In the United States, the three big plays are the Permian, Eagle Ford and Bakken. Since the Permian can be split into the Delaware and Midland basins, maybe we say four. These are the names that usually come up and with good reason. The best source rock is found here, and that is why the majority of US unconventional onshore activity takes place in those plays.  If we were to grade the Basins on economics, the Permian is followed by the Eagle Ford and Bakken. Although the Eagle Ford and Bakken are probably equivalent when looking at source rock, costs are higher in North Dakota. The problem with generalizations about plays is the very large differences in economics by county. One could say those economics change a great deal more by field. As a general rule it is difficult for an investor to follow breakeven prices. The reasons are simple, as it’s a full time job just following generalized statements about play economics. 

Those that follow my articles have a general idea of what we believe to be true. The Bakken play has some of the best economics in southwest Mountrail and northeast McKenzie counties. The Permian has excellent numbers coming from Midland, Martin, Loving and Reeves counties. The Eagle Ford looks good in Dewitt and Karnes. When analysts given generalized numbers, it can be confusing to investors.

This does not mean the above chart is incorrect, it just means the coverage area is very large. When looking at well results, we see huge swings in production from section to section. This data is further corrupted by interval. Then we have to consider the operator and well design. Confusing enough? This chart creates further issues when looking at how the data is provided. We have some listed by country, by drilling type, and interval.  Some mistake intervals as plays. The Eagle Ford, Bakken, Bone Spring and Wolfcamp are all intervals (shale or rock). The Bakken is an interval in the Williston Basin. The Eagle Ford is an interval in the Western Gulf Basin. The Bone Spring is located in the Delaware Basin, which is located in the Permian Basin. I’m not saying this is an impossible premise, but data collection cannot be done by interval, state or county. This must be done by field.  So one can either gather up data from all operators and analyze, or try to find decent analysts to follow.

It has been my experience, the best ways to make money on oil and gas E&Ps by following the price of oil. This is also difficult, as it takes some speculation on the part of the investor. It also takes a great deal of research. What may be the best way, is by following plays with specific upside.  This may be the easiest, but one still needs some knowledge of plays and possible catalysts going forward. Newer plays generally have the most upside/downside and can cause stock prices to move the most. The Bakken was the first real unconventional, horizontal play to get moving in the US. This was followed by significant speculation in the Eagle Ford. The Permian was next. There are a large number of variables to follow when looking at a play. The Permian is an excellent example. There are a couple thousand feet of source rock and a large number of intervals that can produce oil.  The thicker the rock the more locations can be drilled and completed. The larger the number of intervals, the better the chance we find one has exceptional results. Newer plays also have higher costs, which decrease as infrastructure is put in place. 

The STACK may provide significant upside from today’s levels. Recent well results have been very good, and breakeven in core areas are as good as the top US fields. The past quarter was very good for operators in the STACK as we continue to see production and costs improve. This play is located in Oklahoma and has not seen as much traffic as Texas and North Dakota. Although many that follow US oil and gas know about the play, many others still do not. 

(Source: Hart Energy)

The play is located in the Anadarko Basin, and is surrounded by several  good intervals. 

Earnings have been very good for those targeting the STACK. We have seen large improvements in costs and well results. Newfield (NFX) had a very good quarter.  The STACK now represents 56% of its domestic production.  It has raised production total production guidance for three out of the past four months. 

(Source: Newfield)

It increased its STACK production curve by 15%.  It is now at 1,100 MBOE. Keep in mind this is a gas heavy curve with just 40% of production from oil. But the play produces 70% liquids. Its 2016 estimated well costs were $6.8 million, but current costs are down to $6.2 million. 

(Source: Newfield)

At $40/bbl oil, this play is producing returns around 40%. This is up from earlier estimates of 20%. It is important to note that Newfield is seeing a slower decline curve, which is aiding well performance long term. 

The STACK is  Marathon’s (MRO) flagship play. It is also reporting results that are exceeding its curve.

(Source: Marathon)

This is exceptional as its current curve has an EUR of 1,120 MBOE. It continues to tighten stages and increase proppant volumes. Enhanced well designs are functioning very well in this play. 

(Source: Marathon)

The above slide provides a good idea as to where the play is located. The core seems to be around Kingfisher and Blaine counties. The green area delineates the oil window and as the play moves west it becomes condensate and wet gas (red). The western oil window seems to have the most traffic as well pressure remain high, but so to oil percentages. 

Continental (CLR) also has a relatively large footprint in the STACK. 

(Source: Continental)

Its STACK long laterals (9,800 feet) have a 100% ROR at $50 oil.  It has an EUR of 1,700 MBOE. CLR’s EURs are a little higher, but most of its acreage is located in Blaine County, which has a higher percentage of natural gas and NGLs. Although, we are seeing some of its recent wells produce initial oil percentages around 70%. Its Ludwig well has been online for a little over 10 months and has already produced 279,000 BO. Its Compton well has been online for 5 months and produced 221,000 BO. Those results are both ver y good when compared to anywhere in the US.  

(Source: Continental)

CLR believes the best results are and will continue in Blaine and Dewey counties. These areas will have higher pressures, but we will need to see how wells produce in Kingfisher to know for sure. The source rock is 700 to 1200 feet thick, which should produce a large number of locations per section.  1200 feet is the combined thickness of both the Meramec and Woodford intervals. 

Devon (DVN) has reported some excellent results from the STACK as well. It currently operates 15 of the top 25 wells in the play. It also has the top four.

(Source: Devon)

The best wells are coming from the overpressured oil window. This includes southwest Kingfisher, Blaine and Canadian counties. Production keeps improving, and it looks like many operators are starting to get more proficient. Well costs are around $5.5 million, so economics are sound. 

(Source: Devon)

Devon (DVN) is seeing a 15% improvement in IP30 over its type curve. This is important as it does prove well designs can improve from here. Devon is currently doing up to 5 wells per section targeting the Meramec. It is also testing 170 foot spacing between intervals. Targeting the upper and lower Meramec, Devon believes it can do 14 wells per section total. 

(Source: Devon)

Although the Woodford is not thought of as good as an interval as the Meramec, some interesting well design changes are occurring. Devon has increased proppant per foot from 700 to 2000 lbs/ft. It Hobson row of wells saw 2600 lbs/ft of proppant. This is important for names like US Silica (SLCA), Hi Crush (HCLP), Emerge (EMES) and Fairmount (FMSA) given operators are moving to more sand then ceramic in new frac jobs. 

(Source: Devon)

Devon has a huge STACK footprint (along with the Delaware Basin) which is one of the top spots to be in the country. It is increasing capital to the area, and so are many other operators. We continue to see all operators increasing production per foot and decreasing costs. Given the relatively light inventory of wells to date targeting the Meramec (when compared to the Bakken and Eagle Ford cores), we think well design will continue to push the play forward. Costs should continue to decrease as will production numbers.  It is possible that oil prices could stay in the $40 to $50 range until the end of the year. If that is the case, operators will need to stick with areas it can turn a profit in. Look for the STACK play to continue to push down breakeven prices through 2016, and operators with leasehold here to continue to do well.