Is $60/Bbl WTI still considered a break even for Shale Oil

Seen a lot of articles which on their own flip flop through the text and certainly contradict a previous article just the word “could” in an article drains my attention.

What is the current actual break even price for Shale on average, given that some plays do cost more than others??

 

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Currently taking a slight dive

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17 minutes ago, James Regan said:

Seen a lot of articles which on their own flip flop through the text and certainly contradict a previous article just the word “could” in an article drains my attention.

What is the current actual break even price for Shale on average, given that some plays do cost more than others??

 

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That's a very complicated question.  There are a lot of variables that can change the cost mix.

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9 minutes ago, Oil_Engineer said:

That's a very complicated question.  There are a lot of variables that can change the cost mix.

This market is crazy almost a 10% drop in a month, while most articles are leaning on a bull 🐮 

 

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1 minute ago, James Regan said:

This market is crazy almost a 10% drop in a month, while most articles are leaning on a bull 🐮 

 

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That's right.  With the current level of global instability, especially in oil producing regions, oil should be up, but it is trending down.

 

Crude stockpiles are up, which will apply downward pressure.  Oil demand growth has been revised recently, so optimism is down as well.

Winter is over in the northern hemisphere, so natural gas demand will fall off as well.

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(edited)

WTI is a trading market number, how can it be a breakeven price when the producers are not paid WTI?  Producers get paid on an averaged basis over a month, 30 days in arrears.  

Edited by wrs
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(edited)

1 hour ago, wrs said:

WTI is a trading market number, how can it be a breakeven price when the producers are not paid WTI?  Producers get paid on an averaged basis over a month, 30 days in arrears.  

So the market indicator WTI has no relevance to the Shale Industry?

Please excuse my ignorance as there are many types of Shale oil what would the benchmark be?

Edited by James Regan
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2 hours ago, James Regan said:

Currently taking a slight dive

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What difference an hour makes?

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13 minutes ago, AcK said:

What difference an hour makes?

Or Two

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3 hours ago, James Regan said:

So the market indicator WTI has no relevance to the Shale Industry?

Please excuse my ignorance as there are many types of Shale oil what would the benchmark be?

So I’m correct in saying that this will have no impact or “relevance” to any of the Shale oil indicators?🤔🤔🤔

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Looking at this I would say Shale oil price and the market indicator WTI are very relevant and closely linked.

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8 minutes ago, James Regan said:

Looking at this I would say Shale oil price and the market indicator WTI are very relevant and closely linked.

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Many lease producers get well head oil and gas prices that are below WTI and grade specific posted prices, so they run far below the benchmark for the region or even specific grade posted prices.

My international crude sales agreement are based on Brent (DTD) , TAPIS and or other benchmarks that are 6-10$/bbl more than WTI and adjusted or revised as needed.

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4 hours ago, James Regan said:

So I’m correct in saying that this will have no impact or “relevance” to any of the Shale oil indicators?🤔🤔🤔

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I would not say that. Every single shale oil independents presentation I have seen (CLR 1Q recently) benchmarks itself to wti prices (mostly realized prices are at discount). In future of course as US starts to export more - Brent will incrementally become more imp. My sense is one of the advantages integrated oil has over independent shale is preferential access to pipeline-export infra - hence the supposed consolidation argument. Although this is a near term advantage as infra will step up over time.

Caveat - no expert on this particular topic. My 2 cents. Lot of people in the comm who can shed much better light on this topic.

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@James Regan,I believe what @wrsis saying is that no real producer sells to the spot price of WTI. If they have any sense at all they're locked into some kind of long term contract, or as he said, an averaged price computed retroactively. I seem to recall Hamm looking like a genius because he had hedged so much of Continental's production when prices were dropping in 2014. He didn't look so smart when he was obligated to put those same barrels at a 30% discount to the market years later. 

But you asked a good question, which should be separated from the vagaries of spot pricing. Regardless of what oil is Getting, how much is it Costing? If this were simple manufacturing, one could use Standard Costing as taught in 3rd year accounting. Direct costs to produce with some additional surcharge to cover indirect and capital costs. Of course standard costing is more art than science and tends to be all over the place within the same industry. The number only has to be defensible, not necessarily accurate. ;)

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11 hours ago, James Regan said:

This market is crazy almost a 10% drop in a month, while most articles are leaning on a bull 🐮 

 

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Was the market crazy when it jumped 15% in January? Or is it just crazy when the direction does not conform to your wishes?

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10 hours ago, William Edwards said:

Was the market crazy when it jumped 15% in January? Or is it just crazy when the direction does not conform to your wishes?

