Get your natural gas in Texas for a dime, prices fall to record low

 (Reuters) - Next-day natural gas prices for Wednesday at the Waha hub in West Texas plunged to a record low due to an equipment failure in New Mexico that stranded gas in the Permian basin.

Spot prices at the Waha hub collapsed to an average of just 12 cents per million British thermal units (mmBtu) for Wednesday.

That fell below the contract’s prior all-time low of 21 cents in February and compares with an average of $1.72/mmBtu so far this year, $2.10 in 2018 and a five-year (2014-2018) average of $2.80, according to data available on the Refinitiv Eikon going back to 1991.

The equipment failure was on El Paso Natural Gas Pipeline Co LLC’s Lordsburg and Florida compressor stations. That failure, which caused El Paso to declare a force majeure, cut the operational capacity through the stations by about 0.2 billion cubic feet per day to around 0.4 bcfd starting on Tuesday.

El Paso, which is a unit of Kinder Morgan Inc, said the reduction will remain in effect until further notice.

The Permian is the biggest oil-producing shale basin in the United States and since much of that oil comes out of the ground with gas, it is also the nation’s second-biggest shale gas producing region, behind Appalachia in Pennsylvania, West Virginia and Ohio.

With production of both oil and gas more than doubling to record highs over the past five years, the pipeline infrastructure in the Permian has not been able to keep up with the rapid growth in output.

That has caused the basin’s existing oil and gas pipes to become constrained and forced some producers to burn or flare off some of the gas associated with oil production.

Those gas constraints have trapped gas in the Permian and depressed Waha prices, boosting the discount Waha trades at below the U.S. Henry Hub benchmark in Louisiana.

That spread reached $2.79/mmBtu for Wednesday, its widest since December. That compares with an average discount of $1.21 so far this year, $1.06 in 2018 and a five-year (2014-2018) average of 34 cents.

Several new pipelines are being built or developed to enable more gas to flow out of the Permian, including Oneok Inc’s WesTex and Roadrunner projects, Kinder Morgan’s Gulf Coast Express and Permian Highway projects and NAmerico Energy Holdings’ Pecos Trail.

Drillers will, however, have to wait until late 2019 and beyond for those projects to enter service.

Views: 951

Reply to This

Replies to This Discussion

Yikes!

Yikes is an appropriate response however let's put this into perspective.  There has been limited west Texas/New Mexico takeaway capacity (gas pipelines and associated facilities) for years.  That was not a problem until unconventional development took off.  Since natural gas is a "by product" of oil production, most was flared.  As the supply of "associated gas" sky rocketed, pipeline companies saw an opportunity and began the process of regulatory approval, volume commitments from operators and construction.  I've lost count of how many new natural gas and NGL pipelines will be operable by year's end.  Let's just say the takeaway capacity is significant if not yet sufficient to reduce flaring 100%.  As all that new supply flows to the Gulf Coast markets, it will not be 12 cents an mcf as the west Texas supply is no longer constrained by transportation options.  Before new demand catches up over the next few years, west Texas gas will cap if not significantly lower Gulf Coast prices across Texas and Louisiana.  Unlike Marcellus gas which Haynesville manages to compete with owing to the transportation cost differential per mcf, west Texas supply can incur similar transportation costs (a guess on my part, I have not seen any estimates) and Permian operators could make a tidy profit selling gas for $2.50 (this is also a guess on my part).  Until the volumes of new gas reach the Gulf Coast markets/hubs, all we have is speculation.  The bottom line is almost assuredly not good for Haynesville/Bossier gas prices.

Permian natural gas prices are having a rough spring. After a volatile winter that saw two periods of negative-priced trades followed by a period of relatively strong prices, values at the Permian's major trading hubs hit the skids earlier this week just as Spring Break set in for most in the Lone Star state. Once again, pipeline maintenance and burgeoning production appear to be the main culprits, but this upheaval feels different, in our view. Clearly, the price crash has reached a new level of drama, with day-ahead spot prices at West Texas's Waha hub now settling below zero - some days by more than $0.50/MMBtu. Gas production has raced higher too, now within striking distance of 10 Bcf/d, on the coattails of continued oil pipeline capacity expansions, but new gas pipeline takeaway capacity is an estimated six months away. What becomes of Permian gas prices in the meantime, and how much worse could already-negative prices get?

RBN Energy, excerpt.

And significant new demand from LNG is years away.

In the crowded U.S. LNG space, Tellurian Inc says it will likely make a final investment decision on its $30-billion Louisiana Driftwood export project during the first half of this year, alluding to a handful of customers for its planned first phase.

If the FID comes through as planned, the first LNG could come out of this project by 2023, with full completion by 2026, Reuters cited Tellurian CEO Meg Gentle as saying on the sidelines of the BloombergNEF summit in New York.  

The announcement follows Tellurian’s reported losses of nearly $126 million for 2018, on $10.8 million in revenue; nonetheless, that’s better than 2017 losses, which were nearly double.

Tellurian’s Driftwood project, which would produce 27.6 million tonnes per annum (MTPA) of LNG when completed, is unique in that while is one of at least 12 such projects in the pipeline in the United States, it is going for something fully integrated. In other words, it’s planning to both build and own the export terminal, as well as produce its own gas, host its own pipelines, and sell its own LNG globally.

That may soften the blow a little for us mineral owners.  The timeframe will help a little also, what with the LNG plants being said to come online next year.  Of course this is all speculation on my part using what little information I've gleaned from my perusing of the internet.  I'm still contemplating putting a CNG system on my truck as a secondary fuel for the e85.

Significant LNG demand does not arrive until 2025, or there abouts.  Maybe a little later.  Permian gas will hit the Gulf Coast this year.

Shows what I know.  I thought several LNG plants were coming online in 2020.

A couple of "trains" at existing LNG plants will come on line this year.  New LNG export facilities have not commenced construction yet.  That's why it will take 4 to 6 years for those that go forward to be in full operation.  If you have a reliable source of CNG close by and don't mind losing a third of your pick up bed capacity, a conversion might be a reasonable option.  You still have all the moving parts and service associated with a internal combustion engine (ICE).  If it was me I would save the conversion cost, drive the pick up for two to three years and then get an electric pick up.  You can charge it at home and there will be plentiful charging options by then for long distance trips.  It will have a full size bed and will tow somewhere around twice the capacity of your ICE pick up.

It's actually a full size Bronco I plan on doing this to.  With a body lift I am planning to put two smaller diameter(9"-10.5") CNG tanks under the rear of the cabin alongside the frame rails.  I'd love to do LNG in order to get a better G.G.E. for volume, but it doesn't look like that's going to happen.  I'm rebuilding the engine to about a 14.5:1 compression ratio to help optimize the performance from the CNG and the e85, as both of these fuels are quite easy to obtain here in the Houston area.  However, you'll get no argument from me about the torque numbers of an all electric vehicle.

Sounds good.  Let us know how the conversion goes.

Seems like the gas could be reinjected into the wells like CO2 is used in West Texas.

CO2 floods work in conventional reservoirs.  As do water floods and fire floods.  I don't think it would serve any purpose in an unconventional reservoir.

I recall that EOG has done it in the Eagle Ford. A recent article...

article

RSS

Groups

Not a member? Get our email.



Latest Activity

© 2019   Created by Keith Mauck (Site Publisher).   Powered by

Badges  |  Report an Issue  |  Terms of Service