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A flurry of new mainstream media articles telling people not to worry about Peak Oil and hydrocarbon depletion have begun appearing on financial sites like Bloomberg, Forbes or The Wall Street Journal.  Peak Oil is the point when global oil production reaches its maximum, plateaus, then eventually begins declining.  According to the IEA, conventional oil production peaked in 2006.  World all-liquids production has been on a plateau since 2005, and should soon start declining.  “All liquids” includes unconventional sources such as tar sands, ultra deep water, and shale, which the media is championing as ushering in a new era of abundance.  Just to set the record straight, I though it would be worthwhile to analyze some of their arguments.  At least some media outlets are willing to even discuss peak oil at all—most remain completely silent.

One Bloomberg article, “Peak Oil Scare Fades as Shale, Deepwater Wells Gush Crude,” by Joe Carrol, claims that “more than 2 trillion barrels of untouched crude is still locked in the ground,” and that “technological advances enable companies to image, drill, and shatter subterranean rocks with precision never dreamed of in decades past.”  The article then goes on to cite the oil sands of Northern Alberta.  What the article doesn’t discuss, however, is the key concepts of EROEI and flow rate.  Unconventional resources, even with modern technology, always take far more energy to extract, which diminishes returns, and the flow rate is much lower.

Another Bloomberg article by Eric Roston argues that tar sands and shale gas show that there is no need to worry about peak oil, although the article admits that (high flow rate) conventional oil has probably already peaked (it has).  Bob Lutz of Forbes describes a Houston oil & gas conference he attended, where “company after company, executive upon oil economist, all described the coming flood of North American oil and gas discovery and production… whether shale gas or Canadian bitumen, the Bakken field in North Dakota and Southern Canada, coupled with advanced new exploration and extraction technology, it was a scenario of abundance.”  This is the same mantra as another Bloomberg article, “Peak Oil—No Longer the Right Question,” which also sites shale gas, tar sands, and deepwater.

The main fallacy in the articles’ logic is that peak oil isn’t about running out of oil, it is about having to use a bit less oil every year, when our growth-based economies were used to a bit more each year.  The significance is the end of growth as the biggest shock to oil dependent economies, not “running out.”  The Carroll article even says “we will not run out of oil in my lifetime, your lifetime, our children’s lifetimes or our grandchildren’s lifetimes.”  According to Matthew R. Simmons, former energy advisor to George Bush, Houston investment banker, and author of the book “Twilight in the Desert: The Coming Saudi Oil Shock and the World Economy,” which accurately predicted the 2008 oil shock of $147 a barrel and subsequent global economic implosion, “we’ll never run out.”  “Never.”  There’s a tail to the peak oil logistic distribution curve that can go on for centuries.  What matters is flow rates and how much money and energy it takes to mine the resource.  So if we are forced to use a lot less, that is still a problem.

All-liquids oil production is now at an all time high of about 89 million barrels a day, and will soon enter terminal decline of a few percent per year according to Dr. Robert Hirsch.  Even a former head of the IEA admits that 90-95 will be the absolute max, in spite of the fact that as recently as 2005 the IEA was predicting demand to be met at 120 million barrels a day by 2030.  Obama’s recent State of the Union speech echoes the articles, citing “almost 100 years” of natural gas due to fracking technology, and that domestic oil production is back to 2004 levels.  Indeed, new horizontal well and hydro-fracking drilling technology has opened up new reserves, but these resources tend to be expensive in terms of both money and energy, and are limited in flow rate.  In other words, we can’t use the stuff quickly.  An analogy would be someone living off a savings of millions of dollars, but only being able to withdraw a few hundred dollars a month.

U.S. oil extraction rates are indeed back to 2004 levels, after 23 years of falling every year.  This is in part due to an oil boom in North Dakota, which is now the one corner of the country with 3 percent unemployment and growth.  This shale formation only produced 111 million barrels of oil up until 2008—or in other words, over 50 years of extraction, only enough oil was pulled up to meet U.S. needs for 6 days.  This deposit is now producing about a half million barrels a day, a massive increase due to horizontal drilling and fracking technology—but will likely peak by 2015 at below one million barrels a day.  Not much compared to the 21 million barrels a day the U.S. was using in 2006, and 19 million today in our downsized economy.  And Alaska and other areas are steadily declining.

As for the Canadian Tar sands and Shale gas, there is a similar story.  The oil sands is solid earth with about ten percent bitumen, which must be strip mined, heated, processed, and treated with large amounts of fresh water.  The process is so energy intensive, it barely has a positive EROEI, meaning that its only use to us would be as a way of converting natural gas into a liquid fuel—and North American conventional gas has been declining since the 1970s.  They are also working tirelessly, 24/7, to produce about 1.5 million barrels a day—not much compared to the global consumption rate of 89 mbpd.  That’s less than 2 percent, and assumes enough fresh water and natural gas exists to continue to produce that much.  A “crash program” may yield 3 million barrels a day by 2030—but this would still mean a global 75 mbpd flow rate, max, in 2030, optimistically.  And demand by then will be over 100 mbpd, even with perpetual recession curbing growth in demand.  Think peasants on scooters in Third World societies that use very little and derive a greater economic value from the fuel.

