Fossils on the Beach (Part I)
Fossils on the Beach: Risks Relating to Ongoing Investment Reliance on Fossil Fuels
We rely heavily on fossil fuels to power today’s global economy. Coal, but even more so, oil and gas are energy-dense, transportable and can be used in transport and to produce electricity. Our heavy reliance on coal dates back to the 1890s, but by 1970 we had already transitioned most of that from coal to oil and gas. As the following chart shows, we are capable of making fairly rapid shifts in our overall energy mix when newer energy forms prove themselves cheaper or better.
In fact, history would suggest that we are within a decade or two of making another fundamental shift in our energy mix. But why do so when oil and gas have served our needs so well?
Historically, energy mix changes have occurred for three reasons: (i) our demands for the resource exceed our ability to economically provide it; (ii) some by-product of that use causes externalities eventually priced into our use in a way that makes ongoing usage prohibitively expensive; or (iii) something else comes along that is fundamentally better/cheaper. Bottom line: We won’t make a change because we are running out of coal, oil or gas; we will change because we are better off economically using something else.
Investors can be impacted by these changes because so much of the value of coal, oil and gas stocks is tied to the value of the “reserves” held by the companies whose shares investors buy. In fact, most of the value of oil stocks represents assets in the ground not expected to be burned for ten or more years in the future. As a result, if that forward use is curtailed, the impact on current stock prices can be devastating.
Recent years have already shown a relatively small decline in coal prices can lead to much larger declines in coal stock indices. Between 2010 and 2012, U.S. coal commodity prices dropped by 25%, but coal stock indices dropped by 75% – and have not recovered. The last decade has also seen significant swings in the prices of both natural gas (between $2 and $15/mcf) and oil (between $40 and $140/barrel). At the high end, these prices enable both more extravagant extraction methods but also greater levels of substitution through switching to energy sources such as wind, solar, batteries and biofuels. Conversely, at the low end of the spectrum, prices can seemingly crush such renewable competitors (even as they also crush higher cost producers of oil and gas at those price levels – such as tar sands, deep-sea, artic and some shale resources).
As uncertainty and volatility increase, a growing number of experts are questioning whether at least part of these reserves of coal, oil and gas will become stranded as a result of (i) governmental actions to curb CO2; (ii) their costs of recovery exceeding the price that can be charged for them (particularly to the extent that alternatives may increasingly exist at prices that for those alternatives, keep falling); or (iii) rising prices sufficiently curbing demand so as to limit the amount of fossil resources we are willing to use.
In the United States, we have developed a healthy dose of confidence in the ability of shale gas and tight oil to address many issues; chiefly economic, but it is a level of confidence that could overemphasize these fuels and just how much of a “solution” they really pose. This bullish sentiment is perhaps best expressed in a recent article by Edward Morse, “Welcome to the Revolution,” published in Foreign Affairs, May/June 2014  in which he concludes: “The shale revolution in oil and gas production is here to stay. It will spread more rapidly than most think. And all of that is a good thing for the world.” Morse obviously isn’t troubled by Climate issues, but his enthusiasm precedes recent drops in oil prices and one can now ask “just how low can prices go and still enable sustainable profit levels from fracking?” Obviously that question is even more applicable to tar sands, artic and deep water oil extraction.
The Stranded Asset Issue
Definition. The notion of a “stranded asset” is that a change in circumstances renders a once valuable asset into one no longer nearly as useful or from which one can no longer reclaim the value once ascribed to it. As applied to energy today, the concept has largely arisen from the connection between fossil fuels, the carbon dioxide produced by burning them and the amount of global warming produced by that carbon dioxide; with the scientific consensus being that we should not allow the global temperature to increase by more than 2 degrees Celsius. More specifically, it is believed that 2 degrees is the maximum temperature rise we should allow if we want to avoid amplifying carbon-cycle feedbacks. More recent research even suggests that 2 degrees may be too high a limit. Nonetheless, a 2 degree limit means we can burn roughly 565 more gigatons of CO2 by 2050. As of 2014, the amount we “plan” to burn – the amount that is represented by the proven coal and oil and gas reserves of the fossil-fuel companies (the asset value on their books), and the countries that act like fossil-fuel companies – is 2,795 gigatons. In dollars, this asset value is roughly $27 trillion, and ostensibly the amount that would need to be written off between now and 2050, if we hold ourselves to the 2 degree limit is roughly $20 trillion.
For investors, the question this poses is – will we choose to limit ourselves to save the planet or will we simply be unable to act politically and globally. Over the last year, more and more oil companies are admitting in their SEC filings that there will be dire consequences if the world does not act to limit CO2 emissions and at the same time, those oil companies argue that we simply won’t have the will-power to limit ourselves and therefore there is no need to write down their fossil assets – we will burn them.
Although it certainly has not subscribed to the magnitude of the write-off, even the International Energy Agency says global CO2 emissions from energy need to peak by 2017. “The contradiction between global carbon budgets and fossil fuel reserves is gaining increasing attention,” it says.
The risk applies not only to oil, coal or gas companies, there are also financial risks to their shareholders. There are obvious balance sheet implications for these companies; but the risk may also apply to other energy and water-intensive businesses whose value is affected by cost and availability of fossil fuels.
Paths to Stranding. Limitations on burning carbon are not the only path to stranding significant oil, coal and gas assets. There are, in fact, three separate potential paths to stranding:
1. Laws, regulations and taxes, including indirect regulation through increased pollution controls, constraints on water usage, or policies targeting environmental or health concerns; as well as mandates on increased use of renewable energy;
2. Simple market economics, whether a) increasing costs of fossil fuels destroy demand levels or b) declining costs of renewable energy technologies causing substitution between fossils and renewables; and
3. Sociopolitical pressures being applied on institutional and other investors (such as fossil fuel divestment campaigns, environmental advocacy, grassroots protests and changing public opinion) such that capital simply moves away from fossils and their cost of capital increases.
The movement of capital away from coal, oil and gas may prove a more potent and faster-acting force than regulation. As Jonathan Koomey, a research fellow at the Steyer-Taylor Center for Energy Policy and Finance at Stanford University, recently noted in his blog: “The reason why this development is so important is because once markets realize there’s an arbitrage opportunity, they relentlessly chip away at it until it is eliminated. And the stranded fossil asset arbitrage opportunity is one that’s worth many trillions of dollars. So the pressure will continue to build, and soon the disclosures will result in attention paid to this asset risk that simply hasn’t been present before. That attention will become a flood very rapidly. It’s the beginning of the end of the fossil-fuel economy, but the big players just don’t realize it yet (or if they realize it, they’re not admitting it).”
Well worth reading is "Stranded Carbon Assets" a report from Generation Foundation, the nonprofit arm of Generation Investment Management, which does an excellent job of describing the foregoing risks and concluding as follows: “The inevitable transition to a low-carbon economy will revolutionize financial markets at an unprecedented magnitude. Although we cannot, and should not, abandon the world’s current energy infrastructure overnight, investors who equate the transition with drawn-out, incremental change do so at their own peril as the stranding of carbon assets may occur at unforeseen rates and at an unpredictable scale.”
The Generation report focuses on the regulatory changes that are beginning to occur and the increased risks that investors face from stranding. In addition, there are inherent cost changes afoot in the fossil fuels industry that may provide independent accelerants to these risks of stranding assets.
A 2014 study by PwC asked institutional investors: “In general, how satisfied are you with the information companies provide (whether through regulatory filings or otherwise) about climate change risks? Of those investors with over $100 billion in assets under management, 64% responded they were “dissatisfied.”
Recently, the Chief Investment Officer of the giant California Pension Fund, CalSTRS, Jack Ehnes provided the following update: “CalSTRS strongly believes the issues presented in Carbon Tracker’s Unburnable Carbon 2013: Wasted capital and stranded assets report call for action. Of the top 200 global fossil fuel companies listed on the Carbon Tracker website, CalSTRS has engaged 44 U.S. companies held in our portfolio requesting disclosure. Engagement through educated dialogue will be far more productive in accomplishing our goal that these companies publicly price the risk posed by unburnable fossil fuels.”
