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Tight oil market dynamics: Benchmarks, breakeven points,and inelasticities

Fig. 7. U.S. tight oil and shale gas drilled but uncompleted wells (EIA, 2017b) (dotted curve, right axis) and West Texas Intermediate crude oil price (EIA, 2017c) (solid curve, left axis) from January 2014 to April 2017.

In many plays, substantial quantities of associated gas are produced with oil. In such circumstances, the heating value of the combined production can be referenced to barrels of oil equivalent (boe), which is defined in terms of the higher heating value (HHV) of the oil and gas products upon combustion: 1 boe = 5.8 million Btu = 6.1 GJ (IRS, 2005). However, the barrel of oil equivalent is not a valid means of estimating the economic value of production, as the relative prices of gas and oil often do not scale with their heating values. Associated gas rich in methane and natural gas liquids – ethane, propane, normal butane, isobutane, and natural gasoline – can be more accurately assessed in terms of the individual product streams, which have species-specific values to the refining and petrochemical industries (Braziel, 2016, EIA, 2016e).

Taxation

The kinds and amounts of taxes imposed on the petroleum industry by governments are driven by two conflicting desires: first to maximize tax receipts, and second to encourage economic development associated directly and indirectly with hydrocarbon production. Generally speaking, the easier it is to find oil, and the cheaper it is to extract, the larger the tax (Brackett, 2014). Practices vary widely among countries (EY, 2015) and from state to state within the United States (EIA, 2015c). In the U.S., oil and gas production is encouraged by special tax preferences, the three most important of which were worth about $5 billion in net tax reductions to the industry in 2017 (Metcalf, 2018).

Exchange rate factors

Breakeven points are conventionally stated in U.S. dollars per barrel of oil. While oil is traded internationally in dollar-denominated contracts, in some cases breakeven points are more appropriately stated in terms of national currencies. For example, the Russian oilfield service sector is large and well-developed, and prices its services in Russian rubles. From mid-2014 to early 2016, when the ruble fell in value relative to the dollar in synchrony with the decline in the international price of oil, Russian oil companies came under less financial pressure than did Western oil companies (Financial Times, 2016, IHS, 2016). In essence, technical breakeven points in ruble terms remained mostly unchanged. However, Russia’s dollar-denominated balance of trade with other countries suffered as a result of the dollar-denominated oil price decline.

How breakeven points change with time

Despite the lack of transparency of many breakeven point estimates, the mid-2014 consensus range of $60/bbl to $90/bbl for full cycle breakeven in tight oil plays, appears to have been broadly accurate. Once oil prices fell through this range, in the second half of 2014, rig counts in the major tight oil basins collapsed, as illustrated by Fig. 2a and b. More than 100 North American exploration and production companies, and a similar number of oilfield service companies, filed for bankruptcy between January 2015 and mid-2016 (Haynes and Boone, 2016a, Haynes and Boone, 2016b). Even the strongest of the U.S. independent tight oil producers reported negative operating and net incomes throughout this period.

However, one of the pitfalls of inadequate understanding of breakeven points is a failure to realize that they change with time. For example, in Andrews, Martin, Howard, and Midland counties, in the Permian Basin of Texas, breakeven points declined from $76/bbl in June 2014 (Wood Mackenzie, 2014b) to $37/bbl in August 2016 (Wood Mackenzie, 2016c), behavior that was typical of U.S. tight oil plays (IHS, 2017). We identify two kinds of changes. Internally-driven changes reflect steady microeconomic improvements in infrastructure and efficiency. Externally-driven changes occur in response to changing macroeconomic conditions. In the dynamic U.S. oil and gas industry, and particularly in the tight oil sector in which production technology is evolving rapidly, internally and externally driven changes can significantly alter production economics on a time scale of 1–2 years.

