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Italy-Israel gas pipeline moves a step closer to reality

Plans to build a pipeline from Israel to Italy would also give access to the gas reserves of Cyprus (pictured). [Shutterstock]


Cyprus, Greece, Israel and Italy on Tuesday (5 December) signed a memorandum of understanding to build the world’s longest underwater natural gas pipeline to supply Europe.

“The project will secure a direct long-term export route from Israel and Cyprus to Greece, Italy and other European markets… thereby strengthening EU’s security of supply,” a joint statement said.

It said the four states would also pool resources on studies for the construction and operation of the ambitious project, which is seen as technically and financially viable.

The pipeline to supply Europe with natural gas will be some 2,000 kilometres long, and is estimated to cost approximately €5 billion. It will have an annual capacity of 10-16 billion cubic feet, and could be completed by 2025.

Israeli energy minister Yuval Steinitz and his Cyprus and Greece counterparts, George Lakkotrypis and Giorgos Stathakis, attended the ceremony, as did the Italian ambassador to Cyprus, Andrea Cavallari.

The European Commission’s Deputy Director-General for Energy, Christopher Jones, was also present.


In April, representatives of the EU and the four nations signed a joint declaration to back the project to export gas to Europe from Israel’s Leviathan field and Cyprus’s Aphrodite bloc.

They decided to establish a working group to promote an interstate agreement, which could happen as early as spring 2018, during a meeting scheduled to be held on Crete.

The pipeline would connect the Leviathan field via the Aphrodite field, Crete, mainland Greece and Italy. It could become a more profitable venture if Israel and Cyprus discover additional major gas fields, thus lowering costs, although critics have pointed out that the price of gas and falling costs of renewable energy currently casts doubt on its financial viability.

Cyprus is currently the only EU member state that is not connected to another bloc member by either gas or electricity connections, which is not in keeping with the targets of the Energy Union.

In October, Nicosia and Athens agreed to press on with another large-scale energy project, the EuroAsia electricity cable, which would link Greece to Israel via Cyprus and Crete.

With a significantly shorter construction time, the 1,500km-long 2,000MW cable could be up and running by 2022. Costs are estimated to be around the €3.5bn mark.

By Sam Morgan | with AFP

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Enterprise to Ship More Permian Crude to Texas Gulf Coast

Enterprise to Ship More Permian Crude to Texas Gulf Coast

Enterprise says it will have more than 650,000 bpd of total crude pipeline capacity from Permian to Houston-area hub.

Enterprise Products Partners L.P. will convert one of its pipelines linking the Permian Basin to the Texas Gulf Coast from natural gas liquids (NGL) to crude oil service, the company stated Wednesday.

“We have had strong demand for crude oil transportation, storage and marine terminal services for crude oil production from the Permian Basin,” A.J. “Jim” Teague, CEO of Enterprise’s general partner, said in a written statement. “This repurposing of an NGL pipeline to crude oil service is another example of our system flexibility and the innovation of our employees to respond to customer needs while increasing the distributable cash flow and value of our partnership.”

According to Enterprise, the conversion will give the partnership more than 650,000 barrels per day (bpd) of total crude oil pipeline capacity from the Permian Basin to its crude oil hub in the Houston area. Three Enterprise NGL pipelines already link the Permian to the Texas Gulf Coast: the Seminole Blue, Seminole Red and Chaparral. In addition, the partnership is building a fourth Permian-Texas Gulf Coast NGL pipeline – Shin Oak, which is slated for a Second Quarter 2019 in-service date.

Enterprise stated that Shin Oak will enable it to divert NGL volumes from at least one of its existing NGL pipelines and repurpose the vacated NGL pipeline to ship crude oil. The partnership added that it is currently evaluating which NGL pipeline(s) to repurpose.

Enterprise expects to complete the NGL-to-crude pipeline conversion during the first half of 2020.

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Mexico Says Deepwater Oil Tender Doomed By Brazil Competition

Mexico Says Deepwater Oil Tender Doomed By Brazil Competition

Pemex blames the cancellation of a potentially lucrative deepwater Gulf of Mexico project on weak investor appetite.