Pensions moving away from fossils. Increasingly, the pension fund world is leading the reexamination of the fossil fuel asset class. In late 2014, Norway’s largest manager of pension funds, KLP, decided to sell off all of its investments in coal companies. KLP manages the pension funds for the majority of Norway’s public sector employees. With its total assets of nearly NOK 500 billion ($84bn/€67bn), KLP’s clout in the investment world ranks second only to the Norway’s huge sovereign wealth fund, known as the oil fund. That fund, at $890 billion in assets considered the largest sovereign wealth fund in the world, announced in June 2015 that it would sell off many of its investments related to coal, making it the biggest institution yet to join a growing international movement to abandon at least some fossil fuel stocks. Notably, the decision wasn’t just to sell coal stocks directly, but also to shift its holdings out of billions of dollars of stock in companies whose businesses rely at least 30 percent on coal. KLP’s CEO Sverre Thornes announced: “We are divesting our interests in coal companies in order to highlight the necessity of switching from fossil fuel to renewable energy.” A major Norwegian insurance company, Storebrand, dropped 10 fossil fuel companies from its portfolio in 2014 due to their involvement in coal production. Similarly, the large Swedish pension fund, AP2, in Gothenburg, Sweden, also announced that it will divest from coal and oil and gas production companies to reduce its financial risk in fossil-fuel-based energy.
The Church of England announced in May of 2015 that it would drop companies involved with coal or oil sands from its $14 billion investment fund, and the French insurer AXA said it would cut some $560 million in coal-related investments from its portfolio. Local Government Super (LGS) – one of Australia’s largest public sector pension funds with $8bn in managed assets also announced its intent to expunge coal investments from its portfolio, saying the “unarguable scientific reality” creates “very real investment risk”.
A day before 2014’s UN climate summit in New York, the Rockefeller Brothers Fund (RBF), the $850m charitable foundation created by descendants of Standard Oil founder John D. Rockefeller, announced it too was getting out of fossil fuels. RBF said that for climate protection reasons, it could no longer justify investments in that industry, particularly those in coal and in companies that extract oil from tar sands. The RBF also said that along with proceeds from the divestments it would increase investments in renewables “and other business strategies that advance energy efficiency, decrease dependence on fossil fuels and mitigate the effects of climate change.”
In July 2014, a large umbrella group of churches representing more than half a billion Christians worldwide announced that it would pull all of its investments in fossil fuels, saying it had determined the investments were no longer ethical.
Although the move to divest from fossils is still a relatively small one, Bloomberg recently issued a report discussing how difficult such a divestiture would be if all institutional investors suddenly decided they were going to divest – simply because oil and gas in particular are such a large percentage of pension fund holdings that too few investors could ever get out in time – with the result being a free-fall in stock prices, much as we have already seen in coal. Bloomberg concluded that because it is so hard for large investors to exit fossil fuels, it is unlikely that a majority of such investors will move to divest before they have lost a large portion of their current holdings to price declines driven by climate change issues and selling from more motivated investors. Bloomberg also admitted that other factors, such as the declining cost of renewable energy and efficiency technologies and the increasing costs of fossil fuels are moving energy markets today. When these factors will begin to hurt oil and gas stocks is unclear, but the coal industry shows that, although divesting is hard, it does not pay to wait.
Similarly Impax Asset Management recently issued its own report entitled: “Beyond Fossil Fuels: The Investment Case for Fossil Fuel Divestment.” According to the report: “Analysis of historical data shows that over the past seven years eliminating the fossil fuel sector from a global benchmark index would have actually had a small positive return effect. Furthermore, much of the economic effect of excluding fossil fuel stocks could have been replicated with ‘fossil free’ energy portfolios consisting of energy efficiency and renewable energy stocks, with limited additional tracking error and improved returns.”
Fossils and Wealth. The availability of coal, oil and gas has greatly fueled the rise in economic wealth over the last century. However, as the following chart indicates in terms of long-term energy pricing, the economic growth pattern we have seen since 1900 is now under severe challenge and we may be back into a much flatter pattern.
Coal: The First Domino to Fall
Since early 2013, there has been a growing call for city, state and other pension funds to divest from their fossil fuel holdings. These calls have largely resulted in divestment decisions focused on coal holdings. However, a closer look suggests that coal stock had already taken a beating, starting in 2011 and divestment may simply have been an elegant way out of an asset class that was already on the ropes.
Since 2011, a portfolio of U.S. coal stocks, including the nation’s leading companies – Peabody Energy, Alpha Natural Resources, Cloud Peak Energy and Arch Coal – has lost 61% of its value. During that same period, Peabody Energy, the world’s largest pure-play private sector coal company, lost 74% of its value. Most of the declining fortunes of the coal industry in the United States can be ascribed to the gains of the natural gas industry due to the significant increase in gas supplies from U.S. fracking activities. In the course of a single year (2008-2009) Henry Hub gas prices declined from almost $15/mmbtu to roughly $4/mmbtu and have remained in the $4-$5 range since then. This uptick in cheap gas supplies may turn out to be relatively short-lived; however, the likelihood that coal can stage an effective recovery is questionable at best.
The effect on coal was not immediate in that electric producers began to shift production from coal to gas in a process that took almost 5 years to unseat coal from its dominant position (see chart above).
Throughout the 1990’s and as recently as 2003, coal had still supplied 50% of the nation’s electricity. But, by April 2012 the transition was largely complete, with Coal’s market share dropping to a historic low of 33%. Wise investors would have unloaded their coal positions starting in 2009 and could have gotten out long before the popular divestment calls began.
More importantly, there are some patterns of coal’s decline that bear close watch with regard to other fossil fuels. For example, in the ten years from 2004 to 2014, coal industry borrowing rose from $3 billion to $20 billion. Secondly, the nation’s fleet of coal plants is aging rapidly. By 2020, more than 70% of the existing coal-fired power plants will be over 40 years old, and 36% will be more than 50 years old. Gathering the public will to build new plants under current market circumstances will be difficult. Black and Veatch has projected that coal’s market share in the United States power market will drop to 21% by 2038.
Given a move to smaller and more nimble gas turbines, which can flex much more easily in concert with renewable energy sources, it is difficult to see how coal can make a comeback in the United States, even if natural gas prices were to rise to a level that might make coal competitive as a fuel source.
Is Oil Next? – Risks Relating to Oil Dependency
In recent years, the U.S. oil dialog has shifted from a peak-oil supply side issue to a demand side question – namely, will we continue to demand oil at the prices that may be required to profitably extract it? To put this in context, in just the past 22 years, we have used half of all of the oil ever burned by humans. As we continue to pursue newer finds, the costs of discovery are rising rapidly. Popular wisdom in the U.S. is that shale oil has protected us from this future and that we are now somehow “independent” from foreign producers. The facts say otherwise: In 2013, notwithstanding tremendous growth in national shale oil production, the U.S. consumed 18.9M barrels a day of petroleum products. To meet those needs, the US imported 6.2 million barrels of oil a day (after netting exported oil products against imported crude oil).
Notably, oil and gas production by Chevron, ExxonMobil and Royal Dutch Shell has declined during the past five years even as the companies spent more than a half-trillion dollars on new projects. Chevron’s costs alone have jumped 56% since 2010. In fact recent oil price drops have caused most of these oil majors to divest from all but core assets in an attempt to stay solvent.
