4 Sep 2010.
At current prices, most shale gas production is almost certainly unprofitable. Further, the excess supply from shale has caused conventional producers to reduce drilling. I will be surprised if we do not see the excess supply disappear, and gas prices rise substantially, by the end of 2011.
Clippings below covered through 2 Sep 2010.
Definitions (3 Sep 2010)
Many reputable people in the area think costs are understated (3 Sep 2010) For example:
Evidence that costs are being understated (3 Sep 2010)
At least drilling and, in many cases, presenting rosy views may be required for survival (3 Sep 2010)
Break-even price (4 Sep 2010)
History of feast or famine (4 Sep 2010) MIT provides a history of the feast or famine cycles in the gas markets, that is both depressing and amusing. See 25 Jun 2010 clipping below. The very short story is
8 Apr 2009. Seeking Alpha.
“Shale Gas Companies: All Talk, No Walk? Keith Schaefer”
“Ben Dell is the senior energy analyst at Bernstein Research in New York, one of the top sell-side research firms. In a March 27 research note, he notes “a growing discrepancy between the internal rates of return (IRR) presented in corporate presentations and company reported ROACE (return on average capital employed)… For example, in many plays companies claim to generate IRR’s above 100% at $7.50/mcf gas or claim that their production is economical even at $2-3/mcf gas prices, but at the same time report 6-7% ROACE at a corporate level over the last 3 years, when the average gas price was $7.50/mcf.”
Titled “Why the Haynesville Won’t Work…at $4, $5, or $6/mcf gas”, Dell posits that companies are overstating production, understating costs, or there is a terminology gap at work. For example, a producer could say the IP rate of a well (Initial Production) is 8 mmcf/d (million cubic feet per day). But was that a 30 day average, as is normal, or was it a 12 hour average just after coming online. These HD wells can decline in production so rapidly sometimes that for stock promotion purposes, companies issue figures that may have been correct for a short time, but have no context and are not really “best practises” type numbers.
Dell also questions if the all in costs of a well are being amortized properly into the economics that appear in a company’s press release. If the cash operating cost of a well is $3/mcf, which is the number that appears in a release that does not include the $4-7 million it cost to buy the land and drill the hole - costs that Dell suggests basically doubles the breakeven level of the well to $6/mcf. And to get an acceptable return - even to generate enough cash to drill the next well - would be $8/mcf.
He told his readers how one operator in the Haynesville Shale in northern Louisiana (the most prolific shale play in North America) implied a greater than 100% IRR on a very large 14 mmcf/d well. But once Dell started amortizing in some of his own estimated costs for land and drilling and taxes, that came down to a very pedestrian 14% IRR. …
A Canadian firm, Peters & Co. out of Calgary, echoed those thoughts this week with a brief commentary “Where is All the Cheap Gas?”
They ran some numbers on costs on companies operating in shale gas plays on both sides of the border - the FD&A, Finding, Development and Acquisition costs, and tried to adjust for currency differences. And what they came up with is that
This would be quite bullish for natural gas prices and stocks. Concludes Peters & Co: “the prediction that natural gas prices will be capped at US$6.00 per Mcf may prove to be a little premature.””
6 Jun 2009. Resource Investor.
“Natural gas: Costs go down as learning curve goes up. Keith Schaefer”
“Operating costs are still coming down in North American natural gas and oil plays. This isn’t showing up as reduced all-in costs on the financial statements of these energy producers just yet, but it will.
Costs are lowering for two reasons. One is demand destruction, which has cut in half the number of rigs drilling for oil and gas in North America. This has meant that rig rates have also dropped – energy executives are saying they see 20%-35% cost reductions year over year. Lower drilling costs have an obvious impact on profitability.
The second is that companies in both the US and Canada are figuring out how to properly frac these new unconventional gas plays – both tight gas and shale gas.
There was a 20-year learning curve to get the first shale play, the Barnett Shale in Texas, into production. (It’s actually a great story of petrochemical engineering and sleuthing that I will share with you all another time.) Well, that learning curve is still happening. Production out of these long horizontal wells is getting better in all the unconventional gas (and oil) plays in North America.
Chesapeake (CHK-NYSE) is the largest natural gas producer in the United States. They announced in their latest quarterly that they have a new well producing 9.6 million cubic feet of natural gas (mmcfe) – and associated liquids – per day during the past 30 days, which they believe to be the highest 30 day rate of any well in the entire Barnett Shale play to date.
In the Bakken oil play in North Dakota, Canada’s largest brokerage firm, RBC, said in a May 22 report that average initial production (IP) rates have moved up from 417 boe/d in Q2 2007 to 1294 boe/d in Q2 2009. (This number can be skewed by where in the play is being drilled, but the trend is clear).
Calgary based securities firm Tristone Capital says wells in the Montney gas play on the BC-Alberta border are now 8-10 mmcf/d, about twice what they were when the play first started.
And as I wrote in an earlier article, the energy producers are learning how to frac these plays much better, using special mixes of chemicals and water to get the most oil or gas out of these new, very tight reservoirs. It can sometimes take some expensive trial and error on how to get that frac formula right.
