The modern tight oil industry has some important characteristics that make it strikingly different from past production of conventional oil. These are important for understanding future production. It is important to review these aspects in order to evaluate whether the oil production required for the IPCC scenarios can be met.

Why the Sudden and Sharp Increase in US LTO Production Starting in 2011?

LTO production started increasing in 2011 when the price of oil increased to greater than $90/barrel (Fig. 1). Tight oil is expensive to produce. According to Bloomberg BusinessWeek (October 13, 2014), the horizontal drilling process for a single well can cost about $6–$9 million. The production of LTO increased because the price of oil increased, not because of new technologies. The techniques of horizontal drilling (since 1930s) (e.g., Curtis 2011; Blackmon 2013) and fracking (since 1940s) (e.g., Manfreda 2015) with sand and chemicals at high pressure to increase production have long been known, although improvements have continuously been made. Fracking was first used on a large scale to extract natural gas beginning in about 2005. It expanded to the oil fields around 2010. Shale is normally a source rock for hydrocarbons and has very low permeability. The shale revolution began because:

1. more attractive, less expensive conventional opportunities were exhausted, and 2. the market price of oil climbed to support the cost of extraction of unconventional LTO.

Policy exemptions and technological change contributed, but they do not explain the timing. There are many exemptions for hydraulic fracturing under US federal law: The oil and gas industries are exempt or excluded from certain sections of a number of the major federal environmental laws. The most important was The Energy Policy Act of 2005 (https://www.epa.gov/laws-regulations/summary-energy-policy-act), which included the exemption (known as the Halliburton Loophole) of hydraulic fracturing from key provisions of the Safe Drinking Water Act (http://www.nytimes.com/2009/11/03/opinion/03tue3.html; Whitney and Behrens 2010; Hauter 2015). There were technological improvements such as improvements in 3D seismic imaging and (especially) techniques of horizontal drilling. But the main factor that enabled the oil and gas industry to extract oil from shale rock over the past 7 years was higher price. If it were not for higher oil prices, the capital investment needed in the oil and gas sector would not have occurred, and US oil production would have continued to decline.

LTO Production in the Rest of the World

So far, most LTO production has occurred in the USA, and US LTO production is in decline. The US EIA assessed global shale oil resources (US EIA 2013) and concluded that 41 countries have technically recoverable resources. These resource assessments were updated in 2015 (US EIA 2015a). International LTO production requires favorable geology, which includes marine oil source rocks, total organic carbon (TOC), hydrogen index, thermal maturity, and depth of burial (pressure). When you eliminate non-marine shales and shales with insufficient TOC, are over-mature and are either too deep to be commercially horizontally drilled and hydraulically fracked or too shallow to have sufficient pressure to produce, there are not that many prospective basins in the world (Art Berman, personal communication, November 2016). Economic recoverability also depends on above-the-ground factors, such as financial resources, ownership of subsurface mineral rights (which are absent in most countries), extensive infrastructure (rigs, pipelines, rail, roads, service companies), the right physical setting (onshore, easy terrain, unpopulated), and availability of water resources. There is certainly potential for tight oil elsewhere in the world, but the possibility of replicating the success of the US LTO boom in other parts of the world will be difficult (Maugeri 2013). The USA and Canada are unique in terms of the amount of drilling (drilling intensity) that has taken place, which has defined the geological distributions. They also have the most favorable surface/mineral rights regulations and the onsite knowhow with equipment (especially drill rigs), people, and infrastructure. High-quality tight oil plays are not ubiquitous—half of the tight oil production in the USA comes from just two plays (Bakken and Eagle Ford)—and take a lot of capital. Besides the USA, Western Canada (Duvernay Shale), West Siberia (Bazhenov Shale), China (Dagang Formation), and Argentina (Vaca Muerta Shale) are currently the only countries in the world that are producing low but commercial quantities of LTO (US EIA 2015b). Poland is a representative example of where there were initial estimates of large reserves of shale gas (not LTO) that were reduced significantly after initial exploration revealed that there was low permeability and complex faulting. (Economist, 2014, http://www.economist.com/blogs/easternapproaches/2014/11/polish-fracking).

High First Year Decline Rates Require a Drilling Treadmill

In a seminal report, David Hughes (Hughes 2014) analyzed all of the individual LTO producing wells in the USA and determined that the average declines in production rates over the first year were typically 40–70%. The average decline rate for conventional oil wells is about 5–7% per year, meaning that 3.5–4 mb/d of new production are required each year just to stay constant. Because of the high decline rates, an increasing number of new wells are required to just to maintain present production. This drilling treadmill has been called the “Red Queen Effect” (from Lewis Carroll’s “Through the Looking Glass”) (Likvern 2013). To illustrate this, we see that to maintain production of 1 mb/d requires 60 new wells per year in Iraq and 2500 new wells in the Bakken in North Dakota.