“Shale gas,” in contrast, may be a bit more promising, and indeed, natural gas prices are now only $2.50 per million BTU, compared with Brent crude, the world benchmark price for oil, now at $116 on the NYMEX, or $20 per million BTU.  This is a great deal right now, especially for power generation, but prices likely won’t remain low for much longer.  Conventional gas is declining, and an unprecedented amount of fracking shale plays would be needed to cancel this out.  The recession has reduced industrial demand in North America, but in Asia gas is $14 per million BTU.  In fact, the EIA recently downgraded the large Marcellus shale’s technically recoverable resources to 141 tcf, just a 6 year supply, from a previous 410 tcf.  The “hundred year” estimate is absurd, and the flow rate and EROEI don’t even justify drilling at these prices.  Natural gas is probably in better shape than coal, and especially oil, but it too is likely to soon begin slowly declining.  Clearly, growth has ended, and the future will be fueled by something other than fossil fuels.

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EIA’s Annual Energy Outlook 2012 Early Release Reference case, providing updated projections for energy markets through 2035, projects increased domestic crude oil production driven by development of tight oil resources onshore and deepwater resources in the Gulf of Mexico.

Tight oil refers to oil produced from shale, or other very low-permeability rocks, with horizontal drilling and multi-stage hydraulic fracturing technologies.

EIA projects that U.S. domestic crude oil production will increase from 5.5 million barrels per day in 2010 to 6.7 million barrels per day in 2020. Even with a projected decline after 2020, U.S. crude oil production projections remain above 6 million barrels per day through 2035.

The AEO2012 Early Release Reference case projects that onshore tight oil production will increase significantly, reaching 1.3 million barrels per day in 2030 and remaining above 1 million barrels per day for the remainder of the projection. As with shale gas, the application of recent technology advances significantly increases the development of tight oil resources. Projections are made for selected tight oil plays; at this point, not all plays have been, or are being, evaluated for the application of emerging production technology.

The AEO2012 also projects that continued development of deepwater crude oil resources in the Gulf of Mexico will become an increasingly important component of domestic crude production. Drilling in the Gulf of Mexico Outer Continental Shelf has resumed following the lifting of the 2010 moratorium, but on a schedule moderated by a slower permitting process with increased environmental review. Production in the Gulf of Mexico fluctuates as new large development projects are brought onstream.

The AEO2012 Early Release Reference case assumes that lease options in the Pacific and Atlantic will eventually be opened, but significant production from those lease sales is projected to occur after 2035. Most of the Eastern Gulf of Mexico Planning Area remains under a Congressional drilling moratorium until 2022.

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Natural-gas futures rose Thursday as the possibility of additional production cuts overshadowed a U.S. government report showing a smaller-than-average drop in weekly gas inventories.

Natural gas for March delivery settled 2.9 cents, or 1.2%, higher at $2.477 a million British thermal units on the New York Mercantile Exchange.

Chesapeake Energy Corp. (CHK) Thursday said it has cut about 500 million cubic feet a day in natural-gas production and reiterated its earlier decision that it could cut up to one billion cubic feet a day if prices stay low.

A news report earlier in the day quoted a Chesapeake executive at a conference saying the company would increase its curtailment target past one billion cubic feet a day, which offered a boost to gas futures. But in a phone interview with Dow Jones Newswires, Chesapeake spokesman Jim Gipson said the company maintained its earlier target.

The market is keeping close watch on any moves by gas producers to limit production in the face of low prices, Phil Flynn, energy analyst at PFG Best, said.

“I don’t think the traders are worried about production that has already been cut, they are worried about the production cuts that may come,” Flynn said.

Several calls for output cuts have followed a drop in futures to 10-year lows earlier this year. While prices have recovered slightly, data released Thursday showed U.S. stockpiles are 32% above the five-year average for this time of year.

In its weekly report, the U.S. Energy Information Administration said U.S. gas stockpiles fell 78 billion cubic feet last week, much smaller than the 191-bcf average draw over the past five years for the same period. Analysts surveyed by Dow Jones Newswires had expected a draw of 87 billion cubic feet.

Milder-than-normal temperatures this winter have suppressed demand at the same time that producers have been creating record amounts of supply from domestic shale fields. Also, with the end of the winter heating season looming, there is an increasing chance that demand won’t eat into the record available supply.

Total U.S. stockpiles fell to 2.888 trillion cubic feet.

