The world economy is recovering, and the price of oil too. It has crossed $70/barrel, and could return to $150/barrel, if the recovery continues. Can India do anything new to meet this energy challenge?
Yes, it can change its exploration policy to harness a new energy source — shale gas. No Indian has paid attention to the dramatic emergence of shale gas in the US, which has produced a gas glut. This has slashed the US price of natural gas by 75% from its peak in mid-2008. India must learn from this.
Shale is a common rock formation across the world. India has huge shale deposits across the Gangetic plain, Assam, Gujarat, Rajasthan, and many coastal areas. Gas has long been found in shale across the world, but its extraction has been viewed as uneconomic because of shale’s low permeability — gas does not flow easily through this rock. So, exploration for oil and gas has traditionally focused on limestone and sandstone, which have high permeability.
However, in the 1990s a new drilling technology emerged. A tight shale deposit could be cracked open by injecting water into wells at high pressure. When the water injection stopped, the cracks closed again. But then engineers hit on the idea of pumping water mixed with sand.
The sand kept cracks partially open when water injection stopped, increasing permeability and gas flow.
A sedimentary rock deposit has a limited depth but very wide area (sometimes hundreds of square miles). Traditional vertical drilling into a deposit 20 metres deep can yield gas production from a zone of just 20 metres. But new techniques have facilitated horizontal drilling. This makes possible horizontal wells running hundreds of metres long through shale strata, greatly increasing the production zone of each well. Horizontal drilling plus sand cracking have revolutionized the economics of shale gas in the US, and made it a boom industry.
Huge shale deposits lie at shallow depths across the world, and can be explored at a tiny fraction of the hundreds of millions involved in deep offshore wells (as in the Krishna-Godavari basin). The low cost per well compensates for the low yield per well. The share of shale gas in the US gas production has moved up from zero to 8%. One single deposit, the Barnett Shale in Texas, produced 1.1 trillion cubic feet of gas in 2008, and other deposits (Bakken, Haynesville) could be as productive. Anadarko Petroleum is ramping up drilling in the relatively lowyielding Marcellus Shale (stretching hundreds of miles from West Virginia to New York), aiming to achieve a 10% rate of return at a gas price of $2.50/mm British Thermal Unit. This is well below the current US price of $3.70, and a fraction of the $13 in June 2008. It is also well below the $4.20 the government has fixed for KG basin gas, and is close to the $2.34 Anil Ambani is demanding. So, at least some shale gas deposits look entirely economic.
Why has no company in India explored for shale gas despite several rounds of bidding for exploration blocks in the last two decades? The sad answer is that our exploration policy allows companies to produce only conventional oil and gas from their exploration blocks. If they find non-conventional energy — such as coal-bed methane or shale gas — they are forbidden to produce this! Why? Because, the petroleum ministry regards any non-conventional deposit as an unwarranted windfall for the exploring company, and wants separate bidding for non-conventional energy. For coalbed gas, it has called for bids and awarded exploration contracts in known coal deposits. But gas can also be found in deep coal deposits unknown today. When drilling for oil, Indian companies have already hit thick coal seams deep underground, but not bothered to test these for gas because they would not be allowed to extract it.
The same holds for shale gas. When drilling for oil, every company hits shale deposits, but ignores their gas potential since they are not allowed to harness it.
Clearly, two changes in exploration policy are urgently needed. First, the government needs to come out with a shale gas policy. It should facilitate seismic surveys that can quickly delineate potential shale gas deposits, and then invite bids for exploration.
Second, all future exploration contracts for oil should permit exploitation of shale gas as well as conventional gas. That will make it worthwhile for companies to investigate shale gas they may find while drilling for conventional hydrocarbons.
So far India’s relentless efforts during the last 25 years to build pipelines to bring gas from Turkmenistan, Iran, Qatar, Bangladesh and Myanmar have remained pipe dreams. Renewable energy sources like ethanol and bio diesel, wind and solar are high on the national agenda. Thanks to Indo-US nuclear pact, India may succeed in increasing the contribution of nuclear energy.
But a recent phenomenon of shale gas — which has brought about seismic changes in the natural gas scene — has not been given the importance it deserves. Energy economists all over the world have started to admire with awe the great achievement of oil companies in the US in developing shale gas resources on a large scale during the last decade.
As recently as three years back conventional wisdom was that US will have a huge gas deficit and it has to import increasing quantity of LNG. In less than two years, the US supply has changed from one of deficit to surplus. The sudden and unexpected development of shale gas has been a game changer. World renowned energy economist Daniel Yergin, chairman of Cambridge Consulting Group has referred to shale gas development as “the biggest energy innovation of the decade.”
It is not that we in India are not familiar with this development. In an article few months back, columnist Anklesaria Aiyar had urged the government to bring about policy changes to promote shale gas. In India, shale deposits are found across the Gangetic plain, Assam, Rajasthan and many coastal areas, but neither the government nor the corporate sector has carried out any exploration or estimation. Recently, ONGC announced plans to start a pilot project in 2011 when most oil companies in Europe and the US are racing to master the technology of shale gas from those companies who have already succeeded in the US.
Shale gas is natural gas produced from shale formations. Gas shales are organic-rich shale formations. In terms of its chemical makeup, shale gas is typically a dry gas primarily composed of methane. Three factors have contributed to its rapid development of US gas shales: advances in horizontal drilling, advances in hydraulic fracturing, and, perhaps most importantly, rapid increases in natural gas prices in the last several years as a result of significant supply and demand pressures.
The primary differences between modern shale gas development and conventional natural gas development are the extensive uses of horizontal drilling and high-volume hydraulic fracturing. According to a recent DOE report, the use of horizontal drilling has not introduced any new environmental problems.
While unconventional gas sources like gas shales reserves are plentiful, cost to produce is more than the conventional gas production of yesteryears. The shale gas cost has been estimated to be between $6 per mmbtu (Million British Thermal Units) to $9 to 10.
Dependence on Russia
The potential shale gas production in Europe will have huge geopolitical importance. Since gas prices are often higher in Europe than in the US, oil companies are keen on drilling for shale gas prospects even though profits at this stage are only speculative. Europe is today dependent on Russia for its gas supplies to the extent of about 31 per cent. Future shale gas production may reduce this dependence on Russian gas supplies for Europe and improve their energy security.
In reality India’s gas demand is limited by its access to gas supplies based on domestic production and imports availability. If India can produce more gas then it can reduce its coal imports which is environmentally more unfriendly, its gasoline consumption through the use of compressed natural gas, and its demand for LPG through piped natural gas to meet residential cooking and heating requirements, etc. Natural gas is a versatile fuel and more environment friendly.
Unfortunately, Indian government has not been able to implement the right kind of gas policies even after the recommendations given by several high powered commissions. The current gas sector gives plenty of opportunity for rent seeking because of extensive government control.
Today we have three kinds of gas prices in India: 1. Gas prices based on Administered Pricing Mechanism (APM) for those gas reserves before new exploration and licensing policy. This is around $2.50/mmbtu. 2. Import prices paid to LNG imports which depend on international prices which were as high as $16/mmbtu last year and 3. The so called arms length price based on market for those gas reserves discovered after NELP. For Krishna Godavari basin the government has fixed gas price at a level of $4.20/mmbtu on an arbitrary basis when the market based price would be above $6.50/mmbtu.
The basic requirement for proper gas sector development in india is that the government should allow the market to set the prices as recommended by many gas committees.
The government should encourage Indian companies —public sector and private sector — to import gas shale production technology by giving incentives. It may even facilitate such transfer of technology through signing of cooperation pact with the US government as China has done during the recent visit of President Obama.
The government should consider setting a shale gas mission to make efforts to develop India’s shale gas reserves on a war footing. In short, we should actively endeavour to develop shale gas reserves in India in the shortest time with all the human, geologic and financial resources we can assemble.
(The writer is an energy expert) http://www.deccanherald.com/content/...ger-india.html
Gazprom Rejects 'Shale Gas Revolution' That Could Shake Up Its World
The talk these days is of a natural gas revolution shaking up political and economic assumptions everywhere. Not surprisingly, Gazprom – among the biggest beneficiaries of the prior state of affairs, and one of the greatest losers should the ostensible revolution play out – says it’s much ado about nothing.