Tristone estimates the average break even level of these new shale plays is now hovering around $5/mcf, with the best plays already at $4, and as the learning curve goes up, the cost curve will continue to go down, taking the break even price for natural gas production down with it.
What will likely mask these costs on the financial statements of these companies is the huge land acquisition costs these companies had to pay for these unconventional plays. As an example, British Columbia in Canada has sold their land rights at an average $680/hectare (1 hectare = 2.5 acres) compared to $3511 per hectare over the same time frame in 2008 – and B.C. has the new Horn River Basin in the north and part of the Montney gas play along the Alberta border. Both 2007 and 2008 saw huge land cost increases across North America as companies rushed in to buy up acreage.
In the industry you will hear of this being talked of as “full-cycle” costs – how much it costs to get the gas to market right from the time the land is purchased – versus “half-cycle” costs, which, in broad terms, is really just the operating costs.
Companies usually show their long term finding costs (how much it cost to find and develop a barrel of oil into a reserve category) in their financial statements over the life of their reserves. So those very high land acquisition costs will get amortized in over a long period of time.
For the majors, this is not a big deal – their finding costs rarely vary – but for junior and intermediate companies whose reserves can change a lot, it can have a big impact on their balance sheets.
Until some of these high land costs are amortized out, don’t expect to see the “accounting” cost of finding a barrel of oil – usually shown as DD&A - Depletion, Depreciation and Amortization – on the balance sheet, to go down much, even though “real” costs are dropping a lot.
So when people ask “Where is all the cheap gas?”, it’s here, and it’s getting cheaper by the month, but it might not show up in the companies’ financial statements for awhile.”
[This does not answer the main criticism of the skeptics, that current costs are not being properly figured or reported.]
5 Sep 2009. DrillingInfo.com
“How Arthur Berman Could Be Very Wrong… Allen Gilmer, Ramona Hovey, and Jason Simmons”
[Takes issue with a great many details, but does not directly address the question of break-even cost.]
12 Oct 2009. Association for the Study of Peak Oil website.
“Shale Plays A Time for Critical Thinking. Arthur Berman (petroleum geologist)”
[Much of the presentation is about the models used to predict EUR (Estimated Ultimate Recovery), and how small changes in parameters, early in the life of a project, can greatly influence EUR. This is powerpoint, and is not fully explained, but does provide some feeling for how optimists and pessimists could get very different answers from the same data.
Berman gives a feeling for how the psychology of the situation could drive unrealistic EURs:]
Observations and Conclusions
1 Dec 2009. GLG (a facilitator of expert consultants)
“Shale Gas Debate Generates War of Words But No Hard Conclusions Yet”
“For some, the new shale plays appear to be a Rube Goldberg scheme to raise capital and attract investors to feed the drilling addiction of oil and gas industry managements who are anxious to amass Wall Street investors and have found production volume growth via shales as the method to do so. In the end, according to these naysayers, the shale plays haven’t demonstrated that they produce the economics oil and gas management claim, except in very high commodity price environments.
A large coterie of industry participants dispute the methodology and credentials of the naysayers and promise more gas (production volume growth) and strong economics from the shale renaissance underway in the domestic energy market.
A subset of this viewpoint argues that shale supplants other gas sources over time because of superior economics and the industry grades out into winners, or those who have shale, and losers, or those who do not.
War of the Words took on new meaning over the last month with a series of high profile events. The November massacre at World Oil magazine became the latest event in the long-simmering industry donnybrook over the true economics of the new shale gas plays. Apparently, a couple oil and gas company complaints about columnist Arthur Berman may have been a factor in the cancellation of Mr. Berman’s monthly column for the magazine. Mr. Berman has publicly questioned some numbers oil and gas company managements toss about on shale plays in a series of columns dating back a year. The ensuing blowback over the Berman column apparently resulted in the firing of longtime World Oil editor Perry Fischer. …
DrillingInfo.com subsequently published a piece disputing particulars of the Berman Thesis, arguing that new best practices means the conclusions Mr. Berman drew from older wells in plays like the Barnett Shale no longer describe the reality of the shale play. …
(The best single source on the Berman Thesis is Arthur Berman’s ongoing blog at: petroleumtruthreport.blogspot.com. Mr. Berman includes letters from (former) World Oil editor Perry Fischer in his November archives, but magnanimously incorporates rebuttals and criticisms of his thesis from viewpoint opponents, including the complete text of the 10-point Tudor Pickering Holt rebuttal as well as a reprint of the Devon op ed piece from the Oklahoma City paper.
The Drillinginfo rebuttal to the Berman Thesis can be found by scrolling down the link at: http://info.drillinginfo.com/wireline/category/ceocorner/)
The takeaway? Only time will fully inform this debate since several shale plays are so new that there just isn’t enough data to determine how they will pan out. Clearly there is a lot of shale gas potential. But the big picture question is how the interplay of technology, production, and economics will settle over time. One example: are operators harvesting a finite volume of gas more quickly now, or are operators actually increasing the ultimate recovery of gas with high profile IPs (Initial Production) from more frac stages and greater well stimulation inputs? …
In the end, the one fact that seems to surface over and over again is that there just isn’t enough data yet to prove definitively one set of arguments versus the other. Like Peak Oil, no one will know whether the Berman Thesis pans out until well after the fact.
