MARCELLUS GROWTH NOT PEAKING ANY TIME SOON
fuelfix.com - March 3, 2014 at 12:40 pm by Ryan Holeywell
HOUSTON — Natural gas from the booming Marcellus Shale will represent nearly a quarter of U.S. production by 2015, according to a new report published Monday by investment analyst Morningstar.
The report estimates that the Marcellus Shale, which traverses the Northeast from New York to West Virginia, will be the biggest driver of domestic dry gas production growth in the coming years, adding 3 billion cubic feet per day this year and another 2 billion cubic feed per day in 2015.
At that point, the report says, Marcellus gas will account for nearly a quarter of the country’s gas production, up from about 20 percent today.
“In short,” the Morningstar report says, “the growth of the Marcellus over the next several years is likely to be nothing short of astounding.”
No peak anytime soon
According to the Energy Information Administration, dry gas production in the Marcellus Shale averaged 10.4 billion cubic feet per day in 2013 — a 61 percent increase from 2012.
Pad drilling: New technologies require new math for rig counts
The report says the strong growth — which forecasts historically have underestimated forecasters — is due largely to efficiency improvements like a shift towards pad drilling and 24-hour operations.
“For a variety of reasons — including the high initial production rates and relatively shallow declines of wells, the ongoing application of new technologies, and a continued focus on more productive areas of the play — we don’t believe Marcellus natural gas production will reverse course anytime soon,” the report says.
1,600 wells
The report indicated at least 1,000 wells will need to be completed annually to hold production in the formation flat. But the Morningstar forecasters estimate 1,600 wells will be completed each year, with the extra production more than compensating for declines from older wells.
The play has 30 to 75 years of resource potential at current production rates, according to the study. While growth is likely to slow down, the play is so large — it covers nearly 100,000 square miles — that even slight growth will be significant.
The report was based on an analysis of nearly 4,500 wells in Pennsylvania and 1,000 wells in West Virginia, according to Morningstar. Researchers examined their initial production rates, production declines and drilling and completion activity to conduct their analysis.
Ryan Holeywell covers energy for the Houston Chronicle. He previously wrote about transportation and municipal finance for Governing magazine, which is read by state and local government officials nationwide. Holeywell’s previous work has been published by the Washington Post and USA Today, and he has appeared on CNN and public radio to discuss his articles. Holeywell, a Houston native, graduated from George Washington University in Washington, D.C.
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Replies to This Discussion
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Permalink Reply by ATLGator on -
I hear what you're saying about the Marcellus, and to a certain extent, I agree. That field is going to keep growing production for the couple years. I just don't think that it can overcome the legacy declines in the other fields that are not being drilled at the moment. Maybe this year it can (and probably will), but once that Marcellus production looks like it is starting to flatten out, which I think could happen by the end of the year or early next year, I don't see how prices can stay sub $5.
I've been told that for the Marcellus to maintain its current production, around 1,000 wells need to be drilled this year. I know a lot more will be drilled but it gives an indication as to how high the activity must be for the field to keep growing production.
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Permalink Reply by Skip Peel - Mineral Consultant on
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I think HBP in the Marcellus will take longer but that depends on continuing success with the drill bit. Still a lot of rock not tested. As to declining basin production, the Haynesville being a good example, less wells produce more gas. CULs are now the norm and they represent, by lateral length, 1.6 times the previous unit wells. As a greater percentage of domestic production comes from high initial production/high decline unconventional fields the industry will be able to balance supply to demand. Now that the cost to produce an mcf has been significantly reduced many companies claim to make an acceptable return with $4.50 gas. The others probably don't need a price above $5.
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Permalink Reply by ATLGator on
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That "acceptable return" was what I was trying to get at. The companies I listened to on the conference calls don't think that $4.50 creates an "acceptable return" in the dry gas plays as compared to their liquids rich plays.
If I'm wrong, it won't be the first or last time that's happened, lol!
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Permalink Reply by tc on
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Also the Marcellus is not all dry gas. The wet gas areas are profitable at lower NG prices than the Haynesville. Also most royalty is below 20% and that 5% makes a big difference. The county just leased acreage under the county park and got around $3,000/acre bonus, but only a royalty of only 17%.
http://www.marcellus.psu.edu/images/Wet-Dry_Line_with_Depth.gif
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Permalink Reply by ATLGator on
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That is very true tc, and it remains to be seen if the wet gas areas can maintain this massive production growth, because like Skip mentioned, the only people drilling the dry gas areas are doing so to HBP, and some have given up doing that (see HK in the Utica).
