The following is an excerpt from a recent presentation by a major Marcellus Shale operator.  I researched the CHK Haynesville Shale well with the most recent well cost entered in SONRIS for a comparison  and I suspect that CHK's well designs and costs are similar to Vine O&G, the other most active driller currently.  The differences are stark and unlikely to change over the near term.  As more Marcellus gas finds its way to the Gulf Coast market I suspect it will cap the price of natural gas from Texas and Louisiana production.  The other side of the coin, the more optimistic one, is that demand will be increasing for LNG liquefaction and export by NG pipeline to Mexico.


In the SW PA "dry" Marcellus area, a five well pad brought on line in April is expected to have an EUR of ~22 Bcf per well (3.0+ Bcf per 1,000 lateral feet) at a cost of ~ $5.3 million. ___ plans to bring on line 49 wells in SW PA "dry" area (~7000 ft. lateral, $5.2 million well cost, 17.6 Bcfe EUR ....

In the SW PA "wet" Marcellus area, a four well pad brought on line at end of 2015 is expected to have an EUR of ~28 Bcfe per well (4.0 Bcfe per 1,000 lateral feet). ___ plans to bring on line 31 wells in SW PA "wet" area (~6,970 ft. lateral, $5.8 million well cost, 20.6 Bcfe EUR ....

In the "super rich" Marcellus area of SW PA, two pads with a total of 10 wells brought on line in Q1 are expected to have an EUR of ~14 Bcfe per well (2.8 Bcfe per 1,000 lateral feet) with a cost of ~$4.8 million. ___ plans to bring on line 13 wells in SW PA "super-rich" area (~6,660 ft. lateral, $5.9 million well cost, 16.0 Bcfe EUR ....


CHK S/N 248904, Completed 7/11/15 (most recent completion with well cost entered in SONRIS)

14.03 MMCFD, 5280' Perforated Lateral, 14 stages, $8,073,396.

Although there are no EURs available for this well, the better Haynesville Shale horizontal wells are likely in the range of 7 to 10 Bcf or, at a very optimistic comparison, about one half the better Marcellus well production at about twice the cost ($5.8M/6,970' = $832 per foot of perforated lateral vs.  $8.0M/5280' = $1515 pfpl).

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Ask Tue Price Previous Year Ago
Propane, tet, Mont Belvieu, Texas, gal.-G ... ... 0.4591 0.4656 0.3953
Butane, normal, Mont Belvieu, Texas, gal.-G ... ... 0.6021 0.6092 0.5420
Natural Gas, Henry Hub-I ... ... 2.720 2.810 2.880
Natural Gas, Transco Zone 3, $ per Mmbtu-I ... ... 2.720 2.800 2.870
Natural Gas, Transco Zone 6 NY, $ per MMBtu-I ... ... 2.620 2.790 2.990
Natural Gas, Panhandle East, $ per MMBtu-I ... ... 2.500 2.590 2.660
Natural Gas, Opal, $ per MMBtu-I ... ... 2.610 2.690 2.790
Natural Gas, Marcellus NE PA, $ per MMBtu-I ... ... 1.440 1.460 1.400

Natural Gas, Haynesville N. LA, $ per MMBtu-I

How about $1.20 more per mmbtu in the Haynesville

... ... 2.640 2.710


Yes.  That's why more Marcellus/Utica gas is headed to the Gulf Coast.  Marcellus/Utica operators want Henry Hub prices.  Even with transportation costs they can undercut Haynesville gas and still make a much better profit.

"Texas and Louisiana producers have already lost most of their traditional Northeast markets to the Marcellus/Utica.."  "Much of the Midwest and parts of the Southeast are not far behind....thanks to pipeline reversal projects...that for decades moved Texas and Louisiana gas north."


Help me understand something. The NG coming out of Haynesville is going where today? And three years from now where do you expect it to go?