No one denies that the shales have plenty of gas. The question is when will those massive ongoing capital expenditures pay out for investors—and at what commodity price scenario?”
28 Jan 2010. Hart publications, E&P website.
“Gas shales: Energy market solution or problem? Allen Brooks (of Parks Paton Hoepfl & Brown, an energy investment bank)”
“The attraction of gas shales is their production profile — substantial initial production (IP) from wells and large economic ultimate recovery (EUR) potential. These characteristics have convinced producers that the economics of gas shales can be attractive, even in an era of relatively low natural gas prices. …
Leading gas shale producers claim Barnett wells are economic with natural gas prices above US $1.35 per Mcf.
As the industry has moved to exploit other gas shale basins, technological improvements have yielded greater IPs and supposedly EURs too. The conventional wisdom is that the Haynesville, Fayetteville, and Marcellus shales, despite higher lease expenses, are economic with gas prices in the $1.50 per Mcf range. These newer and highly prolific gas shale formations have wowed the energy world with IP flow rates substantially greater than conventional or even Barnett wells. But associated with the strong IPs is a more rapid production decline than the historical norm. This has set the industry on a steep treadmill to sustain production.
There has developed a strong debate within the industry about the economics of gas shales. Leading producers argue that huge IPs are associated with large EURs and long productive well lives, making developments profitable even in today’s low gas price environment. Critics suggest production decline rates are much greater and residual producing volumes so low that EURs are overstated, undercutting profitability estimates. With high acreage costs, large royalty payments, and expensive wells, critics question whether gas shale producers are making any money at current gas prices. Critics suggest gas prices must rise to the $7 to $8 per Mcf price level before producers break even.
Energy investors have embraced the gas shale phenomenon. In fact, if producers don’t have gas shale acreage to highlight in investor presentations — suggesting reserve and production growth — they are ignored in the marketplace. By overstating producing gas shale reserves, companies are able to show extremely favorable finding and development (F&D) economics. Low F&D costs are critical for producers to tap Wall Street for the funds necessary to sustain their aggressive gas shale drilling efforts.”
19 Feb 2010. Energy Tribune.
“New Research Questions Haynesville Shale Economics. By Allen Brooks (managing director at Parks Paton Hoepfl & Brown, a Houston-based investment banking firm)”
“Key to the gas shale revolution is the huge initial production (IP) from wells in certain of the newer plays – Haynesville, Fayetteville, Eagle Ford and Marcellus Shales. The high IP rates of these horizontal wells are believed to lead to the recovery of significantly larger volumes of natural gas than can be extracted from vertical wells. The high IP’s and greater reserve recoveries contribute to low industry finding and development costs that make the fields highly profitable even at relatively low natural gas prices. High well reserve potentials at low per-unit costs have spawned a gas shale leasing boom, which, due to short lease lives, is stimulating a drilling boom. The downside of this industry focus on shales has been sustained natural gas production that has limited any rise in gas prices since demand has yet to recover.
Last week, two different analyses of the Haynesville Shale concluded that the economics of this basin have peaked and it will not become the bonanza producers and investors have forecasted. One of the analyses came from industry consultant Art Berman of Labyrinth Consulting Services, Inc. while the other came from Wall Street E&P analyst Ben Dell of Bernstein Research. Berman’s research report will soon be available on his blog, but we were provided with an early version.
So what’s behind the conclusions of these two analysts?
Both Berman and Dell have studied the results of roughly 135 (133 and 136, respectively) horizontal wells drilled and producing in the Haynesville Shale. The recent data shows that the average IP of Haynesville Shale wells is starting to fall and increasing the number of fracture treatments in each well is not helping to improve their output. While the basin’s production has grown dramatically since 2008, it now appears to be holding steady, which obscures the fact that the leading E&P companies are experiencing declining IP’s. In other words, the recent rise in the basin’s total production is largely due to better performance from newer entrant E&P companies and their use of larger numbers of fracture treatments in each well they drill.
Berman plotted the daily production from the Haynesville Shale wells owned by Petrohawk (HK-NYSE), which appear to be primarily in the core (most prolific) area of the basin. The IP starts high but then declines rapidly. The average daily production line he calculates, which admittedly may be influenced by the natural distortion arising from mathematical averaging, shows a rapid decline before stabilizing within one year. If accurate, these wells are reaching stable production much faster than wells in the Barnett, the oldest producing gas shale basin. That may mean lower volumes of gas recovered from these wells.
Based on the well production data, both analysts conclude the core of the Haynesville Shale will be smaller than for the Barnett Shale and with worse well economics. They question whether wells located outside of the core area will be economic at today’s natural gas prices. They also question whether wells will produce the volume of gas initially predicted. If so, the Haynesville Shale will not be as large a gas field as suggested by early entrant explorers.