Winter is the peak season for gas demand as people rely on the fuel for heating. And while weather forecasters are predicting colder-than-normal temperatures across much of the Northeast, Midwest and South in the next one to five days, the spell is expected to disperse further over the next two weeks.

While output cuts could help stem the price declines, only a burst of frigid temperatures or rising industrial demand will set prices on a higher course, natural-gas trader John Woods, head of JJ Woods Associates, said.

“If people say they are going to cut back production, that’s fine. But it’s still in the ground. Weather and the economy are what’s going to turn this around,” Woods said.

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On January 23, 2012, Chesapeake Energy announced that it would curtail drilling in shale gas plays in the United States. Subsequently, other operators have followed suit. While the outcome of this announcement is unclear, it is a signal that the industry is in distress. One can argue that this distress stems from a lack of discipline as market price began to decline.
After gas prices collapsed in mid-2008, U.S. operators continued to drill as if price did not matter. Many reasons were given to justify the economics of on-going activity including to hold acreage by production, to fulfil contract obligations to build new pipelines, and since well economics remained favourable at lower prices because of forward hedging. Now, with gas prices below $2.50 per thousand cubic feet (mcf), an adjustment in producer behaviour is overdue. Despite statements that shale gas is a profitable venture at low gas prices, it is now clear that the reality has imposed limits on these claims.

Also on January 23, the Energy Information Administration (EIA) released its Annual Energy Outlook 2012 (early release overview). It projects that gas supply will exceed consumption and the U.S. will become a net exporter by 2021. The agency also forecasts gas prices to remain below $5.00 per thousand cubic feet (mcf) until 2022.

In his State of the Union address on January 25, the President stated that the United States has 100 years of natural gas supply. While these events are not related, they reflect the dominant view among analysts that shale gas has fundamentally changed supply and price for the foreseeable future. The purpose of this analysis is to show that there may be an alternate perspective.

U.S. Shale Plays

The advent of shale plays provided an important new source of gas. Yet this new supply is characterized by high decline rates which means that wells must be continuously drilled to maintain supply. In 2001, the U.S. natural gas decline rate was about 23% and the annual replacement requirement was 12 Bcf/d when total consumption was 54 Bcf/d.

According to ARC Financial Research, $22 billion per quarter is needed to maintain domestic gas supply based on analysis of the 34 top U.S. publicly traded producers. Cash flow for those companies is $12 billion per quarter so there is a $10 billion quarterly cash flow deficit (Exhibit 3). The important factor here is that on a whole there are no retained earnings, and historically growth stems from retained earnings. Without retained earnings, companies must borrow money or sell assets into joint venture agreements to raise cash in order to drill.

While the continued drilling has been funded by debt, share offerings and joint venture agreements thus far, the trend is unsustainable given the steep decline in prices, despite some favourable hedges. Drilling, therefore, must decrease in order to shrink the present over-supply and so that prices can rise.

U.S. shale plays share many characteristics with the gold rushes of the nineteenth and early twentieth centuries. Both phenomena result from extreme promotion. Anyone can join. Every participant believes that they will get rich. Great amounts of capital are destroyed as entrants try to get a position. The bonanza is exhausted sooner than most expected (Andreoli, 2011) and few profit in the end except for the vendors that serve participants.

For several years, we have been asked to believe that less is more, that more oil and gas can be produced from shale than was produced from better reservoirs over the past century. We have been told more recently that the U.S. has enough natural gas to last for 100 years. We have been presented with an improbable business model that has no barriers to entry except access to capital, that provides a source of cheap and abundant gas, and that somehow also allows for great profit. Despite three decades of experience with tight sandstone and coal-bed methane production that yielded low-margin returns and less supply than originally advertised, we are expected to believe that poorer-quality shale reservoirs will somehow provide superior returns and make the U.S. energy independent. Shale gas advocates point to the large volumes of produced gas and the participation of major oil companies in the plays as indications of success. But advocates rarely address details about profitability and they never mention failed wells.

Shale gas plays are an important and permanent part of our energy future. We need the gas because there are fewer remaining plays in the U.S. that have the potential to meet demand. A careful review of the facts, however, casts doubt on the extent to which shale plays can meet supply expectations except at much higher prices.

One Hundred Years of Natural Gas

The U.S. does not have 100 years of natural gas supply. There is a difference between resources and reserves that many outside the energy industry fail to grasp. A resource refers to the gas or oil in-place that can be produced, while a reserve must be commercially producible. The Potential Gas Committee (PGC) is the standard for resource assessments because of the objectivity and credentials of its members, and its long and reliable history. In its biennial report released in April 2011, three categories of technically recoverable resources are identified: probable, possible and speculative.

The President and many others have taken the PGC total of all three categories (2,170 trillion cubic feet (Tcf) of gas) and divided by 2010 annual consumption of 24 Tcf. This results in 90 and not 100 years of gas. Much of this total resource is in accumulations too small to be produced at any price, is inaccessible to drilling, or is too deep to recover economically.