The debate is over technological advances in drilling that have opened up an estimated 100-year supply of gas that had been hopelessly locked into shale in Texas, New York, Oklahoma, Pennsylvania and elsewhere. It is said that, because of this sudden surge in gas supplies, the political and economic calculus around the globe – in Europe, Russia, China and the Middle East – can no longer be taken for granted.
The scenario goes like this: The arrival of the shale gas has created a glut in the U.S., and thus freed up otherwise-contracted Qatari liquified natural gas supplies for shipment to Europe. That’s made Europe less economically reliant on Russian natural gas supplied by Gazprom. In Russia, this loss of projected U.S. and European gas demand has stirred doubts about an economic model largely dependent on Gazprom, and also about Gazprom’s continued ability to serve as the spearpoint of Russian foreign policy. Moving on to China, the natural gas surplus could result in a breakout of battery-operated electric cars, to be recharged from natural gas-fired power plants, built as substitutes for currently planned coal-burning plants. If that happens -- if a large number of new Chinese cars are electric, and not gasoline-burning -- it would much-reduce China’s projected skyrocketing oil demand. Which brings us to the Middle East, whose future earnings projections – largely reliant on increased Chinese oil demand – would thus be upended.
As a piece, it may sound too grand. But it isn’t. Should shale gas plays work outside the U.S. – specifically in Europe and China – look for the scenario to shake up the equation somewhere along these same lines.
Back to Gazprom. Ultimately, asserts Gazprom chief Alexander Medvedev, the so-called shale gas revolution will peter out, cut short by imperiled water supplies. There is something to what Medvedev says, as Abrahm Lustgarten has been reporting for a year or so over at ProPublica. The industry will have to demonstrate that the gas can be produced safely.
Medvedev is showing the courage of his convictions. This week, he crossed a crucial milepost in Russia’s quest to forever end its reliance on uppity Ukraine and ship its natural gas directly to Europe. This is Gazprom’s announcement that it has raised $5 billion in loans to begin the construction of the Nord Stream natural gas pipeline from Russia to Europe. That 26 banks and three government lending agencies from France, Germany and Italy are party to the loan shows that they, too, are exercising caution before jumping on the revolution bandwagon.
Yet the oil industry is equally demonstrative -- it is putting down a multiple of that loan in investment to back up its conviction that the revolution is real.
No the energy ministry is still in its slumber. Man i wish i had the money to extract this. Look at the figures from US, gas supply moves from deficit to surplus and they said good bye to gas from Qatar. And we are still in negotiations with Qatar and fighting over prices. With Indias size, we would have a lot and lot of these shale deposits which have to be exploited.
The US planned to offer other countries help in determining whether they had big natural gas resources trapped in shale rock and show them how to bring those supplies to market, a top US State Department official said on Wednesday.
Switching to natural gas from coal to fuel power plants would result in fewer greenhouse gas emissions, while helping developing countries provide electricity supplies for their growing economies.
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- US cautions its citizens to threats of attacks in India
- Colourful diplomacy
- State Dept report focuses on India's counter-terror moves
Improved drilling technology has allowed the US to boost its production of shale gas and increase its gas reserves by decades.
The US Geological Survey (USGS) would offer its services to seven to 10 countries that had the best prospects for holding vast resources of shale gas, said David Goldwyn, the State Department’s coordinator for international energy affairs.
“That is good for their development and that is also good for their ability to have a choice in fuel,” Goldwyn said while speaking at the US Energy Association’s annual meeting.
The US has officially offered its assistance to China and India, and other countries with potentially large shale gas resources under consideration include Jordan, Poland, Chile, Uruguay and Morocco, according to Goldwyn.
He said the State Department might get China’s answer in May and India’s in early June.
He said any country that took up the US offer would have to agree to allow the USGS to make the gas resource information public. That would give companies that wanted to develop the shale resources confidence that the resource assessments were accurate, he added.
Goldwyn said the State Department would also help those countries determined to have shale gas come up with a plan to bring those resources to market.
The US assistance will also show the countries how to auction off the shale gas, how to establish investment returns that attract companies to develop the gas, and how to provide the infrastructure for moving the equipment to produce the gas. http://www.business-standard.com/ind...ources/391357/
With the release of the Potential Gas Committee’s 2008 year end assessment last week, there was a fresh wave of enthusiasm for replacing oil or coal with natural gas. The PGC, led by Dr. John B. Curtis of the Colorado School of Mines, found a lot of new resources in their reevaluation of potential shale plays.
The Potential Gas Committee (PGC) today released the results of its latest biennial assessment of the nation’s natural gas resources, which indicates that the United States possesses a total resource base of 1,836 trillion cubic feet (Tcf). This is the highest resource evaluation in the Committee’s 44-year history. Most of the increase from the previous assessment arose from reevaluation of shale-gas plays in the Appalachian basin and in the Mid-Continent, Gulf Coast and Rocky Mountain areas…
The Potential Gas Committee reports its gas resource assessments biennially in three categories of decreasing certainty—Probable, Possible and Speculative. For each category, a minimum, most likely and maximum volume is assessed for each of 89 geological provinces in the Lower 48 States and Alaska. The mean values shown in Table 1 below were calculated by statistical aggregation of the minimum, most likely and maximum traditional values for each resource category…
[My note: see the link above to view Table 1. Figure 1 shows the major U.S. shale basins.]
Figure 1 — The major shale plays in the United States, from a report by Navigant Consulting, Inc. for the Clean Skies Foundation sponsored by Chesapeake Energy Corp. (CHK). Some of the biggies in or starting development include the Antrim (#1), Barnett (#3), the Haynesville (#10), the Marcellus (#13) and the Bakken (#2).
If you add up the mean values for Traditional Gas Resources, which includes shale gas, and Coal Bed Methane, you get the 1,836 Tcf of potential resources. If you throw in the EIA’s proved reserves, the total resources are 2,074 Tcf in the Lower 48 and Alaska. Curtis explained that his tally represents the ‘technically recoverable’ gas resource potential of the United States. At current consumption rates, the new total represents about 100 years of supply. If speculative resources (500 Tcf) are excluded, we would still have about 75 years of supply.
Suffice it to say that there is little reason to doubt that the potential natural gas resource base in the United States is very large. The hidden problem with such estimates relates to whether the gas is economic to produce, an issue which is outside the PGC’s purview.
Let us assume for now that all the gas (2,074 Tcf) that might be there is actually there. Let’s further assume that it is indeed technically recoverable and economic to produce at a “reasonable” price, which I will leave undefined. What would we do with the gas?
We have two energy problems in the medium to long term, climate change and peak oil. (In the very long term, all bets are off.) Consequently, shale gas has been proposed as a temporary (a few decades) solution to both. We can—
use natural gas to replace liquid fuels in transportation, especially as a replacement for diesel in long-haul trucking. This is the (T. Boone) Pickens Plan, which is currently dead in the water. Pickens expressed his excitement about the PGC reports, saying that “the 2,074 trillion cubic feet of domestic natural gas reserves cited in the study is the equivalent of nearly 350 billion barrels of oil, about the same as Saudi Arabia’s oil reserves.” Pickens is selling his plan—he knows better than to spout nonsense like this. ASPO-USA commentator Tom Standing did an excellent job of analyzing the energy density issues and practicalities (e.g. compressed natural gas versus liquefied natural gas) of replacing diesel with gas. It would take decades build out the supply chain (e.g. swap petroleum gas stations for natural gas stations). Robert Rapier also wrote an analysis worth reading on this subject.
use natural gas to replace coal in electricity generation to reduce CO2 emissions. Dr. Joseph Romm of the influential Center for American Progress is already calling the potential shale gas play a game-changer. The imminently practical idea is to ramp up under-utilized natural gas power generation capacity to replace base-load coal. Geoffrey Styles’ analysis Shale Gas and Climate Change provides an excellent overview, so I won’t repeat the details here. Even if you don’t believe we are going to make an 80% reduction in our emissions by 2050—I don’t believe it—official policy is to act as though we are going to do so. We now have the makings of a de facto moratorium on coal (and here). We seem to be unwilling to build new nuclear capacity. It is theoretically possible for wind to provide 20% of our electricity by 2030, but there are many practical, economic & political barriers to success. Thus it would behoove us to switch to natural gas at large-scales if we want to maintain a functioning electricity grid 10-15 years from now. This is my current view, but the political winds could change quickly as the Great Recession grinds on.