A conclusion that comes from examining the well locations and their IP’s is that there appear to be faults in the basin defining the core and non-core areas. The production data from wells in the core is better than from non-core wells. This structural definition within the basin suggests that the development of the Haynesville Shale will not be a “manufacturing process” where the key to growing the basin’s production is merely drilling more wells and using the optimal number of fracture stages.
Dell’s analysis of the basin’s wells concludes that there are three distinct areas within the core area along with a large non-core area. Within the core area, according to the data, in 2009 the average IP rate of wells drilled was 9.7 million cubic feet per day (MMcf/d) compared to an average of 6.9 MMcf/d for wells drilled outside the core area. The western core area showed an average well IP of 7.5 MMcf/d; the lowest rate within the three core areas. Since all wells were completed with 11 fracture stages, these production results suggest that the well IP performance is related to geology and not due to less complicated well completions.
Berman’s analysis concludes that the average economic ultimate recovery (EUR) of wells in the Haynesville Shale is 2.0 billion cubic feet (Bcf). Based on his analysis of lease, drilling and completion, and operating costs, he estimates the minimum EUR breakeven economics at 5.0 Bcf per well. Of the wells he analyzed, only 11% meet or exceed this commercial breakeven threshold.
While Berman and Dell are critical of Haynesville Shale economics, there remain many Wall Street analysts and industry participants who believe this basin, and all other gas shale basins, will provide long-term profits for E&P companies. One Wall Street firm has estimated the economics for all the major gas shale basins, which includes an estimate of the threshold price needed for profitability. In the case of the Haynesville Shale, the firm estimates the threshold price at $4.40 per thousand cubic feet (Mcf). As natural gas prices are currently in the $5.45/Mcf range, there is roughly a dollar of profit per Mcf. A critical ingredient in this analysis, however, is the estimate of finding and development (F&D) costs. This cost estimate includes all the direct costs such as leasing expense, drilling and completion costs and production maintenance costs, and a share of the corporation’s overhead. In the future, however, there will likely be significant additional costs for new fracturing treatments that will be an ongoing need to sustain gas shale well production. The F&D estimate is also dependent on an assumption of the volume of discovered gas reserves that ultimately will be produced. The greater the gas volume estimate, the lower the F&D cost, and the easier to predict well profitability.
What is the significance for the domestic natural gas industry if the Haynesville Shale turns out to be smaller/less economic than initially anticipated? Early speculative estimates claimed the Haynesville Shale might contain 250 trillion cubic feet (Tcf) of natural gas. Last year, when the Potential Gas Committee reported that the nation had 1,836 Tcf of technically recoverable gas resources, it also estimated that 616 Tcf of this total was contained in gas shale formations. Based on the early estimates, the Haynesville Shale would account for roughly 40% of this estimated total. If the Haynesville Shale does not contain as much gas, does it call into question the Potential Gas Committee’s total resource estimate? Would that shortfall potentially undercut the universal belief that natural gas, especially given the contribution from the gas shales, will be the bridge fuel from an economy relying on dirty hydrocarbon fuels to one powered by clean fuels?
It may be early to draw definitive conclusions, but one at least needs to ask the question: What if?”
20 Feb 2010. ET.
“A Response to “New Research Questions Haynesville Shale Economics”. By Michael Economides, ET editor in chief ”
“I understand Allen’s qualified skepticism, but let me remind all that as late as 2005, the US Geological Survey was rating both the Haynesville and the Marcellus Shales at about 1 trillion cubic feet of recoverable gas. [complete non-sequiter] …
The fact that newer wells in the Haynesville produce at lower initial production should be expected and is likely because of reservoir pressure depletion or because of lower reservoir permeability in outlying locations. Executing more fracture treatments is an easy way to remedy the problem and because of the very low reservoir permeability, they interfere very little with each. [logic is an aberration]”
6 Mar 2010. FTUSA p14.
“The heat continues to rise on the cost of producing shale gas. John Dizard”
“maintaining, let alone increasing, US use of natural gas will require a very substantial increase in prices over the present spot and futures levels. On that point, the shale gas industry people and I are in agreement. One set of data points might turn out to be revealing. Look up the “balancing item” in the “natural gas navigator” on the US Energy Information Administration's website. This is how the difference between reported gas storage and the net of production and consumption is explained. For the last report, in December, the “item”, or unexplained error, is about 100bn cu ft. That is a whole bunch of gas, as they say out there.
The “item” has been increasing steadily from the middle of last year. So production is likely lower, or consumption much higher, than the EIA has been able to count. Given that production is calculated from a sample of producers that is probably overweighted to large companies with access to capital markets, it is probably the case that production is lower than Washington, or most of Wall Street, thinks. Smaller gas producers, who are probably under-sampled, will have had their access to debt or equity proportionately much more restricted than was the case in the boom years.
If that analysis is correct, the US will run short of low priced gas sooner rather than later.
To their credit, gas prophets such as Aubrey McClendon, chief executive of Chesapeake Energy Corp, have been saying that gas at $5 per thousand cu ft is not sustainable. In their laudable enthusiasm for their business, though, they may have understated just how unsustainable the price is.
