Negative Gas Prices in the Permian

(edited)

13 minutes ago, SLL said:

Those prices for the residue don't make a whole lot of sense.  The highest daily trade was for the month of January was $2.675, and the FOM price was $1.54  In addition, 1.3265 for a btu factor is WAAAYYY out of transmission line spec.

But all that is relatively pointless.  You pulled a check for January production, and the whole point of this post was pricing in late March and early April.  Let's see that one when you get it.

First of all we get paid based on what the operator gets paid so you need to argue with them about how they got those prices.  You must understand that wellhead prices aren't the same as electronic futures market prices, right?  If not then I understand your confusion.  However, your observation about the BTU factor is exactly why the gas stream from these shale wells is so valuable.  The stripping of the liquids from the gas is what leaves the residue.

This negative and low pricing at WAHA has been going on for a while and happened in December and January as well.  Again, if you have committed capacity, this isn't an issue.  Operators with contracts get good prices for their gas, those without get the hub pricing or flare it.

https://www.wsj.com/articles/in-booming-oilfield-natural-gas-can-be-free-11545906601

https://marcellusdrilling.com/2018/11/permian-gas-at-waha-hub-briefly-trades-at-0-implications-for-m-u/

https://oilprice.com/Energy/Gas-Prices/Natural-Gas-Prices-Fall-Below-Zero-In-Texas.html

http://www.kallanishenergy.com/2018/07/19/permian-gas-prices-fall-as-production-keeps-growing/

 

Edited by wrs
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2 minutes ago, wrs said:

First of all we get paid based on what the operator gets paid so you need to argue with them about how they got those prices.  You must understand that wellhead prices aren't the same as electronic futures market prices, right?  If not then I understand your confusion.  However, your observation about the BTU factor is exactly why the gas stream from these shale wells is so valuable.  The stripping of the liquids from the gas is what leaves the residue.

This negative pricing has been going on for a while and happened in December and January as well.  Again, if you have committed capacity, this isn't an issue.

https://www.wsj.com/articles/in-booming-oilfield-natural-gas-can-be-free-11545906601

https://marcellusdrilling.com/2018/11/permian-gas-at-waha-hub-briefly-trades-at-0-implications-for-m-u/

https://oilprice.com/Energy/Gas-Prices/Natural-Gas-Prices-Fall-Below-Zero-In-Texas.html

http://www.kallanishenergy.com/2018/07/19/permian-gas-prices-fall-as-production-keeps-growing/

 

I participate in this market every, single day, so I know exactly what the prices are, and how they are determined.  I know exactly where Reeves County is, and I know the pricing in the area.  It certainly isn't Waha +

Again, let's see your remit from XTO for the month of April, when you get it.  Would also be great to see how much of a deduct they are taking not only for taxes, but transportation.

FOM Waha for April was -6¢

GDD Average for April Waha to date is -75¢

Good thing you're oily.

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(edited)

17 minutes ago, SLL said:

I participate in this market every, single day, so I know exactly what the prices are, and how they are determined.  I know exactly where Reeves County is, and I know the pricing in the area.  It certainly isn't Waha +

Again, let's see your remit from XTO for the month of April, when you get it.  Would also be great to see how much of a deduct they are taking not only for taxes, but transportation.

FOM Waha for April was -6¢

GDD Average for April Waha to date is -75¢

Good thing you're oily.

You are seeing exactly what we get paid by XTO.  It's a bad lease that we can't do anything about.  The other operator is on a modern lease that my sister and I negotiated and he has to pay Henry Hub prices for whatever he flares at 25% royalty and based on the BTU factor of 1.32 you saw on those other wells.  So far he has commitments for almost all of his gas.  He does send some north and probably will be affected by the compressor outage.  If he flares, he still has to pay us.  I wish we had XTO on that kind of lease but they are using a lease signed in 1950, six years before I was born.

When the only gas processing plant out there blew up in late 2015 it caused most operators in that Orla area to flare gas.  The independent operator flared our gas and had to pay us for it.  He was selling plenty of oil to make up for it.  However, he sees gas sales as an important part of his revenue stream and so he does his best to make sure he doesn't flare much at all and that he sells his liquids.

Edited by wrs
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9 minutes ago, wrs said:

You are seeing exactly what we get paid by XTO.  It's a bad lease that we can't do anything about.  The other operator is on a modern lease that my sister and I negotiated and he has to pay Henry Hub prices for whatever he flares at 25% royalty and based on the BTU factor of 1.32 you saw on those other wells.  So far he has commitments for almost all of his gas.  He does send some north and probably will be affected by the compressor outage.  If he flares, he still has to pay us.  I wish we had XTO on that kind of lease but they are using a lease signed in 1950, six years before I was born.