MEXICO CITY, Dec 8 (Reuters) – Mexican national oil company Pemex on Friday blamed the cancellation of a potentially lucrative deepwater Gulf of Mexico project on weak investor appetite due to competition from recent auctions in Brazil and low oil prices.

The country’s oil regulator on Thursday canceled a tender for its Nobilis-Maximino project, a joint venture with Pemex , as company interest was not as robust as initially expected.

On Friday, Pemex, known officially as Petroleos Mexicanos, cited a late October deepwater oil auction in Brazil for lessening interest in its project. Six of eight blocks in Brazil were awarded to majors, including Royal Dutch Shell and ExxonMobil.

“(One) factor that affected appetite for new projects was the investment commitment recently taken on by possible bidders,” Pemex said in a statement. Companies that won blocks in Brazil had looked at the Nobilis-Maximino data, it added.

Nearly 30 oil companies had begun the process of pre-qualifying for the Mexican auction, according to data from the National Hydrocarbon Commission, including U.S.-based Chevron and Britain’s BP.

The failure of the project is a setback for Mexico’s energy opening after a decades-long monopoly for Pemex.

Nobilis-Maximino sits in Mexico’s deepwater Gulf near the U.S.-Mexico maritime border in the productive Perdido Fold Belt, and is estimated to contain reserves of about 502 million barrels of mostly light crude.

More Fields Up

Nobilis-Maximino was due to be awarded on Jan. 31, along with another 29 similar deepwater projects. Those tenders, which are still going ahead, are potentially more attractive because companies can bid to develop them without tying up with Pemex.

Pemex said weak oil prices – with medium- and long-term oil price projections at $50-$65 per barrel – have also been a factor in oil companies exercising caution about taking on complicated, expensive deepwater projects like Nobilis-Maximino.

Pemex said it would consider a future farm-out, or joint venture, for the project.

“Pemex will continue to promote its partnership strategy in several oil fields that present less technical difficulties and lower risks,” the company said.

A landmark 2013-2014 energy reform allowed the firm to enter into equity partnerships with foreign and private producers for the first time, which had previously been barred by law.

The regulator selects Pemex’s partners via open auctions.

Late last year, Pemex cemented its first-ever joint venture in the deepwater Gulf with the tender of partnership rights to BHP Billiton at the $11 billion Trion project, located near Nobilis-Maximino.

(Reporting by Veronica Gomez and David Alire Garcia; Editing by Chizu Nomiyama and Rosalba O’Brien)

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Oil Rises Nearly 2% On China Demand, But Weekly Losses Loom

NEW YORK, Dec 8 (Reuters) – Oil prices rose almost 2 percent on Friday, helped by rising Chinese crude demand and threats of a strike in Africa’s largest oil exporter.

But U.S. prices fell 1.7 percent on the week and Brent prices fell 0.5 percent amid concerns that rising U.S. production could undermine OPEC-led supply cuts.

Brent crude settled up $1.20 or 1.9 percent at $63.40 a barrel.

U.S. West Texas Intermediate (WTI) crude settled up $57.36 a barrel, up 67 cents or 1.2 percent.

China’s crude oil imports rose to 9.01 million barrels per day (bpd), the second highest on record, data from the General Administration of Customs showed.

“We have good numbers out of China,” said John Macaluso, an analyst at Tyche Capital Advisors. “A lot of the extra imports are not from Saudi Arabia. Iran, Russia and the U.S. are some of the countries picking up the slack.”

Booming demand will push China ahead of the United States as the world’s biggest crude importer this year.

U.S. investment bank Jefferies forecast 2018 global oil demand growth of 1.5 million bpd, driven by almost 10 percent demand growth in China.

“Generally speaking, the market is looking more healthy than sick,” said Tamas Varga, analyst with PVM Oil Associates.

Varga said the threat of a strike later this month from a union in Nigeria, Africa’s largest oil exporter, was supportive.

An extension to the end of 2018 of production cuts by the Organization of the Petroleum Exporting Countries, Russia and other producers underpinned the market.

The output cuts pushed oil prices higher between June and October, with Brent gaining around 40 percent.

“Even if you have no bullish view … OPEC and Russia have taken away the risk to the downside,” said Bjarne Schieldrop, chief commodities analyst with SEB Bank, adding it was unlikely that Brent would drop below $61 per barrel.

