There is a great deal of excitement in the shale patch in the USA. The culprit; exploration and production companies using horizontal drilling techniques to extract oil and gas from previously uneconomic shallow resource targets (shale) and making oversized profits in the process.
There are several big shale plays in the US, the best known being; Haynesville, Bakken, Eagle Ford, Barnett, Marcellus and Niobrara. Most of these are predominantly natural gas reservoirs and, since natural gas is not very transportable, and the US has enormous quantities of it, the US natural gas market will likely experience oversupply from time to time with limited upside profitability for the producers. Thus, whilst some natural gas stocks will undoubtedly make good profits, at least periodically, some investors prefer to avoid the space because the overall metrics can produce awkward headwinds.
Oil, however, is entirely different and a much more compelling story. It is a highly transportable global commodity and strong international demand growth will underpin US oil prices and maintain excellent profits for drillers.
The purest oil shale plays are found in the entire Bakken region and the entire north side of Eagle Ford. The Niobrara is also emerging as a combined oil and gas play with good potential. The balance of this note will focus primarily on the Bakken, or, more accurately, the Williston Basin.
The Williston Basin is a 125,000 square mile geological structural basin in North Dakota, Montana and Saskatchewan that is rich in petroleum deposits and minerals. The dominant oil bearing rock in Williston is the Bakken formation, a dolomite/limestone sandwich about 40 feet thick, located 10,000 feet deep with shale at the top and bottom. All three layers, upper, middle and lower, are oil-bearing with the middle Bakken being the most proficient.
In addition to Bakken there are other oil bearing rock types in the Williston. Of particular note is Three Forks, a 2-layer dolomite formation found just beneath Bakken. Drillers are still working to delineate its full scope and establish whether it is a separate oil reservoir from the Bakken or part of it. For drillers that have leased acreage that includes both Three Forks and Bakken this represents significant advantages in terms of infrastructure, efficiency and, especially, cost. Other formations such as Red River and Lodgepole are oil bearing although not generating the same level of interest as Bakken or Three Forks.
The Bakken/Three Forks structures are not uniform across Williston and demand for land rights is greatest where some of the richest deposits exist, particularly in and around the mature Bakken ‘kitchen’ as named by Continental Resources. This spans a sizable part of Montana and North Dakota and some of the best drilling locations are found in Divide, Williams, McKenzie, Dunn, Billings, Mountrail, and Mercer counties in ND, and Sheridan, Rooseveldt and Richland counties in MT. This is not to dismiss other areas of the Bakken as overall there are many valuable plays.
Enormous oil reserves
Oil was first discovered in Bakken in 1951, but it was only in recent years with advancements in horizontal drilling and hydraulic fracturing, coupled with higher oil prices, that commercial exploitation became truly viable.
The Williston basin contains enormous amounts of oil with total reserve estimates as high as 500 billion barrels. Recoverable oil is another matter entirely. As shale structures are low in porosity and permeability, and being shallow structures, albeit vast in area, estimates of recoverable oil have traditionally been extremely low. In 1995, the US Geological Survey (USGS) estimated that only 151 million barrels were recoverable. However, by April 2008, they upped the figure to a range of 3.0 to 4.3 billion barrels based on drilling methods and technology in use at the end of 2007.
In recognition of further drilling advances since 2007, the USGS is again undertaking a new study and expectations are that they will move toward a figure of about 8 billion when the exercise is complete in the next couple of years. Separately, industry veterans are estimating that total recoverable reserves may be as high as 24 billion barrels, including deposits in Canada.
To help understand why recoverable estimates are being revised upward so much – a development that has very positive repercussions for companies operating in the space - it is helpful understand how shale drilling is done.
How the oil is extracted
Tight reservoirs such as shale do not contain natural fractures and therefore don’t normally produce oil economically. Also they are shallow, which poses obvious problems for traditional vertical drilling. The methodology used to extract oil in economic quantities from shale involves drilling a vertical well, then curving-off to drill the lateral/horizontal section deep into the oil shale deposit.
Once the lateral well is drilled and cemented it is left for the service crew to perf, frac and prepare it for production. A perf gun is lowered into the well casing to the targeted lateral section of the well. An electrical charge is sent to the perf gun, which shoots small holes through the well cement and into the surrounding oil bearing rock. Thereafter hydraulic fraccing commences; a process whereby sand, water and chemicals are forced down the well and into the surrounding rock via the perfed holes under extremely high hydraulic pressure. This causes the rock to fracture, thus creating a pathway for the oil to seep into the well bore.