When the only gas processing plant out there blew up in late 2015 it caused most operators in that Orla area to flare gas.  The independent operator flared our gas and had to pay us for it.  He was selling plenty of oil to make up for it.  However, he sees gas sales as an important part of his revenue stream and so he does his best to make sure he doesn't flare much at all and that he sells his liquids.

You're getting paid about a GDD Waha - 6¢, after adjustment for the btu factor.

There is a brand-spanking-new-gas processing plant in Orla with two trains operating, and a third coming up by the end of the 2nd quarter.

Heads up, if things don't turn around, your April check is going to have a deduction for residue.

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On 4/8/2019 at 9:47 AM, D Coyne said:

WRS

I get $40.88/BOE for your natural gas including NGL, based on the payment statement above.  About 29% of your revenue for that well comes from natural gas and NGL. and also 29% of your BOE is from natural gas, wow you get a lot for your natural gas and NGL, is this typical or was January a strange month?

It's a January production statement.  It was cold in January.

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3 minutes ago, SLL said:

It's a January production statement.  It was cold in January.

 

I'm not stupid, I know that.  I pointed out this was about as good as it gets for gas and NGLs in any month and that by summer the NGLs will be a lower percentage of the royalty check and oil will be higher.

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29 minutes ago, SLL said:

You're getting paid about a GDD Waha - 6¢, after adjustment for the btu factor.

There is a brand-spanking-new-gas processing plant in Orla with two trains operating, and a third coming up by the end of the 2nd quarter.

Heads up, if things don't turn around, your April check is going to have a deduction for residue.

I am aware of the existence of that plant, I drive by it every few months and there is one going in just southeast of our section out there.  BTW, this XTO section is on 652 just one mile from the intersection with 285, it's effectively downtown Orla. 

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(edited)

20 minutes ago, wrs said:

I am aware of the existence of that plant, I drive by it every few months and there is one going in just southeast of our section out there.  BTW, this XTO section is on 652 just one mile from the intersection with 285, it's effectively downtown Orla. 

I'm sorry, I could have sworn you wrote that the only gas plant in the Orla area blew up in late 2015.  

Read it again...yep, that's what you wrote.

Edited by SLL

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(edited)

9 minutes ago, SLL said:

I'm sorry, I could have sworn you wrote that the only gas plant in the Orla area blew up in late 2015.  

Read it again...yep, that's what you wrote.

What year is this? Anadarko owned it at the time and it was undergoing an upgrade.

 

 

 

IMG_15911.jpg

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This truly sucks for the industry and is a very bad precedent. Lot  more can be done with better planning and strategizing and monetizing the resource much much better and keeping a minimal impact on the environment!!!!

 

_____________________

Oil Producers Are Burning Enough 'Waste' Gas to Power Every Home in Texas

1b5dc050-ffe6-11e8-b9af-62cc4e6b832e
Kevin Crowley and Ryan Collins
BloombergApril 11, 2019
 
image.png.cdb6b120b5a11a2539180e152b0649c8.png
 
 

(Bloomberg) -- America’s hottest oil patch is producing so much natural gas that by the end of last year producers were burning off more than enough of the fuel to meet residential demand across the whole of Texas. The phenomenon has likely only intensified since then.

Flaring is the controversial but common practice in which oil and gas drillers burn off gas that can’t be easily or efficiently captured and stored. It releases carbon dioxide and is lighting up the skies of West Texas and New Mexico as the Permian Basin undergoes a massive production boom. Oil wells there produce gas as a byproduct, and because pipeline infrastructure hasn’t kept pace with the expansion, energy companies must sometimes choose between flaring and slowing production.

“It’s a black eye for the Permian basin,” Pioneer Natural Resources Chief Executive Officer Scott Sheffield said at Wednesday at an energy conference at Columbia University in New York. “The state, the pipeline companies and the producers -- we all need to come together to figure out a way to stop the flaring.”

The amount of gas flared in the Permian rose about 85 percent last year reaching 553 million cubic feet a day in the fourth quarter, according to data from Oslo-based consultant Rystad Energy. Local prices that are hovering near zero will remain “under stress” until more pipelines come online, Moody’s Investors Service said in a note Thursday.