If half of this supply becomes a reserve (225 Tcf), the U.S. has approximately 11.5 years of potential future gas supply at present consumption rates. When proved reserves of 273 Tcf are included, there is an additional 11.5 years of supply for a total of almost 23 years. It is worth noting that proved reserves include proved undeveloped reserves which may or may not be produced depending on economics, so even 23 years of supply is tenuous. If consumption increases, this supply will be exhausted in less than 23 years. Revisions to this estimate will be made and there probably is more than 23 years but based on current information, 100 years of gas is not justified.

Shale Gas Plays May Not Provide Sustainable Supply

Several of the more mature shale gas plays are either in decline or appear to be approaching peak production.

This play is most responsible for the current over-supply of gas with the average well producing 3.3 million cubic feet per day (Mcf/d) compared to only 0.4 Mdf/d in the Barnett. It is too early to say for sure, but the Haynesville Shale may also be approaching peak production.

If some existing shale gas plays are approaching peak production after only a few years since the advent of horizontal drilling and multi-stage hydraulic fracturing, what is the basis for long-term projections of abundant gas supply?

What Publicly Available Data Indicates About Supply

Data for this analysis is from publicly available sources provided by government agencies such as the Texas Railroad Commission (TX RRC), the Louisiana Department of Natural Resources (LA DNR), the Oklahoma Corporation Commission, and the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). This data is available on web sites maintained by these agencies but is also collected and compiled for a fee by service companies, specifically IHS and HPDI (DI Desktop). All of these sources provide access to individual well, field, county, and state production.

The EIA provides valuable data on oil and gas production but not at finer than state level, and state production is only current through 2010. EIA gas production data differs somewhat from state data and from the data collected by service companies, and is generally more optimistic. The EIA uses a model to calculate gas production based on a sample of large gas producers, and then applies a correction to reconcile production with underground storage volumes.

The October 2012 difference was 1.6 Bcf/d. Although TX RRC Data indicates that Texas gas production has declined each month since March 2011, EIA reports show consistent increases. This difference is important because Texas produces 28% of U.S. gas supply (Exhibit 11). Similar differences have been noted for other major gas-producing regions. It should be noted that the EIA data in Exhibit 11 represents marketed production while the TX RRC data shows total gas production.

These accounts should have different values but also should have similar trends. The trends are similar through March 2011 but then diverge producing the present noted variance (The November difference, not shown on the graph, is 2.6 Bcf/d).

We have studied Texas production reporting and find that it is generally reliable and accurate in areas that we follow closely in our oil and gas exploration and production business. Revisions are common for the first and second most recent months of production but are not statistically significant at the state or field level. Data going back three reporting months is reliable. Studies of other major gas-producing states show similar results. Our intent to is to point out the differences between state and EIA data, and to suggest that EIA data is not particularly useful to track individual play or some state production on a current basis.

Texas, Louisiana, Wyoming, Oklahoma, Gulf of Mexico Outer Continental Shelf, and New Mexico account for roughly 75% of U.S. natural gas supply and, therefore, provide a useful proxy for total U.S gas production. Exhibits 12 through 17 show natural gas production for these regions.

All of these major gas-producing areas except Louisiana are in decline. This is largely because non-shale production is declining rapidly since little new drilling in these reservoirs in recent years has occurred. While shale production volumes and initial rates are impressive (Exhibit 18), much of this new production is merely substituting for depleting conventional gas reserves.

With the shift to more oil-prone or “liquids-rich” shale plays, many observers have suggested that associated gas production from these plays is or will be a major contributor to the present over-supply of gas. Approximately 3% of total U.S. gas supply is from shale associated gas so, while this is a factor, it is not the cause of over-supply. Details of this analysis may be found in an earlier post. Overall, U.S. natural gas production using state-level data appears to have reached an undulating plateau (Exhibit 19).

Conclusions

A secular shift has occurred in the U.S. domestic gas supply by drilling mostly shale formations, formerly considered source rocks too costly to develop. The tremendous number of wells drilled in the last several years has contributed to an over-supply of gas. The shale revolution did not begin because producing oil and gas from shale was a good idea but because more attractive opportunities were largely exhausted. Initial production rates from shale are high but expensive drilling and completion costs make economics challenging. The gold rush mentality taken by companies to enter shale plays has added expensive leases and new pipelines to those costs, further complicating shale gas economics.

In the decades before shale plays, the exploration and production emphasis was on discipline. Science was used to identify the most prospective areas in order to limit the amount of acreage to be acquired and its cost. Shale plays have produced a land grab business model in which hundreds of thousands of acres are acquired by each company. Unprecedented lease costs have become the norm often based on limited information and science.