John, that would take a lot of research.  In general I know that Haynesville gas retains some of the Southeastern U.S. market.  Here is another quote from the previously quoted report,

"With faraway domestic markets for Gulf Coast gas being lost to Marcellus/Utica producers, Texas and Louisiana producers increasingly are serving more regional and local needs –– and getting geared up to fight for their pieces of those two new and fast-growing demand centers: 1) new liquefaction/LNG export terminals along the Gulf Coast and 2) Mexico, whose imports of U.S. gas (the vast majority of it crossing the Rio Grande from Texas) have more than quadrupled in the past six years (to more than 3.4 Bcf/d as of April) and are slated to rise past 5 to 6 Bcf/d by the early 2020s."

Haynesville gas is getting a significant share of supply for liquefaction but near term pipeline projects will allow more Marcellus/Utica gas to compete.  In addition to the Mexico and LNG exports previously mentioned, the chemical industry building boom on the Gulf Coast will also add demand.

Where is goes three years from now is a tough prediction.  If prices rise to $3 by then I think the Haynesville will be fine although the price is likely to be range bound between $3 and $3.50 for many years to come excepting the occasional spike for weather related demand peaks.  What Haynesville gas needs is for greater penetration of Northeast markets by Marcellus/Utica gas.  The anti-hydrocarbon sentiment in that part of the country has severely restricted the construction of new pipelines.  Marcellus/Utica should be fueling the Midwest and Northeast instead of coming to the Gulf Coast.

Thanks for the reply back...

You're welcome, John.  I should have added that some portion of the volumes going to long term end users will continue to be supplied by Haynesville production, it just will not be able to command a premium to what Marcellus/Utica goes for in the Gulf Coast market.

Marcellus shale drillers start to come off sidelines as gas prices rebound

By David Conti | Friday, July 29, 2016, 11:00 p.m. Updated 11 hours ago

 Some good news on natural gas prices recently is not likely to drive an immediate boom in Marcellus shale activity.

A rebound in natural gas prices and signs that a constrained market is loosening up are providing a glimmer of optimism for some top Marcellus shale producers.

In quarterly financial updates during the past week, executives outlined plans ranging from restarts of idled drilling programs by Consol and Southwestern Energy, a big ramp-up of shallower drilling by EQT Corp., and a more measured wait-and-see approach from Range Resources and Cabot Oil & Gas.

“We think it's prudent to be rational at this time until we see the infrastructure projects put in place,” Dan Dinges, CEO of Houston-based Cabot, told analysts Friday while discussing second-quarter financial results. Pennsylvania's No. 2 shale gas producer plans to maintain just one drilling rig in the Marcellus this year as it tries to time a larger production increase with construction of pipelines in its operating area in Susquehanna County.

Rising prices and a feeling that the worst is over are encouraging some producers. But analysts and some executives say delays in expanding the pipeline infrastructure and concerns about boosting production too quickly should temper the enthusiasm.

“I think we'll see producers much more cautious or conservative in their approach compared to 2012 or 2013,” when companies last came out of a low-price valley, said Eric Brooks, an energy analyst in Denver with Platts Analytics, a unit of S&P Global Platts.

A price collapse over the past two years — fed by a glut of supply and limited pipelines to take it to well-paying markets — prompted a swift slowdown in drilling across the Marcellus and Utica shales. The 182 shale wells drilled in the first six months of 2016 in Pennsylvania — the country's second-largest gas producer — was 57 percent below the same period last year and 72 percent below the 2014 pace. Companies such as Consol and Southwestern stopped drilling altogether, and Range reduced its number of drilling rigs from 15 at the beginning of last year to three now.

The slowdown, coinciding with a slide in shale oil drilling, capped production as demand from power plants and exports builds. National benchmark prices have risen to nearly $3 per million British thermal units after hitting 17-year lows of $1.64 in March.

“There are signs that later this year and into 2017, supply and demand will be more balanced and pricing could significantly improve,” said Jeff Ventura, CEO of Fort Worth-based Range Resources, echoing comments by fellow executives that the market is coming off a bottom.

“It's a good time to begin the process of restoring our pace of development,” said EQT CEO David Porges.

That process will look different at each producer, in part depending on their access to pipelines.

“They're looking for ways to get out of the region, where demand is picking up,” Brooks said.

Cecil-based Consol is starting up just two rigs that will drill 10 wells in strategic locations already served by pipelines.

“We were one of the first to drop all our rigs last year, and we're not rushing to ramp up capital with rising prices,” Consol CFO David Khani said about the company's cautious approach.

