Innovation increases productivity. Productivity fosters economic growth. Economic growth generates work, which produces jobs, wealth, purchasing power and higher living standards. So tight oil/gas development is a good thing for the United States, yes? Well, yes, if the current trend holds up.
The recent success in oil and gas production from shale formations did not just occur because the oil and gas were there. Unprecedented technical barriers lay between knowing of the existence of oil and gas in shale formations and producing from them. A wave of technical breakthroughs, developed in part over the last two decades and reinforced by the conviction that shale formations could be tamed to yield their treasure, those were the forces that turned promise into reality.
The cost of drilling and completing wells in shale formations is six to eight times higher than that for conventional wells. These costs are also hard to predict, in part due to the variability of the depths and rock characteristics encountered in different plays and within the same plays and because of the speed with which efficiency improvements have been introduced. Cost data that are two years old are, for all practical purposes, obsolete in shale formations. That said, taking one particular company’s data provides an illustration of falling well drilling and completion costs, from start-up to rig release.
EOG Resources, a large independent producer, says its wells on Texas’ Eagleford shale formation have fallen in cost from $16.9mn in 2009 to $6.8mn in 2012 and $5.8mn in 2013. Among other things, this was due to a reduction of drilling days from nearly 17 days in 2009 to 10 days today. The company also published their drilling costs in the Bakken formation (Table 1). Note that Bakken drilling costs rose early on as laterals grew in length, but declined substantially this year, when costs declined by 6% even though average laterals grew by 25%.
The use of sliding sleeves and similar devices that eliminate waiting for cement to dry between frack stages is one of several important technical breakthroughs that brought down completion time by several days. The technology is now offered by the three leading well service companies (Halliburton, Schlumberger, and Baker Hughes). It has become the norm on horizontal multi-stage fracking.
Super-pads that concentrate producing wells in relatively small areas significantly reduce location and construction costs and, in conjunction with self-propelled rigs (“walking rigs”), eliminate the need to dismantle and re-assemble them when moving to new sites. The introduction of these two devices has cut back rig-moving time from rig release to spudding from 5-6 days to less than half a day. Side-by-side super-pads accommodating 24 drill sites and higher are in operation today.
The list of cost-reduction and oil/gas recovery improvement technologies goes on and on, including special drill bit designs for shale formations, borehole telemetry that provides real-time information while the well is being drilled, which permits realigning horizontal bore holes that otherwise would stray outside the target zone, and others. The current relentless drive towards greater drilling efficiency keeps oil and gas production competitive.
Table 1: EOG Resources – Bakken Drilling Costs
|Laterals, ft||Well Cost||Drilling Days|
Table 2: Shale Gas Break-Even Prices ($/’000 Cu Ft)
SHALE OIL: COMFORTABLE MARGINS
As they say in investment circles, past success should not be construed as assuring future profits.
There are still some unknowns out there that need close attention, especially the increasing elusiveness of ‘sweet spots’, severe decline rates of both shale oil and shale gas wells, drilling costs, and, last but not least, oil and gas prices. There are warning signs, more prevalent at the moment in the gas sector, but latent as well in the oil sector that point to potential vulnerabilities.
Current financial incentives to seek out and drill for shale oil are far greater than for gas. US crude oil first purchase prices have been fluctuating between $84/B and $109/B over the last two years, well above companies’ stated ‘break-even prices’ which range from a low of $50-57/B at “reasonable returns” for liquid-rich areas in the Eagleford play (Baker Hughes, March 2013), to $68/B at a 15% return in the Bakken play (Crédit Suisse, May 2012), and on to $65-90/B in oil shales generally at 10% weighted average cost of capital (WACC), according to Merrill Lynch, as quoted by Forbes (5 March 2013). The Forbes article also lists break-even prices of 12 specific shale oil plays, of which the Permian Delaware play is only marginally profitable ($80/B break-even), and the oil-rich Mississipian Lime play is the most lucrative ($45/B). For comparison, the Forbes article gives the break-even price for Saudi Arabia’s Ghawar Field as $15/B. In short, opinions differ as to what rate of return shale oil production will in the end achieve. Still, while not ruling out the possibility that shale oil production might not be sustainable indefinitely, the consensus is that most US shale oil formations will have reasonable comfort margins for some time to come.