@William EdwardsNo and No, figure of speech, I appreciate your feedback. Yesterday was just a regular day that managed to dominate the headlines.

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22 hours ago, James Regan said:

So the market indicator WTI has no relevance to the Shale Industry?

Please excuse my ignorance as there are many types of Shale oil what would the benchmark be?

There isn't one which makes it more difficult for people to assess shale.  There is a discount on the API if it's too far from the spec which is I believe anything from 37-42.  So heavier grades get a discount as well as lighter grades.  I have oil in different categories.  Some of the new wells are just barely inside the spec at 41 while others are above 50.  Even though the lighter oil is better for gasoline and naptha it isn't the most desired feedstock on the gulf.  

A lot of the shale gets mixed with Canadian oil at Cushing to meet the spec or it's sold directly to refiners who mix it with other heavy oil from Venezuela or other middle east suppliers.  The other factor that affects the price that producers receive is the much ballyhooed pipeline discount from Midland to Cushing.  That has eased because an west to east pipeline opened up in February which will take oil from the Permian to Houston.  Those discounts were costing as much as $20/bbl for some operators late last summer and early fall.  When WTI was $75, we were getting $56.  This March the discount has mostly been eliminated and so WTI averaged 58 and we got 56 which is more like only the discount for being too light.

In my experience, WTI is rarely representative of what I get paid from my various shale leases.  I did read that there is a group trying to put together a WTL category for the lighter oils.  It would be sourced out of Corpus Christi as there is good pipeline capacity between the Permian and CC that is expanding this year.

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2 hours ago, wrs said:

There isn't one which makes it more difficult for people to assess shale.  There is a discount on the API if it's too far from the spec which is I believe anything from 37-42.  So heavier grades get a discount as well as lighter grades.  I have oil in different categories.  Some of the new wells are just barely inside the spec at 41 while others are above 50.  Even though the lighter oil is better for gasoline and naptha it isn't the most desired feedstock on the gulf.  

A lot of the shale gets mixed with Canadian oil at Cushing to meet the spec or it's sold directly to refiners who mix it with other heavy oil from Venezuela or other middle east suppliers.  The other factor that affects the price that producers receive is the much ballyhooed pipeline discount from Midland to Cushing.  That has eased because an west to east pipeline opened up in February which will take oil from the Permian to Houston.  Those discounts were costing as much as $20/bbl for some operators late last summer and early fall.  When WTI was $75, we were getting $56.  This March the discount has mostly been eliminated and so WTI averaged 58 and we got 56 which is more like only the discount for being too light.

In my experience, WTI is rarely representative of what I get paid from my various shale leases.  I did read that there is a group trying to put together a WTL category for the lighter oils.  It would be sourced out of Corpus Christi as there is good pipeline capacity between the Permian and CC that is expanding this year.

The oil that is exported, if the pricing is done right , yields a price much higher than WTI. I export a lot of shale crude from API 38-47 that gets a premium when sold to European and Asian refiners, either Brent(DTD), or TAPIS, or over some other benchmark for the region it is going to , and also depending on market conditions and type of deal structure, can obtain additional premiums . I also export custom blends for EU and Asian refiners with blending of mid grade heavy, sour crudes with sweet light shale crudes (approx. 150,000bpd, a separate business segment) and it also includes the Eagle Ford, Bakken , Utica, Permian condensates of 50API and above. The condensates also get a premium on their own for export based upon the end user (used as petchem feedstock etc). In most cases, I doubt that the lease operator, royalty owner gets any benefits of export crude prices.

We own and operate over 300,000 acres of leases and also have JVs with other lease operators and producers to buy their crude and hydrocarbons streams for export. In most cases I share some of the export price benefits with the lease operators, producers.

At one point , I saw the discount spreads you mention as high as 30-35$/bbl, which was killing the shale and non shale producers alike.

Again, when most companies (equity investors, investors, operators etc), do their budgets for CAPEX and OPEX, they base everything on NYMEX or WTI and do not base the price of crude oil and or their other hydrocarbons streams on the regional basins prices where they will be operating and producing from. And therein lies a big problem in the disparity in what is projected and planned for and what they get for their products at the end of the day.

