Haynesville Sizzle Might Fizzle
Tuesday, April 14, 2009
Haynesville Sizzle Might Fizzle
Despite lower natural gas prices, the Haynesville Shale is the hottest onshore play in North America. Production is more than 150 MMcfd from recently drilled horizontal wells, and single-well Initial Production (IP) rates are as high as 24 MMcfd.
I used standard rate-versus-time methods to determine estimated ultimately recoverable reserves (EUR) for 14 horizontally drilled wells that had sufficient production history to project a decline rate. Production was extrapolated using a hyperbolic decline, and an economic limit of 1.0 MMcf/month. The wells had an average EUR of 1.5 Bcf, and 67% (10 wells) had reserves less than 1.5 Bcf. This is an early evaluation, and does not include several recently completed wells because of insufficient production data. Reserves were, with one exception (5.3 Bcf), considerably lower than the 6.5 Bcfe most-likely per well reserves, and 4.5-8.5 Bcfe range, claimed by leading operators in the play Chesapeake Energy Corporations and Petrohawk Energy Corporation.
Problems with the Haynesville Shale include high decline rates and costs. Average monthly decline for the wells that I analyzed is 20–30%, and projected annual decline rates average 80−90%. Rapid decline makes IP rates unreliable indicators of well productivity. The average production history of wells used in this analysis is less than five months; current production rates already average only 48% of IP.
Drilling and completion (D&C) costs are about $7.5 million per well, although Petrohawk recently revised its D&C costs upward to $8.5–9.5 million. Average true vertical depth of wells in this study is 11,500 ft, and average measured depth is 15,250 ft. Five- to ten-stage hydraulic fracturing is typical with 600–750 lb sand/lateral foot in horizontal boreholes, which average 4,500 ft long. Leasing costs in active areas during 2008 were $10,000–30,000/acre, increasing capital expenditures for an 80-acre spacing unit $0.8-2.4 million above D&C costs.
Operating costs average $2.25/Mcf, based on US SEC 10-K filings and annual reports. After gathering and transportation costs, netback gas prices for early March 2009 were less than $2.50/Mcf (RBC Richardson Barr). Net revenue interest, after royalties, is typically 75%, and Louisiana severance tax is $0.27/Mcf (included in operating cost) . While current prices are the lowest in many years, and hedging has helped careful operators, it cost many operators a $7.25/Mcf or more to produce gas during the fourth quarter of 2008.
Clearly, most Haynesville Shale wells will not approach a commercial threshold until both gas prices and per-well reserves increase. To quantify that reserve and price threshold, I ran a basic NPV10 model using the cost information already mentioned. I used decline rates from the Barnett Shale (65%—Year1, 40%—Year 2, 30%—Year 3, 25%—Year 4, and 20% thereafter) instead of the higher decline rates projected from Haynesville production to date.
The break-even (NPV10= 0), minimum per-well reserve volume is 2.5 Bcf with a netback gas price of $8/Mcf (~$9/MMBtu Henry Hub spot). This means that the play would have been marginally commercial in 2009 dollars during only 15 months (12.5%) over the past decade—and over the past 20 years since the advent of the natural gas commodity market in 1989—if an average well had reserves of 2.5 Bcf instead of only 1.5 Bcf. At 1.5 Bcf/well, $12/Mcf netback gas price is needed to break even.
Chesapeake CE O Aubrey McClendon recently said, “We only need gas prices to be ‘good’ for three to six months out of every two-year period.” (Houston Chronicle, February 11, 2009). If ‘good’ means to break even in the Haynesville Shale, it looks like he will meet costs no more than 12.5% of the time, and lose money the other 87.5%, assuming that per-well reserves can be doubled. That business model is difficult to understand, although successful hedging might change those percentages. But that’s not the entire business model.
“We believe in volatility...You can sell volatility. Volatility has value,” McClendon continued. “Our company makes additional money when we sell those calls.” What McClendon means is that his company can make money by selling deals to other companies that fear they will be left behind during brief periods of rising prices. For example, in 2008 Chesapeake sold interests in its shale plays to Plains, BP and StatoilHydro. Chesapeake made $10.3 billion on those transactions.