Once fraccing is completed in one section, temporary plugs are inserted at the section-end and the same perfing and fraccing process is repeated along the bore hole until the entire lateral section is done. When all stages have been perfed and fracced, the end stage plugs are drilled out allowing the oil to flow up the bore hole. The crews then complete the well, install the necessary equipment to connect the well to the pipeline network and add a pump-jack to help bring the oil to the surface.
Whilst, in the early years, a lateral well had just a small number of individual perf and frac stages, this has changed with the advent of higher oil prices during years 2007-2011. Now, multi-stage fraccing has become highly effective for recovering oil from deposits.
During 2007 and 2008, drillers usually drilled a mixture of short and long laterals. Typically, a short lateral would be less than 5,000 feet and contain 5-10 stages, whilst a long lateral would be 5,000+ and have 20 or more stages. A short lateral may have cost $4+ million to complete in 2008 and may have had estimated ultimate recoverable oil (EUR) during its lifetime of about 300,000 barrels. A long lateral would have cost significantly more, perhaps $6+ million, but would have a greater EUR, about 550,000 barrels.
In 2011 the leading drillers are almost exclusively doing long laterals, most being 10-12,000 feet in length with 30-35 stages and even more in some instances. The fully loaded cost of derisking, drilling and completing long laterals has increased and continues to experience upward pressure as activity ramps. Recent fully loaded cost estimates are in the region of $9 million.
Multi-stage fraccing in long laterals has led to significantly improved oil output and EUR. Having had initial production (IP) rates in the ‘hundreds’ of Bopd in 2007/2008, leading drillers are registering IPs of 2,000 or even 3,000 Bopd in 2011. EUR estimates are also rising and recently drillers have been quoting EURs as high as 950,000 barrels with expectations of even higher EURs over time.
With all these advances, and in an environment of assuredly high oil prices, it is no surprise that the economics of drilling in the Bakken are highly attractive, even in a tightening cost environment. Assuming WTI at $90, a differential of $10 for Bakken (Bakken oil sells for about $10 less than WTI), and a EUR of 800,000 barrels, the payback period for a well costing $9 million is in the range of just 1.0 to 2.0 years depending on the efficiencies of the particular driller.
These compelling paybacks have resulted in a huge increase in drilling activity. A total of about 3,600 (horizontal) wells had been drilled in the Bakken as of February 2011, and the industry is now adding about 2,000 new wells annually. Bakken oil output reached 110,000 Bopd in 2010 and is forecast to hit 1 million Bopd in 2015, almost a 10-fold increase in 5 years. A true oil boom is under way.
Further advances on tap
During 2011 and 2012 further advances in drilling techniques are anticipated to yield even better efficiencies. These include the use of frac sleeves and zipper fraccing instead of the perf and plug system, which can substantially boost fraccing efficiency whilst reducing cost. Also, the use of Eco-pad drilling rigs, which walk from one well prospect to the next in hours rather than losing several days in rebuilding and de-assembling a rig for each new well, should enable drillers to reduce the time and cost of drilling each well hole. An excellent video explaining the workings and benefits of ECO-pad rigs can be found here on the Continental Resources web site. Together these two developments are anticipated to bring savings per well that are comfortably in the range of 10%-20%. With each well currently costing about $9 million a saving at the upper end (i.e. 20%) is an important improvement, especially within a large multi-well drilling program.
Additionally, drillers are looking to drill much more intensively on their acreage. Whilst the low porosity and permeability of shale rock represented a barrier for many years - one that was eventually solved by the advent of horizontal drilling with hydraulic fraccing – the flip side is that low permeability and porosity means that drillers can drill wells close to one another without experiencing interference from one well to another. During 2010, most drillers talked of drilling one well per 1,280 acres. Now in 2011, with the help of ECO-pad rigs, a number of pilot programs are under way where 4 wells per 1,280 acres are being done and thus far no interference is being reported. The prospect of having more than 4 wells per 1,280 acres, by drilling into Three Forks, as well as Bakken, is already on the table. All of this leads to further efficiency and much lower land lease cost per well. Suffice to say that drillers will surely extract far greater amounts of oil per acre than had occurred up until now. Little wonder that the USGS is predicted to substantially increase its estimates of recoverable oil in the Bakken.
