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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.

Definitions of breakeven points

The breakeven point is seen by some as the most comprehensive assessment of the economic viability of an energy development project. Breakeven points are also called breakeven costs or breakeven prices. The difference is in the point of view, not in any aspect of the underlying economics. In brief, a hypothetical breakeven project has a net present value of zero. In other words, negative cash flows (capital and operating expenses, taxes, overheads, and so on) are exactly balanced by the discounted positive cash flows (income from sales) expected over the lifetime of the project (Brealey et al., 2009).

Given an expected production schedule, variability of future discounted cash flow due to predicted changes in the price of oil can be built into the breakeven estimates. For tight oil wells, which can be constructed relatively rapidly, and whose production is front loaded, as in Fig. 3, such estimates can be made with some confidence. For projects with long construction schedules and extended production lifetimes, such as those in deepwater offshore, or in the Arctic, risks are commensurately greater. These projects are not sanctioned unless their breakeven points are well below conservative estimates for the future price of oil.

Different assumptions about the discount rate (or required internal rate of return) can have very substantial effects on the breakeven point. Among oil analysts a discount rate of 10% has been widely accepted as a standard, though sometimes 15% is used. Discrepancies also occur because various analysts have used differing slates of costs to include in their breakeven estimates. Because these slates of costs are not standardized nor usually explicitly and fully disclosed, breakeven points published by various analysts, agencies, and oil producers are generally not comparable, and therefore easily misunderstood.

In reality, there are various breakeven points for any given project. Each of these breakeven points is valid, but only for a specific purpose, which is sometimes not stated explicitly. Here we present a scheme which does not necessarily follow any one methodology found in analyst, agency or corporate reports. While recognizing that users will want to define breakeven points in ways most useful to them, we propose a model breakeven point scheme that incorporates elements of diverse breakeven analyses used by analysts and industry participants. We avoid de novo terminology by utilizing terms commonly found in reports of breakeven points – “full cycle”, “half cycle”, and “lifting cost” – and provide explicit definitions of these terms. Table 1 summarizes the definitions, and compares them to related terms: capital expenditures, operating expenditures, finding costs, and development costs.

Table 1. Components of various breakeven points.

Table 1. Components of various breakeven points.

Lifting cost

Lifting cost is the incremental cost of producing one additional barrel of oil from an existing well in an existing field. This includes lease operating expense, which comprises well site costs such as the cost of operating and maintaining equipment, fuels, labor costs, and the like.

At present, tight oil resources are produced almost entirely by primary recovery: oil is pushed out of the rock formation and into the well by the natural pressure of the overburden, plus the pressure generated by gas expansion during production, a process called solution gas drive. Nearly all conventional reservoirs are produced by secondary recovery, during which either reservoir pressure is maintained by injections of water or gas, or water is pumped into injector wells to push oil into nearby producer wells (Cosse, 1993). Tertiary recovery (also called enhanced oil recovery) methods include the employment of steam, chemicals, or carbon dioxide to mobilize oil. Lifting costs include expenses associated with these methods.

Lifting cost also includes taxes and royalties charged to production at the wellhead, and the expense of disposal of oilfield wastes. When the marginal cost of transporting product to market is included, the breakeven point is conventionally referenced to a pricing hub, e.g. Brent in northwest Europe, or West Texas Intermediate in Cushing, Oklahoma. The wellhead breakeven price is the hub price minus the cost of transporting the oil from well to hub. Lifting costs are similar to variable costs of production, but also include general and administrative expenses, which are corporate overheads. Lifting cost is the appropriate breakeven point to use when the producer acknowledges a field is in decline and is functioning as a “cash cow”, for which little or no further investment is anticipated in the present phase of the business cycle.

Half cycle breakeven

The half cycle breakeven point is the cost of oil production, including lifting cost, the expense of existing well workovers, and of drilling, completing, and stimulating additional wells in a developed field, with the goal of maintaining level production. The cost of financing these activities is included in the half cycle breakeven point.