If we are at the beginning of a long term shale gas boom, it is clear we can put the gas to good use. But that’s a big IF. Before we make a policy commitment to a natural gas future, we must be certain the gas will be there.
Let’s return to the real world, a messy place where some potential gas resources may not exist, or may not be economic to produce. Things get complicated here, but don’t they always?
Shale Gas Economics
At first glance, increased shale gas production (Figure 2) looks like a textbook case of resource economics. A “new” technology (horizontal drilling & hydraulic fracturing) combined with rising price (Figure 1) boosts recoverable reserves over time.
Figure 1 — The history of natural gas wellhead prices since the 1970s, from the EIA. Volatile prices have increased since about 2002, but have fallen lately during the downturn.
Figure 2 — Increased shale gas production with a risked estimate out to 2018, from a Tristone Capital study (October, 2008) described in the Oil & Gas Journal’s Study analyzes nine US, Canada shale gas plays. These are risked production additions — “the study expects companies ultimately to recover from these resources 261 Tcf of gas, based on various risk factors applied and a long-term average gas price of $8.50/MMbtu. Without the risk factors, Tristone Capital says these shales have a 743-Tcf recovery potential.” The Horn River and Montney shales are in Canada, so they don’t appear in Figure 1.
Tristone Capital’s future production estimate depends on a long-term average price of $8.50/Mcf (per thousand cubic feet abbreviated as Mcf, equivalent to million British Thermal Units, abbreviated as MMbtu). The required price is well over the 15-year average of ~$5.50/Mcf.
What average natural gas wellhead price allows the shale boom to continue? Shale gas economics is a contentious issue. One camp believes that shale gas is economic at—and will keep future prices in—the $5-6/Mcf range. I’ll call these analysts the optimists.
The other camp believes the marginal cost of shale gas production is $7-8/Mcf, and perhaps much higher depending on the shale play. These are the pessimists. Let’s break down the arguments.
Barclays Capital stock analyst Tom Driscoll is an optimist. On May 27, 2009, Platts quoted Driscoll as saying—
“Conventional gas is being displaced by unconventional gas,” Driscoll said and it may take “20 years for natural gas prices to recover.”
“The emergence of low-cost unconventional, and especially shale gas, resources may lead to lower than expected natural gas prices for the next five to 10 years,” Driscoll said. “Shale — along with other low-cost unconventional gas — could provide 75% to 90% of new gas supply over the next several years and set the marginal cost of new supply.”
Despite the nearly 50% cut in rig counts since their peak in the fall of 2008, Driscoll estimates that fourth-quarter 2009 gas production numbers will show no decline from fourth-quarter 2008 numbers…
He said he estimated the market will average 4 Bcf/d worth of oversupply this year and 3 Bcf/d worth of excess gas in 2010.
Driscoll said the more productive horizontal rigs are profitable at prices “materially below” $6/Mcf, which just keeps gas flooding into the market even as cash prices plummet.
[My note: Driscoll and others also project that shale gas may provide up to 40% of U.S. supply by 2013.]
This is a very bullish forecast. Despite reduced rig counts, and despite the likelihood that we will have low or average gas prices over the next few years due to the recession and oversupply, the market share of shale gas grows and grows. This forecast looks like a high-wire act that defies not only gravity, but also the laws of supply & demand. One wonders what the minimum price is that makes shale gas unprofitable. $4.50/Mcf? $3.50/Mcf?
Another optimist, Ziff Energy, tells us how much gas is produced from shale now.
Ziff Energy Group forecasts unconventional gas production will supply 53% of US gas needs by 2020, up from 30% in 2000.
Ziff Energy’s Shale Gas Outlook to 2020 says shale gas production in 2008 was more than 5 Bcfd (8% of North American gas production), with 70% coming from the Barnett shale in the Fort Worth basin of Texas.
In the future, the report sees increased gas coming from the Barnett, Fayetteville, and Woodford shales as well as many other plays such as the Haynesville, Marcellus, Horn River, Utica, and Gothic. The report expects in 2020 that North America will produce 87 Bcfd compared with 70 Bcfd in 2000.
[My note: "Bcf" stands for billion cubic feet and "Bdfd" is the daily rate. U.S. dry gas production was 20.56 Tcf in 2008. The production rate was 56.33 Bcfd. The U.S. consumes more gas than it produces, getting the rest from Canadian and liquefied natural gas (LNG) imports. Conventional gas production peaked in the 1970's in the United States. New supply from unconventional tight gas (and some coal-bed methane), along with imports, filled the supply/demand gap. As Figure 2 shows, shale gas is a johnny-come-lately on the gas scene.]
The biggest booster is the man who is selling shale gas—Chesapeake CEO Aubrey McClendon.
At Chesapeake Energy’s recent shareholder’s meeting, Chairman and CEO Aubrey McClendon suggested that the increased use of natural gas would be a way to help the U.S. stop indirectly funding nations that are “declared enemies” and would benefit the environment as well. McClendon said the lack of availability of natural-gas-powered cars in the U.S. is “the most frustrating part of my existence today” and pointed out that General Motors manufactures 12 car models throughout the world that come off of the assembly line ready to run on natural gas, yet there are no such models in the U.S.
McClendon knows how to sing the right notes, but I thought his “most frustrating part of my existence” statement is a bit overdone. What do the pessimists—they would prefer to be called realists—say about all this? And how would optimists respond?
Art Berman, a Houston geologist and columnist at World Oil Magazine, does not believe most shale gas wells are economic unless operator costs go down, gas prices rise sharply, and high average prices are sustained. Talking about the Haynesville in A Long Recovery for Natural Gas Prices, Berman says—
Drilling and completion costs [in the Haynesville] vary from $7.5 to $10.5 million per well. The marginal cost for operators to find and develop natural gas reserves is $7 to 8/Mcf, and current netback prices in the play are less than $3/Mcf. The threshold netback gas price for a better-than-average 5.5 Bcf well to break even is $7/Mcf at NPV10 (Bodell and Pittinger, in press). For companies that have favorable hedge positions, realized gas prices for 2009 will be as high as $6.50/Mcf and $6.00/Mcf for 2010. This means that the play is marginally commercial today for operators with favorable hedge positions, but not commercial based on cost and price fundamentals.
Berman’s argument is based on current (and likely future) gas prices, a minimum ultimately recoverable per well, and “all-in” costs of about $7.50/Mcf, not on the impressive initial well flow rates often reported in Rigzone. At current prices, the netback of $3.25/Mcf barely covers operating costs, so no Haynesville well is economic and rates and reserves simply do not matter. Berman’s analysis of the Barnett is just as bad—
Shale gas is not commercial at any “reasonable” price because the costs are too high—I once calculated that at ~$12/Mcf only slightly more than 50% of Barnett Shale wells would break even or more money. I am now working on a re-evaluation of the Barnett Shale 11,500 wells later. The average per-well EUR is about 0.6 Bcf—pathetic! The cost is staggering—more than $30 billion and most of it hopelessly non-commercial…
[My note: quoted from an e-mail from Berman. 0.6 Bcf includes vertical wells, about 1/3 of the total drilling in the Barnett play. The average estimated ultimately recoverable (EUR, reserves) for horizontal wells is ~0.75 Bcf.]
But what about our classic case of resource economics? Prices rose (Figure 1) and shale gas production increased (Figure 2). That would seem to belie Berman’s pessimism—the proof is in the pudding. What’s the problem?
The wrench in the works is that operators appear to have lost money producing shale gas. McClendon recently stated that “we believe that Chesapeake’s strong financial condition and extensive hedges provide us with … [the] flexibility to make prudent natural gas revenue maximization choices.” No doubt Chesapeake will try to maximize their revenue, but do they have a strong financial condition? Berman says No—
I have worked through the 10-Ks of most of the major shale players (Chesapeake, Petrohawk, Range Resources, etc.)—they’re all taking a bath financially but put on a brave face, and have huge debt. As long as their stock price is good, the executives get rich so why do they care? The analyst community is so naive about true costs that they believe the propaganda.
[My note: Chesapeake has 14.4 billion in senior debt and their stock price is faring badly. "CEO Aubrey McClendon has come under some well-deserved fire for his high compensation in the face of poor results and a declining stock price. He was paid a one-time $75 million bonus at the end of 2008—suspicious timing given that the stock had lost most of its value in recent months and Mr. McClendon had lost his entire stake in the company to margin calls."]
