Fossils on the Beach (Part II)
Continued from part I, previously posted
Differing prospects for Rising U.S. Oil Production
The world energy organization (IEA) is actually taking a fairly conservative view with respect to just how much U.S. tight oil production will be able to fill declines elsewhere around the world oil markets (a view that the U.S. EIA seems to largely support). Yet, history would suggest that both are bullish in their assessment with the EIA even more so than the IEA (based upon historic downward revisions). Note also that EIA includes not only conventional and tight oil, but also natural gas plant liquids and ‘other” products in its forecasts.
It takes just 35 rigs operating in conventional fields in Kuwait to produce 2 million barrels a day of oil, while in Texas, tight oil production from the Eagle Ford formation is necessitating 800 rigs to produce the same amount. Our gradual shift to increasingly challenging sources of oil is also why domestic oil extraction returned more than 100 kilojoules of energy per kilojoule invested in the 1930s, but only returns between 11 and 18 kilojoules today. In addition, deep water and tight oil (such as the oil that comes from the Bakken and Eagle Ford) have so far seen very high depletion rates. Deep water wells typically deplete about 10-20 percent a year, whereas early indications are that tight oil depletes at about 40 percent annually the first few years.
In one area the U.S. EIA and the International IEA do seem to agree – namely that the light tight oil renaissance will result in oil production in the United States peaking in 2020 and reaching a plateau thereafter. In their view, this will thereafter require the world to once again rely heavily on OPEC oil. The IEA reiterated this position in its most recent oil market report, declaring a U.S. “production plateau may be in sight, including a rising percentage of supplies that require a higher breakeven price.” Plateauing production in North Dakota and Texas would have enormous ramifications for oil markets globally, which are “tighter today than they were at the onset of the U.S. shale and tight oil boom,” the IEA says.
U.S. oil production has risen to its highest levels in over 20 years, but that achievement may be short-lived. The IEA predicts that tight oil production in non-OPEC countries “starts to run out of steam in the 2020s.” After U.S. shale oil begins to fizzle out, the world “becomes steadily more reliant on investment in the Middle East” to meet demand growth. But the problem is that the Middle East may not be up to the task. The IEA projects that the Middle East will need to lift its production from around 28 million barrels per day (bpd) currently to 34 million bpd by 2035. This will require billions of dollars in new investment.
In its most recent report, the International Energy Agency documents a world of diminishing returns for energy investments. In particular, Big Oil is spending more but getting less in return. Interestingly, the IEA doesn’t seem to see oil or gas production from fracked shale formations as saving the day or even delivering profitable returns. Instead, it predicted that: "Meeting long-term oil demand growth depends increasingly on the Middle East, once the current rise in non-OPEC supply starts to run out of steam in the 2020s." A similar sentiment was expressed by David Hughes, a fellow of the Post Carbon Institute: "Although the shale revolution has temporarily increased North American oil and gas production, its longer term sustainability is highly questionable." Hughes continued: The hype about "Saudi America" and U.S. "energy independence" is unlikely to be realized and North Americans would be well-advised to plan their energy future in the absence of a fossil fuel bonanza from shale.
Note the inclusion of natural gas liquids in the chart above. These have a much lower energy density than crude oil and have a heating content of around 60-70% that of crude oil. Refineries are limited as to how much NGL’s they can blend into their feedstock when producing transportation fuels, which along with the lower energy content, explains why NGL’s sell at a significant discount to crude oil prices.
Unfortunately, the EIA’s track record in predicting oil supplies has not been a positive one. Basically every EIA prediction since 2000 has since been revised downward (see chart).
2015 Was Supposed to be the Year that Upstream Cash-Flow Losses Came to an End for Tight Oil and some Shale Gas – with Lower Oil Prices those Losses are likely to Continue
The severe 2014 winter in the northeastern U.S. led gas prices to once again approach $6/mcf. As a result, gas producers were able to recover enough costs to approach profitability. Therefore, the degree to which the upstream sector can become cash-flow positive (and whether it will have access to capital to acquire more leases) depends heavily on whether prices can reliably stay north of $4-$5/mcf over the next several years. At some point in time companies had to acquire the oil and gas rights they needed and in some cases begin drilling prematurely to hold onto such rights. The real question is to what extent that was still true in 2013 and, if so, when does the industry actually turn cash flow positive? To the extent those early expenditures are justifiable in the long run it begs the question why a number of players are continuing to take major write-downs?