There will always be a “mismatch” between the amount of gas produced and pipeline capacity, so some flaring is inevitable, according to Ryan Sitton, the head of the Railroad Commission of Texas. Despite what its name suggests, his agency oversees the oil and gas industry in the state and regulates flaring, allowing companies to burn gas for limited periods, or in times of emergency.

Some 4 billion cubic feet of pipelines are expected come online in the next year or so, which will likely reduce, but not eliminate, the need to flare, the commissioner said in an interview.

Right now, there’s about 9.5 billion feet a day of gas pipeline capacity in the basin that can reach markets that need the heating and power plant fuel, according to RS Energy Group. That’s not enough to carry the more than 13 billion cubic feet a day of gas that’s being pumped out of wells in the region.

Unsurprisingly, with such an abundance of gas but also real difficulties in getting it to consumers, prices for the fuel in Permian have been cheaper than in other parts of the U.S., and earlier this month they went negative, meaning producers had to pay customers to take their gas.

“Everything now that can reach a market is most definitely running full,” Jen Snyder, a director at RS, said in an interview Wednesday. “This market is going to be super volatile, particularly in the spring when market demand is low and things are tighter.”

The U.S. moved past Nigeria in terms of gas flaring in the recent years, though increases in Iran and Iraq have kept it in fourth place, according to World Bank data for 2017. Russia remains the biggest source, burning off almost 20 billion cubic meters that year.

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Sempra Energy said that Cameron LNG started feeding pipeline gas to the first liquefaction train of the LNG export project as it prepares to start production at the facility in Hackberry, Louisiana.

This is the final commissioning step for Train 1 of Cameron LNG Phase 1, Sempra said in a statement.

Lisa Glatch, chief operating officer of Sempra LNG and board chair for Cameron LNG, said, “Sempra Energy is now one step closer to reaching our goal of building up to 45 million tonnes per annum (Mtpa) of LNG export capacity to serve global markets.”

Following authorization received from the Federal Energy Regulatory Commission Friday, April 5, allowing the introduction of pipeline feed gas, Cameron LNG will begin ramping up the feed gas deliveries to the facility as it completes the commissioning process.

Phase 1 of the Cameron LNG liquefaction-export project, which includes the first three liquefaction trains, is a $10 billion facility with a projected export of 12 mtpa of LNG, or approximately 1.7 billion cubic feet per day.

Cameron LNG Phase 1 is jointly owned by affiliates of Sempra LNG, Total, Mitsui & Co., and Japan LNG Investment, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha (NYK).  Sempra Energy indirectly owns 50.2 percent of Cameron LNG.

Cameron LNG Phase 1 is one of five LNG export projects Sempra Energy is developing in North America.

Cameron LNG Phase 2, previously authorized by FERC, encompasses up to two additional liquefaction trains and up to two additional LNG storage tanks.

Sempra is also developing Port Arthur LNG project in Texas and Energía Costa Azul (ECA) LNG Phase 1 and Phase 2 in Mexico.

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Kinder Morgan in discussions to build third Permian Basin gas pipeline: CEO

 
 

2 Min Read

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(Reuters) - Kinder Morgan Inc has begun internal discussions about building a third natural gas pipeline in the Permian Basin as demand for gas takeaway capacity continues to surge, Chief Executive Officer Steven Kean told investors on Wednesday.

As natural gas production has outpaced pipeline capacity in the Permian Basin, a gas glut has led to plummeting prices in the region, with spot prices at the Waha hub even trading at negative levels.

 

Kinder Morgan believes demand for gas takeaway capacity could grow by 2 billion cubic feet per day each year over the next few years, equivalent to the Houston pipeline operator’s Gulf Coast Express project, Kean said.

 

“Demand to get gas out of the Permian continues to grow and the desire to unlock value that’s in oil and (natural gas liquids) continues to put pressure on need for additional takeaway capacity,” Kean said. “There is interest in pipe three.”

Kinder Morgan’s Gulf Coast Express natural gas pipeline in the Permian Basin is set to come into service in October. Another similar project, the Permian Highway, is on schedule to begin service one year later.

Reporting by Collin Eaton in Houston; Editing by Peter Cooney and Lisa Shumaker

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The US Federal Energy Regulatory Commission has issued the order granting authorization for Tellurian Inc.’s proposed Driftwood LNG export project and an associated pipeline in Louisiana. The project would produce as much as 27.6 million tonnes/year of LNG for export.