A recent report by the firm Douglas Westwood highlights just how much spending on oil has ballooned. Total spending since 2005 on upstream exploration and production was $4 trillion. Of that amount, $350 bn was spent on US and Canadian unconventional oil and gas and another $150 bn was spent on LNG and gas to liquids (GTL). A total of $3.5 trillion was spent just maintaining the 2005 legacy oil and gas system. Of that, about $2.5 trillion was spent on legacy crude oil production—94% of the petroleum liquids supply today. The result of all this spending is that legacy oil production has fallen by one million barrels per day. Put differently, the “peak oil” date for legacy systems is still 2005. For comparison, during the period from 1998 until 2005, an expenditure of $1.5 trillion added just over 8.6 mbpd of crude production.
According to the US EIA, based on data compiled from quarterly reports, for the year ending March 31, 2014, cash from operations for 127 major oil and natural gas companies totaled $568 billion, and major uses of cash totaled $677 billion, a difference of almost $110 billion. To fill this $110 billion hole that they’d dug in just one year, these 127 oil and gas companies increased their net debt by $106bn in the year to March, in order to cover the surging costs of machinery and exploration and at the same time sold off a net $73bn of assets. See chart below:
As the chart shows, revenues from oil and gas reached a plateau in 2011 at roughly $570 billion even as oil prices remained at $100 a barrel. But their costs continued to rise; reaching their own plateau at roughly $700 billion.
As a result, the gap between earnings and expenditure has grown from $18bn in 2010 to $110bn in 2013 even before the 2014 price declines. To deal with this issue, the oil companies appear to be both borrowing heavily and buying back their own shares, spending an average of $39bn on repurchases since 2011
With oil prices now hovering at half that level, all of these cost and borrowing increases signify even greater levels of investment risk.
Producers Need Higher Prices to Maintain Production
Most oil producers now need prices of greater than $95/barrel in order to cost effectively produce oil; without higher prices they see little return from investing in new production. As a result, companies are beginning to sell off reserves they see as not being recoverable at current prices. As oil prices drop, the need to sell off assets increases. From the beginning of 2004, the year in which conventional crude production plateaued, to the end of 2012, the price of Brent oil increased by 375 percent. That near quadrupling in price produced only a 4.31 percent increase in average annual crude production over the same period. The International Energy Agency projects that production rates of all conventional crude-oil fields will fall from 69 million barrels per day (bpd) today to just 28 million bpd in 2035. Current total global production is 91 million bpd. The key issue is the spending and borrowing needed to try to fill that gap. Capex for oilfield development and exploration has nearly trebled in real terms since 2000: from $250bn to $700bn in 2012 (see chart).
ExxonMobil, Shell and Chevron have all been spending at elevated levels to produce less oil.
Change in production and capital expenditures since 2009. Source: The companies and The Wall Street Journal
However, Oil Prices much over $100 are Difficult to Sustain
As the cost of renewables continues to drop, substitution, both in the form of using less through efficiency gains and switching to alternatives (such as electric vehicles) will increasingly occur if oil prices rose back to 2013 levels or higher. Therefore there is a double risk to oil majors – one is that carbon regulation could reduce their useable assets; but an equally large one is that necessary higher prices simply reduce what can ultimately be sold. This perspective is best covered by a recent report by the European Bank, Kepler Cheuvreux. Their report, penned by a team led by Paris-based analyst Mark Lewis, a former head of Deutsche Bank’s carbon and energy team, examined the “stranded asset risk” of carbon regulation, and came to the view that the oil industry has the most to lose, with a potential loss of $19.3 trillion in revenues in the period 2015-2035.
The coal industry stands to lose $4.9 trillion, while the gas industry could lose $4 trillion. According to Lewis, the most at-risk projects are the high-cost, high-carbon sources – particularly deepwater drilling, oil sands and shale-oil plays – which rely on high prices for oil. Perhaps more importantly, “the oil industry’s increasingly unsustainable dynamics...mean that stranded-asset risk exists even under business-as-usual conditions,” Kepler Cheuvreux writes. “High oil prices will encourage the shift away from oil toward renewables (whose costs are falling), while also incentivizing greater energy efficiency." This view aligns with that of a number of the major banks, including Citigroup’s latest assessment that the “age of renewables has begun” on the basis of costs, and Sanford Bernstein’s recent warning that the world faced a scenario of energy price deflation because of the impact of the plunging cost of solar and its likelihood of displacing of fossil fuels across the world. It is not implausible, that major low cost producers of oil could look at this situation and come to a conclusion that it might be economically rewarding to (a) reduce prices to a level that cuts off much of the new production technologies and (b) sell as much as can be sold profitably at those reduced prices before carbon legislation strands the rest.
The global fossil-fuel industry has placed its publicly facing reliance on the International Energy Agency’s New Policies scenario, seeking to justify the huge investment it is making in exploration and ever-more capital-intensive projects to both shareholders and bankers. Kepler Cheuvreux is particularly critical of ExxonMobil’s recent carbon risk report, saying it had focused almost exclusively on business-as-usual scenarios and “did not advance the debate at all.” ExxonMobil’s report says that most existing fossil-fuel production is not at risk. Instead, the risk is in the proven reserves that yet to be developed. As Citigroup and others, including HSBC and Deutsche Bank, have previously noted, these proven but as yet undeveloped assets form a significant part of many oil companies’ market and asset valuations. “This suggests, perhaps paradoxically, that there could be a real risk to the oil industry from rising oil prices under a business-as-usual scenario, as combined with continuing reductions in the costs of renewable technologies, this could drive the accelerated substitution of oil in the global energy mix over the next two decades,” the report states. “In turn, this would risk creating stranded assets over the medium to longer term both for the oil industry itself and -- owing to the central role of oil in energy pricing more generally -- for the global fossil-fuel industry as a whole. “The implications of such a scenario would be momentous, as it would mean that the oil industry potentially faces the risk of stranded assets not only under a scenario of falling oil prices brought about by the structurally lower demand entailed by a future tightening of climate policy, but also under a scenario of rising oil prices brought about by rising demand under increasingly constrained supply conditions.” “Specifically, if oil prices rise faster in the future than currently assumed by the IEA in its base-case projections, we think this could lead to an acceleration of the policy incentives for, and deployment of, renewable-energy technologies and energy-efficiency measures, and hence a faster shift away from oil in the global energy mix over the next three decades than ExxonMobil assumes."
In addition to risks on the supply side and in terms of substitution, there are also risks on the demand side. Increasingly oil companies are coming to the realization that the Tesla Model S has for the first time created an electric vehicle that people want for sheer performance and luxury, not because it consumes electricity instead of oil. Add to that mid-2015 speculation by automotive analysts that BMW may phase out internal combustion engines over as soon as the next ten years. If the entire automotive industry continued to move in this direction it would create an entirely separate “stranded asset” issue not just for the oil companies but also for the assets that existing car manufacturing plants represent, never mind the service and refueling industries.
Shale Gas and Tight Oil: Is it really a Tidal Wave of Cheap and Clean Carbon?
Shale Gas/Tight Oil – A Polaroid Analogy? In a land of shale gas, do we need Clean Energy? Some energy analysts argue that the discovery of vast resources of shale gas and shale oil have extended the life of fossil fuels indefinitely. They posit that shale gas, accessible through cost-effective methods like hydraulic fracturing, are sufficiently plentiful and cheap that most renewable energy sources will not be able to compete for decades, and that we should instead focus our national energy priorities on exploiting our newfound domestic shale gas reserves.
As attractive as that proposition sounds economically (and ignoring any climate change implications), we should not ignore the fate of Polaroid, the former instant camera company. As digital imaging began to grow in popularity, Polaroid offered a product that made film as instant as digital. The theory was that “instant film” would extend the life of film and compete effectively with digital photography. Yet, Polaroid, like Kodak, seemingly failed to see that the rise of digital imaging was actually doing much more than providing “instant pictures.” It was enabling entirely new markets—new ways of creating, managing, and interacting with photographic images (including emailing them, posting them online, creating shared albums, etc.). By failing to identify and seek the vast new opportunities unfolding due to emerging digital technology, Polaroid suffered the same ultimate fate as Kodak, and on October 12, 2001, Polaroid filed for bankruptcy. Obviously photographs and fossil fuels are far different industries, but the importance of understanding how new competing technologies affect existing business models and market assumptions is a valuable lesson to remember.