Those U.S. players who have already taken major write-downs against their reserves include:
WPX Energy, an operator in the Marcellus shale gas play, and Pioneer Natural Resources, an operator in the Barnett shale gas play, each have announced balance sheet “impairments” of more than $1 billion due to low gas prices. Chesapeake Energy, Encana, Apache, Anadarko Petroleum, BP, and BHP Billiton have disclosed similar substantial reserves reductions.
Occidental Petroleum, which has made the most significant attempts to frack California’s Monterey Shale, announced that it will spin off that unit to focus on its core business. More recently, in May 2014 the U.S. Energy Information Administration reduced by 96% the estimated amount of recoverable oil buried in the Monterey Shale, saying that just 600 million barrels of oil can be extracted with existing technology, far below the 13.7 billion barrels once thought recoverable.
EOG Resources, one of the top tight oil operators in the United States, recently said that it no longer expects U.S. production to rise by 1 million barrels per day (mb/d) each year.
Aggregate write-downs by major shale players have now exceeded $35 billion (based on public announcements by Chesapeake, BHP, Encanda, Quicksilver, BP, devon, Total, Shell, Eni, Ultra, SWN, Oxy, Newfield, Anadarko and PXP).
The shale boom is now in its ninth year and Wall Street is beginning to rein in spending in the oil patch. “The era when energy executives cared more about rapid growth than cash flow is over, says Arun Jayaram, a Credit Suisse energy analyst.” The 20 largest U.S. exploration companies—those that drilled wells, but didn't operate refineries—outspent their cash flow by a combined 29.9 billion in 2012 and by $11.5 billion in 2013, according to an analysis of CapitalIQ financial data. Only a handful exploration companies, mostly those with international operations, already are running in the black, including Anadarko Petroleum Corp.; ConocoPhillips and EOG Resources Inc. Certainly one factor in the last twelve months is that a cold winter in the U.S. helped push up gas prices, helping producers generate more cash after several years of overproduction depressed prices. “Perhaps most important, investors and activist shareholders are putting pressure on executives to be more conservative about spending. In part that is because successful shale companies have matured from microcapitalization companies, those with teeny market values that are expected to be risky but hold the prospect of stunning growth, to midcap stocks, which investors expect to have more reliable value."
What should We Expect for U.S. natural gas and oil Prices in 2015 and Beyond?
According to the Oxford Report, “conventional wisdom is that on average, most shale gas wells are out of the money while tight oil wells are in the money.” As the first chart below indicates, the basin economics for various U.S. single well plays in tight oil appear viable at $90/barrel oil prices. According to Howard Newman (Pinebrook Road Partners), most shale oil fields in the U.S. can still generate a return at $80 a barrel and Morgan Stanley analysts have said that the average marginal cost of production from the big unconventional plays is about $64 per barrel (excluding land acquisition costs). At anything below those prices, producers would likely cut capital investment in marginal plays to preserve balance sheet strength.
On the other hand, the basin economics for U.S. single well plays in shale gas, using current Henry Hub pricing, look much less economically attractive.
A recent report from The Carbon tracker Initiative shows that Canadian tar sands oil extraction is similarly price constrained. According to the report, investors in Canadian oil sands risk losing $271 billion of funding spent on projects over the next decade that need high oil prices of more than $95 a barrel to be profitable.
Many of the drilling rigs that were recently producing shale gas have now been reallocated to the production of shale oil (which benefits from a global oil price rather than a low U.S. natural gas price). Unfortunately, a limited focus on U.S. tight oil production ignores what is happening elsewhere in world oil production. Simply put, without U.S. gains, the rest of the world seems to have been at peak oil since about 2005.
As the foregoing chart indicates, since 2004 the total supply of global crude oil and condensates (excluding natural gas plant liquids and biofuels) has remained within a fairly tight 5% band. Note that in 2004 the average spot price for Brent crude oil was $38.35/bbl; by 2012 it had risen by a factor of 2.9X to $111.63. Normally such prices increases would have been expected to produce large increases in production (normal supply/demand curves). The fact that it has not happened suggests that global oil prices are constrained by more than market forces. Until well into the 1970’s new discoveries outpaced consumption; since 1980 however, that trend has reversed and shale has not changed the global picture.