The Driftwood LNG project consists of two main components: the construction and operation of the LNG facility, which includes five LNG plant facilities to liquefy natural gas, three tanks to store the LNG, LNG carrier loading/berthing facilities, and other appurtenant facilities at a site near Carlyss, Calcasieu Parish, La.; and the construction and operation of about 96 miles of pipeline, three new compressor stations, and 15 new meter stations.

Construction is expected to begin this year with first LNG anticipated in 2023.

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  • 23 Apr 2019 | 22:14 UTC
  • Denver

Discounted Permian gas sees potential lift from Wahalajara startup

Highlights

El Encino-Laguna pipeline flows ramp up to 40 MMcf/d

Waha cash up 25 cents/MMBtu from weekend flow dates

Wahalajara could offer outlet for 250 MMcf/d upon completion

 

Denver — Heavily discounted Permian Basin gas could soon access downstream markets in Mexico, following the recent startup of incremental gas deliveries to Fermaca's Wahalajara pipeline system.

On Monday, updated electronic bulletin board flow data showed that a new downstream segment on Wahalajara, the El Encino - La Laguna pipeline, began receiving about 40 MMcf/d on April 17.

In Tuesday trading, cash prices at Waha traded as high at 65 cents/MMBtu, up about 25 cents from weekend flow dates. Forwards prices for May jumped 32 cents on the day, rising to a $2.47/MMBtu discount to benchmark Henry Hub gas on the improving outlook for Permian supply.

The startup of incremental demand on Wahalajara bodes well for Permian producers since all of the system's supply comes entirely from the West Texas play.

Over the past month, about 185 MMcf/d of Permian gas production has flowed westbound on Roadrunner Gas Transmission Pipeline where it meets the border-crossing Tarahumara Pipeline -- Wahalajara's northern-most segment.

After flowing southbound on Tarahumara, an interconnection to El Encino - La Laguna offers access to additional demand in north-central Mexico, and to uncompleted Wahalajara segments and interconnections farther downstream.

Upon its completion, the Wahalajara system could ultimately provide an outlet for an incremental 250 MMcf/d of Permian gas production, according to S&P Global Platts Analytics.

042319-tarahumara.jpg

DOWNSTREAM DEMAND

On Tuesday, flow data provided by Fermaca offered no clear indication on the current southbound reach of Permian gas production. It was also unclear whether recent deliveries to El Encino - La Laguna reflect line-packing or actual demand on the pipeline.

According to Platts Analytics, downstream demand on the Wahalajara system is likely to see its biggest boost upon completion of the Guadalajara interconnect in central Mexico. Recent construction status reports show that interconnection entering service sometime during third-quarter 2019.

Another potential outlet for Permian gas production could come from a connection to Mexico's national Sistrangas pipeline grid. The 70 MMcf/d interconnect at El Encino in Chihuahua state is being jointly developed by Fermaca and Cenagas, Mexico's natural gas system operator.

The interconnect is expected to enter service sometime this year, although Sistrangas has yet to identify a new meter for the project.

WAHA PRICES

The startup of incremental demand on Wahalajara gives Permian Basin gas producers some cause for optimism following an extended period of negative pricing from late March to mid-April.

On April 3, cash prices at Waha settled at a record-low negative-$5.79/MMBtu as gas production reached the ceiling on available takeaway capacity, which was exacerbated by a series of maintenances.

Following the much-anticipated, full ramp-up in demand on Wahalajara, the next major pipeline expansion isn't scheduled to enter service until early autumn.

With the startup of Kinder Morgan's 2 Bcf/d Gulf Coast Express pipeline in October 2019, and an anticipated in-service date of late 2020 for the midstream developer's 2.1 Bcf/d Permian Highway Pipeline, Platts Analytics anticipates a longer-term resolution for Permian producer's gas transportation constraints, at least though the early 2020s.