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15 minutes ago, ceo_energemsier said:

The oil that is exported, if the pricing is done right , yields a price much higher than WTI. I export a lot of shale crude from API 38-47 that gets a premium when sold to European and Asian refiners, either Brent(DTD), or TAPIS, or over some other benchmark for the region it is going to , and also depending on market conditions and type of deal structure, can obtain additional premiums . I also export custom blends for EU and Asian refiners with blending of mid grade heavy, sour crudes with sweet light shale crudes (approx. 150,000bpd, a separate business segment) and it also includes the Eagle Ford, Bakken , Utica, Permian condensates of 50API and above. The condensates also get a premium on their own for export based upon the end user (used as petchem feedstock etc). In most cases, I doubt that the lease operator, royalty owner gets any benefits of export crude prices.

We own and operate over 300,000 acres of leases and also have JVs with other lease operators and producers to buy their crude and hydrocarbons streams for export. In most cases I share some of the export price benefits with the lease operators, producers.

At one point , I saw the discount spreads you mention as high as 30-35$/bbl, which was killing the shale and non shale producers alike.

Again, when most companies (equity investors, investors, operators etc), do their budgets for CAPEX and OPEX, they base everything on NYMEX or WTI and do not base the price of crude oil and or their other hydrocarbons streams on the regional basins prices where they will be operating and producing from. And therein lies a big problem in the disparity in what is projected and planned for and what they get for their products at the end of the day.

My independent has a connection to the Cactus pipeline but I don't believe that he has any agreement in place on volumes.  I think he plans to but not sure where his negotiations are.  At the time of my last visit I think they were trying to figure out how much volume they should commit.  That would be key to the people trying to put together the WTL marker category.  They need to get delivery commitments and producers aren't sure about what kind of market there will be.  I hope it can work out to be a benefit to both sides.

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9 minutes ago, wrs said:

My independent has a connection to the Cactus pipeline but I don't believe that he has any agreement in place on volumes.  I think he plans to but not sure where his negotiations are.  At the time of my last visit I think they were trying to figure out how much volume they should commit.  That would be key to the people trying to put together the WTL marker category.  They need to get delivery commitments and producers aren't sure about what kind of market there will be.  I hope it can work out to be a benefit to both sides.

I am negotiating with several companies to see what volumes they can deliver to Corpus or Houston Ship Channel for WTL. I would love to get a combined volume of 100,000bpd+ for WTL is they can manage it.

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20 minutes ago, ceo_energemsier said:

Again, when most companies (equity investors, investors, operators etc), do their budgets for CAPEX and OPEX, they base everything on NYMEX or WTI and do not base the price of crude oil and or their other hydrocarbons streams on the regional basins prices where they will be operating and producing from. And therein lies a big problem in the disparity in what is projected and planned for and what they get for their products at the end of the day.

This. Of course analysts are lazy, so they just focus on spot pricing, which while it trends up and down is ultimately subservient to the futures contracts the refineries operate on. Imagine a refinery the size of Motiva trying to fill its production trains (635,000 bbls/day) on Spot pricing? Instead they have long term commitments and only poke into the spot market if one or more if their suppliers declared force majure. Otherwise if there's a tremendous bargain in the spot market they'll pick up as much as they can store, because that's just smart business. Then there's all the hedge funds who play in the market, and have no intention of ever picking up one ounce of the slimy stuff. 

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1 hour ago, wrs said:

My independent has a connection to the Cactus pipeline but I don't believe that he has any agreement in place on volumes.  I think he plans to but not sure where his negotiations are.  At the time of my last visit I think they were trying to figure out how much volume they should commit.  That would be key to the people trying to put together the WTL marker category.  They need to get delivery commitments and producers aren't sure about what kind of market there will be.  I hope it can work out to be a benefit to both sides.

Increased lighter crude production from west Texas and New Mexico has prompted new infrastructure to accommodate a segregated stream, sometimes referred to as West Texas Light (WTL).

New production from the Delaware formation of the Permian basin is trending lighter, limiting the amount of West Texas Intermediate (WTI) that can be blended. So crude of varying quality is combined to meet WTI pipeline specifications.

WTI requirements can vary slightly from pipeline to pipeline, but in practice the oil shipped is typically toward the lighter end of the allowable range, which for most lines cuts off at 44˚API gravity. For example, the Longhorn and BridgeTex pipeline specifications for WTI include gravity between 36˚-44˚API, but deliveries to Magellan's East Houston terminal have averaged 42.45˚APImonthly from June to November.

When more light crude is produced than can be blended to meet specifications, it needs to be segregated.

Batching the lighter production is not something new. Plains All American Pipeline has said that it moved segregated batches from the Permian to Corpus Christi on the Texas coast since April 2017, with the most common segregation in the 45˚-50˚API range. Plains has also shipped batches from Midland to Magellan's East Houston terminal by way of the BridgeTex and Longhorn pipelines, requiring segregated storage at both ends.