Most shale operators work on borrowed capital—who is going to lend that kind of money [~$150 billion for the ~30,000 wells required to quadruple shale gas production] to companies like HK [Petrohawk] and CHK [Chesapeake] that are already in debt up to their eyeballs?
[My note: The 10k is a document filed with the SEC that contains ... the same financial statements the annual report does in a more detailed form.]
I entirely agree with Berman’s take on things here. There’s no dearth of clueless analysts—I’ve read or listened to more than a few. Berman’s deeper point about propaganda is also right on the mark. In the Age of Hype, the Ponzi Scheme and the Swindle, why wouldn’t some natural gas companies want to get in on the deal?
Other analysts like Ben Dell, a senior energy analyst at Bernstein Research in New York, are suspicious about corporate reporting of returns on shale wells.
In a March 27 research note, [Dell] 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 practices” 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.
Dell’s analysis and Berman’s are the same in all the essentials. Let’s sum up the situation so far—
Shale gas operators are up to their eyeballs in debt. They would need to borrow vast sums of money—Berman suggests it would take ~30,000 wells and ~$150 billion—to get shale gas up to 40% of total U.S. dry gas production by 2013.
Shale gas operators can’t possibly make money at current natural gas prices, or medium-term future prices if these are close to the 15-year average (~$5.50/Mcf).
The situation is actually worse than our summary indicates. Shale gas wells have very steep decline rates. Consider the Griffith #1 well in the Haynesville as reported at Rigzone.
The Griffith #1 well located in Desoto Parish, Louisiana was completed and brought online in January 2009. The exact reading for total gas produced from the Haynesville shale [Griffith #1] and shipped to market through March 10, 2009 is reported at 568,856 Mcf or .568 Bcf…
The Haynesville Shale play is a new play less than one year old and there is limited data to work with to determine the decline rate for Haynesville Shale wells. [Mainland Resources, Inc.] believes that the recoverable reserves for the Griffith well may ultimately be from 7.5 Bcf to 15.81 Bcf. The 15.81 Bcf rate was determined by a reserve report for the Griffith #1 done by T.W. McQuire & Associates, Inc., prepared pursuant to U.S. Securities legislation. The ultimate recovery was determined by using a type curve that uses 80% decline for the first year, followed by 30% decline for the second year, 15% decline for the third year, and then a 10% decline over the remaining expected life of the well. This decline was derived from the Deutsche Bank report issued in 7/08 based on a study of various shale plays.
[My note: The quoted .568 Bcf is over the first 40 days of operation. Using a type curve to figure declines in the Haynesville may be misleading. Berman's observed decline rates for the Barnett Shale are as follows:
Year 1: 65%;
Year 2: 53%;
Year 3: 23%;
Year 4: 21%;
Year 5: 20%;
Year 6: 17%;
Year 7: 21%
Berman notes that "there is no empirical justification to lower terminal decline rates to 10%/year, and there is no factual evidence for the declines used in Years 2 & 3 by Deutsche Bank. This is what happens when bankers try to do petroleum engineering and geology. They have used a model to get these declines but have not bothered to calibrate it against the only shale play in the world with enough production history to it compare to."]
The Griffith #1 well may or may not turn out to be a winner, but the stated reserves (7.5-15.8 Bcf) seem inordinately large for a shale gas well. Steep declines several years into production, even when there is a high initial flow rate, largely determine what the well reserves will be, which Berman calculated as only 0.6 Bcf on average for the 11,500 wells drilled in the Barnett Shale.
And we only hear about the successful wells, the creme de la creme. It would be unusual to find a story at Rigzone that reads like this—
Desoto Parish, Louisiana — March 13, 2010
Mainland Resources, Inc. announced today that their Bogus #2 well in the Haynesville showed weak flows in the first few weeks after production began … Spokesman John Q. Smith said “we probably won’t get 0.3 Bcf out of the damn thing… We’ll never get our money back.” He called the results “very disappointing.” … Smith concluded that “drilling this well was a complete waste of time and money.”
When we consider disappointing wells and high decline rates in successful wells, it is clear that getting shale gas up to 40% of U.S. production by 2013 is not only very expensive—$7.5-10.5 million for drilling & completion according to Berman—but also requires poking a lot of very expensive holes in the ground.
One problem with analysts like Tom Driscoll, who is a stock analyst working for Barclays, which is a bank, is that they remember how to add but they’ve “forgotten” how to subtract. This applies straightforwardly to the shale gas play. The usual human bias, as evidenced in Rigzone stories, is to play up the successes and ignore the failures, as Nassim Taleb pointed out in his book Fooled By Randomness. We see the single entrepreneur who succeeded on TV, but we never hear about the 10,000 who failed. This introduces a significant skew into the data being examined.
I do not mean to make a sweeping generalization. Paul Horsnell, who is an oil market analyst at Barclays, knows what he’s talking about.
The optimists’ response to all this bad news is summed up by Keith Shaefer’s Natural Gas: Costs go down as learning curve goes up. To give the opposition equal time, I will quote it at length.
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…
Calgary based securities firm Tristone Capital says wells in the Montney gas play on the BC-Alberta border are now 8-10 mmcf/d [million cubic feet], about twice what they were when the play first started.
… 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…
Until some of these high land costs are amortized out, don’t expect to see the “accounting” cost of finding a barrel of oil [gas] — 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.
It appears Tritone has changed its tune, revising its $/Mcf from $8.50 (Figure 2) to $5. This story says that 1) previous “all-in” costs of $7.50 or more were due to expensive land acquisition; 2) oilfield expenses are declining as rig rates go down; and 3) operators are ascending the learning curve for shale drilling, which lowers costs and boosts reserves & flows. These factors imply that fewer wells will produce more gas due to “more productive horizontal rigs,” as Driscoll maintains.
If shale operators cannot substantially reduce their costs, I doubt that most of them can survive a year or so more of low prices (Barclay’s “low camp” $5-6/Mcf) because their marginal cost of production is $7-8/Mcf, much less find $150 billion or so for more unprofitable drilling. I believe that the cost of services will escalate at a higher rate than cost, and will never drop to meet low price (except for possibly too brief a period for most operators to take advantage of).
Actually the frac costs keep increasing because operators are now commonly using 10-12-stage fracs that cost millions. Rates are higher but at what cost and for how long? The key here is that the extra cost may only accomplish a rate acceleration and not an increase in reserves. In the Barnett Shale, the average horizontally drilled and fractured wells only have ~25% more reserves than vertical wells but 3x the cost! This talk about lowering operating cost and increasing reserves is more propaganda, and most cost benefit is more than negatively compensated by more interest expense on debt.
Let’s sum up.
A Shale Gas Boom?
Will we have a shale gas boom? I’ve described the contentious argument among those who follow the natural gas industry. Generally, my sympathy lies with skeptics like Art Berman. As someone who has written extensively about peak oil, I’ve encountered the human proclivity to hype a situation far beyond any semblance to reality time and time again—the Jack #2 discovery in the Gulf of Mexico comes to mind.
Nevertheless, I’m going to say the jury is still out on this one. That’s not a cop-out, because the verdict will be in very soon, certainly within the next few years. Art Berman is making specific predictions, just as Driscoll, Shaefer, and Ziff Energy do. Berman surmises that natural gas prices may stay below or in their average range (~$5.50) for a few years based on a host of new factors that include greater availability of tight gas from the Rockies and increased LNG imports. If Berman is right, we will not see large increases in shale gas production through 2011, or some companies will go belly up, or both.
Promoters like T. Boone Pickens and Aubrey McClendon have offered us a Golden Vision of a future powered by natural gas. Their forecasts assume a shale boom that will last for decades. But we shouldn’t count our chickens before they’re hatched. It costs us very little to take a wait & see attitude on the shale gas boom—we’ll know soon enough if it’s for real. http://www.energybulletin.net/node/49342
May 25 (Bloomberg) -- When Victoria Switzer awoke on a cold night in March, her dog was staring out the window at the flame roaring from a natural-gas-drilling rig 2,000 feet behind her house. She remembers trees silhouetted in a demonic dance as the plume burned off gas that had been building up under her land.