Ben Dell of Bernstein Research in New York who has, so to speak, done some of the deepest drilling into the shale gas industry numbers, believes that the full cost of finding, developing, and operating shale gas wells , and paying an average return on capital to investors, requires a spot gas price of $7.50 to $8 a thousand cu ft.
As Mr Dell points out, the horizontal drilling rigs that are needed to drill shale gas wells are in relatively short supply. “We think there will be a 15 per cent to 20 per cent increase in costs from last year to this year. That includes the costs of drilling and fracking [hydraulic fracturing of rock layers holding gas].”
Furthermore, the producers partially insulated themselves from gas price weakness over the past year with hedges that are gradually running off. New hedges have to be put on at lower prices. So revenues will be declining while costs are increasing.
Shale gas is not magic. Production costs are high, and probably underestimated. An even more gas-dependent policy will accelerate the coming price rise. For the producers' sake, it better.”
20 Mar 2010. FTUSA p14.
“A glimpse through the smoke and mirrors of shale economics. John Dizard”
“A couple of weeks ago, I quoted Ben Dell, an analyst with Bernstein Research in New York, as estimating the shale gas industry really needs a price of $7.50-$8 to break even on its all-in costs of finding and producing the stuff, which would be a 60 per cent price rise. …
I worked people in the energy service industry, and gas producers to try and refute Ben Dell's numbers. I could not. My industry sources' numbers all converged close to $8 per mcf. They do not believe the producers are covering their all-in costs.”
25 Apr 2010. Financial Times.
“Chevron chief shuns shale gas rush. By Sheila McNulty”
“John Watson, chief executive of Chevron, is refusing to join rival international oil majors in the rush for US shale gas, warning that the “price tag is too high” to justify the investments required.
Mr Watson, who has only been in the top job at the US’s second-biggest oil company for three months, is confident his decision not to follow the pack into US shale gas is the right one. “We haven’t seen the returns,” he told the Financial Times.”
25 Jun 2010. MIT Energy Initiative website.
“The future of natural gas”
”[History of feast or famine]
The somewhat erratic history of natural gas in the U.S. over the last three decades or so provides eloquent testimony to the difficulties of forecasting energy futures, particularly for gas, and is a reminder of the need for caution in the current period of supply exuberance.
This history starts with a perception of supply scarcity. In 1978, convinced that the U.S. was running out of natural gas, Congress passed the Power Plant and Industrial Fuel Use Act (FUA) which essentially outlawed the building of new gas-fired power plants.
Between 1978 and 1987 (the year the FUA was repealed) the U.S. added 172 Giga- watts (GW) of net power generation capacity. Of this, almost 81 GW was new coal capacity, around 26% of today’s entire coal fleet. About half of the remainder was nuclear power.
There then followed a prolonged period of supply surplus. By the mid 1990s, whole- sale electricity markets had been deregulated; new, highly efficient and relatively inexpensive combined cycle gas turbines had been deployed; and new upstream technologies had enabled the development of offshore gas resources. This all con- tributed to the perception that natural gas was abundant, and new gas-fired power capacity was added at a rapid pace.
Since the repeal of the FUA in 1987, the U.S. has added 361 GW of power generation capacity, of which 70% is gas fired and 11% coal fired. Today, the name-plate capacity of this gas-fired generation is significantly underutilized.
By the turn of the 21st century, a new set of concerns arose about the adequacy of domestic gas supplies. For a number of reasons, conventional supplies were in decline, unconventional gas resources remained expensive and difficult to develop, and overall confidence in gas was low. Surplus once again gave way to a perception of shortage and gas prices started to rise, becoming more closely linked to the oil price, which itself was rising. This rapid buildup in gas price, and perception of long term shortage, created the economic incentive for the accelerated development of an LNG import infrastructure.
Since 2000, North America’s rated LNG capacity has expanded from approximately 2.3 Bcf/day to 22.7 Bcf/day, around 35% of the nation’s average daily requirement. This expansion of LNG capacity coincided with the market diffusion of technologies to develop affordable unconventional gas. The game-changing potential of these tech- nologies has become more obvious over the last three years, radically altering the U.S. supply picture. The LNG import capacity goes largely unused at present, although it provides valuable optionality for the future. We have once again returned to a period of supply surplus.
This cycle of feast and famine demonstrates the genuine difficulty of forecasting the future, and underpins the efforts of this study to account for this uncertainty in an analytical manner.”
18 Jul 2010. FT.com.
“The shale gas fairytale continues. By John Dizard”
“I looked again at shale gas production reports, development costs, technical papers, and, yes, the PowerPoints. I went to Texas to meet producers, geologists, and landmen.
And I’m sticking with my position. Yes, shale gas is there, but it is expensive to produce, and there is much, much less of it available at today’s low prices than policy people, investors, and energy consumers are counting on. …
American shale gas companies assert that they can profitably produce gas from formations such as the Marcellus in Pennsylvania for $2 or $3 per mcf (thousand cubic feet). But in the fine print you find that represents only the “finding and development” costs, which are only a quarter to a third of the total needed to get a molecule to market.