“Hot Spots” are Drilled First

The production from shale formations is spatially highly variable. In the case of the Bakken Formation, four counties account for 85% of the production. As of March 2013, there were 5047 wells, producing 0.70 mb/d for an average of 140 barrels per day per well. That average production per well has decreased with time as the “hot spots” have become depleted, and subsequent new wells were less productive (Hughes 2014). For comparison, production of wells in conventional oil fields can be 1000s of barrels per day per well.

Tight Oil is Not Profitable!

Estimates of the break-even price for light tight oil vary but range from about $75 per barrel (presentation by Paal Kibsgaard (CEO Schulumberger) at the Scolia Howard Weil 2015 Energy Conference, http://www.slb.com/news/presentations/2015/2015_0323_pkibsgaard_howard_weil.aspx) to greater than $90 per barrel. There are many reports in the press of lower break-even prices, but these do not take into account full costs, which vary between different oil plays (Berman 2015a). The true story can be seen in the individual companies’ full-year 10-K earnings reports filed with the Securities and Exchange Commission. Full-year free cash flow has been negative for most tight oil Exploration and Production (E&P) companies since 2009. The composite free cash flow for the 19 largest LTO E&P companies was −$2.9B in 2013. For the same group, it decreased by −$7.5B to −$10.5B in 2014 (Berman 2015b). This total negative cash flow of $10.5B in 2014 was for a year when the average Brent price was $93/barrel. These losses continue. All of the E&P companies in the tight oil business had negative cash flow in the first quarter of 2016 except EP Energy and Occidental Petroleum. Nine companies increased their capital expenditures (capex)-to-cash flow ratios compared with full-year 2015 results and six increased that ratio by more than 2.5 times (Berman 2016). Even ExxonMobil has had progressively decreasing free cash flow from $24B in 2011 to $1.0B in 2016 YTD. The industry consistently spends more cash than it generates, even while trying hard to cut costs.

Cheap Money Helped Inflate LTO Production

The E&P companies have been financed by high risk, high-yielding “junk bonds” issued by the industry (Wall Street Journal, Zero Hedge, 1 June Zero Hedge 2016). The Federal Reserve lowered the Fed funds rate essentially to zero at the end of 2008, but the economy continued to worsen. So the Fed tried to see what it could accomplish by buying huge quantities of longer-term securities (called quantitative easing) in order to stimulate the US economy. Junk debt earned the name for a reason: It means risky business for investors, but also a higher yield if the bet goes well. The yields on energy junk bonds varied between 5 and 9% from 2010 to 2015 but increased to as high as 10.8% in February 2016 (Abramowicz 2016). This provided the cash needed for E&P companies to do necessary exploration and production. That tells us that LTO producers are heavily dependent on debt. Were it not for the Federal Reserve’s policy, the ever-accelerating drilling treadmill (see “High First Year Decline Rates Require a Drilling Treadmill” section) would likely slow down, making shale oil and gas production a less lucrative endeavor for oil and gas companies and the financiers bankrolling it.

In addition to the availability of high interest rates, analysts and investment bankers encouraged the investment that helped promote the LTO surge (Rogers 2013). The story for LTO was pretty much the same as for shale gas. Both gas and oil reserves were initially vastly overestimated (Rogers 2013). Wells are characterized by steep decline rates that resulted in underperformance relative to original projections. Market gluts of gas and oil resulted from overproduction in order to meet financial market’s production targets and to provide cash flow. Prices were driven to new lows, and this opened the doors to transactional deals and consolidations that secured large fees for the investment banks, who profit regardless of the profitability of the E&P companies.

Why did companies continue producing LTO when they were losing so much money? The answer is complicated. The executives have their incentives, often based on stock performance. Their goal is to keep shareholders happy and ensure that cash flow at least covers interest costs. They continued drilling new wells to keep their reserves and production growing and to maintain the illusion of profitability. The shareholders are looking for production growth. They see E&P companies as growth companies (the International Oil Companies (IOCs) with dividends are an exception). As long as there is reserve and production growth, they will stay with the stock and discount the lack of present profitability. The easy money policies created an environment where yield-hungry investors pushed into riskier assets. High yield justifies high risk. If cash flow covers debt, they are satisfied. Depletion gets ignored because it is not a cash item. Capital expenditures are ignored because they presumably are funding future growth.

The recently accumulated debt is massive. The total industry debt increased to $3 trillion with at least $1 trillion being spent on unprofitable projects (Financial Times, March 21, 2016). The companies on the Bloomberg North American Independent E&P Index spent $4.15 in operating expenses for every dollar earned selling oil and gas in the first quarter 2015 (Bloomberg Business, June 18, 2015). Standard and Poor’s assigns junk rating to 45 out of the 62 companies on this index. Access to cheap cash via capital markets has allowed money-losing producers to keep drilling even at low prices. Even so, 69 oil and gas producers have filed for bankruptcy in North America as of May 2016 (Forbes May 9, 2016).