She discovered later that such flaring can occur when Cabot Oil & Gas Corp. and dozens more companies drill for gas trapped in shale rock. The deposits, stretching from Texas to New York, and as far away as Australia and China, represent what may be the biggest energy bonanza in decades -- one that Switzer, 57, recalls thinking the Earth isn’t surrendering without a fight, Bloomberg Markets reports in its July issue.
Switzer, a retired teacher in Pennsylvania, is on the front line of a shale gas rush that’s dividing communities, creating millionaires and shaking up global energy markets.
Companies from India’s Reliance Industries Ltd. to Japan’s Mitsui & Co. are spending billions of dollars to dislodge natural gas from a band of Pennsylvania shale -- sedimentary rock composed of mud, quartz and calcite.
Shale gas proponents, led by 91-year-old oil patch billionaire George Mitchell, who invented the process to extract it, say the U.S. should plumb all forms of natural gas. That would help unhook the nation from coal and foreign petroleum.
Gas is about two-thirds cheaper than oil and greener too. It produces 117 pounds (53 kilograms) of carbon dioxide per million British thermal units (MMBtu) of energy equivalent compared with 156 for gasoline and 205 for coal.
“This discovery will change the course of world history, not just to de-carbonize the economy but to de-OPEC-ize it,” Chesapeake Energy Corp. Chief Executive Officer Aubrey McClendon said in December in Copenhagen as the United Nations climate conference was under way.
Chesapeake, based in Oklahoma City, has profited by selling drilling rights and gas reserves for $10.7 billion during the past 2 1/2 years, quadruple the $2.7 billion it paid. McClendon -- with $33 billion in assets left to sell -- says he’s open for business.
Shale gas has plenty of detractors. Environmentalists say fracking, a process in which drillers blast water into a well to shatter rock and unleash the gas, threatens pristine watersheds. Dish, a hamlet of 180 residents north of Fort Worth, Texas, has almost as many wells, compressors and pipelines as people.
‘Children, Old People’
Last year, the Texas Commission on Environmental Quality found benzene, which it classifies as a carcinogen, at 10,700 times the safe long-term exposure limit next to a well 6 miles (10 kilometers) west of town on which a valve had been left open.
“We have children, old people, pregnant women,” Mayor Calvin Tillman says. “They’re not supposed to be subjected to toxins.”
Switzer, who moved to Dimock Township, Pennsylvania, to build a $350,000 dream home with her husband, Jimmy, in 2004, had no idea how shale gas would consume her village of 1,400.
She says she found so much methane in her well that her water bubbled like Alka-Seltzer. Neighbor Norma Fiorentino says methane in her well blew an 8-inch-thick (20-centimeter-thick) concrete slab off the top. The $180 bonus Cabot paid to drill on Switzer’s 7.2 acres (2.9 hectares) and the $900 in royalties she gets each month don’t compensate, she says.
‘Beads and Baubles’
“I feel like one of the Indians who sold Manhattan for beads and baubles,” she says.
The economics of shale don’t look great right now for big companies either. Natural gas prices plunged to $2.41 per MMBtu in September 2009 from $13.69 in July 2008 as the recession cut demand while drilling accelerated. On May 24, gas traded at $4.04.
James Barrow, who invests one-ninth of his $50 billion portfolio in energy stocks as president of Dallas-based Barrow Hanley Mewhinney & Strauss, says leases signed as gas peaked in 2008 make drilling necessary -- even in a slump. When this new gas hits the market, the price could again sink into the mid-$2 range, he says.
For companies to profit from new wells, gas has to rise to $7.50, says Ben Dell, a Sanford C. Bernstein & Co. analyst in New York. He predicts it’s only a matter of time before firms trim production, which he says will boost gas to $8.50 by 2011.
If gas stays above $4, a price that lets companies cover costs on existing wells, U.S. output could grow 20 percent to 65 billion cubic feet (1.8 billion cubic meters) a day from 2008 through 2030, says Peter Wells, director of U.K. research firm Neftex Petroleum Consultants Ltd. Shale gas production could quadruple to more than 20 billion cubic feet, he says.
That would help meet rising power demand. Global energy consumption will soar 44 percent by 2030 from 2006, the U.S. Energy Department says. China and India will siphon off 28 percent by then, according to the DOE forecast. Demand is rising because the planet’s population will balloon to 8.2 billion in 2030 from 6.8 billion today.
Hydroelectric, wind and other renewable sources will plug only part of the gap: They’ll contribute 17 percent of U.S. electricity generation by 2035 from 9.1 percent in 2009, the DOE says.
“Taking advantage of the new natural gas finds, the shale finds, would be an important piece of how we begin to break our dependence on foreign oil,” Carol Browner, President Barack Obama’s senior energy adviser, told a Washington audience in April.
Investors are primed for a boom. Chesapeake’s shares fell 47 percent from the beginning of 2008 to $20.75 on May 24 as gas prices sank. Bernstein’s Dell predicted in mid-May that shares would rise to $34 during the next 12 months while companies curb output, reducing supply as rebounding economies demand more energy.
The stock prices of Chesapeake and fellow gas developers Petrohawk Energy Corp. and Range Resources Corp. don’t reflect the firms’ shale holdings, says David Heikkinen, a Tudor Pickering Holt & Co. analyst in Houston.
Fort Worth-based Range has assets valued at $65 a share, he says, a third more than its May 24 stock price of $42.47.
Range began plumbing the Marcellus shale that underlies New York, Pennsylvania and West Virginia in 2004. The band of rock -- so designated because it pokes through the surface near a city of that name in northern New York -- may contain 262 trillion cubic feet of recoverable gas, the DOE estimates. The U.S. uses 20 TCF annually, mostly for power plants and home heating.
That means the Marcellus shale alone could supply America’s needs for more than a decade.
Getting a Bargain
Range CEO John Pinkerton says he got a bargain when his company paid $1,000 an acre for Marcellus drilling rights near Pittsburgh starting in 2004. India’s Reliance paid 14 times more in April, a price Pinkerton says he wouldn’t consider.
“If I sold today for $14,000 an acre, I’d be selling for a quarter of what it’s worth,” Pinkerton told investors in April.
Range has 200 wells in Washington County south of Pittsburgh and may add another 4,300 in the county over 10 years.
Even oil and coal companies are raising their bets on gas. In December, Exxon Mobil Corp. agreed to pay $41 billion in stock and assumed debt for Fort Worth-based XTO Energy Inc., the biggest U.S. gas producer.
Outside North America, unexplored geology and nonexistent pipelines make it harder to gauge how much shale gas exists.
“Regions including China, India, Australia and Europe are thought to hold large resources,” the International Energy Agency said in November.
Liking the Odds
Firms are taking those odds. European oil giants BP Plc and Royal Dutch Shell Plc are looking in China. Chevron Corp., ConocoPhillips and Exxon purchased drilling licenses in Poland.
“Companies are rushing to get the last available license,” says Henryk Jacek Jezierski, Poland’s chief national geologist.
Consol Energy Inc., the second-largest U.S. coal producer by market value, owns land near Pittsburgh that’s in the heart of Marcellus shale. It also bought shale assets valued at $4.4 billion in April. CEO Brett Harvey says coal will remain the bedrock of the U.S. economy far into the future. He’s not ignoring gas.
Because Consol already owns the Pittsburgh-area property, it can charge as little as $3.71 MMBtu for gas and still earn a 20 percent after-tax return, he says. Firms forced to pay $5,000 an acre for drilling rights and a 20 percent leasing royalty would have to charge $5.18, he says.
“If there’s a flood of gas at $4, guess who’s going to produce it?” Harvey says. “We are.”
Managing a Windfall
Pennsylvania is no stranger to energy euphoria. Edwin Drake drilled the world’s first successful oil well in 1859 in Titusville, 240 miles west of the Switzers’ home in Dimock. Now it’s learning to manage its latest windfall.
In October, companies will be required to disclose the chemical composition of fracking water, says John Hanger, secretary of Pennsylvania’s Department of Environmental Protection. The department is doubling its number of oil and gas enforcers to 193.
Switzer says it’s about time. She says she’s had nothing but trouble since Houston-based Cabot arrived in 2006. It sank 50 wells in 2009 and plans 81 this year. Convoys loaded with drilling rigs, pipes and compressors crisscross the village. Her creek ran red with spilled diesel after a truck slid on ice and hit a tree. Some neighbors are moving. Switzer wants Cabot shut down instead.