Still, data this week showed that U.S. crude output had risen 25,000 bpd to 9.7 million bpd in the week to Dec. 1, the highest production since the 1970s and close to the production levels of Russia and Saudi Arabia.

U.S. energy companies this week added oil rigs for a third week in a row, the longest string of increases since summer, as higher crude prices prompted drillers to return to the well pad after a break in the autumn.

Drillers added two oil rigs in the week to Dec. 8, bringing the total count up to 751, the highest level since September, General Electric Co’s Baker Hughes energy services firm said in its closely followed report on Friday. <RIG-OL-USA-BHI>

Hedge funds and money managers cut their bullish bets on U.S. crude in the week to Dec. 5, the U.S. Commodity Futures Trading Commission (CFTC) said on Friday on fears of higher U.S. production.

(Additional reporting by Libby George in London, Henning Gloystein in Singapore; Editing by Rosalba O’Brien and Lisa Shumaker)

Copyright 2017 Thomson Reuters.

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Global Oil Sector Will Shift to Upcycle in 2018

Global Oil Sector Will Shift to Upcycle in 2018

The global oil and gas sector will shift from downcycle to upcycle in 2018, according to a new report from BMI Research.

The global oil and gas sector will shift from downcycle to upcycle in 2018, according to a new report from BMI Research.

“Oil prices reached their nadir in 2016 and have averaged c.20 percent higher on an annual average basis in 2017,” the report said.

“However, the recovery in price has yet to be fully reflected in the market,” the report added.

Many of the trends unfolding in the global oil sector over 2017 will remain in play next year, a BMI representative said in a statement sent to Rigzone.

BMI expects capex will continue to grow gradually at 4.3 percent and companies will continue to target margin, rather than revenue, accretive investments, with cost control remaining a key focus.

“Market conditions will likely be broadly supportive of M&A activity in 2018, with a more stable price environment, stronger balance sheets and tighter bid-ask spreads supporting deal making,” the report said.

“However, as was the case in 2017, asset purchases and divestments will largely be directed towards high-grading portfolios, rather than a blanket expansion of acreage or reserves,” the report added.


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US Jobs Report: Slight Increase in Oil, Gas Jobs

US Jobs Report: Slight Increase in Oil, Gas Jobs

After a month of slight declines, oil and gas employment inches up in November.

Keeping with its current trend, employment in mining remained steady for November, according to data released Dec. 8 from the U.S. Bureau of Labor Statistics. Jobs in oil and gas extraction increased by 200. But the biggest increase came in support activities for mining, with the addition of 4,100 jobs.

The small uptick seems to offset the prior month’s (October) employment statistics in which jobs in oil and gas extraction and support activities for mining decreased by 400 and 1,600 respectively. With the exception of October, oil and gas employment increased for all of 2017.

Moving forward, HR professionals in oil and gas have expressed there will be a need for skills around robotics and automation. While this has already affected the oilfield, in which some of the tasks formerly performed by roughnecks and roustabouts are being automated, employers maintain that this will not replace jobs, rather create new opportunities and new roles in the industry.

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Texas’ Austin Chalk Booms While Shale Plays Remain Mostly Dormant

Texas' Austin Chalk Booms While Shale Plays Remain Mostly Dormant

New technology applications are breaking records in the Austin Chalk.

Somewhere down the line, someone coined the phrase, “Big oilfields only get bigger.” Now an adage, the observation was made when large oilfields had reached peak production, only to reveal later they had much more to give when new technology was applied.

The Austin Chalk formation, which sits right on top of the Eagle Ford formation, was a hot play in the mid-1900s, mid-1970s and 1990s. However, it was all but forgotten during the shale boom when the Eagle Ford formation took front and center. With the majority of shale plays still on the shelf, the Austin Chalk is back on the radar and stronger than ever, proving a prominent contender in the ever-growing oilfield category.

“Discussing the Austin Chalk again is very much a surprise to us,” said William R. Thomas, chairman and CEO of EOG Resources, Inc., during a recent energy conference.

EOG is one of the largest operators in both the Eagle Ford and Austin Chalk plays.