Why do I reach different conclusions about the Haynesville and other shale plays than some industry analysts? First, they are not industry insiders and, therefore, many do not incorporate true operational costs including interest expense for debt service, or netback gas prices into their evaluations. Second, investment company analysts are marketing a product and make a commission on stock that they sell to clients—their analyses cannot be truly objective. Third, they do little investigative research, and generally accept information on rates, reserves, and declines provided by the companies that promote these plays. They cannot have done independent decline analysis on the Haynesville Shale or they would have recognized the obvious reserve discrepancy (1.5 vs. 6.5 Bcf/well).
I expect shale plays to be part of the natural gas landscape for awhile, despite the fact that they are marginally commercial at best. Most companies in these plays have a lot of debt, and the only way to service the debt is to generate cash by drilling wells to produce gas.
The Haynesville Shale play appeared at a time when gas prices were rising. Companies rushed to pay great sums to obtain positions based on the irrational belief that prices would continue to rise. This is the same thinking that brought us the global financial crisis. The magnitude of capital expenditure for leasing and drilling illustrates a profound breakdown of due diligence by the financial and E&P industries.
It is difficult to imagine that the Haynesville Shale can become commercial when per-well reserves are similar to those of the Barnett Shale at more than twice the cost. Maybe the most recently completed wells will tell a different story; otherwise the Haynesville Shale play will likely be replaced by other shale plays that lose less money.
Posted by Arthur E. Berman at 6:44 AM
Haynesville Sizzle Might Fizzle
Despite lower natural gas prices, the Haynesville Shale is the hottest onshore play in North America. Production is more than 150 MMcfd from recently drilled horizontal wells, and single-well Initial Production (IP) rates are as high as 24 MMcfd.
I used standard rate-versus-time methods to determine estimated ultimately recoverable reserves (EUR) for 14 horizontally drilled wells that had sufficient production history to project a decline rate. Production was extrapolated using a hyperbolic decline, and an economic limit of 1.0 MMcf/month. The wells had an average EUR of 1.5 Bcf, and 67% (10 wells) had reserves less than 1.5 Bcf. This is an early evaluation, and does not include several recently completed wells because of insufficient production data. Reserves were, with one exception (5.3 Bcf), considerably lower than the 6.5 Bcfe most-likely per well reserves, and 4.5-8.5 Bcfe range, claimed by leading operators in the play Chesapeake Energy Corporations and Petrohawk Energy Corporation.
Problems with the Haynesville Shale include high decline rates and costs. Average monthly decline for the wells that I analyzed is 20–30%, and projected annual decline rates average 80−90%. Rapid decline makes IP rates unreliable indicators of well productivity. The average production history of wells used in this analysis is less than five months; current production rates already average only 48% of IP.
Drilling and completion (D&C) costs are about $7.5 million per well, although Petrohawk recently revised its D&C costs upward to $8.5–9.5 million. Average true vertical depth of wells in this study is 11,500 ft, and average measured depth is 15,250 ft. Five- to ten-stage hydraulic fracturing is typical with 600–750 lb sand/lateral foot in horizontal boreholes, which average 4,500 ft long. Leasing costs in active areas during 2008 were $10,000–30,000/acre, increasing capital expenditures for an 80-acre spacing unit $0.8-2.4 million above D&C costs.
Operating costs average $2.25/Mcf, based on US SEC 10-K filings and annual reports. After gathering and transportation costs, netback gas prices for early March 2009 were less than $2.50/Mcf (RBC Richardson Barr). Net revenue interest, after royalties, is typically 75%, and Louisiana severance tax is $0.27/Mcf (included in operating cost) . While current prices are the lowest in many years, and hedging has helped careful operators, it cost many operators a $7.25/Mcf or more to produce gas during the fourth quarter of 2008.
Clearly, most Haynesville Shale wells will not approach a commercial threshold until both gas prices and per-well reserves increase. To quantify that reserve and price threshold, I ran a basic NPV10 model using the cost information already mentioned. I used decline rates from the Barnett Shale (65%—Year1, 40%—Year 2, 30%—Year 3, 25%—Year 4, and 20% thereafter) instead of the higher decline rates projected from Haynesville production to date.