The chart below provides one explanation – namely the huge increase in upstream capital costs associated with oil exploration. As the chart shows, global expenditures on oil projects jumped by 100% from $300 billion per year in 2005 to $600 billion by 2012. Despite a 100% increase in capital spending by the petroleum industry, petroleum supplies remained essentially flat.
More recent work by the Carbon Tracker group, released in July 2014, reveals, “There is an estimated $1.1trillion of capex earmarked for high cost oil projects needing a market price of over $95 out to 2025. This is largely made up of Deepwater, Arctic, Oil sands and other unconventionals. This should be the starting point for investors seeking to reduce their exposure to the high end of the cost curve.”
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 1 mbpd. Put differently, the “peak oil” date for legacy systems is still 2005. For comparison, during the period from 1998 until 2005, spending of $1.5 trillion added just over 8.6 mbpd of crude production.
All of this would imply that global oil production costs and global oil demand are likely to keep global oil prices at and above $100/barrel during our lifetimes. In fact a recent global oil report from the IMF concludes: “our prediction of small further increases in world oil production comes at the expense of a near doubling, permanently, of real oil prices over the coming decade. This is uncharted territory for the world economy, which has never experienced such prices for more than a few months.” Yet, the recent moves by Saudi Aramco and OPEC have sent prices spiraling down to $70/barrel, a level that makes much of current production untenable in the long run. Will these cost reductions have the same effect on oil company stock prices as similar declines in coal prices led to heavy declined in coal company stock prices?
The following chart highlights the current global oil production cost curve.
Focusing on just U.S. production numbers, shows that the breakeven levels vary hugely across producers.
Goldman Sachs’ research reaches very much the same conclusion, if not implying an even higher midpoint price of $100 or more. Clearly, if unprofitable production is halted, demand will soon outstrip supply leaving the world in uncertain territory with respect to what comes next.
The majority of the recent years’ increase in U.S. oil production comes from just the Bakken and the Eagle Ford. Nationally, the top 50 operators invested $186 billion in production costs in 2012 (a 20% increase over 2011), according to Ernst & Young. Yet, notwithstanding all of the efficiency and cost improvements Morse claims, total U.S. oil and gas production was up “just” 13% on the year.
Bernstein’s Bob Brackett described the challenge recently: “The average shale well produces about 600 barrels (of oil and gas equivalents) per day during its first year. The decline rate on those wells is about 40%. The average shale well costs about $7 million to drill. So the cost to add 1,000 barrels per day is about $11.7 million. Thus, if you have a shale field producing 100,000 bpd and declining 40% a year, you’ll need to invest about $500 million a year just to keep that production level. Across North America then, about two-thirds of all the dollars invested (well over $120 billion a year) goes just to keep production levels flat.”
The overall good news is that domestic production provides significant protection against oil price shocks that could otherwise arise from Mideast political instabilities. The bad news is that those same U.S. production increases are coming about because of high global oil prices and significant downward moves would stall capital inflows and thereafter stall production levels. The fact is that conventional oil extraction did, in fact, peak in the early 2000’s. As a result, the benefits of fracking are working hard to fill the growing gap, rather than creating a new world surplus that would lead to lower prices.
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. From the beginning of 2004, the year in which conventional crude production plateaued, to the end of 2012, the price of Brent oil (the global benchmark) 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.
Specifically, John Watson, the CEO of Chevron noted earlier this year, that “All of us are facing new realities and pressures. Labor and capital costs have doubled over the last decade. To pay for the rising price of extracting fossil fuels, the industry needs triple-digit oil prices. The $100 barrel is the new $20," he said—a sobering statement since global oil prices haven't been in the $20 range since 2002.