Half-cycle breakeven costs are often the largest expenses incurred in the development of an oil field. Drilling expenses include the rental of a drilling rig, and ancillary equipment and supplies such as drill bits and drilling fluids. Directional drilling services enable the construction of increasingly popular horizontal wells. Completion expenses include the steel casing used to stabilize the wellbore, and the cement placed between casing and wellbore to assure that hydrocarbons cannot contaminate potable water resources by moving upwards between casing and subsurface rock. Such operations are more efficient and economic when multiple wells are serviced from a single site, a development referred to as “pad drilling”. A review of half-cycle costs can be found in EIA (2016c).

Stimulation was historically a small part of the total cost of well construction. With the advent of massive hydraulic fracturing, it is now roughly half the expense of drilling and completing a shale gas or tight oil well. In modern practice, well stimulation is a choreographed industrial operation involving multiple service providers using a considerable quantity of heavy equipment, along with roughly 30,000 cubic meters of water, 3000 tons of sand, and 300 tons of specialty chemicals per well.

For the purposes of taxation in the United States, the expenses of drilling and completing a well are divided into tangible and intangible drilling costs (IRS, 2016). The exact division between the two is declared by the owner. Generally, the former are permanent fixtures of wells and pads, including well heads, casings, pumps, gathering lines, and storage tanks. Intangible drilling costs include items with no salvage value, including wages, fuel, repairs, hauling, and supplies. In North America in 2014, 23% of the average well cost was classified as tangible drilling expense, with the balance classified as intangible drilling expense (Wood Mackenzie, 2015b).

Stopping (“shutting in”) production from a producing oil well is problematic, both technically and economically. However, there is a safer strategy to delay production. After wells are drilled they must be cased and cemented in order to protect potable water resources and to prevent the wellbore from collapsing. Drilling, casing, and cementing usually account for roughly half the expense of a modern horizontal, massively fractured well. Remaining operations required to start the flow of oil, including perforating, stimulating, and installing production tubing and downhole pumps, can be delayed indefinitely at very little cost and with little or no geological risk.

Such wells are called “drilled but uncompleted” wells (“DUCs”). This strategy is useful when an oilfield operator is under contractual obligation to continue drilling (to hold a lease or to satisfy a drilling rig rental contract, for example), but wishes to conserve capital and delay production until market conditions are more favorable (EIA, 2016l).

Half cycle breakeven costs include the capital expense of implementing secondary and tertiary recovery methods, where used. These expenses can be significant, particularly for tertiary recovery methods. For example, heavy oil production requires large scale infrastructure to generate steam.

A workover is a procedure in which the subsurface plumbing of a well is repaired or replaced after it has been in service for some time. Refracture is a procedure in which current fractures of a well are enlarged, or new fractures are created. Refracture is most commonly performed several years after the well has been completed and initially stimulated, and is described further in Section 4.3.

The ultimate cost of decommissioning should also be included in the half cycle breakeven point. Decommissioning includes the secure plugging and abandonment (P&A) of the wells, and any necessary or desirable site restoration. P&A expenses are largest in offshore developments; in 2016 the U.S. Bureau of Ocean Energy Management promulgated new rules governing liability (Gladstone et al., 2016). The Texas Railroad Commission requires oil and gas producers to post surety bonds (Texas, 2005), but in many cases liability must be determined through litigation, particularly when an operator has abandoned the well or declared bankruptcy (Oran and Reiner, 2016).

Full cycle breakeven

The full cycle breakeven point encompasses the cost of oil production including all expenses of developing a new field. It is thus the most comprehensive measure of the cost of oil, and is appropriately used when planning a major extension of operations. It includes all the expenses of finding and delineating a resource, including geophysical prospecting, exploratory drilling, and measurements of the size and richness of the resource (“reservoir characterization”). It also includes obtaining rights to resource exploitation, which can be a complicated process where mineral rights are broadly distributed. Above-ground infrastructure such as roads are also included in full-cycle costs.

If a common carrier is not available, as with liquefied natural gas projects, it includes takeaway capacity, including the capital expense of providing transportation to a market or to a specified pricing hub. The cost of financing all the above activities is included in the full cycle breakeven point. It might also include property tax on reserves, where levied (see e.g. Texas, 2016). Half cycle expenses, including all costs of maintaining level production, and lifting cost expenses, to actually produce oil and pay taxes and royalties as described above, are subsets of full cycle expenses.