“We, probably like the rest of the industry, had kind of written off the Austin Chalk,” Thomas said. “But we have discovered a new geologic concept in an existing play in the Eagle Ford. Our team has cracked the code on how to make our particular footprint in the Austin Chalk – a top-tier horizontal play, earning returns on par with the Eagle Ford, Permian and Bakken plays.”

Two of EOG’s wells, the Leonard AC Unit 101H and the Denali Unit 101H, produced an average of 2,175 and 3,130 barrels of oil equivalent per day over 30-day and 20-day periods, respectively. Its Kilimanjaro 101H well produced 675,000 barrels of oil and 1.2 billion cubic feet of gas in just nine months. The wells are located in the Giddings Field – the largest field in the Austin Chalk – in southeast Texas.

Noting that other operators have wells in the Austin Chalk that have produced 300,000 to 400,000 barrels of oil in their first years, David W. Trice, EOG executive vice president of Exploration & Production, called the discoveries “substantial.” “Based on the data we have, we think they are repeatable,” he said in a statement to stakeholders last year.

Other operators think so as well. Companies including EnerVest Ltd., GeoSouthern Energy, Blackbrush Oil & Gas, Gulftex Energy, Marathon Oil Corp. and WildHorse Resource Development have leased thousands of acres in the Giddings Field spanning seven counties, including the prolific Karnes, Fayette, Washington and Gonzales counties, near the state’s capitol.

Austin Chalk Comeback

The Austin Chalk, which extends from Mexico across south and east Texas and into Louisiana, is sourced by the Eagle Ford formation. It was discovered in the 1920s and began significantly producing in the 1950s with vertical wells. Much of the formation is naturally fractured, and vertical wells that happened to tap into those fractures had good shows, explained Duane Wagner, a technical advisor of geology at EnerVest, to Rigzone. However, this was predominantly a hit-or-miss operation.

Having begun his career in the Chalk, Wagner has watched the Giddings Field ebb and flow over the decades as new technology has come onto the scene.

The City of Giddings No. 1 well, drilled in 1961 by Union Producing Company, produced roughly 36,000 barrels of oil from 1961-1972. When it was hydraulically fractured for the first time in 1973 by C.W. “Chuck” Alcorn, Jr., the result was a production spike of more than 500,000 barrels by 1981.

“That was an eye-opener,” Wagner said.

Operators were quick to grab available 2-D seismic data to identify the natural fractures in the formation and began hydraulically fracturing them. Many wells produced several hundred thousand barrels over their lifetimes.

Horizontal drilling was introduced in the Austin Chalk in 1988 and accelerated in the early 1990s, making it much easier for operators to tap into the naturally fractured reservoir.

“It took most of the risk out of drilling in the Chalk,” Wagner said. “It was very much like a sure thing.” From 1990-95, nearly 4,000 wells were drilled in the Giddings Field. Today, EnerVest operates nearly 1,100 of them.

It wasn’t too long before operators discovered that the horizontal wells produced even more hydrocarbons when mildly stimulated with water and sand. The Austin Chalk was simply a phenomenal play.

Whatever excitement it had generated, though, the Chalk was quickly erased by the shale boom. The combination of horizontal wells, multi-stage drilling completions and hydraulic fracturing became the golden ticket for extracting oil from source rocks in the Eagle Ford, Bakken and Marcellus formations, doubling the United States’ oil production to 9.5 million barrels a day from 2011 to 2015.

The Austin Chalk was cast aside – until oil prices dropped to $30 a barrel and shale plays were no longer economical.

A handful of operators in the Eagle Ford needed to bide their time and hold their leases, so they took advantage of the double-stacked play roughly two years ago and began drilling in the Chalk with the same rigs, crews and technology they had used in the Eagle Ford. With many service companies offering a 30 percent discount and Chalk wells not requiring near the drilling depth, drilling in the Chalk was economically feasible and, to some, worth the gamble.

Old Dog, New Tricks

Many areas of the Austin Chalk that were once undesirable because of low porosity and low permeability have become sweet spots today.