Kiplinger, the Washington, D.C.-based publisher of business forecasts, predicts that the U.S. price for crude oil (West Texas Intermediate) will stabilize at $85 to $90 a barrel, slightly lower than the $95 a barrel that EIA predicts for crude in 2014. Kiplinger attributed the lower prices to an anticipated cooling of tensions in the Middle East (coming prior to recent activities in Israel) and the ongoing rise in U.S. domestic oil production. Perhaps more interesting is the viewpoint by Kiplinger associate editor Jim Patterson, who authored the analysis, that the gasoline price decline is part of a long-term trend driven by, among other things, more fuel-efficient cars, to lifestyle changes and economic and societal evolution.
A Broad Range of Concerns Has Been Raised Regarding the Safety of Fracking.
The oil and gas industry takes the view that all of the risks inherent in shale drilling can be mitigated, and they are in fact being addressed in the industry’s evolving set of best practices. If their claims were true, then the price balances achieved over the last several years in both oil and gas may in fact be long lived and support healthy growth in the U.S. economy. On the other hand, it appears greatly premature to say that the shale industry has developed, never mind implemented “best practices.” Early indications are that such a set of best practices can be and perhaps are being developed and that such best practices can, in fact, mitigate a fairly long list of concerns. The much bigger question is “what will the implantation of those best practices add to the cost of a mcf of gas or a barrel of oil?”
An increasing number of reports are focusing on potential environmental risks to fracking. These include, but are not limited to methane leaks, water usage and contamination and earthquakes. The indication is that many, but perhaps not all of these issues are addressable through better procedures and regulation.
Methane leakage and other air pollutants. The Energy Department, along with the Environmental Protection Agency and the Interior and Agriculture departments, is working on an expanded study of methane emissions and other problems associated with natural gas production. "We will expand the study from the narrow focus of emissions at the well to end-to-end emissions, including the transportation infrastructure." This follows an earlier report by the EPA that concluded fairly low levels of leakage, but was based largely on industry supplied data and sites.
A number of recent independent studies have alleged that shale gas production produces methane and radon leakage three times greater than expected. In some cases the volume of seeping methane, a greenhouse gas that traps heat 25 times more effectively than carbon dioxide, is so high it challenges the notion that shale gas can be a bridge to a cleaner energy future. “The most serious environmental concern related to the role of shale gas and climate change is the leakage of methane during shale gas operations, as methane represents 99% of gas extracted. Even though natural gas contains only 50% of the CO2 contained in coal per unit of energy produced, every gram of methane that leaks into the atmosphere has 72 times as much potential for trapping heat than a gram of CO2 over a 20 year time span, and is 20 times more noxious than CO2 over a 100-year period;” according to a new report from the Generation Foundation.
The new studies suggest that there needs to be a far greater level of air quality monitoring on and near well and injection sites than is current practice. In addition, there are questions as to whether the fracturing activity, by itself, may impact natural leakage rates from the underlying rock formations. It appears that methane seepage may be strongest in those sites where drillers have been fracturing seams of coal, which tends to be much richer in methane than shale rock, or where there are existing underground coal mines. If true, the ramification of these studies is that natural gas, at least as currently produced, may in fact be far worse than coal as a global warming gas.
The early studies were further supported by a 2013 Harvard-led study in which real time monitoring again confirmed the significant under-reporting of methane emissions by the U.S. Environmental Protection Agency. This study was followed by another study published in Science and funded in part by a foundation set up by George Mitchell, one of the pioneers of modern hydraulic fracturing. That study also found a significant difference between measured methane emission rates and "official" estimates. Additionally, Stanford University researcher Adam Brandt reported that a small number of high-emitting sources such as leaky pipelines, faulty wellbores, polluting gas plants, and venting storage tanks might account for the high rates of methane.
These studies have been hotly contested by the shale gas industry, which instead refers to another 2013 study by the University of Texas and U.S. Environmental Defense Fund that concluded far lower leakage rates. Note, however, that the shale industry carefully picked the sites that were studied in this study and the times that data was collected. This could imply Morse’s conclusion that there may be best practices to be applied to the methane problem and that such practices, when employed, will produce the levels of leakage that the industry wants to report. Left unsaid is “at what cost?’ Yet another study, just recently completed, reported that an airplane survey over a two-day period found large plumes of methane above shale gas well pads over southwestern Pennsylvania two to three times order of magnitude greater than expected during drilling operations. The scientists in that study suggested that just a few shale gas wells may be super methane leakers and account for the large spikes of methane in the atmosphere.