But the increase in lighter production is prompting new pipeline tariffs to include a lighter crude specification, falling between WTI and condensate but with varying dividing lines. Oil that would now be considered WTL may have been referred to as condensate previously.

One line that can ship the lighter crude is Enterprise Products Partners' new 575,000 b/d Midland-to-Sealy pipeline that carries crude for delivery to Houston. Its tariff contains specifications for "West Texas Light Sweet" from 44.1˚-49.9˚API gravity.

Plains' 500,000 b/d Sunrise pipeline expansion from Midland to Cushing started up in November. It is currently moving 300,000-350,000 b/d from Midland to Wichita Falls, with only about 220,000 b/d of that reaching Cushing. The line has tariffs from Loving County, Texas, to Cushing for four common streams, including one with 45˚-47.9˚API gravity — falling between WTI and condensate.

A WTL spot market has been slow to emerge although market sources say the segregated crude is shipping. Most discussion heard in the spot market for WTL has been for delivery at Enterprise's Midland terminal, with most recent bids and offers at a $1.50 and $0.25/bl discount to WTI Midland. Actual spot discussion has been scarce. Market sentiment suggests it is valued in Midland at a discount to the Argus WTI Midland price between roughly $1/bl and the midpoint of spot market discussion.

Volumes are heard to be sold predominantly at a discount to the Argus WTI Midland trade month average, on an "evergreen" basis, or on month-to-month terms.

But market participants predict WTL spot activity will increase as production rises and new pipelines are built, but large hikes are not expected to begin to come on line until mid-2019 or the third quarter.

In mid-2019, Enterprise plans to convert a natural gas liquids (NGL) pipeline to carry 200,000 b/d of crude from the Permian to Houston. In the third quarter, Plains' 670,000 b/d Cactus 2 pipeline project is expected to start partial service to the Corpus Christi area. And Epic Midstream is temporarily converting its 400,000 b/d NGL pipeline to crude conversion in the third quarter, from west Texas to Corpus Christi.

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7 minutes ago, ceo_energemsier said:

Increased lighter crude production from west Texas and New Mexico has prompted new infrastructure to accommodate a segregated stream, sometimes referred to as West Texas Light (WTL).

New production from the Delaware formation of the Permian basin is trending lighter, limiting the amount of West Texas Intermediate (WTI) that can be blended. So crude of varying quality is combined to meet WTI pipeline specifications.

WTI requirements can vary slightly from pipeline to pipeline, but in practice the oil shipped is typically toward the lighter end of the allowable range, which for most lines cuts off at 44˚API gravity. For example, the Longhorn and BridgeTex pipeline specifications for WTI include gravity between 36˚-44˚API, but deliveries to Magellan's East Houston terminal have averaged 42.45˚APImonthly from June to November.

When more light crude is produced than can be blended to meet specifications, it needs to be segregated.

Batching the lighter production is not something new. Plains All American Pipeline has said that it moved segregated batches from the Permian to Corpus Christi on the Texas coast since April 2017, with the most common segregation in the 45˚-50˚API range. Plains has also shipped batches from Midland to Magellan's East Houston terminal by way of the BridgeTex and Longhorn pipelines, requiring segregated storage at both ends.

But the increase in lighter production is prompting new pipeline tariffs to include a lighter crude specification, falling between WTI and condensate but with varying dividing lines. Oil that would now be considered WTL may have been referred to as condensate previously.

One line that can ship the lighter crude is Enterprise Products Partners' new 575,000 b/d Midland-to-Sealy pipeline that carries crude for delivery to Houston. Its tariff contains specifications for "West Texas Light Sweet" from 44.1˚-49.9˚API gravity.

Plains' 500,000 b/d Sunrise pipeline expansion from Midland to Cushing started up in November. It is currently moving 300,000-350,000 b/d from Midland to Wichita Falls, with only about 220,000 b/d of that reaching Cushing. The line has tariffs from Loving County, Texas, to Cushing for four common streams, including one with 45˚-47.9˚API gravity — falling between WTI and condensate.

A WTL spot market has been slow to emerge although market sources say the segregated crude is shipping. Most discussion heard in the spot market for WTL has been for delivery at Enterprise's Midland terminal, with most recent bids and offers at a $1.50 and $0.25/bl discount to WTI Midland. Actual spot discussion has been scarce. Market sentiment suggests it is valued in Midland at a discount to the Argus WTI Midland price between roughly $1/bl and the midpoint of spot market discussion.