And when gas promoters say “per mcf”, those mcf’s are projected over 30 or 40 years, or even longer. Not that there are any horizontally drilled, fracked shale wells that old, but accountants exist to make generous assumptions. In fact, wells in one of the first shale fields developed with the new technologies, the Barnett in Texas, have had faster-than-expected productivity declines.
One large German bank’s commodity group is developing its own estimates of the average economic life of shale fields; they think 10 years is a reasonable assumption. That is close to what Arthur Berman, a sceptical Houston geologist, thinks is reasonable. As Mr Berman says: “Unconventional gas has at least twice as fast a decline rate as conventional resources. About 85 per cent of the value of shale wells in the Barnett will be produced in the first 10 years.”
Yes, there is a lot of shale gas in the world. It will take prices perhaps twice as high as today’s to maintain gradual increases in production when capital is no longer provided as freely.”
28 Jul 2010. The Oil Drum.
“Arthur Berman talks about Shale Gas. Posted by Gail the Actuary”
“Recently, ASPO-USA's newsletter printed an interview (Part 1 and Part 2) with Oil Drum staff member Art Berman (aeberman). Art is a geological consultant whose specialties are subsurface petroleum geology, seismic interpretation, and database design and management. The people doing the interview are members of the “Peak Oil Review Team,” abbreviated POR in the text below. This is the shale gas portion of the interview. …
One other important thing is the Barnett shale. We keep coming back to it because it’s the only play that has much more than 24 months worth of history. I recently grouped all the Barnett wells by their year of first production. Then I asked, of all the wells that were drilled in each one of those years, how many of them are already at or below their economic limit? It was a stunning exercise because what it showed is that 25-35% of wells drilled during 2004-2006-wells drilled during the early rush and that are on average 5 years old-are already sub-commercial. So if you take the position that we’re going to get all these great reserves because these wells are going to last 40-plus years, then you need to explain why one-third of wells drilled 4 and 5 and 6 years ago are already dead.
POR: When you say one-third of the wells are already sub-commercial, do you mean they have been shut in, or that they are part of a large pool where no one has sharpened the pencil?
Berman: Some of them never produced to begin with. No one talks about dry holes in shale plays, but there are bona fide dry holes-maybe 5 or 6 or 7 percent that are operational failures for some reason. So that’s included. There are wells that, let’s just call them inactive; they produced, and now they’re inactive, which means they are no longer producing to sales. They are effectively either shut-in or plugged. Combined, that’s probably less than 10 percent of the total wells. But then there are all the wells that are producing a preposterously low amount of gas; my cut-off is 1 million cubic feet a month, which is only 30,000 cubic feet per day. Yet those volumes, at today’s gas prices, don’t even cover your lease/operating expenses. I say that from personal experience. I work in a little tiny company that has nowhere near the overhead of Chesapeake Energy or a Devon Energy. I do all the geology and all the geophysics and there’s four or five other people, and if we’ve got a well that’s making a million a month, we’re going to plug it because we’re losing money; it’s costing us more to run it than we’re getting in revenue.
So why do they keep producing these things? Well, that’s part of the whole syndrome. It’s all about production numbers. They call these things asset plays or resource plays; that reflects where many are coming from, because they’re not profit plays. The interest is more in how big are the reserves, how much are we growing production, and that’s what the market rewards. If you’re growing production, that’s good-the market likes that. The fact that you’re growing production and creating a monstrous surplus that’s causing the price of gas to go through the floor, which makes everybody effectively lose money….apparently the market doesn’t care about that. So that’s the goal: to show that they have this huge level of production, and that production is growing.
But are you making any money? The answer to that is…no. Most of these companies are operating at 200 to 300 to 400 percent of cash flow; capital expenditures are significantly higher than their cash flows. So they’re not making money. Why the market supports those kinds of activities…we can have all sorts of philosophical discussions about it but we know that’s the way it works sometimes. And if you look at the shareholder value in some of these companies, there is either very little, none, or negative. If you take the companies’ asset values and you subtract their huge debts, many companies have negative shareholder value. So that’s the bottom line on my story. I’m not wishing that shale plays go away, I’m not against them, I’m not disputing their importance. I’m just saying that they haven’t demonstrated any sustainable value yet.”
12 Aug 2010. Platts Energy Week.
“Devon Energy CEO says current price of gas means economics of increasing drilling rigs is not sustainable. Regina Griffin”
“Gas rig counts will begin to decline in the middle of 2011 if prices continue to hover around $5/MMBtu, the president and CEO of Devon Energy said Wednesday.
“Something isn't working right now; either the price has to come up or costs have to come down for rig increases to be sustainable,” John Richels said during a speech at the Petroleum Club in Houston.
In an interview afterward, Richels said the sharp increase in the gas rig count over the past year stemmed from producers drilling in order to hold their leases. Many of those leases were purchased in 2008 for two- or three-year terms and, once they expire or are renewed, drilling should slow and the rig count should start falling, he said.
In his speech, Richels said the gas industry is facing an unusual phenomenon: $5/MMBtu gas in both the spot and forwards markets. “The contango is out of the forwards market. … We are going to have to deal with some very difficult economics,” he said.