A separate MIT study in 2011 studied methane migration into adjacent freshwater zones, most likely as a result of substandard well completion practices. Similar results were reported in separate 2011 studies by Duke University and the Colorado School of Public Health. The industry’s response to these studies has generally been that the methane contamination is not caused by the hydraulic fracturing itself, but by other well drilling and completion processes. Such claims do not deny or eliminate the problem; they simply shift the blame from one part of the process to another – in either case, best practices would dictate dealing with the issue.
Water usage and contamination. A second and potentially greater problem, particularly as fracking activities increase, is the question of just how much water fracking requires and whether or not there are serious environmental issue relating to the use of and re-injection of that water. The Generation Foundation report continues: “Shale gas production is a highly water-intensive process, with a typical well requiring around 5 million gallons of water to drill and fracture. With high quantities of freshwater required, pressure on sources is intense in water scarce regions, and competition for water withdrawal permits is already taking place in some regions. The water used during the fracturing process is mixed with sand and multiple chemicals – some of which are toxic – and becomes contaminated with minerals from the shale formations – some of which are also toxic. As a result, the water used for fracturing is heavily polluted when it is removed from the well, and if not properly treated or carefully disposed of creates a risk of groundwater contamination.”
Industry experts acknowledge that fracking is a very water-intensive process but argue that given the energy returned, fracking to produce natural gas uses less water on a unit basis than extracting oil from tar sands, or making electricity from biomass. On average, a gas well opened with a combination of horizontal drilling and injection of hydraulic fluids requires water on the order of 1 to 5 million gallons per well, depending on the geology. And only one-third of that water, on average, is ever returned to the surface. Around the Eagle Ford fields in east Texas, where annual precipitation is only about 20 inches, the pumping has the potential to draw down aquifers by "feet to tens of feet." Additional water is used when wells are re-fractured. Increasingly, this usage of water competes directly with agricultural uses, particularly in states like Texas, which have also suffered from recent droughts.
There is no “easy” solution to the water consumption issue. Techniques have been developed that could reduce water needs by re-using recycled flowback water, or using carbon dioxide, liquid propane or other gases instead of water. Whether any of these might be considered “best practices” or are viable on a cost basis is as yet unclear. Certainly any flowback water that is then injected into deep wells for disposal is forever lost to human consumption or use.
Out of the roughly 2,500 identified hydraulic fracturing additives, more than 650 contain known or possible human carcinogens regulated under the Safe Water Drinking Act or listed as hazardous air pollutants". The EPA intends to release a comprehensive study this year about its views on the impact of hydraulic fracturing on groundwater. Flowback water introduces its own set of environmental concerns. It can be partially recycled, but is an expensive time- and-chemical-consuming process. Here too, best practices are still in early stages of development and raise significant questions as to the necessary level of regulatory oversight needed on a local, state and federal level. Lastly, studies have raised concerns about the levels of radioactivity contained in flowback water. These are particularly serious when that flowback water is released in local wastewater treatment plants and then withdrawn for human consumption downstream. 
Earthquakes. Last, and perhaps least, except in states like California where earthquake dangers already exist at scale, it is known that fracking routinely produces seismic events of varying size. As of late 2012, there have been four known instances of hydraulic fracturing, through induced seismicity, triggering quakes large enough to be felt by people: one each in the United States and Canada, and two in England. But these quakes tend to be of lesser concern than those that appear to be triggered by deep well injection of flowback water.
In addition, the frequency of the quakes has been increasing. The number of 3.0-plus earthquakes in the U.S. has grown from 29 in 2008; to 50 in 2009; to 87 in 2010, and a dramatic increase to 134 in 2011. A new study by the National Academies (available through the NAS online catalog) found that maintaining fluid balance in the injection wells is the key to avoiding induced earthquakes. A USGS team based in Menlo Park, Calif., found that the quake in Colorado and a damaging 5.6-magnitude quake in Oklahoma both were induced by disposal of fracking waste underground. The chart below, which reflects the cumulative growth in U.S. earthquakes over time, clearly suggests that something has changed:
In some cases the facts are so stark that the actions of local officials simply defy logic. In Oklahoma, the statistics for earthquakes since fracking began are shown in the chart below. Nonetheless, state officials resolutely denied any linkage between fracking and earthquakes. In a major turnabout, in a post dated April 21, 2015: “The Oklahoma Geological Survey announced today the majority of recent earthquakes in central and north-central Oklahoma are likely triggered by the injection of produced water in disposal wells.”