Karnes County and areas outside the naturally-fractured fairway in Giddings County are very similar to the Niobrara play in Colorado’s DJ Basin, requiring that they be treated as a shale play, using multi-stage, high density stimulation. After such treatment, production from EnerVest Austin Chalk wells in Karnes County produce 250,000 to 300,000 barrels of oil in their first year, with ultimate recoveries of up to 1 million barrels of oil equivalent, Wagner said.

“Operators are drilling in areas where they would not have drilled in the ‘90s because these areas had fewer natural fractures,” he said. “But they are completing these wells just like they would in the Eagle Ford and are finding that they are actually more productive. Now you’ve got operators moving all up and down this trend.”

EOG, which has drilled more than 2,000 wells in the Eagle Ford and Austin Chalk formations, has expressed confidence over additional success in the Chalk.

“We’ve delineated what we think is a zone or multiple pay zones,” said Lloyd W. Helms, Jr., EOG executive vice president for Exploration & Production, in a statement. The Austin Chalk “lends itself really well to horizontal drilling and the high-density completions that we are doing in most of our other plays. We’re excited about the potential here.”

To date, the formation has produced 1.7 billion barrels of oil equivalent from roughly 9,500 wells, and it appears that the hydrocarbons will continue to flow.

“These wells are absolutely amazing,” Wagner said. “We are going to see million-barrel wells. This has been a game-changer.”


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OPEC could face challenge from shale if US producers abandon discipline mantra

A coalition of major oil-producing nations on Thursday is expected to extend a pact to keep some crude off the market to support oil prices and curb a worldwide glut created three years ago by U.S. drillers.

At a closely watched gathering in Vienna, the Organization of Petroleum Exporting Countries will consider a nine-month extension for a deal with Russia and other nations to trim output by 1.8 million barrels a day through the end of next year.

So far the effort appears on track, analysts say, but even if all goes to plan, OPEC still faces a dilemma: its rivals in West Texas and Oklahoma may still impede the group’s efforts and stall the long-anticipated rebalancing of the oil market again if prices rise high enough to tempt U.S. shale producers to abandon their recently adopted mantra of financial discipline.

Even though several major U.S. oil companies have promised investors they plan to throttle back operational growth and focus more on returning profits to shareholders next year – with some going so far as to make financial discipline part of executive compensation – high oil prices have historically led to land rushes and drilling surges by companies guided not by national fiat, but profits.

This time last year, when OPEC and its partners first announced an agreement to curb supplies, crude prices soared, U.S. oil companies dispatched hundreds of drilling rigs and economic activity surged in Houston for months. But market and industry enthusiasm waned in mid-2017 amid fears a second shale boom would offset OPEC’s output reductions and undercut prices.

The latest wrinkle is that U.S. oil companies have said they will only drill as long as they can make returns on the crude they pump. Whether they do could determine if Houston’s recovery gains momentum or stalls.

“It’s hard to believe they can keep their fingers off the levers,” said Bill Gilmer, director of the Institute for Regional Forecasting at the University of Houston. “Someone is going to be tempted, and as soon as one goes for it, they’re all going to.”

OPEC’s production-cut agreement, reached last fall between two dozen countries and renewed over the summer to run through March, has cut deep into bulging crude stockpiles around the world, reducing inventory levels from 338 million barrels above historical norms in January to 138 million barrels in September.

But in the United States, at $54 a barrel oil, crude production growth in 2018 could double this year’s gains, growing at an annual average of 700,000 barrels a day, compared with 365,000 barrels a day this year, said Mike Wittner, an oil-market analyst at French bank Société Générale. In the first half of next year, the bank believes global oil inventories could rise by 300,000 barrels a day.

U.S. oil prices slid 22 cents in early trading on Tuesday to $57.89 a barrel amid market jitters over whether Russia will play ball with OPEC. But if a deal goes through, as analysts expect, higher crude prices could provide financial cover for U.S. oil companies to drill more.

“For most of these guys, $60 oil means they have cash flow for the first time in many years, after cutting and cutting, when most were planning for oil prices around $50,” said R.T. Dukes, an analyst at energy research firm Wood Mackenzie. “Does extra cash flow mean they’re going to blow out their balance sheets again? Some will. Growth rates will probably grow higher, but I’m not sure they’ll spend at all costs.”