The costs of financing field and well development are included in full cycle and half cycle categories respectively. Remarkably, free cash flow (cash flow less capital expenditures) has been negative for U.S. onshore producers from the inception of the shale gas and tight oil boom through at least 2016 (Wall Street Journal, 2014, Sandrea, 2014, Domanski et al., 2015, EIA, 2016h). Producers have remained solvent by taking on debt, and by selling assets and equity; it appears some investors view tight oil plays primarily as real estate deals. Negative free cash flow is a characteristic of an industry in the process of building up its stock of productive assets. Indeed, since drilling slowed in Q1 2015, the gap between capital expenditures and operating cash flow has narrowed (EIA, 2016h).

Relationship between fixed and variable costs

Fixed costs do not depend on the level of production, whereas variable costs scale with output. The division between fixed and variable costs in Table 1 depends on the maturity of the asset. Finding costs come closest to being purely fixed costs, because normally geophysical surveys and leasing are completed prior to the drilling of producing wells. Delineation wells, which are generally not significant contributors to production, are part of the fixed costs.

Whether development costs are considered fixed or variable depends on the maturity of the asset. Early in the life of a field, its value is directly proportional to the number of wells drilled; thus these can be considered variable costs. Once drilling ceases, the cost of the wells is sunk, and the only variable cost is the lifting cost, except for general and administrative costs.

Fiscal breakeven

Full cycle breakeven costs, and all its components, are essentially technical and economic in nature, and as such are controlled by corporate decision-making, geological and geographic factors, market forces, and rates of taxation. Fiscal breakeven is of a completely different nature. It is the price of oil required to finance national expenditures, for those nations which depend heavily on oil receipts to fund government operations (Clayton and Levi, 2015, IMF, 2016). It includes full-cycle, half-cycle, or lifting cost expenses, depending on the state of the indigenous industry. Moreover, it depends directly on certain components of the technical breakeven costs, such as leases, royalties, and taxes. Where government is a major shareowner in oil companies, as is often the case in countries heavily dependent on resources, fiscal breakeven also depends on corporate dividends and similar payouts.

Although not generally expressed in this manner, individual corporations also have fiscal breakevens, which relate to the expectations of their investors. For those corporations financed predominantly by equity, fiscal breakeven includes revenues required to meet expected corporate dividends. Corporations like to show steady or rising dividends over time, which are put under pressure when income falls as a result of unexpected costs, or falling commodity prices. Recently, corporations have increased their debt load in order to pay dividends (Bloomberg, 2016).

Externalities breakeven

In some cases, breakeven costs might be considered to include additional aspects of production activities, such as social cost of carbon (EPA, 2016), direct and indirect costs of accidents, environmental impacts, and societal impacts (Greenstone and Looney, 2012, Jackson et al., 2014, HEI, 2015).

Geological, geographical, quality, taxation and exchange rate influences on breakeven points

Geological factors

Every oil field has a range of distinct breakeven points. A primary cause of breakeven point variation is geological. Conventional oil plays are defined by traps: the subsurface structural or stratigraphic geometries of oil or gas reservoirs in which the placement of fluids is driven by their buoyancy (USGS, 2016). Small traps are clearly harder to find, and are less productive when found. Large traps can be delineated and produced at exceptionally low cost – as low as a few dollars per barrel of oil produced.

Unlike conventional reservoirs found in traps, “shales” (more properly referred to as organic-rich mudstones (Kleinberg, forthcoming)) are continuous: “large volumes of rock pervasively charged with oil and gas” (USGS, 2016). Although these plays may be hundreds of kilometers in extent, the richest rock bodies, and those most susceptible to hydraulic fracturing, can be quite localized (Gulen et al., 2015, Ikonnikova et al., 2015). Thus there are considerable variations in breakeven points between and within sub-plays (North Dakota Department of Mineral Resources, 2015, Wood Mackenzie, 2015a).