Shale: Extender of the Old Order or Long Term Opportunity? The perfection of horizontal drilling and hydraulic fracturing for shale oil and shale gas has jumpstarted U.S. oil and gas production. It has been said that we have access to as much as 2,600 trillion cubic feet (tcf) of natural gas domestically in the United States. The U.S. currently uses approximately 22 tcf per year. Quick math says that could mean another 100 years of cheap electricity and more. As stated above, these finds have already accelerated the retirement of coal power plants. They have also reduced our dependence on foreign oil and our foreign exchange imbalance. Further, these developments represent the U.S. oil and gas industry’s use of innovative technologies to take a giant leap forward at a time when it risked a significant decline in domestic production.
Shale gas potentially provides for reduced pollution compared to coal, but does still emit more pollution than clean energy sources like solar, wind, and nuclear energy. Natural gas can help us reduce our reliance on coal and imported oil and can play an important role in utility-scale renewable energy generation. Its contribution to our national economy might also serve as a catalyst to allow us to make appropriate investments in the next generation of energy technologies.
What shale gas should not do, is dissuade us that new, cleaner energy technologies represent the inevitable forward march of technology and innovation. Much like the digital camera or flat-screen televisions, these new technologies will continue to improve in quality, decrease in price, and ultimately take over, with or without subsidies. We should take care to avoid turning domestic shale gas into our version of Polaroid cameras: temporarily useful to serve some current needs well, but it won’t help us become pioneers and leaders in the as-yet-to-be-seen new energy markets of the future. As with digital imaging, clean energy technologies will enable entirely new ways of creating, managing, and interacting with energy… in ways that no one can fully imagine or know today.
Shale Gas Production Curves – What to Expect? The story of shale gas production is fairly complex. It took a while to really learn the fracking process, but as that was going on a new land rush developed to secure valuable leases to sites that appeared likely to produce the greatest volumes of gas. Early on, the land rush got ahead of itself, forcing many drillers to move forward so rapidly with drilling operations that they produced a flood of gas and tanked the market, resulting in rapidly plummeting prices. That, in turn, led to a pull-back in drilling operations and a reallocation of drilling rigs away from dry gas sites toward tight oil sites (many of which also happen to produce gas). The overproduction caused a number of companies to take significant write-downs and levels of new investment in gas dipped sharply. Since then, things appear to have stabilized somewhat and it appears that at least for 2014 and 2015 investment will reappear and shale gas production will ramp up, so long as prices remain above today’s sub-$4.00/mcf levels.
Increases in gas prices will obviously spur greater investment – a reason why U.S. gas drillers are so eager to see significant export growth in the form of LNG – with foreign prices being higher, greater exports should raise U.S. prices to a level that will enable more investment, more drilling and, at those prices, positive cash flow and profit.
But, will investment returns from shale be sufficiently attractive to continue to attract increasing levels of new investment and greater levels of production? A quick look at rig counts, production levels and gas prices begins to tell the story. As gas production grew prices fell, from a starting point that ranged between $6 and $10 per million cubic feet (mcf) to a low point of $2/mcf. Not surprisingly, as prices fell drillers moved rigs from gas drilling to oil drilling, as oil prices reflected a global trading market for oil and overproduction was easily absorbed. As the charts below show, gas rig counts began to drop precipitously in 2012 and have largely remained flat since then. Nonetheless, production levels, while slowing, have continued to grow as drillers have learned to get more gas from each rig. Equally important is that a significant amount of gas is now being produced by wells drilled primarily for oil; thereby continuing to grow gas production even as drillers move away from “dry” gas and toward “wet” gas (oil and gas liquids).
But, production lags capital investment and thus future price assumptions must be made at the time leases are negotiated and wells are drilled. Over-drilling and overproduction can quickly produce prices that make it difficult to recoup investment.
Dylan Murphy and Jo Murphy point out that in 2012, for example, annual capital investment was $42 billion but shale gas revenues were only $32 billion – a pattern that is clearly not sustainable. “There are thirty shale plays yet only six of them account for 88% of shale gas production. Two thirds of fracking gas comes from three major plays: Barnet in Texas, Haynesville in Eastern Texas and Western Louisiana and the Marcellus play of Pennsylvania and West Virginia. In addition, production appears to have peaked in both the Barnet and Haynesville plays despite the growth in the number of operating wells.
Generally, the most productive wells, “sweet spots”, are drilled first. Then drilling moves on to the less productive wells. Due to the rapid decline in a shale well’s output (which typically declines by 80-95% over the initial 36 months) there is a constant need to drill new wells – hence the capital intensity. Across America overall shale gas fields have been depleting at such a rapid pace that they require 30-50% of annual production to be replaced by new drilling. It is estimated that 7,200 wells a year are needed just to maintain current levels of production. This currently translates to about $42 billion of annual capital investment just to maintain current production (not including leasing costs or the costs of other infrastructure such as pipelines and roads, etc.) By contrast, shale gas sales in 2012 only amounted to $32 billion. No wonder the oil and gas industry are screaming for the U.S. Congress to authorize natural gas exports to countries where prices are much higher.”
Since 2010, shale debt has almost doubled while shale revenues have grown by only 5.6% (based on an analysis of 61 shale drillers). Asjylyn Loder, a reporter for Bloomberg News, argues that although significant new investment in drilling will be required to maintain supply levels, she doubts whether the cash is there. "Drillers are caught in a bind. They must keep borrowing to pay for exploration needed to offset the steep production declines typical of shale wells. At the same time, investors have been pushing companies to cut back. Spending tumbled at 26 of the 61 firms examined. For companies that can't afford to keep drilling, less oil coming out means less money coming in, accelerating the financial tailspin." Her piece concludes: "the U.S. shale patch is facing a shakeout as drillers struggle to keep pace with the relentless spending needed to get oil and gas out of the ground."
In a specific example, Ruud Weijermars, a Dutch energy consultant, in the Oil and Gas Journal; speaks about a project built by Chesapeake for the Dallas Fort Worth Airport (DFWA) in 2006. Chesapeake offered to drill 330 wells and frack the Barnett shales underneath. DFWA agreed to a signing bonus for 18,543 acres and a 25% royalty. But Chesapeake overestimated the amount of gas in the ground and underestimated the cost of extracting it. The company reportedly not only set off earthquakes with its injection wells, but had to retrofit its equipment with electric engines so as not to cause any safety hazards at the airport. In the end, Chesapeake drilled only half its projected wells at a cost of $7.21 per thousand cubic feet (Mcf) in a market that offered a price of $4.23 Mcf. The airport made money, but Chesapeake lost $316 million. "The project performance of the DFWA shale gas development project is exemplary for the lagging returns on investment from U.S. shale gas fields," concluded the Dutch analyst. "All in all, the permissive attitude of regulators and financiers and their neglect of the flagging signs of weak fundamentals are all typical for investment bubble hypes, as seen recently in the dot-com bubble and housing scandal. The shale gas bubble is likely the next one to burst."
Similar conclusions are drawn by Virendra Chauhan, an analyst at London-based Energy Aspects. In his piece, titled: The Other Tale of Shale, 2013, reports that depletion rates for shale wells, whether producing oil or gas, were so great that companies constantly borrowed more money to drill more wells. Chauhan found that interest payments on debt (for the 35 shale firms that represent 40 per cent of production) increasingly consumed a growing share of their revenue. "The very nature of shale wells, which exhibit high decline rates, results in the need to constantly allocate capital towards exploration drilling in order to maintain and grow production volumes," explained Chauhan. "As a result, the average Capex (capital expenditure) spending of the 35 companies analyzed … has amounted to a staggering $50 per barrel of oil equivalent (BOE) over the last five years, at a time when their revenue per BOE has averaged $51.5." Note that here, as is often the case in other studies, the most productive wells are being studied – implying that numbers for less productive wells are even worse.