Operators have indulged in over-drilling these plays for many reasons but adding reserves, holding leases and company growth are among the main factors particularly with the low cost of capital. The inevitable result has been the collapse of prices as supply exceeded demand. Most analysts forecast that the future will be much like the present, and that natural gas will be abundant and cheap for decades to come. There are, however, strong and consistent indicators that natural gas supply may be less certain than most observers believe and require a higher price to be developed economically. Natural gas demand is growing as fuel switching for electric power generation continues, and will be increased by environmental regulation in the coming years. The U.S. will shift more of its future energy needs to natural gas in many sectors of the economy. The best justification, in fact, for the land grab and over-drilling spree is expectation of higher prices. Those companies that grabbed the land and held it by production will profit greatly once the true supply and cost of shale gas is recognized.

The financial survival of all companies in this position is not, however, certain. Price matters, and there is finally some response from shale gas producers with recent announcements to curtail drilling. While price was cited as the main reason for reduced drilling, it is likely that some companies now have financial constraints. The shale gas phenomenon has been funded mostly by debt and equity offerings. At this point, further debt and share dilution are less feasible for many companies. Joint ventures have provided a way for some to prolong spending but that now seems like a less likely source of funding. Capital availability in the near term will likely be tighter than is has until now. Acquisition and consolidation may become more attractive to companies with cash as producers become more extended.

Some of the shale gas plays may be at or near peak production at least at the current price of gas and technology. All major producing areas except Louisiana are in decline. Some doubt the accuracy of public data compared with EIA data, but it seems unlikely that the trends it shows are erroneous. In any case, the data the EIA makes available does not have sufficient resolution to evaluate individual plays or state-level trends.

Intermediate-term shale well performance is poorer than assumed previously. Continuous treadmill drilling masks this issue so play decline rates are not recognized. High decline rates are, however, a salient issue meaning that and most of a shale gas well’s reserve is produced in the first few years. Well life appears to be shorter than initial expectations. This means that an increasing number of wells must be drilled in order to maintain supply. Now, it appears that fewer wells may be drilled until price recovers to commercial levels. The argument for improved efficiency that cites increasing production with lower rig count is suspect. It is mostly because of the large backlog of previously drilled wells that are just now being connected to sales. This spare capacity provides a boost to supply during a period of falling gas-directed rig count.

The gold rush is over at least for now for the less commercial shale plays. The money and activity have moved to more oil-prone shale plays such as the Eagle Ford and Bakken or to higher potential gas plays such as the Marcellus. Improbable stories that great profits can be made at increasingly lower prices have intersected with reality. A painful adjustment is underway in the natural gas exploration and production industry. Fewer jobs will be created and projects may develop more slowly. This development may expose the notion of long-term natural gas abundance and cheap gas as an illusion. The good news is that this adjustment will lead to higher gas prices in a future less distant than most believe. Higher prices coupled with greater discipline in drilling will allow operators to earn a suitable return and offer the best opportunity for supply to grow to meet future needs.

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Natural gas prices continued to fall this week, pulling down Encana Corp. shares with them as a looming storage overhang pressured markets basking in an unseasonably warm winter.

Encana, the third largest natural gas producer in North America, has seen its stock battered by steadily declining gas prices, falling to a low of $17.39 per share mid-January from a 12-month high of $25.75 in August 2011.

Shares of the company slid two per cent to close at $19.48 on the Toronto Stock Exchange on Wednesday, falling on natural gas futures which settled at $2.448 US per million British thermal units, down 2.4 US cents.

Yet market confidence in the Calgary-based producer appeared relatively unshaken despite no end in sight for soft pricing and the sudden resignation of a key executive earlier this week.

“Investors are concerned about the macro environment, that’s their No. 1 concern” said Randy Ollenberger, analyst with BMO Capital Markets. “So, not so much (Encana) directly, more just the company that’s exposed to a commodity where no one really sees much opportunity for material upside.”

News Mike Graham, president of Encana’s Canadian division, resigned Tuesday barely caused a ripple in the market after executive vice-president Mike Marsh confirmed his abrupt departure.

Ollenberger noted Encana has one of the lowest operating costs in the industry and boasts a high-quality asset base, although levered to the wrong commodity. The company produced approximately 3.36 billion cubic feet of natural gas per day during the third quarter.

Encana has been manoeuvring its assets to recover from a failed $5.4-billion joint venture with China on its Horn River shale gas project last June, divesting $3.5 billion in assets in the past year.

The company has been focusing capital to build up liquids plays from its dry gas-weighed assets.

Encana has several legacy assets in northwest Alberta and northeast B.C., and has stakes in hot new shale plays such as the Niobrara in Wyoming and Tuscaloosa Marine shale in Louisiana.

While Encana is considered a leader in the use of shale-cracking technologies to reduce costs and increase efficiencies, the market’s assessment of its move into liquids will depend on how the company spent on the leases.