TIGHT GAS, TIGHT MARGINS
This is not the case with shale gas. Current US wellhead gas prices (August 2013) are $3.34/’000 cu ft. These prices have followed a torturous trajectory, coming down from a high of $13.90 in June 2006 to drop to $1.87 by April 2012 (and back up to $4.30 by 30 April 2013 prior to the more recent slump).
No doubt, the explosive rise in US shale gas production and the inability of the market to readily absorb the gas have been the main drivers in depressing prices. Unlike oil, which is more easily absorbed in the market (it can be shipped by rail, for example, while gas cannot), the complex infrastructure of gas markets imposes a rigidity that can only respond to temporary surpluses by sharply reducing prices.
The market is busy restructuring itself to accommodate higher gas volumes, including the conversion of LNG import facilities for export. The first of these, the Sabine Pass Terminal in Louisiana on the US Gulf Coast, has been fully approved (MEES, 23 August). Two of a total of six planned liquefaction trains are currently under construction. They are 38% complete, with liquefaction start-up estimated to occur in late 2015 or early 2016. Several other terminal conversions have been approved and are approaching the construction phase. As to displacing coal by natural gas as a relatively environmentally friendly and low-cost fuel of choice for power generation, the EIA projects in its May 2013 Short-Term Energy Outlook that “year-over-year increases in natural gas prices [will] contribute to declines in natural gas used for electric power generation from 25bn cfd in 2012 to 22.8bn cfd in 2013 and 22.2bn cfd in 2014.”
Low wellhead natural gas prices are a boon for LNG export operations. But these low prices, together with wild price volatility, bring into question the sustainability of shale gas production. An attempt to achieve some sort of congruence on the break-even price of shale gas has proved inconclusive. Break-even prices as low as $2.50/’000 cu ft and as high as $8.94/’000 cu ft are listed in the literature. The problem is in part a reflection of different accounting methods that are used in assessing them and in part because of the steep first-year decline rates of shale gas wells, as high as 80 to 85%, where minor price or cost variations can create havoc on discounting calculations.
On accounting methods, it appears that break-even price and internal rate-of-return calculations for shale gas fall into two distinct groups. The lower break-even group is based on what has been called point-forward calculations, meaning on a well-only cost basis. These calculations track drilling, fracking, completing and subsequent variable operating costs, and discount them to the present. The other method, called full-cycle analysis, also uses the discounting method, but in addition, it takes into consideration past outlays such as land acquisition costs that have soared during the early euphoric shale gas period but are now retreating rapidly. Full-cycle analysis also includes fixed costs such as overheads incurred at the corporate level and allocated on a per-well or per-’000 cu ft basis to gas produced. For example, Labyrinth Consulting Services, working with the James A Baker Institute for Public Policy at Rice University, Houston, lists the break-even prices for four shale gas plays (Table 2).
These break-even prices seem high, especially if one considers that the authors used an 8%/year discount rate, but the numbers do demonstrate how this seemingly small difference in accounting methodology can bring widely disparate results. Investors may be interested in knowing that the relevant regulatory agency, the Securities and Exchange Commission (SEC), mandates the use of full-cycle analysis on official government documents, but not in private company statements.
Oliver Wyman, a wholly-owned subsidiary of international consultants Marsh & McLennan, has published a list of break-even prices of 26 shale gas plays. These prices range from roughly $2.85/’000 cu ft to nearly $6, with a median price just below $4/’000 cubic feet equivalent (cfe – including liquids converted to cu ft on a heat-content basis). The use of cu ft versus cfe is another methodological incongruence that makes comparisons difficult. Another study worth mentioning is a Master’s Thesis by A K Cohen (Winner of the 2013 John Dunlop Undergraduate Thesis Prize in Business and Government, Harvard), that lists break-even prices of 11 shale gas plays under several operational scenarios. The 10-year 10% discount scenario has break-even prices ranging from $3.32 to $7.31/mn BTU (another minor discrepancy, compared with $/’000 cu ft; for ‘typical’ dry gas, the latter is a few pennies higher.
All things considered, the wide discrepancies in analyses makes it virtually impossible to come to a clear-cut break-even price for shale gas plays in general or for individual plays, but one thing does emerge from this search: at the current price of $3.43/’000 cu ft, some of the plays now on production are almost certainly uneconomic under the full-cycle standard, which is why the emphasis here is on shale gas.
