I could be completely wrong here, but Rex Energy is forced to limit production on some of its wells because the area lacks the right infrastructure.
Ethane and wet gas
A shale gas well will produce methane and ethane, both in gas form. Natural gas with high amounts of ethane is referred to as “wet” gas and low amounts as “dry” gas.
Pipeline companies will limitation the percentage of ethane carried over their pipelines. However, I believe that technical limitations of the pipeline are not the current limiting factor. The real issue is that ethane burns hotter than methane (explained by this blog post). The end customers of natural gas cannot handle gas that burns too hot.
I believe Rex Energy has wells in areas of the US that have hit this limitation. To deal with this problem, Rex will have to remove ethane from its natural gas by recovering it as a liquid. There are different technologies that can be used to do this. According to the presentation “NGL 101 – The Basics“:
- “Lean oil” plants recover only 15-30% ethane
- Refrigeration plants recover up to 80-85% ethane
- Cryogenic technology recovers up to 85-90% ethane
(The presentation is definitely worth reading as it explains industry terminology and the economics behind recovering ethane.)
Rex’s YE2011 10-K states that their refrigeration plant is not good enough and that cryogenic plants are needed:
[…] $1.6 million in impairment expense related to a refrigeration plant in the Appalachian Basin which was formerly in use before the commencement of operations at our cryogenic gas processing plant in Butler County, Pennsylvania. With larger scale gas processing capabilities in the region there is no further value for the refrigeration plant.
More cryogenic plants are being added to the region so Rex’s infrastructure limitations will soon be alleviated. In the meantime however, it seems that Rex has been required to reduce its production as there is a limitation as to how much wet gas can be sold. This explains why its press releases constantly talk about “full ethane recovery”. Without cryogenic plants, Rex’s wells cannot produce at their full rate of production. In an ideal world, Rex would defer the drilling of its well until the right infrastructure is in place. By drilling too early, its full production potential is essentially stranded until cryogenic plants come online (or until the wells start to naturally decline).
Pricing of natural gas liquids
The cost of transporting liquid ethane causes its price to vary from area to area. The local price is determined by the local supply and the demand from end users. Ethane can be shipped by trucks. It can also be transported by pipelines to areas with higher demand or to ports for international export. Another option is to mix the ethane with dry gas and to sell the mixture as natural gas. The article “Infrastructure Projects Connect Marcellus Shale To Ethane, NGL Markets” is worth reading as it explains the options and issues better than I do.
It is possible that Rex may end up flooding its local market with ethane and receive mediocre prices for it. I have no idea if this will happen. However, Rex has tied itself to arrangements where I believe it will be expected to dramatically increase liquid ethane production. Its YE2012 10-K states:
As of December 31, 2012, we had long-term marketing agreements in place for approximately 78.5 MMcf per day of natural gas, of which approximately 64.5 MMcf is currently in effect with the remaining volumes expected to be in effect by the fourth quarter of 2013. In addition to our marketing agreements for natural gas, during 2012 we entered into various transportation and processing arrangements for our Ohio Utica Shale production, supplementing pre-existing arrangements for our operated Appalachian production. We now have several processing agreements in place to separate our NGLs from our produced natural gas. In total, these agreements currently call for 65.0 MMcf of gross inlet natural gas volumes and increase to 205.0 MMcf of gross inlet volumes in 2015. We also entered into a transportation agreement for produced ethane, expected to become effective in 2014, which initially calls for a commitment of 3,000 gross barrels per day.
A concern I have with Rex is whether or not the current ethane pricing will hold up (I don’t think it will).
Effect of full ethane recovery on gas production
This is something that I couldn’t figure out. Rex’s Dec 2013 presentation shows the following chart on page 21:
The chart shows that production is “higher” with “Full Ethane Recovery”. This makes no sense to me. The unit Mcfe/d should be based on energy equivalence. Recovering more ethane should not change the amount of energy in the hydrocarbons produced. Perhaps Rex is using a different definition of “Mcfe/d”. The company could be making the assumption that liquid ethane will fetch a much higher price, so the ethane is “equivalent” to a much higher volume of natural gas (???). I honestly don’t know what’s going on.
GulfPort Energy (GPOR)
GulfPort is a much bigger player in the Utica basin and has the same problems as Rex. I find it interesting that it is saying different things about wet gas well economics. Here is their type curve:
Their type curve is flat in the very beginning. This is consistent with what I was saying earlier about limitations about how much wet gas can be sold in the region. The rest of the curve declines as one would normally expect. The use of a logarithmic scale on the chart is unusual; it seems like it is hiding very dramatic drops in initial production.Another thing that I would note is that GulfPort is more promotional than Rex and far more optimistic about its wells’ economics. The $9.6M well will have an EUR of 18.2 to 23.6 Bcfe. Rex projects that their $6.5M wells will have an EUR of 9.7 Bcfe with full ethane recovery. Normalizing for the well cost, GulfPort’s well will have an EUR of 18.2-23.6 Bcfe versus Rex’s 14.3Bcfe. That’s 27% to 65% higher.
Expected ultimate recovery (EUR) figures are a little misleading
Big EUR figures sound like they would make a dramatic difference to a well’s economics. I don’t believe that they do. Many shale gas companies assume a well life of 40 to 60 years (*we actually have no idea how long these wells will last, but that’s another story…). The present value of these future cash flows is very low. If you use a 6% discount rate, a dollar 40 years from now is worth 9.72 cents today. At 8%, it’s 4.60 cents. At 10%, it’s 2.20 cents. A well will also have very low margins near the end of its life. The small future profits discounted to the present don’t add up to much.
Investors should really be focusing on the net present value of a well’s future cash flows. Unfortunately, shale companies rarely provide much information to investors. For starters, they could provide after-tax PV-10 values at different discount rates. This would allow investors to estimate the market value of the assets using the discount rates that public and private markets are using.
I find that most oil and gas companies are more interested in misleading investors than helping them understand what they own.
*Disclosure: Short Rexx. I have no position in GPOR because I haven’t researched it (the Bronte Capital blog has an analysis of GPOR). Both stocks have high short interest.