“They said we’d never notice the drilling,” she says of Cabot. “Now, we won’t be able to remember when they weren’t here.”
The Switzers and 31 neighbors are suing Cabot for negligence. The company had until June 1 to respond. Cabot spokesman George Stark declined to comment on the suit.
Separately, and without acknowledging any wrongdoing, Cabot agreed with Pennsylvania officials on April 15 to stop drilling in Dimock for a year, cap three wells with casings that the state deemed defective and pay a $240,000 fine.
Ken Komoroski, a Cabot attorney, says there’s no proof drilling polluted Dimock’s water. He says loose soil collapsed at a well, snapping the drilling pipe and dragging the bit 1,700 feet (520 meters) underground. Methane may have migrated through the cavity into aquifers as Cabot recovered the bit, he says. Cabot now tests for methane and uses latex to ensure well casings are cemented properly.
‘More Like Texas’
“In the big picture, drilling is going very well,” Komoroski says. “Pennsylvania is going to look more like Texas.”
Shale gas pioneer Mitchell can take credit if that happens. His parents, Greek immigrants who ran a dry cleaning store, put him through Texas A&M University, where he majored in geology and petroleum engineering. In 1946, he started consulting for a company he later bought and renamed Mitchell Energy & Development Corp.
Mitchell knew gas had become embedded in shale, the most common sedimentary rock, when ancient seabeds were covered and compressed by erosion. Starting in 1981, he experimented with drilling down and then horizontally. He fracked the wells, pumping fluid to blast out the gas -- testing the method sparking today’s boom.
“We tried propane, diesel, anything you can think of,” says Mitchell, who uses a motorized scooter to zip around in his Houston office, where he greets emissaries from China and Europe who have been bitten by the shale bug. “Water with a small amount of sand worked best.”
By 1993, Mitchell had developed shale gas extraction into a viable business. Rivals didn’t pay attention until prices rose in tandem with oil and passed $4 a decade later. Mitchell sold his company to Oklahoma City-based Devon Energy Corp. for $3.1 billion in 2002. Since then, he has invested $25 million in Alta Resources LLC, which has five wells near Montrose in northeastern Pennsylvania and may drill 500 more.
Mitchell says shale gas is a better bet than oil. A typical gas well near Fort Worth costs $4 million and is virtually assured of success. In the Gulf of Mexico, oil companies spend $300 million drilling through 1,000 feet of water and 35,000 feet of rock and can still come up empty.
“They decided they better start working on shale gas,” he says.
The U.S. Congress is investigating offshore drilling for a more tragic reason. On April 20, an explosion at a BP oil rig began spewing at least 5,000 barrels of crude a day. The disaster killed 11 people, wiped $58.3 billion off BP’s value as of May 24 and prompted the governors of Florida and California to withdraw support for ocean drilling.
While Chesapeake’s McClendon, 50, expects offshore drilling to become more difficult, shale gas has its own drawbacks, Neftex’s Wells says.
“With deep-water exploration, there is a very small risk of a catastrophic event,” he says. “With shale gas, there is a persistent risk of long-term contamination of groundwater. This doesn’t have easy-to-see TV imagery, like oiled-up seabirds. It needs scientific explanation for which the public is not trained.”
BP had started looking for gas before the oil spill. In 2008, it paid Chesapeake $1.75 billion for rights on 90,000 acres near Stuart, Oklahoma, 100 miles south of Tulsa. BP has since tripled initial output from wells on this land to 10 million cubic feet a day.
On a sunny February afternoon, workers prepare new wells using a road grader to scrape flat a 5-acre patch called the drill pad. They’ll cover the area with rubber and surround it with 18-inch-high berms to contain any spilled liquid from fracking or drilling debris. They’ll bore as many as eight wells in the pad.
From a 14-story white rig with a blue platform, workers in a control room called the doghouse use computers to manipulate hydraulic lifts that arrange 30-foot sections of black pipe into rows. Mechanical claws screw one pipe to a volleyball-size drill bit studded with diamonds and the other pipes to each other. An 11-ton rotating clamp called a top drive pushes the pieces into the pad to start the well.
Within 10 Feet
The bit and drilling pipes, which are surrounded by three rings of metal casings cemented in place to protect aquifers, go down 8,000 feet. Workers activate a motor in the pipe, which has a slight bend near the bit, so that 1,000 feet of drilling produces a 90-degree turn.
After probing for 3 miles, the driller, from his perch in the doghouse, can place the bit within 10 feet of his target, says Bryant Chapman, BP’s vice president for North American gas operations.
Next comes fracking. Workers park 40 tractor-trailers loaded with pumps, sand, chemicals and portable containment tanks on the pad and spend three days blasting 5 million gallons (19 million liters) of water into the well.
As much as 40 percent flows back out. In Texas, the water is injected into underground rock. In Pennsylvania, which lacks suitable deep-rock formations, the water gets recycled or goes to treatment plants.
Fracking worries people far from Stuart and Dimock. New York City serves 8 million residents from a watershed so pristine it’s exempt from federal filtration requirements.
A consulting firm hired by the city, Hazen & Sawyer PC, said in December that chemicals from fracked wells could have a catastrophic impact. Some, like pesticide 2,2-dibromo-3- nitrilopropionamide, are toxic. Each well needs 82 tons of assorted chemicals for reasons such as killing bacteria and inhibiting corrosion, the report says. New York has banned shale gas drilling statewide until it adopts new rules.
“We firmly believe, based on the best available science and current industry and technological practices, that drilling cannot be permitted in the city’s watershed,” Mayor Michael Bloomberg said in an April press release.
Bloomberg is the founder and majority owner of Bloomberg LP, the parent of Bloomberg News.
Range CEO Pinkerton says New York’s leaders are ignoring facts.
“They’re cuckoo for Cocoa Puffs,” he says, quoting a 1960s breakfast cereal slogan.
Pinkerton, 56, says all Marcellus wells that will ever be built will use less water than one nuclear plant and that damage from coal mines is much worse than shale drilling.
As the drilling debate intensifies, shale gas supporters and opponents are squaring off along the Delaware River, the waterway U.S. General George Washington crossed on Christmas Day in 1776 to defeat Hessian mercenaries.
In April, Pennsylvania issued a permit for the first of up to nine exploratory shale wells in the river basin for New York- based Hess Corp. and Houston-based Newfield Exploration Co. The first well will be 2.5 miles west of the Delaware and 15 miles north of Honesdale.
Pat Carullo says drilling is a beast that can’t be tamed. Carullo, 56, co-founded Damascus Citizens for Sustainability, which wants case-by-case reviews of new wells.
“The gas industry thought they could spread money around like pimps and drill anywhere in the watershed,” he says. “I’ll be dead before that happens.”
Preserving the Farm
Marian Schweighofer, executive director of the Northern Wayne Property Owners Alliance, is rooting for shale gas. If commercial drilling is banned in the river basin, she’d lose out on income for the 712-acre farm in Tyler Hill that’s been in her family for four generations. Marian and her husband Edward, both 54, have gotten $500,000 from Hess so far.
Jack Ivey is contemplating the riches shale gas can bring. He leased 111 acres in Montrose to Mitchell’s Alta for $310,800. Ivey, 80, hopes for at least $346 a day from the first well if gas prices hold up. Royalties may reach $1,734 a day with five more wells.
“Hopefully, I’ll live five or six years so I can get some of this money,” he says.
Mitchell predicts companies will win public support for drilling in Pennsylvania the way they did in Texas.
“With money,” he says, and pauses, as if no elaboration is needed.
Learning From Dimock
Billions of dollars -- and energy for the 21st century -- are at stake. In Australia, Beach Energy Ltd. wants to explore an area that may hold 200 TCF of shale gas. China may produce a quarter of its gas from shale deposits in the next 20 years, the DOE says.
Before Schweighofer’s group signed on for drilling, members toured Dimock and met Victoria Switzer. They hired a lawyer and insisted on stronger well casings than Pennsylvania requires and that farmers be allowed to keep drilling equipment out of their best fields.
Switzer, now a shale gas veteran, says she hopes the world can learn from her and her neighbors that there are costs as well as benefits from unlocking a treasure the Earth has guarded for hundreds of millions of years. http://www.bloomberg.com/apps/news?p...d=a28NMApkl.RQ
Swaminomics declared last week that India must forget the proposed Iran-Pakistan-India gas pipeline because of the outrageously high cost of Iranian gas. Some readers have asked, “Why is Pakistan willing to pay the Iranian price, and go ahead with the project minus India?”