Internally-driven changes

Table 2 outlines some of the internal drivers of breakeven point change. Changes can be early or late in the development cycle, and can increase or decrease costs. Often, breakeven points are high or increasing early in development, as oil producers compete for resources such as leases, personnel, and infrastructure. Later in the development cycle, debottlenecking and increased competition among service providers causes costs to fall. Thus well drilling and completion costs in five U.S. shale gas and tight oil plays rose from 2010 to 2012 and fell from 2012 to 2015 (EIA, 2016c), during a period in which oil prices were stable.

Table 2. Internally-driven factors which change breakeven points, early and late in the development cycle.

Table 2. Internally-driven factors which change breakeven points, early and late in the development cycle. Factors which increase costs are shown in bold font, and factors which decrease costs are shown in italic font.

Decreasing costs can be accompanied by increasing production. From late 2012 to the third quarter of 2014, internally-driven improvements led to a doubling of new well oil productivity per rig in the Bakken tight oil play, see Fig. 4. This was partly due to wells being drilled and completed more quickly, and partly due to increases in the initial production per well (EIA, 2016a). Throughout this period, West Texas Intermediate crude traded in a narrow range around $100/bbl (EIA, 2016m).

Fig. 4. Productivity of drilling rigs directed to Bakken tight oil. Internally-driven changes occur throughout the period shown.

Fig. 4. Productivity of drilling rigs directed to Bakken tight oil. Internally-driven changes occur throughout the period shown. Externally-driven changes are driven by rapid declines in the price of oil, e.g. mid-2014 through 2016. The vertical axis represents the amount of new production an average rig, operating for one month, contributes to the oil supply (EIA, 2016k).

Taxes and other aspects of “government take” can be important exceptions to the pattern of costs falling over time. Governments seek to maximize their share of oil industry revenues, and while some countries have fixed rates of taxation, others change their tax rates at will, increasing taxes to just short of the point at which local oil exploration and production is discouraged and moves elsewhere. At the inception of activity, when risks are high and sunk costs are low, or when oil prices are low, governments encourage activity with low tax rates. After reserves have been booked and expensive infrastructure built, or when oil prices increase, tax rates can increase.

Externally-driven changes

Breakeven points change as a result of changes in the price of oil. While the price of oil depends on the cost of its production, the opposite is also true: the cost of oil production depends on capital, labor, and material inputs, the prices of which are affected by the state of the oil market. When the price of oil is high relative to long term trends, as it was in 2011–2014, the goals of producers are rapid growth of reserves and production: they are incentivized to find, delineate, and develop new fields, with all the attendant inefficiencies. Service providers offer new, more expensive technology directed to those objectives. Cost control is a secondary consideration. Service company profitability increases.

These trends are also dependent on the rate of change of the oil price. Rapid expansion of the industry creates bottlenecks in equipment, supplies, labor, and infrastructure. The oil industry faced such stresses from the early 1970s to the early 1980s, when the price of oil quadrupled in inflation-adjusted dollars. Discovery of rich new plays sets off a similar gold-rush mentality, as illustrated by the advent of tight oil production in 2009–2014.

When oil prices decline, all these trends are reversed. Exploration, the growth engine of the industry, slows to a crawl. Determination of the areal and vertical extent of the reservoir, and measurements of the spatial variation of its richness (asset delineation or “de-risking”) is no longer prioritized. The industry tends to focus on familiar resources and geographical areas known to contain substantial recoverable reserves (with a few notable exceptions, such as the Alpine High field (Apache, 2016)), and within those areas, the best drilling locations (“sweet spots”), a process known as asset high grading.

This leads to a greater responsiveness to price changes (Smith and Lee, 2017). Moreover, a large reduction in the number of drilling rigs results in survival of the most modern and efficient rigs, manned by the most experienced and successful drilling crews. This might be termed operational high grading. Thus over the period 2004 to 2015, the IHS Upstream Capital Cost Index (IHS, 2015a) tended to increase after increases in the price of Brent crude, and tended to decrease after decreases in the crude price.