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ATLG - I don't think any of us are willing bet our lives on these government/analyst projections. I see how these projections can happen, but I also see how your projections can also happen. They probably have a better chance of correctly predicting the temperature 10 years from today than NG price.
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Permalink Reply by jim weyland on
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tc & atlgator,
i agree with both of y'all. and, i'll carry things a bit further; most of the outfits scrambling today to build liquification export facilities are building them on acreage adjacent to their lng import terminals. of those that weren't new built in the early 2000's they were ones originally built in the 70's and recommissioned in the early 2000's.
my point being none of them saw coming what came after 2005, i.e. a plethora of shale production. imo, no one, government or industry folks, are any good at predicting forward prices. and, in my further opinion, it's a fool's errand to attempt it. fwiw, i happen to know one such fool and, i know him pretty well.
note: in a prior post i attempted to make the point that the us producer wouldn't see any benefit from the spread between the domestic gas price and the world lng price unless he controlled all aspects of that value chain: us production, locked in liquification plant capacity, locked in lng tanker capacity and locked in end user contracts. i wasn't trying to predict forward prices domestic gas or world lng.
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a whole bunch of acres in appalachia where today they're drilling the marcellus are hbp where the old, shallow wells have been producing for between 50 to 100 years. a company (one of the two big legacy players up there) i worked for had the whole value chain thing down cold. they owned many leases, the fields services company gathering the gas to the interstate pl they also owned. between the northern and southern portion of the interstate, they have a massive straddle plant where they get all the liquids and only return equivalent btus to the producer. i don't know the typical royalty % of the old hbp leases up there but i'd be very surprised if it was in excess of 1/8.
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Jim - you are spot on. In Pa the minimal royalty is 12.5% by law. However, the court ruled that this is a gross amount and not a net amount, so deductions are allowed, so your royalty could be zero.
As the natural gas industry has grown, many Pennsylvanians signed leases with the understanding that under state law, they were entitled to a certain percentage of the money companies made selling the gas.
Pennsylvania’s Guaranteed Minimum Royalty Act of 1979 put the figure at 12.5 percent.
However some gas leases allow companies to deduct the expenses they incur processing and transporting gas– for things like compressor stations and pipelines. These are known as “post-production costs” or “gathering fees.”
Several years ago a number of Pennsylvania landowners complained and filed lawsuits. In dozens of cases they argued all the deductions invalidated their leases because they ended up with less than 12.5 percent. Gas companies disagreed.
In 2010 the State Supreme Court sided with the gas industry.
In a unanimous decision in Kilmer v. Elexco Land Services Inc., the court held that since the word royalty was not defined in state law, the industry could rely on its own interpretation, which allowed for subtracting the costs of moving the gas to market.
Landowners have continued to complain they’re being underpaid. The issue has become particularly hot topic in the state’s busiest drilling hub – Bradford County.
In response to the complaints, the State Senate Environmental Resources & Energy Committee held a hearing in June 2013. Within a few weeks Governor Corbett signed a new law requiring gas companies to clarify the deductions on royalty check stubs.
However, a group representing the state’s mineral owners was angered over language inserted in the bill at the last minute, which allows oil gas companies to combine or “pool” some leases.
They argued the measure could adversely impact some people who signed contracts years ago and didn’t anticipate modern shale gas drilling–hindering their ability to renegotiate old leases.
Corbett contends the language will enhance the efficient extraction of oil and gas, while protecting the rights of landowners.
Many of the royalty complaints have centered around the state’s biggest driller, Oklahoma City based Chesapeake Energy. In August 2013, Chesapeake agreed to a settlement in a class action lawsuit over the issue. The company denies wrongdoing but has called the agreement “fair and reasonable.”
The settlement agreement is still awaiting approval from a federal judge.
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<they get all the liquids and only return equivalent btus to the producer>>>
That's a nasty little trick.
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and, they know 'em all.
for the record as to my good name, i didn't work for any of the appalachian companies, i worked for the affiliated e&p outfit based in nola.
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