Answer: The pipeline is going to become Pakistan’s Enron. It will drive Pakistan towards bankruptcy and be aborted, just as Enron drove the Maharashtra government towards bankruptcy and was aborted.
Iran and other Gulf producers have long linked the price of gas to that of oil. This was acceptable for decades when oil prices, and hence linked gas prices, were subdued. But oil shot up from $14/barrel in 1995 to a peak of $150/barrel in 2008, and it is still around $75/barrel today.
Iran and Pakistan have agreed on a gas price linked to 80% of the Brent crude oil price. This would have been fair in 1995 but not any longer as oil is up from $14/barrel to $75/barrel.
In a recent interview with Newsline magazine, former Pakistan petroleum secretary Gulfraz Ahmed declared bluntly, “I am now appalled to know that the present negotiations are in the region of 80% of Brent crude.” He adds, “We need this gas urgently, but on the other hand, not at this price.”
He recalls that his original negotiation in the 1990s was for a gas price of $2.05/mmbtu (million metric British thermal unit) from Iran. But the new gas deal implies a price of $8/mmbtu if oil is $60/barrel. If oil goes up to $100/barrel — very likely in the next year or so — the gas price will soar to $13/mmbtu. And if oil returns to its 2008 level of $150/barrel — entirely possible when the Iran-Pakistan pipeline is completed in 2015 — gas will cost a mind-boggling $20/mmbtu, or 10 times as high as originally negotiated in the 1990s.
The cost of 5,000 MW of power to be generated from the gas will rise correspondingly. If oil costs $100/barrel, the linked gas price will translate into an electricity price of around Rs 7.50/ unit. Remember that Enron had to be closed when its price rose to just Rs 4.25/unit: the Maharashtra government said this would empty its coffers.
When Pakistan begins generating power with Iran gas in 2015, oil could be as high as $150/barrel. If so, the corresponding cost of electricity will be Rs 11/unit. Producing power at that price will be economic suicide.
Why has Pakistan got itself into such a trap? Well, don’t be surprised: many Indians still want to join this project. Politicians and strategy wonks can be so fascinated by projects with political appeal that they forget commercial sense. The Left Front is dying to join the project just to spite the US. Pakistan too has foreign policy wonks who see the pipeline as a way to kick the US and display solidarity with Islamic neighbours, oblivious of the suicidal cost.
When Enron proposed its 2000 MW plant in India, this was seen as a fabulously strategic project, worth paying a premium for. At the time the state electricity boards were bust, and India had a terrible power shortage. In this energy desperation, the Enron project was grasped eagerly and cleared at record speed, notwithstanding warnings about the cost. Many hoped this strategic deal would open the gate for dozens more foreign investments.
Fifteen years later, Pakistan also has a terrible power shortage. It too suffers from energy desperation, and so is eagerly grasping a massive power project based on Iranian fuel, ignoring warnings from its own experts about the cost.
Gulfraz Ahmed mentions a third reason for Pakistan’s behaviour: lack of negotiating skills to understand the risks of a 40-year deal with an unfavourable pricing formula. This happened in Enron’s case as well. In both cases the negotiators failed to realize the risks of a contract linked to world oil prices (which could shoot up) and denominated in dollars (the electricity price shot up every time the rupee declined).
Critics of Enron shouted “corruption”. More than 20 cases were filed against the project but all were dismissed by the courts — there was no hard evidence. However, many Indians remained convinced that money had changed hands because Indian politicians are so obviously corrupt. I predict that the Iran gas deal will also be widely condemned as corrupt in Pakistan once the high cost of electricity becomes patently obvious.
Corruption charges are a distraction. The Enron fiasco was caused by a combination of energy desperation, incompetent negotiation, and fanciful notions of strategic importance. Pakistan faces a similar fiasco for the same three reasons.
Maharashtra is India's richest state with a GDP and per capita income greater than Pakistan with almost half the population. If it could not afford a power price a fraction of what it would cost the power from the IP pipeline, Pakistan can hardly afford it.
There's an energy revolution brewing right under our feet.
Over the past decade, a wave of drilling around the world has uncovered giant supplies of natural gas in shale rock. By some estimates, there's 1,000 trillion cubic feet recoverable in North America alone—enough to supply the nation's natural-gas needs for the next 45 years. Europe may have nearly 200 trillion cubic feet of its own.
We've always known the potential of shale; we just didn't have the technology to get to it at a low enough cost. Now new techniques have driven down the price tag—and set the stage for shale gas to become what will be the game-changing resource of the decade.
I have been studying the energy markets for 30 years, and I am convinced that shale gas will revolutionize the industry—and change the world—in the coming decades. It will prevent the rise of any new cartels. It will alter geopolitics. And it will slow the transition to renewable energy.
To understand why, you have to consider that even before the shale discoveries, natural gas was destined to play a big role in our future. As environmental concerns have grown, nations have leaned more heavily on the fuel, which gives off just half the carbon dioxide of coal. But the rise of gas power seemed likely to doom the world's consumers to a repeat of OPEC, with gas producers like Russia, Iran and Venezuela coming together in a cartel and dictating terms to the rest of the world.
The advent of abundant, low-cost gas will throw all that out the window—so long as the recent drilling catastrophe doesn't curtail offshore oil and gas activity and push up the price of oil and eventually other forms of energy. Not only will the shale discoveries prevent a cartel from forming, but the petro-states will lose lots of the muscle they now have in world affairs, as customers over time cut them loose and turn to cheap fuel produced closer to home.
The shale boom also is likely to upend the economics of renewable energy. It may be a lot harder to persuade people to adopt green power that needs heavy subsidies when there's a cheap, plentiful fuel out there that's a lot cleaner than coal, even if gas isn't as politically popular as wind or solar.
But that's not the end of the story: I also believe this offers a tremendous new longer-term opportunity for alternative fuels. Since there's no longer an urgent need to make them competitive immediately through subsidies, since we can use natural gas now, we can pour that money into R&D—so renewables will be ready to compete without lots of help when shale supplies run low, decades from now.
To be sure, plenty of people (including Russian Prime Minister Vladimir Putin and many Wall Street energy analysts) aren't convinced that shale gas has the potential to be such a game changer. Their arguments revolve around two main points: that shale-gas exploration is too expensive and that it carries environmental risks.
I'd argue they are wrong on both counts.
Take costs first. Over the past decade, new techniques have been developed that drastically cut the price tag of production. The Haynesville shale, which extends from Texas into Louisiana, is seeing costs as low as $3 per million British thermal units, down from $5 or more in the Barnett shale in the 1990s. And more cost-cutting developments are likely on the way as major oil companies get into the game. If they need to do shale for $2, I am willing to bet they can, in the next five years.
When it comes to environmental risks, critics do have a point: They say drilling for shale gas runs a risk to ground water, even though shale is generally found thousands of feet below the water table. If a well casing fails, they argue, drilling fluids can seep into aquifers.
They're overplaying the danger of such a failure. For drilling on land, where most shale-gas deposits are, the casings have been around for decades with a good track record. But water pollution can occur if drilling fluids are disposed of improperly. So, regulations and enforcement must be tightened to ensure safety. More rules will raise costs—but, given the abundance of supply, producers can likely absorb the hit. Already, some are moving to nontoxic drilling fluids, even without imposed bans.
But the skeptics aren't just overstating the obstacles. They're missing two much bigger points. For one thing, they're ignoring history: The reserves and production of new energy resources tend to increase over time, not decrease. They're also not taking into account how quickly public opinion can change. The country can turn on a dime and embrace a cheaper energy source, casting aside political or environmental reservations. This has happened before, with the rapid spread of liquefied-natural-gas terminals over the past few years.
In short, the skeptics are missing the bigger picture—the picture I think is the much more likely one. Here's a closer look at what I'm talking about, and how I believe the boom in shale gas will shake up the world.
One of the biggest effects of the shale boom will be to give Western and Chinese consumers fuel supplies close to home—thus scuttling a potential natural-gas cartel. Remember: Prior to the discovery of shale gas, huge declines were expected in domestic production in U.S., Canada and the North Sea. That meant an increasing reliance on foreign supplies—at a time when natural gas was becoming more important as a source of energy.