“It really boils down to how much land were they able to acquire and at what cost,” said Phil Skolnick, with Canaccord Genuity.

Skolnick noted much of the market’s view will hinge on next weeks quarterly results and guidance.

Last week credit rating agency Standard & Poor’s downgraded Encana to BBB, just two steps above non-investment grade, because of poor natural gas prices in the near term. The company’s debt to adjusted earnings before taxes was 2.1 times, on a trailing 12-month basis, according to third quarter results.

A corporate decision to proceed with the Kitimat liquefied natural gas project in northern British Columbia could provide a boost to Encana’s sagging shares, providing an outlet for its B.C. gas production.

Apache Corp., the Houston, Texas-based lead on the project, is expected to announce a decision on the $4.2-billion project next Tuesday when it releases the company’s fourth quarter results. Encana, which historically would have released its quarterly results this week or earlier, will release its quarterly information the following day.

“The consensus is that the Kitimat project is going to go ahead, and obviously that provides an opportunity for the partners in that LNG project to access higher-priced markets,” said Ollenberger. “It will significantly improve the economics of the Horn River for companies that have that exposure, so Encana, Apache and EOG are the big beneficiaries there.”

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At the start of last year Marius Kloppers had $10 billion burning a hole in his pocket. Rebuffed in attempts to acquire mining rival Rio Tinto as well as Potash Corp. of Saskatchewan, the chief executive of BHP Billiton needed a big deal to deploy the $24 billion in profits the company had piled up last year feeding China’s insatiable appetite for natural resources.

He found it in Arkansas, shelling out $4.75 billion to acquire gas giant Chesapeake Energy’s acreage in the Fayetteville Shale. Then in July he bet again, paying $15 billion—a 65% premium to market value—for Petrohawk Energy and its accumulation of prime shale fields in Louisiana and Texas. Though BHP had zero experience drilling for shale gas, the deals suddenly made the world’s largest and richest mining company, headquartered in Melbourne, Australia, one of the 15 largest natural gas producers in America. Even for Kloppers, who’s a 19-year veteran of BHP Billiton and known for his steeliness in building one of the most powerful commodities companies of the past half-century, it all looks risky—maybe too risky

Evy Hambro, manager of a $30 billion mining fund at BlackRock, wondered aloud last fall what BHP had gotten his clients into. “We are waiting to be educated by BHP on these transactions,” Hambro said at a Melbourne conference in October. “When you start putting something on your stall that you’ve never told investors about, people are naturally a bit reserved. So when you are suddenly exposed to shale gas, you want to know why.”

For one thing, BHP Billiton Petroleum, the oil-and-gas subsidiary, has focused mostly on deepwater projects; it hadn’t “fracked” a single shale well until it took over the operations of Chesapeake. Meanwhile, the U.S. nat-gas glut shows no signs of abating. The price of domestic gas already appeared to be at a nadir at $4.25 per thousand cubic feet (mcf ) when the Petrohawk deal was cut. Yet in the intervening months prices fell to $2.30 per mcf in early February, a depth not seen since 2002 and so low that drillers are losing money on marginal shale fields. Shares of big gas drillers have fallen, and in January gas giants Chesapeake Energy and ConocoPhillips both announced they would curtail gas development to pare losses.

As if that weren’t enough for shareholders to worry about, the $20 billion shale outlay is just an ante. Michael Yeager, the Houston-based chief executive of BHP Billiton Petroleum, says it will take ten years and at least $50 billion in capital investment to develop these assets. By comparison, Rio Tinto and Potash Corp. are already mature companies that throw off loads of cash.

Kloppers shrugs off the Cassandras. “Shale gas is like coal mining,” he says. “Like coal the formation is extensive, and you can programmatically and at lowest cost move through the basin and extract the gas.” Besides, it has held on to most of Petrohawk’s 800 employees and many key engineers.

Yeager admits that for the average well in the Fayetteville and Haynesville shales BHP needs gas prices of $3 and $4 per mcf just to break even. Yet, he says, Petrohawk had laid claim to the thickest, juiciest acres in those plays, where the economics are slightly better. What’s more, in the oil-rich Eagle Ford and Permian Basin acreage, BHP can give away the gas and still make good profits on the oil.

The executives believe that in time demand will follow supply. “Shale is a game changer; it’s real, it’s abundant, it’s economic,” says Yeager, a former Marine who spent 26 years at Exxon. “On a global basis it is cheap molecules.” Eventually “the U.S. will connect cars to natural gas,” says Kloppers. And if that’s not enough to raise the gas price, there are exports. A handful of liquefied natural gas export terminals are already in the works on the U.S. Gulf Coast. Considering that LNG fetches $15 per mcf in Asia and $10 per mcf in Europe, “putting a price marker down for export gas is an important thing,” says Kloppers. He’s convinced that natural gas, like oil, will someday fetch pretty much the same price all over the world. “We are confident, based on all the other products we’ve got, that the arbitrage will continue,” says Kloppers.