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Houston (TX) Chronicle
Houston oilfield service company Baker Hughes is using the Permian Basin in West Texas to debut a fleet of new turbines that use excess natural gas from a drilling site to power hydraulic fracturing equipment — reducing flaring, carbon dioxide emissions, people and equipment in remote locations. Baker Hughes CEO Lorenzo Simonelli spoke about the company’s “electric frack” technology during a Tuesday morning investors call. The company said its first quarter profit fell more than half to $32 million from $70 million during the same period a year earlier. Revenues rose to $5.6 billion from $5.4 billion revenue inthe first quarter of 2018. As production continues to outpace pipeline construction in the Permian Basin, operators are burning off, or flaring, an estimated 104 billion cubic feet of natural gas per year instead of shipping it to market. Simonelli said he views wasted natural gas, a byproduct of oil drilling, as a business opportunity. “We’re solving some of our customers’ toughest challenges such as logistics, power and reducing flare gas emissions with products from our portfolio,” Simonelli said during the call. Baker Hughes estimates 500 hydraulic fracturing fleets are deployed in shale basins across the United States and Canada. Most of them are powered by trailer-mounted diesel engines. Each fleet consumes more than 7 million gallons of diesel per year, emits an average of 70,000 metric tons of carbon dioxide and require 700,000 tanker truck loads of diesel supplied to remote sites, according to Baker Hughes. “Electric frack enables the switch from diesel-driven to electrical-driven pumps powered by modular gas turbine generating units,” Simonelli said. “This alleviates several limiting factors for the operator and the pressure pumping company such as diesel truck logistics, excess gas handling, carbon emissions and the reliability of the pressure pumping operation.” Baker Hughes estimates that the 500 diesel frack fleets require a combined 20 million horsepower of energy, which translates into a potential market to provide 15 gigawatts of electricity using gas-fired turbines. So far, eight electric frack crews are deployed in the Permian Basin.

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On 4/16/2019 at 1:07 PM, ceo_energemsier said:

This truly sucks for the industry and is a very bad precedent. Lot  more can be done with better planning and strategizing and monetizing the resource much much better and keeping a minimal impact on the environment!!!!

 

_____________________

Oil Producers Are Burning Enough 'Waste' Gas to Power Every Home in Texas

1b5dc050-ffe6-11e8-b9af-62cc4e6b832e
Kevin Crowley and Ryan Collins
BloombergApril 11, 2019
 
image.png.cdb6b120b5a11a2539180e152b0649c8.png
 
 

(Bloomberg) -- America’s hottest oil patch is producing so much natural gas that by the end of last year producers were burning off more than enough of the fuel to meet residential demand across the whole of Texas. The phenomenon has likely only intensified since then.

Flaring is the controversial but common practice in which oil and gas drillers burn off gas that can’t be easily or efficiently captured and stored. It releases carbon dioxide and is lighting up the skies of West Texas and New Mexico as the Permian Basin undergoes a massive production boom. Oil wells there produce gas as a byproduct, and because pipeline infrastructure hasn’t kept pace with the expansion, energy companies must sometimes choose between flaring and slowing production.

“It’s a black eye for the Permian basin,” Pioneer Natural Resources Chief Executive Officer Scott Sheffield said at Wednesday at an energy conference at Columbia University in New York. “The state, the pipeline companies and the producers -- we all need to come together to figure out a way to stop the flaring.”

The amount of gas flared in the Permian rose about 85 percent last year reaching 553 million cubic feet a day in the fourth quarter, according to data from Oslo-based consultant Rystad Energy. Local prices that are hovering near zero will remain “under stress” until more pipelines come online, Moody’s Investors Service said in a note Thursday.

There will always be a “mismatch” between the amount of gas produced and pipeline capacity, so some flaring is inevitable, according to Ryan Sitton, the head of the Railroad Commission of Texas. Despite what its name suggests, his agency oversees the oil and gas industry in the state and regulates flaring, allowing companies to burn gas for limited periods, or in times of emergency.

Some 4 billion cubic feet of pipelines are expected come online in the next year or so, which will likely reduce, but not eliminate, the need to flare, the commissioner said in an interview.

Right now, there’s about 9.5 billion feet a day of gas pipeline capacity in the basin that can reach markets that need the heating and power plant fuel, according to RS Energy Group. That’s not enough to carry the more than 13 billion cubic feet a day of gas that’s being pumped out of wells in the region.

Unsurprisingly, with such an abundance of gas but also real difficulties in getting it to consumers, prices for the fuel in Permian have been cheaper than in other parts of the U.S., and earlier this month they went negative, meaning producers had to pay customers to take their gas.

“Everything now that can reach a market is most definitely running full,” Jen Snyder, a director at RS, said in an interview Wednesday. “This market is going to be super volatile, particularly in the spring when market demand is low and things are tighter.”

The U.S. moved past Nigeria in terms of gas flaring in the recent years, though increases in Iran and Iraq have kept it in fourth place, according to World Bank data for 2017. Russia remains the biggest source, burning off almost 20 billion cubic meters that year.

The flaring needs to stop. Natural gas needs to take over from the much dirtier and more expensive diesel. It will save the transportation industry and customers billions of dollars. 

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