DRILLING DOWN BUT PRODUCTION EDGEs UP – FOR NOW
The ultimate arbiter on profitability, the market, offers no help. Shale gas drilling has been stagnating from February 2011 (the earliest available data point) to October of 2011. From that point on, it has been declining at a practically unbroken 2-year stretch to early August 2013, from about 930 to 390 rigs (Graph 1). During the early gas-drill stagnation period, shale oil drilling kept rising vigorously as did overall basin drilling, which indicates that the oil companies were focusing more intensely on oil. By July/August of 2012 shale oil drilling entered its own stagnation that is ongoing today. Overall, having reached a high of 2016 rigs, drilling for both shale oil and shale gas dropped to 1,782 rigs today. Clearly, and that is the bad news, shale oil and shale gas development had lost some of its luster, shale gas more so than oil.
The good news is that US dry gas production continued to rise during the gas-drilling stagnation period; it has held its own over the last 20 months as drilling for shale gas declined (Graph 2). Was this due to the use of increasingly long laterals? Was it that the steep first-year decline rates eased up a year or so after initial production? These and other issues need to be looked into before judgment can be rendered regarding the future course of the shale gas revolution. Economic or not, at this stage it seems fairly clear that shale gas rests on a less secure footing than shale oil, not because it has less technical potential, but because its development is restricted by prices.
Graphs 1 and 2 can in no way be construed to deny history. The explosion of shale gas production has been real and it has had ripple effects throughout the world. The resources are there to sustain rapid and continued production increases, provided gas prices rise to sufficient levels and at sufficient speeds to warrant increasingly intense drilling efforts, and they may do just that, depending on developments in world markets.
LNG EXPORT ECONOMICS
The one big variable in estimating future prices for US LNG exports is the international LNG market. Average US LNG import prices declined roughly, very roughly, from $8/’000 cu ft in 2005 to $4 in 2013, and they have become very volatile over the last eight years.
Big-time investors, especially those that bet on the profitability of turning around import LNG terminals, look at delivered LNG prices in regional markets, where they are currently (August 2013) running at $15/mn BTU in east Asia for a margin of $4.40/mn BTU, given delivered costs of $10.60/mn BTU, according to Cheniere Energy, the majority owner and operator of the Sabine Pass Terminal project.
The margin in the European market comes out at $3.40/mn BTU, given the delivered price of $12 and costs of $8.40. Cheniere Energy estimates delivered costs in the Americas at $8.10/mn BTU for a margin of $6.90/mn BTU, given current regional prices of $15/mn BTU. The cutting-edge advantage for US LNG terminals delivering to markets in the Americas is shipping costs that are roughly six times less than those to Asia and half those for deliveries to Europe.
In short, the LNG terminal conversion in itself appears to be sound. The weak link is the shale gas market, which is new and poses as of yet unknown risks. If it can be sustained at current $4/mn BTU prices for the US Henry Hub gas marker, or if regional prices rise with rising LNG demand in energy-poor countries, thereby raising break-even wellhead prices of shale gas in the United States, the birth of a giant new LNG export industry in the United States would be assured.
Missing in our narrative is a detailed discussion about the short-term outlook for the development of US shale oil and an in-depth analysis regarding long-term prospects for both the US shale oil and shale gas. This would include a discussion of different approaches that have been used by principal players in assessing the new resource, and where the evaluation of reserves has been completely changed.
Instead of physically defined boundaries in conventional reserves, we are dealing with continuous plays that have no physical boundaries, where the focus has been on the Estimated Ultimate Recovery (EUR) on a per-well basis, which requires an evaluation, well-by-well, for hundreds or thousands of wells, to sort out what the reserves of a given play might be. These topics will be discussed in a forthcoming MEES OP-ED.
*Dr Merklein is a consultant on oil and gas policies. He was Assistant Secretary of International Affairs and Energy Security at the US Department of Energy, and Administrator of the Energy Information Administration (EIA) from 1984 to 1990. As head of EIA, Dr Merklein was in effect the Government’s Chief Energy Analyst. Prior to Joining the Reagan Administration, he was Professor of Petroleum Engineering at Texas A&M University and Dean of the Graduate School of Management of the University of Dallas. He can be reached at [email protected]