The expectation is, that for 2015, the gas industry will be making steep capital demands for new pipelines, LNG export terminals, and nearby chemical plants. To date, the industry has been pleasantly surprised by the continuing supply of new capital from lenders and investors (contrary to historical oil & gas lending and investment practices which would have resulted in large cutbacks in times of uncertainty). The question is, if quantitative easing is pulled back and interest rates rise, or if global oil prices fall, will the availability of capital suddenly and dramatically change?
High Production Levels for Shale Gas may be Short-lived
A number of sources question just how long the “long tail” of shale production is and suggest that industry claims of flat tail curves do not yet (and may never) match up to reality. If, as seems demonstrated by the data so far, decline rates continue to be greater than assumed (particularly by lenders), then the amount of new drilling and the economies of scale resulting therefrom must truly be stellar in order for the industry to match its forward financial claims. If not, it is to be expected that lending for new drilling will become significantly more prohibitive.
Few seem to contest that shale wells have steeper initial decline curves than conventional ones. Therefore, the critical question becomes what is, in fact, the long-term decline curve for a well; and how do new wells perform vis-à-vis those already drilled? In other words, did we get to the best wells first or are we just now learning which ones are the good ones?
Shale gas and tight oil fields typically have very high initial rates of decline in their productivity. The high decline rates require continuous capital inputs. Individual well-decline rates range from 79 to 95 per cent after 36 months. Currently, US shale gas production is declining for 36 per cent of wells and “flat” for 34 per cent. However, as the curves below indicate “flat” has different meaning for different audiences; and, in the end, there is a huge difference in value between nearly flat and truly flat.
By comparison, a commonly quoted CERA global conventional gas well decline rate is: 4.5%; calculated from an analysis of 811 large to giant size fields, covering ~66% of global production. CERA notes that most production is from large fields, and that these fields tend to produce on-plateau for longer and to decline at a slower rate than smaller fields. The IEA 2008 World Oil Report (using HIS data) published a production-weighted average decline rate worldwide of 6.7% as of 2007. This is predicted to rise to 8.6% by 2030 as more and more old giant fields pass their plateau and start to decline.
To date, the industry response has been to accelerate drilling activities to compensate for depletion rates. According to Pete Stark, senior research director at IHS Inc.: “The average flow from a shale gas well drops by about 50 percent to 75 percent in the first year, and up to 78 percent for oil. The decline rate is a potential show stopper after a while, you just can’t keep up with it." The industry has so far been able to live with the decline curve problem because operators have been able to scratch out better initial production in wells. Stark continues: "If you don't have that improvement, then you get stuck after a while and have to drill more and more wells just to stay even."
The Oxford Institute for Energy Studies, suggests that “below ground” technology and innovation are improving, but it agrees that, on average, the decline curve profile and recovery factors are not changing across the drilling landscape. A recent report by Rafael Sandrea, suggests both oil and gas plays exhibit high first-year well decline rates varying from 65% to 90% and have low recovery efficiencies when averaged over the lifetime of the play (typically 7% for shale gas and 1-2% for tight oil). In the Bakken, these innovations served to substantially improve average well production levels between 2004 and 2008; however, since then, production levels per well have flattened substantially (see chart below).
According to Ivan Sandrea, an OIES research associate and senior partner of Ernst & Young London, the 15 main shale gas operators have now taken asset write-downs approaching $35 billion since the shale boom began. “While most of the companies that have made write-downs are not quitting, many players in this industry have already noted that the revolution is not as technically and financially attractive as they expected,” Sandrea also cites a recent analysis by Energy Aspects, a commodity research consultancy, showing 6 years of progressively worsening financial performance by 35 independent companies focused on shale gas and tight oil plays in the US. “This is despite showing production growth and shifting a large portion of their activity to oil since 2010, presumably to chase a higher-margin business,” he adds. Each “fracking” well drilled into shale (which costs US$3 to US$10 million, with oil wells costing on the high side) has a much shorter useful lifetime than a well drilled into a liquid petroleum or a gas deposit. The optimists are assuming well lifetimes of 40 years, as compared to experience thus far in Texas, which suggests that 8 years is more likely.
Therefore, understanding the correct estimated ultimate recovery (“EUR”) curves may be the single most determinative factor in who is right and who is wrong about the future of shale oil and gas. Historically, gas wells were described using the classical Arps formula. However, this formulation may have problems when applied to tight gas reservoirs such as shales. Arps based his equations on boundary-dominated flow, which conventional reservoirs reach in months compared with years in shales. According to John Lee, a University of Houston engineering professor and an authority on reserves, “the problem is the Arps equation has been twisted to apply to shale technology, which didn’t exist when Arps died in 1976. As a result, “billions of barrels of untapped shale oil are counted by companies relying on limited drilling history and tweaks to Arps’s formula that exaggerate future production. Things could turn out more pessimistic than people project – the long-term production of some of those oil-rich wells may be overstated.” 
As one blogger recently explained: “Specifically, the terminal decline of Arps formula approaches zero, and the cumulative production it projects approaches infinity with a b-factor larger than 1.0. That's problematic, as in the long term, shale wells should decline a terminal decline rate above zero. I discovered that as producers tend to over-estimate the EURs and over-estimate the life span of shale wells, they end up amortizing the cost way below the fair amount of amortization they should have calculated. Thus, as they under-estimate the costs, they end up over-estimating the profitability of the operations. But one thing they could not hide is that in quarter after quarter, the producers have consistently spent several times higher on capital spending, than the revenue they take in. Producers continue to borrow more and more on debts in order to continue their well drilling programs.”
Unfortunately, the information on well performance is extremely hard to obtain (most producers aren’t willing to share their data) and the general response from producers to these arguments is that the early curve fits in conventional gas production were similarly dismissed as problematic, but as knowledge improved, so did production and so will it in shale. Billions are riding on those assumptions being true.
Currently, alongside continued tinkering by companies, researchers are testing new formulas to help in the calculations. These include Stretched Exponential, a formula Lee helped develop; the Duong method by Anh Duong of ConocoPhilips; and the Simple Scaling Theory by Tad Patzek, chairman of the Department of Petroleum and Geosystems Engineering at the University of Texas. Hopefully, some or all of these will provide a greater degree of certainty and comfort over future production levels.
Arthur Berman and Lynn Pittinger comment on the notion of reserves and recoveries as follows: “Reserves and economics depend on estimated ultimate recoveries (EUR) based on hyperbolic, or increasingly flattening, decline profiles that predict decades of commercial production. With only a few years of production history in most of these plays, this model has not been shown to be correct, and may be overly optimistic….Our analysis of shale gas well decline trends indicates that the Estimated Ultimate Recovery per well is approximately one-half the values commonly presented by operators.” In brief, the gas producers have built the illusion that their unconventional and increasingly costly shale gas will last for decades.
Basing his analysis on actual well data from major shale gas regions in the US, Berman concludes that shale gas wells decline in production volumes at an exponential rate and are liable to run out far faster than what the market commonly believes. He asks: “Could this be the reason financially exposed US shale gas producers, loaded with billions of dollars in potential lease properties bought during the peak of prices, have recently been desperately trying to sell off their shale properties to naïve foreign or other investors?”
Berman wrote in 2011: “[M]ost wells are not commercial at current gas prices and require prices at least in the range of $8.00 to $9.00/mcf to break even on full-cycle prices, and $5.00 to $6.00/mcf on point-forward prices. Our price forecasts ($4.00-4.55/mcf average through 2012) are below $8.00/mcf for the next 18 months. It is, therefore, possible that some producers will be unable to maintain present drilling levels from cash-flow, joint ventures, asset sales and stock offerings.” Berman continued, “Decline rates indicate that a decrease in drilling by any of the major producers in the shale gas plays would reveal the insecurity of supply. This is especially true in the case of the Haynesville Shale play where initial rates are about three times higher than in the Barnett or Fayetteville. Already, rig rates are dropping in the Haynesville as operators shift emphasis to more liquid-prone objectives that have even lower gas rates. This might create doubt about the paradigm of cheap and abundant shale gas supply and have a cascading effect on confidence and capital availability.”