Even more troubling, most of those gas supplies were located in unstable regions. Two countries in particular had a stranglehold over supply: Russia and Iran. Before the shale discoveries, these nations were expected to account for more than half the world's known gas resources.
Russia made no secret about its desire to leverage its position and create a cartel of gas producers—a kind of latter-day OPEC. That seemed to set the stage for a repeat of the oil issues that have worried the world over the past 40 years.
As far as I'm concerned, you can now forget all that. Shale gas will breed competition among energy companies and exporting countries—which in turn will help economic stability in industrial countries, and thwart petro-suppliers that try to empower themselves at our expense. Market competition is the best kryptonite for cartel power.
For one measure of the coming change, consider the prospects for liquefied natural gas, which has been converted to a liquid so it can be carried in a supertanker like oil. It's the easiest way to move natural gas very long distances, so it gives a good picture of how much countries are relying on foreign supplies.
Before the shale discoveries, experts expected liquefied natural gas, or LNG, to account for half of the international gas trade by 2025, up from 5% in the 1990s. With the shale boom, that share will be more like one-third.
In the U.S., the impact of shale gas and deep-water drilling is already apparent. Import terminals for LNG sit virtually empty, and the prospects that the U.S. will become even more dependent on foreign imports are receding. Also, soaring shale-gas production in the U.S. has meant that cargoes of LNG from Qatar and elsewhere are going to European buyers, easing their dependence on Russia. So, Russia has had to accept far lower prices from formerly captive customers, slashing prices to Ukraine by 30%, for instance.
But the political fallout from shale gas will do a lot more than stifle natural-gas cartels. It will throw world politics for a loop—putting some longtime troublemakers in their place and possibly bringing some rivals into the Western fold.
Again, remember that as their energy-producing influence grew, nations like Russia, Venezuela and Iran became more successful in resisting Western interference in their affairs—and exporting their ideologies and strategic agendas through energy-linked deal-making and threats of cutoffs.
In 2006 and 2007, disputes with Ukraine led Russia to cut off supplies, leaving customers in Kiev and Western Europe briefly without fuel in the dead of winter. That cutoff effectively shifted Ukraine's internal politics: The country turned away from the pro-NATO, anti-Moscow candidate and toward a coalition more to Moscow's liking.
It looked like the U.S. and Europe would see their global power eclipse as they kowtowed to their energy suppliers. But shale gas is going to defang the energy diplomacy of petro-nations. Consuming nations throughout Europe and Asia will be able to turn to major U.S. oil companies and their own shale rock for cheap natural gas, and tell the Chavezes and Putins of the world where to stick their supplies—back in the ground.
Europe, for instance, receives 25% of its natural-gas supply via pipelines from Russia, with some consumers almost completely dependent on the big supplier. In the wake of Russia's strong-arming of Ukraine, Europe has been actively diversifying its supply, and shale gas will make that task cheaper and easier.
Shale-gas resources are believed to extend into countries such as Poland, Romania, Sweden, Austria, Germany—and Ukraine. Once European shale gas comes, the Kremlin will be hard-pressed to use its energy exports as a political lever.
I would also argue that greater shale-gas production in Europe will make it harder for Iran to profit from exporting natural gas. Iran is currently hampered by Western sanctions against investment in its energy sector, so by the time it can get its natural gas ready for export, the marketing window to Europe will likely be closed by the availability of inexpensive shale gas.
And that may lead Tehran to tone down its nuclear efforts. Look at it this way: If Iran can't sell its gas in Europe, what options does it have? Piping to the Indian subcontinent is impractical, and LNG markets will be crowded with lower-cost, competing supplies.
It's admittedly a long shot, but if the regime acts rationally, it will realize it has a chance to win some global goodwill by shifting away from nuclear-power efforts—and using its cheap natural-gas supplies to generate electricity at home.
Overall, the Middle East might get a bit poorer as gas eats into the market for oil. If the drop in revenue is severe enough, it could bring instability.
Shale-gas development could also mean big changes for China. The need for energy imports has taken China to problematic nations such as Iran, Sudan and Burma, making it harder for the West to forge global policies to address the problems those countries create. But with newly accessible natural gas available at home, China could well turn away from imports—and the hot spots that produce them.
The less vulnerable China is to imported oil and gas, the more likely it would be to support sanctions or other measures against petro-states with human-rights problems or aggressive agendas. Moreover, the less Beijing worries about U.S. control of sea lanes, the easier it will be for the U.S. and China to build trust. So, domestic shale gas for China may help integrate Beijing into a Pax Americana global system.
With natural gas cheap and abundant, the prospects for renewable energy will change just as drastically. I have been a big believer that renewable energy was about to see its time. Prior to the shale-gas revolution, I thought rising hydrocarbon prices would propel renewables and nuclear power into the marketplace easily—albeit with a little shove from a carbon tax or a cap-and-trade system.
But the shale discoveries complicate the issue, making it harder for wind, solar and biomass energy, as well as nuclear, to compete on economic grounds. Subsidies that made renewables competitive with shale gas would get more expensive, as would loan guarantees and incentives for new nuclear plants. Shale gas also hurts the energy-independence argument for renewables: Shale gas is domestic, just like wind and solar, so we won't be shipping those dollars to the Middle East.
But that doesn't mean we should stop investing in renewables. As large as our shale-gas resources are, they're still exhaustible, and eventually we will still need to transition to energy that is cleaner and more plentiful. So, what should we do?
First, avoid the urge to protect coal states and let cheaper natural gas displace coal, which accounts for about half of all power generated in the U.S. Ample natural gas for electricity generation could also make it easier to shift to electric vehicles—once again helping the environment and lessening our dependence on the Middle East.
Then, I think we still need to invest in renewables—but smartly. States with renewable-energy potential, such as windy Texas or sunny California, should keep their mandates that a fixed percentage of electricity must be generated by alternative sources. That will give companies incentives and opportunities to bring renewables to market and lower costs over time through experience and innovation. Yes, renewables may seem relatively more expensive in those states as shale gas hits the market. And, yes, that may mean getting more help from government subsidies. But I don't think the cost would be prohibitive, and the long-term benefits are worth it.
Still, I don't believe we should set national mandates—which would get prohibitively expensive in states without abundant renewable resources. Instead of pouring money into subsidies to make such a plan work, the federal government should invest in R&D to make renewables competitive down the road without big subsidies.
In the end, what's important to understand is that shale gas may be the key to solving some of our most pressing short-term crises, a way to bridge the gap to a more-secure energy and economic future.
The trade deficit has crippled our economy and shows no signs of abating as long as we remain tethered to imported energy. Why ship dollars abroad where they can destabilize global financial markets—and then hit us back in lost jobs and savings—when we can develop the resources we have here in our own country? Shall we pay Vladimir Putin and Mahmoud Ahmadinejad to develop our natural gas—or the citizens of Pennsylvania and Louisiana?
India, beaten by China in the race for energy assets across the world, plans to offer shale-gas areas for exploration for the first time, the nation’s oil regulator said.
Preliminary estimates show India’s shale-gas reserves may be larger than its proven conventional gas deposits, said P.K. Bhowmick, president of the country’s Association of Petroleum Geologists.
India will need to change exploration laws for shale gas to be produced because current exploration licenses don’t include unconventional sources, Srivastava said. The changes will have to be approved by the nation’s Cabinet.
“We have to run now, we can’t just walk,” Srivastava said. “We don’t yet know the extent of our reserves and we hope to put everything together within a year.”
“Shale rocks have been found in Gujarat, Assam, Jharkhand,” Sharma said June 25. “We have to study the extent of the reserves and the economics of producing it.”
The shale rock found in India is similar to those in the U.S., Bhowmick said. The cost of producing the gas may be different because the rocks are found deeper in the ground in India than in the U.S., he said.
“The rocks are definitely gas-charged,” Bhowmick said.
Supply of natural gas in India lags behind demand as the nation seeks to cut air pollution and as power plants and fertilizer users seek to replace more expensive naphtha and imported liquefied natural gas with cheaper domestic fuel. Gas demand may rise to 120 billion cubic meters a year by 2015 from 62 billion currently, B.C. Tripathi, chairman of GAIL India Ltd., said June 24.
The nation faces an energy shortfall of 55 percent by 2030 as demand more than doubles to the equivalent of 1.3 billion metric tons of oil, according to the Paris-based International Energy Agency.