Volumes are heard to be sold predominantly at a discount to the Argus WTI Midland trade month average, on an "evergreen" basis, or on month-to-month terms.

But market participants predict WTL spot activity will increase as production rises and new pipelines are built, but large hikes are not expected to begin to come on line until mid-2019 or the third quarter.

In mid-2019, Enterprise plans to convert a natural gas liquids (NGL) pipeline to carry 200,000 b/d of crude from the Permian to Houston. In the third quarter, Plains' 670,000 b/d Cactus 2 pipeline project is expected to start partial service to the Corpus Christi area. And Epic Midstream is temporarily converting its 400,000 b/d NGL pipeline to crude conversion in the third quarter, from west Texas to Corpus Christi.

This is all quite interesting, CEO, and we appreciate your providing us with the reality of what is happening in the field. Of course, this is all from the producers' perspective. And historically producers have presumed that their entire job is to get oil out of the ground and to the refiner or to the water. Somebody else will take responsibility for utilizing their production and, of course, pay the producer a fat price for his efforts.

But there is a big fat fly in this ointment. The quality of production must, eventually be adjusted to match the quality of the products that are derived from the crude. Who is responsible for making that match, particularly on a timely basis. And if there is a significant mis-match, as was recently the case of Canadian oil sands oversupply until the government stepped in to avoid $50/B discounts, what gives? The same quality-type mis-match appears likely as West Texas tries to push too much light oil into the market. Changing grades and specs can allow buyers to adjust prices to try to accommodate imbalances, but physical characteristics limit that activity. For an extreme but illustrative example, it is unlikely that WTL will ever supply an asphalt plant with feedstock.

In the past several months, about 2 MMB/D of ultra-light crude has replaced a similar quantity of heavy crude in the global market. That is equivalent to a million barrels a day of conversion capacity that was bestowed, without cost, upon the refining industry. But does the refining industry need that additional conversion capacity? Certainly not right now. So we will have a price problem. And because in our current futures-dominated pricing mechanism, the price will be set by the most desperate seller (or buyer), be prepared for ultra-low prices for ultra-light oil as this thing shakes out.

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2 minutes ago, William Edwards said:

This is all quite interesting, CEO, and we appreciate your providing us with the reality of what is happening in the field. Of course, this is all from the producers' perspective. And historically producers have presumed that their entire job is to get oil out of the ground and to the refiner or to the water. Somebody else will take responsibility for utilizing their production and, of course, pay the producer a fat price for his efforts.

But there is a big fat fly in this ointment. The quality of production must, eventually be adjusted to match the quality of the products that are derived from the crude. Who is responsible for making that match, particularly on a timely basis. And if there is a significant mis-match, as was recently the case of Canadian oil sands oversupply until the government stepped in to avoid $50/B discounts, what gives? The same quality-type mis-match appears likely as West Texas tries to push too much light oil into the market. Changing grades and specs can allow buyers to adjust prices to try to accommodate imbalances, but physical characteristics limit that activity. For an extreme but illustrative example, it is unlikely that WTL will ever supply an asphalt plant with feedstock.

In the past several months, about 2 MMB/D of ultra-light crude has replaced a similar quantity of heavy crude in the global market. That is equivalent to a million barrels a day of conversion capacity that was bestowed, without cost, upon the refining industry. But does the refining industry need that additional conversion capacity? Certainly not right now. So we will have a price problem. And because in our current futures-dominated pricing mechanism, the price will be set by the most desperate seller (or buyer), be prepared for ultra-low prices for ultra-light oil as this thing shakes out.

That is where the use of ultra light crude and pr condensate creates a new, well not new but adds to a blending business volume, blending heavy crudes with these ultra light/condensates. It is a large volume business, creating custom blends for refiners along the USGC, USAC as well as Europe, South Asia, Pacific Rim and Far East.

WTL will definitely not be a feedstock to asphalt plants but it will definitely be a very good volumetric component to blending, refining into ultra clean lighter fuels, and a very valuable petchem feedstock globally.

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(edited)

2 minutes ago, ceo_energemsier said:

That is where the use of ultra light crude and pr condensate creates a new, well not new but adds to a blending business volume, blending heavy crudes with these ultra light/condensates. It is a large volume business, creating custom blends for refiners along the USGC, USAC as well as Europe, South Asia, Pacific Rim and Far East.

WTL will definitely not be a feedstock to asphalt plants but it will definitely be a very good volumetric component to blending, refining into ultra clean lighter fuels, and a very valuable petchem feedstock globally.

Quantities still must match. Producers and traders usually ignore that fact.

Edited by William Edwards
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