Geographical factors

Equally important are geographical factors. The local availability of oil field infrastructure has a major influence on breakeven points. Much of the field and well development inherent in resource exploitation is performed by a network of contractors who provide materials and perform services essential to every aspect of this process. Local availability of – and the presence of competitive markets for – exploration expertise and instrumentation; drilling rigs, equipment and services; and completion and stimulation services, have a major influence on oil field development costs.

Operators engaged in onshore exploratory drilling in advanced industrialized nations in Europe are dismayed to learn they are in “frontier areas” with respect to oil field services, where costs can be double or triple those prevailing in Texas or Oklahoma. This is true even when those nations, such as the United Kingdom, have well established offshore exploration and production industries with globally competitive economic structures.

All else being equal, well construction costs in ultra-deepwater (greater than 1500 m water depth) are an order of magnitude greater than on land. Therefore only very productive reservoirs can be exploited, and there must be a strong expectation that future oil prices will be high enough to warrant investment. Arctic regions can also be economically challenging, even though in various parts of the Arctic very significant amounts of oil have been produced.

Nonetheless, the petroleum industry is remarkably adaptable, and operates efficiently in many improbably remote locations. Economy of scale is key, and once sufficient activity develops in a geographical locale, no matter how remote or uninhabitable, cost reduction will follow. Thus the lowest-cost places in the world to work are many areas in the United States and Canada, the nations surrounding the Arabian Gulf, and infrastructure-rich parts of Russia, all of which have long histories of intensive oil and gas development. For example, in mid-2014, at a recent peak of oil prices, there were 1850 land rigs in the United States and only 100 in all of Europe. This is one of the reasons why exploitation of shale gas resources developed so much more rapidly in the United States than anywhere else.

One of the greatest hurdles to working in remote areas is the cost of transporting product to markets (“takeaway”). This is particularly true for natural gas, for which practical transport is limited to large-diameter high-pressure pipelines, or liquefied natural gas ships and associated export and import facilities. Both approaches are costly (Shaw and Kleinberg, forthcoming). Thus, for example, plans for exploitation of natural gas on the North Slope of Alaska have been repeatedly frustrated by the cost of moving gas to markets. Oil transportation is generally cheaper and easier because of its much higher energy density under ambient conditions of temperature and pressure.

Finally, country risk can be a decisive factor in the decision whether or not to develop a resource. There are a wide variety of risk factors, including the extent and stability of environmental regulations; labor availability, regulations, and militancy; disputed land claims; political and legal instability; and insecurity arising from crime, conflict, or terrorism (Jackson et al., 2016). Arguably, tight oil fields are less subject to political risk such as expropriation because the payback time of an individual well is short, and field production can only be maintained by continuous drilling of wells requiring technically sophisticated horizontal well construction and high volume multistage fracturing.

Quality factors and price hub locations

The market price of a barrel of crude oil depends on its value to refiners. Generally speaking, “light” (low mass density) oils comprising low molecular weight hydrocarbons are more valuable than “heavy” (high mass density) oils with high contents of nitrogen-, sulfur-, and oxygen-bearing compounds.

The location of the hub at which oil is priced can also be an important factor. As mentioned above, oil is normally relatively inexpensive to ship long distances via pipeline or tanker (Shaw and Kleinberg, forthcoming). However, when the rate of oil production temporarily exceeds available transport capacity, significant price differentials between hubs can develop. Historically, prices of Brent Crude, traded in northwestern Europe, and West Texas Intermediate (WTI), traded in Cushing, Oklahoma, have been within a few percent of each other. However, between 2011 and 2014, when U.S. tight oil production increased so rapidly that pipeline capacity was exceeded and railroads were brought into service to move crude oil (EIA, 2016o), the Brent price exceeded WTI by as much as 20% (EIA, 2013).

When quality and hub location factors combine, price differences can be especially large. For example, in December 2013, WTI sold for $98/bbl in Cushing, while Western Canadian Select, which is both heavy and transportation constrained, sold for $59/bbl in Hardisty, Alberta (Alberta, 2016).

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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