As illustrated in Fig. 4, rig productivity can increase rapidly due to externally-driven factors. After having doubled during times of relatively constant oil prices, Bakken rig productivity increased by another factor of three while oil prices declined precipitously from the third quarter of 2014 through 2016. During this period, normal process improvements were amplified by asset high grading and operational high grading.

In addition to internally-driven cost reductions due to normal improvements in efficiency, and externally-driven market-related cost reductions due to asset high grading, steep declines in activity enable operators to drive down costs while the supply of services exceeds the demand for them. Service providers respond by laying off personnel and by warehousing (“stacking”) or destroying or cannibalizing (“writing off”) equipment, but these cost-control measures, which are costly in themselves, usually do not keep pace with the rapid declines in business activity, such as occurred in 2014–2016.

The Permian Basin provides another dramatic example of how rapidly price structures can change. Following the national trend, the Permian Basin oil-directed rig count fell by more than 75%, from a peak of about 560 rigs in November 2014 to a trough of about 130 rigs in April of 2016 (Baker Hughes, 2016), see Fig. 2b. Much of this decline was due to retirement of almost all of the 200 vertical and directional rigs, which were primarily exploiting the conventional subplays of the basin, but even the horizontal rig fleet declined by almost two-thirds. Nonetheless, tight oil production continued to increase through 2016 (EIA, 2016k). While oil prices were relatively stable between 2012 and late 2014, internally-driven improvements doubled rig productivity. Falling oil prices after late 2014 triggered externally-driven improvements, which increased rig productivity by a further factor of 2.7 (EIA, 2016k), while well costs declined by 35% and production costs declined by 25% (Pioneer Natural Resources, 2016).

Governments can change tax structures and rates in response to market conditions. When oil prices are rising, governments can increase tax rates without driving producers out of business or to other countries. When oil prices fall, governments are forced to make tax concessions to maintain the viability of their petroleum industry (Wood Mackenzie, 2017).

Change in type of breakeven point

Just as importantly, the relevant type of breakeven point changes with time. Once finding costs are sunk, the full cycle breakeven oil price is no longer relevant in assessing project economics going forward. Similarly, once drilling concludes, the cost of well construction becomes irrelevant. Thus there is a natural progression of a project from full cycle economics through half cycle economics to lifting cost economics.

The relevance of the various breakeven points also changes due to external drivers:

  • During periods of rising oil prices, when producers move into new plays, full cycle breakeven is relevant to planners and investors.
  • In stable markets, when activity is focused on in-fill drilling and modest step outs in de-risked plays where infrastructure is in place, half cycle breakeven economics is most relevant.
  • When markets are in free fall and oil companies are focused on survival, the viability of existing assets is measured against lifting costs.
  •  When prices rebound, some operators will have accumulated substantial acreages of derisked prospects, with plenty of undrilled sites in their inventories. They will be able to continue with favorable half-cycle economics for some time. However, as their sweet spots are depleted, as is already occurring in the Barnett shale, and they have to move to fresh prospects, they will be forced to return to full cycle economics.

The tiered nature of breakeven points is important because the tiers are relatively far apart. In mid-2014, full cycle breakeven points for U.S. tight oil produced by massive hydraulic fracturing were generally in the range of $60–$90/bbl. Given that the excess of oil supply over demand was in the range of 1–2%, and that “rapidly responding” tight oil constituted about 4% of the world oil market, one might have expected that the price of oil was unlikely to fall below about $60/bbl. However, half cycle breakeven points were in the range of $50–$70/bbl, and lifting costs were below $20/bbl.

When oil prices declined, not only did these brackets move to lower cost ranges due to internal and external drivers (compare e.g. Wood Mackenzie, 2014a, Wood Mackenzie, 2015a, Wood Mackenzie, 2016b, Goldman Sachs, 2017), but there was a large-scale transition from greenfield full cycle economics, to the half cycle economics of drilling to maintain level production, and eventually, after the second half of 2015, to production from existing wells. Anticipated profits vanished, and the capital expenses accounted for in full-cycle economics became sunk costs reflected in falling share prices, debt restructuring, asset sales, or bankruptcy.