By contrast, the Arkansas Oil and Gas Commission recently temporarily shut down two injection wells used for flow-back water from fracking in Arkansas. Since that time, the number and strength of earthquakes in central Arkansas have noticeably dropped, although a state researcher says it's too early to draw any conclusions. "We have definitely noticed a reduction in the number of earthquakes, especially the larger ones," said Scott Ausbrooks, geohazards supervisor for the Arkansas Geological Survey. "It's definitely worth noting." The Center for Earthquake Research and Information recorded around 100 earthquakes in the seven days preceding the shutdown, including the largest quake to hit the state in 35 years – a magnitude 4.7.
George Mitchell himself, the “founding” figure behind fracking, recently expressed his views on some of these “risks” and how they might be dealt with: “As a concerned businessman and philanthropist, I have come to understand that the natural gas industry can no longer simply focus on the benefits of shale gas while failing to address its challenges. We know that there are significant impacts on air quality, water consumption, water contamination, and local communities. We need to ensure that the vast renewable resources in the United States are also part of the clean energy future, especially since natural gas and renewables are such great partners to jointly fuel our power production. Energy efficiency is also a critical part of the overall energy strategy that our nation needs to adopt. Some in the industry have been reluctant to support common-sense regulation, and that needs to change.” 
“Industry leaders, representing companies of all sizes, need to rally behind solutions based on hard science and technological innovation. To find these solutions, industry leaders must lend their best engineers and scientists to a national campaign, teaming up with counterparts from government, academia, and the environmental community, to develop strong state‐by‐state regulations and effective solutions to the environmental challenges of shale gas.”
“We need to replace all-or-nothing arguments with a reasoned discussion that identifies a new path forward. Most rules should be designed at the state level, starting with the 14 states that possess 85% of U.S. onshore natural gas reserves. Best regulatory practices should be shared among state regulators and similar best management practices should be shared among health, safety, and environmental affairs professionals.”
“A strong federal role is also necessary, starting with the Environmental Protection Agency’s new rules calling for more controls over the most dangerous air pollution associated with hydraulic fracturing. The rules will also mitigate methane leakage during the drilling process. This is critical, since methane is a powerful greenhouse gas pollutant, and uncontrolled leakages call into question whether natural gas is cleaner than coal from a global climate perspective.”
It is clear that “best practices for shale gas and tight oil drilling are far from established or settled. How long it will take to establish those best practices, whether they will be implemented broadly and what they might cost is anyone’s guess at this time. It is unlikely that they will be cheap and a number of the oil majors have argued for some time that allowing the smaller independents to dominate the shale gas revolution came with an environmental penalty but perhaps also significantly cheaper prices than had large global companies with huge balance sheets to protect attempted to institute their best practices from day one.
Despite a strong desire to put an exuberant gloss on the future of shale gas and tight oil, a closer look suggests that there remain many uncertainties and that most producers, lenders and investors are hoping for a continued set of price conditions that the market may or may not make available to them in the future. It appears that relatively small moves, in gas prices, oil prices, interest rates or investor sentiments may have outsized consequences on the financial health of the companies involved, the production levels of oil and gas and the returns achievable by investors. The possibility of adding an overlay of a “carbon bubble” due to climate change concerns adds yet another layer of potential instability. Lastly, ongoing price decreases in wind energy, solar energy, batteries, and electric vehicles, as those technologies continue to improve and scale are now seemingly very close to those price points at which consumer choice, when available, may move in unprecedented directions.
 Wall Street Journal; The New Winners and Losers in the Shale Boom - Energy Companies That Spend More Than They Make No Longer in Vogue; By Russell Gold, April 20, 2014
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Technology, and Policy Issues
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 The Economist; Schumpeter, An interview with George Mitchell: The industry can no longer simply focus on the benefits of shale gas; Aug 1st 2013