporter of natural gas in each month remaining in 2018 and each month of 2019 as pipeline exports to Mexico continue to grow along with LNG export capacity.