Other factors affecting tight oil market dynamics

The conventional definition of price elasticity of supply is the ratio of the percentage change of quantity supplied to the percentage change in price. When this ratio is less than unity, the market is said to be inelastic (Mankiw, 2011). The supply of oil is inelastic in the short term. This inelasticity arises from many sources, each of which has its own characteristics.

Rate of growth of tight oil production

Part of the conventional wisdom surrounding tight oil production is that it is very responsive to changes in markets. This certainly seemed true from 2009 to 2014, when tight oil production grew from 700,000 bbl/d to 4,200,000 bbl/d (EIA, 2015b). During the latter part of this period (following recovery from the recession of 2008), rates of growth of U.S. oil production were the largest in more than 100 years, mostly attributable to tight oil (EIA, 2015a).

However, these dramatic growth rates do not imply tight oil is cheaper or easier to produce than conventional oil. In fact, tight oil wells are more expensive and more complex to construct than most conventional oil wells, requiring specialized equipment, such as bottom hole assemblies capable of horizontal drilling and fleets of truck-mounted high-pressure high-volume pumps. However, exactly the same drilling rigs and hydraulic fracturing equipment are used to exploit shale gas and tight oil, and large quantities of this equipment had been brought into service during the shale gas boom that started in 2004.

That boom terminated abruptly at the end of 2008, when gas prices fell from $6–$14 per million British thermal units (1 MMBtu = 1.055 GJ) to $2–$4/MMBtu, causing the number of U.S. gas-directed drilling rigs to fall from 1600 to 700. Thus tight oil drilling programs could ramp up rapidly when the West Texas Intermediate benchmark oil price doubled in 2009, as shown in Fig. 5. The rapid increase of tight oil production, rather than being a property intrinsic to tight oil, was the product of the accidental, rapid crossing of oil and gas prices, and the fact that shale gas and tight oil drilling and stimulation equipment is interchangeable.

Fig. 5. Horizontal drilling rigs (bottom) (Baker Hughes, 2016) and hydraulic fracturing equipment moved from gas plays (dotted curve) to oil plays (solid curve) after oil and gas prices diverged (top) (EIA, 2016m, EIA, 2016n).

Fig. 5. Horizontal drilling rigs (bottom) (Baker Hughes, 2016) and hydraulic fracturing equipment moved from gas plays (dotted curve) to oil plays (solid curve) after oil and gas prices diverged (top) (EIA, 2016m, EIA, 2016n).

Note however that despite the redirection of drilling rigs from shale gas to tight oil, U.S. natural gas production did not decrease. One reason was continued improvement in well recovery rates in the Marcellus dry gas play. Another was the rapidly increasing production of natural gas associated with tight oil, mostly from the Bakken, Eagle Ford, and unconventional Permian plays, which grew from essentially zero in 2009 to 13% of total U.S. gas production by mid-2015 (IHS, 2015b).

Once drilling and stimulation infrastructure are generally available, onshore production of oil can respond rapidly to price signals. The average lag between investment and production for tight oil wells is about one year, coincident with the shortest lags associated with all oil wells drilled in 14,000 oilfields between 1970 and 2015 (Bornstein et al., 2017). The entire Bornstein data set is broadly distributed, the longest lags presumably associated with wells drilled in deepwater or frontier regions.

Rate of decline of tight oil production

When oil prices fell, the decrease of tight oil production proved slower than some expected. In the two years following the completion of a well, tight oil production from that well declines quickly, in contrast to conventional oil wells under secondary recovery. Thereafter, the decline of tight oil wells roughly parallels that of conventional wells, see Fig. 3. However, there are important differences between the production rate of individual wells and that of a field of such wells. The rate of decline of production for a field comprising numerous wells drilled at various times is not necessarily the same as the rate of decline of an individual well in that field, even if all wells have exactly the same production parameters.

Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo. In an independent way he’s researching about shale gas & tight oil and building this website to spread the scientist knowledge of the shale industry.
http://www.allaboutshale.com

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