The break-even (NPV10= 0), minimum per-well reserve volume is 2.5 Bcf with a netback gas price of $8/Mcf (~$9/MMBtu Henry Hub spot). This means that the play would have been marginally commercial in 2009 dollars during only 15 months (12.5%) over the past decade—and over the past 20 years since the advent of the natural gas commodity market in 1989—if an average well had reserves of 2.5 Bcf instead of only 1.5 Bcf. At 1.5 Bcf/well, $12/Mcf netback gas price is needed to break even.
Chesapeake CE O Aubrey McClendon recently said, “We only need gas prices to be ‘good’ for three to six months out of every two-year period.” (Houston Chronicle, February 11, 2009). If ‘good’ means to break even in the Haynesville Shale, it looks like he will meet costs no more than 12.5% of the time, and lose money the other 87.5%, assuming that per-well reserves can be doubled. That business model is difficult to understand, although successful hedging might change those percentages. But that’s not the entire business model.
“We believe in volatility...You can sell volatility. Volatility has value,” McClendon continued. “Our company makes additional money when we sell those calls.” What McClendon means is that his company can make money by selling deals to other companies that fear they will be left behind during brief periods of rising prices. For example, in 2008 Chesapeake sold interests in its shale plays to Plains, BP and StatoilHydro. Chesapeake made $10.3 billion on those transactions.
Why do I reach different conclusions about the Haynesville and other shale plays than some industry analysts? First, they are not industry insiders and, therefore, many do not incorporate true operational costs including interest expense for debt service, or netback gas prices into their evaluations. Second, investment company analysts are marketing a product and make a commission on stock that they sell to clients—their analyses cannot be truly objective. Third, they do little investigative research, and generally accept information on rates, reserves, and declines provided by the companies that promote these plays. They cannot have done independent decline analysis on the Haynesville Shale or they would have recognized the obvious reserve discrepancy (1.5 vs. 6.5 Bcf/well).
I expect shale plays to be part of the natural gas landscape for awhile, despite the fact that they are marginally commercial at best. Most companies in these plays have a lot of debt, and the only way to service the debt is to generate cash by drilling wells to produce gas.
The Haynesville Shale play appeared at a time when gas prices were rising. Companies rushed to pay great sums to obtain positions based on the irrational belief that prices would continue to rise. This is the same thinking that brought us the global financial crisis. The magnitude of capital expenditure for leasing and drilling illustrates a profound breakdown of due diligence by the financial and E&P industries.
It is difficult to imagine that the Haynesville Shale can become commercial when per-well reserves are similar to those of the Barnett Shale at more than twice the cost. Maybe the most recently completed wells will tell a different story; otherwise the Haynesville Shale play will likely be replaced by other shale plays that lose less money.
Posted by Arthur E. Berman at 6:44 AM
Views: 85
Replies to This Discussion
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Permalink Reply by CB on
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These 2 wells have been the exception, not the norm. Go to DNR, then Haynesville, then download all the HS wells production info. Most wells are much much poorer performers. By the way the decline rate on the #237530 is 57% for 4 1/2 months made 1.85 BCFG. Looks like there will be sweet spots, but not the norm.
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Permalink Reply by w.r. frank on -
What is your point?
Your original post was: "I believe he' right on. Talks facts not the BS hype."
When confronted with facts, you retreat to "not the norm."
Can we agree that the early wells completed in 2007 and early 2008 are not likely to be the norm? E&P's are improving both their drilling (depth, pressure, direction and length of laterals) and completion (proppant, fracs and stages).
You say Mr. Berman is "right on." Right on about what? EUR of 1.5 bcf/well? Right on about operating costs? Right on about Perryville pricing vs. HH? Right on about decline curves?
It seems clear to me that as others have pointed out that the facts don't support Mr. Berman on EUR since some wells have produced substantially more bcf in less than one year than Mr. Berman says will produced over the entire life of the well.