Interestingly, as is often the case with energy traders and analysts, the only obvious tradeoff they see is the one between natural gas and coal (ignoring the possible impact of wind or solar). As one commentator put it: “Is a business profitable, if it continues to borrow more debts quarter after quarter, and it continues to spend several times more on capital spending, than the revenue it takes in? This is neither profitable, nor sustainable. I can see that when the banks get suspicious and stop lending money, then the shale industry will collapse… Investors should bet their money on the rebound of the coal sector, not on the false promise of shale gas or shale oil.”
Bill Powers, an independent analyst, private investor and author of the book "Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth," puts it into more graphic terms “I think it will be similar to the housing crisis, where a handful of people saw it coming and profited from it.” There was significant evidence that housing prices were unsustainable, but most people were surprised when the housing bubble popped. People from Alan Greenspan to Ben Bernanke and others had a lot of information about the economy and how unsustainable house prices were, but did not want to talk about it publicly. There's a saying that "the impossible can become the inevitable in the blink of an eye." Interestingly, Powers, as an oil and gas investor, and very much like Anthony above, sees the risk specifically only as to shale gas and thus concludes that the “gas bubble” bursting represents an investment opportunity for the fossil fuels that will then be substituted for gas, ignoring totally the substitution possibilities toward renewables.
A very recent piece by Ambrose Evans-Pritchard, in Britain’s The Telegraph, echoes these same sentiments, but does see the role of new clean technologies: “The epicentre of irrational behaviour across global markets has moved to the fossil fuel complex of oil, gas and coal. This is where investors have been throwing the most good money after bad. They are likely to be left holding a clutch of worthless projects as renewable technology sweeps in below radar, and the Washington-Beijing axis embraces a greener agenda. Data from Bank of America show that oil and gas investment in the US has soared to $200bn a year. It has reached 20pc of total US private fixed investment, the same share as home building. This has never happened before in US history, even during the Second World War when oil production was a strategic imperative.”
Another blogger, Zoltan Ban, writes: “It is estimated that there is a 2-3 trillion barrel shale oil resource base. Of that immense resource base, it is estimated by the USGS that about 1-2% will be recoverable given current technology and recent price levels. Many people jumped [to the conclusion] that technological innovation just unlocked that 1-2%, so given the fast paced change in technology we are witnessing currently, much more will be ultimately recovered, perhaps as much as 10-20%, or somewhere around 500 billion barrels. My response to that is that anything is possible, but at the moment we have to take a step back and recognize that it was not technological innovation that made these resources available, but a fivefold leap in average yearly oil prices that happened in the last decade. The fracking technology and even horizontal drilling have been around for a long time now, so no new major innovation was involved. … So, in the absence of some innovation at current price levels, the 25-50 billion barrel addition to US recoverable resources is all that the US will get out of this resource. It is a huge resource for sure, but put into global perspective, it is only one to two years’ worth of consumption.”
Yet another piece, by Deborah Lawrence, originally published in Energy Policy Forum; also looks at the difference in claimed EURs. “Chesapeake Energy (CHK) claims average EUR’s for the Marcellus at 4.2 Bcf. Range Resources (RRC) has claimed average EUR’s as high as 5.7 Bcf in investor presentations. According to the USGS, however, the average EUR for the Marcellus turns out to be about 1.1 Bcf. This is obviously problematic on many levels, not least of which is the fact that these companies can borrow money based on EUR expectations and claims. If they have overstated EUR’s, then monies may have been borrowed on assets that either simply don’t exist or are not commercially viable. “Based on production data filed with the Texas Railroad Commission, about 94% of all wells in the Barnett are underperforming their type curves. This is not surprising in that every major operator in the Barnett has bailed on its properties. They have jv’ed or sold outright to get the proverbial albatross off their financial necks. I don’t care how much PR spin you put on it, if these properties were monetizing at the giddy levels originally claimed by operators, they would not be selling. To put into perspective how ridiculous Chesapeake’s claims of 2.6 Bcf is, consider the following: of the company’s 742 operated wells completed on the Fayetteville, only 66 have produced more than one Bcf and none have produced more than 1.7 Bcf. Chesapeake’s average Fayetteville well has produced only 541 Mcf.” The USGS confirms these numbers again with the average EUR for Fayetteville wells coming in at 1.1 Bcf, significantly lower than 2.4-2.6.”
She continues: “But shale gas has turned out to be a major profit center for the investment banks and so it is in their interest to promote the hype every bit as much as their oil and gas clients. I often refer to this phenomenon as “financial co-dependency.” Lawrence further notes that shale accounted for 46% of all energy M&A in Q3 2011.
Lawrence also refers to a recent paper issued by the Society of Petroleum Engineers (SPE) on the Eagle Ford shale: “We are once again confronted with the specter of overestimation of reserves. As SPE notes: “…nearly all the quoted figures [for EUR], which range up to 850,000 BOE (barrels of oil equivalent) or 8.5 billion cubic feet, are from companies active in the trend.” They also note that very little of company data backing such claims is made available. Like disclosure of fracking chemicals, it appears conveniently proprietary. Further, the SPE report examines production data up through early 2012 so their numbers are timely. SPE’s conclusion? “…the mean EUR per well [for the Eagle Ford] is 206,800 BOE and the median is 160,500 BOE.” That is four times less than operator claims of 850,000 BOE – a very significant difference.
“The per well EUR has not shown any general increase since mid-2010 in spite of heady comments by industry such as “we are very early in the game and recovery factors are being improved by leaps and bounds”, a comment made in late summer 2012, a full two years after the historical production data had “not shown any general increase since mid-2010″. Frac size and perforated length turn out to have only a rough correlation to EUR rather than the certainty promised by industry. And SPE states that any reference to BOE should include better explanations than operators are currently providing.”
Yet another article in Energy Policy Forum, states: “The USGS examined well data for every shale play in the US and extrapolated EUR’s, or reserve estimates, based on actual production. Reserve estimates were slashed significantly from operator’s prior overly optimistic assumptions and claims. In fact, operators have overestimated reserves by a minimum of 100% to as much as 400-500% on shale gas and tight oil. These figures are now being corroborated by other independent geologists as well. Add to this mix extremely steep decline curves for both shale gas and tight oil. A paper presented to the Society of Petroleum Engineers, which researched well data in the Eagle Ford shale of South Texas, found that first year decline rates were about 80-93%! Shale gas overall yearly field declines are in excess of 40%. The Haynesville is in excess of 50%. In other words, wells are playing out much quicker than expected. And this segues nicely into the heart of the matter. If operators thought that shale assets would be long-lived and highly productive they would build pipeline infrastructure to ensure equally long-lived profits. But that is not the case. They have chosen instead to ship by rail for three times the cost of a pipeline. It is more likely that industry recognizes the short lives of shale wells and are not prepared to invest the capital needed to build the infrastructure.”
The Race Between Reserves and Reduced extraction Costs
Ongoing experience and technology improvements are having the effect of reducing the cost of tight oil and shale gas recovery, provided the quality of new wells is the same as those previously drilled. This appears particularly true with respect to tight oil wells, as they are receiving the greatest amount of drilling and R&D activity today. What is less clear is exactly where we are in the technology learning curve and whether such costs will continue to come down or whether we are approaching efficiency asymptotes.
Clearly, when prices are high enough to attract lots of activity, the level of that activity then tends to drive the innovation and economies of scale that further reduce drilling costs. The converse is equally true – lower prices dissuade activity, innovation and scale.