EQT will drill 30 more wells than it planned, but will tap a shallower and cheaper-to-exploit layer above the Marcellus. Those wells in the Upper Devonian layer won't increase overall spending or come online until next year, when the company expects pipelines to the Gulf Coast and Midwest to start up.

“They don't want to get too far over their skis. That speaks for much of the industry,” said David Holt, an equity analyst at S&P Global Market Intelligence.

EQT's Porges and others warned that production gains could outpace demand and pipeline capacities, sending the region back into a glut that pushes prices lower.

“We are a bit wary of more of the same that got us into this lower-price environment,” said Brooks, who noted that many pipelines once expected to come online next year won't be ready until at least 2018.

Range officials are watching those pipeline plans closely with goals to move up to 80 percent of gas produced in the Marcellus out of the region.

The company is maintaining its complement of three drilling rigs but has a plan to ramp up quickly and cheaply as demand increases. It has identified 200 existing well pads that have room and permits for additional wells. Drilling there can cut in half the time it takes to get gas flowing — while ruffling fewer feather among neighbors — compared with starting a fresh pad.

“We'll be able to react more quickly,” said Dennis Degner, a vice president at Range, who estimated such wells cost about $700,000 less. “It helps streamline it from start to finish.”

Remember when all the Haynesville operators said the average well was 6.5 BCF? Now we know few will make over 4 and it's a short list that will make 7 BCF. Be skeptical of the claims from PA and elsewhere.

Range has been there as long as anyone and their presentation is full of discrepancies. I can't believe their lawyers let them put this stuff out there. Their recent presentation shows the best combined gas in place for the Marcellus, Upr. Devonian and Point Pleasant to be 300-350 BCF per 640 acres. Let's be generous and say there is a 10% recovery: that's 30 to 35 BCF per 640 acres. At 6 wells per 640 (very generous for the Point Pleasant) that is 5 to 6 BCF per well. That is if you could drill all three zones with one well--which you can't. So let's be generous and say on average it's 3 BCF per well. In fact, if you look at the production from SW Pennsylvania 3 BCF will be a typical good well. So the map is consistent with current production models, but their claims of 10 BCF wells are not. Looking at the Marcellus alone: shown on slide #43, there are only two areas with gas in place of 125-150 BCF per 640 acres. Using the 150 value and 10% recovery and 6 wells per section yields 2.5 BCF per well. This is a pretty good match to most Marcellus wells. But many in the sweet spots look much better--especially Cabot in NE PA. This leads me to question the recovery factor or the number of wells per section. My own opinion is that the well spacing will not support 6 wells per section for commercial production. Time will tell. But certainly these projected EUR numbers from PA are not justified by the data.

Thanks for the observations, Doob.  I don't recall the Haynesville Shale operators that claimed a 6.5 Bcf average across all their acreage.  By the parameters from the early days of the Haynesville Play 6.5 Bcf would have been a lower Tier One well.  The problem with comparisons comes with the evolution of well designs.  Data analysis from Haynesville 1.0 wells does not provide an accurate assessment of 2.0 wells and data from 2.0 wells does not provide an accurate assessment of 3.0 wells.  A number of companies have claimed significant increases in the amount of their acreage that is economic with each major improvement in well designs and the ability to drill longer laterals with HC wells.  There should be sufficient data for the 3.0 HC wells this year and we will likely see some articles that provide an opinion of the accuracy of company EUR  claims.

The bottom line for myself, and I think a lot of GHS members, is that Marcellus/Utica gas is considerably cheaper currently and that more of it is coming into the Gulf Coast market to complete directly with Texas and Louisiana production.

Natural Gas, Marcellus NE PA, $ per MMBtu-I






Natural Gas, Haynesville N. LA, $ per MMBtu-I






I don't buy 22 Bcf UER per well at 5.3 Million.  The economics may be better to some degree but not to that degree.

Your welcome, Mike.  The pipeline projects providing increased capacity to the Gulf Coast markets should come on line later this year and next.  Then we will see if there is sufficient demand to support increasing that capacity.  By then I hope that new markets for Marcellus/Utica supply to New England and the Atlantic Coast become possible.  At the moment that is looking doubtful.


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