Separating wheat from chaff
Despite all the recent advances it’s not all good news in the shale patch. Ballooning demand has caused costs to rise on many fronts and good service providers are harder to acquire in a timely manner. The cost of land rights has risen from $400 per acre in 2008 to $2,000 or even $3,000 currently for top quality locations. Contract costs for fraccing and completion crews are also increasing. These developments are especially difficult for small drillers who are dealing with just a few wells and, for them, acquiring crews at competitive prices for small work lots is more challenging and service delays are becoming common. This situation will exacerbate over time as demand for crews and services increases further. Thus, whilst the overall economics for Bakken oil wells are very attractive, over time this may change, particularly for small or less efficient drillers.
All companies in the shale patch must deal with one particular phenomenon; because of low rock porosity there is a dramatic fall-off in flow-rates during the early life of an oil well. A typical readout for a well may be as follows: IP rate of 2,500 barrels with average production during the first 30 days of say 1,100 bpd. By the end of the first year the production rate may fall to about 250 bpd. In subsequent years the decline is less pronounced with oil output being perhaps 175 bpd after 2 years, 140 bpd after 3 years, 100 bpd after 4 years and so on. Putting that in context, total oil production in year 1 may be 180,000 barrels, followed by 80,000 in year 2, then 60,000 in year 3, and 45,000 in year 4 etc. With such severe depletion there is a world of difference– from a profitability and investment perspective - between E&P companies that achieve a very fast payback on the cost of a well and those that don’t. The latter can soon struggle in an environment when diminishing oil output is coupled with ever increasing costs. This is especially true for companies that lack the finances and economies of scale needed to adopt the latest industry advances.
Shorter term, the financial metrics look highly attractive for almost all companies operating in the Williston basin. Consequently, the Bakken oil industry has many years of strong growth ahead, and those companies who have acquired sizable acreage in desirable locations should do particularly well.
Just how profitable are Bakken oil drillers?
One of the main drivers behind the profitability of E&P companies in the Williston basin is the fact that Bakken and Three Forks shale are predominantly oil rich with natural gas playing little more than a cameo role.
Drillers in the Williston basin are reporting healthy and improving profit margins. Whilst no two oil wells are the same, and E&P companies differ greatly from one to another, the following is a reasonable outline of Bakken fully-loaded production and extraction costs as reported by E&P companies for 2010:
Operating costs per barrel; $14
Production taxes per barrel; $6
Depletion, depreciation per barrel; $25
Total costs per barrel; $45
This cost per barrel backdrop has led to good drillers reporting Net Income margins of about 30% for 2010. In the next 2-3 years a strong cocktail of cost reductions and efficiency improvement should result in the fully loaded costs per barrel falling toward $35 or lower for drillers who have efficiency of scale, who employ latest techniques, and who acquired land leases early in the cycle. This will lead to even better Net Income margins.
A work-through of current brokers’ estimates for 2011 and 2012 indicates that Net Income margins are expected to expand well into the 30%+ range for a number of Bakken E&P companies. This will enable them to generate strong cash flows.
To illustrate this last and important point: An E&P company with a 35% Net Income margin, arrived after deducting typical “non-cash charges like Depletion/Depreciation” of 25/30% of Sales (say $25 cost Vs $90 oil), should generate cash from operations of over 50% of Sales, other factors being equal. The essential point here is that such tremendous cash flows facilitate aggressive capital investment programs and multi-year growth. It becomes a largely self-perpetuating cycle; high profits generate strong cash flows that fund improved capex, which in turn leads to higher profits and so on. The compounded effect over just a few years is impressive. Whilst this model can’t last forever it should certainly function nicely for leading Bakken E&P companies for the next few years.
Bakken drillers as a group have some of the highest Net Income margins of all US quoted E&P companies and some of the best multi-year growth prospects. It helps greatly of course that they can achieve a pay-back on total well drilling costs of just over 1 year.
Several companies operating in the Williston basin appear to be very good investment opportunities especially following the 2011 mid-year market pull back. A selection of plays will be examined in the next two articles. Ranked in order of lease acreage, these will include; Continental Resources (CLR); Whiting Petroleum (WLL), Brigham Exploration (BEXP), Oasis Petroleum (OAS), Northern Oil (NOG) and Kodiak Oil (KOG).