Many of the technological advances involve getting more from a good well site, including increasing the length of horizontals out to two miles or more, drilling additional horizontals at new depth layers, and using a single rig to continue to drill more and more wells on a site. EOG claims to have cut its well drilling time by one third over the last couple of years. But cost improvements in 2013 and 2014 have also been fueled by an overcapacity in the oil services industry, an industry (companies such as Schlumberger, Halliburton and Baker Hughes) that itself expanded greatly in anticipation of headlong growth. “Those were the gold rush years,” says Keith Cochrane, chief executive of Weir. Then in early 2012, it became very clear we had started to see a dramatic shift . . . We had a much more challenging environment for the supply chain, as the industry sought to adjust.”
The growing realization, according to Tad Patzek, chairman of the Department of Petroleum and Geosystems Engineering at the University of Texas at Austin is that “we are beginning to live in a different world where getting more oil takes more energy, more effort and will be more expensive.”
Even with crude prices above $100 a barrel, U.S. independent producers will spend $1.50 drilling this year for every dollar they get back from selling oil and gas and will carry debt that is twice as much as annual earnings, said Ryan Oatman, an energy analyst with SunTrust Robinson Humphrey Inc., an investment bank in Houston. Consider Sanchez Energy Corp. The Houston-based company plans to spend as much as $600 million this year, almost double its estimated 2013 revenue in the Eagle Ford Shale. Its Santé North 1H oil well pumped five times more water than crude, Sanchez Energy said in a Feb. 17 regulatory filing. Shares sank 7 percent. It will take 2,500 new wells a year just to sustain output of 1 million barrels a day in North Dakota’s Bakken shale, according to the Paris-based International Energy Agency. 
The trend of faster well drilling can be seen in newly released data from the Eagle Ford Shale. The number of rigs drilling wells declined by 5% in September from a year earlier. But each remaining rig was drilling more, and the oil and gas output from these wells was 28% higher than wells drilled by a single rig the previous year. Overall, oil and gas production in the Eagle Ford was up 57%, according to EIA data.
Ultimately, the life cycle production cost of shale gas requires one to calculate a number of different costs: (i) the ultimate gas recovery from a well (EUR); (ii) the sunk costs drilling a well; (iii) the land costs; (iv) the cost of pipelines, process facilities and transport to market; (v) taxes and royalties; (vi) interest paid and interest rates; and (vii) corporate overhead. There can be enormous variations in some of these variables from State to State, e.g. tax regime, and even bigger variance between N America and Europe. In the various estimates given below it is not clear in some cases if full life cycle or point-forward economics are used. According to Ken Medlock, Senior Director of Rice University’s Baker Institute Center for Energy Studies: “Some wells are profitable at $2.65 per thousand cubic feet, others need $8.10…the median is $4.85,” Ruud Weijermars came up with the numbers shown in the two charts below (which seem to indicate minimum costs in the range $4 to $6 / mcf):
Overall, efficiencies have increased on the productivity, but not necessarily the profitability side of the equation. Similarly, there is little doubt that if capital expenditures continue to increase, so will production levels. But capital expenditures must ultimately be recouped. It appears that prevailing oil prices near $100/barrel are sufficient to keep capital expenditures coming in on the tight oil side of the equation. It also appears, however, that gas prices of $4 per mcf are too low to attract similar increases in new capital expenditures for many shale gas regions. Fortunately, many of the oil plays are now also producing gas and thus may benefit from the greater capital availability in basins that support both.
One of the biggest arguments around shale gas and tight oil involves the “Red Queen” question – whether drilling must run faster and faster just to keep up. One side of the argument is that it will require an ever-increasing level of drilling activity to keep production levels up. The other side of the argument is probably best represented by the EIA’s Drilling Productivity Reports (issued monthly). Originally, the easiest way to track activity was simply to look at rig counts; however, recently it is clear that even as rig counts have declined, additional drilling at existing wells continues to spur production such that production levels have continued to grow even as rig counts dropped. That doesn’t nullify the Red queen issue, but the costs of running faster today may be lower than they were a few years ago.
The chart below, by focusing on well rather than rig counts, shows that, at least in the Bakken, maintaining growth seems to require ever increasing well counts over the last few years:
The Energy Information Administration, the statistical arm of the U.S. Department of Energy, released its first "Drilling Productivity Report" in October 2013. The EIA's report measured rig efficiencies, production and declines in six petroleum basins in the U.S. Of the six, only the Permian Basin in West Texas didn't show improvements in efficiency (but again note the focus on rigs at a time where it is clear that more and more drilling is being done from each rig so that year-over-year comparisons are not apples-to-apples).
For the six regions tracked in the report, the Bakken and Eagle Ford regions accounted for roughly 75% of monthly oil production increases. In 2013, oil production from these two regions rose by 700,000 barrels per day. The Marcellus region showed a 75% increase in gas production over the prior year. Four out of the six regions saw increases in production growth. Although total active rig count numbers have continued to rise, the EIA believes that the current growth curves in oil and gas production are mainly due to drilling efficiencies and new well productivity.
In a recent presentation, EIA Administrator Adam Sieminski said: “Higher drilling efficiency and new well productivity are really the main drivers of what’s happening, not the rig count itself, when you think about production growth. The six plays that we are looking at…do have steep legacy production declines, but nevertheless the growth that’s taking place across the board in those six plays is beating productivity declines by almost 70 percent for oil and almost three-quarters for natural gas.”
He continues: “One of the things that has clearly been learned over the course of the past few years and is shown in this drilling productivity report is the importance of technology and the importance of price in helping to drive that technology is absolutely critical to understanding this. … In the near term there is more room for growth in both oil and natural gas production in the United States, and probably a lot more.” The charts below illustrate further his comments:
One thing that is never quite clear about these production numbers is just which wells/rigs are being measured. It is obviously in the industry’s best interests to have production numbers come from its largest and best producing wells. Therefore any study that represents just 45 or 60 wells or just 6 basins is likely speaking to a data set that excludes the least productive wells and basins. J. David Hughes, a geoscientist with four decades of experience analyzing Canada’s energy resources, including 32 years with the Geological Survey of Canada produced a 2013 publication, Drill Baby Drill: Can unconventional fuels user in a new era of energy abundance? It contained a number of charts quite relevant to this discussion; starting with on production figures for shale wells in different U.S. regions:
The production rate of 30 US shale gas plays, May 2012. The vast majority of production is concentrated in just a few plays. There is further variation in productivity within the best plays. High decline rates mean ever-increasing capital inputs for drilling and infrastructure to maintain production.
The production of 21 US tight oil plays, May 2012. The vast majority of production is concentrated in two plays. As with shale gas plays, high decline rates of shale oil wells mean ever-increasing capital inputs for drilling and infrastructure to maintain production.
As both charts show, the disparity between great/good and average is enormous. In reality, these figures suggest that sizeable chunks of both the shale gas and tight oil industry are on the ragged edge and cannot survive long in times of turbulent prices.
This provides one more reason why Sieminski’s comment on the importance of price as a driver should not be underestimated. Certainly, when taking prevailing prices into account, the results for cash flows have not been attractive.
Cash flow levels per share of U.S. oil and gas independents has been trending in a negative direction for more than a decade and shale production seems not to have impacted that in a positive way (see chart). Similarly, Overall free cash flows for both independent gas and oil operators have not trended in an attractive direction (chart below).
In looking at these cash flow numbers, the Oxford report concludes: “In the near and medium term, it is increasingly evident that the new U.S. shale gas and tight oil industry is likely to remain challenged, which is partially why the write-offs have been made.”
U.S. Gas Production is Likely to Continue to Grow; the Question is for How Long?