Some of the liquids-rich gas plays in the US work with prices at that level, but most gas drilling activity is not occurring in such plays, Richels said. As a result, gas prices would have to reach $6 to $7/MMBtu and stay there to sustain drilling activity.
[and more generally on Devon's strategy:]
Richels said Devon would continue its shift toward oil and liquids - part of a growing trend among independent producers. “We've never really wanted to be just a natural gas company or just an oil company,” he said. “We always thought that having some kind of a balance was a better thing in the long run.”
About 40% of Devon's reserves comprise oil, condensates and liquids, while 60% is gas. About 80% of the company's capital expenditure budget is going to oil and condensate plays or to gas fields rich with natural gas liquids, he said.
But Richels stressed that Devon will continue to aggressively develop shale gas reserves, which have been “a huge revolution in this industry.”
Devon has 4,300 to 4,400 wells in the Barnett Shale of North Texas and has leased substantial acreage in up-and-coming shale formations, including the Avalon Shale in New Mexico, the Cana Woodford Shale in Oklahoma and the Wolfberry Shale in Texas.
On the financial front, Richels said the company 's sale of offshore and foreign assets has yielded a greater profit than the $4.5 billion to $7.5 billion it was expecting. “It looks like we are getting about $8 billion,” he said, cautioning that a few deals are still pending.
The divestitures have allowed Devon to become “essentially debt-free” and to have “a lot of flexibility in how we deploy our capital,” the CEO said.”
20 Aug 2010. GuruFocus.com
“Devon Energy CEO Expects Consolidation of Independent Natural Gas Producers – And Higher Gas Prices in 2011”
“John Richels who is the CEO of Devon Energy (DVN) presented at the NAPE Expo conference in Houston on Wednesday. What I found interesting was why he expects a merger wave in the fairly near future. According to Richels the consolidation should already have happened, but has been deferred by a huge cash infusion from Wall Street which has allowed independent producers to continue drilling even as natural gas prices are low. Richels expects that the availability of this cash will soon end which will pressure debt laden producers to sell.
Another factor that has allowed these companies to keep drilling has been the hedges that were laid on during 2008 at much, much higher natural gas prices. Richels thinks that as these expire cash flows for the independent producers will drop and so will spending on new wells. Richels and company believes that as 2011 rolls around there will be a reduction in drilling which will lead to higher natural gas prices. …
The old saying is that the best cure for lower gas prices is lower gas prices. And we will start to see this going forward. Chesapeake plans to make a large shift in it’s drilling capex to move from 90% natural gas drilling to a 50/50 split between gas and oil. Sandridge Energy is another which will go from being primarily a natural gas driller to over 80% oil drilling. It is going to take some time, but the market will address this oversupply.
Richels also went on to say that much of the current drilling for natural gas in the U.S. isn't profitable at current prices, as drilling costs for the natural gas and oil industry onshore the U.S. has significantly increased and that the trend is expected to continue.
Another well respected voice in the energy business is legendary figure Henry Groppe. Groppe has had a knack for correctly calling the oil market time and time again. Back in May he also predicted rising natural gas prices, here is recap of his thinking at that time:
“Everyone thinks [shale gas] is going to solve all of our problems. There are very optimistic estimates about the economically recoverable volumes of gas from this new resource,” he said in an interview last week in the Toronto offices of boutique fund manager Middlefield Capital Corp., where he's a long-time consultant and is special adviser to the nine-month-old Middlefield Groppe Tactical Energy mutual fund.
“That's dominating everyone's views about the gas supply picture – that we're going to be flooded with gas.”
The reality, he argues, is that shale gas deposits are a tiny part of the North American production pool – and they are already depleting fast.
Mr. Groppe says that while the average depletion rate in conventional gas wells is about 25 per cent (in other words, if you didn't drill at all for new wells, production would decline by a quarter each year), shale gas shows even more rapid depletion – output tumbles, on average, 45 per cent in the first year for shale wells.
Drilling of shale plays has recovered rapidly from the slowdown during the recession – indeed, the count of active horizontal drill rigs in the United States has ramped up to record levels – which, because of the high initial production volumes that are characteristic of shale wells, has flooded the market with supplies and fuelled expectations of continued rapid growth. But given Mr. Groppe's depletion numbers, the high drilling pace may also be serving to drain the resource in the major shale pools even faster than they would otherwise.
As for the shorter-term supply picture, Mr. Groppe notes that for all that horizontal drilling frenzy, shale gas accounts for just 6 per cent of U.S. natural gas production.
In the other 94 per cent – conventional gas – the rig count is 70 per cent below the pre-financial-crisis levels of September, 2008, as low prices and high inventory levels have convinced producers to keep drills idled.
“With that extraordinary drop in drilling, the [production] decline rate from all these [non-shale] sources is accelerating – and will be much more than offset whatever increases you get in shale.”
Add to that the fact that consumption continues to grow as the economy recovers, and he believes the glut in gas will prove strikingly short-lived.
“We think that we're now having a continuous, rapid decline of gas in storage,” he says. “By summer, it could get to be alarming.”
“We would expect gas prices to get above $8 in the August-September range.”
With natural gas now just over $4 Mr. Groppe is either early or wrong with his call.”