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ExxonMobil To Merge Refining And Marketing Divisions

ExxonMobil To Merge Refining And Marketing Divisions

ExxonMobil says it would merge its refining and marketing divisions in the first quarter of 2018.

Dec 1 (Reuters) – Exxon Mobil Corp is merging its refining and marketing divisions as part of Chief Executive Darren Woods push to reorganize the company’s refining operations amid volatile oil and natural gas prices.

Exxon said on Friday the combination of the two units will happen in the first quarter of 2018 and named Bryan Milton president of the merged entity, which will be called ExxonMobil Fuels & Lubricants Co.

Milton, 53, who joined the company in 1986, is currently president of ExxonMobil Fuels, Lubricants & Specialties Marketing Co.

Woods took over the top job in January after former chief Rex Tillerson resigned to become U.S. secretary of state.

(Reporting by Ankit Ajmera in Bengaluru; Editing by Anil D’Silva)

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Oil Price to Rise in 2H18 with OPEC, NOPEC Cut Extension

Oil Price to Rise in 2H18 with OPEC, NOPEC Cut Extension

Supply-demand balance expected to tighten in second half of 2018.

The OPEC and NOPEC agreement to keep current production restraints in place through 2018 will contribute to an oil price increase in the second half of next year, according to Wood Mackenzie.

“The stakes were high for OPEC,” Ann-Louise Hittle, Wood Mackenzie vice president of oils research, said in a statement sent to Rigzone.

“Despite the success in cutting output and follow-on price recovery, if the agreement had ended in March 2018, our forecast shows there would have been a very large 2.4 million barrels per day year-on-year increase in total world oil supply for 2018,” she added.

“That would have led to a persistent oversupply for every quarter of 2018,” Hittle continued.

With the extension in place, Wood Mackenzie expects the supply and demand balance to tighten in the second half of next year, which will help lift prices during the period. The research and consultancy firm expects a pullback in the first half of 2018 because of a resumption of oversupply in the first two quarters.

Oil and gas analysts at investment banking firm Jefferies suggested the latest production cut extension deal was widely anticipated, which explains the ‘muted’ immediate oil price reaction.

“We expect this outcome has been a consensus view (and has been our base case for several months), and thus the oil price reaction was muted,” analysts said in a statement sent to Rigzone.

At the time of writing, the price of Brent Crude stood at $63.2 per barrel, a slight increase from the $63.1 per barrel figure on Nov. 29, the day before the latest OPEC meeting.

Following the production cut extension announcement, several analysts warned of the impact of U.S. oil output on the sector, with Rystad Energy markets team leader, Nadia Wiggen, suggesting it would have been better for OPEC if U.S. producers were kept guessing.

“We actually recommended that OPEC not extend the deal beyond June 2018 at this November meeting and instead discuss a further extension at the next OPEC meeting,” Wiggen told Rigzone.

“Our reasoning is we believe it is better for OPEC that shale producers are less certain about OPEC policy and oil price strength, heading into 2018,” she added.

Rystad believes that a $55+ per barrel WTI price environment in December 2017 through 2018 would further encourage activity by U.S. shale producers and result in a year on year output growth of 1.1 million barrels per day.

“As a result, we are concerned that the market will see large stock builds 4Q18,” Wiggen said.

Wood Mackenzie also acknowledged the effect of U.S. producers, with Hittle stating that the mid-2018 review of the agreement could be warranted “due to several uncertainties that could shift the fundamentals for 2018”.

“These include political risk to oil supply, level of recovery from Libya and Nigeria, and rate of growth in U.S. oil production during 2018,” Hittle said.

Abhishek Kumar, senior energy analyst at Interfax Energy’s Global Gas Analytics in London said member countries involved in the deal were under no illusion regarding the contribution of, and incremental growth, in U.S. tight oil output.

“They will keep a close eye on the U.S. oil production profile and will not shy away from taking appropriate steps to counter its impact,” Kumar told Rigzone.

On Thursday, OPEC and participating NOPEC countries agreed to extend production cuts to December 2018. A further meeting to evaluate this plan is expected to take place in June next year.

“In agreeing to this decision, member countries confirmed their continued focus on a stable and balanced oil market, in the interests of both producers and consumers,” OPEC said in an organization statement released Dec. 1.