Further increases in gas production are quite plausible; but just how much of an increase we will see seems to hinge greatly on what price will be paid for production. The higher the price, the greater is the likelihood of more production. At the moment, it seems that the easiest way to achieve both higher and more stable pricing is to make the markets for gas larger. Rapidly building a viable U.S. gas export market would accomplish that (although it would also have the effect of raising gas prices for U.S. consumers). The much tougher question is the longevity of these increases and whether we are talking about 10-year, 30-year or 100-year supplies. Clearly a relatively small number of basins are producing the lion’s share of both oil and gas output. Just how long they will continue to do so harkens back to the earlier discussions of decline rates and long-term production. Perhaps the most one can really say today is that it is “possible” that such production levels can be maintained for decades.
The Potential Gas Committee (PGC), the standard for US gas resource assessments, uses three categories of technically recoverable gas resources: probable, possible and speculative. Adding together PGC’s latest total of all of three categories get you to 2,170 trillion cubic feet (Tcf) of gas. If you then divide that total by the 2010 annual consumption of 24 Tcf, you get to roughly 90 years of gas that might be available to us. Unfortunately, saying we have 100 years of gas available to us is not quite the same as saying, “if we include the possible and speculative resources, along with the probable ones, we might get to 100 years of supply.” In addition, all three numbers include gas accumulations too small to be produced at any price, inaccessible to drilling, or too deep to recover economically. In fact, the majority of the 2,170 Tcf may fall into these categories, making that 100-year number far smaller again.
Arthur Berman, in another analysis, points out that if we use more conservative and realistic assumptions such as the PGC does in its detailed assessment; we should instead be focusing on the Committee’s probable mean resources value of 550 (Tcf) of gas. The problem is, that if one also conservatively estimates, based on experience, that about half of this resource actually becomes a reserve (225 Tcf), then the US only has approximately 11.5 years of potential future gas supply at present consumption rates.
If we include proved reserves of 273 Tcf, 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.
In 2012 the 50 largest shale gas producers recorded $26 billion in asset impairment charges. That basically means that natural gas reserves that were worth $26 billion the previous year became worthless because it cost too much to drill them. This led to a 58% decline in after-tax profits in 2012 over 2011.
There are also widely differing estimates within the US Government over shale gas recoverable resources. The US Energy Information Administration (EIA) uses a calculation for shale gas average recovery efficiency of 13% versus other conservative estimates of about half that or 7% in contrast to recovery efficiencies of 75-80% for conventional gas fields. The generously high recovery efficiency values used for EIA calculations allow the EIA to project an estimate of 482 tcf of recoverable gas for the US. In August 2011, the Interior Department’s US Geological Survey (USGS) released a far more sober estimate for the large shale plays in Pennsylvania and New York called Marcellus Shale. The USGS estimated there are about 84 trillion cubic feet of technically recoverable natural gas under the Marcellus Shale. Previous estimates from the EIA put the figures at 410 trillion cubic feet – being wrong by a factor of five can obviously have tremendous ramifications. The obvious question is who is right and who is wrong?
Dimming Prospects for the U.S. become a Major Gas Exporter
So long as foreign gas prices remain high, there is a potential to grow U.S. LNG exports, because those higher prices will spur increased production. European price levels at or above $10/mcf and Japan prices at or above $15/mcf should continue to spur LNG export activities. As the chart below indicates, the last two years have given LNG facility owners reason for optimism.
However, in just the last several months, the price of LNG on the Asian spot market has begun to fall and has recently been trading at its lowest levels since March 2011. Price is a critical determinant and higher offshore prices a key attraction for U.S. gas producers. If, as expected, U.S. gas prices stay in the $3-$5 per mcf range, industry data show that US LNG exporters would need a European price of $9/mmBtu to sell there at profit, and $10.65/ mmBtu for Asia (Note: for these purposes 1 mcf = 1mmBtu is close enough).  As Royal Dutch Shell's director of projects and technology, Matthias Bichsel, said in June: "Gas projects are extremely price-sensitive because the margins are so thin and only a small fraction of them (large LNG export projects) will get built. The Asian and European price drops also mean their premium over US gas prices has fallen sharply, and if the trend lasts, could spell difficulty for some US LNG export projects in selling their gas to the world profitably.
In July of this year, British prices had come down as low as $6.25/mmBtu; thereby putting Europe out of the money for US LNG supplies. At the same time, Asian prices were down to $11/mmBtu, also threatening to make Asia look uncompetitive. "We're reviewing our previous cost and return projections and will also have to reduce production costs in order to compete in a lower priced gas environment," one source with a planned US LNG export project said.
Art Berman: "It amazes me that the geniuses behind gas export assume that the business conditions that resulted in a price benefit overseas will remain static until they finish building export facilities." In this case Berman appears downright conservative next to another commentator – William Engdahl: “There’s only one thing wrong with all the predictions of a revitalized United States energy superpower flooding the world with its shale oil and shale gas. It’s based on a bubble, on hype from the usual Wall Street spin doctors. In reality it is becoming increasingly clear that the shale revolution is a short-term flash in the energy pan, a new Ponzi fraud, carefully built with the aid of the same Wall Street banks and their “market analyst” friends, many of whom brought us the 2000 “dot.com” bubble and, more spectacularly, the 2002-2007 US real estate securitization bubble. A more careful look at the actual performance of the shale revolution and its true costs is instructive.” 
Shale is not that Likely to Become a Global Phenomenon
Recent events suggest more caution than optimism about the global spread of fracking. In general, other countries are generally taking a somewhat more cautious approach to rushing into shale development. In Europe, only the current U.K. administration has taken a strong governmental stand that is bullish toward shale development. On the other hand, China appears to be taking an active interest; though actual results will be harder to follow.
We sometimes forget how the shale boom came into existence. A significant enabler was passage of Congressional legislation in 2005 that exempted the oil industry’s hydraulic fracking, from any regulatory supervision by the US Environmental Protection Agency (EPA) under the Safe Drinking Water Act. As a result, the oil and gas industry is the only industry in America that is allowed by EPA to inject known hazardous materials – unchecked – directly into or adjacent to underground drinking water supplies. This 2005 law is often referred to as the “Halliburton Loophole” because it was introduced by lobbying pressure from the company that produces the lion’s share of chemical hydraulic fracking fluids – Dick Cheney’s old company, Halliburton. As Vice President under George W. Bush in early 2001, Cheney obtained responsibility for a major Energy Task Force to make a comprehensive national energy strategy. It is unclear whether other countries will be anywhere near as friendly from a regulatory perspective.
The Oxford Institute for Energy Studies recently said: “Annual capex associated with shale and tight oil plays has increased exponentially, from around $5billion (b) in 2006 to more than $80b in 20133. Further, more than $200b of mergers & acquisitions (M&A) deals" and joint ventures (JVs) have been completed as part of industry positioning (i.e., millions of acres with potential resources have been traded). Some call this supply surge epic - a once in a lifetime opportunity that is still unfolding. However, outside the US, there has been little visible supply response except in Canada (mainly gas) and to some extent in Argentina (mainly oil), while China has embarked on an aggressive shale development effort, so far with mixed results. Time and politics will tell if these plays and production techniques can be replicated elsewhere. The speed at which capital and innovation have moved in the US has not yet been replicated in any other country that may be rich in similar resources.” The Oxford Report further notes that “about 80 per cent of global hydraulic fracturing horsepower is in the U.S., and this constitutes one of the key limitations to developing the business beyond North America. Additionally, local conditions outside the U.S. and Canada are drastically different, regardless of how many similarities one tries to find.” 
Decision making about fracking in other parts of the world must take into account very different political agendas than those in the U.S. In Europe, the relationship with Russia plays a key role. “European Union politics have already had significant impact on regulatory schemes for shale development in Europe, a trend that could potentially model the decisions of other shale-rich states looking to develop necessary infrastructure in the coming years. Concern over the environmental impact of shale development has led to political backlash from some states within the European Union, with France going as far as completely suspending or banning the hydraulic fracturing techniques used to remove oil and gas from shale.” “Political concerns noted by one European nation certainly influence the way that other states in the region view potential domestic energy expansion insofar as it makes states think more substantially about the political ramifications of behavior not in line with perceived European norms.”
END OF PART I
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