2 Sep 2010. Investing Daily.
“Pugh Clauses and Shale-Gas Activity. By Peter Staas”
“Why hasn’t Chevron made a bigger splash in North American shale gas? During last year’s third-quarter conference call Vice Chairman George Kirkland indicated that an oversupply of natural gas had prompted management to curtail its drilling activity in the Lower 48 states.
Kirkland elaborated on this decision during a recent conference call to discuss Chevron’s second-quarter results: “We like unconventional gas where we can make reasonable returns…[Our US holdings] don't presently make development sense because the gas price and the market conditions with oversupply in the U.S. just doesn't make it attractive.”
This statement reflects an apparent anomaly in the domestic market for natural gas: Drilling activity in unconventional plays remains robust despite depressed natural gas prices–a puzzling disconnect that prompts many investors to steer clear shale-gas producers.
Attractive economics in some of the nation’s hottest shale plays partially explain why producers continue to ramp up production, even as the seasonally weak “shoulder” period approaches and concerns.
As my colleague Elliott Gue explains at some length in Why Some Natural Gas Is Worth $7.28, producers in the Eagle Ford and Marcellus, two shale plays rich in natural gas liquids (NGL), continue to enjoy solid profit margins. NGLs such as propane, butane and ethane tend to command a higher price that tracks crude oil; for many producers, the natural gas is almost an afterthought.
But NGLs don’t explain why drilling activity remains strong in the Haynesville Shale, a dry-gas play in Louisiana and east Texas. Although profit margins aren’t as attractive as in liquids-rich areas, producers can still eke out positive returns because the play is so prolific. …
Why then is Chevron’s Vice Chairman down on the US natural gas market? The answer relates to the Pugh Clause, a term contained in most of the leases that producers sign with landowners in parts of the US.
Louisiana attorney Lawrence Pugh pioneered the clause in the 1940s to ensure that energy companies developed leased land within a reasonable amount of time.
Although these clauses vary slightly, they generally require the operator to make the well commercially viable within a certain period. Producers that fail to comply with these requirements run the risk of losing their lease–and a substantial amount of money.
Chevron doesn’t pay royalties on its holdings in Colorado’s Piceance Basin, and its position in the Haynesville Shale is “held by production” (HBP)–that is, the company produced commercially viable wells within the allotted time frame. In other words, Chevron has the flexibility to curtail drilling activity without fear of forfeiting its acreage.
Many producers aren’t in this boat. The case of the Haynesville Shale is particularly instructive, as the returns aren’t as compelling as those offered by the Eagle Ford and other liquids-rich plays.
Producers began snatching up acreage in earnest in 2007 and 2008, primarily under three-year terms; most management teams readily acknowledge that ensuring that these leaseholds are HBP is a top priority.
Consider these comments from Aubrey McClendon, CEO of Chesapeake Energy (NYSE: CHK) at Bentek Energy LLC’s Benposium earlier this summer: “If I had my druthers we’d be running no more than a couple [rigs]…You’d be surprised how much drilling is not voluntary today.”
This urgency to complete leaseholds afflicts many in the industry and explains why drilling costs have increased dramatically over the past year. According to one of the most cost-effective producers in the Haynesville Shale, fracturing costs have increased 35 to 40 percent in 2010, further squeezing margins. I discussed rising service costs in shale-gas plays in the Aug. 17 issue of The Energy Letter, Big Fracking Deals: Investing in Shale Gas Production. …
Pressing deadlines to secure leaseholds and an influx of cash from JVs and asset sales also explain why producers continue to drill at a frenzied pace despite lower natural gas prices.
At the same time, the disconnect between gas prices and drilling activity offers investors an attractive opportunity to pick up best-in-class names at cheap prices. The bearish outlook for natural gas prices continues to weigh on related stocks.”
undated; accessed 2 Sep 2010. Announcement for conference 23-24 Sep 2010.
“unconventional gas is seen as perhaps the most exciting prospect in years.
At least, that’s the promise — but what is the reality? Does it really have the potential to transform countries’ energy mix and security of supply? Is the industry up to the technological challenge? And just how workable are the economics, especially given the recovery rates? …
All these issues and much more will be addressed at Platts Unconventional Gas conference.”
20 Jan 2011. Conference presentation.
“Shale Gas—Abundance or Mirage? Arthur E. Berman”
[These claims seem exaggerated or just plain wrong when compared to the Ernst & Young benchmarking study and my own analysis of Encana figures. For example E&Y do include a portion of G&A in production costs, and they say undeveloped proved reserves actually went down following the rule change. And dry hole costs are included in reserve replacement costs. Here is how the capex accounting works. When new exploration and development takes place, all costs are counted as capex, and these capex costs are taken into account in valuation, via reserve replacement cost, which is total capex divided by total additions to reserves. The capital expenditures are added to running totals in an exploration capital account. If the wells turn out to be productive, the costs are transferred from the exploration capital account to the property, plant, and equipment account. If the wells are dry, the costs are taken out of the exploration capital account and expensed; however this does not change that they were counted as capex in reserve replacement costs when the costs were incurred.]