He should know. Kloppers, 49, joined Billiton back in 1993. He leapt up the ranks, and at the time of Billiton’s merger with BHP in 2001 the wunderkind was appointed chief marketing officer–responsible for matching his supply with customer demand on a myriad of minerals. In 2005 he spearheaded BHP Billiton’s $7 billion acquisition of Australia’s Western Mining Co. (which owned BHP’s new Olympic Dam megaproject).

When he was appointed CEO of BHP Billiton in 2007 the global mining business had never been better, as booming de- mand in China, where BHP sells 30% of its products, fattened bottom lines across the industry. Kloppers waited less than a month to launch an $80 billion takeover bid for rival Rio Tinto. It was a bold move that would have resulted in one of the world’s ten biggest companies. The deal made sense, too: As with BHP Billiton, Rio’s assets (Alcan acquisition aside) are high quality, long-lived and low cost. Yet the betrothal ultimately foundered in the wake of the global financial crisis.

Kloppers is not afraid of challenge or change. He grew up in Johannesburg, during the apartheid era. He was conscripted into South Africa’s war with Angola at age 18, went to the University of Pretoria, won a Fulbright scholarship, earned a doctorate at MIT and an M.B.A. at Insead, and worked as a consultant at McKinsey & Co. before joining Billiton. Married to his high school sweetheart, with three kids, including an adopted Zulu daughter, Kloppers is a family man. He’s also a sophisticate, a prodigious reader and a lover of avant-garde cinema who doesn’t suffer fools.

Kloppers brushed off the Rio Tinto deal and in 2010 set his sights on the new target—-Potash Corp. of Saskatchewan. The hostile $30 billion bid was ultimately blocked by the Canadian government, which was unwilling to see control of possibly the world’s biggest potash re- serves fall into foreign hands. No matter, Kloppers is taking the fight to Potash Corp. Having grabbed some undeveloped Canadian potash reserves, BHP is likely to invest $10 billion in its new Jansen mine.

Kloppers has fully rationalized the benefits of plunging BHP into shale gas. He speaks professorially of the sweep of civilizations and how BHP is set to supply their needs at every step of development. “As economies grow they consume everything in infrastructure: steel, coking coal, manganese. As they continue to industrialize they need copper and nickel, aluminum,” he says. “As you hit $30,000 GDP per person economies consume more energy. They need more oil and gas.”

The average Indian or Chinese is far from that, but give it a decade or two. Because BHP Billiton’s time horizon is closer to 30 years than 3 months, Yeager says, he has no problem swallowing several quarters of losses on certain shale fields. “We want to become masterful at working shale. Not only here, but on a global basis.” To that end he suspects the controversy over fracking will be short-lived. “The industry is doing a great job of taking frack fluids and making them more benign and more safe,” Yeager says, and BHP is dedicated to investigating “greener” fracking techniques.

BHP also has a good reputation for safety and was the first allowed to drill in the deepwater Gulf of Mexico after the BP oil spill. With BP, BHP is set to start the next phase of development on its 4-billion-barrel Mad Dog field. Yeager predicts BHP’s oil and gas volumes will grow from 600,000 bpd now to 1 million bpd in 2015.

And if natural gas gets even cheaper? That would give BHP only more opportunities to pick off weaklings, it says. With their decades-long view, Kloppers and Yeager don’t doubt in the least that world demand for gas, as a cleaner-burning fuel to supplant coal and oil, will grow. “Shale is going to work around the world, and it’s going to be here for 50 years,” says Yeager. “Wouldn’t it be irresponsible to not be in that?”

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Federal policing of oil and natural gas drilling on public lands is lax and inconsistent, with only 6 percent of violations resulting in monetary fines over 13 years, U.S. House Democrats said in a report Wednesday. Fines over that time totaled less than $275,000, an amount that the Democratic staff of the House Natural Resources Committee characterized as little more than “pocket change” for oil and gas companies.

The report, obtained by The Associated Press before its public release later Wednesday, said the government does little to ensure accountability or protect the environment, even as drilling on federal land has increased in recent years. The increase is driven in part by hydraulic fracturing, or “fracking,” a drilling technique that has allowed companies to extract oil and gas long locked underground.

The report focuses on drilling activity that occurred on federal land in 17 states during three administrations, two Democratic and one Republican. A total of 2,025 citations for safety and drilling violations were issued to 335 companies, the report said, with 64 companies fined a total of $273,875

“It would be an overstatement to even call these fines a slap on the wrist. For oil and gas companies making billions from drilling on America’s public lands, this kind of inadequate oversight and enforcement is little more than a pin prick,” said Massachusetts Rep. Edward Markey, the committee’s top Democrat. Markey and Rep. Rush Holt, D-N.J., requested the report.