SEC operating costs are for the company--not the HA. Shale. HK reports that its first year LOE for the HA. Shale are 5 cents/mcf. Do you and Mr. Berman mean that this is NOT a fact or are Mr. Wilson and Mr. Stoneburner not speaking the truth or are the 15 HK wells "not the norm."
On decline rates, neither CHK, HK, XCO, ECA, EOG nor Mr. Berman, nor you, nor me, nor anyone else knows because it is in the future. However, HK has released a decline curve which is the average on its first 15 wells (good and bad). The curve is hyperbolic and posted in its DUG presentation and is consistent with the 7 bcf EUR AVERAGE it projects for the its HA. Shale acreage. Incidentally, the average IP for these 15 wells was 18 mmcfd. If you use this average IP and a decline rate of 90%, 30%, 20% and 8% to terminus, you get an EUR of 8.6 bcf (nobody is currently using a 90% first year decline rate). Furthermore, a 57% decline rate is not inconsistent with a hyperbolic decline cure of 80%. After all, it is hyperbolic, not linear.
Finally, using the 18 mmcfd average of HK's 15 wells and a 90% first year decline rate results in first year production 0f 3.6 bcf, more than double the 1.5 bcf EUR that Mr. Berman projects over the entire life of his average HA. Shale well. Perhaps Mr. Berman should revisit his projection.
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Permalink Reply by Grillin' - MmmMmm on
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CB: I work with the science and the economics everyday, on a somewhat local level as well as a North America level and some global level. I think economics are difficult right now, but with the hedges most companies have in place, the wells are doing quite well. I just don't put any SCIENTIFIC or ECONOMIC credence on Mr. Berman's work. It is just too full of holes. If there is one piece of accurate information or proper conclusion, it is offset by 10 mistakes!
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Permalink Reply by JB on
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Sorry, but his assessment is flawed. He never once mentioned geo-political issues or that a direct hit from a cat 3 hurricane could wipe out production and pipelines in the gulf. You can factor in all the numbers, rates, formulas, etc., all he wants, it still does not take into account the variables that are out of our control.
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Permalink Reply by Count of Monte Cristo on
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Have you read The Black Swan? It's a very good read. The biggest impacts to NG prices will probably be unexpected events that almost noone knew was coming.
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Permalink Reply by DaddyT on
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If the Sizzle is going to Fizzle why do I keep getting letters from Chesapeake wanting to buy any Interest or Royalty I might be willing to sell them? They even give a "Hotline" number and want to buy any interest (Overriding Royalty or Working Interest) or anything other interest I am willing to sell them. I do not think it is a Fizzle. There is some reason they would want to buy interest and they aren't going for Dry Holes. They have people working for them that expect pay checks and they are not being advised to buy into a Fizzle.
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Permalink Reply by Jack Blake on
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Off with Arthur Berman's head!!!!!!!!!!!
Shale Geo for President!
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Permalink Reply by joey on
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Yo Haney...not to be confused with The Caney
Don't disrespect our boy and call him the Bossier
Peeps who make that mistake are a hoser
And where you turn to lime
Its time......To break out the acid...
But nowadays there you won't make a dime.
Your pressure gradient is whack
When a pump job goes down there's a frac
But then it grows out of zone and that's a fact
Then some homies from OKC took a core
And when it came to land they just wanted more
Pimpin' royalties till their butts was sore
The TOC in your pores provides a wealth of gas
And that neutron-density response has gotten us to ask
When my drink was on I was lookin' for sand like it was a noble task
Look here we got the Hawk all up in the club
Their IPs are off the hook when mo' money comes from the Hub
And now Barak Obama wants to tax all the pub
And what's up with yo bro' Barney?
I went to N. TX to axe him for some money
Homie straight up sicked his chickenhead on me like it was funny
Naaah, that's alright 'cause then I saw yo' cuz from PA
He pimped my ride and straight-up promised to pay
'Cause Marcello always had the gas but didn't produce until today
As for reserves there are a few engineers that should be fired
For not knowin' that pseudo-steady state flow is required
When pimpin' decline curves for the EUR desired
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Permalink Reply by king john on
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dude,
that s been cracking me up all day!
free stylenn and profilenn!
kj
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