“American citizens and workers should feel confident that oil and gas companies are conducting business in the safest manner possible, and when they don’t, that the U.S. government will step in and make sure they pay the price for their actions. This report indicates that confidence in the oversight of drilling on public lands should be limited, at best,” Markey said.

The Obama administration is considering new rules for fracking at oil and gas wells on federal land.

President Barack Obama said in his State of the Union speech last month that the Interior Department will require energy companies to publicly disclose chemicals used in drilling for natural gas on public lands. Federal rules for fracking on public lands are set to be released in a few weeks.

In fracking, millions of gallons of water, sand and chemicals are pumped into wells to break up underground rock formations, allowing oil and gas to escape. Energy companies have greatly expanded their use of fracking as they tap previously unreachable shale deposits, including the lucrative Marcellus Shale formation in Pennsylvania, New York and neighboring states.

The drilling practice has also attracted increased attention from Congress and regulators, as private groups and government agencies research whether it poses a danger to drinking water.

The report found that more than 2,000 violations were handed out by the Interior Department to oil and gas companies drilling on federal land. Of these, 549, or 27 percent, were classified by committee staff as a major environmental or safety violation. More than half the major violations stemmed from a nonfunctioning or missing blowout preventer, the same device that failed in the BP oil spill in the Gulf of Mexico, the report said.

A total of 113 major violations cited inadequate well-casing or cementing, another problem that occurred in the BP spill. Onshore, well-casing and cementing are a key defense against groundwater contamination. On at least 54 occasions, oil and gas companies began drilling on federal land before receiving formal approval to do so, the report said.

Despite those problems, monetary fines were rarely issued, the report said. In eight states — Alaska, Arkansas, Louisiana, North Dakota, Nevada, Ohio, South Dakota and West Virginia — no fines were issued for the period studied.

Thirteen companies were cited for at least 30 violations over the period studied, topped by Oklahoma-based Williams Production RMT Co., which received 98 citations and seven fines totaling $6,000.

Colorado-based Encana Oil & Gas Inc. received 63 citations and four fines totaling $11,000, while Texas-based Anadarko E & P Co. received 61 violations and one fine totaling $5,000.

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The Sierra Club is asking President Barack Obama to ensure any

settlement of the government’s case against responsible parties for

the 2010 BP oil spill in the Gulf of Mexico include financing for Gulf

Coast coastal restoration efforts. A lengthy trial to determine

liability under the Clean Water Act and Oil Pollution Act is scheduled

to begin Feb. 27 in New Orleans federal court. Some legal experts

expect settlement talks to heat up once the trial is under way.

In a letter this week to Obama, Michael Brune, executive director of

the Sierra Club, said a settlement should include at least $10 billion

to implement an early restoration strategy for the Gulf of Mexico and

another $20 billion to enhance the Gulf’s natural resources.

Given the environmental damages discovered long after the 1989 Exxon

Valdez spill, including the continued collapse of the Pacific herring

fishery, Brune said it’s critical that any settlement on the BP spill

has a “reopener provision” to address unanticipated damage.

Rep. Cedric Richmond, D-New Orleans, agreed that the president should

be prepared to act to ensure adequate coastal restoration funding from

the parties responsible for the spill if Congress doesn’t act.

Sen. Mary Landrieu, D-La., and other Gulf Coast lawmakers continue to

push for congressional enactment of legislation that would allocate 80

percent of Clean Water Act fine money to affected coastal states.

Landrieu expressed doubt the president could target money from any

settlement or court decision to Gulf restoration efforts because she

says the law specifies penalties go to the general fund unless

Congress “directs the money elsewhere.”

Devorah Ancel, a Sierra Club attorney, said the administration could

negotiate a settlement that lowers certain fine and penalty payments

in return for creation of a large fund for Gulf restoration.

Landrieu cautions it would be a shame if talk of a possible settlement

eases the pressure on Congress to pass the Restore Act, which sets

aside most of the penalty money for the five Gulf States.

During a news conference Wednesday with state and local officials who

have been lobbying Congress to pass the legislation, Landrieu said

she’s looking to add the Restore Act to “must pass legislation.” Among

the possibilities, she said, are bills extending the payroll tax

reduction and authorizing transportation projects.

Rep. Steve Scalise, R-Jefferson, said he continues to urge House GOP

leaders to schedule a vote on the Restore Act.

Billy Nungesser, president of Plaquemines Parish, one of the local

officials lobbying this week for the Restore Act, said damage from the

spill continues to degrade the Gulf’s environment.

If Congress doesn’t act to ensure that there’s enough money for

coastal restoration, it would be a mistake of epic proportions,

Nungesser said.

Connie Rocko, a Harrison County (Miss.) Commissioner said the “toxic

political environment” in Washington shouldn’t kill off a bill that

Republicans and Democrats along the Gulf Coast agree is desperately

needed.

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